Edited by J.B. Kitto and S.C. Stultz
The Babcock & Wilcox Company
Copyright © 2005 by
The Babcock & Wilcox Company
a McDermott company
Forty-first edition
First printing
All rights reserved.
Reproduction or translation of any part of this work in any form or by any means beyond
that permitted by the 1976 United States Copyright Act without the permission of the
copyright holder is unlawful. Requests for permission or further information should be
addressed to: STEAM, The Babcock & Wilcox Company, 20 S. Van Buren Avenue, P.O. Box
351, Barberton, Ohio, U.S.A. 44203-0351.
Disclaimer
The information contained within this book has been obtained by The Babcock
& Wilcox Company from sources believed to be reliable. However, neither The
Babcock & Wilcox Company nor its authors make any guarantee or warranty,
expressed or implied, about the accuracy, completeness or usefulness of the
information, product, process or apparatus discussed within this book, nor
shall The Babcock & Wilcox Company or any of its authors be liable for error,
omission, losses or damages of any kind or nature. This book is published
with the understanding that The Babcock & Wilcox Company and its authors
are supplying general information and neither attempting to render engineering
or professional services nor offering a product for sale. If services are desired,
an appropriate professional should be consulted.
Steam/its generation and use. 41st edition.
Editors: John B. Kitto and Steven C. Stultz.
The Babcock & Wilcox Company, Barberton, Ohio, U.S.A.
2005
Includes bibliographic references and index.
Subject areas: 1. Steam boilers.
2. Combustion – Fossil fuels.
3. Nuclear power.
The editors welcome any technical comments, notes on inaccuracies, or thoughts on important omissions. Please direct these to the
editors at SteamBook@babcock.com.
© 1955, 1960, 1963, 1972, 1975, 1978, 1992, The Babcock & Wilcox Company. All rights reserved.
ISBN 0-9634570-1-2
Library of Congress Catalog Number: 92-74123
ISSN 1556-5173
ii
Printed in the United States of America.
Steam 41
The Babcock & Wilcox Company
Steam, Edition: 41
Steam/its generation and use is the longest continuously published engineering text of its kind in the world. It has always been, and continues to be, written and published by The Babcock & Wilcox Company, the Original, headquartered in Barberton, Ohio, and incorporated in Delaware, The United States
of America.
Steam 41
iii
The Babcock & Wilcox Company
The Babcock & Wilcox Company
iv
Steam 41
The Babcock & Wilcox Company
Preface
Dear Reader:
The founders of our company, George Babcock and Stephen Wilcox, invented
the safety water tube boiler. This invention resulted in the commercialization
of large-scale utility generating stations. Rapid increases in generation of safe,
dependable and economic electricity literally fueled the Industrial Revolution
and dramatically increased the standard of living in the United States and
industrialized economies worldwide throughout the twentieth century.
Advancements in technology to improve efficiency and reduce environmental emissions have continued for nearly 140 years, creating a unique and valuable body of applied engineering that represents the individual and collective
contributions of several generations of employees. As in other areas of science
and engineering, our field has continued to evolve, resulting in an extensive
amount of new material that has been incorporated into our 41st edition of
Steam/its generation and use. This edition required an extensive amount of
personal time and energy from hundreds of employees and reflects our commitment to both our industry and our future.
Today it is clear that the challenge to generate power more efficiently from
fossil fuels, while minimizing impacts to our environment and global climate,
will require significant technological advancements. These advances will require creativity, perseverance and ingenuity on the part of our employees and
our customers. For inspiration, we can recall the relentless drive and imagination of one of our first customers, Mr. Thomas Alva Edison. For strength,
we will continue to embrace our Core Values of Quality, Integrity, Service and
People which have served us well over our long history as a company.
I thank our shareholders, our employees, our customers, our partners and
our suppliers for their continued dedication, cooperation and support as we move
forward into what will prove to be a challenging and rewarding century.
To help guide us all along the way, I am very pleased to present Edition: 41.
David L. Keller
President and Chief Operating Officer
The Babcock & Wilcox Company
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The Babcock & Wilcox Company
Table of Contents
Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
viii to ix
System of Units: English and Système International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
x
Editors’ Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
xi
Introduction to Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intro-1 to 17
Selected Color Plates, Edition: 41 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Plates 1 to 8
Section I – Steam Fundamentals
Chapter 1
Steam Generation – An Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
Thermodynamics of Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3
Fluid Dynamics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
Heat Transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5
Boiling Heat Transfer, Two-Phase Flow and Circulation . . . . . . . . . . . . . .
6
Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion . . . .
7
Metallurgy, Materials and Mechanical Properties . . . . . . . . . . . . . . . . . . . .
8
Structural Analysis and Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1-1
2-1
3-1
4-1
5-1
6-1
7-1
8-1
to
to
to
to
to
to
to
to
1-17
2-27
3-17
4-33
5-21
6-25
7-25
8-17
Section II – Steam Generation from Chemical Energy
Chapter 9
Sources of Chemical Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10
Principles of Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
Oil and Gas Utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12
Solid Fuel Processing and Handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
Coal Pulverization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14
Burners and Combustion Systems for Pulverized Coal . . . . . . . . . . . . . . .
15
Cyclone Furnaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
Stokers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
Fluidized-Bed Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18
Coal Gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19
Boilers, Superheaters and Reheaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20
Economizers and Air Heaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
Fuel Ash Effects on Boiler Design and Operation . . . . . . . . . . . . . . . . . . . .
22
Performance Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23
Boiler Enclosures, Casing and Insulation . . . . . . . . . . . . . . . . . . . . . . . . . .
24
Boiler Cleaning and Ash Handling Systems . . . . . . . . . . . . . . . . . . . . . . . .
25
Boiler Auxiliaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9-1
10-1
11-1
12-1
13-1
14-1
15-1
16-1
17-1
18-1
19-1
20-1
21-1
22-1
23-1
24-1
25-1
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
9-19
10-31
11-17
12-19
13-15
14-21
15-13
16-11
17-15
18-17
19-21
20-17
21-27
22-21
23-9
24-21
25-23
Section Ill – Applications of Steam
Chapter 26
Fossil Fuel Boilers for Electric Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
27
Boilers for Industry and Small Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28
Chemical and Heat Recovery in the Paper Industry . . . . . . . . . . . . . . . . .
29
Waste-to-Energy Installations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
Wood and Biomass Installations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31
Marine Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
26-1
27-1
28-1
29-1
30-1
31-1
to
to
to
to
to
to
26-17
27-21
28-29
29-23
30-11
31-13
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Section IV – Environmental Protection
Chapter 32
Environmental Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33
Particulate Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
34
Nitrogen Oxides Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
35
Sulfur Dioxide Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
36
Environmental Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32-1
33-1
34-1
35-1
36-1
to
to
to
to
to
32-17
33-13
34-15
35-19
36-15
Section V – Specification, Manufacturing and Construction
Chapter 37
Equipment Specification, Economics and Evaluation . . . . . . . . . . . . . . . . . 37-1 to 37-17
38
Manufacturing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38-1 to 38-13
39
Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39-1 to 39-19
Section VI – Operations
Chapter 40
Pressure, Temperature, Quality and Flow Measurement . . . . . . . . . . . . . .
41
Controls for Fossil Fuel-Fired Steam Generating Plants . . . . . . . . . . . . . .
42
Water and Steam Chemistry, Deposits and Corrosion . . . . . . . . . . . . . . . . .
43
Boiler Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
40-1
41-1
42-1
43-1
to
to
to
to
40-25
41-21
42-29
43-17
Section VII – Service and Maintenance
Chapter 44
Maintaining Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44-1 to 44-21
45
Condition Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45-1 to 45-21
Section VIII – Steam Generation from Nuclear Energy
Chapter 46
Steam Generation from Nuclear Energy . . . . . . . . . . . . . . . . . . . . . . . . . . .
47
Fundamentals of Nuclear Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
48
Nuclear Steam Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
49
Nuclear Services and Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50
Nuclear Equipment Manufacture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Appendices
Appendix 1
2
Steam 41
Conversion Factors, SI Steam Properties and Useful Tables . . . . . . . . . . .
Codes and Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Symbols, Acronyms and Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B&W Trademarks in Edition: 41 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
46-1
47-1
48-1
49-1
50-1
to
to
to
to
to
46-25
47-15
48-15
49-21
50-13
T-1 to T-16
C-1 to C-6
S-1 to S-10
TM-1
I-1 to I-22
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The Babcock & Wilcox Company
Acknowledgments
Steam/its generation and use is the culmination of the work of hundreds of B&W employees who have contributed directly and indirectly to this edition and to the technology upon which it is based. Particular recognition goes to individuals who formally committed to preparing and completing this expanded 41st edition.
Editor-in-Chief/Project Manager
S.C. Stultz
Technical Editor/Technical Advisor
J.B. Kitto
Art Director/Assistant Editor
G.L. Tomei
Assistant Technical Editors
J.J. Gaidos
M.A. Miklic
Lead Authors
M.J. Albrecht
G.T. Bielawski
K.P. Brolly
P.A. Campanizzi
P.L. Cioffi
R.A. Clocker
P.L. Daniel
R.A. Detzel
J.A. Dickinson
W. Downs
D.D. Dueck
S.J. Elmiger
J.S. Gittinger
J.E. Granger*
G.R. Grant
G.H. Harth
T.C. Heil
D.A. Huston
B.J. Jankura
C.S. Jones
K.L. Jorgensen
J.B. Kitto
D.L. Kraft
A.D. LaRue
M.P. Lefebvre
P. Li
G.J. Maringo
W.N. Martin
E.H. Mayer*
D.K. McDonald
R.M. McNertney Jr.
J.E. Monacelli
T.E. Moskal
N.C. Polosky
E.F. Radke
K.E. Redinger
J.D. Riggs
D.E. Ryan
D.P. Scavuzzo
S.A. Scavuzzo
W.G. Schneider
T.D. Shovlin
T.A. Silva
B.C. Sisler
J.W. Smith
R.E. Snyder
W.R. Stirgwolt
J.R. Strempek
S.C. Stultz
J.M. Tanzosh
G.L. Tomei
D.P. Tonn
S.J. Vecci
P.S. Weitzel
R.A. Wessel
L.C. Westfall
P.J. Williams
* The editors offer special acknowledgment to authors J.E. Granger and E.H. Mayer who passed away
during the preparation of Edition: 41.
viii
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The Babcock & Wilcox Company
Primary Support Authors
S.A. Bryk
D.E. Burnham
D.S. Fedock
J.T. Griffin
B.L. Johnson
N. Kettenbauer
T.P. Kors
G.J. Lance
R.C. Lenzer
E.P.B. Mogensen
G.M. Pifer
K.J. Rogers
B.J. Youmans
J.W. Malone
M.G. Morash
R.E. Reimels
Executive Steering Committee
B.C. Bethards
E.M. Competti
J.S. Kulig
D.C. Langley
Production Group
J.L. Basar
L.A. Brower
Steam 41
Outside Support
P.L. Fox
L.M. Shepherd
P.C. Lutjen (Art)
J.R. Grizer (Tables)
ix
The Babcock & Wilcox Company
System of Units
English and Système International
To recognize the globalization of the power industry, the 41st edition of Steam
incorporates the Système International d’Unitès (SI) along with the continued use of English or U.S. Customary System (USCS) units. English units
continue to be the primary system of units with SI provided as secondary units
in parentheses. In some instances, SI units alone have been provided where
these units are common usage. In selected figures and tables where dual units
could detract from clarity (logarithmic scales, for example) SI conversions are
provided within the figure titles or as a table footnote.
Extensive English-SI conversion tables are provided in Appendix 1. This
appendix also contains a complete SI set of the Steam Tables, Mollier diagram,
pressure-enthalpy diagram and psychrometric chart.
The decision was made to provide exact conversions rounded to an appropriate number of figures. This was done to avoid confusion about the original
source values.
Absolute pressure is denoted by psi or kPa/MPa and gauge pressure by psig
or kPa/MPa gauge. The difference between absolute pressure and pressure
difference is identified by the context. Finally, in Chapters 10 and 22, as well
as selected other areas of Steam which provide extensive numerical examples,
only English units have been provided for clarity.
For reference and clarity, power in British thermal units per hour (Btu/h)
has typically been converted to megawatts-thermal and is denoted by MWt
while megawatts-electric in both systems of units has been denoted by MW.
The editors hope that these conversion practices will make Steam easily usable
by the broadest possible audience.
x
Steam 41
The Babcock & Wilcox Company
Editors’ Foreword
When we completed the 40th edition of Steam in 1992, we had a sense that
perhaps our industry was stabilizing. But activity has again accelerated. Today, efficiencies are being driven even higher. Emissions are being driven even
lower. Many current technologies are being stretched, and new technologies
are being developed, tested and installed. We have once again changed much
of Steam to reflect our industry’s activity and anticipated developments.
Recognizing the rich history of this publication, we previously drew words
from an 1883 edition’s preface to say that “we have revised the whole, and
added much new and valuable matter.” For this new 41st edition we can draw
from the 1885 edition to say “Having again revised Steam, and enlarged it by
the addition of new and useful information, not published heretofore, we shall
feel repaid for the labor if it shall prove of value to our customers.”
We hope this new edition is of equal value to our partners and suppliers,
government personnel, students and educators, and all present and future employees of The Babcock & Wilcox Company.
Steam 41
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The Babcock & Wilcox Company
Introduction to Steam
Throughout history, mankind has reached beyond
the acceptable to pursue a challenge, achieving significant accomplishments and developing new technology. This process is both scientific and creative. Entire civilizations, organizations, and most notably, individuals have succeeded by simply doing what has
never been done before. A prime example is the safe
and efficient use of steam.
One of the most significant series of events shaping today’s world is the industrial revolution that began in the late seventeenth century. The desire to generate steam on demand sparked this revolution, and
technical advances in steam generation allowed it to
continue. Without these developments, the industrial
revolution as we know it would not have taken place.
It is therefore appropriate to say that few technologies developed through human ingenuity have done
so much to advance mankind as the safe and dependable generation of steam.
Intimately related to steam generation is the steam
turbine, a device that changes the energy of steam
into mechanical work. In the early 1600s, an Italian
named Giovanni Branca produced a unique invention
(Fig. 2). He first produced steam, based on Hero’s
aeolipile. By channeling the steam to a wheel that
rotated, the steam pressure caused the wheel to turn.
Thus began the development of the steam turbine.
The primary use of steam turbines today is for electric power production. In one of the most complex systems ever designed by mankind, superheated highpressure steam is produced in a boiler and channeled
to turbine-generators to produce electricity.
Steam as a resource
In 200 B.C., a Greek named Hero designed a simple
machine that used steam as a power source (Fig. 1).
He began with a cauldron of water, placed above an
open fire. As the fire heated the cauldron, the cauldron shell transferred the heat to the water. When the
water reached the boiling point of 212F (100C), it
changed form and turned into steam. The steam
passed through two pipes into a hollow sphere, which
was pivoted at both sides. As the steam escaped
through two tubes attached to the sphere, each bent
at an angle, the sphere moved, rotating on its axis.
Hero, a mathematician and scientist, labeled the
device aeolipile, meaning rotary steam engine. Although the invention was only a novelty, and Hero
made no suggestion for its use, the idea of generating
steam to do useful work was born. Even today, the basic
idea has remained the same – generate heat, transfer the heat to water, and produce steam.
Steam 41 / Introduction to Steam
Fig. 1 Hero’s aeolipile.
Intro-1
The Babcock & Wilcox Company
Today’s steam plants are a complex and highly sophisticated combination of engineered elements. Heat
is obtained either from primary fossil fuels like coal,
oil or natural gas, or from nuclear fuel in the form of
uranium. Other sources of heat-producing energy include waste heat and exhaust gases, bagasse and biomass, spent chemicals and municipal waste, and geothermal and solar energy.
Each fuel contains potential energy, or a heating
value measured in Btu/lb (J/kg). The goal is to release
this energy, most often by a controlled combustion
process or, with uranium, through fission. The heat is
then transferred to water through tube walls and other
components or liquids. The heated water then changes
form, turning into steam. The steam is normally heated
further to specific temperatures and pressures.
Steam is also a vital resource in industry. It drives
pumps and valves, helps produce paper and wood
products, prepares foods, and heats and cools large
buildings and institutions. Steam also propels much
of the world’s naval fleets and a high percentage of
commercial marine transport. In some countries, steam
plays a continuing role in railway transportation.
Steam generators, commonly referred to as boilers,
range in size from those needed to heat a small building to those used individually to produce 1300 megawatts of electricity in a power generating station –
enough power for more than one million people. These
larger units deliver more than ten million pounds of
superheated steam per hour (1260 kg/s) with steam
temperatures exceeding 1000F (538C) and pressures
exceeding 3800 psi (26.2 MPa).
Today’s steam generating systems owe their dependability and safety to the design, fabrication and
operation of safe water tube boilers, first patented by
George Babcock and Stephen Wilcox in 1867 (Fig. 3).
Because the production of steam power is a tremendous resource, it is our challenge and responsibility to
further develop and use this resource safely, efficiently,
dependably, and in an environmentally-friendly manner.
Fig. 3 First Babcock & Wilcox boiler, patented in 1867.
Fuels were needed for space heating and cooking and
for general industrial and military growth. Forests were
being stripped and coal was becoming an important
fuel. Coal mining was emerging as a major industry.
As mines became deeper, they were often flooded
with underground water. The English in particular
were faced with a very serious curtailment of their
industrial growth if they could not find some economical way to pump water from the mines. Many people
began working on the problem and numerous patents
were issued for machines to pump water from the
mines using the expansive power of steam. The early
machines used wood and charcoal for fuel, but coal
eventually became the dominant fuel.
The most common source of steam at the time was
a shell boiler, little more than a large kettle filled with
water and heated at the bottom (Fig. 4).
Not all early developments in steam were directed
toward pumps and engines. In 1680, Dr. Denis Papin,
a Frenchman, invented a steam digester for food pro-
The early use of steam
Steam generation as an industry began almost two
thousand years after Hero’s invention, in the seventeenth century. Many conditions began to stimulate
the development of steam use in a power cycle. Mining for ores and minerals had expanded greatly and
large quantities of fuel were needed for ore refining.
Fig. 2 Branca’s steam turbine.
Intro-2
Fig. 4 Haycock shell boiler, 1720.
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
cessing, using a boiler under heavy pressure. To avoid
explosion, Papin added a device which is the first safety
valve on record. Papin also invented a boiler with an
internal firebox, the earliest record of such construction.
Many experiments concentrated on using steam
pressure or atmospheric pressure combined with a
vacuum. The result was the first commercially successful steam engine, patented by Thomas Savery in
1698, to pump water by direct displacement (Fig. 5).
The patent credits Savery with an engine for raising
water by the impellant force of fire, meaning steam.
The mining industry needed the invention, but the
engine had a limited pumping height set by the pressure the boiler and other vessels could withstand.
Before its replacement by Thomas Newcomen’s engine
(described below), John Desaguliers improved the
Savery engine, adding the Papin safety valve and using an internal jet for the condensing part of the cycle.
Steam engine developments continued and the earliest cylinder-and-piston unit was based on Papin’s
suggestion, in 1690, that the condensation of steam
should be used to make a vacuum beneath a piston,
after the piston had been raised by expanding steam.
Newcomen’s atmospheric pressure engine made practical use of this principle.
While Papin neglected his own ideas of a steam engine to develop Savery’s invention, Thomas
Newcomen and his assistant John Cawley adapted
Papin’s suggestions in a practical engine. Years of experimentation ended with success in 1711 (Fig. 6).
Steam admitted from the boiler to a cylinder raised a
piston by expansion and assistance from a counterweight on the other end of a beam, actuated by the
piston. The steam valve was then closed and the steam
in the cylinder was condensed by a spray of cold water. The vacuum which formed caused the piston to
be forced downward by atmospheric pressure, doing
work on a pump. Condensed water in the cylinder was
expelled through a valve by the entry of steam which
was at a pressure slightly above atmospheric. A 25 ft
(7.6 m) oak beam, used to transmit power from the
cylinder to the water pump, was a dominant feature
Fig. 5 Savery’s engine, circa 1700.
Steam 41 / Introduction to Steam
Fig. 6 Newcomen’s beam engine, 1711.
of what came to be called the beam engine. The boiler
used by Newcomen, a plain copper brewer’s kettle,
was known as the Haycock type. (See Fig. 4.)
The key technical challenge remained the need for
higher pressures, which meant a more reliable and
stronger boiler. Basically, evolution of the steam boiler
paralleled evolution of the steam engine.
During the late 1700s, the inventor James Watt
pursued developments of the steam engine, now
physically separated from the boiler. Evidence indicates that he helped introduce the first waggon boiler,
so named because of its shape (Fig. 7). Watt concentrated on the engine and developed the separate steam
condenser to create the vacuum and also replaced
atmospheric pressure with steam pressure, improving
the engine’s efficiency. He also established the measurement of horsepower, calculating that one horse
could raise 550 lb (249 kg) of weight a distance of 1 ft
(0.3 m) in one second, the equivalent of 33,000 lb
(14,969 kg) a distance of one foot in one minute.
Fig. 7 Waggon boiler, 1769.
Intro-3
The Babcock & Wilcox Company
Fire tube boilers
The next outstanding inventor and builder was Richard Trevithick, who had observed many pumping
stations at his father’s mines. He realized that the
problem with many pumping systems was the boiler
capacity. Whereas copper was the only material previously available, hammered wrought iron plates could
now be used, although the maximum length was 2 ft
(0.6 m). Rolled iron plates became available in 1875.
In 1804, Trevithick designed a higher pressure engine, made possible by the successful construction of a
high pressure boiler (Fig. 8). Trevithick’s boiler design
featured a cast iron cylindrical shell and dished end.
As demand grew further, it became necessary to either build larger boilers with more capacity or put up
with the inconveniences of operating many smaller
units. Engineers knew that the longer the hot gases were
in contact with the shell and the greater the exposed surface area, the greater the capacity and efficiency.
While a significant advance, Newcomen’s engine
and boiler were so thermally inefficient that they were
frequently only practical at coal mine sites. To make
the system more widely applicable, developers of steam
engines began to think in terms of fuel economy. Noting that nearly half the heat from the fire was lost
because of short contact time between the hot gases
and the boiler heating surface, Dr. John Allen may
have made the first calculation of boiler efficiency in
1730. To reduce heat loss, Allen developed an internal furnace with a smoke flue winding through the
water, like a coil in a still. To prevent a deficiency of
combustion air, he suggested the use of bellows to force
the gases through the flue. This probably represents
the first use of forced draft.
Later developments saw the single pipe flue replaced
by many gas tubes, which increased the amount of
heating surface. These fire tube boilers were essentially the design of about 1870. However, they were
limited in capacity and pressure and could not meet
the needs that were developing for higher pressures
and larger unit sizes. Also, there was the ominous
record of explosions and personal injury because of
direct heating of the pressure shell, which contained
large volumes of water and steam at high temperature and pressure.
The following appeared in the 1898 edition of
Steam: That the ordinary forms of boilers (fire tube
boilers) are liable to explode with disastrous effect is
conceded. That they do so explode is witnessed by the
sad list of casualties from this cause every year, and
almost every day. In the year 1880, there were 170
explosions reported in the United States, with a loss
of 259 lives, and 555 persons injured. In 1887 the
number of explosions recorded was 198, with 652 persons either killed or badly wounded. The average reported for ten years past has been about the same as the
two years given, while doubtless many occur which are
not recorded.
Inventors recognized the need for a new design, one
that could increase capacity and limit the consequences of pressure part rupture at high pressure and
temperature. Water tube boiler development began.
Fig. 8 Trevithick boiler, 1804.
Fig. 9 William Blakey boiler, 1766.
Intro-4
Early water tube design
A patent granted to William Blakey in 1766, covering an improvement in Savery’s steam engine, includes
a form of steam generator (Fig. 9). This probably was
the first step in the development of the water tube
boiler. However, the first successful use of a water
tube design was by James Rumsey, an American inventor who patented several types of boilers in 1788.
Some of these boilers used water tube designs.
At about this time John Stevens, also an American,
invented a water tube boiler consisting of a group of
small tubes closed at one end and connected at the
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
Fig. 10 John Stevens water tube boiler, 1803.
other to a central reservoir (Fig. 10). Patented in the
United States (U.S.) in 1803, this boiler was used on
a Hudson River steam boat. The design was short
lived, however, due to basic engineering problems in
construction and operation.
Blakey had gone to England to obtain his patents,
as there were no similar laws in North America.
Stevens, a lawyer, petitioned the U.S. Congress for a
patent law to protect his invention and such a law was
enacted in 1790. It may be said that part of the basis
of present U.S. patent laws grew out of the need to
protect a water tube boiler design. Fig. 11 shows another form of water tube boiler, this one patented by
John Cox Stevens in 1805.
In 1822, Jacob Perkins built a water tube boiler that
is the predecessor of the once-through steam generator. A number of cast iron bars with longitudinal holes
were arranged over the fire in three tiers by connecting the ends outside of the furnace with a series of
bent pipes. Water was fed to the top tier by a feed
pump and superheated steam was discharged from the
lower tier to a collecting chamber.
Fig. 12 Inclined water tubes connecting front and rear water
spaces, complete with steam space above. Stephen Wilcox, 1856.
with inclined water tubes that connected water spaces
at the front and rear, with a steam chamber above.
Most important, as a water tube boiler, his unit was inherently safe. His design revolutionized the boiler industry.
In 1866, Wilcox partnered with his long-time friend,
George H. Babcock. The following year, U.S. Patent
No. 65,042 was granted to George H. Babcock and
Steven Wilcox, Jr., and the partnership of Babcock,
Wilcox and Company was formed. In 1870 or 1871,
Babcock and Wilcox became the sole proprietors, dropping Company from the name, and the firm was
known as Babcock & Wilcox until its incorporation in
1881, when it changed its name to The Babcock &
Wilcox Company (B&W). (see Fig. 3).
Industrial progress continued. In 1876, a giantsized Corliss steam engine, a device invented in Rhode
Island in 1849, went on display at the Centennial Ex-
The Babcock & Wilcox Company
It was not until 1856, however, that a truly successful water tube boiler emerged. In that year, Stephen
Wilcox, Jr. introduced his version of the water tube
design with improved water circulation and increased
heating surface (Fig. 12). Wilcox had designed a boiler
Fig. 11 Water tube boiler with tubes connecting water chamber
below and steam chamber above. John Cox Stevens, 1805.
Steam 41 / Introduction to Steam
Fig. 13 Babcock & Wilcox Centennial boiler, 1876.
Intro-5
The Babcock & Wilcox Company
hibition in Philadelphia, Pennsylvania, as a symbol
of worldwide industrial development. Also on prominent display was a 150 horsepower water tube boiler
(Fig. 13) by George Babcock and Stephen Wilcox, who
were by then recognized as engineers of unusual ability. Their professional reputation was high and their
names carried prestige. By 1877, the Babcock & Wilcox
boiler had been modified and improved by the partners
several times (Fig. 14).
At the exhibition, the public was awed by the size
of the Corliss engine. It weighed 600 tons and had cylinders 3 ft (0.9 m) in diameter. But this giant size was
to also mark the end of the steam engine, in favor of
more efficient prime movers, such as the steam turbine. This transition would add momentum to further
development of the Babcock & Wilcox water tube
boiler. By 1900, the steam turbine gained importance
as the major steam powered source of rotary motion,
due primarily to its lower maintenance costs, greater overloading tolerance, fewer number of moving parts, and
smaller size.
Perhaps the most visible technical accomplishments
of the time were in Philadelphia and New York City.
In 1881 in Philadelphia, the Brush Electric Light Company began operations with four boilers totaling 292
horsepower. In New York the following year, Thomas
Alva Edison threw the switch to open the Pearl Street
Central station, ushering in the age of the cities. The
boilers in Philadelphia and the four used by Thomas
Edison in New York were built by B&W, now incorporated. The boilers were heralded as sturdy, safe and
Fig. 14 Babcock & Wilcox boiler developed in 1877.
reliable. When asked in 1888 to comment on one of
the units, Edison wrote: It is the best boiler God has
permitted man yet to make. (Fig. 15).
The historic Pearl Street Central station opened with
59 customers using about 1300 lamps. The B&W boilers consumed 5 tons of coal and 11,500 gal (43,532 l)
of water per day.
The B&W boiler of 1881 was a safe and efficient
steam generator, ready for the part it would play in
worldwide industrial development.
Water tube marine boilers
The first water tube marine boiler built by B&W
was for the Monroe of the U.S. Army’s Quartermaster
George Herman Babcock
George Herman Babcock was born June 17, 1832
near Otsego, New York. His father was a well
known inventor and mechanic. When George was
12 years old, his parents moved to Westerly,
Rhode Island, where he met Stephen Wilcox, Jr.
At age 19, Babcock started the Literary Echo,
editing the paper and running a printing business.
With his father, he invented the first polychromatic printing press, and he also patented a job
press which won a prize at the London Crystal
Palace International Exposition in 1855.
In the early 1860s, he was made chief draftsman
of the Hope Iron Works at Providence, Rhode Island, where he renewed his acquaintance with
Stephen Wilcox and worked with him in developing the first B&W boiler. In 1886, Babcock became
the sixth president of the American Society of Mechanical Engineers.
He was the first president of The Babcock &
Wilcox Company, a position he held until his
death in 1893.
Intro-6
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
department. A major step in water tube marine boiler
design came in 1889, with a unit for the steam yacht
Reverie. The U.S. Navy then ordered three ships featuring a more improved design that saved about 30%
in weight from previous designs. This design was
again improved in 1899, for a unit installed in the U.S.
cruiser Alert, establishing the superiority of the water tube boiler for marine propulsion. In this installation, the firing end of the boiler was reversed, placing
the firing door in what had been the rear wall of the
boiler. The furnace was thereby enlarged in the direction in which combustion took place, greatly improving combustion conditions.
The development of marine boilers for naval and
merchant ship propulsion has paralleled that for land
use (see Fig. 16). Throughout the twentieth century
and into the twenty-first, dependable water tube marine boilers have contributed greatly to the excellent performance of naval and commercial ships worldwide.
Bent tube design
The success and widespread use of the inclined
straight tube B&W boiler stimulated other inventors
to explore new ideas. In 1880, Allan Stirling developed
a design connecting the steam generating tubes directly to a steam separating drum and featuring low
headroom above the furnace. The Stirling Boiler Company was formed to manufacture and market an improved Stirling® design, essentially the same as shown
in Fig. 17.
The merits of bent tubes for certain applications
were soon recognized by George Babcock and Stephen
Wilcox, and what had become the Stirling Consolidated Boiler Company in Barberton, Ohio, was purchased by B&W in 1906. After the problems of internal
tube cleaning were solved, the bent tube boiler replaced
the straight tube design. The continuous and economical production of clean, dry steam, even when using poor
quality feedwater, and the ability to meet sudden load
swings were features of the new B&W design.
Electric power
Until the late 1800s, steam was used primarily for
heat and as a tool for industry. Then, with the advent
of practical electric power generation and distribution,
utility companies were formed to serve industrial and
residential users across wide areas. The pioneer stations in the U.S. were the Brush Electric Light Company and the Commonwealth Edison Company. Both
used B&W boilers exclusively.
During the first two decades of the twentieth century, there was an increase in steam pressures and
temperatures to 275 psi (1.9 MPa) and 560F (293C),
with 146F (81C) superheat. In 1921, the North Tess
station of the Newcastle Electric Supply Company in
northern England went into operation with steam at
450 psi (3.1 MPa) and a temperature of 650F (343C).
The steam was reheated to 500F (260C) and regenerative feedwater heating was used to attain a boiler
feedwater temperature of 300F (149C). Three years
later, the Crawford Avenue station of the Commonwealth Edison Company and the Philo and Twin
Stephen Wilcox, Jr.
Stephen Wilcox was born February 12, 1830 at
Westerly, Rhode Island.
The first definite information concerning his engineering activities locates him in Providence,
Rhode Island, about 1849, trying to introduce a
caloric engine. In 1853, in association with Amos
Taylor of Mystic, Connecticut, he patented a letoff
motion for looms. In 1856, a patent for a steam
boiler was issued to Stephen Wilcox and O.M.
Stillman. While this boiler differed materially
from later designs, it is notable as his first recorded step into the field of steam generation.
In 1866 with George Babcock, Wilcox developed
the first B&W boiler, which was patented the following year.
In 1869 he went to New York as selling agent
for the Hope Iron Works and took an active part
in improving the boiler and the building of the
business. He was vice president of The Babcock
& Wilcox Company from its incorporation in 1881
until his death in 1893.
Steam 41 / Introduction to Steam
Intro-7
The Babcock & Wilcox Company
Fig. 15 Thomas Edison’s endorsement, 1888.
Intro-8
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
Branch stations of the present American Electric
Power system were placed in service with steam at 550
psi (38 MPa) and 725F (385C) at the turbine throttle.
The steam was reheated to 700F (371C).
A station designed for much higher steam pressure,
the Weymouth (later named Edgar) station of the Boston Edison Company in Massachusetts, began operation in 1925. The 3150 kW high pressure unit used
steam at 1200 psi (8.3 MPa) and 700F (371C), reheated to 700F (371C) for the main turbines (Fig. 18).
Pulverized coal and water-cooled furnaces
Other major changes in boiler design and fabrication occurred in the 1920s. Previously, as power generating stations increased capacity, they increased the
number of boilers, but attempts were being made to
increase the size of the boilers as well. Soon the size
requirement became such that existing furnace designs and methods of burning coal, primarily stokers,
were no longer adequate.
Pulverized coal was the answer in achieving higher
volumetric combustion rates and increased boiler capacity. This could not have been fully exploited without the use of water-cooled furnaces. Such furnaces
eliminated the problem of rapid deterioration of the
refractory walls due to slag (molten ash). Also, these
designs lowered the temperature of the gases leaving
the furnace and thereby reduced fouling (accumulation of ash) of convection pass heating surfaces to
manageable levels. The first use of pulverized coal in
furnaces of stationary steam boilers had been demonstrated at the Oneida Street plant in Milwaukee,
Wisconsin, in 1918.
Fig. 16 Two drum Integral Furnace marine boiler.
Integral Furnace boiler
Water cooling was applied to existing boiler designs,
with its circulatory system essentially independent of
the boiler steam-water circulation. In the early 1930s,
however, a new concept was developed that arranged
Requirements of a Perfect Steam Boiler – 1875
In 1875, George Babcock and Stephen Wilcox published their conception of the perfect boiler, listing twelve
principles that even today generally represent good design practice:
1st. Proper workmanship and simple construction, using materials which experience has shown to be best,
thus avoiding the necessity of early repairs.
2nd. A mud-drum to receive all impurities deposited
from the water, and so placed as to be removed from
the action of the fire.
3rd. A steam and water capacity sufficient to prevent
any fluctuation in steam pressure or water level.
4th. A water surface for the disengagement of the steam
from the water, of sufficient extent to prevent foaming.
5th. A constant and thorough circulation of water
throughout the boiler, so as to maintain all parts at the
same temperature.
6th. The water space divided into sections so arranged
that, should any section fail, no general explosion can
occur and the destructive effects will be confined to the
escape of the contents. Large and free passages between
Steam 41 / Introduction to Steam
the different sections to equalize the water line and pressure in all.
7th. A great excess of strength over any legitimate
strain, the boiler being so constructed as to be free from
strains due to unequal expansion, and, if possible, to
avoid joints exposed to the direct action of the fire.
8th. A combustion chamber so arranged that the combustion of the gases started in the furnace may be completed before the gases escape to the chimney.
9th. The heating surface as nearly as possible at right
angles to the currents of heated gases, so as to break
up the currents and extract the entire available heat
from the gases.
10th. All parts readily accessible for cleaning and repairs. This is a point of the greatest importance as regards safety and economy.
11th. Proportioned for the work to be done, and capable
of working to its full rated capacity with the highest
economy.
12th. Equipped with the very best gauges, safety valves
and other fixtures.
Intro-9
The Babcock & Wilcox Company
the furnace water-cooled surface and the boiler surface
together, each as an integral part of the unit (Fig. 19).
Shop-assembled water tube boilers
In the late 1940s, the increasing need for industrial
and heating boilers, combined with the increasing costs
of field-assembled equipment, led to development of
the shop-assembled package boiler. These units are
now designed in capacities up to 600,000 lb/h (75.6
kg/s) at pressures up to 1800 psi (12.4 MPa) and temperatures to 1000F (538C).
Fig. 17 Early Stirling® boiler arranged for hand firing.
Further developments
In addition to reducing furnace maintenance and
the fouling of convection heating surfaces, water cooling also helped to generate more steam. Boiler tube
bank surface was reduced because additional steam
generating surface was available in the furnace. Increased feedwater and steam temperatures and increased steam pressures, for greater cycle efficiency,
further reduced boiler tube bank surface and permitted the use of additional superheater surface.
As a result, Radiant boilers for steam pressures above
1800 psi (12.4 MPa) generally consist of furnace water
wall tubes, superheaters, and such heat recovery accessories as economizers and air heaters (Fig. 20). Units for
lower pressures, however, have considerable steam generating surface in tube banks (boiler banks) in addition
to the water-cooled furnace (Fig. 21).
Universal Pressure boilers
An important milestone in producing electricity at
the lowest possible cost took place in 1957. The first
Fig. 18 High pressure reheat boiler, 1925.
Intro-10
Fig. 19 Integral Furnace boiler, 1933.
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
Steam Platen Secondary Secondary
Drum
Superheater
Superheater
Final Reheat
Superheater
Primary
Superheater
Primary
Reheater
Economizer
SCR
Furnace
Catalyst
Air Heater
Pulverizer
Forced Draft Primary Air
Fan
Fan
lations, both bubbling and circulating bed, for reduced
emissions.
Waste-to-energy systems also became a major effort
worldwide. B&W has installed both mass burn and
refuse-derived fuel units to meet this growing demand
for waste disposal and electric power generation. B&W
installed the world’s first waste-to-energy boiler in 1972.
In 2000, an acquisition by Babcock & Wilcox expanded
the company’s capabilities in design and construction of
waste-to-energy and biomass boilers and other multifuel burning plants.
For the paper industry, B&W installed the first
chemical recovery boiler in the U.S. in 1940. Since that
time, B&W has developed a long tradition of firsts in this
industry and has installed one of the largest black liquor
chemical recovery units operating in the world today.
Modified steam cycles
High efficiency cycles involve combinations of gas
turbines and steam power in cogeneration, and direct
thermal to electrical energy conversion. One direct
conversion system includes using conventional fuel or
char byproduct from coal gasification or liquefaction.
Despite many complex cycles devised to increase
overall plant efficiency, the conventional steam cycle
Fig. 20 Typical B&W® Radiant utility boiler.
boiler with steam pressure above the critical value of
3200 psi (22.1 MPa) began commercial operation. This
125 MW B&W Universal Pressure (UP) steam generator (Fig. 22), located at Ohio Power Company’s Philo
plant, delivered 675,000 lb/h (85 kg/s) steam at 4550 psi
(31.4 MPa); the steam was superheated to 1150F (621C)
with two reheats to 1050 and 1000F (566 and 538C).
B&W built and tested its first once-through steam generator for 600 psi (4.1 MPa) in 1916, and built an experimental 5000 psi (34.5 MPa) unit in the late 1920s.
The UP boiler, so named because it can be designed
for subcritical or supercritical operation, is capable of
rapid load pickup. Increases in load rates up to 5% per
minute can be attained.
Fig. 23 shows a typical 1300 MW UP boiler rated
at 9,775,000 lb/h (1232 kg/s) steam at 3845 psi (26.5
MPa) and 1010F (543C) with reheat to 1000F (538C).
In 1987, one of these B&W units, located in West Virginia, achieved 607 days of continuous operation.
Most recently, UP boilers with spiral wound furnaces (SWUP steam generators) have gained wider
acceptance for their on/off cycling capabilities and
their ability to operate at variable pressure with
higher low load power cycle efficiency (see Fig. 24).
Subcritical units, however, remain the dominant
design in the existing worldwide boiler fleet. Coal has
remained the dominant fuel because of its abundant
supply in many countries.
Other fuels and systems
B&W has continued to develop steam generators
that can produce power from an ever widening array
of fuels in an increasingly clean and environmentally
acceptable manner. Landmark developments by B&W
include atmospheric fluidized-bed combustion instalSteam 41 / Introduction to Steam
Fig. 21 Lower pressure Stirling® boiler design.
Intro-11
The Babcock & Wilcox Company
Steam
Separator
Final
Final
Superheater Reheater
Water
Collection Tank
Platen
Superheater
Primary
Superheater
Intermediate
Superheater
Primary
Reheater
Economizer
Catalyst
Spiral
Transition
Headers
Overfire
Air Ports
Low NOX
Burners
Furnace
Ammonia
Injection
Grid
SCR
B&W
Roll Wheel
Pulverizers
Air
Heater
Fig. 22 125 MW B&W® Universal Pressure (UP®) boiler, 1957.
remains the most economical. The increasing use of
high steam pressures and temperatures, reheat superheaters, economizers, and air heaters has led to improved efficiency in the modern steam power cycle.
Nuclear power
Since 1942, when Enrico Fermi demonstrated a controlled self-sustaining reaction, nuclear fission has
been recognized as an important source of heat for
producing steam for power generation. The first significant application of this new source was the landbased prototype reactor for the U.S.S. Nautilus submarine (Fig. 25), operated at the National Reactor
Fig. 23 1300 MW B&W® Universal Pressure (UP®) boiler.
Intro-12
Circulation Forced Steam Coil
Pump
Draft Air Heater
Fan
Flue Primary
Gas
Air
Outlet
Fan
Fig. 24 Boiler with spiral wound universal pressure (SWUP™) furnace.
Testing Station in Idaho in the early 1950s. This prototype reactor, designed by B&W, was also the basis
for land-based pressurized water reactors now being
used for electric power generation worldwide. B&W
and its affiliates have continued their active involvement in both naval and land-based programs.
The first nuclear electric utility installation was the
90 MW unit at the Shippingport atomic power station
in Pennsylvania. This plant, built partly by Duquesne
Light Company and partly by the U.S. Atomic Energy
Commission, began operations in 1957.
Spurred by the trend toward larger unit capacity,
developments in the use of nuclear energy for electric
power reached a milestone in 1967 when, in the U.S.,
nuclear units constituted almost 50% of the 54,000
MW of new capacity ordered that year. Single unit capacity designs have reached 1300 MW. Activity regarding nuclear power was also strong outside the
Fig. 25 U.S.S. Nautilus – world’s first nuclear-powered ship.
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
U.S., especially in Europe. By 2004, there were 103
reactors licensed to operate in the U.S. Fifty of the operating units had net capacities greater than 1000 MW.
Throughout this period, the nuclear power program
in Canada continued to develop based on a design
called the Canada Deuterium Uranium (CANDU)
reactor system. This system is rated high in both availability and dependability. By 2003, there were 21
units in Canada, all with B&W nuclear steam generators, an additional 11 units operating outside of
Canada, and 18 units operating, under construction
or planned that are based on CANDU technology.
The B&W recirculating steam generators in these
units have continually held excellent performance
records and are being ordered to replace aging equipment. (See Fig. 26.)
While the use of nuclear power has remained somewhat steady in the U.S., the future of nuclear power
is uncertain as issues of plant operating safety and longterm waste disposal are still being resolved. However,
nuclear power continues to offer one of the least polluting forms of large-scale power generation available and
may eventually see a resurgence in new construction.
Materials and fabrication
Pressure parts for water tube boilers were originally
made of iron and later of steel. Now, steam drums and
nuclear pressure vessels are fabricated from heavy
steel plates and steel forgings joined by welding. The
development of the steam boiler has been necessarily
concurrent with advances in metallurgy and progressive improvements in the fabrication and welding of
steel and steel alloys.
The cast iron generating tubes used in the first B&W
boilers were later superseded by steel tubes. Shortly
after 1900, B&W developed a commercial process for
the manufacture of hot finished seamless steel boiler
tubes, combining strength and reliability with reasonable cost. In the midst of World War II, B&W completed
a mill to manufacture tubes by the electric resistance
welding (ERW) process. This tubing has now been used
in thousands of steam generating units throughout the
world.
The cast iron tubes used for steam and water storage in the original B&W boilers were soon replaced
by drums. By 1888, drum construction was improved
by changing from wrought iron to steel plates rolled
into cylinders.
Before 1930, riveting was the standard method of
joining boiler drum plates. Drum plate thickness was
limited to about 2.75 in. (70 mm) because no satisfactory method was known to secure a tight joint in
thicker plates. The only alternative available was to
forge and machine a solid ingot of steel into a drum,
which was an extremely expensive process. This
method was only used on boilers operating at what was
then considered high pressure, above 700 psi (4.8 MPa).
The story behind the development of fusion welding was one of intensive research activity beginning
in 1926. Welding techniques had to be improved in
many respects. Equally, if not more important, an acceptable test procedure had to be found and instituted
that would examine the drum without destroying it
Steam 41 / Introduction to Steam
in the test. After extensive investigation of various
testing methods, the medical radiography (x-ray) machine was adapted in 1929 to production examination
of welds. By utilizing both x-ray examination and
physical tests of samples of the weld material, the
soundness of the welds could be determined without
affecting the drum.
In 1930, the U.S. Navy adopted a specification for
construction of welded boiler drums for naval vessels.
In that same year, the first welded drums ever accepted by an engineering authority were part of the
B&W boilers installed in several naval cruisers. Also
in 1930, the Boiler Code Committee of the American
Society of Mechanical Engineers (ASME) issued complete rules and specifications for the fusion welding
of drums for power boilers. In 1931, B&W shipped the
first welded power boiler drum built under this code.
The x-ray examination of welded drums, the rules
declared for the qualification of welders, and the control of welding operations were major first steps in the
development of modern methods of quality control in
the boiler industry. Quality assurance has received
additional stimulus from the naval nuclear propulsion
program and from the U.S. Nuclear Regulatory Commission in connection with the licensing of nuclear
plants for power generation.
Research and development
Since the founding of the partnership of Babcock,
Wilcox and Company in 1867 and continuing to the
present day, research and development have played important roles in B&W’s continuing service to the power
industry. From the initial improvements of Wilcox’s original safety water tube boiler to the first supercritical pressure boilers, and from the first privately operated
nuclear research reactor to today’s advanced environmental systems, innovation and the new ideas of its employees have placed B&W at the forefront of safe, efficient and clean steam generation and energy conversion technology. Today, research and development activities remain an integral part of B&W’s focus on tomorrow’s
product and process requirements.
Fig. 26 B&W replacement recirculating steam generators.
Intro-13
The Babcock & Wilcox Company
A key to the continued success of B&W is the ability to bring together cross-disciplinary research teams
of experts from the many technical specialties in the
steam generation field. These are combined with stateof-the-art test facilities and computer systems.
Expert scientists and engineers use equipment designed specifically for research programs in all aspects
of fossil power development, nuclear steam systems,
materials development and evaluation, and manufacturing technology. Research focuses upon areas of central importance to B&W and steam power generation.
However, partners in these research programs have
grown to include the U.S. Departments of Energy and
Defense, the Environmental Protection Agency, public and private research institutes, state governments,
and electric utilities.
Key areas of current research include environmental protection, fuels and combustion technology, heat
transfer and fluid mechanics, materials and manufacturing technologies, structural analysis and design,
fuels and water chemistry, and measurement and
monitoring technology.
Environmental protection
Environmental protection is a key element in all
modern steam producing systems where low cost
steam and electricity must be produced with minimum
impact on the environment. Air pollution control is a
key issue for all combustion processes, and B&W has
been a leader in this area. Several generations of low
nitrogen oxides (NOx) burners and combustion technology for coal-, oil- and gas-fired systems have been
developed, tested and patented by B&W. Post-combustion NOx reduction has focused on both selective catalytic and non-catalytic reduction systems. Combined
with low NOx burners, these technologies have reduced
NOx levels by up to 95% from historical uncontrolled
levels. Ongoing research and testing are being combined with fundamental studies and computer numerical modeling to produce the ultra-low NOx steam generating systems of tomorrow.
Since the early 1970s, extensive research efforts
have been underway to reduce sulfur dioxide (SO2)
emissions. These efforts have included combustion
modifications and post-combustion removal. Research
during this time aided in the development of B&W’s
wet SO2 scrubbing system. This system has helped control emissions from more than 32,000 MW of boiler capacity. Current research focuses on improved removal
and operational efficiency, and multi-pollution control
technology. B&W has installed more than 9000 MW
of boiler capacity using various dry scrubbing technologies. Major pilot facilities have permitted the testing of in-furnace injection, in-duct injection, and dry
scrubber systems, as well as atomization, gas conditioning and combined SO2, NOx and particulate control. (See Fig. 27.)
Since 1975, B&W has been a leader in fluidizedbed combustion (FBC) technology which offers the
ability to simultaneously control SO2 and NOx formation as an integral part of the combustion process, as
well as burn a variety of waste and other difficult to
combust fuels. This work led to the first large scale (20
Intro-14
Fig. 27 B&W boiler with SO2, NOx, and particulate control systems.
MW) bubbling-bed system installation in the U.S.
B&W’s research and development work has focused
on process optimization, limestone utilization, and performance characteristics of various fuels and sorbents.
Additional areas of ongoing environmental research
include air toxic emissions characterization, efficient
removal of mercury, multi-pollutant emissions control,
and sulfur trioxide (SO3) capture, among others (Fig.
28). B&W also continues to review and evaluate processes to characterize, reuse, and if needed, safely
dispose of solid waste products.
Fuels and combustion technology
A large number of fuels have been used to generate steam. This is even true today as an ever-widening and varied supply of waste and byproduct fuels
such as municipal refuse, coal mine tailings and biomass wastes, join coal, oil and natural gas to meet
steam production needs. These fuels must be burned
and their combustion products successfully handled
while addressing two key trends: 1) declining fuel
quality (lower heating value and poorer combustion),
and 2) more restrictive emissions limits.
Major strengths of B&W and its work in research
and development have been: 1) the characterization
of fuels and their ashes, 2) combustion of difficult fuels, and 3) effective heat recovery from the products
of combustion. (See Fig. 29.) B&W has earned interSteam 41 / Introduction to Steam
The Babcock & Wilcox Company
simulator (Fig. 30) permits a simulation of the timetemperature history of the entire combustion process.
The subsystems include a vertical test furnace; fuel
subsystem for pulverizing, collecting and firing solid
fuels; fuel storage and feeding; emission control modules; gas and stack particulate analyzers for O2, CO,
CO2 and NOx; and instrumentation for solids grinding characterization.
Research continues in the areas of gas-side corrosion, boiler fouling and cleaning characteristics, advanced pulp and paper black liquor combustion, oxygen and oxygen enhanced firing systems, and coal gasification, among others.
Fig. 28 Tests for multi-pollutant emissions control.
national recognition for its fuels analysis capabilities
that are based upon generally accepted procedures,
as well as specialized B&W procedures. Detailed
analyses include, but are not limited to: heating value,
chemical constituents, grindability, abrasion resistance, erosiveness, ignition, combustion characteristics, ash composition/viscosity/fusion temperature, and
particle size. The results of these tests assist in pulverizer specification and design, internal boiler dimension selection, efficiency calculations, predicted unit
availability, ash removal system design, sootblower
placement, and precipitator performance evaluation.
Thousands of coal and ash samples have been analyzed and catalogued, forming part of the basis for
B&W’s design methods.
Combustion and fuel preparation facilities are
maintained that can test a broad range of fuels at
large scale. The 6 × 106 Btu/h (1.8 MWt) small boiler
Fig. 29 Atomic absorption test for ash composition.
Steam 41 / Introduction to Steam
Heat transfer and fluid dynamics
Heat transfer is a critical technology in the design
of steam generation equipment. For many years, B&W
has been conducting heat transfer research from hot
gases to tube walls and from the tube walls to enclosed
water, steam and air. Early in the 1950s, research in
heat transfer and fluid mechanics was initiated in the
supercritical pressure region above 3200 psi (22.1
MPa). This work was the technical foundation for the
large number of supercritical pressure once-through
steam generators currently in service in the electric
power industry.
A key advancement in steam-water flow was the
invention of the ribbed tube, patented by B&W in
1960. By preventing deterioration of heat transfer
under many flow conditions (called critical heat flux
or departure from nucleate boiling), the internally
ribbed tube made possible the use of natural circulation boilers at virtually all pressures up to the critical
point. Extensive experimental studies have provided
the critical heat flux data necessary for the design of
boilers with both ribbed and smooth bore tubes.
Fig. 30 B&W’s small boiler simulator.
Intro-15
The Babcock & Wilcox Company
Closely related to heat transfer, and of equal importance in steam generating equipment, is fluid mechanics. Both low pressure fluids (air and gas in ducts
and flues) and high pressure fluids (water, steamwater mixtures, steam and fuel oil) must be investigated. The theories of single-phase fluid flow are well
understood, but the application of theory to the complex, irregular and multiple parallel path geometry of
practical situations is often difficult and sometimes
impossible. In these cases, analytical procedures must
be supplemented or replaced by experimental methods. If reliable extrapolations are possible, economical modeling techniques can be used. Where extrapolation is not feasible, large-scale testing at full pressure, temperature and flow rate is needed.
Advances in numerical modeling technology have
made possible the evaluation of the complex three-dimensional flow, heat transfer and combustion processes in coal-fired boiler furnaces. B&W is a leader
in the development of numerical computational models to evaluate the combustion of coal, biomass, black
liquor and other fuels that have a discrete phase, and
the application of these models to full boiler and system analysis (Fig. 31). Continuing development and
validation of these models will enhance new boiler
designs and expand applications. These models are
also valuable tools in the design and evaluation of combustion processes, pollutant formation, and environmental control equipment.
Research, analytical and field test studies in boiling heat transfer, two-phase flow, and stability, among
other key areas, continue today by B&W alone and
in cooperation with a range of world class organizations.
Materials and manufacturing technologies
Because advanced steam producing and energy
conversion systems require the application and fabrication of a wide variety of carbon, alloy and stainless
steels, nonferrous metals, and nonmetallic materials,
it is essential that experienced metallurgical and materials science personnel are equipped with the finest
investigative tools. Areas of primary interest in the
metallurgical field are fabrication processes such as
welding, room temperature and high temperature material properties, resistance to corrosion properties,
wear resistance properties, robotic welding, and
changes in such material properties under various
operating conditions. Development of oxidation-resistant alloys that retain strength at high temperature,
and determination of short-term and long-term high
temperature properties permitted the increase in
steam temperature that has been and continues to be
of critical importance in increasing power plant efficiency and reducing the cost of producing electricity.
Advancements in manufacturing have included a
process to manufacture large pressure components
entirely from weld wire, designing a unique manu-
Intro-16
Fig. 31 B&W has developed advanced computational numerical models
to evaluate complex flow, heat transfer and combustion processes.
facturing process for bi-metallic tubing, using pressure
forming to produce metallic heat exchangers, developing air blown ultra-high temperature fibrous insulation, and combining sensor and control capabilities
to improve quality and productivity of manufacturing processes.
Research and development activities also include
the study of materials processing, joining processes,
process metallurgy, analytical and physical metallurgical examination, and mechanical testing. The results
are subsequently applied to product improvement.
Structural analysis and design
The complex geometries and high stresses under
which metals must serve in many products require
careful study to allow prediction of stress distribution
and intensity. Applied mechanics, a discipline with
highly sophisticated analytical and experimental techniques, can provide designers with calculation methods and other information to assure the safety of structures and reduce costs by eliminating unnecessarily
conservative design practices. The analytical techniques
involve advanced mathematical procedures and computational tools as well as the use of advanced computers.
An array of experimental tools and techniques are used
to supplement these powerful analytical techniques.
Computational finite element analysis has largely
displaced experimental measurement for establishing
detailed local stress relationships. B&W has developed
and applied some of the most advanced computer programs in the design of components for the power industry. Advanced techniques permit the evaluation of
stresses resulting from component response to thermal and mechanical (including vibratory) loading.
Fracture mechanics, the evaluation of crack formation and growth, is an important area where analytical techniques and new experimental methods permit
a better understanding of failure modes and the pre-
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
diction of remaining component life. This branch of
technology has contributed to the feasibility and safety
of advanced designs in many types of equipment.
To provide part of the basis for these models, extensive computer-controlled experimental facilities allow the
assessment of mechanical properties for materials under environments similar to those in which they will
operate. Some of the evaluations include tensile and
impact testing, fatigue and corrosion fatigue, fracture
toughness, as well as environmentally assisted cracking.
Fuel and water chemistry
Chemistry plays an important role in supporting the
effective operation of steam generating systems.
Therefore, diversified chemistry capabilities are essential to support research, development and engineering. The design and operation of fuel burning equipment must be supported by expert analysis of a wide
variety of solid, liquid and gaseous fuels and their
products of combustion, and characterization of their
behavior under various conditions. Long-term operation of steam generating equipment requires extensive water programs including high purity water
analysis, water treatment and water purification.
Equipment must also be chemically cleaned at intervals to remove water-side deposits.
To develop customized programs to meet specific
needs, B&W maintains a leadership position in these
areas through an expert staff for fuels characterization, water chemistry and chemical cleaning. Studies
focus on water treatment, production and measurement
of ultra-high purity water (parts per billion), water-side
deposit analysis, and corrosion product transport.
B&W was involved in the introduction of oxygen
water treatment for U.S. utility applications. Specialized chemical cleaning evaluations are conducted to
prepare cleaning programs for utility boilers, industrial boilers and nuclear steam generators. Special
analyses are frequently required to develop boiler-specific cleaning solvent solutions that will remove the
desired deposits without damaging the equipment.
Steam 41 / Introduction to Steam
Measurements and monitoring technology
Development, evaluation and accurate assessment
of modern power systems require increasingly precise
measurements in difficult to reach locations, often in
hostile environments. To meet these demanding
needs, B&W continues the investigation of specialized
sensors, measurement and nondestructive examination. B&W continues to develop diagnostic methods
that lead to advanced systems for burner and combustion systems as well as boiler condition assessment.
These techniques have been used to aid in laboratory research such as void fraction measurements for
steam-water flows. They have also been applied to
operating steam generating systems. New methods
have been introduced by B&W to nondestructively
measure oxide thicknesses on the inside of boiler
tubes, detect hydrogen damage, and detect and measure corrosion fatigue cracks. Acoustic pyrometry systems have been introduced by B&W to nonintrusively
measure high temperature gases in boiler furnaces.
Steam/its generation and use
This updated and expanded edition provides a broad,
in-depth look at steam generating technology and equipment, including related auxiliaries that are of interest to
engineers and students in the steam power industry. The
reader will find discussions of the fundamental technologies such as thermodynamics, fluid mechanics, heat transfer, solid mechanics, numerical and computational methods, materials science and fuels science. The various components of the steam generating equipment, plus their
integration and performance evaluation, are covered in
depth. Extensive additions and updates have been made
to the chapters covering environmental control technologies and numerical modeling. Key elements of the balance of the steam generating system life including operation, condition assessment, maintenance, and retrofits are
also discussed.
Intro-17
The Babcock & Wilcox Company
Intro-18
Steam 41 / Introduction to Steam
The Babcock & Wilcox Company
Selected Color Plates — Edition: 41
Steam 41
The Babcock & Wilcox Company
Vertical
Steam Separators
Platen
Superheater
Intermediate
Superheater
Primary Superheater
Final
Superheater
Primary Reheater
Final
Reheater
Economizer
Furnace
Overfire
Air Ports
SCR
Low NOX
Burners
Trisector
Air Heater
B&W Roll Wheel
Pulverizers
Circulation
Pump
Axial Forced
Draft Fan
Primary Air
Fan
B&W supercritical boiler with spiral wound Universal Pressure (SWUP™) furnace.
Steam 41 / Selected Color Plates
Plate 1
The Babcock & Wilcox Company
Steam Drum
Reheat
Superheater
Platen
Secondary
Superheater
Primary
Superheater
Secondary
Superheater
Economizer
Wing
Walls
Furnace
Overfire
Air Ports
SCR
Low NOx
Burners
Trisector
Air Heater
B&W Roll Wheel
Pulverizers
Forced
Draft Fans
Primary
Air Fans
Carolina-type 550 MW Radiant boiler for pulverized coal.
Plate 2
Steam 41 / Selected Color Plates
The Babcock & Wilcox Company
Large coal- and oil-fired two-drum Stirling® power boiler for industry, 885,000 lb/h (112 kg/s) steam flow.
Steam 41 / Selected Color Plates
Plate 3
The Babcock & Wilcox Company
Single-drum chemical recovery boiler for the pulp and paper industry.
Plate 4
Steam 41 / Selected Color Plates
The Babcock & Wilcox Company
U-Beams
Steam
Drum
Superheater
Wing Wall
Internal
Evaporative
Circuit
Coal
Silo
Economizer
Dust
Collector
Furnace
Tubular
Air Heater
Bottom
Ash Cooler
Startup
Burner
Secondary
Air
Primary
Air
Forced Draft
Fan
Coal-fired circulating fluidized-bed combustion steam generator.
Steam 41 / Selected Color Plates
Plate 5
The Babcock & Wilcox Company
Wet flue gas desulfurization scrubber module for sulfur dioxide control.
Plate 6
Steam 41 / Selected Color Plates
The Babcock & Wilcox Company
Inlet Flue
Gas (Upper)
Rotary
Atomizer
Central
Gas
Disperser
To
Particulate
Collection
Inlet Flue
Gas (Lower)
Outlet
Poppet
Damper
Pulse Air
Blowpipe
Pulse Air
Header
Outlet
Manifold
Tubesheet
Filter Bag
with
Internal
Cage
Inlet
Manifold
Inlet
Louver
Damper
Dry flue gas desulfurization spray dryer absorber for sulfur dioxide control (upper left) and fabric filter baghouse for particulate control (lower right).
Steam 41 / Selected Color Plates
Plate 7
Plate 8
B&W Roll Wheel
Pulverizers
Steam
Drum
Furnace
Platen
Secondary
Superheater
Primary
Air Fan
Intermediate
Secondary
Superheater
Air
Heater
SCR
Forced
Draft Fan
Economizer
Primary
Superheater
Final Secondary
Superheater
Reheat
Superheater
Precipitator
Induced
Draft Fan
Stack
Absorber
The Babcock & Wilcox Company
Modern 660 MW coal-fired utility boiler system with environmental control equipment.
Steam 41 / Selected Color Plates
The Babcock & Wilcox Company
Section I
Steam Fundamentals
Steam is uniquely adapted, by its availability and advantageous properties,
for use in industrial and heating processes and in power cycles. The fundamentals of the steam generating process and the core technologies upon which
performance and equipment design are based are described in this section of
eight chapters. Chapter 1 provides an initial overview of the process, equipment and design of steam generating systems, and how they interface with
other processes that produce power and use steam. This is followed by fundamental discussions of thermodynamics, fluid dynamics, heat transfer, and the
complexities of boiling and steam-water flow in Chapters 2 through 5. New
Chapter 6 is dedicated to exploring the dramatic increase in the use of advanced
computational numerical analysis in the design of modern steam generators.
The section concludes with Chapters 7 and 8 discussing key elements of material science and structural analysis that permit the safe and efficient design of
the steam generating units and components.
Steam 41
The Babcock & Wilcox Company
Chapter 1
Steam Generation – An Overview
Steam generators, or boilers, use heat to convert
water into steam for a variety of applications. Primary
among these are electric power generation and industrial process heating. Steam is a key resource because
of its wide availability, advantageous properties and
nontoxic nature. Steam flow rates and operating conditions are the principal design considerations for any
steam generator and can vary dramatically: from 1000
lb/h (0.1 kg/s) in one process use to more than 10 million lb/h (1260 kg/s) in large electric power plants; from
about 14.7 psi (0.1013 MPa) and 212F (100C) in some
heating applications to more than 4500 psi (31.03 MPa)
and 1100F (593C) in advanced cycle power plants.
Fuel use and handling add to the complexity and
variety of steam generating systems. The fuels used
in most steam generators are coal, natural gas and oil.
However, nuclear energy also plays a major role in at
least the electric power generation area. Also, an increasing variety of biomass materials and process
byproducts have become heat sources for steam generation. These include peat, wood and wood wastes,
bagasse, straw, coffee grounds, corn husks, coal mine
wastes (culm), and waste heat from steelmaking furnaces. Even renewable energy sources, e.g., solar, are
being used to generate steam. The steam generating
process has also been adapted to incorporate functions
such as chemical recovery from paper pulping processes, volume reduction for municipal solid waste or
trash, and hazardous waste destruction.
Steam generators designed to accomplish these
tasks range from a small package boiler (Fig. 1) to
large, high capacity utility boilers used to generate
1300 MW of electricity (Fig. 2). The former is a factory-assembled, fully-automated, gas-fired boiler,
which can supply saturated steam for a large building, perhaps for a hospital. It arrives at the site with
all controls and equipment assembled. The large fielderected utility boiler will produce more than 10 million lb/h (1260 kg/s) steam at 3860 psi (26.62 MPa)
and 1010F (543C). Such a unit, or its companion
nuclear option (Fig. 3), is part of some of the most complex and demanding engineering systems in operation today. Other examples, illustrating the range of
combustion systems, are shown by the 750 t/d (680
tm/d) mass-fired refuse power boiler in Fig. 4 and the
circulating fluidized-bed combustion boiler in Fig. 5.
The central job of the boiler designer in any of these
Steam 41 / Steam Generation – An Overview
applications is to combine fundamental science, technology, empirical data, and practical experience to
produce a steam generating system that meets the
steam supply requirements in the most economical
package. Other factors in the design process include
fuel characteristics, environmental protection, thermal
efficiency, operations, maintenance and operating
costs, regulatory requirements, and local geographic
and weather conditions, among others. The design
process involves balancing these complex and sometimes competing factors. For example, the reduction
of pollutants such as nitrogen oxides (NOx) may require a larger boiler volume, increasing capital costs
and potentially increasing maintenance costs. Such
a design activity is firmly based upon the physical and
thermal sciences such as solid mechanics, thermodynamics, heat transfer, fluid mechanics and materials
science. However, the real world is so complex and
variable, and so interrelated, that it is only by applying the art of boiler design to combine science and
practice that the most economical and dependable
design can be achieved.
Steam generator design must also strive to address
in advance the many changes occurring in the world
to provide the best possible option. Fuel prices are
expected to escalate while fuel supplies become less
certain, thereby enforcing the need for continued efficiency improvement and fuel flexibility. Increased
environmental protection will drive improvements in
combustion to reduce NOx and in efficiency to reduce
carbon dioxide (CO2) emissions. Demand growth continues in many areas where steam generator load
Fig. 1 Small shop-assembled package boiler.
1-1
The Babcock & Wilcox Company
power plant thermal efficiency. Also, modularization
and further standardization will help reduce fabrication and erection schedules to meet more dynamic
capacity addition needs.
Steam generation fundamentals
Boiling
The process of boiling water to make steam is a familiar phenomenon. Thermodynamically, instead of
increasing the water temperature, the energy used
results in a change of phase from a liquid to a gaseous
state, i.e., water to steam. A steam generating system
should provide a continuous process for this conversion.
The simplest case for such a device is a kettle boiler
where a fixed quantity of water is heated (Fig. 6). The
applied heat raises the water temperature. Eventually, for the given pressure, the boiling (saturation)
temperature is reached and bubbles begin to form. As
heat continues to be applied, the temperature remains
constant, and steam escapes from the water surface.
If the steam is continuously removed from the vessel,
the temperature will remain constant until all of the
water is evaporated. At this point, heat addition would
increase the temperature of the kettle and of any
steam remaining in the vessel. To provide a continuous process, all that is needed is a regulated supply of
water to the vessel to equal the steam being generated and removed.
Technical and economic factors indicate that the most
effective way to produce high pressure steam is to heat
relatively small diameter tubes containing a continuous
flow of water. Regardless of whether the energy source
is nuclear or fossil fuel, two distinct boiling systems are
Fig. 2 1300 MW coal-fired utility steam generator.
may have to cycle up and down more frequently and
at a faster rate.
There are technologies such as pressurized fluidized-bed combustion and integrated gasification combined cycle systems, plus others, which actually integrate the environmental control with the entire steam
generation process to reduce emissions and increase
Fig. 3 900 MW nuclear power system.
1-2
Fig. 4 Babcock & Wilcox 750 ton per day mass-fired refuse power
boiler.
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
used to accomplish this task: those that include a steam
drum (see Fig. 7a), or fixed steam-water separation point,
and those that do not (see Fig. 7b), termed once-through
steam generators (OTSG).
The most common and simplest to control is the
steam drum system. In this system, the drum serves
as the point of separation of steam from water
throughout its boiler’s load range. Subcooled water
(less than boiling temperature) enters the tube to
which heat is applied. As the water flows through the
tube, it is heated to the boiling point, bubbles are
formed, and wet steam is generated. In most boilers,
a steam-water mixture leaves the tube and enters the
steam drum, where steam is separated from water. The
remaining water is then mixed with the replacement
water and returned to the heated tube.
Without a steam drum, i.e., for an OTSG system,
subcooled water also enters the tube to which heat is
applied, but the flowing water turns into steam somewhere along the flow path (length of tube), dependent
upon water flow rate (boiler load) and heat input rates.
Shown in Fig. 7b, the flow rate and heat input are
closely controlled and coordinated so that all of the
water is evaporated and only steam leaves the tube.
There is no need for the steam drum (fixed steamwater separation point).
Circulation
For both types of boiling systems described above,
water must continuously pass through, or circulate
through, the tubes for the system to generate steam
continuously. For an OTSG, water makes one pass
through the boiler’s tubes before becoming steam to
be sent to the turbine-generator. However, for those
boilers with a fixed steam-water separation point or
steam drum, a molecule of water can make many
passes through a circulation loop before it leaves as
In-Furnace
U-Beams
Fig. 6 Simple kettle boiler.
steam to the turbine-generator. Options for this latter system are shown in Fig. 8.
Two different approaches to circulation are commonly
used: natural or thermal circulation, and forced or
pumped circulation. Natural circulation is illustrated
in Fig. 8a. In the downcomer, unheated tube segment
A-B, no steam is present. Heat addition generates a
steam-water mixture in segment B-C. Because the
steam and steam-water mixture in segment B-C are less
dense than the water segment A-B, gravity will cause
the water to flow downward in segment A-B and will
External
U-Beams
Superheater
Steam Drum
Feedwater
to Drum
Downcomer
Internal
Evaporative
Circuit
Multi-Cyclone
Dust
Collector
Wing Wall
Fuel Bunker
Economizer
Ash
Recycle
System
Air
Heater
Gravimetric
Feeder
Fuel
Chute
Flue
Gas
Refractory
Line
Fluid Bed
Cooler
Secondary Primary
Air Duct to
Steam Coil
Air Duct Air Duct Fluid Bed Cooler Air Heater
Fig. 5 Coal-fired circulating fluidized-bed combustion steam generator.
Steam 41 / Steam Generation – An Overview
Fig. 7 Boiling process in tubular geometries.
1-3
The Babcock & Wilcox Company
Fig. 8 Simple circulation systems.
cause the steam-water mixture (B-C) to move upward
into the steam drum. The rate of water flow or circulation depends upon the difference in average density between the unheated water and the heated steam-water mixture.
The total circulation rate in a natural circulation
system depends primarily upon four factors: 1) the height
of the boiler, 2) the operating pressure, 3) the heat input rate, and 4) the free flow areas of the components.
Taller boilers result in a larger total pressure difference
between the heated and unheated legs and therefore can
produce larger total flow rates. Higher operating pressures provide higher density steam and higher density
steam-water mixtures. This reduces the total weight difference between the heated and unheated segments and
tends to reduce flow rate. Higher heat input typically
increases the amount of steam in the heated segments
and reduces the average density of the steam-water
mixture, increasing total flow rate. An increase in the
cross-sectional (free flow) areas for the water or steamwater mixtures may increase the circulation rate. For
each unit of steam produced, the amount of water entering the tube can vary from 3 to 25 units.
Forced or pumped circulation is illustrated in Fig.
8b. A mechanical pump is added to the simple flow loop
and the pressure difference created by the pump controls the water flow rate.
The steam-water separation in the drum requires
careful consideration. In small, low pressure boilers,
steam-water separation can be easily accomplished
with a large drum approximately half full of water.
Natural gravity steam-water separation (similar to a
kettle) can be sufficient. However, in today’s high ca1-4
pacity, high pressure units, mechanical steam-water
separators are needed to economically provide moisture-free steam from the drum. With such devices installed in the drum, the vessel diameter and cost can
be significantly reduced.
At very high pressures, a point is reached where
water no longer exhibits boiling behavior. Above this
critical pressure [3200.11 psi (22.1 MPa)], the water
temperature continuously increases with heat addition. Steam generators can be designed to operate at
pressures above this critical pressure. Drums and
steam-water separation are no longer required and
the steam generator operates effectively on the oncethrough principle.
There are a large number of design methods used to
evaluate the expected flow rate for a specific steam
generator design and set of operating conditions. In
addition, there are several criteria which establish the
minimum required flow rate and maximum allowable
steam content or quality in individual tubes, as well as
the maximum allowable flow rates for the steam drum.
System arrangement and key components
Most applications of steam generators involve the
production of electricity or the supply of process steam.
In some cases, a combination of the two applications,
called cogeneration, is used. In each application, the
steam generator is a major part of a larger system that
has many subsystems and components. Fig. 9 shows a
modern coal-fired power generating facility; Fig. 10
identifies the major subsystems. Key subsystems include fuel receiving and preparation, steam generator
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
and combustion, environmental protection, turbinegenerator, and heat rejection including cooling tower.
First, follow the fuel and products of combustion
(flue gas) through the system. The fuel handling system stores the fuel supply (coal in this example), prepares the fuel for combustion and transports it to the
steam generator. The associated air system supplies
air to the burners through a forced draft fan. The
steam generator subsystem, which includes the air
heater, burns the fuel-air mixture, recovers the heat,
and generates the controlled high pressure and high
temperature steam. The flue gas leaves the steam
generator subsystem and selective catalytic reduction
(SCR) system if supplied, then passes through particulate collection and sulfur dioxide (SO2) scrubbing systems where pollutants are collected and the ash and solid
scrubber residue are removed. The remaining flue gas
is then sent to the stack through an induced draft fan.
Next, follow the steam-water path. The steam generator (boiler) evaporates water and supplies high
temperature, high pressure steam, under carefully
controlled conditions, to a turbine-generator set that
produces the electricity. The steam may also be reheated in the steam generator, after passing through
part of a multi-stage turbine system, by running the
exhaust steam back to the boiler convection pass
(reheater not shown). Ultimately, the steam is passed
from the turbine to the condenser where the remaining waste heat is rejected. Before the water from the
condenser is returned to the boiler, it passes through
several pumps and heat exchangers (feedwater heaters) to increase its pressure and temperature. The heat
absorbed by the condenser is eventually rejected to the
atmosphere by one or more cooling towers. These cool-
Electricity
Fig. 9 Coal-fired utility power plant.
ing towers are perhaps the most visible component in
the power system (Fig. 9). The natural draft cooling
tower shown is basically a hollow cylindrical structure
which circulates air and moisture to absorb the heat
rejected by the condenser. Such cooling towers exist
at most modern power plant sites, both nuclear- and
fossil fuel-fired.
For an industrial power system, many of the same
features are needed. However, the turbine-generator
and heat rejection portions are replaced by the process application, such as radiant space heaters or heat
exchangers.
In a nuclear power system (Fig. 11), the fossil fuelfired steam generator is replaced by a nuclear reactor
vessel and, typically, two or more steam generators. The
coal handling system is replaced by a nuclear reactor
fuel bundle handling and storage facility, and the large
scale air pollution control equipment is not needed.
Steam
Stack
Boiler
Water
from
Heaters
SCR
Substation
Transformer
Particulate
Collector
Air
Cooling
Tower
Makeup
Pumps
Air
Heater
Combustion Air
TurbineGenerator
Fuel
Condenser
Primary
Air Fan
Induced
Draft
Fan
Forced
Draft Fan
Water
to
Boiler
Pumps
Condensate
Pump
Low Pressure
Heaters
SO2
Scrubber
Feed
Pump
High Pressure
Heaters
(Not Shown: Reheater, Ash and Reagent Handling and Sludge Disposal)
Coal
Pulverization
Coal
Supply
Fig. 10 Coal-fired utility power plant schematic.
Steam 41 / Steam Generation – An Overview
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The Babcock & Wilcox Company
Fig. 11 Nuclear power plant schematic.
Fossil steam generator classifications
Modern steam generating systems can be classified
by various criteria. These include end use, firing method,
operating pressure, fuel, and circulation method.
Utility steam generators are used primarily to generate electricity in large central power stations. They
are designed to optimize overall thermodynamic efficiency at the highest possible availability. New units
are typically characterized by large, main steam flow
rates with superheated steam outlet pressures from
1800 to 3860 psi (12.41 to 26.62 MPa) with steam temperatures at or above 1050F (566C). A key characteristic of newer units is the use of a reheater section to
increase overall cycle efficiency.
Industrial steam generators generally supply steam
to processes or manufacturing activities and are designed with particular attention to: 1) process controlled (usually lower) pressures, 2) high reliability
with minimum maintenance, 3) use of one or more
locally inexpensive fuels, especially process
byproducts or wastes, and 4) low initial capital and
minimum operating costs. On a capacity basis, the
larger users of such industrial units are the pulp and
paper industry, municipal solid waste reduction industry, food processing industry, petroleum/petrochemical industry, independent power producers and
cogenerators, and some large manufacturing operations. Operating pressures range from 150 to 1800 psi
(1.04 to 12.41 MPa) with saturated or superheated
steam conditions.
Impact of energy source
The primary fuel selected has perhaps the most significant impact on the steam generator system configuration and design. In the case of nuclear energy,
a truly unique system for containing the fuel and the
nuclear reaction products has been developed with an
1-6
intense focus on safety and protecting the public from
radiation exposure. Acceptable materials performance
in the radiative environment and the long term thermal-hydraulic and mechanical performance are central to system design. When fossil, biomass, or
byproduct fuels are burned, widely differing provisions must be made for fuel handling and preparation, fuel combustion, heat recovery, fouling of heat
transfer surfaces, corrosion of materials, and emissions
control. For example, in a natural gas-fired unit
(Fig.12), there is minimal need for fuel storage and
handling. Only a small furnace is needed for combustion, and closely spaced heat transfer surfaces may be
used because of lack of ash deposits (fouling). The corrosion allowance is relatively small and the emissions
control function is primarily for NOx formed during the
combustion process. The result is a relatively small,
compact and economical design.
If a solid fuel such as coal (which has a significant
level of noncombustible ash) is used, the overall system is much more complex. This system could include
extensive fuel handling and preparation facilities, a
much larger furnace, and more widely spaced heat
transfer surfaces. Additional components could be special cleaning equipment to reduce the impact of fouling
and erosion, air preheating to dry the fuel and enhance
combustion, more extensive environmental equipment,
and equipment to collect and remove solid wastes.
The impact of fuel alone on a utility boiler design is
clearly indicated in Fig. 12, where both steam generators produce the same steam flow rate. Further adding to the size and cost difference, but not shown, are
the facts that the coal-fired boiler will be wider (dimension not shown) and will require more flue gas
cleanup equipment to meet emissions requirements.
The particular challenge when burning different solid
fuels is indicated in Fig. 13, where provision is made for
burning both pulverized (finely ground) coal using the
burners and for wood chips and bark which are burned
on the moving grate (stoker) at the bottom of the unit.
Impact of steam conditions
The steam temperature and pressure for different
boiler applications can have a significant impact on
design. Fig. 14 identifies several typical boiler types,
as well as the relative amount of heat input needed,
for water heating, evaporation (boiling), superheating, and reheating, if required. The relative amount
of energy needed for evaporation is dramatically reduced as operating pressure is increased. As a result, the
relative amount of physical heat transfer surface (tubes)
dedicated to each function can be dramatically different.
Fossil fuel systems
Fossil fuel steam generator components
Modern steam generators are a complex configuration of thermal-hydraulic (steam and water) sections
which preheat and evaporate water, and superheat
steam. These surfaces are arranged so that: 1) the fuel
can be burned completely and efficiently while minimizing emissions, 2) the steam is generated at the
required flow rate, pressure and temperature, and 3)
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
Fig. 12 Comparison of gas- and coal-fired steam generators.
the maximum amount of energy is recovered. A relatively simple coal-fired utility boiler is illustrated in
Fig. 15. The major components in the steam generating and heat recovery system include:
1.
2.
3.
4.
5.
6.
7.
8.
furnace and convection pass,
steam superheaters (primary and secondary),
steam reheater,
boiler or steam generating bank (industrial units
only),
economizer,
steam drum,
attemperator and steam temperature control system, and
air heater.
These components are supported by a number of subsystems and pieces of equipment such as coal pulverizers, combustion system, flues, ducts, fans, gas-side
cleaning equipment and ash removal equipment.
The furnace is a large enclosed open space for fuel
combustion and for cooling of the flue gas before it
enters the convection pass. Excessive gas temperatures leaving the furnace and entering the tube
bundles could cause particle accumulation on the tubes
or excessive tube metal temperatures. The specific
geometry and dimensions of the furnace are highly
influenced by the fuel and type of combustion equipment. In this case, finely ground or pulverized coal is
blown into the furnace where it burns in suspension.
The products of combustion then rise through the
upper furnace. The superheater, reheater and economizer surfaces are typically located in the flue gas
horizontal and vertical downflow sections of the boiler
enclosure, called the convection pass.
In modern steam generators, the furnace and convection pass walls are composed of steam- or watercooled carbon steel or low alloy tubes to maintain wall
Steam 41 / Steam Generation – An Overview
metal temperatures within acceptable limits. These
tubes are connected at the top and bottom by headers, or manifolds. These headers distribute or collect
the water, steam or steam-water mixture. The furnace
wall tubes in most modern units also serve as key
steam generating components or surfaces. The tubes
are welded together with steel bars to provide membrane wall panels which are gas-tight, continuous and
rigid. The tubes are usually prefabricated into shippable membrane panels with openings for burners,
observation doors, sootblowers (boiler gas-side surface
cleaning equipment) and gas injection ports.
Superheaters and reheaters are specially designed
in-line tube bundles that increase the temperature of
saturated steam. In general terms, they are simple
single-phase heat exchangers with steam flowing inside the tubes and the flue gas passing outside, generally in crossflow. These critical components are
manufactured from steel alloy material because of
their high operating temperature. They are typically
configured to help control steam outlet temperatures,
keep metal temperatures within acceptable limits, and
control steam flow pressure loss.
The main difference between superheaters and
reheaters is the steam pressure. In a typical drum
boiler, the superheater outlet pressure might be 2700
psi (18.62 MPa) while the reheater outlet might be
only 580 psi (4.0 MPa). The physical design and location of the surfaces depend upon the desired outlet
temperatures, heat absorption, fuel ash characteristics and cleaning equipment. These surfaces can be
either horizontal or vertical as shown. The superheater and sometimes reheater are often divided into
multiple sections to help control steam temperature
and optimize heat recovery.
The heat transfer surface in the furnace may not
be sufficient to generate enough saturated steam for
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The Babcock & Wilcox Company
Fig. 13 Large industrial boiler with multiple fuel capability.
the particular end use. If this is the case, an additional
bank of heat exchanger tubes called the boiler bank
or steam generating bank is added. (See Fig. 13.) This
is needed on many smaller, low pressure industrial
boilers, but is not often needed in high pressure utility boilers. This boiler bank is typically composed of
the steam drum on top, a second drum on the bottom,
and a series of bent connecting tubes. The steam drum
internals and tube sizes are arranged so that subcooled
water travels down the tubes (farthest from the furnace) into the lower drum. The water is then distributed to the other tubes where it is partially converted
to steam and returned to the steam drum. The lower
drum is often called the mud drum because this is
where sediments found in the boiler water tend to
settle out and collect.
The economizer is a counterflow heat exchanger for
recovering energy from the flue gas beyond the superheater and, if used, the reheater. It increases the
temperature of the water entering the steam drum.
The tube bundle is typically an arrangement of parallel horizontal serpentine tubes with the water flowing inside but in the opposite direction (counterflow)
to the flue gas. Tube spacing is as tight as possible to
promote heat transfer while still permitting adequate
tube surface cleaning and limiting flue gas-side pressure loss. By design, steam is usually not generated
inside these tubes.
The steam drum is a large cylindrical vessel at the
top of the boiler, in which saturated steam is separated
from the steam-water mixture leaving the boiler tubes.
Drums can be quite large with diameters of 3 to 6 ft
1-8
(0.9 to 1.8 m) and lengths approaching 100 ft (30.5
m). They are fabricated from thick steel plates rolled
into cylinders with hemispherical heads. They house
the steam-water separation equipment, purify the
steam, mix the replacement or feedwater and chemicals, and provide limited water storage to accommodate
small changes in unit load. Major connections to the
steam drum are provided to receive the steam-water mixture from the boiler tubes, remove saturated steam, add
replacement or makeup water, and return the near saturated water back to the inlet of the boiler tubes.
The steam temperature control system can be complex and include combinations of recirculating some of
the flue gas to the bottom or top of the furnace, providing special gas flow passages at the back end of the
steam generator, adjusting the combustion system, and
adding water or low temperature steam to the high
temperature steam flow (attemperation). The component most frequently used for the latter is called a spray
attemperator. In large utility units, attemperators with
direct injection of water or low temperature steam are
used for dynamic control because of their rapid response. They are specially designed to resist thermal
shock and are frequently located at the inlet of the superheater or between superheater sections to better
control the superheater outlet metal temperatures.
Positioning of individual superheater sections can also
help maintain proper outlet steam temperatures.
The air heater is not a portion of the steam-water
circuitry, but serves a key role in the steam generator
system heat transfer and efficiency. In many cases,
especially in high pressure boilers, the temperature
of the flue gas leaving the economizer is still quite
high. The air heater recovers much of this energy and
adds it to the combustion air to reduce fuel use. Designs include tubular, flat plate, and regenerative heat
exchangers, among others.
Steam-water flow system
The steam-water components are arranged for the
most economical system to provide a continuous supply of steam. The circulation system (excluding reheater) for a natural circulation, subcritical pressure,
drum type steam generator is shown in Fig. 16. Feed-
Fig. 14 Steam generator energy absorption by function.
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
water enters the bottom header (A) of the economizer
and passes upward in the opposite direction to the flue
gas. It is collected in an outlet header (B), which may
also be located in the flue gas stream. The water then
flows through a number of pipes which connect the
economizer outlet header to the steam drum. It is
sometimes appropriate to run these tubes vertically (BC) through the convection pass to economizer outlet
headers located at the top of the boiler. These tubes
can then serve as water-cooled supports for the horizontal superheater and reheater when these banks
span too great a distance for end support. The feedwater is injected into the steam drum (D) where it
mixes with the water discharged from the steam-water separators before entering connections to the
downcomer pipes (D-E) which exit the steam drum.
The water travels around the furnace water wall
circuits to generate steam. The water flows through
the downcomer pipes (D-E) to the bottom of the furnace where supply tubes (E-F) route the circulating
water to the individual lower furnace panel wall headers (F). The water rises through the furnace walls to
individual outlet headers (G), absorbing energy to
become a steam-water mixture. The mixture leaves the
furnace wall outlet headers by means of riser tubes
(G-D), to be discharged into the drum and steam-water separators. The separation equipment returns essentially steam-free water to the downcomer inlet connections. The residual moisture in the steam that
leaves the primary steam separation devices is removed in secondary steam separators, and dry steam
is discharged to the superheater through a number
of drum outlet connections (H-I and H-J).
The steam circuitry serves dual functions: cooling
the convection pass enclosure, and generating the
required superheated steam conditions. Steam from
the drum passes through multiple connections to a
Fig. 15 Coal-fired utility boiler.
Steam 41 / Steam Generation – An Overview
Fig. 16 Coal-fired boiler steam-water circulation system.
header (I) supplying the roof tubes and, separately,
to headers (J) supplying the membrane panels in the
pendant convection pass (so named because the superheater/reheater vertical tubes are hanging from
supports above). The steam flows through these membrane panels to outlet headers (K). Steam from these
headers and the roof tube outlet headers (L) then provides the cooling for the horizontal convection pass
enclosure (L-M) (so named because the superheater/
reheater/economizer tubes are horizontal in this flue
gas downpass). Steam flows downward through these
panels and is collected in outlet headers (M) just upstream of the economizer bank.
Steam flow then rises through the primary superheater and discharges through the outlet header (N)
and connecting piping equipped with a spray
attemperator (O). It then enters the secondary superheater inlet header (P), flowing through the superheater sections to an outlet header (Q). A discharge
pipe (R) terminates outside of the boiler enclosure
where the main steam lines route the steam flow to
the control valves and turbine.
Combustion system and auxiliaries
Most of the non-steam generating components and
auxiliaries used in coal-fired steam generators are part
of the fuel preparation and combustion systems. These
include:
1. fuel preparation: feeders and coal pulverizers,
2. combustion system: burners, flame scanners, lighters, controls, windbox,
3. air-gas handling: fans, flues and ducts, dampers,
control and measurement systems, silencers, and
4. other components and auxiliaries: sootblowers
(heat transfer surface cleaning equipment), ash
collection and handling equipment, control and
monitoring equipment.
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The Babcock & Wilcox Company
Because of their intimate relationship with the steam
generation process, many of these components are
supplied with the boiler. If not, careful specification
and interaction with the steam generator manufacturer are critical.
The combustion system has a dramatic impact on
overall furnace design. Wall mounted burners are
shown in Figs. 15 and 17. These are typical for large
coal-, oil-, or gas-fired units today. However, a variety of other systems are also used and are continuing
to be developed to handle the variety of fuel characteristics and unit sizes. Other combustion systems include stokers (Figs. 4 and 13), Cyclone furnaces, and
fluidized-bed combustion units (Fig. 5). All have their
strengths and weaknesses for particular applications.
Key elements of these systems involve the need to
control the formation and emission of pollutants, provide complete efficient combustion, and handle inert
material found in the fuel. The fuel characteristics
play a central role in how these functions are met and
how the equipment is sized and designed.
Air-gas flow system
Many of these auxiliaries are identified in Fig. 17
along with the air-gas flow path in the large coal-fired
utility boiler. Air is supplied by the forced draft fan
(A) to the air heater (B) where it is heated to recover
energy and enhance combustion. Most of the hot air
(typically 70 to 80%), called secondary air, passes directly to the windboxes (C) where it is distributed to
individual burners. The remaining 20 to 30%, called
primary air, passes to the booster (or primary air) fan
and then to the coal pulverizers (D) where the coal is
dried and ground. The hot primary air then pneumatically conveys the pulverized coal to the burners (E)
where it is mixed with the secondary air for combustion. The coal and air are rapidly mixed and burned
in the furnace (F) and the flue gas then passes up
through the furnace, being cooled primarily by radiation until it reaches the furnace exit (G). The gas then
progressively passes through the secondary superheater, reheater, primary superheater and economizer before leaving the steam generator enclosure (H).
The gas passes through the air heater (B) and then
through any pollution control equipment and induced
draft fan (I) before being exhausted to the atmosphere.
Emissions control
A key element of fossil fuel-fired steam generator
system design is environmental protection. A broad
range of government regulations sets limits on primary
gaseous, liquid and solid waste emissions from the
steam generating process. For coal-, oil-, and gas-fired
units, the primary air pollutant emissions include
sulfur dioxide (SO2), nitrogen oxides (NOx) and airborne particulate or flyash. Water discharges include
trace chemicals used to control corrosion and fouling as
well as waste heat rejected from the condenser. Solid
waste primarily involves the residual ash from the fuel
and any spent sorbent from the pollution control systems.
The gaseous and solid waste from the fuel and combustion process can be minimized by fuel selection,
1-10
Fig. 17 Coal-fired boiler air/gas flow path.
control of the combustion process, and equipment located downstream of the steam generator. SO2 emissions may be reduced by using fuels which contain low
levels of sulfur, by fluidized-bed combustors, or by
using a post-combustion scrubber system. Combustion
NOx emissions are typically controlled by using equipment such as special low NOx burners or fluidized-bed
combustors. Where it is required to significantly reduce NOx emissions (to levels lower than is practically
achieved by combustion techniques alone), back-end
or post-combustion techniques, such as selective catalytic reduction (SCR) or selective noncatalytic reduction (SNCR) technologies, are employed. Flyash or airborne particulate is collected by either a fabric filter
(baghouse) or electrostatic precipitator (ESP) with removal efficiencies above 99%. The particulate collection equipment and SO 2 scrubbers produce solid
byproduct streams which must be safely landfilled or
used for some industrial applications.
The water discharges are minimized by installing
recirculating cooling systems. An example of this is
cooling towers that reject the waste heat from the
power cycle to the air, instead of to a water source.
These are used on virtually all new fossil and nuclear
power plants. Chemical discharges are minimized by
specially designed zero discharge systems. A set of
emissions rates before and after control for a typical
500 MW power plant is shown in Table 1.
Nuclear steam generating systems
Overview
Nuclear steam generating systems include a series
of highly specialized heat exchangers, pressure vessels, pumps and components which use the heat generated by nuclear fission reactions to efficiently and
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
Table 1
Typical 500 MW Subcritical Coal-Fired Steam Generator Emissions and Byproducts*
Power System Characteristics
• 500 MW net
• 196 t/h (49.4 kg/s) bituminous coal
− 2.5% sulfur
− 16% ash
− 12,360 Btu/lb (28,749 kJ/kg)
• 65% capacity factor
Emission
SOx as SO2
NOx as NO2
CO2
Flyash to air**
Thermal discharge to water sources
Ash to landfill**
Scrubber sludge: gypsum plus water
Typical Control Equipment
Discharge Rate t/h (tm /h)
Uncontrolled
Controlled
Wet limestone scrubber
9.3
(8.4)
Low NOx burners and SCR
2.9
(2.6)
Not applicable
485
(440)
Electrostatic precipitator or baghouse
22.9
(20.8)
Natural draft cooling tower
2.8 x 109 Btu/h (821 MWt )
Controlled landfill
9.1
(8.3)
Controlled landfill or wallboard quality gypsum
0
(0)
0.3
0.1
0.05
∼0
32
27.7
(0.3)
(0.1)
(0.04)
(0)
(29)
(25)
* See Chapter 32, Table 1, for a modern 615 MW supercritical coal-fired steam generator.
** As flyash emissions to the air decline, ash to landfill increases.
safely generate steam. The system is based upon the
energy released when atoms within certain materials,
such as uranium, break apart or fission. Fission occurs when a fissionable atom nucleus captures a free
subatomic particle – a neutron. This upsets the internal forces which hold the atom nucleus together. The
nucleus splits apart producing new atoms as well as
an average of two to three neutrons, gamma radiation and energy.
The nuclear steam supply system (NSSS) is designed to serve a number of functions: 1) house the
nuclear fuel, 2) stimulate the controlled fission of the
fuel, 3) control the nuclear reaction rate to produce
the required amount of thermal energy, 4) collect the
heat and generate steam, 5) safely contain the reaction products, and 6) provide backup systems to prevent release of radioactive material to the environment. Various systems have been developed to accomplish these functions. The main power producing system in commercial operation today is the pressurized
water reactor (PWR).
A key difference between the nuclear and chemical energy driven systems is the quantity of fuel. The
energy released per unit mass of nuclear fuel is many
orders of magnitude greater than that for chemical
based fuels. For example, 1 lb (0.454 kg) of 3% enriched uranium fuel produces about the same amount
of thermal energy in a commercial nuclear system as
100,000 lb (45,360 kg) of coal in a fossil-fired steam
system. While a 500 MW power plant must handle approximately one million tons of coal per year, the
nuclear plant will handle only 10 tons of fuel. The fossil
fuel plant must be designed for a continuous fuel supply process, while most nuclear plants use a batch fuel
process, where about one third of the fuel is replaced
during periodic outages. However, once the steam is
generated, the balance of the power producing system (turbine, condenser, cooling system, etc.) is similar to that used in the fossil fuel plant.
Steam 41 / Steam Generation – An Overview
Nuclear steam system components
A typical nuclear steam system from The Babcock
& Wilcox Company (B&W) is shown in Fig. 3 and a
simplified schematic is shown in Fig. 18. This nuclear
system consists of two coolant loops. The primary loop
cools the reactor, transports heat to two or more steam
generators (only one shown), and returns coolant to
the reactor by four or more primary coolant pumps
(only one shown). The coolant is high purity, subcooled,
single-phase water flowing at very high rates [350,000
to 450,000 GPM (22,100 to 28,400 l/s)] at around 2200
psi (15.17 MPa) and an average temperature of approximately 580F (304C). The primary loop also contains a
pressurizer to maintain the loop pressure at design operating levels.
The secondary loop includes the steam generation
and interface with the balance of the power plant.
High purity water from the last feedwater heater
passes through the steam generator and is converted
into steam. From the steam generator outlet, the saturated or superheated steam flows out of the containment building to the high pressure turbine. The operating pressure is typically around 1000 psi (6.9
MPa). The balance of the secondary loop resembles
fossil fuel-fired systems. (See Figs. 10 and 11.)
The center of the NSSS is the reactor vessel and reactor core (Fig. 19). The fuel consists of compressed pellets [for example, 0.37 in. (9.4 mm) diameter by 0.7 in.
(18 mm) long] of 2.5 to 5% enriched uranium oxide.
These pellets are placed in zircaloy tubes which are
sealed at both ends to protect the fuel and to contain
the nuclear reaction products. The tubes are assembled
into bundles with spacer and closure devices. These
bundles are then assembled into the nuclear fuel core.
The reactor enclosure (Fig. 19) is a low alloy steel
pressure vessel lined with stainless steel for corrosion
protection. The rest of the reactor includes flow distribution devices, control rods, core support structures,
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The Babcock & Wilcox Company
steam generator upper shell is mixed with feedwater
and is returned to the bottom of the tube bundle.
The pressurizer is a simple cylindrical pressure vessel which contains both water and steam at equilibrium. Electrical heaters and spray systems maintain
the pressure in the pressurizer vessel and the primary
loop within set limits. The primary loop circulating
pumps maintain high flow rates to the reactor core to
control its temperature and transfer heat to the steam
generators.
A number of support systems are also provided.
These include reactor coolant charging systems,
makeup water addition, spent fuel storage cooling, and
decay heat removal systems for when the reactor is
shut down. Other specialized systems protect the reactor system in the case of a loss of coolant event. The
key function of these systems is to keep the fuel bundle
temperature within safe limits if the primary coolant
flow is interrupted.
Fig. 18 Nuclear steam system schematic.
thermal shielding and moderator. The moderator in
this case is water which serves a dual purpose. It reduces the velocity of the neutrons thereby making the
nuclear reactions more likely. It also serves as the coolant to maintain the core materials within acceptable
temperature limits and transports thermal energy to
the steam generators. The control rods contain neutron
absorbing material and are moved into and out of the
nuclear core to control the energy output.
The steam generators can be of two types, oncethrough (Fig. 20) and recirculating (Fig. 21). In both
types, the pressure vessel is a large heat exchanger
designed to generate steam for the secondary loop from
heat contained in the primary coolant. The primary
coolant enters a plenum and passes through several
thousand small diameter [approximately 0.625 in.
(15.9 mm)] Inconel® tubes. The steam generator is a
large, carbon steel pressure vessel. Specially designed
tubesheets, support plates, shrouds, and baffles provide effective heat transfer, avoid thermal expansion
problems, and avoid flow-induced vibration.
In the once-through steam generator (OTSG), Fig.
20, the secondary loop water flows from the bottom to
the top of the shell side of the tube bundle and is continuously converted from water to superheated steam.
The superheated steam then passes to the high pressure turbine.
In the recirculating steam generator (RSG), Fig. 21,
water moves from the bottom to the top of the shell side
of the tube bundle being converted partially into steam.
The steam-water mixture passes into the upper shell
where steam-water separators supply saturated dry
steam to the steam generator outlet. The steam is sent
to the high pressure turbine. The water leaving the
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Nuclear steam system classifications
A variety of reactor systems have been developed
to recover thermal energy from nuclear fuel and to
generate steam for power generation. These are usually identified by their coolant and moderator types.
The principal systems for power generation include:
1. Pressurized water reactor (PWR) This is the system discussed above, using water as both reactor
coolant and moderator, and enriched uranium
oxide as the fuel.
2. Boiling water reactor (BWR) The steam generator is eliminated and steam is generated directly
in the reactor core. A steam-water mixture cools
and moderates the reactor core. Enriched uranium
oxide fuel is used.
Fig. 19 Reactor vessel and internals.
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
3. CANDU (PHWR) Heavy water (deuterium) is
used as the moderator and primary loop coolant.
The reactor configuration is unique but the steam
generator is similar to the recirculating steam generator for the PWR. Natural (not enriched) uranium oxide is used as the fuel.
4. Gas-cooled reactors These are a variety of gascooled reactors which are typically moderated by
graphite and cooled by helium or carbon dioxide.
5. Breeder reactors These are advanced reactor systems
using sodium as the reactor coolant with no moderator. These systems are specially designed to produce
more fissionable nuclear fuel than they use.
Engineered safety systems
Safety is a major concern in the design, construction and operation of nuclear power generating facilities. The focus of these efforts is to minimize the likelihood of a release of radioactive materials to the environment. Three approaches are used to accomplish
this goal. First, the nuclear power industry has developed one of the most extensive and rigorous quality
control programs for the design, construction and
maintenance of nuclear facilities. Second, reactor systems are designed with multiple barriers to prevent
radioactive material release. These include high temperature ceramic fuel pellets, sealed fuel rods, reactor
vessel and primary coolant system, and the contain-
Fig. 21 Recirculating steam generator.
ment building including both the carbon steel reactor
containment vessel and the reinforced concrete shield
building. The third approach includes a series of engineered safety systems to address loss of coolant conditions and maintain the integrity of the multiple
barriers. These systems include:
1. emergency reactor trip systems including rapid insertion of control rods and the addition of soluble
neutron poisons in the primary coolant to shut
down the nuclear reaction,
2. high and low pressure emergency core cooling systems to keep the reactor core temperature within
acceptable limits and remove heat from the fuel
in the event of a major loss of primary coolant or
a small pipe break,
3. a heat removal system for the cooling water and
containment building, and
4. spray and filtering systems to collect and remove
radioactivity from the containment building.
Fig. 20 Once-through steam generator.
Steam 41 / Steam Generation – An Overview
Because of the high power densities and decay heat
generation, the reactor integrity depends upon the
continuous cooling of the nuclear fuel rods. Multiple
independent components and backup power supplies
are provided for all critical systems.
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The Babcock & Wilcox Company
Steam system design
Steam generator interfaces
The steam generator system’s primary function is
to convert chemical or nuclear energy bound in the
fuel to heat and produce high temperature, high pressure steam. The variety of fuel sources, the high temperature nature of these processes, and the large
number of subsystem interfaces contribute to the challenging nature of the design process. The initial steps
in evaluating the steam generating system include establishing key interfaces with other plant systems and
with the power cycle. These are typically set by the
end user or consulting engineer after an in-depth
evaluation indicates: 1) the need for the expanded
power supply or steam source, 2) the most economical
fuel selection and type of steam producing system, 3)
the plant location, and 4) the desired power cycle or
process steam conditions. The key requirements fall
into six major areas:
1. Steam minimum, nominal, and maximum flow
rates; pressure and temperature; need for one or
more steam reheat stages; auxiliary equipment
steam usage; and future requirements.
2. Source of the steam flow makeup or replacement water supply, water chemistry and inlet temperature.
3. The type and range of fuels considered, including
worst case conditions, and the chemical analyses
(proximate and ultimate analyses) for each fuel
or mixture of fuels.
4. Elevation above sea level, overall climate history and
forecast, earthquake potential and space limitations.
5. Emissions control requirements and applicable
government regulations and standards.
6. The types of auxiliary equipment; overall plant
and boiler efficiency; access needs; evaluation
penalties, e.g., power usage; planned operating
modes including expected load cycling requirements, e.g., peaking, intermediate or base load;
and likely future plant use.
When these interfaces are established, boiler design
and evaluation may begin.
Systematic approach
There are a variety of evaluation approaches that
can be used to meet the specific steam generator performance requirements. These include the multiple
iterations commonly found in thermal design where
real world complexities and nonlinear, noncontinuous
interactions prevent a straightforward solution. The
process begins by understanding the particular application and system to define conditions such as steam
flow requirements, fuel source, operating dynamics,
and emissions limits, among others. From these, the
designer proceeds to assess the steam generator options, interfaces, and equipment needs to achieve performance. Using a coal-fired boiler as an example, a
systematic approach would include the following:
1. Specify the steam supply requirements to define
the overall inputs of fuel, air and water, and the
steam output conditions.
1-14
2. Evaluate the heat balances and heat absorption
by type of steam generator surface.
3. Perform combustion calculations to define heat input and gas flow requirements.
4. Configure the combustion system to complete the
combustion process while minimizing emissions
(fuel preparation, combustion and air handling).
5. Configure the furnace and other heat transfer surfaces to satisfy temperature, material, and performance tradeoffs while meeting the system control
needs.
6. Size other water-side and steam-side components.
7. Specify the back-end tradeoffs on the final heat
recovery devices such as water heaters (economizers) and air heaters.
8. Check the steam generating system performance
to ensure that the design criteria are met.
9. Verify overall unit performance.
10. Repeat steps 2 through 9 until the desired steam
mass flow and temperature are achieved over the
specified range of load conditions.
11. Use American Society of Mechanical Engineers
(ASME) Code rules to design pressure parts to
meet the anticipated operating conditions and complete detailed mechanical design.
12. Design and integrate environmental protection
equipment to achieve prescribed emissions levels.
13. Incorporate auxiliaries as needed, such as tube
surface cleaning equipment, fans, instrumentation and controls, to complete the design and assure safe and continuous operation.
The life cycle and daily operation of the steam generator (and the plant in which it will operate) are
important elements to be considered from the beginning of the design and throughout the design process.
Today, some steam generators will be required to operate efficiently and reliably for up to 60 years or
more. During this time, many components will wear
out because of the aggressive environment, so routine
inspection of pressure parts is needed to assure continued reliability. Unit operating procedures, such as
the permitted severity and magnitude of transients,
may be monitored to prevent reduced unit life. Operating practices including water treatment, cycling operation procedures, and preventive maintenance programs, among others, can significantly affect steam
generator availability and reliability. Key unit components may be upgraded to improve performance. In
each case, decisions made during the design phase and
subsequent operation can substantially enhance the
life and performance of the unit.
System design example
Now that the basic fossil fuel and nuclear steam
generating systems have been described, it is appropriate to explore the general design and engineering
process. While each of the many systems requires specialized evaluations, they share many common elements. To illustrate how the design process works, a
small industrial B&W PFI gas-fired boiler has been
selected for discussion. (See Figs. 22 and 23.)
Basically, the customer has one overriding need:
when the valve is turned on, steam is expected to be
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
supplied at the desired pressure, temperature and flow
rate. In this example, the customer specifies 400,000
lb/h (50.4 kg/s) of superheated steam at 600 psi (4.14
MPa) and 850F (454C). The customer has agreed to
supply high purity feedwater at 280F (138C) and to
supply natural gas as a fuel source. As with all steam
generating systems, there are a number of additional
constraints and requirements as discussed in Steam
generator interfaces, but the major job of the steam
generator or boiler is to supply steam.
Combustion of the natural gas produces a stream
of combustion products or flue gas at perhaps 3600F
(1982C). To maximize the steam generator thermal
efficiency, it is important to cool these gases as much
as possible while generating the steam. The minimum
flue gas outlet temperature is established based upon
technical and economic factors (discussed below). For
now, a 310F (154C) outlet temperature to the exhaust
stack is selected. The approximate steam and flue gas
temperature curves are shown in Fig. 24 and define
the heat transfer process. The heat transfer surface
for the furnace, boiler bank, superheater and air
heater is approximately 69,000 ft2 (6410 m2).
From a design perspective, the PFI boiler can be
viewed as either a steam heater or gas cooler. The latter approach is most often selected for design. The
design fuel heat input is calculated by dividing the
steam heat output by the target steam generator thermal efficiency. Based upon the resulting fuel flow, combustion calculations define the air flow requirements
and combustion products gas weight. The heat transfer surface is then configured in the most economical
way to cool the flue gas to the temperature necessary
for the target steam generator efficiency. Before proceeding to follow the gas through the cooling process, the
amount of heat recovery for each of the different boiler
surfaces (superheater and boiler) must be established.
Fig. 25 illustrates the water heating process from
an inlet temperature of 280F (138C) to the superheater
Fig. 22 Small PFI industrial boiler.
Steam 41 / Steam Generation – An Overview
Fig. 23 Small industrial boiler – sectional view.
steam outlet temperature of 850F (454C). This curve
indicates that about 20% of the heat absorbed is used
to raise the water from its inlet temperature to the
saturation temperature of 490F (254C). 60% of the
energy is then used to evaporate the water to produce
saturated steam. The remaining 20% of the heat input is used to superheat or raise the steam temperature to the desired outlet temperature of 850F (454C).
The fuel and the combustion process selected set the
geometry of the furnace. In this case, simple circular
burners are used. The objective of the burners is to
mix the fuel and air rapidly to produce a stable flame
and complete combustion while minimizing the formation of NOx emissions. Burners are available in several standardized sizes. The specific size and number
are selected from past experience to provide the desired heat input rate while permitting the necessary
level of load range control. The windbox, which distributes the air to individual burners, is designed to
provide a uniform air flow at low enough velocities to
permit the burners to function properly.
The furnace volume is then set to allow complete
fuel combustion. The distances between burners and
between the burners and the floor, roof, and side walls
are determined from the known characteristics of the
particular burner flame. Adequate clearances are
specified to prevent flame impingement on the furnace
surfaces, which could overheat the tubes and cause
tube failures.
Once the furnace dimensions are set, this volume is
enclosed in a water-cooled membrane panel surface.
This construction provides a gas-tight, all steel enclosure which minimizes energy loss, generates some
steam and minimizes furnace maintenance. As shown
in Fig. 23, the roof and floor tubes are inclined slightly
to enhance water flow and prevent steam from collecting on the tube surface. Trapped steam could result in
overheating of the tubes. Heat transfer from the flame
to the furnace enclosure surfaces occurs primarily by
thermal radiation. As a result, the heat input rates per
1-15
The Babcock & Wilcox Company
Fig. 24 Industrial boiler – temperature versus heat transfer surface.
unit area of surface are very high and relatively independent of the tubewall temperatures. Boiling water
provides an effective means to cool the tubes and keep
the tube metal temperatures within acceptable limits
as long as the boiling conditions are maintained.
Fig. 26 shows the effect of the furnace on gas temperature. The gas temperature is reduced from 3600
at point A to 2400F at point B (1982 to 1316C), while
boiling takes place in the water walls (points 1 to 2). A
large amount of heat transfer takes place on a small
amount of surface. From the furnace, the gases pass
through the furnace screen tubes shown in Fig. 23.
The temperature drops a small amount [50F (28C)]
from points B to C in Fig. 26, but more importantly,
the superheater surface is partially shielded from the
furnace thermal radiation. The furnace screen tubes
are connected to the drum and contain boiling water.
Next, the gas passes through the superheater where
the gas temperature drops from 2350 at point C to
1750F at point D (1288 to 954C). Saturated steam
from the drum is passed through the superheater tubing to raise its temperature from 490F (254C) saturation temperature to the 850F (454C) desired outlet temperature (points 5 to 4).
The location of the superheater and its configuration are critical in order to keep the steam outlet temperature constant under all load conditions. This involves radiation heat transfer from the furnace with
convection heat transfer from the gas passing across
the surface. In addition, where dirty gases such as
combustion products from coal are used, the spacing
of the superheater tubes is also adjusted to accommodate the accumulation of fouling ash deposits and the
use of cleaning equipment.
After the superheater, almost half of the energy in
the gas stream has been recovered with only a small
amount of heat transfer surface [approximately 6400
ft2 (595 m2)]. This is possible because of the large temperature difference between the gas and the boiling
1-16
water or steam. The gas temperature has now been dramatically reduced, requiring much larger heat transfer
surfaces to recover incremental amounts of energy.
The balance of the steam is generated by passing
the gas through the boiler bank. (See Figs. 22 and 23.)
This bank is composed of a large number of watercontaining tubes that connect the steam drum to a
lower (mud) drum. The temperature of the boiling
water is effectively constant (points 5 to 6 in Fig. 26),
while the gas temperature drops by almost 1000F
(556C) to an outlet temperature of 760F (404C), between points D and E. The tubes are spaced as closely
as possible to increase the gas flow heat transfer rate.
If a particulate-laden gas stream were present, the
spacing would be set to limit erosion of the tubes, reduce the heat transfer degradation due to ash deposits, and permit removal of the ash. Spacing is also
controlled by the allowable pressure drop across the
bank. In addition, a baffle can be used in the boiler
bank bundle to force the gas to travel at higher velocity through the bundle, increase the heat transfer rate,
and thereby reduce the bundle size and cost. To recover this additional percentage of the supplied energy, the boiler bank contains more than 32,000 ft2
(3000 m2) of surface, or approximately nine times more
surface per unit of energy than in the high temperature furnace and superheater. At this point in the
process, the temperature difference between the saturated water and gas is only 270F (150C), between
points 6 and E in Fig. 26.
Economics and technical limits dictate the type and
arrangement of additional heat transfer surfaces. An
economizer or water-cooled heat exchanger could be
used to heat the makeup or feedwater and cool the gas.
The lowest gas exit temperature possible is the inlet
temperature of the feedwater [280F (138C)]. However,
the economizer would have to be infinitely large to
accomplish this goal. Even if the exit gas temperature
is 310F (154C), the temperature difference at this
point in the heat exchanger would only be 30F (17C),
still making the heat exchanger relatively large. Instead of incorporating an economizer, an air preheater
could be used to recover the remaining gas energy and
preheat the combustion air. This would reduce the
Fig. 25 Steam-water temperature profile.
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
natural gas needed to heat the steam generator. Air
heaters can be very compact. Also, air preheating can
enhance the combustion of many difficult to burn fuels such as coal. All of the parameters are reviewed to
select the most economical solution that meets the technical requirements.
In this case, the decision has been made to use an
air heater and not an economizer. The air heater is
designed to take 80F (27C) ambient air (point 9) and
increase the temperature to 570F (299C), at point 8.
This hot air is then fed to the burners. At the same
time, the gas temperature is dropped from 760F (404C)
to the desired 310F (154C) outlet temperature (points
E to F). If a much lower gas outlet temperature than
310F (154C) is used, the heat exchanger surfaces may
become uneconomically large, although this is a case
by case decision. In addition, for fuels such as oil or
coal which can produce acid constituents in the gas
stream (such as sulfur oxides), lower exit gas temperatures may result in condensation of these constituents onto the heat transfer surfaces, and excessive
corrosion damage. The gas is then exhausted through
the stack to the atmosphere.
Finally, the feedwater temperature increases from
280F (138C) to saturation temperature of 490F
(254C). In the absence of an economizer, the
feedwater is supplied directly to the drum where it is
mixed with the water flowing through the boiler bank
tubes and furnace. The flow rate of this circulating
water in industrial units is approximately 25 times
higher than the feedwater flow rate. Therefore, when
the feedwater is mixed in the drum, it quickly approaches the saturation temperature without appreciably lowering the temperature of the recirculating
water in the boiler tubes.
Reviewing the water portion of the system, the feedwater is supplied to the drum where it mixes with the
recirculating water after the steam is extracted and
sent to the superheater. The drum internals are spe-
Fig. 26 Gas and steam temperature schematic.
Steam 41 / Steam Generation – An Overview
cially designed so that the now slightly subcooled
water flows down through a portion of the boiler bank
tubes to the lower or mud drum. This water is then
distributed to the remainder of the boiler bank tubes
(also called risers) and the furnace enclosure tubes
where it is partially converted to steam (approximately
4% steam by weight). The steam-water mixture is
then returned to the steam drum. Here, the steamwater mixture is passed through separators where the
steam is separated from the water. The steam is then
sent to the superheater, and from there to its end use.
The remaining water is mixed with the feedwater and
is again distributed to the downcomer tubes.
Other steam producing systems
A variety of additional systems also produce steam
for power and process applications. These systems
usually take advantage of low cost or free fuels, a combination of power cycles and processes, and recovery
of waste heat in order to reduce overall costs. Examples of these include:
1. Gas turbine combined cycle (CC) Advanced gas
turbines with heat recovery steam generators as
part of a bottoming cycle to use waste heat recovery and increase thermal efficiency.
2. Integrated gasification combined cycle (IGCC) Adds
a coal gasifier to the CC to reduce fuel costs and
minimize airborne emissions.
3. Pressurized fluidized-bed combustion (PFBC)
Includes higher pressure combustion with gas
cleaning and expansion of the combustion products through a gas turbine.
4. Blast furnace hood heat recovery Generates steam
using the waste heat from a blast furnace.
5. Solar steam generator Uses concentrators to collect
and concentrate solar radiation and generate steam.
Common technical elements
The design of steam generating systems involves
the combination of scientific and technical fundamentals, empirical data, practical experience and designer
insight. While technology has advanced significantly,
it is still not possible to base the design of modern systems on fundamentals alone. Instead, the fundamentals provide the basis for combining field data and
empirical methods.
Even given the wide variety of shapes, sizes and
applications (see Fig. 27), steam generator design involves the application of a common set of technologies.
The functional performance of the steam generator is
established by combining thermodynamics, heat
transfer, fluid mechanics, chemistry, and combustion
science or nuclear science with practical knowledge of
the fouling of heat transfer surfaces and empirical
knowledge of the behavior of boiling water. The design and supply of the hardware are aided by structural design and advanced materials properties research combined with expertise in manufacturing
technologies and erection skills to produce a quality,
reliable product to meet the highly demanding system
requirements.
1-17
The Babcock & Wilcox Company
Fig. 27 This energy complex in the northern U.S. includes four coal-fired steam systems, ranging from 80 to 330 MW, installed over a 25-year period.
The ASME Boiler and Pressure Vessel Code is the
firm basis from which steam generator pressure parts
can be safely designed. Once built, the operation and
maintenance of the steam generator are critical to
ensure a long life and reliable service. Water chemistry and chemical cleaning are increasingly recognized
as central elements in any ongoing operating program. The impact of fuel and any residual flyash is
important in evaluating the corrosion and fouling of
heat transfer surfaces. The use of modern techniques
to periodically inspect the integrity of the steam generator tubes leads to the ability to extend steam generator life and improve overall performance. These are
accomplished by the application of engineered component modification to better meet the changing needs
of the steam generating system. Finally, the control
systems which monitor and operate many subsystems
to optimize unit performance are important to maintain system reliability and efficiency.
All of these functions – functional performance,
mechanical design, manufacture, construction, operation, maintenance, and life extension – must be fully
combined to provide the best steam generating system. Long term success depends upon a complete life
cycle approach to the steam generating system. Steam
generator system operators routinely require their
equipment to operate continuously and reliably for
more than 60 years in increasingly demanding conditions. Therefore, it is important to consider later
boiler life, including component replacement, in the
initial phases of boiler specification. Changes in design to reduce initial capital cost must be weighed
against their possible impact on future operation.
Bibliography
Aschner, F.S., Planning Fundamentals of Thermal Power
Plants, John Wiley & Sons, New York, New York, 1978.
Axtman, W.H., and American Boiler Manufacturers Association staff, “The American Boiler Industry: A Century
of Innovation,” American Boiler Manufacturers Association (ABMA), Arlington, Virginia, 1988.
“Boilers and auxiliary equipment,” Power, Vol. 132, No.
6, pp B-l to B-138, Platts/McGraw-Hill, New York, New
York, June, 1988.
1-18
Clapp, R.M., Ed., Modern Power Station Practice: Boilers and Ancillary Plant, Third Ed., Pergamon Press,
Oxford, England, United Kingdom, April 1, 1993.
Collier, J.G., and Hewitt, G.F., Introduction to Nuclear
Power, Taylor and Francis Publishers, Washington, D.C.,
June 1, 2000.
Elliot, T.C., Chen, K., Swanekamp, R.C., Ed., Standard
Handbook of Powerplant Engineering, McGraw-Hill Company, New York, New York, 1997.
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
El-Wakil, M.M., Powerplant Technology, McGraw-Hill
Primis Custom Publishing, New York, New York, 1984.
Foster, A.R., and Wright, R.L., Basic Nuclear Engineering, Pearson Allyn and Bacon, Boston, Massachusetts,
January, 1983.
Fraas, A.P., Heat Exchanger Design, Second Ed.,
Interscience, New York, New York, March, 1989.
Gunn, D., and Horton, R., Industrial Boilers, Longman
Scientific and Technical, Longman Science & Technology,
London, England, United Kingdom, April, 1989.
Hambling, P., Modern Power Station Practice: Turbines,
Generators and Associated Plant, Third Ed., Pergamon
Press, Oxford, England, United Kingdom, April 1, 1993.
Jackson, A.W., “The How and Why of Boiler Design,” Engineers Society of Western Pennsylvania Power Symposium, Pittsburgh, Pennsylvania, February 15, 1967.
Kakaç, S., Ed., Boilers, Evaporators and Condensers,
Interscience, April 15, 1991. See Chapter 6, “Fossil FuelFired Boilers: Fundamentals and Elements,” by J.B. Kitto
and M.J. Albrecht.
Li, K.W., and Priddy, A.P., Power Plant System Design,
Wiley Text Books, New York, New York, February, 1985.
Shields, C.D., Boilers: Types, Characteristics, and Functions, McGraw-Hill Company, New York, New York, 1961.
Wiener, M., “The Latest Developments in Natural Circulation Boiler Design,” Proceedings of the American Power
Conference, Vol. 39, pp. 336-348, 1977.
Inconel is a trademark of the Special Metals Corporation group of
companies.
Steam 41 / Steam Generation – An Overview
1-19
The Babcock & Wilcox Company
Mix
Bottle
Final
Superheater
Final
Reheater
Steam
Separator
Platen
Superheater
Water
Collection
Tank
Intermediate
Superheater
Primary Superheater
Primary Reheater
Economizer
Spiral Transition
Headers
Catalyst
NOx Ports
Furnace
Ammonia
Injection
Grid
Low NOx
Burners
SCR
B&W
Roll Wheel™
Pulverizers
Air Heater
Flue Gas
Outlet
Forced Draft
Fan
Circulation
Pump
Steam Coil
Air Heater
Primary Air
Fan
750 MW once-through spiral wound universal pressure (SWUP™) coal-fired utility boiler.
1-20
Steam 41 / Steam Generation – An Overview
The Babcock & Wilcox Company
Chapter 2
Thermodynamics of Steam
Thermodynamics is the science which describes and
defines the transformation of one form of energy into
another – chemical to thermal, thermal to mechanical, and mechanical to thermal. The basic tenets include: 1) energy in all of its forms must be conserved,
and 2) only a portion of available energy can be converted to useful energy or work. Generally referred
to as the first and second laws of thermodynamics,
these tenets evolved from the early development of the
steam engine and the efforts to formalize the observations of its conversion of heat into mechanical work.
Regardless of the type of work or form of energy
under consideration, the terms heat, work, and energy
have practical significance only when viewed in terms
of systems, processes, cycles, and their surroundings.
In the case of expansion work, the system is a fluid
capable of expansion or contraction as a result of pressure, temperature or chemical changes. The way in
which these changes take place is referred to as the
process. A cycle is a sequence of processes that is capable of producing net heat flow or work when placed
between an energy source and an energy sink. The
surroundings represent the sources and sinks which
accommodate interchanges of mass, heat and work to
or from the system.
Steam may be viewed as a thermodynamic system
which is favored for power generation and heat transfer. Its unique combination of high thermal capacity
(specific heat), high critical temperature, wide availability, and nontoxic nature has served to maintain
this dominant position. High thermal capacity of a
working fluid generally results in smaller equipment
for a given power output or heat transfer. The useful
temperature range of water and its high thermal capacity meet the needs of many industrial processes and
the temperature limitations of power conversion
equipment.
Properties of steam
Before a process or cycle can be analyzed, reliable
properties of the working fluid are needed. Key properties include enthalpy, entropy, and specific volume.
While precise definitions are provided later in this
chapter, enthalpy is a general measure of the internally stored energy per unit mass of a flowing stream,
Steam 41 / Thermodynamics of Steam
specific entropy is a measure of the thermodynamic
potential of a system in the units of energy per unit
mass and absolute temperature, and specific volume
is the volume per unit mass.
In the case of steam, a worldwide consensus of these
and other thermophysical properties has been reached
through the International Association for the Properties of Steam. The most frequently used tabulation of
steam properties is the American Society of Mechanical Engineers (ASME) Steam Tables.1,2 Selected data
from this tabulation in English units are summarized
in Tables 1, 2 and 3. Corresponding SI tabulations are
provided in Appendix 1. These properties are now well
described by formulas that have been agreed to by the
International Association for the Properties of Water
and Steam, and are available from a number of sources
on the Internet as add-on functions to spreadsheets
and other software products.
The first two columns of Tables 1 and 2 define the
unique relationship between pressure and temperature referred to as saturated conditions, where liquid
and vapor phases of water can coexist at thermodynamic equilibrium. For a given pressure, steam heated
above the saturation temperature is referred to as superheated steam, while water cooled below the saturation temperature is referred to as subcooled or compressed water. Properties for superheated steam and
compressed water are provided in Table 3. Reproduced
from Reference 1, Fig. 1 shows the values of enthalpy
and specific volume for steam and water over a wide
range of pressure and temperature.
Under superheated or subcooled conditions, fluid
properties, such as enthalpy, entropy and volume per
unit mass, are unique functions of temperature and
pressure. However, at saturated conditions where
mixtures of steam and water coexist, the situation is
more complex and requires an additional parameter
for definition. For example, the enthalpy of a steamwater mixture will depend upon the relative amounts
of steam and water present. This additional parameter is the thermodynamic equilibrium quality or simply quality (x) defined by convention as the mass fraction of steam:
x =
ms
ms + mw
(1)
2-1
The Babcock & Wilcox Company
Note: The following steam tables and Fig. 1 have been abstracted from ASME International Steam Tables for Industrial Use
(copyright 2000 by The American Society of Mechanical Engineers), based on the IAPWS industrial formulation 1997 for the
Thermodynamic Properties of Water and Steam (IAPWS-IF97).
Table 1
Properties of Saturated Steam and Saturated Water (Temperature)
Temp
F
Press.
psia
Specific Volume, ft3/lb
Water
Evap
Steam
vf
vfg
vg
Enthalpy,2 Btu/lb
Water
Evap
Steam
Hf
Hfg
Hg
1
Entropy, Btu/lb F
Water
Evap
Steam
sf
sfg
sg
Temp
F
32
0.08865
0.01602
3302
3302
-0.02
1075.2
1075.2
-0.00004
2.1869
2.1868
32
35
40
45
50
60
0.09998
0.12173
0.14757
0.17813
0.2564
0.01602
0.01602
0.01602
0.01602
0.01603
2946
2443
2035.6
1702.9
1206.0
2946
2443
2035.6
1702.9
1206.1
3.00
8.03
13.05
18.07
28.08
1073.5
1070.7
1067.8
1065.0
1059.4
1076.5
1078.7
1080.9
1083.1
1087.4
0.0061
0.0162
0.0262
0.0361
0.0555
2.1701
2.1427
2.1159
2.0896
2.0385
2.1762
2.1590
2.1421
2.1257
2.0941
35
40
45
50
60
70
80
90
100
110
0.3633
0.5074
0.6990
0.9504
1.2766
0.01605
0.01607
0.01610
0.01613
0.01617
867.2
632.4
467.4
349.9
265.0
867.2
632.4
467.4
349.9
265.0
38.08
48.07
58.05
68.04
78.02
1053.7
1048.0
1042.4
1036.7
1031.0
1091.8
1096.1
1100.4
1104.7
1109.0
0.0746
0.0933
0.1116
0.1296
0.1473
1.9894
1.9420
1.8964
1.8523
1.8098
2.0640
2.0353
2.0080
1.9819
1.9570
70
80
90
100
110
120
130
140
150
160
170
180
190
200
1.6949
2.2258
2.8929
3.723
4.747
6.000
7.520
9.350
11.538
0.01620
0.01625
0.01629
0.01634
0.01639
0.01645
0.01651
0.01657
0.01663
202.95
157.09
122.81
96.92
77.17
61.97
50.15
40.90
33.59
202.96
157.10
122.82
96.93
77.19
61.98
50.17
40.92
33.61
88.00
97.99
107.98
117.97
127.98
137.99
148.01
158.05
168.10
1025.2
1019.4
1013.6
1007.8
1001.9
995.9
989.9
983.8
977.6
1113.2
1117.4
1121.6
1125.7
1129.8
1133.9
1137.9
1141.8
1145.7
0.1647
0.1817
0.1985
0.2151
0.2313
0.2474
0.2631
0.2787
0.2940
1.7686
1.7288
1.6903
1.6530
1.6168
1.5816
1.5475
1.5143
1.4820
1.9333
1.9106
1.8888
1.8680
1.8481
1.8290
1.8106
1.7930
1.7760
120
130
140
150
160
170
180
190
200
212
220
230
240
250
14.709
17.201
20.795
24.985
29.843
0.01671
0.01677
0.01684
0.01692
0.01700
26.76
23.12
19.356
16.299
13.799
26.78
23.13
19.373
16.316
13.816
180.18
188.25
198.35
208.47
218.62
970.1
965.0
958.6
952.1
945.4
1150.3
1153.3
1157.0
1160.5
1164.0
0.3122
0.3241
0.3388
0.3534
0.3678
1.4443
1.4198
1.3899
1.3607
1.3322
1.7565
1.7440
1.7288
1.7141
1.7000
212
220
230
240
250
260
270
280
290
300
35.445
41.874
49.218
57.567
67.021
0.01708
0.01717
0.01726
0.01735
0.01745
11.743
10.042
8.627
7.444
6.449
11.760
10.059
8.644
7.461
6.467
228.79
238.99
249.21
259.5
269.8
938.6
931.7
924.7
917.5
910.2
1167.4
1170.7
1173.9
1177.0
1180.0
0.3820
0.3960
0.4099
0.4236
0.4372
1.3043
1.2769
1.2502
1.2239
1.1982
1.6862
1.6730
1.6601
1.6476
1.6354
260
270
280
290
300
310
320
340
360
380
77.68
89.65
118.00
153.00
195.71
0.01755
0.01765
0.01787
0.01811
0.01836
5.609
4.897
3.771
2.940
2.318
5.627
4.915
3.789
2.958
2.336
280.1
290.4
311.3
332.3
353.6
902.7
895.0
879.2
862.5
844.9
1182.8
1185.5
1190.5
1194.8
1198.5
0.4507
0.4640
0.4903
0.5162
0.5416
1.1728
1.1480
1.0994
1.0522
1.0062
1.6235
1.6120
1.5897
1.5684
1.5478
310
320
340
360
380
400
420
440
460
480
247.22
308.71
381.44
466.7
565.9
0.01864
0.01894
0.01926
0.0196
0.0200
1.8454
1.4818
1.1986
0.9755
0.7980
1.8640
1.5007
1.2179
0.9952
0.8180
375.1
396.9
419.0
441.5
464.4
826.4
806.7
785.9
763.7
739.9
1201.5
1203.6
1204.9
1205.2
1204.4
0.5667
0.5915
0.6161
0.6405
0.6648
0.9613
0.9171
0.8735
0.8304
0.7874
1.5280
1.5086
1.4896
1.4709
1.4522
400
420
440
460
480
500
520
540
560
580
680.5
812.1
962.2
1132.7
1325.4
0.0204
0.0209
0.0215
0.0221
0.0228
0.6551
0.5392
0.4441
0.3654
0.2995
0.6756
0.5601
0.4656
0.3875
0.3223
487.9
511.9
536.7
562.3
589.0
714.5
687.0
657.3
624.9
589.3
1202.3
1198.9
1194.0
1187.2
1178.2
0.6890
0.7133
0.7377
0.7624
0.7875
0.7445
0.7013
0.6575
0.6128
0.5668
1.4335
1.4145
1.3952
1.3752
1.3543
500
520
540
560
580
600
620
640
660
680
1542.5
1786.1
2059.2
2364.8
2707.3
0.0236
0.0246
0.0259
0.0277
0.0303
0.2438
0.1961
0.1543
0.1167
0.0809
0.2675
0.2207
0.1802
0.1444
0.1112
616.9
646.6
678.7
714.5
757.3
549.7
505.0
453.3
390.9
309.3
1166.6
1151.6
1132.0
1105.3
1066.6
0.8133
0.8400
0.8683
0.8991
0.9354
0.5187
0.4677
0.4122
0.3491
0.2714
1.3320
1.3077
1.2804
1.2482
1.2068
600
620
640
660
680
700
3092.9
705.1028 3200.1
0.0368
0.0497
0.0378
0
0.0747
0.04975
823.6
897.5
167.0
0
990.6
897.5
0.9910
1.0538
0.1440
0
1.1350
1.0538
700
705.1028
1. SI steam tables are provided in Appendix 1.
2. In the balance of Steam, enthalpy is denoted by H in place of h to avoid confusion with heat transfer coefficient.
2-2
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
Table 2
Properties of Saturated Steam and Saturated Water (Pressure)
Press.
psia
Temp
F
Volume, ft3/lb
Water
Evap
Steam
vf
vfg
vg
0.0886
31.986
0.01602 3303.8
3303.8
-0.03
1075.2 1075.2
0.1
0.15
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
35.005
45.429
53.132
64.452
72.834
79.549
85.180
90.05
94.34
98.20
0.01602
0.01602
0.01603
0.01604
0.01606
0.01607
0.01609
0.01610
0.01611
0.01613
2945.0
2004.3
1525.9
1039.4
791.9
641.3
539.9
466.81
411.57
368.32
3.01
13.48
21.20
32.53
40.91
47.62
53.24
58.10
62.39
66.24
1073.5
1067.6
1063.2
1056.8
1052.1
1048.3
1045.1
1042.3
1039.9
1037.7
1035.7
1021.7
1012.8
1006.1
1000.6
995.9
991.8
988.2
984.9
981.8
2945.0
2004.3
1525.9
1039.4
791.8
641.3
539.9
466.80
411.56
368.30
Enthalpy,2 Btu/lb
Water Evap Steam
Hf
Hfg
Hg
1
Internal
Entropy, Btu/lb F
Energy, Btu/lb
Water Evap Steam Water Steam
sf
sfg
sg
uf
ug
Press.
psia
0
2.1869
2.1869
0
1021.0
0.0886
1076.5
1081.1
1084.4
1089.4
1093.0
1095.9
1098.3
1100.4
1102.3
1103.9
0.0061
0.0271
0.0422
0.0641
0.0799
0.0925
0.1028
0.1117
0.1195
0.1264
2.1701
2.1136
2.0734
2.0164
1.9758
1.9441
1.9182
1.8962
1.8770
1.8601
2.1762
2.1407
2.1156
2.0805
2.0557
2.0366
2.0210
2.0079
1.9965
1.9865
3.01
13.48
21.20
32.53
40.91
47.62
53.24
58.10
62.39
66.23
1022.0
1025.4
1028.0
1031.7
1034.4
1036.6
1038.4
1040.0
1041.4
1042.6
0.1
0.15
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1105.4
1115.8
1122.2
1126.9
1130.7
1133.9
1136.6
1139.0
1141.1
1143.1
0.1326
0.1750
0.2009
0.2198
0.2349
0.2474
0.2581
0.2675
0.2760
0.2836
1.8450
1.7445
1.6849
1.6423
1.6090
1.5816
1.5583
1.5381
1.5201
1.5040
1.9776
1.9195
1.8858
1.8621
1.8438
1.8290
1.8164
1.8056
1.7961
1.7875
69.73
94.01
109.38
120.87
130.15
137.97
144.77
150.80
156.24
161.19
1043.7
1051.5
1056.3
1059.9
1062.7
1065.1
1067.1
1068.9
1070.5
1072.0
1
2
3
4
5
6
7
8
9
10
101.69
126.03
141.42
152.91
162.18
170.00
176.79
182.81
188.22
193.16
0.01614
0.01623
0.01630
0.01636
0.01641
0.01645
0.01649
0.01652
0.01656
0.01659
333.49
173.70
118.69
90.61
73.507
61.963
53.632
47.328
42.387
38.406
333.51
173.72
118.70
90.63
73.52
61.98
53.65
47.34
42.40
38.42
69.73
94.02
109.39
120.89
130.16
137.99
144.79
150.83
156.27
161.22
14.696
211.95
0.01671
26.787
26.80
180.13
970.1 1150.3
0.3121
1.4445
1.7566
180.09 1077.4
15
20
30
40
50
60
70
80
90
100
212.99
227.92
250.30
267.22
280.99
292.69
302.92
312.03
320.27
327.82
0.01672
0.01683
0.01700
0.01715
0.01727
0.01738
0.01748
0.01757
0.01766
0.01774
26.278
20.075
13.7312
10.4832
8.4998
7.1588
6.1896
5.4554
4.8792
4.4146
26.30
20.09
13.748
10.500
8.517
7.176
6.207
5.473
4.897
4.432
181.18
196.25
218.9
236.2
250.2
262.2
272.8
282.2
290.7
298.6
969.5
959.9
945.2
933.7
924.0
915.6
908.0
901.2
894.8
888.9
1150.7
1156.2
1164.1
1169.8
1174.2
1177.8
1180.8
1183.3
1185.6
1187.5
0.3137
0.3358
0.3682
0.3921
0.4113
0.4273
0.4412
0.4534
0.4644
0.4744
1.4413
1.3961
1.3313
1.2845
1.2475
1.2169
1.1907
1.1678
1.1473
1.1288
1.7549
1.7319
1.6995
1.6766
1.6588
1.6443
1.6319
1.6212
1.6117
1.6032
181.13
196.18
218.8
236.0
250.1
262.0
272.5
281.9
290.4
298.2
1077.7
1081.8
1087.8
1092.1
1095.4
1098.1
1100.4
1102.3
1104.0
1105.5
15
20
30
40
50
60
70
80
90
100
120
140
160
180
200
341.26
353.04
363.55
373.08
381.81
0.01789
0.01802
0.01815
0.01827
0.01839
3.7107
3.2019
2.8163
2.5137
2.2696
3.729
3.220
2.834
2.532
2.288
312.6
325.0
336.1
346.2
355.5
878.1
868.4
859.4
851.1
843.3
1190.7
1193.4
1195.5
1197.3
1198.8
0.4920
0.5072
0.5207
0.5328
0.5439
1.0964
1.0685
1.0440
1.0220
1.0021
1.5883
1.5757
1.5647
1.5549
1.5460
312.2
324.5
335.6
345.6
354.9
1108.0
1110.0
1111.6
1113.0
1114.1
120
140
160
180
200
250
300
350
400
450
400.98
417.37
431.75
444.63
456.32
0.01865
0.01890
0.01913
0.0193
0.0196
1.8252
1.5245
1.3071
1.14225
1.01283
1.8439
1.5434
1.3262
1.1616
1.0324
376.2
394.0
409.8
424.2
437.3
825.4
809.4
794.6
780.9
767.9
1201.6
1203.4
1204.5
1205.0
1205.2
0.5679
0.5883
0.6060
0.6217
0.6360
0.9591
0.9229
0.8914
0.8635
0.8383
1.5270
1.5111
1.4974
1.4853
1.4743
375.3
393.0
408.6
422.7
435.7
1116.3
1117.7
1118.6
1119.1
1119.2
250
300
350
400
450
500
550
600
700
800
467.05
476.98
486.25
503.14
518.27
0.0198
0.0199
0.0201
0.0205
0.0209
0.90840
0.82229
0.75002
0.63535
0.54830
0.9282
0.8422
0.7702
0.6559
0.5692
449.5
460.9
471.7
491.6
509.8
755.5
743.6
732.2
710.3
689.5
1205.0
1204.6
1203.9
1201.9
1199.3
0.6490
0.6611
0.6723
0.6928
0.7112
0.8152
0.7939
0.7740
0.7377
0.7050
1.4643
1.4550
1.4464
1.4305
1.4162
447.7
458.9
469.5
489.0
506.7
1119.1
1118.8
1118.4
1117.0
1115.0
500
550
600
700
800
900
1000
1100
1200
1300
1400
1500
2000
2500
3000
3200.11
532.02
544.65
556.35
567.26
577.50
587.14
596.27
635.85
668.17
695.41
705.1028
0.0212
0.0216
0.0220
0.0223
0.0227
0.0231
0.0235
0.0256
0.0286
0.0344
0.0497
0.47983
0.42446
0.37869
0.34014
0.30718
0.27861
0.25357
0.16255
0.10208
0.05015
0
0.5011
0.4461
0.4006
0.3625
0.3299
0.3017
0.2770
0.1882
0.1307
0.0845
0.0498
526.7
542.6
557.6
571.8
585.5
598.8
611.6
671.8
730.8
802.9
897.5
669.4
650.0
631.0
612.4
593.9
575.7
557.4
464.7
360.7
213.6
0
1196.2
1192.6
1188.6
1184.2
1179.5
1174.4
1169.0
1136.5
1091.5
1016.5
897.5
0.7279
0.7434
0.7578
0.7714
0.7843
0.7966
0.8084
0.8622
0.9130
0.9736
1.0538
0.6751
0.6472
0.6211
0.5963
0.5727
0.5499
0.5279
0.4242
0.3199
0.1849
0
1.4030
1.3906
1.3789
1.3677
1.3570
1.3465
1.3363
1.2864
1.2329
1.1585
1.0538
523.2
538.6
553.1
566.9
580.1
592.8
605.1
662.3
717.6
783.8
868.0
1112.7
1110.0
1107.0
1103.7
1100.1
1096.3
1092.1
1066.9
1031.1
969.5
868.0
1
2
3
4
5
6
7
8
9
10
14.696
900
1000
1100
1200
1300
1400
1500
2000
2500
3000
3200.11
1. See Note 1, Table 1.
2. See Note 2, Table 1.
Steam 41 / Thermodynamics of Steam
2-3
The Babcock & Wilcox Company
Table 3
Properties of Superheated Steam and Compressed Water (Temperature and Pressure)
Press., psia
(sat. temp)
V
1
(101.74)
H
S
V
5
(162.24)
H
S
V
10
(193.21)
H
S
V
15
(213.03)
H
S
V
20
(227.96)
H
S
V
40
(267.25)
H
S
V
60
(292.71)
H
S
V
80
(312.04)
H
S
V
100
(327.82)
H
S
V
120
(341.27)
H
S
V
140
(353.04)
H
S
V
160
(363.55)
H
S
V
180
(373.08)
H
S
V
200
(381.80)
H
S
V
250
(400.97)
H
S
V
300
(417.35)
H
S
V
350
(431.73)
H
S
V
400
(444.60)
H
S
V
500
(467.01)
H
S
Temperature, F
700
800
100
200
300
400
500
600
0.0161
68.00
0.1295
392.5
1150.2
2.0509
452.3
1195.7
2.1152
511.9
1241.8
2.1722
571.5
1288.6
2.2237
631.1
1336.1
2.2708
690.7
1384.5
2.3144
0.0161
68.01
0.1295
78.14
1148.6
1.8716
90.24
1194.8
1.9369
102.24
1241.3
1.9943
114.21
1288.2
2.0460
126.15
1335.9
2.0932
138.08
1384.3
2.1369
0.0161
68.02
0.1295
38.84
1146.6
1.7928
44.98
1193.7
1.8593
51.03
1240.6
1.9173
57.04
1287.8
1.9692
63.03
1335.5
2.0166
0.0161
68.04
0.1295
0.0166
168.09
0.2940
29.899
1192.5
1.8134
33.963
1239.9
1.8720
37.985
1287.3
1.9242
0.0161
68.05
0.1295
0.0166
168.11
0.2940
22.356
1191.4
1.7805
25.428
1239.2
1.8397
0.0161
68.10
0.1295
0.0166
168.15
0.2940
11.036
1186.6
1.6992
0.0161
68.15
0.1295
0.0166
168.20
0.2939
0.0161
68.21
0.1295
1
900
1000
1100
1200
1300
1400
1500
150.01
1433.6
2.1776
161.94
1483.7
2.2159
173.86
1534.7
2.2521
185.78
1586.7
2.2866
197.70
1639.6
2.3194
209.62
1693.3
2.3509
221.53
1748.0
2.3811
233.45
1803.5
2.4101
69.00
1384.0
2.0603
74.98
1433.4
2.1011
80.94
1483.5
2.1394
86.91
1534.6
2.1757
92.87
1586.6
2.2101
98.84
1639.5
2.2430
104.80
1693.3
2.2744
110.76
1747.9
2.3046
116.72
1803.4
2.3337
41.986
1335.2
1.9717
45.978
1383.8
2.0155
49.964
1433.2
2.0563
53.946
1483.4
2.0946
57.926
1534.5
2.1309
61.905
1586.5
2.1653
65.882
1639.4
2.1982
69.858
1693.2
2.2297
73.833
1747.8
2.2599
77.807
1803.4
2.2890
28.457
1286.9
1.8921
31.466
1334.9
1.9397
34.465
1383.5
1.9836
37.458
1432.9
2.0244
40.447
1483.2
2.0628
43.435
1534.3
2.0991
46.420
1586.3
2.1336
49.405
1639.3
2.1665
52.388
1693.1
2.1979
55.370
1747.8
2.2282
58.352
1803.3
2.2572
12.624
1236.4
1.7608
14.165
1285.0
1.8143
15.685
1333.6
1.8624
17.195
1382.5
1.9065
18.699
1432.1
1.9476
20.199
1482.5
1.9860
21.697
1533.7
2.0224
23.194
1585.8
2.0569
24.689
1638.8
2.0899
26.183
1992.7
2.1224
27.676
1747.5
2.1516
29.168
1803.0
2.1807
7.257
1181.6
1.6492
8.354
1233.5
1.7134
9.400
1283.2
1.7681
10.425
1332.3
1.8168
11.438
1381.5
1.8612
12.446
1431.3
1.9024
13.450
1481.8
1.9410
14.452
1533.2
1.9774
15.452
1585.3
2.0120
16.450
1638.4
2.0450
17.448
1692.4
2.0765
18.445
1747.1
2.1068
19.441
1802.8
2.1359
0.0166
168.24
0.2939
0.0175
269.74
0.4371
6.218
1230.5
1.6790
7.018
1281.3
1.7349
7.794
1330.9
1.7842
8.560
1380.5
1.8289
9.319
1430.5
1.8702
10.075
1481.1
1.9089
10.829
1532.6
1.9454
11.581
1584.9
1.9800
12.331
1638.0
2.0131
13.081
1692.0
2.0446
13.829
1746.8
2.0750
14.577
1802.5
2.1041
0.0161
68.26
0.1295
0.0166
168.29
0.2939
0.0175
269.77
0.4371
4.935
1227.4
1.6516
5.588
1279.3
1.7088
6.216
1329.6
1.7586
6.833
1379.5
1.8036
7.443
1429.7
1.8451
8.050
1480.4
1.8839
8.655
1532.0
1.9205
9.258
1584.4
1.9552
9.860
1637.6
1.9883
10.460
1691.6
2.0199
11.060
1746.5
2.0502
11.659
1802.2
2.0794
0.0161
68.31
0.1295
0.0166
168.33
0.2939
0.0175
269.81
0.4371
4.0786
1224.1
1.6286
4.6341
1277.4
1.6872
5.1637
1328.1
1.7376
5.6831
1378.4
1.7829
6.1928
1428.8
1.8246
6.7006
1479.8
1.8635
7.2060
1531.4
1.9001
7.7096
1583.9
1.9349
8.2119
1637.1
1.9680
8.7130
1691.3
1.9996
9.2134
1746.2
2.0300
9.7130
1802.0
2.0592
0.0161
68.37
0.1295
0.0166
168.38
0.2939
0.0175
269.85
0.4370
3.4661
1220.8
1.6085
3.9526
1275.3
1.6686
4.4119
1326.8
1.7196
4.8585
1377.4
1.7652
5.2995
1428.0
1.8071
5.7364
1479.1
1.8461
6.1709
1530.8
1.8828
6.6036
1583.4
1.9176
7.0349
1636.7
1.9508
7.4652
1690.9
1.9825
7.8946
1745.9
2.0129
8.3233
1801.7
2.0421
0.0161
68.42
0.1294
0.0166
168.42
0.2938
0.0175
269.89
0.4370
3.0060
1217.4
1.5906
3.4413
1273.3
1.6522
3.8480
1325.4
1.7039
4.2420
1376.4
1.7499
4.6295
1427.2
1.7919
5.0132
1478.4
1.8310
5.3945
1530.3
1.8678
5.7741
1582.9
1.9027
6.1522
1636.3
1.9359
6.5293
1690.5
1.9676
6.9055
1745.6
1.9980
7.2811
1801.4
2.0273
0.0161
68.47
0.1294
0.0166
168.47
0.2938
0.0174
269.92
0.4370
2.6474
1213.8
1.5743
3.0433
1271.2
1.6376
3.4093
1324.0
1.6900
3.7621
1375.3
1.7362
4.1084
1426.3
1.7784
4.4505
1477.7
1.8176
4.7907
1529.7
1.8545
5.1289
1582.4
1.8894
5.4657
1635.9
1.9227
5.8014
1690.2
1.9545
6.1363
1745.3
1.9849
6.4704
1801.2
2.0142
0.0161
68.52
0.1294
0.0166
168.51
0.2938
0.0174
269.96
0.4369
2.3598
1210.1
1.5593
2.7247
1269.0
1.6242
3.0583
1322.6
1.6776
3.3783
1374.3
1.7239
3.6915
1425.5
1.7663
4.0008
1477.0
1.8057
4.3077
1529.1
1.8426
4.6128
1581.9
1.8776
4.9165
1635.4
1.9109
5.2191
1689.8
1.9427
5.5209
1745.0
1.9732
5.8219
1800.9
2.0025
0.0161
68.66
0.1294
0.0166
168.63
0.2937
0.0174
270.05
0.4368
0.0186
375.10
0.5667
2.1504
1263.5
1.5951
2.4662
1319.0
1.6502
2.6872
1371.6
1.6976
2.9410
1423.4
1.7405
3.1909
1475.3
1.7801
3.4382
1527.6
1.8173
3.6837
1580.6
1.8524
3.9278
1634.4
1.8858
4.1709
1688.9
1.9177
4.4131
1744.2
1.9482
4.6546
1800.2
1.9776
0.0161
68.79
0.1294
0.0166
168.74
0.2937
0.0174
270.14
0.4307
0.0186
375.15
0.5665
1.7665
1257.7
1.5703
2.0044
1315.2
1.6274
2.2263
1368.9
1.6758
2.4407
1421.3
1.7192
2.6509
1473.6
1.7591
2.8585
1526.2
1.7964
3.0643
1579.4
1.8317
3.2688
1633.3
1.8652
3.4721
1688.0
1.8972
3.6746
1743.4
1.9278
3.8764
1799.6
1.9572
00161
68.92
0.1293
0.0166
168.85
0.2936
0.0174
270.24
0.4367
0.0186
375.21
0.5664
1.4913
1251.5
1.5483
1.7028
1311.4
1.6077
1.8970
1366.2
1.6571
2.0832
1419.2
1.7009
2.2652
1471.8
1.7411
2.4445
1524.7
1.7787
2.6219
1578.2
1.8141
2.7980
1632.3
1.8477
2.9730
1687.1
1.8798
3.1471
1742.6
1.9105
3.3205
1798.9
1.9400
0.0161
69.05
0.1293
0.0166
168.97
0.2935
0.0174
270.33
0.4366
0.0162
375.27
0.5663
1.2841
1245.1
1.5282
1.4763
1307.4
1.5901
1.6499
1363.4
1.6406
1.8151
1417.0
1.6850
1.9759
1470.1
1.7255
2.1339
1523.3
1.7632
2.2901
1576.9
1.7988
2.4450
1631.2
1.8325
2.5987
1686.2
1.8647
2.7515
1741.9
1.8955
2.9037
1798.2
1.9250
0.0161
69.32
0.1292
0.0166
169.19
0.2934
0.0174
270.51
.04364
0.0186
375.38
0.5660
0.9919
1231.2
1.4921
1.1584
1299.1
1.5595
1.3037
1357.7
1.6123
1.4397
1412.7
1.6578
1.5708
1466.6
1.6690
1.6992
1520.3
1.7371
1.8256
1574.4
1.7730
1.9507
1629.1
1.8069
2.0746
1684.4
1.8393
2.1977
1740.3
1.8702
2.3200
1796.9
1.8998
1. See Notes 1 and 2, Table 1.
2-4
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
Table 3
Properties of Superheated Steam and Compressed Water (Temperature and Pressure)
Press., psia
(sat. temp)
V
600
(486.20)
H
S
V
700
(503.08)
H
S
V
800
(518.21)
H
S
V
900
(531.95)
H
S
V
1000
(544.58)
H
S
V
1100
(556.28)
H
S
V
1200
(567.19)
H
S
V
1400
(587.07)
H
S
V
1600
(604.87)
H
S
V
1800
(621.02)
H
S
V
2000
(635.80)
H
S
V
2500
(668.11)
H
S
V
3000
(695.33)
H
S
V
3200
(705.08)
H
S
V
3500
H
S
V
4000
H
S
V
5000
H
S
V
6000
H
S
V
7000
H
S
Temperature, F
700
800
1
100
200
300
400
500
600
900
1000
1100
1200
1300
1400
1500
0.0161
69.58
0.1292
0.0166
169.42
0.2933
0.0174
270.70
0.4362
0.0186
375.49
0.5657
0.7944
1215.9
1.4590
0.9456
1290.3
1.5329
1.0726
1351.8
1.5844
1.1892
1408.3
1.6351
1.3008
1463.0
1.6769
1.4093
1517.4
1.7155
1.5160
1571.9
1.7517
1.6211
1627.0
1.7859
1.7252
1682.6
1.8184
1.8284
1738.8
1.8494
1.9309
1795.6
1.8792
0.0161
69.84
0.1291
0.0166
169.65
0.2932
0.0174
270.89
0.4360
0.0186
375.61
0.5655
0.0204
487.93
0.6889
0.7928
1281.0
1.5090
0.9072
1345.6
1.5673
1.0102
1403.7
1.6154
1.1078
1459.4
1.6580
1.2023
1514.4
1.6970
1.2948
1569.4
1.7335
1.3858
1624.8
1.7679
1.4757
1680.7
1.8006
1.5647
1737.2
1.8318
1.6530
1794.3
1.8617
0.0161
70.11
0.1290
0.0166
169.88
0.2930
0.0174
271.07
0.4358
0.0186
375.73
0.5652
0.0204
487.88
0.6885
0.6774
1271.1
1.4869
0.7828
1339.2
1.5484
0.8759
1399.1
1.5980
0.9631
1455.8
1.6413
1.0470
1511.4
1.6807
1.1289
1566.9
1.7175
1.2093
1622.7
1.7522
1.2885
1678.9
1.7851
1.3669
1735.0
1.8164
1.4446
1792.9
1.8464
0.0161
70.37
0.1290
0.0166
170.10
0.2929
0.0174
271.26
0.4357
0.0186
375.84
0.5649
0.0204
487.83
0.6881
0.5869
1260.6
1.4659
0.6858
1332.7
1.5311
0.7713
1394.4
1.5822
0.8504
1452.2
1.6263
0.9262
1508.5
1.6662
0.9998
1564.4
1.7033
1.0720
1620.6
1.7382
1.1430
1677.1
1.7713
1.2131
1734.1
1.8028
1.2825
1791.6
1.8329
0.0161
70.63
0.1289
0.0166
170.33
0.2928
0.0174
271.44
0.4355
0.0186
375.96
0.5647
0.0204
487.79
0.6876
0.5137
1249.3
1.4457
0.6080
1325.9
1.5149
0.6875
1389.6
1.5677
0.7603
1448.5
1.6126
0.8295
1504.4
1.6530
0.8966
1561.9
1.6905
0.9622
1618.4
1.7256
1.0266
1675.3
1.7589
1.0901
1732.5
1.7905
1.1529
1790.3
1.8207
0.0161
70.90
0.1289
0.0166
170.56
0.2927
0.0174
271.63
0.4353
0.0185
376.08
0.5644
0.0203
487.75
0.6872
0.4531
1237.3
1.4259
0.5440
1318.8
1.4996
0.6188
1384.7
1.5542
0.6865
1444.7
1.6000
0.7505
1502.4
1.6410
0.8121
1559.4
1.6787
0.8723
1616.3
1.7141
0.9313
1673.5
1.7475
0.9894
1731.0
1.7793
1.0468
1789.0
1.8097
0.0161
71.16
0.1288
0.0166
170.78
0.2926
0.0174
271.82
0.4351
0.0185
376.20
0.5642
0.0203
487.72
0.6868
0.4016
1224.2
1.4061
0.4905
1311.5
1.4851
0.5615
1379.7
1.5415
0.6250
1440.9
1.5883
0.6845
1499.4
1.6298
0.7418
1556.9
1.6679
0.7974
1614.2
1.7035
0.8519
1671.6
1.7371
0.9055
1729.4
1.7691
0.9584
1787.6
1.7996
0.0161
71.68
0.1287
0.0166
171.24
0.2923
0.0174
272.19
0.4348
0.0185
376.44
0.5636
0.0203
487.65
0.6859
0.3176
1194.1
1.3652
0.4059
1296.1
1.4575
0.4712
1369.3
1.5182
0.5282
1433.2
1.5670
0.5809
1493.2
1.6096
0.6311
1551.8
1.6484
0.6798
1609.9
1.6845
0.7272
1668.0
1.7185
0.7737
1726.3
1.7508
0.8195
1785.0
1.7815
0.0161
72.21
0.1286
0.0166
171.69
0.2921
0.0173
272.57
0.4344
0.0185
376.69
0.5631
0.0202
487.60
0.6851
0.0236
616.77
0.8129
0.3415
1279.4
1.4312
0.4032
1358.5
1.4968
0.4555
1425.2
1.5478
0.5031
1486.9
1.5916
0.5482
1546.6
1.6312
0.5915
1605.6
1.6678
0.6336
1664.3
1.7022
0.6748
1723.2
1.7344
0.7153
1782.3
1.7657
0.0160
72.73
0.1284
0.0165
172.15
0.2918
0.0173
272.95
0.4341
0.0185
376.93
0.5626
0.0202
487.56
0.6843
0.0235
615.58
0.8109
0.2906
1261.1
1.4054
0.3500
1347.2
1.4768
0.3988
1417.1
1.5302
0.4426
1480.6
1.5753
0.4836
1541.1
1.6156
0.5229
1601.2
1.6528
0.5609
1660.7
1.6876
0.5980
1720.1
1.7204
0.6343
1779.7
1.7516
0.0160
73.26
0.1283
0.0165
172.60
0.2916
0.0173
273.32
0.4337
0.0184
377.19
0.5621
0.0201
487.53
0.6834
0.0233
614.48
0.8091
0.2488
1240.9
1.3794
0.3072
1353.4
1.4578
0.3534
1408.7
1.5138
0.3942
1474.1
1.5603
0.4320
1536.2
1.6014
0.4680
1596.9
1.6391
0.5027
1657.0
1.6743
0.5365
1717.0
1.7075
0.5695
1777.1
1.7389
0.0160
74.57
0.1280
0.0165
173.74
0.2910
0.0173
274.27
0.4329
0.0184
377.82
0.5609
0.0200
487.50
0.6815
0.0230
612.08
0.8048
0.1681
1176.7
1.3076
0.2293
1303.4
1.4129
0.2712
1386.7
1.4766
0.3068
1457.5
1.5269
0.3390
1522.9
1.5703
0.3692
1585.9
1.6094
0.3980
1647.8
1.6456
0.4259
1709.2
1.6796
0.4529
1770.4
1.7116
0.0160
75.88
0.1277
0.0165
174.88
0.2904
0.0172
275.22
0.4320
0.0183
378.47
0.5597
0.0200
487.52
0.6796
0.0228
610.08
0.8009
0.0982
1060.5
1.1966
0.1759
1267.0
1.3692
0.2161
1363.2
1.4429
0.2484
1440.2
1.4976
0.2770
1509.4
1.5434
0.3033
1574.8
1.5841
0.3282
1638.5
1.6214
0.3522
1701.4
1.6561
0.3753
1761.8
1.6888
0.0160
76.4
0.1276
0.0165
175.3
0.2902
0.0172
275.6
0.4317
0.0183
378.7
0.5592
0.0199
487.5
0.6788
0.0227
609.4
0.7994
0.0335
800.8
0.9708
0.1588
1250.9
1.3515
0.1987
1353.4
1.4300
0.2301
1433.1
1.4866
0.2576
1503.8
1.5335
0.2327
1570.3
1.5749
0.3065
1634.8
1.6126
0.3291
1698.3
1.6477
0.3510
1761.2
1.6806
0.0160
77.2
0.1274
0.0164
176.0
0.2899
0.0172
276.2
0.4312
0.0183
379.1
0.5585
0.0199
487.6
0.6777
0.0225
608.4
0.7973
0.0307
779.4
0.9508
0.1364
1224.6
1.3242
0.1764
1338.2
1.4112
0.2066
1422.2
1.4709
0.2326
1495.5
1.5194
0.2563
1563.3
1.5618
0.2784
1629.2
1.6002
0.2995
1693.6
1.6358
0.3198
1757.2
1.6691
0.0159
78.5
0.1271
0.0164
177.2
0.2893
0.0172
277.1
0.4304
0.0182
379.8
0.5573
0.0198
487.7
0.6760
0.0223
606.9
0.7940
0.0287
763.0
0.9343
0.1052
1174.3
1.2754
0.1463
1311.6
1.3807
0.1752
1403.6
1.4461
0.1994
1481.3
1.4976
0.2210
1552.2
1.5417
0.2411
1619.8
1.5812
0.2601
1685.7
1.6177
0.2783
1750.6
1.6516
0.0159
81.1
0.1265
0.0164
179.5
0.2881
0.0171
279.1
0.4287
0.0181
381.2
0.5550
0.0196
488.1
0.6726
0.0219
604.6
0.7880
0.0268
746.0
0.9153
0.0591
1042.9
1.1593
0.1038
1252.9
1.3207
0.1312
1364.6
1.4001
0.1529
1452.1
1.4582
0.1718
1529.1
1.5061
0.1890
1600.9
1.5481
0.2050
1670.0
1.5863
0.2203
1737.4
1.6216
0.0159
83.7
0.1258
0.0163
181.7
0.2870
0.0170
281.0
0.4271
0.0180
382.7
0.5528
0.0195
488.6
0.6693
0.0216
602.9
0.7826
0.0256
736.1
0.9026
0.0397
945.1
1.0176
0.0757
1188.8
1.2615
0.1020
1323.6
1.3574
0.1221
1422.3
1.4229
0.1391
1505.9
1.4748
0.1544
1582.0
1.5194
0.1684
1654.2
1.5593
0.1817
1724.2
1.5962
0.0158
86.2
0.1252
0.0163
184.4
0.2859
0.0170
283.0
0.4256
0.0180
384.2
0.5507
0.0193
489.3
0.6663
0.0213
601.7
0.7777
0.0248
729.3
0.8926
0.0334
901.8
1.0350
0.0573
1124.9
1.2055
0.0816
1281.7
1.3171
0.1004
1392.2
1.3904
0.1160
1482.6
1.4466
0.1298
1563.1
1.4938
0.1424
1638.6
1.5355
0.1542
1711.1
1.5735
1. See Notes 1 and 2, Table 1.
Steam 41 / Thermodynamics of Steam
2-5
The Babcock & Wilcox Company
Fig. 1 Pressure-enthalpy chart for steam (English units).
2-6
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
where ms is the mass of steam and mw is the mass of
water. The quality is frequently recorded as a percent
steam by weight (% SBW) after multiplying by 100%.
The mixture enthalpy (H ) (see Note below), entropy
(s) and specific volume (v) of a steam-water mixture
can then be simply defined as:
H = Hf + x (Hg − Hf )
(2a)
s = sf + x ( s g − sf )
(2b)
v = vf + x (vg − vf )
(2c)
where the subscripts f and g refer to properties at saturated liquid and vapor conditions, respectively. The
difference in a property between saturated liquid and
vapor conditions is frequently denoted by the subscript
fg; for example, Hfg = Hg – Hf. With these definitions,
if the pressure or temperature of a steam-water mixture is known along with one of the mixture properties, the quality can then be calculated. For example,
if the mixture enthalpy is known, then:
x = ( H − H f ) / H fg
(3)
Engineering problems deal mainly with changes or
differences in enthalpy and entropy. It is not necessary to establish an absolute zero for these properties,
although this may be done for entropy. The Steam
Tables indicate an arbitrary zero internal energy and
entropy for the liquid state of water at the triple point
corresponding to a temperature of 32.018F (0.01C) and
a vapor pressure of 0.08865 psi (0.6112 kPa). The
triple point is a unique condition where the three states
of water (solid, liquid and vapor) coexist at equilibrium.
lations often rely on tabulated gas properties for
greater accuracy.
Tabulated gas properties are available from numerous sources. (See References 4 and 5 for examples.)
Unfortunately, there is less agreement on gas properties than on those for steam. The United States (U.S.)
boiler industry customarily uses 80F (27C) and 14.7
psia (101.35 kPa) as the zero enthalpy of air and combustion products. A more general reference is one atmosphere pressure, 14.696 psia (101.35 kPa), and 77F
(25C). This is the standard reference point for heats
of formation of compounds from elements in their
standard states, latent heats of phase changes and free
energy changes. Because of different engineering conventions, considerable care must be exercised when
using tabulated properties. Selected properties for air
and other gases are provided in Chapter 3, Table 3.
Conservation of mass and energy
Thermodynamic processes are governed by the laws
of conservation of mass and conservation of energy except for the special case of nuclear reactions discussed
in Chapter 47. These conservation laws basically state
that the total mass and total energy (in any of its forms)
can neither be created nor destroyed in a process. In an
open flowing power system, where mass continually
enters and exits a system such as Fig. 2, these laws can
take the forms:
Conservation of mass
m1 − m2 = ∆m
(5)
Conservation of energy
E2 − E1 + ∆E = Q − W
(6)
Properties of gases
In addition to steam, air is a common working fluid
for some thermodynamic cycles. As with steam, well defined properties are important in cycle analysis. Air and
many common gases used in power cycle applications
can usually be treated as ideal gases. An ideal gas is
defined as a substance that obeys the ideal gas law:
Pv = RT
(4)
where R is a constant which varies with gas species;
P and T are the pressure and temperature, respectively. R is equal to the universal gas constant, R [1545
ft lb/lb-mole R (8.3143 kJ/kg mole K)], divided by the
molecular weight of the gas. For dry air, R is equal to
53.34 lbf ft/lbm R (0.287 kJ/kg K). Values for other
gases are summarized in Reference 3. The ideal gas
law is commonly used in a first analysis of a process
or cycle because it simplifies calculations. Final calcuNote: To avoid confusion with the symbol for heat transfer coefficient, enthalpy (Btu/lb or kJ/kg) is denoted by H
in this chapter and the balance of Steam unless specially
noted. Enthalpy is frequently denoted by h in thermodynamic texts.
Steam 41 / Thermodynamics of Steam
Fig. 2 Diagram illustrating thermodynamic processes.
2-7
The Babcock & Wilcox Company
where m is the mass flow, ∆m is the change in internal system mass, E is the total energy flowing into or
out of the processes, ∆E is the change in energy stored
in the system with time, Q is the heat added to the system, W is the work removed, and the subscripts 1 and
2 refer to inlet and outlet conditions respectively. For
steady-state conditions ∆m and ∆E are zero.
The conservation of energy states that a balance
exists between energy, work, and heat quantities entering and leaving the system. This balance of energy
flow is also referred to as the first law of thermodynamics. The terms on the left side of Equation 6 represent stored energy entering or leaving the system
as part of the mass flows and the accumulation of total stored energy within the system. The terms on the
right side are the heat transferred to the system, Q,
and work done by the system, W. The stored energy
components, represented by the term E, consist of the
internally stored energy and the kinetic and potential energy. In an open system, there is work required
to move mass into the system and work done by the
system to move mass out. In each case, the total work
is equal to the product of the mass, the system pressure, and the specific volume. Separating this work
from other work done by the system and including a
breakdown of the stored energy, the energy conservation equation becomes:
V
V
+ z − m1 u + Pv +
+ z
m2 u + Pv +
2 gc
2 gc
2
1 (7)
+ ∆E = Q − Wk
2
2
where m is the mass, u is the internal stored energy,
P is the system pressure, V is the fluid velocity, v is the
specific volume, z is the elevation, and Wk is the sum
of the work done by the system.
In this form, the work terms associated with mass
moving into and out of the system (Pv) have been
grouped with the stored energy crossing the system boundary. Wk represents all other work done by the system.
For many practical power applications, the energy
equation can be further simplified for steady-state processes. Because the mass entering and leaving the system over any time interval is the same, dividing Equation 7 by the mass (m2 or m1 because they are equal)
yields a simple balance between the change in stored
energy due to inflow and outflow and the heat and
work terms expressed on a unit mass basis. Heat and
work expressed on a unit mass basis are denoted q and
w, respectively. The unsteady term for system stored energy in Equation 7 is then set to zero. This yields the
following form of the energy conservation equation:
∆u + ∆ ( Pv ) + ∆
g
V2
+ ∆z
= q − wk
gc
2 gc
(8)
Each ∆ term on the left in Equation 8 represents
the difference in the fluid property or system characteristic between the system outlet and inlet. ∆u is the
difference in internally stored energy associated with
molecular and atomic motions and forces. Internally
stored energy, or simply internal energy, accounts for
2-8
all forms of energy other than the kinetic and potential
energies of the collective molecule masses. This is possible
because no attempt is made to absolutely define u.
The term ∆(Pv) can be viewed as externally stored
energy in that it reflects the work required to move a
unit mass into and out of the system. The remaining
terms of externally stored energy, ∆(V 2 /2gc) and ∆z,
depend on physical aspects of the system. ∆(V 2 /2gc) is
the difference in total kinetic energy of the fluid between two reference points (system inlet and outlet).
∆zg/gc represents the change in potential energy due
to elevation, where g is the gravitational constant 32.17
ft/s2 (9.8 m/s2) and gc is a proportionality constant for
English units. The value of the constant is obtained
from equivalence of force and mass times acceleration:
Force =
mass × acceleration
gc
(9)
In the English system, by definition, when 1 lb
force (lbf) is exerted on a 1 lb mass (lbm), the mass
accelerates at the rate of 32.17 ft/s2. In the SI system,
1 N of force is exerted by 1 kg of mass accelerating at
1 m/s2. Therefore, the values of gc are:
gc = 32.17 lbm ft / lbf s2
(10a)
gc = 1 kg m / N s2
(10b)
Because of the numerical equivalency between g and
gc in the English system, the potential energy term in
Equation 8 is frequently shown simply as ∆z. When SI
units are used, this term is often expressed simply as ∆zg
because the proportionality constant has a value of 1.
While many texts use the expression lbf to designate
lb force and lbm to designate lb mass, this is not done
in this text because it is believed that it is generally clear
simply by using lb. As examples, the expression Btu/lb
always means Btu/lb mass, and the expression ft lb/lb
always means ft lb force/lb mass.
Application of the energy equation requires dimensional consistency of all terms and proper conversion
constants are inserted as necessary. For example, the
terms u and q, usually expressed in Btu/lb or J/kg,
may be converted to ft lb/lb or N m/kg when multiplied by J, the mechanical equivalent of heat. This
conversion constant, originally obtained by Joule’s experiments between 1843 and 1878, is defined as:
J = 778.17 ft lbf / Btu
(11a)
J = 1 Nm / J
(11b)
Particular attention should be given to the sign convention applied to heat and work quantities. Originating with the steam engine analysis, heat quantities
are defined as positive when entering the system and
work (for example, shaft work) is positive when leaving the system.
Because u and Pv of Equation 8 are system properties, their sum is also a system property. Because these
properties of state can not be changed independently
of one another and because the combination (u + Pv)
appears whenever mass enters or leaves the system,
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
it is customary to consider the sum (u + Pv) as a single
property H, called enthalpy.
H = u + ( Pv / J )
(12)
where Pv is divided by J to provide consistent units.
In steam applications, H is usually expressed in Btu/
lb or J/kg. The examples in the following section illustrate the application of the steady-state open system energy Equation 7 and the usefulness of enthalpy
in the energy balance of specific equipment.
u2 + ( P2 v2 / J ) − u1 − ( P1 v1 / J ) = wk / J
(13a)
H 2 − H1 = wk / J
(13b)
or
Equation 13 indicates that the work done by the steam
turbine, wk/J, is equal to the difference between the enthalpy of the steam entering and leaving. However, H1
and H2 are seldom both known and further description
of the process is required for a solution of most problems.
Steam boiler
The boiler does no work, therefore wk = 0. Because
∆z and ∆(V 2 /2gc) from the feedwater inlet (1) to the
steam outlet (2) are small compared to (H2 – H1), the
steady-state energy equation becomes:
(14)
Based on Equation 14 the heat added, q (positive),
in the boiler per unit mass of flow in is equal to the
difference between H2 of the steam leaving and H1 of
the feedwater entering. Assuming that the pressure
varies negligibly through the boiler and the drum
pressure is known, Equation 14 can be solved knowing the temperature of the incoming feedwater.
Water flow through a nozzle
For water flowing through a nozzle, the change in
specific volume is negligible. Commonly the change
in elevation, ∆z, the change in internal energy, ∆u,
the work done, wk, and the heat added, q, are negligible and the energy equation reduces to:
(V
2
2
) (
)
/ 2 gc − V12 / 2 gc = ( P1 − P2 ) v
(15)
The increase in kinetic energy of the water is given
by Equation 15 for the pressure drop (P1 – P2). If the
approach velocity to the nozzle, V1, is zero, Equation
15 becomes:
Steam 41 / Thermodynamics of Steam
(16)
Flow of a compressible fluid through a nozzle
In contrast to water flow, when steam, air or other
compressible fluid flows through a nozzle, the changes
in specific volume and internal energy are not negligible. In this case, assuming no change in elevation
∆z, Equation 8 becomes:
2
2
Steam turbine
To apply the energy equation, each plant component is considered to be a system, as depicted in Fig.
2. In many cases, ∆z, ∆(V 2 /2gc) and q from throttle (1)
to exhaust (2) of the steam turbine are small compared
to (H2 − H1). This reduces Equation 8 to:
2 gc ( P1 − P2 ) v
The quantity (P1 – P2) v is often referred to as the
static head.
(V
Applications of the energy equation
q = H 2 − H1
V2 =
) (
)
/ 2 gc − V12 / 2 gc = ( H1 − H 2 ) J
(17)
If the approach velocity, V1, is zero, this further simplifies to:
V2 =
2 gc J ( H1 − H 2 )
(18)
From this, it is evident that the velocity of a compressible fluid leaving a nozzle is a function of its entering
and leaving enthalpies. Unfortunately, as with the steam
turbine, H1 and H2 are seldom both known.
Compressor
If a compressible fluid moves through an adiabatic
compressor (q = 0, a convenient approximation) and
the change in elevation and velocity are small compared to (H2 – H1), the energy equation reduces to:
− wk / J = H 2 − H1
(19)
Note that wk is negative because the compressor does
work on the system. Therefore, the net effect of the
compressor is expressed as an increase in fluid enthalpy from inlet to outlet.
Pump
The difference between a pump and a compressor
is that the fluid is considered to be incompressible for
the pumping process; this is a good approximation for
water. For an incompressible fluid, the specific volume
is the same at the inlet and outlet of the pump. If the
fluid friction is negligible, then the internal energy
changes, ∆u, are set to zero and the energy equation
can be expressed as:
− wk = ( P2 − P1 ) v
(20)
Because all real fluids are compressible, it is important
to know what is implied by the term incompressible. The
meaning here is that the isothermal compressibility, kT,
given by
kT = −
1 δv
v δP
(21)
is assumed to be arbitrarily small and approaching
zero. Because neither v nor P is zero, δv must be zero
and v must be a constant. Also, for isothermal conditions (by definition) there can be no change in internal energy, u, due to pressure changes only.
2-9
The Babcock & Wilcox Company
Entropy and its application to processes
The preceding examples illustrate applications of the
energy balance in problems where a fluid is used for heat
transfer and shaft work. They also demonstrate the usefulness of the enthalpy property. However, as was
pointed out, H1 and H2 are seldom both known. Additional information is frequently provided by the first and
second laws of thermodynamics and their consequences.
The first and second laws of thermodynamics
The first law of thermodynamics is based on the
energy conservation expressed by Equation 6 and, by
convention, relates the heat and work quantities of
this equation to internally stored energy, u. Strictly
speaking, Equation 6 is a complete form of the first
law of thermodynamics. However, it is frequently useful to use the steady-state formulation provided in
Equation 8 and further simplify this for the special
case of 1) no change in potential energy due to gravity acting on the mass, and 2) no change in kinetic
energy of the mass as a whole. In a closed system
where only shaft work is permitted, these simplifying
assumptions permit the energy Equation 8 for a unit
mass to be reduced to:
∆u = q − ( wk / J )
(22a)
or in differential form
du = δ q − (δ wk / J )
(22b)
The first law treats heat and work as being interchangeable, although some qualifications must apply.
All forms of energy, including work, can be wholly converted to heat, but the converse is not generally true.
Given a source of heat coupled with a heat-work cycle,
such as heat released by high temperature combustion in a steam power plant, only a portion of this heat
can be converted to work. The rest must be rejected to
an energy sink, such as the atmosphere, at a lower
temperature. This is essentially the Kelvin statement
of the second law of thermodynamics. It can also be
shown that it is equivalent to the Clausius statement
wherein heat, in the absence of external assistance,
can only flow from a hotter to a colder body.
Concept and definition of entropy
Heat flow is a function of temperature difference.
If a quantity of heat is divided by its absolute temperature, the quotient can be considered a type of distribution property complementing the intensity factor of temperature. Such a property, proposed and
named entropy by Clausius, is widely used in thermodynamics because of its close relationship to the
second law.
Rather than attempt to define entropy (s) in an absolute sense, consider the significance of differences
in this property given by:
S2 − S1 = ∆S
2
=
2-10
δ qrev
× total system mass
T
1
∫
(23)
where
∆S = change in entropy, Btu/R (J/K)
qrev = reversible heat flow between thermodynamic
equilibrium states 1 and 2 of the system, Btu/
lb (J/kg)
T = absolute temperature, R (K)
Entropy is an extensive property, i.e., a quantity of
entropy, S, is associated with a finite quantity of mass,
m. If the system is closed and the entire mass undergoes a change from state 1 to 2, an intensive property
s is defined by S/m. The property s is also referred to
as entropy, although it is actually specific entropy. If
the system is open as in Fig. 2, the specific entropy is
calculated by dividing by the appropriate mass.
Use of the symbol δ instead of the usual differential operator d is a reminder that q depends on the
process and is not a property of the system (steam).
δ q represents only a small quantity, not a differential. Before Equation 23 can be integrated, qrev must
be expressed in terms of properties, and a reversible
path between the prescribed initial and final equilibrium states of the system must be specified. For example, when heat flow is reversible and at constant
pressure, qrev = cpdT. This may represent heat added
reversibly to the system, as in a boiler, or the equivalent of internal heat flows due to friction or other
irreversibilities. In these two cases, ∆s is always positive.
The same qualifications for δ hold in the case of
thermodynamic work. Small quantities of w similar in
magnitude to differentials are expressed as δ w.
Application of entropy to a reversible process
Reversible thermodynamic processes exist in theory
only; however, they serve an important function of defining limiting cases for heat flow and work processes.
The properties of a system undergoing a reversible process are constrained to be homogeneous because there
are no variations among subregions of the system. Moreover, during interchanges of heat or work between a
system and its surroundings, only corresponding potential gradients of infinitesimal magnitude may exist.
All actual processes are irreversible. To occur, they
must be under the influence of a finite potential difference. A temperature difference supplies this drive
and direction for heat flow. The work term, on the
other hand, is more complicated, because there are as
many different potentials (generalized forces) as there
are forms of work. However, the main concern here is
expansion work for which the potential is clearly a
pressure difference.
Regardless of whether a process is to be considered
reversible or irreversible, it must have specific beginning and ending points (limits) in order to be evaluated. To apply the first and second laws, the limits must
be equilibrium states. Nonequilibrium thermodynamics is beyond the scope of this text. Because the limits
of real processes are to be equilibrium states, any process can be approximated by a series of smaller reversible processes starting and ending at the same states
as the real processes. In this way, only equilibrium
conditions are considered and the substitute processes
can be defined in terms of the system properties. The
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
following lists the reversible processes for heat flow
and work:
Reversible Heat Flow
Constant pressure,
dP
Constant temperature, dT
Constant volume,
dv
w
Reversible Work
= 0 Constant pressure,
dP = 0
= 0 Constant temperature, dT = 0
= 0 Constant entropy,
ds = 0
=0
q =0
The qualification of these processes is that each describes
a path that has a continuous functional relationship on
coordinate systems of thermodynamic properties.
A combined form of the first and second laws is obtained by substituting δ qrev = Tds for δ q in Equation
22b, yielding:
du = Tds − δ wk
(24)
Because only reversible processes are to be used, δw
should also be selected with this restriction. Reversible work for the limited case of expansion work can
be written:
δ (wrev ) = Pdv
(25)
In this case, pressure is in complete equilibrium with
external forces acting on the system and is related to
v through an equation of state.
Substituting Equation 25 in 24, the combined expression for the first and second law becomes:
du = Tds − Pdv
finite net force on the boundary. Real processes can
be solved approximately, however, by substituting a
series of reversible processes. An example of such a
substitution is illustrated in Fig. 3, which represents
the adiabatic expansion of steam in a turbine or any
gas expanded from P1 to P2 to produce shaft work. T1,
P1 and P2 are known. The value of H1 is fixed by T1
and P1 for a single-phase condition (vapor) at the inlet. H1 may be found from the Steam Tables, a T-s diagram (Fig. 3) or, more conveniently, from an H-s (Mollier) diagram, shown in the chapter frontispiece. From
the combined first and second laws, the maximum energy available for work in an adiabatic system is (H1
− H3), as shown in Fig. 3, where H3 is found by the
adiabatic isentropic expansion (expansion at constant
entropy) from P1 to P2. A portion of this available energy, usually about 10 to 15%, represents work lost
(wL) due to friction and form loss, limiting ∆H for shaft
work to (H1 − H2). The two reversible paths used to
arrive at point b in Fig. 3 (path a to c at constant entropy, s, and path c to b at constant pressure) yield the
following equation:
( H1 − H3 )
− ( H 2 − H3 ) = H1 − H 2
Point b, identified by solving for H2, now fixes T2; v1
and v2 are available from separate tabulated values
of physical properties.
Note that ∆H 2-3 can be found from:
(26)
Equation 26, however, only applies to a system in
which the reversible work is entirely shaft work. To
modify this expression for an open system in which
flow work d(Pv) is also present, the quantity d(Pv) is
added to the left side of Equation 25 and added as
(Pdv + vdP) on the right side. The result is:
du + d ( Pv ) = Tds − Pdv + Pdv + vdP
(27a)
dH = Tds + vdP
(27b)
(28)
2
∆H 2−3 =
∫ Tds
(29)
3
or, graphically, the area on the T-s diagram (Fig. 3)
under the curve P2 from points c to b. Areas bounded
by reversible paths on the T-s diagram in general rep-
or
The work term vdP in Equation 27 now represents reversible shaft work in an open system, expressed on
a unit mass basis.
Because Tds in Equation 26 is equivalent to δ q, its
value becomes zero under adiabatic or zero heat transfer conditions (δ q = 0). Because T can not be zero, it
follows that ds = 0 and s is constant. Therefore, the
maximum work from stored energy in an open system during a reversible adiabatic expansion is ∫ vdP
at constant entropy. The work done is equal to the
decrease in enthalpy. Likewise for the closed system,
the maximum expansion work is –∫ Pdv at constant
entropy and is equal to the decrease in internal energy. These are important cases of an adiabatic isentropic expansion.
Irreversible processes
All real processes are irreversible due to factors such
as friction, heat transfer through a finite temperature
difference, and expansion through a process with a
Steam 41 / Thermodynamics of Steam
Fig. 3 Irreversible expansion, state a to state b.
2-11
The Babcock & Wilcox Company
resent q (heat flow per unit mass) between the system and its surroundings. However, the path a to b is
irreversible and the area under the curve has no significance. The area under path c to b, although it has
the form of a reversible quantity q, does not represent
heat added to the system but rather its equivalent in
internal heat flow. A similar situation applies to the relationship between work and areas under reversible
paths in a pressure-volume equation of state diagram.
Because of this important distinction between reversible and irreversible paths, care must be exercised in
graphically interpreting these areas in cycle analysis.
Returning to Fig. 3 and the path a to b, wL was considered to be a percentage of the enthalpy change
along the path a to c. In general, the evaluation should
be handled in several smaller steps (Fig. 4) for the following reason. Point b has a higher entropy than point
c and, if expansion to a pressure lower than P2 (Fig.
3) is possible, the energy available for this additional
expansion is greater than that at point c. In other
words, a portion of wL (which has the same effect as
heat added to the system) for the first expansion can
be recovered in the next expansion or stage. This is
the basis of the reheat factor used in analyzing expansions through a multistage turbine. Since the pressure curves are divergent on an H-s or T-s diagram,
the sum of the individual ∆Hs values (isentropic ∆H)
for individual increments of ∆P (or stages in an irreversible expansion) is greater than that of the reversible ∆Hs between the initial and final pressures (Fig.
4). Therefore the shaft work that can be achieved is
greater than that calculated by a simple isentropic
expansion between the two pressures.
Principle of entropy increase
Although entropy has been given a quantitative
meaning in previous sections, there are qualitative
aspects of this property which deserve special emphasis. An increase in entropy is a measure of that portion of process heat which is unavailable for conversion to work. For example, consider the constant pressure reversible addition of heat to a working fluid with
the resulting increase in steam entropy. The minimum
portion of this heat flow which is unavailable for shaft
work is equal to the entropy increase multiplied by the
absolute temperature of the sink to which a part of
the heat must be rejected (in accordance with the second law). However, because a reversible addition of
heat is not possible, incremental entropy increases also
occur due to internal fluid heating as a result of temperature gradients and fluid friction.
Even though the net entropy change of any portion of a fluid moving through a cycle of processes is
always zero because the cycle requires restoration of
all properties to some designated starting point, the
sum of all entropy increases has a special significance.
These increases in entropy, less any decreases due to
recycled heat within a regenerator, multiplied by the
appropriate sink absolute temperature (R or K) are
equal to the heat flow to the sink. In this case, the net
entropy change of the system undergoing the cycle is
zero, but there is an entropy increase of the surroundings. Any thermodynamic change that takes place,
2-12
Fig. 4 Three-stage irreversible expansion – ∆Hs1 + ∆Hs2 + ∆Hs3 >
∆Hsac.
whether it is a stand alone process or cycle of processes,
results in a net entropy increase when both the system and its surroundings are considered.
Cycles
To this point, only thermodynamic processes have
been discussed with minor references to the cycle. The
next step is to couple processes so heat may be converted to work on a continuous basis. This is done by
selectively arranging a series of thermodynamic processes in a cycle forming a closed curve on any system of thermodynamic coordinates. Because the main
interest is steam, the following discussion emphasizes
expansion or Pdv work. This relies on the limited differential expression for internal energy, Equation 26,
and enthalpy, Equation 27. However, the subject of
thermodynamics recognizes work as energy in transit under any potential other than differential temperature and electromagnetic radiation.
Carnot cycle
Sadi Carnot (1796 to 1832) introduced the concept
of the cycle and reversible processes. The Carnot cycle
is used to define heat engine performance as it constitutes a cycle in which all component processes are
reversible. This cycle, on a temperature-entropy diagram, is shown in Fig. 5a for a gas and in Fig. 5b for
a two-phase saturated fluid. Fig. 5c presents this cycle
for a nonideal gas, such as superheated steam, on
Mollier coordinates (entropy versus enthalpy).
Referring to Fig. 5, the Carnot cycle consists of the
following processes:
1. Heat is added to the working medium at constant
temperature (dT = 0) resulting in expansion work
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
and changes in enthalpy. (For an ideal gas,
changes in internal energy and pressure are zero
and, therefore, changes in enthalpy are zero.)
2. Adiabatic isentropic expansion (ds = 0) occurs with
expansion work and an equivalent decrease in enthalpy.
3. Heat is rejected to the surroundings at a constant
temperature and is equivalent to the compression
work and any changes in enthalpy.
4. Adiabatic isentropic compression occurs back to
the starting temperature with compression work
and an equivalent increase in enthalpy.
This cycle has no counterpart in practice. The only
way to carry out the constant temperature processes
in a one-phase system would be to approximate them
through a series of isentropic expansions and constant
pressure reheats for heat addition, and isentropic compressions with a series of intercoolers for heat rejections.
Another serious disadvantage of a Carnot gas engine
would be the small ratio of net work to gross work (net
work referring to the difference between the expansion
work and the compression work, and gross work being
expansion work). Even a two-phase cycle, such as Fig.
5b, would be subject to the practical mechanical difficulties of wet compression and, to a lesser extent, wet expansion where a vapor-liquid mixture exists.
Nevertheless, the Carnot cycle illustrates the basic
principles of thermodynamics and, because the processes
are reversible, the Carnot cycle offers the maximum
thermodynamic efficiency attainable between any given
temperatures of heat source and sink. The efficiency of
the cycle is defined as the ratio of the net work output to
the total heat input. Various texts refer to this ratio as
either thermodynamic efficiency, thermal efficiency, or
simply efficiency. Using the T-s diagram for the Carnot
cycle shown in Fig. 5a, the thermodynamic efficiency
depends solely on the temperatures at which heat addition and rejection occur:
η =
T1 − T2
T
= 1− 2
T1
T1
(30)
where
η =thermodynamic efficiency of the conversion
from heat into work
T1 =absolute temperature of heat source, R (K)
T2 =absolute temperature of heat sink, R (K)
The efficiency statement of Equation 30 can be extended to cover all reversible cycles where T1 and T2
are defined as mean temperatures found by dividing
the heat added and rejected reversibly by ∆s. For this
reason, all reversible cycles have the same efficiencies
when considered between the same mean temperature limits of heat source and heat sink.
Fig. 5 Carnot cycles.
Steam 41 / Thermodynamics of Steam
Rankine cycle
Early thermodynamic developments were centered
around the performance of the steam engine and, for
comparison purposes, it was natural to select a reversible cycle which approximated the processes related
to its operation. The Rankine cycle shown in Fig. 6,
proposed independently by Rankine and Clausius,
2-13
The Babcock & Wilcox Company
meets this objective. All steps are specified for the system only (working medium) and are carried out reversibly as the fluid cycles among liquid, two-phase
and vapor states. Liquid is compressed isentropically
from points a to b. From points b to c, heat is added
reversibly in the compressed liquid, two-phase and
finally superheat states. Isentropic expansion with
shaft work output takes place from points c to d and
unavailable heat is rejected to the atmospheric sink
from points d to a.
The main feature of the Rankine cycle is that compression (pumping) is confined to the liquid phase,
avoiding the high compression work and mechanical
problems of a corresponding Carnot cycle with twophase compression. This part of the cycle, from points
a to b in Fig. 6, is greatly exaggerated, because the
difference between the saturated liquid line and point
b (where reversible heat addition begins) is too small
to show in proper scale. For example, the temperature
rise with isentropic compression of water from a saturation temperature of 212F (100C) and one atmosphere to 1000 psi (6.89 MPa) is less than 1F (0.6C).
If the Rankine cycle is closed in the sense that the
fluid repeatedly executes the various processes, it is
termed a condensing cycle. Although the closed, condensing Rankine cycle was developed to improve
steam engine efficiency, a closed cycle is essential for
any toxic or hazardous working fluid. Steam has the
important advantage of being inherently safe. However, the close control of water chemistry required in
high pressure, high temperature power cycles also
favors using a minimum of makeup water. (Makeup
is the water added to the steam cycle to replace leakage and other withdrawals.) Open steam cycles are
still found in small units, some special processes, and
heating load applications coupled with power. The condensate from process and heating loads is usually returned to the power cycle for economic reasons.
The higher efficiency of the condensing steam cycle
is a result of the pressure-temperature relationship
between water and its vapor state, steam. The lowest
temperature at which an open, or noncondensing,
Fig. 6 Temperature-entropy diagram of the ideal Rankine cycle.
2-14
steam cycle may reject heat is approximately 212F
(100C), the saturation temperature corresponding to
atmospheric pressure of 14.7 psi (101.35 kPa). The
pressure of the condensing fluid can be set at or below atmospheric pressure in a closed cycle. This takes
advantage of the much lower sink temperature available for heat rejection in natural bodies of water and
the atmosphere. Therefore, the condensing temperature in the closed cycle can be 100F (38C) or lower.
Fig. 7 illustrates the difference between an open and
closed Rankine cycle. Both cycles are shown with
nonideal expansion processes. Liquid compression
takes place from points a to b and heat is added from
points b to c. The work and heat quantities involved
in each of these processes are the same for both cycles.
Expansion and conversion of stored energy to work
take place from points c to d´ for the open cycle and
from c to d for the closed cycle. Because this process is
shown for the irreversible case, there is internal fluid
heating and an entropy increase. From points d´ to a,
and d to a, heat is rejected in order to condense the
steam. Because this last portion of the two cycles is
shown as reversible, the shaded areas are proportional
to the rejected heat. The larger amount of rejected
heat for the open cycle is evident and is directly related to the lower amount of work that can be done
by the expansion process.
Regenerative Rankine cycle
The reversible cycle efficiency given by Equation
30, where T2 and T1 are mean absolute temperatures
for rejecting and adding heat respectively, indicates
only three choices for improving ideal cycle efficiency:
decreasing T2, increasing T1, or both. Little can be
done to reduce T2 in the Rankine cycle because of the
limitations imposed by the temperatures of available
rejected heat sinks in the general environment. Some
T2 reduction is possible by selecting variable condenser
pressures for very large units with two or more exhaust hoods, because the lowest temperature in the
condenser is set by the lowest temperature of the cooling water. On the other hand, there are many ways
to increase T1 even though the steam temperature
may be limited by high temperature corrosion and allowable stress properties of the material.
One early improvement to the Rankine cycle was the
adoption of regenerative feedwater heating. This is done
by extracting steam from various stages in the turbine
to heat the feedwater as it is pumped from the bottom
of the condenser (hot well) to the boiler economizer.
Fig. 8 is a diagram of a widely used supercritical
pressure steam cycle showing the arrangement of various components including the feedwater heaters. This
cycle also contains one stage of steam reheat, which
is another method of increasing the mean T1. Regardless of whether the cycle is high temperature, high
pressure or reheat, regeneration is used in all modern condensing steam power plants. It improves cycle
efficiency and has other advantages, including lower
volume flow in the final turbine stages and a convenient means of deaerating the feedwater. In the power
plant heat balances shown in Fig. 8 and later in Fig.
10, several parameters require definition:
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
Fig. 7 Rankine cycles.
DC: In the feedwater heater blocks, this parameter
is the drain cooler approach temperature or the
difference between the shell-side condensate
outlet (drain) temperature and the feedwater
inlet temperature.
TD: In the feedwater heater blocks, this parameter
is the terminal temperature difference or the
difference between the shell-side steam inlet temperature and the feedwater outlet temperature.
P: In the feedwater heater blocks, this parameter
is the nominal shell-side pressure.
The temperature-entropy diagram of Fig. 9 for the
steam cycle of Fig. 8 illustrates the principle of regeneration in which the mean temperature level is increased for
heat addition. Instead of heat input starting at the hot
well temperature of 101.1F (38.4C), the water entering
the boiler economizer has been raised to 502F (261C) by
the feedwater heaters.
Fig. 9 also shows that the mean temperature level
for heat addition is increased by reheating the steam
after a portion of the expansion has taken place. Because maximum temperatures are limited by physical or economic reasons, reheating after partial expansion of the working fluid is also effective in raising the
average T1. The hypothetical case of an infinite number of reheat and expansion stages approaches a constant temperature heat addition of the Carnot cycle,
at least in the superheat region. It would appear beneficial to set the highest temperature in the superheat
reheat stage at the temperature limit of the working
medium or its containment. However, merely increasing T1 may not improve efficiency. If the entropy increase accompanying reheat causes the final expansion process to terminate in superheated vapor, the
mean temperature for heat rejection, T2, has also been
increased unless the superheat can be extracted in a
regenerative heater, adding heat to the boiler
feedwater. Such a regenerative heater would have to
operate at the expense of the very effective cycle. All
Steam 41 / Thermodynamics of Steam
of these factors, plus component design limitations,
must be considered in a cycle analysis where the objective is to optimize the thermodynamic efficiency
within the physical and economic constraints of the
equipment. In addition, there are constraints imposed
by the economics of fuel selection and the environmental impacts of fuel combustion that impact the design
of the boiler/turbine regenerative cycle. Overall cycle
characteristics, including efficiency, can also be illustrated by plotting the cycle on a Mollier chart. (See
chapter frontispiece and Fig. 4.)
The procedure used in preparing Fig. 9 deserves
special comment because it illustrates an important
function of entropy. All processes on the diagram represent total entropies divided by the high pressure
steam flow rate. Total entropies at any point of the
cycle are the product of the mass flowing past that
point in unit time and the entropy per pound (specific
entropy) corresponding to the pressure, temperature,
and state of the steam. Specific entropy values are provided by the Steam Tables such as those provided here
in Tables 1, 2, and 3. If a point falls in the two-phase
region, entropy is calculated in the same manner as
enthalpy. That is, the value for evaporation is multiplied by the steam quality (fraction of uncondensed
steam) and added to the entropy value of water at
saturation conditions corresponding to the pressure at
that point in the system.
Because there are different flow rates for the various cycle processes, small sections of individual T-s
diagrams are superimposed in Fig. 9 on a base diagram that identifies saturated liquid and vapor parameters. However, the saturation parameters can
only be compared to specific points on the T-s diagram.
These points correspond to the parts of the cycle representing heat addition to high pressure steam and
the expansion of this steam in a high pressure turbine. In these parts of the cycle, the specific entropy
of the fluid and the value plotted in the diagram are
the same. At each steam bleed point of the intermedi2-15
The Babcock & Wilcox Company
Fig. 8 Supercritical pressure, 3500 psig turbine cycle heat balance (English units).
ate and low pressure turbine, the expansion line
should show a decrease in entropy due to reduced flow
entering the next turbine stage. However, for convenience, the individual step backs in the expansion
lines have been shifted to the right to show the reheated steam expansion as one continuous process.
Feedwater heating through the regenerators and
compression by the pumps (represented by the zigzag
lines in Fig. 9) result in a net entropy increase. However, two factors are involved in the net increase, an
entropy increase from the heat added to the feedwater and
a decrease resulting from condensing and cooling the bleed
steam and drain flows from higher pressure heaters.
Consider an example in which the feedwater heater
just before the deaerating heater increases the temperature of a 3,661,954 lb/h feedwater from 203.0 to 239.5F.
From Table 1, this increases the enthalpy, H, of the
feedwater from 171.2 to 208.0 and increases the entropy,
s, from 0.2985 to 0.3526. The total entropy increase per
lb of high pressure steam flowing at 4,813,813 lb/h is:
2-16
( s2 − s1 ) m feedwater
HP steam
m
=
( 0.3526 − 0.2985 )
3, 661, 954
4, 813,8
813
= 0.0412 Btu / lb F
(31)
The feedwater temperature rises 36.5F and the total heat absorbed is:
=
( H2 − H1 ) m feedwater
( 208.0 − 171.2 ) 3,661,954
= 134,759, 907 Btu / h
(32)
On the heat source side of the balance, 132,333 lb/
h of steam are bled from the low pressure turbine at
28.8 psig. This steam has an enthalpy of 1200.3 and
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
an entropy of 1.7079. The steam is desuperheated and
condensed according to the following equation:
H 2 = H1 −
heat absorbed by feedwater
LP steam
m
= 1200.3 −
134,759,9
907
= 182.0 Btu/lb
132,333
(33)
Interpolating Table 1, the low pressure steam is
cooled to 213.0F at Hf = 181.2 Btu/lb. The corresponding entropy of the heater drain is 0.3136 Btu/lb F.
Therefore, the entropy decrease is:
( s1 − s2 ) m LP steam
HP steam
m
=
(1.7079 − 0.3136 ) 132,333
4,813,813
= 0.0383 Btu / lb F
(34)
This heater shows a net entropy increase of 0.0412
− 0.0383 = 0.0029 Btu/lb F.
Recall that an increase in entropy represents heat
energy that is unavailable for conversion to work.
Therefore, the net entropy increase through the
feedwater heater is the loss of available energy that
can be attributed to the pressure drop required for flow
and temperature difference. These differences are
necessary for heat transfer. The quantity of heat rendered unavailable for work is the product of the entropy increase and the absolute temperature of the
sink receiving the rejected heat.
Available energy
From the previous feedwater heater example, there
is a derived quantity, formed by the product of the
corresponding entropy and the absolute temperature
of the available heat sink, which has the nature of a
property. The difference between H (enthalpy) and Tos
is another derived quantity called available energy.
e = H − To s
(35)
where
e =
H=
To =
s =
available energy, Btu/lb (kJ/kg)
enthalpy, Btu/lb (kJ/kg)
sink temperature, R (K)
entropy, Btu/lb R (kJ/kg K)
Available energy is not a property because it can
not be completely defined by an equation of state;
rather, it is dependent on the sink temperature. However, a combined statement of the first and second laws
of thermodynamics indicates that the difference in the
available energy between two points in a reversible
process represents the maximum amount of work (on a
unit mass basis) that can be extracted from the fluid due
to the change of state variables H and s between the
two points. Conceptually then, differences in the value
of Tos represent energy that is unavailable for work.
The concept of available energy is useful in cycle
Steam 41 / Thermodynamics of Steam
Fig. 9 Steam cycle for fossil fuel temperature-entropy diagram –
single reheat, seven-stage regenerative feedwater heating – 3500
psig, 1000F/1000F steam.
analysis for optimizing the thermal performance of
various components relative to overall cycle efficiency.
In this way small, controllable changes in availability may be weighed against larger, fixed unavailable
heat quantities which are inherent to the cycle. By
comparing actual work to the maximum reversible
work calculated from differences in available energy,
the potential for improvement is obtained.
Rankine cycle efficiency
As with the Carnot cycle efficiency, the Rankine
cycle efficiency (η) is defined as the ratio of the net
work (Wout – Win) produced to the energy input (Qin):
η =
Wout − Win
Qin
(36)
For the simple cycle shown in Fig. 7, the work terms
and the energy input are defined as:
w ( Hc − Hd )
Wout = ηt m
w ( Hb − H a ) / η p
Win = m
(37)
w va ( Pb − Pa ) / η p
≅m
(38)
w ( H c − Hb )
Qin = m
(39)
w is
where Ha – d are the enthalpies defined in Fig. 7, m
the water flow rate, Pa – b are the pressures at points a
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The Babcock & Wilcox Company
Fig. 10 Subcritical pressure, 2400 psig turbine cycle heat balance (English units).
and b, va is the water specific volume at point a, while
ηt and ηp are the efficiencies of the turbine and boiler
feed pump respectively.
Substituting Equations 37, 38 and 39 into Equa w , which is
tion 36 and canceling the mass flow rate, m
the same in all three cases provide the following overall
thermodynamic efficiency (ηth):
η th =
ηt ( H c − H d ) − va ( Pb − Pa ) / η p
( H c − Hb )
(40)
In even a simple power producing facility using the
Rankine cycle, several other factors must also be considered:
1. Not all of the chemical energy supplied to the boiler
from the fuel is absorbed by the steam – typically
80 to 85% of the energy input is absorbed.
2. A variety of auxiliary equipment such as fans, sootblowers, environmental protection systems, water
2-18
treatment equipment, and fuel handling systems,
among others use part of the power produced.
3. Electrical generators and motors are not 100% efficient.
Incorporating these general factors into Equation
40 for a simple power cycle yields the net generating
efficiency, ηnet:
ηnet =
η gηt ( H c − H d ) − v1 ( Pb − Pa ) / η pηm − waux
( H c − Hb ) / ηb
(41)
where waux is the auxiliary power usage, ηb is the boiler
efficiency, while ηg and η m are the electrical generator
and motor efficiencies, both typically 0.98 to 0.99. The
gross power efficiency can be evaluated from Equation 41 with waux set at zero.
The evaluation of efficiency in modern high pressure steam power systems is more complex. Provision
in the evaluation must be made for steam reheat or
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
double reheat, and turbine steam extraction for regenerative feedwater heating, among others. This evaluation is based upon a steam turbine heat balance or
steam cycle diagram such as that shown in Fig. 8 for
a 3500 psig (24.13 MPa) supercritical pressure fossil
fuel-fired unit, or Fig. 10 for a 2400 psig (16.55 MPa)
subcritical pressure unit. The subcritical pressure unit
shown has a single reheat, six closed feedwater heaters and one open feedwater heater.
Rankine cycle heat rate
Heat rate is a term frequently used to define various power plant efficiencies. If the electrical generation used is the net output after subtracting all auxiliary electrical power needs, then Equation 42 defines
the net heat rate using English units. If the auxiliary
electrical usage is not deducted, Equation 42 defines
the gross heat rate.
Heat rate =
Total fuel heat input (Btu / h)
Electrical generation (kW)
(42)
Heat rate is directly related to plant efficiency, η,
by the following relationships:
Net heat rate =
Gross heat rate =
3412.14 Btu / kWh
ηnet
3412.14 Btu / kWh
ηgross
(43a)
(43b)
Steam cycle in a nuclear plant
Fig. 11 illustrates a Rankine cycle whose thermal
energy source is a pressurized water nuclear steam
system. High pressure cooling water is circulated from
a pressurized water reactor to a steam generator.
Therefore, heat produced by the fission of enriched
uranium in the reactor core is transferred to
feedwater supplied to the steam generator which, in
turn, supplies steam for the turbine. The steam generators of a nuclear plant are shell and tube heat exchangers in which the high pressure reactor coolant
flows inside the tubes and lower pressure feedwater
is boiled outside of the tubes. For the pressurized water reactor system, the Rankine cycle for power generation takes place entirely in the nonradioactive water side
(secondary side) that is boiling and circulating in the
steam system; the reactor coolant system is simply the
heat source for the power producing Rankine cycle.
The steam pressure at the outlet of the steam generator varies among plants due to design differences
and ranges from 700 to 1000 psi (4.83 to 6.90 MPa).
Nominally, a nuclear steam system by The Babcock &
Wilcox Company (B&W) with a once-through steam
generator provides slightly superheated steam at 570F
(299C) and 925 psi (6.38 MPa). Steam flow from the
once-through generator reaches the high pressure
turbine at about 900 psi (6.21 MPa) and 566F (297C).
More prevalent are nuclear steam systems that use a
recirculating steam generator. In this design,
feedwater is mixed with saturated water coming from
Steam 41 / Thermodynamics of Steam
the steam generator’s separators before entering the
tube bundle and boiling to generate steam. This boiling steam-water mixture reaches a quality of 25 to 33%
at the end of the heat exchanger and enters the steam
generator’s internal separators. The separators return
the liquid flow to mix with incoming feedwater and
direct the saturated steam flow to the outlet of the
steam generator. Inevitably, a small amount of moisture is formed by the time the steam flow reaches the
high pressure turbine.
Even though the once-through steam generator is
capable of providing superheated steam to the turbine,
the pressure and temperature limitations of nuclear
plant components must be observed. As a result, the
expansion lines of the power cycle lie largely in the
wet steam region. This is essentially a saturated or
nearly saturated steam cycle. The expansion lines for
the nuclear steam system shown in Fig. 11 (featuring
a once-through steam generator) are plotted on an
enthalpy-entropy or H-s diagram in Fig. 12.
The superheated steam is delivered to the turbine
at a temperature only 34F (19C) above saturation. Although this superheat improves cycle efficiency, large
quantities of condensed moisture still exist in the turbine. For example, if expansion from the initial conditions shown in Fig. 12 proceed down one step to the
back pressure of 2.0 in. Hg [approximately 1.0 psi (6.9
kPa)] the moisture formed would exceed 20%. At best,
steam turbines can accommodate about 15% moisture
content. High moisture promotes erosion, especially in
the turbine blades, and reduces expansion efficiency.
In addition to mechanical losses from momentum
exchanges between slow moving condensate particles,
high velocity steam and rotating turbine blades, there
is also a thermodynamic loss resulting from the condensate in the turbine. The expansion of the steam is
too rapid to permit equilibrium conditions to exist when
condensation is occurring. Under this condition, the
steam becomes subcooled, retaining a part of the available energy which would be released by condensation.
Fig. 11 indicates two methods of moisture removal
used in this cycle and Fig. 12 shows the effect of this
moisture removal on the cycle. After expansion in the
high pressure turbine, the steam passes through a
moisture separator, which is a low pressure drop separator external to the turbine. After passing through
this separator, the steam is reheated in two stages, first
by bleed steam and then by high pressure steam to
503F (262C), before entering the low pressure turbine.
Here a second method of moisture removal, in which
grooves on the back of the turbine blades drain the
moisture from several stages of the low pressure turbine, is used. The separated moisture is carried off with
the bleed steam.
Internal moisture separation reduces erosion and
affords a thermodynamic advantage due to the divergence of the constant pressure lines with increasing
enthalpy and entropy. This can be shown by the use
of available energy, e, as follows. Consider the moisture removal stage at 10.8 psi in Fig. 12. After expansion to 10.8 psi, the steam moisture content is 8.9%.
Internal separation reduces this to approximately
8.2%. Other properties are as follows:
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The Babcock & Wilcox Company
Fig. 11 Power cycle diagram, nuclear fuel: reheat by bleed and high pressure steam, moisture separation, and six-stage regenerative feedwater
heating – 900 psi, 566F/503F (6.21 MPa, 297C/262C) steam.
P
H
s
To (at 2 in. Hg)
T os
e = H – Tos
End of
Expansion
After Moisture
Extraction
10.8 psi
1057.9 Btu/lb
1.6491 Btu/lb F
560.8 R
924.8 Btu/lb
133.1 Btu/lb
10.8 psi
1064.7 Btu/lb
1.6595 Btu/lb F
560.8 R
930.7 Btu/lb
134.0 Btu/lb
The increase in available energy, ∆e, due to moisture
extraction is 134.0 − 133.1 = 0.9 Btu/lb of steam.
The values of moisture and enthalpy listed are
given for equilibrium conditions without considering
the nonequilibrium effects that are likely to exist
within the turbine. These effects can be empirically
accounted for by the isentropic efficiency of the expansion line. An important point to observe from this example is the need to retain a sufficient number of significant digits in the calculations. Frequently, the
evaluation of thermodynamic processes results in working with small differences between large numbers.
Supercritical steam cycles
As previously pointed out, cycle thermodynamic efficiency is improved by increasing the mean temperature of the heat addition process. This temperature can
2-20
be increased when the feedwater pressure is increased
because the boiler inlet pressure sets the saturation
temperature in the Rankine cycle. If the pressure is
increased above the critical point of 3200.1 psi (22.1
MPa), heat addition no longer results in the typical
boiling process in which there is an interface between
the steam and water. Rather, the fluid can be treated
as a single phase as it passes through the process
where properties change from those of a liquid to a
gas without an interface. Additional heating superheats the steam and expansion in a first stage (high
pressure) turbine can occur entirely in a superheated
state. This is referred to as a supercritical steam cycle,
originally given the name Benson Super Pressure
Plant when first proposed in the 1920s. The first commercial unit featuring the supercritical cycle and two
stages of reheat was placed in service in 1957.
The steam cycle of a typical supercritical plant is
shown in Fig. 13. In this T-s diagram, point a represents the outlet of the condensate pump. Between
points a and b, the condensate is heated in the low
pressure feedwater heater using saturated liquid and/
or steam extracted from the steam turbines. Point b
corresponds to the high pressure feedwater pump inlet. The pump increases the pressure to 4200 psi (28.96
MPa), obtaining conditions of point c. Between points
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
The high pressure of the feedwater in the
supercritical cycle requires a substantially higher
power input to the feedwater pump than that required
by the saturated Rankine cycle. In a typical Rankine
cycle with a steam pressure of 2400 psi (16.55 MPa),
the pump power input requires approximately 2% of
the turbine output. This may increase to as much as
3% in the supercritical unit. However, this increase is
justified by the improved thermodynamic efficiency of
the cycle. In general, with equivalent plant parameters (fuel type, heat sink temperature, etc.), the
supercritical steam cycle generates about 4% more net
power output than the subcritical pressure regenerative Rankine steam cycle.
Fig. 12 Steam cycle for nuclear fuel on a Mollier chart: reheat by bleed
and high pressure steam, moisture separation and six-stage regenerative feedwater heating – 900 psi, 566F/503F steam (English units).
c and d, additional feedwater heating is provided by
steam extracted from the high and low pressure turbines. Point d corresponds to the supercritical boiler
inlet. Due to the nature of the fluid, the supercritical
boiler is a once-through design, having no need for
separation equipment. The Universal Pressure, or
UP®, boiler design used in the supercritical unit is described further in Chapter 26. For the supercritical
cycle shown, the steam arrives at the high pressure
turbine at 3500 psi (24.1 MPa) and 1050F (566C). Expansion in this turbine is complete at point f, which
corresponds to a superheated condition. Steam exhausted from the high pressure turbine is then reheated in the boiler to approximately 1040F (560C),
before entering the low pressure turbine at approximately 540 psi (3.7 MPa); this corresponds to point g
on the T-s diagram. The low pressure turbine expands
the steam to point h on the diagram. The cycle is completed by condensing the exhaust from the low pressure
turbine to a slightly subcooled liquid, and a condensate
pump delivers the liquid to the low pressure feedwater
heater, which corresponds to point a in the T-s diagram.
Steam 41 / Thermodynamics of Steam
Process steam applications
In steam power plants generating only electric
power, economically justifiable thermodynamic efficiencies range up to about 42% in fossil fuel plants
(higher in combined cycle plants discussed later in this
chapter) and 34% in nuclear plants. Therefore, typically more than half of the heat released from the fuel
must be transferred to the environment.
Energy resources may be more efficiently used by
operating multipurpose steam plants, where steam is
exhausted or extracted from the cycle at a sufficient
pressure for use in an industrial process or space heating application. With these arrangements, an overall
thermal utilization of 65% or greater is possible. Combination power and process installations have been
common for many years, but the demand for process
steam is not sufficient to permit the use of these combined cycles in most central station electric power generating plants. However, in regions where waste disposal and renewable energy sources have become significant environmental issues, the use of cogeneration,
biomass and waste-to-energy installations have been
successfully tied together with district heating and
Fig. 13 Supercritical steam cycle with one reheat.
2-21
The Babcock & Wilcox Company
other process steam application projects. In recent
years, the most successful of these have been in European municipalities.
Gas turbine cycle
In the thermodynamic cycles previously described,
the working fluid has been steam used in a Rankine
cycle. The Rankine cycle efficiency limit is dictated by
the ratio of the current maximum and minimum cycle
temperatures. The current maximum temperature of
the steam Rankine cycle is approximately 1200F
(649C), which is set primarily by material constraints
at the elevated pressures of the steam cycles. One
means of extending the efficiency limit is to replace
the working fluid with air or gas. The gas turbine
system in its simplest form consists of a compressor,
combustor and turbine, as shown in Fig. 14. Because
of its simplicity, low capital cost and short lead time,
gas turbine systems are being used by some utilities
to add capacity in smaller increments. Use of the gas
turbine system in conjunction with the steam Rankine cycle is also an effective means of recovering some
of the heat lost when combustion gases are released
to the atmosphere at high temperatures.
In the simple gas turbine system shown in Fig. 14,
air is compressed then mixed with fuel and burned in
a combustor. The high temperature gaseous combustion products enter the turbine and produce work by
expansion. A portion of the work produced by the turbine is used to drive the compressor and the remainder is available to produce power. The turbine exhaust
gases are then vented to the atmosphere. To analyze
the cycle, several simplifying assumptions are made.
First, although the combustion process changes the
composition of the working fluid, the fluid is treated
as a gas of single composition throughout, and it is considered an ideal gas to obtain simple relationships between points in the system. Second, the combustion process is approximated as a simple heat transfer process
in which the heat input to the working fluid is determined by the fuel heating values. A result of this approximation is that the mass flow rate through the system
remains constant. The final approximation is to assume
that each of the processes is internally reversible.
If the turbine expansion is complete with the exhaust gas at the same pressure as the compressor inlet air, the combination of processes can be viewed as
a cycle. The simplifying assumptions above result in
the idealized gas turbine cycle referred to as the airstandard Brayton cycle. Fig. 15 shows the cycle on Ts and P-v diagrams, which permit determining the
state variables at the various cycle locations.
The idealized cycle assumes an isentropic process
between points 1 and 2 (compression) and between 3
and 4 (expansion work). The temperature rise between
points 2 and 3 is calculated by assuming the heat addition due to combustion is at a constant pressure. In
the analysis, the pressure ratio between points 1 and
2 is given by the compressor design and is assumed to
be known. To determine the temperature at point 2, a
relationship between the initial and final states of an
isentropic ideal gas process is obtained as follows.
2-22
Fig. 14 Simple gas turbine system.
First, the general definitions of constant pressure
and constant volume specific heats, respectively, are:
∂H
cp =
∂T p
(44)
∂u
cv =
∂T v
(45)
Strictly speaking, the specific heat values vary with
temperature. In practice, however, they are assumed
to be constant to facilitate the calculations. The two
constants are related in that their difference equals
the gas constant in the ideal gas law (Pv = RT ):
c p − cv = R
(46)
The ratio of the constant pressure and constant volume
specific heats is designated the specific heat ratio, k.
k = c p / cv
(47)
From these definitions, changes in enthalpy and internal energy for an ideal gas can be calculated from:
dH = c p dT
(48)
du = cv dT
(49)
Although expressed to relate differential changes
in enthalpy and temperature, the concept of specific
heat can be used to calculate finite enthalpy changes
as long as the change in temperature is not excessive.
When higher accuracy is required, tabulated enthalpy
values should be used.
Recalling Equation 26, the combined expression of
the first and second laws of thermodynamics, setting
ds = 0 for the isentropic process, and inserting the
change in internal energy given by Equation 49, the
former equation may be written:
Tds = du + Pdv = cv dT + Pdv = 0
(50)
Substituting the ideal gas law (in differential form,
RdT = Pdv + vdP) and using the specific heat ratio definition, Equation 50 becomes:
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
Fig. 15 Air-standard Brayton cycle.
dP kdv
+
=0
P
v
(51)
T2 s
Integrating this yields:
Pvk = constant
(52)
From Equation 52 and the ideal gas law, the following relationship between pressures and temperatures in an isentropic process is obtained, and the temperatures at points 2 and 4 are determined.
P
T
T2
= 3 = 2
T1
T4
P1
( k −1) / k
(53)
With this, the temperature and pressure (state variables) at all points in the cycle are determined. The
turbine work output, wt, required compressor work, wc,
and heat input to the process, qb, are calculated as:
w t = c p (T3 − T4 )
(54)
wc = c p (T2 − T1 )
(55)
qb = cv (T3 − T2 )
(56)
As in other cycle analyses described to this point,
the cycle efficiency η is calculated as the net work produced divided by the total heat input to the cycle and
is given by:
η =
these irreversible aspects of the real gas turbine cycle
are shown in the T-s diagram in Fig. 16. An isentropic
compression would attain the point 2s, whereas the
real compressor attains the pressure P2, with an entropy corresponding to point 2 on the T-s diagram; likewise the turbine expansion attains point 4 rather than
4s. Constant-pressure lines on the diagram for pressures P2 and P3 illustrate the effect of pressure losses
in the combustor and connecting piping, and the deviation of the process between points 4 and 1 from a
constant-pressure process illustrates the effect of compressor inlet and turbine exhaust pressure losses on
the cycle efficiency.
Points along the real cycle are determined by calculating the temperature T2s from Equation 53 as:
wt − wc
qb
(57)
in which qb is the heat input in the combustor (burner)
per unit mass of gas (the working fluid) flowing
through the system. For the ideal cycle, this can also
be expressed in terms of gas temperatures by using
Equation 48 to express the enthalpy change in the
combustor and Equations 54 and 55 for the turbine
and compressor work:
T − T1 c p
η = 1 − 4
T3 − T2 cv
(58)
The actual gas turbine cycle differs from the ideal
cycle due to inefficiencies in the compressor and turbine and pressure losses in the system. The effects of
Steam 41 / Thermodynamics of Steam
P
= T1 2
P1
( k −1) / k
(59)
Using the compressor efficiency provided by the manufacturer and solving for enthalpy or temperature at
the compressor outlet yields the following:
ηc =
T2 s − T1
H − H1
= 2s
T2 − T1
H 2 − H1
(60)
Despite the significant advances in the mechanical efficiency of compressor and turbine designs (both
on the order of 80% or greater), the overall cycle efficiency of a real gas turbine system is relatively low
(30 to 35%) due to the high exhaust gas temperature
and because a significant portion of the turbine output is used for compressor operation. The cycle efficiency may be increased by using a heat exchanger
to preheat the air between the compressor and combustor. This heat is supplied by the turbine exhaust
gas in a manner similar to that of the Rankine cycle
regenerative heat exchangers. However, the higher
efficiency is achieved in a system with a lower pressure ratio across the compressor and turbine, which
in turn lowers the net work output for a given combustion system. The lower net output and extra hardware cost must be weighed in each case against the
thermodynamic efficiency improvement.
One of the key benefits of the gas turbine cycle is
its ability to operate at much higher temperatures
than the Rankine steam cycle. Gas turbines typically
operate with an inlet temperature of 1800 to 2200F
(982 to 1204C) and some turbine designs with complex internal cooling systems have been operated as
high as 2300F (1260C), raising the thermodynamic
efficiency. With the ability to operate at elevated temperatures and to use combustion gases as a working
fluid, some gas turbine systems are operated in conjunction with the steam Rankine cycle.
Combined cycles and cogeneration
As seen in the previous discussions of the Rankine
and Brayton cycles, the gas turbine Brayton cycle efficiently uses high temperature gases from a combustion process but discharges its exhaust gas at a rela2-23
The Babcock & Wilcox Company
the steam temperature and, therefore, to improve the
steam cycle performance. Thermodynamic efficiency
is defined as the work output of the two cycles divided
by the total heat supplied (Qtotal):
η = (Wout − Win )GT + (Wout − Win )ST / Qtotal
Fig. 16 T-s diagram of an actual gas turbine system.
tively high temperature; in the Brayton cycle, this constitutes wasted heat. On the other hand, the steam
turbine Rankine cycle is unable to make full use of
the highest temperatures. Combined cycles are designed to take advantage of the best features of these
two cycles to improve the overall thermodynamic efficiency of the plant. Advanced combined cycles, in
which the gas turbine exhaust is used as a heat source
for a steam turbine cycle, can achieve overall thermal
efficiencies in excess of 50%, generally representing
a 15% improvement in the cycle efficiency compared
to the gas turbine alone.
Waste heat boilers
In its simplest form, the combined cycle plant is a
gas turbine (Brayton cycle) plant enhanced by passing the turbine exhaust through a steam generator,
as shown in Fig. 17. The steam generator uses the hot
turbine exhaust as a heat source for a steam turbine
Rankine cycle. Electric power is generated from the
mechanical work provided by the gas turbine and the
steam turbine. In concept, the steam generator in the
combined cycle is recovering the otherwise wasted
heat from the gas turbine exhaust, and therefore it is
referred to as a heat recovery steam generator or a
waste heat boiler. (See Chapter 27.) More recent applications of the combined cycle have incorporated
supplemental firing in the waste heat boiler to elevate
Fig. 17 Simple combined cycle plant.
2-24
(61)
where the subscripts GT and ST refer to gas turbine
and steam turbine, respectively.
Another approach to combining the gas and steam
cycles, in which the steam generator serves as the combustion chamber for the gas turbine cycle, is shown
in Fig. 18. In this arrangement, the principal heat
source to the gas and steam cycle is the combustion
process taking place in the steam generator. The gaseous combustion products are expanded in the gas
turbine and the steam generated in the boiler tubes
is expanded in the steam turbine. Although not shown
in Fig. 18, the heat contained in the gas turbine exhaust may be recovered by using either a regenerative heat exchanger in the gas turbine cycle or a
feedwater heater in the steam cycle. A pressurized fluidized-bed combustion combined cycle is a specific
example of this approach to combining the gas and
steam cycles. (See Chapter 17.)
Cogeneration
In the most general sense, cogeneration is the production of more than one useful form of energy (thermal, mechanical, electrical, etc.) simultaneously from
a single fuel. In practice, cogeneration refers to generating electricity while principally performing an industrial function such as space heating, process heating or fuel gasification. Cogeneration systems are divided into two basic arrangements, topping and bottoming cycles.
A topping cycle is shown in Fig. 19. In this system
the fuel is used for power generation in a steam boiler
or gas turbine cycle combustor, and the waste heat
from the power generation cycle supports an industrial process. The most common topping cycle is one
in which a boiler generates steam at a higher pressure
than that needed for the process or space conditioning
application. The high pressure steam is then expanded
in a turbine to a pressure that is appropriate for the
application, generating electricity in the expansion
process. Steam turbines, gas turbines and reciprocating engines are commonly used in topping cycles.
A bottoming cycle is most commonly associated with
the recovery or waste heat boiler. In the bottoming
cycle, fuel is not supplied directly to the power generating cycle. Rather, steam is generated from a waste
Fig. 18 Pressurized combustion combined cycle plant.
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
heat source and then expanded in a turbine to produce work or to generate electricity. Steam is frequently used in the bottoming cycle because of its
ability to condense at low temperatures in the closed
Rankine cycle. The bottoming cycle is shown in Fig.
20. The steam Rankine cycle used as a bottoming cycle
has been illustrated previously in the descriptions of
combined cycle plants.
Combustion processes
To this point, cycles have been compared based on
the thermodynamic efficiency achieved, i.e., the net
work produced divided by the total heat input to the
cycle. To complete the evaluation of a combustionbased cycle, however, the performance must be expressed in terms of fuel consumption. In addition, the
ability of the different machines to make full use of
the combustion energy varies with temperatures
reached in the combustion chamber and with dissociation of the combustion products.
The energy release during combustion is illustrated
by considering the combustion of carbon (C) and oxygen (O2) to form carbon dioxide (CO2):
C + O2 → CO2
If heat is removed from the combustion chamber
and the reactants and products are maintained at 25C
and 0.1 MPa (77F and 14.5 psi) during the process,
the heat transfer from the combustion chamber would
be 393,522 kJ per kmole of CO2 formed. From the first
law applied to the process, the heat transfer is equal
to the difference in enthalpy between the reactants
and products:
spectively, is obtained from the chemical reaction equation. By convention, the enthalpy of elements at 25C
and 0.1 MPa (77F and 14.5 psi) are assigned the value
of zero. Consequently, the enthalpy of CO2 at these
conditions is –393,522 kJ/kmole (the negative sign is
due to the convention of denoting heat transferred
from a control volume as negative). This is referred to
as the enthalpy of formation and is designated by the
symbol H fo. The enthalpy of CO2 (and other molecular
species) at other conditions is found by adding the
change in enthalpy between the desired condition and
the standard state to the enthalpy of formation. [Note
that some tables may not use 25C and 0.1 MPa (77F
and 14.5 psi) as the standard state when listing the
enthalpy of formation.] Ideal gas behavior or tabulated properties are used to determine enthalpy
changes from the standard state.
The stoichiometrically balanced chemical reaction
equation provides the relative quantities of reactants and
products entering and leaving the combustion chamber.
The first law analysis is usually performed on a per mole
or unit mass of fuel basis. The heat transfer from a combustion process is obtained from a first law analysis of
the combustion process, given the pressure and temperature of the reactants and products. Unfortunately, even
in the case of complete combustion as assumed in the
previous example, the temperature of the combustion
products must be determined by additional calculations
discussed later in this section.
The combustion of fossil or carbon based fuel is commonly accompanied by the formation of steam or water
(H2O) as in the reaction:
CH4 + 2O2 → CO2 + 2H2O
The number of moles of each element or molecular
species entering or leaving the chamber, nR or nP re-
Again, the difference in enthalpy between the reactants and products is equal to the heat transfer from
the combustion process. The heat transfer per unit
mass of fuel (methane in this example) is referred to
as the heating value of the fuel. If the H2O is present
as liquid in the products, the heat transferred is referred to as the higher heating value (HHV). The term
lower heating value (LHV) is used when the H2O is
present as a vapor. The difference between these two
values is frequently small (about 4% for most hydrocarbon fuels) but still significant. When the efficiency
Fig. 19 Topping cycle.
Fig. 20 Bottoming cycle.
q − w = HP − HR
(62)
The subscripts R and P refer to reactants and products, respectively. Assuming that no work is done in the
combustion chamber and expressing the enthalpy of
reactants and products on a per mole basis, this becomes:
Q =
∑n
P
H P − ∑ nR H R
Steam 41 / Thermodynamics of Steam
(63)
2-25
The Babcock & Wilcox Company
of a cycle is expressed as a percentage of the fuel’s
heating value, it is important to know whether the
HHV or LHV is used.
As noted, one of the difficulties in completing the
first law analysis of the combustion process is determining the temperature of the products. In some applications an upper limit of the combustion temperature may be estimated. From the first law, this can
occur if the combustion process takes place with no
change in kinetic or potential energy, with no work
and with no heat transfer (adiabatically). Under these
assumptions, the first law indicates that the sum of
the enthalpies of the reactants equals that of the products. The temperature of the products is then determined iteratively by successively assuming a product
temperature and checking the equality of the reactant
and product enthalpies. For a given fuel and reactants
at the specified inlet temperature and pressure, this
procedure determines the highest attainable combustion temperature, referred to as the adiabatic combustion or flame temperature.
Gibbs free energy
An important thermodynamic property derived
from a combination of other properties (just as enthalpy
was derived from u, P and v) is Gibbs free energy (g),
which is also frequently referred to as free energy:
g = H − Ts
(64)
Free energy g is a thermodynamic potential similar
to enthalpy and internal energy because in any thermodynamic process, reversible or irreversible, differences in this quantity depend only on initial and final states of the system.
The usefulness of free energy is particularly evident
from the following expression of the combined first and
second laws, expressed for a reversible process with negligible changes in kinetic and potential energy:
Wrev =
∑m (H
1
1
− To s1 )
− ∑ m2 ( H 2 − To s2 )
(65)
When applied to a combustion process in which the
reactants and products are in temperature equilibrium
with the surroundings, this becomes:
Wrev =
∑n
R
g R − ∑ nP gP
(66)
This equation indicates the maximum value of reversible work that can be obtained from the combustion
of a given fuel. The reversible work is maximized
when the reactants constitute a stoichiometrically balanced mixture (no excess air). The quantities nR and
nP are obtained from the chemical reaction equation
and g is expressed on a per mole basis in Equation 66.
From this, one might expect to express the efficiency
of a cycle that extracts energy from a combustion process as a percentage of the Gibbs free energy decrease,
rather than in terms of the heating value of the fuel.
It is uncommon for this to be done, however, because
the difference between the free energy decrease and
2-26
the heating value of hydrocarbon fuels is small and because the use of fuel heating value is more widespread.
Free energy is more commonly used to determine
the temperature reached in burning fuel, including
the effects of dissociation. The problem of dissociation
is illustrated by again considering the combustion of
carbon and oxygen to form CO2. If the temperature
of the combustion process is high enough, the CO2 dissociates to form CO and O2 according to the reaction:
CO2 ↔ CO +
1
O2
2
As the dissociation reaction occurs from left to right
(from all CO2 to none), the sum of the reactant free
energies and that of the products vary. Equilibrium of
this reaction is reached when the sum of the free energies is a minimum. The equilibrium point (degree of
dissociation) varies with the combustion temperature.
While the process of iteratively determining a minimum free energy point is suited for computer calculations, the equilibrium conditions of the dissociation
reaction at an assumed temperature can also be determined using tabulated values of a constant relating the species involved in the reaction. This constant
is known as the equilibrium constant Keq, which for
ideal gases is given by:
( PB ) ( PC )
a
( PA )
b
K eq =
c
(67)
where PA, PB and PC are the partial pressures, i.e., the
products of total pressure and mole fractions in the
mixture, of the reactants and products. The exponents
represent the number of moles present for each species (A, B and C) in the stoichiometric balance equation as follows:
aA ↔ bB + cC
(68)
Equations 67 and 68 yield simultaneous equations
for the mole fractions a, b and c. For nonideal gas reactions, the partial pressures are replaced by what are
known as fugacities (the tendencies of a gas to expand
or escape). Thermodynamic properties and relationships for the compounds and their elements encountered in the combustion process are available in the
literature. One of the best sources for this information
is the JANAF Thermochemical Tables, published by
the U.S. Department of Commerce.6 These tables include log10 values of the equilibrium constants for temperatures from 0 to 6000K.
To continue the carbon-oxygen combustion example,
the overall chemical reaction, including dissociation, is
now written as:
C + O2 → aCO2 + bCO + cO2
in which the coefficients a, b and c represent the mole
fractions of the product components as determined by
the solution to the dissociation reaction at the assumed
combustion temperature. The overall reaction equation is now used to check the assumed temperature
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
by adding the enthalpies of the combustion products
at the assumed temperature, noting that the enthalpy
per mole must be multiplied by the corresponding mole
fraction a, b, or c for each product species. The combustion temperature is determined when the sum of
product enthalpies minus that of the reactants equals
the heat transfer to the surroundings of the combustion chamber. The convective and radiative heat
transfer from the combustion products to the chamber and eventually to the working fluid of the cycle
at the assumed combustion temperature are discussed
in Chapter 4.
References
1. Parry, W.T., et al., ASME International Steam Tables
for Industrial Use, Based on IAPWS-IF97, The American
Society of Mechanical Engineers, New York, New York,
January, 2000.
2. ASME Steam Properties for Industrial Use, Based on
IAPWS-IF97, Professional Version 1.1, The American Society of Mechanical Engineers, New York, New York, 2003.
3. Weast, R.C., et al., CRC Handbook of Chemistry and
Physics, 70th Ed., CRC Press, Inc., Boca Raton, Florida,
1989.
Steam 41 / Thermodynamics of Steam
4. Keenan, J.H., Chao, J., and Kaye, J., Gas Tables:
Thermodynamic Properties of Air Products of Combustion and Component Gases Compressible Flow Functions,
Second Ed., John Wiley & Sons, New York, New York,
June, 1983.
5. Vargaftik, N.B., Tables on the Thermophysical Properties of Liquids and Gases: In Normal and Dissociated
States, Second Ed., John Wiley & Sons, New York, New
York, November, 1975.
6. Chase, Jr., M.W., et al., JANAF Thermochemical
Tables, Fourth Ed., American Chemical Society, American Institute of Physics, New York, New York, 1998.
2-27
The Babcock & Wilcox Company
Mollier diagram (H-s) for steam.
2-28
Steam 41 / Thermodynamics of Steam
The Babcock & Wilcox Company
Chapter 3
Fluid Dynamics
In the production and use of steam there are many
fluid dynamics considerations. Fluid dynamics addresses steam and water flow through pipes, fittings,
valves, tube bundles, nozzles, orifices, pumps and turbines, as well as entire circulating systems. It also considers air and gas flow through ducts, tube banks, fans,
compressors and turbines plus convection flow of gases
due to draft effect. The fluid may be a liquid or gas
but, regardless of its state, the essential property of a
fluid is that it yields under the slightest shear stress.
This chapter is limited to the discussion of Newtonian
liquids, gases and vapors where any shear stress is
directly proportional to a velocity gradient normal to
the shear force. The ratio of the shear stress to the velocity gradient is the property viscosity represented by
the symbol µ.
Liquids and gases are recognized as states of matter. In the liquid state, a fluid is relatively incompressible, having a definite volume. It is also capable of
forming a free surface interface between itself and its
vapor or any other fluid with which it does not mix. On
the other hand, a gas is highly compressible. It expands
or diffuses indefinitely and is subject only to the limitations of gravitational forces or an enclosing vessel.
The term vapor generally implies a gas near saturation conditions where the liquid and the gas phase
coexist at essentially the same temperature and pressure, during a process such as vaporization or boiling.
In a similar sense the term gas denotes a highly superheated steam. Sometimes steam may be treated as
an ideal gas and careful judgment is needed when
doing so.
Fluid dynamics principles normally consider the
fluid to be a continuous region of matter, a continuum,
and a molecular model is not required except for rare
instances. However, one property is noteworthy to consider due to the effect on steam generation fluid flow
and due to intermolecular forces. Surface tension, σ,
is a liquid property of the vapor-liquid interface and
is the energy per unit area required to extend the interface. Surface tension is important in two-phase systems, such as a mixture flowing in a boiler tube, and
relates to the shape and flow regime of the bubble interface and also to the heat transfer area of droplets.
Vapor bubbles increase the resistance to fluid flow.
Steam 41 / Fluid Dynamics
The surface tension of water is dependent on temperature and its value goes to zero at the critical temperature (705.47 F, 374.15C). Supercritical water is considered single phase in fluid dynamic analysis due to
zero surface tension.
The recommended correlation1 for the surface tension of water and its vapor, σ, is:
(T − T )
σ = 235.8 × 10 N / m c
T
1.256
−3
Tc − T
1 − 0.625 T
(1)
where Tc = 647.15K and T is the fluid temperature in K.
Water in steam generators operating at supercritical pressure (above 3200.1 psia, 22.1 MPa) will behave as a single phase fluid converting from liquid to
steam without creating bubbles. At the critical pressure and critical temperature, the density of water and
steam are identical and there is no distinguishable interface at equilibrium conditions. Surface tension is
also related to the latent heat of vaporization which
also decreases to zero at the critical temperature.2 This
chapter discusses single phase fluid flow. Chapter 5
pertains to two-phase fluid flow that occurs in boiling
tube circuits.
Fundamental relationships
Three fundamental laws of conservation apply to
fluid dynamic systems: conservation of mass, momentum and energy. With the exception of nuclear reactions where minute quantities of mass are converted
into energy, these laws must be satisfied in all flowing systems. Fundamental mathematical relationships
for these principles are presented in several different
forms that may be applied in particular fluid dynamic
situations to provide an appropriate solution method.
However, full analytical solutions are frequently too
complex without the use of a computer. Simplified
forms of the full equations can be derived by applying engineering judgment to drop negligible terms and
consider only terms of significant magnitude for cer3-1
The Babcock & Wilcox Company
tain classes of problems. Fluid dynamics problems can
be classified as compressible or incompressible, viscous
or inviscid. Engineering practice is based upon applying various assumptions and empirical relationships
in order to obtain a practical method of solution. A
more complete discussion of the derivation of these
conservation law relationships and vector notation
representing three dimensional spaces may be found
in References 3, 4, 5 and 6.
Conservation of mass
The law of conservation of mass simply states that
the rate of change in mass stored in a system must
equal the difference in the mass flowing into and out
of the system. The continuity equation of mass for one
dimensional single phase flow in a variable area channel or stream tube is:
A
∂V
∂A
∂ρ
∂ρ
= 0
+ ρA
+ ρV
+ AV
∂x
∂x
∂x
∂t
(2)
In its simplest form in x, y and z three dimensional
Cartesian coordinates, conservation of mass for a small
fixed control volume is:
∂ρ
∂
∂
∂
ρu +
ρv +
ρw = −
∂t
∂z
∂y
∂x
(3)
where u, v and w are the fluid velocities in the x, y
and z coordinate directions; t is time and ρ is the fluid
density. An important form of this equation is derived
by assuming steady-state (∂ /∂ t = 0) and incompressible (constant density) flow conditions:
∂u ∂v ∂w
= 0
+
+
∂x ∂y ∂z
(4)
Although no liquid is truly incompressible, the assumption of incompressibility simplifies problem solutions and is frequently acceptable for engineering
practice considering water and oils.
Another relationship useful in large scale pipe flow
systems involves the integration of Equation 3 around
the flow path for constant density, steady-state conditions. For only one inlet (subscript 1) and one outlet
(subscript 2):
The conservation of momentum for one dimensional
single phase flow in a variable area channel or stream
tube is:
τ Pf
1 ∂G 1 ∂ G 2 A
+
+
gc ∂t
A ∂x ρ
A
∂P
g
= 0
+
ρ sin θ +
∂x
gc
where
P
G
A
ρ
τ
Pf
g
gc
θ
=
=
=
=
=
=
=
=
=
pressure, psia (MPa)
mass flux, G = ρV, lb/h ft2 (kg/s m2)
flow area of channel ft2 (m2)
density lb/ft3 (kg/m3)
wall shear stress, lb/ft2 (N/m2) (refer to Equation 26)
channel wetted perimeter, ft (m)
32.17 ft /s2 (9.8 m /s2)
32.17 lbm ft/lbf s2 (1 kg m /N s2)
angle of channel inclination for x distance
This relationship is useful in calculating steam generator tube circuit pressure drop.
The conservation of momentum is a vector equation and is direction dependent, resulting in one equation for each coordinate direction (x, y and z for Cartesian coordinates), providing three momentum equations for each scaler velocity component, u, v and w.
The full mathematical representation of the momentum equation is complex and is of limited direct use in
many engineering applications, except for numerical
computational models. As an example, in the x coordinate direction, the full momentum equation becomes:
∂u
∂u
∂u
∂u
+w
+v
+u
ρ
∂z
∂y
∂x
∂t
= ρ fx
∂P
∂x
∂ 2 ∂u ∂v ∂w
+
−
−
µ 2
∂x 3 ∂x ∂y ∂z
−
(5)
+
where ρ is the average density, V is the average velocity, A is the cross-sectional area, and m is the mass
flow rate.
∂ ∂v ∂u
+
µ
∂y ∂x ∂y
+
∂ ∂w ∂u
+
µ
∂z
∂z ∂x
= ρ1 A1 V1 = ρ 2 A2 V2
m
Conservation of momentum
The law of conservation of momentum is a representation of Newton’s Second Law of Motion – the
mass of a particle times its acceleration is equal to the
sum of all of the forces acting on the particle. In a flowing system, the equivalent relationship for a fixed (control) volume becomes: the rate of change in momentum entering and leaving the control volume is equal
to the sum of the forces acting on the control volume.
3-2
(6)
Term 1
Term 2
Term 3
Term 4
(7)
where ƒx is the body force in the x direction, P is the
pressure, and µ is the viscosity. This equation and the
corresponding equations in the y and z Cartesian coordinates represent the Navier-Stokes equations
which are valid for all compressible Newtonian fluids
with variable viscosity. Term 1 is the rate of momentum change. Term 2 accounts for body force effects
such as gravity. Term 3 accounts for the pressure gradient. The balance of the equation accounts for moSteam 41 / Fluid Dynamics
The Babcock & Wilcox Company
mentum change due to viscous transfer. Term 1 is
sometimes abbreviated as ρ (Du /Dt) where Du /Dt is
defined as the substantial derivative of u. For a function β (scaler or vector), D /Dt is the substantial derivative operator on function β defined as:
∂β
∂β
∂β
Dβ
+v
+u
=
∂y
∂x
∂t
Dt
∂β
∂β
+ v i ∇β
=
+w
∂t
∂z
(8)
∇β or grad β or del β = i ∂ β/∂x + j ∂ β/∂y + k ∂ β/∂z
For the special case of constant density and viscosity,
this equation reduces to (for the x coordinate direction):
(9)
The y and z coordinate equations can be developed
by substituting appropriate parameters for velocity u,
pressure gradient ∂P / ∂x, and body force ƒx. Where viscosity effects are negligible ( µ = 0), the Euler equation
of momentum is produced (x direction only shown):
1 ∂P
Du
= fx −
Dt
ρ ∂x
(10)
Energy equation (first law of thermodynamics)
The law of conservation of energy for nonreacting
fluids states that the energy transferred into a system less the mechanical work done by the system must
be equal to the rate of change in stored energy, plus
the energy flowing out of the system with a fluid,
minus the energy flowing into the system with a fluid.
A single scaler equation results. The one dimensional
single phase flow energy equation for a variable area
channel or stream tube is:
ρ
P
∂H
∂H
1 ∂P
= q′′ H + q′′′ +
+G
A
J ∂τ
∂x
∂t
(11)
where
P
G
A
ρ
τ
PH
x
H
J
=
=
=
=
=
=
=
=
=
pressure, psia (MPa)
mass flux, lb/h ft2 (kg/s m2)
flow area of channel, ft2 (m2)
density, lb/ft3 (kg/m3)
wall shear stress, lb/ft2 (N/m2)
channel heated area, ft2 (m2)
channel distance, ft (m) for x distance
enthalpy, Btu/lb (kJ/kg)
mechanical equivalent of heat = 778.17 ft lbf/
Btu (1 N m/J)
q ′′ = heat flux at boundary, Btu/h ft2 (W/m2)
q ′′′ = internal heat generation, Btu/h ft3 (W/m)
Steam 41 / Fluid Dynamics
ρ
DH
= q′′′ +
Dt
DP
µ
+ ∇ik∇T +
Φ
Dt
gc
Term 1 Term 2 Term 3 Term 4
where the vector gradient or grad or del operator on
function β is defined as:
1 ∂P
Du
µ ∂ 2u ∂ 2u ∂ 2u
+ 2 + 2 + 2
= fx −
∂z
∂y
Dt
ρ ∂x
ρ ∂x
A general form of the energy equation for a flowing system using an enthalpy based formulation and
vector notation is:
Term 5
(12)
where ρ is the fluid density, H is the enthalpy per unit
mass of a fluid, T is the fluid temperature, q′′′ is the
internal heat generation, k is the thermal conductivity, and Φ is the dissipation function for irreversible
work.6 Term 1 accounts for net energy convected into
the system, Term 2 accounts for internal heat generation, Term 3 accounts for work done by the system,
Term 4 addresses heat conduction, and Term 5 accounts for viscous dissipation.
As with the momentum equations, the full energy
equation is too complex for most direct engineering
applications except for use in numerical models. (See
Chapter 6.) As a result, specialized forms are based
upon various assumptions and engineering approximations. As discussed in Chapter 2, the most common
form of the energy equation for a simple, inviscid (i.e.,
frictionless) steady-state flow system with flow in at
location 1 and out at location 2 is:
JQ − W = J ( u2 − u1 ) + ( P2v2 − P1v1 )
+
g
1
V22 − V12 + ( Z2 − Z1 )
gc
2 gc
(
)
(13a)
or
JQ − W = J ( H 2 − H1 )
+
g
1
V22 − V12 + ( Z2 − Z1 )
gc
2 gc
(
)
(13b)
where
Q = heat added to the system, Btu lbm (J/kg)
(See Note below)
W = work done by the system, ft-lbf/lbm (N m/kg)
J = mechanical equivalent of heat = 778.17 ft lbf/
Btu (1 N m/J)
u = internal energy, Btu/lbm (J/kg)
P = pressure, lbf/ft2 (N/m2)
υ = specific volume, ft3/lbm (m3/kg)
V = velocity, ft /s (m/s)
Z = elevation, ft (m)
H = enthalpy = u + Pυ/J, Btu/lbm (J/kg)
g = 32.17 ft /s2 (9.8 m /s2)
g c = 32.17 lbm ft/lbf s2 (1 kg m /N s2)
Note: Where required for clarity, the abbreviation lb is augmented by f (lbf) to indicate pound force and by m (lbm) to
indicate pound mass. Otherwise lb is used with force or
mass indicated by the context.
3-3
The Babcock & Wilcox Company
Energy equation applied to fluid flow
(pressure loss without friction)
The conservation laws of mass and energy, when
simplified for steady, frictionless (i.e., inviscid) flow of
an incompressible fluid, result in the mechanical energy balance referred to as Bernoulli’s equation:
P1v + Z1
V2
V2
g
g
+ 1 = P2v + Z2
+ 2
gc
gc
2 gc
2 gc
(14)
The variables in Equation 14 are defined as follows
with the subscripts referring to location 1 and location 2 in the system:
P
υ
Z
V
=
=
=
=
pressure, lbf/ft2 (N/m2)
specific volume of fluid, ft3/lbm (m3/kg)
elevation, ft (m)
fluid velocity, ft/s (m/s)
Briefly, Equation 14 states that the total mechanical energy present in a flowing fluid is made up of pressure energy, gravity energy and velocity or kinetic
energy; each is mutually convertible into the other
forms. Furthermore, the total mechanical energy is
constant along any stream-tube, provided there is no
friction, heat transfer or shaft work between the points
considered. This stream-tube may be an imaginary
closed surface bounded by stream lines or it may be
the wall of a flow channel, such as a pipe or duct, in
which fluid flows without a free surface.
Applications of Equation 14 are found in flow measurements using the velocity head conversion resulting from flow channel area changes. Examples are the
venturi, flow nozzle and various orifices. Also, pitot
tube flow measurements depend on being able to compare the total head, Pυ + Z + (V2 /2 gc ), to the static
head, Pυ + Z, at a specific point in the flow channel.
Descriptions of metering instruments are found in
Chapter 40. Bernoulli’s equation, developed from
strictly mechanical energy concepts some 50 years
before any precise statement of thermodynamic laws,
is a special case of the conservation of energy equation or first law of thermodynamics in Equations 13a
and b.
Applications of Equation 13 to fluid flow are given
in the examples on water and compressible fluid flow
through a nozzle under the Applications of the Energy Equation section in Chapter 2. Equation 18,
Chapter 2 is:
V2 =
2 gc J ( H1 − H 2 ) = C H1 − H 2
(15)
where
V2 =
gc =
J =
H1 =
H2 =
C =
downstream velocity, ft/s (m/s)
32.17 lbm ft/lbf s2 = 1 kg m/Ns2
778.26 ft lbf/Btu = 1 Nm/J
upstream enthalpy, Btu/lb (J/kg)
downstream enthalpy, Btu/lb (J/kg)
223.8 lbm/Btu × ft/s (1.414 kg/J × m/s)
This equation relates fluid velocity to a change in enthalpy under adiabatic (no heat transfer), steady, inviscid (no friction) flow where no work, local irrevers3-4
ible flow pressure losses, or change in elevation occurs.
The initial velocity is assumed to be zero and compressible flow is permitted. If the temperature (T ) and pressure (P ) of steam or water are known at points 1 and
2, Equation 15 provides the exit velocity using the enthalpy (H) values provided in Tables 1, 2 and 3 of Chapter 2. If the pressure and temperature at point 1 are
known but only the pressure at point 2 is known, the
outlet enthalpy (H2) can be evaluated by assuming constant entropy expansion from points 1 to 2, i.e., S1 = S2.
Ideal gas relationships
There is another method that can be used to determine velocity changes in a frictionless adiabatic expansion. This method uses the ideal gas equation of
state in combination with the pressure-volume relationship for constant entropy.
From the established gas laws, the relationship between pressure, volume and temperature of an ideal
gas is expressed by:
Pv = RT
or
Pv =
(16a)
R
T
M
(16b)
where
P
υ
M
= absolute pressure, lb/ft2 (N/m2)
= specific volume, ft3/lb of gas (m3/kg)
= molecular weight of the gas, lb/lb-mole
(kg/kg-mole)
T = absolute temperature, R (K)
R = gas constant for specific gas, ft lbf/lbm R
(N m/kg K)
MR = R = the universal gas constant
= 1545 ft lb/lb-mole R (8.3143 kJ/kg-mole K)
The relationship between pressure and specific volume along an expansion path at constant entropy, i.e.,
isentropic expansion, is given by:
Pvk = constant
(17)
Because P1 and υ1 in Equation 13 are known, the constant can be evaluated from P1υ1k. The exponent k is
constant and is evaluated for an ideal gas as:
k = c p / cv = specific heat ratio
(18)
where
cp = specific heat at constant pressure, Btu/lb F (J/kg K)
cv = specific heat at constant volume, Btu/lb F (J/kg K)
= (u1 – u2)/(T1 – T2)
For a steady, adiabatic flow with no work or change
in elevation of an ideal gas, Equations 13, 16, 17 and
18 can be combined to provide the following relationship:
V22 − V12
k −1
P2 k
k
= 2 gc
P1 v1 1 − P
k −1
1
(19)
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
When V1 is set to zero and using English units Equation 19 becomes:
V2 = 8.02
k −1
P2 k
k
P1 v1 1 − , ft/s
k −1
P1
(20)
Equations 19 and 20 can be used for gases in pressure drop ranges where there is little change in k, provided values of k are known or can be calculated.
Equation 20 is widely used in evaluating gas flow
through orifices, nozzles and flow meters.
It is sufficiently accurate for most purposes to determine velocity differences caused by changes in flow
area by treating a compressible fluid as incompressible. This assumption only applies when the difference
in specific volumes at points 1 and 2 is small compared
to the final specific volume. The accepted practice is
to consider the fluid incompressible when:
(v2 − v1 ) / v2 < 0.05
(21)
Because Equation 14 represents the incompressible
energy balance for frictionless adiabatic flow, it may
be rearranged to solve for the velocity difference as
follows:
V22 − V12 = 2 gc ∆ ( Pv ) + ∆Zg / gc
22)
where
∆(Pυ) = pressure head difference between locations
1 and 2 = (P1 – P2) υ, ft (m)
∆Z
= head (elevation) difference between locations 1 and 2, ft (m)
V
= velocity at locations 1 and 2, ft/s (m/s)
When the approach velocity is approximately zero,
Equation 22 in English units becomes:
V2 =
2 gh = 8.02 h , ft/s
most flow situations there are also bulk fluid interchanges known as eddy diffusion. The net result of
all inelastic momentum exchanges is exhibited in
shear stresses between adjacent layers of the fluid. If
the fluid is contained in a flow channel, these stresses
are eventually transmitted to the walls of the channel. To counterbalance this wall shear stress, a pressure gradient proportional to the bulk kinetic energy,
V 2 / 2 gc, is established in the fluid in the direction of
the bulk flow. The force balance is:
π
D = tube diameter or hydraulic diameter Dh ft (m)
Dh = 4 × (flow area)/(wetted perimeter) for circular or noncircular cross-sections, ft (m)
dx = distance in direction of flow, ft (m)
τw = shear stress at the tube wall, lb/ft2 (N/m2 )
Solving Equation 24 for the pressure gradient (dP /
dx):
4
dP
=
τw
dx
D
Steam 41 / Fluid Dynamics
(25)
This pressure gradient along the length of the flow
channel can be expressed in terms of a certain number of velocity heads, ƒ, lost in a length of pipe equivalent to one tube diameter. The symbol ƒ is called the
friction factor, which has the following relationship to
the shear stress at the tube wall:
τw =
f 1 V2
4 v 2 gc
(26)
Equation 25 can be rewritten, substituting for τw from
Equation 26 as follows:
4 f 1 V2
dP
f 1 V2
=
=
dx
D 4 v 2 gc
D v 2 gc
(27)
The general energy equation, Equation 13, expressed
as a differential has the form:
VdV
+ d ( Pv ) = dQ − dWk
gc
(28a)
VdV
+ Pdv + vdP = dQ − dWk
gc
(28b)
du +
Pressure loss from fluid friction
So far, only pressure changes associated with the
kinetic energy term, V 2/2 gc, and static pressure term,
Z, have been discussed. These losses occur at constant
flow where there are variations in flow channel crosssectional area and where the inlet and outlet are at
different elevations. Fluid friction and, in some cases
heat transfer with the surroundings, also have important effects on pressure and velocity in a flowing fluid.
The following discussion applies to fluids flowing in
channels without a free surface.
When a fluid flows, molecular diffusion causes
momentum interchanges between layers of the fluid
that are moving at different velocities. These interchanges are not limited to individual molecules. In
(24)
where
(23)
In this equation, h, in ft head of the flowing fluid, replaces ∆(Pυ) + ∆Z. If the pressure difference is measured in psi, it must be converted to lb/ft2 to obtain Pυ
in ft.
D2
( dP ) = τ wπ D ( dx )
4
or
du +
Substituting Equation 26 of Chapter 2 (du = Tds –
Pdυ) in Equation 28 yields:
VdV
Tds +
+ vdP = dQ − dWk
(29)
gc
The term Tds represents heat transferred to or from
the surroundings, dQ, and any heat added internally
to the fluid as the result of irreversible processes.
These processes include fluid friction or any irrevers3-5
The Babcock & Wilcox Company
ible pressure losses resulting from fluid flow. (See
Equation 29 and explanation, Chapter 2.) Therefore:
Tds = dQ + dQF
(30)
where dQF is the heat equivalent of fluid friction and
any local irrecoverable pressure losses such as those
from pipe fittings, bends, expansions or contractions.
Substituting Equation 30 into Equation 29, canceling dQ on both sides of the equation, setting dWk equal
to 0 (no shaft work), and rearranging Equation 29
results in:
dP = −
dQF
VdV
−
vgc
v
dQF
dx V 2
= f
D v 2 gc
v
(32)
Substitution of Equation 32 into Equation 31 yields:
VdV
f V2
dx
−
vgc
D v 2 gc
(33)
From Equation 5, the continuity equation permits
definition of the mass flux, G, or mass velocity or mass
flow rate per unit area [lb/h ft2 (kg/m2 s)] as:
V
= G = constant
(34)
v
Substituting Equation 34 into Equation 33 for a flow
channel of constant area:
dP = − 2
G2 v
G2
dx
dv − f
2 gc
2 gc D
(35)
Integrating Equation 35 between points 1 and 2, located at x = 0 and x = L, respectively:
P1 − P2 = 2
3-6
G2 1
G2
(v2 − v1 ) + f
2 gc
2 gc D
dx =
and
∫
(31)
Three significant facts should be noted from Equation 31 and its derivation. First, the general energy
equation does not accommodate pressure losses due
to fluid friction or geometry changes. To accommodate
these losses Equation 31 must be altered based on the
first and second laws of thermodynamics (Chapter 2).
Second, Equation 31 does not account for heat transfer except as it may change the specific volume, υ,
along the length of the flow channel. Third, there is
also a pressure loss as the result of a velocity change.
This loss is independent of any flow area change but
is dependent on specific volume changes. The pressure
loss is due to acceleration which is always present in
compressible fluids. It is generally negligible in incompressible flow without heat transfer because friction
heating has little effect on fluid temperature and the
accompanying specific volume change.
Equation 27 contains no acceleration term and
applies only to friction and local pressure losses. Therefore, dQF/υ in Equation 31 is equivalent to dP of
Equation 27, or:
dP = −
The second term on the right side of Equation 36 may
be integrated provided a functional relationship between υ and x can be established. For example, where
the heat absorption rate over the length of the flow
channel is constant, temperature T is approximately
linear in x, or:
∫
L
0
vdx
(36)
L
0
vdx =
L
dT
T2 − T1
L
T2 − T1
∫
2
1
vdT = Lvav
(37)
(38)
The term υaυ is an average specific volume with respect to temperature, T.
vav = φ (v2 + v1 ) = φv1 (vR + 1 )
(39)
where
υR = υ 2 / υ 1
φ = averaging factor
In most engineering evaluations, υ is almost linear in T and φ ≈ l/2. Combining Equations 36 and
37, and rewriting υ 2 – υ 1 as υ 1 (υ R – 1):
P1 − P2 = 2
+ f
G2
v1 ( vR − 1 )
2 gc
L G2
v1φ ( vR + 1 )
D 2 gc
(40)
Equation 40 is completely general. It is valid for compressible and incompressible flow in pipes of constant
cross-section as long as the function T = F(x) can be assigned. The only limitation is that dP/dx is negative at
every point along the pipe. Equation 33 can be solved
for dP/dx making use of Equation 34 and the fact that
P1υ1 can be considered equal to P2υ2 for adiabatic flow
over a short section of tube length. The result is:
dP
=
dx
Pf / 2 D
g Pv
1− c 2
V
(41)
At any point where V 2 = gcPυ, the flow becomes choked
because the pressure gradient is positive for velocities
greater than (gcPυ)0.5. The flow is essentially choked
by excessive stream expansion due to the drop in pressure. The minimum downstream pressure that is effective in producing flow in a channel is:
P2 = V 2 / v2 gc = v2 G 2 / gc
(42)
Dividing both sides of Equation 40 by G2 υ l / 2gc,
the pressure loss is expressed in terms of velocity
heads. One velocity head equals:
∆P (one velocity head) =
V2
ρV 2
=
2 gcCv
2 gcC
(43)
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
where
∆P = pressure drop equal to one velocity head, lb/
in.2 (N/m2)
V = velocity, ft/s (m/s)
υ = specific volume, ft3/lb (m3/kg)
g c = 32.17 lbm ft/lbf s2 = 1 kg m/N s2
C = 144 in.2/ft2 (1 m2/m2)
ρ = density, lb/ft3 (kg/m3)
In either case, ƒ represents the number of velocity
heads (Nvh) lost in each diameter length of pipe.
The dimensionless parameter defined by the pressure loss divided by twice Equation 43 is referred to
as the Euler number:
(
Eu = ∆P / ρV 2 / gc
)
(44)
where ρ is the density, or l/υ .
Two other examples of integrating Equation 35
have wide applications in fluid flow. First, adiabatic
flow through a pipe is considered. Both H and D are
constant and Plυ lm = P2υ 2m where m is the exponent
for constant enthalpy. Values of m for steam range
from 0.98 to 1.0. Therefore, the assumption Pυ = constant = P1υ 1 is sufficiently accurate for pressure drop
calculations. This process is sometimes called isothermal pressure drop because a constant temperature ideal
gas expansion also requires a constant enthalpy. For Pυ
= P1υ 1, the integration of Equation 35 reduces to:
v
G 2 2v1 v2
n 2
2 gc v1 + v2
v1
L G 2 2v1v2
+ f
D 2 gc v1 + v2
P1 − P2 = 2
L G2
v
D 2 gc
L G
v
De 105
2
(47)
where
∆P =
ƒ =
L =
De =
fluid pressure drop, psi
friction factor from Fig. 1, dimensionless
length, ft
equivalent diameter of flow channel, in. (note
units)
υ = specific volume of fluid, ft3/lb
G = mass flux of fluid, lb/h ft2
Friction factor
The friction factor (ƒ) introduced in Equation 26, is
defined as the dimensionless fluid friction loss in velocity heads per diameter length of pipe or equivalent
diameter length of flow channel. Earlier correlators in
this field, including Fanning, used a friction factor one
fourth the magnitude indicated by Equation 26. This
is because the shear stress at the wall is proportional
to one fourth the velocity head. All references to ƒ in
this book combine the factor 4 in Equation 25 with ƒ as
has been done by Darcy, Blasius, Moody and others.
The friction factor is plotted in Fig. 1 as a function of
the Reynolds number, a dimensionless group of variables defined as the ratio of inertial forces to viscous
forces. The Reynolds number (Re) can be written:
Re =
ρVDe
VDe
GDe
or
or
µ
ν
µ
(48)
where
(46)
All terms in Equations 45 and 46 are expressed in
consistent units. However, it is general practice and
Steam 41 / Fluid Dynamics
∆P = f
(45)
Neither P2 nor υ2 are known in most cases, therefore
Equation 45 is solved by iteration. Also, the term 2υ1 υ2
/(υ1 + υ2) can usually be replaced by the numerical average of the specific volumes – υav = 1/2 υ1(PR + 1) where
PR = P1 /P2 = υ2/υ1. The maximum high side error at PR
= 1.10 is 0.22% and this increases to 1.3% at PR = 1.25.
It is common practice to use a numerical average for
the specific volume in most fluid friction pressure drop
calculations. However, where the lines are long, P2
should be checked by Equation 42. Also, where heat
transfer is taking place, P2 is seldom constant along the
flow channel and appropriate averaging factors should
be used. Computation using small zone subdivisions
along the length of the tube circuit is recommended to
limit errors in widely varying property values.
The second important example considering flow
under adiabatic conditions assumes an almost incompressible fluid, i.e., υ1 is approximately equal to υ2. (See
Equation 21.) Substituting υ for υ1 and υ2 in Equation 45, the result is:
P1 − P2 = f
often more convenient to use mixed units. For example, a useful form of Equation 46 in English units
is:
ρ =
ν =
µ =
V =
G =
De =
density of fluid, lbm/ft3 (kg/m3)
kinematic viscosity = µ /ρ, ft2/h (m2/s)
viscosity of fluid, lbm/ft h (kg/m s)
velocity of fluid, ft/h (m/s)
mass flux of fluid, lb/h ft2 (kg/m2 s)
equivalent diameter of flow channel, ft (m)
Fluid flow inside a closed channel occurs in a viscous
or laminar manner at low velocity and in a turbulent
manner at high velocities. Many experiments on fluid
friction pressure drop, examined by dimensional
analysis and the laws of similarity, have shown that
the Reynolds number can be used to characterize a
flow pattern. Examination of Fig. 1 shows that flow
is laminar at Reynolds numbers less than 2000, generally turbulent at values exceeding 4000 and completely turbulent at higher values. Indeterminate conditions exist in the critical zone between Reynolds
numbers of 2000 and 4000.
Fluid flow can be described by a system of simultaneous partial differential equations. (See earlier Fundamental relationships section.) However, due to the
complexity of these equations, solutions are generally
only available for the case of laminar flow, where the
only momentum changes are on a molecular basis. For
laminar flow, integration of the Navier-Stokes equa3-7
The Babcock & Wilcox Company
tion with velocity in the length direction only gives the
following equation for friction factor:
f = 64 / Re
(49)
The straight line in the laminar flow region of Fig. 1
is a plot of this equation.
It has been experimentally determined that the
friction factor is best evaluated by using the Reynolds
number to define the flow pattern. A factor ε/De is then
introduced to define the relative roughness of the
channel surface. The coefficient ε expresses the average height of roughness protrusions equivalent to the
sand grain roughness established by Nikuradse.6 The
friction factor values in Fig. 1 and the ε/De values in
Fig. 2 are taken from experimental data as correlated
by Moody.7
Laminar flow
Laminar flow is characterized by the parallel flowing of individual streams like layers sliding over each
other. There is no mixing between the streams except
for molecular diffusion from one layer to the other. A
small layer of fluid next to the boundary wall has zero
velocity as a result of molecular adhesion forces. This
establishes a velocity gradient normal to the main body
of flow. Because the only interchanges of momentum
in laminar flow are between the molecules of the fluid,
the condition of the surface has no effect on the velocity gradient and therefore no effect on the friction
factor. In commercial equipment, laminar flow is usually encountered only with more viscous liquids such
as the heavier oils.
Turbulent flow
When turbulence exists, there are momentum interchanges between masses of fluid. These interchanges are induced through secondary velocities,
irregular fluctuations or eddys, that are not parallel
to the axis of the mean flow velocity. In this case, the
condition of the boundary surface, roughness, does
have an effect on the velocity gradient near the wall,
which in turn affects the friction factor. Heat transfer is substantially greater with turbulent flow (Chapter 4) and, except for viscous liquids, it is common to
induce turbulent flow with steam and water without
Fig. 1 Friction factor/Reynolds number relationship for determining pressure drop of fluids flowing through closed circuits (pipes and ducts).
3-8
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
excessive friction loss. Consequently, it is customary
to design for Reynolds numbers above 4000 in steam
generating units.
Turbulence fluctuations in the instantaneous velocity introduce additional terms to the momentum
conservation equation called Reynolds stresses. These
fluctuations influence the mean motion and increase
the flow resistance in a manner producing an increase
in the apparent viscosity. Analysis of turbulent flow
must consider the impact of the fluctuating velocity
component along with the mean flow velocity or resort to empirical methods that account for the additional momentum dissipation.4, 6, 8
Velocity ranges
Table 1 lists the velocity ranges generally encountered in the heat transfer equipment as well as in duct
and piping systems of steam generating units. These
values, plus the specific volumes from the ASME
Steam Tables (see Chapter 2) and the densities listed
in Tables 2 and 3 in this chapter, are used to establish
mass velocities for calculating Reynolds numbers and
fluid friction pressure drops. In addition, values of
viscosity, also required in calculating the Reynolds
number, are given in Figs. 3, 4 and 5 for selected liquids and gases. Table 4 lists the relationship between
various units of viscosity.
Resistance to flow in valves and fittings
Pipelines and duct systems contain many valves and
fittings. Unless the lines are used to transport fluids
over long distances, as in the distribution of process
steam at a factory or the cross country transmission
of oil or gas, the straight runs of pipe or duct are relatively short. Water, steam, air and gas lines in a power
plant have relatively short runs of straight pipe and
many valves and fittings. Consequently, the flow resistance due to valves and fittings is a substantial part
of the total resistance.
Methods for estimating the flow resistance in valves
and fittings are less exact than those used in establishing the friction factor for straight pipes and ducts.
In the latter, pressure drop is considered to be the result of the fluid shear stress at the boundary walls of
the flow channel; this leads to relatively simple boundary value evaluations. On the other hand, pressure
losses associated with valves, fittings and bends are
mainly the result of impacts and inelastic exchanges
Table 1
Velocities Common in Steam Generating Systems
Velocity
Nature of Service
Air:
Air heater
Coal and air lines,
pulverized coal
Compressed air lines
Forced draft air ducts
Forced draft air ducts,
entrance to burners
Ventilating ducts
Crude oil lines [6 to 30
in. (152 to 762 mm)]
Flue gas:
Air heater
Boiler gas passes
Induced draft flues
and breaching
Stacks and chimneys
Natural gas lines (large
interstate)
Steam:
Steam lines
High pressure
Low pressure
Vacuum
Superheater tubes
Fig. 2 Relative roughness of various conduit surfaces. (SI conversion: mm = 25.4 X in.)
Steam 41 / Fluid Dynamics
ft/min
m/s
1000 to 5000
5.1 to 25.4
3000 to 4500
1500 to 2000
1500 to 3600
15.2 to 22.9
7.6 to 10.2
7.6 to 18.3
1500 to 2000
1000 to 3000
7.6 to 10.2
5.1 to 15.2
60 to 3600
0.3 to 18.3
1000 to 5000
3000 to 6000
5.1 to 25.4
15.2 to 30.5
2000 to 3500
2000 to 5000
10.2 to 17.8
10.2 to 25.4
1000 to 1500
5.1 to 7.6
8000 to 12,000 40.6 to
12,000 to 15,000 61.0 to
20,000 to 40,000 101.6 to
2000 to 5000
10.2 to
Water:
Boiler circulation
Economizer tubes
Pressurized water
reactors
Fuel assembly channels
Reactor coolant piping
Water lines, general
61.0
76.2
203.2
25.4
70 to 700
150 to 300
0.4 to 3.6
0.8 to 1.5
400 to 1300
2400 to 3600
500 to 750
2.0 to 6.6
12.2 to 18.3
2.5 to 3.8
3-9
The Babcock & Wilcox Company
Table 2
Physical Properties of Liquids at 14.7 psi (0.101 MPa)
Liquid
Temperature F (C)
Water
70 (21)
212 (100)
70 (21)
Automotive oil
SAE 10
SAE 50
Mercury
Fuel oil, #6
70
70
180
70
Kerosene
55 to 57
57 to 59
846
60 to 65
60 to 65
50 to 51
(21)
(21)
(82)
(21)
Table 3
Physical Properties of Gases at 14.7 psi (0.101 MPa)**
Instantaneous
Specific Heat
Temperature Density, cp
cv
k,
F
lb/ft3 Btu/lb F Btu/lb F cp/cv
Air
70
200
500
1000
0.0749
0.0601
0.0413
0.0272
0.241
0.242
0.248
0.265
0.172
0.173
0.180
0.197
1.40
1.40
1.38
1.34
70
200
500
1000
0.1148
0.0922
0.0634
0.0417
0.202
0.216
0.247
0.280
0.155
0.170
0.202
0.235
1.30
1.27
1.22
1.19
H2
70
200
500
1000
0.0052
0.0042
0.0029
0.0019
3.440
3.480
3.500
3.540
2.440
2.490
2.515
2.560
1.41
1.40
1.39
1.38
Flue gas*
70
200
500
1000
0.0776
0.0623
0.0429
0.0282
0.253
0.255
0.265
0.283
0.187
0.189
0.199
0.217
1.35
1.35
1.33
1.30
70
200
500
1000
0.0416
0.0334
0.0230
0.0151
0.530
0.575
0.720
0.960
0.406
0.451
0.596
0.836
1.30
1.27
1.21
1.15
CO2
CH4
* From coal; 120% total air; flue gas molecular weight 30.
** SI conversions: T, C = 5/9 (F-32); ρ, kg/m3 = 16.02 x lbm/
ft3; cp, kJ/kg K = 4.187 x Btu/lbm F.
3-10
Specific Heat
Btu/lb F (kJ/kg C)
62.4 (999.4)
59.9 (959.3)
of momentum. These losses are frequently referred to
as local losses or local nonrecoverable pressure losses.
Even though momentum is conserved, kinetic energies are dissipated as heat. This means that pressure
losses are influenced mainly by the geometries of
valves, fittings and bends. As with turbulent friction
factors, pressure losses are determined from empirical correlations of test data. These correlations may
Gas
Density
lb/ft3 (kg/m3 )
1.000 (4.187)
1.000 (4.187)
(881 to 913)
(913 to 945)
(13,549)
(961 to 1041)
(961 to 1041)
(801 to 817)
0.435
0.425
0.033
0.40
0.46
0.47
(1.821)
(1.779)
(0.138)
(1.67)
(1.93)
(1.97)
be based on equivalent pipe lengths, but are preferably defined by a multiple of velocity heads based on
the connecting pipe or tube sizes. Equivalent pipe
length calculations have the disadvantage of being
dependent on the relative roughness (ε/D) used in the
correlation. Because there are many geometries of
valves and fittings, it is customary to rely on manufacturers for pressure drop coefficients.
It is also customary for manufacturers to supply
valve flow coefficients (CV) for 60F (16C) water. These
are expressed as ratios of weight or volume flow in the
fully open position to the square root of the pressure
drop. These coefficients can be used to relate velocity
head losses to a connecting pipe size by the following
expression:
(50)
N v = kD 4 / CV 2
Table 4
Relationship Between Various Units of Viscosity
Part A: Dynamic (or Absolute) Viscosity, µ
Pa s
Ns
m2
=
Centipoise
kg
ms
0.01 g
cm s
1.0
0.001
1.49
413 x 10−6
47.90
1000
1.0
1488
0.413
47,900
lbm
ft s
672 x 10−3
672 x 10−6
1.0
278 x 10−6
32.2
lbm
ft h
lbf s
ft2
20.9 x 10−3
20.9 x 10−6
0.0311
8.6 x 10−6
1.0
2420
2.42
3600
1.0
115,900
Part B: Kinematic Viscosity, ν = µ/ρ
Centistoke
m2
s
1.0
10−6
92.9 x 10−3
25.8 x 10−6
0.01 cm2
s
ft2
s
ft2
h
106
1.0
92,900
25.8
10.8
10.8 x 10−6
1.0
278 x 10−6
38,800
0.0389
3600
1.0
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
Fig. 4 Absolute viscosities of some common gases at atmospheric
pressure.
Fig. 3 Absolute viscosities of some common liquids (Pa s =
0.000413 X lbm/ft h).
where
Nυ = number of velocity heads, dimensionless
k = units conversion factor: for CV based upon
gal/min/(∆ρ)1/2, k = 891
D = internal diameter of connecting pipe, in.
(mm)
CV = flow coefficient in units compatible with k and
D: for k = 891, CV = gal/min/(∆ρ)1/2
CV and corresponding values of Nυ for valves apply
only to incompressible flow. However, they may be extrapolated for compressible condition using an average
specific volume between P1 and P2 for ∆P values as high
as 20% of P1. This corresponds to a maximum pressure
ratio of 1.25. The ∆P process for valves, bends and fittings is approximately isothermal and does not require
the most stringent limits set by Equation 21.
When pressure drop can be expressed as an equivalent number of velocity heads, it can be calculated by
the following formula in English units:
∆P = N v
v
12
G
105
2
(51)
where
∆P = pressure drop, lb/in.2
Nυ = number of equivalent velocity heads, dimensionless
υ = specific volume, ft3/lb
G = mass flux, lb/ft2 h
Another convenient expression, in English units only,
for pressure drop in air (or gas) flow evaluations is:
Steam 41 / Fluid Dynamics
∆P = N v
30 T + 460 G
B 1.73 × 105 103
2
(52)
where
∆P = pressure drop, in. wg
B = barometric pressure, in. Hg
T = air (or gas) temperature, F
Equation 52 is based on air, which has a specific
volume of 25.2 ft3/lb at 1000R and a pressure equivalent to 30 in. Hg. This equation can be used for other
gases by correcting for specific volume.
The range in pressure drop through an assortment
of commercial fittings is given in Table 5. This resistance
to flow is presented in equivalent velocity heads based
on the internal diameter of the connecting pipe. As noted,
pressure drop through fittings may also be expressed as
the loss in equivalent lengths of straight pipe.
Contraction and enlargement irreversible
pressure loss
The simplest sectional changes in a conduit are converging or diverging boundaries. Converging boundaries can stabilize flow during the change from pressure energy to kinetic energy, and local irrecoverable
flow losses (inelastic momentum exchanges) can be
practically eliminated with proper design. If the included angle of the converging boundaries is 30 deg
(0.52 rad) or less and the terminal junctions are
smooth and tangent, any losses in mechanical energy
are largely due to fluid friction. It is necessary to consider this loss as 0.05 times the velocity head, based
on the smaller downstream flow area.
3-11
The Babcock & Wilcox Company
When the elevation change (Z2 – Z1) is zero, the
mechanical energy balance for converging boundaries
becomes:
P1v +
V12
2 gc
= P2v +
V22
V2
+ Nc 2
2 gc
2 gc
(53)
Subscripts 1 and 2 identify the upstream and downstream sections. Nc, the contraction loss factor, is the
number of velocity heads lost by friction and local nonrecoverable pressure loss in contraction. Fig. 6 shows
values of this factor.
When there is an enlargement of the conduit section in the direction of flow, the expansion of the flow
stream is proportional to the kinetic energy of the
flowing fluid and is subject to a pressure loss depending on the geometry. Just as in the case of the contraction loss, this is an irreversible energy conversion
to heat resulting from inelastic momentum exchanges. Because it is customary to show these losses
as coefficients of the higher kinetic energy term, the
mechanical energy balance for enlargement loss is:
P1v +
V12
V2
V2
= P2v + 2 + N e 1
2 gc
2 gc
2 gc
(54)
The case of sudden enlargement [angle of divergence
β = 180 deg (π rad)] yields an energy loss of (V1 - V2)2/
2gc. This can also be expressed as:
Ne
A
= 1 − 1
A2
2
(55)
where A1 and A2 are the upstream and downstream
cross-sectional flow areas, respectively and (A1 < A2).
Even this solution, based on the conservation laws,
depends on qualifying assumptions regarding static
Fig. 5 Absolute viscosities of saturated and superheated steam.
Table 5
Resistance to Flow of Fluids Through
Commercial Fittings*
Fitting
Loss in Velocity Heads
L-shaped, 90 deg (1.57 rad)
standard sweep elbow
L-shaped, 90 deg (1.57 rad)
long sweep elbow
T-shaped, flow through run
T-shaped, flow through 90 deg
(1.57 rad) branch
Return bend, close
Gate valve, open
Check valve, open
Globe valve, open
Angle valve, 90 deg (1.57 rad) open
Boiler nonreturn valve, open
0.3 to 0.7
0.2 to 0.5
0.15 to 0.5
0.6
0.6
0.1
2.0
5.0
3.0
1.0
to
to
to
to
to
to
to
1.6
1.7
0.2
10.0
16.0
7.0
3.0
* See Fig. 9 for loss in velocity heads for flow of fluids
through pipe bends.
3-12
Fig. 6 Contraction loss factor for β >30 deg (Nc = 0.05 for β ≤30 deg).
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
pressures at the upstream and downstream faces of
the enlargement.
Experimental values of the enlargement loss factor, based on different area ratios and angles of divergence, are given in Fig. 7. The differences in static
pressures caused by sudden and gradual changes in
section are shown graphically in Fig. 8. The pressure
differences are shown in terms of the velocity head at
the smaller area plotted against section area ratios.
Flow through bends
Bends in a pipeline or duct system produce pressure
losses caused by both fluid friction and momentum
exchanges which result from a change in flow direction. Because the axial length of the bend is normally
included in the straight length friction loss of the pipeline or duct system, it is convenient to subtract a calculated equivalent straight length friction loss from
experimentally determined bend pressure loss factors.
These corrected data form the basis of the empirical
bend loss factor, Nb.
The pressure losses for bends in round pipe in excess of straight pipe friction vary slightly with Reynolds numbers below 150,000. For Reynolds numbers
above this value, they are reasonably constant and
depend solely on the dimensionless ratio r/D, the ratio of the centerline radius of the bend to the internal
diameter of the pipe. For commercial pipe, the effect
of Reynolds number is negligible. The combined effect of radius ratio and bend angle, in terms of velocity heads, is shown in Fig. 9.
Flow through rectangular ducts
The loss of pressure caused by a direction change
in a rectangular duct system is similar to that for cylindrical pipe. However, an additional factor, the shape
Fig. 8 Static pressure difference resulting from sudden and gradual
changes in section.
of the duct in relation to the direction of bend, must
be taken into account. This is called the aspect ratio,
which is defined as the ratio of the width to the depth
of the duct, i.e., the ratio b/d in Fig. 10. The bend loss
for the same radius ratio decreases as the aspect ratio
increases, because of the smaller proportionate influence
of secondary flows on the stream. The combined effect
of radius and aspect ratios on 90 deg (1.57 rad) duct
bends is given in terms of velocity heads in Fig. 10.
The loss factors shown in Fig. 10 are average values of test results on ducts. For the given range of
aspect ratios, the losses are relatively independent of
the Reynolds number. Outside this range, the variation with Reynolds number is erratic. It is therefore
recommended that Nb values for b/d = 0.5 be used for
all aspect ratios less than b/d = 0.5, and values for b/
d = 2.0 be used for ratios greater than b/d = 2.0. Losses
for bends other than 90 deg (1.57 rad) are customarily considered to be proportional to the bend angle.
Fig. 7 Enlargement loss factor for various included angles.
Steam 41 / Fluid Dynamics
Turning vanes
The losses in a rectangular elbow duct can be reduced by rounding or beveling its corners and by in3-13
The Babcock & Wilcox Company
For applications requiring a uniform velocity distribution directly after the turn, a full complement or
normal arrangement of turning vanes (see Fig. 12b)
is required. However, for many applications, it is sufficient to use a reduced number of vanes, as shown in
Fig. 12c.
For nonuniform flow fields, the arrangement of
turning vanes is more difficult to determine. Many
times, numerical modeling (see Chapter 6) and flow
testing of the duct system must be done to determine
the proper vane locations.
Fig. 9 Bend loss for round pipe, in terms of velocity heads.
stalling turning vanes. With rounding or beveling, the
overall size of the duct can become large; however,
with turning vanes, the compact form of the duct is
preserved.
A number of turning vane shapes can be used in a
duct. Fig. 11 shows four different arrangements. Segmented shaped vanes are shown in Fig. 11a, simple
curved thin vanes are shown in Fig. 11b, and concentric splitter vanes are shown in Fig. 11c. In Fig. 11c,
the vanes are concentric with the radius of the duct.
Fig. 11d illustrates simple vanes used to minimize flow
separation from a square edged duct.
The turning vanes of identical shape and dimension, Fig. 11b, are usually mounted within the bend
of an elbow. They are generally installed along a line
or section of the duct and are placed from the inner
corner to the outside corner of the bend. Concentric
turning vanes, Fig. 11c, typically installed within the
bend of the turn, are located from one end of the turn
to the other end.
The purpose of the turning vanes in an elbow or turn
is to deflect the flow around the bend to the inner wall
of the duct. When the turning vanes are appropriately
designed, the flow distribution is improved by reducing flow separation from the walls and reducing the
formation of eddy zones in the downstream section of
the bend. The velocity distribution over the downstream
cross-section of the turn is improved (see Fig. 12), and
the pressure loss of the turn or elbow is decreased.
The main factor in decreasing the pressure losses
and obtaining equalization of the velocity field is the
elimination of an eddy zone at the inner wall of the
turn. For a uniform incoming flow field, the largest
effect of decreasing the pressure losses and establishing a uniform outlet flow field for a turn or elbow is
achieved by locating the turning vanes closer to the
inner curvature of the bend. (See Figs. 11d and 12c.)
3-14
Fig. 10 Loss for 90 deg (1.57 rad) bends in rectangular ducts.
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
Fig. 12 Velocity profiles downstream of an elbow: a) without
vanes, b) with typical vanes, and c) with optimum vanes (adapted
from Idelchik, Reference 12).
Fig. 11 Turning vanes in elbows and turns: a) segmented, b) thin
concentric, c) concentric splitters, and d) slotted (adapted from
Idelchik, Reference 12).
Pressure loss
A convenient chart for calculating the pressure loss
resulting from impact losses in duct systems conveying air (or flue gas) is shown in Fig. 13. When mass
flux and temperature are known, a base velocity head
in inches of water at sea level can be obtained.
Flow over tube banks
Bare tube The transverse flow of gases across tube
banks is an example of flow over repeated major crosssectional changes. When the tubes are staggered, sectional and directional changes affect the resistance.
Experimental results and the analytical conclusions
of extensive research by The Babcock & Wilcox Company (B&W) indicate that three principal variables
other than mass flux affect this resistance. The primary variable is the number of major restrictions, i.e.,
the number of tube rows crossed, N. The second variable is the friction factor ƒ which is related to the
Reynolds number (based on tube diameter), the tube
spacing diameter ratios, and the arrangement pattern
(in-line or staggered). The third variable is the depth
factor, Fd (Fig. 14), which is applicable to banks less
than ten rows deep. The friction factors ƒ for various
in-line tube patterns are given in Fig. 15.
The product of the friction factor, the number of
major restrictions (tube rows) and the depth factor is,
in effect, the summation of velocity head losses
through the tube bank.
N v = f N Fd
Flow through stacks or chimneys
The flow of gases through stacks or chimneys is established by the natural draft effect of the stack and/
or the mechanical draft produced by a fan. The resistance to this flow, or the loss in mechanical energy be-
(56)
The Nυ value established by Equation 56 may be
used in Equations 51 or 52 to find the tube bank pressure loss. Some test correlations indicate ƒ values
higher than the isothermal case for cooling gas and
lower for heating gas.
Finned tube In some convective boiler design applications, extended surface tube banks are used.
Many types of extended surface exist, i.e., solid helical fin, serrated helical fin, longitudinal fin, square fin
and different types of pin studs. For furnace applications,
the cleanliness of the gas or heat transfer medium dictates whether an extended surface tube bank can be used
and also defines the type of extended surface.
Steam 41 / Fluid Dynamics
Several different tube bank calculation methods
exist for extended surface, and many are directly related to the type of extended surface that is used.
Various correlations for extended surface pressure loss
can be found in References 9 through 15. In all cases,
a larger pressure loss per row of bank exists with an
extended surface tube compared to a bare tube. For
in-line tube bundles, the finned tube resistance per
row of tubes is approximately 1.5 times that of the bare
tube row. However, due to the increased heat transfer absorption of the extended surface, a smaller number of tube rows is required. This results in an overall
bank pressure loss that can be equivalent to a larger
but equally absorptive bare tube bank.
Fig. 13 Mass flux/velocity head relationship for air.
3-15
The Babcock & Wilcox Company
Fig. 14 Draft loss depth factor for number of tube rows crossed in
convection banks.
tween the bottom and the top of the stack, is a result of
the friction and stack exit losses. Application examples
of these losses are given in Chapter 25.
example of inelastic momentum exchanges occurring
within the fluid streams.
The injector is a jet pump that uses condensing steam
as the driving fluid to entrain low pressure water for
delivery against a back pressure higher than the pressure of the steam supplied. The ejector, similar to the
injector, is designed to entrain gases, liquids, or mixtures of solids and liquids for delivery against a pressure less than that of the primary fluid. In a waterjet aspirator, water is used to entrain air to obtain a
partial vacuum. In the Bunsen type burner, a jet of
gas entrains air for combustion. In several instances,
entrainment may be detrimental to the operation of
steam boilers. Particles of ash entrained by the products of combustion, when deposited on heating surfaces, reduce thermal conductance, erode fan blades,
and add to pollution when discharged into the atmosphere. Moisture carrying solids, either in suspension
or in solution, are entrained in the stream. The solids
may be carried through to the turbine and deposited
on the blades, decreasing turbine capacity and efficiency. In downcomers or supply tubes, steam bubbles
are entrained in the water when the drag on the
bubbles is greater than the buoyant force. This reduces the density in the pumping column of natural
circulation boilers.
Pressure loss in two-phase flow
Evaluation of two-phase steam-water flows is much
more complex. As with single-phase flow, pressure loss
occurs from wall friction, acceleration, and change in
elevation. However, the relationships are more complicated. The evaluation of friction requires the assessment of the interaction of the steam and water phases.
Acceleration is much more important because of the
large changes in specific volume of the mixture as
water is converted to steam. Finally, large changes in
average mixture density at different locations significantly impact the static head. These factors are presented in detail in Chapter 5.
Entrainment by fluid flow
Collecting or transporting solid particles or a second fluid by the flow of a primary fluid at high velocity is known as entrainment. This is usually accomplished with jets using a small quantity of high pressure fluid to carry large quantities of another fluid or
solid particles. The pressure energy of the high pressure fluid is converted into kinetic energy by nozzles,
with a consequent reduction of pressure. The material to be transported is drawn in at the low pressure
zone, where it meets and mixes with the high velocity jet. The jet is usually followed by a parallel throat
section to equalize the velocity profile. The mixture
then enters a diverging section where kinetic energy
is partially reconverted into pressure energy. In this
case, major fluid flow mechanical energy losses are an
3-16
Fig. 15 Friction factor (f ) as affected by Reynolds number for
various in-line tube patterns; crossflow gas or air.
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
Boiler circulation
An adequate flow of water and steam-water mixture is necessary for steam generation and control of
tube metal temperatures in all circuits of a steam generating unit. At supercritical pressures this flow is
produced mechanically by pumps. At subcritical pressures, circulation is produced by the force of gravity
or pumps, or a combination of the two. The elements
of single-phase flow discussed in this chapter, twophase flow discussed in Chapter 5, heat input rates,
and selected limiting design criteria are combined to
evaluate the circulation in fossil-fired steam generators. The evaluation procedures and key criteria are
presented in Chapter 5.
References
1.
2.
3.
4.
5.
6.
7.
8.
Meyer, C.A., et al., ASME Steam Tables, Sixth Ed.,
American Society of Mechanical Engineers, New York,
New York, 1993.
Tabor, D., Gases, Liquids and Solids: and Other
States of Matter, First Ed., Penguin Books, Ltd.,
Harmondsworth, England, United Kingdom, 1969.
Lahey, Jr., R.T., and Moody, F.J., The Thermal-Hydraulics of a Boiling Water Nuclear Reactor, American Nuclear Society, Hinsdale, Ilinois, 1993.
Rohsenow, W., Hartnett, J., and Ganic, E., Handbook
of Heat Transfer Fundamentals, McGraw-Hill Company, New York, 1985.
Burmeister, L.C., Convective Heat Transfer, Second
Ed., Wiley-Interscience, New York, New York, 1993.
Schlichting, H.T. Gersten, K., and Krause, E.,
Boundary-Layer Theory, Eighth Ed., Springer-Verlag,
New York, New York, 2000.
Moody, L.F., “Friction Factors for Pipe Flow,” Transactions of the American Society of Mechanical Engineers (ASME), Vol. 66, 8, pp. 671-684, November, 1944.
Hinze, J.O., Turbulence: An Introduction to Its
Mechanism and Theory, Second Ed., McGraw-Hill
Company, New York, New York, 1975.
Steam 41 / Fluid Dynamics
9. Briggs, D.E., and Young, E.H., “Convective heat
transfer and pressure drop of air flowing across triangular pitch banks of finned tubes,” Chemical Engineering Progress Symposium Series (Heat Transfer),
AIChE, Vol. 41, No. 41, pp. l-10, Houston, Texas, 1963.
10. Grimison, E.D., “Correlation and utilization of new
data on flow resistance and heat transfer for crossflow
of gases over tube banks,” Transactions of ASME,
Process Industries Division, Vol. 59, pp. 583-594, New
York, New York, 1937.
11. Gunter, A.Y., and Shan, W.A., “A general correlation
of friction factors for various types of surfaces in crossflow,” Transactions of ASME, Vol. 67, pp. 643-660,
1945.
12. Idelchik, I.E., Handbook of Hydraulic Resistance,
Third Ed., Interpharm/CRC, New York, New York,
November, 1993.
13. Jakob, M., Discussion appearing in Transactions of
ASME, Vol. 60, pp. 384-386, 1938.
14. Kern, D.Q., Process Heat Transfer, p. 555, McGrawHill Company, New York, New York, December, 1950.
15. Wimpress, R.N., Hydrocarbon Processing and Petroleum Refiner, Vol. 42, No. 10, pp. 115-126, Gulf Publishing Company, Houston, Texas, 1963.
3-17
The Babcock & Wilcox Company
Laser velocity measurements in a steam generator flow model.
3-18
Steam 41 / Fluid Dynamics
The Babcock & Wilcox Company
Chapter 4
Heat Transfer
Heat transfer deals with the transmission of thermal energy and plays a central role in most energy
conversion processes. Heat transfer is important in
fossil fuel combustion, chemical reaction processes,
electrical systems, nuclear fission and certain fluid
systems. It also occurs during everyday activities including cooking, heating and refrigeration, as well as
being an important consideration in choosing clothing for different climates.
Although the fundamentals of heat transfer are
simple, practical applications are complex because real
systems contain irregular geometries, combined modes
of heat transfer and time dependent responses.
Fundamentals
Basic modes of heat transfer
There are three modes of heat transfer: conduction,
convection and radiation. One or more of these modes
controls the amount of heat transfer in all applications.
Conduction Temperature is a property that indicates the kinetic energy possessed by the molecules of
a substance; the higher the temperature the greater
the kinetic energy or molecular activity of the substance. Molecular conduction of heat is simply the
transfer of energy due to a temperature difference
between adjacent molecules in a solid, liquid or gas.
Conduction heat transfer is evaluated using
Fourier’s law:
qc = − kA
dT
dx
(1)
The flow of heat, qc, is positive when the temperature gradient, dT/dx, is negative. This result, consistent with the second law of thermodynamics, indicates
that heat flows in the direction of decreasing temperature. The heat flow, qc, is in a direction normal (or perpendicular) to an area, A, and the gradient, dT/dx, is
the change of temperature in the direction of heat flow.
The thermal conductivity, k, a property of the material, quantifies its ability to conduct heat. A range of
thermal conductivities is listed in Table 1. The discrete
form of the conduction law is written:
Steam 41 / Heat Transfer
q =
kA
(T1 − T2 )
L
(2)
Fig. 1 illustrates positive heat flow described by this
equation and shows the effect of variable thermal conductivity on the temperature distribution. The grouping kA/L is known as the thermal conductance, Kc;
the inverse L/kA is known as the thermal resistance,
Rc and Kc = 1/Rc.
A special case of conduction is the thermal contact
resistance across a joint between solid materials. At the
interface of two solid materials the surface to surface
contact is imperfect from the gap that prevails due to
surface roughness. In nuclear applications with fuel
pellets and fuel cladding, surface contact resistance
can have a major impact on heat transfer. If one dimensional steady heat flow is assumed, the heat transfer across a gap is defined by:
q =
T1 − T2
Rct
(3)
where the quantity Rct is called the thermal contact
resistance, 1/hctA, and hct is called the contact coefficient. T1 and T2 are the average surface temperatures
on each side of the gap. Tabulated values of the contact coefficient are presented in References 1 and 2.
Table 1
Thermal Conductivity, k, of Common Materials
Material
Btu/h ft F
Gases at atmospheric
pressure
0.004 to 0.70
Insulating materials
Nonmetallic liquids
Nonmetallic solids
(brick, stone, concrete)
Liquid metals
Alloys
Pure metals
W/m C
0.007 to 1.2
0.01 to 0.12
0.05 to 0.40
0.02 to 0.21
0.09 to 0.70
0.02 to 1.5
0.04 to 2.6
5.0 to 45
8.0 to 70
30 to 240
8.6 to 78
14 to 121
52 to 415
4-1
The Babcock & Wilcox Company
Nomenclature
A
cp
Cf
Ct
C
D
De
Eb
F
F
Fa
Fd
F pp
FT
F
g
G
G
h
hc
h ct
surface area, ft2 (m2)
specific heat at constant pressure, Btu/lb F (J/kg K)
cleanliness factor, dimensionless
thermal capacitance, Btu/ft3 F (J/m3 K)
electrical capacitance, farad
diameter, ft (m)
equivalent diameter, ft (m)
blackbody emissive power, Btu/h ft2 (W/m2)
radiation configuration factor, dimensionless
heat exchanger arrangement factor, dimensionless
crossflow arrangement factor, dimensionless
tube bundle depth factor, dimensionless
fluid property factor, see text
fluid temperature factor, dimensionless
total radiation exchange factor, dimensionless
acceleration of gravity, 32.17 ft/s2 (9.8 m/s2)
incident thermal radiation, Btu/h ft2 (W/m2)
mass flux or mass velocity, lb/h ft2 (kg/m2 s)
heat transfer coefficient, Btu/h ft2 F (W/m2 K)
crossflow heat transfer coef., Btu/h ft2 F (W/m2 K)
contact coefficient, Btu/h ft2 F (W/m2 K)
crossflow velocity and geometry factor, see text
hc′
hl
longitudinal heat transfer coef., Btu/h ft2 F (W/m2 K)
h′
longitudinal flow velocity and geometry factor, see text
l
H
enthalpy, Btu/lb (J/kg)
H fg latent heat of vaporization, Btu/lb (J/kg)
I
electrical current, amperes
J
radiosity, Btu/h ft2 (W/m2)
k
thermal conductivity, Btu/h ft F (W/m K)
K
thermal conductance, Btu/h F (W/K)
Ky
mass transfer coefficient, lb/ft2 s (kg/m2 s)
L
beam length, ft (m)
length or dimension, ft (m)
L,
Lh
fin height, ft (m)
fin spacing, ft (m)
Lt
mass flow rate, lb/h (kg/s)
m
p
pressure or partial pressure, atm (Pa)
P
temp. ratio for surface arrgt. factor, dimensionless
q
heat flow rate, Btu/h (W)
volumetric heat generation rate, Btu/h ft3 (W/m3)
q′′′
q rel heat release, Btu/h ft3 (W/m3)
r
radius, ft (m)
R
electrical resistance (ohms)
R
temp. ratio for surface arrgt. factor, dimensionless
R
thermal resistance, h F/Btu (K/W)
R
radiative resistance, 1/ft2 (1/m2)
Rf
fouling factor, h ft2 F/Btu (m2 K/W)
S
total exposed surface area for a finned surface, ft2 (m2)
Sf
fin surface area; sides plus peripheral area, ft2 (m2)
S H source term for internal heat generation, Btu/h ft3
(W/m3)
t
time, s or h, see text (s)
T
temperature, F or R (C or K)
T°
temperature at initial time, F (C)
∆t
time interval, s
∆T temperature difference, F (C)
∆T log mean temperature difference, F (C)
u,v,w velocity in x, y, z coordinates respectively, ft/s (m/s)
U
overall heat transfer coef., Btu/h ft2 F (W/m2 K)
V
electrical voltage, volts
V
velocity, ft/s (m/s)
V
volume, ft3 (m3)
LMTD
4-2
x
x,y,z
∆x
Y
Yg
Yi
Z
α
β
Γ
ε
η
µ
ρ
ρ
σ
τ
b
c
ct
cv
e
eff
f
fd
g
i
j
o
p
r
s
sg
w
w
δ
∞
⊥
dimension, ft (m)
dimensions in Cartesian coordinate system, ft (m)
change in length, ft (m)
Schmidt fin geometry factor, dimensionless
concentration in bulk fluid, lb/lb (kg/kg)
concentration at condensate interface, lb/lb (kg/kg)
Schmidt fin geometry factor, dimensionless
absorptivity, or total absorptance, dimensionless
volume coefficient of expansion, 1/R (1/K)
effective diffusion coefficient, lb/ft s (kg/m s)
emissivity, or total emittance, dimensionless
Schmidt fin efficiency, dimensionless
dynamic viscosity, lbm/ft s (kg/m s)
density, lb/ft3 (kg/m3)
reflectivity, dimensionless
Stefan-Boltzmann constant, 0.1713 × 10-8 Btu/h ft2
R4 (5.669 × 10-8 W/m2 K4)
transmissivity, dimensionless
Subscripts:
bulk
conduction
contact
convection
node point east
effective
film or fin
fully developed
gas
inside or ith parameter
jth parameter
outside
node point under evaluation
radiation
surface
surface to gas
node point west
wall
liquid film surface (gas liquid interface)
free stream conditions
perpendicular to flow
parallel to flow
Dimensionless groups:
Gr =
g β (Ts − T∞ ) ρ 2 L3
µ2
hL
k
Pe = Re Pr
c µ
Pr = p
k
Ra = Gr Pr
Nu =
ρV L G L
=
µ
µ
Nu
h
St =
=
Re Pr cp G
Re =
Grashof number
Nusselt number
Peclet number
Prandtl number
Rayleigh number
Reynolds number
Stanton number
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Examples include 300 Btu/h ft2 F (1.7 kW/m2 K) between two sections of ground 304 stainless steel in air
and 25,000 Btu/h ft2 F (142 kW/m2 K) between two
sections of ground copper in air. The factors are usually unknown for specific applications and estimates
need to be made. There are two principal contributions
across the gap – solid to solid conduction at the points
of contact and thermal conduction through the entrapped gases in the void spaces.
Convection Convection heat transfer within a fluid
(gas or liquid) occurs by a combination of molecular
conduction and macroscopic fluid motion. Convection
occurs adjacent to heated surfaces as a result of fluid
motion past the surface as shown in Fig. 2.
Natural convection occurs when the fluid motion is
due to buoyancy effects caused by local density differences. In the top portion of Fig. 2, the fluid motion
is due to heat flow from the surface to the fluid; the
fluid density decreases causing the lighter fluid to rise
and be replaced by cooler fluid. Forced convection results when mechanical forces from devices such as fans
give motion to the fluids. The rate of heat transfer by
convection, qcv, is defined:
qcv = hA (Ts − Tf )
(4)
where h is the local heat transfer coefficient, A is the
surface area, Ts is the surface temperature and Tƒ is
the fluid temperature. Equation 4 is known as
Newton’s Law of Cooling and the term hAs is the convection conductance, Kcv. The heat transfer coefficient,
h, is also termed the unit conductance, because it is
defined as the conductance per unit area. Average
heat transfer coefficients over a surface are used in
most engineering applications. This convective heat
transfer coefficient is a function of the thermal and
Fig. 2 Natural and forced convection. Above, boundary layer on a
vertical flat plate. Below, velocity profiles for laminar and turbulent
boundary layers in flow over a flat plate. (Vertical scale enlarged for
clarity.)
fluid dynamic properties and the surface geometry. Approximate ranges are shown in Table 2.
Radiation Radiation is the transfer of energy between bodies by electromagnetic waves. This transfer, unlike conduction or convection, requires no intervening medium. The electromagnetic radiation, in
the wavelength range of 0.1 to 100 micrometers, is
produced solely by the temperature of a body. Energy
at the body’s surface is converted into electromagnetic
waves that emanate from the surface and strike another body. Some of the thermal radiation is absorbed
by the receiving body and reconverted into internal
energy, while the remaining energy is reflected from
or transmitted through the body. The fractions of radiation reflected, transmitted and absorbed by a surface are known respectively as the reflectivity, ρ, transmissivity, τ, and absorptivity α. The sum of these fractions equals one:
Table 2
Typical Convective Heat Transfer Coefficients, h
Condition
Fig. 1 Temperature-thickness relationships corresponding to
different thermal conductivities, k.
Steam 41 / Heat Transfer
Air, free convection
Air, forced convection
Steam, forced convection
Oil, forced convection
Water, forced convection
Water, boiling
Btu/h ft2 F
1 to 5
5 to 50
300 to 800
5 to 300
50 to 2000
500 to 20,000
W/m2 C
6 to 30
30 to 300
1800 to 4800
30 to 1800
300 to 12,000
3000 to 120,000
4-3
The Babcock & Wilcox Company
ρ +τ +α = 1
(5)
All surfaces absorb radiation, and all surfaces whose
temperatures are above absolute zero emit thermal radiation. Surfaces in boilers are typically opaque, which
do not allow transmission of any radiation (τ = 0).
Thermal radiation generally passes through gases
such as dry air with no absorption taking place. These
nonabsorbing, or nonparticipating, gases do not affect the radiative transfer. Other gases, like carbon dioxide, water vapor and carbon monoxide, to a lesser
degree, affect radiative transfer and are known as
participating gases. These gases, prevalent in the flue
gases of a boiler, affect the heat transfer to surfaces
and the distribution of energy absorbed in the boiler.
All bodies continuously emit radiant energy in
amounts which are determined by the temperature
and the nature of the surface. A perfect radiator, or
blackbody, absorbs all of the incident thermal radiation, G, reaching its surface:
qr+ = A G
(6)
and emits radiant energy at the maximum theoretical limit according to the Stefan-Boltzmann law:
qr− = A σ Ts4
(7)
σ is the Stefan-Boltzmann constant 0.1713 × 10-8 Btu/
h ft2 R4 (5.669 × 10-8 W/m2 K4), and Ts is the absolute
temperature of the surface, R (K). The product σ Ts4
is also known as the blackbody emissive power, Eb. The
net radiative heat transfer of a blackbody is the difference between absorbed and emitted radiant energy:
qr = qr+ − qr− = A (G − σ Ts4 )
(8)
The radiation from a blackbody extends over the
whole range of wavelengths, although the bulk of it
in boiler applications is concentrated in a band from
0.1 to 20 micrometers. The wavelength at which the
maximum radiation intensity occurs is inversely proportional to the absolute temperature of the body; this
is known as Wien’s law.
A real radiator absorbs less than 100% of the energy incident on it and emits less than the maximum
theoretical limit. The net heat transfer by radiation
from a real surface can be expressed by:
qr = A (α G − ε σ Ts4 )
(9)
where ε is the total emissivity and α is the total absorptivity. If the emissivity and absorptivity are independent of wavelength, the surface is termed a nonselective radiator, or gray surface. According to
Kirchoff ’s law, emissivity and absorptivity are always
equal for a gray surface:
ε = α
(10)
Therefore, a can be eliminated from Equation 9, and
emissivity is all that is needed to describe the radiation properties of the surface. Table 3 shows some representative values of emissivity. If all surfaces are assumed to be gray, a simpler treatment of radiation is
4-4
Table 3
Representative Values of Emissivity
Polished metals
Metals, as-received
Metals oxidized
Ceramic oxides
Special paints
0.01 <
0.1 <
0.25 <
0.4 <
0.9 <
ε<
ε<
ε<
ε<
ε<
0.08
0.2
0.7
0.8
0.98+
possible. For two surface enclosures, this treatment
involves introducing a total exchange factor, F 12,
which depends on the configuration (geometry), the
emissivities and the surface areas.3
If the emissivity depends on wavelength, the surface is termed a selective or non-gray radiator. According to Kirchhoff ’s law, spectral emissivity and spectral absorptivity are always equivalent, ελ = αλ, for nongray surfaces. Total emissivity is the integrated average of ελ over the spectrum of emitted radiation, and
total absorptivity is the integrated average of αλ over
the spectrum of incident radiation. The terms emissivity and emittance (and corresponding terms absorptivity and absorptance) are commonly interchanged
in the literature. For convenience, the term emittance
is used here for total emissivity and absorptance is
used for total absorptivity, of non-gray surfaces.
For non-gray surfaces, the emittance can be expressed as a function of the surface temperature ε (Ts),
and absorptance as a function of the incident radiation or flame temperature, α (T f ). Based on
Kirchhoff ’s law, plots of ε vs Ts may be interpreted as
plots of α vs Tf if the physical state of the surface is
unchanged. An analysis of non-gray conditions requires temperature dependent emittance and absorptance, or spectral property calculations which are more
complicated. An example of non-gray radiators in a
boiler are the ash deposits on waterwall heating surfaces.
The net radiation heat transfer between two blackbody surfaces which are separated by a vacuum or
nonparticipating gas is written:
q12
(
= A1 F12 σ T14 − T24
)
(11)
A1 is the surface area; F12 is the geometric shape factor and represents the fraction of radiant energy leaving surface 1 that directly strikes surface 2. As will be
discussed later for radiation between two surfaces, F12
is the exchange factor for two surfaces based on the
geometric arrangement only, and F 12 is the exchange
factor that includes the effects of emissivity for gray
surfaces, and participating media between the surfaces. For blackbody surfaces (ε1 = ε2 = 1) and nonparticipating media, F 12 = F12. T1 and T2 are the surface
temperatures. Since the net energy at surface 1 must
balance the net energy at surface 2, we can write:
q12 = − q21
(12)
Using Equations 11 and 12, the following results:
A1 F12 = A2 F21
(13)
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
This equation, known as the principle of reciprocity,
guarantees conservation of the radiant heat transfer
between two surfaces. The following rule applies to the
surfaces of an enclosure:
∑F
j
ij
=1
(14)
stating that the total fraction of energy leaving surface i to all other ( j) surfaces must equal 1. Many
texts include the calculation of geometric shape factors, commonly named shape factors or configuration factors. 1,2 Radiation balances for participating
and nonparticipating media are presented later in the
chapter.
Governing equations
Energy balances The solution of a heat transfer
problem requires defining the system which will be
analyzed. This usually involves idealizing the actual
system by defining a schematic control volume of the
modeled system. A net energy balance on the control
volume reflects the first law of thermodynamics and
can be stated:
energy in − energy out = stored energy
(15)
For a steady flow of heat, the balance simplifies to:
heat in = heat out
(16)
The laws governing the flow of heat are used to obtain equations in terms of material temperature or
fluid enthalpy.
Steady-state conduction The basic laws for each heat
transfer mode and the energy balance provide the tools
needed to write the governing equations for rectangular and cylindrical heat transfer systems. For example, for the plane wall shown in Fig. 1, the steady
flow energy balance for a slice of thickness, dx, is:
dq
dx = 0
q1 − q2 = q − q +
dx
(17)
After substituting Equation 1, this is rewritten as:
d
dx
dT
kA dx = 0
(18)
The conditions at the boundaries, T = T1 at x = 0 and
T = T2 at x = L, provide closure. The general symbolic
form of the equation in three dimensions can be represented, vector notation:
∇ ⋅ (k ∇T ) = 0
(19)
or in x, y, z Cartesian coordinates:
∂
∂x
∂T ∂ ∂T ∂ ∂T
k ∂x + ∂y k ∂y + ∂z k ∂z = 0
(20)
This assumes there is no net heat storage or heat generation in the wall.
Steam 41 / Heat Transfer
Unsteady-state conduction So far only steady-state
conduction, where temperatures vary from point to
point but do not change with time, has been discussed.
All unsteady-state conduction involves heat storage.
For instance, in heating a furnace, enough heat must
be supplied to bring the walls to the operating temperature and also to make up for the steady-state
losses of normal operation. In large power boilers that
run for long periods of time, heat storage in the walls
and boiler metal is an insignificant fraction of the total heat input. In small boilers with refractory settings
that are operated only part time, or in furnaces that
are frequently heated and cooled in batch process
work, heat stored in the walls during startup may be
a considerable portion of the total heat input.
Unsteady-state conduction is important when equalizing boiler drum temperature during pressure raising and reducing periods. When boiler pressure is
raised, the water temperature rises. The inner surface
of the steam drum is heated by contact with the water below the water line and by the condensation of
steam above the water line. The inside and outside
drum temperatures are increased by unsteady-state
conduction. During this transient heatup period, temperature differentials across the drum wall (or thermal gradients) will be larger than during steady-state
operation. Larger thermal gradients result in higher
thermal stresses as discussed in Chapter 8. The rate
of temperature and pressure increase must therefore
be controlled to maintain the thermal stresses within
acceptable levels in order to protect the drum. During
pressure reducing periods, the inside of the drum below the water line is cooled by boiler water while the
top of the drum is cooled by radiation to the water, by
the steam flow to the outlet connections, and by unsteady-state conduction through the drum walls.
Unsteady-state conduction occurs in heating or cooling processes where temperatures change with time.
Examples include heating billets, quenching steel, operating regenerative heaters, raising boiler pressure,
and heating and cooling steam turbines. By introducing time as an additional variable, conduction analyses become more complicated. For unsteady heat flow,
the one dimensional thermal energy equation becomes:
ρ cp
∂ ∂T
∂T
k
=
∂x ∂x
∂t
(21)
The left side of the equation represents the rate of
energy storage. The two boundary temperatures at x
= 0 and L, and the initial temperature, T = To, are
sufficient to find a solution. Other boundary conditions
involving radiation, convection, or specified heat flux
at x = 0 or L can also be applied.3
A general form of the energy equation for multidimensional applications is:
ρ cp
∂T
= ∇⋅ ( k ∇ T )
∂t
(22)
where ∇·(k∇T) is defined in Equations 19 and 20. Conditions on the boundary as a function of time, and initial
temperature of the system, are sufficient to find a solution.
4-5
The Babcock & Wilcox Company
Electrical analogy The basic laws of conduction,
convection and radiation can frequently be rearranged into equations of the form:
q =
T1 − T2
Rt
(23)
This equation can be compared to Ohm’s law for electrical circuits (I = V/R). The heat transfer or heat flow
from point 1 to 2 (q) is analogous with current (I ),
the temperature difference (T1 – T2) is analogous with
voltage (V), and the thermal resistance (Rt) is analogous with electrical resistance (R). Thermal resistance
is defined as the reciprocal of thermal conductance,
K t. Table 4 contains analog thermal resistances used
in many applications.
For systems with unsteady-state conduction governed by Equation 21 or 22, an electrical analogy can
be written:
dT
dt
q = Ct
(24)
where Ct is the thermal capacitance, ρ cpV. This equation can be compared with its electrical equivalent:
I = C
dV
dt
(25)
where C is the electrical capacitance. Kirchhoff ’s law
for electrical circuits provides the last analogy needed.
In heat transfer notation this would be:
∑q
= qstored
(26)
Table 4
Summary of Thermal Resistances
Rectangular
Geometries
and Surfaces
Cylindrical
Geometries
and Surfaces
Conduction, Rc
∆x
kA
n (r2/r1)
2πkl
Convection, Rcv
from surface
1
hA
1
2πr2lh
T2−T3
T2−T3
Radiation, Rr
from surface
T2
σ(T24−T34 )
T1
h, A
Heat flow
T3
Body of conductivity, k,
and area, A, normal to
heat flow
∆x
4-6
23A2
23(2πr2l)
r1
l
This is an expression of the first law of thermodynamics which states that all heat flows into a point equal
the rate of energy storage.
Consider the composite system and the equivalent
thermal circuit shown in Fig. 3. The concepts of resistance and conductance are particularly useful when
more than one mode of heat transfer or more than one
material or boundary is involved. When two modes of
heat transfer, such as convection and radiation, occur simultaneously and independently, the combined
conductance, K, is the sum of the individual conductances, K cv and K r. These individual conductances are
essentially heat flows in parallel. When the heat flows
are in series, the resistances, not the conductances, are
additive. The total or equivalent thermal resistance
can then be substituted into Equation 23 to calculate
the total heat flow.
Flowing systems Boilers have complex distributions
of flow, temperature and properties. In the basic example depicted in Fig. 4, there is steady flow into and
out of the system, which is lumped into a single control
volume. This leads to a balance of energy written as:
1 H1 + m
2 H2 + m
3 H3 = m
4 H4
m
σ(T24−T34 )
Heat flow
Fig. 3 Temperature distribution in composite wall with fluid films.
T3
r2
T1
T2
(27)
is the mass flow rate at each inlet or outlet
where m
and H is the fluid enthalpy.
As discussed in Chapter 3, the full energy equation
sets the net energy entering a system (from mass flow
into and out of the system) equal to the internal heat
generation, plus the work done by the system, plus
energy conducted into the system, plus a viscous dissipation term (see Chapter 3, Equation 12). Viscous
dissipation and work done in the boiler system can
both usually be neglected. For steady-state conditions,
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Radiation balances for enclosures
Nonparticipating media Referring to Equation 11, the net
radiation between two blackbody surfaces can be written:
(
q12 = A1 F12 σ T14 − T24
Fig. 4 Energy balance for a flowing system.
the energy equation in terms of fluid enthalpy and in
vector notation can then be written as:
∇ ⋅ ( ρ uH ) = ∇⋅ ( Γ ∇ H )
Convection
Conduction
+
SH
Internal heat
gen
neration
(28)
)
(31)
The term F12 is the geometric shape factor and is
shown for two common geometries in Fig. 5. Use of the
tabulated values for more complex problems is demonstrated in the example problems under Applications. Equation 31 has limited value in boilers, because
most fireside surfaces are not blackbodies. This equation is better used to obtain estimates of radiation heat
transfer, because it describes the maximum theoretical rate of energy transfer between two surfaces.
For the theory of radiation heat transfer in enclosures, see Reference 4. The energy striking a surface,
called the incident energy, G, is the total energy striking a surface from all other surfaces in the enclosure.
The energy leaving a surface, called the radiosity, J, is
comprised of the energy emitted from the surface (Eb)
The parameter Γ is an effective diffusion coefficient
that includes molecular diffusion and turbulent diffusion. SH is internal heat generation per unit volume.
Rearranging Equation 28 and replacing enthalpy with
temperature (dH = cp dT) the energy equation becomes:
ρ c pu ⋅ ∇T = ∇ ⋅ ( keff ∇T ) + SH
(29)
The parameter keff = cp Γ is effective thermal conductivity. Using x, y, z Cartesian coordinates, the equation is expressed:
∂T
∂T
∂T
+w
+v
ρ cp u
∂z
∂y
∂x
(30)
∂
∂T ∂
∂T ∂
∂T
keff
keff
+
=
+
keff
+ SH
∂x
∂x ∂y
∂y ∂z
∂z
In boiler applications, internal heat generation (SH)
includes radiation absorption and emission from participating gases, and heat release from combustion.
The complete velocity field and thermal boundary
conditions are necessary to find a solution to the fluid
temperature field.
Equations 28 or 29 can be used with single phase
flow or can be used with multiple phase flow (gas-solid
or steam-water) by using mass averaged enthalpy or
temperature. The development and application of the
energy equation in rectangular, cylindrical and spherical coordinates are discussed in References 1 and 2.
Most boiler applications are too complex for an algebraic solution of the energy equation. However, the
continuity and momentum equations discussed in
Chapter 3 (Equations 3 to 10) are combined with the
energy equation to form a fundamental part of the
computational models discussed in Chapter 6. A numerical solution to this equation can then be readily
achieved for many complex problems involving radiation and combustion.
Steam 41 / Heat Transfer
Fig. 5 Shape factors, Fij, for calculating surface-to-surface radiation
heat transfer.
4-7
The Babcock & Wilcox Company
and the reflected incident energy. These terms are related by:
J = ε Eb + ρ G
(32)
The net radiation heat transfer from a surface is found
as follows:
q = A (J − G )
(33)
Combining Equations 32 and 33 leads to the electrical analogy listed first in Table 5. This circuit equivalent describes the potential difference between the
surface at an emissive power, evaluated at Ts, and the
surface radiosity. To evaluate the radiative heat transfer, the radiosity must first be determined. The net
energy between surface i and surface j is the difference between the outgoing radiosities:
qij = Ai Fij ( J i − J j )
(34)
The electrical analogy of the net exchange between
two surfaces is listed in Table 5. The sum of similar
terms for all surfaces in the enclosure yields the circuit diagram in the table and the equation:
qi =
N
∑ A F (J
j =1
i
ij
i
− Jj)
where
R1 =
Eb2 − Eb1
=
R1 + R2 + R3
(36)
1 − ε1
1 − ε2
1
,R =
, R3 =
ε1 A1 2
ε 2 A2
A1 F12
Total radiation exchange factors for common two-surface geometries encountered in boiler design are listed
in Table 6.
Participating media On the fire side of the boiler,
the mixture of gases and particles absorbs, emits, and
scatters radiant energy. When a uniform temperaturebounding surface encloses an isothermal gas volume,
the radiant heat transfer can be treated as one zone,
with absorption and emission from the participating gas
mixture. The incident radiation on the surfaces is made up
of the emitted energy from the gas, εg Ebg, and incoming
energy from the surrounding walls, (1 − αg) Js. Therefore,
the incident radiation is defined by:
Gs = ε g Ebg + (1 − α g ) J s
(35)
The rules for electrical circuits are useful in finding
the net radiation heat transfer. Consider the electrical circuit for radiation heat transfer between two gray
walls shown in Fig. 6.
The rules for series circuits can be used to determine
the net heat transfer:
q12
Fig. 6 Electric circuit analogy for thermal radiation.
(37)
Table 6
Common Gray Two-Surface Enclosures
Large (Infinite) Parallel Planes
A1 = A2 = A
A1,T1,ε1
1
12 =
A2,T2,ε2
1
ε1
F12 = 1
1
+
ε2
−1
Long (Infinite) Concentric Cylinders
r1
Table 5
Network Equivalents for Radiative
Exchange in Enclosures with Gray Surfaces
Circuit
Equivalent
Description
Net exchange
at surface
Ji
=
Ri
Net exchange
between surfaces
i and j
Ji
Net exchange
between
surface i and
all other surfaces
Ji
Jj
Rij
=
Rij
J1
Rik =
=
r1
r2
1
12 =
1
ε1
+
1−ε2
ε2
r1
r2
F12 = 1
Concentric Spheres
1− ε i
Ai εi
r1
1
r2
Ai Fij
1
A1
A2
=
r12
1
12 =
1
r22
ε1
+
1−ε2
ε2
r1
2
r2
F12 = 1
Small Convex Object in a Large Cavity
A1,T1,ε1
Ai Fik
A1
A2
≈ 0
12 =
ε1
J2
Jk
Jj
4-8
Ri
A2
r2
Resistance
Ebi
A1
A2,T2,ε2
F12 = 1
Note: The net heat flow is calculated from
q12 = σA1 12(T14−T24)
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
The energy leaving the surface is made up of direct
emission, εs Ebs, and reflected incident energy, (1−εs)Gs.
Therefore, the radiosity is:
J s = ε s Ebs + (1 − ε s ) Gs
(38)
The solution of Equations 37 and 38 yields values for
the incoming and the outgoing heat fluxes (q /As). The
net heat transfer between the surface and gas becomes:
qsg = J s − Gs =
As ε s (ε g Ebg − α g Ebs )
1 − (1 − α g ) (1 − ε s )
(39)
The calculation of absorptivity is described in the examples at the end of the chapter. When the surfaces
are radiatively black, εs = 1 and Equation 39 becomes:
qsg = As (ε g Ebg − α g Ebs )
(40)
The procedures presented here provide the basis for
engineering estimates which are described with examples at the end of the chapter. However, boiler enclosure wall and gas temperatures generally vary from
wall to wall and even from point to point. A multi-zone,
three-dimensional numerical analysis is then required,
because simple expressions of surface heat transfer and
participating media can not be solved analytically.
Numerical analysis of radiation heat transfer in
multi-dimensional applications with absorption, emission and scattering is routinely applied with commercially available computational fluid dynamics (CFD)
software. This involves the solution of an integral-differential equation for radiation intensity as a function of position, direction, and wavelength. The radiative transport equation (RTE) accounts for loss in intensity by absorption and scattering and gain in intensity by emission and scattering. Boundary conditions are applied for absorption, emission, and reflection at the surface. Integration of the equation over
the blackbody spectrum simplifies the transport equation by eliminating the dependence on wavelength.
The RTE for total (spectrally integrated) radiation
intensity uses total radiative properties for gases, particles, and surfaces.
Heat transfer properties and correlations
Thermal conductivity, specific heat and density
Thermal conductivity, k, is a material property that is
expressed in Btu/h ft F (W/m K) and is dependent on
the chemical composition and physical characteristics of
the substance. The relative order of magnitude of values for various substances is shown in Table 7. Thermal
conductivities are generally highest for solids, lower for
liquids and lower yet for gases. Insulating materials have
the lowest conductivities of solid materials.
Thermal conductivities of pure metals generally
decrease with an increase in temperature, while alloy conductivities may either increase or decrease. (See
Fig. 7.) Conductivities of several steels and alloys are
shown in Table 7. Thermal conductivities of various
Steam 41 / Heat Transfer
Table 7
Properties of Various Substances
at Room Temperature (see Note 1)
ρ
lb
ft3
cp
Btu
lb F
k
Btu
h ft F
559
169
556
493
487
488
0.09
0.21
0.12
0.11
0.11
0.11
223
132
52
42
25
9.4
105
170
27
140
8
~0.2
~0.2
~0.2
~0.2
~0.2
0.87
0.58
0.14
0.075
0.016
0.006
0.09
0.08
0.08
0.04
3.3
0.22
0.24
0.25
0.45
0.099
0.014
0.014
0.014
0.015
62.4
89.8
1.0
0.33
0.32
0.12
METALS
Copper
Aluminum
Nickel
Iron
Carbon steel
Alloy steel 18Cr 8Ni
NONMETAL SOLIDS
Limestone
Pyrex glass
Brick K-28
Plaster
Kaowool
GASES
Hydrogen
Oxygen
Air
Nitrogen
Steam (see Note 2)
LIQUIDS
Water
Sulfur dioxide (liquid)
Notes:
1. SI conversions: ρ, 1 lb/ft3 = 16.018 kg/m3; cp, 1 Btu/lb F =
4.1869 kJ/kg K; k, 1 Btu/h ft F = 1.7307 W/m K.
2. Reference temperature equals 32F (0C) except for steam
which is referenced at 212F (100C).
refractory materials are shown in Chapter 23, Fig. 10.
For many heat transfer calculations it is sufficiently accurate to assume a constant thermal conductivity that
corresponds to the average temperature of the material.
The effective thermal conductivity of ash deposits
on water wall heating surfaces varies widely depending on temperature, composition, heating cycle and
physical characteristics of the deposits. The lower limit
is close to the thermal conductivity of air or lower (0.03
Btu/h ft F or 0.05 W/m K), and the upper limit does
not exceed values for refractory materials (1.4 Btu/h
ft F or 2.4 W/m K). The effective thermal conductivity of a friable particulate layer is near the lower limit
and is fairly independent of temperature below 1650
to 2200F (899 to 1204C) at which sintering usually
occurs. Above this temperature, particles fuse together
and thermal contact between particles increases, resulting in a sharp increase in thermal conductivity. The highest conductivity is achieved with complete melting. The
physical changes caused by fusion and melting are irreversible upon cooling, and thermal conductivity of
fused deposits decreases with decreasing temperature.
4-9
The Babcock & Wilcox Company
40
(69)
Thermal Conductivity, Btu/h ft F (W/m K)
Carbon Steel,
SA210A1, SA106A,B,C
30
(52)
Low Alloy (1-1/4 Cr-1/2 Mo-Si)
SA213T2,T12,T11
Low Alloy (2-1/4 Cr-1Mo)
SA213T22
20
(35)
Medium Alloy (9Cr-1Mo-V)
SA213T9, T91
Alloy 600
Stainless Steel
SA213TP304
10
(17)
Alloy 625
0
100
(38)
300
(149)
Alloy 825
500
(260)
Alloy 800
Stainless Steel
SA213TP309,
TP310, TP316, TP317,
TP321, TP347
700
900
1100
(371)
(482)
(593)
Temperature, F (C)
1300
(704)
1500
(816)
Fig. 7 Thermal conductivity, k, of some commonly used steels and
alloys. (1 Btu/h ft F = 1.7307 W/m K)
Thermal conductance of ash deposits (k/x) is less sensitive to changing conditions than thermal conductivity.
As the deposit grows in thickness (x), thermal conductivity (k) also increases due to fusion and slagging. The
net effect is that unit thermal conductance may only vary
by a factor of four, 25 to 100 Btu/h ft2 F (142 to 568 W/
m2 C), while variations in thermal conductivity are an
order of magnitude larger. The thermal effects of coalash deposits are further described by Wall et al.5
The thermal conductivity of water ranges from 0.33
Btu/h ft F (0.57 W/m K) at room temperature to 0.16
Btu/h ft F (0.28 W/m K) near the critical point. Water
properties are relatively insensitive to pressure, particularly at pressures far from the critical point. Most
other nonmetallic liquid thermal conductivities range
from 0.05 to 0.15 Btu/h ft F (0.09 to 0.26 W/m K). In
addition, thermal conductivities of most liquids decrease with temperature.
The thermal conductivities of gases increase with
temperature and are independent of pressure at normal boiler conditions. These conductivities generally
decrease with increasing molecular weight. The relatively high conductivity of hydrogen (a low molecular weight gas) makes it a good cooling medium for
electric generators. The relatively low conductivity of
argon (a high molecular weight gas) makes a good
insulating medium for thermal pane windows.
When calculating the conductivity of nonhomogeneous materials, the designer must use an apparent
thermal conductivity to account for the porous or layered construction materials. In boilers and furnaces
with refractory walls, thermal conductivity may vary
from site to site due to variations in structure, composition, density, or porosity when the materials were installed. The thermal conductivities of these materials
are strongly dependent on their apparent bulk density (mass per unit volume). For higher temperature
4-10
insulations, the apparent thermal conductivity of fibrous insulations and insulating firebrick decreases
as bulk density increases, because the denser material attenuates the radiation. However, an inflection
occurs at some point at which a further increase in density increases the thermal conductivity due to conduction in the solid material.
Theory shows that specific heats of solids and liquids are generally independent of pressure. Table 7
lists specific heats of various metals, alloys and
nonhomogeneous materials at 68F (20C). These values may be used at other temperatures without significant error.
The temperature dependence of the specific heat for
gases is more pronounced than for solids and liquids.
In boiler applications, pressure dependence may generally be neglected. Tables 8a and 8b give specific heat
data for air and other gases.
In the case of steam and water, property variations
(specific heat and thermal conductivity) can be significant over the ranges of temperature and pressure
found in boilers. It is therefore recommended that the
properties as compiled in the American Society of
Mechanical Engineers (ASME) Steam Tables6 be used.
Radiation properties
Bodies that are good radiation absorbers are equally
good emitters and Kirchhoff ’s law states that, for gray
surfaces at thermal equilibrium, their emissivities are
equal to their absorptivities. A blackbody is one which
absorbs all incident radiant energy while reflecting or
transmitting none of it. The absorptivity and emissivity of a blackbody are, by definition, each equal to one.
This terminology does not necessarily mean that the
body appears to be black. Snow, for instance, absorbs
only a small portion of the incident visible light, but
to the longer wavelengths (the bulk of thermal radiation), snow is almost a blackbody. At a temperature of
2000F (1093C) a blackbody glows brightly, because a
non-negligible part of its radiation is in the visible
range. Bodies are never completely black, but a hole
through the wall of a large enclosure can be used to
approximate blackbody conditions, because radiation
entering the hole undergoes multiple reflections and
absorptions. As a result, most of the radiation is retained
in the enclosure, and surfaces are treated as gray.
Fortunately, a number of commercial surfaces, particularly at high temperatures, have emissivities of
0.80 to 0.95 and behave much like blackbodies. Typical average emissivity values are noted in Table 9.
Although emissivity depends on the surface composition and roughness and wavelength of radiation, the
wavelength dependence is often neglected in practical boiler calculations and surfaces are treated as gray.
Ash deposits The emittance and thermal properties of furnace ash deposits have a large effect on boiler
heat transfer. The emittance depends on the temperature, chemical composition, structure and porosity of
the particulate layer, and whether deposits are partially fused or molten. The same ash at different locations within the same boiler (or the same location in
different boilers) may have significantly different
values of surface emittance. Reported values in the
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Table 8b
Table 8a
Properties of Selected Gases
at 14.696 psi (101.33 kPa) (see Note 1)
Properties of Selected Gases
at 14.696 psi (101.33 kPa) (see Note 1)
T
F
ρ
lb/ft3
cp
Btu/
lb F
k
Btu/
h ft F
µ
lbm/
ft h
Pr
Air
0
100
300
500
1000
1500
2000
2500
3000
0.0860
0.0709
0.0522
0.0413
0.0272
0.0202
0.0161
0.0134
0.0115
0.239
0.240
0.243
0.247
0.262
0.276
0.286
0.292
0.297
0.0133
0.0154
0.0193
0.0231
0.0319
0.0400
0.0471
0.0510
0.0540
0.0400
0.0463
0.0580
0.0680
0.0889
0.1080
0.1242
0.1328
0.1390
0.719
0.721
0.730
0.728
0.730
0.745
0.754
0.760
0.765
Carbon Dioxide (CO2)
0
0.1311
0.184
100
0.1077
0.203
300
0.0793
0.226
500
0.0628
0.247
1000
0.0413
0.280
1500
0.0308
0.298
2000
0.0245
0.309
2500
0.0204
0.316
3000
0.0174
0.322
0.0076
0.0100
0.0149
0.0198
0.0318
0.0420
0.0500
0.0555
0.0610
0.0317
0.0378
0.0493
0.0601
0.0828
0.1030
0.1188
0.1300
0.1411
0.767
0.767
0.748
0.750
0.729
0.731
0.734
0.739
0.745
Water Vapor (H2O)
212
0.0372
300
0.0328
500
0.0258
1000
0.0169
1500
0.0127
2000
0.0100
2500
0.0083
3000
0.0071
0.451
0.456
0.470
0.510
0.555
0.600
0.640
0.670
0.0145
0.0171
0.0228
0.0388
0.0570
0.0760
0.0960
0.1140
0.0313
0.0360
0.0455
0.0691
0.0889
0.1091
0.1289
0.1440
0.974
0.960
0.938
0.908
0.866
0.861
0.859
0.846
Oxygen (O2)
0
0.0953
100
0.0783
300
0.0577
500
0.0457
1000
0.0300
1500
0.0224
2000
0.0178
2500
0.0148
3000
0.0127
0.219
0.220
0.227
0.235
0.253
0.264
0.269
0.275
0.281
0.0131
0.0159
0.0204
0.0253
0.0366
0.0465
0.0542
0.0624
0.0703
0.0437
0.0511
0.0642
0.0759
0.1001
0.1195
0.1414
0.1594
0.1764
0.730
0.707
0.715
0.705
0.691
0.677
0.701
0.703
0.703
Nitrogen (N2)
0
0.0835
100
0.0686
300
0.0505
500
0.0400
1000
0.0263
1500
0.0196
2000
0.0156
2500
0.0130
3000
0.0111
0.248
0.248
0.250
0.254
0.269
0.284
0.292
0.300
0.305
0.0132
0.0154
0.0193
0.0232
0.0330
0.0423
0.0489
0.0565
0.0636
0.0380
0.0440
0.0547
0.0644
0.0848
0.1008
0.1170
0.1319
0.1460
0.713
0.710
0.710
0.704
0.691
0.676
0.699
0.700
0.701
Note:
1. SI conversions: T(C) = [T(F) − 32]/1.8; ρ, 1 lb/ft3 = 16.018
kg/m3; cp, 1 Btu/lb F = 4.1869 kJ/kg K; k, 1 Btu/h ft F =
1.7307 W/m K; µ, 1 lbm/ft h = 0.0004134 kg/m s.
Steam 41 / Heat Transfer
µ
lbm/
ft h
Pr
Flue gas − natural gas (see Note 2)
300
0.0498
0.271
0.0194
500
0.0394
0.278
0.0237
1000
0.0259
0.298
0.0345
1500
0.0193
0.317
0.0452
2000
0.0154
0.331
0.0555
2500
0.0128
0.342
0.0651
3000
0.0109
0.351
0.0742
0.0498
0.0593
0.0803
0.0989
0.1160
0.1313
0.1456
0.694
0.694
0.694
0.693
0.692
0.691
0.689
Flue gas − fuel oil (see Note 3)
300
0.0524
0.259
500
0.0415
0.266
1000
0.0273
0.287
1500
0.0203
0.304
2000
0.0162
0.316
2500
0.0134
0.326
3000
0.0115
0.334
0.0192
0.0233
0.0336
0.0436
0.0531
0.0618
0.0700
0.0513
0.0608
0.0817
0.1001
0.1169
0.1318
0.1459
0.692
0.694
0.696
0.697
0.697
0.696
0.695
Flue gas − coal (see Note 4)
300
0.0537
0.254
500
0.0425
0.261
1000
0.0279
0.282
1500
0.0208
0.299
2000
0.0166
0.311
2500
0.0138
0.320
3000
0.0118
0.328
0.0191
0.0232
0.0333
0.0430
0.0521
0.0605
0.0684
0.0519
0.0615
0.0824
0.1007
0.1173
0.1322
0.1462
0.691
0.693
0.697
0.699
0.700
0.701
0.701
T
F
ρ
lb/ft3
cp
Btu/
lb F
k
Btu/
h ft F
Notes:
1. SI conversions: T(C) = [T(F) − 32]/1.8; ρ, 1 lb/ft3 = 16.018
kg/m3; cp, 1 Btu/lb F = 4.1869 kJ/kg K; k, 1 Btu/h ft F =
1.7307 W/m K; µ, 1 lbm/ft h = 0.0004134 kg/m s.
2. Flue gas composition by volume (natural gas, 15% excess air):
71.44% N2, 2.44% O2, 8.22% CO2, 17.9% H2O.
3. Flue gas composition by volume (fuel oil, 15% excess air):
74.15% N2, 2.54% O2, 12.53% CO2, 0.06% SO2, 10.72% H2O.
4. Flue gas composition by volume (coal, 20% excess air):
74.86% N2, 3.28% O2, 13.97% CO2, 0.08% SO2, 7.81% H2O.
literature claim emittances between 0.5 and 0.9 for
most ash and slag deposits.
The effect of coal ash composition, structure, and
temperature on deposit emittance5,7 is shown in Fig.
8. A friable particulate material has low emittance because radiation is scattered (and reflected) from individual particles and does not penetrate beyond a thin
layer (~1 mm) near the surface. Emittance of friable
ash deposits decreases with increasing surface temperature, until sintering and fusion changes the structure of the deposit. A sharp increase in emittance is
associated with ash fusion as particles grow together
(pores close) and there are fewer internal surfaces to
scatter radiation. Completely molten ash or slag is
partially transparent to radiation, and emittance may
depend upon substrate conditions. The emittance of
completely fused deposits (molten or frozen slag) on
oxidized carbon steel is about 0.9. Emittance increases
4-11
The Babcock & Wilcox Company
1.0
Table 9
211-422 µm
Normal Emissivities, ε, for
Various Surfaces13 (see Note 1)
Emissivity, ε
Temp., F
Aluminum
Aluminum
oxide
Aluminum
paint
Brass
Copper
Copper
Cuprous
oxide
Iron
Iron
Iron
Iron oxide
Steel
Steel
Steel
Steel (Cr-Ni)
0.09 212
0.27 to 0.67
0.22
0.16 to 0.13
0.023
212
120 to 660
1970 to 2330
242
0.66 to 0.54
0.21
0.55 to 0.60
0.24
0.85 to 0.89
0.79
0.66
0.28
0.44 to 0.36
1470 to 2012
392
1650 to 1900
68
930 to 2190
390 to 1110
70
2910 to 3270
420 to 914
Steel (Cr-Ni)
0.90 to 0.97 420 to 980
Description
70
1832
Polished, cast
Smooth sheet
Fresh emeried
Oxidized at 1100F
Rolled sheet
Molten
18-8 rough, after
heating
25-20 oxidized in
service
Rough
Increasing
Particle
Size
<44 µm
0.6
Varying age and Al
content
Dull plate
Molten
Polished
Cooling
Particulates
Fused
Fusion
0.5
(a)
Heating
0.4
Sintering
1.0
0.9
With Carbon
0.8
Increasing
Absorption
0.7
With Fe O
0.6
0.5
Colorless
(b)
0.4
100
300
500
700
900
1100
Surface Temperature, T , C
100 to 700
32 to 212
0.003 in. or thicker
Note:
1. SI conversion: T(C) = [T(F) − 32]/1.8; 1 in. = 25.4 mm.
with increasing particle size of friable particulate deposits (Fig. 8a), because larger particles have less capacity to back-scatter incident radiation. Emittance
increases with increasing iron oxide (Fe2O3) and unburned carbon content of the ash (Fig. 8b) because
these components have a greater capacity to absorb
radiation. Low emittance of some lignitic ash deposits, known as reflective ash, may be attributed to low
Fe2O3 content, although this alone is not a reliable
indicator of a reflective ash. Emittance is also indirectly dependent upon oxidizing and reducing environment of the flue gas, due to the effect on the melting characteristics and unburned carbon content in
the ash. The thermal and radiative effects of coal-ash
deposits are further described by Wall et al.5
Combustion gases Although many gases, such as
oxygen and nitrogen, absorb or emit only insignificant
amounts of radiation, others, such as water vapor,
carbon dioxide, sulfur dioxide and carbon monoxide,
substantially absorb and emit. Water vapor and carbon dioxide are important in boiler calculations because of their presence in the combustion products of
hydrocarbon fuels. These gases are selective radiators.
They emit and absorb radiation only in certain bands
(wavelengths) of the spectrum that lie outside of the
visible range and are consequently identified as
nonluminous radiators. Whereas the radiation from
a furnace wall is a surface phenomenon, a gas radiates and absorbs (within its absorption bands) at every point throughout the furnace. Furthermore, the
emissivity of a gas changes with temperature, and the
presence of one radiating gas may have characteris4-12
53-104 µm
0.7
Commercial sheet
0.63 to 0.42 530 to 930
Brick, red
0.93
Brick, fireclay
0.75
Carbon, lampblack
0.945
Water
0.95 to 0.963
104211 µm
0.8
Total Emissivity or Emittance,
Material
0.9
Fig. 8 Effect of coal ash composition, structure and temperature on
deposit emittance.5,7
tics that overlap with the radiating characteristics of
another gas when they are mixed. The energy emitted by a radiating gaseous mixture depends on gas
temperature, the partial pressures, p, of the constituents and a beam length, L, that depends on the shape
and dimensions of the gas volume. An estimate of the
mean beam length is L = 3.6 V/A for radiative transfer from the gas to the surface of the enclosure, where
V is the enclosure volume and A is the enclosure surface area. The factor 3.6 is approximate, and values
between 3.4 to 3.8 have been recommended depending on the actual geometry.4
Figs. 9 and 10 show the emissivity for water vapor
and carbon dioxide.8 The accuracy of these charts has
gained greater acceptance than the more widely known
charts of Hottel,4 particularly at high temperatures and
short path lengths. The effective emissivity of a water
vapor-carbon dioxide mixture is calculated as follows:
ε = ε H2O + ε CO2 − ∆ ε
(41)
where ∆ε is a correction factor that accounts for the
effect of overlapping spectral bands. This equation
neglects pressure corrections and considers boilers operating at approximately 1 atm. The factors shown in
Fig. 11 depend on temperature, the partial pressures,
p, of the constituents and the beam length, L. The presence of carbon monoxide and sulfur dioxide can typically be neglected in combustion products, because CO
and SO2 are weakly participating and overlap with the
infrared spectrum of H2O and CO2.
When using Figs. 9 to 11 to evaluate absorptivity,
α, of a gas, Hottel4 recommends modification of the pL
product by a surface to gas temperature ratio. This is
illustrated in Example 6 at the end of this chapter.
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
0.70
0.30
400 bar cm
Water Vapor
Total Pressure 1 bar
Partial Pressure 0 bar
0.50
100 bar
0.20
150 bar cm
r cm
80 bar cm
15 b
40 bar c
m
ar cm
0.10
4b
20 ba
r cm
10 b
ar c
0.10
m
6 ba
r cm
0.08
3b
ar
0.05
cm
0.04
1.5
0.03
ba
0.
5
wL
2b
0.05
0.03
0.
m
0.02
rc
600
rc
m
0.
ba
0.01
p
cL
200
800 1000 1200 1400 1600 1800 2000 2200
400
Fig. 9 Emissivity of water vapor at one atmosphere total pressure:
pwL= partial pressure in atmospheres x mean beam length in feet.8
(1 bar-cm = 0.0324 ft-atm; T(F) = [T(C) x 1.8] + 32)
Radiation properties of gases can be calculated more
accurately based on fundamental models for spectral
gas radiation. The exponential wide band model9 predicts spectral absorption and emission properties of
single and multi-component gases including H 2O,
CO2, CO, CH4, NO, and SO2 as a function of temperature and pressure. Diatomic gases N2, O2 and H2 may
contribute to the total gas volume and pressure of the
mixture, but are considered transparent to infrared
radiation. Radiation properties are conveniently expressed as emission and absorption coefficients that
depend on local variations in gas composition, temperature, and pressure. This approach is suitable for numerical modeling of radiation with participating media,
which requires frequent evaluation of gas properties
at a large number of control volumes.
Entrained particles Combustion usually involves
some form of particulate that is entrained in combustion gases. Particles are introduced as the fuel which
undergo transformations of combustion and/or are
formed by the processes of condensation and agglomeration of aerosol particles. Entrained particles have
a significant role in radiation heat transfer because they
absorb, emit, and scatter radiation. Scattering effectively extends the beam length of radiation in an enclosure, because the beam changes direction many times
before it reaches a wall. Radiation from entrained particles depends on the particle shape, size distribution,
chemical composition, concentration, temperature, and
the wavelength of incident radiation.
Particulates in boilers are comprised of unreacted
fuel (coal, oil, black liquor), char, ash, soot, and other
aerosols. Soot is an example of an aerosol that con-
600
=
0.
5
Carbon Dioxide
Total Pressure 1 bar
Partial Pressure 0 bar
ba
rc
m
800 1000 1200 1400 1600 1800 2000 2200
Temperature, C
(T)F = (T(C) x 1.8) + 32
Temperature, C
T(F) = (T(C) x 1.8) + 32
Steam 41 / Heat Transfer
ba
m
rc
m
400
0.6
ba
15
0.005
ba
0.01
cm
rc
m
2
200
0.3
rc
=
m
ar
0.04
m
ar c
1b
ba
p
ar c
m
m
rc
0.02
8b
ar c
Emissivity of Carbon Dioxide
Emissivity of Water Vapor
0.20
cm
40 ba
Fig.10 Emissivity of carbon dioxide at one atmosphere total pressure:
pcL= partial pressure in atmospheres x mean beam length in feet.8
(1 bar-cm = 0.0324 ft-atm; T(F) = [T(C) x 1.8] + 32)
0.07
1700F (925C) and Above
p L + p L = 120 bar cm
0.06
90 bar cm
0.05
60 bar cm
0.04
0.03
30 bar cm
0.02
0.01
90 bar cm
0.00
0.0
0.2
0.6
0.4
0.8
1.0
p
p +p
Fig. 11 Radiation heat transfer correction factor associated with
mixtures of water vapor and carbon dioxide.8 (1 bar-cm = 0.0324 ft-atm)
4-13
The Babcock & Wilcox Company
tributes to radiation from gas flames in boilers. Neglecting the effect of soot on radiation heat transfer
in the flame could lead to significant errors in the calculated flame temperature, and radiation heat transfer to the furnace walls in the flame zone. Ash is an
example of particulate that contributes to radiation in
coal-fired boilers. Scattering by ash particles effectively
redistributes radiation in the furnace, and smooths out
variations in radiation heat flux, analogous to the way
a cloud distributes solar radiation on the earth. The
absorption and emission characteristics of flyash particles increase, and scattering decreases with the relative amount of iron oxide or residual carbon, which acts
as a coloring agent in the ash.
Analytical methods such as Equation 39 that depend upon emissivity and absorptivity of the participating media are inaccurate when particles other
than soot are involved, because the effects of scattering are neglected. Numerical methods which solve the
general form of the radiative transport equation include the effects of scattering (see Numerical methods).
Mie Theory10 is a general method for calculating the
radiation properties of spherical particles as a function of particle composition, concentration, diameter
and wavelength. Rigorous calculations by this method
can only be performed with the aid of a computer and
require that optical properties (complex refractive index as a function of wavelength) of the particle materials are known. The complex refractive index of lignite, bituminous, and anthracite coals, and corresponding properties of char and ash have been measured, as well as other materials that are typically encountered in combustion systems. Radiation properties
of particles are conveniently expressed as total emission,
absorption, and scattering efficiencies that depend on
particle composition, diameter and temperature. Particle
properties must be combined with gas properties in an
analysis of radiation with participating media.
Working formulas for convection
heat transfer
Heat transfer by convection between a fluid (gas
or liquid) and a solid is expressed by Equation 4. This
equation is a definition of the heat transfer coefficient
but is inadequate in describing the details of the convective mechanisms. Only a comprehensive study of the
flow and heat transfer would define the dependence
of the heat transfer coefficient along the surface. In the
literature, simple geometries have been modeled and
predictions agree well with experimental data. However, for the more complex geometries encountered in
boiler analysis, correlations are used that have been
developed principally from experimental data.
Convective heat transfer near a surface takes place
by a combination of conduction and mass transport. In
the case of heat flowing from a heated surface to a cooler
fluid, heat flows from the solid first by conduction into
a fluid element, raising its internal energy. The heated
element then moves to a cooler zone where heat flows
from it by conduction to the cooler surrounding fluid.
Fluid motion can occur in two ways. If the fluid is
set in motion due to density differences arising from
4-14
temperature variations, free or natural convection
occurs. If the motion is externally induced by a pump
or fan, the process is referred to as forced convection.
Convective heat transfer can occur in laminar or
turbulent flows. For laminar flow, the fluid moves in
layers, or lamina, with each element following an orderly path. In turbulent flow, prevalent in boiler passages, the local motion of the fluid is chaotic and statistical treatment is used to establish average velocity
and heat transfer values.
Experimental studies have confirmed that a flow
field can be divided into two zones: a viscous zone
adjacent to the surface and a nonviscous zone removed
from the heat transfer surface. The viscous, heated
zone is termed the boundary layer region. The hydrodynamic boundary layer is defined as the distance
from the wall at which the local velocity reaches 99%
of the velocity far from the wall.
At the entrance of a pipe or duct, the boundary layer
begins to grow; this flow portion is called the developing
region. Downstream, when the viscous region fills the
pipe core or grows to a maximum, the flow is termed fully
developed. Developing region heat transfer coefficients
are larger than the fully developed values. In many
applications it is sufficient to assume that the hydrodynamic and thermal boundary layers start to grow at the
same location, although this is not always the case.
Flow over a body (around a circular cylinder) is
termed external flow, while flow inside a confined region, like a pipe or duct, is termed internal flow.
Natural or free convection
A fluid at rest, exposed to a heated surface, will be
at a higher temperature and lower density than the
surrounding fluid. The differences in density, because
of this difference in temperature, cause the lighter,
warmer fluid elements to circulate and carry the heat
elsewhere. The complex relationships governing this
type of convective heat transfer are covered extensively
in other texts.1 Experimental studies have confirmed
that the main dimensionless parameters governing free
convection are the Grashof and Prandtl numbers:
Gr =
g β (Ts − T∞ ) ρ 2 L3
µ2
Pr =
cp µ
(42)
(43)
k
The Grashof number is a ratio of the buoyant to viscous forces. The Prandtl number is the ratio of the diffusion of momentum and heat in the fluid. The product, Gr Pr, is also called the Rayleigh number, Ra.
In boiler system designs, air and flue gases are the
important free convection heat transfer media. For
these designs, the equation for the convective heat
transfer coefficient h is:
h = C (Ts − T∞ )
1/3
(44)
This correlation is applicable when the Rayleigh number, Ra, is greater than 109, which is generally recogSteam 41 / Heat Transfer
The Babcock & Wilcox Company
nized as the transition between laminar and turbulent flow. Values of the constant C in the equation are
listed below:
Geometry
Horizontal plate facing upward
Vertical plates or pipes more than
1 ft (0.3 m) high
Horizontal pipes
Btu
h ft2 F4/3
W
m2 K 4/3
0.22
1.52
0.19
0.18
1.31
1.24
to turbulence is generally considered for Re ≥ 105. In
the case of flow over a tube, the outside diameter (OD),
D, is the characteristic length. In tube bundles with
crossflow, transition generally occurs at Re > 100.
Experimental studies have confirmed that the convective heat transfer coefficient can be functionally
characterized by the following dimensionless groups:
Nu = f ( Re, Pr )
The correlation generally produces convective heat
transfer coefficients in the range of 1 to 5 Btu/h ft2 F
(5.68 to 28.39 W/m2 K).
where Nu is the Nusselt number, Re is the Reynolds
number and Pr is the Prandtl number.
The Nusselt number, a ratio of the wall temperature
gradient to reference gradients, is defined as follows:
Forced convection
Nu =
Dimensionless numbers Forced convection implies
the use of a fan, pump or natural draft stack to induce fluid motion. Studies of many heat transfer systems and numerical simulation of some simple geometries confirm that fluid flow and heat transfer data
may be correlated by dimensionless numbers. Using
these principles, scale models enable designers to predict field performance. For simple geometries, a minimum of dimensionless numbers is needed for modeling. More complex scaling requires more dimensionless groups to predict unit performance.
The Reynolds number is used to correlate flow and
heat transfer in closed conduits. It is defined as:
ρV L
GL
=
(45)
µ
µ
where L is a characteristic length of the conduit or an
obstacle in the flow field. This dimensionless group
represents the ratio of inertial to viscous forces.
The Reynolds number is only valid for a continuous fluid filling the conduit. The use of this parameter generally assumes that gravitational and intermolecular forces are negligible compared to inertial
and viscous forces.
The characteristic length, termed equivalent hydraulic diameter, is different for circular and
noncircular conduits. For circular conduits, the inside
diameter (ID) is used. For noncircular ducts, the
equivalent diameter becomes:
Re =
De = 4 ×
Flow cross-sectional area
Wetted perimeter
hL
k
(48)
The previously discussed Prandtl number, representing a ratio of the diffusion of momentum and heat in
the fluid, is also the ratio of the relative thickness of
viscous and thermal boundary layers. For air and flue
gases, Pr < 1.0 and the thermal boundary layer is
thicker than the viscous boundary layer.
In the literature, correlations are also presented
using other dimensionless groups; the Peclet and
Stanton numbers are the most common. The Peclet
number is defined as follows:
Pe = Re Pr
(49)
The Stanton number is defined in terms of the Nusselt,
Reynolds and Prandtl numbers:
St =
Nu
Re Pr
(50)
Laminar flow inside tubes For heating or cooling of
viscous fluids in horizontal or vertical tubes with constant surface temperature and laminar flow conditions
(Re < 2300), the heat transfer coefficient, or film conductance, can be determined by the following equation:11
1/3
D
Nu = 1.86 Re Pr
L
µb
µw
0.14
(51)
or
(46)
This approach, used to compare dynamically similar
fluids in geometrically similar conduits of different size,
yields equal Reynolds numbers for the flows considered.
At low velocities, the viscous forces are strong and
laminar flow predominates, while at higher velocities,
the inertial forces dominate and there is turbulent flow.
In closed conduits, such as pipes and ducts, the transition to turbulent flow occurs near Re = 2000. The generally accepted range for transition to turbulent flow
under common tube flow conditions is 2000 < Re < 4000.
For fluid flow over a flat external surface, the characteristic length for the Reynolds number is the surface length in the direction of the flow, x. Transition
Steam 41 / Heat Transfer
(47)
1/3
k GD c p µ D µb
h = 1.86 b
D µ k L b µw
0.14
(52)
where the parameter G = ρV is defined as the mass flux
or mass flow rate per unit area and tube diameter, D, is
the characteristic length used in the evaluation of the
Reynolds number. The ratio of viscosities ( µb /µw) is a
correction factor that accounts for temperature dependent fluid properties. Properties in Equations 51 and 52
are evaluated at an average bulk fluid temperature,
except µw which is evaluated at the wall temperature.
For low viscosity fluids, such as water and gases, a
more complex equation is required to account for the
effects of natural convection at the heat transfer sur4-15
The Babcock & Wilcox Company
face. This refinement is of little interest in industrial
practice because water and gases in laminar flow are
rarely encountered.
Turbulent flow Studies of turbulent flow indicate
several well defined regions as shown in Fig. 12. Next
to the heat transfer surface is a very thin laminar flow
region, less than 0.2% of the characteristic length,
where the heat flow to or from the surface is by molecular conduction. The next zone, known as the buffer
layer, is less than 1% of the characteristic length and
is a mixture of laminar and turbulent flow. Here the
heat is transferred by a combination of convection and
conduction. In the turbulent core, which comprises
roughly 98% of the cross-section, heat is transferred
mainly by convection.
In turbulent flow, the local but chaotic motion of the
fluid causes axial and radial motion of fluid elements.
This combination of motions sets up eddies, or local
swirling motions, augmenting the heat transfer from
the core to the laminar sublayer. The laminar flow in
the sublayer and the laminar component in the buffer
layer act as a barrier, or film, to the heat transfer process. Increasing the fluid velocity has been found to
decrease this film thickness, reducing the resistance
to heat transfer.
Turbulent flow in tubes The distance required to
obtain hydrodynamically and thermally fully developed turbulent flow is shorter than that for laminar
flow. The flow length needed to achieve hydrodynamically fully developed conditions is variable and depends upon the specific Reynolds number (operating
conditions) and surface geometry. It typically varies
from 6 to 20 diameters (x/D). Fully developed thermal flow for gases and air, important in boiler analysis, occurs at similar x/D ratios. However, for liquids,
the ratio is somewhat higher and increases with the
Prandtl number.
Extensive research data using low viscosity gases
and liquids have been correlated. The following equation12 is recommended for fully developed flow with
small to moderate temperature differences:
Nu fd = 0.023 Re0.8 Pr n
(53)
with n = 0.4 for heating of the fluid and n = 0.3 for cooling of the fluid, and properties evaluated at the bulk
temperature. Equation 53 applies to gases and liquids
in the range 0.7 < Pr < 160, which covers all fluids in
boiler analysis. If the conditions are not fully developed,
the correlation is corrected as shown below:13
0.7
Nu = Nu fd 1 + ( D / x )
Fig. 12 Structure of turbulent flow field near a solid boundary.
4-16
(54)
with the stipulation that 2 ≤ x/D ≤ 20. These correlations should only be used for small to moderate temperature differences.
A correlation by Seider and Tate11 is widely used
for heating or cooling of a fluid and larger temperature differences. All of the properties are evaluated at
the bulk temperature, except µw which is evaluated
at the wall temperature:
Nu fd = 0.027 Re
0.8
1/3
Pr
µb
µw
0.14
(55)
The foregoing correlations may be applied for both
constant surface temperature and heat flux conditions
to a good approximation.
For boiler applications involving turbulent flow in
tubes, Equation 53 is rewritten with the temperature
ratio added to convert the properties from a bulk to
film temperature basis:
Nu fd = 0.023 Re
0.8
f
0.4
f
Pr
Tb
Tf
0.8
(56)
All properties are evaluated at the film temperature
(Tƒ), which is defined as the arithmetic mean temperature between the wall temperature (Tw) and the bulk
fluid temperature (Tb ): Tƒ = (Tw + Tb )/ 2 with all temperatures in absolute units (R or K). Equation 56 is
rewritten using parametric groupings:
G 0.8
hl = 0.023 0.2
De
c0p.4 k0.6
0.4
µ
f
Tb
Tf
0.8
(57)
which can be expressed in the form:
hl = hl′ Fpp FT
(58)
Figs. 13 to 17 display the various factors that make
up the right side of Equation 58. Unlike non-dimensional parameters (Nu, Re, Pr), these terms do not
have any physical significance and are dependent
upon the choice of engineering units. The physical
properties factor, Fpp, combines all of the properties of
the fluid into one term, and is evaluated at the gas
film temperature for a particular fluid (gas, air or
steam). Note that if Fpp for steam can not be obtained
from Fig. 16, it can be calculated with values of cp, k
and µ evaluated at the film temperature from the
ASME Steam Tables.6
Turbulent cross flow around tubes The most important boiler application of convection is heat transfer
from the combustion gases to the tubular surfaces in
the convection passes. Perhaps the most complete and
authoritative research on heat transfer of tubes in
crossflow was completed in an extensive program conducted by The Babcock & Wilcox Company (B&W).14
The following correlation was adapted from this study
for different fluids:
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Fig. 15 Effect of film temperature, Tf, and moisture on the physical
properties factor, Fpp, for air; turbulent flow inside tubes or longitudinal flow over tubes (English units only).
Fig. 13 Basic convection velocity and geometry factor, hl′ , for air,
gas or steam; turbulent flow inside tubes or longitudinal flow over
tubes (English units only).
Nu = 0.321 Re
0.61
f
0.33
f
Pr
Fa Fd
(59)
The last terms are an arrangement factor, Fa, and a
depth factor Fd, that correct the results from the base
configuration ( /D0 = 2.0, ⊥ /D0 = 1.75, number of
rows ≥ 10) which by definition Fa = Fd = 1. The equation applies to heating and cooling of fluids for clean
tubes in crossflow. Equation 59 is rewritten using
parametric groupings shown below:
Fig. 14 Effect of film temperature, Tf, and moisture on the physical
properties factor, Fpp, for gas; turbulent flow inside tubes or
longitudinal flow over tubes (English units only).
Steam 41 / Heat Transfer
0.321 G 0.61
hc =
0.39
D
c0p.33 k0.67
Fa Fd
0.28
µ
f
(60)
which can be expressed in the form:
hc = hc′ Fpp Fa Fd
(61)
Figs. 18 to 23 display the various factors that make
up the right side of Equation 61. Unlike non-dimensional parameters (Nu, Re, Pr), these terms do not
Fig. 16 Effect of film temperature, Tf, and pressure on the physical
properties factor, Fpp, for steam; turbulent flow inside tubes or
longitudinal flow over tubes (English units only).
4-17
The Babcock & Wilcox Company
Fig. 17 Temperature factor, FT, for converting mass velocity from
bulk to film basis for air, gas or steam; turbulent flow inside tubes or
longitudinal flow over tubes.
have any physical significance and are dependent
upon the choice of engineering units. The physical
properties factor, Fpp, similar to the one previously
defined, is evaluated at the gas film temperature for
a particular fluid (gas or air). The mass flux or mass
flow per unit area, G, and the Reynolds numbers used
in Equations 59 and 60 and Figs. 18, 21 and 22 are
calculated based on flow conditions at the minimum
free area (maximum velocity) between tubes.
The arrangement factor, Fa, depends on the geometric configuration of tubes, the ratio of tube spacing to
diameter, Reynolds number, and the presence of ash
in the flue gas. Values of Fa for clean tube conditions
with air or flue gas without ash are given in Fig. 21.
Values of Fa for commercially clean tube conditions
with ash-laden flue gas are given in Fig. 22.
The depth factor, Fd, accounts for entrance effects
for banks of tubes which are less than ten rows deep
in the direction of gas flow. For undisturbed flow [flow
that is straight and uninterrupted for at least 4 ft (1.2
m) before entering a tube bank] approaching a bank
of less than ten rows, the film conductance must include the correction factor, Fd, shown in Fig. 23. Fd is
unity when the tube bank is preceded by a bend, screen,
damper or another tube bank in close proximity.
Fig. 19 Effect of film temperature, Tf, and moisture on the physical
properties factor, Fpp, for gas in turbulent crossflow over tubes
(English units only).
Turbulent longitudinal flow around tubes Correlations that were developed based on turbulent flow in
tubes (Equations 56 and 57, and Figs. 13 to 17) can
also be applied for external flow parallel to tubes. In
this case, the equivalent diameter D e (defined by
Equation 46) is used in the evaluation of Reynolds
number. For flow parallel to a bank of circular tubes
arranged on rectangular spacing, the equivalent diameter becomes:
De =
4 1 2
− Do
π Do
(62)
where Do is the tube outside diameter and 1 and 2 are
the centerline spacing between tubes. The mass flux
or mass flow per unit area, G, in Equations 56 and
57, and Fig. 13 is calculated based on the free area
between tubes.
h = Basic Convection Velocity and Geometry Factor
for Crossflow
1000
500
Crossflow
h = 0.321 G /D
300
200
be
100
e
tsid
D
Tu
u
D
=O
0.5
1
50
2
3
30
20
.
, in
ter
e
iam
4
5
10
5
3
2
1
0.1
1
10
G = Mass Flux of Gas or Air, 1000 lb/h ft
100
Fig. 18 Basic crossflow convection velocity and geometry factor,
h′c, for gas or air (English units only).
4-18
Fig. 20 Effect of film temperature, Tf, and moisture on the physical
properties factor, Fpp, for air in crossflow over tubes (English units only).
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Curves Denoted By:
1.1
1.0
0.9
0.8
0.7
0.6
0.5
1.1
1.0
0.9 2
0.8
0.7
0.6
0.5
0.4
1.1
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
1.0
2
3
Curves Denoted By:
0.9
1.25 - 1.5
Tube Spacing in Direction of Gas Flow
Outside Tube Diameter
2
3
0.8
1.25 - 1.5
0.7
Reynolds No. = 40,000
0.6
1
Reynolds No. = 40,000
1
0.5
0.9
2
1.25 - 1.5
3
Reynolds No. = 20,000
1
3
2-3
1.8
1.5
1.25
Reynolds No. = 8,000
1
3
2
1.8
1.5
1.25
Reynolds No. = 2,000
1
1.5
2.0
2.5 3.0 3.5 4.0 4.5 5.0 5.5
Tube Spacing Transverse to Gas Flow
Outside Tube Diameter
6.0
F = Arrangement Factor for In-Line Tube Banks
F = Arrangement Factor for In-Line Tube Banks
1.1
1.0
0.9
0.8
0.7
0.6
0.5
Tube Spacing in Direction of Gas Flow
Outside Tube Diameter
2
0.8
0.7
1.25 - 1.5
3
0.6
Reynolds No. = 20,000
0.5
1
0.4
0.9
0.8
2
0.7
3
0.6
0.5
0.4
0.3
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
1.0
2-3
1.8
1.5
1.25
Reynolds No. = 8,000
1
3
2
1.8
1.5
1.25
Reynolds No. = 2,000
1.5
2.0
2.5 3.0 3.5 4.0 4.5 5.0 5.5
Tube Spacing Transverse to Gas Flow
Outside Tube Diameter
1
6.0
Fig. 21 Arrangement factor, Fa, as affected by Reynolds number for
various in-line tube patterns, clean tube conditions for crossflow of
air or natural gas combustion products.
Fig. 22 Arrangement factor, Fa, as affected by Reynolds number for
various in-line tube patterns, commercially clean tube conditions for
crossflow of ash-laden gases.
General heat transfer topics
rangement correction factor, respectively. The term
∆TLMTD, known as the log mean temperature difference,
is defined as:
Heat exchangers
Boiler systems contain many heat exchangers. In
these devices, the fluid temperature changes as the
fluids pass through the equipment. With an energy
balance specified between two locations, 1 and 2:
p (T2 − T1 )
q = mc
(63)
∆TLMTD =
∆T1 − ∆T2
n ( ∆T1 / ∆T2 )
(66)
∆T1 is the initial temperature difference between the hot
and cold fluids (or gases), while ∆T2 defines the final
temperature difference between these media. The pa-
the change in fluid temperature can be calculated:
p)
T2 = T1 + ( q / mc
(64)
It is therefore appropriate to define a mean effective
temperature difference governing the heat flow. This
difference is determined by performing an energy balance on the energy lost by the hot fluid and that energy gained by the cold fluid. An equation of the form:
q = UA F ∆TLMTD
(65)
is obtained where the parameters U, A and F define the
overall heat transfer coefficient, surface area, and arSteam 41 / Heat Transfer
Fig. 23 Heat transfer depth factor for number of tube rows crossed
in convection banks. (Fd = 1.0 if tube bank is immediately preceded
by a bend, screen or damper.)
4-19
The Babcock & Wilcox Company
rameter U in Equation 65 defines the overall heat transfer coefficient for clean surfaces and represents the unit
thermal resistance between the hot and cold fluids:
1
1
1
=
+ Rw +
UAclean
hi Ai
ho Ao
Type of Fluid
(67)
For surfaces that are fouled, the equation is written:
R
R
1
1
= f ,i +
+ f ,o
UA
Ai
UAclean
Ao
(68)
where Rf,i is the reciprocal effective heat transfer coefficient of the fouling on the inside surface, ( l / UA)
is the thermal resistance and Rf,o is the reciprocal heat
transfer coefficient of the fouling on the outside surface. Estimates of overall heat transfer coefficients and
fouling factors are listed in Tables 10 and 11. Actual
fouling factors are site specific and depend on water
chemistry and other deposition rate factors. Overall
heat transfer coefficients can be predicted using: 1)
the fluid conditions on each side of the heat transfer
surface with either Equation 56 or 59, 2) the known
materials of the heat transfer surface, and 3) the fouling factors listed in Table 11. Often the heat exchanger
tube wall resistance (Rw) is small compared to the surface resistances and can be neglected, leading to the
following equation for a clean surface:
U =
hi ho
hi + ( ho Do / D i )
(69)
This equation assumes that area, A in product UA, is
based on the outside diameter of the tube, Do.
The difficulty in quantifying fouling factors for gas-,
oil- and coal-fired units has led to use of a cleanliness
factor. This factor provides a practical way to provide
extra surface to account for the reduction in heat transfer due to fouling. In gas-fired units, experience indicates that gas-side heat transfer coefficients are higher
as a result of the cleanliness of the surface. In oil- and
coal-fired units that are kept free of slag and deposits, a
Table 10
Approximate Values of Overall Heat Transfer Coefficients
Physical Situation
Plate glass window
Double plate glass window
Steam condenser
Feedwater heater
Water-to-water heat
exchanger
Finned tube heat exchanger,
water in tubes, air
across tubes
Water-to-oil heat exchanger
Steam-to-gas
Water-to-gas
4-20
Btu/h ft2 F
Table 11
Selected Fouling Factors
W/m2 K
1.10
0.40
200 to 1000
200 to 1500
6.20
2.30
1100 to 5700
1100 to 8500
150 to 300
850 to 1700
5 to 10
20 to 60
5 to 50
10 to 20
30 to 55
110 to 340
30 to 300
55 to 110
Sea water above 125F (50C)
Treated boiler feedwater
above 125F (50C)
Fuel oil
Alcohol vapors
Steam, non-oil bearing
Industrial air
h ft2 F/Btu
m2 K/W
0.001
0.0002
0.001
0.005
0.0005
0.0005
0.002
0.0002
0.0010
0.0001
0.0001
0.0004
lower value is used. For units with difficult to remove
deposits, values are reduced further.
There are three general heat transfer arrangements: parallel flow, counterflow and crossflow, as
shown in Fig. 24. In parallel flow, both fluids enter at
the same relative location with respect to the heat
transfer surface and flow in parallel paths over the
heating surface. In counterflow, the two fluids enter
at opposite ends of the heat transfer surface and flow
in opposite directions over the surface. This is the most
efficient heat exchanger although it can also lead to
the highest tube wall metal temperatures. In crossflow,
the paths of the two fluids are, in general, perpendicular to one another.
Fig. 24 shows the flow arrangements and presents
Equation 66 written specifically for each case. The arrangement correction factor, F, is 1.0 for parallel and
counterflow cases. For crossflow and multi-pass arrangements, the correction factors are shown in Figs.
25 and 26.
Extended surface heat transfer
The heat absorption area in boilers can be increased
using longitudinally and circumferentially finned
tubes. Finned, or extended, tube surfaces are used on
the flue gas side. In regions prone to fouling, the fins
must be spaced to permit cleaning. Experimental data
on actual finned or extended surfaces are preferred
for design purposes; the data should be collected at
conditions similar to those expected to be encountered.
However, in place of these data, the method by
Schmidt15 generally describes the heat transfer across
finned tubes. It is based on heat transfer to the underlying bare tube configuration, and it treats the tube
as if it has zero fin height. Schmidt’s correlation for
the gas-side conductance to tubes with helical, rectangular, circular, or square fins is as follows:
S
hf = hc Z 1 − (1 − η f ) f
S
(70)
where hc is the heat transfer coefficient of the bare
tubes in crossflow defined by Equations 59 and 60,
and Z is the geometry factor defined as:
Z
L
= 1 − 0.18 h
Lt
0.63
(71)
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Fig. 25 Arrangement correction factors for a single-pass,
crossflow heat exchanger with both fluids unmixed.
for rectangular, square or circular fins. The parameter Y is defined in Fig. 28.
The overall conductance can be written:
1
1
1
=
+ Rw +
UA
C f Ao hf ,o
Ai hc ,i
(74)
The parameter Cf is the surface cleanliness factor.
NTU method
There are design situations for which the performance of the heat exchanger is known, but the fluid
temperatures are not. This occurs when selecting a unit
for which operating flow rates are different than those
Fig. 24 Mean effective temperature difference.
Sf represents the fin surface area including both sides
and the peripheral area, while S represents the exposed bare tube surface between the fins plus the fin
surface, Sf. The ratio Lh/Lt is the fin height divided
by the clear spacing between fins. Fin efficiency, ηf, is
shown in Fig. 27 as a function of the parameter X,
defined as:
X = Lh 2Zhc / ( kf Lt )
(72)
for helical fins, and
X = rY
Steam 41 / Heat Transfer
2Zhc / ( kf Lt )
(73)
Fig. 26 Arrangement correction factors for a single-pass,
crossflow heat exchanger with one fluid mixed and the other
unmixed (typical tubular air heater application).
4-21
The Babcock & Wilcox Company
In high temperature applications, heat transfer
across the voids occurs mainly by radiation and the
third term of Equation 75 dominates. In low temperature applications, heat flow by conduction dominates
and the first two terms of Equation 75 are controlling.
Fig. 27 Fin efficiency as a function of parameter X.
previously tested. The outlet temperatures can only be
found by trial and error using the methods previously
presented. These applications are best handled by the
net transfer unit (NTU) method that uses the heat
exchanger effectiveness (see Reference 16).
Heat transfer in porous materials
Porosity is an important factor in evaluating the effectiveness of insulation materials. In boiler applications, porous materials are backed up by solid walls or
casings, so that there is minimal flow through the pores.
Heat flow in porous insulating materials occurs by
conduction through the material and by a combination of conduction and radiation through the gas-filled
voids. In most refractory materials, the GrashofPrandtl (Raleigh) number is small enough that negligible convection exists although this is not the case
in low density insulations [< 2 lb/ft3 (32 kg/m3)]. The
relative magnitudes of the heat transfer mechanisms
depend, however, on various factors including porosity of the material, gas density and composition filling the voids, temperature gradient across the material, and absolute temperature of the material.
Analytical evaluation of the separate mechanisms
is complex, but recent experimental studies at B&W
have shown that the effective conductivity can be
approximated by:
keff = a + bT + cT 3
(75)
Experimental data can be correlated through this
form, where a, b and c are correlation coefficients. The
heat flow is calculated using Equation 1; k is replaced
by keff and T is the local temperature in the insulation.
Film condensation
When a pure saturated vapor strikes a surface of
lower temperature, the vapor condenses and a liquid
film is formed on the surface. If the film flows along
the surface because of gravity alone and a condition
of laminar flow exists throughout the film thickness,
then heat transfer through this film is by conduction
only. As a result, the thickness of the condensate film
has a direct effect on the quantity of heat transferred.
The film thickness, in turn, depends on the flow rate
of the condensate. On a vertical surface, because of
drainage, the thickness of the film at the bottom will
be greater than at the top. Film thickness increases
as a plate surface is inclined from the vertical position.
As the film temperature increases, its thickness
decreases primarily due to increased drainage velocity. In addition, the film thickness decreases with increasing vapor velocity in the direction of drainage.
Mass diffusion and transfer
Heat transfer can also occur by diffusion and mass
transfer. When a mixture of a condensable vapor and
a noncondensable gas is in contact with a surface that
is below the dew point of the mixture, some condensation occurs and a film of liquid is formed on the surface. An example of this phenomenon is the condensation of water vapor on the outside of a metal container. As vapor from the main body of the mixture
diffuses through the vapor-lean layer, it is condensed
on the cold surface as shown in Fig. 29. The rate of
condensation is therefore governed by the laws of gas
diffusion. The heat transfer is controlled by the laws
of conduction and convection.
The heat transferred across the liquid layer must
equal the heat transferred across the gas film plus the
latent heat given up at the gas-liquid interface due
to condensation of the mass transferred across the gas
film. An equation relating the mass transfer is:
hδ (Ti − Tδ ) = hg (Tg − Ti ) + K y H fg (Yg − Yi )
(76)
where T and Y define the temperatures and concentrations respectively identified in Fig. 29, hδ is the
heat transfer coefficient across the liquid film, hg is
the heat transfer coefficient across the gas film, and
Ky is the mass transfer coefficient. Hfg is the latent
heat of vaporization.
Heat transfer due to mass transfer is important in designing cooling towers and humidifiers, where mixtures
of vapors and noncondensable gases are encountered.
Fig. 28 Coefficient Y as a function of ratio R/r for fin efficiency.
4-22
Evaporation or boiling
The phenomenon of boiling is discussed in Chapters 1 and 5, where the heat transfer advantages of
nucleate boiling are noted. Natural-circulation fossil
fuel boilers are designed to operate in the boiling
range. In this range, the heat transfer coefficient varSteam 41 / Heat Transfer
The Babcock & Wilcox Company
and 17.) The governing equation is integrated, or averaged, over the subvolume, leading to an expression
of the form:
Te − Tp
R pe
Fig. 29 Simultaneous heat and mass transfer in the dehumidification of air.
ies from 5000 to 20,000 Btu/h ft2 F (28,392 to 113,568
W/m2 K). This is not a limiting factor in the design of
fossil fuel boilers provided scale and other deposits are
prevented by proper water treatment, and provided
the design avoids critical heat flux (CHF) phenomena.
(See Chapter 5.)
In subcritical pressure once-through boilers, water
is completely evaporated (dried out) in the furnace wall
tubes which are continuous with the superheater
tubes. These units must be designed for subcooled
nucleate boiling, nucleate boiling, and film boiling,
depending on fluid conditions and expected maximum
heat absorption rates.
Fluidized-bed heat transfer
The heat transfer in gas-fluidized particle beds used in
some combustion systems is complex, involving particle-tosurface contact, general convection and particle-to-surface
thermal radiation. Correlations for heat transfer to tube
bundles immersed in fluidized beds are summarized in
Chapter 17.
+
Tw − Tp
R pw
+ q′′′
p Vp = cp
Tp − Tpo
∆t
(77)
where the subscripts denote the neighbor locations as
points on a compass. If the steady-state solution is desired, the right hand side of the equation, cp (Tp − Tpo ) / ∆t,
which accounts for changes in stored energy is set to zero.
A solution is then obtained numerically. Equation 77
is a discrete form of the continuous differential equation. The modeled geometry is subdivided and equations of this form are determined for each interior
volume. The electrical analogy of the equation is apparent. First, each term is an expression of heat flow
into a point using Fourier’s law by Equation 1 and,
second, Kirchhoff ’s law for electrical circuits, Equation 26, is used to determine the net flow of heat into
any point. The application of the electrical analogy is
straightforward for any interior volume once the
subvolumes are defined. At the boundaries, temperature or heat flow is defined.
For unsteady-state problems, a sequence of solutions
is obtained for the time interval ∆t, with Tpo being the node
temperature at the beginning of the interval and Tp
being the temperature at the end of the interval. References 16 and 17 explore these models in depth. Various computer codes are commercially available to perform the analysis and display the results.
Radiation
Numerical methods provide accurate estimates of
radiative transfer in the absorbing and scattering
media that is ubiquitous in the combustion and post-
Numerical modeling
Advances in computers have enabled B&W to mathematically model complex heat transfer systems. These
models provide a tool for analyzing thermal systems
inexpensively and rapidly. Although empirical methods and extensive equipment testing continue to provide information to designers, numerical simulation of
boiler components, e.g., membrane walls, will become
increasingly important as computer technology evolves.
(See Chapter 6.)
Conduction
The energy equation for steady-state heat flow was
previously defined as Equation 19 and is more generally written as Equation 20. Solutions of these equations for practical geometries are difficult to obtain
except in idealized situations. Numerical methods
permit the consideration of additional complex effects
including irregular geometries, variable properties,
and complex boundary conditions. Conduction heat
flow through boiler membrane walls, refractory linings with several materials, and steam drum walls are
several applications for these methods. The approach
is to divide the heat transfer system into subvolumes
called control volumes (Fig. 30). (See References 16
Steam 41 / Heat Transfer
Fig. 30 Control volume layout for a plane wall with notation for heat
flow to node 3 and steady-state solution.
4-23
The Babcock & Wilcox Company
combustion zones of a boiler. Many numerical methods have the advantage of incorporating complex geometrical description of the enclosure walls. These
methods solve the radiation transport equation (RTE)
in two and three dimensions and include the effects
of absorption, emission, and scattering media, for gray
or non-gray enclosure walls. Numerical models start
by dividing the volume and surfaces of an enclosure
into multiple control volumes and surface elements (as
described in Chapter 6). Radiation properties of gases
and particles are evaluated at each control volume,
and may vary with local composition and temperature
of the combustion mixture. Emissivity and temperature of the walls may also vary with local conditions,
for each surface element of the enclosure. The solution of the RTE is generally carried out for the entire
radiative spectrum for greatest numerical efficiency.
However, if increased accuracy is required, the spectrum can be divided into discrete bands corresponding with the bands of gaseous radiation and the RTE
is solved for each band separately.
Radiative heat transfer in furnaces can be calculated
by one of several numerical methods, which are described in Reference 10. The simplest of these is the zonal
method,4 an extension of the network exchange method
described previously in this chapter. The enclosure is
divided into a finite number of isothermal volume and
surface area zones. Exchange factors for all combinations of volume to volume, volume to surface, and surface to surface exchange are precalculated. This analysis leads to a set of simultaneous equations for unknown
radiant heat fluxes, which are solved numerically.
The discrete ordinates method is perhaps the most
robust approach for numerical analysis of radiation
heat transfer in boilers. The angular dependence of
radiation is first expressed in spherical coordinates,
and is divided into a finite number of discrete directions for solving the RTE. The equations are transformed into a set of simultaneous partial differential
equations, one for each direction, that are solved numerically. The accuracy of the method increases with
the number of directions that are used in the approximation (typically 12, 24, or 48). Discrete ordinates was
developed and optimized for thermal radiation in
multi-dimensional geometries by the pioneering work
at B&W.18 Since then, it has gained in popularity, and
is now used in many commercial computational fluid
dynamics (CFD) codes.
The numerical solution for radiation leads to the
distribution of radiant intensity or radiant heat flux,
for a given temperature field. This solution is coupled
to the energy equation and temperature of the gasparticle mixture. The energy equation (Equation 28
or 29) can be solved numerically for gas-particle temperature field using the methods described in Chapter 6. Radiation absorption and emission is represented
by the internal heat generation term, SH. Wall temperature is determined from an energy balance for
convection and radiation heat transfer to the surface,
and heat conduction through the wall. Several iterations between radiation, gas-particle energy, and wall
temperature will ultimately yield a converged solution
in which an overall energy balance is achieved.
4-24
Design considerations
Furnaces
Fossil-fuel fired boiler designers need to evaluate
furnace wall temperature and heat flux, flue gas temperature, and furnace exit gas temperature. These parameters are required to determine materials and their
limits, and to size heat transfer surface.
An analytical solution for heat transfer in a steam
generating furnace is extremely complex. It is not possible to calculate furnace outlet temperatures by theoretical methods alone. Nevertheless, this temperature
must be correctly predicted because it determines the
design of the superheater and other system components.
In a boiler, all of the principal heat transfer mechanisms take place simultaneously. These mechanisms
are intersolid radiation between suspended solid particles, tubes, and refractory materials; nonluminous
gas radiation from the products of combustion; convection from the gases to the furnace walls; and conduction through ash deposits on tubes.
Fuel variation is significant. Pulverized coal, gas,
oil or waste-fuel firing may be used. In addition, different types of the same fuel also cause variations.
Coal, for example, may be high volatile or low volatile, and may have high or low ash and moisture contents. The ash fusion temperature may also be high
or low, and may vary considerably with the oxidizing
properties of the furnace atmosphere.
Furnace geometry is complex. Variations occur in
the burner locations and spacing, in the fuel bed size,
in the ash deposition, in the type of cooling surface,
in the furnace wall tube spacing, and in the arch and
hopper arrangements. Flame shape and length also
affect the distribution of radiation and heat absorption in the furnace.
High intensity, high mixing burners produce bushy
flames and promote large high temperature zones in
the lower furnace. Lower intensity, controlled mixing
burners frequently have longer flames that delay combustion while controlling pollutant formation.
Surface characteristics vary. The enclosing furnace
walls may include any combination of fuel arrangements, refractory material, studded tubes, spaced tubes
backed by refractory, close-spaced tubes, membrane construction or tube banks. Emissivities of these surfaces are
different. The water-cooled surface may be covered with
fluid slag or dry ash in any thickness, or it may be clean.
Temperature varies throughout the furnace. Fuel
and air enter at relatively low temperatures, reach high
temperatures during combustion, and cool again as the
products of combustion lose heat to the furnace enclosure. All temperatures change with load, excess air,
burner adjustment and other operating conditions.
Accurate estimates of furnace exit gas temperature
are important. For example, high estimates may lead
to over-estimating the heat transfer surface, while low
estimates may cause operational problems. These are
discussed in Chapter 19.
Empirical methods Considering the fuel type, firing rate and furnace configuration, empirical methods as illustrated in Fig. 31 have long been used to
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
predict local absorption rates in the furnace. These
methods, although largely empirical, contain engineering models which are based on fundamentals.
Data and operating experience are used to tune the
models employed in the design envelope. Fig. 31 shows
typical vertical and horizontal heat flux distributions
for furnace walls.
Deviations in the heat flux distribution are caused by
unbalanced firing, variations in tube surface condition,
differences in slagging, load changes, sootblower operation and other variations in unit operation. A typical upset
heat flux distribution is shown in Fig. 31. These upset
factors are typically a function of vertical/horizontal location, firing method and fuel, and furnace configuration. They are derived from operating experience.
The heat flux applied to the tubes in the furnace
wall is also nonuniform in the circumferential direction. As shown in Fig. 32, the membrane wall is exposed to the furnace on one side while the opposite side
is typically insulated to minimize heat loss. The resulting heat flux distribution depends upon the tube outside diameter, wall thickness, and spacing, as well as
the web thickness and materials. The fluid temperature and inside heat transfer coefficient have secondary effects. This distribution can be evaluated using
commercially available computer codes.
Fig. 31 Typical vertical and horizontal heat flux distributions for
furnace walls.
Steam 41 / Heat Transfer
Fig. 32 Typical circumferential heat flux distribution for a furnace
membrane wall panel tube.
To correlate data and calculations for different furnaces, methods for comparing the relative effectiveness
of different furnace wall surfaces are needed. The effectiveness and spacing of tubes compared to a completely water-cooled surface are shown in Fig. 33. A wall
of flat-studded tubes is considered completely watercooled. The effectiveness of expected ash covering, compared with completely water-cooled surfaces, can also
be estimated. The entire furnace envelope can then be
evaluated in terms of equivalent cold surface.
The heat energy supplied by the fuel and by the
preheated combustion air, corrected for unburned combustible loss, radiation loss, and moisture from the fuel,
may be combined into a single variable, known as heat
available. The heat available divided by the equivalent flat projected furnace enclosure plus furnace
Fig. 33 Furnace wall area effectiveness factor (1.0 for completely
water-cooled surface). A reduced area (equivalent cold surface) is
determined from these curves for walls not completely water cooled.
(Adapted from Hottel4.)
4-25
The Babcock & Wilcox Company
platen area is called the furnace heat release rate. The
heat input from fuel divided by the furnace volume is
called the furnace liberation rate. The furnace exit
plane defines the boundary of the furnace volume and
flat projected furnace enclosure area. The furnace exit
plane area and back spacing between the furnace
platen tubes are included in the flat projected area
calculation. For furnace platens and membrane wall
furnace enclosure, the effectiveness factor for all examples given in this and other chapters is equal to 1.00.
Furnace exit gas temperature (FEGT) is primarily
a function of heat release rate rather than liberation
rate. The furnace exit is commercially defined as being located at the face of the first tube bank having a
tube spacing of less than 15 in. (38.1 cm) side centers
because, as can be inferred from Fig. 39, convection
conductance typically becomes the predominant heat
transfer mode at this side spacing. The furnace exit
plane, generally used for the accurate calculation of
overall heat transfer, is normally set at the face of the
first tube bank having a tube spacing of 36 in. (91.4
cm) side centers or less in order to include the convection conductance in the heat transfer calculations. At
tube side centers of 36 in. (91.4 cm) or less, the convection conductance is too significant to ignore as a portion
of total heat transfer. The approximate relation of FEGT
to heat release rate at the furnace exit plane for a typical pulverized bituminous coal is given in Fig. 34.
Furnace exit gas temperatures and related heat
absorption rates, as functions of furnace heat release
rate for most pulverized coal-fired furnaces, lie within
2800
(1538)
2600
(1427)
the shaded bands shown in Figs. 35 and 36. The limits indicated serve only as a general guide and may
vary due to combustion system type, burner and air
port placement, stoichiometry, fuel characteristics and
cleaning cycle. The bands for dry ash and for slag-tap
furnaces overlap between 100,000 and 150,000 Btu/
h ft2 (315,460 to 473,190 W/m2), but different types of
coal are involved. To be suitable for a slag-tap furnace,
a bituminous coal should have an ash viscosity of 250
poises at 2450F (1343C) or lower. In the overlapping
range, dry ash and slag-tap both have about the same
heat absorption rate, or dirtiness factor, as shown in
Fig. 36. Both bands are rather broad, but they cover a
wide range of ash characteristics and a considerable
diversity in waterwall construction and dirtiness.
The heat leaving the furnace is calculated from the
exiting gas flow rate (the gas enthalpy values evaluated at the furnace exit gas temperature) plus the net
radiative transfer at the furnace exit. The heat absorbed in the furnace is the difference between the
heat available from the fuel, including the preheated
combustion air, and heat leaving the furnace.
Numerical methods Empirical design methods are
gradually being supplemented with numerical methods, as the level of detail increases and confidence is
improved. Radiation heat transfer in furnace enclosures can now be solved on computers, in combination with turbulent flow, energy, and combustion. Radiation properties of gases, particles, and fuel specific
properties of ash deposits can be included in the analysis with more advanced engineering models and correlations. The effects of spectral radiation from gases
and particles can also be included to improve accuracy
of the analysis. Detailed results include the three-dimensional distribution of radiation intensity, gas temperature, and heat flux on the furnace walls. Numeri-
2400
(1316)
3000
(1649)
Furnace Exit Gas Temperature, F (C)
Furnace Exit Gas Temperature, F (C)
3400
(1871)
2200
(1204)
2000
(1093)
1800
(982)
1600
(871)
20
(63)
60
(189)
100
(315)
140
(442)
180
(568)
220
(694)
Heat Release Rate, 1000 Btu/h ft2 (kW/m2)
Fig. 34 Approximate relationship of furnace exit gas temperatures to
heat release rate for a typical pulverized bituminous coal.
4-26
2600
(1427)
2200
(1204)
Dry Ash
1800
(982)
1400
(760)
0
(-18) 0
Slag-Tap
1400
(760) 0
100
(315)
200
(631)
300
(946)
400
(1262)
500
(1577)
Heat Release Rate, 1000 Btu/h ft2 (kW/m2)
Fig. 35 General range of furnace exit gas temperature for dry ash
and slag-tap pulverized coal-fired furnaces.
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
the horizontal section of the convection pass were included in the model. Inlet fuel, inlet air and exit
streams were properly located around the boundaries.
An example of the predicted heat flux distribution is
shown in Fig. 38. The predicted furnace exit gas temperature for this case was 2242F (1228C), while the
observed average value was 2276F (1247C). Relative
magnitudes of convective and radiative heat transfer
at various locations are shown in Fig. 39 for a 650 MW
boiler. The furnace area is dominated by radiation
while the back-end heat transfer surfaces in the direction of flow are increasingly dominated by convection.
Convection banks
Fig. 36 General range of furnace heat absorption rates for dry ash
and slag-tap pulverized coal-fired furnaces.
cal methods have the potential for more accurate prediction of heat flux distribution on furnace walls and
convective surfaces. However, further validation of
results and improvements in computational efficiency
are needed to make numerical methods more practical for routine engineering applications.
A numerical model was created for the furnace of a
560 MW supercritical steam pressure boiler firing high
volatile eastern United States bituminous coal. A schematic of the furnace is shown in Fig. 37. The sloping
furnace walls of the ash hopper, the furnace nose, and
Fig. 37 560 MW utility boiler schematic used for numerical model
(see Fig. 38).
Steam 41 / Heat Transfer
Tube spacing and arrangement In addition to heat
absorption and resistance to gas flow, other important
factors must be considered in establishing the optimum tube spacing and arrangement for a convection
surface. These are slagging or fouling of surfaces, accessibility for cleaning, and space occupied. A large
longitudinal spacing relative to the transverse spacing is usually undesirable because it increases the
space requirement without improving performance.
These are discussed further in Chapter 21.
Tube diameter For turbulent flow, the heat transfer coefficient is inversely proportional to a power of
the tube diameter. In Equations 57 and 60 the exponent for longitudinal flow is 0.20; for cross flow it is
0.39. These equations indicate that the tube diameter
should be minimized for the most effective heat transfer. However, this optimum tube diameter may require
Fig. 38 Numerical model – predicted furnace wall flat projected heat
flux distribution. (1 W/m2 = 0.317 Btu/h ft2)
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The Babcock & Wilcox Company
Convective
Radiative
50
(157.7)
4
3
7
9
1
2
5
6
7
Surfaces in Zone
8
9
9 in. RH
Cavity
9 in. RH
4
Cavity
3
12 in. SH
10
(31.5)
1
Cavity
20
(63.1)
24 in. SH Platens
2
30
(94.6)
0
8 10
6
5
40
(126.1)
48-54 in. Platens + Enclosure
Heat Flux, 1000 Btu/h ft2 (kW/m2)
60
(189.3)
10
Fig. 39 Comparison of radiative and convective heat transfer
contributions to absorption in various locations within a large utility
boiler (SH = superheater; RH = reheater; 1 in. = 2.54 cm).
an arrangement that is expensive to fabricate, difficult to install, or costly to maintain. A compromise
between heat transfer effectiveness and manufacturing, erection, and service limitations is therefore necessary in selecting tube diameter.
Penetration of radiation A convection bank of tubes
bordering a furnace or a cavity acts as a blackbody
radiant heat absorber. Some of the impinging heat,
however, radiates through the spaces between the
tubes of the first row and may penetrate as far as the
fourth row. The quantity of heat penetration can be
established by geometric or analytical methods. The
effect of this penetration is especially important in
establishing tube temperatures for superheaters located close to a furnace or high temperature cavity.
Consider 2.0 in. (50.8 mm) OD tubes placed in an array of tubes on a 6.0 in. (152.4 mm) pitch. Fig. 33,
curve 1 can be used to estimate the remaining radiation. For a given radiant heat flux, 45% is absorbed
in the first tube row, and 55% passes to the second
row. 45% of this reduced amount is again absorbed in
the second tube row. After the fourth row, less than
10% of the initial radiation remains.
Effect of lanes Lanes in tube banks, formed by the
omission of rows of tubes, may decrease the heat absorption considerably. These passages act as bypasses
for flowing hot gases and radiation losses. Although
the overall efficiency decreases, the high mass flow
through the lanes increases the absorption rate of the
adjacent tubes. Critical tube temperatures in superheaters or steaming conditions in economizers may
develop. Whenever possible, lanes should be avoided
within tube banks and between tube banks and walls;
however, this is not always possible. A calculation accounting for the lanes is necessary in such cases.
Heat transfer to water
Water heat transfer coefficient The heat transfer coefficient for water in economizers is so much higher
than the gas-side heat transfer coefficient that it can
be neglected in determining economizer surface.
Boiling water heat transfer coefficient The combined
gas-side heat transfer coefficient (convection plus
4-28
intertube radiation) seldom exceeds 30 Btu/h ft2 F (170
W/m2 K) in boiler design practice. The heat transfer
coefficient for boiling water [l0,000 Btu/h ft2 F (56,784
W/m2 K)] is so much larger that it is generally neglected in calculating the resistance to heat flow, although Equation 4 in Chapter 5 can be used to calculate this value.
Effect of scale Water-side and steam-side scale deposits provide high resistance to heat flow. As scale
thickness increases, additional heat is required to
maintain a given temperature inside a furnace tube.
This leads to high metal temperatures and can cause
tube failure. Deposition of scale and other contaminants is prevented by good feedwater treatment and
proper operating practices.
Heat transfer to steam In superheaters, the steamside convection constitutes a significant resistance to
heat flow. Although this resistance is much lower than
the gas-side resistance, it can not be neglected in computing the overall heat flow resistance or the heat
transfer rate. It is particularly significant in calculating superheater tube temperatures, because the mean
tube wall temperature is equal to the steam temperature plus the temperature drop through the steam film
plus half of the metal temperature drop.
The steam-side heat transfer coefficient is calculated
from Equation 58 using information from Figs. 13, 16
and 17. If the steam heat transfer coefficient is designated as h, the film temperature drop, ∆Tf, is q/(hA),
using the outside surface area of the tube as the base
in each expression.
It is imperative to prevent scale deposits in superheater tubes. Because of its high resistance to heat flow
and due to the elevated temperatures, even a thin layer
of scale may be sufficient to overheat and fail a tube.
Cavities
Cavities are necessary between tube banks of steam
generating units for access, for sootblowers, and for
possible surface addition. Hot flue gas radiates heat
to the boundary surfaces while passing through the
cavity. The factors involved in calculating heat transfer in cavities are as follows.
Temperature level Radiation from nonluminous
gases to boundary surfaces and radiation to the gas
by the surroundings increase approximately by the
fourth power of their respective absolute temperatures. Remembering that Eb = σ T 4, Equations 39 and
40 illustrate this relationship.
Gas composition Carbon dioxide and water vapor
are the normal constituents of flue gases which emit
nonluminous radiation in steam generating units.
The concentrations of these constituents depend on the
fuel burned and the amount of excess air.
Particles in the gas The particles carried by flue
gases receive heat from the gas by radiation, convection, and conduction, and emit heat by radiation to
the furnace enclosure.
Size of cavity The heat transfer rate increases with
cavity size. Thick layers of gas radiate more vigorously
than thin layers. The shape of the cavity can also complicate heat transfer calculations.
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Receiving surface A refractory surface forming part
of a cavity boundary reaches a high temperature by
convection and radiation from the flue gas. It also
reradiates heat to the gas and to the other walls of the
enclosure. Reradiation from a clean, heat-absorbing
surface is small unless the receiving surface temperature is high, as is the case with superheaters and
reheaters. Ash or slag deposits on the tube reduce heat
absorption and increase reradiation.
In boiler design, there are two significant effects of
cavity radiation: 1) the temperature of flue gas drops,
from several degrees up to 40F (22C), in passing across
a cavity, and 2) gas radiation increases the heat absorption rates for the tubes forming the cavity boundaries. The second effect influences superheater tube
temperatures and the selection of alloys.
Insulation
The calculation of heat transfer through insulation
follows the principles outlined for conduction through
a composite wall. Refer to Chapter 23 for more information regarding insulating materials.
Hot face temperature In a furnace with tube-to-tube
walls, the hot face temperature of the insulation is the
saturation temperature of the water in the tubes. If the
inner face of the furnace wall is refractory, the hot face insulation temperature must be calculated using radiation and
convection heat transfer principles on the gas side of the
furnace wall, or estimated using empirical data.
Heat loss and cold face temperature The heat loss to
the surroundings and the cold face temperature decrease as the insulation thickness increases. However,
once an acceptable layer of insulation is applied, additional amounts are not cost effective. Standard commercial insulation thicknesses should be used in the
composite wall.
The detailed calculation of overall heat loss by radiation and convection from the surfaces of a steam
generating unit (usually called radiation loss) is tedious and time consuming. A simple approximate
method is provided by the chart prepared from the
American Boiler Manufacturers Association (ABMA)
original. (See Chapter 23, Fig. 12.)
Ambient air conditions Low ambient air temperature and high air velocities reduce the cold face temperature. However, they have only a small effect on
total heat loss, because surface film resistance is a
minor part of the total insulation resistance. Combined
heat loss rates (radiation plus convection) are given
in Chapter 23, Fig. 11, for various temperature differences and air velocities. The effect of surface film
resistance on casing temperature and on heat loss
through casings is shown in Chapter 23, Fig. 15.
Temperature limits and conductivities Refractory or insulating material suitable for high temperature applications is usually more expensive and less effective than
low temperature materials. It is therefore customary to
use several layers of insulation. The lower cost, more
effective insulation is used in the cool zones; the higher
cost materials are used only where demanded by high
operating temperatures. Thermal conductivities for refractory and insulating materials, and temperatures for
which they are suitable, are shown in Chapter 23, Fig. 10.
Steam 41 / Heat Transfer
Applications
Example 1 – Conduction through a plane wall
If a flat plate is heated on one side and cooled on the
other, the heat flow rate in the wall, shown in Fig. 1, is
given by Equation 2. The rate of heat flow through a
0.25 in. thick steel plate with 1 ft2 surface area and ∆T
= 25F may be evaluated with Equation 2 as follows:
q = kA
∆T
30 × 1 × 25
=
= 36, 000 Btu/h
0.25 / 12
L
(78)
where the thermal conductivity, k, for steel is 30 Btu/h ft F.
Example 2 – Heat flow in a composite wall
with convection
The heat flow through a steel wall which is insulated on both sides is shown in Fig. 3. This example
demonstrates the procedure for combining thermal
resistances. In addition to the thermal resistance of
the firebrick, steel, and insulation, the heat flow is
impeded by the surface resistances. Consider a 600 ft2
surface with gases at 1080F or 1540R on the inside
exposed to an ambient temperature of 80F on the outside. The thermal conductivities of the firebrick, steel
flue and insulation are assumed to be k1 = 0.09, k2 =
25, and k3 = 0.042 Btu/h ft F, respectively. These assumptions are verified later. The layer thicknesses are
∆x1 = 4 in., ∆x2 = 0.25 in., and ∆x3 = 3 in. The heat
transfer coefficients for convection are hcv,i = 5.0 Btu/
h ft2 F on the inside surface hcv,o = 2.0 Btu/h ft2 F on
the outside surface. Where the temperature difference
between the radiating gas, Tg , and a surface, Ts , is
small, the radiation heat transfer coefficient can be
estimated by:
hr ≅ 4.0 σ ε F (Tg + Ts ) / 2
3
≈ 4 σ ε F Tg3 (79a)
where Tg and Ts are the absolute temperatures, R (K).
In this example, the surface emissivity is assumed
close to 1.0 and F = 1.0 resulting in:
(
hr = 4.0 0.1713 × 10−8
= 25 Btu/h ft2 F
) (1080 + 460 )
3
(79b)
Using the Req shown in Fig. 3 and values of R evaluated using Table 4:
1 1
4
0.25
3
5 25
1
Req A =
+ 12 + 12 + 12 +
1 1
0.09
25
0.042 2
+
5 25
= 0.033 + 3.70 + 0.000833 + 5.95 + 0.5 (80)
= 10.18
h ft2 F
Btu
It is clear that the firebrick and insulation control the
overall resistance; the steel resistance can be ne4-29
The Babcock & Wilcox Company
glected. If the successive material layers do not make
good thermal contact with each other, there will be
interface resistances due to the air space or film. These
resistances may be neglected in composite walls of
insulating materials. However, they must be included
in calculations if the layer resistances are small compared to the interface resistances. An example of this
is heat transfer through a boiler tube with internal
oxide deposits.
The heat flow can be computed using Equation 23:
q =
Tf − T∞
Req
= A
Tf − T∞
Req A
Btu
1080 − 80
= 58, 939
= 600
h
10.18
(81)
To determine if the correct thermal conductivities
were assumed and if the temperature levels are within
allowable operating limits of the material, it is necessary to calculate the temperatures at the material interfaces. Solving Equation 81 for temperature and substituting individual resistances and local temperatures:
T1 = Tf −
T2 = T1 −
T3 = T2 −
T4 = T3 −
q
( R A ) f = 1080 −
A
q
A
q
A
q
A
T∞ = T4 −
(R A)
1
(R A)
2
(R A)
q
A
3
= 1077 −
= 713 −
= 713 −
( R A )∞
(59,939 )(0.033 )
600
(58, 939 )(3.70 )
600
= 1077F (82)
= 713F
(58, 939 )( 0.000833 )
600
(58, 939 )(5.95 )
= 129 −
600
(58, 939 )( 0.5 )
600
= 713F
= 129F
= 80F
(83)
(84)
(85)
(86)
Req =
ln ( r2 / r1 )
1
+
2 π k2 l
hi ( 2 π r1 l )
+
ln ( r3 / r2 )
2 π k3 l
+
1
h0 ( 2 π r3 l )
(87)
A 3 in. Schedule 40 steel pipe (k = 25 Btu/h ft F) is
covered with 0.75 in. insulation of k = 0.10 Btu/h ft F.
This pipe has a 3.07 in. ID and a 3.50 in. OD. The
pipe transports fluid at 300F and is exposed to an
ambient temperature of 80F. With an inside heat
transfer coefficient of 50 Btu/h ft2 F and an outside
heat transfer coefficient of 4 Btu/h ft2 F, the thermal
resistance and heat flow per unit length are:
3.50
ln
1
3.07
+
Req l =
2π ( 25 )
3.07 / 2
50 ( 2π )
12
5.0
ln
3.5 +
+
2π ( 0.1 )
1
5.0 / 2
4 ( 2π )
12
(88)
Req l = 0.0249 + 0.000834 + 0.568 + 0.191
= 0.785
h ft F
Btu
(89)
The overall resistance is dominated by the insulation resistance and that of the outer film boundary
layer. The resistance of the metal pipe is negligible.
300 − 80
q
=
= 280 Btu/h ft
0.785
l
(90)
The small temperature difference between the radiating gas and the surface (Tf – T1 = 3F ) verifies the assumption for using Equation 79a. Had the temperature
difference been larger, then the full equation for the radiation resistance in Table 4 may have been required.
The negligible resistance of the steel flue is reflected
in the temperature drop T2 – T3 = 0. If the calculated
interface temperatures indicate the conductivity was
chosen improperly, new conductivities are defined
using the mean temperature of each material. For
example, a new firebrick conductivity is determined
using 0.5 (T1 + T2).
Example 3 – Heat flow in an insulated pipe
Heat flow in cylindrical geometries is important in
evaluating boiler heat transfer. Refer to the example
steam line shown in Fig. 40. The resistances in Table
4 for cylindrical geometries must be used. The thermal analogy for the pipe in Fig. 40 can be written:
4-30
Fig. 40 Example of heat flow in an insulated pipe.
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Example 4 – Heat flow between a small object
and a large cavity
Consider an unshielded thermocouple probe with
an emissivity of 0.8 inserted in a duct at 240F carrying combustion air. If the thermocouple indicates a
temperature of 540F and the surface heat transfer
coefficient, h, between the thermocouple and gas is 20
Btu/h ft2 F, the true gas temperature can be estimated.
The thermocouple temperature must be below the gas
temperature because heat is lost to the walls. Under
steady-state conditions, an energy balance equates the
radiant heat loss from the thermocouple to the wall and
the rate of heat flow from the gas to the thermocouple.
Using Table 6, the heat flow between the thermocouple and the cavity becomes:
q
= 0.8 0.1713 × 10−8
A
(
)
4
4
× ( 540 + 460 ) − ( 240 + 460 )
2
= 1041.4 Btu/h ft
(91)
Intervening gases and/or gray walls further reduce
the net heat flow.
Example 6 – Radiation from a hot gas to
furnace walls
Consider a furnace with a volume of 160,000 ft3 and
a heat transfer surface area of 19,860 ft2. The gas traversing the furnace (Tg) is at 2540F (1393C) and the
furnace walls (Ts) are at 1040F (560C). The radiant
heat transfer rate can be estimated using Equation
40, assuming the walls are radiatively black (εs = 1).
If the products of combustion at one atmosphere consist of 10% carbon dioxide, 5% water vapor, and 85%
nitrogen, Figs. 9 to 11 can be used to estimate the gas
emissivity and absorptivity. The beam length is L =
3.6 V/A = 29.0 ft. Then for H2O, pwL = (29.0) (0.05) =
1.45 ft-atm (45 bar-cm) and from Fig. 9 at 1393C the
emissivity is found to be 0.22. For CO2, pcL = (29.0)
(0.l0) = 2.90 ft-atm (89 bar-cm) and from Fig. 10, at
1393C, the emissivity is found to be 0.16. The correction ∆ε is determined from Fig. 11. The total gas emissivity is then found from Equation 41:
ε g = ε H2O + ε CO2 − ∆ ε g
(95)
ε g = 0.22 + 0.16 − 0.06 = 0.32
(96)
The true gas temperatures becomes:
Tg =
q/ A
1041.4
+ Tt =
+ 540 = 592F
h
20
(92)
Similar analyses can be performed for thermocouples
shielded with reflective foils in high temperature environments. This practice prevents thermocouple heat
losses and incorrect temperature readings. The heat flow
from a shielded thermocouple is calculated as follows:
1
q
( N + 1) no shield
qshielded =
Example 5 – Heat flow between two surfaces
An estimate of the maximum radiant heat transfer
between two surfaces can be determined using Equation 11. This approximation is valid when the walls are
considered black and any intervening absorbing gases
are neglected. If two 5 × 10 ft black rectangles, directly
opposed, are spaced 10 ft apart with temperatures of 940
and 1040F, the energy exchange is estimated as follows.
The energy from surface 1 directly striking surface
2 is defined by the shape factor F12. Referring to Fig.
5, this factor F12 is 0.125, indicating that 87.5% of the
energy leaving surface 1 strikes a surface other than
surface 2. The net heat flow is:
(
q12 = A1 F12 σ T − T
(
4
2
)
= 50 ( 0.125 ) 0.1713 ×10−8
Ts
1040 + 460
= ( 0.05 )( 29 )
2540 + 460
Tg
= 0.73 ft-atm (or 22 barr-cm)
Fc = pc L
Ts
1040 + 460
= ( 0.10 )( 29 )
2540 + 460
Tg
ar-cm)
= 1.45 ft-atm (or 45 ba
α H2 O
T
= ε H2O ( Fw ,Ts ) × g
Ts
2540 + 460
= 0.21
1040 + 460
αCO2 = ε CO2 ( Fc ,Ts )
(94)
(97)
(98)
0.45
0.45
T
× g
Ts
2540 + 460
= 0.15
1040 + 460
)
4
4
× (1040 + 460 ) − ( 940 + 460 )
q12 = 13, 071 Btu/h
Steam 41 / Heat Transfer
Fw = pw L
(93)
where N is the number of concentric layers of material.
4
1
Hottel4 suggests calculating the absorptivity of the gas
using modified pressure length parameters:
= 0.29
(99)
0.65
0.65
= 0.24
(100)
∆ α g = ∆ ε (Ts ) = 0.04
(101)
α g = α H2O + αCO2 − ∆ α g = 0.49
(102)
4-31
The Babcock & Wilcox Company
The net rate of heat flow calculated from Equation 40:
qsg = A (ε g Ebg − α g Ebs )
(
= 19, 860 0.32 σ 30004 − 0.49 σ 15004
)
(103)
6
u/h
= 797 × 10 Btu
In estimating boiler heat transfer, the beam lengths
are large, effecting large pL values. Proprietary data
are used to estimate the heat transfer for these values, and extrapolation of the curves in Figs. 9 to 11 is
not recommended.
Example 7 – Radiation in a cavity
Radiation in a cavity containing absorbing gases
can be analyzed with the concepts previously presented. These concepts are useful in analyzing surface to surface heat transfer. Examples include boiler
wall to boiler wall, platen to platen, and boiler wall to
boiler enclosure heat exchanges. Table 5 (and Reference 4) contains the thermal resistances used in constructing the thermal circuit in Fig. 41. Note the resistance between surface 1 and 2 decreases as the
transmission in the gas, τ 12, increases to a transparent condition τ 12 = 1. At τ 12 near zero, the gases are
opaque, and the resistance is very large. As the gas
emissivity decreases, the thermal circuit reduces to Fig.
6 and Equation 36. The solution of the circuit in Fig.
41 is found using Kirchhoff ’s rule for nodes J1 and J2.
The equations are solved simultaneously for J1 and
J2:
E − J1
Eb1 − J1
J 2 − J1
+
+ bg
= 0
1 − ε1
1
1
A1 F12 τ 12
A1 ε g1
ε1 A1
Fig. 41 Example of radiation in a cavity.
E − J b2
Eb2 − J 2
J − J2
+ 1
+ bg
= 0
1 − ε2
1
1
A1 F12 τ 12
A1 ε g 2
ε 2 A2
The net heat flow between the surfaces is:
q12 = A1 F12 τ 12 ( J1 − J 2 )
(104)
(105)
(106)
Hottel4 demonstrates the procedures for finding the
beam length to determine F12, εg1, and εg2.
References
1. Roshenow, W.M., Hartnett, J.P., and Ganic, E.N.,
Handbook of Heat Transfer Fundamentals, Second Ed.,
McGraw-Hill, Inc., New York, New York, 1985.
2. Roshenow, W.M., Hartnett, J.P., and Ganic, E.N.,
Handbook of Heat Transfer Applications, Second Ed.,
McGraw-Hill, Inc., New York, New York, 1985.
3. Kreith, F., and Bohn, M.S., Principles of Heat Transfer, Fourth Ed., Harper and Row, New York, New York,
1986.
4. Hottel, H.C., and Sarofim, A.F., Radiative Transfer,
McGraw-Hill, Inc., New York, New York, 1967.
5. Wall, T.F., Bhattacharya, S.P., Zhang, D.K., et al.,
“The Properties and Thermal Effects of Ash Deposits in
Coal-Fired Furnaces,” Progress in Energy and Combustion Science, Vol. 19, pp. 487-504, 1993.
6. Meyer, C.A., et al., ASME Steam Tables: Thermodynamic and Transport Properties of Steam, Sixth Ed.,
American Society of Mechanical Engineers, New York,
New York, 1993.
4-32
7. Boow, J., and Goard, P.R.C., “Fireside Deposits and
Their Effect on Heat Transfer in a Pulverized Fuel-Fired
Boiler: Part III. The Influence of the Physical Characteristics of the Deposit on its Radiant Emittance and Effective Thermal Conductance,” Journal of the Institute of
Fuel, pp. 412-419, Vol. 42, No. 346, 1969.
8. Leckner, B., “Spectral and Total Emissivity of Water
Vapor and Carbon Dioxide,” Combustion and Flame, Vol.
19, pp. 33-48, 1972.
9. Edwards, D.K., “Molecular Gas Band Radiation,” Advances in Heat Transfer, Vol. 12, Academic Press, New
York, New York, pp. 115-193, 1964.
10. Modest, M.F., Radiative Heat Transfer, McGraw-Hill,
Inc., New York, New York, 1993.
11. Sieder, E.N., and Tate, G.E., “Heat Transfer and Pressure Drop of Liquids in Tubes,” Industrial & Engineering
Chemistry Research (I&EC), Vol. 28, p. 1429, 1936.
12. Dittus, F.W., and Boelter, L.M.K., University of California Publications on Engineering, Vol. 2, p. 443, Berkeley, California, 1930.
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
13. McAdams, W., Heat Transmission, Third Ed.,
McGraw-Hill, Inc., New York, New York, 1954.
14. Grimison, E.D., “Correlation and Utilization of New
Data on Flow Resistance and Heat Transfer for Crossflow
of Gases over Tube Banks,” Transactions of the American
Society of Mechanical Engineers, Vol. 59, pp. 583-594,
1937.
15. Schmidt, T.F., “Wärme leistung von berippten
Flächen,” Mitt. des Kältetechn. Institut der T.H.
Karlshruhe, Vol. 4, 1949.
16. Incropera, F., and DeWitt, D.P., Fundamentals of
Heat and Mass Transfer, Third Ed., John Wiley & Sons,
New York, New York, 1990.
17. Patankar, S., Numerical Heat Transfer and Fluid
Flow, McGraw-Hill, Inc., New York, New York, 1980.
18. Fiveland, W. A., “Discrete-Ordinates Solutions of the
Radiative Transport Equation for Rectangular Enclosures,” Transactions of the American Society of Mechanical Engineers Journal of Heat Transfer, Vol. 106, pp. 699706, 1984.
Pyrex is a trademark of Corning Incorporated.
Steam 41 / Heat Transfer
4-33
The Babcock & Wilcox Company
Wall-fired utility boiler furnace under construction.
4-34
Steam 41 / Heat Transfer
The Babcock & Wilcox Company
Chapter 5
Boiling Heat Transfer,
Two-Phase Flow and Circulation
A case of heat transfer and flow of particular interest in steam generation is the process of boiling and
steam-water flow. The boiling or evaporation of water is a familiar phenomenon. In general terms, boiling is the heat transfer process where heat addition
to a liquid no longer raises its temperature under constant pressure conditions; the heat is absorbed as the
liquid becomes a gas. The heat transfer rates are high,
making this an ideal cooling method for surfaces exposed to the high heat input rates found in fossil fuel
boilers, concentrated solar energy collectors and the
nuclear reactor fuel bundles. However, the boiling
phenomenon poses special challenges such as: 1) the
sudden breakdown of the boiling behavior at very high
heat input rates, 2) the potential flow rate fluctuations
which may occur in steam-water flows, and 3) the efficient separation of steam from water. An additional
feature of boiling and two-phase flow is the creation
of significant density differences between heated and
unheated tubes. These density differences result in
water flowing to the heated tubes in a well designed
boiler natural circulation loop.
Most fossil fuel steam generators and all commercial nuclear steam supply systems operate in the pressure range where boiling is a key element of the heat
transfer process. Therefore, a comprehensive understanding of boiling and its various related phenomena is essential in the design of these units. Even at
operating conditions above the critical pressure, where
water no longer boils but experiences a continuous
transition from a liquid-like to a gas-like fluid, boiling type behavior and special heat transfer characteristics occur.
ture (Tsat) is a unique function of pressure. The American Society of Mechanical Engineers (ASME) and the
International Association for the Properties of Steam
(IAPS) have compiled extensive correlations of thermophysical characteristics of water. These characteristics
include the enthalpy (or heat content) of water, the
enthalpy of evaporation (also referred to as the latent
heat of vaporization), and the enthalpy of steam. As
the pressure is increased to the critical pressure [3200
psi (22.1 MPa)], the latent heat of vaporization declines
to zero and the bubble formation associated with boiling no longer occurs. Instead, a smooth transition from
liquid to gaseous behavior occurs with a continuous increase in temperature as energy is applied.
Two other definitions are also helpful in discussing
boiling heat transfer:
1. Subcooling For water below the local saturation
temperature, this is the difference between the
saturation temperature and the local water temperature (Tsat – T ).
2. Quality This is the flowing mass fraction of steam
(frequently stated as percent steam by weight or
%SBW after multiplying by 100%):
x =
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
(1)
where
steam = steam flow rate, lb/h (kg/s)
m
water = water flow rate, lb/h (kg/s)
m
Thermodynamically, this can also be defined as:
Boiling process and fundamentals
Boiling point and thermophysical properties
The boiling point, or saturation temperature, of a
liquid can be defined as the temperature at which its
vapor pressure is equal to the total local pressure. The
saturation temperature for water at atmospheric pressure is 212F (100C). This is the point at which net
vapor generation occurs and free steam bubbles are
formed from a liquid undergoing continuous heating.
As discussed in Chapter 2, this saturation tempera-
steam
m
water + m
steam
m
x =
H − Hf
H fg
or
H − Hf
Hg − Hf
(2)
where
H
Hf
Hg
Hfg
=
=
=
=
local average fluid enthalpy, Btu/lb (J/kg)
enthalpy of water at saturation, Btu/lb (J/kg)
enthalpy of steam at saturation, Btu/lb (J/kg)
latent heat of vaporization, Btu/lb (J/kg)
When boiling is occurring at saturated, thermal
equilibrium conditions, Equation 2 provides the fractional steam flow rate by mass. For subcooled condi5-1
The Babcock & Wilcox Company
tions where H < Hf, quality (x) can be negative and is
an indication of liquid subcooling. For conditions where
H > Hg, this value can be greater than 100% and represents the amount of average superheat of the steam.
Boiling curve
Fig. 1 illustrates a boiling curve which summarizes
the results of many investigators. This curve provides
the results of a heated wire in a pool, although the
characteristics are similar for most situations. The heat
transfer rate per unit area, or heat flux, is plotted
versus the temperature differential between the metal
surface and the bulk fluid. From points A to B, convection heat transfer cools the wire and boiling on the
surface is suppressed. Moving beyond point B, which
is also referred to as the incipient boiling point, the
temperature of the fluid immediately adjacent to the
heated surface slightly exceeds the local saturation
temperature of the fluid while the bulk fluid remains
subcooled. Bubbles, initially very small, begin to form
adjacent to the wire. The bubbles then periodically
collapse as they come into contact with the cooler bulk
fluid. This phenomenon, referred to as subcooled boiling, occurs between points B and S on the curve. The
heat transfer rate is quite high, but no net steam generation occurs. From points S to C, the temperature
of the bulk fluid has reached the local saturation temperature. Bubbles are no longer confined to the area
immediately adjacent to the surface, but move into the
bulk fluid. This region is usually referred to as the
nucleate boiling region, and as with subcooled boiling, the heat transfer rates are quite high and the
metal surface is only slightly above the saturation
temperature.
As point C is approached, increasingly large surface evaporation rates occur. Eventually, the vapor
generation rate becomes so large that it restricts the
liquid return flow to the surface. The surface eventually becomes covered (blanketed) with an insulating
layer of steam and the ability of the surface to transfer heat drops. This transition is referred to as the
Fig. 1 Boiling curve – heat flux versus applied temperature difference.
5-2
critical heat flux (CHF), departure from nucleate boiling (DNB), burnout, dryout, peak heat flux, or boiling crisis. The temperature response of the surface under this condition depends upon how the surface is
being heated. In fossil fuel boiler furnaces and nuclear
reactor cores, the heat input is effectively independent
of surface temperature. Therefore, a reduction in the
heat transfer rate results in a corresponding increase
in surface temperature from point D to D′ in Fig. 1.
In some cases, the elevated surface temperature is so
high that the metal surface may melt. If, on the other
hand, the heat input or heat transfer rate is dependent upon the surface temperature, typical of a
nuclear steam generator, the average local temperature of the surface increases as the local heat transfer rate declines. This region, illustrated in Fig. 1 from
points D to E, is typically referred to as unstable film
boiling or transition boiling. Because a large surface
temperature increase does not occur, the main consequences are a decline in heat transfer performance per
unit surface area and less overall energy transfer. The
actual local phenomenon in this region is quite complex and unstable as discrete areas of surface fluctuate between a wetted boiling condition and a steam
blanketed, or dry patch, condition. From position E
through D′ to F, the surface is effectively blanketed
by an insulating layer of steam or vapor. Energy is
transferred from the solid surface through this layer
by radiation, conduction and microconvection to the
liquid-vapor interface. From this interface, evaporation occurs and bubbles depart. This heat transfer
region is frequently referred to as stable film boiling.
In designing steam generating systems, care must
be exercised to control which of these phenomena occur. In high heat input locations, such as the furnace
area of fossil fuel boilers or nuclear reactor cores, it is
important to maintain nucleate or subcooled boiling
to adequately cool the surface and prevent material
failures. However, in low heat flux areas or in areas
where the heat transfer rate is controlled by the boiling side heat transfer coefficient, stable or unstable
film boiling may be acceptable. In these areas, the
resultant heat transfer rate must be evaluated, any
temperature limitations maintained and only allowable temperature fluctuations accepted.
Flow boiling
Flow or forced convective boiling, which is found in
virtually all steam generating systems, is a more complex phenomenon involving the intimate interaction
of two-phase fluid flow, gravity, material phenomena
and boiling heat transfer mechanisms. Fig. 2 is a classic picture of boiling water in a long, uniformly heated,
circular tube. The water enters the tube as a subcooled
liquid and convection heat transfer cools the tube. The
point of incipient boiling is reached (point 1 in Fig. 2).
This results in the beginning of subcooled boiling and
bubbly flow. The fluid temperature continues to rise
until the entire bulk fluid reaches the saturation temperature and nucleate boiling occurs, point 2. At this
location, flow boiling departs somewhat from the
simple pool boiling model previously discussed. The
steam-water mixture progresses through a series of
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
flow structures or patterns: bubbly, intermediate and
annular. This is a result of the complex interaction of
surface tension forces, interfacial phenomena, pressure drop, steam-water densities and momentum effects coupled with the surface boiling behavior. While
boiling heat transfer continues throughout, a point is
reached in the annular flow regime where the liquid
film on the wall becomes so thin that nucleation in the
film is suppressed, point 3. Heat transfer then occurs
through conduction and convection across the thin
annular film with surface evaporation at the steamwater interface. This heat transfer mechanism, called
convective boiling, also results in high heat transfer
rates. It should also be noted that not all of the liquid
is on the tube wall. A portion is entrained in the steam
core as dispersed droplets.
Eventually, an axial location, point 4, is reached
where the tube surface is no longer wetted and CHF
or dryout occurs. This is typically associated with a
temperature rise. The exact tube location and magnitude of this temperature, however, depend upon a
variety of parameters, such as the heat flux, mass
flux, geometry and steam quality. Fig. 3 illustrates the
effect of heat input rate, or heat flux, on CHF location and the associated temperature increase. From
points 4 to 5 in Fig. 2, post-CHF heat transfer, which
is quite complex, occurs. Beyond point 5, all of the liquid is evaporated and simple convection to steam occurs.
Boiling heat transfer evaluation
Engineering design of steam generators requires the
evaluation of water and steam heat transfer rates under boiling and nonboiling conditions. In addition, the
Fig. 2 Simplified flow boiling in a vertical tube (adapted from Collier1).
identification of the location of critical heat flux (CHF)
is important where a dramatic reduction in the heat
transfer rate could lead to: 1) excessive metal temperatures potentially resulting in tube failures, 2) an unacceptable loss of thermal performance, or 3) unacceptable temperature fluctuations leading to thermal fa-
Fig. 3 Tube wall temperatures under different heat input conditions.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
5-3
The Babcock & Wilcox Company
tigue failures. Data must also be available to predict
the rate of heat transfer downstream of the dryout point.
CHF phenomena are less important than the heat
transfer rates for performance evaluation, but are more
important in defining acceptable operating conditions.
As discussed in Chapter 4, the heat transfer rate per
unit area or heat flux is equal to the product of temperature difference and a heat transfer coefficient.
Heat transfer coefficients
Heat transfer correlations are application (surface
and geometry) specific and The Babcock & Wilcox
Company (B&W) has developed extensive data for its
applications through experimental testing and field
experience. These detailed correlations remain proprietary to B&W. However, the following generally available correlations are provided here as representative
of the heat transfer relationships.
Single-phase convection Several correlations for
forced convection heat transfer are presented in Chapter 4. Forced convection is assumed to occur as long as
the calculated forced convection heat flux is greater than
the calculated boiling heat flux (point 1 in Fig. 2):
′′ Convection > qBoiling
′′
qForced
(3)
While not critical in most steam generator applications, correlations are available which explicitly define this onset of subcooled boiling and more accurately
define the transition region.1
Subcooled boiling In areas where subcooled boiling occurs, several correlations are available to characterize the heat transfer process. Typical of these is
the Jens and Lottes2 correlation for water. For inputs
with English units:
∆Tsat = 60 ( q′′ / 106 )
1/4
e − P / 900
(4a)
and for inputs with SI units:
∆Tsat = 25 ( q′′)
1/4
e − P / 6.2
(4b)
where
∆T sat
Tw
T sat
q′′
P
=
=
=
=
=
Tw – Tsat, F (C)
wall temperature, F (C)
saturated water temperature, F (C)
heat flux, Btu/h ft2 (MWt/m2)
pressure, psi (MPa)
Another relationship frequently used is that developed
by Thom.3
Nucleate and convective boiling Heat transfer in the
saturated boiling region occurs by a complex combination of bubble nucleation at the tube surface (nucleate boiling) and direct evaporation at the steam-water interface in annular flow (convective boiling). At
low steam qualities, nucleate boiling dominates while
at higher qualities convective boiling dominates. While
separate correlations are available for each range, the
most useful relationships cover the entire saturated
boiling regime. They typically involve the summation
of appropriately weighted nucleate and convective
5-4
boiling components as exemplified by the correlation
developed by J.C. Chen and his colleagues.4 While
such correlations are frequently recommended for use
in saturated boiling systems, their additional precision
is not usually required in many boiler or reactor applications. For general evaluation purposes, the
subcooled boiling relationship provided in Equation
4 is usually sufficient.
Post-CHF heat transfer As shown in Fig. 3, substantial increases in tube wall metal temperatures are
possible if boiling is interrupted by the CHF phenomenon. The maximum temperature rise is of particular
importance in establishing whether tube wall overheating may occur. In addition, the reliable estimation of the heat transfer rate may be important for an
accurate assessment of thermal performance. Once the
metal surface is no longer wetted and water droplets
are carried along in the steam flow, the heat transfer
process becomes more complex and includes: 1) convective heat transfer to the steam which becomes superheated, 2) heat transfer to droplets impinging on
the surface from the core of the flow, 3) radiation directly from the surface to the droplets in the core flow,
and 4) heat transfer from the steam to the droplets.
This process results in a nonequilibrium flow featuring superheated steam mixed with water droplets.
Current correlations do not provide a good estimate of
the heat transfer in this region, but computer models
show promise. Accurate prediction requires the use of
experimental data for similar flow conditions.
Reflooding A key concept in evaluating emergency
core coolant systems for nuclear power applications is
reflooding. In a loss of coolant event, the reactor core
can pass through critical heat flux conditions and can
become completely dry. Reflooding is the term for the
complex thermal-hydraulic phenomena involved in
rewetting the fuel bundle surfaces as flow is returned
to the reactor core. The fuel elements may be at very
elevated temperatures so that the post-CHF, or steam
blanketed, condition may continue even in the presence
of returned water flow. Eventually, the surface temperature drops enough to permit a rewetting front to
wash over the fuel element surface. Analysis includes
transient conduction of the fuel elements and the interaction with the steam-water heat transfer processes.
Critical heat flux phenomena
Critical heat flux is one of the most important parameters in steam generator design. CHF denotes the
set of operating conditions (mass flux, pressure, heat
flux and steam quality) covering the transition from
the relatively high heat transfer rates associated with
nucleate or forced convective boiling to the lower rates
resulting from transition or film boiling (Figs. 1 and
2). These operating conditions have been found to be
geometry specific. CHF encompasses the phenomena
of departure from nucleate boiling (DNB), burnout,
dryout and boiling crisis. One objective in recirculating boiler and nuclear reactor designs is to avoid CHF
conditions. In once-through steam generators, the
objective is to design to accommodate the temperature
increase at the CHF locations. In this process, the heat
flux profile, flow passage geometry, operating pressure
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
and inlet enthalpy are usually fixed, leaving mass
flux, local quality, diameter and some surface effects
as the more easily adjusted variables.
Factors affecting CHF Critical heat flux phenomena
under flowing conditions found in fossil fuel and
nuclear steam generators are affected by a variety of
parameters.5 The primary parameters are the operating conditions and the design geometries. The operating conditions affecting CHF are pressure, mass flux
and steam quality. Numerous design geometry factors
include flow passage dimensions and shape, flow path
obstructions, heat flux profile, inclination and wall
surface configuration. Several of these effects are illustrated in Figs. 3 through 7.
Fig. 3 illustrates the effect of increasing the heat
input on the location of the temperature excursion in a
uniformly heated vertical tube cooled by upward flowing water. At low heat fluxes, the water flow can be almost completely evaporated to steam before any temperature rise is observed. At moderate and high heat
fluxes, the CHF location moves progressively towards
the tube inlet and the maximum temperature excursion increases. At very high heat fluxes, CHF occurs at
a low steam quality and the metal temperature excursion can be high enough to melt the tube. At extremely
high heat input rates, CHF can occur in subcooled
water. Avoiding this type of CHF is an important design criterion for pressurized water nuclear reactors.
Many large fossil fuel boilers are designed to operate between 2000 and 3000 psi (13.8 and 20.7 MPa).
In this range, pressure has a very important effect,
shown in Fig. 4, with the steam quality limit for CHF
falling rapidly near the critical pressure; i.e., at constant heat flux, CHF occurs at lower steam qualities
as pressure rises.
Many CHF correlations have been proposed and are
satisfactory within certain limits of pressure, mass
velocity and heat flux. Fig. 5 is an example of a correlation which is useful in the design of fossil fuel natural circulation boilers. This correlation defines safe and
unsafe regimes for two heat flux levels at a given pressure in terms of steam quality and mass velocity. Additional factors must be introduced when tubes are
used in membrane or tangent wall construction, are
inclined from the vertical, or have different inside diameter or surface configuration. The inclination of the
flow passage can have a particularly dramatic effect
on the CHF conditions as illustrated in Fig. 6.6
Ribbed tubes Since the 1930s, B&W has investigated a large number of devices, including internal
twisters, springs and grooved, ribbed and corrugated
tubes to delay the onset of CHF. The most satisfactory
overall performance was obtained with tubes having
helical ribs on the inside surface.
Two general types of rib configurations have been
developed:
Fig. 4 Steam quality limit for CHF as a function of pressure.
Fig. 5 Steam quality limit for CHF as a function of mass flux.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
1. single-lead ribbed (SLR) tubes (Fig. 8a) for small
internal diameters used in once-through subcritical pressure boilers, and
2. multi-lead ribbed (MLR) tubes (Fig. 8b) for larger internal diameters used in natural circulation boilers.
Both of these ribbed tubes have shown a remarkable ability to delay the breakdown of boiling. Fig. 7
5-5
The Babcock & Wilcox Company
Fig. 8a Single-lead ribbed tube.
Fig. 8b Multi-lead ribbed tube.
Fig. 6 Effect of inclination on CHF at 700,000 lb/h ft2 (950 kg/m2 s).6
compares the effectiveness of a ribbed tube to that of
a smooth tube in a membrane wall configuration. This
plot is different from Fig. 5 in that heat flux is given
as an average over the flat projected surface. This is
more meaningful in discussing membrane wall heat
absorption.
The ribbed bore tubes provide a balance of improved
CHF performance at an acceptable increase in pressure drop without other detrimental effects. The ribs
generate a swirl flow resulting in a centrifugal action
which forces the water to the tube wall and retards
entrainment of the liquid. The steam blanketing and
film dryout are therefore prevented until substantially
higher steam qualities or heat fluxes are reached.
Fig. 7 Steam quality limit for CHF in smooth and ribbed bore tubes.
5-6
Because the ribbed bore tube is more expensive than
a smooth bore tube, its use involves an economic balance of several design factors. In most instances, there
is less incentive to use ribbed tubes below 2200 psi
(15.2 MPa).
Evaluation CHF is a complex combination of thermal-hydraulic phenomena for which a comprehensive
theoretical basis is not yet available. As a result, experimental data are likely to continue to be the basis
for CHF evaluations. Many data and correlations define CHF well over limited ranges of conditions and
geometries. However, progress is being made in developing more general evaluation procedures for at
least the most studied case – a uniformly heated
smooth bore tube with upward flowing water.
To address this complex but critical phenomenon in
the design of reliable steam generating equipment,
B&W has developed an extensive proprietary database and associated correlations. A graphical example
is shown in Fig. 5 for a fossil fuel boiler tube. A B&W
correlation 7 for nuclear reactor fuel rod bundle
subchannel analysis is shown in Table 1.
CHF criteria A number of criteria are used to assess
the CHF margins in a particular tube or tube bundle
geometry.8 These include the CHF ratio, flow ratio and
quality margin, defined as follows:
CHF heat flux
1.
CHF ratio = minimum value of
2.
flow ratio = minimum value of
3.
quality margin = CHF quality − max. design quality
upset heat flux
min. design mass flux
mass flux at CHF
The CHF ratios for a sample fossil fuel boiler are
illustrated in Fig. 9 for a smooth bore tube ( qB′′ / q′′A ) and
a ribbed bore tube ( qC′′ / q′′A ). The graph indicates the
relative increase in local heat input which can be tolerated before the onset of CHF conditions. A similar
relationship for a nuclear reactor fuel rod application
is shown in Fig. 10.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
Supercritical heat transfer
Unlike subcritical pressure conditions, fluids at supercritical pressures experience a continuous transition from water-like to steam-like characteristics. As
a result, CHF conditions and boiling behavior would
not be expected. However, at supercritical pressures,
especially in the range of 1 < P/Pc < 1.15 where Pc is
the critical pressure, two types of boiling-like behavior have been observed: pseudo-boiling and pseudofilm boiling. Pseudo-boiling is an increase in heat
transfer coefficient not accounted for by traditional
convection relationships. In pseudo-film boiling, a
dramatic reduction in the heat transfer coefficient is
observed at high heat fluxes. This is similar to the
critical heat flux condition at subcritical pressures.
These behaviors have been attributed to the sharp
changes in fluid properties as the transition from
water-like to steam-like behavior occurs.
Fluid properties In the supercritical region, the thermophysical properties important to the heat transfer
process, i.e., conductivity, viscosity, density and specific heat, experience radical changes as a certain pressure-dependent temperature is approached and exceeded. This is illustrated in Fig. 11. The transition
temperature, referred to as the pseudo-critical temperature, is defined as the temperature where the
specific heat, cp, reaches its maximum. As the operating pressure is increased, the pseudo-critical temperature increases and the dramatic change in the thermophysical properties declines as this temperature is
approached and exceeded.
Heat transfer rates Because of the significant
changes in thermophysical properties (especially in
specific heat) near the pseudo-critical temperature, a
Fig. 9 Fossil boiler CHF ratio = minimum value of critical heat flux
divided by upset heat flux.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
Table 1
B&W2 Reactor Rod Bundle Critical Heat
Flux (CHF) Correlation7
q"CHF =
(a − bDi ) A1 (A2G) A3+A4(P−2000) − A9GxCHF Hfg
A5 (A6G) A7+A8(P−2000)
where
a
b
A1
A2
A3
A4
A5
A6
A7
A8
A9
=
=
=
=
=
=
=
=
=
=
=
1.15509
0.40703
0.37020 x 108
0.59137 x 10−6
0.83040
0.68479 x 10−3
12.710
0.30545 x 10−5
0.71186
0.20729 x 10−3
0.15208
A
Di
G
Hfg
=
=
=
=
P
Per
=
=
=
xCHF
q"CHF =
area, in.2
equivalent diameter = 4A/Per
mass flux, lb/h ft2
latent heat of vaporization,
Btu/lb
pressure, psi
wetted perimeter, in.
steam quality at CHF conditions, fraction steam by weight
heat flux at CHF conditions,
Btu/h ft2
modified approach to evaluating convective heat
transfer is needed. A number of correlations have been
developed and a representative relationship for smooth
bore tubes is:9
D G
hDi
= 0.00459 i
kw
µw
H − Hb µw
× w
Tw − Tb kw
0.923
0.613
υb
υ w
0.231
(5)
Fig. 10 Nuclear reactor CHF ratio = minimum value of critical heat
flux divided by design heat flux.
5-7
The Babcock & Wilcox Company
turbulence to move the higher temperature steam-like
fluid away from the tube wall into the colder, higher
density (water-like) fluid in the bulk stream. A phenomenon similar to steam blanketing occurs and the
wall temperature increases in response to the relatively constant applied heat flux.
Single-lead ribbed (SLR) bore tubes are very effective in suppressing the temperature peaks encountered in smooth bore tubes.10
Two-phase flow
Flow patterns
As illustrated in Fig. 2, two-phase steam-water flow
may occur in many regimes or structures. The transition from one structure to another is continuous rather
than abrupt, especially under heated conditions, and
is strongly influenced by gravity, i.e., flow orientation.
Because of the qualitative nature of flow pattern identification, there are probably as many flow pattern
descriptions as there are observers. However, for vertical, heated, upward, co-current steam-water flow in a
tube, four general flow patterns are generally recognized
(see Fig. 12):
Fig. 11 Thermophysical properties of water (English units).
where
h
k
Di
G
µ
H
T
υ
=
=
=
=
=
=
=
=
heat transfer coefficient, Btu/h ft2 F (W/m2 K)
thermal conductivity, Btu/h ft F (W/m K)
inside tube diameter, ft (m)
mass flux, lb/h ft2 (kg/m2 s)
viscosity, lb/ft h (kg/m s)
enthalpy, Btu/lb (J/kg)
temperature, F (C)
specific volume, ft3/lb (m3/kg)
The subscripts b and w refer to properties evaluated
at the bulk fluid and wall temperatures respectively.
This correlation has demonstrated reasonable
agreement with experimental data from tubes of 0.37
to 1.5 in. (9.4 to 38.1 mm) inside diameter and at low
heat fluxes.
Pseudo-boiling For low heat fluxes and bulk fluid
temperatures approaching the pseudo-critical temperature, an improvement in the heat transfer rate
takes place. The enhanced heat transfer rate observed
is sometimes referred to as pseudo-boiling. It has been
attributed to the increased turbulence resulting from
the interaction of the water-like and steam-like fluids
near the tube wall.
Pseudo-film boiling Potentially damaging temperature excursions associated with a sharp reduction
in heat transfer can be observed at high heat fluxes.
This temperature behavior is similar to the CHF phenomenon observed at subcritical conditions and is referred to as pseudo-film boiling. This phenomenon has
been attributed to a limited ability of the available
5-8
1. Bubbly flow Relatively discrete steam bubbles are
dispersed in a continuous liquid water phase.
Bubble size, shape and distribution are dependent
upon the flow rate, local enthalpy, heat input rate
and pressure.
2. Intermediate flow This is a range of patterns between bubbly and annular flows; the patterns are
also referred to as slug or churn flow. They range
from: a) large bubbles, approaching the tube size
in diameter, separated from the tube wall by thin
annular films and separated from each other by
slugs of liquid which may also contain smaller
bubbles, to b) chaotic mixtures of large nonsymmetric bubbles and small bubbles.
3. Annular flow A liquid layer is formed on the tube
wall with a continuous steam core; most of the liq-
Fig. 12 Flow pattern – upward, co-current steam-water flow in a
heated vertical tube.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
uid is flowing in the annular film. At lower steam
qualities, the liquid film may have larger amplitude waves adding to the liquid droplet entrainment and transport in the continuous steam core.
At high qualities, the annular film becomes very
thin, bubble generation is suppressed and the
large amplitude waves disappear.
4. Mist flow A continuous steam core transports entrained water droplets which slowly evaporate
until a single-phase steam flow occurs. This is also
referred to as droplet or dispersed flow.
In the case of inclined and horizontal co-current
steam-water flow in heated tubes, the flow patterns
are further complicated by stratification effects. At high
flow rates, the flow patterns approach those of vertical tubes. At lower rates, additional distinct flow patterns (wavy, stratified and modified plug) emerge as
gravity stratifies the flow with steam concentrated in
the upper portion of the tube. This can be a problem
where inclined tubes are heated from the top. CHF or
dryout conditions occur at much lower steam qualities and lower heat input rates in such inclined or
horizontal tubes.
Additional complexity in patterns is observed when
two-phase flow occurs in parallel or crossflow tube
bundles. The tubes, baffles, support plates and mixing devices further disrupt the flow pattern formation.
Flow maps The transitions from one flow regime to
another are quite complex, with each transition representing a combination of factors. However, two dimensional flow maps provide at least a general indication of which flow pattern is likely under given operating conditions. The maps generally are functions
of superficial gas and liquid velocities. An example for
vertical, upward, steam-water co-current flow is provided in Fig. 13.11 The axes in this figure represent
the superficial momentum fluxes of the steam (y-axis)
and water (x-axis). A sample flow line is shown beginning at nearly saturated water conditions and ending with saturated steam conditions. The tube experiences bubbly flow only near its inlet. This is followed
by a brief change to intermediate flow before annular flow dominates the heated length.
Other flow maps are available for arrangements
such as downflow tubes, inclined tubes and bundles.
Flow maps, however, are only approximations providing guidance in determining the relevant flow structure for a given situation.
Pressure loss
The local pressure loss, ∆P [lb/ft2 (Pa)] or gradient
δP/δ l [lb/ft2/ft (Pa/m)] in a two-phase steam-water
system may be represented by:
∆P = ∆Pf + ∆Pa + ∆Pg + ∆Pl
Fig. 13 Flow pattern map for vertical upward flow of water.11
the momentum or acceleration loss incurred as the
volume increases due to evaporation. The hydraulic
or static head loss is accounted for by ∆Pg and –(δ P/
δ l)g. Finally, all of the local losses due to fittings, contractions, expansions, bends, or orifices are included
in ∆Pl. The evaluation of these parameters is usually
made using one of two models: homogeneous flow or
separated flow.
A parameter of particular importance when evaluating the pressure loss in steam-water flows is void
fraction. The void fraction can be defined by time-averaged flow area ratios or local-volume ratios of steam
to the total flow. The area-based void fraction, α, can
be defined as the ratio of the time-averaged steam flow
cross-sectional area (Asteam) to the total flow area (Asteam
+ Awater):
α =
δP
δP
δP δP
−
−
= −
+ ∆Pl
δl
δ l f δ l a δ l g
(7)
Using the simple continuity equation, the relationship between quality, x, and void fraction is:
α =
(6a)
or
−
Asteam
Asteam + Awater
x
x + (1 − x )
ρg
S
ρf
(8)
where
(6b)
The ∆Pf and –(δ P/δ l)f terms account for local wall
friction losses. The ∆Pa and –(δ P/δ l)a terms address
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
S = ratio of the average cross-sectional velocities
of steam and water (referred to as slip)
ρg = saturated steam density, lb/ft3 (kg/m3)
ρ f = saturated water density, lb/ft3 (kg/m3)
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The Babcock & Wilcox Company
If the steam and water are moving at the same velocity, S = 1 (no slip). Obviously, the relationship between
void fraction and quality is also a strong function of
system pressure. This relationship is illustrated in Fig.
14. The difference between the homogeneous and
separated flow models is illustrated by the shaded
band. The upper bound is established by the homogeneous model and the lower bound by the separated
flow model.
Homogeneous model The homogeneous model is
the simpler approach and is based upon the premise
that the two-phase flow behavior can be directly modeled after single-phase behavior (see Chapter 3) if
appropriate average properties are determined. The
temperature and velocities of steam and water are
assumed equal. The mixed weight averaged specific
volume (υ ) or the inverse of the homogeneous density
(1/ρhom) is used:
υ = υ f (1 − x ) + υ g x
1
ρ hom
where
υf =
υg =
ρf =
ρg =
x =
=
ρf
g
∆Pg = ± ρ hom L sin θ
gc
(10)
where
g
gc
L
θ
=
=
=
=
acceleration of gravity, ft/s2 (m/s2)
32.17 lbm ft/lbf s2 (1 kg m/N s2)
length, ft (m)
angle from the horizontal
The constant gc is discussed in Chapter 2. A pressure
gain occurs in downflow and a pressure loss occurs in
upflow. The acceleration loss can be evaluated by:
∆Pa =
(9a)
or
(1 − x ) +
The friction pressure drop (∆Pf) can be evaluated
by the equations provided in Chapter 3 using the mixture thermophysical properties. The pressure difference due to elevation (∆Pg) can be evaluated as:
G2 1
1
−
gc ρ out ρ in
(11)
where
x
ρg
(9b)
saturated water specific volume, ft3/lb (m3/kg)
saturated steam specific volume, ft3/lb (m3/kg)
saturated water density, lb/ft3 (kg/m3)
saturated steam density, lb/ft3 (kg/m3)
steam quality
This model provides reasonable results when high
or low steam qualities exist, when high flow rates are
present, or at higher pressures. In these cases, the flow
is reasonably well mixed.
G = mass flux, lb/s ft2 (kg/m2s)
ρout = outlet homogeneous density, lb/ft3 (kg/m3)
ρin = inlet homogeneous density, lb/ft3 (kg/m3)
Separated flow model In the steady-state separated flow model, the steam and water are treated as
separate streams under the same pressure gradient
but different velocities and differing properties. When
the actual flow velocities of steam and water are equal,
the simplest separated flow models approach the homogeneous case. Using one of several separated flow
models1 with unequal velocities, the pressure drop
components (in differential form) are:
δP
δP
2
= −
−
φLO
δ l LO
δ l f
2
f G υf
δP
=
−
Di 2 gc
δ l LO
(12)
(single-phase friction) (13)
2
2
G 2 δ x υ g (1.0 − x ) υ f
δP
=
+
−
gc δ l α
(1.0 − α )
δ l a
g
δP
−
= g sin θ
δ
l
g
c
(friction)
(accelerration) (14)
α
(1.0 − α )
+
υf
υg
(static head) (15)
∆Pl = Φ K
G2 υ f
2 gc
(local losses)
(16)
where
Fig. 14 Void fraction – quality relationship (homogeneous model,
upper bound; separated flow model, lower bound).
2
= appropriate two-phase multipliers
Φ and φ LO
G = mass flux, lb/s ft2 (kg/m2 s)
f = fanning friction factor (see Chapter 3)
Di = tube inside diameter, ft (m)
g = acceleration of gravity, ft/s2 (m/s2)
g c = 32.17 lbm ft/lbf s2 (1 kg m/N s2)
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Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
υf
υg
x
α
θ
K
=
=
=
=
=
=
liquid specific volume, ft3/lb (m3/kg)
vapor specific volume, ft3/lb (m3/kg)
steam quality
void fraction
angle from the horizontal
loss coefficient
While ∆Pl usually represents just the irreversible pressure loss in single-phase flows, the complexity of twophase flows results in the loss of ∆Pl typically representing the reversible and irreversible losses for fittings.
To evaluate the individual pressure losses from
Equations 12 through 16 and Equation 6b, it is nec2
essary to calculate φ LO
, α and Φ. Unfortunately, these
factors are not well defined.
Specific correlations and evaluations can only be
used where experimental data under similar conditions provide confidence in the prediction. Proprietary
correlations used by B&W are based upon experimental data and practical experience.
For straight vertical tubes, generally available representative relationships include:
1. Acceleration loss The void fraction can frequently
be evaluated with the homogeneous model (S = 1
in Equation 8).
2. Friction loss and void fraction Typical two-phase
2
multiplier, φ LO
, and void fraction, α, relationships
are presented by Thom, 12 Martinelli-Nelson, 13
Zuber-Findlay14 and Chexal-Lellouche.15 For illustration purposes the correlations of Thom are presented in Figs. 15 and 16. These curves can be approximated by:
2
φLO
0.5
υ g
0.97303 (1 − x ) + x
υ f
=
0.5
× 0.97303 (1 − x ) + x + 0.027 (1 − x )
2.0
(17)
Fig. 15 Thom two-phase friction multiplier.12
1. unit control problems, including unacceptable
variations in steam drum water level,
2. CHF/DNB/dryout,
3. tube metal temperature oscillation and thermal
fatigue failure, and
4. accelerated corrosion attack.
Two of the most important types of instabilities in
steam generator design are excursive instability, including Ledinegg and flow reversal, and density
wave/pressure drop oscillations. The first is a static instability evaluated using steady-state equations while
the last is dynamic in nature requiring the inclusion
of time dependent factors.
and
α =
γx
1 + x (γ − 1 )
(18)
where
γ
n
P
υg
υf
x
=
=
=
=
=
=
(υg /υf)n
(0.8294 – 1.1672/P)
pressure, psi
saturated steam specific volume, ft3/lb
saturated liquid specific volume, ft3/lb
steam quality
Instabilities
Instability in two-phase flow refers to the set of
operating conditions under which sudden changes in
flow direction, reduction in flow rate and oscillating
flow rates can occur in a single flow passage. Often in
manifolded multi-channel systems, the overall mass
flow rate can remain constant while oscillating flows
in individual channels still may occur. Such unstable
conditions in steam generating systems can result in:
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
Fig. 16 Thom void fraction correlation (>3% SBW).12
5-11
The Babcock & Wilcox Company
Excursive and flow reversal instability evaluation The
excursive instability is characterized by conditions
where small perturbations in operating parameters
result in a large flow rate change to a separate steadystate level. This can occur in both single channel and
multi-channel manifolded systems. Excursive instabilities can be predicted by using the Ledinegg criteria.16 Instability may occur if the slope of the pressure
drop versus flow characteristic curve (internal) for the
tube becomes less than the slope of the supply (or
applied) curve at any intersection point:
δ∆P
δ∆P
≤
δG
internal δ G applied
(19)
The stable and unstable situations are illustrated
in Fig. 17. As shown in the figure for unstable conditions, if the mass flow rate drops below point B then
the flow rate continues to fall dramatically because the
applied pumping head is less than that needed to move
the fluid. For slightly higher mass flow rates (higher
than point B), a dramatic positive flow excursion occurs because the pumping head exceeds the flow system requirement.
In most systems, the first term in Equation 19 is
generally positive and the second is negative. Therefore, Equation 19 predicts stability. However, in twophase systems, thermal-hydraulic conditions may combine to produce a local area where (δ∆P/δ G)internal is
negative and the potential for satisfying Equation 19
and observing an instability exists. A heated tube flow
characteristic showing a potential region of instability is illustrated in Fig. 18 where multiple flow rates
can occur for a single applied pressure curve. Operating at point B is unstable with small disturbances resulting in a shift to point A or point C. More intense disturbances could result in flow shifts between A and C.
For the relatively small subcooling found at the entrance to tube panels in recirculating drum boilers and
due to the relatively low exit steam qualities, negative
slope regions in the pressure drop versus flow curves
are typically not observed for positive flow cases. However, for once-through fossil fuel boilers and nuclear
steam generators with high subcooling at the inlet and
evaporation to dryness, negative slope regions in the
upflow portion of the pressure drop characteristic may
occur. Steps can be taken to avoid operation in any region where the circuit internal δ∆P/δG ≤ 0. General
effects of operating and design parameters on the pressure drop versus mass flow curves include:
Parameter
Increased
Effect on ∆P
Comment
heat input
inlet ∆P
pressure
decrease
increase
increase
more stable
more stable
more stable
In situations where static instability may occur, the
inlet pressure drop can be increased by adding an
orifice or flow restriction to modify the overall flow
characteristic as shown in Fig. 18.
5-12
Fig. 17 Stable and unstable flow-pressure drop characteristics.
Fig. 18 Pressure drop characteristics showing unstable region.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
Density wave/pressure drop instability Density wave
instabilities involve kinematic wave propagation phenomena. Regenerative feedback between flow rate,
vapor generation rate and pressure drop produce self
sustaining alternating waves of higher and lower density mixture that travel through the tube. This dynamic instability can occur in single tubes that contain two-phase flows. In addition, when multiple tubes
are connected by inlet and outlet headers, a more complex coupled channel instability, which is driven by
density wave oscillations, may occur. Vertical heat flux
distribution is a particularly sensitive parameter in
dynamic instability evaluation.
Density wave oscillations can be predicted by the
application of feedback control theory. A number of
computer codes have been developed to provide these
predictions. In addition, instability criteria, which use
a series of dimensionless parameters to reduce the
complexity of the evaluation, have been developed.
Effects of operating and design parameters on the
density wave instability include:
Parameter
Increased
mass flux
heat flux
pressure
inlet ∆P
inlet subcooling
Change in stability
improved
reduced
improved
improved
improved (large subcooling)
reduced (small subcooling)
Steam-water separation
Subcritical pressure recirculating boilers and steam
generators are equipped with large cylindrical vessels
called steam drums. Their primary objective is to permit separation of the saturated steam from the steamwater mixture leaving the boiling heat transfer surfaces. The steam-free water is recirculated with the
feedwater to the heat absorbing surfaces for further
steam generation. The saturated steam is discharged
through a number of outlet nozzles for direct use or
further heating. The steam drum also serves to:
1. mix the feedwater with the saturated water remaining after steam separation,
2. mix the corrosion control and water treatment
chemicals (if used),
3. purify the steam to remove contaminants and residual moisture,
4. remove part of the water (blowdown) to control the
boiler water chemistry (solids content), and
5. provide limited water storage to accommodate
rapid changes in boiler load.
However, the primary function of the steam drum
is to permit the effective separation of steam and water. This may be accomplished by providing a large
steam-water surface for natural gravity-driven separation or by having sufficient space for mechanical
separation equipment.
High efficiency separation is critical in most boiler
applications in order to:
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
1. prevent water droplet carryover into the superheater where thermal damage may occur,
2. minimize steam carryunder in the water leaving
the drum where residual steam can reduce the
effective hydraulic pumping head, and
3. prevent the carryover of solids dissolved in the steamentrained water droplets into the superheater and
turbine where damaging deposits may form.
The last item is of particular importance. Boiler water may contain contaminants, principally in solution.
These arise from impurities in the makeup water,
treatment chemicals and condensate system leaks, as
well as from the reaction of the water and contaminants with the boiler and preboiler equipment materials. Even low levels of these solids in the steam (less
than 0.6 ppm) can damage the superheater and turbine. Because the solubility of these solids is typically
several orders of magnitude less in steam than in water (see Chapter 42), small amounts of water droplet carryover (greater than 0.25% by weight) may result in dramatically increased solids carryover and unacceptable
deposition in the superheater and turbine. The deposits
have caused turbine damage as well as superheater tube
temperature increases, distortion and burnout.
A cross-section of a horizontal steam drum found
on a modern high capacity fossil fuel boiler is shown
in Fig. 19. This illustrates the general arrangement
of the baffle plates, primary cyclone separators, secondary separator elements (scrubbers), water discharger (downcomer) and feedwater inlets. The blowdown (water removal) connections are not shown. The
steam-water separation typically takes place in two
stages. The primary separation removes nearly all the
steam from the water so that very little steam is recirculated from the bottom of the drum through the outlet connection (downcomer) towards the heated tubes.
The steam leaving the primary separators in high
pressure boilers still typically contains too much liquid in the form of contaminant-containing droplets for
satisfactory superheater and turbine performance.
Therefore, the steam is passed through a secondary
set of separators, or scrubber elements (usually closely
spaced, corrugated parallel plates) for final water
droplet removal. The steam is then exhausted through
several connections. As this figure indicates, successful steam-water separation involves the integrated
operation of primary separators, secondary scrubbers
and general drum arrangement.
Factors affecting steam separation
Effective steam separation from the steam-water
mixture relies on certain design and operating factors.
The design factors include:
1. pressure,
2. drum length and diameter,
3. rate of steam generation,
4. average inlet steam quality,
5. type and arrangement of mechanical separators,
6. feedwater supply and steam discharge equipment
arrangement, and
7. arrangement of downcomer and riser connections
to the steam drum.
5-13
The Babcock & Wilcox Company
Fig. 19 Steam drum with three rows of primary cyclone separators.
The operating factors include:
1.
2.
3.
4.
5.
pressure,
boiler load (steam flow),
type of steam load,
chemical analysis of boiler water, and
water level.
Primary separation equipment generally takes one of
three forms:
1. natural gravity-driven separation,
2. baffle-assisted separation, and
3. high capacity mechanical separation.
Natural gravity-driven separation
While simple in concept, natural steam-water separation is quite complex. It is strongly dependent upon
inlet velocities and inlet locations, average inlet steam
quality, water and steam outlet locations, and disengagement of liquid and steam above the nominal water surface. Some of these effects are illustrated in Figs.
20 and 21.
For a low rate of steam generation, up to about 3
ft/s (0.9 m/s) velocity of steam leaving the water surface, there is sufficient time for the steam bubbles to
separate from the mixture by gravity without being
drawn into the discharge connections and without
5-14
carrying entrained water droplets into the steam outlet (Fig. 20a). However, for the same arrangement at
a higher rate of steam generation (Fig. 20b), there is
insufficient time to attain either of these desirable
results. Moreover, the dense upward traffic of steam
bubbles in the mixture may also cause a false water
level indication, as shown.
The effect of the riser or inlet connection locations
in relation to the water level is illustrated in diagrams
a and b of Fig. 21. Neither arrangement is likely to
yield desirable results in a drum where gravity alone
is used for separation.
From an economic standpoint, the diameter of a
single drum may become prohibitive. To overcome this
limitation, several smaller steam drums may be used,
as shown in Fig. 22a, although this is no longer common. However, in most boiler applications, natural
gravity-driven separation alone is generally uneconomical, leading to the need for separation assistance.
Baffle-assisted primary separation
Simple screens and baffle arrangements may be
used to greatly improve the steam-water separation
process. Three relatively common baffle arrangements
are illustrated in Fig. 22. In each case, the baffles
provide: 1) changes in direction, 2) more even distriSteam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
Fig. 20 Effect of rate of steam generation on steam separation in a
boiler drum without separation devices.
Fig. 21 Effect of location of discharge from risers on steam
separation in a boiler drum without separation devices.
bution of the steam-water mixture, 3) added flow resistance, and 4) the maximum steam flow travel length
to enhance the gravity-driven separation process.
Various combinations of perforated plates have also
been used. The performance of these devices must be
determined by experimental evaluations and they are
typically limited to smaller, low capacity boilers.
downcomers virtually free of steam bubbles, the maximum net pumping head is available for producing flow
in the circuits. The steam moving upward from the
cylinder passes through a small primary corrugated
scrubber at the top of the cyclone (see Fig. 24) for additional separation. Under many operating conditions,
no further separation is required.
When wide load fluctuations and water analysis
variations are expected, large corrugated secondary
scrubbers may be installed at the top of the drum (see
Fig. 19) to provide very high steam separation. These
scrubbers are also termed secondary separators. They
provide a large surface which intercepts water droplets as the steam flows sinuously between closely fitted plates. Steam velocity through the corrugated plate
assembly is very low, so that water re-entrainment is
avoided. The collected water is drained from the bottom of the assembly to the water below.
One to four rows of cyclone separators are installed
in boiler drums, with ample room for access. For
smaller boilers at lower pressures [100 psig (0.7 MPa
gauge)], the separation rate of clean steam by single
and double rows of cyclone separators is approximately
Mechanical primary separators
Centrifugal force or radial acceleration is used almost universally for modern steam-water separators.
Three types of separators are shown in Fig. 23: the
conical cyclone, the curved arm and the horizontal
cyclone. The B&W vertical cyclone steam separator is
shown in more detail in Fig. 24. Vertical cyclones are
arranged internally in rows along the length of the
drum and the steam-water mixture is admitted tangentially as shown in Fig. 19. The water forms a layer
against the cylinder walls and the steam moves to the
core of the cylinder then upward. The water flows
downward in the cylinder and is discharged through
an annulus at the bottom, below the drum water level.
With the water returning from drum storage to the
Fig. 22 Simple types of primary steam separators in boiler drums: a) deflector baffle, b) alternate deflector baffle, and c) compartment baffle.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
5-15
The Babcock & Wilcox Company
Steam Out
Long Tangential
Steam-Water Inlet
Diverging
Body
(a) Conical Cyclone
Water
Out
Baseplate with Swirl Vanes
Steam Out
Curved Arm
Injector
Shroud
Cylinder
(b) Curved Arm
SteamWater
Inlet
Water
Out
Steam Out
Washing the steam with condensate or feedwater of
acceptable purity may be used for this purpose.
Specialized vertical steam-water separators can be
used in once-through fossil fueled boiler systems
which are designed for part-load recirculation of water during startup and low-load operation. These are
basically vertical cylindrical pressure vessels (see Fig.
25) where the steam-water mixture enters through
multiple tangential inlets in the vertical vessel wall.
The resulting centrifugal acceleration creates a cyclone
action similar to that in the primary cyclone separators (Fig. 24) which separates the water from the
steam. Water is returned to the boiler circuitry for
further heating and steam generation while the steam
is sent to the superheating circuits.
Mechanical separator performance
The overall performance of mechanical separators
is defined by: 1) the maximum steam flow rate at a
specified average inlet quality per cyclone which meets
droplet carryover limits, and 2) the predicted pressure
loss. In addition, the maximum expected steam carryunder (% steam by weight) should also be known.
These parameters are influenced by total flow rate,
pressure, separator length, aperture sizes, drum water level, inlet steam quality, interior separator finish
and overall drum arrangement. Performance characteristics are highly hardware-specific. The general
trends are listed in Table 2.
Steam separator evaluation To date, theoretical
analyses alone do not satisfactorily predict separation
performance. Therefore, extensive experimental investigations are performed to characterize individual
steam-water primary separator designs.
(c) Horizontal
Cyclone Separator
Steam-Water Inlet
Water Out
Fig. 23 Typical primary steam-water separators.
4000 and 6000 lb, respectively, per hour per foot of
drum length (1.7 and 2.5 kg/s m). At pressures near
1050 psig (7.24 MPa gauge), these values increase to
9000 and 15,000 lb/h ft (3.7 and 6.2 kg/s m), respectively. For large utility boilers operating at 2800 psig
(19.3 MPa gauge), separation can be as high as 67,000
lb/h ft (28 kg/s m) of steam with four rows of cyclone
separators.
This combination of cyclone separators and scrubbers provides a steam purity of less than 1.0 ppm solids content under a wide variety of operating conditions. This purity is generally adequate in commercial practice. However, further refinement in steam
purification is required where it is necessary to remove
boiler water salts, such as silica, which are entrained
in the steam by a vaporization or solution mechanism.
5-16
Fig. 24 Vertical cyclone separator.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
Fig. 25 Vertical steam-water separator in a spiral wound universal
pressure (SWUP™) boiler startup system.
Pressure drop of two-phase flow through a separator is extremely complex. An approximation involves
using the homogeneous model two-phase multiplier,
Φ, and a dimensionless loss coefficient, Kss, as follows:
∆Pseparator = K ss Φ
G 2υ f
2 gc
(20)
where
υ −υf
Φ = 1.0 + g
υ
f
x
The variable Kss is a unique function of pressure for
each steam separator design. The other variables are
defined after Equation 16.
The maximum steam flow per primary separator
defines the minimum number of standard units required, while the ∆P is used in the circulation calculations. Given the unique design of each separator,
B&W has acquired extensive experimental performance data under full-scale, full-flow and full-pressure conditions for its equipment.
Table 2
Mechanical Separator Performance Trends
Moisture carryover with steam
1. increases gradually with steam flow rate until a
breakaway point is reached where a sudden rise in
carryover occurs,
2. increases with water level until flooding occurs, and
3. increases with steam quality.
Carryunder of steam with water
1. declines with increasing water level, and
2. declines with decreasing inlet steam quality.
Pressure drop (Pin − Pdrum )
1. increases with mass flow and steam quality.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
Steam drum capacity
Given the flow capabilities of standardized steamwater separation equipment, the boiler drum is sized
to accommodate the number of separators necessary
for the largest expected boiler load (maximum steam
flow rate) and to accommodate the changes in water level
that occur during the expected load changes. The drum
diameter, in incremental steps, and length are adjusted
to meet the space requirements at a minimum cost.
An evaluation limit in steam drum design is the
maximum steam carryunder into the downcomer.
Carryunder, or transport of steam into the downcomers, is not desirable because it reduces the available
thermal pumping force by reducing the density at the
top of the downcomer. Carryunder performance is a
function of physical arrangement, operating pressure,
feedwater enthalpy, free-water surface area, drum
water level and separator efficiency. Empirical correction factors for specific designs are developed and used
in the circulation calculations to account for the steam
entering the downcomers. The steam is eventually
completely condensed after it travels a short distance
into the downcomer. However, the average density in
the top portion of the downcomer is still lower than
thermal equilibrium would indicate.
A rapid increase in steam demand is usually accompanied by a temporary drop in pressure until the firing rate can be sufficiently increased. During this interval, the volume of steam throughout the boiler is
increased and the resulting swell raises the water level
in the drum. The rise depends on the rate and magnitude of the load change and the rate at which the
heat and feed inputs can be changed to meet the load
demand. Steam drums are designed to provide the necessary volume, in combination with the controls and
firing equipment, to prevent excessive water rise into
the steam separators. This, in turn, prevents water
carryover with the steam.
Circulation
The purpose of the steam-water flow circuitry is to
provide the desired steam output at the specified temperature and pressure. The circuitry flow also ensures
effective cooling of the tube walls under expected operating conditions, provided the unit is properly operated and maintained. A number of methods have
been developed. Four of the most common systems are
illustrated in Fig. 26. These systems are typically classified as either recirculating or once-through.
In recirculating systems, water is only partially
evaporated into steam in the boiler tubes. The residual
water plus the makeup water supply are then recirculated to the boiler tube inlet for further heating and
steam generation. A steam drum provides the space
required for effective steam-water separation. Oncethrough systems provide for continuous evaporation
of slightly subcooled water to 100% steam without
steam-water separation. Steam drums are not required. These designs use forced circulation for the
necessary water and steam-water flow. In some cases,
a combination of these approaches is used. At low
loads, recirculation maintains adequate tube wall cool5-17
The Babcock & Wilcox Company
Superheater
(SH)
Econ
Drum
Economizer
(Econ)
SH
Furnace
Walls
(Furn)
Drum
Circ
Pump
Furn
Orifices
(a) Natural Recirculation
(b) Forced Recirculation
SH
SH
Sep
Furn
Furn
Circ
Pump
Econ
Econ
(d) Once-Through with Part-Load
Recirculation
(c) Once-Through
Fig. 26 Common fossil fuel boiler circulation systems.
ing while at high loads, high pressure once-through
operation enhances cycle efficiency.
Natural circulation
In natural circulation, gravity acting on the density difference between the subcooled water in the
downcomer and the steam-water mixture in the tube
circuits produces the driving force or pumping head
to drive the flow. As shown in Fig. 27, a simplified
boiler circuit consists of an unheated leg or downcomer
and heated boiler tubes. The water in the downcomer
is subcooled through the mixing of the low temperature feedwater from the economizer with the saturation-temperature water discharged from the steamwater separators. Steam-water, two-phase flow is created in the boiler tubes as a result of the heat input.
Because the steam-water mixture has a lower average
density than the single-phase downcomer flow, a pressure differential or pumping pressure is created by the
action of gravity and the water flows around the circuit. The flow increases or decreases until the pressure
losses in all boiler circuits are balanced by the available pumping pressure. For steady-state, incompressible flow conditions, this balance takes the form:
g
− ∫ 0Z ρ ( z ) dz =
gc
( ∆Pfriction + ∆Pacceleration + ∆Plocal )
(Z ρ
d
)
Fig. 27 Simple furnace circulation diagram.
g c = 32.17 lbm ft/lbf s2 (l kg m/N s2)
∆P = circuitry pressure loss due to friction, fluid
acceleration and local losses, lb/ft2 (Pa)
As the heat input increases, circulation rate increases until a maximum flow rate is reached (Fig. 28).
If higher heat inputs occur, they will result in larger
pressure losses in the heated tubes without corresponding increases in pressure differential. As a result, the
flow rate declines.
Natural circulation boilers are designed to operate
in the region where increased heat input results in an
increase in flow for all specified operating conditions.
In this mode, a natural circulation system tends to be
self compensating for numerous variations in heat
absorption. These can include sudden changes in load,
(21)
where
Z
= total vertical elevation, ft (m)
z
= incremental vertical elevations, ft (m)
ρ(z) = heated tube local fluid density, lb/ft3 (kg/m3)
ρ d = average downcomer fluid density, lb/ft3 (kg/
m3 )
g
= acceleration of gravity, ft/s2 (m/s2)
5-18
Fig. 28 Typical relationship between circulation at a given pressure
and steam production (arbitrary scale).
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
The Babcock & Wilcox Company
changes in heating surface cleanliness and changes
in burner operation.
Natural circulation is most effective where there is
a considerable difference in density between steam
and water phases. As shown in Fig. 29, the potential
for natural circulation flow remains very high even
at pressures of 3100 psi (21.4 MPa).
Forced circulation
In recirculating or once-through forced circulation
systems, mechanical pumps provide the driving head
to overcome the pressure losses in the flow circuitry.
Unlike natural circulation, forced circulation does not
enjoy an inherent flow-compensating effect when
heat input changes, i.e., flow does not increase significantly with increasing heat input. This is because a
large portion of the total flow resistance in the boiler
tubes arises from the flow distribution devices (usually
orifices) used to balance flow at the circuit inlets. The
large resistance of the flow distributors prevents significant increases in flow when heat absorption is increased.
Forced circulation is, however, used where the boilers are designed to operate near or above the critical
pressure [3200 psi (22.1 MPa)]. There are instances
in the process and waste heat fields and in some specialized boiler designs where the use of circulating
pumps and forced circulation can be economically attractive. At pressures above 3100 psi (21.4 MPa) a natural circulation system becomes increasingly large and
costly and a pump can be more economical. In addition,
the forced circulation principle can work effectively in
both the supercritical and subcritical pressure ranges.
In forced recirculation there is a net thermal loss
because of the separate circulating pump. While practically all the energy required to drive the pumps reappears in the water as added enthalpy, this energy
originally came from the fuel at a conversion to useful energy factor of less than 1.0. If an electric motor
drive is used, the net energy lost is about twice the
energy supplied to the pump motor for typical fossil
fuel systems.
Fig. 29 Effect of pressure on pumping head.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
Circulation design and evaluation
The furnace wall enclosure circuits are very important areas in a boiler. High constant heat flux conditions make uninterrupted cooling of furnace tubes
essential. Inadequate cooling can result in rapid overheating, cycling thermal stress failure, or material
failures from differential tube expansion. Sufficient
conservatism must be engineered into the system to
provide adequate cooling even during transient upset conditions. Simultaneously, the rated steam flow
conditions must be maintained at the drum outlet. Any
of the circulation methods discussed may be used to
cool the furnace waterwall tubes. In evaluating the
circulation method selected for a particular situation,
the following general procedure can be used:
1. The furnace geometry is set by the fuel and combustion system selected. (See Chapters 11, 14, 19 and 21.)
2. Standardized components (furnace walls, headers,
drums, etc.) are selected to enclose the furnace arrangement as needed. (See Chapters 19 and 21.)
3. The local heat absorption is evaluated based upon
the furnace geometry, fuel and firing method. Local upset factors are evaluated based upon past
field experience. (See Chapter 4.)
4. Circulation calculations are performed using the
pressure drop relationships.
5. The calculated circulation results (velocities, steam
qualities, etc.) are compared to the design criteria.
6. The flow circuitry is modified and the circulation
re-evaluated until all of the design criteria are met.
Some of the design criteria include:
1. Critical heat flux limits For recirculating systems,
CHF conditions are generally avoided. For oncethrough systems, the temperature excursions at
CHF are accommodated as part of the design.
2. Stability limits These limits generally indicate
acceptable pressure drop versus mass flow relationships to ensure positive flow in all circuits and to
avoid oscillating flow behavior.
3. Steam separator and steam drum limits These
indicate maximum steam and water flow rates to
individual steam-water separators and maximum
water flow to the drum downcomer locations to
ensure that steam carryunder and water carryover
will not be problems.
4. Minimum velocity limits Minimum circuit saturated velocities assure that solids deposition, potentially detrimental chemistry interactions, and
selected operating problems are minimized.
5. Sensitivity The system flow characteristic is
checked to ensure that flow increases with heat
input for all expected operating conditions.
Circulation is analyzed by dividing the boiler into
individual simple circuits – groups of tubes or circuits
with common end points and similar geometry and
heat absorption characteristics. The balanced flow
condition is the simultaneous solution of the flow characteristics of all boiler circuits.
At the heart of a B&W circulation evaluation is a
circulation computer program that incorporates tech5-19
The Babcock & Wilcox Company
Critical flow
A two-phase flow parameter of particular importance
in nuclear reactor safety analysis and in the operation
of valves in many two-phase flow systems is the critical flow rate. This is the maximum possible flow rate
through an opening when the flow becomes choked
and further changes in upstream pressure no longer
affect the rate. For single-phase flows, the critical flow
rate is set by the sonic velocity. The analysis is based
upon the assumption that the flow is one dimensional,
homogeneous, at equilibrium and isentropic. These assumptions result in the following relationships:
Sonic velocity = C =
dP
Critical flow = Gmax = ρ
gc
dρ
Fig. 30 Moody critical flow model for maximum steam-water flow rate.17
niques for calculating the single- and two-phase heat
transfer and flow parameters discussed above and in
Chapters 3 and 4. With this program, a circulation
model of the entire boiler is developed. Input into the
program is a geometric description of each boiler circuit including descriptions of downcomers, supplies,
risers, orifices, bends and swages, as well as individual
tubes. Each of the circuits within the boiler is subjected
to the local variation in heat transfer through inputs
based upon the furnace heat flux distribution. (See
Chapter 4.) Given the geometry description and heat
absorption profile, the computer program determines
the balanced steam-water flow to each circuit by solving the energy, mass and momentum equations for the
model. The results of the program provide the detailed
information on fluid properties, pressure drop and flow
rates for each circuit so that they can be compared to
the design criteria. Adjustments frequently made to
improve the individual circuit circulation rates can
include: changing the number of riser and supply
connections, changing the number or type of steam
separators in the drum, adding orifices to the inlets to
individual tubes, changing the drum internal baffling,
changing the operating pressure (if possible) and lowering the feedwater temperature entering the drum.
Once the steam-water circuitry is finalized, the detailed
mechanical design proceeds.
dP
d ρ gc
s
(22)
(23)
where
C
P
ρ
gc
Gmax
=
=
=
=
=
velocity, ft/s (m/s)
pressure, lb/ft2 (Pa)
fluid density, lb/ft3 (kg/m3)
32.17 lbm ft/lbf s2 (1 kg m/N s2)
mass flux, lb/s ft2 (kg/m2 s)
However, when saturated water or a two-phase
steam-water mixture is present, these simplifying assumptions are no longer valid. The flow is heterogeneous and nonisentropic with strong interfacial transport and highly unstable conditions.
Moody’s analysis17 of steam-water critical flow is perhaps the most frequently used. It is based upon an
annular flow model with uniform axial velocities of
each phase and equilibrium between the two phases.
A key element of the analysis involves maximizing the
flow rate with respect to the slip ratio and the pressure. The results are presented in Fig. 30. The critical
steam-water flow rate is presented as a function of the
stagnation condition. Compared to experimental observations, this correlation slightly overpredicts the
maximum discharge at low qualities (x < 0.1) and predicts reasonably accurately at moderate qualities (0.2
< x < 0.6), but tends to underpredict at higher qualities (x > 0.6).
References
1. Collier, J.G., and Thome, J.R., Convective Boiling & Condensation, Third Ed., Oxford University Press, Oxford,
United Kingdom, 1994.
2. Jens, W.H., and Lottes, P.A., “Analysis of heat transfer, burnout, pressure drop, and density data for high pressure water,” Argonne National Laboratory Report ANL4627, May, 1951.
3. Thom, J.R.S., et al., “Boiling in subcooled water during flow up heated tubes or annuli,” Proceedings of Institute of Mechanical Engineers, Vol. 180, pp. 226-246, 1966.
5-20
4. Chen, J.C., “Correlation for boiling heat transfer to saturated liquids in convective flow,” Industrial & Engineering Chemistry Process & Design Development, Vol. 5, pp.
322-329, 1966.
5. Kitto, J.B., and Albrecht, M.J., “Elements of two-phase
flow in fossil boilers,” Two-Phase Flow Heat Exchangers,
Kakaç, S., Bergles, A.E. and Fernandes, E.O., Eds., Kluwer
Academic Publishers, Dordrecht, The Netherlands, pp.
495-552, 1988.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
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6. Watson, G.B., Lee, R.A., and Wiener, M., “Critical heat
flux in inclined and vertical smooth and ribbed tubes,” Proceedings of The Fifth International Heat Transfer Conference, Vol. 4, Japan Society of Mechanical Engineers, Tokyo, Japan, pp. 275-279, 1974.
7. Gellerstedt, J.S., et al., “Correlation of critical heat
flux in a bundle cooled by pressurized water,” Two-Phase
Flow and Heat Transfer in Rod Bundles, Schock, V.E.,
Ed., American Society of Mechanical Engineers (ASME),
New York, New York, pp. 63-71, 1969.
8. Wiener, M., “The latest developments in natural circulation boiler design,” Proceedings of The American
Power Conference, Vol. 39, pp. 336-348, 1977.
9. Swenson, H.S., Carver, J.R., and Kakarala, C.R.,
“Heat transfer to supercritical water in smooth-bore
tubes,” Journal of Heat Transfer, Vol. 87, pp. 477-484,
1965.
10. Ackerman, J.W., “Pseudoboiling heat transfer to supercritical pressure water in smooth and ribbed tubes,”
Journal of Heat Transfer, Vol. 92, pp. 490-498, 1970.
11. Hewitt, G.F., and Roberts, D.W., “Studies of two-phase
flow patterns by simultaneous x-ray and flash photography,” Atomic Energy Research Establishment Report
M2159, HMSO, London, England, United Kingdom, 1969.
12. Thom, J.R.S., “Prediction of pressure drop during
forced circulation boiling of water,” International Journal
of Heat and Mass Transfer, Vol. 7, pp. 709-724, 1964.
13. Martinelli, R.C., and Nelson, D.B., “Prediction of pressure drop during forced-circulation boiling of water,” Transactions of the American Society of Mechanical Engineers
(ASME), pp. 695-702, 1948.
14. Zuber, N., and Findlay, J.A., “Average volumetric concentration in two-phase flow systems,” Journal of Heat
Transfer, Vol. 87, pp. 453-468, 1965.
15. Chexal, B.J., Horowitz, J., and Lellouche, G.S., “An
assessment of eight void fraction models for vertical flows,”
Electric Power Research Institute Report NSAC-107, December, 1986.
16. Ledinegg, M., “Instability of flow during natural and
forced circulation,” Die Wärme, Vol. 61, No. 48, pp. 891898, 1938 (AEC-tr-1861, 1954).
17. Moody, F.J., “Maximum flow rate of a single component, two-phase mixture,” Journal of Heat Transfer, Vol.
87, pp. 134-142, 1965.
Bibliography
Bergles, A.E., et al., Two-Phase Flow and Heat Transfer
in the Power and Process Industries, Hemisphere, Washington, D.C., August, 1981.
Butterworth, D., and Hewitt, G.F., Eds., Two-Phase Flow
and Heat Transfer, Oxford University Press, Oxford,
England, United Kingdom, 1977.
Chen, J.C., Ed., Flow Boiling, Taylor and Francis Group,
New York, New York, 1996.
Hsu, Y-Y, and Graham, R.W., Transport Processes in
Boiling and Two-Phase Systems, Hemisphere, Washington, D.C., 1976.
Kakaç, S., Boilers, Evaporators and Condensers, John
Wiley & Sons, New York, New York, 1991.
Steam 41 / Boiling Heat Transfer, Two-Phase Flow and Circulation
Kitto, J.B., “Steam Generators,” Standard Handbook of
Powerplant Engineering, Second Ed., Elliot, T.C., Chen,
K., and Swanekamp, R.C., McGraw-Hill, New York, New
York, 1998.
Lahey, R.T., and Moody, F.J., Thermal-Hydraulics of a
Boiling Water Nuclear Reactor, Second Ed., American
Nuclear Society (ANS), Hinsdale, Illinois, 1993.
Lokshin, V.A., Peterson, D.F., and Schwarz, A.L., Standard Methods of Hydraulic Design for Power Boilers,
Hemisphere Publishing, New York, New York, 1988.
Tong, L.S., Boiling Heat Transfer and Two-Phase Flow,
John Wiley & Sons, New York, New York, 1965.
Wallis, G.B., One-Dimension Two-Phase Flow, McGrawHill, New York, New York, 1969.
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Two-phase flow void fraction measurements.
5-22
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The Babcock & Wilcox Company
Chapter 6
Numerical Modeling for Fluid Flow,
Heat Transfer, and Combustion
Numerical modeling – an overview
Continuous and steady advances in computer technology have changed the way engineering design and
analyses are performed. These advances allow engineers to deal with larger-scale problems and more complex systems, or to look in more detail at a specific
process. Indeed, through the use of advanced computer technology to perform engineering analysis, numerical modeling has emerged as an important field
in engineering. While this chapter focuses on fluid
flow and heat transfer, Chapter 8 provides a brief discussion of numerical modeling for structural analysis.
In general, the term numerical method describes
solving a mathematical description of a physical process using a numerical rather than an analytical approach. This may be done for a number of reasons,
including the following:
1. An analytical means of solving the equations that
describe the system may not exist.
2. Even though an analytical method is available, it
may be necessary to repeat the calculation many
times, and a numerical method can be used to accelerate the overall process.
A small-scale replica of an apparatus is considered
a physical model because it describes the full-size apparatus on a smaller scale. This model can incorporate varying levels of detail depending on need and
circumstances. A mathematical description of a physical system (referred to as a mathematical model) can
also incorporate varying levels of detail. Similar to a
physical model, the amount of detail is often determined by the accuracy required and the resources
available to use the model. This creates a need to
strike a balance between accuracy, complexity and
efficiency.
There are two basic approaches to mathematical
modeling.
1. Model the behavior of a system. Network flow models and heat exchanger heat transfer correlations
are examples of a system model.
2. Model the fundamental physics of a system to determine the behavior. Computational fluid dynamics (CFD) and chemical reaction models fall into
this category.
The term numerical modeling usually refers to the
use of numerical methods on high-powered computers
to solve a complex system of mathematical models based
on the fundamental physics of the system. In this respect, it describes the second approach identified above.
As an example, consider analysis of hot air moving
through a length of duct composed of several different components all in a cold environment.
The first type of analysis would involve a network
model. This model would describe the pressure drop
and heat loss along the duct based on the length,
shape, number of turns, etc. This model is based on
extensive flow measurements taken on the individual
components (i.e., straight sections, turns, reductions,
etc.) that make up the duct. A set of empirical and fundamental correlations is used to analyze the flow rate
through the duct. The computation can be set up quickly
and with minimal effort. Results and multiple variations
can be rapidly obtained. While results are reasonably
accurate, they are limited to the components for which
a flow correlation already exists. A unique component
design that has not been described by a correlation may
not be accurately evaluated with this type of model.
The second type of analysis would involve a CFD
model of the same duct. The detailed behavior of the
flow through the entire duct is modeled. From this
information, pressure drop and heat loss along the
length of the duct may be determined. However, unlike the first analysis, this type of model provides additional details. For example, the first model does not
consider how the flow through a bend differs if it is
followed by another bend or a straight section; the first
model may result in the same pressure drop regardless of how the components are arranged. The second
analysis would account for these differences. In addition, variation in heat loss from one side of the duct to
the other can be determined. Most importantly, this
model is not restricted to duct components where extensive experimental data is available. New concepts
can easily be evaluated.
These two approaches have both benefits and limitations. The appropriate use of each is determined by
the information needed and the information available.
While both approaches are important engineering tools,
the remaining discussion here will focus on the second,
specifically on CFD and combustion modeling, and how
they relate to furnaces, boilers and accessory equipment.
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Benefits
There are numerous benefits to using a sophisticated tool such as a numerical model for engineering
analysis. These tools can often provide information
that can only be obtained through expensive experiments or may not be available any other way. Numerical modeling may often be used to obtain needed information quickly and at a reduced cost.
While it is important to understand the advantages
of using numerical modeling, it is equally important
to understand that it is only one means of obtaining
the required information. Engineering has long relied
on theory and experiments for design and analysis.
Numerical modeling adds a third approach. Each approach offers different insights with different benefits.
Increased understanding
The primary purpose of using numerical modeling
is to increase understanding of a physical process. As
such, it is often used in addition to or in conjunction
with other available tools. Consider the duct example
described above. It is possible to use a network model
on a large number of duct designs to narrow the possibilities to a few candidate designs. A full CFD model
could then be used to analyze each of the candidate
designs to gain a better understanding of the
strengths and weaknesses of each design.
Exploration of unfamiliar conditions
As previously described, it is possible that a component of the duct can not be accurately described within
the context of a flow network model. A conservative
approximation can be used but may result in an overly
conservative solution. A CFD model of the new component can provide the missing information, or a CFD
model of the entire system can be performed. The
model allows the exploration and analysis of new
equipment and systems.
Design validation/examination of interactions
Traditional methods of analysis and design are often focused on individual system components such as
the burners, air system, or heat transfer surfaces in a
furnace. A full accounting of the complex interaction
between the components is often not given. Numerical modeling provides a vehicle to evaluate the interactions and validate the system design.
Troubleshooting
Engineering analysis often investigates the behavior of existing systems. This is particularly true when
the behavior does not agree with the expectations. Numerical modeling can play a vital role in determining
the nature of the problem and suggesting solutions.
Flexibility
A distinct feature of numerical modeling is that it
is a flexible method of analysis. Modeling can be used
to look at any number of different geometries or operating conditions. In addition, the level of detail used
in the model can vary from use to use. A high level of
detail may be required to model flow near a fuel inlet
6-2
to a burner, but the same level of detail may not be
necessary for flow in a duct. The complexity is often
dictated by the problem.
Historical perspectives
In many ways, the history of numerical modeling
in the context of CFD has followed the development
of computational capabilities. Early efforts in CFD
started in the 1960s, when computers first became
commercially available, and when many of the concepts and ideas that form the basis of current techniques in CFD were first developed. One example is
the way much of the turbulent flow is modeled today.
Early efforts were often limited to simple two-dimensional laminar flows. The resolution of the geometry
was also very limited.
It was not until the 1970s that CFD saw substantial successes. It was during this time that CFD began to be used for general engineering problems.
Progress included turbulence modeling, two-dimensional reacting flows and three-dimensional flows.
As further advances were made in computational
technology, more sophisticated and detailed numerical models, as well as increased resolution, became
possible. This increased the acceptance of CFD as a
useful engineering tool and gave it a much wider application base. Soon, large comprehensive combustion
CFD models were developed. These were fully threedimensional turbulent-reacting flow models. Sub-models of detailed physics for specific applications were
included, such as pulverized coal combustion and radiation heat transfer models. Improvements continue
to be made today that promise to increase the utility
of combustion CFD modeling.
Modeling process
In its simplest terms, a numerical model is provided
with input data that is used to fix specific operating
parameters and return results. Without further understanding, this simplistic view of modeling can lead
to unsatisfactory results. More appropriately, a multistep process is used:
1. Obtain a complete situational description including physical geometry, process flow, physical property data and the level of detail needed. It is important to obtain detailed information because
seemingly small differences can have a significant
effect on numerical solutions.
2. Define the modeling assumptions appropriate for
the specific flow system and computer model selected while making appropriate tradeoffs; cost
and time are balanced against level of detail and
information required.
3. Prepare the input data by converting the general
technical information obtained in step 1 into the
detailed inputs required by the computational
model selected. Much of this is accomplished with
the use of various computer programs such as computer assisted drafting (CAD) software and mesh
generation software. Verification of the input data
is an important part of this process.
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
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4. Run the numerical computational model until an
acceptable solution is obtained.
5. Analyze the results to verify the initial model assumptions, to check the results against known
trends, to benchmark the output with known field
data, and to present the results in a usable form.
In application, the computer programs or software
used to perform the modeling function are broken
down into three general groups that work together to
complete the analysis:
1. Pre-processing: generation of the calculational
mesh or grid representing all boundary conditions
(part of step 3 above and discussed later under
Mesh generation),
2. Solution: execution of the numerical model to derive an acceptable solution (step 4 above), and
3. Post-processing: generation of typically graphical
or tabular key results from the numerical model
to permit interpretation and evaluation of the results (part of step 5 above).
are used to predict boiler behavior, evaluate design
modifications, or investigate localized phenomena. Examples of flue gas applications include predicting temperature distributions within a furnace, evaluating
fluid mixing due to the retrofit of systems to control
nitrogen oxides (NOx) emissions, and improving air
heater flow distributions to increase heat absorption.
Water-side applications include determining flow rates
for boiler furnace circulation systems and evaluating
system stability, among others. Many of the uses are
summarized in Table 1.
Theory
The foundation of numerical modeling is the development of a mathematical description of the physical
system to be modeled. Whether this is as simple as
heat transfer through a wall or as complex as a pul-
Table 1
Sample Numerical Model Applications
Limitations
Despite recent advances in technology, increased
understanding of physics, and improvements in describing input conditions, limitations remain in applying numerical modeling to engineering problems. Numerical modeling can only be applied where there is
an adequate understanding of the physics involved.
In situations where there is not an appropriate mathematical description of the physics, numerical modeling is not possible. Even when a description exists, it
may be too complex to be readily used in a model and
a simplified approach is required. In this case, results
will reflect the simplifying assumptions of the model.
Computer technology continues to limit the level of
detail that can be modeled with numerical methods.
Our understanding of the physics of systems that are
routinely modeled with CFD far exceeds the computational resources (size and speed) that are available
to model them. A considerable amount of effort is expended on developing simplified descriptions of the
physics to make the problem manageable with current
computer technology.
The precision and accuracy of the input data also
represents a significant limitation to numerical modeling. Sources where this may be significant include
the level at which the geometry is described and represented, the accuracy of imposing an inlet condition,
and the assumptions made in specifying other boundary conditions and modeling parameters.
Despite these limitations, numerical modeling can
be used in conjunction with other engineering analyses. When applied appropriately, numerical modeling
can provide invaluable information.
Application
Windboxes
Evaluate flow field within windbox,
determine expected air distribution
to combustion equipment, and
determine pressure losses
throughout system
Burners
Accurately determine boundary
conditions for furnace models,
evaluate flame and burner flow
characteristics
Overfire air ports
Accurately determine boundary
conditions for furnace models,
determine flow characteristics and
pressure losses through port
Pulverized
coal-fired boilers
Examine combustion characteristics
throughout the entire furnace;
evaluate fuel/air mixing, furnace
performance, heat transfer,
emissions and flow characteristics
Recovery boilers
Examine combustion characteristics
throughout the entire furnace;
evaluate fuel/air mixing, furnace
performance, heat transfer,
emissions, carryover and flow
characteristics within the furnace
Waste-to-energy
boilers
Examine combustion characteristics
of the entire furnace; evaluate
fuel/air mixing, furnace
performance, heat transfer,
emissions and flow characteristics
Selective catalytic
reduction systems
Determine inlet flow and
temperature distributions; evaluate
flow correction devices to meet
specified velocity and temperature
criteria
Wet scrubbers
Determine flow and pressure drop
conditions, evaluate scrubber
emission removal performance
Uses
Many applications for CFD and combustion modeling exist within the design and evaluation of steam
generators (or boilers) and related equipment. Numerical models of the flue gas and steam-water flows
Purpose
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
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The Babcock & Wilcox Company
verized coal flame, the first step is to adequately define the mathematical description.
The description is derived from first principles and
physical laws and is primarily based on a set of conservation relationships that result in a series of ordinary and partial differential equations (ODE and
PDE). The PDEs describe such things as the conservation of mass, momentum, energy, and others. In
addition, fundamental relationships are used to complete
the description of the system. The complete description
is made up of these PDEs and algebraic relationships.
Combustion modeling results in a particularly complex mathematical description of the overall process.
Each physical process involved in a combustion system is described individually; however, they interact
with other physical processes. This interaction creates
a coupling between all the descriptions of the individual processes.
To demonstrate this coupling, consider a simple diffusion flame. Fluid dynamics describe the process of
mixing two streams of reactants. The resulting reaction alters the constituents of the fluid, and heat release from the reaction increases the local temperature. The change in temperature and chemical composition has a strong effect on local density. This change
in density, in turn, has a strong effect on the fluid flow.
The system of processes, equations and interrelationships in a coal-fired boiler is far more complex, as
shown in Fig. 1. Five fundamental processes must be
addressed while providing for all key interactions:
1. Fluid transport: fluid motion, component mass
and energy transport in a turbulent mixing environment.
2. Particle transport: particle (in this case coal) or discrete phase motion in a fluid.
3. Homogeneous chemical reactions: gaseous species
combustion.
4. Heterogeneous chemical reactions: particle combustion.
5. Radiative heat transfer: radiative heat transfer in
a particle-laden participating media.
The second step to modeling the system is to use an
appropriate technique to solve the set of equations that
has been chosen to describe the physical system. It is not
possible to analytically solve the partial differential equations typically encountered in modeling combustion systems. Thus, the differential equations are discretized to
obtain a set of non-linear algebraic equations that can
be solved with known numerical techniques. The last
step in the process is to obtain the final solution.
Following is a more detailed description of each of
these processes.
Complex Coupling Phenomena
Between Subprocess Modules
Fluid Transport
Module
Gas Properties
Particle Velocities
Gas Velocities
Gas Velocities
Change in Gas
Composition and
Enthalpy
Particle Size
and Density
Particle Transport
Module
Number and Velocity
of Particles
Number and
Location of
Particles
Gas Velocities
and Pressure
Heterogeneous
Chemical Reaction
Module
Particle Size,
Temperature, and
Composition
Gas Composition
and Temperature
O2
NOX
CHX
CO2
Homogeneous
Chemical Reaction
Module
Radiation Heat
Transfer
Gas Composition
and Temperature
Radiative Heat
Transfer Module
Fig. 1 Model for the evaluation of pulverized coal-fired combustion based upon five fundamental processes.
6-4
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Fundamental equations
Combustion systems involve a complex interaction
of many different physical processes. This includes
fluid flow, heat transfer, chemical reactions, and potentially fluid-solid interactions. Some of the fundamental equations that describe these processes are
introduced in Chapters 3 and 4. Each of these processes is briefly described below in the context of numerical modeling.
Representation of turbulence
Large-scale combustion systems are typically characterized by turbulent, reacting flow conditions. The
effect of turbulent flow (turbulence) on combustion
processes is significant and must be considered to account for this effect. As yet, it is not practical to model
the full detail of the temporal and spatial fluctuations
that are associated with turbulence. As computing
resources become more powerful and our ability to
handle the enormous amount of information that will
be generated increases, it may one day be possible to
model the details of turbulent flow on industrial combustion systems. Until that day, a simplified model
representation of turbulence must be used.
Often, dealing with turbulence involves time-averaging the fundamental equations to eliminate the turbulent fluctuations and utilizing a separate turbulence
model to account for the influence of turbulent fluctuations on the flow. The fundamental equations can
then be solved for the mean quantities. Alternatively,
large scale turbulent fluctuations can be directly
solved while utilizing a turbulence model for the small
scale fluctuations. This technique, called large eddy
simulation (LES), is an important advancement in turbulence modeling but requires large computational resources compared to time-averaging.
Time-averaging is typically done either with
Reynolds averaging, the conventional time-averaging,
or with Favre averaging, a density-weighted averaging. The latter is better suited to handle the large density variations experienced in combustion applications.
Averaging of the conservation equations is accomplished by first assuming that instantaneous quantities are represented by mean and fluctuating portions
as shown in Equation 1. By allowing φ to represent
the dependant variable, this can be expressed as:
φ = φ + φ′
(1)
where φ is the instantaneous value, φ is the mean
portion and φ ′ is the fluctuating portion. Densityweighted averaging offers advantages over conventional time-averaging for combustion-related flows
since it simplifies the treatment of large density
changes. The density-weighted mean value, φ , is defined as:
ρφ
φ =
ρ
(2)
taneous density (ρ) and instantaneous value ( φ ) and
ρ is the time-averaged density. The instantaneous
value may then be written as the sum of the densityweighted average and the fluctuating value φ ′′ :
φ = φ + φ ′′
(3)
Equation 3 can be substituted into the transport
equation and then time-averaged to derive equations
in terms of the mean quantities. While it is not important to detail the process here, it is important to note
that the results produce additional terms in the resulting equations. These extra terms are known as
Reynolds stresses in the equations of motion and turbulent fluxes in the other conservation equations. Turbulence models are generally required to model these
extra terms, closing the system of equations.
Fluid flow and heat transfer
Gas-phase transport in combustion systems is governed by PDEs that describe the conservation of mass,
momentum, component mass and energy. The conservation of mass or continuity equation is discussed in
Chapter 3. The conservation of momentum is represented by the Navier-Stokes equations that are also
briefly discussed in Chapter 3. The Cartesian form of
Navier-Stokes equations, as well as the continuity
equation, can be found in the first four equations in
Table 2. In these four equations, ρ is the density, u, v,
and w are the velocity components, and x, y, and z are
the coordinate directions, µ is the dynamic viscosity, P
is the pressure, and g is the body force due to gravity.
The remaining conservation equations used to describe the gas-phase transport are the energy and component mass equations, expressed in Table 2 in terms
of specific enthalpy and component mass fraction. The
energy source terms are on a volumetric basis and represent the contribution from radiative heat transfer, −∇ i qr , energy exchange with the discrete phase particles, S Hpart, and viscous dissipation, SH. The component
mass source terms include the mean production rate
due to gas-phase reactions, Ri, and the net species production rate from heterogeneous reactions, Sipart .
Turbulence model
As previously mentioned, the process of time-averaging the conservation equations introduces extra
terms into the equations. Numerous turbulence models have been developed over the years to determine
the values of these extra terms. One of the most common and widely accepted approaches, known as the
Boussinesq hypothesis, is to assume that the Reynolds
stresses are analogous to viscous dissipation stresses.
This approach introduces the turbulent viscosity µ and
a turbulent transport coefficient σ into each equation.
Most of the turbulence models currently used for
fluid flow and combustion are focused on determining µ. In the k-epsilon model (one of the most widely
used and accepted), the turbulent viscosity is given as:
where ρφ is the time-averaged product of the instanSteam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
µt =
ρ Cµ k2
ε
(4)
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Table 2
Summary of Fundamental Differential Equations
General form of the transport equation:
Physical
Parameter
Transport
Coefficient
Γ
Continuity
1
0
X-Momentum
~
u
Y-Momentum
~
v
Z-Momentum
~
w
Enthalpy
~
H
Equation
Source
Term
S
Smpart
H
Turbulent
Energy
k
Dissipation
Rate
ε
k
~
Yi
Species
i
Other terms appearing in general form:
Nomenclature
Subscripts/Superscripts
S part
=
u, v, w
H
k
ε
=
=
=
=
=
=
=
=
=
=
=
e
t
x, y, z
i
~
−
part
g
c1, c2
Ri
Yi
6-6
source term accounting for exchange between
discrete phase particles and gas phase
velocity components
enthalpy
turbulent kinetic energy
turbulent kinetic energy dissipation
effective viscosity
turbulent viscosity
gravitational vector (x, y, z)
density
model constants
reaction rate
species mass fraction
=
=
=
=
=
=
=
effective
turbulent
directional component
ith chemical specie
Favre (density weighted) average
time-average
discrete phase particle component
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where Cµ is a model parameter, k is the turbulent kinetic energy, and ε is the turbulent kinetic energy
dissipation. The turbulent kinetic energy and the dissipation are determined by solving an additional partial differential equation for each quantity as given
in Table 2.
Discrete phase transport
Many combustion applications, including pulverized
coal, oil, black liquor and even wood involve small solid
or liquid particles moving through the combustion
gases. The combustion gases are described by assuming
that they represent a continuum, whereas a description
of the solid and liquid fuel involves discrete particles.
Describing the motion of this discrete phase presents
unique modeling challenges. There are two basic reference frames that can be used to model the transport of
the discrete phase particles, Eulerian and Lagrangian.
The Eulerian reference frame describes a control
volume centered at a fixed point in space. Conservation equations similar to the ones used for gas transport are used to describe the transport mass and energy of particles passing through this control volume.
The interaction of the particle phase and the gas phase
is accomplished through source terms in the respective transport equations.
The Lagrangian reference frame considers a control volume centered on a single particle. This approach tracks the particle on its trajectory as it travels through space and interacts with the surrounding
gases. The motion of a particle can be described by:
du part
= FD + Fg
mpart
(5)
dt
where mpart represents the mass of the particle, u part is the
particle vector velocity, t is time, and FD and Fg represent
drag and gravitational forces. Aerodynamic drag is a
function of the relative differences between particle and
gas velocities, Reynolds number and turbulent fluctuations in the gas. Consideration is also given for mass loss
from the particle due to combustion.1,2,3
Turbulence has the effect of dispersing or diffusing the particles. This dispersion effect has been identified with the ratio of the particle diameter to turbulence integral scale. For large particle sizes, particle
migration will be negligible, while at small sizes particles will follow the motion of the gas phase. This effect can be modeled using the Lagrangian stochastic
deterministic (LSD) model.4 The LSD model computes
an instantaneous gas velocity which is the sum of the
mean gas velocity and a fluctuating component. The
instantaneous gas velocity is used in computing the
right-hand side of Equation 5.
From the particle velocity the particle position, xpart,
is expressed as:
dx part
= u part
(6)
dt
This equation, along with appropriate initial conditions, describes the particle trajectory within the computational domain.
Combustion
Homogeneous chemical reactions Homogeneous or
gas-phase combustion involves the transport and
chemical reaction of various gas species. During this
process, heat is released and combustion product species are formed. As mentioned, a transport equation
for each of the chemical species involved is solved. The
main objective of a gas-phase combustion model is to
determine the mean production rate, Ri for turbulent
combustion.
Various methods can be used to determine the production rate. One common method known as the Eddy
Dissipation Combustion Model (EDM) was developed
by Magnussen and Hjertager5 and is based on the
eddy break-up model.6 This model assumes that the
rate of combustion is controlled by the rate of mixing
of the reactants on a molecular scale. The reaction rate
is given by:
Ri =
Wiω i
=
ρ
ε
Wi ∑ (vij′′ − vij′ ) C A
ρk
j=1
N rc
Term 1
Term 2
Yk
Wk
min
: k ∈ RCT j
′
(7)
vkj
Term 3
where Wi is the component molecular weight, vij′ and
vij′′ are the reactant and product stoichiometric coefficients for the ith species and the jth reaction, ε is the
turbulent dissipation, k is the turbulent kinetic energy,
CA is the model dependent mixing constant and RCTj
denotes the set of species that are reactants for the jth
reaction. Term 1 represents the stoichiometric coefficients in the particular reaction, Term 2 represents the
molecular mixing rate, and Term 3 limits the reaction
to the availability of individual reactants.
Magnussen7 later proposed the eddy dissipation concept (EDC) to overcome some limitations of other models. Specifically, the EDC model is applicable to nonpremixed and premixed combustion and can be used
with simplified or detailed chemistry to describe the
reaction process. A detailed description of the EDC
model can be found in Magnussen,7 Lilleheie et al.,8
Magnussen9 and Lilleheie et al.10
Magnussen’s premise is that chemical reactions occur in the fine structures of turbulence where the turbulent energy is being dissipated. Within these structures, molecular mixing occurs and the reactions can
be treated at the molecular level. The EDC model is
based on the concept of a reactor defined by a reaction
zone in these fine turbulence structures. The length
and time scales from the turbulence model are used to
characterize these fine turbulence structures. The reaction rates within these fine structures can be defined
with the specification of an appropriate chemical kinetics mechanism. These reaction rates are then related
to the average reaction rates in the bulk fluid and then
applied to the time-averaged transport equations.
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
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The Babcock & Wilcox Company
While some of the simpler models mentioned above
have been utilized extensively, the EDC provides a
means of more accurately treating the complexities of
coal combustion and modern combustion systems. This
is particularly important as the sophistication of the
heterogeneous combustion models improves.
Heterogeneous chemical reactions Simulation of coal
combustion must account for a complex set of physical
processes including drying, devolatilization, and char
oxidation. When a coal particle enters the combustion
zone, the rapid heatup causes moisture to evaporate.
Coal → Dry Coal + Water Vapor
The Carbon Burnout Kinetic (CBK) model has been
developed by Hurt et al.17 specifically to model the
details of carbon burnout. The model has a quantitative description of thermal annealing, statistical kinetics, statistical densities, and ash inhibition in the late
stages of combustion.
Radiative heat transfer
Radiative heat transfer in combustion systems is an
important mode of heat transfer and is described by
the radiative transfer equation (RTE):
(8)
( Ω i ∇ ) I (r, Ω ) = − (κ
λ
Evaporation is followed by devolatilization to produce
volatiles and char.
Dry Coal → Gaseous Fuel + Char
(9)
The volatiles consist of light gases (primarily hydrogen, carbon monoxide, carbon dioxide, and methane),
tars and other residues. The devolatilization rate can
not be adequately represented with a single first-order kinetic expression. Ubhayaker et al.11 suggested
a two first-order kinetic rate expression:
d
K i → α Gaseous Fuel
Dry Coal
i
i
+ (1 − α i ) Char i
i = 1, 2
(10)
where Kid is the kinetic rate of reaction and ai is the volatiles’ mass fraction. The kinetic rates are first-order in the
mass of coal remaining and are expressed in an Arrhenius
form. The total devolatilization rate becomes:
K
∑α
=
d
i
d
Ki
i
(11)
A more advanced model known as the Chemical
Percolation Devolatilization (CPD)12,13,14 has been developed and is described elsewhere. Unlike the empirical formulation of Ubhayaker et al.,11 the CPD model
is based on characteristics of the chemical structure
of the parent coal.
Following devolatilization the remaining particle
consists of char residue and inert ash. Char is assumed
to react heterogeneously with the oxidizer:
Char + Oxidant → Gaseous Products + Ash (12)
A basic approach to char oxidation was described
by Field.15 The effective char oxidation rate is a function of the kinetic rate of the chemical reaction and
the diffusion rate of the oxidizer to the particle.15,16
ch
K i → Gaseous Products
Char + Oxidanti
i
i = 1,2
2
+ Ash
(13)
σ
+ κ λ I bλ ( r ) +
4π
ch
=
∑K
i
6-8
ch
i
(14)
+ σ λ ) Iλ r ,Ω
(
)
∫ Φ (Ω′ → Ω) I (r , Ω′) dΩ′
λ
(15)
Ω
where κ λ is the spectral absorption coefficient, σ λ is
the scattering coefficient, and I bλ is the black body radiant intensity.
This equation describes the change in radiant in
tensity, I λ ( r,Ω ), at location r in direction Ω. The three
terms on the right-hand side represent the decrease
in intensity due to absorption and out-scattering, the
increase in intensity due to emission, and the increase
in intensity due to in-scattering.
Radiative heat transfer information is obtained by
solving the RTE (Equation 15) which is coupled with
the thermal energy equation by the divergence of the
radiant flux vector −∇iℑ. The divergence can be obtained from:
∞
∞
4π
∇ i ℑ = 4 ∫ κ λ Ebλ (T ) d λ − ∫ κ λ ∫ I λ ( Ω ) d Ω dλ
0
0
0
(16)
The two terms on the right-hand side account for
emission and absorption, respectively.
Discretization of equations
In the preceding sections, a mathematical description of combustion modeling, consisting of a fundamental set of algebraic relations and differential equations
of various forms, has been described. This includes
fluid transport, particle transport, combustion and radiative heat transfer. Because this system of equations
is too complex to solve with analytic methods, a numerical method must be employed. The methods of
discretizing the fluid transport and radiative heat transfer are of particular interest and are presented here.
Finite volume approach
It should be recognized that many of the partial differential equations are of a single general form as provided in Table 2 and can be expressed as:
∂
∂
∂
∂
( ρφ ) +
( ρ uφ ) +
( ρ vφ ) +
( ρ w φ )
∂z
∂y
∂x
∂t
where Kich is the effective char oxidation rate. The total char oxidation rate is expressed as:
K
λ
=
∂ ∂φ ∂ ∂φ ∂ ∂φ
+
Γφ
+ Sφ
+
Γφ
Γφ
∂x ∂x ∂y ∂y ∂z ∂z
(17)
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
The Babcock & Wilcox Company
Since many of the equations share this form, a
single method can be used to solve all of the associated equations. Most of these methods involve dividing the physical domain into small sub-domains and
obtaining a solution only at discrete locations, or grid
points, throughout the domain. The well-known finite
difference method is one such method. Another very
powerful method, that is particularly suited for use in
combustion modeling, is the finite volume approach.
The basic idea of the finite volume approach is very
straightforward and is detailed in Patankar.18 The
entire domain is divided into non-overlapping control
volumes with a grid point at the center of each. The
differential equation in the form of Equation 17 is integrated over the entire control volume and after some
rearrangement becomes:
(18)
Carrying out the integrations, the resulting equation is:
∂
( ρφ ) ∆ V +
∂t
∑ (C
f
f
φf − Df (φ )) = Sφ ∆ V
(19)
where ∆V is the volume of the control volume, Cf is
the mass flow rate out of the control volume, Df is the
diffusive flux into the control volume, and the summation is made over all the control volume faces, f. The
temporal derivative in the first term of Equation 19
can be expressed using a first-order backward difference scheme:
φ t +∆t − φ t
∂
( ρφ ) = ρ t
∆t
∂t
(20)
The mass flow rate Cf is determined from the solution of the mass and momentum equations while the
diffusive flux Df is based on the effective diffusivity
and the gradient at the control volume face. Combining Equations 19 and 20 with the definitions of Cf and
Df and an interpolated value for φf results in an algebraic expression in terms of the dependant variable
φi at grid point i and the neighboring grid points. This
is expressed as:
ai φi =
∑a
n
n
φn + bi
(21)
where ai and an are coefficients for the control volume
and its neighbors respectively and bi represents the
remaining terms. The number of neighboring values
that appear in Equation 21 is a function of the mesh,
the method used to interpolate the dependant variable to the control volume face, and the method used
to determine gradients at the control volume face.
Following this procedure for each grid point in the
entire domain produces a coupled set of algebraic
equations. This set of equations can be solved with an
appropriate method from linear algebra. Many differ-
ent techniques are possible and can be found in a reference on numerical methods.
There are two advantages to the finite volume approach. First, the dependant variable in the resultant
discretized equation is a quantity of fundamental interest such as enthalpy, velocity or species mass fraction, and the physical significance of the individual
terms is maintained. Second, this approach expresses
the conservation principle for the dependant variable
over a finite control volume in the same way the conservation equation expresses it for an infinitesimal
control volume. By so doing, conservation is maintained over any collection of control volumes and is
enforced over the entire domain.
Discrete ordinates method
Several radiative heat transfer models have been
developed and many are described by Brewster19 and
Modest.20 A recent review of radiative heat transfer
models21 states that the discrete ordinates method
coupled with an appropriate spectral model provide
the necessary detail to accurately model radiative heat
transfer in combustion systems. This is one of the most
common methods currently used to model radiative
heat transfer.
The discrete ordinates method (DOM)22,23 solves the
radiative transport equation for a number of ordinate
directions. The integrals over direction are replaced
by a quadrature and a spectral model is used to determine radiative properties of κ and σ. This results
in a set of partial differential equations given by:
∂I
∂I
∂I m
+ ηm m + ξm m =
∂z
∂y
∂x
σ
− (κ + σ ) I m + κ I b +
Sm
4π
µm
(22)
where µm , ηm , ξm are the direction cosines of the chosen intensity Im and Sm is the angular integral. This
set of equations is solved by a method outlined by
Fiveland22 to find the radiative intensities throughout
the combustion space. The source term for the energy
equation can be found by summing over all directions:
∇ i qr = 4 κ σ T 4 − κ ∑ wm′ I m′
m′
(23)
Mesh generation
Once discretized, the transport equations must be
solved at individual points throughout the domain.
This requires that the individual points be specified
and the relationship between other points be identified. Displaying the points along with the connections
between them creates a pattern that looks something
like a woven mesh. The process of creating the mesh
is therefore known as mesh generation.
Mesh generation is an important and often challenging step in the overall modeling effort. The first
criterion in mesh generation is to accurately represent
the geometry being modeled. Secondly, adequate detail must be placed throughout the domain to obtain
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
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The Babcock & Wilcox Company
an accurate solution. Other criteria include mesh
quality and total mesh size. A discussion on these criteria can be found elsewhere.24
Cell types
The basic unit in a mesh is the control volume or
cell. The cells are arranged such that they cover the
entire domain without overlapping. Common cell types
are shown in Fig. 2. The mesh may be made of a single
cell type (homogeneous mesh) or possibly a combination of different types (hybrid mesh).
Structured mesh
Structured meshes consist of cells placed in a regular arrangement such that adjacent cells can be identified simply by their order in a list. Fig. 3 shows how
the neighboring cells are identifiable simply by
incrementing an index that is typically aligned with
the coordinate directions. This greatly simplifies the
task of retrieving information from neighboring cells.
For simple geometries, a structured mesh is both simple
to generate and efficient when solving the problem.
However, complex geometries highlight particular
challenges with this approach. This is illustrated in
Fig. 4. Two common techniques of dealing with irregularities in geometry are 1) a cartesian stair-stepped
mesh and 2) body-fitted mesh. The stair-stepped mesh
can place cells in areas outside of the domain and
approximates boundaries by stair-stepping the mesh
(Fig. 4a). The cells outside of the domain are maintained as part of the mesh structure but are unused
during the computation. The body-fitted mesh follows
geometric features and the cell shape changes to accommodate these physical features (Fig. 4b).
Slight variations of the simple structured mesh can
be used. Block structured meshes provide more geometric flexibility since the entire mesh is a composite
of smaller structured meshes.
Unstructured mesh
An unstructured mesh provides the maximum flexibility for complex geometries. While the ease of obtaining neighboring cell information has been lost, the
ability to place cells anywhere in the computational
domain increases the ease by which the geometry can
be accurately represented. Fig. 4 compares an unstructured mesh with two structured mesh approaches. With an unstructured mesh approach there
is greater control over the level of detail in the mesh
for different parts of the domain.
Embedding and adaption
More detail can be obtained in portions of the domain through increasing the mesh resolution by embedding more cells. This is accomplished by splitting
an existing cell in some fashion to create additional
cells. By splitting a cell in each of the cell’s parametric
coordinate directions, a single hexahedron would become
eight. This greatly increases the resolution in this region.
Often it is not possible to know where resolution is
needed a priori. The process of adaption can be used to
increase the resolution based on the actual solution. For
example, high discretization error may often be related
6-10
to high solution gradients across cells. In this case the
velocity gradient from the solution can be used to discover where more cells are needed. This is an especially
powerful tool when computational resources are limited.
Example applications
Wet scrubbers
Situation The two-phase flow in a wet flue gas desulfurization (WFGD) scrubber tower is a complex process involving spray atomization, liquid entrainment,
droplet disengagement and phase separation. The
physical arrangement of a basic WFGD scrubber module is shown in Chapter 35, Fig. 2. With a tray, there
is a bubbly froth due to countercurrent flow of liquid
and gas with holdup of liquid on the tray. The various two-phase flow regimes complicate the calculation
of pressure drop and gas velocity distribution in a wet
scrubber. Prediction of two-phase flow is essential since
liquid residence time and total interfacial liquid/gas
area are important factors in determining the amount
of SO2 absorption. Therefore, The Babcock & Wilcox
Company (B&W) has implemented a multi-dimensional two-phase flow model for wet scrubbers based
on CFD analysis.
A multi-dimensional hydraulic model solves separate equations for mass and momentum for both the
liquid and gas phases. An interfacial drag law calculates the resistance of liquid to the gas flow and vice
versa. These interfacial drag laws depend primarily
on droplet diameter. However, alternate drag equations can be implemented in the multi-dimensional
model for the various two-phase flow regimes. By using the fundamental relations for interfacial drag, the
model can calculate separate three-dimensional velocity fields for the liquid and gas phases. Both liquid and
gas momentum equations share a common static pressure field.
Two-Dimensional
Elements
Three-Dimensional
Elements
Triangle
Tetrahedron
Pyramid
Quadrilateral
Hexahedron
Prism or Wedge
Fig. 2 Cell or control volume types used in numerical modeling grids
or meshes.
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
The Babcock & Wilcox Company
The numerical model is used as an analysis tool to
compare and contrast various design configurations
for wet scrubbers. The design features considered by
the model include:
1.
2.
3.
4.
5.
6.
7.
an overall cylindrical geometry,
a tray model with baffles and porous plates,
nozzles located at various elevations,
conventional or interspatial headers,
separate air and water outlets,
multiple mist eliminator heights and elevations,
conical or straight inlets with or without inlet awnings, and
8. cylindrical or conical outlet ducts.
These design features are adjustable, thereby permitting a wide range of scrubber configurations for utility boiler applications. The boundary conditions at the
gas inlet and spray nozzles can be adjusted to cover
all scrubber gas velocities and liquid mass fluxes.
Analysis The model was initially validated against
hydraulic data from a one-eighth scale laboratory wet
scrubber. By comparing model predictions to scale
model pressure drop data, confidence was built in the
two-phase flow modeling capability. Once validated,
the model was tested for full-scale application by comparing results to company design standards. Although
the model compared favorably to data and standards,
absolute prediction of wet scrubber performance is not
the primary purpose. Instead, comparative studies are
done to predict relative performance of various design
options. The numerical model excels at looking at new
design configurations that fall outside of existing design standards.
Results As discussed in Chapter 35, Sulfur Dioxide (SO2) Control, the flue gas enters the side of the
scrubber tower and turns upward to flow through the
tower while the reagent slurry flows countercurrent
downward, removing SO2. A uniform gas velocity profile across the tower diameter maximizes removal efficiency as the reagent slurry and flue gas flow are
uniformly mixed. Fig. 5 shows the CFD modeling results as vertical velocity profiles at several plains
through the tower, and illustrates the impact of the
B&W tray design in producing uniform flue gas flow
i-1, j+1
i, j+1
i+1, j+1
i-1, j
i, j
i+1, j
a) Stair-Stepped
b) Body Fitted
c) Unstructured
i-1, j-1
i, j-1
i+1, j-1
Fig. 3 Unit cell identification in a rectangular arrangement.
Fig. 4 How mesh or grid structure approximates geometric features.
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
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The Babcock & Wilcox Company
through the unit. Fig. 5a shows the case without the
tray. The lowest profile shows how non-uniform flow
develops as the high velocity flue gas is introduced into
the tower, is decelerated, and makes a sharp rightangle turn to flow up the tower. In the absence of a
tray, the high velocity (red) and low velocity (blue)
regions persist as the flue gas moves through the
middle of the tower (middle velocity profile) entering
the first level of spray headers. Some of the non-uniformity persists even up to the mist eliminators. With
the addition of the tray (Fig. 5b), the large high and
low velocity regions are effectively eliminated. The resulting more-uniform velocity profile and the gas/reagent mixing on top of the tray permit higher levels
of SO2 control at reduced slurry recirculation rates.
This model has also been used to explore design
changes to meet site-specific new and retrofit requirements.25 These have included alternate flue gas exit
geometries, flue gas inlet conditions, tower diameter
transitions, header locations, slurry recirculation rates
or other factors while still achieving the desired performance. It has also been used to investigate internal design alternatives to boost performance and reduce pressure drop.
Popcorn ash
Situation Popcorn, or large particle, ash forms under certain conditions from the combustion of coal and
is light, porous, irregularly shaped, and often forms
in the upper boiler furnace or on the convective heat
transfer surface. This ash can plug the top catalyst
layer in selective catalyst reduction (SCR) NOx control systems, increasing pressure drop and decreasing
catalyst performance. Modifications to both the economizer outlet hoppers and the ash removal systems can
increase ash capture to address this situation.
Accurately predicting how the popcorn ash behaves
within the economizer gas outlet requires detailed
knowledge of the aerodynamic properties of the ash
particles and sophisticated modeling techniques. Key
ash properties include the particle density, drag coefficient, coefficients of restitution, and its coefficient of
friction with a steel plate. CFD models involve solving the gas flow solution, then calculating the particle
trajectories using B&W’s proprietary CFD software.
Analysis Most CFD programs that handle particleto-wall interactions are not adequate to accurately
predict the complex behavior seen in the popcorn ash
physical experiments. These deficiencies have been
remedied by adding capabilities to B&W’s proprietary
CFD software. First, the coefficient of restitution is
separated into its normal and tangential components.
Next, a particle-to-wall friction model is used for particles sliding along the wall and experiencing a friction force proportional to the coefficient of friction
measured in the physical tests. Also, the ability to set
Fig. 5 Effect of B&W’s tray design on gas velocities through a wet flue gas desulfurization system – numerical model results on a 650 MW absorber.
6-12
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
The Babcock & Wilcox Company
Gas and Particle Inlet
Economizer Gas Outlet
Gas Outlet Flue
Percent of Ash Particles Captured
100
90
80
70
60
Baseline
50
40
Economizer
Hoppers
Baffle Arrangement
Increasing Density
Fig. 8 Comparison of sensitivity to particle density between base
case and baffled numerical models.
up user-defined planes through which flue gas could
flow, but off which particles would reflect, has been
developed to accurately model particle interaction with
wire mesh screens.
Results The numerical models used in popcorn ash
analysis normally extend from just above the bottom
of the economizer (providing a reasonably uniform
inlet flow distribution) to just beyond the opening of
the economizer gas outlet flue (see Fig. 6). For this
sample geometry, the baseline particle trajectories from
the numerical model are shown in Fig. 7. Over the ash
particle size range typical of this application, 20 to 50
% of the particles (Fig. 8) pass through the economizer
hopper into the downstream equipment depending on
particle size, potentially causing the plugging problems in the SCR or air heater. Several solutions were
evaluated for this sample geometry including a design
that relies on the aerodynamic separation of the particles from the flue gas and another design that involves physical barriers to the particles using a wire
mesh screen. The aerodynamic solution was selected
and a baffle was designed and installed. The general
baffle location and the particle trajectories from the
numerical model are shown in Fig. 9. The fully threedimensional model predicted a dramatic improvement
in the particle collection efficiency with more than
90% of particles collected for the range of particle sizes
evaluated and virtually 100% above a certain cut size
Fig. 7 Base case particle trajectories from popcorn ash evaluation.
Fig. 9 Particle trajectories from popcorn ash evaluation numerical
model with baffle.
Surfaces for Ash Removal
Fig. 6 Profile of popcorn ash evaluation numerical model.
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
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The Babcock & Wilcox Company
(see Fig. 8). Using numerical models also permitted an
optimization of the baffle position to achieve the greatest capture rate while minimizing the pressure drop.
In other cases, where an aerodynamic solution is not
obtainable, barriers made from wire mesh screens have
been recommended. In these cases, the screen openings
would be smaller than the openings in the catalyst.26
Kraft recovery boilers
Situation A kraft process recovery boiler, as its
name implies, recovers energy and chemicals from
black liquor, a byproduct of the papermaking process
(see Chapter 28). Air and liquor delivery systems control several complex and interacting combustion processes (black liquor spray, deposition and burning on
furnace walls, char bed burning, smelt flow) that affect boiler performance (capacity, reliability, emissions,
chemical recovery, and energy efficiency). Good air jet
penetration and effective mixing of secondary and tertiary air are desirable for complete combustion and reduced emissions of carbon monoxide (CO) and hydrogen sulfide. Distribution of air to three or more air injection levels produces fuel-rich conditions in the lower
furnace that are desirable for smelt reduction and reduced emissions of NOx. Flow and temperature uniformity in the furnace minimize carryover of inorganic
salts, provide an even heat load, and minimize deposition on convection surfaces at the furnace exit. Uniform
distribution of liquor spray ensures adequate drying
of liquor spray, minimum carryover, and stable char
bed combustion.
Analysis Detailed combustion models for black liquor have been developed27,28 and are used in conjunction with CFD modeling. Black liquor combustion is
simulated for individual droplets as they heat up and
burn in suspension. Stages of combustion along a
single trajectory include drying, devolatilization, char
burning, smelt oxidation, and molten salt formation.
The trajectories of thousands of particles determine
the distribution of liquor spray in the furnace as
shown in Fig. 10 for a range of droplet sizes. Combustion processes on the walls and char bed are also simulated with particle deposition, char burning, smelt flow
and char accumulation. These capabilities are useful
for evaluating the effect of air and liquor delivery systems on combustion processes in the furnace and for
predicting the quantity and composition of particulate
that leaves the furnace.
Results Fig. 11 shows gas velocity vectors at selected
planes that cross-sect the furnace. The char bed shape
is approximated so its impact on flow in the lower furnace can be evaluated with the model. Jets of air penetrate across the furnace to produce uniform upward
flow and effective mixing with combustion gases.
Three-dimensional computer-generated images can be
examined interactively to help visualize air jet penetration and the interaction of jets from neighboring
air ports. Gas temperature distribution predictions,
shown in Fig. 12, are used to analyze heat transfer
in the furnace and convection pass. Other information such as char bed surface temperature and burning rates, gas species concentrations (i.e., O 2, CO,
NOx), and wall heat flux distribution are also gener6-14
ated. Results are used by boiler designers and operators to evaluate air system designs, liquor spraying
systems, liquor firing capacity, char bed combustion
instabilities, convection pass fouling, furnace wall
corrosion, and CO and NOx emissions. The results
shown were created by B&W’s proprietary CFD software.
Wall-fired pulverized-coal boiler furnaces
Situation Within a staged, wall-fired furnace, the
mixing between the upward-flowing partially-reacted
fuel and the jets from the overfire air (OFA) ports is a
complex, three-dimensional process. This mixing process can have a significant impact on the distribution
and magnitude of CO emissions. While proprietary
technology standards can initially be used to set effective OFA port arrangements for a staged combustion system, numerical modeling is often used to confirm this design and suggest alternatives to improve
performance. Modeling is especially useful when there
are physical obstructions that prevent OFA port placement in the optimal locations. In these circumstances,
compromises must be made and determining the best
available port layout may not be obvious.
Analysis In this example, a numerical model has
been used to predict the steady-state flow, heat transfer, and combustion processes within a wall-fired pulverized-coal boiler being upgraded with low NOx burners and OFA ports. As part of the design process, many
Fig. 10 Liquor spray distribution in the lower furnace of a recovery boiler.
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
The Babcock & Wilcox Company
configurations (number and location) of OFA ports
were modeled, and the results were compared to determine the best port configuration. Boiler geometry,
including a portion of the convection tube banks, was
approximated using a collection of control volumes,
also called a computational grid or mesh, for one of
the configurations considered (see Fig. 13). Local refinement of the mesh was used as needed to better
resolve the solution, such as within the OFA region.
The coal analysis and boiler operating conditions including burner and OFA port settings were used to
set inlet and boundary conditions for the model.
Results The model produces tabular (integrated
species concentrations, gas temperatures, gas flow
rates, emissions) and graphical (color contour plots of
gas speed, gas temperature, or species; coal particle
trajectories; gas streamlines) output that are used to
evaluate each configuration. As an example, Fig. 14
compares contours of CO concentration throughout
the boiler for two different OFA arrangements for a
775 MW wall-fired pulverized coal boiler. Arrangement 1 has the OFA ports directly above the burner
openings and directly across from the ports on the
opposing wall, while arrangement 2 uses horizontally
offset ports which provide better mixing and cross-sectional coverage. As shown in the figure, OFA arrangement 2 results in lower CO concentrations in the upper furnace than the OFA arrangement 1 (15% lower
at the arch, and 23% lower at the furnace exit). The
results for this example were created by the B&Wdeveloped computer software.
The numerical model described above also provides
Fig. 11 Velocity vectors at selected planes that cross-sect a recovery furnace – horizontal planes at primary, secondary and tertiary levels
(left); vertical planes at center of furnace (center and right).
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
6-15
The Babcock & Wilcox Company
a wealth of other information for the boiler designer.
Fig. 15 provides a flue gas temperature profile
through the center of the furnace and a horizontal
section profile across the furnace exit gas pass. As
noted in Chapter 19, the average or integrated furnace exit gas temperature (FEGT) is a critical design
parameter in boiler sizing for performance while mitigating slagging and fouling. Flow areas with excessively high local temperatures identified by such numerical models may be more prone to slagging in the
furnace or fouling in the convection pass. Additional
parameters of interest provided by the numerical
models include, but are not limited to, local velocity
profiles for performance enhancement and erosion
evaluation, furnace heat flux profiles for steam-water circulation evaluation,29 variation in local chemical constituents such as oxygen for studying combustion optimization, and many others. Numerical boiler
furnace models continue to evolve and more closely
simulate field conditions. While current models as of
this publication are not sufficient alone for final boiler
design, they offer an additional tool to: 1) aid in design optimization, 2) address non-standard conditions,
3) evaluate the relative impact of fuel changes, 4)
highlight areas for design improvement, 5) help investigate the root causes of unusual field observations,
and 6) screen potential approaches to address design
issues. Numerical modeling will become an increasingly important tool in boiler engineering.
Windbox
Situation The problems encountered in a windbox
analysis deal with air flow imbalance and/or excess
system pressure loss. Difficulties in tuning burner
combustion performance can be frequently attributed
to the flow distribution within the windbox. Therefore,
creating a uniform flow distribution to each burner is
highly desirable to obtain optimum emissions performance. The flow imbalance problem can be between the
front and rear walls of a furnace, compartments in a
Fig. 12 Gas temperature contours at vertical planes at the center of a recovery boiler furnace.
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Fig. 13 Computational mesh on wall-fired boiler surface – full mesh (left) and enlarged view of upper burners and OFA ports (right).
windbox, or individual burners and/or ports. Any imbalance or maldistribution causes non-uniform air introduction into the furnace. This imbalance can lead to poor
furnace combustion and potentially higher gas emissions. The system can be modeled to reduce air flow imbalance and reduce system pressure loss, which allows
more flexibility in combustion tuning of a single burner.
Analysis A computer model that describes the details of the windbox (walls, bends, etc.) must first be
built (see Fig. 16). This requires both flow and geometric design information. Care must be taken to ensure accurate representation of the entire air flow path
including any significantly-sized internal obstructions.
The inlet of the model is usually the outlet of the air
heater. This is done for two reasons. An accurate and
simple air flow distribution is usually known at this
location, and it is far enough upstream to capture all
the resulting flow disturbances. The burners and ports
must also be modeled accurately to ensure precise flow
results. Boundary conditions are the final and very
important step, to be placed accurately in the model
to exactly represent the windbox/duct flow conditions.
Results Once the model has been built, it is checked
to make sure grid characteristics are acceptable. This
step ensures that there is enough grid resolution to accurately represent the flow conditions in any area (i.e.,
turns, ducts, plenums) and around any objects (i.e., turning vanes, perforated plates, air foils). The model is then
run using CFD software. These calculations yield an
accurate representation of the air flowing in the space
inside the ducts and windbox.
Fig. 17 shows the plan view of the secondary air
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Fig. 14 Carbon monoxide concentration contours at various elevations – comparison between two OFA arrangements.
ducts and the windbox with the velocity-vector flow
field at the middle of the duct system. Each arrow provides the direction and the magnitude (arrow length)
of the local air flow. Fig. 18 is Section A-A through the
windbox plan view of Fig. 17, looking into the furnace. Fig. 18a shows the original design which included a simple windbox with a large horizontal perforated plate intended to provide uniform flow to the
bottom three burner rows. The numerical model results indicated a very high velocity zone (large red
arrows) in the upper windbox which forced much of
the air to bypass the upper burner row and over-supply the bottom two rows. The 30% flow variation between highest and lowest flow burners was too high
and could lead to poor emissions performance and incomplete combustion. Several numerical modeling iterations using CFD computer software suggested the
optimized solution shown in Fig. 18b. Eliminating the
original large horizontal perforated plate plus adding
two turning vanes, a vertical solid plate in the top of
the windbox, and ten short vertical perforated plates
6-18
dramatically improved the burner-to-burner flow distribution to within normal design tolerances.
The numerical model permitted testing of ten alternatives prior to selecting the low-cost solution which
would also achieve the desired performance results.
SCR systems with economizer bypass
Situation A selective catalyst reduction (SCR) system with an economizer bypass is designed to reduce
NOx emissions by a chemical reaction between NOx and
added ammonia in the presence of a catalyst. (See
Chapter 34.) To optimize the chemical reaction at low
and intermediate loads, an economizer bypass is
needed to increase the temperature of the economizer
exit flue gas. The ammonia injection grid (AIG) distributes ammonia uniformly into the exit gas for the
correct molar ratio of ammonia to NOx. Finally, the
catalyst is used to aid in the chemical reaction.
CFD modeling of the SCR system includes full-scale
representation, multiple temperature gas paths, heat
absorption modeling capability, multi-point testing
Steam 41 / Numerical Modeling for Fluid Flow, Heat Transfer, and Combustion
The Babcock & Wilcox Company
Fig. 15 Numerical modeling results of furnace temperature profiles for a typical 775 MW bituminous coal-fired boiler.
over an entire grid plane or discrete point testing,
chemical species tracking, and rapid flow device testing for proper mixing, flow distribution, and minimal
pressure drop.
Analysis The numerical model is constructed and
tuned for actual conditions of an unmodified system
according to existing economizer exit flue gas conditions. Drawings of future construction and design of
the flue work, AIG, and information supplied by the
catalyst vendor are used to establish a base operating condition. The chemical species are tracked for accurate mixing of ammonia and NOx reagents. The data
collected at specific planes in the grid are evaluated
against established criteria for efficient NOx removal
such as velocity distribution, ammonia-to-NOx ratio,
and average temperature entering the catalyst. Internal corrective devices such as turning vanes, flow distribution diverters, static mixers and porous plates, are
used to precondition the flue gas to meet the criteria
for NOx reduction. Grid refinement may be necessary
to accurately predict the physical characteristics of in-
ternal objects, flue bends and flow distribution devices.
Results One such design involves a unit operating
at three loads with an economizer bypass taken off the
reheat side of the back wall convection pass to achieve
adequate remix temperatures for the chemical reaction. For bypass operation, three gas paths are considered in the design process: superheat, reheat, and
economizer bypass. Because of physical constraints
and potential changes in the economizer outlet temperature with reheater or superheater bypass arrangements, a bypass around the economizer surface
was selected. Fig. 19 shows the velocity flow field for
the numerical evaluation from the superheater
through the exit of the SCR. Fig. 20 shows the detailed
velocity field and physical geometry at the bypass location. A key issue was the complete mixing of the high
temperature bypass flow with the main flue gas flow
exiting the economizer in order to provide an acceptably uniform flue gas temperature entering the SCR
catalyst. To achieve the desired mixing, a series of
turning vanes and mixing devices for the economizer
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Fig. 16 Numerical model of 1100 MW coal-fired boiler windbox and secondary air system.
Fig. 17 Plan view of secondary air system flow model results – velocity vectors.
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outlet hopper were developed with the aid of the numerical model to provide the high velocity bypass jet
that would adequately penetrate the main economizer
outlet flue gas flow. Success in the design iteration process was achieved when the velocity profile entering
the AIG and the temperature profile entering the SCR
achieved the specified uniformity.
Waste-to-energy systems
Situation Effective combustion of municipal solid
waste (MSW) and biomass fuels has become more challenging over time as emissions regulations have been
tightened and the variation of fuel characteristics has
increased. As part of the process to meet these more
demanding requirements, numerical modeling has
become a routine engineering tool used in the installation of emissions control systems such as selective
non-catalytic reduction (SNCR) NOx control systems
(see Chapter 34), refinement of the design and operation of the stoker/grate combustion system with auxiliary burners (Chapter 16) and overall design of the
boiler (Chapters 29 and 30). Control of the flue gas in
the furnace in terms of chemical species, particles, temperature and flow is important where a good furnace
design results in more uniform velocity profiles. High
velocity regions can cause: 1) increased wall deterioration from the hot corrosive flue gas with premature
component replacement, 2) sub-optimal emissions control without adequate residence time at temperature,
and 3) incomplete burnout of the fuel.
Analysis A numerical evaluation of the furnace was
conducted as part of the design of a 132 ton per day
(120 tm/d) mass burn MSW stoker-fired system. Fig.
21 shows the sectional side view of a European wasteto-energy plant design supplied by B&W. A complete
flow field evaluation of the furnace design using numerical modeling was conducted to determine the
physical furnace modifications necessary to minimize
high velocity areas.
Results Fig. 22 shows the numerically evaluated
velocity vector flow field before (a) and after (b) the
design changes. The flow field is represented by arrows that show the local velocity direction and magnitude (arrow length). In Fig. 22a, a high velocity jet
region impinges on the top of the grate, and high velocity regions exist along the first (up) and second
(down) pass furnace walls. The addition of noses at the
bottom of the first pass and the top of the second pass
walls as shown in Fig. 22b significantly reduce the velocities throughout the furnace and reduce the peak
velocity regions near the grate and along the furnace
walls. The more moderate velocity in the first pass
results in less particle impingement and longer overall residence time. The maximum velocity in the second pass is reduced from 13 m/s to 9 m/s (42.6 to 29.5
ft/s), which reduced the thermal load on the back wall
of the second pass.
Advanced burner development
Situation Advanced burner and combustion system
development are increasingly relying on the use of
numerical modeling as an integral tool in the quest
for new hardware and concepts to improve the NOx
reduction performance of coal-fired burners. While traditional experimental methods of burner development
have been able to dramatically reduce NOx emission
levels from bituminous pulverized coal burners below
0.4 lb/106 Btu (492 mg/Nm3), increasingly more stringent emission reduction regulations are pushing specified combustion emission limits to well below 0.15 lb/
106 Btu (184 mg/Nm3). To develop such equipment, it
is becoming even more necessary to understand not
only what is happening at the macro-level (which can
be observed and tested) but also with small-scale interactions deep within the flame and initial ignition
zone. Numerical modeling studies of detailed burner
designs offer a valuable tool by combining fundamental knowledge of combustion with complex fluid and
thermal dynamics to better understand how to further
reduce NOx emissions and improve combustion efficiency. When combined with small-scale and largescale tests with advanced test instrumentation, nu-
Fig. 18a Before – high velocity zone in upper windbox (red arrows)
under-supplies top row of burners and over-supplies other rows.
Fig. 18b After – removal of the large horizontal perforated plate plus
the addition of two turning vanes and 10 small vertical perforated
plates provides more uniform flow to the burners.
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Fig. 19 Velocity field numerical model output – SCR system from the boiler convection pass to SCR outlet. The high velocity, high temperature
bypass flow is visible as high jet penetration is needed to achieve good thermal mixing by the SCR inlet. See also Fig. 20.
Fig. 20 SCR detail at the bypass flue location – turning vanes and mixing devices provide adequate bypass flow penetration for optimal mixing.
6-22
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Flue
Gas
Outlet
Fuel
Feed
Hopper
merical modeling is helping identify techniques to
burn fuels more cleanly.
Analysis Numerical models, with enhanced resolution (see Fig. 23), have been developed that accurately
represent the critical details of physical burners. Experimental studies provide inlet flow boundary conditions that can offer the starting point for the analysis. These are combined with the results from fundamental studies of fuel devolatilization, burning of gaseous species, gaseous diffusion, combustion of solid
material and other factors to develop numerical models that begin to simulate the complex combustion process in commercial coal-fired burners. Physical testing, validation and adjustments to the model can produce numerical tools that can be used for advanced
burner development.
Results Fig. 24 shows detailed gas velocity fields for
an advanced burner design. In this case, analysis of
the numerical model predictions helped identify the
value of an additional burner air supply zone to induce recirculation of nitrogen oxide (NO) formed in
the outer oxygen-rich portions of the flame into the
fuel-rich internal recirculation zone where NO is reduced. See Chapter 14 for further discussion of coalfired burners and combustion systems.
Grates
Fig. 21 Sectional view of a 132 t/d (120 tm/d) mass burn municipal
solid waste (MSW) boiler for European application.
a) Before design changes
b) After guide nose additions
Fig. 22 MSW boiler from Fig. 21 showing flow field before and after the addition of guide noses in the furnace wall.
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Fig. 23 Detailed numerical model evaluation grid for an advanced coal burner.
Fig. 24 Gas velocity model for the coal burner shown in Fig. 23.
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References
1. Wallis, G.B., One-Dimensional Two-Phase Fundamental, McGraw-Hill Company, New York, New York,
1969.
2. Crowe, C.T., Smoot, L.D., Pratt, D.T., Eds., “Gas Particle Flow,” Pulverized Coal Combustion and Gasification,
Plenum Press, New York, New York, 1979.
3. Bailey, G.H., Slater, I.W., Eisenblam, P., “Dynamics
Equations and Solutions for Particles Undergoing Mass
Transfer,” British Chemical Engineering, Vol. 15, p. 912,
1970.
4. Milojevic, D., “Lagrangian Stochastic-Deterministic
(LSD) Predictions of Particle Dispersion in Turbulence,”
Journal of Particles and Particle Systems Characterization, Vol. 7, pp. 181-190, 1990.
5. Magnussen, B. F., and Hjertager, B. H., “On mathematical modeling of turbulent combustion with emphasis on soot formation and combustion,” Proceedings of the
16th International Symposium on Combustion, 719-729,
The Combustion Institute, Pittsburgh, Pennsylvania, 1976.
6. Spalding, D. B., “Mixing and Chemical Reaction in
Steady Confined Turbulent Flames,” Proceedings of the
13th International Symposium on Combustion. The Combustion Institute, Pittsburgh, Pennsylvania, 1971.
7. Magnussen, B. F., “On the structure of turbulence and
the generalized Eddy Dissipation Concept for turbulent
reactive flows,” Proceedings of the 19 th American Institute of Aeronautics and Astronautics Aerospace Science
Meeting, St. Louis, Missouri, 1981.
8. Lilleheie, N. I., Ertesvåg, I., Bjosrge, T., et al., “Modeling and Chemical Reactions,” SINTEF Report STF1sA89024, 1989.
9. Magnussen, B. F., “The Eddy Dissipation Concept,”
XI Task Leaders Meeting: Energy Conservation in Combustion, IEA, 1989.
10. Lilleheie, N. I., Byggstøyl, B., Magnussen, B. F., et
al., “Modeling Natural Gas Turbulent Jet Diffusion Flames
with Full and Reduced Chemistry,” Proceedings from the
1992 International Gas Research Conference, Orlando,
Florida, November 2-5, 1992.
11. Ubhayakar, S.K., Stickler, D.B., Von Rosenburg,
C.W., et al., “Rapid Devolatilization of Pulverized Coal in
Hot Combustion Gases,” 16th International Symposium
on Combustion, The Combustion Institute, Pittsburgh,
Pennsylvania, 1975.
12. Grant, D. M., Pugmire, R. J., Fletcher, T. H., et al.,
“A Chemical Model of Coal Devolatilization Using Percolation Lattice Statistics,” Energy and Fuels, Vol. 3, p. 175,
1989.
13. Fletcher, T. H., Kerstein, A. R., Pugmire, R. J., et al.,
“A Chemical Percolation Model for Devolatilization: Milestone Report,” Sandia report SAND92-8207, available National Technical Information Service, May, 1992.
14. Perry, S., “A Global Free-Radical Mechanism for Nitrogen Release During Devolatilization Based on Coal
Chemical Structure,” Ph.D. dissertation for the Department of Chemical Engineering, Brigham Young University, Provo, Utah, United States, 1999.
15. Field, M.A., Grill, D.W., Morgan, B.B., et al., Combustion of Pulverized Coal, The British Coal Utilization
Research Association, Leatherhead, Surrey, England,
United Kingdom, 1967.
16. Fiveland, W.A., Jamaluddin, A.S., “An Efficient
Method for Predicting Unburned Carbon in Boilers,” Combustion Science and Technology, Vol. 81, pp. 147-167,
1992.
17. Hurt, R., Sun, J.K., Lunden, L., “A Kinetic Model of
Carbon Burnout in Pulverized Coal Combustion,” Combustion and Flame, Vol. 113, pp. 181-197, 1998.
18. Patakanar, S., Numerical Heat Transfer and Fluid
Flow, Hemisphere Publishing Corporation, New York,
New York, 1980.
19. Brewster, M. Q., Thermal Radiative Transfer and
Properties, John Wiley & Sons, Inc. New York, New York,
1992.
20. Modest, M. F., Radiative Heat Transfer, McGraw-Hill,
Inc., New York, New York, 1993.
21. Viskanta, R., “Overview of computational radiation
transfer methods for combustion systems,” Proceedings
of the Third International Conference on Computational
Heat and Mass Transfer, Banff, Alberta, Canada, 2003.
22. Fiveland, W. A., “Discrete-ordinates solutions of the
radiative transport equations for rectangular enclosures,”
Transactions of American Society of Mechanical Engineers Journal of Heat Transfer, 106, pp. 699-706, 1984.
23. Jessee, J.P. and Fiveland, W.A., “Bounded, High-Resolution Differencing Schemes Applied to the Discrete Ordinates Method,” Journal of Thermophysics and Heat
Transfer, Vol.11, No. 4. October-December, 1997.
24. Thompson, J.F., Soni, B., Weatherhill, N., Eds., Handbook of Grid Generation, CRC Press, New York, New
York, 1999.
25. Dudek, S.A., Rodgers, J.A. and Gohara, W.F., “Computational Fluid Dynamics (CFD) Model for Predicting
Two-Phase Flow in a Flue-Gas-Desulfurization Wet Scrubber,” EPRI-DOE-EPA Combined Utility Air Pollution Control Symposium, Atlanta, Georgia, United States, August
16-20, 1999 (BR-1688).
26. Ryan, A. and St. John B., “SCR System Design Considerations for ‘Popcorn’ Ash,” EPRI-DOE-EPA-AWMA
Combined Power Plant Air Pollutant Control Mega Symposium, Washington, D.C., May 19-22, 2003 (BR-1741).
27. Verrill, C.L., Wessel, R.A., “Detailed Black Liquor Drop
Combustion Model for Predicting Fume in Kraft Recovery Boilers,” TAPPI Journal, 81(9):139, 1998.
28. Wessel, R.A., Parker, K.L., Verrill, C.L., “Three-Dimensional Kraft Recovery Furnace Model: Implementation and Results of Improved Black Liquor Combustion
Models,” TAPPI Journal, 80(10):207, 1997.
29. Albrecht, M.J., “Enhancing the Circulation Analysis
of a Recovery Boiler through the Incorporation of 3-D Furnace Heat Transfer Results from COMO™,” TAPPI Fall
Technical Conference, San Diego, California, September
8-12, 2002.
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Advanced computational numerical modeling of a pulverized coal burner.
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The Babcock & Wilcox Company
Chapter 7
Metallurgy, Materials and
Mechanical Properties
Boilers, pressure vessels and their associated components are primarily made of metals. Most of these
are various types of steels. Less common, but still important, are cast irons and nickel base alloys. Finally,
ceramics and refractories, coatings, and engineered
combinations are used in special applications.
Metallurgy
Crystal structure
The smallest unit of a metal is its atom. In solid
structures, the atoms of metals follow an orderly arrangement, called a lattice. An example of a simple
point lattice is shown in Fig. 1a and the unit cell is
emphasized. The lengths of the unit cell axes are defined by a, b and c, and the angles between them are
defined by α, β and γ in Fig. 1b. The steels used in
boilers and pressure vessels are mainly limited to two
different lattice types: body-centered cubic (BCC) and
face-centered cubic (FCC). (See Fig. 2.) Where changes
in the structure or interruptions occur within a crystal, these are referred to as defects. Crystal (or grain)
boundaries are a type of crystal defect. A few useful
structures are composed of a single crystal in which
all the unit cells have the same relationship to one
another and have few defects. Some high performance
jet engine turbine blades have been made of single
crystals. These structures are difficult to make, but are
worthwhile; their strength is very high as it is determined by close interactions of the atomic bonds in their
Fig. 1 Simple point lattice and unit cell (courtesy of Addison-Wesley).1
Steam 41 / Metallurgy, Materials and Mechanical Properties
Fig. 2 Two Bravais lattices.1
optimum arrangement. The behavior of all other metallic structures, which make up the huge majority of
engineering metallic materials, is determined by the
nature and extent of the defects in their structures.
Structures are made of imperfect assemblies of imperfect crystals, and their strengths are orders of magnitude lower than the theoretical strengths of perfect
single crystals.
Defects in crystals
Perfect crystals do not exist in nature. The imperfections found in metal crystals and their interactions
control their material properties.
Point defects Point defects include missing atoms
(vacancies), atoms of a different element occurring on
crystal lattice points (substitutionals), and atoms of a
different element occurring in the spaces between
crystal lattice points (interstitials). Thermally created
vacancies are always present, because they reduce the
free energy of the crystal structure by raising its entropy. There is an equilibrium number of vacancies
present; this number varies with the temperature of the
crystal. The presence of such vacancies permits diffusion (the transport of one species of metal atom through
the lattice of another) and helps facilitate some forms
of time dependent deformation, such as creep.
Vacancies can also be created by irradiation damage and plastic deformations, and the thermodynamically controlled processes of diffusion and creep can
also be affected by these other processes.
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When atoms of two metals are mixed in the molten
state and then cooled to solidification, the atoms of one
metal may take positions in the lattice of the other,
forming a substitutional alloy. Because the atoms may
be different sizes and because the bond strength between unlike atoms is different from that of like atoms, the properties of the alloy can be quite different
from those of either pure metal.
Atoms of carbon, oxygen, nitrogen and boron are
much smaller than metal atoms and they can fit in
the spaces, or interstices, between the metal atoms in
the lattice structure. The diffusion of an interstitial in
a metal lattice is also affected by temperature, and is
much more rapid at higher temperatures. Interstitial
elements are often only partly soluble in metal lattices.
Certain atoms such as carbon in iron are nearly insoluble,
so their presence in a lattice produces major effects.
Several crystal defects are illustrated in Fig. 3. This
is a two-dimensional schematic of a cubic iron lattice
containing point defects (vacancies, substitutional
foreign atoms, interstitial atoms), linear and planar
defects (dislocations, sub-boundaries, grain boundaries), and volume defects (voids, and inclusions or
precipitates of a totally different structure).2 Dislocations are linear defects formed by a deformation process called slip, the sliding of two close-packed crystal
structure planes over one another.
Grain boundaries Grain boundaries are more complex interfaces between crystals (grains) of significantly different orientations in a metal. They are arrays of dislocations between misoriented crystals. Because the atomic bonds at grain boundaries and at
other planar crystal defects are different from those
in the body of the more perfect crystal, they react differently to heat and chemical reagents. This difference
appears as grain boundaries on polished and etched
metal surfaces under a microscope. Grain size can
have positive or negative effects on metal properties.
At lower temperatures, a steel with very small grains
(fine grain size) may be stronger than the same steel
with fewer large grains (coarse grain size) because the
Fig. 3 Some important defects and defect complexes in metals
(courtesy of Wiley).3
7-2
grain boundaries act as barriers to deformation due
to slip. At higher temperatures, where thermally activated deformation such as creep can occur, a fine
grain structure material may be weaker because the
irregular structure at the grain boundaries promotes
local creep due to a mechanism known as grain boundary sliding.
Volume defects Volume defects can be voids formed
by coalescence of vacancies or separation of grain
boundaries. More common volume defects are inclusions of oxides, sulfides and other compounds, or other
phases that form during solidification from the molten state.
Physical metallurgy of steel
Phases A phase is a homogeneous body of matter
existing in a prescribed physical form. Metallurgists
use a graph, called a phase diagram, to plot the stable
phases at temperature versus composition of any metal
composed of two or more elements.
When more than one element is involved, even for
binary alloys, a variety of phases can result. One type
is the binary isomorphous system, typified by only a
few combinations: copper-nickel (Cu-Ni), gold-silver
(Au-Ag), gold-platinum (Au-Pt) and antimony-bismuth (Sb-Bi). The phase diagram for one of these
simple systems illustrates two characteristics of all solid
solutions: 1) a range of composition can coexist in liquid/solid solutions, and 2) the change of phase (in
these systems, from liquid to solid) takes place over a
range of temperatures (unlike water and pure metals
which freeze and change structure at a single temperature). Fig. 4 is a portion of the phase diagram for
Cu-Ni, which shows what species precipitate out of
solution when the liquid is slowly cooled.4 (In the remainder of this chapter, chemical symbols are often
used to represent the elements. See Periodic Table,
Appendix 1.)
Alloy systems in which both species are infinitely
soluble in each other are rare. More often the species
are only partly soluble and mixtures of phases precipitate on cooling. Also common is the situation in
which the species attract each other in a particular
ratio and form a chemical compound. These intermetallic compounds may still have a range of compositions, but it is much narrower than that for solid solutions. Two systems that form such intermetallic compounds are chromium-iron (Cr-Fe) and iron-carbon
(Fe-C).
Iron-carbon phase diagram Steel is an iron base alloy containing manganese (Mn), carbon and other
alloying elements. Virtually all metals used in boilers
and pressure vessels are steels. Mn, usually present
at about 1% in carbon steels, is a substitutional solid
solution element. Because its atomic size and electronic
structure are similar to those of Fe, it has little effect
on the Fe lattice or phase diagram in these low concentrations. Carbon, on the other hand, has significant effects; by varying the carbon content and heat
treatment of Fe, an enormous range of mechanical
properties can be obtained. These effects can best be
understood using the Fe-C equilibrium phase diagram,
shown in Fig. 5. This shows that the maximum soluSteam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
Fig. 4 The copper-nickel equilibrium diagram (courtesy of Hodder and Staughton).4
bility of carbon in α (BCC) iron is only about 0.025%,
while its solubility in γ (FCC) iron is slightly above
2.0%. Alloys of Fe-C up to 2% C are malleable and are
considered steels. Iron alloys containing more than 2%
C are decidedly inferior to steels in malleability,
strength, toughness and ductility. They are usually
used in cast form and are called cast irons.
Carbon atoms are substantially smaller than iron
atoms, and in BCC iron, they fit at the midpoints of
the cube edges and face centers. This structure is called
ferrite. In FCC iron, the carbon atoms fit at the midpoints of the cube edges at the cube center. This structure is called austenite. In both structures, the interstitial spaces are smaller than the carbon atom, leading to local distortion of the lattice and resulting in
limited carbon solubility in iron. The interstices are
larger in austenite than in ferrite, partly accounting
for the higher solubility of carbon in austenite. If austenite containing more than 0.025% C cools slowly
and transforms to ferrite, the carbon in excess of
0.025% precipitates from the solid solution. However,
it is not precipitated as pure carbon (graphite) but as
the intermetallic compound Fe3C, cementite. As with
most metallic carbides, this is a hard substance. Therefore, the hardness of steel generally increases with
carbon content even without heat treatment.
Critical transformation temperatures The melting
point of iron is reduced by the addition of carbon up
to about 4.3% C. At the higher temperatures, solid and
liquid coexist. The BCC δ iron range is restricted and
finally eliminated as a single phase when the carbon
content reaches about 0.1%. Some δ iron remains up
to about 0.5% C but is in combination with other
phases. Below the δ iron region, austenite exists and
absorbs carbon up to the composition limits (Fig. 5),
Steam 41 / Metallurgy, Materials and Mechanical Properties
the limiting solid-solution solubility. The temperature
at which only austenite exists decreases as the carbon increases (line G-S) to the eutectoid point: 0.80%
C at 1333F (723C). Then, the temperature increases
along line S-E with the carbon content because the
Fig. 5 Carbon-iron equilibrium diagram showing phase solubility limits.
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austenite is unable to absorb additional carbon, except at higher temperatures.
Any transformation in which a single solid phase
decomposes into two new phases on cooling, and in
which the reverse reaction takes place on heating, is
called a eutectoid reaction. At the eutectoid composition of 0.80% C, only austenite exists above 1333F
(723C) and only ferrite and Fe3C carbide exist below
that temperature. This is the lower critical transformation temperature, A1. At lower carbon contents, in
the hypoeutectoid region, as austenite cools and
reaches A3, the upper critical transformation temperature, ferrite precipitates first. As the temperature is
further reduced to 1333F (723C) at A1, the remaining
austenite is transformed to ferrite and carbide. In the
hypereutectoid region, above 0.80% C, cementite precipitates first when austenite cools to the thermal arrest line (Acm). Again, the remaining austenite transforms to ferrite and carbide when it cools to 1333F
(723C). For a given steel composition, A3, A1 and Acm
represent the critical transformation temperatures, or
critical points. A2 is the Curie point, the temperature
at which iron loses its ferromagnetism.
At the A1 temperature, on cooling, all the remaining austenite must transform to ferrite and carbide.
Because there is not time for the carbon to go very far
as it is rejected from the forming ferrite matrix, the
resulting structure is one of alternating thin plates,
or lamellae, of ferrite and carbide. This lamellar structure is typical of all eutectoid decomposition reactions.
In steel, this structure is called pearlite, which always
has the eutectoid composition of 0.8% C.
When pearlite is held at a moderately high temperature, such as 950F (510C), for a long time (years), the
metastable cementite eventually decomposes to ferrite
and graphite. First, the Fe3C lamellae agglomerate
into spheres. The resulting structure is considered
spheroidized. Later, the iron atoms are rejected from
the spheres, leaving a graphitized structure. Graphitized structures are shown in Fig. 6.
Isothermal transformation diagrams The transformation lines on the equilibrium diagram, Fig. 5, are
subject to displacement when the austenite is rapidly
cooled or when the pearlite and ferrite, or pearlite and
cementite, are rapidly heated. This has led to the refinement of A1 and A3 into Ac1 and Ac3 on heating (c,
from the French chauffage, heating) and into Ar1 and
A r3 for the displacement on cooling (r, from
refroidissement, cooling). Because these are descriptions of dynamic effects, they distort the meaning of
an equilibrium diagram which represents prevailing
conditions given an infinite time for reactions to occur. Because fabrication processes involve times ranging from seconds (laser welding) to several days (heat
treatment of large vessels), the effect of time is important. Isothermal transformation experiments are used
to determine phase transformation times when the
steel is cooled very rapidly to a particular temperature.
The data are plotted on time-temperature-transformation (TTT) diagrams.
The isothermal transformation diagram in Fig. 7,
for a hypoeutectoid steel, shows the time required for
transformation from austenite to other constituents at
7-4
Fig. 6 Chain graphitization (black areas) in carbon-molybdenum
steel, 200 X magnification.
the various temperature levels. The steel is heated to
about 1600F (871C) and it becomes completely austenitic. It is then quickly transferred to and held in a
furnace or bath at 700F (371C). Fig. 5 shows that
ferrite and carbides should eventually exist at this
temperature and Fig. 7 indicates how long this reaction takes. By projecting the time intervals during the
transformation, as indicated in the lower portion of
Fig. 7, to the top portion of the diagram, the austenite is predicted to exist for about three seconds before
transformation. Then, at about 100 s, the transformation is 50% complete. At 700 s, the austenite is entirely
replaced by an agglomerate of fine carbides and ferrite.
For this particular steel, at temperatures below
about 600F (316C) austenite transforms to martensite,
the hardest constituent of heat treated steels. The temperature at which martensite starts to form is denoted
Ms. It decreases with increasing carbon content of the
austenite. The nose of the left curve in Fig. 7, at about
900F (482C), is of prime significance because the
transformation at this temperature is very rapid. Also,
if this steel is to be quenched to form martensite (for
maximum hardness), it must pass through about 900F
(482C) very rapidly to prevent some of the austenite from
transforming to pearlite (F + C), which is much softer.
Martensite is therefore a supercooled metastable
structure that has the same composition as the austenite from which it forms. It is a solution of carbon in
iron, having a body-centered tetragonal (BCT) crystal structure. (See Reference 1.) Because martensite
forms with no change of composition, diffusion is not
required for the transformation to occur. It is for this
reason that martensite can form at such low temperatures. Its hardness is due to the high, supersaturated
carbon content, to the great lattice distortion caused
by trapping excess carbon, and to the volume change
of the transformation. The specific volume of martensite is greater than that of the austenite.
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
forms to δ ferrite and lowers A3 in Fig. 5. Adding a
sufficient amount of these elements increases the size
of the austenite field and the FCC structure may become stable at room temperature. Because most of
these elements do not form carbides, the carbon stays
in solution in the austenite. Many useful material
properties result, including high stability, strength and
ductility, even at high temperatures. The elements Cr,
molybdenum (Mo), tungsten (W), vanadium (V), aluminum (Al) and silicon (Si) have the opposite effect
and are considered ferrite formers. They raise the A3
temperature and some of them form very stable carbides, promoting the stability of BCC ferrite, even at
very high temperatures.
Fig. 7 Typical isothermal transformation diagram. Time required in a
specific steel at 700F (371C) taken as an example.
The formation of martensite does not occur by
nucleation and growth. It can not be suppressed by
quenching and it is athermal. Austenite begins to form
martensite at a temperature Ms. As the temperature
is lowered, the relative amount of martensite in the
structure increases. Eventually, a temperature (Mf) is
reached where the transformation to martensite is complete. At any intermediate temperature, the amount of
martensite characteristic of that temperature forms
instantly and holding at that temperature results in no
further transformation. The Ms and Mf temperatures,
therefore, are shown on the isothermal transformation
diagram (Fig. 8) as horizontal lines. Under the microscope, martensite has the appearance of acicular
needles. Each needle is a martensite crystal.
Bainite is produced when the eutectoid (0.8% C)
transformation takes place at a lower temperature
(but above the Ms temperature for the alloy). The temperature regions of the TTT curve in which pearlite,
bainite and martensite form are shown in Fig. 8. In
the pearlite transformation, the cementite and the
ferrite form in a fine lamellar pattern of alternating
layers of ferrite and cementite.
Effects of alloying elements on the Fe-Fe3C phase diagram Adding one or more elements to the Fe-C alloy
can have significant effects on the relative size of the
phase fields in the Fe-Fe3C phase diagram. The elements Ni, Mn, Cu and cobalt (Co) are called austenite
formers because their addition to the Fe-C alloy system raises the temperature at which austenite trans-
Steam 41 / Metallurgy, Materials and Mechanical Properties
Specific effect of alloying elements
Steel alloys are the chief structural materials of
modern engineering because their wide range in properties suits so many applications. These properties are
affected directly not only by the characteristics and
the amounts of the elements which, either alone or in
combination, enter into the composition of the steel,
but also by their reaction as constituents under various conditions of temperature and time during fabrication and use. For example, Cr increases resistance
to corrosion and scaling, Mo increases creep strength
at elevated temperatures, and Ni (in adequate
amounts) renders the steel austenitic. The specific
effects of the most important elements found in steel
are as follows.
Carbon (C) is the most important alloying element
in steel. In general, an increase in carbon content produces higher ultimate strength and hardness but lowers the ductility and toughness of steel alloys. The
curves in Fig. 9 indicate the general effect of carbon
on the mechanical properties of hot rolled carbon steel.
Carbon also increases air hardening tendencies and
Fig. 8 Time-temperature-transformation curves for a 0.8% plain
carbon steel.4
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The Babcock & Wilcox Company
weld hardness, especially in the presence of Cr. In low
alloy steel for high temperature applications, the carbon content is usually restricted to a maximum of
about 0.15% to ensure optimum ductility for welding,
expanding and bending operations, but it should be
no lower than 0.07% for optimum creep strength. To
minimize intergranular corrosion caused by carbide
precipitation, the carbon content of austenitic stainless steel alloys is limited to 0.10%. This maximum may
be reduced to 0.03% in extremely low carbon grades
used in certain corrosion resistant applications. However, at least 0.04% C is required for acceptable creep
strength. In plain, normalized carbon steels, the creep
resistance at temperatures below 825F (441C) increases with carbon content up to 0.4% C; at higher
temperatures, there is little variation of creep properties with carbon content. An increase in carbon content also lessens the thermal and electrical conductivities of steel and increases its hardness on quenching.
Manganese (Mn) is infinitely soluble in austenite
and up to about 10% soluble in ferrite. It combines
with residual sulfur while the steel is molten to form
manganese sulfides, which have a much higher melting point than iron sulfides. Without the Mn, iron sulfides, which melt at about 1800F (982C), would form.
This would lead to hot-shortness, a brittle-failure
mechanism, during hot forming operations. The Mn
therefore produces the malleability that differentiates
steel from cast iron.
Mn is a good solid solution strengthener, better than
Ni and about as good as Cr. In alloy steels, manganese decreases the critical cooling rate to cause martensitic structure and thus contributes to deep hardening. It can also be used in austenitic stainless steels
to replace Ni as the austenite stabilizer at lower cost.5
Molybdenum (Mo), when added to steel, increases
its strength, elastic limit, resistance to wear, impact
qualities and hardenability. Mo contributes to high
temperature strength and permits heating steel to a
red hot condition without loss of hardness. It also in-
Fig. 9 General effect of carbon on the mechanical properties of hotrolled carbon steel.
7-6
creases the resistance to softening on tempering and
restrains grain growth. Mo makes chromium steels less
susceptible to temper embrittlement and it is the most
effective single additive that increases high temperature creep strength.
An important use of Mo is for corrosion resistance
improvement in austenitic stainless steels. It enhances
the inherent corrosion resistance of these steels in
reducing chemical media and it increases their passivity under mildly oxidizing conditions. Under certain conditions, molybdenum reduces the susceptibility of stainless steels to pitting.
Chromium (Cr) is the essential constituent of stainless steel. While other elements are stronger oxide formers, Cr is the only one that is highly soluble in iron
(about 20% in austenite and infinite in ferrite) and forms
a stable, tightly adherent oxide. It is virtually irreplaceable in resisting oxidation at elevated temperatures.
Cr raises the yield and ultimate strength, hardness,
and toughness of ferritic steel at room temperature.
It also contributes to high temperature strength. The
optimum chromium content for creep strength in annealed low alloy steels is about 2.25%.
A steady improvement in resistance to atmospheric
corrosion and to attack by many reagents is also noted
when the chromium content is increased. A steel with
12% or more Cr is considered stainless, i.e., the Cr2O3
film is sufficient to prevent surface rust (hydrated iron
oxide) formation. The chemical properties of the steel,
however, are affected by the carbon content. Higher
chromium and lower carbon levels generally promote
increased corrosion resistance.
Adding more than 1% of chromium may cause appreciable air hardening in the steel. Up to about 13.5%
Cr, air hardening is a direct function of chromium and
carbon content. Low carbon alloy steels containing
more than 12% Cr can become nonhardening, but the
impact strength is reduced and the ductility is poor. Cr
lessens thermal and electrical conductivities. The addition of sufficient Cr prevents graphitization during
long-term high temperature service of ferritic steels.
Nickel (Ni) increases toughness when added to
steel, particularly in amounts over 1%. Improved resistance to corrosion by some media is attained with
Ni contents over 5%. Ni dissolves in the iron matrix
in all proportions and, therefore, raises the ultimate
strength without impairing the ductility of the steel.
Ni is particularly effective in improving impact properties, especially at low temperature.
The most important use of nickel as an alloying element in steel is its combination with chromium in
amounts of 8% Ni or more. Ni is such a strong austenite former that the high chromium Fe-Ni-C alloys are
austenitic at room temperature. The various combinations of chromium and nickel in iron produce alloy
properties that can not be obtained with equivalent
amounts of a single element. Common combinations
are 18% Cr - 8% Ni, 25% Cr - 12% Ni, 25% Cr - 20%
Ni, and 20% Cr - 30% Ni. These steels are resistant to
atmospheric corrosion and to oxidation at high temperatures. In addition, they offer greatly enhanced
creep strength.
Ni is only slightly beneficial to creep properties of
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
low alloy ferritic steels. It reduces the coefficient of
thermal expansion and diminishes the electrical and
thermal conductivities. It is attacked by sulfur compounds at elevated temperatures.
Cobalt (Co) suppresses hardenability in steels. However, when added to austenite, it is a strong solution
strengthener and a carbide former. It also significantly
improves creep strength. Binary Fe-Co alloys have the
highest magnetic saturation induction of any known
materials. Therefore, such alloys are often used in
permanent magnets.
Tungsten (W) acts similarly to molybdenum. It is a
very strong carbide former and solid solution
strengthener. It forms hard, abrasion resisting carbides in tool steels, develops high temperature hardness in quenched and tempered steels, and contributes to creep strength in some high temperature alloys.5
Vanadium (V) is a degasifying and deoxidizing
agent, but it is seldom used in that capacity because
of high cost. It is applied chiefly as an alloying element in steel to increase strength, toughness and
hardness. It is essentially a carbide forming element
which stabilizes the structure, especially at high temperatures. Vanadium minimizes grain growth tendencies, thereby permitting much higher heat treating temperatures. It also intensifies the properties of other elements in alloy steels. Small additions of vanadium (0.1
to 0.5%), accompanied by proper heat treatment, give
steels containing 0.5 to 1.0% molybdenum pronounced
improvement in high temperature creep properties.
Titanium (Ti) and columbium (Cb) (also known as
niobium) are the most potent carbide forming elements. Ti is also a good deoxidizer and denitrider.
These elements are most effective in the Cr-Ni austenitic alloys, where they react more readily with carbon than does Cr. This allows the Cr to remain in solid
solution and in the concentrations necessary to maintain corrosion resistance. Ti and Cb [or Cb plus tantalum (Ta)] are used to reduce air hardening tendencies and to increase oxidation resistance in steel
containing up to 14% Cr. These elements have a beneficial effect on the long term, high temperature properties of Cr-Ni stainless steels because of the stability of
their carbides, nitrides and carbonitrides. Cb and Ti have
also been used in some of the super alloys to improve
high temperature properties. Ti forms an intermetallic
compound with Ni in these alloys, Ni3Ti, called gamma
prime ( γ ′), which is a potent strengthening phase.
Copper (Cu), when added to steel in small amounts,
improves its resistance to atmospheric corrosion and
lowers the attack rate in reducing acids. Cu, like Ni,
is not resistant to sulfur compounds at elevated temperatures. Consequently, it is not ordinarily used in
low alloy steels intended for high temperature service
where sulfur is a major component of the environment, as in combustion gases. Cu is added (up to 1%)
in low alloy constructional steels to improve yield
strength and resistance to atmospheric corrosion. Its
presence in some of the high alloy steels increases
corrosion resistance to sulfuric acid.
Boron (B) is usually added to steel to improve
hardenability, that is, to increase the depth of hardening during quenching of alloy steels. When com-
Steam 41 / Metallurgy, Materials and Mechanical Properties
bined with Mo, it is a strong bainite stabilizer. Small
amounts of boron in the presence of Mo suppress the
formation of martensite, leading to the complete transformation to bainite before the Ms temperature is
reached. This substantially improves the strength and
stability of Cr-Mo pressure vessel steels. The B-10 isotope of boron has a very high neutron-capture crosssection, so it is added to steels used for containment and
storage vessels of nuclear fuels and waste products.
Nitrogen (N) has two primary functions as an alloying agent in steels. In carbon and low alloy steels,
it is used in case hardening, in which nascent nitrogen is diffused into the steel surface. Nitrogen and carbon are interstitial solid solution strengtheners. In the
presence of Al or Ti, additional strengthening results
by precipitate formations of the respective nitrides or
carbonitrides. In austenitic stainless steels, nitrogen
provides the same interstitial strengthening as carbon, but does not deplete the austenite of chromium
as does carbon by the formation of carbides. The
strength of nitrogen-containing stainless steels is
therefore equivalent to that of the carbon-containing
stainlesses. This strength is achieved without the susceptibility to corrosive attack that results from local
carbide formation at grain boundaries of these steels.
Oxygen (O) is not normally considered to be an alloying element. It is present in steel as a residual of
the steel making process.6,7 However, a few oxides are
so hard and stable, notably those of Al, Ti and thorium
(Th), that they are potent strengtheners when dispersed
as fine particles throughout an alloy. This can be accomplished by internal oxidation in an oxygen-containing
atmosphere or by powder metallurgical techniques.
Aluminum (Al) is an important minor constituent
of low alloy steels. It is an efficient deoxidizer and
grain refiner, and is widely used in producing killed
steel. When added to steel in appreciable quantities,
Al forms tightly adhering refractory oxide scales and
therefore, increases resistance to scaling. It is difficult,
however, to add appreciable amounts of this element
without producing undesirable effects. In the amounts
customarily added (0.015 to 0.080%), Al does not increase resistance to ordinary forms of corrosion. Because of their affinity for oxygen, high-aluminum
steels generally contain numerous alumina inclusions
which can promote pitting corrosion. The refined grain
size does improve room temperature toughness and
ductility of carbon steels.
An excessive quantity of aluminum has a detrimental effect on creep properties, particularly in plain
carbon steel. This is attributable to its grain refining
effect and to its acceleration of graphitization of the
carbide phase.
Silicon (Si) greatly contributes to steel quality because of its deoxidizing and degasifying properties.
When added in amounts up to 2.5%, the ultimate
strength of steel is increased without loss in ductility.
Si in excess of 2.5% causes brittleness and amounts
higher than 5% make the steel nonmalleable.
Resistance to oxidation of steel is increased by adding silicon. Si increases the electrical conductivity of
steel and decreases hysteresis losses. Si steels are,
therefore, widely used in electrical apparatus.
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The Babcock & Wilcox Company
Killing agents, such as Si and Al, are added to steel
for deoxidation; the latter is used for grain size control. Calcium and rare earth metals, when added to
the melt, have the same effects. Additionally, these
elements form complex oxides or oxysulfides and can
significantly improve formability by controlling the
sulfide shape.
Phosphorus (P) is a surprisingly effective hardener
when dissolved in quantities of up to 0.20%.5 However,
a high phosphorus content can notably decrease the
resistance of carbon steel to brittle fracture and reduce
ductility when the metal is cold worked. This embrittling
effect is referred to as cold-shortness. The detrimental
effect of phosphorus increases with carbon content.
Phosphorus is effective in improving the machinability of free-cutting steels. This is related to its
embrittling effect, which permits easier chip formation
on machining. In alloy steels intended for boiler applications, the permissible phosphorus content is less
than that for machining steels and its presence is objectionable for welding. Phosphorus is used as an alloying element (up to 0.15%) in proprietary low alloy,
high strength steels, where increased yield strength
and atmospheric corrosion resistance are primary requirements. In the presence of certain acids, however, a
high phosphorus content may increase the corrosion rate.
Sulfur (S) is generally undesirable in steel and
many processes have been developed to minimize its
presence. However, sulfur is sometimes added to steel
to improve its machinability, as are phosphorus and
other free-machining additives: calcium, lead, bismuth, selenium and tellurium. Several of these elements are virtually insoluble in steel and have low
melting points, or they form low melting temperature
compounds. These compounds can lead to cracking
due to liquid metal embrittlement or hot-shortness at
even moderately elevated temperatures. Hot-shortness
occurs when liquid iron sulfide forms at grain boundaries during hot-working and heat treatment of steels.6
Because the fastener industry favors free machining
steels due to their beneficial production effects, boiler
and pressure vessel manufacturers must exercise care
in applying threaded fasteners containing these elements at high temperatures.
Heat treating practices
Steel can be altered by modifying its microstructure
through heat treatment. Various heat treatments may
be used to meet hardness or ductility requirements,
improve machinability, refine grain structure, remove
internal stresses, or obtain high strength levels or
impact properties. The more common heat treatments,
annealing, normalizing, spheroidizing, hardening
(quenching) and tempering, are briefly described.
Annealing is a general term applied to several distinctly different methods of heat treatment. These are
full, solution, stabilization, intercritical, isothermal,
and process annealing.
Full annealing is done by heating a ferritic steel
above the upper critical transformation temperature
(A3 in Fig. 5), holding it there long enough to fully
transform the steel to austenite, and then cooling it
at a controlled rate in the furnace to below 600F
7-8
(316C). A full anneal refines grain structure and provides a relatively soft, ductile material that is free of
internal stresses.
Solution annealing is done by heating an austenitic stainless steel to a temperature that puts most of
the carbides into solution. The steel is held at this temperature long enough to achieve grain growth. It is
then quenched in water or another liquid for fast cooling, which prevents most of the carbides from
reprecipitating. This process achieves optimum creep
strength and corrosion resistance. For many boiler
applications, austenitic stainless steels require the high
creep strength of a coarse grain structure but do not
require aqueous corrosion resistance, because they are
only exposed to dry steam and flue gases. Solution
treatment, used to achieve grain growth, is required for these
applications, but the quenching step is not required.
Stabilization annealing is performed on austenitic
stainless steels used in severe aqueous corrosion environments. The steel is first solution annealed, then
reheated to about 1600F (871C) and held there. Initially, chromium carbides precipitate at the grain
boundaries in the steel. Because these are mostly of
the complex M23C6 type, which are very high in Cr, the
austenite adjacent to the grain boundaries is depleted
of chromium. This would normally leave the steel susceptible to corrosive attack, but holding it at 1600F (871C)
permits the Cr remaining in the austenite solution to redistribute within the grains, restoring corrosion resistance, even adjacent to the grain boundaries.
Intercritical annealing and isothermal annealing
are similar. They involve heating a hypoeutectoid ferritic steel above the lower critical transformation temperature (A1 in Fig. 5) but below the upper critical
temperature, A3. This dissolves all the iron carbides but
does not transform all the ferrite to austenite. Cooling slowly from this temperature through A1 produces
a structure of ferrite and pearlite that is free of internal stresses. In intercritical annealing, the steel continues to cool slowly in the furnace, similarly to full
annealing. In isothermal annealing, cooling is stopped
just below A1, assuring complete transformation to
ferrite and pearlite, and eliminating the potential for
bainite formation.
Process annealing, sometimes called subcritical annealing or stress relieving, is performed at temperatures just below the lower critical temperature A1, usually between 950 and 1300F (510 and 704C). Process
annealing neither refines grains nor redissolves cementite, but it improves the ductility and decreases
residual stresses in work hardened steel.
Normalizing is a variation of full annealing. Once
it has been heated above the upper critical temperature, normalized steel is cooled in air rather than in a
controlled furnace atmosphere. Normalizing is sometimes used as a homogenization procedure; it assures
that any prior fabrication or heat treatment history
of the material is eliminated. Normalizing relieves the
internal stresses caused by previous working and, while
it produces sufficient softness and ductility for many purposes, it leaves the steel harder and with higher tensile
strength than full annealing. To remove cooling stresses,
normalizing is often followed by tempering.
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
Spheroidizing is a type of subcritical annealing used
to soften the steel and to improve its machinability.
Heating fine pearlite just below the lower critical temperature of the steel, followed by very slow cooling,
causes spheroidization.
Hardening (quenching) occurs when steels of the
higher carbon grades are heated to produce austenite and then cooled rapidly (quenched) in a liquid such
as water or oil. Upon hardening, the austenite transforms into martensite. Martensite is formed at temperatures below about 400F (204C), depending on the
carbon content and the type and amount of alloying
elements in the steel. It is the hardest form of heat
treated steels and has high strength and abrasion
resistance.
Tempering is applied after normalizing or quenching some air hardening steels. These preliminary treatments impart a degree of hardness to the steel but also
make it brittle. The object of tempering, a secondary
treatment, is to remove some of that brittleness by
allowing certain transformations to proceed in the
hardened steel. It involves heating to a predetermined
point below the lower critical temperature, A1, and is
followed by any desired rate of cooling. Some hardness is lost by tempering, but toughness is increased,
and stresses induced by quenching are reduced or
eliminated. Higher tempering temperatures promote
softer and tougher steels. Some steels may become
embrittled on slow cooling from certain tempering temperatures. These steels are said to be temper brittle.
To overcome this difficulty, they are quenched from
the tempering temperature.
Post fabrication heat treatments are often applied
to restore more stable, stress free conditions. These include post weld and post forming heat treatments and
solution treatment.
Fabrication processes
Any mechanical work applied to the metal below its
recrystallization temperature is cold work. Mechanical work performed above the recrystallization temperature is hot work and the simultaneous annealing
that occurs at that temperature retards work-hardening. The recrystallization temperature is dependent on
the amount of deformation. If a material is formed at a
temperature significantly above room temperature, but
below its recrystallization temperature, the process is
sometimes referred to as warm working.
The temperature at which steel is mechanically
worked has a profound effect on its properties. Cold
work increases the hardness, tensile strength and yield
strength of steel, but its indices of ductility – elongation and reduction of area – are decreased. The extent of the work-hardening, with progressive elongation of the grains in the direction of working, depends
on the amount of cold work and on the material. If
the work-hardening caused by the necessary shaping
operation becomes excessive, the ductility may be exhausted and further work can cause fracture.
Hot working variations include forging, rolling,
pressing, extruding, piercing, upsetting and bending.
Most of these are largely compressive operations, in
which the metal is squeezed into a desired shape. They
Steam 41 / Metallurgy, Materials and Mechanical Properties
introduce some degree of orientation to the internal
structure. Even if the metal experiences phase transformations or other recrystallization processes, some
degree of orientation is maintained in the pattern retained by the oxides, sulfides, and other inclusions
that do not dissolve during hot working or heat treatment. Depending on the application, the resultant
orientation may have no effect, be useful, or be harmful. Rolled plates, for instance, often have inferior
properties in the through-thickness direction due to
retention of mid-plane segregated inclusions and to the
predominant grain orientation in the longitudinal and
transverse directions. This can result in a failure mode
known as lamellar tearing if not addressed.
Hot rolling of carbon steel and low alloy steel into
drum or pressure vessel sections is often done at temperatures above A3. Temperatures and times of heating before forming need to be controlled to ensure that
the resulting product retains the desired fine grain size
and consequent good toughness, and to ensure that
excessive plate surface oxidation does not occur.
Cold working operations used in manufacturing
boiler components are rolling, forging, bending and
swaging. Detailed information about these processes
and their effects on materials can be found elsewhere.
(See References 6 and 7.)
Cold rolling of plate to make shells for drums is limited only by the capacity and diameter of available
rolling equipment and the inherent ductility of the
steel. This process is most often applied to carbon steel,
and any post forming heat treatment performed is
usually combined with post weld heat treatment of the
completed drum. In some low pressure applications,
tube-to-header or tube-to-drum connections may be
made by roll expanding the tube into an internally
grooved socket in the shell. The strength of the connection depends on the mechanical interference between the roll expanded tube, which generally deforms plastically, and the hole in the shell, which
mostly deforms elastically.
Cold forging of boiler components is usually limited to final size forming of shells. Threaded fasteners used in boilers may have been cold headed or may
have had their threads cold rolled. Effects of such
forming operations are normally mitigated by heat
treatments required by the specification, but occasionally this heat treatment does not eliminate microstructural differences between the cold formed portion and
the remainder of the part. This is particularly true of
austenitic stainless steel or nickel alloy bolts, which
do not transform during heat treatment. These bolts
may be susceptible to cracking at the interface between
the cold formed head and the shank in certain aqueous environments.
Cold bending is performed on many configurations
of tubes and pipes for boilers. Boiler designers consider
the effects of this process on the geometry and properties of the finished product.
Austenitic stainless steels and nickel alloys used in
high pressure boilers are often exposed to temperatures at which the strain energy of the cold bending
is sufficient to cause polygonization and recrystallization to a fine grain size during service. The service
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The Babcock & Wilcox Company
Welding is the joining of two or more pieces of metal
by applying heat or pressure, or both, with or without the addition of filler metal, to produce a localized
union through fusion across the interface.8 There are
many welding processes, but the most widely used for
joining pressure parts is fusion welding with the addition of filler metal, using little or no pressure. Fig.
10 indicates the variety of processes.
Weld morphology Because of the heat distribution
characteristics of the welding process, the weld joint
is usually a chemically and mechanically heterogeneous composite consisting of up to six metallurgically
distinct regions: a composite zone, the unmixed zone,
the weld interface, the partially melted zone, the heataffected zone (HAZ) and the unaffected base metal.
These zones are shown in Fig. 11. The composite zone
is the completely melted mixture of filler metal and
melted base metal. The narrow region surrounding the
composite zone is the unmixed zone, which is a boundary layer of melted base metal that solidifies before
mixing in the composite zone. This layer is at the edges
of the weld pool, with a composition essentially identical to the base metal. The composite zone and the
unmixed zone together make up what is commonly
referred to as the fusion zone. The third region is the
weld interface, or the boundary between the unmelted
base metal on one side and the solidified weld metal
on the other. The partially melted zone occurs in the
base metal immediately adjacent to the weld interface,
where some localized melting of lower melting temperature constituents, inclusions or impurities may
have occurred. Liquation, for instance, of manganese
sulfide inclusions can result in hot cracking or
microfissuring. The heat-affected zone is that portion
of the base material in the weld joint that has been
subjected to peak temperatures high enough to produce solid state microstructural changes, but not high
temperature is insufficient to produce grain growth
and the fine grain size material has lower high temperature (creep) strength. To prevent this from happening, cold bends in these alloys are given a high
temperature (solution) heat treatment to stabilize the
coarse grain structure.
Most carbon and low alloy ferritic steel tube and pipe
alloys may be used in the cold bent condition, unless
the amount of cold strain imparted is very high. If strain
in excess of about 30% is developed in bending, the resulting structure and low residual ductility can render
the bends susceptible to strain aging and breakage
during subsequent handling and service.
Cold working of carbon steels has also been shown
to render them susceptible to creep crack growth of
minor surface flaws and imperfections when these
steels are operating at temperatures where the cracking mechanism is operative.
Certain Cr-Mo high strength ferritic steels can also
experience significant degradation of creep strength
if they are cold worked to levels near and above about
20% strain. In all of these cases, post fabrication heat
treatments must be applied to recover acceptable properties. This most often requires re-annealing, normalization, or normalizing and tempering as is appropriate for the given alloy. In some cases, simple subcritical tempering or stress relief heat treatment may be
sufficient.
Welding
Joining of boiler pressure parts and of nonpressure
parts to pressure parts is almost always accomplished
by welding. This is particularly true of high temperature, high pressure boilers, whose service conditions
are too severe for most mechanical joints (bolted
flanges with gaskets) and brazed joints.
Welding Processes
Fusion
Energy
Beam
Gas
Welding
Electron
Beam
Oxyacetylene
Brazing
Shielded Metal
Arc
Pressure
Thermit
Process
Arc
Welding
Smith
Friction
Cold
Resistance
Welding
Butt
Flash
Laser
Beam
Metallic
Arc
Flux Cored
Arc
Gas
Shielded
Submerged
Arc
Gas Metal
Arc
Electroslag
Spot
Seam
Gas Tungsten
Arc
Fig. 10 Classification of welding processes.4
7-10
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
Fig. 11 Metallurgical zones developed in a typical weld (courtesy of
ASM).9
enough to cause melting. Finally, the last part of the
work piece that has not undergone a metallurgical
change is the unaffected base metal.
Weld quality issues
The general subject of welding and weldability is a
very broad subject, addressed by a large number of
excellent references.10,10a The following addresses only
a few issues that are particularly unique and important to boilers and pressure vessels.
Ferrite content Austenitic stainless steel weld metals are susceptible to hot cracking or microfissuring
as they cool from the solidus to about 1800F (982C).
The microfissuring can be minimized by providing a
small percentage of ferrite in the as-deposited welds.
Graphitization The shrinkage of the weld on freezing results in plastic deformation and high residual
stresses in the weld joint. In carbon and carbon-molybdenum steels containing no stronger carbide-forming elements, the areas of localized strain adjacent to
the heat-affected weld zones provide sites where the
volume increase of the cementite to graphite decomposition can be more readily accommodated. At about
900F (482C), graphite nodules can precipitate on these
planes of deformation. When samples of such materials are viewed in cross-section, the nodules appear to
be arranged in rows or chains, and this condition has
been termed chain graphitization (Fig. 6). The interfacial bond between the graphite and the ferrite matrix in such weldments is very low, much lower than
that between ferrite and pearlite or ferrite and cementite. In the early 1950s, several failures of carbonmolybdenum main steam piping weldments occurred
due to this phenomenon. The ruptures occurred with
little warning because they were not preceded by
swelling of the joints and, as a result, significant damage resulted. In consequence, the use of carbon-molybdenum main steam piping has been essentially
eliminated and the maximum use temperature of carbon steel piping has been significantly restricted.
Post weld heat treatment When cooling is complete, the welded joint contains residual stresses comparable to the yield strength of the base metal at its
final temperature. The thermal relief of residual
stresses by post weld heat treatment (PWHT) is accomplished by heating the welded structure to a temperature high enough to reduce the yield strength of
the steel to a fraction of its magnitude at ambient temSteam 41 / Metallurgy, Materials and Mechanical Properties
perature. Because the steel can no longer sustain the
residual stress level, it undergoes plastic deformation
until the stresses are reduced to the at-temperature
yield strength. Fig. 12 shows the effect of stress relief
on several steels. The temperature reached during the
treatment has a far greater effect in relieving stresses
than the length of time the weldment is held at temperature. The closer the temperature is to the critical
or recrystallization temperature, the more effective it
is in removing residual stresses, provided the proper
heating and cooling cycles are used.10
Lamellar tearing Weld defect causes and inspection procedures are covered more extensively in References 9 and 11. However, one metallurgical effect
of residual stresses should be mentioned in the context of boilers and pressure vessels: lamellar tearing.
Lamellar tearing may result when an attachment is
welded to a plate in the T-shaped orientation shown
in Fig. 13, particularly if the plate contains shrinkage voids, inclusions, or other internal segregation
parallel to the plate surface. In such an instance, the
residual shrinkage stresses may be sufficient to open
a tear or tears parallel to the plate surface to which
the T-portion is welded.
Joining dissimilar metals It may be necessary to join
austenitic and ferritic steels. Weld failures have occurred in these welds since the introduction of austenitic stainless steel superheater tubing materials.
Nickel base filler metals have long been used to mitigate these problems, but these do not offer a permanent solution. Additional system stresses from component location, system expansion and bending can increase the potential for such failures.
Fig. 12 Effect of temperature and time on stress relief in carbon
steel (upper graph) and steels with varying as-welded strengths
(courtesy of AWS).11
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The Babcock & Wilcox Company
Fig. 13 Lamellar tearing.
Research is continuing toward the development of
filler metals less likely to permit failures but none has
become commercially available. The best alternative is
to avoid dissimilar metal welds by using higher strength
ferritic alloy materials, such as modified 9Cr-1Mo-V tubing and piping, when design conditions permit.
Materials
Almost all of the materials used in constructing
boilers and pressure vessels are steels and the vast
majority of components are made of carbon steels.
Carbon steels are used for most types of pressure and
nonpressure parts: drums, headers, piping, tubes,
structural steel, flues and ducts, and lagging.
Carbon steels may be defined by the amount of carbon retained in the steel or by the steelmaking practice. These steels are commonly divided into four
classes by carbon content: low carbon, 0.15% C maximum; medium-low carbon, between 0.15 and 0.23%
C; medium-high carbon, between 0.23 and 0.44% C;
and high carbon, more than 0.44% C. However, from
a design viewpoint, high carbon steels are those over
0.35%, because these can not be used as welded pressure parts. Low carbon steels see extensive use as pressure parts, particularly in low pressure applications
where strength is not a significant design issue. For
most structural applications and the majority of pressure parts, medium carbon steels, with carbon contents
between 0.20 and 0.35%, predominate.
Carbon steels are also referred to as killed, semikilled, rimmed and capped, depending on how the
carbon-oxygen reaction of the steel refining process
was treated. During the steelmaking process, oxygen,
introduced to refine the steel, combines with carbon
to form carbon monoxide or carbon dioxide, and also
exists as excess oxygen. If the oxygen introduced is
not removed or combined prior to or during casting by
the addition of Si, Al, or some other deoxidizing agent,
the gaseous products are trapped during solidification
of the metal in the mold. The amount of gas evolved
7-12
during solidification determines the type of steel and
the amount of carbon left in the steel. If no gas is
evolved and the liquid lies quietly in the mold, it is
known as killed steel. With increasing degrees of gas
evolution, the products are known as semi-killed and
rimmed steels. Virtually all steels used in boilers today are fully killed.
Microalloyed steels are carbon steels to which small
amounts (typically less than 1%) of alloying elements
have been added to achieve higher strength. Common
additions are vanadium and boron. Such steels are
seldom used in pressure part applications, but they are
gaining acceptance as structural steels.
Residual elements are present in steels in small
amounts and are elements other than those deliberately added as alloying or killing agents during the
steelmaking process. Their source is the scrap or pig
iron used in the furnace charge. Cu, Ni, Cr, V and B
are typical examples of residuals often found in carbon steels. S and P, also considered to be residual elements, usually are reported in chemical analyses of
steels, and their concentrations are limited by specification because they degrade ductility. The residual
elements S, P, Sb and tin (Sn) are also important contributors to temper embrittlement in steels.
Historically, residual elements other than S and P were
neither limited nor reported. This practice is changing, however, and several residuals have established limits.
Low and medium alloy steels are the next most important category of steels used in boilers. These are
characterized by Cr contents less than 11.5% and lesser
amounts of other elements. The most common alloy
combinations in this group encountered in boilers are:
C-1/2Mo, 1/2Cr-1/2Mo, 1Cr-1/2Mo, 1-1/4Cr-1/2Mo-Si,
2-1/4Cr-1Mo, and 9Cr-1Mo-V. Other less common alloys in this group are 3Cr-1Mo, 5Cr-1/2Mo and 9Cr-1Mo.
Because of the exceptional strength-enhancing capability of Mo in carbon steel, it is not surprising that
C-1/2Mo steel has many applications for pressure
parts, particularly in the temperature range of about
700 to 975F (371 to 524C). C-Mo steels, however, are
particularly prone to graphitization at temperatures
above about 875F (468C). Inside the boiler, where
graphitization failures do not present a safety hazard,
C-Mo tubing has many uses up to 975F (524C), its
oxidation limit. Because Al content promotes graphitization, C-Mo steel is usually Si-killed and it has a
coarse grain structure as a consequence. Therefore,
C-Mo components are somewhat prone to brittle failures at low temperatures. This is not a problem in
service, because the design application range of this
alloy is at high temperature.
The oxidation resistance of low alloy steels increases
with Cr content. The first common alloy in the Cr-Mo
family is 1/2Cr-1/2Mo. This steel was developed in
response to the graphitization failures of C-Mo piping. It was found that the addition of about 0.25% Cr
was sufficient to make the alloy immune to graphitization. Furthermore, 1/2Cr-1/2Mo has essentially the
same strength as C-Mo and has therefore displaced it
in many applications. Because the application of 1/2Cr1/2Mo is virtually unique to the boiler industry, it is less
readily available in certain sizes and product forms.
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
The next alloys in this series are the nearly identical 1Cr-1/2Mo and 1-1/4Cr-1/2Mo-Si; the Si-containing version is slightly more oxidation resistant. However, extensive analyses of the databases indicate that
the 1Cr-1/2Mo version is stronger over the temperature range of 800 to 1050F (427 to 566C). As a result,
this alloy is rapidly displacing 1-1/4Cr-1/2Mo-Si in
most applications in this temperature regime.
Absent the addition of other alloying elements, the
2-1/4Cr-1Mo composition is the optimum alloy for high
temperature strength. Where the need for strength
at temperatures between 975 and 1115F (524 and
602C) is the dominant design requirement, 2-1/4Cr1Mo is the industry workhorse alloy. The 3Cr through
9Cr alloys are less strong, but they have application
where improved oxidation resistance is desired and
lower strength can be tolerated. The increasing airhardenability of these alloys with increasing Cr content makes fabrication processes more complex and
their use is somewhat more costly as a result.
Mn-Mo and Mn-Mo-Ni alloys have limited use in
fossil-fueled boilers. Their slightly higher strength
compared to carbon steels promotes their application
in very large components, where the strength to
weight ratio is an important consideration. Their generally superior toughness has made them a popular
choice for nuclear pressure vessels.
The heat treatable low alloy steels, typified by the
AISI-SAE 4340 grade (nominally 0.40C-0.80Cr-1.8Ni0.25Mo), are used for relatively low temperature structural applications in boilers and nuclear pressure vessels. The instability of their microstructures and therefore, of their strength, with long exposure at elevated
temperatures, has eliminated them from consideration
for boiler pressure parts.
Higher Cr-Mo alloys Because of their tendency toward embrittlement, the martensitic 9Cr-1Mo and
12Cr-1Mo steels have not been widely used for pressure vessel and piping applications in North America
prior to the 1980s. However, in the early 1970s, the
United States (U.S.) Department of Energy (DOE)
sponsored research to develop a 9Cr-1Mo steel with
improved strength, toughness and weldability12 for
tubing in steam generators for liquid metal fast
breeder nuclear reactors.13 The alloy is 9Cr-1Mo-V,
commonly called Grade 91. It has exceptional strength,
toughness and stability at temperatures up to 1150F
(621C). Because it is nearly twice as strong as 2-1/4Cr1Mo at 1000F (538C), it is displacing that alloy in high
pressure header applications. The resultant thinner
vessels have significantly reduced thermal stresses
and associated creep-fatigue failures compared to 21/4Cr-1Mo and 1-1/4Cr-1/2Mo-Si headers.14,15 Because
Grade 91 is stronger than austenitic stainless steel up
to about 1125F (607C), it is also displacing that alloy
class in high pressure tubing applications. It has the
added advantage of being a ferritic alloy, eliminating
the need for many dissimilar metal welds between
pressure parts. The Grade 91 gains its strength, toughness, and stability from its alloy additions and features
the fully bainitic microstructure resulting from careful normalizing and tempering.
While not popular in North America because of the
Steam 41 / Metallurgy, Materials and Mechanical Properties
care necessary in handling very air-hardenable alloys
during fabrication, the 12Cr-Mo and 12Cr-Mo-V alloys have had wide use in the European boiler industry. In addition, the experience being gained with
Grade 91 may eventually enhance the acceptance of
the 12Cr group.
Austenitic stainless steel Every attempt is made to
minimize the use of stainless steels in boilers because
of their high cost, but the combination of strength and
corrosion resistance they provide makes them the favored choices in certain applications. They are virtually the only choices for service above 1150F (621C).
At lower temperatures, down to about 1050F (566C),
they often displace the Cr-Mo ferritic steels, where the
lower pressure drop afforded by the thinner stainless
steel component wall is important.
The common alloys of stainless steels used in boiler
pressure parts are 18Cr-8Ni, 18Cr-8Ni-Ti, 18Cr-8NiCb, 16Cr-12Ni-2Mo, 25Cr-12Ni, 25Cr-20Ni, and 20Cr30Ni. The last alloy in this group is technically a nonferrous alloy, because it has less than 50% Fe when
its other minor alloying constituents are considered.
However, because it is so similar to the other austenitic stainless steels, it may be considered one of them.
These alloys are commonly designated the 300 series:
304, 321, 347, 316, 309 and 310 stainless steels, respectively. The 20Cr-30Ni alloy is commonly known
as Alloy 800. Because the strength of these materials
at high temperature is dependent on a moderate carbon content and usually on a coarse grain size, materials with those qualities are often specified for high
temperature service. They carry the added designation of the letter H, e.g., 304H or 800H.
Of these alloys, 304H is the most commonly used.
It provides an excellent balance of strength and oxidation resistance at the lowest cost of any alloy in this
group. However, if severe aqueous corrosive conditions
may exist either before or during service, especially
in solutions containing halogens, other stainless steel
alloys should be substituted. The 304H alloy is susceptible to sensitization at grain boundaries and, thus,
may suffer stress corrosion cracking or intergranular
attack in that environment. In these cases, a stabilized stainless steel composition such as 347H should
be used. Further details on how the American Society
of Mechanical Engineers (ASME) Code establishes
allowable design stresses for materials can be found
in the Appendix to ASME Section II, Part D.
All of the 300 series alloys are susceptible to sigma
phase formation after long exposure at temperatures
of 1050 to 1700F (566 to 927C). Those with some initial ferrite, such as 309, can form the sigma phase
earlier, but all eventually do so. This phase formation
decreases toughness and ductility but has no effect on
strength or corrosion resistance. It has been a problem in heavy-section piping components made of 316
stainless steels, but it is not a design consideration for
smaller (tubing) components.
The 321 type is not as strong as the others in this
series. While it is a stabilized grade and has important low temperature applications, the stability of the
titanium carbide makes it extremely difficult to heat
treat type 321 in one thermal treatment and obtain a
7-13
The Babcock & Wilcox Company
resulting structure that is both coarse grained, for
high temperature creep strength, and has stabilized
carbides for sensitization resistance. It is possible to
apply a lower temperature stabilizing heat treatment,
at about 1300F (704C), following the solution treatment to achieve a stabilized condition and good creep
strength. The stability of the columbium (niobium)
carbides in type 347 is better, and this grade can be heat
treated to obtain creep strength and sensitization resistance. This 18Cr-8Ni-Cb alloy is widely used at high
temperatures because of its superior creep strength.
The Mo content of the 316 type increases its pitting
resistance at lower temperatures. While this alloy has
good creep strength, it is not often used because of its
higher cost.
These alloys are susceptible to stress corrosion cracking in certain aqueous environments. The 300 series
alloys are particularly sensitive to the presence of
halide ions. As a result, their use in water-wetted service is usually prohibited. The stress corrosion cracking experience with Alloy 800 has been mixed and,
while this grade is permitted in water-wetted service,
it is not common practice.
Types 309, 25Cr-12Ni, and 310, 25Cr-20Ni, have
virtually identical strengths and corrosion resistance.
They are not as strong as 304 or 347 but are more
oxidation resistant. The high Ni alloys, like Alloy 800,
are somewhat more affected by sulfidation attack.
They have been used as nonpressure fluidized-bed
boiler components designed to remove particulate from
hot gas streams.
Most of these alloys are available in a multiplicity
of minor variations: H grades, with 0.04 to 0.10% C
and a required high temperature anneal and coarse
grain size for creep strength; L grades, with 0.035%
maximum C for sensitization resistance; N grades,
with 0.010% minimum N added for strength; LN
grades, with 0.035% maximum C and 0.010% minimum N for sensitization resistance and strength; and
straight (no suffix) grades, with 0.08% maximum C.
Ferritic stainless steels contain at least 10% Cr and
have a ferrite-plus-carbide structure. Martensitic
stainless steels are ferritic in the annealed condition
but are martensitic after rapid cooling from above the
critical temperature. They usually contain less than
14% Cr.16 Precipitation hardened stainless steels are
more highly alloyed and are strengthened by precipitation of a finely dispersed phase from a supersaturated solution on cooling. None of these steels are used
for pressure parts or load carrying components in boilers because, at the high temperatures at which their
oxidation resistance is useful, they are subject to a variety of embrittling, phase precipitation reactions, including 885F (474C) embrittlement and sigma phase formation. They are used as studs for holding refractories and
heat absorbing projections and as thermal shields. These
alloys are also difficult to weld without cracking.
Duplex alloys, with mixed austenitic-ferritic structures, have been developed. They are useful in corrosive lower temperature applications such as those
found in wet desulfurization equipment used as boiler
flue gas scrubbers.
Bimetallic materials Weld cladding of one alloy with
7-14
another has been available for many years. A more
recent development has been the proliferation of bimetallic components, such as tubes and plate containing a load carrying alloy for their major constituent
covered with a layer of a corrosion resistant alloy. The
first bimetallic tubes to see wide use in boilers were
made from Alloy 800H clad with a 50Cr-50Ni alloy
(Alloy 671) for coal ash corrosion resistance. The combination in widest use today is carbon steel clad with
304L, used in pulp and paper process recovery (PR)
boilers. One of the latest to be developed is carbon steel
or 1/2Cr-1/2Mo clad with Alloy 825 (42Ni-21.5Cr-5Mo2.3Cu) used in PR and refuse-fired boilers.17 Other
combinations that have been used are 1/2Cr-1/2Mo
and 2-1/4Cr-1Mo clad with 309.
Cast irons Cast irons and cast steels (containing
more than 2% or less than 2% C, respectively) have
long had wide acceptance as wear resistant and structural components in boilers. Cast steels are also used
for boiler pressure parts. The three types of cast iron
used in boilers are white, gray and ductile iron.
White iron White cast iron is so known because of
the silvery luster of its fracture surface. In this alloy,
the carbon is present in combined form as the iron
carbide cementite (Fe3C). This carbide is chiefly responsible for the hardness, brittleness and poor machinability of white cast iron. Chilled iron differs from
white cast iron only in its method of manufacture and
it behaves similarly. This type of iron is cast against
metal blocks, or chills, that cause rapid cooling at the
adjacent areas, promoting the formation of cementite. Consequently, a white or mottled structure, which
is characterized by high resistance to wear and abrasion, is obtained. Elverite® alloys, a series of white iron,
Ni-enriched cast materials developed by The Babcock
& Wilcox Company (B&W) for use in pulverizers and
other wear resistant parts, have long been noted for
their uniformity and high quality.
VAM 20, a more recent development, is a 20% Cr
white iron with a carbide-in-martensite matrix, very
high hardness and good toughness (compared to other
white irons). The hardness and wear resistance of
VAM 20 are superior to those of the Elverites and similar alloys. It is always used in the heat treated condition, which accounts for its good toughness and uniformity. VAM 20 is used in grinding elements of coal
pulverizers.
Malleable cast iron is white cast iron that has been
heat treated to change its combined carbon (cementite) into free, or temper carbon (nodules of graphite).
The iron becomes malleable because, in this condition,
the carbon no longer forms planes of weakness.
Gray iron Gray cast iron is by far the most widely
used cast metal. In this alloy, the carbon is predominantly in the free state in the form of graphite flakes,
which form a multitude of notches and discontinuities
in the iron matrix. The fracture appearance of this iron
is gray because the graphite flakes are exposed. Gray
iron’s strength depends on the size of the graphite
crystals and the amount of cementite formed with the
graphite. The strength of the iron increases as the
graphite crystal size decreases and the amount of cementite increases. Gray cast iron is easily machinable
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
because the graphite acts as a lubricant. It also provides discontinuities that break the chips as they are
formed. Modern gray iron having a wide range of tensile strength, from 20,000 to 90,000 psi (138 to 621
MPa), can be made by suitable alloying with Ni, Cr,
Mo, V and Cu.
Ductile iron Another member of the cast iron family
is ductile cast iron. It is a high carbon, Mg-treated
ferrous product containing graphite in the form of
spheroids or impacted particles. Ductile cast iron is
similar to gray cast iron in melting point, fluidity and
machinability, but it possesses superior mechanical
properties. This alloy is especially suited for pressure
castings. By special procedures (casting against a chill),
it is possible to obtain a carbide-containing abrasion
resistant surface with an interior of good ductility.
Cast iron was used extensively in early steam boilers for tubes and headers. This material is no longer
used in the pressure parts of modern power boilers but
is used in related equipment such as stoker parts and
the grinding elements of coal pulverizers.
Cast alloys Cast steels and non-ferrous alloys are
used for many support and alignment applications in
boilers, and for some pressure parts having complex
shapes. The alloys range from carbon steel and 2-1/
4Cr-1Mo to 25Cr-12Ni and 50Cr-50Ni.
Ceramics and refractory materials Ceramics and
refractory materials are used for their insulating and
erosion resisting properties. Brick furnace walls have
mostly been replaced by steel membrane panels. (See
Chapter 23.) However, in many applications, these
walls may still have a rammed, troweled or cast refractory protection applied. Refractory linings are still
important features of some furnaces, particularly those
exposed to molten slag. In Cyclone furnaces (see Chapter 15) and other wet-bottom boilers, gunned and
troweled alumina and silicon carbide refractory products are generally used. Chromium-containing refractories are no longer in general use since being classified as a hazardous material.
Cera-VAM is a high density alumina ceramic used
as an erosion liner in coal-air pipeline elbows, coal
pulverizer internals, and pulverizer swing valves to
reduce erosion and the associated maintenance costs.
(See Chapter 13.) Structural ceramics have also been
introduced as hot gas filters. These filters remove particulates from the flue gas of fluidized-bed boilers before the gas enters the high temperature gas turbine
of combined cycle plants. (See Chapter 17.)
Coatings Many types of coatings are applied to
boiler metal parts. In addition to the cast, gunned and
troweled types mentioned above, thinner carbide-containing, metallic matrix coatings are sprayed onto
surfaces in boilers exposed to high velocity particulate
erosion. Metallic coatings are sprayed on boiler parts
exposed to erosion and corrosion wastage by the flame
spraying, twin-wire electric arc, plasma and high velocity
oxy-fuel processes. These are shop- and field-applied
maintenance processes that protect and repair components that experience wastage. Proper surface preparation and process control must be exercised to ensure
that these coatings adhere, have the proper density, and
achieve the recommended thickness on all surfaces.
Steam 41 / Metallurgy, Materials and Mechanical Properties
Chromizing In the mid 1970s, B&W pioneered the
use of chemical vapor deposition (CVD) coatings for
boiler components. Chromizing, a process previously
applied to aircraft jet engine components, is applied
to large surfaces on the interior of tubing and piping.
The purpose of this process is to develop a high Crcontaining surface that is resistant to oxidation and
subsequent exfoliation. High temperature steam carrying pressure parts suffer from oxidation on their
internal surfaces. When the oxide layer becomes thick
enough, it spalls off the surface and the particles are
carried to the steam turbine, where the resulting erosion damage causes loss of efficiency and creates a risk
of mechanical damage. Perfect coverage of tube inside
diameter (ID) surfaces is not necessary to reduce this
condition. If 95% of the susceptible tube surface is
chromized, a twenty-fold reduction in exfoliate particles will result.
In CVD processes, such as chromizing, the surfaces
to be coated are usually covered with or embedded in
a mixture containing powdered metal of the coating
element, e.g., Cr, a halide salt, and a refractory powder, often alumina. When the parts and the mixture
are heated to a sufficiently high temperature, the salt
decomposes and the metal powder reacts with the
halide ion to form a gas, e.g., CrCl2 or CrBr2. At the
surface of the part being coated, an exchange reaction takes place. An Fe atom replaces the Cr in the gas
and the Cr atom is deposited on the surface. The process is conducted at sufficient time and temperature
to permit the Cr to diffuse into the base material. At
the chromizing temperature, 2-1/4Cr-1Mo, for example, is fully austenitic. However, as Cr atoms are
deposited on the surface, the Cr increases the stability of the ferrite phase. As a result, the diffusion front
advances into the matrix concurrently with the phase
transformation front. This results in a diffusion zone
with a nearly constant Cr content. (See Fig. 14.) Typical depths of this zone range from 0.002 to 0.025 in.
(0.051 to 0.64 mm). The diffusion layer on a 2-1/4Cr1Mo substrate has a Cr content range of 30 to 13%.
Chromizing, though first developed to reduce solid
particle erosion of turbines, is now being applied to
external surfaces of boiler pressure parts to reduce or
prevent corrosion and corrosion-fatigue damage. In
these applications, near perfect continuity and integrity of the coating is required. A thicker coating is
necessary to resist the more hostile external environments. Improvements in chromized coating composition and processing have been achieved. Co-diffusion
of Cr and Si, or Cr and Al, is now possible, improving
the corrosion resistance of the coating. Process improvements have allowed for shorter times at diffusing temperature, thus resulting in less undercoating
decarburization and better material properties.
Aluminizing Aluminizing, a similar CVD process,
has been used for many years to protect components
in petrochemical process pressure vessels. However,
alumina, as silica, is soluble in high temperature, high
pressure steam and it can be carried to the turbine,
where pressure and temperature drops cause it to
precipitate on the turbine components; this is undesirable. Aluminizing, either with diffusion processes
7-15
The Babcock & Wilcox Company
Mechanical properties
Low temperature properties
Steels of different properties are used in boilers,
each selected for one or more specific purposes. Each
steel must have properties for both manufacturing and
satisfactory service life. Each particular type, or grade,
of steel must be consistent in its properties, and tests
are normally run on each lot to demonstrate that the
desired properties have been achieved.
Specifications standardizing all the conditions relating to test specimens, methods and test frequency
have been formulated by the American Society for
Testing and Materials (ASTM) and other authorities.
Fig. 14 Chromized 2-1/4Cr-1Mo at 400 X magnification.
or spray metallizing, has also seen some use as an
external, fireside surface protective coating. The diffusion coating over iron-based alloys does create a
brittle iron aluminide phase that can lead to premature loss of the coating, but it has had long term success in a number of petrochemical applications, especially sulfuric acid service, and where carburization
(metal dusting) must be avoided.
Fused coatings Tungsten carbide/chromium carbide
fused metallic coatings are also used for erosion protection of tube membrane panels, for example, in basic oxygen furnace steelmaking furnace hoods. Fused
coatings differ from sprayed coatings in possessing
higher density and achieving better bond strength due
to the brazing-type action of the application process,
which includes a high temperature heat treatment
following the coating application using a conventional
metallizing process.
Galvanizing More mundane coatings, such as galvanizing, painting and organic rust prevention coatings, are also used on boiler components.
Galvanizing, a zinc coating usually applied by dipping in molten metal or by electroplating, is usually
used on structural components external to the boiler,
when erection is near a seashore or a petrochemical
complex.18 Galvanized components must be kept out of
high temperature areas to avoid structural damage due
to zinc grain boundary embrittlement, generally believed to occur at temperatures above 450F (232C).
7-16
Tensile test
In the tensile test, a gradually applied unidirectional pull determines the maximum load that a material can sustain before breaking. The relationship
between the stress (load per unit area) and the corresponding strain (change of length as a percent of the
original length) in the test piece is illustrated in the
stress-strain diagrams of Figs. 15 and 16. The metal
begins to stretch as soon as the load is applied and, for
some range of increasing load, the strain is proportional
to the stress. This is the elastic region of the stress-strain
curve, in which the material very closely follows Hooke’s
Law: strain, ε, is proportional to stress, σ. The proportionality constant may be considered as a spring constant and is called Young’s modulus, E. Young’s modulus is a true material property, characteristic of each
alloy. Young’s modulus for steel is approximately 30 ×
106 psi (206.8 × 106 kPa) at room temperature.
If the stress is released at any point in this region,
the test specimen will return to very nearly its initial
dimensions. However, if the stress is increased beyond
a certain point, the metal will no longer behave elastically; it will have a permanent (plastic) elongation,
and the linear relationship between stress and strain
ceases. This value is known as the proportional limit
of the material and, in this discussion, may be considered practically the same as the elastic limit, which
may be defined as the maximum stress that can be
developed just before permanent elongation occurs.
Fig. 15 Engineering stress-strain curve for 1030 carbon steel
(courtesy of Wiley).19
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
Hardness is usually determined by using specially
designed and standardized machines: Rockwell,
Brinell, Vickers (diamond pyramid), or Tukon. These
all measure resistance to indentation under static
loads. The pressure is applied using a fixed load and
for a specified time, and the indentation is measured
either with a microscope or automatically. It is expressed
as a hardness number, by reference to tables. Hardness
can also be determined by a scleroscope test, in which
the loss in kinetic energy of a falling metal weight, absorbed by indentation upon impact of the metal being
tested, is indicated by the height of the rebound.
Fig. 16 Engineering stress-strain diagram for polycrystalline copper.
Left, complete diagram. Right, elastic region and initial plastic region
showing 0.2% offset yield strength.19
When a material has a well defined point at which
it continues to elongate without further increase in
load, this point is called the yield point. Many steels
do not have a yield point and even in those that do,
neither it nor the proportional or elastic limits can be
determined with accuracy. By convention, therefore,
engineers have adopted an arbitrary but readily measurable concept: the yield strength of a metal. This is
defined as the stress at which the strain reaches 0.2%
of the gauge length of the test specimen. This is illustrated in Fig. 16. (Other values, 0.1% or 0.5% are occasionally used, but 0.2% is most common.)
If the loading is continued after yielding begins, a
test specimen of a ductile material with homogeneous
composition and uniform cross-section will be elongated uniformly over its length, with a corresponding
reduction in area. Eventually, a constriction or necking may occur. In some materials, localized necking
may not occur, but the cross-section may reduce more
or less uniformly along the full gauge length to the
instant of rupture. In all ductile materials, however,
an appreciable increase in elongation occurs in the
reduced area of the specimen. The more ductile the
steel, the greater is the elongation before rupture. The
maximum applied load required to pull the specimen
apart, divided by the area of the original cross-section,
is known as the ultimate tensile strength. Brittle materials do not exhibit yielding or plastic deformation,
and their yield point and ultimate tensile strength are
nearly coincident.
The ductility of the metal is determined by measuring the increase in length (total elongation) and the
final area at the plane of rupture after the specimen
has broken, and is expressed as percent elongation or
percent reduction of area.
Hardness test
Hardness may be defined as resistance to indentation under static or dynamic loads and also as resistance to scratching, abrasion, cutting or drilling. To
the metallurgist, hardness is important as an indicator of the effect of heat treatment, fabrication processes, or service exposure. Hardness values are
roughly indicative of the ultimate tensile strength of
steels. Hardness tests are also used as easy acceptance
tests and to explore local variations in properties.
Steam 41 / Metallurgy, Materials and Mechanical Properties
Toughness tests
Toughness is a property that represents the ability
of a material to absorb local stresses by plastic deformation and thereby redistribute the stresses over a
larger volume of material, before the material fails
locally. It is therefore dependent on the rate of application of the load and the degree of concentration of
the local stresses. In most steels, it is also temperature
dependent, increasing with increasing temperature
(although not linearly). Toughness tests are of two
types, relative and absolute.
Notched bar impact tests are an example of the relative type. The most common is the Charpy test, in
which a simple horizontal beam, supported at both
ends, is struck in the center, opposite a V-shaped notch,
by a single blow of a swinging pendulum. A Charpy
specimen is illustrated in Fig. 17a. The energy absorbed by the breaking specimen can be read directly
on a calibrated scale and is expressed in ft lb units.
The specimen is also examined to determine how
much it has spread laterally and how much of its fracture surface deformed in shear versus cleavage. The
toughness is expressed in units of absorbed energy (ft
lb or J), mils (thousandths of an inch or mm) lateral
expansion and percent shear. The values are characteristic of not only the material and temperature, but
also of the specimen size. Therefore, comparison between materials and tests have meaning only when
specimen geometries and other test conditions are identical. Specimens are inexpensive and the test is easy
to do. Often, vessel designers are interested in the
variation of toughness with temperature. Fig. 18 illustrates the variation in toughness with temperature
of 22 heats of a fine grained carbon steel, SA-299, as
determined by Charpy testing. This material displays
a gradual transition from higher to lower toughness.
Another toughness test, and one that provides a
more sharply defined transition, is the drop-weight
test. The specimen for this test is shown in Fig. 17b. A
known weight is dropped from a fixed height and impacts the specimen. This is a pass or fail test and is
performed on a series of specimens at varying temperatures, selected to bracket the break versus nobreak temperature within 10F (6C). If the impact
causes a crack to propagate to either edge of the specimen from the crack-starter notch in the brittle weld
bead deposited on the face of the specimen, the specimen is considered to have broken at that temperature.
The lowest temperature at which a specimen fails
determines the nil-ductility transition temperature
7-17
The Babcock & Wilcox Company
growth behavior. Fig. 20 illustrates the difference in
crack growth rate in air and in a salt solution for 4340
steel tempered to two strength levels.
Formability tests
Several different types of deformation tests are used
to determine the potential behavior of a material in fabrication. These include bending, flattening, flaring and
cupping tests. They furnish visual evidence of the capability of the material to withstand various forming operations. They are only a rough guide and are no substitute for full scale testing on production machinery.
Fig. 17 (a) Charpy specimen, (b) nil ductility transition temperature
(drop weight) test specimen, (c) compact tension specimen
(courtesy of Prentice-Hall).20
(NDTT). Fig. 19 shows a histogram of NDTTs from 20
heats of fine grained SA-299.
Fracture toughness tests measure true characteristics of a given metal. They are more complex and
specimens are more costly. However, they produce
values that can be used in analytical stress calculations to determine critical flaw sizes above which flaws
or cracks may propagate with little or no increase in
load. A typical fracture toughness specimen is shown
in Fig. 17c. Variations of fracture toughness tests involve testing under cyclic rather than monotonically
increasing load (fatigue crack growth testing) and testing in various environments to determine crack growth
rates as a function of concurrent corrosion processes.
The same specimen is used to determine fatigue crack
Fig. 18 Charpy V-notch impact energy versus test temperature for
fine grained SA-299 plate material.
7-18
High temperature properties
Tensile or yield strength data determined at ambient temperatures can not be used as a guide to the
mechanical properties of metals at higher temperatures. Even though such tests are made at the higher
temperatures, the data are inadequate for designing
equipment for long term service at these temperatures.
This is true because, at elevated temperatures, continued application of load produces a very slow continuous deformation, which can be significant and measurable over a period of time and may eventually lead to
fracture, depending on the stress and temperatures
involved. This slow deformation (creep) occurs for temperatures exceeding about 700F (371C) for ferritic
steels and about 1000F (538C) for austenitic steels.
Tensile strength
Although the design of high temperature equipment
generally requires use of creep and creep-rupture test
data, the short time tensile test does indicate the
strength properties of metals up to the creep range of
the material. This test also provides information on
ductility characteristics helpful in fabrication.
The ultimate strength of plain carbon steel and a
number of alloy steels, as determined by short time
tensile tests over a temperature range of 100F (38C)
to 1300 to 1500F (704 to 816C), is shown in Fig. 21.
In general, the results of these tests indicate that
strength decreases with increase in temperature, although there is a region for the austenitic alloys between 400 and 900F (204 and 482C) where strength
is fairly constant. An exception to the general rule is
Fig. 19 Drop weight nil-ductility transition temperature (NDTT) frequency
distribution for 20 heats of fine grained SA-299 plate material.
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
Fig. 20 Corrosion fatigue crack growth rates for 4340 steel.20
the increase in strength over that at room temperature of carbon and many low alloy steels (with corresponding decrease in ductility) over the temperature
range of 100 to 600F (38 to 316C). As the temperature is increased beyond 600 to 750F (316 to 399C),
the strength of the carbon and most of the low alloy
steels falls off from that at room temperature with a
corresponding increase in ductility.
Creep and creep-rupture test
It has long been known that certain nonmetallic
materials, such as glass, undergo slow and continuous deformation with time when subjected to stress.
The concept of creep in metallic materials, however,
did not attract serious attention until the early 1920s.
Results of several investigations at that time demonstrated that rupture of a metallic material could occur when it is subjected to a stress at elevated temperatures for a sufficiently long time, even though the
load applied is considerably lower than that necessary
to cause rupture in the short time tensile test at the
same temperature.
The earliest investigations of creep in the U.S. were
sponsored by B&W in 1926. Many steels now used
successfully in power generating units and in the petroleum refining and chemical industries were tested
and proved in the course of these investigations, using the best equipment available at the time.
The creep-rupture test is used to determine both the
rate of deformation and the time to rupture at a given
temperature. The test piece, maintained at constant
temperature, is subjected to a fixed static tensile load.
The deformation of the test sample is measured during the test and the time to rupture is determined. The
duration of the test may range from 1000 to 10,000
Steam 41 / Metallurgy, Materials and Mechanical Properties
h, or even longer. A diagrammatic plot of the observed
length of the specimen against elapsed time is often
of the form illustrated in Fig. 22.
The curve representing classical creep is divided into
three stages. It begins after the initial extension (0A), which is simply the measure of deformation of the
specimen caused by the loading. The magnitude of this
initial extension depends on test conditions, varying
with load and temperature and normally increasing
with increases in temperature and load. The first stage
of creep (A-B), referred to as primary creep, is characterized by a decreasing rate of deformation during
the period. The second stage (B-C), referred to as secondary creep, is usually characterized by extremely
small variations in rate of deformation; this period is
essentially one of constant rate of creep. The third
stage (C-D), referred to as tertiary creep, is characterized by an accelerating rate of deformation leading to fracture. Some alloys, however, display a very
limited (or no) secondary creep and spend most of their
test life in tertiary creep.
To simplify the practical application of creep data it
is customary to establish two values of stress (for a
material at a temperature) that will produce two corresponding rates of creep (elongation): 1.0% per
10,000 h and 100,000 h, respectively.
For any specified temperature, several creep-rupture tests must be run under different loads. The creep
rate during the period of secondary creep is determined from these curves and is plotted against the
stress. When these data are plotted on logarithmic
scales, the points for each specimen often lie on a line
Fig. 21 Tensile strength of various steels at temperatures to 1500F
(816C).
7-19
The Babcock & Wilcox Company
the behavior of the particular alloy for which design
values are being established and on the extent and
quality of the database that is available. Several informative discussions on these methods may be found
in ASME publications. (See Appendix 2.)
Material applications in boilers
Fig. 22 Classic (diagrammatic) creep test at constant load and
temperature.
with a slight curvature. The minimum creep rate for
any stress level can be obtained from this graph, and
the curve can also be extrapolated to obtain creep rates
for stresses beyond those for which data are obtained.
Fig. 23 presents such creep rate curves for 2-1/4Cr1Mo steel at 1000, 1100 and 1200F (538, 593 and
649C). The shape of the creep curve depends on the
chemical composition and microstructure of the metal
as well as the applied load and test temperature.
Creep-rupture strength is the stress (initial load
divided by initial area) at which rupture occurs in some
specified time, in an air atmosphere, in the temperature range in which creep takes place. The time for
rupture at any temperature is a function of the applied load. A logarithmic-scale plot of stress versus time
for fracture of specimens generally takes the form of
the curves shown for 2-1/4Cr-1Mo steel in Fig. 24.
In general, rapid rates of elongation indicate a
transgranular (ductile) fracture and slow rates of elongation indicate an intergranular (brittle) fracture. As
a rule, surface oxidation is present when the fracture
is transgranular, while visible intercrystalline oxidation may or may not be present when the fracture is
intergranular. Because of the discontinuities produced
by the presence of intercrystalline oxides, the time to
rupture at a given temperature-load relationship may
be appreciably reduced. In Fig. 24, the slope of the
data at 1200F (649C) is steeper than those for lower
temperatures. This is to be expected, because 1200F
(649C) is above the usual temperature limit for maximum resistance to oxidation of 2-1/4Cr-1Mo. Therefore, excessive scaling occurs in the long time rupture
tests conducted at 1200F (649C).
A complete creep-rupture test program for a given
steel actually consists of a series of tests at constant
temperature with each specimen loaded at a different
level. Because tests are not normally conducted for
more than 10,000 h, the values for rupture times
longer than this are determined by extrapolation. The
ASME Boiler and Pressure Vessel Code Committee
uses several methods of extrapolation, depending on
7-20
ASME specifications and allowable stresses
The ASME Boiler and Pressure Vessel Code Subcommittee on Materials is responsible for identifying
and approving material specifications for those metals deemed suitable for boiler and pressure vessel construction and for developing the allowable design
values for metals as a function of temperature. Most
industrial and all utility boilers are designed to Section I of the Code, Power Boilers, which lists those
material specifications approved for boiler construction. The specifications themselves are listed in Section II, Part A, Ferrous Materials, and Section II, Part
B, Non-Ferrous Materials. The design values are listed
in Section II, Part D, Properties. (Section II, Part C,
Specifications for Welding Rods, Electrodes, and Filler
Metals, contains approved welding materials.)
For many years, there were relatively few changes
in either specifications or design values. Over the last
five or ten years, however, many new alloys have been
introduced and much new data have become available. The restructuring of the North American steel
industry and the globalization of sources of supply and
markets are partly responsible for this rapid rate of
change. As a result, detailed tables of design values
in a text such as this become obsolete much more rapidly than was once the case. A few examples of current allowable stresses are presented below for illustrative purposes. However, the reader is encouraged
to consult Section II for an exposure to material specifications and the latest design values.
The maximum allowable working stresses for materials in power boilers, set by the American Society
of Mechanical Engineers (ASME), are based on both
time-independent and time-dependent properties.
The ASME Boiler and Pressure Vessel Code, Section I, Power Boilers, has established the maximum
Fig. 23 Creep rate curves for 2-1/4Cr-1Mo steel.
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
long-term service, a temperature at which graphitization may be expected, or current commercial practice, whichever is least.
Fig. 24 Typical creep rupture curves for 2-1/4Cr-1Mo steel.
allowable design stress values for pressure parts to be
no higher than the lowest of:
1. 1 / 3.5 × the minimum specified ultimate tensile
strength,
2. 1.1 / 3.5 × the tensile strength at temperature,
3. 67% of the specified minimum yield strength at
room temperature,
4. 67% of the yield strength at temperature, for ferritic steels; or 90% of the yield strength at temperature of austenitic steels and nickel base alloys,
5. a conservative average of the stress to give a creep
rate of 0.01% in 1000 hours (1% in 100,000
hours), or
6. 67% of the average or 80% of the minimum stress
to produce rupture in 100,000 hours.
Furthermore, the allowable stress at a higher temperature can not exceed that at a lower temperature,
so no advantage is taken of strain aging behavior. The
allowable stress is therefore the lower bound envelope
of all these criteria. The tensile and yield strengths at
temperature have a particular meaning in Code usage.
For austenitic materials that possess allowable design properties above 1500F (816C), the ASME Code
has recently adopted an additional criterion applied
to creep rupture data of the specific alloy. The criterion involves a statistical evaluation of the data and
ensures that a consistent safety factor exists at the
very high temperatures.
Pressure part applications
The metal product forms used in boiler pressure
parts are tubes and pipe (often used interchangeably),
plate, forgings and castings. Tubular products compose the greatest part of the weight. The matrix in
Table 1 shows the common pressure part material
specifications used in fossil fuel fired boilers today,
their minimum specified properties, recommended
maximum use temperatures, and their applications.
This list is not meant to be all inclusive, as there are
many other specifications permitted by Section I and
several of them see occasional use. Neither is it meant
to be exclusive, as several of these specifications are
used occasionally for components not checked in Table
1. Finally, the recommended maximum use temperatures represent one or more of a variety of limits. The
temperature listed may be the highest for which
stresses are listed in Section I, the oxidation limit for
Steam 41 / Metallurgy, Materials and Mechanical Properties
Boiler, furnace waterwall, convection pass
enclosures and economizers
Boiler, furnace waterwall, and convection pass enclosure surfaces are generally made of carbon steel,
C-Mo, and 1/2Cr-1/2Mo seamless or electric-resistancewelded (ERW) tubes. Lower carbon grades and 1/2Cr1/2Mo alloy are used in high heat input regions to
avoid the risk of graphitization in this region where
tube metal temperatures may be subject to more fluctuation and uncertainty. Higher carbon grades and
C-Mo are used in furnace floors, upper furnace walls,
convection pass enclosures, and economizers.
The boiler industry is seeing increasing use of
higher Cr-Mo grades in these applications, especially
as temperatures and pressures increase with the latest designs. 1Cr-1/2Mo, 1-1/4 Cr-1/2Mo-Si, and even
2-1/4 Cr-1Mo will see increased use. Even higher alloys present formidable manufacturing challenges
that will likely restrict these applications to alloys possessing less than 3% Cr.
Superheaters and reheaters
The highest metal temperatures of pressure parts
in the steam generating unit occur in the superheater
and reheater. Consequently, these tubes are made of
material having superior high temperature properties
and resistance to oxidation. Carbon steel is a suitable
and economical material to about 850 to 950F (454 to
510C) metal temperature, depending on pressure.
Above this range, alloy and stainless steels are required because of the low oxidation resistance and the
low allowable stresses of carbon steel. Usually two or
more alloys are used in the construction of the superheater. The lower alloys, such as carbon and C-Mo
steels, are used toward the inlet section, while the low
and intermediate alloy Cr-Mo steels are used toward
the outlet, where the steam and metal temperatures
are higher. (See Chapter 19.)
Stainless steel tubes have been required in the
hottest sections of the superheater. However, stainless
steels are being replaced in many applications by 9Cr1Mo-V. This high strength ferritic steel was developed
initially by The Oak Ridge National Laboratory for
fast breeder nuclear reactor components. However, it
has found many applications in fossil fuel-fired boilers because of its high strength and excellent toughness. Because it is ferritic, its use in place of stainless
steel eliminates dissimilar metal weld failures.
New alloys, both ferritic and austenitic, are constantly being developed and are appearing in boilers
around the world. The most promising ferritic alloys
use alloying additions of elements such as V, Cb (Nb),
W and N which, when combined with controlled normalizing and tempering heat treatment, result in
materials possessing creep strength far superior to the
traditional Cr-Mo alloy grades in the 2.25 to 12% Cr
range. Newer austenitic alloys use modified alloying
with elements such as Cu, Cb (Nb) and N, sometimes
combined with special thermal mechanical processing,
7-21
The Babcock & Wilcox Company
Table 1
Boiler Materials and Typical Applications (English Units)
Specification
SA-178A
SA-192
SA-178C
SA-210A1
SA-106B
SA-178D
SA-210C
SA-106C
SA-216WCB
SA-105
SA-181-70
SA-266Cl2
SA-516-70
SA-266Cl3
SA-299
SA-250T1a
SA-209T1a
SA-250T2
SA-213T2
SA-250T12
SA-213T12
SA-335P12
SA-250T11
SA-213T11
SA-335P11
SA-217WC6
SA-250T22
SA-213T22
SA-213T23
SA-335P22
SA-217WC9
SA-182F22Cl1
SA-336F22Cl1
SA-213T91
SA-335P91
SA-217C12A
SA-182F91
SA-336F91
SA-213T92
SA-213TP304H
SA-213TP347H
SA-213TP310H
SB-407-800H
SB-423-825
Nominal
Composition
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Steel
C-Mo
C-Mo
1/2Cr-1/2Mo
1/2Cr-1/2Mo
1Cr-1/2Mo
1Cr-1/2Mo
1/2Cr-1/2Mo
1-1/4Cr-1/2Mo-Si
1-1/4Cr-1/2Mo-Si
1-1/4Cr-1/2Mo-Si
1-1/4Cr-1/2Mo
2-1/4Cr-1Mo
2-1/4Cr-1Mo
2-1/4Cr-W-V
2-1/4Cr-1Mo
2-1/4Cr-1Mo
2-1/4Cr-1Mo
2-1/4Cr-1Mo
9Cr-1Mo-V
9Cr-1Mo-V
9Cr-1Mo-V
9Cr-1Mo-V
9Cr-1Mo-V
9Cr-2W
18Cr-8Ni
18Cr-10Ni-Cb
25Cr-20Ni
Ni-Cr-Fe
Ni-Fe-Cr-Mo-Cu
Product
Form
ERW tube
Seamless tube
ERW tube
Seamless tube
Seamless pipe
ERW tube
Seamless tube
Seamless pipe
Casting
Forging
Forging
Forging
Plate
Forging
Plate
ERW tube
Seamless tube
ERW tube
Seamless tube
ERW tube
Seamless tube
Seamless pipe
ERW tube
Seamless tube
Seamless pipe
Casting
ERW tube
Seamless tube
Seamless tube
Seamless pipe
Casting
Forging
Forging
Seamless tube
Seamless pipe
Casting
Forging
Forging
Seamless tube
Seamless tube
Seamless tube
Seamless tube
Seamless tube
Seamless tube
Min
Tensile,
ksi
Min High Heat Other Furn SH
Unheated
Headers
Recomm
Yield, Input Furn Walls and
RH
Conn Pipe
and Pipe
Max Use
ksi
Walls
Enclosures Econ <10.75 in. OD >10.75 in. OD Drums Temp, F Notes
(47.0) (26.0)
(47.0) (26.0)
60.0
37.0
60.0
37.0
60.0
35.0
70.0
40.0
70.0
40.0
70.0
40.0
70.0
36.0
70.0
36.0
70.0
36.0
70.0
36.0
70.0
38.0
75.0
37.5
75.0
40.0
60.0
32.0
60.0
32.0
60.0
30.0
60.0
30.0
60.0
32.0
60.0
32.0
60.0
32.0
60.0
30.0
60.0
30.0
60.0
30.0
70.0
40.0
60.0
30.0
60.0
30.0
74.0
58.0
60.0
30.0
70.0
40.0
60.0
30.0
60.0
30.0
85.0
60.0
85.0
60.0
85.0
60.0
85.0
60.0
85.0
60.0
90.0
64.0
75.0
30.0
75.0
30.0
75.0
30.0
65.0
25.0
85.0
35.0
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
950
950
950
950
950
950
950
950
950
950
950
800
800
800
800
975
975
1025
1025
1050
1050
1050
1050
1050
1050
1100
1115
1115
1115
1100
1115
1115
1100
1150
1150
1200
1150
1150
1200
1400
1400
1500
1500
1000
1,2
1
2
3
2
3
3
3
4,5
4
6
6
5
5
5
Notes:
1. Values in parentheses are not required minimums, but are expected minimums.
2. Requires special inspection if used at 100% efficiency above 850F.
3. Limited to 800F maximum for piping 10.75 in. OD and larger and outside the boiler setting.
4. Limited to 875F maximum for applications outside the boiler setting.
5. Requires special inspection if used at 100% efficiency.
6. Maximum OD temperature is 1025F. Maximum mean metal temperature for Code calculations is l000F.
to enhance creep strength. A new family of Ni and NiCr-Co alloys is also available, specifically for advanced
supercritical and advanced supercritical boiler designs.
Fuel ash corrosion considerations might dictate the
use of higher alloys at lower temperatures. This is
common in process recovery and refuse-fired boilers
with very corrosive flue gas and ash. For example, SB407-825 (42Ni-21.5Cr-3Mo-2.25Cu-0.9Ti-bal Fe) is
used in the highly corrosive regions of refuse boiler
superheaters, even at temperatures below 1000F
(538C). In extreme cases, bimetallic tubes, with a core
7-22
of a Code material for pressure retention and a cladding of a corrosion resistant alloy, are used for both
furnace wall and superheater applications. Some common combinations are SA-210A1/304L, SA-210A1/
Alloy 825, and SB-407-800H/50Cr-50Ni.
Selection factors
Many factors influence material selection in a superheater. These include cost as well as performance
factors (heat transfer surface area required, final
steam temperature, total mass flow through the tubes,
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
and flow balancing among circuits); mechanical factors (internal pressure, design temperature, support
systems and relative thermal expansion stresses);
environmental factors (resistance to steam oxidation
and out of service pitting corrosion on the ID, and oxidation, fuel ash corrosion, and erosion on the outside
diameter/OD); and manufacturing process and equipment limitations and considerations, such as weldability.
Cost
Material cost is usually the single largest factor
affecting material selection when more than one material candidate exists for a given set of boiler application conditions. Raw material cost is established by
taking into account each material’s allowable design
stress, at design temperature and pressure, and required mass flow requirements for the water or steam.
Pressure part sizes are established, average weight
determined, and material cost is estimated when
knowing the raw material cost offered by the selected
raw material supplier. Other factors are also considered such as required corrosion allowance, if any, and
unique manufacturing costs and risks. Once this
evaluation is accomplished and comparison of materials
is completed, it is quite common to find that stronger,
higher alloys become economically attractive over lower
strength, less costly steels at operating conditions usually acceptable and appropriate for the lower alloy steel.
Headers and piping
Specifications for most of the commonly used pipe
materials are listed in Table 1. As these components
are usually not in the gas stream and are unheated,
the major design factor, other than strength at temperature, is steam oxidation resistance. Carbon steels
are not used above 800F (427C) outside the boiler setting, and C-Mo is limited to applications of small sizes
[less than 10.75 in. (273 mm) OD] and below 875F
(468C) to avoid graphitization.
9Cr-1Mo-V has replaced 2-1/4Cr-1Mo for many
superheater outlet header applications (see Fig. 25).
This material is not operating in the creep range even
at the 1000 to 1050F (538 to 566C) design temperatures of most such components. This factor and its very
high strength allow thinner components which are
much less susceptible to the creep-fatigue failures
observed in older 1-1/4Cr-1/2Mo-Si and 2-1/4Cr-1Mo
headers. The use of forged outlet nozzle tee sections
in place of welded nozzles has also reduced the potential for failure of these large piping connections.
Drums
Carbon steel plate is the primary material used in
drums. SA-299, a 75,000 psi (517.1 MPa) tensile
strength material, ordered to fine grain melting practice for improved toughness, is used for heavy section
Fig. 25 The 9Cr-1Mo-V superheater outlet header features high strength and thin material less susceptible to creep-fatigue failure.
Steam 41 / Metallurgy, Materials and Mechanical Properties
7-23
The Babcock & Wilcox Company
drums, those more than about 4 in. (101.6 mm) in
thickness. SA-516 Gr 70, a fine grained 70,000 psi
(482.7 MPa) tensile strength steel, is used for applications below this thickness, down to 1.5 in. (38.1 mm)
thick shells. SA-515 Gr 70, a coarse grain melting
practice steel, is used for thinner shells. Steel grades
of 80,000 psi (552 MPa) and higher are available.
However, only in rare cases, where crane lifting capacity or long distance shipping costs are important
considerations, are higher strength steels used due to
increased manufacturing difficulties with the higher
strength steels.
Heat resistant alloys for nonpressure parts
High alloy heat resistant materials must be used
for certain boiler parts that are exposed to high temperature and can not be water or steam cooled. These
parts are made from alloys of the oxidation resistant,
relatively high strength Cr-Ni-Fe type, many of them
cast to shape as baffles, supports and hanger fittings.
Oil burner impellers, sootblower clamps and hangers
are also made of such heat resisting alloy steels.
Deterioration of these parts may occur through conversion of the surface layers to oxides, sulfides and
sulfates. Experience indicates that 25Cr-12Ni and
25Cr-20Ni steels give reasonably good service life,
depending on the location of the part in the flue gas
stream and on the characteristics of the fuel. Temperatures to which these metal parts are exposed may
range from 1000 to 2800F (538 to 1538C). Welding of
such austenitic castings to ferritic alloy tubes presents
a dissimilar metal weld that is susceptible to failure.
Normal practice is to use a nickel-base filler metal that
better matches the thermal expansion properties of the
ferritic tube than would an austenitic stainless weld
composition. If possible, a ferritic alloy weld rod should
be used to further reduce stresses against the ferritic
pressure part, provided there is adequate weldability
and operating conditions at the weld location are acceptable. Special patented nonwelded constructions
are also used where such combinations are required.
Life may be shortened if these steels are exposed to
flue gases from fuel oil containing vanadium compounds. Sulfur compounds formed from combustion
of high sulfur fuels are also detrimental and act to
reduce life. These may react in the presence of V and
cause greatly accelerated rates of attack, especially
when the temperature of the metal part exceeds 1200F
(649C). Combinations of Na, S and V compounds are
reported to melt at as low as 1050F (566C). Such deposits are extremely corrosive when molten because of
their slagging action. In these circumstances, 50Cr50Ni or 60Cr-40Ni castings are used to resist corrosion.
References
1. Cullity, B.D., Elements of X-Ray Diffraction, Second
Ed., Addison-Wesley Publishing Company, Inc., Reading,
Massachusetts, 1978.
2. Darken, L.S., The Physical Chemistry of Metallic Solutions and Intermetallic Compounds, Her Majesty’s Stationery Office, London, England, United Kingdom, 1958.
3. Swalin, R.A., Thermodynamics of Solids, Wiley &
Sons, New York, New York, 1972.
4. Higgins, R.A., Properties of Engineering Materials,
Hodder and Staughton, London, England, United Kingdom, 1979.
5. Bain, E.C., and Paxton, H.W., Alloying Elements in
Steel, Second Ed., American Society for Metals, Metals
Park, Ohio, 1966.
6. McGannon, H.E., Ed., The Making, Shaping and Treating of Steel, Ninth Ed., United States Steel, Pittsburgh,
Pennsylvania, 1970.
7. Lankford, W.T., Jr., et al., The Making, Shaping and
Treating of Steel, Tenth Ed., Association of Iron and Steel
Engineers, Pittsburgh, Pennsylvania, 1985.
8. Long, C.J., and DeLong, W.T., “The ferrite content of
austenitic stainless steel weld metal,” Welding Journal,
Research Supplement, pp. 281S-297S, Vol. 52 (7), 1973.
9. Boyer, H.E., and Gall, T.L., Eds., Metals Handbook:
Desk Edition, American Society for Metals, Metals Park,
Ohio, 1985.
7-24
10. Connor, L., Ed., Welding Handbook, Eighth Ed.,
American Welding Society, Vol. 1, Miami, Florida, 1987.
10a. Weisman, C., Ed., Welding Handbook, Seventh Ed.,
American Welding Society, p. 272, Vol. 1, Miami, Florida,
l981.
11. Weisman, C., Ed., Welding Handbook, Seventh Ed.,
American Welding Society, p. 229, Vol. 1, Miami, Florida,
l981.
12. Sikka, V.K., et al., “Modified 9Cr-1Mo steel: an improved alloy for steam generator application,” Ferritic
Steels for High Temperature Applications, Proceedings of
the ASM International Conference on Production, Fabrication, Properties and Application of Ferritic Steels for
High Temperature Service, pp. 65-84, Warren, Pennsylvania, October 6-8, 1981, Khare, A.K., Ed., American Society for Metals, Metals Park, Ohio, 1963.
13. Swindeman, R.W., and Gold, M., “Developments in ferrous alloy technology for high temperature service,” Widera,
G.E.O., Ed., Transactions of the ASME: J. Pressure Vessel
Technology, p. 135, American Society of Mechanical Engineers (ASME), New York, New York, May, 1991.
14. Rudd, A.H., and Tanzosh, J.M., “Developments applicable to improved coal-fired power plants,” presented at the
First EPRI International Conference on Improved CoalFired Power Plants, Palo Alto, California, November 1921, 1986.
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
15. Viswanathan, R., et al., “Ligament cracking and the
use of modified 9Cr-1Mo alloy steel (P91) for boiler headers,” presented at the 1990 American Society of Mechanical Engineers (ASME) Pressure Vessels and Piping Conference, Nashville, Tennessee, June 17-21, 1990, Prager, M.,
and Cantzlereds, C., New Alloys for Pressure Vessels and
Piping, pp. 97-104, ASME, New York, New York, 1990.
16. Benjamin, D., et al., “Properties and selection: stainless steels, tool materials and special purpose metals,”
Metals Handbook, Ninth Ed., Vol. 3, American Society for
Metals, Metals Park, Ohio, p. 17, 1980.
17. Barna, J.L., et al., “Furnace wall corrosion in refusefired boilers,” presented to the ASME 12th Biennial National Waste Processing Conference, Denver, Colorado,
June l-4, 1986.
Steam 41 / Metallurgy, Materials and Mechanical Properties
18. Morro, H., III, “Zinc,” Metals Handbook, Desk Edition, pp. 11-l to 11-3, Boyer, H.E., and Gall, T.L., Eds.,
American Society for Metals, Metals Park, Ohio.
19. Hayden, H.W., et al., The Structure and Properties
of Materials, Vol. III, Mechanical Behavior, Wiley & Sons,
New York, New York, 1965.
20. Barsom, J.M., and Rolfe, S.T., Fracture and Fatigue
Control in Structures, Second Ed., Prentice-Hall,
Englewood Cliffs, New Jersey, 1987.
7-25
The Babcock & Wilcox Company
Application of protective coating to boiler tubes.
7-26
Steam 41 / Metallurgy, Materials and Mechanical Properties
The Babcock & Wilcox Company
Chapter 8
Structural Analysis and Design
Equipment used in the power, chemical, petroleum
and cryogenic fields often includes large steel vessels.
These vessels may require tons of structural steel for
their support. Steam generating and emissions control equipment, for example, may be comprised of pressure parts ranging from small diameter tubing to vessels weighing more than 1000 t (907 tm). A large fossil
fuel boiler may extend 300 ft (91.4 m) above the
ground, requiring a steel support structure comparable to a 30 story building. To assure reliability, a
thorough design analysis of pressure parts and their
supporting structural components is required.
Boiler and Pressure Vessel Code. Key sections include
Sections I, Rules for Construction of Power Boilers; III,
Rules for Construction of Nuclear Power Plant Components; and VIII, Rules for Construction of Pressure
Vessels. A further introduction to the ASME Code is
presented in Appendix 2.
Stress significance
Stress is defined as the internal force between two
adjacent elements of a body, divided by the area over
which it is applied. The main significance of a stress
is its magnitude; however, the nature of the applied
Pressure vessel design and analysis
Steam generating units require pressure vessel
components that operate at internal pressures of up
to 4000 psi (27.6 MPa) and at steam temperatures up
to 1100F (566C). Even higher temperature and pressure conditions are possible in advanced system designs. Maximum reliability can be assured only with
a thorough stress analysis of the components. Therefore, considerable attention is given to the design and
stress analysis of steam drums, superheater headers,
heat exchangers, pressurizers and nuclear reactors.
In designing these vessels, the basic approach is to
account for all unknown factors such as local yielding and stress redistribution, variability in material
properties, inexact knowledge of loadings, and inexact stress evaluations by using allowable working
stresses that include appropriate factors of safety.
The analysis and design of complex pressure vessels and components such as the reactor closure head,
shown in Fig. 1, and the fossil boiler steam drum,
shown in Fig. 2, requires sophisticated principles and
methods. Mathematical equations based on the theory
of elasticity are applied to regions of discontinuities,
nozzle openings and supports. Advanced computerized
structural mechanics methods, such as the finite element
method, are used to determine complex vessel stresses.
In the United States (U.S.), pressure vessel construction codes adopted by state, federal and municipal authorities establish safety requirements for vessel construction. The most widely used code is the
American Society of Mechanical Engineers (ASME)
Steam 41 / Structural Analysis and Design
Fig. 1 Head of nuclear reactor vessel.
8-1
The Babcock & Wilcox Company
Maximum stress theory The maximum stress theory
considers failure to occur when one of the three principal stresses (σ) reaches the material yield point (σy.p.)
in tension:
σ = σ y.p.
Fig. 2 Fossil fuel boiler steam drum.
load and the resulting stress distribution are also important. The designer must consider whether the loading is mechanical or thermal, whether it is steady-state
or transient, and whether the stress pattern is uniform.
Stress distribution depends on the material properties. For example, yielding or strain readjustment
can cause redistribution of stresses.
Steady-state conditions An excessive steady-state
stress due to applied pressure results in vessel material distortion, progresses to leakage at fittings and
ultimately causes failure in a ductile vessel. To prevent this type of failure a safety factor is applied to
the material properties. The two predominant properties considered are yield strength, which establishes
the pressure at which permanent distortion occurs,
and tensile strength, which determines the vessel
bursting pressure. ASME Codes establish pressure
vessel design safety factors based on the sophistication of quality assurance, manufacturing control, and
design analysis techniques.
Transient conditions When the applied stresses are
repetitive, such as those occurring during testing and
transient operation, they may limit the fatigue life of
the vessel. The designer must consider transient conditions causing fatigue stresses in addition to those
caused by steady-state forces.
Although vessels must have nozzles, supports and
flanges in order to be useful, these features often embody abrupt changes in cross-section. These changes
can introduce irregularities in the overall stress pattern called local or peak stresses. Other construction
details can also promote stress concentrations which,
in turn, affect the vessel’s fatigue life.
Strength theories
Several material strength theories are used to determine when failure will occur under the action of
multi-axial stresses on the basis of data obtained from
uni-axial tension or compression tests. The three most
commonly applied theories which are used to establish elastic design stress limits are the maximum (principal) stress theory, the maximum shear stress theory,
and the distortion energy theory.
8-2
(1)
This theory is the simplest to apply and, with an
adequate safety factor, it results in safe, reliable pressure vessel designs. This is the theory of strength used
in the ASME Code, Section I, Section VIII Division 1,
and Section III Division 1 (design by formula Subsections NC-3300, ND-3300 and NE-3300).
Maximum shear stress theory The maximum shear
stress theory, also known as the Tresca theory,1 considers failure to occur when the maximum shear stress
reaches the maximum shear stress at the yield
strength of the material in tension. Noting that the
maximum shear stress (τ) is equal to half the difference of the maximum and minimum principal stresses,
and that the maximum shear stress in a tension test
specimen is half the axial principal stress, the condition for yielding becomes:
σ
σ max − σ min
= y.p.
2
2
2τ = σ max − σ min = σ y.p.
τ =
(2)
The value 2τ is called the shear stress intensity. The
maximum shear stress theory predicts ductile material yielding more accurately than the maximum stress
theory. This is the theory of strength used in the
ASME Code, Section VIII Division 2, and Section III
Division 1, Subsection NB, and design by analysis,
Subsections NC-3200 and NE-3200.
Distortion energy theory The distortion energy
theory (also known as the Mises criterion1) considers
yielding to occur when the distortion energy at a point
in a stressed element is equal to the distortion energy
in a uni-axial test specimen at the point it begins to yield.
While the distortion energy theory is the most accurate
for ductile materials, it is cumbersome to use and is not
routinely applied in pressure vessel design codes.
Design criteria1
To determine the allowable stresses in a pressure
vessel, one must consider the nature of the loading and
the vessel response to the loading. Stress interpretation determines the required stress analyses and the
allowable stress magnitudes. Current design codes
establish the criteria for safe design and operation of
pressure vessels.
Stress classifications Stresses in pressure vessels
have three major classifications: primary, secondary
and peak.
Primary stresses (P) are caused by loadings which
are necessary to satisfy the laws of equilibrium with
applied pressure and other loads. These stresses are
further divided into general primary membrane (Pm),
local primary membrane (PL) and primary bending (Pb)
stresses. A primary stress is not self-limiting, i.e., if the
material yields or is deformed, the stress is not reduced.
A good example of this type of stress is that produced
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
by internal pressure such as in a steam drum. When
it exceeds the vessel material yield strength, permanent distortion appears and failure may occur.
Secondary stresses (Q), due to mechanical loads or
differential thermal expansion, are developed by the
constraint of adjacent material or adjacent components. They are self-limiting and are usually confined
to local areas of the vessel. Local yielding or minor
distortion can reduce secondary stresses. Although
they do not affect the static bursting strength of a
vessel, secondary stresses must be considered in establishing its fatigue life.
Peak stresses (F ) are concentrated in highly localized areas at abrupt geometry changes. Although no
appreciable vessel deformations are associated with
them, peak stresses are particularly important in
evaluating the fatigue life of a vessel.
Code design/analysis requirements Allowable stress
limits and design analysis requirements vary with
pressure vessel design codes.
According to ASME Code, Section I, the minimum
vessel wall thickness is determined by evaluating the
general primary membrane stress. This stress, limited
to the allowable material tension stress S, is calculated
at the vessel design temperature. The Section I regulations have been established to ensure that secondary and peak stresses are minimized; a detailed analysis of these stresses is normally not required.
The design criteria of ASME Code, Sections VIII
Division 1, and Section III Division 1 (design by formula Subsections NC-3300, ND-3300 and NE-3300),
are similar to those of Section I. However, they require
cylindrical shell thickness calculations in the circumferential and longitudinal directions. The minimum
required pressure vessel wall thickness is set by the
maximum stress in either direction. Section III Division 1 and Subsections NC-3300 and ND-3300 permit the combination of primary membrane and primary bending stresses to be up to 1.5 S at design temperature. Section VIII Division 1 permits the combination of primary membrane and primary bending
stresses to be 1.5 S at temperatures where tensile or
yield strength sets the allowable stress S, and a value
smaller than 1.5 S at temperatures where creep governs the allowable stress.
ASME Code, Section VIII Division 2 provides formulas and rules for common configurations of shells
and formed heads. It also requires detailed stress
analysis of complex geometries with unusual or cyclic
loading conditions. The calculated stress intensities are
assigned to specific categories. The allowable stress
intensity of each category is based on a multiplier of
the Code allowable stress intensity value. The Code
allowable stress intensity, Sm, is based on the material
yield strength, Sy, or tensile strength, Su. (See Table 1.)
The factor k varies with the type of loading:
k
Loading
1.0
sustained
1.2
sustained and transient
1.25
hydrostatic test
1.5
pneumatic test
Steam 41 / Structural Analysis and Design
Table 1
Code-Allowable Stress Intensity
Stress Intensity
Category
Allowable
Value
Basis for
Allowable
Value at k = 1.0
(Lesser Value)
General primary
membrane (Pm )
kSm
2/3 Sy or 1/3 Su
Local primary
membrane (PL )
3/2 kSm
Sy or 1/2 Su
Primary membrane
plus primary
bending (Pm + Pb )
3/2 kSm
Sy or 1/2 Su
3 Sm
2 Sy or Su
Range of primary plus
secondary (Pm + Pb + Q)
The design criteria for ASME Code, Section III Division 1, Subsection NB and design by analysis Subsections NC-3200 and NE-3200 are similar to those for
Section VIII Division 2 except there is less use of design
formulas, curves, and tables, and greater use of design
by analysis in Section III. The categories of stresses and
stress intensity limits are the same in both sections.
Stress analysis methods
Stress analysis of pressure vessels can be performed
by analytical or experimental methods. An analytical
method, involving a rigorous mathematical solution
based on the theory of elasticity and plasticity, is the
most direct and inexpensive approach when the problem is adaptable to such a solution. When the problem is too complex for this method, approximate analytical structural mechanics methods, such as finite
element analysis, are applied. If the problem is beyond
analytical solutions, experimental methods must be
used.
Mathematical formulas2 Pressure vessels are commonly spheres, cylinders, ellipsoids, tori or composites
of these. When the wall thickness is small compared to
other dimensions, vessels are referred to as membrane
shells. Stresses acting over the thickness of the vessel
wall and tangential to its surface can be represented by
mathematical formulas for the common shell forms.
Pressure stresses are classified as primary membrane
stresses since they remain as long as the pressure is
applied to the vessel. The basic equation for the longitudinal stress σ1 and hoop stress σ2 in a vessel of
thickness h, longitudinal radius r1, and circumferential radius r2, which is subject to a pressure P, shown
in Fig. 3 is:
σ1 σ 2
P
+
=
r1
r2
h
(3)
From this equation, and by equating the total pressure load with the longitudinal forces acting on a transverse section of the vessel, the stresses in the commonly
used shells of revolution can be found.
8-3
The Babcock & Wilcox Company
Fig. 4 Stress in an ellipsoid.2
σ2 =
r22
P
r2 −
h
2r1
(11)
At the equator, the longitudinal stress is the same
as the longitudinal stress in a cylinder, namely:
σ1 =
Fig. 3 Membrane stress in vessels (courtesy Van Nostrand Reinhold).2
1. Cylindrical vessel – in this case, r1 = ∞, r2 = r, and
Pr
σ1 =
2h
(4)
Pr
h
(5)
σ2 =
2. Spherical vessel – in this case, r1 = r2 = r, and
Pr
σ1 =
(6)
2h
σ2 =
Pr
2h
(7)
3. Conical vessel – in this case, r1 = ∞, r2 = r/cos α
where α is half the cone apex angle, and
Pr
σ1 =
2h cos α
Pr
σ2 =
h cos α
σ1 =
8-4
Pr2
2h
σ2 =
Pa
h
a2
1 − 2
2b
(10)
(13)
When the ratio of major to minor axis is 2:1, the
hoop stress is the same as that in a cylinder of the
same mating diameter, but the stress is compressive rather than tensile. The hoop stress rises rapidly when the ratio of major to minor axis exceeds
2:1 and, because this stress is compressive, buckling instability becomes a major concern. For this
reason, ratios greater than 2:1 are seldom used.
5. Torus – in this case (Fig. 5), Ro is the radius of the
bend centerline, θ is the angular hoop location
from this centerline and:
(8)
4. Ellipsoidal vessel – in this case (Fig. 4), the instantaneous radius of curvature varies with each position on the ellipsoid, whose major axis is a and
minor axis is b, and the stresses are given by:
(12)
and the hoop stress is:
Pr
2h
(14)
Pr 2 Ro + r sin θ
2h Ro + r sin θ
(15)
σ1 =
(9)
Pa
2h
σ2 =
The longitudinal stress remains uniform around the
circumference and is the same as that for a straight
cylinder. The hoop stress, however, varies for different points in the torus cross-section. At the bend
centerline, it is the same as that in a straight cylinder. At the outside of the bend, it is less than this and
is at its minimum. At the inside of the bend, or crotch,
the value is at its maximum. Hoop stresses are depenSteam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
dent on the sharpness of the bend and are inversely
proportional to bend radii. In pipe bending operations,
the material thins at the outside and becomes thicker
at the crotch of the bend. This is an offsetting factor
for the higher hoop stresses that form with smaller
bend radii.
Thermal stresses result when a member is restrained as it attempts to expand or contract due to a
temperature change, ∆T. They are classified as sec-
ASME Code calculations
In most U.S. states and Canadian provinces laws
have been established requiring that boilers and pressure vessels comply with the rules for the design and
construction of boilers and pressure vessels in the ASME
Code. The complexity of these rules and the amount of
analysis required are inversely related to the factors of
safety which are applied to the material properties used
to establish the allowable stresses. That is, when the
stress analysis is simplified, the factor of safety is larger.
When the stress analysis is more complex, the factory
of safety is smaller. Thus, overall safety is maintained
even though the factor of safety is smaller. For conditions when material tensile strength establishes the
allowable stress, ASME Code, Section IV, Rules for Construction of Heating Boilers, requires only a simple
thickness calculation with a safety factor on tensile
strength of 5. ASME Code, Section I, Rules for Construction of Power Boilers and Section VIII, Division 1, Rules
for Construction of Pressure Vessels, require a more
complex analysis with additional items to be considered.
However, the factor of safety on tensile strength is reduced to 3.5. Section III, Rules for Construction of
Nuclear Components and Section VIII, Division 2, Rules
for Construction of Pressure Vessels require extensive
analyses which are required to be certified by a registered professional engineer. In return, the factor of safety
on tensile strength is reduced even further to 3.0.
When the wall thickness is small compared to the diameter, membrane formulas (Equations 4 and 5) may be
used with adequate accuracy. However, when the wall
thickness is large relative to the vessel diameter, usually
to accommodate higher internal design pressure, the membrane formulas are modified for ASME Code applications.
Basically the minimum wall thickness of a cylindrical shell is initially set by solving the circumferential
or hoop stress equation assuming there are no additional
loadings other than internal pressure. Other loadings
may then be considered to determine if the initial minimum required wall thickness has to be increased to
keep calculated stresses below allowable stress values.
As an example, consider a Section VIII, Division 1,
pressure vessel with no unreinforced openings and no
additional loadings other than an internal design pressure of 1200 psi at 500F. The inside diameter is 10 in.
and the material is SA-516, Grade 70 carbon steel. There
is no corrosion allowance required by this application
and the butt weld joints are 100% radiographed. What
is the minimum required wall thickness needed? The
equation for setting the minimum required wall thickness in Section VIII, Division 1, of the Code (paragraph
UG-27(c)(l), 2001 Edition) is:
t =
ondary stresses because they are self-limiting. If the
material is restricted in only one direction, the stress
developed is:
σ = ± E α ∆T
(16)
where E is the modulus of elasticity and α is the coefficient of thermal expansion. If the member is restricted from expanding or contracting in two direc-
where
t
P
R
S
=
=
=
=
minimum required wall thickness, in.
internal design pressure, psi
inside radius, in.
allowable stress at design temperature, psi (Section II, Part D) = 20,000 psi
E = lower of weld joint efficiency or ligament efficiency
(fully radiographed with manual penetrations) =
1.0
For the pressure vessel described above:
P
R
S
E
= 1200 psi
= 5 in.
= 20,000 psi
= 1.0
t =
(1200) (5)
= 0.311 in.
(20, 000) (1.0 ) − (0.6) (1200 )
Using commercial sizes, this plate thickness probably
would be ordered at 0.375 in.
If Equation 5 for simple hoop stress (see Figure below) is used alone to calculate the plate thickness using
the specified minimum tensile strength of SA-516, Grade
70 of 70,000 psi, the thickness h would be evaluated to be:
h =
1200 (5)
= 0.0857
70, 000
Therefore, the factor of safety (FS) based on tensile
strength is:
FS =
0.311
= 3.6
0.0857
PR
SE − 0.6P
Steam 41 / Structural Analysis and Design
8-5
The Babcock & Wilcox Company
For relatively thin tubes and Ta > Tb, this can be simplified to:
Fig. 5 Hoop stress variation in a bend.2
tions, as is the case in pressure vessels, the resulting
stress is:
E α ∆T
1−µ
(17)
σr =
σt =
αE
−
1
( µ ) r2
r2 − a2
b2 − a 2
α E r2 + a2
(1 − µ ) r 2 b2 − a2
σz =
∫
b
a
∫
b
a
Trdr +
αE 2
(1 − µ ) b2 − a2
Trdr
(18)
Trdr − Tr 2
(19)
Trdr −
∫
b
a
∫
r
a
∫
r
a
Trdr − T
(20)
where
E = modulus of elasticity
µ = Poisson’s ratio
r = radius at any location
a = inside radius
b = outside radius
T = temperature
For a cylindrical vessel in which heat is flowing
radially through the walls under steady-state conditions, the maximum thermal stresses are:
2b2
b
n
σ ta ( inside ) =
1− 2
2
b −a
b
a (21)
2 (1 − µ ) n
a
α E Ta
σ tb ( outside ) =
8-6
2a 2
b
−
n
1
2
2
b −a
b
a (22)
2 (1 − µ ) n
a
α E Ta
σ tb =
α E ∆T
2 (1 − µ )
(24)
σ = K
E α ∆T
1−µ
(25)
where K ranges between 0.5 and 1.0.
Alternating stresses resulting from cyclic pressure
vessel operation may lead to fatigue cracks at high
stress concentrations. Fatigue life is evaluated by comparing the alternating stress amplitude with design
fatigue curves (allowable stress versus number of
cycles or σ-N curves) experimentally established for
the material at temperature. A typical σ-N design
curve for carbon steel is shown in Fig. 6 and can be
expressed by the equation:
σa =
100
E
n
+ .01 (TS ) da
4 N
100 − da
(26)
where
σ a = allowable alternating stress amplitude
E = modulus of elasticity at temperature
N = number of cycles
d a = percent reduction in area
TS = tensile strength at temperature
The two controlling parameters are tensile strength
and reduction in area. Tensile strength is controlling
in the high cycle fatigue region, while reduction in
area is controlling in low cycle fatigue. The usual dipsi (MPa)
These thermal stress equations consider full restraint, and therefore are the maximum that can be
created. When the temperature varies within a member, the natural growth of one fiber is influenced by
the differential growth of adjacent fibers. As a result,
fibers at high temperatures are compressed and those
at lower temperatures are stretched. The general
equations for radial (σr), tangential (σt), and axial (σz)
thermal stresses in a cylindrical vessel subject to a
radial thermal gradient are:
(23)
(6,890)
700F
(371C)
800F
(427C)
a,
where µ is Poisson’s ratio.
−α E ∆T
2 (1 − µ )
To summarize, the maximum thermal stress for a
thin cylinder with a logarithmic wall temperature
gradient is one half the thermal stress of an element
restrained in two directions and subjected to a temperature change ∆T (Equation 17). For a radial thermal gradient of different shape, the thermal stress can
be represented by:
Values of
Alternating Stress Intensity,
σ = ±
σ ta =
(689)
900F
(482C)
1000F
(538C)
(68.9)
(6.90)
N, Number of Allowed Cycles
Fig. 6 Design fatigue curve.
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
vision between low and high cycle fatigue is 105 cycles.
Pressure vessels often fall into the low cycle fatigue
category, thereby demonstrating the importance of the
material’s ability to deform in the plastic range without fracturing. Lower strength materials, with their
greater ductility, have better low cycle fatigue resistance than do higher strength materials.
Practical operating service conditions subject many
vessels to the random occurrence of a number of stress
cycles at different magnitudes. One method of appraising the damage from repetitive stresses to a vessel is the criterion that the cumulative damage from
fatigue will occur when the summation of the increments of damage at the various stress levels exceeds
unity. That is:
n
∑N
=1
(27)
where n = number of cycles at stress σ, and N = number of cycles to failure at the same stress σ. The ratio
n/N is called the cycle damage ratio since it represents
the fraction of the total life which is expended by the
cycles that occur at a particular stress value. The
value N is determined from σ-N curves for the material. If the sum of these cycle ratios is less than unity,
the vessel is considered safe. This is particularly important in designing an economic and safe structure
which experiences only a relatively few cycles at a
high stress level and the major number at a relatively
low stress level.
Discontinuity analysis method At geometrical
discontinuities in axisymmetric structures, such as the
intersection of a hemispherical shell element and a
cylindrical shell element (Fig. 7a), the magnitude and
characteristic of the stress are considerably different
than those in elements remote from the discontinuity. A linear elastic analysis method is used to evaluate these local stresses.
Discontinuity stresses that occur in pressure vessels, particularly axisymmetric vessels, are determined
by a discontinuity analysis method. A discontinuity
stress results from displacement and rotation incompatibilities at the intersection of two elements. The
forces and moments at the intersection (Fig. 7c) are
redundant and self-limiting. They develop solely to
ensure compatibility at the intersection. As a consequence, a discontinuity stress can not cause failure in
ductile materials in one load application even if the
maximum stress exceeds the material yield strength.
Such stresses must be considered in cyclic load applications or in special cases where materials can not
safely redistribute stresses. The ASME Code refers to
discontinuity stresses as secondary stresses. The application to the shell of revolution shown in Fig. 7
outlines the major steps involved in the method used
to determine discontinuity stresses.
Under internal pressure, a sphere radially expands
approximately one half that of a cylindrical shell (Fig.
7b). The difference in free body displacement results
in redundant loadings at the intersection if Elements
(1) and (2) are joined (Fig. 7c). The final displacement
and rotation of the cylindrical shell are equal to the
Steam 41 / Structural Analysis and Design
Fig. 7 Discontinuity analysis.
free body displacement plus the displacements due to
the redundant shear force Vo and redundant bending
moment Mo (Fig. 7d).
The direction of the redundant loading is unknown
and must be assumed. A consistent sign convention
must be followed. In addition, the direction of loading
on the two elements must be set up consistently because Element (1) reacts Element (2) loading and vice
versa. If Mo or Vo as calculated is negative, the correct
direction is opposite to that assumed.
In equation form then, for Element (1):
δ FINAL 1 = δ FREE 1 − βδ V 1 Vo + βδ M 1 M o
(28)
γ FINAL 1 = γ FREE 1 + βγ V 1 Vo − βγ M 1 M o
(29)
Similarly for Element (2):
δ FINAL 2 = δ FREE 2 + βδ V 2 Vo + βδ M 2 M o
(30)
γ FINAL 2 = γ FREE 2 + βγ V 2 Vo + βγ M 2 M o
(31)
where
δ FREE 1 =
µ
1 − 2
PR 2
(1 − µ )
2Et
= γ FREE 2 = 0 in this case
δ FREE 2 =
γ FREE 1
PR 2
Et
(32)
(33)
The constants β are the deflections or rotations due to
loading per unit of perimeter, and are referred to as
influence coefficients. These constants can be determined for a variety of geometries, including rings and
thin shells of revolution, using standard handbook
solutions. For example:
βδV1 = radial displacement of Element (1) due to unit
shear load
8-7
The Babcock & Wilcox Company
βδM1 = radial displacement of Element (1) due to unit
moment load
βγV1 = rotation of Element (1) due to unit shear load
βγM1 = rotation of Element (1) due to unit moment
load
Because δFINAL 1 = δFINAL 2 and γFINAL 1 = γFINAL 2 from compatibility requirements, Equations 28 through 31 can
be reduced to two equations for two unknowns, Vo and
Mo, which are solved simultaneously. Note that the
number of equations reduces to the number of redundant loadings and that the force F can be determined
by static equilibrium requirements.
Once Vo and Mo have been calculated, handbook
solutions can be applied to determine the resulting
membrane and bending stresses. The discontinuity
stress must then be added to the free body stress to
obtain the total stress at the intersection.
Although the example demonstrates internal pressure loading, the same method applies to determining thermally induced discontinuity stress. For more
complicated geometries involving four or more unknown redundant loadings, commercially available
computer programs should be considered for solution.
Finite element analysis When the geometry of a component or vessel is too complex for classical formulas
or closed form solutions, finite element analysis (FEA)
can often provide the required results. FEA is a powerful numerical technique that can evaluate structural
deformations and stresses, heat flows and temperatures, and dynamic responses of a structure. Because
FEA is usually more economical than experimental
stress analysis, scale modeling, or other numerical
methods, it has become the dominant sophisticated
stress analysis method.
During product development, FEA is used to predict performance of a new product or concept before
building an expensive prototype. For example, a design idea to protect the inside of a burner could be analyzed to find out if it will have adequate cooling and fatigue life. FEA is also used to investigate field problems.
To apply FEA, the structure is modeled as an assembly of discrete building blocks called elements. The
elements can be linear (one dimensional truss or beam),
plane (representing two dimensional behavior), or solid
(three dimensional bricks). Elements are connected at
their boundaries by nodes as illustrated in Fig. 8.
Except for analyses using truss or beam elements,
the accuracy of FEA is dependent on the mesh density. This refers to the number of nodes per modeled
volume. As mesh density increases, the result accuracy also increases. Alternatively, in p-method analysis, the mesh density remains constant while increased
accuracy is attained through mathematical changes
to the solution process.
A computer solution is essential because of the numerous calculations involved. A medium sized FEA may require the simultaneous solution of thousands of equations, but taking merely seconds of computer time. FEA
is one of the most demanding computer applications.
FEA theory is illustrated by considering a simple
structural analysis with applied loads and specified
node displacements. The mathematical theory is essentially as follows.
8-8
Fig. 8 Finite element model composed of brick elements.
For each element, a stiffness matrix satisfying the
following relationship is found:
k {d} = {r}
(34)
where
[k] = an element stiffness matrix. It is square and
defines the element stiffness in each direction
(degree of freedom)
{d} = a column of nodal displacements for one element
{r} = a column of nodal loads for one element
The determination of [k] can be very complex and its
theory is not outlined here. Modeling the whole structure requires that:
K {D} = {R}
(35)
where
[K] = structure stiffness matrix; each member of [K]
is an assembly of the individual stiffness
contributions surrounding a given node
{D} = column of nodal displacements for the structure
{R} = column of nodal loads on the structure
In general, neither {D} nor {R} is completely known.
Therefore, Equation 35 must be partitioned (rearranged) to separate known and unknown quantities.
Equation 35 then becomes:
K11 K12 Ds
Ro
=
K 21 K 22 Do
Rs
(36)
where
Ds
Do
Rs
Ro
=
=
=
=
unknown displacements
known displacements
unknown loads
known loads
Equation 36 represents the two following equations:
K11 {Ds } + K12 {Do } = {Ro }
(37)
K 21 {Ds } + K 22 {Do } = {Rs }
(38)
Equation 37 can be solved for Ds and Equation 38 can
then be solved for Rs.
Using the calculated displacements {D}, {d} can be
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
found for each element and the stress can be calculated by:
{σ } =
E B {d}
(39)
where
{σ } are element stresses
[E] and [B] relate stresses to strains and strains to
displacements respectively
FEA theory may also be used to determine temperatures throughout complex geometric components. (See
also Chapter 4.) Considering conduction alone, the
governing relationship for thermal analysis is:
{}
C T + K {T } = {Q}
(40)
where
[C ] = system heat capacity matrix
{ T } = column of rate of change of nodal
temperatures
[K ] = system thermal conductivity matrix
{T } = column of nodal temperatures
{Q } = column of nodal rates of heat transfer
In many respects, the solution for thermal analysis is similar to that of the structural analysis. One important difference, however, is that the thermal solution is iterative and nonlinear. Three aspects of a thermal analysis require an iterative solution.
First, thermal material properties are temperature
dependent. Because they are primary unknowns, temperature assumptions must be made to establish the
initial material properties. Each node is first given an
assumed temperature. The first thermal distribution
is then obtained, and the calculated temperatures are
used in a second iteration. Convergence is attained
when the calculated temperature distributions from
two successive iterations are nearly the same.
Second, when convective heat transfer is accounted
for, heat transfer at a fluid boundary is dependent on
the material surface temperature. Again, because temperatures are the primary unknowns, the solution must
be iterative.
Third, in a transient analysis, the input parameters,
including boundary conditions, may change with time,
and the analysis must be broken into discrete steps.
Within each time step, the input parameters are held
constant. For this reason, transient thermal analysis
is sometimes termed quasi-static.
FEA applied to dynamic problems is based upon the
differential equation of motion:
{ }
{ }
+ C D + K {D} = {R}
M D
where
[M ] =
[C ] =
[K ] =
{R} =
(41)
structure lumped mass matrix
structure damping matrix
structure stiffness matrix
column of nodal forcing functions
} are columns of nodal displacements,
{ D }, { D } and { D
velocities, and accelerations, respectively.
Steam 41 / Structural Analysis and Design
Variations on Equation 41 can be used to solve for
the natural frequencies, mode shapes, and responses
due to a forcing function (periodic or nonperiodic), or
to do a dynamic seismic analysis.
Limitations of FEA involve computer and human
resources. The user must have substantial experience
and, among other abilities, he must be skilled in selecting element types and in geometry modeling.
In FEA, result accuracy increases with the number of nodes and elements. However, computation
time also increases and handling the mass of data can
be cumbersome.
In most finite element analyses, large scale yielding (plastic strain) and deformations (including buckling instability), and creep are not accounted for; the
material is considered to be linear elastic. In a linear
structural analysis, the response (stress, strain, etc.)
is proportional to the load. For example, if the applied
load is doubled, the stress response would also double.
For nonlinear analysis, FEA can also be beneficial.
Recent advancements in computer hardware and software have enabled increased use of nonlinear analysis techniques.
Although most FEA software has well developed three
dimensional capabilities, some pressure vessel analyses
are imprecise due to a lack of acceptance criteria.
Computer software consists of commercially available and proprietary FEA programs. This software can
be categorized into three groups: 1) preprocessors, 2)
finite element solvers, and 3) postprocessors.
A preprocessor builds a model geometry and applies
boundary conditions, then verifies and optimizes the
model. The output of a finite element solver consists
of displacements, stresses, temperatures, or dynamic
response data.
Postprocessors manipulate the output from the finite element solver for comparison to acceptance criteria or to make contour map plots.
Application of FEA Because classical formulas and
shell analysis solutions are limited to simple shapes,
FEA fills a technical void and is applied in response
to ASME Code requirements. A large portion of The
Babcock & Wilcox Company’s (B&W) FEA supports
pressure vessel design. Stresses can be calculated near
nozzles and other abrupt geometry changes. In addition, temperature changes and the resulting thermal
stresses can be predicted using FEA.
The raw output from a finite element solver can not
be directly applied to the ASME Code criteria. The
stresses or strains must first be classified as membrane,
bending, or peak (Fig. 9). B&W pioneered the classification of finite element stresses and these procedures
are now used throughout the industry.
Piping flexibility, for example, is an ideal FEA application. In addition, structural steel designers rely
on FEA to analyze complex frame systems that support steam generation and emissions control equipment.
Finite element analysis is often used for preliminary
review of new product designs. For example, Fig. 10
shows the deflected shape of two economizer fin configurations modeled using FEA.
8-9
The Babcock & Wilcox Company
stress intensity factor, KI. LEFM assumes that unstable propagation of existing flaws occurs when the
stress intensity factor becomes critical; this critical
value is the fracture toughness of the material KIC.
The theory of linear elastic fracture mechanics,
LEFM, is based on the assumption that, at fracture,
stress σ and defect size a are related to the fracture
toughness KIC, as follows:
KI = C σ π a
(42a)
K I ≥ K IC at failure
(42b)
and
Fig. 9 Classification of finite element stress results on a vessel crosssection for comparison to code criteria.3
Fracture mechanics methods
Fracture mechanics provides analysis methods to
account for the presence of flaws such as voids or
cracks. This is in contrast to the stress analysis methods discussed above in which the structure was considered to be free of those kinds of defects. Flaws may
be found by nondestructive examination (NDE) or
they may be hypothesized prior to fabrication. Fracture mechanics is particularly useful to design or evaluate components fabricated using materials that are more
sensitive to flaws. Additionally, it is well suited to the
prediction of the remaining life of components under
cyclic fatigue and high temperature creep conditions.
During component design, the flaw size is hypothesized. Allowable design stresses can be determined
knowing the lower bound material toughness from
accepted design procedures in conjunction with a factor of safety.
Fracture mechanics can be used to evaluate the
integrity of a flawed existing structure. The defect,
usually found by NDE, is idealized according to accepted ASME practices. An analysis uses design or
calculated stresses based on real or hypothesized loads,
and material properties are found from testing a specimen of similar material. Determining allowable flaw
sizes strongly relies on accurate material properties and
the best estimates of structural stresses. Appropriate
safety factors are then added to the calculations.
During inspection of power plant components, minor cracks or flaws may be discovered. However, the
flaws may propagate by creep or fatigue and become
significant. The remaining life of components can not be
accurately predicted from stress/cycles to failure (σ/N)
curves alone. These predictions become possible using
fracture mechanics.
Linear elastic fracture mechanics The basic concept
of linear elastic fracture mechanics (LEFM) was originally developed to quantitatively evaluate sudden
structural failure. LEFM, based on an analysis of the
stresses near a sharp crack, assumes elastic behavior
throughout the structure. The stress distribution near
the crack tip depends on a single quantity, termed the
8-10
The critical material property, KIC, is compared to
the stress intensity factor of the cracked structure, KI,
to identify failure potential. KI should not be confused
with the stress intensity used elsewhere in ASME
design codes for analysis of unflawed structures. The
term C, accounting for the geometry of the crack and
structure, is a function of the crack size and relevant
structure dimensions such as width or thickness.
C is exactly 1.0 for an infinitely wide center cracked
panel with a through-wall crack length 2a, loaded in
tension by a uniform remote stress σ. The factor C
varies for other crack geometries illustrated in Fig. 11.
Defects in a structure due to manufacture, in-service
environment, or in-service cyclic fatigue are usually
assumed to be flat, sharp, planar discontinuities where
the planar area is normal to the applied stress.
ASME Code procedures for fracture mechanics design/analysis are presently given in Sections III and
XI which are used for component thicknesses of at
least 4 in. (102 mm) for ferritic materials with yield
strengths less than 50,000 psi (344.7 MPa) and for
simple geometries and stress distributions. The basic
concepts of the Code may be extended to other ferritic
materials (including clad ferritic materials) and more
complex geometries; however, it does not apply to
austenitic or high nickel alloys. These procedures provide methods for designing against brittle fractures
in structures and for evaluating the significance of
flaws found during in-service inspections.
Fig. 10 Economizer tube and fin (quarter symmetry model) deformed
shape plots before (upper) and after (lower) design modifications.
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
The ASME Code, Section III uses the principles of
linear elastic fracture mechanics to determine allowable loadings in ferritic pressure vessels with an assumed defect. The stress intensity factors (KI) are calculated separately for membrane, bending, and thermal gradient stresses. They are further subdivided
into primary and secondary stresses before summing
and comparison to the allowable toughness, KIR. KIR is
the reference critical stress intensity factor (toughness). It accounts for temperature and irradiation
embrittlement effects on toughness. A safety factor of
2 is applied to the primary stress components and a
factor of 1 is applied to the secondary components.
To determine an operating pressure that is below the
brittle fracture point, the following approach is used:
1. A maximum flaw size is assumed. This is a semielliptical surface flaw one fourth the pressure vessel wall thickness in depth and 1.5 times the thickness in length.
2. Knowing the specific material’s nil ductility temperature, and the design temperature KIR can be
found from the Code.
3. The stress intensity factor is determined based on
the membrane and bending stresses, and the appropriate correction factors. Additional determinants include the wall thickness and normal stress
to yield strength ratio of the material.
4. The calculated stress intensity is compared to KIR.
The ASME Code, Section XI provides a procedure
to evaluate flaw indications found during in-service
inspection of nuclear reactor coolant systems. If an
indication is smaller than certain limits set by Section
XI, it is considered acceptable without further analysis. If the indication is larger than these limits, Section XI provides information that enables the following procedure for further evaluation:
1. Determine the size, location and orientation of the
flaw by NDE.
2. Determine the applied stresses at the flaw location
(calculated without the flaw present) for all normal
(including upset), emergency and faulted conditions.
3. Calculate the stress intensity factors for each of
the loading conditions.
4. Determine the necessary material properties, including the effects of irradiation. A reference temperature shift procedure is used to normalize the
lower bound toughness versus temperature
curves. These curves are based on crack arrest and
static initiation values from fracture toughness tests.
The temperature shift procedure accounts for heat
to heat variation in material toughness properties.
5. Using the procedures above, as well as a procedure
for calculating cumulative fatigue crack growth,
three critical flaw parameters are determined:
af = maximum size to which the detected flaw
can grow during the remaining service of
the component
acrit = maximum critical size of the detected flaw
under normal conditions
ainit = maximum critical size for nonarresting
growth initiation of the observed flaw under emergency and faulted conditions
Steam 41 / Structural Analysis and Design
Fig. 11 Types of cracks.
6. Using these critical flaw parameters, determine if
the detected flaw meets the following conditions
for continued operation:
a f < 0.1 acrit
a f < 0.5 ainit
(43)
Elastic-plastic fracture mechanics (EPFM) LEFM
provides a one parameter failure criterion in terms of
the crack tip stress intensity factor (KI), but is limited
to analyses where the plastic region surrounding the
crack tip is small compared to the overall component dimensions. As the material becomes more ductile and the
structural response becomes nonlinear, the LEFM approach loses its accuracy and eventually becomes invalid.
A direct extension of LEFM to EPFM is possible by
using a parameter to characterize the crack tip region
that is not dependent on the crack tip stress. This
parameter, the path independent J-integral, can characterize LEFM, EPFM, and fully plastic fracture mechanics. It is capable of characterizing crack initiation,
growth, and instability. The J-integral is a measure
of the potential energy rate of change for nonlinear
elastic structures containing defects.
The J-integral can be calculated from stresses
around a crack tip using nonlinear finite element
analysis. An alternate approach is to use previously
calculated deformation plasticity solutions in terms of
the J-integral from the Electric Power Research Institute (EPRI) Elastic-Plastic Fracture Analysis
Handbook.4
The onset of crack growth is predicted when:
J I ≥ J IC
(44)
The material property JIC is obtained using American
Society for Testing and Materials (ASTM) test E81389, and JI is the calculated structural response.
Stable crack growth occurs when:
J I ( a, P ) = J R ( ∆ a )
8-11
The Babcock & Wilcox Company
and
a = ao + ∆ a
(45)
where
a
= current crack size
P
= applied remote load
JR(∆a) = material crack growth resistance (ASTM
test standard E1152-87)
∆a
= change in crack size
ao
= initial crack size
For crack instability, an additional criterion is:
∂J / ∂a ≥ ∂J R / ∂a
(46)
Failure assessment diagrams Failure assessment diagrams are tools for the determination of safety margins, prediction of failure or plastic instability and
leak-before-break analysis of flawed structures. These
diagrams recognize both brittle fracture and net section collapse mechanisms. The failure diagram (see
Fig. 12) is a safety/failure plane defined by the stress
intensity factor/toughness ratio (Kr) as the ordinate
and the applied stress/net section plastic collapse stress
ratio (Sr) as the abscissa. For a fixed applied stress and
defect size, the coordinates Kr, Sr are readily calculable. If the assessment point denoted by these coordinates lies inside the failure assessment curve, no
crack growth can occur. If the assessment point lies
outside the curve, unstable crack growth is predicted.
The distance of the assessment point from the failure
assessment curve is a measure of failure potential of
the flawed structure.
In a leak-before-break analysis, a through-wall
crack is postulated. If the resulting assessment point
lies inside the failure assessment curve, the crack will
leak before an unstable crack growth occurs.
The deformation plasticity failure assessment diagram (DPFAD)5 is a specific variation of a failure assessment diagram. DPFAD follows the British PD 6493
R-66 format, and incorporates EPFM deformation plasticity J-integral solutions. The DPFAD curve is determined by normalizing the deformation plasticity J-
Fig. 12 Deformation plasticity failure assessment diagram in terms of
stable crack growth.
8-12
integral response of the flawed structure by its elastic
response. The square root of this ratio is denoted by
Kr. The Sr coordinate is the ratio of the applied stress
to the net section plastic collapse stress. Various computer programs are available which automate this
process for application purposes.
Subcritical crack growth Subcritical crack growth
refers to crack propagation due to cyclic fatigue, stress
corrosion cracking, creep crack growth or a combination of the three. Stress corrosion cracking and creep
crack growth are time based while fatigue crack
growth is based on the number of stress cycles.
Fatigue crack growth Metal fatigue, although studied for more than 100 years, continues to plague structures subjected to cyclic stresses. The traditional approach to prevent fatigue failures is to base the allowable fatigue stresses on test results of carefully made
laboratory specimens or representative structural components. These results are usually presented in cyclic
stress versus cycles to failure, or σ/N, curves.
The significant events of metal fatigue are crack
initiation and subsequent growth until the net section
yields or until the stress intensity factor of the structure exceeds the material resistance to fracture. Traditional analysis assumes that a structure is initially
crack free. However, a structure can have cracks that
originate during fabrication or during operation.
Therefore, fatigue crack growth calculations are required to predict the service life of a structure.
Fatigue crack growth calculations can 1) determine
the service life of a flawed structure that (during its
lifetime) undergoes significant in-service cyclic loading, or 2) determine the initial flaw size that can be
tolerated prior to or during a specified operating period of the structure.
The most useful way of presenting fatigue crack
growth rates is to consider them as a function of the
stress intensity difference, ∆K, which is the difference between the maximum and minimum stress intensity factors.
To calculate fatigue crack growth, an experimentally determined curve such as Fig. 13 is used. The
vertical axis, da/dN, is the crack growth per cycle.
ASME Code, Section XI contains similar growth rate
curves for pressure vessel steels.
Creep crack growth Predicting the remaining life of
fossil power plant components from creep rupture data
alone is not reliable. Cracks can develop at critical locations and these cracks can then propagate by creep
crack growth.
At temperatures above 800F (427C), creep crack
growth can cause structural components to fail. Operating temperatures for certain fossil power plant
components range from 900 to 1100F (482 to 593C).
At these temperatures, creep deformation and crack
growth become dependent on strain rate and time
exposure. Macroscopic crack growth in a creeping
material occurs by nucleation and joining of
microcavities in the highly strained region ahead of
the crack tip. In time dependent fracture mechanics
(TDFM), the energy release rate (power) parameter Ct
correlates7 creep crack growth through the relationship:
da / dt = bC qt
(47)
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
By using the energy rate definition, Ct can be determined experimentally from test specimens. The constants b and q are determined by a curve fit technique.
Under steady-state creep where the crack tip stresses
no longer change with time, the crack growth can be
characterized solely by the path independent energy
rate line integral C*, analogous to the J-integral.
C* and Ct can both be interpreted as the difference
in energy rates (power) between two bodies with incrementally differing crack lengths. Furthermore, C*
characterizes the strength of the crack tip stress singularity in the same manner as the J-integral characterizes the elastic-plastic stress singularity.
The fully plastic deformation solutions from the
EPRI Elastic-Plastic Fracture Handbook can then be
used to estimate the creep crack tip steady-state parameter, C*.
Significant data support Ct as a parameter for correlating creep crack growth behavior represented by Equation 47. An approximate expression8 for Ct is as follows:
n −3
Ct = C * (tT / t ) n −1 + 1
(48)
where tT is the transition time given by:
(1 − µ ) K
2
tT =
2
I
( n + 1) EC *
(49)
wall thickness. An alternate, more economical stress
reduction method is to thicken the vessel locally
around the nozzle axis of symmetry. The reinforcing
material must be within the area of high local stress
to be effective.
The ASME Code provides guidelines for reinforcing openings. The reinforcement must meet requirements for the amount and distribution of the added
material. A relatively small opening [approximately
d<0.2 (Rts)1/2 where R is mean radius of shell and ts is
thickness of shell] remote from other locally stressed
areas does not require reinforcement.
Larger openings are normally reinforced as illustrated in Figs. 14a and 14b. It is important to avoid
excessive reinforcement that may result in high secondary stresses. Fig. 14c shows an opening with over
reinforcement and Fig. 14a shows one with well proportioned reinforcement. Fig. 14b also shows a balanced
design that minimizes secondary stresses at the nozzle/
shell juncture. Designs a and b, combined with generous radii r, are most suitable for cyclic load applications.
The ligament efficiency method is also used to compensate for metal removed at shell openings. This
method considers the load carrying ability of an area
between two points in relation to the load carrying
ability of the remaining ligament when the two points
become the centers of two openings. The ASME Code
guidelines used in this method only apply to cylindri-
and µ is Poisson’s ratio, and n is the secondary creep
rate exponent.
For continuous operation, Equation 48 is integrated
over the time covering crack growth from the initial
flaw size to the final flaw size. The limiting final flaw
size is chosen based on fracture toughness or instability considerations, possibly governed by cold startup
conditions. For this calculation, fracture toughness
data such as KIC, JIC or the JR curve would be used in
a failure assessment diagram approach to determine
the limiting final flaw size.
Construction features
All pressure vessels require construction features
such as fluid inlets and outlets, access openings, and
structural attachments at support locations. These
shell areas must have adequate reinforcement and
gradual geometric transitions which limit local stresses
to acceptable levels.
Openings Openings are the most prevalent construction features on a vessel. They can become areas of weakness and may lead to unacceptable local
distortion, known as bell mouthing, when the vessel
is pressurized. Such distortions are associated with
high local membrane stresses around the opening.
Analytical studies have shown that these high stresses
are confined to a distance of approximately one hole
diameter, d, along the shell from the axis of the opening and are limited to a distance of 0.37 (dtnozzle)1/2 normal to the shell.
Reinforcement to reduce the membrane stress near
an opening can be provided by increasing the vessel
Steam 41 / Structural Analysis and Design
Fig. 13 Relationship between da/dN and ∆K as plotted on logarithmic
coordinates.
8-13
The Babcock & Wilcox Company
cal pressure vessels where the circumferential stress is
twice the longitudinal stress. In determining the thickness of such vessels, the allowable stress in the thickness calculation is multiplied by the ligament efficiency.
Nozzle and attachment loadings When external loadings are applied to nozzles or attachment components,
local stresses are generated in the shell. Several types
of loading may be applied, such as sustained, transient and thermal expansion flexibility loadings. The
local membrane stresses produced by such loadings
must be limited to avoid unacceptable distortion due
to a single load application. The combination of local
membrane and bending stresses must also be limited
to avoid incremental distortion under cyclic loading.
Finally, to prevent cyclic load fatigue failures, the
nozzle or attachment should include gradual transitions which minimize stress concentrations.
Pressure vessels may require local thickening at
nozzles and attachments to avoid yielding or incremental distortion due to the combined effects of external loading, internal pressure, and thermal loading. Simple procedures to determine such reinforcement are not available, however FEA methods can be
used. The Welding Research Council (WRC) Bulletin
No. 107 also provides a procedure for determining local stresses adjacent to nozzles and rectangular attachments on cylindrical and spherical shells.
The external loadings considered by the WRC are
longitudinal moment, transverse moment, torsional
moment, and axial force. Stresses at various inside
and outside shell surfaces are obtained by combining
the stresses from the various applied loads. These external load stresses are then combined with internal pressure stresses and compared with allowable stress limits.
Use of the WRC procedure is restricted by limitations
on shell and attachment parameters; however, experimental and theoretical work continues in this area.
Structural support components
Pressure vessels are normally supported by saddles,
cylindrical support skirts, hanger lugs and brackets,
ring girders, or integral support legs. A vessel has
concentrated loads imposed on its shell where these
supports are located. Therefore, it is important that
the support arrangements minimize local stresses in
the vessel. In addition, the components must provide
support for the specified loading conditions and withstand corresponding temperature requirements.
Fig. 14 Nozzle opening reinforcements.
8-14
Design criteria
Structural elements that provide support, stiffening, and/or stabilization of pressure vessels or components may be directly attached by welding or bolting.
They can also be indirectly attached by clips, pins, or
clamps, or may be completely unattached thereby transferring load through surface bearing and friction.
Loading conditions In general, loads applied to
structural components are categorized as dead, live,
or transient loads. Dead loads are due to the force of
gravity on the equipment and supports. Live loads
vary in magnitude and are applied to produce the
maximum design conditions. Transient loads are time
dependent and are expected to occur randomly for the
life of the structural components. Specific loadings
that are considered in designing a pressure component
support include:
1. weight of the component and its contents during
operating and test conditions, including loads due
to static and dynamic head and fluid flow,
2. weight of the support components,
3. superimposed static and thermal loads induced by
the supported components,
4. environmental loads such as wind and snow,
5. dynamic loads including those caused by earthquake, vibration, or rapid pressure change,
6. loads from piping thermal expansion,
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
7. loads from expansion or contraction due to pressure, and
8. loads due to anchor settlement.
Code design/analysis requirements Code requirements for designing pressure part structural supports
vary. The ASME Code, Section I, only covers pressure
part attaching lugs, hangers or brackets. These must
be properly fitted and must be made of weldable and
comparable quality material. Only the weld attaching the structural member to the pressure part is considered within the scope of Section I. Prudent design
of all other support hardware is the manufacturer’s
responsibility.
The ASME Code, Section VIII, Division 1, does not
contain design requirements for vessel supports; however, suggested rules of good practice are presented.
These rules primarily address support details which
prevent excessive local shell stresses at the attachments. For example, horizontal pressure vessel support saddles are recommended to support at least one
third of the shell circumference. Rules for the saddle
design are not covered. However, the Code refers the
designer to the Manual of Steel Construction, published by the American Institute of Steel Construction
(AISC). This reference details the allowable stress
design (ASD) method for structural steel building designs. When adjustments are made for elevated temperatures, this specification can be used for designing pressure vessel support components. Similarly,
Section VIII, Division 2, does not contain design methods for vessel support components. However, materials for structural attachments welded to pressure components and details of permissible attachment welds
are covered.
Section III of the ASME Code contains rules for the
material, design, fabrication, examination, and installation of certain pressure component and piping supports. The supports are placed within three categories:
1. plate and shell type supports, such as vessel skirts
and saddles, which are fabricated from plate and
shell elements,
2. linear supports which include axially loaded
struts, beams and columns, subjected to bending,
and trusses, frames, rings, arches and cables, and
3. standard supports (catalog items) such as constant
and variable type spring hangers, shock arresters, sway braces, vibration dampers, clevises, etc.
The design procedures for each of these support
types are:
1. design by analysis including methods based on maximum shear stress and maximum stress theories,
2. experimental stress analysis, and
3. load rating by testing full size prototypes.
applicable code, choosing the analysis method is the
designer’s prerogative. Linear elastic analysis (covered
in depth here), using the maximum stress or maximum
shear stress theory, is commonly applied to plate, shell
type and linear type supports. As an alternate, the
method of limit (plastic) analysis can be used for
framed linear structures when appropriate load adjustment factors are applied.
Plate and shell type supports Cylindrical shell skirts
are commonly used to support vertical pressure vessels. They are attached to the vessel with a minimum
offset in order to reduce local bending stresses at the
vessel skirt junction. This construction also permits
radial pressure and thermal growth of the supported
vessel through bending of the skirt. The length of the
support is chosen to permit this bending to occur safely.
See Fig. 15 for typical shell type support skirt details.
In designing the skirt, the magnitudes of the loads
that must be supported are determined. These normally include the vessel weight, the contents of the
vessel, the imposed loads of any equipment supported
from the vessel, and loads from piping or other attachments. Next a skirt height is set and the forces and
moments at the skirt base, due to the loads applied,
are determined. Treating the cylindrical shell as a
beam, the axial stress in the skirt is then determined
from:
σ =
− Pv
Mc
±
A
I
(50)
where
σ
Pv
A
M
c
I
=
=
=
=
=
=
axial stress in skirt
total vertical design load
cross-sectional area
moment at base due to design loads
radial distance from centerline of skirt
moment of inertia
For thin shells (R/t > 10), the equation for the axial
stress becomes:
σ =
− Pv
M
±
2 π Rt π R 2 t
(51)
where
R = mean radius of skirt
t = thickness of skirt
Because the compressive stress is larger than the tensile stress, it usually controls the skirt design. Using
the maximum stress theory for this example, the skirt
thickness is obtained by:
t =
Pv
M
+
2 π RFA π R 2 FA
(52)
The analysis required for each type of support depends on the class of the pressure component being
supported.
where
Typical support design considerations
Design by analysis involves determining the stresses
in the structural components and their connections by
accepted analysis methods. Unless specified in an
The designer must also consider stresses caused by
transient loadings such as wind or earthquakes. Finally, skirt connections at the vessel and support base
must be checked for local primary and secondary
Steam 41 / Structural Analysis and Design
FA = allowable axial compressive stress
8-15
The Babcock & Wilcox Company
to the outside of the furnace membraned vertical tube
walls. As shown in Fig. 16, the buckstay ends are connected to tie bars that link them to opposing wall
buckstays thereby forming a self-equilibrating structural system. The furnace enclosure walls are continuously welded at the corners creating a water-cooled,
orthotropic plate, rectangular pressure vessel. The
strength of the walls in the horizontal direction is considerably less than in the vertical direction, therefore
the buckstay system members are horizontally oriented.
The buckstay spacing is based on the ability of the
enclosure walls to resist the following loads:
1.
2.
3.
4.
5.
6.
Fig. 15 Support skirt details.2
bending stresses. The consideration of overall stress
levels provides the most accurate design.
Local thermal bending stresses often occur because
of a temperature difference between the skirt and support base. The magnitudes of these bending stresses
are dependent upon the severity of this axial thermal
gradient; steeper gradients promote higher stresses.
To minimize these stresses, the thermal gradient at
the junction can be reduced by full penetration welds
at the skirt to shell junction, which permit maximum
conduction heat flow through the metal at that point,
and by selective use of insulation in the crotch region
to permit heat flow by convection and radiation. Depending on the complexity of the attachment detail,
the discontinuity stress analysis or the linear elastic
finite element method is used to solve for the thermal
bending stresses.
Linear type supports Utility fossil fuel-fired steam
generators contain many linear components that support and reinforce the boiler pressure parts. For example, the furnace enclosure walls, which are constructed of welded membraned tube panels, must be
reinforced by external structural members (buckstays)
to resist furnace gas pressure as well as wind and seismic forces. (See Chapter 23.) Similarly, chambers, such
as the burner equipment enclosure (windbox), require
internal systems to support the enclosure and its contents as well as to reinforce the furnace walls. The
design of these structural systems is based on linear
elastic methods using maximum stress theory allowable limits.
The buckstay system is typically comprised of horizontally oriented beams or trusses which are attached
8-16
internal tube design pressure (P),
axial dead loads (DL),
sustained furnace gas pressure (PLs),
transient furnace gas pressure (PLT),
wind loads (WL), and
seismic loads (EQ).
The buckstay elevations are initially established
based on wall stress checks and on the location of necessary equipment such as sootblowers, burners, access
doors, and observation ports. These established
buckstay elevations are considered as horizontal supports for the continuous vertical tube wall. The wall
is then analyzed for the following load combinations
using a linear elastic analysis method:
1.
2.
3.
4.
DL + PLs + P,
DL + PLs + WL + P,
DL + PLs + EQ + P, and
DL + PLT + P.
Buckstay spacings are varied to assure that the wall
stresses are within allowable design limits. Additionally, their locations are designed to make full use of
the structural capability of the membraned walls.
The buckstay system members, their end connections, and the wall attachments are designed for the
maximum loads obtained from the wall analysis. They
are designed as pinned end bending members according to the latest AISC ASD specification. This specification is modified for use at elevated temperatures and
uses safety factors consistent with ASME Code, Sections I and VIII. The most important design considerations for the buckstay system include:
1. stabilization of the outboard beam flanges or truss
chords to prevent lateral buckling when subjected
to compression stress,
2. the development of buckstay to tie bar end connections and buckstay to wall attachments that
provide load transfer but allow differential expansion between connected elements, and
3. providing adequate buckstay spacing and stiffness
to prevent resonance due to low frequency combustion gas pressure pulsations common in fossil
fuel-fired boilers.
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
Fig. 16 Typical buckstay elevation, plan view.
References
1. Farr, J.R., and Jawad, M.H., Structural Analysis and
Design of Process Equipment, Second Ed., John Wiley
and Sons, Inc., New York, New York, January, 1989.
2. Harvey, J.F., Theory and Design of Pressure Vessels,
Van Nostrand Reinhold Company, New York, New York,
1985.
3. Kroenke, W.C., “Classification of Finite Element
Stresses According to ASME Section III Stress Categories,”
Pressure Vessels and Piping, Analysis and Computers,
American Society of Mechanical Engineers (ASME), June,
1974.
4. Kumar, V., et al., “An Engineering Approach for Elastic-Plastic Fracture Analysis,” Report EPRI NP-1931, Electric Power Research Institute (EPRI), Palo Alto, California, July, 1981.
5. Bloom, J.M., “Deformation Plasticity Failure Assessment Diagram,” Elastic Plastic Fracture Mechanics Technology, ASTM STGP 896, American Society for Testing
and Materials, Philadelphia, Pennsylvania, 1985.
6. “Guidance on Methods for Assessing the Acceptability
of Flaws in Fusion Welded Structure,” PD 6493:1991 Welding Standards Committee, London, England, United Kingdom, August 30, 1991.
7. Saxena, A., “Creep Crack Growth Under Non-SteadyState Conditions,” Fracture Mechanics, Vol. 17, ASTM STP
905, Philadelphia, Pennsylvania, 1986.
8. Bassani, J.L., Hawk, D.E., and Saxena, A., “Evaluation of the Ct Parameter for Characterizing Creep Crack
Growth Rate in the Transient Region,” Third International
Symposium on Nonlinear Fracture Mechanics, ASTM
STP 995, Philadelphia, Pennsylvania, 1989.
Bibliography
Manual of Steel Construction (M016): Includes Code of
Standard Practice, Simple Shears, and Specification for
Structural Joints Using ASTM A325 or A490 Bolts, Ninth
Ed., American Institute of Steel Construction, July 1, 1989.
Cook, R.D. et al., Concepts and Applications of Finite
Element Analysis, Fourth Ed., Wiley Publishers, New
York, New York, October, 2001.
Harvey, J.F., Theory and Design of Pressure Vessels,
Second Ed., Chapman and Hall, London, England, United
Kingdom, December, 1991.
Steam 41 / Structural Analysis and Design
Mershon, J.L., et al., “Local Stresses in Cylindrical Shells
Due to External Loadings on Nozzles,” Welding Research
Council (WRC) Bulletin No. 297, Supplement to WRC Bulletin No. 107 (Revision 1), August, 1984, revised September, 1987.
Thornton, W.A., Manual of Steel Construction: Load and
Resistance Factor Design (Manual of Steel Construction),
Third Ed., American Institute of Steel Construction
(AISC), November 1, 2001.
Wichman, K.R., Hopper, A.G., and Mershon, J.L., “Local
Stresses in Spherical and Cylindrical Shells Due to External Loadings,” Welding Research Council (WRC), Bulletin No. 107, August, 1965, revised March, 1979, updated
October, 2002.
8-17
The Babcock & Wilcox Company
A large steam drum is being lifted within power plant structural steel.
8-18
Steam 41 / Structural Analysis and Design
The Babcock & Wilcox Company
Section II
Steam Generation from
Chemical Energy
This section containing 17 chapters applies the fundamentals of steam generation to the design of boilers, superheaters, economizers and air heaters for
steam generation from chemical or fossil fuels (coal, oil and natural gas). As
discussed in Chapter 1, the fuel and method of combustion have a dramatic
impact on the size and configuration of the steam producing system. Therefore, Chapters 9 and 10 begin the section by exploring the variety and characteristics of chemical and fossil fuels, and summarize the combustion calculations that are the basis for system design.
The variety of combustion systems available to handle these fuels and the
supporting fuel handling and preparation equipment are then described in
Chapters 11 through 18. These range from the venerable stoker in its newest
configurations to circular burners used for pulverized coal, oil and gas, to fluidized-bed combustion and coal gasification. A key element in all of these systems is the control of atmospheric emissions, in particular oxides of nitrogen
(NOx) which are byproducts of the combustion process. Combustion NOx control is discussed as an integral part of each system. It is also discussed in Section IV, Chapter 34.
Based upon these combustion systems, Chapters 19 through 22 address the
design and performance evaluation of the major steam generator heat transfer components: boiler, superheater, reheater, economizer and air heater. These
are configured around the combustion system selected with special attention
to properly handling the high temperature, often particle-laden flue gas. The
fundamentals of heat transfer, fluid dynamics, materials science and structural analysis are combined to provide the tradeoffs necessary for an economical steam generating system design. The boiler setting and auxiliary equipment, such as sootblowers, ash handling systems and fans, which are key elements in completing the overall steam system, conclude this section in Chapters 23 through 25.
Steam 41
The Babcock & Wilcox Company
Chapter 9
Sources of Chemical Energy
World energy consumption continues to grow with
the primary resources being the fossil fuels. Between
1991 and 2000, world production of primary energy
increased at an annual rate of 1.4%. Production of primary energy increased from 351 × 1015 Btu (370 × 1018
J) in 1991 to 397 × 1015 Btu (419 × 1018 J) in 2000.
The trend in energy production by source from 1970
to 2000 is shown in Fig. 1. World energy production and
fossil fuel reserves by region are shown in Figs. 2 and 3.
The United States (U.S.), former Soviet Union
(FSU) and China were the leading producers and consumers of world energy in 2000. They produced 38%
and consumed 41% of the world’s energy. Energy use
in the developing world is expected to continue to increase with demand in developing Asia and Central
and South America more than doubling between 1999
and 2020. Projected world energy consumption
through the year 2025 is shown in Fig. 4.
Annual energy production in the U.S. rose to 71.6
× 1015 Btu (75.5 × 1018 J) in 2000, which is about 18%
of world production. Approximately 81% of this energy
is in the form of fossil fuels. U.S. energy production
by source is given in Fig. 5.
The relative U.S. production of coal compared to
other fossil fuels has increased since 1976, when 26%
was coal, 29% was crude oil and 33% was natural gas.
In 1999, coal production accounted for 32%, crude oil
was 17% and natural gas was 28%. Coal production
133
136
155
55
80
40
20
0
Crude Oil
and NGL
Natural
Gas (Dry)
2000
12
18
23
28
37
60
1990
Coal
Hydroelectric
Power
20
26
94
93
91
100
1980
76
120
1970
101
Quadrillion Btu
140
63
73
160
1
8
180
Nuclear
Power
Fig. 1 Trends in world energy production by source (NGL = natural
gas liquids).
Steam 41 / Sources of Chemical Energy
Central/South America
6%
Africa
7%
Western
Europe
11%
North America
25%
Middle East
14%
Far East and
Oceania
21%
Eastern Europe and FSU
16%
Fig. 2 World primary energy production by region, 2001.
for 1999 and 2000 represented the first time in forty
years that production declined for two consecutive
years. On an annual basis, the average utility price
per ton of coal delivered to utilities dropped by 1.8% in
2000, continuing a downward trend started in 1978.
Overall energy consumption in the U.S. was approximately 99 × 1015 Btu (104 × 1018 J) in 2000. About
28% of this energy was consumed by electric utilities
in the form of fossil fuels.
Overall U.S. fossil fuel consumption continues to
increase and grew to 84 × 1015 Btu (88.6 × 1018 J) in
2000. In spite of the decline in the cost of crude oil in
the 1980s, it continues to be the most dominant and
costly fuel in the fossil fuel mix. The trends in coal, oil
and natural gas prices are given in Fig. 6.
World availability of coal
Coal is the second leading source of fuel, supplying
23% of the world’s primary energy in 2000. It is also the
most used fossil fuel for utility and industrial power gen9-1
The Babcock & Wilcox Company
Crude Oil
End of Year 1999
1018 Billion Barrels
250
History
Projections
Oil
200
Far East and Oceania
Eastern Europe
and FSU
Western
Europe
Quadrillion Btu
Natural Gas
Africa
North, South
and
Central
America
Middle
East
150
Coal
100
Renewables
50
Nuclear
Natural Gas
End of Year 1999
5150 Trillion ft
Eastern
Western Europe
Europe
and FSU
Far East and Oceania
Africa
North, South and Central America
Middle
East
Coal
End of Year 1999
1082 Billion Short Tons
Africa
Western
Europe
Middle East, Far East
and Oceania
Eastern
Europe
and FSU
North, South and Central America
Fig. 3 Fossil fuel reserves by world region.
eration. Major reserves by coal type and location are lignite in the U.S. and the former Soviet Union (FSU); subbituminous in China, the FSU, Australia and Germany;
and bituminous in China, the U.S. and the FSU.
Reserves of coal by regions of the world are given
in Fig. 3. Of those regions, China consumed the most
(25%) in 2000, followed by the U.S. (21%) and the FSU
(9%). Because of its worldwide availability and low
price, the demand for coal has grown and world coal
trade has expanded by about 40% since 1980. The
largest coal exporters are Australia, China, Indonesia,
South Africa, the U.S., Canada, the FSU and Poland.1
0
1970
1980
1990
2000
2010
2025
Year
Fig. 4 World primary energy consumption by fuel.1
×109 tm ).3 The U.S. produced 1.074 × 109 t (0.974 ×
109 tm) of coal in 2000. Fig. 7 summarizes U.S. production from 1978 to 2000. U.S. coal consumption has
steadily increased from 0.7 billion short tons in 1980
to 1.05 billion in 1999. The states with the largest coal
reserves in the ground as of January, 2000, are shown
in Table 1.4 States with large reserves, such as Montana and Illinois, do not necessarily rank as high in production as Wyoming, Kentucky or West Virginia.
Because of the resulting sulfur dioxide (SO2) emissions, coal sulfur levels are important production criteria and have been a factor in the growth of production from the western region, particularly the Powder
River Basin. Table 2 shows the distribution of coal
reserves by state at various sulfur levels.
Coal fields in the U.S. are shown in Fig. 8. The two
largest producing regions are the western region consisting of Arizona, Colorado, Montana, New Mexico,
North Dakota, Utah, Washington, and Wyoming and
the Appalachian region including Pennsylvania, West
Virginia, Ohio, western Maryland, eastern Kentucky,
Virginia, Tennessee and Alabama. In 2000, these regions produced 510.7 × 106 t (463 × 106 tm ) and 419 ×
106 t (380 × 106 tm ), respectively. Two-thirds of the re-
Hydroelectric
Power
Natural Gas
4%
Plant Liquids
4%
Wood, Waste, Other
5%
Coal
31%
Nuclear Power
11%
U.S. availability of coal
The coal reserves of the U.S. constitute a vast energy resource, accounting for about 25% of the world’s
total recoverable coal.2 According to the Energy Information Administration (EIA), the national estimate of
the Demonstrated Reserve Base coal resources remaining as of 2002, is 498 billion short tons. Reserves that
are likely to be mined are estimated at 275 ×109 t (249
9-2
Crude Oil
17%
Natural Gas
28%
Fig. 5 U.S. energy production by source, 2002.
Steam 41 / Sources of Chemical Energy
10
8
700
600
Fossil Fuel
Composite
Crude Oil
Million Short Tons
Chained (1996) Dollars per Million Btu
The Babcock & Wilcox Company
6
Coal
4
2
Natural Gas
0
1975
1980
657
534
1978
549
1989
500
434
300
231
200
97
100
1985
1990
1995
2000
Year
0
Bituminous Coal
Subbituminous Coal
Fig. 7 U.S. coal production trends.
serves lie in the Great Plains, the Rocky Mountains
and the western states. These coals are mostly subbituminous and lignitic, which have low sulfur content.
Therefore, these fields have been rapidly developed
to meet the increasing demands of electric utilities.
The low sulfur coal permits more economical conformance to the Federal Clean Air Act, its Amendments, and
acid rain legislation. (See Chapter 32.)
U.S. electric utilities used coal to generate 51% of
the net electrical power in 2000, and remain the largest coal consumers. Continuing the downward trend
since 1982, the average delivered cost of coal decreased
27% in current dollars per million Btu.
Environmental concerns about SO2, nitrogen oxides
(NOx), carbon dioxide (CO2) and mercury (Hg) emissions could limit the growth of coal consumption. However, the U.S., as well as Japan and several European
countries, is researching clean coal technologies to
reduce these emissions while boosting power production efficiency. These technologies are rapidly approaching commercialization in the U.S. They are
expected to be integrated into current and future
power plants.
How coal is formed
State
Total Underground Surface % Total
Reserves Reserves Reserves U.S.
t
Montana
Illinois
Wyoming
West Virginia
Kentucky
Pennsylvania
Ohio
Colorado
Texas
New Mexico
Indiana
All others
Total U.S.
(tm)
t
120 109
105 95
67 61
35 32
31 28
28 25
24 22
17 15
13 12
12 11
10
9
41 37
503 456
71
88
43
30
18
24
18
12
0
6
9
20
339
(tm)
t
64 49
80 17
39 24
27
4
16 14
22
4
16
6
11
5
0 13
5
6
8
1
18 21
306 164
* Figures are rounded and include anthracite.
Steam 41 / Sources of Chemical Energy
(tm)
44 23.9
15 20.9
22 13.3
3.6
7.0
13
6.2
3.6
5.5
5
4.8
4.5
3.4
11.8
2.6
5
2.4
0.9
2.0
19
8.2
147 100.0
89
87
34
Fig. 6 Trends in U.S. fossil fuel prices.
Table 1
U.S. Energy Information Administration States with
Largest Demonstrated Coal Reserves (x 109 t)*
2000
400
Lignite
Coal is formed from plants by chemical and geological processes that occur over millions of years. Layers
of plant debris are deposited in wet or swampy regions
under conditions that prevent exposure to air and complete decay as the debris accumulates. Bacterial action, pressure and temperature act on the organic
matter over time to form coal. The geochemical process that transforms plant debris to coal is called coalification. The first product of this process, peat, often
contains partially decomposed stems, twigs, and bark
Table 2
Sulfur Content and Demonstrated Total Underground and
Surface Coal Reserve Base of the U.S. (Million tons)
Sulfur Range, %
State
<1.0
Alabama
624.7
Alaska
11,458.4
Arizona
173.3
Arkansas
81.2
Colorado
7,475.5
Georgia
0.3
Illinois
1,095.1
Indiana
548.8
Iowa
1.5
Kansas
0.0
Kentucky-East 6,558.4
Kentucky-West
0.2
Maryland
135.1
Michigan
4.6
Missouri
0.0
Montana
101,646.6
New Mexico
3,575.3
North Carolina
0.0
North Dakota
5,389.0
Ohio
134.4
Oklahoma
275.0
Oregon
1.5
Pennsylvania
7,318.3
South Dakota
103.1
Tennessee
204.8
Texas
659.8
Utah
1,968.5
Virginia
2,140.1
Washington
603.5
West Virginia 14,092.1
Wyoming
33,912.3
Total*
200,181.4
1.1 to 3.0
>3.0 Unknown
Total*
1,099.9
16.4 1,239.4 2,981.8
184.2
0.0
0.0 11,645.4
176.7
0.0
0.0
350.0
463.1
46.3
74.3
665.7
786.2
47.3 6,547.3 14,869.2
0.0
0.0
0.2
0.5
7,341.4 42,968.9 14,256.2 65,664.8
3,305.8 5,262.4 1,504.1 10,622.6
226.7 2,105.9
549.2 2,884.9
309.2
695.6
383.2 1,388.1
3,321.8
299.5 2,729.3 12,916.7
564.4 9,243.9 2,815.9 12,623.9
690.5
187.4
34.6 1,048.2
85.4
20.9
7.0
118.2
182.0 5,226.0 4,080.5 9,487.3
4,115.0
502.6 2,116.7 108,396.2
793.4
0.9
27.5 4,394.8
0.0
0.0
31.7
31.7
10,325.4
268.7
15.0 16,003.0
6,440.9 12,534.3 1,872.0 21,077.2
326.6
241.4
450.5 1,294.2
0.3
0.0
0.0
1.8
16,913.6 3,799.6 2,954.2 31,000.6
287.9
35.9
1.0
428.0
533.2
156.6
88.0
986.7
1,884.6
284.1
444.0 3,271.9
1,546.7
49.4
478.3 4,042.5
1,163.5
14.1
330.0 3,649.9
1,265.5
39.0
45.1 1,954.0
14,006.2 6,823.3 4,652.5 39,589.8
14,657.4 1,701.1 3,060.3 53,336.1
92,997.5 92,571.5 50,788.0 436,725.7
*Data may not add to totals shown due to independent rounding.
Source, Bureau of Mines Bulletin, CoalBituminous and Lignite,
1974.
9-3
The Babcock & Wilcox Company
Fig. 8 U.S. coal reserves.
and is not classified as coal. However, peat is progressively transformed to lignite that eventually can become anthracite, given the proper progression of geological changes.
Various physical and chemical processes occur during coalification. The heat and pressure to which the
organic material is exposed cause chemical and structural changes. These changes include an increase in
carbon content; loss of water, oxygen and hydrogen;
and resistance to solvents. The coalification process is
shown schematically in Fig. 9.
Coal is very heterogeneous and can vary in chemical composition by location. In addition to the major
organic ingredients (carbon, hydrogen and oxygen),
coal also contains impurities. The impurities that are
of major concern are ash and sulfur. The ash results
from mineral or inorganic material introduced during
coalification. Ash sources include inorganic substances, such as silica, that are part of the chemical
structure of the plants. Dissolved inorganic ions and
mineral grains found in swampy water are also captured by the organic matter during early coalification.
Mud, shale and pyrite are deposited in pores and cracks
of the coal seams.
Sulfur occurs in coal in three forms: 1) organic sulfur, which is part of the coal’s molecular structure, 2)
pyritic sulfur, which occurs as the mineral pyrite, and
3) sulfate sulfur, primarily from iron sulfate. The principal sulfur source is sulfate ion, found in water. Fresh
water has a low sulfate concentration while salt water has a high sulfate content. Therefore, bituminous
9-4
coal, deposited in the interior of the U.S. when seas
covered this region, are high in sulfur. Some Iowa
coals contain as much as 8% sulfur.
Although coal is a complex, heterogeneous mixture
and not a polymer or biological molecule, it is sometimes useful for chemists to draw an idealized structural formula. These formulas can serve as models that
illustrate coal reactions. This can aid the further development of coal processes such as gasification, combustion and liquefaction.
Fig. 9 The coalification process (DAF = dry ash-free).
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Classifying coal
A coal classification system is needed because coal
is a heterogeneous substance with a wide range of composition and properties. Coals are typically classified
by rank. This indicates the progressive alteration in
the coalification process from lignite to subbituminous,
bituminous and anthracite coals. The rank indicates
a coal’s geological history and broad characteristics.
ASTM classification by rank
The system used in the U.S. for classifying coal by rank
was established by the American Society for Testing and
Materials (ASTM).5 ASTM classification is a system that
uses the volatile matter (VM) and fixed carbon (FC) results from the proximate analysis and the heating value
of the coal as ranking criteria. This system aids in identifying commercial uses of coals and provides basic information regarding combustion characteristics.
The classification system is given in Table 3 and
described in section D 388 of the ASTM standards.
Proximate analysis is based on the laboratory procedure described in ASTM D 3172. In this procedure,
moisture content, ash remaining after complete burning, amount of gases released when heated to a prescribed temperature, and fixed carbon remaining after volatilization are determined.
Table 4 gives a typical as-received proximate analysis of a West Virginia coal. An as-received analysis includes the total moisture content of the coal as it is
received at the power plant.
For older or higher rank coals, FC and VM are used
as the classifying criteria. These criteria are determined
on a dry, mineral-matter-free basis using formulas developed by S.W. Parr in 1906 (shown in Equations 1
through 6).6 The younger or low rank coals are classified by Btu content on a moist, mineral-matter-free basis. Agglomerating or weathering indices, as described in
ASTM D 388, are used to differentiate adjacent groups.
Parr Formulas
Dry, mineral-free FC =
FC − 0.15 S
× 100, %
100 − ( M + 1.08 A + 0.55 S )
(1)
Table 3
Classification of Coals by Ranka (ASTM D 388)
Fixed Carbon Volatile Matter Calorific Value
Limits, %
Limits, %
Limits, Btu/lb
(Dry, Mineral- (Dry, Mineral(Moist,b
Matter-Free
Matter-Free Mineral-MatterBasis)
Basis)
Free Basis)
Class
I. Anthracitic
II. Bituminous
Group
1. Meta-anthracite
2. Anthracite
3. Semianthracitec
98
92
86
−
98
92
−
2
8
2
8
14
1. Low volatile bituminous coal
2. Medium volatile bituminous coal
3. High volatile A bituminous coal
4. High volatile B bituminous coal
5. High volatile C bituminous coal
78
69
−
−
−
86
78
69
−
−
14
22
31
−
−
22
31
−
−
−
1. Subbituminous A coal
III. Subbituminous 2. Subbituminous B coal
3. Subbituminous C coal
IV. Lignitic
Equal or
Equal Equal or
Greater Less Greater or Less Greater Less
Than Than Than
Than
Than Than
1. Lignite A
2. Lignite B
a
−
−
−
−
−
−
−
−
−
−
−
−
−
−
−
−
−
−
−
−
This classification does not include a few coals, principally
nonbanded varieties, which have unusual physical and chemical
properties and which come within the limits of fixed carbon
or calorific value of the high volatile bituminous and
subbituminous ranks. All of these coals either contain less
than 48% dry, mineral-matter-free fixed carbon or have more
than 15,500 moist, mineral-matter-free Btu/lb.
b
Moist refers to coal containing its natural inherent moisture
but not including visible water on the surface of the coal.
Steam 41 / Sources of Chemical Energy
−
−
−
−
−
−
Agglomerating
Character
Nonagglomerating
−
−
−
−
−
14,000d
13,000d 14,000
11,500 13,000
10,500e 11,500
Agglomerating
10,500 11,500
9,500 10,500
8,300 9,500
Nonagglomerating
6,300
−
Commonly
agglomeratinge
8,300
6,300
c
If agglomerating, classify in low volatile group of the
bituminous class.
d
Coals having 69% or more fixed carbon on the dry, mineralmatter-free basis shall be classified according to fixed carbon,
regardless of calorific value.
e
It is recognized that there may be nonagglomerating varieties
in these groups of the bituminous class, and there are notable
exceptions in high volatile C bituminous group.
9-5
The Babcock & Wilcox Company
Table 4
Coal Analyses on As-Received Basis
(Pittsburgh Seam Coal, West Virginia)
Proximate Analysis
Component
% by wt
Ultimate Analysis
Component
% by wt
Moisture
Volatile matter
Fixed carbon
Ash
Total
2.5
37.6
52.9
7.0
100.0
Heating value,
Btu/lb
(kJ/kg)
13,000
(30,238)
Moisture
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Ash
Total
2.5
75.0
5.0
2.3
1.5
6.7
7.0
100.0
Dry, mineral-free VM =
100 − Dry, mineral-free FC , %
(2)
Moist, mineral-free Btu =
Btu − 50 S
× 100, per lb
100 − (1.08 A + 0.55 S )
(3)
Approximation Formulas
Dry, mineral-free FC =
FC
× 100, %
100 − ( M + 1.1 A + 0.1 S )
(4)
Dry, mineral-free VM =
100 − Dry, mineral-free FC , %
(5)
Moist, mineral-free Btu =
Btu
× 100, per lb
100 − (1.1 A + 0.1 S )
(6)
where
Btu
FC
VM
M
A
S
=
=
=
=
=
=
heating value per lb (kJ/kg = 2.326 × Btu/lb)
fixed carbon, %
volatile matter, %
bed moisture,
ash, %
sulfur, %
all for coal on a moist basis.
Table 5 lists 16 selected U.S. coals, arranged in order
of ASTM classification. The following descriptions briefly
summarize the characteristics of each coal rank.
Peat Peat, the first product in the formation of coal,
is a heterogeneous material consisting of partially decomposed plant and mineral matter. Its color ranges
from yellow to brownish-black, depending on its geologic age. Peat has a moisture content up to 70% and
a heating value as low as 3000 Btu/lb (6978 kJ/kg).
Lignite Lignite is the lowest rank coal. Lignites are
9-6
relatively soft and brown to black in color with heating values of less than 8300 Btu/lb (19,306 kJ/kg). The
deposits are geologically young and can contain recognizable remains of plant debris. The moisture content of lignites is as high as 30% but the volatile content is also high; consequently, they ignite easily. Lignite coal dries when exposed to air and spontaneous
combustion during storage is a concern. Long distance
shipment of these coals is usually not economical because of their high moisture and low Btu content. The
largest lignite deposit in the world spreads over the
regions of North and South Dakota, Wyoming, and
Montana in the U.S. and parts of Saskatchewan and
Manitoba in Canada.
Subbituminous Subbituminous coals are black,
having little of the plant-like texture and none of the
brown color associated with the lower rank lignite
coal. Subbituminous coals are non-coking (undergo
little swelling upon heating) and have a relatively high
moisture content which averages from 15 to 30%. They
also display a tendency toward spontaneous combustion when drying.
Although they are high in VM content and ignite
easily, subbituminous coals generally have less ash
and are cleaner burning than lignite coals. Subbituminous coals in the U.S. in general have a very low
sulfur content, often less than 1%. Because they have
reasonably high heating values [8300 to 11,500 Btu/
lb (19,306 to 26,749 kJ/kg)] and low sulfur content,
switching to subbituminous coal has become an attractive option for many power plants to limit SO2 emissions.
Bituminous Bituminous coal is the rank most commonly burned in electric utility boilers. In general, it
appears black with banded layers of glossy and dull
black. Typical bituminous coals have heating values
of 10,500 to 14,000 Btu/lb (24,423 to 32,564 kJ/kg)
and a fixed carbon content of 69 to 86%. The heating
value is higher, but moisture and volatile content are
lower than the subbituminous and lignite coals. Bituminous coals rarely experience spontaneous combustion in storage. Furthermore, the high heating
value and fairly high volatile content enable bituminous coals to burn easily when pulverized to a fine
powder. Some types of bituminous coal, when heated
in the absence of air, soften and release volatiles to
form the porous, hard, black product known as coke.
Coke is used as fuel in blast furnaces to make iron.
Anthracite Anthracite, the highest rank of coal, is
shiny black, hard and brittle, with little appearance
of layers. It has the highest content of fixed carbon,
86 to 98%. However, its low volatile content makes it
a slow burning fuel. Most anthracites have a very low
moisture content of about 3%; heating values of
15,000 Btu/lb (34,890 kJ/kg) are slightly lower than
the best quality bituminous coals. Anthracite is low in
sulfur and volatiles and burns with a hot, clean flame.
These qualities make it a premium fuel used mostly
for domestic heating.
Other classification systems
There are other classifications of coal that are currently in limited use in Europe. These are the International Classification of Hard Coals by Type and the
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Table 5
Sixteen Selected U.S. Coals Arranged in Order of ASTM Classification
No.
1
2
3
Coal Rank
Class Group
I
1
I
2
I
3
Coal Analysis, Bed Moisture Basis
VM
FC
A
S
1.7
84.1
9.7
0.77
6.2
79.4
11.9
0.60
10.6
67.2
20.2
0.62
State
Pa.
Pa.
Va.
County
Schuylkill
Lackawanna
Montgomery
M
4.5
2.5
2.0
1.0
1.3
1.5
1.5
1.5
2.5
3.6
16.6
17.5
20.8
23.4
30.7
36.7
40.0
77.3
70.9
67.5
64.9
56.6
57.5
47.3
5.1
10.3
10.2
10.2
11.2
3.3
9.1
Btu
12,745
12,925
11,925
Rank
FC
99.2
94.1
88.7
Rank
Btu
14,280
14,880
15,340
0.74
1.68
1.68
2.20
1.82
0.70
4.00
14,715
13,800
13,720
13,800
13,325
14,480
12,850
82.8
81.3
77.5
74.5
65.8
61.3
55.4
15,600
15,595
15,485
15,580
15,230
15,040
14,380
4
5
6
7
8
9
10
II
II
II
II
II
II
II
1
1
2
2
3
3
3
W.Va.
Pa.
Pa.
Pa.
Pa.
Ky.
Ohio
McDowell
Cambria
Somerset
Indiana
Westmoreland
Pike
Belmont
11
12
13
II
II
II
4
4
5
Ill.
Utah
Ill.
Williamson
Emery
Vermilion
5.8
5.2
12.2
36.2
38.2
38.8
46.3
50.2
40.0
11.7
6.4
9.0
2.70
0.90
3.20
11,910
12,600
11,340
57.3
57.3
51.8
13,710
13,560
12,630
14
15
III
III
2
3
Wyo.
Wyo.
Sheridan
Campbell
25.0
31.0
30.5
31.4
40.8
32.8
3.7
4.8
0.30
0.55
9,345
8,320
57.5
51.5
9,745
8,790
16
IV
1
N.D.
Mercer
37.0
26.6
32.2
4.2
0.40
7,255
55.2
7,610
Notes: For definition of Rank Classification according to ASTM requirements, see Table 3.
Data on Coal (Bed Moisture Basis)
M = equilibrium moisture, %; VM = volatile matter, %;
FC = fixed carbon, %; A = ash, %; S = sulfur, %;
Btu = Btu/lb, higher heating value.
International Classification of Brown Coals. These systems were developed by the Coal Committee of the
Economic Commission for Europe in 1949.
Coal characterization
As previously described, the criteria for ranking coal
are based on its proximate analysis. In addition to providing classifications, coal analysis provides other useful information. This includes assistance in selecting
coal for steam generation, evaluation of existing handling and combustion equipment, and input for design. The analyses consist of standard ASTM procedures and special tests developed by The Babcock &
Wilcox Company (B&W). The following briefly summarizes some of these tests.
Standard ASTM analyses5,7
Bases for analyses Because of the variability of
moisture and ash content in coals, the composition
determined by proximate analysis can be reported on
several bases. The most common include as-received,
moisture-free or dry, and mineral-matter-free. The asreceived analysis reports the percentage by weight of
each constituent in the coal as it is received at the laboratory. As-received samples contain varying levels of
moisture. For analysis on a dry basis, the moisture of
the sample is determined and then used to correct each
Steam 41 / Sources of Chemical Energy
Rank FC = dry, mineral-matter-free fixed carbon, %;
Rank Btu = moist, mineral-matter-free Btu/lb.
Calculations by Parr formulas.
constituent to a common dry level. As previously mentioned, the ash in coal as determined by proximate
analysis is different than the mineral matter in coal.
This can cause problems when ranking coals by the
ASTM method. Formulas used to correct for the mineral matter and to determine volatile matter, fixed
carbon and heating value on a mineral-matter-free
basis are provided in Equations 1 to 6 above.
Moisture determination Coal received at an electric
power plant contains varying amounts of moisture in
several forms. There is inherent and surface moisture
in coal. Inherent moisture is that which is a naturally
combined part of the coal deposit. It is held tightly
within the coal structure and can not be removed easily when the coal is dried in air. The surface moisture
is not part of the coal deposit and has been added externally. Surface moisture is more easily removed from
coal when exposed to air. It is not possible to distinguish, by analysis, inherent and surface moisture.
There are many other moistures that arise when
characterizing coal including equilibrium, free and air
dry moisture. Their definitions and use depend on the
application. Equilibrium moisture is sometimes used
as an estimate of bed moisture. The ASTM standard
terminology of coal and coke, D 121, defines the total
coal moisture as the loss in weight of a sample under
controlled conditions of temperature, time and air flow.
Using ASTM D 3302, the total moisture is calculated
9-7
The Babcock & Wilcox Company
from the moisture lost or gained in air drying and the
residual moisture. The residual moisture is determined
by oven drying the air dried sample. Because subsequent ASTM analyses (such as proximate and ultimate) are performed on an air dried sample, the residual moisture value is required to convert these results to a dry basis. In addition, the moisture lost on
air drying provides an indication of the drying required in the handling and pulverization portions of
the boiler coal feed system.
Proximate analysis Proximate analysis, ASTM D 3172,
includes the determination of volatile matter, fixed carbon and ash. Volatile matter and fixed carbon, exclusive
of the ash, are two indicators of coal rank. The amount
of volatile matter in a coal indicates ease of ignition and
whether supplemental flame stabilizing fuel is required.
The ash content indicates the load under which the ash
collection system must operate. It also permits assessing
related shipping and handling costs.
Ultimate analysis Ultimate analysis, described in
ASTM D 3176, includes measurements of carbon, hydrogen, nitrogen and sulfur content, and the calculation of oxygen content. Used with the heating value
of the coal, combustion calculations can be performed
to determine coal feed rates, combustion air requirements, heat release rates, boiler performance, and
sulfur emissions from the power plant. (See Table 4.)
Heating value The gross calorific value of coal, determined using an adiabatic bomb calorimeter as described in ASTM D 2015, is expressed in Btu/lb (kJ/
kg) on various bases (dry, moisture and ash free, etc.).
This value determines the maximum theoretical fuel
energy available for the production of steam. Consequently, it is used to determine the quantity of fuel
which must be handled, pulverized and fired.
Gross (higher) heating value (HHV) is defined as
the heat released from combustion of a unit fuel quantity (mass), with the products in the form of ash, gaseous CO2, SO2, nitrogen and liquid water, exclusive of
any water added as vapor. The net (lower) heating
value (LHV) is calculated from the HHV. It is the heat
produced by a unit quantity of fuel when all water in
the products remains as vapor. This LHV calculation
(ASTM Standard D 407) is made by deducting 1030
Btu/lb (2396 kJ/kg) of water derived from the fuel,
including the water originally present as moisture and
that formed by combustion. In the U.S., the gross calorific value is commonly used in heat balance calculations, while in Europe the net value is generally used.
Grindability The Hardgrove Grindability Test, developed by B&W, is an empirical measure of the relative ease with which coal can be pulverized. The ASTM
D 409 method has been used for the past 30 years to
evaluate the grindability of coals. The method involves
grinding 50 g of air-dried 16 × 30 mesh (1.18 mm ×
600 µm) test coal in a small ball-and-race mill. The mill
is operated for 60 revolutions and the quantity of material that passes a 200 mesh (75 micron) screen is measured. From a calibration curve relating –200 mesh
(–75 micron) material to the grindability of standard
samples supplied by the U.S. Department of Energy,
the Hardgrove Grindability Index (HGI) is determined
for the test coal. Pulverizer manufacturers have de9-8
veloped correlations relating HGI to pulverizer capacity at desired levels of fineness.
Sulfur forms The sulfur forms test, ASTM D 2492,
measures the amounts of sulfate sulfur, pyritic sulfur
and organically bound sulfur in a coal. This is accomplished by measuring the total sulfur, sulfate, and pyritic sulfur contents and obtaining the organic sulfur
by difference. The quantity of pyritic sulfur is an indicator of potential coal abrasiveness.
Free swelling index The free swelling index can be
used to indicate caking characteristics. The index is
determined by ASTM D 720 which consists of heating a one gram coal sample for a specified time and
temperature. The shape of the sample or button
formed by the swelling coal is then compared to a set
of standard buttons. Larger formed buttons indicate
higher free swelling indices. Oxidized coals tend to
have lower indices. The free swelling index can be used
as a relative measurement of a coal’s caking properties and extent of oxidation.
Ash fusion temperatures Coal ash fusion temperatures are determined from cones of ash prepared and
heated in accordance with ASTM method D 1857. The
temperatures at which the cones deform to specific
shapes are determined in oxidizing and reducing atmospheres. Fusion temperatures provide ash melting
characteristics and are used for classifying the slagging potentials of the lignitic-type ashes.
Ash composition Elemental ash analysis is conducted using a coal ash sample produced by the ASTM
D 3174 procedure. The elements present in the ash
are determined and reported as oxides. Silicon dioxide (SiO2), aluminum oxide (Al2O3), titanium dioxide
(TiO2), ferric hydroxide (Fe2O3), calcium oxide (CaO),
magnesium oxide (MgO), sodium oxide (Na2O) and
potassium oxide (K2O) are measured using atomic
absorption per ASTM D 3682. The results of the ash
analyses permit calculations of fouling and slagging
indices and slag viscosity versus temperature relationships. The nature, composition and properties of coal
ash and their effects on boiler performance are described further in Chapter 21.
Special B&W tests7
Burning profiles The burning profile technique was
originated by B&W for predicting the relative combustion characteristics of fuels. The technique and application of results were described by Wagoner and
Duzy,8 and are routinely applied to liquid and solid
fuels. The test uses derivative thermogravimetry in
which a sample of fuel is oxidized under controlled conditions. A 300 mg sample of solid fuel with a particle size
less than 60 mesh (250 microns) is heated at 27F/min
(15C/min) in a stream of air. Weight change is measured
continuously and the burning profile is the resulting plot
of rate of weight loss versus furnace temperature.
Coals with similar burning profiles would be expected to behave similarly in large furnaces. By comparing the burning profile of an unknown coal with
that of a known sample, furnace design, residence
time, excess air and burner settings can be predicted.
In comparing profiles, key information is provided by
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
the start and completion temperatures of oxidation.
The area under the temperature curve is proportional
to the amount of combustible material in the sample;
the height of the curve is a measure of the combustion intensity. Burning profiles are particularly useful for preliminary evaluations of new boiler fuels such
as chars, coal-derived fuels and processed refuse. Fig.
10 shows burning profiles of coals of various ranks.
Abrasiveness index The abrasiveness of coal affects
pulverizer grinding element life, and quartz particles
in the coal can significantly contribute to its abrasiveness. A procedure for determining a coal’s quartz count
has been developed at B&W. This procedure consists
of burning the coal, collecting and washing the ash
to remove acid soluble constituents, and screening to
separate size fractions. In each size fraction, 1000 particles are counted and the number of quartz particles
is determined by a microscopic technique. From these
data, the relative quartz value, an indicator of the coal’s
relative abrasiveness, is calculated.
Another abrasion index is determined using the
Yancey-Geer Price apparatus. In this test, a sample of
coal, sized 0.25 in. × 0 (6.35 mm × 0), is placed in contact
with four metal test samples or coupons attached to a
rotating shaft. The shaft is rotated at 1440 rpm (150.8
rad/s) for a total of 12,000 revolutions (75,400 rad). The
weight loss of the metal coupons is then determined, from
which a relative abrasion index is calculated. Indices
from the test coals can be compared to those for other
fuels. B&W has used the Yancey-Geer Price Index to
determine wear in full scale pulverizers. The quartz
count procedure and the Yancey-Geer Price procedures
can provide some relative information and insight when
comparing the abrasiveness of different coals; however,
they have limited value in predicting actual field wear
rates. (See Chapter 13.)
Erosiveness index Erosion occurs in boilers due to
the impact of pulverized particles on burner lines and
other components between the pulverizers and burners. The erosiveness test, developed by B&W, subjects
a steel coupon to a stream of pulverized coal under
controlled conditions. The measured weight loss of the
coupon indicates the erosiveness of the coal.
Slag viscosity The viscosity of a coal ash slag is
measured at various temperatures under oxidizing
and reducing conditions using a high temperature rotational bob viscometer. This viscometer and its application are described in more detail in Chapter 21. The
data obtained from slag viscosity measurements are
used to predict a coal’s slagging behavior in pulverized coal-fired boiler applications. The results also indicate the suitability of a coal for use in B&W’s slagging and Cyclone furnaces.
Properties of selected coals
Table 6 gives basic fuel characteristics of typical U.S.
coals. The coals are identified by state and rank, and
the analytical data include proximate and ultimate
analyses and HHVs. Table 7 provides similar fuel properties of coals mined outside the U.S. The source of this
information, B&W’s Fuels Catalogue, contains more
than 10,000 fuel analyses performed and compiled
since the 1950s.
Steam 41 / Sources of Chemical Energy
Fuels derived from coal
Because of abundant supplies and low prices, the
demand for coal as the prime or substitute fuel for
utility boilers will most likely continue to increase. In
addition, the future use of coal-derived fuels, such as
coal refined liquids and gases, coal slurries, and chars,
as inexpensive substitutes for oil and natural gas, is
also possible. Therefore, methods to obtain clean and
efficiently burning fuels derived from coal are continually being investigated. A few of these fuels that apply to steam generation are discussed below.
Coke
When coal is heated in the absence of air or with a
large deficiency of air, the lighter constituents are
volatilized and the heavier hydrocarbons crack, liberating gases and tars and leaving a residue of carbon. Some of the volatilized portions crack on contact
with the hot carbon, leaving an additional quantity
of carbon. The carbonaceous residue containing the
ash and some of the original coal sulfur is called coke.
The amount of sulfur and ash in the coke mainly depends on the coal from which it is produced and the
coking process used. The principal uses for coke are
the production of pig iron in blast furnaces and the
charging of iron foundry cupolas. Because it is smokeless when burned, considerable quantities have been
used for space heating.
Undersized coke, called coke breeze, usually passing a 0.625 in. (15.875 mm) screen, is unsuitable for
charging blast furnaces and is often used for steam
generation. A typical analysis of coke breeze appears
in Table 8. Approximately 4.5% of the coal supplied to
slot-type coke ovens is recovered as coke breeze. A
portion of the coal tars produced as byproducts of the
various coking processes may be burned in equipment
similar to that used for heavy petroleum oil.
Gaseous fuels from coal
A number of gaseous fuels are derived from coal as
process byproducts or from gasification processes. (See
Fig. 10 Coal burning profiles.
9-9
The Babcock & Wilcox Company
Table 6
Properties of U.S. Coals
Pittsburgh #8 Illinois #6
HV
HV
Anthracite Bituminous Bituminous
Upper
Freeport
MV
Bituminous
Spring Creek
Subbituminous
Decker
Subbituminous
Lignite
Lignite
Lignite
Lignite
(S.Hallsville) (Bryan) (San Miguel)
Ohio or Pa.
Illinois
Pennsylvania
Wyoming
Montana
North Dakota
Texas
Texas
Texas
Proximate:
Moisture
Volatile matter, dry
Fixed carbon, dry
Ash, dry
7.7
6.4
83.1
10.5
5.2
40.2
50.7
9.1
17.6
44.2
45.0
10.8
2.2
28.1
58.5
13.4
24.1
43.1
51.2
5.7
23.4
40.8
54.0
5.2
33.3
43.6
45.3
11.1
37.7
45.2
44.4
10.4
34.1
31.5
18.1
50.4
14.2
21.2
10.0
68.8
Heating value, Btu/lb:
As-received
Dry
MAF
11,890
12,880
14,390
10,300
12,500
14,010
12,970
13,260
15,320
9,190
12,110
12,840
9,540
12,450
13,130
7,090
10,630
11,960
7,080
11,360
12,680
3,930
5,960
12,020
2,740
3,200
10,260
69.0
4.9
1.0
4.3
10.8
10.0
74.9
4.7
1.27
0.76
13.4
4.97
70.3
5.0
0.96
0.35
5.7
17.69
72.0
5.0
0.95
0.44
5.2
16.41
63.3
4.5
1.0
1.1
11.1
19.0
66.3
4.9
1.0
1.2
10.4
16.2
33.8
3.3
0.4
1.0
50.4
11.1
State
Ultimate:
Carbon
Hydrogen
Nitrogen
Sulfur
Ash
Oxygen
Ash fusion temps, F
Reducing/Oxidizing:
ID
ST Sp.
ST Hsp.
FT 0.0625 in.
FT Flat
Ash analysis:
SiO2
Al2O3
Fe2O3
TiO2
CaO
MgO
Na2O
K2O
P2O5
SO3
83.7
1.9
0.9
0.7
10.5
2.3
Red
Oxid
51.0
34.0
3.5
2.4
0.6
0.3
0.74
2.65
−
1.38
12,540
13,230
14,550
74.0
5.1
1.6
2.3
9.1
7.9
Red
2220
2440
2470
2570
2750+
Oxid
2560
2640
2650
2670
2750+
50.58
24.62
17.16
1.10
1.13
0.62
0.39
1.99
0.39
1.11
Red
1930
2040
2080
2420
2490
Oxid
2140
2330
2400
2600
2700
41.68
20.0
19.0
0.8
8.0
0.8
1.62
1.63
−
4.41
Red
2750+
2750+
2750+
2750+
2750+
Oxid
2750+
2750+
2750+
2750+
2750+
59.60
27.42
4.67
1.34
0.62
0.75
0.42
2.47
0.42
0.99
Red
2100
2160
2170
2190
2370
Oxid
2180
2300
2320
2360
2700
32.61
13.38
7.53
1.57
15.12
4.26
7.41
0.87
0.44
14.56
Red
2120
2250
2270
2310
2380
Oxid
2420
2470
2490
2510
2750+
23.77
15.79
6.41
1.08
21.85
3.11
6.20
0.57
0.99
18.85
Red
2030
2130
2170
2210
2300
Oxid
2160
2190
2220
2280
2300
29.80
10.0
9.0
0.4
19.0
5.0
5.80
0.49
−
20.85
Red
2000
2060
2090
2220
2330
Oxid
2210
2250
2280
2350
2400
23.32
13.0
22.0
0.8
22.0
5.0
1.05
0.27
−
9.08
Red
2370
2580
2690
2900+
2900+
Oxid
2470
2670
2760
2900+
2900+
62.4
21.5
3.0
0.5
3.0
1.2
0.59
0.92
−
3.50
18.4
2.3
0.29
1.2
68.8
9.01
Red
2730
2750+
2750+
2750+
2750+
Oxid
2750+
2750+
2750+
2750+
2750+
66.85
23.62
1.18
1.46
1.76
0.42
1.67
1.57
−
1.32
Note: HV = high volatile; MV = medium volatile; ID = initial deformation temp; ST = softening temp; FT = fluid temp; Sp. = spherical; Hsp. = hemispherical.
Chapter 18.) Table 9 lists selected analyses of these
gases. They have currently been largely supplanted
by natural gas and oil. However, improvements in coal
gasification and wider use of coal in the chemical and
liquid fuel industries could reverse this trend.
Coke oven gas A considerable portion of coal is converted to gases in the production of coke. Valuable
products recovered from these gaseous portions include
ammonium sulfate, oils and tars. The non-condensable portion is called coke oven gas. Constituents depend on the nature of the coal and the coking process
used (Table 9).
Part of the sulfur from coal may be present in coke
oven gas as hydrogen sulfide and carbon disulfide.
These may be removed by scrubbing. Coke oven gas
often contains other impurities that deposit in pipelines and burners. The gas burns readily because of
its high free hydrogen content and presents minimal
problems when used as steam generation fuel.
9-10
Blast furnace gas The gas discharged from steel mill
blast furnaces is used at the mills in furnaces, in gas
engines and for steam generation. Blast furnace gas
has variable quality but generally has a high carbon
monoxide (CO) content and low heating value (Table 9).
This gas may be burned for steam generation. However,
blast furnace gas deposits adhere firmly and provisions
must be made for cleaning boiler heating surfaces.
Water gas The gas produced by passing steam
through a bed of hot coke is known as water gas. Carbon in the coke combines with the steam to form H2
and CO. This is an endothermic reaction that cools the
coke bed. Water gas is often enriched with oil by passing the gas through a checkerwork of hot bricks
sprayed with oil. The oil, in turn, is cracked to a gas
by the heat. Refinery gas is also used for enrichment.
It may be mixed with the steam and passed through
the coke bed or may be mixed directly with the water
gas. Such enriched gas is called carbureted water gas
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Table 7
Properties of Selected International Coals
Source
Ultimate:
Carbon
Hydrogen
Nitrogen
Sulfur
Ash
Oxygen
Proximate:
Moisture
Volatile matter, dry
Fixed carbon, dry
Ash, dry
Higher heating
value, Btu/lb
Ash analysis:
SiO2
Al2O3
Fe2O3
TiO2
CaO
MgO
Na2O
K2O
P2O5
SO3
Australia
China
France
S. Africa
Indonesia
Korea
Spain
56.60
3.50
1.22
0.35
24.00
7.43
62.67
3.86
0.83
0.46
4.71
10.34
74.60
4.86
1.39
0.79
8.13
9.42
69.70
4.50
1.60
0.70
10.10
9.10
56.53
4.13
0.88
0.21
1.77
12.58
68.46
0.90
0.20
2.09
23.48
4.38
37.02
2.75
0.88
7.46
38.69
11.39
6.90
24.80
44.30
24.00
17.13
30.92
47.24
4.71
0.80
36.11
54.96
8.13
4.30
35.30
50.30
10.10
23.90
45.57
28.76
1.77
0.50
7.46
68.56
23.48
1.80
45.27
14.24
38.69
9660
10,740
13,144
12,170
9,840
9,443
6,098
57.90
32.80
6.20
1.00
0.60
0.80
0.10
0.50
−
0.80
22.70
9.00
15.68
0.43
28.88
2.00
0.70
0.46
0.09
20.23
44.60
29.90
13.10
0.60
−
3.50
3.10
−
−
2.80
44.00
32.70
4.60
1.20
5.70
1.30
0.10
0.30
2.20
4.60
71.37
13.32
7.00
0.57
2.88
0.53
0.34
0.25
0.16
3.90
55.00
17.00
12.50
1.40
0.10
0.10
0.10
3.10
−
−
14.50
8.20
2.70
0.30
45.00
1.20
0.10
0.40
−
−
Ash fusion temps, F
Reducing/Oxidizing: Red
ID
2740
ST Sp.
2750+
ST Hsp.
2750+
FT 0.0625 in.
2750+
FT Flat
2750+
Oxid
2750+
2750+
2750+
2750+
2750+
Red
2200
2240
2250
2280
2340
Oxid
2220
2270
2280
2290
2320
Red
2190
2310
−
2670
−
Oxid
2300
2500
−
2820
−
(Table 9). In many areas, carbureted water gas has
been replaced by natural gas.
Producer gas When coal or coke is burned with a
deficiency of air and a controlled amount of moisture
(steam), a product known as producer gas is obtained.
This gas, after removal of entrained ash and sulfur
compounds, is used near its source because of its low
heating value (Table 9).
Byproduct gas from gasification
Coal gasification processes are a source of synthetic
natural gas. There are many processes under development. The effluent gas from steam-oxygen coal gasification consists principally of H2, CO, CH4, CO2 and
unreacted steam. The gas will also be diluted with N2
if air is used as the oxygen source. Although the competing chemical reactions that coal undergoes during
gasification are complex, they usually include the reaction of steam and carbon to produce H2 and CO.
Steam 41 / Sources of Chemical Energy
Red
2620
2750
2750+
2750+
2750+
Oxid
2670
2750+
2750+
2750+
2750+
Red
2140
2400
2450
2630
2750
Oxid
2410
2490
2540
2680
2750+
Red
2350
2630
−
2900
−
Oxid
2600
2730
−
2900
−
Red
2530
2700
−
2730
−
Oxid
2520
2670
−
2740
−
Some CH4 is produced by the reaction of carbon with
H2 and by thermal cracking of the heavy hydrocarbons in the coal. CO2 and heat needed for the process
are produced by reaction of carbon with O2. Final gas
composition is modified by reaction between CO and
steam to produce H2 and CO2.
The products of coal gasification are often classified
as low, intermediate and high Btu gases. Low Btu gas
has a heating value of 100 to 200 Btu/SCF (3.9 to 7.9
MJ/Nm3) and is produced by gasification with air
rather than oxygen. Typically, the gas is used as a
boiler fuel at the gasification plant site or as feed to a
turbine in combined cycles. Intermediate Btu gas has
a heating value of 300 to 450 Btu/SCF (11.8 to 17.7
MJ/Nm3) and is produced by gasification with oxygen
or by a process that produces a nitrogen-free product.
The applications of intermediate Btu gas are similar to
low Btu gas. High Btu gas has a heating value greater
than 900 Btu/SCF (35.4 MJ/Nm3) and is used as a fuel
9-11
The Babcock & Wilcox Company
20
Table 8
Blast
Coke Oven Furnace Carbureted Producer
Gas
Gas
Water Gas
Gas
1
2
3
4
9-12
534
(19,896)
163
(6,073)
2000
* Non-OPEC Country
200
150
112.5
100
97.8
96.5
89.7
76.9
50
0
Kuwait
14.0
3.0
27.0
4.5
50.9
0.6
0.857
United Arab
Emirates
34.0
15.5
4.7
32.0
4.3
6.5
0.7
2.3
0.666
1995
261.7
250
Saudi
Arabia
Analyses, % by volume
Hydrogen, H2
47.9
2.4
Methane, CH4
33.9
0.1
5.2
Ethylene, C2H4
Carbon monoxide, CO 6.1
23.3
Carbon dioxide, CO2 2.6
14.4
Nitrogen, N2
3.7
56.4
Oxygen, O2
0.6
Benzene, C6H6
Water, H2O
3.4
Specific gravity
0.413
1.015
(relative to air)
HHV Btu/ft3 (kJ/m3 )
at 60F (16C) and
590
30 in. Hg (102 kPa) (21,983)
at 80F (27C) and
83.8
30 in. Hg (102 kPa)
(3,122) (3,122)
300
Billions of Barrels
Analysis No.
Fuel oil characterization
Fuel oils include virtually all petroleum products
that are less volatile than gasoline. They range from
light oils, suitable for use in internal combustion or
turbine engines, to heavy oils requiring heating. The
57.1
28.3
24
22
U.S.*
Table 9
Selected Analyses of Gaseous Fuels Derived from Coal
Fuel oil consumption for steam generation accounts
for a minor share of U.S. domestic petroleum fuel usage. Industrial users, excluding transportation, account for about 25% of all petroleum use; electric utilities consume about 2% of the total.2 The end users of
petroleum products for the years 1975 to 2000 are
shown in Fig. 11. Crude oil reserves and world petroleum consumption are shown in Figs. 12 and 13.
Compared to coal, fuel oils are relatively easy to
handle and burn. There is less bulk ash to dispose of
and the ash discharged is correspondingly small. In
most oil burners, the fuel is atomized and mixed with
combustion air. In the atomized state, the characteristics of oil approach those of natural gas. (See Chapter 11.)
Because of its relatively low cost, No. 6 fuel oil is
the most widely used for steam generation. It can be
considered a byproduct of the refining process. Its ash
content ranges from 0.01 to 0.5% which is very low
compared to coal. However, despite this low ash content, compounds of vanadium, sodium and sulfur in
the ash can pose operating problems. (See Chapter 21.)
China*
One of the most widely accepted theories explaining the origin of oil is the organic theory. Over millions of years, rivers carried mud and sand that deposited and ultimately became sedimentary rock formations. Along with this inorganic material, tiny
marine organisms were buried with the silt. Over time,
in an airless and high pressure environment, the organic material containing carbon and hydrogen was
converted to the hydrocarbon molecules of petroleum
(oil). Because of the porosity of sedimentary rock formations, the oil flowed and collected in traps, or locations where crude oil is concentrated. This phenomenon
greatly assists the economic recovery of crude oil.
Year
Fig. 11 U.S. petroleum end users.
Mexico*
Fuel oil
0
FSU*
in place of natural gas. High Btu gas is produced by the
same gasification process as intermediate Btu gas and
then upgraded by methanation. (See also Chapter 18.)
5
1990
0.3
80.0
0.6
0.3
0.5
7.3
11.0
11,670
(27,144)
10
Venezuela
2.8
23.4
trace
0.1
20.0
52.0
1.7
4000
(9304)
7.3
2.3
79.4
11.0
Iran
52.0
40.2
6.1
1.7
Iraq
Proximate
Moisture
Volatile matter
Fixed carbon
Ash
Ultimate
Hydrogen, H2
Carbon, C
Sulfur, S
Nitrogen, N2
Oxygen, O2
Moisture, H2O
Ash
Heating value, Btu/lb
(kJ/kg)
1985
Bagasse
15
1980
Coke
Breeze
1975
Analyses (as-fired),
% by wt
Million Barrels per Day
Analyses Bagasse and Coke Breeze
Fig. 12 Major world crude oil reserves, 2000 (OPEC = Organization
of Petroleum Exporting Countries).
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
heavier fuels are primarily suited for steam generation boilers. The ASTM specifications for fuel oil properties are given in Table 10.
Fuel oils can be divided into two classes: distillate
and residual. Distillate fuels are those that are vaporized in a petroleum refining operation. They are typically clean, essentially free of sediment and ash, and
relatively low in viscosity. These fuels fall into the No.
1 or No. 2 category in ASTM D 396. Although No. 2
oil is sometimes used as a premium steam generation
fuel, it best lends itself to applications where cleanliness and ease of handling outweigh its cost. Examples
include home heating and industrial applications
where low ash and/or sulfur are important. Steam
generating applications are primarily limited to use
as a startup or support fuel.
The residual fuel oils are those that are not vaporized by heating. They contain virtually all the inorganic constituents present in the crude oil. Frequently,
residual oils are black, high viscosity fluids that require heating for proper handling and combustion.
Fuel oils in grades No. 4 and 5 are less viscous and
therefore more easily handled and burned than is No.
6 oil. Depending on the crude oil used, a fuel meeting
the No. 4 specification may be a blend of residual oil
and lighter distillate fractions. This oil does not usually require heating for pumping and handling.
No. 5 oils may require heating, depending on the
firing equipment and the ambient temperature. No.
6 oils usually require heating for handling and burning. (See Chapter 11 for oil storage, handling and use
requirements.)
Table 10
ASTM Standard Specifications for Fuel Oilsa
No. 1 A distillate oil intended for vaporizing pot-type burners
and other burners requiring this grade of fuel
No. 2 A distillate oil for general purpose domestic heating for
use in burners not requiring No. 1 fuel oil
No. 4 Preheating not usually required for handling or burning
Grade
of
Fuel
Oilb
Water
Carbon
Flash Pour
and
Residue
Point, Point, Sediment, on 10%
F
F
% by
Bottoms,
(C)
(C)
vol
%
No. 5 (Light) Preheating may be required depending on climate
and equipment
No. 5 (Heavy) Preheating may be required for burning and, in
cold climates, may be required for handling
No. 6 Preheating required for burning and handling
Distillation
Temperatures,
F (C)
Ash
% by
wt
10%
Point
90%
Point
Kinematic Viscosity,
centistokes
Saybolt Viscosity, s
Universal at
100F (38C)
Furol at
122F (50C)
At 122F
(50C)
Copper
Strip
Corrosion
Min
Max
Max
Max
Max
Max
Min
Max
Min
Max
Min
Max
Min
Max
Min
Max
No. 1
100 or
legal
(38)
0
trace
0.15
420
(216)
550
(288)
1.4
2.2
35
Νο. 3
No. 2
100 or
legal
(38)
20c
(-7)
0.10
0.35
d
540c
(282)
640
(338)
(32.6)f
(37.93)
2.0e
3.6
30
No. 4
130 or
legal
(55)
20
(-7)
0.50
0.10
45
125
(5.8)
(26.4)
No. 5
(Light)
130 or
legal
(55)
1.00
0.10
150
300
(32)
(65)
No. 5
(Heavy)
130 or
legal
(55)
1.00
0.10
350
750
(75)
(162)
(42)
(81)
No. 6
150
(65)
2.00g
(900)
(9000)
(92)
(638)
Notes:
a. Recognizing the necessity for low sulfur fuel oils used in connection
with heat treatment, nonferrous metal, glass, and ceramic furnaces
and other special uses, a sulfur requirement may be specified in
accordance with the following table:
Grade of
Fuel Oil
Sulfur, Max, %
No. 1 . . . . . . . . . . . . . . . . . .
0.5
No. 2 . . . . . . . . . . . . . . . . . .
0.7
No. 4 . . . . . . . . . . . . . . . . . .
no limit
No. 5 . . . . . . . . . . . . . . . . . .
no limit
No. 6 . . . . . . . . . . . . . . . . . .
no limit
Other sulfur limits may be specified only by mutual agreement
between the purchaser and the seller.
b. It is the intent of these classifications that failure to meet any
requirement of a given grade does not automatically place an oil in
Steam 41 / Sources of Chemical Energy
Min Max
At 100F
(38C)
Gravity,
deg
API
(23) (40)
45
300
the next lower grade unless, in fact, it meets all requirements of
the lower grade.
c. Lower or higher pour points may be specified whenever required
by conditions of storage or use.
d. The 10% distillation temperature point may be specified at 440F
(226C) maximum for use in other than atomizing burners.
e. When pour point less than 0F is specified, the minimum viscosity
shall be 1.8 cs (32.0 s, Saybolt Universal) and the minimum 90%
point shall be waived.
f. Viscosity values in parentheses are for information only and not
necessarily limiting.
g. The amount of water by distillation plus the sediment by extraction
shall not exceed 2.00%. The amount of sediment by extraction
shall not exceed 0.50%. A deduction in quantity shall be made for
all water and sediment in excess of 1.0%.
Source, ASTM D 396.
9-13
The Babcock & Wilcox Company
30,000
Africa
Middle
East
Eastern
Europe
and FSU
Western
Europe
Central
and South
America
North
America
0
Far East
and Oceania
1,474
2,004
2,440
4,773
2,058
3,117
4,456
11,082
10,567
3,573
3,612
5,131
10,000
10,733
12,868
2000
15,000
5,000
20,773
1989
13,947
12,880
14,672
20,000
20,204
20,750
23,775
Thousand Barrels per Day
25,000
1980
ent is condensed and cooled to its initial temperature.
Therefore, the heat of vaporization of the water formed
is included in the HHV. For the LHV, it is assumed that
none of the water vapor condenses. Both heating values
are determined by using an oxygen bomb calorimeter.
Viscosity The viscosity of a liquid is the measure of
its internal resistance to flow. Although there are numerous viscosity scales, those most commonly used in
the U.S. are:
1.
2.
3.
4.
The kinematic viscosity of oil is related to the absolute viscosity by the following formula:
Kinematic viscosity (centistokes) =
Absolute viscosity (centipoise)
Specific gravity
Fig. 13 Major petroleum consumption.
Fuel analyses
A typical analysis of a fuel oil or waste liquid contains the following information:
1.
2.
3.
4.
5.
6.
7.
ultimate analysis
API gravity
heating value
viscosity
pour point
flash point
water and sediment
Ultimate analysis The ultimate analysis for an oil is
similar to that for a coal. The results indicate the quantities of sulfur, hydrogen, carbon, nitrogen, oxygen
and ash. Ultimate analyses for various fuel oils are
given in Table 11.
The sulfur content of the oil is an indicator of its
corrosiveness and is oxidized to sulfur oxides during
combustion. These oxides can react with water vapor
or ash constituents to form corrosive acids, salts, or
boiler fouling potassium sulfate. When molten, these
ash deposits are corrosive. Furthermore, vanadium
can combine with the sulfur oxides to form a corrosive product. (See Chapter 21.)
API gravity The petroleum industry uses the API
gravity scale to determine the relative density of oil.
The scale was devised jointly by the American Petroleum Institute (API) and the National Bureau of Standards. The relationship between the API gravity and
the specific gravity is given by the following formula:
Deg API Gravity =
141.5
− 131.5
Specific gravity at 60 / 60F
Given this relationship, heavier liquid fuels are denoted by lower API gravity values.
Heating value The heating value of a liquid fuel indicates the heat released by the complete combustion
of one unit of fuel [lb (kg)]. As for coal, there are two
calculated heating values, higher (HHV) and lower
(LHV). In computing the HHV, it is assumed that any
water vapor formed by burning the hydrogen constitu9-14
Saybolt Universal Seconds (SUS),
Saybolt Furol Seconds (SFS),
absolute viscosity (centipoise), and
kinematic viscosity (centistokes).
Pour point The pour point is the lowest temperature at which a liquid fuel flows under standardized
conditions.
Flash point The flash point is the temperature to
which a liquid must be heated to produce vapors that
flash but do not burn continuously when ignited.
There are two instruments used to determine the flash
point: the Pensky-Martens or closed cup flash tester,
and the Cleveland or open cup tester. The closed cup
tester indicates a lower flash point because it retains
light vapors which are lost by the open cup unit.
Water and sediment The water and sediment level,
also called bottom sediment and water (BSW), is a
measure of the contaminants in a liquid fuel. The sediment normally consists of calcium, sodium, magnesium
and iron compounds. For heavy fuels, the sediment
may also contain carbon.
The basic analyses described are important in designing oil-fired boilers. The HHV determines the
quantity of fuel required to reach a given heat input.
The ultimate analysis determines the theoretical air
required for complete combustion and therefore indicates the size of the burner throat. Also available from
the ultimate analysis is the carbon/hydrogen ratio,
which shows the ease with which a fuel burns. This
ratio also indicates the expected level of carbon particulate emissions. A carbon/hydrogen ratio in excess
of 7.5 is usually indicative of troublesome burning.
Considering the percentages of nitrogen and sulfur in conjunction with the HHV, an estimate of NOx
and SO2 emissions can be made. The ash percentage
has a similar bearing on particulate emissions. The ash
constituent analysis and ash content indicate fouling
and corrosion tendencies.
Additional information, which is often required
when designing a boiler, includes:
1.
2.
3.
4.
5.
carbon residue,
asphaltenes,
elemental ash analysis,
burning profile, and
distillation curve.
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Table 11
Analyses of Fuel Oils
Grade of Fuel Oil
% by weight:
Sulfur
Hydrogen
Carbon
Nitrogen
Oxygen
Ash
Gravity:
Deg API
Specific
lb/gal
No. 1
0.01 to
13.3 to
85.9 to
nil to
40 to 44
0.825 to 0.806
6.87 to 6.71
Pour point, F
Viscosity:
Centistokes at 100F
SUS at 100F
SFS at 122F
0.05 to
11.8 to
86.1 to
nil to
No. 4
1.0
13.9
88.2
0.1
28 to 40
0.887 to 0.825
7.39 to 6.87
0.2 to
(10.6 to
(86.5 to
0 to
2.0
13.0)*
89.2)*
0.1
No. 5
0.5 to
(10.5 to
(86.5 to
0 to
3.0
12.0)*
89.2)*
0.1
No. 6
0.7 to
(9.5 to
(86.5 to
0.01 to
3.5
12.0)*
90.2)*
0.5
15 to 30
0.966 to 0.876
8.04 to 7.30
14 to 22
0.972 to 0.922
8.10 to 7.68
7 to 22
1.022 to 0.922
8.51 to 7.68
0 to −50
0 to −40
−10 to +50
−10 to +80
+15 to +85
1.4 to 2.2
1.9 to 3.0
32 to 38
10.5 to 65
60 to 300
65 to 200
20 to 40
260 to 750
45 to 300
0 to 0.1
tr to 1.0
0.05 to 1.0
0.05 to 2.0
18,280 to 19,400
18,100 to 19,020
17,410 to 18,990
Water and sediment, % by vol
Heating value, Btu/lb
gross (calculated)
0.5
14.1
86.7
0.1
No. 2
19,670 to 19,860
19,170 to 19,750
*Estimated
Properties of fuel oils
Analytical results for various fuel oil properties are
given in Table 11.
Fuel oil heating values are closely related to their
specific gravities. The relationships between the HHV
of various fuel oils and their API gravities are shown
in Fig. 14.
A more accurate estimate of the heating value for
an oil is obtained by correcting the HHV from Fig. 14
as follows:
Apparent heating value =
where
HHV 100 − ( A + M + S )
+ 40.5 S
100
(7)
A = % weight of ash
M = % weight of water
S = % weight of sulfur
The volume percentages of water and sediment can
be used without appreciable error in place of their
weight percentages.
Fuel oils are generally sold on a volume basis using 60F (16C) as the base temperature. Correction
factors are given in Fig. 15 for converting volumes at
Steam 41 / Sources of Chemical Energy
Fig. 14 Relationship between HHV of various fuel oils and their API
gravities.
9-15
The Babcock & Wilcox Company
9-16
35,000
30.000
Gross
25,680
25,409
40,000
32,759
25.000
Dry
Africa
Middle
East
Eastern
Europe
and FSU
Western
Europe
0
9,980
9,102
Far East
and Oceania
5,000
8,239
4,016
5,344
3,148
10,000
10,352
6,930
15,000
11,503
9,923
20,000
Central
and South
America
Past consumption and availability
Natural gas is found in porous rock in the earth’s
crust. World natural gas production for 1999 is shown
in Fig. 17.
Electric power generation is the fastest growing segment of U.S. natural gas consumption. By 2000, electric generators had overtaken the residential segment
as the second largest user of natural gas with a 22%
share of U.S. consumption (Table 12). Environmental regulations, higher efficiency gas turbines, and a
large base of simple and combined cycle gas turbine
plants installed in the late 1990s and early 2000s drove
the annual usage of natural gas in the U.S., for electric power generation, from 3.8 trillion cubic feet in 1996
to 5.5 trillion cubic feet in 2002. The Department of
Energy (DOE) expects that the volatile price of natural
gas will hold growth to about 1.8% per year to 2025.
Natural gas characteristics
Natural gas can be found with petroleum reserves
or in separate reservoirs. Methane is the principal component of natural gas; smaller components include
ethane, propane and butane. Other hydrocarbons, such
as pentane through decane, can also be found in natural gas. Furthermore, other gases such as CO2, nitrogen,
helium and hydrogen sulfide (H2S) may be present.
Gas containing mostly methane is referred to as lean
gas. Wet gas contains appreciable amounts of the higher
hydrocarbons (5 to 10% C). Gas containing H2S is sour
gas; conversely, sweet gas contains little or no H2S.
26,383
Natural gas
Fig. 16 Approximate viscosity of fuel oil at various temperatures
(courtesy of ASTM).
North
America
other temperatures to this standard base. This correction is also dependent on the API gravity range, as
illustrated by the three lines of Fig. 15.
Handling and burning equipment are usually designed for a maximum oil viscosity. If the viscosities
of heavy oils are known at two temperatures, their
viscosities at other temperatures can be closely predicted by a linear interpolation between these two
values on the standard ASTM chart (Fig. 16). Viscositytemperature variations for certain light oils can also be
found using the ASTM chart. In this case, however, the
designer only needs to know the viscosity at one temperature. For example, the viscosity of a light oil at a
given temperature within the No. 2 fuel oil range can
be found by drawing a line parallel to the No. 2 boundary lines through the point of known temperature.
Note: On the Y axis, find the SUS viscosity at 100F (standard
test temperature) for the given oil; move horizontally to the vertical line for 100F. From this intersection, move parallel to the
diagonal lines to the viscosity required for atomization; the temperature necessary to achieve this viscosity can be read on the
X axis. The chart, based on U.S. Commercial Standard 12-48,
has been developed from data for many fuels and should be
sufficiently accurate for most applications.
Production, Billion ft
Fig. 15 Oil volume-temperature correction factors.
Fig. 17 World natural gas production, 1999.
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Table 12
Table 13
U.S. Natural Gas Consumption (Trillion ft3)
Year
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
Selected Samples of Natural Gas from U.S. Fields
ResiCom- Indus- Elec. Transpordential mercial trial Power tation Total
4.78
4.39
4.56
4.69
4.96
4.85
4.85
5.24
4.98
4.52
4.73
5.00
4.78
4.91
2.72
2.62
2.73
2.80
2.86
2.90
3.03
3.16
3.22
3.00
3.05
3.22
3.04
3.11
7.89
8.26
8.36
8.70
8.87
8.91
9.38
9.69
9.71
9.49
9.16
9.29
8.45
8.23
3.11
3.25
3.32
3.45
3.47
3.90
4.24
3.81
4.07
4.57
4.82
5.21
5.34
5.55
0.63
0.66
0.60
0.59
0.63
0.69
0.71
0.72
0.76
0.65
0.66
0.66
0.64
0.65
19.12
19.17
19.56
20.23
20.79
21.25
22.21
22.61
22.74
22.25
22.41
23.37
22.25
22.46
Note: Total may not equal sum of components due to
independent rounding. Source: Energy Information
Administration, Annual Energy Review, 2003.
Of all chemical fuels, natural gas is considered to
be the most desirable for steam generation. It is piped
directly to the consumer, eliminating the need for storage. It is substantially free of ash and mixes easily
with air, providing complete combustion without
smoke. Although the total hydrogen content of natural gas is high, its free hydrogen content is low. Because of this, natural gas burns less easily than some
manufactured gases with high free hydrogen content.
The high hydrogen content of natural gas compared
to that of oil or coal results in more water vapor being
produced in the combustion gases. This results in a
correspondingly lower efficiency of the steam generating equipment. (See Chapter 10.) This can readily
be taken into account when designing the equipment.
Properties of natural gas
Analyses of natural gas from several U.S. fields are
given in Table 13.
Other fuels
While coal, oil and gas are the dominant fuel
sources, other carbonaceous fuels being used for boiler
applications include petroleum byproducts and heavy
hydrocarbon emulsions; wood, its byproducts and
wastes from wood processing industries; certain types
of vegetation, particularly bagasse; and municipal
solid waste.
Coke from petroleum
The heavy residuals from petroleum cracking processes are presently used to produce a higher yield of
lighter hydrocarbons and a solid residue suitable for
fuel. Characteristics of these residues vary widely and
depend on the process used. Solid fuels from oil include
delayed coke, fluid coke and petroleum pitch. Some
selected analyses are given in Table 14.
The delayed coking process uses residual oil that is
Steam 41 / Sources of Chemical Energy
Sample No.
Source:
1
Pa.
2
S.C.
3
Ohio
4
La.
5
Ok.
Analyses:
Constituents, % by vol
H2, Hydrogen
1.82
CH4, Methane
83.40
84.00
93.33
90.00
84.10
0.25
C2H4, Ethylene
C2H6, Ethane
15.80
14.80
5.00
6.70
CO, Carbon
monoxide
0.45
CO2, Carbon
dioxide
0.70
0.22
0.80
N2, Nitrogen
0.80
0.50
3.40
5.00
8.40
O2, Oxygen
0.35
H2S, Hydrogen
sulfide
0.18
Ultimate, % by wt
S, Sulfur
0.34
H, Hydrogen
23.53
23.30
23.20
22.68
20.85
C, Carbon
75.25
74.72
69.12
69.26
64.84
N, Nitrogen
1.22
0.76
5.76
8.06
12.90
O, Oxygen
1.22
1.58
1.41
Specific gravity
(rel to air)
0.636
0.636
0.567
0.600
0.630
HHV
Btu/ft3 at 60F
and 30 in. Hg
1,129
1,116
964
1,022
974
(kJ/m3 at 16C
and 102 kPa)
(42,065) (41,581) (35,918) (38,079) (36,290)
Btu/lb(kJ/kg)
of fuel
23,170 22,904 22,077 21,824 20,160
(53,893) (53,275) (51,351) (50,763) (46,892)
heated and pumped to a reactor. Coke is deposited in
the reactor as a solid mass and is subsequently
stripped, mechanically or hydraulically, in the form of
lumps and granular material. Some cokes are easy to
pulverize and burn while others are difficult.
Fluid coke is produced by spraying hot residual feed
onto externally heated seed coke in a fluidized bed.
The fluid coke is removed as small particles, which are
built up in layers. This coke can be pulverized and
burned, or it can be burned in a Cyclone furnace or
in a fluidized bed. All three types of firing require
supplemental fuel to aid ignition.
The petroleum pitch process is an alternate to the
coking process and yields fuels of various characteristics. Melting points vary considerably, and the physi-
Table 14
Selected Analyses of Solid Fuels Derived from Oil
Analyses (dry basis)
% by wt
Proximate:
VM
FC
Ash
Ultimate:
Sulfur
Heating value,
Btu/lb
(kJ/kg)
Delayed Coke
Fluid Coke
10.8
88.5
0.7
9.1
90.8
0.1
6.0
93.7
0.3
6.7
93.2
0.1
9.9
1.5
4.7
5.7
14,700
15,700
(34,192) (36,518)
14,160 14,290
(32,936) (33,239)
9-17
The Babcock & Wilcox Company
cal properties vary from soft and gummy to hard and
friable. The low melting point pitches may be heated and
burned like heavy oil, while those with higher melting
points may be pulverized or crushed and burned.
Oil emulsions
With the discovery of large reserves of heavy hydrocarbon and bitumen in Venezuela, considerable
effort has been devoted to developing these sources
as commercial fuels. This has led to the formulation
of bitumen oil emulsions. Generically, these emulsions
are liquid fuels composed of micron-size oil droplets dispersed in water. Droplet coalescence is prevented by
adding a small amount of a proprietary chemical. The
fuel is characterized by relatively high levels of sulfur, asphaltenes and metals. The heating value, ash
content and viscosity of the emulsions are similar to
residual fuel oil as are their handling and combustion
performance characteristics. The emulsions can contain
vanadium which forms corrosive compounds during combustion. Vanadium can also catalyze the oxidation of SO2
to SO3 and require the use of specific emission controls
to avoid stack plumes of sulfuric acid aerosol.
Orimulsion is the trade name of a proprietary bitumen emulsion produced by Bitor, a part of Petroleos
de Venezuela SA (PDVSA), the Venezuelan national
oil company. It is prepared from approximately 30%
water and 70% bitumen from the Orinoco basin. Combined with other performance enhancing chemicals, a
stable emulsified fuel for application in boilers and other
combustion equipment is produced. A typical Orimulsion
composition compared to fuel oil is shown in Table 15.
As of 2000, Orimulsion was being utilized worldwide at the rate of 6.2 million tons per year at boiler
installations in Denmark, Japan, Italy and Canada.
The fuel can offer cost advantage over No. 6 fuel oil. Environmental control equipment is required to address sulfur oxides, nitrogen oxides, and particulate emissions.
Wood
Selected analyses and heating values of wood and
wood ash are given in Table 16. Wood is composed primarily of carbohydrates. Consequently, it has a relatively low heating value compared with bituminous
coal and oil.
Wood bark may pick up impurities during transportation. It is common practice to drag the rough logs to
central loading points and sand is often picked up.
Table 15
Composition of Orimulsion 400
Carbon (%)
Hydrogen (%)
Sulfur (%)
Oxygen (%)
Nitrogen (%)
Water (%)
Ash (%)
HHV (Btu/lb)
9-18
Orimulsion 400
No. 6 Fuel Oil
60.20
7.20
2.85
0.18
0.50
29.00
0.07
12,984
85.71
10.14
2.63
0.92
0.51
0
0.09
18,192
Table 16
Analyses of Wood and Wood Ash
Wood analyses (dry
basis), % by wt
Pine
Bark
Oak
Bark
Proximate analysis, %
Volatile matter
72.9
Fixed carbon
24.2
Ash
2.9
76.0
18.7
5.3
69.6
26.6
3.8
72.6
27.0
0.4
Ultimate analysis, %
Hydrogen
Carbon
Sulfur
Nitrogen
Oxygen
Ash
5.4
49.7
0.1
0.2
39.3
5.3
5.7
51.8
0.1
0.2
38.4
3.8
5.1
51.9
0.1
0.1
42.4
0.4
5.6
53.4
0.1
0.1
37.9
2.9
Spruce Redwood
Bark* Bark*
Heating value, Btu/lb
9,030
8,370
8,740
8,350
(kJ/kg) (21,004) (19,469) (20,329) (19,422)
Ash analysis, % by wt
SiO2
Fe2O3
TiO2
Al2O3
Mn3O4
CaO
MgO
Na2O
K2O
SO3
Cl
39.0
3.0
0.2
14.0
Trace
25.5
6.5
1.3
6.0
0.3
Trace
11.1
3.3
0.1
0.1
Trace
64.5
1.2
8.9
0.2
2.0
Trace
Ash fusibility temp, F
Reducing
Initial deformation
Softening
Fluid
2180
2240
2310
2690
2720
2740
Oxidizing
Initial deformation
Softening
Fluid
2210
2280
2350
2680
2730
2750
32.0
6.4
0.8
11.0
1.5
25.3
4.1
8.0
2.4
2.1
Trace
14.3
3.5
0.3
4.0
0.1
6.0
6.6
18.0
10.6
7.4
18.4
* Salt water stored.
Where the logs are immersed in salt water, the bark
can absorb the salt. Combustion temperatures from
burning dry bark may be high enough for these impurities to cause fluxing of refractory furnace walls
and fouling of boiler heating surfaces, unless sufficient
furnace cooling surface is provided. Sand passing
through the boiler banks can cause erosion of the
tubes, particularly if the flue gas sand loading is increased by returning collected material to the furnace.
Such collectors may be required with some bark burning equipment to reduce the stack discharge of incompletely burned bark.
Wood or bark with a moisture content of 50% or less
burns quite well; however, as the moisture increases
above this amount, combustion becomes more difficult.
With a moisture content above 65%, a large part of
the heat is required to evaporate the inherent moisture and little remains for steam generation. Burning this wet bark becomes a means of disposal rather
than a source of energy.
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Hogged wood and bark are very bulky and require
relatively large handling and storage equipment. Uninterrupted flow from bunkers or bins through chutes
is difficult to maintain. (Also see Chapter 30.)
Wood wastes There are several industries using
wood as a raw material where combustible byproducts
or wastes are available as fuels. The most important
of these are the pulp and turpentine industries. The
nature and methods of utilization of the combustible
byproducts from the pulp industry are discussed in
Chapter 28.
The residue remaining after the steam distillation
of coniferous woods for the production of turpentine
is usable as a fuel. Some of the more easily burned
constituents are removed in the distillation process; as
a result, the residue is somewhat more difficult to burn.
Other than this, fuel properties are much the same
as those of the raw wood and the problems involved
in utilization are similar.
Bagasse
Mills grinding sugar cane commonly use bagasse
for steam production. Bagasse is the dry pulp remaining after the juice has been extracted from sugar cane.
The mills normally operate 24 hours per day during
the grinding season. The supply of bagasse will easily meet the plant steam demands in mills where the
sugar is not refined. Consequently, where there is no
other market for the bagasse, no particular effort is
made to burn it efficiently, and burning equipment is
provided that will burn the bagasse as-received from
the grinders. In refining plants, supplemental fuels
are required to provide the increased steam demands.
Greater efforts to obtain higher efficiency are justified in these plants. A selected analysis of bagasse is
given in Table 8.
Other vegetation wastes
Food and related industries produce numerous vegetable wastes that are usable as fuels. They include
such materials as grain hulls, the residue from the
Table 17
Analyses of MSW and RDF Compared to Bituminous Coal
Analyses, % by wt
Constituent
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Chlorine
Water
Ash
HHV (wet), Btu/lb
(kJ/kg)
MSW
RDF
27.9
36.1
3.7
5.1
20.7
31.6
0.2
0.8
0.1
0.1
0.1
0.1
31.3
20.2
16.0
6.0
5,100
6,200
(11,863) (14,421)
Bituminous Coal
72.8
4.8
6.2
1.5
2.2
0
3.5
9.0
13,000
(30,238)
production of furfural from corn cobs and grain hulls,
coffee grounds from the production of instant coffee,
and tobacco stems. Fuels of this type are available in
such small quantities that they are relatively insignificant in total energy production.
Municipal solid waste
Municipal solid waste (MSW), or refuse, is an energy source in the U.S., Europe and Japan. MSW is
the combined residential and commercial waste generated in a given municipality. It is burned as-received, called mass burning, or processed using size
reduction and material recovery techniques to produce
refuse-derived fuel (RDF). Much MSW continues to
be landfilled, since siting and acceptance of waste-toenergy boilers have been greatly limited by the public’s
concern over environmental issues.
Table 17 shows a typical analysis of raw refuse and
RDF compared to bituminous coal. The relatively low
calorific value and high heterogeneous nature of MSW
provide a challenge to the combustion system design
engineer. The design of MSW handling and combustion systems is discussed in Chapter 29.
References
1. International Energy Outlook 2003, Report DOE/EIA0484 (2003), United States (U.S.) Energy Information Administration, Washington, D.C., May, 2003.
2. Annual Energy Review 2001, Report DOE/EIA-0384
(2001), U.S. Energy Information Administration, Washington, D.C., November, 2002.
3. 2001 Survey of Energy Resources, World Energy Congress, London, England, 2001.
4. Coal Industry Annual 2000, Report DOE/EIA-0584
(2000), U.S. Energy Information Administration, Washington, D.C., 2001.
5. “Gaseous Fuels; Coal and Coke,” Vol. 05.05, Annual
Book of ASTM Standards, American Society for Testing
and Materials, West Conshohocken, Pennsylvania, 1999.
6. Parr, S.W., “The Classification of Coal,” Bulletin No.
180, Engineering Experiment Station, University of Illinois, Chicago, Illinois, 1928.
7. Vecci, S.J., Wagoner, C.L., and Olson, G.B., “Fuel and
Ash Characterization and Its Effect on the Design of Industrial Boilers,” Proceedings of the American Power Conference, Vol. 40, pp. 850-864, 1978.
8. Wagoner, C.L., and Duzy, A.F., “Burning Profiles for
Solid Fuels,” Technical Paper 67-WA-FU-4, American Society of Mechanical Engineers, New York, New York, 1967.
Orimulsion is a trademark of Bitumenes Orinoco, S.A.
Steam 41 / Sources of Chemical Energy
9-19
The Babcock & Wilcox Company
Coal remains the dominant fuel source for electric power generation worldwide.
9-20
Steam 41 / Sources of Chemical Energy
The Babcock & Wilcox Company
Chapter 10
Principles of Combustion
A boiler requires a source of heat at a sufficient temperature to produce steam. Fossil fuel is generally
burned directly in the boiler furnace to provide this
heat although waste energy from another process may
also be used.
Combustion is defined as the rapid chemical combination of oxygen with the combustible elements of
a fuel. There are just three combustible elements of
significance in most fossil fuels: carbon, hydrogen and
sulfur. Sulfur, usually of minor significance as a heat
source, can be a major contributor to corrosion and
pollution problems. (See Chapters 21 and 32.)
The objective of good combustion is to release all of
the energy in the fuel while minimizing losses from
combustion imperfections and excess air. System requirement objectives include minimizing nitrogen
oxides (NOx), carbon monoxide (CO), volatile organic
compounds (VOC) and, for more difficult to burn fuels, minimizing unburned carbon (UBC) and furnace
corrosion. The combination of the combustible fuel elements and compounds in the fuel with all the oxygen requires temperatures high enough to ignite the
constituents, mixing or turbulence to provide intimate
oxygen-fuel contact, and sufficient time to complete
the process, sometimes referred to as the three Ts of
combustion.
Table 1 lists the chemical elements and compounds
found in fuels generally used in commercial steam
generation.
Concept of the mole
The mass of a substance in pounds equal to its
molecular weight is called a pound-mole (lb-mole) of
the substance. The molecular weight is the sum of the
atomic masses of a substance’s constituent atoms. For
example, pure elemental carbon (C) has an atomic mass
and molecular weight of 12 and therefore a lb-mole is
equal to 12. In the case of carbon dioxide (CO2), carbon still has an atomic mass of 12 and oxygen has an
atomic mass of 16 giving CO2 a molecular weight and
For clarity, this chapter is provided in English units only.
Appendix 1 provides a comprehensive list of conversion factors. Selected factors of particular interest here include:
Btu/lb × 2.326 = kJ/kg; 5/9 (F-32) = C; lb × 0.4536 = kg.
Selected SI constants include: universal gas constant =
8.3145 kJ/kmole K; one kmole at 0C and 1.01 bar = 22.4 m3.
Steam 41 / Principles of Combustion
a lb-mole equal to (1 × 12) + (2 × 16) or 44. In SI, a
similar system is based upon the molecular weight in
kilograms expressed as kg-mole or kmole. In the
United States (U.S.) power industry it is common practice to replace lb-mole with mole.
In the case of a gas, the volume occupied by one
mole is called the molar volume. The volume of one
mole of an ideal gas (a good approximation in most
combustion calculations) is a constant regardless of its
composition for a given temperature and pressure.
Therefore, one lb-mole or mole of oxygen (O2) at 32 lb
and one mole of CO2 at 44 lb will occupy the same
volume equal to 394 ft3 at 80F and 14.7 psi. The volume occupied by one mole of a gas can be corrected to
other pressures and temperatures by the ideal gas law.
Because substances combine on a molar basis during combustion but are usually measured in units of
mass (pounds), the lb-mole and molar volume are
important tools in combustion calculations.
Fundamental laws
Combustion calculations are based on several fundamental physical laws.
Conservation of matter
This law states that matter can not be destroyed or
created. There must be a mass balance between the
sum of the components entering a process and the sum
of those leaving: X pounds of fuel combined with Y
pounds of air always results in X + Y pounds of products (see Note below).
Conservation of energy
This law states that energy can not be destroyed or
created. The sum of the energies (potential, kinetic,
thermal, chemical and electrical) entering a process must
equal the sum of those leaving, although the proportions
of each may change. In combustion, chemical energy is
converted into thermal energy (see Note below).
Note: While the laws of conservation of matter and energy
are not rigorous from a nuclear physics standpoint (see Chapter 47), they are quite adequate for engineering combustion
calculations. When a pound of a typical coal is burned releasing 13,500 Btu, the equivalent quantity of mass converted
to energy amounts to only 3.5 × 10–10 lb.
10- 1
10- 2
Carbon
Hydrogen
Oxygen
Nitrogen
Nitrogen (atm.) f
Carbon Monoxide
Carbon Dioxide
1
2
3
4
4
5
6
Methane
Ethane
Propane
n-Butane
Isobutane
n-Pentane
Isopentane
Neopentane
n-Hexane
Ethylene
Propylene
n-Butene (Butylene)
Isobutene
n-Pentene
H 2S
SO2
H 2O
30
31
32
33
34.0819
64.0648
18.0153
28.9625
32.0660
11.030
5.806g
19.863
13.098
0.0907
0.1722g
0.0503
0.0763
14.480
2.955h
11.820h
8.224h
22.008g
4.518
3.637h
2.874h
13.447
8.874
6.560g
6.561g
5.135h
23.608
12.514
8.456
6.310
6.328
4.952
4.999
5.040g
3.987
0.0691
0.3384h
0.0846h
0.1216h
0.0454g
0.2213
0.2750h
0.3480h
0.0744
0.1127
0.1524g
0.1524g
0.1947h
0.0424
0.0799
0.1183
0.1585
0.1580
0.2019
0.2001
0.1984g
0.2508
0.0053 188.245
0.0844
11.850
0.0738
13.543
0.0742
13.474
0.0738
13.542
0.1166
8.574
1509
2220
2974
2955
3781
911
1634
2359
3124
3104
3956
3908
3857
4900
593
0.0
1484 1433
5866 5665
868g 768
1602g 1451
440g 364
4024 3873
5068g 4867
6480g 6228
1609
2371
3175g
3156g
4032g
1012
1785
2561
3376
3355
4258
4210
4159g
5252
324.2 273.9
320.6 320.6
1.1875
643
2.2558g
0.6594 50.312
1.0000
0.9046
4.4323h
1.1081h
1.5927h
0.5951g
2.8989
3.6016h
4.5576h
0.9740
1.4760
1.9966g
1.9964g
2.5508h
0.5548
1.0466
1.5489
2.0758
2.0699
2.6450
2.6202
2.5989g
3.2849
0.0696
1.1053
0.9671
0.9720
0.9672
1.5277
Btu per ft
Grossd Nete
3
20,282
19,678
19,470
19,343
19,343
21,511
20,429
19,921
19,657
19,589
19,498
19,455
19,370
19,392
7094
1059.8
3980
6534
0.0
3980
21,482 20,749
17,335 16,739
10,265g 9073
13,172g 11,929
9680g 7998
18,179 17,446
18,430g 17,602
18,622g 17,723
21,643
21,039
20,831g
20,704g
20,704g
23,891
22,334
21,653
21,299
21,231
21,085
21,043
20,958g
20,943
14,093 14,093
61,029 51,558
4342
4342
Nete
Btu per lb
Grossd
All gas volumes corrected to 60F and 14.696 psi dry.
a 1987 Atomic Weights: C=12.011, H=1.00794, O=15.9994, N=14.0067, S=32.066.
b Densities calculated from ideal values and compressibility factor given in ASTM D 3588-98. Some of the materials can not
exist as gases at 60F and 14.696 psi, in which case the values are theoretical ones. Under the actual concentrations in
which these materials are present, their partial pressure is low enough to keep them as gases.
c For gases saturated with water at 60F and 14.696 psi, 1.74% of the Btu value must be deducted. Reference 2.
Hydrogen sulfide
Sulfur dioxide
Water vapor
Air f
78.1137
92.1406
106.1675
28.0538
42.0807
56.1076
56.1076
70.1345
16.0428
30.0697
44.0966
58.1235
58.1235
72.1504
72.1504
72.1504
86.1773
12.0110
2.0159
31.9988
28.0134
28.1580
28.0104
44.0098
C 2H 2
26.0379
C10H8
128.1736
CH3OH 32.0422
C2H5OH 46.0691
NH3
17.0306
S
Acetylene
Naphthalene
Methyl alcohol
Ethyl alcohol
Ammonia
C 6H 6
C 7H 8
C8H10
C 2H 4
C 3H 6
C 4H 8
C 4H 8
C5H10
CH4
C 2H 6
C 3H 8
C4H10
C4H10
C5H12
C5H12
C5H12
C6H14
C
H2
O2
N2
N2a
CO
CO2
Formula
29 Sulfur
24
25
26
27
28
Miscellaneous
21 Benzene
22 Toluene
23 Xylene
Aromatic series CnH2n-6
16
17
18
19
20
Olefin series CnH2n
7
8
9
10
11
12
13
14
15
Parafin series CnH2n+2
Substance
No.
Density,b
Molecular
lb per
Weighta
ft3
Specific
Volumeb Specific
Gravityb
ft3
per lb
(air=1)
c
d
e
f
g
h
11.320
16.980
22.640
22.640
28.300
7.547
13.206
18.866
24.526
24.526
30.186
30.186
30.186
35.846
3.773
1.887
1.887
N2a
5.660
3.773
6.0
7.0
8.0
2.0
3.0
4.0
4.0
5.0
1.0
2.0
3.0
4.0
4.0
5.0
5.0
5.0
6.0
1.0
1.0
11.320
16.980
22.640
22.640
28.300
7.547
13.206
18.866
24.526
24.526
30.186
30.186
30.186
35.846
3.773
1.887
1.887
1.0
5.660
3.773
1.0 9.433
4.0 45.279
2.0 5.660
3.0 11.320
1.5 3.330
3.0 28.300
4.0 33.959
5.0 39.619
2.0
3.0
4.0
4.0
5.0
2.0
3.0
4.0
5.0
5.0
6.0
6.0
6.0
7.0
1.0
N2a
Flue Products
CO2 H2O
11.933
2.0
57.279 10.0
7.160
1.0
14.320
2.0
3.580
SO2
4.773
1.0
SO2
7.160
1.0
35.800
42.959
50.119
14.320
21.480
28.640
28.640
35.800
9.547
16.706
23.866
31.026
31.026
38.186
38.186
38.186
45.346
4.773
2.387
2.387
Air
1.410
1.000
3.072
2.995
1.498
2.084
1.409
3.072
3.125
3.164
3.422
3.422
3.422
3.422
3.422
3.989
3.724
3.628
3.578
3.578
3.548
3.548
3.548
3.527
2.664
7.936
0.571
O2
4.682
3.320
10.201
9.947
4.974
6.919
4.679
10.201
10.378
10.508
11.362
11.362
11.362
11.362
11.362
13.246
12.367
12.047
11.882
11.882
11.781
11.781
11.781
11.713
8.846
26.353
1.897
N2a
Air
6.093
4.310
13.274
12.943
6.472
9.003
6.088
13.274
13.504
13.673
14.784
14.784
14.784
14.784
14.784
17.235
16.092
15.676
15.460
15.460
15.329
15.329
15.329
15.240
11.510
34.290
2.468
Required
for Combustion
3.380
3.434
1.373
1.911
SO2
1.998
SO2
1.880
3.380
3.343
3.316
3.138
3.138
3.138
3.138
3.138
2.743
2.927
2.994
3.029
3.029
3.050
3.050
3.050
3.064
3.664
1.571
CO2
N2a
11.362
11.362
11.362
11.362
11.362
13.246
12.367
12.047
11.882
11.882
11.781
11.781
11.781
11.713
0.529
4.682
3.320
0.692 10.201
0.562 9.947
1.124 4.974
1.173 6.919
1.587 5.502
0.692 10.201
0.782 10.378
0.848 10.508
1.284
1.284
1.284
1.284
1.284
2.246
1.797
1.634
1.550
1.550
1.498
1.498
1.498
1.463
8.846
8.937 26.353
1.897
H 2O
Flue Gas Products
lb per lb of Combustible
8.576
10.829
6.179
7.467
6.305
6.835
6.290
7.302
7.327
7.342
6.831
7.027
7.097
7.141
7.140
7.214
7.205
7.239
7.259
7.282
7.270
7.284
7.314
7.277
8.167
5.619
5.684
Theor
air lb/
10,000
Btu
Reference 2, ASTM 3588-98.
Correction from gross to net heating value determined by deducting the HV shown for water vapor times the moles of H2.
Reference 3, Jones, F.E.
Gas Processors Suppliers Association (GPSA) Data Book, Fig 23-2, Physical Constants, 1987.
Either the density or the compressibility factor has been assumed.
1.5
1.0
2.5
9.433
12.0 45.279
1.5
5.660
3.0
11.320
0.75
2.830
7.5
28.300
9.0
33.959
10.5 39.619
3.0
4.5
6.0
6.0
7.5
2.0
3.5
5.0
6.5
6.5
8.0
8.0
8.0
9.5
1.0
0.5
0.5
O2
Reference 1
ft per ft3 of Combustible
3
Required
for Combustion
Combustion Constants
Heat of Combustion
Table 1
The Babcock & Wilcox Company
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Ideal gas law
This law states that the volume of an ideal gas is
directly proportional to its absolute temperature and
inversely proportional to its absolute pressure.
The proportionality constant is the same for one mole
of any ideal gas, so this law may be expressed as:
vM
where
vM =
R =
T =
P =
RT
=
P
(1)
volume, ft3/mole
universal gas constant, 1545 ft lb/mole R
absolute temperature, R = F + 460
absolute pressure, lb/ft2
Most gases involved in combustion calculations can
be approximated as ideal gases.
Law of combining weights
This law states that all substances combine in accordance with simple, definite weight relationships.
These relationships are exactly proportional to the
molecular weights of the constituents. For example,
carbon (molecular weight = 12) combines with oxygen
(molecular weight of O2 = 32) to form carbon dioxide
(molecular weight = 44) so that 12 lb of C and 32 lb of
O2 unite to form 44 lb of CO2. (See Application of fundamental laws below.)
Avogadro’s law
Avogadro determined that equal volumes of different gases at the same pressure and temperature contain the same number of molecules. From the concept
of the mole, a pound mole of any substance contains
a mass equal to the molecular weight of the substance.
Therefore, the ratio of mole weight to molecular weight
is a constant and a mole of any chemically pure substance contains the same number of molecules. Because a mole of any ideal gas occupies the same volume
at a given pressure and temperature (ideal gas law),
equal volumes of different gases at the same pressure
and temperature contain the same number of molecules.
Dalton’s law
This law states that the total pressure of a mixture
of gases is the sum of the partial pressures which
would be exerted by each of the constituents if each
gas were to occupy alone the same volume as the mixture. Consider equal volumes V of three gases (a, b
and c), all at the same temperature T but at different
pressures (Pa, Pb and Pc). When all three gases are
placed in the space of the same volume V, then the
resulting pressure P is equal to Pa + Pb + Pc. Each gas
in a mixture fills the entire volume and exerts a pressure independent of the other gases.
Amagat’s law
Amagat determined that the total volume occupied
by a mixture of gases is equal to the sum of the volumes which would be occupied by each of the constituents when at the same pressure and temperature as
the mixture. This law is related to Dalton’s law, but it
Steam 41 / Principles of Combustion
considers the additive effects of volume instead of pressure. If all three gases are at pressure P and temperature T but at volumes Va, Vb and Vc, then, when combined so that T and P are unchanged, the volume of
the mixture V equals Va + Vb + Vc.
Application of fundamental laws
Table 2 summarizes the molecular and weight relationships between fuel and oxygen for constituents
commonly involved in combustion. The heat of combustion for each constituent is also tabulated. Most of
the weight and volume relationships in combustion calculations can be determined by using the information
presented in Table 2 and the seven fundamental laws.
The combustion process for C and H2 can be expressed as follows:
+
C
1 molecule
1 mole
(See Note below)
12 lb
+
+
+
+
+
2H2
2 molecules
2 moles
2 ft3
4 lb
+
+
+
+
O2
1 molecule
1 mole
1 ft3
32 lb
O2
1 molecule
1 mole
1 ft3
32 lb
=
CO2
→
=
→
=
1 molecule
1 mole
1 ft3
44 lb
=
2H2O
→
=
→
=
2 molecules
2 moles
2 ft3
36 lb
Note: When 1 ft3 of oxygen (O2) combines with carbon (C),
it forms 1 ft3 of carbon dioxide (CO2). If carbon were an ideal
gas instead of a solid, 1 ft3 of carbon would be required.
It is important to note that there is a mass or weight
balance according to the law of combining weights but
there is not necessarily a molecular or volume balance.
Molar evaluation of combustion
Gaseous fuel
Molar calculations have a simple and direct application to gaseous fuels, where the analyses are usually reported on a percent by volume basis. Consider
the following fuel analysis:
Fuel Gas Analysis, % by Volume
CH4
C2H6
CO2
N2
O2
Total
85.3
12.6
0.1
1.7
0.3
100.0
The mole fraction of a component in a mixture is
the number of moles of that component divided by the
total number of moles of all components in the mixture. Because a mole of every ideal gas occupies the
same volume, by Avogadro’s Law, the mole fraction of
a component in a mixture of ideal gases equals the
volume fraction of that component.
10- 3
The Babcock & Wilcox Company
Table 2
Common Chemical Reactions of Combustion
Combustible
Reaction
Moles
Mass or weight, lb
Heat of Combustion
(High) Btu/lb of Fuel
Carbon (to CO)
2C + O2 = 2CO
2 + 1 = 2
24 +
32
=
56
3,967
Carbon (to CO2 )
C + O2 = CO2
1 + 1 = 1
12 +
32
=
44
14,093
Carbon monoxide
2CO + O2 = 2CO2
2 + 1 = 2
56 +
32
=
88
4,342
Hydrogen
2H2 + O2 = 2H2O
2 + 1 = 2
4 +
32
=
36
61,029
Sulfur (to SO2 )
S + O2 = SO2
1 + 1 = 1
32 +
32
=
64
3,980
Methane
CH4 + 2O2 = CO2 + 2H2O
1 + 2 = 1 + 2
16 +
64
=
80
23,891
Acetylene
2C2H2 + 5O2 = 4CO2 + 2H2O
2 + 5 = 4 + 2
52 + 160
= 212
21,482
Ethylene
C2H4 + 3O2 = 2CO2 + 2H2O
1 + 3 = 2 + 2
28 +
= 124
21,643
96
Ethane
2C2H6 + 7O2 = 4CO2 + 6H2O
2 + 7 = 4 + 6
60 + 224
= 284
22,334
Hydrogen sulfide
2H2S + 3O2 = 2SO2 + 2H2O
2 + 3 = 2 + 2
68 +
= 164
7,094
Moles of component
Volume of component
=
Total moles
Volume of mixture
(2)
This is a valuable concept because the volumetric
analysis of a gaseous mixture automatically gives the
mole fractions of the components.
Accordingly, the previous fuel analysis may be expressed as 85.3 moles of CH4 per 100 moles of fuel, 12.6
moles of C2H6 per 100 moles of fuel, etc.
The elemental breakdown of each constituent may
also be expressed in moles per 100 moles of fuel as
follows:
= 85.3 × 1
= 12.6 × 2
=
0.1 × 1
moles fuel
=
=
=
=
85.3
25.2
0.1
110.6
H2 in CH4
= 85.3 × 2
= 12.6 × 3
H2 in C2H6
Total H2 per 100 moles fuel
=
=
=
170.6 moles
37.8 moles
208.4 moles
O2 in CO2
=
0.1 × 1
O2 as O2
=
0.3 × 1
Total O2 per 100 moles fuel
=
=
=
0.1 moles
0.3 moles
0.4 moles
Total N2 per 100 moles fuel
=
1.7 moles
C in CH4
C in C2H6
C in CO2
Total C per 100
moles
moles
moles
moles
The oxygen/air requirements and products of combustion can now be calculated for each constituent on
an elemental basis. These requirements can also be
calculated directly using Table 1. Converting the gaseous constituents to an elemental basis has two advantages. It provides a better understanding of the
combustion process and it provides a means for determining an elemental fuel analysis on a mass basis. This
is boiler industry standard practice and is convenient
for determining a composite fuel analysis when gaseous and solid/liquid fuels are fired in combination.
The following tabulation demonstrates the conversion
of the gaseous fuel constituents on a moles/100 moles gas
basis to a lb/100 lb gas (percent mass) basis.
10- 4
96
Moles/ Mol Wt
Consti- 100
lb/
tuent Moles Mole
C
110.6 × 12.011
H2
208.4 × 2.016
0.4 × 31.999
O2
N2
1.7 × 28.013
Total
lb/
100
Moles
= 1328.4
= 420.1
= 12.8
= 47.6
1808.9
lb/
100
lb
/1808.9
/1808.9
/1808.9
/1808.9
× 100 =73.5
× 100 =23.2
× 100 = 0.7
× 100 = 2.6
100.0
Solid/liquid fuel
The ultimate analysis of solid and liquid fuels is
determined on a percent mass basis. The mass analysis is converted to a molar basis by dividing the mass
fraction of each elemental constituent by its molecular weight.
lb Constituent
Mole constituent
100 lb Fuel
=
lb Constituent
100 lb Fuel
Mole constituent
(3)
The calculation is illustrated in Table 3.
The products of combustion and moles of oxygen
required for each combustible constituent are shown.
Note that when a fuel contains oxygen, the amount
of theoretical O2/air required for combustion is reduced
(as designated by the brackets).
Composition of air
So far, combustion has been considered only as a
process involving fuel and oxygen. For normal combustion and steam generator applications, the source
of oxygen is air. Atmospheric air is composed of oxygen, nitrogen and other minor gases. The calculations
and derivation of constants which follow in this text
are based upon a U.S. standard atmosphere3 composed
of 0.20946 O2, 0.78102 N2, 0.00916 argon (Ar) and
0.00033 CO2 moles per mole of dry air, which has an
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Table 3
Calculation of Combustion Products and
Theoretical Oxygen Requirements Molar Basis
Fuel con- % Molecular
stituent by wt weight
(1)
(2)
(3)
C
H2
S
O2
N2
H2O
Ash
Total
72.0
4.4
1.6
3.6
1.4
8.0
9.0
100.0
Moles/100 ComMoles
lb fuel bustion theoretical
(2 ÷ 3) product O2 required
(4)
(5)
(6)
12.011
2.016
32.066
31.999
28.013
18.015
=
=
=
=
=
=
5.995
2.183
0.050
0.113
0.050
0.444
CO2
H2O
SO2
N2
H2O
8.835
5.995
1.091*
0.050
(0.113)
0.000
0.000
7.023
* Column 6 is based upon moles of oxygen as O2 needed for
combustion. Therefore, the moles of H2O need to be divided
by 2 to obtain equivalent moles of O2.
average molecular weight of 28.9625. To simplify the
calculations, N2 includes argon and other trace elements; it is referred to as atmospheric nitrogen (N2a)
having an equivalent molecular weight of 28.158. (See
Table 4.)
Air normally contains some moisture. As standard
practice, the American Boiler Manufacturers Association (ABMA) considers moisture content to be 0.013
lb water/lb dry air, which corresponds to approximately 60% relative humidity at 80F. For combustion
calculations on a molar basis, multiply the mass basis
moisture by 1.608 (molecular weight of air divided by
molecular weight of water). Therefore, 0.013 lb water/
lb dry air becomes 0.0209 moles water/mole dry air.
The moisture content in air is normally determined
from wet and dry bulb temperatures or from relative
humidity using a psychrometric chart, as shown in
Fig. 1. Air moisture may also be calculated from:
Pv
MFWA = 0.622 ×
( Pb − Pv )
(4)
where
MFWA = moisture content in air, lb/lb dry air
Pb
= barometric pressure, psi
Pυ
= partial pressure of water vapor in air, psi
= 0.01 (RH) (Pυ d), psi
Pυd
= saturation pressure of water vapor at dry
bulb temperature, psi
RH
= relative humidity, %
Pυ may also be calculated from Carrier’s equation:
Fig. 1 Psychrometric chart – water content of air for various wet
and dry bulb temperatures.
Pv = Pvw −
( Pb − Pvw ) (Td − Tw )
2830 − (1.44Tw )
(5)
where
Td = dry bulb temperature, F
Tw = wet bulb temperature, F
Pvw = saturation pressure of water vapor at wet
bulb temperature, psi
The following constants, with values from Table 4,
are frequently used in combustion calculations:
=
100
20.95
=
4.77
moles N2a /mole O2
=
79.05
20.95
=
3.77
lb air (dry)/lb O2
=
100
23.14
=
4.32
lb N2a /lb O2
=
76.86
23.14
=
3.32
moles air/mole O2
or
ft3 air/ft3 O2
The calculations in Table 2 can be converted to combustion with air rather than oxygen by adding 3.77
moles of N2a/mole of O2 to the left and right side of each
equation. For example, the combustion of carbon
monoxide (CO) in air becomes:
2 CO + O2 + 3.77 N2a = 2CO2 + 3.77 N2a
or for methane, CH4:
Table 4
Air Composition
Composition of Dry Air
% by vol
% by wt
Oxygen, O2
Atmospheric nitrogen, N2a
Steam 41 / Principles of Combustion
20.95
79.05
23.14
76.86
CH4 + 2O2 + 2(3.77) N2a = CO2 + 2H2O + 7.54 N2a
Theoretical air requirement
Theoretical air is the minimum air required for complete combustion of the fuel, i.e., the oxidation of car10- 5
The Babcock & Wilcox Company
bon to CO2, hydrogen to water vapor (H2O) and sulfur to sulfur dioxide (SO2). In the combustion process,
small amounts of sulfur trioxide (SO3), nitrogen oxides (NOx), unburned hydrocarbons and other minor
species may be formed. While these may be of concern
as pollutants, their impact is negligible with regard to the
quantity of air and combustion products and, therefore,
they are not normally considered in these calculations.
In practice, it is necessary to use more than the
theoretical amount of air to assure complete combustion of the fuel. For the example shown in Table 3,
consider completing the combustion calculations on a
molar basis using 20% excess air. These calculations
are summarized in Table 5.
Now consider the portion of the combustion products attributable to the air. The oxygen in the theoretical air is already accounted for in the products of
combustion: CO2, H2O (from the combustion of hydrogen) and SO2. That leaves N2a in the theoretical air,
N2a in the excess air, O2 in the excess air and H2O in
air (as calculated in Table 5) as the products in the
combustion gas attributable to the wet combustion air.
These constituents are in addition to the combustion
products from fuel shown in Table 3.
Table 5
Calculation of Wet Air Requirements
for Combustion Molar Basis
Line
No.
Description
Source
Quantity (mole/
100 lb fuel)
1
Theoretical
combustion O2
From Table 3
7.023
2
Molar fraction
O2 in dry air
O2 Vol fraction
from Table 4
0.2095
3
Theoretical dry
combustion air
Line 1/Line 2
33.523
4
Excess air at 20%
Line 3 x 0.20
6.705
5
Total dry
combustion air
Line 3 + Line 4
40.228
6
Molar fraction
of H2O in dry air
*
0.0209
7
H2O in total
dry air
Line 5 x Line 6
0.841
8
Molar fraction
of N2a in dry air
N2a Vol fraction
from Table 4
0.7905
9
N2a in theoretical
dry air
Line 3 x Line 8
26.500
10
N2a in dry
excess air
Line 4 x Line 8
5.300
11
O2 in dry
excess air
Line 2 x Line 4
1.405
* Standard combustion air: 80F, 60% relative humidity;
0.013 lb H2O/lb dry air; 0.0209 moles H2O/mole dry air.
10- 6
Products of combustion –
mass/mass fuel basis
Table 6 shows a tabulation of the flue gas products
and combustion air on a molar (or volumetric) basis
and the conversion to a mass basis (wet and dry). The
products of combustion calculated on a molar basis in
Tables 3 and 5 are itemized in column A. The moisture (H2O) sources are separated from the dry products for convenience of calculating the flue gas composition on a wet and dry basis.
The water products shown in column A are from the
combustion of hydrogen in the fuel, from moisture in
the fuel and from moisture in the air. The N2a is the
sum of nitrogen in the theoretical air plus the nitrogen in the excess air. The N2a is tabulated separately
from the elemental nitrogen in the fuel to differentiate the molecular weight of the two. In practice, the
nitrogen in the fuel is normally small with respect to
the N2a and can be included with the nitrogen in air.
For manufactured gases that are formed when combustible products oxidize with air (blast furnace gas,
for example), the nitrogen in the fuel is predominately
atmospheric nitrogen.
Flue gas products are normally measured on a volumetric basis. If the sample includes water products, it
is measured on a wet basis, typical of in situ analyzers. Conversely, if water products are excluded, measurements are done on a dry basis, which is typical of
extractive gas sample systems. (See Flue gas analysis.) Note that the flue gas products are summed on a
dry and wet basis to facilitate calculation of the flue
gas constituents on a dry and wet percent by volume
basis in columns B and C. The molecular weight of each
constituent is given in column D. Finally, the mass of
each constituent on a lb/100 lb fuel basis is the product of the moles/100 lb fuel and the molecular weight.
The calculation of the mass of air on a lb/100 lb fuel
basis, shown at the bottom of Table 6, follows the same
principles as the flue gas calculations.
For most engineering calculations, it is common U.S.
practice to work with air and flue gas (combustion products) on a mass basis. It is usually more convenient to
calculate these products on a mass basis directly as discussed later. The mole method described above is the
fundamental basis for understanding and calculating
the chemical reactions. It is also the basis for deriving
certain equations that are presented later. For those
who prefer using the mole method, Table 7 presents this
method in a convenient calculation format.
Alternate units – Btu method
It is customary within the U.S. boiler industry to
use units of mass rather than moles for expressing the
quantity of air and flue gas. This is especially true for
heat transfer calculations, where the quantity of the
working fluid (usually steam or water) is expressed
on a mass basis and the enthalpy of the hot and cold
fluids is traditionally expressed on a Btu/lb basis.
Therefore, if the combustion calculations are performed on the mole basis, it is customary to convert
the results to lb/100 lb fuel.
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Table 6
Calculation of Flue Gas and Air Quantities
Mass Basis
Flue Gas or Combustion Product
A (From
Tables 3
B
C
D (From
E
and 5)
(A/A6) (A/A11) Table 1) (A x D)
Moles/100
% Vol % Vol Molecular lb/100
Constituent lb Fuel
dry
wet
weight lb Fuel
1
2
3
4
CO2
SO2
N2 (fuel)
N2a (air)
5
O2
6
Total, dry
combustion
products
7 H2O combustion
8 H2O fuel
9 H2O air
10 Total H2O
11 Total, wet
combustion
products
Air
5.995
0.050
0.050
31.800
(26.500 +
5.300)
1.405
15.25
0.13
0.13
80.92
14.02
0.115
0.115
74.35
44.010
64.065
28.013
28.158
263.8
3.2
1.4
895.4
3.57
3.29
31.999
45.0
39.300
100.00
1208.8
2.183
+0.444
+0.841
3.468
8.11
42.768
100.00
12 Dry air
40.228
0.841
13 H2O
14 Total wet air
18.015
62.5
1271.3
28.963
18.015
1165.1
15.2
1180.3
Items that are expressed on a unit of fuel basis
(mole/100 lb fuel, mass/mass fuel, etc.) can be normalized by using an input from fuel basis. For example,
knowing that a coal has 10% ash only partly defines
the fuel. For a 10,000 Btu/lb fuel, there are 10 lb ash
per million Btu input, but for a 5000 Btu/lb fuel there
would be 20 lb ash per million Btu input. Considering that fuel input for a given boiler load does not vary
significantly with heating value, a boiler firing the
lower heating value fuel would encounter approximately twice the amount of ash.
The mass per unit input concept is valuable when
determining the impact of different fuels on combustion calculations. This method is particularly helpful
in theoretical air calculations. Referring to Table 8, in
the first column, theoretical air has been tabulated for
various fuels on a mass per mass of fuel basis. The
resulting values have little significance when comparing the various fuels. However, when the theoretical
air is converted to a mass per unit heat input from fuel
basis, the theoretical air varies little between fuels. Also
refer to the discussion on the Btu Method in the Combustion calculations section. The common units are
lb/10,000 Btu, abbreviated as lb/10KB. The fuel labeled MSW/RDF refers to municipal solid waste and
refuse derived fuel. Note that the theoretical air is in
the same range as that for fossil fuels on a heat input
basis. Carbon and hydrogen, the principal combustible
fuel elements, are shown for reference. Note that the
coals listed in the table are limited to those with a
volatile matter (moisture and ash free) greater than
Steam 41 / Principles of Combustion
30%. As volatile matter decreases, the carbon content
increases and requires more excess air. To check the
expected theoretical air for low volatile coals, refer to
Fig. 2. The theoretical air of all coals should fall within
plus or minus 0.2 lb/10,000 Btu of this curve. Table 9
provides the fuel analysis and theoretical air requirements for a typical fuel oil and natural gas.
Heat of combustion
In a boiler furnace (where no mechanical work is
done), the heat energy evolved from combining combustible elements with oxygen depends on the ultimate products of combustion; it does not rely on any
intermediate combinations that may occur.
For example, one pound of carbon reacts with oxygen to produce about 14,093 Btu of heat (refer to Table
2). The reaction may occur in one step to form CO2 or,
under certain conditions, it may take two steps. In this
process, CO is first formed, producing only 3967 Btu
per pound of carbon. In the second step, the CO joins
with additional oxygen to form CO2, releasing 10,126
Btu per pound of carbon (4342 Btu per pound of CO).
The total heat produced is again 14,093 Btu per pound
of carbon.
Measurement of heat of combustion
In boiler practice, a fuel’s heat of combustion is the
amount of energy, expressed in Btu, generated by the
complete combustion, or oxidation, of a unit weight of
fuel. Calorific value, fuel Btu value and heating value
are terms also used.
The amount of heat generated by complete combustion is a constant for a given combination of combustible elements and compounds. It is not affected by the
manner in which the combustion takes place, provided
it is complete.
A fuel’s heat of combustion is usually determined
by direct calorimeter measurement of the heat evolved.
Combustion products within a calorimeter are cooled
to the initial temperature, and the heat absorbed by
the cooling medium is measured to determine the
higher, or gross, heat of combustion (typically referred
to as the higher heating value, or HHV).
For all solid and most liquid fuels, the bomb type
calorimeter is the industry standard measurement
device. In these units, combustible substances are
burned in a constant volume of oxygen. When they
Fig. 2 Theoretical air in lb/10,000 Btu heating value of coal with a
range of volatile matter.
10- 7
The Babcock & Wilcox Company
Table 7
Combustion Calculations
1
2
3
INPUTS (see also lightly shaded blocks)
Excess air: at burner/at boiler/econ, %
Moisture in air, lb/lb dry air
Fuel heating value, Btu/lb
20/20
0.013
14,100
COMBUSTION PRODUCTS CALCULATIONS
Ultimate Analysis, % mass
8 Molecular
Fuel
AsCarbon
Weight
Constituent
Fired
Burned(CB)
lb/mole
A C
80.31
80.31
B UBC [6]
0.39
C CB [A] − [B]
79.92
12.011
7
D
E
F
G
S
H2
H2O
N2
H O2
I Ash
K Total
32.066
2.016
18.015
28.013
31.999
1.54
4.47
2.90
1.38
2.85
6.55
100.00
9
4
5
6
Molar Basis
FUEL − Bituminous coal, Virginia
Fuel input, 1,000,000 Btu/h
Unburned carbon loss, % efficiency
Unburned carbon (UBC), [5] x [3] / 14,500
Moles
/100 lb Fuel
[7] / [8]
10 Moles O
2
/Mole Fuel
Constituent
330.0
0.40
0.39
11 Moles Theo. 12
Combustion
O2/100 lb Fuel
[9] x [10]
Product
6.654
1.0
6.654
CO2
0.048
2.217
0.161
0.049
0.089
1.0
0.5
0.048
1.109
SO2
H 2O
H 2O
N2 (fuel)
−1.0
−0.089
9.218
7.722
AIR CONSTITUENTS, Moles/100 lb Fuel
13 O2 − excess
[11K] x [1] / 100
14 O2 − total
[13] + [11K]
15 N2a − air
[14] x 3.77
At Burner
1.544
9.266
34.933
At Blr/Econ
1.544
9.266
34.933
16 Air (dry)
17 H2O − air
[14] + [15]
[16] x [2] x 1.608
44.199
0.924
44.199
0.924
18 Air (wet)
[16] + [17]
45.123
45.123
19
FLUE GAS CONSTITUENTS
A CO2
B SO2
C O2
[9C]
[9D]
[13]
D
E
F
G
H
N2 (fuel)
N2a (air)
H 2O
Total dry
Total wet
24
25
26
27
28
29
30
31
KEY PERFORMANCE PARAMETERS
Molecular weight wet flue gas, lb/mole
H2O in wet gas, % by wt
Dry gas weight, lb/10,000 Btu
Wet gas weight, lb/10,000 Btu
Wet gas weight, 1000 lb/h
Air flow (wet), lb/100 lb fuel
Air flow (wet), lb/10,000 Btu
Air flow (wet), 1000 lb/h
10- 8
[9G]
[15]
[9E] + [9F] + [17]
Sum [A] through [E]
Sum [A] through [F]
20 Vol % Dry
Moles
100 x
/100 lb Fuel
[19] / [19G]
21 Vol % Wet
100 x
[19] / [19H]
22 Molecular
Weight
lb/mole
23 Flue Gas
lb/100 lb Fuel
[19] x [22]
6.654
0.048
1.544
15.39
0.11
3.57
14.30
0.10
3.32
44.010
64.065
31.999
292.8
3.1
49.4
0.049
34.933
3.302
43.228
46.530
0.11
80.82
0.11
75.07
7.10
28.013
28.158
18.015
1.4
983.6
59.5
1330.3
1389.8
100.00
100.00
At Burner
[23H] / [19H]
100 x [23F] / [23H]
100 x [23G] / [3]
100 x [23H] / [3]
[27] x [4] / 10
[16] x 28.966 + [17] x 18.015
100 x [29] / [3]
[30] x [4] / 10
At Blr/Econ
29.869
4.28
9.435
9.857
325.3
1296.9
9.198
303.5
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Using the ideal gas law, the energy change due to
the volume change is as follows:
Table 8
Theoretical Air Required for Various Fuels
Fuel
Theoretical
Theoretical Air
Air, lb/lb HHV
Typical
Range
Fuel
Btu/lb lb/104 Btu lb/104 Btu
Bituminous coal
(VM* >30%)
Subbituminous
coal (VM* >30%)
Oil
Natural Gas
Wood
MSW* and RDF*
Carbon
Hydrogen
∆HHV =
k
∑N
n =1
k
R ×T
J
, Btu/lb
(6)
where
9.07
12,000
7.56
7.35 to 7.75
6.05
8,000
7.56
7.35 to 7.75
13.69
15.74
18,400
21,800
7.46
7.22
7.35 to 7.55
7.15 to 7.35
3.94
4.13
5,831
5,500
6.75
7.50
6.60 to 6.90
7.20 to 7.80
11.51
34.29
14,093
61,029
8.16
5.62
* VM = volatile matter, moisture and ash free basis
MSW = municipal solid waste
RDF = refuse-derived fuel
are properly operated, combustion is complete and all
of the heat generated is absorbed and measured. Heat
from external sources can be excluded or proper corrections can be applied.
For gaseous fuels of 900 to 1200 Btu/ft3, continuous or constant flow type calorimeters are industry
standards. The principle of operation is the same as
for the bomb calorimeter; however, the heat content
is determined at constant pressure rather than at constant volume.
For most fuels, the difference between the constant
pressure and constant volume heating values is small
and is usually neglected. However, because fuel is
burned under essentially constant pressure conditions, the constant pressure heating value is the technically correct value.
For solid or liquid fuels, to convert the constant volume higher heating value (HHVCV) measured in the
bomb calorimeter to constant pressure (HHVCP), an
adjustment for the volume change is required. During the constant pressure combustion process:
1. Every mole of carbon combines with one mole of
oxygen to form one mole of carbon dioxide. Therefore, there is no volume change.
2. Every mole of sulfur combines with one mole of
oxygen to form one mole of sulfur dioxide. Therefore, there is no volume change.
3. Every mole of hydrogen combines with 1/2 mole of
oxygen to form one mole of water vapor. Therefore,
there is a net increase of 1/2 mole of gas produced.
When the water vapor is condensed to a liquid in the
bomb calorimeter, there is a net decrease of 1/2 mole
of gas for each mole of hydrogen.
4. For every mole of oxygen in the fuel, there is one
mole of oxygen gas produced. Therefore, there is
a net increase of one mole of gas produced for each
mole of oxygen in the fuel.
5. The solid or liquid nitrogen in the fuel is released
as a gas. Therefore, there is a net increase of one
mole of gas produced for every mole of nitrogen.
Steam 41 / Principles of Combustion
Nk
R
T
J
= number of moles of constituent k
= universal gas constant, 1545 ft-lb/mole-R
= absolute reference temperature for the bomb
calorimeter, 537R
= mechanical equivalent of heat, 778.2 ft lbf/
Btu
Substituting:
0.5 H2 R T
−N 2
−O2
∆HHV =
+
+
(7)
×
31.9988 28.0134 2.0159 778.2
where
O2 = mass fraction of oxygen in fuel
N2 = mass fraction of nitrogen in fuel
H2 = mass fraction of hydrogen in fuel
The corrections for nitrogen and oxygen in typical
solid and liquid fuels are small, generally less than 1
and 2 Btu/lbm respectively, and are generally considered negligible. The fuel heating value correction from
constant volume to constant pressure then becomes:
(8)
HHVCP = HHVCV + 264.4 H 2 , Btu/lb
Gas chromatography is also commonly used to determine the composition of gaseous fuels. When the
composition of a gas mixture is known, its heat of combustion may be determined as follows:
Table 9
Fuel Analysis and Theoretical Air
for Typical Oil and Gas Fuels
Heavy Fuel Oil,
% by wt
S
H2
C
N2
O2
1.16
10.33
87.87
0.14
0.50
Btu/lb,
as-fired 18,400
Natural Gas,
% by vol
85.3
CH4
C2H6
12.6
0.1
CO2
N2
1.7
O2
0.3
Sp Gr
0.626
Btu/ft3,
as-fired
1090
Btu/lb,
as-fired 22,379
Theoretical Air, Fuel and Moisture
Theoretical air,
lb/10,000 Btu
7.437
Theoretical air,
lb/10,000 Btu
7.206
Fuel, lb/
10,000 Btu
0.543
Fuel, lb/
10,000 Btu
0.440
Moisture, lb/
10,000 Btu
0.502
Moisture, lb/
10,000 Btu
0.912
10- 9
The Babcock & Wilcox Company
(9)
hcmix = va hca + vb hcb + … + vx hcx
where
hcmix = heat of combustion of the mixture
vx
= volume fraction of each component
hcx = heat of combustion of each component
For an accurate heating value of solid and liquid
fuels, a laboratory heating value analysis is required.
Numerous empirical methods have been published for
estimating the heating value of coal based on the
proximate or ultimate analyses. (See Chapter 9.) One
of the most frequently used correlations is Dulong’s
formula which gives reasonably accurate results for
bituminous coals (within 2 to 3%). It is often used as
a routine check of calorimeter-determined values.
HHV = 14,544 C + 62, 028 H2 − ( O2 / 8 )
+ 4050 S
(10)
where
HHV
C
H2
O2
S
=
=
=
=
=
higher heating value, Btu/lb
mass fraction carbon
mass fraction hydrogen
mass fraction oxygen
mass fraction sulfur
LHVCP = HHVCP
− 1049.7 ( H2 × 8.937 + M ) , Btu/lb
A far superior method for checking whether the
heating value is reasonable in relation to the ultimate
analysis is to determine the theoretical air on a mass
per Btu basis. (See Alternate units – Btu method.)
Table 8 indicates the range of theoretical air values.
The equation for theoretical air can be rearranged to
calculate the higher heating value, HHV, where the
median range for theoretical air for the fuel from Table
8, MQTHA, is used:
HHV = 100
11.51 C + 34.29 H2 + 4.31 S − 4.32 O2
×
MQTHA
(11)
where
HHV
C
H2
S
O2
MQTHA
=
=
=
=
=
=
higher heating value, Btu/lb
mass percent carbon, %
mass percent hydrogen, %
mass percent sulfur, %
mass percent oxygen, %
theoretical air, lb/10,000 Btu
Higher and lower heating values
Water vapor is a product of combustion for all fuels
that contain hydrogen. The heat content of a fuel depends on whether this vapor remains in the vapor
state or is condensed to liquid. In the bomb calorimeter, the products of combustion are cooled to the initial temperature and all of the water vapor formed
during combustion is condensed to liquid. This gives the
HHV or gross calorific value (defined earlier) of the fuel,
and the heat of vaporization of water is included in the
reported value. For the lower heating value (LHV) or
net calorific value (net heat of combustion at constant
10- 10
pressure), all products of combustion including water
are assumed to remain in the gaseous state, and the
water heat of vaporization is not available.
While the high, or gross, heat of combustion can be
accurately determined by established American Society for Testing and Materials (ASTM) procedures, direct determination of the lower heating value is difficult. There is no international standard for calculation of LHV from the measured HHV. The constants
used for heats of combustion, and the temperature
used to calculate the latent heat of vaporization (HFG),
may vary slightly between references. It is important
that the temperature used for the calculation of HFG
be consistent with the basis for the boiler efficiency
calculations, otherwise there can be errors in calculated fuel flow for a given boiler output. ASME Performance Test Code PTC 4 specifies a reference temperature of 77F (25C). The value given for HFG at 77F
in the ASME International Steam Tables for Industrial Use, based on IAWPS-IF97 is 1049.7 Btu/lb. Calculation of LHV at constant pressure from HHV at constant pressure is then as follows:
(12)
where
H2 = mass fraction of hydrogen in fuel
M = mass fraction of water in fuel
In some references, the calculation of LHV includes a
correction for the difference between constant volume
and constant pressure combustion. Combining Equations 8 and 12, the calculation of LHV at constant
pressure from HHV at constant volume is as follows:
LHVCP = HHVCV − 1049.7 ( H2 × 8.937 + M )
+ 264.4 H 2 , Btu/lb
(13)
Ignition temperatures
Ignition temperatures of combustible substances
vary greatly, as indicated in Table 10. This table lists
minimum temperatures and temperature ranges in air
for fuels and for the combustible constituents of fuels
commonly used in the commercial generation of heat.
Many factors influence ignition temperature, so any
tabulation can be used only as a guide. Pressure, velocity, enclosure configuration, catalytic materials, air/
fuel mixture uniformity and ignition source are examples of the variables. Ignition temperature usually
decreases with rising pressure and increases with increasing air moisture content.
The ignition temperatures of coal gases vary considerably and are appreciably higher than those of the
fixed carbon in the coal. However, the ignition temperature of coal may be considered as the ignition temperature of its fixed carbon content, because the gaseous constituents are usually distilled off, but not ignited, before this temperature is attained.
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Table 10
Ignition Temperatures of Fuels in Air
(Approximate Values or Ranges
at Atmospheric Pressure)
Combustible
Sulfur
Charcoal
Fixed carbon
(bituminous coal)
Fixed carbon
(semi-anthracite)
Fixed carbon
(anthracite)
Acetylene
Ethane
Ethylene
Hydrogen
Methane
Carbon monoxide
Kerosene
Gasoline
Formula
Temperature, F
S
C
470
650
C
765
C
870
C
C2H2
C2H6
C2H4
H2
CH4
CO
840 to 1115
580 to 825
880 to 1165
900 to 1020
1065 to 1095
1170 to 1380
1130 to 1215
490 to 560
500 to 800
Adiabatic flame temperature
The adiabatic flame temperature is the maximum
theoretical temperature that can be reached by the
products of combustion of a specific fuel and air (or
oxygen) combination, assuming no loss of heat to the
surroundings and no dissociation. The fuel’s heat of
combustion is the major factor in the flame temperature, but increasing the temperature of the air or the
fuel also raises the flame temperature. This adiabatic
temperature is a maximum with zero excess air (only
enough air chemically required to combine with the
fuel). Excess air is not involved in the combustion
process; it only acts as a dilutant and reduces the average temperature of the products of combustion.
The adiabatic temperature is determined from the
adiabatic enthalpy of the flue gas:
Hg =
HHV − Latent heat H2O + Sensible heat in air (14)
Wet gas weight
where
Hg = adiabatic enthalpy, Btu/lb
Knowing the moisture content and enthalpy of the
products of combustion, the theoretical flame or gas
temperature can be obtained from Fig. 3 (see pages
12 and 13).
The adiabatic temperature is a fictitiously high value
that can not exist. Actual flame temperatures are
lower for two main reasons:
1. Combustion is not instantaneous. Some heat is lost
to the surroundings as combustion takes place.
Faster combustion reduces heat loss. However, if
combustion is slow enough, the gases may be cooled
sufficiently and incomplete combustion may occur,
i.e., some of the fuel may remain unburned.
Steam 41 / Principles of Combustion
2. At temperatures above 3000F, some of the CO2 and
H2O in the flue gases dissociates, absorbing heat
in the process. At 3500F, about 10% of the CO2 in
a typical flue gas dissociates to CO and O2. Heat
absorption occurs at 4342 Btu/lb of CO formed,
and about 3% of the H2O dissociates to H2 and O2,
with a heat absorption of 61,029 Btu/lb of H 2
formed. As the gas cools, the dissociated CO and
H2 recombine with the O2 and liberate the heat
absorbed in dissociation, so the heat is not lost.
However, the overall effect is to lower the maximum actual flame temperature.
The term heat available (Btu/h) is used throughout this text to define the heat available to the furnace. This term is analogous to the energy term (numerator) in the adiabatic sensible heat equation above
except that one half of the radiation heat loss and the
manufacturer’s margin portion are not considered
available to the furnace.
Practical combustion application issues
In addition to the theoretical combustion evaluation methodologies addressed above, several application issues are very important in accurate combustion
calculations of actual applications. These include the
impact of the injection of SO 2 sorbents and other
chemicals into the combustion process, solid ash or
residue, unburned carbon and excess air.
Sorbents and other chemical additives
In some combustion systems, chemical compounds
are added to the gas side of the steam generator to
reduce emissions. For example, limestone is used universally in fluidized-bed steam generators to reduce
SO2 emissions. (See Chapter 17.)
Limestone impacts the combustion and efficiency
calculations by: 1) altering the mass of flue gas by
reducing SO2 and increasing CO2 levels, 2) increasing the mass of solid waste material (ash residue), 3)
increasing the air required in forming SO3 to produce
calcium sulfate, CaSO4, 4) absorbing energy (heat)
from the fuel to calcine the calcium and magnesium
carbonates, and 5) adding energy to the system in the
sulfation reaction (SO2 + ½ O2 + CaO → CaSO4 ). The
impact of sorbent/limestone is shown as a correction
to the normal combustion calculations presented later.
The limestone constituents that are required in the
combustion and efficiency calculations are:
Reactive constituents:
Calcium carbonate (CaCO3)
Magnesium carbonate (MgCO3)
Water
Inerts
Some processes may use sorbents derived from limestone. These sorbents contain reactive constituents
such as calcium hydroxide [Ca(OH)2] and magnesium
hydroxide [Mg(OH)2].
For design purposes, the amount of sorbent is determined from the design calcium to sulfur molar ratio, MOFCAS. The sorbent to fuel ratio, MFSBF, is a
10- 11
The Babcock & Wilcox Company
Fig. 3 Enthalpy of flue gas above 77F at 30 in. Hg.
10- 12
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Steam 41 / Principles of Combustion
10- 13
The Babcock & Wilcox Company
convenient equation that converts sorbent products
to a mass of fuel or input from fuel basis.
MOFCAS × S
MFSBF =
MOPCA × 32.066
(15)
Ca ( OH )2 Mg ( OH )2
MOWSB = H2O +
+
74.096
84.321
(20)
where
and
CaCO3
Ca ( OH )2
MOPCA =
+
100.089
74.096
(16)
where
MFSBF
MOFCAS
S
MOPCA
CaCO3
Ca(OH)2
=
=
=
=
mass ratio of sorbent to fuel, lb/lb
calcium to sulfur molar ratio
mass percent sulfur in fuel, %
calcium in sorbent molar basis, moles/
100 lb sorbent
= mass percent calcium carbonate in
sorbent, %
= mass percent calcium hydroxide in
sorbent, %
When calcium carbonate and magnesium carbonate are heated, they release CO2, which adds to the
flue gas products. This is referred to as calcination.
Magnesium carbonate calcines readily; however, at
the operating temperatures typical of atmospheric
pressure fluidized beds, not all of the calcium carbonate is calcined. For design purposes, 90% calcination
is appropriate for atmospheric fluidized-bed combustion. On an operating unit, the mass fraction of calcination can be determined by measuring the CO2 in the
ash residue and by assuming it exists as CaCO3. The
quantity of CO2 added to the flue gas may be calculated from:
MQGSB = 44.01 × MOGSB ×
and
100
HHV
(17)
MFCL × CaCO3 MgCO3
MOGSB = MFSBF
+
(18)
100.089
58.320
where
MQGSB = incremental CO 2 from sorbent, lb/
10,000 Btu
MOGSB = moles CO2 from sorbent, moles/100 lb
sorbent
HHV
= higher heating value, Btu/lb fuel
MFCL
= fraction of available CaCO3 calcined, lb/
lb
CaCO3 = mass percent calcium carbonate in sorbent, %
MgCO3 = mass percent magnesium carbonate in
sorbent, %
The water added to the flue gas, MQWSB, includes
the free water and water evaporated due to dehydration of calcium and magnesium hydroxide products.
MQWSB = 18.015 × MOWSB ×
10- 14
and
100
HHV
(19)
MQWSB = water added to flue gas from sorbent,
lb/10,000 Btu
MOWSB = moles of water from sorbent, moles/100
lb sorbent
HHV
= higher heating value, Btu/lb fuel
H2O
= free water from sorbent, moles/100 lb
sorbent
Ca(OH)2 = mass percent calcium hydroxide in sorbent, %
Mg(OH)2 = mass percent magnesium hydroxide in
sorbent, %
Spent sorbent refers to the solid products remaining due to the use of limestone. Spent sorbent is the
sum of the inerts in the limestone, the mass of the reactive constituents after calcination (CaCO3, CaO and
MgO), and the SO3 formed in the sulfation reaction.
MQSSB = MFSSB ×
10, 000
HHV
(21)
and
MFSSB = MFSBF − ( 0.4401 × MOGSB )
− ( 0.18015 × MOWSB ) + ( 250 × S × MFSC )
(22)
where
MQSSB
MFSSB
HHV
MFSBF
MOGSB
=
=
=
=
=
solids added to flue gas, lb/10,000 Btu
solids added to flue gas, lb/lb fuel
higher heating value, Btu/lb fuel
mass ratio of sorbent to fuel, lb/lb
moles CO2 from sorbent, moles/100 lb
sorbent
MOWSB = moles H2O from sorbent, moles/100 lb
sorbent
S
= mass percent sulfur in fuel, %
MFSC
= mass fraction of sulfur in fuel captured,
lb/lb
The combustion and efficiency values related to limestone (sorbent) are calculated separately in this text; they
are treated as a supplement to the basic calculations. (See
Combustion and efficiency calculations.)
Residue versus refuse
The term residue is used within this text to refer to
the solid waste products that leave the steam generator envelope. This replaces the term refuse which is
now used to refer to municipal solid waste fuels and
their derivatives.
Unburned carbon
In commercial solid fuel applications, it is not always
practical to completely burn the fuel. Some of the fuel
may appear as unburned carbon in the residue or CO
in the flue gas, although the hydrogen in the fuel is
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
usually completely consumed. The capital and operating (energy) costs incurred to burn this residual fuel
are usually far greater than the energy lost. In addition, the evolution of combustion equipment to reduce
NOx emissions has resulted in some tradeoffs with
increases in unburned carbon and CO.
Unburned carbon impacts the combustion calculations and represents an efficiency loss. Therefore, unburned carbon must be measured when present. The
preferred procedure is to determine the quantity of
combustible carbon in the boiler flyash and bottom ash
in accordance with ASTM D-6316, Determination of
Total, Combustible, and Carbonate Carbon in Solid
Residues from Coal and Coke.
The unburned carbon determined by ASTM D-6316
is on the basis of percent carbon in the flyash/bottom
ash (lb carbon/100 lb residue). The combustion calculations require unburned carbon on a lb/100 lb fuel
basis (percent unburned carbon from fuel) calculated
from the following equations:
UBC = MPCR × MFR
(23)
and
MFR =
AF + (100 × MFSSB )
(100 − MPCR )
UBCLMEAS = measured heat loss due to unburned
carbon, %
HHVREF
= higher heating value of reference
fuel, Btu/lb
Equation 25 assumes that the unburned carbon loss,
UBCL, is constant between the test and reference
conditions.
Excess air
For commercial applications, more than theoretical
air is needed to assure complete combustion. This excess air is needed because the air and fuel mixing is
not perfect. Because the excess air that is not used for
combustion leaves the unit at stack temperature, the
amount of excess air should be minimized. The energy
required to heat this air from ambient to stack temperature usually serves no purpose and is lost energy.
Typical values of excess air required at the burning
equipment are shown in Table 11 for various fuels and
methods of firing. When substoichiometric firing is
used in the combustion zone, i.e., less than the theoretical air is used, the values shown would apply to
the furnace zone where the final air is admitted to
(24)
Table 11
Typical Excess Air Requirements
at Fuel Burning Equipment
where
= unburned carbon, lb/100 lb fuel
= unburned carbon in residue (measured
or reference), mass %
MFR
= mass fraction residue, fuel basis, lb/lb
fuel
AF
= mass percent ash from fuel, %
MFSSB = mass fraction of spent sorbent, lb/lb fuel
UBC
MPCR
The quantity of ash in solid fuels is variable, and
therefore it is sometimes desirable to correct the measured percent unburned carbon in residue to a reference (or baseline) fuel ash content in order to evaluate combustion system performance. For given boiler
operating conditions, the heat loss due to unburned
carbon (UBCL) is assumed to remain constant for typical variations in fuel ash (and spent sorbent if applicable). The unburned carbon as it would appear in a
residue produced by the reference fuel (and sorbent
flow) may be calculated using the following equation:
MPCRREF =
100
14,500 × ( AFREF + 100 × MFSSBREF )
+1
UBCLMEAS × HHVREF
AFREF
MFSSBREF
= unburned carbon in residue corrected
to reference fuel ash (and spent sorbent), %
= mass percent ash from reference fuel, %
= reference mass fraction of spent sorbent, lb/lb fuel
Steam 41 / Principles of Combustion
Pulverized coal
Crushed coal
Coal
Fuel oil
Natural, coke
oven and
refinery gas
Blast furnace
gas
Wood/bark
(25)
where
MPCRREF
Fuel
Refuse-derived
fuels (RDF)
Municipal solid
waste (MSW)
Bagasse
Black liquor
Type of Furnace
or Burners
Excess Air
% by wt
Completely water-cooled
furnace wet or dry
ash removal
Partially water-cooled
furnace
Cyclone furnace
pressure or suction
Fluidized-bed combustion
Spreader stoker
Water-cooled vibrating
grate stoker
Chain grate and
traveling grate
Underfeed stoker
Register type burners
Register type burners
15 to 20
15 to 40
13 to 20
15 to 20
25 to 35
25 to 35
25 to 35
25 to 40
3 to 15
3 to 15
Register type burners
15 to 30
Traveling grate, watercooled vibrating grate
Fluidized-bed combustion
Completely water-cooled
furnace traveling grate
Water-cooled/refractory
covered furnace
reciprocating grate
Rotary kiln
All furnaces
Recovery furnaces for
Kraft and soda pulping
processes
20 to 25
5 to 15
40 to 60
80 to 100
60 to 100
25 to 35
15 to 20
10- 15
The Babcock & Wilcox Company
complete combustion. The amount of excess air at the
exit of the pressure parts (where it is usually monitored) must be greater than the air required at the
burning equipment to account for setting infiltration
on balanced draft units (or seal air on pressure-fired
units). On modern units with membrane wall construction, this is usually only 1 or 2% excess air at full
load. On older units, however, setting infiltration can
be significant, and operating with low air at the steam
generator exit can result in insufficient air at the burners. This can cause poor combustion performance.
For units with air heaters, excess air must be measured at the air heater gas inlet to determine efficiency.
When equipment such as selective catalytic reduction
(SCR) systems or dust collection equipment is located
between the exit of the pressure parts and air heater
gas inlet, additional air infiltration may occur, including SCR dilution air for ammonia transport. A typical
value for SCR dilution air is 0.8% excess air.
Combustion and efficiency calculations
The combustion calculations are the starting point
for all design and performance calculations for boilers and their related component parts. They establish
the quantities of the constituents involved in the combustion process chemistry (air, flue gas, residue and
sorbent), the efficiency of the combustion process and
the quantity of heat released.4
The units used for the combustion and efficiency
calculations are lb/10,000 Btu. The acronym MQxx
also refers here to constituents on a mass per 10,000
Btu basis. For gaseous fuels, the volumetric analysis
is converted to an elemental mass basis, as described
in Molar evaluation of combustion.
Combustion air – theoretical air
The combustion air is the total air required for the
burning equipment; it is the theoretical air plus the
excess air. Theoretical air is the minimum air required
for complete conversion of the carbon, hydrogen and
sulfur in the fuel to standard products of combustion.
For some fuels and/or combustion processes, all of the
carbon is not converted. In addition, when limestone
or other additives are used, some of the sulfur is not
converted to sulfur dioxide. However, additional air
is required for the conversion of sulfur dioxide to sulfur trioxide in the sulfation reaction (CaO + SO2 + 1/2
O2 → CaSO4). Because the actual air required is the
desired calculation result, the theoretical air is corrected for unburned carbon and sulfation reactions.
MQTHAC = THAC ×
100
HHV
(26)
and
THAC = 11.51 × CB + 34.29 × H2
+ 4.31 × S × (1 + 0.5 × MFSC ) − 4.32 × O2
(27)
where
MQTHAC = theoretical air, corrected, lb/10,000 Btu
10- 16
= theoretical air, corrected, lb/100 lb
fuel
= higher heating value, Btu/lb
= mass percent carbon burned
= percent carbon in fuel − UBC, %
= mass percent hydrogen in fuel, %
= mass percent sulfur in fuel, %
= mass fraction sulfur captured by furnace sorbent, lb/lb sulfur
= mass percent oxygen in fuel, %
= unburned carbon percent from fuel, %
THAC
HHV
CB
H2
S
MFSC
O2
UBC
For test purposes, the unburned carbon is measured.
For design calculations, the unburned carbon may be
calculated from the estimated unburned carbon loss,
UBCL:
UBC = UBCL ×
HHV
14,500
(28)
MFSC is the sulfur capture/retention ratio or mass
of sulfur captured per mass sulfur available from the
fuel. It is zero unless a sorbent, e.g., limestone, is used
in the furnace to reduce SO2 emissions. See Flue gas
analysis to determine MFSC for test conditions.
The mass of dry air, MQDA, water in air, MQWA,
and wet air, MQA, are calculated from the following
equations:
PXA
MQDA = MQTHAC × 1 +
100
(29)
MQWA = MA × MQDA
(30)
MQA = MQDA + MQWA
= MQDA × (1 + MA )
(31)
where
MQDA
MQTHAC
PXA
MQWA
MA
MQA
=
=
=
=
=
=
mass dry air, lb/10,000 Btu
theoretical air, lb/10,000 Btu
percent excess air, %
mass of moisture in air, lb/10,000 Btu
moisture in air, lb/lb dry air
mass of wet air, lb/10,000 Btu
Flue gas
The total gaseous products of combustion are referred to as wet flue gas. Solid products or residue are
excluded. The wet flue gas flow rate is used for heat
transfer calculations and design of auxiliary equipment. The total gaseous products excluding moisture
are referred to as dry flue gas; this parameter is used
in the efficiency calculations and determination of flue
gas enthalpy.
The wet flue gas is the sum of the wet gas from fuel
(fuel less ash, unburned carbon and sulfur captured),
combustion air, moisture in the combustion air, additional moisture such as atomizing steam and, if sorbent
is used, carbon dioxide and moisture from sorbent. Dry
flue gas is determined by subtracting the summation
of the moisture terms from the wet flue gas.
Wet gas from fuel is the mass of fuel less the ash in
the fuel, less the percent unburned carbon and, when
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
sorbent is used to reduce SO2 emissions, less the sulfur captured:
100
MQGF = 100 − AF −UBC − ( MFSC × S ) ×
(32)
HHV
where
= wet gas from fuel, lb/10,000 Btu
= mass percent ash in fuel, %
= unburned carbon as mass percent in
fuel, %
= mass fraction of sulfur captured, lb/lb
sulfur
= mass percent sulfur in fuel, %
= higher heating value, Btu/lb
MQGF
AF
UBC
MFSC
S
HHV
lated as follows:
MPWG = 100 ×
MQWFF = water from fuel, lb/10,000 Btu
H2
= mass percent hydrogen in fuel, %
= mass percent moisture in fuel, %
H2O
Refer to Sorbents and other chemical additives for
calculating gas from sorbent (CO2), MQGSB, and
water from sorbent, MQWSB. The total wet gas
weight, MQG, is then the sum of the dry air, water in
air, wet gas from fuel and, when applicable, additional water, gas from sorbent (CO2), and water from
sorbent:
MQG = MQDA + MQWA + MQGF + MQWAD
(34)
+ MQGSB + MQWSB
where
=
=
=
=
=
total wet gas weight, lb/10,000 Btu
mass dry air, lb/10,000 Btu
mass of moisture in air, lb/10,000 Btu
wet gas from the fuel, lb/10,000 Btu
additional water such as atomizing
steam, lb/10,000 Btu
MQGSB = gas from the sorbent, lb/10,000 Btu
MQWSB = water from the sorbent, lb/10,000 Btu
The total moisture in the flue gas, MQWG, is the
sum of the water from fuel, water in air and, if applicable, additional water and water from sorbent.
MQWG = MQWFF + MQWA
+ MQWAD + MQWSB
(35)
Dry flue gas, MQDG in lb/10,000 Btu, is the difference between the wet flue gas and moisture in the flue
gas:
MQDG = MQG − MQWG
(36)
The percent moisture in flue gas is a parameter required to determine flue gas energy heat content or
enthalpy (see Enthalpy of air and gas) and is calcuSteam 41 / Principles of Combustion
MQRF = ( AF + UBC ) ×
100
HHV
(38)
where
(33)
where
MQG
MQDA
MQWA
MQGF
MQWAD
(37)
For most fuels, the mass of solids, or residue, in the
flue gas is insignificant and can be ignored. Even
when the quantity is significant, solids do not materially impact the volume flow rate of flue gas. However,
solids add to the heat content, or enthalpy, of flue gas
and should be accounted for when the ash content of
the fuel is greater than 0.15 lb/10,000 Btu or when
sorbent is used.
The mass of residue from fuel, MQRF in lb/10,000
Btu, is calculated from the following equation:
Water from fuel is the sum of the water in the fuel,
H2O and the water produced from the combustion of
hydrogen in the fuel, H2:
100
MQWFF = ( 8.937 × H2 ) + H2O ×
HHV
MQWG
,%
MQG
MQRF = residue from fuel, lb/10,000 Btu
AF
= mass percent ash in fuel, %
UBC = unburned carbon as mass percent in fuel, %
The mass percent of solids or residue in the flue gas
is then:
MPRG = 100 ×
MQRF + MQSSB
MQG
(39)
where
MPRG
= mass percent solids or residue in flue
gas, %
MQSSB = spent sorbent, lb/10,000 Btu
MQG
= mass of gaseous combustion products
excluding solids, lb/10,000 Btu
Efficiency
Efficiency is the ratio of energy output to energy
input and is usually expressed as a percentage. The
output term for a steam generator is the energy absorbed by the working fluid that is not recovered
within the steam generator envelope. It includes the
energy added to the feedwater and desuperheating
water to produce saturated/superheated steam, reheat
steam, auxiliary steam and blowdown. It does not
include the energy supplied to preheat the entering
air such as air preheater coil steam supplied by the
steam generator. The energy input term is the maximum energy available when the fuel is completely
burned, i.e., the mass flow rate of fuel, MRF, multiplied by the higher heating value of the fuel. This is
conventionally expressed as:
Output
Input fuel
Output
= 100 ×
,%
MRF × HHV
η f = 100 ×
(40)
and is commonly referred to as steam generator fuel
efficiency. In the U.S., it is customary to express steam
generator efficiency on a higher heating value basis.
Steam generator efficiency may also be expressed on
10- 17
The Babcock & Wilcox Company
a lower heating value basis (common in Europe). For
the same mass flow rate of fuel, the LHV efficiency
may be 3 to 10 percentage points higher than the HHV
efficiency, depending upon the amount of H2 and H2O
in the fuel. When comparing steam generator efficiency and/or plant heat rate, they must be on the
same basis, i.e., HHV or LHV.
Efficiency may be determined by measuring the
mass flow rate of fuel and steam generator output,
which is referred to as the input-output method, or by
the energy balance method. The energy balance
method is generally the preferred method. It is usually more accurate than the input-output method and
is discussed below.
According to the law of conservation of energy, for
steady-state conditions, the energy balance on the
steam generator envelope can be expressed as:5
QRF = QRO + QHB , Btu/h
(41)
where QRF is the input from fuel, Btu/h, QRO is the
steam generator output, Btu/h, and QHB is the energy required by heat balance for closure, Btu/h. The
heat balance energy associated with the streams entering the steam generator envelope and the energy
added from auxiliary equipment power are commonly
referred to as heat credits, QRB (Btu/h). The heat balance energy associated with streams leaving the steam
generator and the heat lost to the environment are
commonly referred to as heat losses, QRL (Btu/h). This
steam generator energy balance may be written as:
QRF = QRO + QHB
= QRO + QRL − QRB , Btu/h
(42)
and the efficiency may be expressed as:
η f = 100 ×
QRO
,%
QRO + QRL − QRB
(43)
When losses and credits are expressed as a function of percent input from fuel, QPL and QPB, the
efficiency may be calculated from:
η f = 100 − QPL + QPB , %
(44)
Most losses and credits are conveniently calculated
on a percent input from fuel basis. However, some losses
are more conveniently calculated on a Btu/h basis. The
following expression for efficiency allows the use of
mixed units; some of the losses/credits are calculated
on a percent basis and some on a Btu/h basis.
η f = (100 − QPL + QPB )
QRO
×
, %
QRO + QRL − QRB
(45)
For a more detailed understanding of losses and
credits, refer to the American Society of Mechanical
Engineers (ASME) Performance Test Code, PTC 4, for
steam generators.
The general form for calculating losses (QPLk) us-
10- 18
ing the mass per unit of heat input basis to express
the percent heat loss for individual constituents is:
QPLk =
=
MQk × MCPk × (TOk − TR )
100
MQk × ( HOk − HRk )
100
,%
(46)
where
MQk = mass of constituent k, lb/10,000 Btu
MCPk = mean specific heat between TOk and TR,
Btu/lb F
TOk = outlet temperature, F
TR
= reference temperature, F
HOk = outlet enthalpy, Btu/lb
HRk = reference enthalpy, Btu/lb
For units with gas to air heat exchangers, there is
usually some air leakage from the air inlet to the gas
outlet. This leakage lowers the gas temperature leaving the air heater (measured gas temperature) without performing any useful work. It is recommended
that the calculated gas temperature leaving the air
heater without leakage be used for TOk above, in accordance with PTC 4 (see Chapter 20 for calculation).
For this case, the dry gas weight is based on the excess air entering the air heater. Other codes, including the older PTC 4.1, may use the measured gas temperature leaving the air heater, in which case, the dry
gas weight must be based on the excess air leaving
the air heater.
The reference temperature for PTC 4 is 77F (25C)
and the calculation of both losses and credits are required to determine efficiency. The energy credit will
be negative for any stream entering the steam generator envelope at a temperature lower than the reference temperature. The most significant credit is
generally the energy in the entering air. The entering air temperature (air temperature entering the
boundary) is the air temperature leaving the forced
draft fans or leaving the air pre-heater coils (entering an air to gas heat exchanger) if the source of energy (steam) is external to the steam generator. When
air pre-heater coils are used and the energy is supplied by steam from the steam generator, the entering air temperature is the air temperature entering
the pre-heater coils. The air temperature entering the
fan(s) is usually taken as the design ambient condition, but may be some other specified condition such
as when the fan inlets are supplied by air from within
the building. The fan compression energy (typically
1/2 degree F per 1 in. wg fan pressure rise) may be
considered to establish the fan discharge temperature.
Some test codes, including the older PTC 4.1, may use
some other arbitrary reference temperature or the
entering air temperature as the reference temperature. An advantage of using the entering air temperature as the reference temperature is that it eliminates
the need to calculate credits for entering air and moisture in air.
The general form for calculating credits (QPBk) us-
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
ing the mass per unit of input basis to express the
quantity of individual constituents is:
QPBk =
=
MQk × MCPk × (TI k − TR )
100
MQk × ( HI k − HRk )
100
,%
(47)
where
TIk = inlet temperature, F
HIk = inlet enthalpy, Btu/lb
and other terms were defined in Equation 46.
The terms used to calculate losses and credits that
are a function of fuel input have been discussed previously. The other losses and credits are described below.
Surface radiation and convection loss
This is the heat lost to the atmosphere from the
boiler envelope between the first and the last heat trap
(commonly between the steam generator air inlet and
the boiler exit or air heater exit). Surfaces include the
boiler casing, flues and ducts, piping and other surfaces above ambient temperature as a result of the
energy entering the unit. It is a function of the average velocity and the difference between the average
surface temperature and average ambient temperature. The U.S. industry and PTC 4 standard for calculating this heat loss use a temperature differential
of 50F (for insulated surfaces) and a surface velocity
of 100 ft/min. For PTC 4, the heat loss is based on the
actual flat projected area of the unit and standard
ASME Performance Test Code heat transfer coefficients. For convenience, the American Boiler Manufacturers Association (ABMA) standard radiation loss
chart, shown in Chapter 23, may be used for an approximation. The ABMA curve expresses the radiation
loss on a percent of gross heat input basis as a function of steam generator output (percent gross heat
input may be interpreted as heat input from fuel for
most applications). This curve is the basis for the surface radiation and convection loss prior to the release
of PTC 4 and is approximately the same as PTC 4 for
oil- and gas-fired units. For coal-fired units, due to the
requirement for a larger furnace and convection surface area due to the requirement for lower gas velocities, the PTC 4 radiation loss is typically on the order
of 2 to 2.5 times greater than the ABMA curve.
Unburned carbon loss
For design of a unit, this is normally estimated based
on historical data and/or combustion models. For an efficiency test, this item is calculated from measured unburned carbon in the residue. (See Unburned carbon.)
Other losses and manufacturers’ margins
When testing a unit, it is usually only economically
practical to measure the major losses and credits. The
other minor losses (and credits) are estimated or based
on historical data. Accordingly, when designing a unit,
the individual losses and credits to be tested are itemized separately and the estimated losses (and credits)
Steam 41 / Principles of Combustion
are grouped together and referred to as Other losses
and credits (also referred to as Unaccounted for or
Unmeasured losses). The most typical Other losses are
CO (0.05% loss for 145 ppm or 0.12 lb/106 Btu), NOx
(0.01% for 50 ppm or 0.07 lb/106 Btu), radiation to the
furnace ash pit (0.03% loss for a typical radiation rate
of 10,000 Btu/ft2 h), pulverizer rejects (0.02% loss for
a reject rate of 0.25% of fuel flow at a higher heating
value of 1000 Btu/lb and 170F/77C mill outlet temperature), and unburned hydrocarbons/VOCs (normally negligible and assumed to be zero). In addition,
the manufacturer normally adds a margin, or safety
factor, to the losses to account for unexpected performance deviations and test measurement uncertainty.
Typical design values for these margins are 0 to 0.5%
of heat input for gas, oil and coals with good combustion characteristics and slagging/fouling properties to
0 to 1.5% of heat input or higher for fuels with poor
combustion characteristics and poor slagging/fouling
characteristics. In the evaluation of actual unit efficiency, the minor or Other losses that are not measured
should be estimated and agreed to.
Enthalpy
Enthalpy of air and gas
Enthalpy, H, in Btu/lb is an indication of the relative energy level of a material at a specific temperature and pressure. It is used in thermal efficiency, heat
loss, heat balance and heat transfer calculations (see
Chapter 2). Extensive tabulated and graphical data
are available such as the ASME Steam Tables summarized in Chapter 2. Except for steam and water at
high pressure, the pressure effect on enthalpy is negligible for engineering purposes.
Enthalpies of most gases used in combustion calculations can be curve-fitted by the simple second order equation:
H = aT 2 + bT + c
(48)
where
H = enthalpy in Btu/lb
T = temperature in degrees, F
To determine the enthalpy of most gases used in
combustion calculations at a temperature, T, Equation
48 can be used with the coefficients summarized in
Table 12. Reference 6 is the source for the properties
and the curve fits are in accordance with Reference
7. The curve fits are within plus or minus 0.2 Btu/lb
for enthalpies less than 40 Btu/lb and within plus or
minus 0.5% for larger values. If the enthalpy of a fluid
is known, the temperature in degrees F can be evaluated from the quadratic equation:
T =
−b +
b2 − 4 a ( c − H )
2a
(49)
For mixtures of gases, such as dry air and water
vapor or flue gas and water vapor, Equation 48 coefficient, a, b and c can be determined by a simple mass
10- 19
The Babcock & Wilcox Company
average:
Table 12
nmix =
∑x
i
ni
(50)
where
nmix = equivalent coefficient a, b or c of the mixture
xi
= mass fraction of constituent i
n i = coefficient a, b or c for constituent i
For convenience, Table 12 lists coefficients for a
number of gas mixtures including standard wet air
with 0.013 lb H2O per lb dry air. In addition, Figs. 3
and 4 provide graphical representations of flue gas
and standard air enthalpy.
Another method of evaluating the change in specific
enthalpy of a substance between conditions 1 and 2 is
to consider the specific heat and temperature difference:
H 2 − H1 = c p (T2 − T1 )
(51)
where
H = enthalpy, Btu/lb
cp = specific heat at constant pressure, Btu/lb F
T = temperature, F
Enthalpy of solids and fuels
Enthalpy of coal, limestone and oil can be evaluated from the following relationships:
Coal:8
H = (1 − WF ) ( 0.217 + 0.00248 VM ) + WF (T − 77 ) (52)
Limestone:
H = (1 − WF ) H LS + WF (T − 77 )
(53)
and
(
)
H LS = ( 0.179 T ) + 0.1128 × 10−3 T 2 − 14.45 (54)
Oil:
9
H = C1 + C2 ( API ) + C3T + C4 ( API ) T
+ C5 + C6 ( API ) T 2
(55)
API = (141.5 − 131.5 SPGR ) / SPGR
(56)
and
Fig. 4 Enthalpy of air assuming 0.987 mass fraction dry air plus
0.013 mass fraction of water vapor.
10- 20
Enthalpy Coefficients for Equation 48
Coefficient
Dry air (a)
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
a
b
c
8.299003E-06
1.474577E-05
8.137865E-06
4.164187E-06
0.2383802
0.2332470
0.2526050
0.2726073
−18.43552
−17.48061
−31.64983
−56.82009
Wet air (b)
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
8.577272E-06
1.514376E-05
8.539973E-06
4.420080E-06
0.2409682
0.2357032
0.2551066
0.2758523
−18.63678
−17.64590
−31.89248
−58.00740
Water vapor
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
2.998261E-05
4.575975E-05
3.947132E-05
2.413208E-05
0.4400434
0.4246434
0.4475365
0.5252888
−34.11883
−30.36311
−50.55380
−149.06430
Dry flue gas (c)
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
1.682949E-05
1.725460E-05
8.957486E-06
4.123110E-06
0.2327271
0.2336275
0.2578250
0.2821454
−18.03014
−18.58662
−36.21436
−66.80051
Dry turbine exhaust gas (d)
0 to 500
1.157682E-05
500 to 1500
1.553788E-05
1500 to 2500
8.510000E-06
2500 to 4000
4.168439E-06
0.2369243
0.2343280
0.2550950
0.2768102
−18.35542
−18.04780
−33.38583
−60.53935
Ash/SiO2
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
7.735829E-05
2.408712E-05
1.394202E-05
1.084199E-05
0.1702036
0.2358873
0.2324186
0.2460190
−13.36106
−32.88512
−4.85559
−19.48141
N2a − Atmospheric nitrogen (e)
0 to 500
5.484935E-06
500 to 1500
1.496168E-05
1500 to 2500
8.654128E-06
2500 to 4000
3.953408E-06
0.2450592
0.2362762
0.2552508
0.2789019
−18.93320
−16.91089
−31.18079
−60.92904
O2 − Oxygen
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
1.764672E-05
1.403084E-05
6.424422E-06
4.864890E-06
0.2162331
0.2232213
0.2438557
0.2517422
−16.78533
−19.37546
−33.21262
−43.18179
CO2 − Carbon dioxide
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
5.544506E-05
2.560224E-05
1.045045E-05
4.595554E-06
0.1943114
0.2270060
0.2695022
0.2989397
−15.23170
−24.11829
−53.77107
−90.77172
SO2 − Sulfur dioxide
0 to 500
500 to 1500
1500 to 2500
2500 to 4000
3.420275E-05
1.366242E-05
4.470094E-06
2.012353E-06
0.1439724
0.1672132
0.1923931
0.2047152
−11.25959
−17.74491
−34.83202
−50.27639
CO − Carbon monoxide
0 to 500
5.544506E-05
0.1943114
−15.23170
500 to 1500
2.559673E-05
0.2269866
−24.10722
1500 to 2500
1.044809E-05
0.2695040
−53.79888
2500 to 4000
4.630355E-06
0.2987122
−90.45853
Notes:
(a) Dry air composed of 20.946% O2, 78.105% N2, 0.916% Ar and
0.033% CO2 by volume.
(b) Wet air contains 0.013 lb H2O/lb dry air.
(c) Dry gas composed of 3.5% O2, 15.3% CO2, 0.1% SO2 and 81.1%
N2a by volume.
(d) Dry turbine exhaust gas (TEG) composed of 11.48% O2, 5.27%
CO2 and 83.25% N2a by volume (natural gas with 110% excess
air). See PTC 4.4 for a rigorous determination of TEG enthalpy.
(e) N2a composed of the atomic nitrogen, Ar and CO2 in standard air.
Source: JANAF Thermochemical Tables, 2nd Ed., NSRDS-NBS 37,
1971. Curve fits developed from NASA SP-273, 1971 correlations.
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
where
= enthalpy of coal, limestone or oil at T,
Btu/lb
WF
= mass fraction free moisture in coal or limestone, lb/lb
VM
= volatile matter on a moisture and ash free
basis, %
T
= temperature, F
HLS
= enthalpy of dry limestone, Btu/lb
API
= degrees API
SPGR = specific gravity, dimensionless
= density in lb/ft3 divided by 62.4 at 60F
C1
= −30.016
C2
= −0.11426
C3
= 0.373
C4
= 0.143 × 10-2
C5
= 0.2184 × 10-3
C6
= 7.0 × 10-7
H
Measurement of excess air
One of the most critical operating parameters for
attaining good combustion is excess air. Too little air
can be a source of excessive unburned combustibles
and can be a safety hazard. Too much excess air increases stack gas losses.
Flue gas analysis
The major constituents in flue gas are CO2, O2, N2
and H2O. Excess air is determined by measuring the
O2 and CO2 contents of the flue gas. Before proceeding with measuring techniques, consider the form of
the sample. A flue gas sample may be obtained on a
wet or dry basis. When a sample is extracted from the
gas stream, the water vapor normally condenses and
the sample is considered to be on a dry basis. The
sample is usually drawn through water near ambient temperature to ensure that it is dry. The major constituents of a dry sample do not include the water
vapor in the flue gas. When the gas is measured with
an in situ analyzer or when precautions are taken to
keep the moisture in the sample from condensing, the
sample is on a wet basis.
The amount of O2 in the flue gas is significant in
defining the status of the combustion process. Its presence always means that more oxygen (excess air) is
being introduced than is being used. Assuming complete combustion, low values of O2 reflect moderate
excess air and normal heat losses to the stack, while
higher values of O2 mean needlessly higher stack losses.
The quantity of excess O2 is very significant since
it is a nearly exact indication of excess air. Fig. 5 is a
dry flue gas volumetric combustion chart that is universally used in field testing; it relates O2, CO2 and
N2a (by difference). For complete uniform combustion
of a specific fuel, all points should lie along a straight
line drawn through the pivot point. This line is referred
to as the combustion line. The combustion line should
be determined by calculating the CO2 content at zero
O2 for the test fuel (see Table 15). Lines indicating constant excess air have been superimposed on the volumetric combustion chart. Note that excess air is essentially constant for a given O2 level over a wide range
Steam 41 / Principles of Combustion
of fuels. The O2 is an equally constant indication of
excess air when the gas is sampled on a wet or in situ
basis because the calculated excess air result is insensitive to variations in moisture for specific types/
sources of fuel.
The current industry standard for boiler operation
is continuous monitoring of O2 in the flue gas with in
situ analyzers that measure oxygen on a wet basis.
For testing, the preferred instrument is an electronic
oxygen analyzer. The Orsat unit, which measures
(CO2 + SO2) and O2 on a dry volumetric basis, remains
a trusted standard for verifying the performance of
electronic equipment. The Orsat uses chemicals to
absorb the (CO2 + SO2) and O2, and the amount of each
is determined by the reduction in volume from the
original flue gas sample. When an Orsat is used, the
dry flue gas volumetric combustion chart should be
used to plot the results. Valid results for any test with
a consistent fuel should fall on a single combustion
line (plus or minus 0.2 points of O2 /CO2 is a reasonable tolerance). The Orsat has several disadvantages.
It lacks the accuracy of more refined devices, an experienced operator is required, there are a limited
number of readings available in a test, and the results
do not lend themselves to electronic recording. Electronic CO2 analyzers may be used in addition to oxygen analyzers to relate the O2 /CO2 results to the fuel
line on the volumetric combustion chart. When CO2
is measured, by Orsat or a separate electronic analyzer, it is best to calculate excess air based on the O2
result due to the insensitivity of excess air versus O2
results in the fuel analysis.
Depending upon whether O2 is measured or excess
air known, the corresponding excess air, O2, CO2 and
SO2 can be calculated using procedures provided in
ASME Performance Test Code 4, Steam Generators.5
The calculations are summarized in Table 15 at the
end of this chapter in the Combustion calculations –
examples section.
Flue gas sampling
To ensure a representative average gas sample,
samples from a number of equal area points should
be taken. Reference the U.S. Environmental Protection Agency (EPA) Method 1 standards and ASME
Performance Test Code PTC 19.10. For normal performance testing, equal areas of approximately 9 ft2
(0.8 m2 ) up to 24 points per flue are adequate.
For continuous monitoring, the number of sampling
points is an economic consideration. Strategies for locating permanent monitoring probes should include
point by point testing with different burner combinations. As a guideline, four probes per flue located at
quarter points have been used successfully on large
pulverized coal-fired installations.
Testing heterogeneous fuels
When evaluating the performance of a steam generator firing a heterogeneous fuel such as municipal
solid waste (MSW) (see Chapter 29), it is generally not
possible to obtain a representative fuel sample. Waste
fuel composition may vary widely between samples
and is usually not repeatable.
10- 21
The Babcock & Wilcox Company
Fig. 5 Dry flue gas volumetric combustion chart.
10- 22
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
For boiler design, an ultimate analysis for an average fuel and a range of the most significant components, such as moisture and ash, are used. Therefore,
the design calculations are the same as those for homogeneous fuels.
When firing a heterogeneous fuel, the current industry practice used to evaluate average fuel properties and determine boiler efficiency is to test using the
boiler as a calorimeter (BAC). The BAC method features the same principles for determining efficiency
as those used when the fuel analysis is known. The
significant difference is that the mass/volume flow rate
of flue gas and moisture in the flue gas are measured
directly rather than being calculated based upon the
measured fuel analysis and O2 in the flue gas.
The additional measurements that are required for
the BAC test method versus conventional test methods are flue gas flow, moisture in flue gas, O2 and CO2
in the flue gas, and residue mass flow rates from the
major extraction points.
BAC calculation method
This section describes how to calculate excess air,
dry gas weight and water from fuel (water evaporated). The results are on a mass per unit of time basis and losses and credits, therefore, are calculated as
Btu/h. Refer to the basic efficiency equations for application. (See Equations 42 and 43.)
The wet gas weight and water in the wet gas are
measured. The dry gas weight is then calculated as
the difference of the two.
The composition of flue gas is determined by measuring O2 and CO2. N2a is determined by difference from
100%. The nitrogen in flue gas is considered to be
atmospheric with a molecular weight of 28.158 lb/mole.
Because waste fuel combustors operate at high levels
of excess air and the nitrogen in the fuel is small, this
nitrogen can be ignored.
The moisture in the flue gas may be from vapor or
liquid sources. Vapor sources include moisture in the
air and atomizing steam. Water sources are moisture
in the fuel, moisture formed by combustion of H2,
water from ash quenching systems, and fuel pit water spray. The moisture in air and that from other
vaporous sources must be measured, so the sensible
heat efficiency loss may be differentiated from the
water evaporated loss. The water evaporated is the
total moisture in the flue gas less the vaporous sources.
The water evaporation loss is calculated in the same
manner as the water from fuel loss and is analogous
to the total water from fuel loss if miscellaneous water sources are accounted for.
The total dry air flow at the point of flue gas measurement is calculated from the nitrogen in the flue
gas. Excess air is determined from the measured O2
and theoretical air is calculated by difference from the
total air flow. The percent excess air is calculated from
the excess air and theoretical air weight flow rates.
Combustion calculations – examples
The detailed steps in the solution of combustion
problems are best illustrated by examples. The ex-
Steam 41 / Principles of Combustion
amples in this section are presented through calculation forms which are a convenient method for organizing the calculations in a logical sequence. The input required to complete the forms is located at the top
of the form. An elemental fuel analysis on a mass basis
is used for all of the examples. For gaseous fuels, the
analysis on a volume basis must be converted to an
elemental mass basis as described in Molar evaluation
of combustion. The calculations required are shown
as a combination of item numbers (enclosed in brackets) and constants.
Mole method
The mole method is the fundamental basis for all
combustion calculations. It is the source for the constants used in other more simplified methods. The only
constants the user needs are the molecular weights
of the fuel and air constituents. The reader should
understand the mole method before proceeding with
the Btu method.
Table 7 is an example of the combustion calculations
for a bituminous coal on a molar basis. Items 1
through 6 are the required input. If the unburned
carbon is known (Item 6), the unburned carbon loss
(Item 5) is calculated. Provision is made for entering
the excess air to the burners and excess air leaving
the boiler if the user desires to account for setting infiltration (Item 1). For this example, the excess air to the
burners is assumed to be the same as that leaving the
boiler. An intermediate step in the calculations on a
molar basis is the volumetric flue gas analysis (Items
20 and 21). Air and gas mass flow rates are shown on
a lb/10,000 Btu basis as well as a 1000 lb/h basis.
Btu method
Once the reader understands the principles of the
combustion calculations on a mole basis, the Btu
method is the preferred method for general combustion calculations. The calculations provided in Table
13A are more comprehensive than the simple calculation of air and gas weights shown in Table 7. Provision is made for handling the impact of sorbent on the
combustion calculations, the calculation of efficiency
and finally heat available to the furnace.
The inputs to Table 13A are similar to those used
in Table 7. The same fuel analysis and excess air are
used and the calculated input from fuel is very nearly
the same. These inputs are also the same as those used
in the example performance problem in Chapter 22.
Items 1 through 19 are the inputs and initial calculations required for the combustion calculations. For the
efficiency calculations, Items 44 through 46 must be
provided. If sorbent is used, Table 14, Combustion
Calculations – Sorbent, must be completed first. (See
Items 11 through 14 and 46). Because the entering
air temperature and fuel temperature are the same
as the reference temperature selected (80F), the efficiency credits are zero. The total fuel heat is calculated
from the efficiency, Item 53, and steam generator
output, Item 10. Flue gas and air flow rates are calculated from the fuel input and the results of the combustion gas calculations.
Table 13A shows the calculation results for a typi10- 23
The Babcock & Wilcox Company
cal eastern U.S. coal. A similar set of calculations can
be made for a typical western subbituminous coal
which has an increased moisture content (30% by
weight) and reduced LHV (8360 Btu/lb).
For the same boiler rating and other boundary conditions, the results can be compared on a lb per 10,000
Btu basis:
Eastern
Bit.
Theoretical air
Dry air
Dry gas weight
Wet gas weight
H2O in gas
Efficiency, %
7.572
9.086
9.442
9.864
0.422
86.91
Western No. 6 Natural
Subbit. Oil
Gas
7.542
9.050
9.463
10.303
0.840
82.10
7.437
8.924
8.965
9.583
0.618
85.30
7.220
8.664
8.194
9.236
1.042
80.79
The theoretical air, dry air and resulting dry gas
weight are approximately the same for each coal. The
wet gas weight and H2O in gas are higher for the subbituminous coal due to the higher moisture content.
Referring to the efficiency calculations and losses, the
efficiency is lower for the subbituminous coal essentially due to the higher moisture content, not the lower
heating value. However, if the actual mass flow rates
for subbituminous coal versus an eastern bituminous
coal are compared, it will be found that a higher air
weight is required primarily due to the lower efficiency,
while a higher gas weight is required due to the higher
moisture in the fuel and the lower efficiency.
Table 13B is the same example as shown in Table
13A except that it is assumed that a limestone sorbent
is used in a fluidized bed at a calcium to sulfur molar
ratio of 2.5. A sulfur capture of 90% is expected. A
higher unburned carbon loss is used, typical of this
combustion process. It is necessary to complete the
calculations shown in Table 14 to develop input for this
Table. The net losses due to sorbent, Item 46 in Table
13B, are not overly significant. Therefore, the difference in efficiency from the example in Table 13A is
primarily due to the difference in the assumed unburned carbon loss.
When testing a boiler, the excess air required for
the combustion calculations is determined from measured O2 in the flue gas. Table 15A, Excess Air Calculations from Measured O2, demonstrates the calculation of excess air from O2 on a wet basis. The fuel analysis and unburned carbon are the same as in Tables 7
and 13A. These tables can also be used to determine
the volumetric composition of wet or dry flue gas when
excess air is known (Items 25 through 32). These values can be compared to the flue gas composition calculated on a molar basis, Table 7.
Table 15B is an example of calculating excess air
from O2 when a sorbent is used. All of the sulfur in
the fuel will not be converted to sulfur dioxide. Therefore, the sulfur capture must first be determined from
Table 16, Sulfur Capture Based on Gas Analysis. The
example presented in Tables 13B and 14 is used as
the basis for this example. The flue gas composition
in Tables 13A and 13B can be compared to assess the
impact of adding the sorbent.
When units firing municipal solid waste or refusederived fuels are tested, it is not practical to determine
the ultimate analysis of the fuel. Table 17, Combustion Calculations – Measured Gas Weight, shows the
combustion calculations for determining dry gas
weight, water evaporated and excess air using measured gas weight.
References
1. American Gas Association, Segeler, C.G., Ed., Gas Engineers Handbook, Industrial Press, Inc., New York, New
York, 1965.
2. “Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuel,”
ASTM 3588-98, Annual Book of ASTM Standards, Vol.
05.06, September, 2003.
3. Jones, F.E., “The Air Density Equation and the Transfer of Mass Unit,” Journal of Research of the National
Bureau of Standards, Vol. 83, No. 5, September-October,
1978.
4. Gerhart, P.M., Heil, T.C., and Phillips, J.T., “Steam
Generator Performance Calculation Strategies for ASME
PTC 4,” Technical Paper 91-JPGC-PTC-1, American Society of Mechanical Engineers, New York, New York, October, 1991.
10- 24
5. Entwistle, J., Heil, T.C., and Hoffman, G.E., “Steam
Generation Efficiency Revisited,” Technical Paper 88JPGCLPTC-3, American Society of Mechanical Engineers,
New York, New York, September, 1988.
6. JANAF Thermochemical Tables, Second Ed., Publication NSRDS-NBS 37, United States National Bureau of
Standards (now National Institute of Standards and Technology), Washington, D.C., 1971.
7. Taken from NASA Publication SP-273, Chemical Equilibrium Code, 1971.
8. Elliot, M.A., Ed., Chemistry of Coal Utilization, Second Supplemental Volume, Wiley, New York, New York,
1981.
9. Dunstan, A.E., The Science of Petroleum, Oxford University Press, Oxford, United Kingdom, 1938.
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Bibliography
ASME Steam Properties for Industrial Use, Based on
IAPWS-IF97, Professional Version 1.1, The American
Society of Mechanical Engineers, New York, New York,
2003.
International Boiler & Pressure Vessel Code, “ASME
Performance Test Code PTC4,” The American Society of
Mechanical Engineers, New York, New York, 2004.
Parry, W.T., et al., ASME International Steam Tables for
Industrial Use, Based on IAPWS-IF97, The American
Society of Mechanical Engineers, New York, New York,
January, 2000.
See the following pages for Tables 13 through 17.
Steam 41 / Principles of Combustion
10- 25
The Babcock & Wilcox Company
Table 13A
Combustion Calculations (Efficiency per PTC 4.1)
INPUT CONDITIONS − BY TEST OR SPECIFICATION
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Btu Method
FUEL − Bituminous coal, Virginia: no sorbent
Excess air: at burners; leaving boiler/econ/entering AH, % by wt.
Entering air temperature, F
Reference temperature, F (tRA = 77 for PTC 4)
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, lb/lb dry air
Additional moisture, lb/100 lb fuel
Residue leaving boiler/econ/entering AH, % Total
Output, 1,000,000 Btu/h
Corrections for sorbent (if used)
Sulfur capture, lbm/lbm sulfur
Table 16, Item [24]
CO2 from sorbent, lb/10,000 Btu
Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu
Table 14, Item [20]
Spent sorbent, lb/10,000 Btu
Table 14, Item [24]
15
Ultimate Analysis
16
Theo Air, lb/100 lb fuel 17
20/20
80
80
80
350
390
0.013
0
85
285.5
A
B
C
D
E
F
G
H
C
S
H2
H 2O
N2
O2
Ash
Total
0
0
0
0
18
19
20
21
Higher heating value (HHV), Btu/lb
Unburned carbon loss, % fuel input
Theoretical air, lb/10,000 Btu
Unburned carbon, % of fuel
Constituent
% by weight
80.31
1.54
4.47
2.90
1.38
2.85
6.55
100.00
K1
11.51
4.31
34.29
[15] x K1
924.4
6.6
153.3
−4.32
−12.3
Air
1072.0
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
Moisture in air, %
Unburned carbon, %
Surface radiation and convection
Other, % (include manufacturers margin if applicable)
Sensible heat of residue, % (PTC 4)
Sorbent net losses, % if sorbent used
Summation of losses, %
Credits
Entering dry air, %
Moisture in entering air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
KEY PERFORMANCE PARAMETERS
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000 lb/h
Wet gas weight, 1000 lb/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1000 lb/h
Heat available, 1,000,000 Btu/h
Ha =
66.0 Btu/lb
61 Heat available/lb wet gas, Btu/lb
62 Adiabatic flame temperature, F
55
56
57
58
59
60
10- 26
[35D] x (HFg[6] − HFg[3]) / 100
H1 = (3.958E − 5 x T + 0.4329) x T + 1062.2
H2 = [3] − 32
[29] x ([39] − [40]) / 100
[27D] x (HWv[6] − HWv[3]) / 100
[19] or [21] x 14,500 / [18]
See surface radiation and convection loss
39.96
2.90
H2O
42.86
7.571
0.049
D Leaving Blr/Econ/Entering AH
20.0
9.085
0.118
0.118
0.000
0.000
0.304
0.660
0.000
0.000
0.000
9.863
0.422
0.422
9.441
4.28
0.00
9.441 x (75.3 − 0.7) / 100
1237.1
48.0
0.304 x 1189.1 / 100
0.118 x (142.0 − 1.3) / 100
0.39 x 14,500 / 14,100
9.085 x (0.7 − 0.7) / 100
0.118 x (1.3 − 1.3) / 100
100 x (1.0 − 1.0) / 14,100
Summation [48] through [51]
100 − [48] + [53]
100 x [10] / [54]
1000 x [55] / [18]
[55] x [33] / 10
(1 + [7]) x (1 + [25A] / 100) x [22]
[55] x [58] / 10
[55] x {([18] − 10.30 x [17H]) / [18] − 0.005
x ([44] + [45]) + Ha[5] x [58] / 10,000}
1000 x [60] / [57]
From Fig. 3 at H = [61], % H2O = [36C]
14,100
0.40
7.603
0.39
0.049
[24] x (100 − [9]) x 516 + [9] x HRs[6] / 10,000 HRs[6] = 0 (or Table 14, Item [40])
From Table 14, Items ([30] − [31] + [37])
Summation [38] through [46]
[26D] x (HDA[2] − HDA[3]) / 100
[27D] x (HWv[2] − HWv[3]) / 100
100 x (HF[4] − HF[3]) / [18]
[15] x K2
8.94
1.00
[16H] x 100 / [18]
[19] x [18] / 14,500
COMBUSTION GAS CALCULATIONS, Quantity per 10,000 Btu Fuel Input
22 Theoretical air (corrected), lb/10,000 Btu
[20] − [21] x 1151 / [18] + [11] x [15B] x 216 / [18]
23 Residue from fuel, lb/10,000 Btu
([15G] + [21]) x 100 / [18]
24 Total residue, lb/10,000 Btu
[23] + [14]
A At Burners B Infiltration C Leaving Furnace
25 Excess air, % weight
20.0
0.0
20.0
26 Dry air, lb/10,000 Btu
(1 + [25] / 100) x [22]
9.085
27 H2O from air, lb/10,000 Btu
[26] x [7]
0.118
0.118
28 Additional moisture, lb/10,000 Btu
[8] x 100 / [18]
0.000
0.000
29 H2O from fuel, lb/10,000 Btu
[17H] x 100 / [18]
0.304
30 Wet gas from fuel, lb/10,000 Btu
(100 − [15G] − [21] − [11] x [15B]) x 100 / [18]
0.660
31 CO2 from sorbent, lb/10,000 Btu
[12]
0.000
32 H2O from sorbent, lb/10,000 Btu
[13]
0.000
0.000
33 Total wet gas, lb/10,000 Btu
Summation [26] through [32]
9.863
34 Water in wet gas, lb/10,000 Btu
Summation [27] + [28] + [29] + [32]
0.422
0.422
35 Dry gas, lb/10,000 Btu
[33] − [34]
9.441
36 H2O in gas, % by weight
100 x [34] / [33]
4.28
37 Residue, % by weight (zero if < 0.15 lbm/10KB)
[9] x [24] / [33]
0.00
EFFICIENCY CALCULATIONS, % Input from Fuel
Losses
Dry gas, %
Enthalpy of steam at 1 psia, T = [6]
Water from
fuel, as fired
Enthalpy of water at T = [3]
%
H2O, lb/100 lb fuel
K2
Leaving Furnace
324.1
9.203
302.4
7.04
3.61
0.17
0.40
0.40
1.50
0.00
0.00
13.12
0.00
0.00
0.00
0.00
0.00
86.88
Leaving Blr/Econ/Entering AH
328.6
23.3
324.1
335.2
1034.2
3560
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Table 13B
Combustion Calculations (Efficiency per PTC 4)
INPUT CONDITIONS − BY TEST OR SPECIFICATION
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Btu Method (with Sorbent)
FUEL − Bituminous coal, Virginia: with sorbent
Excess air: at burners; leaving boiler/econ/entering AH, % by wt.
Entering air temperature, F
Reference temperature, F (tRA = 77 for PTC 4)
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, lb/lb dry air
Additional moisture, lb/100 lb fuel
Residue leaving boiler/econ/entering AH, % Total
Output, 1,000,000 Btu/h
Corrections for sorbent (if used)
Sulfur capture, lbm/lbm sulfur
Table 16, Item [24]
CO2 from sorbent, lb/10,000 Btu
Table 14, Item [19]
H2O from sorbent, lb/10,000 Btu
Table 14, Item [20]
Spent sorbent, lb/10,000 Btu
Table 14, Item [24]
15
Ultimate Analysis
16
Theo Air, lb/100 lb fuel 17
18/20
80
77
80
350
390
0.013
0
90
285.5
A
B
C
D
E
F
G
H
C
S
H2
H 2O
N2
O2
Ash
Total
0.9000
0.0362
0.0015
0.0819
18
19
20
21
Higher heating value (HHV), Btu/lb
Unburned carbon loss, % fuel input
Theoretical air, lb/10,000 Btu
Unburned carbon, % of fuel
Constituent
% by weight
80.31
1.54
4.47
2.90
1.38
2.85
6.55
100.00
K1
11.51
4.31
34.29
[15] x K1
924.4
6.6
153.3
−4.32
−12.3
Air
1072.0
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
Moisture in air, %
Unburned carbon, %
Surface radiation and convection
Other, % (include manufacturers margin if applicable)
Sensible heat of residue, % (PTC 4)
Sorbent net losses, % if sorbent used
Summation of losses, %
Credits
Entering dry air, %
Moisture in entering air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
KEY PERFORMANCE PARAMETERS
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000 lb/h
Wet gas weight, 1000 lb/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1000 lb/h
Heat available, 1,000,000 Btu/h
Ha =
66.0 Btu/lb
61 Heat available/lb wet gas, Btu/lb
62 Adiabatic flame temperature, F
55
56
57
58
59
60
Steam 41 / Principles of Combustion
[35D] x (HFg[6] − HFg[3]) / 100
H1 = (3.958E − 5 x T + 0.4329) x T + 1062.2
H2 = [3] − 32
[29] x ([39] − [40]) / 100
[27D] x (HWv[6] − HWv[3]) / 100
[19] or [21] x 14,500 / [18]
See surface radiation and convection loss
39.96
2.90
H2O
42.86
7.426
0.146
D Leaving Blr/Econ/Entering AH
20.0
8.911
0.116
0.116
0.000
0.000
0.304
0.636
0.036
0.002
0.002
9.701
0.422
0.422
9.279
4.35
1.35
9.279 x (75.3 − 0.0) / 100
1237.1
45.0
0.304 x 1192.1 / 100
0.116 x (142.0 − 0.0) / 100
2.43 x 14,500 / 14,100
8.911 x (0.7 − 0.0) / 100
0.116 x (1.3 − 0.0) / 100
100 x (1.0 − 0.0) / 14,100
Summation [49] through [51]
100 − [48] + [53]
100 x [10] / [54]
1000 x [55] / [18]
[55] x [33] / 10
(1 + [7]) x (1 + [25A] / 100) x [22]
[55] x [58] / 10
[55] x {([18] − 10.30 x [17H]) / [18] − 0.005
x ([44] + [45]) + Ha[5] x [58] / 10,000}
1000 x [60] / [57]
From Fig. 3 at H = [61], % H2O = [36C]
14,100
2.50
7.603
2.43
0.064
[24] x (100 − [9]) x 516 + [9] x HRs[6] / 10,000 HRs[6] = 65.1 (or Table 14, Item [40])
From Table 14, Items ([30] − [31] + [37])
Summation [38] through [46]
[26D] x (HDA[2] − HDA[3]) / 100
[27D] x (HWv[2] − HWv[3]) / 100
100 x (HF[4] − HF[3]) / [18]
[15] x K2
8.94
1.00
[16H] x 100 / [18]
[19] x [18] / 14,500
COMBUSTION GAS CALCULATIONS, Quantity per 10,000 Btu Fuel Input
22 Theoretical air (corrected), lb/10,000 Btu
[20] − [21] x 1151 / [18] + [11] x [15B] x 216 / [18]
23 Residue from fuel, lb/10,000 Btu
([15G] + [21]) x 100 / [18]
24 Total residue, lb/10,000 Btu
[23] + [14]
A At Burners B Infiltration C Leaving Furnace
25 Excess air, % weight
18.0
1.0
19.0
26 Dry air, lb/10,000 Btu
(1 + [25] / 100) x [22]
8.837
27 H2O from air, lb/10,000 Btu
[26] x [7]
0.115
0.115
28 Additional moisture, lb/10,000 Btu
[8] x 100 / [18]
0.000
0.000
29 H2O from fuel, lb/10,000 Btu
[17H] x 100 / [18]
0.304
30 Wet gas from fuel, lb/10,000 Btu
(100 − [15G] − [21] − [11] x [15B]) x 100 / [18]
0.636
[12]
0.036
31 CO2 from sorbent, lb/10,000 Btu
32 H2O from sorbent, lb/10,000 Btu
[13]
0.002
0.002
33 Total wet gas, lb/10,000 Btu
Summation [26] through [32]
9.626
34 Water in wet gas, lb/10,000 Btu
Summation [27] + [28] + [29] + [32]
0.421
0.421
35 Dry gas, lb/10,000 Btu
[33] − [34]
9.205
36 H2O in gas, % by weight
100 x [34] / [33]
4.37
37 Residue, % by weight (zero if < 0.15 lbm/10KB)
[9] x [24] / [33]
1.37
EFFICIENCY CALCULATIONS, % Input from Fuel
Losses
Dry gas, %
Enthalpy of steam at psia, T = [6]
Water from
fuel, as fired
Enthalpy of water at T = [3]
%
H2O, lb/100 lb fuel
K2
Leaving Furnace
324.2
8.877
299.0
6.99
3.62
0.16
2.50
0.40
1.50
0.15
−0.03
15.45
0.06
0.00
0.01
0.00
0.07
84.78
Leaving Blr/Econ/Entering AH
336.8
23.9
326.7
342.8
1057.4
3627
10- 27
The Babcock & Wilcox Company
Table 14
INPUTS (see also lightly shaded blocks)
1
2
3
4
5
Combustion Calculations Sorbent
FUEL − Bituminous coal, Virginia
Sulfur in fuel, % by weight
Ash in fuel, % by weight
HHV of fuel, Btu/lb
Unburned carbon loss, % fuel input
Calcium to sulfur molar ratio
1.54
6.55
14,100
2.5
2.5
6
7
8
9
Sulfur capture, lb/lb sulfur
Reference temperature, F
Exit gas temperature (excluding leakage), F
Sorbent temperature, F
0.90
80.0
390.0
80.0
SORBENT PRODUCTS
A
B
C
D
E
F
G
10 Chemical 11
Analysis
% Mass
CaCO3
89.80
MgCO3
5.00
Ca(OH)2
0.00
Mg(OH)2
0.00
1.60
H2O
Inert
3.60
Total Ca, mole/100 lb sorbent
13
Molecular 12
Ca
Weight mole/100 lb sorb Calcination
[10] / [11]
lb/mole
Fraction
100.089
0.897
0.90
84.321
1.00
74.096
0.000
1.00
58.328
1.00
18.015
1.00
17
18
19
20
21
22
23
24
25
26
27
SORBENT/GAS CALCULATIONS, lb/10,000 Btu Except as Noted
Sorbent, lb/lb fuel
[1] x [5] / [12G] / 32.066
Sorbent, lb/10,000 Btu
10,000 x [17] / [3]
CO2 from sorbent, lb/10,000 Btu
[15G] x [18] / 100
H2O from sorbent, lb/10,000 Btu
[16G] x [18] / 100
Additional theoretical air, lb/10,000 Btu
216 x [1] x [6] / [3]
SO2 reduction, lb/10,000 Btu
200 x [1] x [6] / [3]
SO3 formed, lb/10,000 Btu
0.2314 x [21] + [22]
Spent sorbent, lb/10,000 Btu
[18] − [19] − [20] + [23]
Unburned carbon, lb/10,000 Btu
[4] x 100 / 14,500
Residue from fuel, lb/10,000 Btu
[2] x 100 / [3] + [25]
Total residue, lb/10,000 Btu
[24] + [26]
14 Molecular
Weight
lb/mole
44.010
44.010
18.015
18.015
18.015
0.897
Total
Calcination/Dehydration, %
CaCO3, %
MgCO3, %
Ca(OH)2, %
Mg(OH)2, %
Heat gain due to sulfation, %
Total of losses due to chemical reactions, %
[10]x[13]x[14]/[11] [10]x[13]x[14]/[11]
35.529
2.610
0.000
0.000
1.600
38.139
1.600
0.1339
0.0950
0.0362
0.0015
0.0212
0.0197
0.0246
0.0819
0.0172
0.0637
0.1456
LOSSES DUE TO SORBENT, % Input from Fuel
28
H of steam at 1 psi, T = [8]
H1 = (3.958E − 5 x [8] + 0.4329) x [8] + 1062.2
H2O from
29
H of water
H2 = [9] − 32
sorbent, %
30
0.01 x [20] x ([28] − [29])
31 Sensible heat sorbent (dry), %
[18] x (1.0 − [10E] / 100) x (H at T = [9] − H at T = [7]) / 100
H of limestone (dry) = (0.1128E − 3 x T + 0.179) x T − 14.45
32
33
34
35
36
37
16 H2O
15 CO2
lb/100 lb sorb lb/100 lb sorb
[10A] x [13A] x [18] x 766 / 10,000
[10B] x 1.0 x [18] x 652 / 10,000
[10C] x 1.0 x [18] x 636 / 10,000
[10D] x 1.0 x [18] x 625 / 10,000
[6] x [1] x 6733 / [3]
[32] + [33] + [34] + [35] − [36]
1237.1
48.0
0.018
0.000
0.588
0.031
0.000
0.000
0.662
−0.043
Sensible Heat of Residue Loss, %
Temp
[27]
x ( H at T = [38] − H at T = [7]
39 Mass Flow x
Residue, F
Rate, % Total x lb/10,000 Btu x (
Btu/lb
−
Btu/lb
1500
10 x
0.1456
x (
376.3
−
0.5
600
10 x
0.1456
x (
116.2
−
0.5
390
80 x
0.1456
x (
64.3
−
0.5
H Residue = (( −2.843E − 8 x T + 1.09E − 4) x T + 0.16) x T − 12.95
41 Summation losses due to sorbent, %
[30] − [31] + [37] + [40]
38
Location
A Bed drain
B Economizer
C Flyash
10- 28
) / 10,000
) / 10,000
) / 10,000
) / 10,000
) / 10,000
40
Total
=
=
=
=
=
Loss
%
0.055
0.017
0.074
0.146
0.121
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Table 15A
Excess Air Calculations from Measured O2
Bituminous coal, Virginia − O2 on wet basis
INPUTS (see also lightly shaded blocks)
1
2
Moisture in air, lb/lb dry air
Additional moisture, lb/100 lb fuel
3
4
HHV fuel, Btu/lb
Unburned carbon loss, % fuel input
5
Unburned carbon (UBC),
0.013
0.00
6
7
14,100
0.40
8
[3] x [4] / 14,500
SORBENT DATA (if applicable)
CO2 from sorbent, moles/100 lb fuel, Table 16 [17]
0
H2O from sorbent, moles/100 lb fuel, Table 16 [16]
0
Sulfur capture, lb/lb sulfur fuel, Table 16 [24]
0
0.39
COMBUSTION PRODUCTS
9
Ultimate Analysis, % Mass
10
Fuel
AsCarbon
Constituent
Fired
Burned (CB)
A C
80.31
B UBC [5]
C CB [A] − [B]
D
E
F
G
S
H2
H 2O
N2
H O2
I Ash
K Total
Theoretical Air
lb/100 lb Fuel
K1
[9] x K1
11 Dry Products from Fuel 12 Wet Products from Fuel
mole/100lb Fuel
mole/100 lb Fuel
K2
[9] / K2
K3
[9] / K3
80.31
0.39
79.92
1.54
4.47
2.90
1.38
2.85
6.55
11.51
919.9
12.011
6.654
4.31
34.29
6.6
153.3
32.066
0.048
2.016
18.015
28.013
−4.32
100.00
2.217
0.161
0.049
−12.3
1067.5
6.751
13 Dry products of combustion, mole/100 lb fuel
14 Wet products of combustion, mole/100 lb fuel
[11K] − [11D] x [8] + [6]
[12K] + [13] + [7]
15 Theoretical air (corrected), mole/100 lb fuel
([10K] + [8] x [9D] x 2.16) / 28.963
2.378
6.751
9.129
36.857
EXCESS AIR WHEN O2 KNOWN
16 O2, % volume (input)
3.315
17 O2 measurement basis
18 Moisture in air, mole/mole dry air
19
20
21
22
23
24
0 = Dry 1 = Wet
Dry/wet products of combustion, mole/100 lb fuel
Additional moisture, mole/100 lb fuel
Intermediate calculation, step 1
Intermediate calculation, step 2
Intermediate calculation, step 3
Excess air, % by weight
Wet
[1] x 1.608
0.021
[13]
[14]
0.0
[2] / 18.016
[15] x (0.7905 + [18])
[19] + [20] + [21]
20.95 − [16] x (1 + [18])
100 x [16] x [22] / [15] / [23]
9.129
0.000
29.909
39.038
17.565
20.0
1
Dry
0.0
O2, CO2, SO2 WHEN EXCESS AIR KNOWN
25 Excess air, % by weight
26 Dry gas, mole/100 lb fuel
27 Wet gas, mole/100 lb fuel
28
29
30
31
32
O2, % by volume
CO2, % by volume
SO2, % by volume
H2O, % by volume
N2 (fuel), % by volume
33 N2a (air), % by volume
20.0
43.258
46.565
[13] + [15] x (0.7905 + [25] / 100)
[14] + [15] x (0.7905 + [18] + (1 + [18]) x [25] / 100) + [20]
[25] x [15] x 0.2095 / ([26] or [27])
100 x ([11C] + [6]) / ([26] or [27])
100 x (1 − [8]) x [11D] / ([26] or [27])
H2O = 0.0 if dry or 100 x ([27] − [26]) / [27]
100 x [11G] / ([26] or [27])
Dry
[26]
[26]
[26]
NA
[26]
Wet
[27]
[27]
[27]
[27]
[27]
100 − [28] − [29] − [30] − [31] − [32]
34 MW wet flue gas, lbm/mole 0.32 x [28] + 0.4401 x [29] + 0.64064 x [30] + 0.18015 x [31] + 0.28013 x [32] + 0.28158 x [55]
35 Density flue gas, lbm/ft3 at 60F and 29.92 in. Hg 0.0026356 x [34]
Wet basis
Steam 41 / Principles of Combustion
3.32
14.29
0.1031
7.10
0.11
75.08
29.868
0.07872
10- 29
The Babcock & Wilcox Company
Table 15B
Excess Air Calculations from Measured O2
Bituminous coal, Virginia: with sorbent − O2 on wet basis
INPUTS (see also lightly shaded blocks)
1
2
3
4
Moisture in air, lb/lb dry air
Additional moisture, lb/100 lb fuel
HHV fuel, Btu/lb
Unburned carbon loss, % fuel input
5
Unburned carbon (UBC),
0.013
0.00
14,100
2.50
[3] x [4] / 14,500
6
7
8
SORBENT DATA (if applicable)
CO2 from sorbent, moles/100 lb fuel, Table 16 [17]
H2O from sorbent, moles/100 lb fuel, Table 16 [16]
Sulfur capture, lb/lb sulfur fuel, Table 16 [24]
0.116
0.012
0.90
2.43
COMBUSTION PRODUCTS
9
Ultimate Analysis, % Mass
10
Fuel
AsCarbon
Constituent
Fired
Burned (CB)
A C
80.31
80.31
B UBC [5]
C CB
D
E
F
G
H O2
I
Ash
K Total
11 Dry Products from Fuel 12 Wet Products from Fuel
mole/100lb Fuel
mole/100 lb Fuel
K2
[9] / K2
K3
[9] / K3
2.43
[A] − [B]
S
H2
H 2O
N2
Theoretical Air
lb/100 lb Fuel
K1
[9] x K1
77.88
1.54
4.47
11.51
896.4
12.011
6.484
4.31
34.29
6.6
153.3
32.066
0.048
2.90
1.38
28.013
−4.32
2.85
6.55
100.00
2.016
2.217
18.015
0.161
0.049
−12.3
1044.0
6.581
2.378
[11K] − [11D] x [8] + [6]
[12K] + [13] + [7]
([10K] + [8] x [9D] x 2.16) / 28.963
13 Dry products of combustion, mole/100 lb fuel
14 Wet products of combustion, mole/100 lb fuel
15 Theoretical air (corrected), mole/100 lb fuel
6.654
9.044
36.149
EXCESS AIR WHEN O2 KNOWN
16 O2, % volume (input)
3.315
17 O2 measurement basis
18 Moisture in air, mole/mole dry air
19
20
21
22
23
24
0 = Dry 1 = Wet
Dry/wet products of combustion, mole/100 lb fuel
Additional moisture, mole/100 lb fuel
Intermediate calculation, step 1
Intermediate calculation, step 2
Intermediate calculation, step 3
Excess air, % by weight
Wet
[1] x 1.608
0.021
[13]
[14]
0.0
[2] / 18.016
[15] x (0.7905 + [18])
[19] + [20] + [21]
20.95 − [16] x (1 + [18])
100 x [16] x [22] / [15] / [23]
9.044
0.000
29.335
38.379
17.565
20.0
1
Dry
0.0
O2, CO2, SO2 WHEN EXCESS AIR KNOWN
25 Excess air, % by weight
26 Dry gas, mole/100 lb fuel
27 Wet gas, mole/100 lb fuel
28 O2, % by volume
29 CO2, % by volume
30 SO2, % by volume
31 H2O, % by volume
32 N2 (fuel), % by volume
33 N2a (air), % by volume
20.0
42.460
45.761
[13] + [15] x (0.7905 + [25] / 100)
[14] + [15] x (0.7905 + [18] + (1 + [18]) x [25] / 100) + [20]
Dry
Wet
[25] x [15] x 0.2095 / ([26] or [27])
100 x ([11C] + [6]) / ([26] or [27])
[26]
[26]
[27]
[27]
3.31
14.42
100 x (1 − [8]) x [11D] / ([26] or [27])
H2O = 0.0 if dry or 100 x ([27] − [26]) / [27]
100 x [11G] / ([26] or [27])
[26]
NA
[26]
[27]
[27]
[27]
0.0105
7.21
0.11
100 − [28] − [29] − [30] − [31] − [32]
74.94
34 MW wet flue gas, lbm/mole 0.32 x [28] + 0.4401 x [29] + 0.64064 x [30] + 0.18015 x [31] + 0.28013 x [32] + 0.28158 x [55]
35 Density flue gas, lbm/ft3 at 60F and 29.92 in. Hg 0.0026356 x [34]
Wet basis
10- 30
29.843
0.07866
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Table 16
Sulfur Capture Based on Gas Analysis
Bituminous coal, Virginia
INPUTS
SO2, ppm
105
/ 10,000 = %
0.0105
2
Data from Table 15, Excess Air Calculations from Measured O2
3 Moisture in air, lb/lb dry air
[1]
0.013
7
4 Additional moisture, lb/100 lb fuel
[2]
0
8
1
5
6
Sulfur in fuel, % by weight
[9D]
1.54
HHV fuel, Btu/lb fuel
[3]
14,100
Data from Table 14, Combustion Calculations - Sorbent
[15G]
38.139
10 CO2 from sorbent, lb/100 lb sorbent
[16G]
1.600
11 H2O from sorbent, lb/100 lb sorbent
CALCULATIONS, Moles/100 lb Fuel Except As Noted
SO2 / O2 Measurement basis
0 = Dry
O2 Flue gas at location SO2 measured, %
9
Theoretical air, lb/100 lb fuel
Dry products of fuel, mole/100 lb fuel
[10K]
[11K]
1044.0
6.581
Wet products of fuel, mole/100 lb fuel
[12K]
2.378
[17]
0.134
12 Sorbent, lb sorbent/lb fuel
1 = Wet
1
13 Moisture in air, mole/mole dry air
14
15
16
17
18
19
20
21
22
23
24
25
Additional moisture
Products of combustion from fuel
H2O from sorbent
CO2 from sorbent
Intermediate calculation, step 1
Intermediate calculation, step 2
Intermediate calculation, step 3
Intermediate calculation, step 4
Intermediate calculation, step 5
Intermediate calculation, step 6
Sulfur capture, lb/lb sulfur
SO2 released, lb/1,000,000 Btu
3.31
[11] x [12] / 18.015
[10] x [12] / 44.01
(0.7905 + [13]) x [7] / 28.963
Summation [14] through [18]
1.0 − (1.0 + [13]) x [2] / 20.95
(0.7905 + [13]) x 2.387 − 1.0
[1] x [19] x 32.066 / [5] / [20]
[21] x [1] / [20]
(100 − [22]) / (100 + [23])
20,000 x (1.0 − [24]) x [5] / [6]
Dry
0.0
Wet
[3] x 1.608
0.0
[8]
0.0
[4] / 18.015
[8] + [9]
Calculate
0.0209
0.000
8.959
0.012
0.116
29.245
38.332
0.8387
0.9368
9.992
0.0117
0.90
0.22
Table 17
Combustion Calculations
Measured Gas Weight
INPUTS
A Wet Analysis
(not required)
B
9.28
Measured dry or 100 / (100 − [3A]) x [1A]
O2, % volume
8.56
Measured dry or 100 / (100 − [3A]) x [2A]
CO2, % volume
12.00
H2O, % volume
Mass flow wet gas, 1000 lb/h
Moisture in wet gas, lb/lb wet gas
Moisture in air, lb/lb dry air
Additional moisture (sources other than fuel and air), 1000 lb/h
CALCULATIONS
8 Water in wet gas, 1000 lb/h
[4] x [5]
9 Dry gas weight, 1000 lb/h
[4] − [8]
10 N2a in dry gas, % dry volume
100 − [1B] − [2B]
1
2
3
4
5
6
7
Dry
Analysis
10.55
9.73
539.2
0.0754
0.0130
0
40.7
498.5
11 Molecular weight of dry gas, lb/mole
12 Dry gas, 1000 moles/h
13 Dry air weight, 1000 lb/h
0.32 x [1B] + 0.4401 x [2B] + 0.28158 x [10]
[9] / [11]
0.28161 x [10] x [12] / 0.7685
79.72
30.11
16.56
483.8
14
15
16
17
18
[13] x [6]
[8] − [7] − [14]
[1B] x [9] x 0.32 / 0.2314 / [11]
[13] − [16]
100 x [16] / [17]
6.3
34.4
241.5
242.3
99.7
Water in dry air, 1000 lb/h
Water evaporated, 1000 lb/h
Excess air, 1000 lb/h
Theoretical air, 1000 lb/h
Excess air, % by weight
Steam 41 / Principles of Combustion
10- 31
The Babcock & Wilcox Company
450 MW midwest power station firing pulverized subbituminous coal.
10- 32
Steam 41 / Principles of Combustion
The Babcock & Wilcox Company
Chapter 11
Oil and Gas Utilization
Before the industrial revolution, distilled petroleum
products were used primarily as a source of illumination. Today, petroleum finds its primary importance as
an energy source and greatly influences the world’s
economy. The following discusses the use of petroleum
products and natural gas as energy sources for steam
generation.
Fuel oil
Preparation
Petroleum or crude oil is the source of various fuel
oils used for steam generation (Fig. 1, facing page).
Most petroleum is refined to some extent before use
although small amounts are burned without processing. Originally, refining petroleum was simply the
process of separating the lighter compounds, higher
in hydrogen, from the heavier compounds by fractional distillation. This yielded impure forms of kerosene, gasoline, lubricating oils and fuel oils. Through
the development of refining techniques, such as thermal cracking and reforming, catalytic reforming, polymerization, isomerization and hydrogenation, petroleum is now regarded as a raw material source of
hydrogen and carbon elements that can be combined
as required to meet a variety of needs.
In addition to hydrocarbons, crude oil contains compounds of sulfur, oxygen and nitrogen and traces of
vanadium, nickel, arsenic and chlorine. Processes are
used during petroleum refinement to remove impurities, particularly compounds of sulfur. Purification processes for petroleum products include sulfuric acid treatment, sweetening, mercaptan extraction, clay treatment,
hydrogen treatment and the use of molecular sieves.
The refining of crude oil yields a number of products having many different applications. Those used
as fuel include gasoline, distillate fuel, residual fuel
oil, jet fuels, still gas, liquefied gases, kerosene and
petroleum coke. Products for other applications include
lubricants and waxes, asphalt, road oil, and petrochemical feedstock.
Fuel oils for steam generation consist primarily of
residues from the distillation of crude oil. As refinery
methods improve, the quality of residual oil available
Steam 41 / Oil and Gas Utilization
for utility and industrial steam generation is deteriorating. High sulfur fuels containing heavy components create challenges during combustion that range
from high particulate and sulfur oxide emissions to
higher maintenance costs due to the corrosive constituents in the flue gas.
Transportation, storage and handling
The high heating value per unit of volume of oil,
its varied applications, and its liquid form have fostered a worldwide system of distribution. The use of
supertankers for the transportation of crude oil has
significantly reduced transportation costs and has
allowed refineries to be located near centers of consumption rather than adjacent to the oil fields. Large
supertankers, up to 250,000 t (227,000 tm), are capable
of transporting nearly 2,000,000 bbl (318,000 m3) of
crude oil at a time to deepwater ports.
Tanker and barge shipments on coastal and inland
waterways are by far the cheapest method of transporting the various grades of oil. With the depletion
of oil fields in the eastern United States (U.S.), crude
oil trunk lines were developed in the early 1900s to
transport oil from points west of the Mississippi River
to the east coast refineries. Today, more than 170,000
mi (274,000 km) of pipeline, including small feeder lines,
are used for the transportation of oil within the U.S.
Much smaller quantities of oil are shipped overland by
rail and truck because of the higher cost of haulage.
Fuel oil systems require either underground or surface storage tanks. Oil is usually stored in cylindrical
shaped steel tanks to eliminate evaporation loss. Loss
in storage of the relatively nonvolatile heavy fuel oils
is negligible. Lighter products, such as gasoline, may
volatilize sufficiently in warm weather to cause appreciable loss. In this instance, storage tanks with
floating roofs are used to eliminate the air space above
the fuel where vapors can accumulate. The National
Fire Protection Association (NFPA) has prepared a
standard set of codes for the storage and handling of
oils (NFPA 30 and 31). These codes serve as the basis
for many local ordinances and are required for the safe
transportation and handling of fuel products.
Extensive piping and valving and suitable pumping and heating equipment are necessary for the
11-1
The Babcock & Wilcox Company
transportation and handling of fuel oil. Storage tanks,
piping and heaters for heavy oils must be cleaned periodically because of fouling or sludge accumulation.
Fuel properties
Safe and efficient transportation, handling and combustion of fuel oil requires a knowledge of fuel characteristics. Principal physical properties of fuel oils, important to boiler applications, are summarized below (see
Chapter 9 for typical fuel oil physical property values):
Viscosity The viscosity of an oil is the measure of
its resistance to internal movement, or flow. Viscosity
is important because of its effect on the rate at which
oil flows through pipelines and on the degree of atomization obtained by oil firing equipment.
Ultimate analysis An ultimate analysis is used to
determine theoretical air requirements for combustion
of the fuel and also to identify potential environmental emission characteristics.
Heating value The heating value of a liquid fuel is
the energy produced by the complete combustion of
one unit of fuel [Btu/lb (J/kg)]. Heating value can be
reported either as the gross or higher heating value
(HHV) or the net or lower heating value (LHV). To
determine HHV, it is assumed that any water vapor
formed during combustion is condensed and cooled to
the initial temperature (i.e., all of the chemical energy
is available). The heat of vaporization of the water
formed is included in the HHV. For LHV, it is assumed
that the water vapor does not condense and is not
available. The heating value determines the quantity
of fuel necessary to achieve a specified heat input.
Specific gravity Specific gravity (sp gr) is the ratio
of the density of oil to the density of water. It is important because fuel is purchased by volume, in gallons (l) or barrels (m3). The most widely used fuel oil
gravity scale is degree API devised by the American
Petroleum Institute; its use is recommended by the
U.S. Bureau of Standards and the U.S. Bureau of
Mines. The scale is based on the following formula:
degrees API =
141.5
– 131.5
sp gr at 60/60F (16/16C)
[sp gr at 60/60F (16/16C) means when both oil and
water are at 60F (16C)]
Flash and fire point Flash point is the lowest temperature at which a volatile oil will give off explosive
or ignitable vapors. It is important in determining oil
handling and storage requirements. The fire point is
the temperature to which a liquid must be heated to
produce vapors sufficient for continuous burning
when ignited by an external flame.
Pour point The pour point is the temperature at which
a liquid fuel will first flow under standardized conditions.
Distillation Distillation determines the quantity
and number of fractions which make up the liquid fuel.
Water and sediment Water and sediment are a measure of the contaminates in a liquid fuel. The sediment
normally consists of calcium, sodium, magnesium, and
iron compounds. Impurities in the fuel provide an
indication of the potential for plugging of fuel handling and combustion equipment.
11-2
Carbon residue Residue that remains after a liquid
fuel is heated in the absence of air is termed carbon residue. The tests commonly used to determine carbon residue are the Conradson Carbon Test and the Ramsbottom
Carbon Test. Carbon residue gives an indication of the
coking tendency of a particular fuel (i.e. the tendency of
oil, when heated, to form solid compounds).
Asphaltene content Asphaltenes are long chain,
high molecular weight hydrocarbon compounds. The
asphaltene content of a petroleum product is the percentage by weight of wax free material insoluble in
n-heptane but soluble in hot benzene. Their structure
requires high temperatures and high atomization
energy for the fuel to burn completely. Higher
asphaltene content indicates a higher potential to
produce particulate emissions.
Burning profile Burning profile is a plot of the rate
at which a sample of fuel burns under standard conditions as temperature is increased at a fixed rate. The
burning profile is a characteristic fingerprint of the
fuel oxidized under standard conditions and is not intended to provide absolute kinetic and thermodynamic
data. It helps evaluate combustion characteristics of
various fuels on a relative basis to determine excess air
and residence time necessary for complete combustion.
Natural gas
Preparation
Natural gas, found in crude oil reservoirs, either dissolved in the oil or as a gas cap above the oil, is called
associated gas. Natural gas is also found in reservoirs
that contain no oil and is termed non-associated gas.
Natural gas, directly from the well, must be treated
to produce commercially marketable fuels. Initially,
natural gas undergoes a process to remove condensate which is distilled to produce butane, propane and
stabilized gasoline. Propane and butane are widely
used as bottle gas. They are distributed and stored
liquefied under pressure. When the pressure is released, the liquid boils, producing a gaseous fuel.
Natural gas may contain enough sand or gaseous
sulfur compounds to be troublesome. The sand is usually removed at the source. Natural gas containing
excessive amounts of hydrogen sulfide, commonly
known as sour gas, can be treated by a process known
as sweetening. Sweetening removes hydrogen sulfide
as well as carbon dioxide. Additional treatments include the removal of mercaptan by soda fixation and
the extraction of long chain hydrocarbons.
Where natural gas is used to replace or supplement
manufactured gas, it is sometimes reformed to bring its
heating value in line with the manufactured gas. Natural gas may also be mixed directly with manufactured
gas to increase the heating value of the final product.
Transportation, storage and handling
Pipelines are an economical means of transporting
natural gas in its gaseous form. The rapid increase in
consumption of natural gas in areas far from the
source has resulted in an extensive system of long
distance pipelines. Natural gas can also be transported
Steam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
Fuel properties
Natural gas is comprised primarily of methane and
ethane. Physical properties of practical importance to
boiler applications include constituents by volume
percent, heating value, specific gravity, sulfur content
and flammability (see Chapter 9 for typical natural
gas physical property values).
nitrogen, ash, asphaltenes, vanadium and other metals. Thus, careful design and cleanup considerations
are important when firing a fuel with high levels of
these constituents.
Steel mill blast furnaces generate a byproduct gas
containing about 25% carbon monoxide by volume.
This fuel can be burned to produce steam for mill heating and power applications. Many mills also have their
own coke producing plant, another source of byproduct
fuel. Coke oven gas is an excellent fuel that burns
readily because of its high free hydrogen content.
With these gases, available supply pressures and the
volumetric heating value of fuel may be different from
that of natural gas. Therefore, gas components must
be designed to accommodate the particular characteristics of the gas to be burned.
In the petroleum industry, refinery gas and regenerator offgas are frequently used as energy sources
for boilers. Refinery gas is a mixture of gaseous hydrocarbon streams from various refinery processes.
Depending on economic and technical considerations
within the refinery, the compositions of these individual streams vary with process modifications and
thus, the resultant refinery gas can change over time.
Combustion equipment and controls for refinery gas
must be suitably designed for this variability. Regenerator offgas, or CO (carbon monoxide) gas, is a hightemperature gas produced in catalytic cracking units.
CO boilers have been developed to reclaim the thermal energy present in this gas (see Chapter 27).
Landfill gas is a combustible gas recovered by a gas
collection system at a landfill. Its primary constituents
are methane and carbon dioxide. Landfill gas processing systems filter suspended particulates and condensate from the gas stream. Additional processing may
be done to further purify the gas, but trace contaminants that typically remain in the gas require special
attention when designing fuel handling systems to
minimize corrosion concerns.
Other liquid and gaseous fuels
Oil and gas combustion – system design
by tanker when liquefied under pressure producing
liquefied natural gas (LNG).
The distribution of natural gas is subject to some
practical limitations because of the energy required
for transportation. High pressures, in the order of 1000
psig (6895 kPa), are necessary for economic pipeline
transportation over long distances. Compression stations are needed at specified intervals to boost the
pressure due to losses in the line.
In general, it is not practical to vary the supply of
natural gas to accommodate the hourly or daily fluctuations in consumer demand. For economic reasons,
long distance pipelines operate with a high load factor. The rate of withdrawal from the wells may often
be limited for conservation reasons, and the cost of the
pipeline to provide the peak rate would be prohibitive.
Therefore, to meet fluctuations in demand, it is usually necessary to provide local storage or to supplement
the supply with manufactured gas for brief periods.
Above ground methods of storage include: 1) large
water seal tanks, 2) in-pipe holders laid parallel to
commercial gas lines, and 3) using the trunk transmission line as a reservoir by building up the line
pressure. In consumer areas where depleted or partially depleted gas and oil wells are available, underground storage of gas pumped back into these wells
provides, at minimum cost, the large storage volume
required to meet seasonal variations in demand. In
liquid form, natural gas can be stored in insulated steel
tanks or absorbed in a granular substance, released
by passing warm gas over the grains.
Numerous combustion system applications utilize
liquid or gaseous fuels other than conventional fuel
oils or natural gas. These fuels include Orimulsion®,
blast furnace gas, coke oven gas, refinery gas, regenerator offgas, landfill gas, and other byproduct gases.
The large heavy hydrocarbon and bitumen reserves
available in Venezuela have led to a bitumen oil emulsion fuel that has gained acceptability. Orimulsion is
the trade name for a commercially established fossil
fuel oil emulsion. It consists of natural bitumen dispersed in water, in approximately a 70/30 proportion
split. The resulting emulsion is stabilized by a surfactant package. Orimulsion can be transported over land
or water and stored for extended periods while maintaining a consistent quality. Although it can be
handled using most of the equipment and systems
originally designed for heavy fuel oil, Orimulsion requires some special handling and combustion considerations because of its emulsified state. In addition,
although the fuel exhibits very good combustion characteristics, it contains relatively high levels of sulfur,
Steam 41 / Oil and Gas Utilization
The burner is the principal equipment component
for the combustion of oil and natural gas (Fig. 2). In
utility and industrial steam generating units (both
wall and corner-fired designs), the burner admits fuel
and air to the furnace in a manner that ensures safe
and efficient combustion while realizing the full capability of the boiler. Burner design determines mixing
characteristics of the fuel and air, fuel particle size and
distribution, and size and shape of the flame envelope.
The means of transporting, measuring and regulating fuel and air to the furnace, together with the
burners, igniters and flame safety equipment, comprises the overall combustion system. The following
factors must be considered when designing the combustion system and when establishing overall performance requirements:
1. the rate of feed of the fuel and air to comply with
load demand on the boiler over a predetermined
operating range,
2. the types of fuel to be fired including elemental constituents and characteristic properties of each fuel,
11-3
The Babcock & Wilcox Company
Performance requirements
Fig. 2 Typical oil and gas utility boiler burner front.
3. the efficiency of the combustion process to minimize unburned combustibles and excess air requirements,
4. imposed limitations on emissions,
5. physical size and complexity of the furnace and
burners to establish the most efficient and economic design,
6. hardware design and material properties of the
combustion equipment to ensure reliable uninterrupted service for long firing periods, and
7. safety standards and procedures for control of the
burners and boiler, including starting, stopping,
load changes and variations in fuel.
The combustion system must be designed for optimum flexibility of operation, including the potential
for variations in fuel type, fuel firing rate and combinations of burners in and out of service. Control must
be simple and direct to ensure rapid response to varying load demands.
Combustion air is typically conveyed to the burners by forced draft fans. To improve both thermal and
combustion efficiency and further ensure burner stability, combustion air is normally preheated to a temperature of 400 to 600F (204 to 316C) by air preheaters
located downstream of the fans. The fans must be
capable of delivering adequate quantities of air for
complete combustion at a pressure sufficient to overcome losses across the air preheaters, burners, control
dampers, and intervening duct work. The total combustion air is that required to theoretically burn all
the fuel plus excess air necessary for complete combustion. (See Chapter 10.)
The fuel delivery system must be able to regulate
fuel pressure and flow to the burners and must be
safeguarded in accordance with applicable fire protection codes. Proper distribution of fuel to the burners,
in multiple burner applications, is critical to safe and
efficient operation of the combustion system. Piping
and valves must be designed for allowable velocity limits, absolute pressure requirements, and pressure losses.
11-4
Excess air
Excess air is the air supplied for combustion and
cooling of idle burners in excess of that theoretically
required for complete oxidation of the fuel. Excess air
is generally required to compensate for imperfections
in the air delivery system that results in maldistribution of combustion air to the burners. Excess air also
helps compensate for imperfect mixing of the air and
fuel in the furnace. At full load, with all burners in
service, excess air required for gas and oil firing, expressed as a percent of theoretical air, is typically in
the range of 5 to 10%, depending upon fuel type and
the requirements of the combustion system. Operation
at excess air levels below these values is possible if
combustion efficiency does not deteriorate. Combustion efficiency is measured in terms of carbon monoxide, unburned combustibles in the ash, soot, particulate matter and stack opacity. Through careful design
of the burners and the air delivery system, excess air
can be held to a minimum, thereby minimizing sensible heat loss to the stack.
Operation at partial load requires additional excess
air. When operating with all burners in service at reduced load, lower air velocity at the burners results
in reduced mixing efficiency of the fuel and air. Increasing the excess air improves combustion turbulence and maintains overall combustion efficiency.
Additional excess air and improved burner mixing also
compensate for lower furnace temperature during
partial load operation. In some instances, boiler performance dictates the use of higher than normal excess air at reduced loads to maintain steam temperature or to minimize cold end corrosion.
Additional excess air is also necessary when operating with burners out of service. Sufficient cooling
air must be provided to idle burners to prevent overheat damage. Permanent thermocouples installed on
selected burners measure metal temperatures and
establish the minimum excess air necessary to maintain burner temperatures below the maximum use
limits of the steel. Excess air for burner cooling varies
with the percentage of burners out of service.
Stability and turndown
Proper burner and combustion system design will
permit stable operation of the burners over a wide
operating range. A stable burner, best determined
through visual observation, is one where the flame
front remains relatively stationary and the root of the
flame is securely anchored near the burner fuel element. To ensure stable combustion, the burner must
be designed to prevent blowoff or flashback of the
flame for varying rates of fuel and air flow.
It is often desirable to operate over a wide boiler
load range without taking burners out of service. This
reduces partial load excess air requirements to cool
idle burners. The burners must therefore be capable
of operating in a turned down condition. Burner turndown is defined as the ratio of full load fuel input to
partial load input while still maintaining stable combustion. Limitations in burner turndown are generSteam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
ally dictated by fuel characteristics, fuel and air velocity, full load to partial load fuel pressures, and adequacy of the flame safety system. Automated and
reliable flame safety supervision, with proper safeguards, must be available to achieve high burner
turndown ratios.
With gas firing, a turndown ratio of 10:1 is not uncommon. Natural gas is easily burned and relatively
easy to control. Residual oil, on the other hand, is more
difficult to burn. Combustion characteristics are highly
sensitive to particle size distribution, excess air and
burner turbulence. A typical turndown ratio for oil is
in the order of 6:1, depending upon fuel characteristics, flexibility of the delivery system and atomization
technique.
Burner pulsation
Burner pulsation is a phenomenon frequently associated with natural gas firing and, to a lesser degree, with oil firing. Pulsation is thought to occur
when fuel rich pockets of gas suddenly and repeatedly ignite within the flame envelope. The resultant
pulsating burner flame is often accompanied by a noise
referred to as combustion rumble. Combustion rumble
may transmit frequencies that coincide with the natural frequency of the furnace enclosure resulting in apparent boiler vibration. In some instances, these vibrations may become alarmingly violent.
Boiler vibration on large furnaces can sometimes
be attributed to a single burner. Minor air flow adjustment to a given burner, or removing select burners
from service, may suddenly start or stop pulsations.
Pulsation problems can be corrected through changes
to burner hardware that affect mixing patterns of the
fuel and air. Changes to the burner throat profile to
correct anomalies in burner aerodynamics or changes
to the fuel element discharge ports have successfully
eliminated pulsation.
Historical operating data has enabled the development of empirical curves that are useful in designing
burners to avoid pulsation. These curves relate the
potential for burner pulsation to the ratio of burner
fuel to air velocity. Together with careful consideration
of furnace geometry, burner firing patterns and
burner aerodynamics, problems with burner pulsation
are becoming less common.
Combustion efficiency
Many factors influence combustion efficiency including excess air, burner mixing, fuel properties,
furnace thermal environment, residence time, and
particle size and distribution. Complete combustion
occurs when all combustible elements and compounds
of the fuel are entirely oxidized. In utility and industrial boilers, the goal is to achieve the highest degree
of combustion efficiency with the lowest possible excess air. Thermal efficiency decreases with increasing
quantities of excess air. Combustion performance is
then measured in terms of the boiler efficiency loss due
to incomplete combustion together with the efficiency
loss due to sensible heat in the stack gases.
From the standpoint of optimum combustion efficiency, the following factors are critical to proper design:
Steam 41 / Oil and Gas Utilization
1. careful distribution and control of fuel and air to
the burners,
2. burner and fuel element design that provides thorough mixing of fuel and air and promotes rapid,
turbulent combustion, and
3. proper burner arrangement and furnace geometry
to provide sufficient residence time to complete
chemical reactions in a thermal environment conducive to stable and self-sustained combustion.
In most cases, boiler efficiency loss due to unburned
carbon loss (UCL) when firing oil and natural gas is
virtually negligible. However, depending on fuel oil
properties and the condition of the combustion system,
the percent UCL can be in the order of 0.10% while
firing oil. Combustion efficiency with these fuels is
usually measured in terms of carbon monoxide (CO)
emissions, particulate emissions and stack opacity.
Generally, CO levels less than 200 ppm (corrected to
3% O2) are considered satisfactory.
Emission control techniques
Ever increasing concern over atmospheric pollutants is changing the focus of wall and corner-fired
boiler and combustion system designs. The combustion of fossil fuels produces emissions that have been
attributed to the formation of acid rain, smog, changes
to the ozone layer, and the so-called greenhouse effect.
To mitigate these problems, federal and local regulations are currently in place that limit oxides of nitrogen, oxides of sulfur, particulate matter and stack
opacity. While emission limits vary depending upon
state and local regulations, the trend is toward more
stringent control. (See also Chapter 32.)
Many combustion control techniques have emerged
to reduce fossil fuel emissions. These techniques generally focus on the reduction of nitrogen oxides (NOx),
as changes to the combustion process can greatly influence NOx formation and destruction.
Oxides of nitrogen
Nitrogen oxides in the form of NO and NO2 are
formed during combustion by two primary mechanisms: thermal NOx and fuel NOx. A secondary mechanism called prompt NOx can also contribute to overall
NOx formation.
Thermal NOx results from the dissociation and oxidation of nitrogen in the combustion air. The rate and
degree of thermal NOx formation is dependent upon
oxygen availability during the combustion process and
is exponentially dependent upon combustion temperature. Thermal NOx reactions occur rapidly at combustion temperatures in excess of 2800F (1538C). Thermal NOx is the primary source of NOx formation from
natural gas and distillate oils because these fuels are
generally low in or devoid of fuel-bound nitrogen.
Fuel NOx, on the other hand, results from oxidation
of nitrogen organically bound in the fuel and is the
primary source of NOx formation from heavy fuel oil.
Fuel bound nitrogen in the form of volatile compounds
is intimately tied to the fuel hydrocarbon chains. For
this reason, the formation of fuel NOx is linked to both
11-5
The Babcock & Wilcox Company
fuel nitrogen content and fuel volatility. Inhibiting
oxygen availability during the early stages of combustion, where the fuel devolatilizes, is the most effective
means of controlling fuel NOx formation.
Prompt NOx is formed during the early, low temperature stages of combustion. Hydrocarbon fragments may react with atmospheric nitrogen under
fuel-rich conditions to yield fixed nitrogen species.
These, in turn, can be oxidized to NO in the lean zone
of the flame. In most flames, especially those from nitrogen-containing fuels, the prompt mechanism is responsible for only a small fraction of the total NOx.
Numerous combustion process NOx control techniques are commonly used. These vary in effectiveness and cost. In all cases, control methods are mainly
aimed at reducing either thermal NOx, fuel NOx, or a
combination of both. A range of typical anticipated NOx
emission levels relative to various NOx control mechanisms is shown in Fig. 3.
Low excess air Low excess air (LEA) effectively reduces NOx emissions with little, if any, capital expenditure. LEA is a desirable method of increasing thermal efficiency and has the added benefit of inhibiting thermal NOx. If burner stability and combustion
efficiency are maintained at acceptable levels, lowering the excess air may reduce NOx by as much as 5 to
15% from an uncontrolled baseline. The success of this
method depends largely upon fuel properties and the
ability to carefully control fuel and air distribution to
the burners. Operation may require more sophisticated methods of measuring and regulating fuel and
air flow to the burners and modifications to the air
delivery system to ensure equal distribution of combustion air to all burners.
Burners out of service Essentially a simple form of
two-stage combustion, burners out of service (BOOS)
is a simple and direct method of reducing NOx emissions. When removing burners from service in multiple burner applications, active burner inputs are
typically increased to maintain load. Without changing total air flow, increased fuel input to the active
burners results in a fuel rich mixture, effectively limiting oxygen availability and thereby limiting both
fuel and thermal NOx formation. Air control registers
on the out of service burners remain open, essentially
serving as staging ports.
While a fairly significant NOx reduction is possible
with this method, lower NOx is frequently accompa-
Relative NO Emissions, %
100
Gas Firing
Oil Firing
80
60
40
20
0
Uncontrolled
LEA
BOOS
TSC
FGR + TSC
Fig. 3 Approximate NOx emission reductions for oil and gas burners
using various control techniques. (LEA = low excess air; BOOS =
burner out of service; TSC = two-stage combustion; FGR = flue gas
recirculation.)
11-6
nied by higher levels of CO in the flue gas and boiler
back-end oxygen (O2) imbalances. With oil firing, an
increase in particulate emissions and increased stack
opacity are likely. Through trial and error, some patterns of burners out of service may prove more successful than others. A limiting factor is the ability of
existing burners to handle the increased input necessary
to maintain full load operation. Short of derating the
unit, changes to fuel element sizes may be required.
Two-stage combustion Two-stage combustion is a
relatively long standing and accepted method of
achieving significant NOx reduction. Combustion air
is directed to the burner zone in quantities less than
that required to theoretically burn the fuel, with the
remainder of the air introduced through overfire air
ports. By diverting combustion air away from the
burners, oxygen concentration in the lower furnace
is reduced, thereby limiting the oxidation of chemically bound nitrogen in the fuel. By introducing the
total combustion air over a larger portion of the furnace, peak flame temperatures are also lowered.
Appropriate design of a two-stage combustion system can reduce NOx emissions by as much as 50% and
simultaneously maintain acceptable combustion performance. The following factors must be considered in
the overall design of the system.
1. Burner zone stoichiometry The fraction of theoretical air directed to the burners is predetermined
to allow proper sizing of the burners and overfire
air ports. Normally a burner zone stoichiometry
in the range of 0.85 to 0.90 will result in desired
levels of NOx reduction without notable adverse
effects on combustion stability and turndown.
2. Overfire air port design Overfire air ports must
be designed for thorough mixing of air and combustion gases in the second stage of combustion.
Ports must have the flexibility to regulate flow and
air penetration to promote mixing both near the
furnace walls and toward the center of the furnace.
Mixing efficiency must be maintained over the anticipated boiler load range and the range in burner
zone stoichiometries.
3. Burner design Burners must be able to operate
at lower air flow rates and velocities without detriment to combustion stability. In a two-stage
combustion system, burner zone stoichiometry is
typically increased with decreasing load to ensure
that burner air velocities are maintained above minimum limits. This further ensures positive windboxto-furnace differential pressures at reduced loads.
4. Overfire air port location Sufficient residence time
from the burner zone to the overfire air ports and
from the ports to the furnace exit is critical to proper
system design. Overfire air ports must be located to
optimize NOx reduction and combustion efficiency
and to limit change to furnace exit gas temperatures.
5. Furnace geometry Furnace geometry influences
burner arrangement and flame patterns, residence
time and thermal environment during the first and
second stages of combustion. Liberal furnace sizing is generally favorable for lower NOx as combustion temperatures are lower and residence
times are increased.
Steam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
6. Air flow control Ideally, overfire air ports are
housed in a dedicated windbox compartment. In
this manner, air to the NOx ports can be metered
and controlled separately from air to the burners.
This permits operation at desired stoichiometric
levels in the lower furnace and allows for compensation to the flow split as a result of air flow adjustments to individual burners or NOx ports.
Additional flexibility in controlling burner fuel and
air flow characteristics is required to optimize combustion under a two-stage system. Improved burner designs have addressed these needs.
In the reducing gas of the lower furnace, sulfur in
the fuel forms hydrogen sulfide (H2S) rather than
sulfur dioxide (SO2) and sulfur trioxide (SO3). The
corrosiveness of reducing gas and the potential for
increased corrosion of lower furnace wall tubes is
highly dependent upon H2S concentration. Two-stage
combustion is therefore not normally recommended
when firing high sulfur residual fuel oils except when
extra furnace wall protection measures are included.
Flue gas recirculation Flue gas recirculation (FGR)
to the burners is instrumental in reducing NOx emissions when the contribution of fuel nitrogen to total
NOx formation is small. For this reason, the use of gas
recirculation is generally limited to the combustion of
natural gas and fuel oils. By introducing flue gas from
the economizer outlet into the combustion air stream,
burner peak flame temperatures are lowered and NOx
emissions are significantly reduced. (See Fig. 4.)
Air foils are commonly used to mix recirculated flue
gas with the combustion air. Flue gas is introduced in
the sides of the secondary air measuring foils and exits
through slots downstream of the air measurement
taps. This method ensures thorough mixing of flue gas
and combustion air before reaching the burners and does
not affect the air flow metering capability of the foils.
In general, increasing the rate of flue gas recirculation to the burners results in an increasingly significant NOx reduction. Target NOx emission levels and
limitations on equipment size and boiler components
dictate the practical limit of recirculated flue gas for
NOx control. Other limiting factors include burner stability and oxygen concentration of the combustion air.
Typically, oxygen content must be maintained at or
above 17% on a dry basis for safe and reliable operation of the combustion equipment.
The expense of a flue gas recirculation system can
be significant. Gas recirculation (GR) fans may be
required for the desired flow quantities at static pressures capable of overcoming losses through the flues,
ducts, mixing devices and the burners themselves.
Additional controls and instruments are also necessary
to regulate GR flow to the windbox at desired levels
over the load range. In retrofit applications, significant cost is associated with routing of flues and ducts
to permit mixing of the flue gas with combustion air.
Also, the accompanying increase in furnace gas
weight at full load operation may require modifications
to convection pass surfaces or dictate changes to standard operating procedures.
From an operational standpoint, the introduction
of flue gas recirculation as a retrofit NOx control techSteam 41 / Oil and Gas Utilization
Fig. 4 Flue gas recirculation low NOx system for oil and gas firing.
nique must, in virtually all cases, be accompanied by
the installation of overfire air ports. Oil and gas burners, initially designed without future consideration to
FGR, are not properly sized to accommodate the increase in burner mass flow as a result of recirculated
flue gas. The quantity of flue gas necessary to significantly reduce NOx emissions will, in all likelihood, result in burner throat velocities that exceed standard
design practices. This, in turn, may cause burner instability, prohibitive burner differentials and in the
case of gas firing, undesirable pulsation. Therefore,
the installation of overfire air ports in conjunction with
FGR serves two useful purposes, 1) lower NOx emissions through two-stage combustion, and 2) a decrease
in mass flow of air to the burners to accommodate the
increased burden of recirculated flue gas.
When employing flue gas recirculation in combination with overfire air, it is desirable to house the
overfire air ports in a dedicated windbox compartment
separate from the burners. In this manner, it is possible to introduce recirculated flue gas to the burners
only. This permits more efficient use of the GR fans
and overall system design as only that portion of flue
gas introduced through the burners is considered effective in controlling NOx emissions.
An inexpensive means of recirculating lesser
amounts of flue gas is induced FGR, or IFGR. Here,
flue gas is introduced through the forced draft fan(s)
and is restricted by the fans’ capacity for flue gas. The
effectiveness of IFGR is, as a result, limited.
Reburning Reburning is an in-furnace NOx control
technique that divides the furnace into three distinct
zones (main, reburn, and burnout). By effectively staging both fuel and combustion air, NOx emission reductions of 50 to 75% from baseline levels can be achieved.
Heat input is spread over a larger portion of the furnace,
with combustion air carefully regulated to the various
zones to achieve optimum NOx reduction (Fig. 5).
In reburning, the lower furnace or main burner
zone provides the major portion of the total heat in11-7
The Babcock & Wilcox Company
put to the furnace. Depending on the percent NOx
reduction and the specific combustion system requirements, the main zone burners can be designed to operate at less than theoretical air to normal excess air
levels. Combustion gases from the main burner zone
then pass through a second combustion zone termed
the reburning zone. Here, burners provide the remaining heat input to the furnace to achieve full load operation but at a significantly lower stoichiometry. By
injecting reburn fuel above the main burner zone, a
NOx reducing region is produced in the furnace where
hydrocarbon radicals from the partially oxidized
reburn fuel strip oxygen from the NO molecules, forming nitrogen compounds and eventually molecular
nitrogen (N2). Overfire air ports are installed above the
reburning zone where the remainder of air is introduced
to complete combustion in an environment both chemically and thermally non-conducive to NOx formation.
Application of this technology must consider a number of variables. System parameters requiring definition include: fuel split between the main combustion
zone and the reburn zone, stoichiometry to the main
and reburn burners, overall stoichiometry in the
reburn and burnout zones of the furnace, residence
time in the reburn zone, and residence time required
above the overfire air ports to complete combustion.
An optimum range of values has been defined for each
of these parameters through laboratory tests and field
application and is largely dependent upon the type of
fuel being fired. For example, fuels with high sulfur
contents (Orimulsion or some heavy fuel oils) are not
as suitable in applications where operating the main
combustion zone under low sub-stoichiometric conditions is required to reduce NOx levels due to corrosion
concerns. For these fuels, reburning technology can
be effectively used by operating the main zone at
higher stoichiometries, thus minimizing corrosion concerns while still achieving good NOx reduction results.
Although implementation of the reburning technol-
Balance of
Combustion
Air
10-30%
Heat Input
(Flue Gas
RecirculationOptional)
70-90%
Heat Input
Overfire
Air Ports
Reburn
Burners
Low NO
Main
Burners
Burnout
Zone
1.06-1.15
Burnout Zone
Stoichiometry
Reburn
Zone
0.80-0.95
Reburn Zone
Stoichiometry
Main
Combustion
Zone
0.90-1.10 Main
Combustion Zone
Stoichiometry
Fig. 5 Boiler side view showing reburn principle and combustion
zones for a utility boiler.
11-8
ogy adds complexity to operation and maintenance of
the overall combustion system, it also provides considerable emission performance optimization flexibility.
In addition, higher initial costs for a reburn system
as compared to other combustion techniques need to
be factored into the evaluation process. From an economic standpoint, the potential benefits and technical merit of the reburning process must be commensurate with long term goals for NOx abatement.
Oxides of sulfur
The sulfur content of fuel oils can range anywhere
from a fraction of a percent for lighter oils to 3.5% for
some residual oils. During the combustion process,
sulfur contained in the fuel is converted to either sulfur dioxide, SO2, or sulfur trioxide, SO3 (SOx emissions). The control of SOx emissions is a key environmental concern and sulfur compounds in the flue gas
can also cause corrosion problems in the boiler and
downstream equipment.
SO3 will form sulfuric acid when cooled in the presence of water vapor. In addition to corrosion problems,
it can produce emissions of acid smut and visible
plume opacity from the stack. Emissions of SO3 are best
controlled during combustion through low excess air
operation and can also be reduced by use of magnesium based fuel additives.
Techniques to control sulfur oxides during the combustion process have been investigated in laboratory
and pilot scale tests with varying degrees of success. At
present, however, the most effective and commercially
accepted method, short of firing low sulfur fuels, is to
install flue gas cleanup equipment. (See Chapter 35.)
Particulate matter
Particulate matter in the form of soot or coke is a
byproduct of the combustion process resulting from
carryover of inert mineral matter in the fuel and from
incomplete combustion. Primarily a concern on oilfired units, particulate matter becomes apparent when
fuel oil droplets undergo a form of fractional distillation during combustion, leaving relatively large carbonaceous particles known as cenospheres.
Cenospheres are porous, hollow particles of carbon
that are virtually unaffected by further combustion
in a conventional furnace environment. Cenospheres
can also absorb sulfur oxides in the gaseous phase and
thereby further contribute to the formation of ash
particles contaminated with acid.
Particulate matter from the combustion of fuel oil
is, in large part, a function of the fuel properties. Ash
content of the fuel oil plays a significant role in forming submicron particulate emissions. These ultrafine
particulate emissions are potentially more dangerous
to the environment than larger particles as they tend
to stay suspended in the atmosphere. The fuel oil
property most closely linked to forming cenospheres
during the combustion process is asphaltene concentration. Asphaltenes are high molecular weight hydrocarbons that do not vaporize when heated. The combustion of fuel oils high in asphaltene content produces a greater quantity of large and intermediate
size particulate emissions. Carbon residue, commonly
Steam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
determined by the Conradson Carbon Test, is also a
means of evaluating the tendency to form particulate
matter during combustion.
Control of particulate emissions is best achieved
through proper atomization of the fuel oil and careful design of the burners and combustion control system to ensure thorough and complete mixing of fuel
and air. Liberal residence time in a high temperature
environment is favorable for complete combustion of
fuel and low particulate emissions, although not conducive to low NOx emissions. Oil emulsification also has
a favorable impact on reducing particulate emissions.
Oil emulsified with water further breaks up individual
oil droplets when the water vaporizes during combustion. In addition, many fuel additives are now available to promote carbon burnout. These additives are
primarily transition metals such as iron, manganese,
cobalt and nickel that act as catalysts for the further
oxidation of carbon particles.
Opacity
A visible plume emanating from the stack is undesirable from both a regulatory and public relations
standpoint. Stack opacity is controlled in much the
same manner as particulate emissions. Careful selection of fuels and complete combustion are keys to minimizing plume visibility.
Dark plumes are generally the result of incomplete
combustion and can be controlled by careful attention
to the combustion process and through transition
metal-based additives. White plumes are frequently
the result of sulfuric acid in the flue gas and can be
controlled by low excess air operation or alkaline-based
fuel additives that neutralize the acid.
The simultaneous control of all criteria pollutants
poses a significant challenge to the burner and boiler
designer. Techniques, or operating conditions, effective
in reducing one form of atmospheric contaminant are
frequently detrimental to controlling others or to unit
performance. For this reason, hardware design and combustion controls are becoming increasingly complex.
Modern boilers must have the added flexibility necessary to optimize thermal efficiency and combustion performance in conjunction with sound environmental practices.
applications. The tangentially disposed doors of the circular burner air register provide the turbulence necessary to mix the fuel and air and produce short, compact flames. This burner typically operates with high
secondary air velocities providing rapid, turbulent
combustion for high combustion efficiency. Fuel is introduced to the burner in a fairly dense mixture in the
center. The direction and velocity of the air and dispersion of the fuel result in complete and thorough
mixing of fuel and air.
XCL-S® type burner
The XCL-S® type oil and gas combination burner
shown in Fig. 7 was originally developed to replace
the circular burner. It not only met the demand for
added flexibility and improved control of combustion
air flow, but also incorporated the necessary design
features to result in producing low NOx emission levels. The XCL-S type burner incorporates several design features not available with the circular register.
This burner has two air zones: the inner or core zone
and the outer secondary air zone. When firing natural gas or oil, combustion air is introduced to the core
zone through slots located around the periphery of the
inner sleeve. An oil impeller or swirler is unnecessary
with this burner; control of the flow entering the core
zone ensures stable ignition. The core zone houses the
main gas fuel element(s) and the main fuel oil atomizer.
The majority of combustion air enters the burner
through the outer air zone. Axially disposed spin
vanes are located in the outer sleeve to impart swirl
to the combustion air and a sliding disk separately
controls total air to the burner independent of swirl.
An air zone swirler (AZS) device can also be incorporated
into this zone to help reduce excess air and associated
emission levels. The burner is equipped with an air measuring device upstream of the spin vanes. This device
provides a relative indication of air flow to each burner
and, on multiple burner applications, permits balancing
of air flow from burner to burner. The outer zone also
houses the igniter and flame detection equipment.
Because it can measure air flow to individual burners and regulate total air flow independent of swirl,
the XCL-S type burner provides the added flexibility
Burner selection and design
As environmental concerns continue to dictate boiler
and combustion system design, higher standards of performance are imposed on the fuel burning equipment.
Control techniques to reduce NOx emissions can conflict
with proven methods of good combustion performance,
e.g., time, temperature and turbulence.
Potential increases in carbon monoxide emissions,
particulate emissions and stack opacity as a result of
low NOx operation suggest that the burners must be
capable of continued reliable mechanical operation
and of providing the flexibility necessary to optimize
combustion under a variety of operating conditions.
Circular burner
Shown in Fig. 6, the circular type burner has long
been the standard design for wall-fired oil and gas
Steam 41 / Oil and Gas Utilization
Fig. 6 Circular register burner with water-cooled throat for oil and
gas firing.
11-9
The Babcock & Wilcox Company
Core Air
Damper
Sliding Air
Damper
Pitot
Grid
Linear
Actuator
Adjustable
Vanes
Adjustable
Hemispherical
Gas Spuds
Gas Manifold
Inlet Connection
Oil Gun
Sliding
Linkage
Local
Manometer
Burner Support
System
Fig. 7 XCL-S® low NOx burner for oil and gas.
needed when employing combustion control techniques aimed at reducing NOx emissions. This burner
is ideally suited as an upgrade to existing circular (or
other wall-fired type) burners as burner throat pressure part modifications can typically be avoided.
This advanced low NOx burner achieves superior
emission performance in burner only applications, as
well as situations using overfire air and/or flue gas
recirculation. In applications using overfire air ports,
The Babcock & Wilcox Company’s (B&W’s) Dual Air Zone
port provides maximum operating flexibility to optimize
overall performance. See Chapter 14 for more details.
Corner-firing system
The general theory and configuration for corner firing of oil and/or natural gas is the same as that for
pulverized coal firing described in Chapter 14.
Fuel and combustion air are introduced and distributed in each corner of the furnace through windbox
assemblies similar to that shown in Fig. 8. The general arrangement of the windbox for natural gas or
oil firing is essentially the same as that for coal firing
in that the windbox is divided along its height into
alternating compartments of fuel and air. For oil firing, a retractable oil gun is inserted into the center
air nozzle of each fuel compartment. For natural gas
firing, a stationary manifold gas nozzle attached to
the inside of the windbox fuel compartment distributes fuel into the bellmouth of the air nozzle.
For conventional firing applications, approximately
half of the total combustion air is introduced through
the fuel compartments. This is known as fuel air and
11-10
is used to support combustion and stabilize flames. The
balance of the air, known as auxiliary air, is used to
complete combustion and is introduced through the
compartments located above and below each fuel elevation. All of the combustion air enters through the corner windbox assemblies and is distributed in the windbox
by a system of dampers at the inlet of each compartment.
The fuel air dampers are controlled based on fuel flow
rate whereas the auxiliary air dampers are controlled
based on windbox to furnace differential pressure.
The most cost effective method of reducing NOx in
oil and/or natural gas corner-fired boilers is by addition of overfire air which uses the air staging or two
stage combustion principle commonly used with pulverized coal firing. Application of overfire air to a corner fired system involves diverting a portion of the
auxiliary air to an overfire air zone located above the
combustion zone (admitted at the top of the windbox
through two or more compartments and/or through
separate ports located several feet above the top fuel
elevation). The overfire air port compartments are
typically equipped with individual dampers to control
air flow, tilting mechanisms to allow for variation in
separation distance for improved NOx performance,
and air flow measuring devices (e.g., pitot tubes) to
facilitate air flow control. The design and arrangement
of the B&W overfire air system and corresponding
windbox modifications for oil and/or natural gas firing
are similar to that described in Chapter 14 for pulverized coal firing.
Also, flue gas recirculation (FGR) has been used
successfully and has provided significant NOx reducSteam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
tions in units firing natural gas and/or heavy fuel oil.
With FGR, a portion of the flue gas (typically 10 to
15% by weight) is taken from the boiler exhaust and
is mixed with the combustion air. However, the use of
FGR requires careful analysis as its effects on boiler
operation and maintenance costs can be significant.
Fuel oil equipment
Oil for combustion must be atomized into the furnace as a fine mist and dispersed into the combustion
air stream. Proper atomization is the key to efficient
combustion and reduced particulate emissions. Atomization quality is measured in terms of droplet size and
droplet size distribution. High quality atomization
occurs when oil droplets are small, producing high
surface to volume ratios and thereby exposing more
surface to the combustion air. A convenient means of
expressing and comparing atomization quality produced by various atomizer designs is the Sauter mean
diameter (Dsm). This is the ratio of the mean volume
of the oil droplets over the mean surface area, expressed in microns. The lower the Sauter mean diameter, the better the atomization.
For proper atomization, oil grades heavier than No.
2 must be heated by means of steam or electric heaters to reduce their viscosity to between 100 and 150
SUS (Saybolt Universal Seconds). In heating fuel oils,
caution must be observed to ensure that temperatures
are not raised to the point where vapor lock may occur. Vapor lock results when volatile fractions of the
Fig. 8 Windbox assembly for corner-firing system; compartment
dampers on opposite side not shown (courtesy of R-V Industries, Inc.).
Steam 41 / Oil and Gas Utilization
fuel separate in the fuel supply system causing flow
interruptions and subsequent loss of ignition. Fuel
supplied to the atomizers must also be free of acid, grit
and fibrous or other foreign matter likely to clog or
damage hardware components.
Fuel oil is atomized by either mechanical or dual
fluid atomizers that use steam or air as the medium.
The choice of whether to use mechanical or steam atomization is determined by the boiler design and operating requirements. In general, steam assisted atomizers produce a higher quality spray and are more
appropriate for low NOx applications or where particulate emissions and stack opacity are of primary concern. At some installations, however, the heat balance
is such that steam can not be used economically for
oil atomization. Another factor to consider is the necessity to conserve boiler feedwater. In these instances,
mechanical atomization may be more appropriate.
B&W’s atomization test facility has been used to
quantitatively and qualitatively characterize numerous atomizer designs through state-of-the-art laser
diagnostic techniques. B&W’s family of atomizers
range from mechanical Return Flow to various dual
fluid (Racer®, Y-Jet, T-Jet, and I-Jet) atomizer types.
A summary of their operating characteristics is provided in Fig. 9.
Mechanical atomizers With mechanical atomizers,
the pressure of the fuel itself provides the energy necessary for atomization. These atomizers require relatively high pressure oil for proper performance. Three
conventional types are in common use: the Uniflow,
the Return Flow and the Steam Mechanical atomizer.
The Uniflow atomizer is used in small and medium
sized stationary power plants, as well as in naval and
merchant marine boilers. This atomizer is simple to
operate and made with as few parts as possible. Fuel
is introduced into ports that discharge tangentially
into a whirl chamber. The fuel is spun out of the whirl
chamber and passes through an orifice into the combustion chamber as a well atomized conical spray.
Required oil pressure at the atomizer is above 300 psig
(2.07 MPa gauge) for heat inputs of 70 to 80 × 106 Btu/
h (20.5 to 23.4 MWt).
The Return Flow atomizer (Fig. 10) is used on either stationary or marine boilers that require wide
capacity ranges. This atomizer is designed to minimize,
or eliminate entirely, the need for changing sprayer
plates or the number of burners in service during
normal operation. A wide range of operation is possible
by maintaining a high flow through the sprayer plate
slots even at reduced firing rates. At reduced firing
rates, because the quantity of oil supplied is greater
than the required firing rate, the excess oil is returned
to a low pressure point in the piping system. The required
oil pressure at the atomizer must be either 600 or 1000
psig (4.14 or 6.90 MPa gauge) depending upon fuel,
capacity and load range requirements. Maximum input
is in the order of 200 × 106 Btu/h (58.6 MWt).
The Steam Mechanical atomizer combines the features of steam and mechanical atomization permitting
operation over wide ranges, including low loads with
cold furnaces. At high loads it can be operated as a
mechanical atomizer. At reduced loads mechanical
11-11
The Babcock & Wilcox Company
200
20
15
50
10
5
Turndown
Ratio
Steam Flow/Oil Flow
100
Return
Flow
5 to 1
Racer
Y-Jet
T-Jet
I-Jet
10 to 1
6 to 1
6 to 1
8 to 1
Sauder Mean Diameter, Microns
Droplet % Over 320 Micron
150
0.05
0.10
0.15
0.20
Fig. 9 Operating characteristics of B&W atomizers.
atomization is augmented by the use of steam. Required oil pressure is 200 to 300 psig (1.38 to 2.07 MPa
gauge) depending upon capacity requirements. Steam
pressure at the atomizer must be 10 to 15 psi (0.07 to
0.10 MPa) above oil pressure not to exceed 125 psig
(0.86 MPa gauge). Maximum capacity of this atomizer
is in the order of 80 to 90 × 106 Btu/h (23.4 to 26.4 MWt).
Residual fuel oils contain heavy residues that may
condense on cold surfaces creating potentially hazardous conditions. Improving atomization quality can
help avoid this situation. A certain number of steam
or air atomizers could be provided for satisfactory operation when boiling and drying out new units and
for continued operation at very low capacities.
Steam atomizers Due to better operating and safety
characteristics, steam assisted atomization is preferred. Steam atomization generally produces a finer
spray. The steam-fuel emulsion produced in a dual
fluid atomizer reduces oil droplet size when released
into the furnace through rapid expansion of the steam.
As a minimum, dry saturated steam at the specified
pressure must be used for fuel oil atomization to avoid
the potential for burner pulsation. Typically, 20 to 40F
(11.1 to 22.2C) superheat is recommended to avoid
such problems. If necessary, moisture free compressed
air can be substituted.
Several steam atomizer designs are available in
sizes up to 300 × 106 Btu/h (87.9 MWt) or about 16,500
lb/h (2.08 kg/s) of fuel. Required oil pressure is much
lower than for mechanical atomizers. Steam and oil
pressure requirements are dependent upon the specific atomizer design. Maximum oil pressure can be as
much as 300 psig (2.07 MPa gauge) with steam pressures as high as about 200 psig (1.38 MPa gauge). The
four most common steam atomizer designs are the Yjet, Racer, T-jet and I-jet. (See Fig. 11.) Each design is
characterized by different operating ranges, steam
11-12
consumption rates, and atomization quality based on
resultant oil droplet particle size distributions. Fig. 9
summarized these various characteristics for each of
the atomizers.
The Y-jet is designed for a wide firing range without changing the number of burners in service or the
size of the sprayer plate. It can be used on any type
of boiler with either steam or air atomization. Fuel oil
and atomizing medium flow through separate channels to the atomizer sprayer plate assembly where they
mix immediately before discharging into the furnace.
Required oil pressure at the atomizer for maximum
capacity ranges from 65 to 90 psig (0.45 to 0.62 MPa
gauge). The Y-jet is a constant differential atomizer
design requiring steam pressure to be maintained at
40 psi (0.28 MPa) over the oil pressure throughout the
normal operating range. Steam consumption with this
design is in the order of 0.1 lb steam/lb oil.
The Racer atomizer is a refinement of the Y-jet. It
was developed primarily for use where high burner
turndown and low atomizing steam consumption are
required. The Racer name refers to the class of merchant ship where this atomizer was first used. Required design oil pressure for maximum capacity is 300
psig (2.07 MPa gauge). Steam pressure is held constant throughout the load range at 150 psig (1.03 MPa
gauge). Atomizing steam consumption at full load is
approximately 0.02 lb steam/lb oil.
The T-jet and I-jet atomizers also allow a wide range
of operation without the need for excessive oil pressure. These atomizer designs are unique in that the
steam and oil are mixed in a chamber prior to discharging through the sprayer cap (Fig. 11). Rated capacity
oil pressure for the T-jet may range from 90 to 110 psig
(0.62 to 0.76 MPa gauge) depending upon fuel and
capacity requirement. The I-jet atomizer rated capacity oil pressure ranges from 70 to about 170 psig (0.48
to 1.17 MPa gauge). Of the constant differential variety, the I-jet and T-jet require a steam pressure of
approximately 20 to 40 psi (0.14 to 0.28 MPa) above
oil pressure. Steam pressures may be adjusted to obtain optimum combustion performance. Steam consumption rates vary with these atomizer designs depending upon actual operating pressures. The standard design steam consumption rates at full atomizer
Supply Fuel Barrel
Return Fuel Barrel
Air Holes
Regulating Rod
Oil Inlet
Oil Return
Oil Supply
Oil Return
Slip Fit
Sprayer Head
Intermediate Plate
Sprayer Plate
Fig. 10 Mechanical Return Flow oil atomizer assembly.
Steam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
Mix Chamber (side view)
Outer
Barrel
Sprayer Cap (side view)
Internal
Tube
Sprayer Cap (front view)
Mix
Chamber
Sprayer
Cap
Steam/Air Inlet
Oil Inlet
Fig. 11 I-jet atomizer assembly.
capacity for the T-jet and I-jet are 0.20 and 0.10 lb
steam/lb oil, respectively. In general, higher steam consumption rates result in improved atomization quality.
A disadvantage of the steam atomizer is its consumption of steam. For a large unit, this can amount
to a sizable quantity of steam and consequent heat
loss to the stack. When the boiler supplies a substantial amount of steam for a process where condensate
recovery is small, the additional makeup for the steam
atomizer is inconsequential. However, in a large utility boiler where turbine losses are low and there is little
makeup, the use of atomizing steam can have a significant effect.
Natural gas equipment
Three common types of gas element assemblies
available for the combustion of commercial high Btu
natural gas are the variable mix multi-spud, hemispherical multi-spud and the radial spud. The variable mix multi-spud gas element was developed for use
with the circular type burner. The goal was to improve
ignition stability when flue gas recirculation or twostage combustion are implemented for NOx control.
This design uses a manifold outside the furnace, with
a number of individual gas elements, or spuds, projecting through the windbox into the throat. The following
is a list of the distinctive features of this gas element:
1. Individual gas spuds are removable with the boiler
in service to enable cleaning or redrilling of the
gas nozzles as required.
2. Individual spuds can be rotated to orient the discharge holes for optimum firing conditions with
the burner in service.
Steam 41 / Oil and Gas Utilization
3. The location of the spud tip, with respect to the
burner throat, can be varied to a limited degree
for optimum firing conditions.
4. Individual gas spud flame retainers provide added stability and are more conducive to lower NOx emissions.
This gas element design adds needed flexibility for
optimizing combustion under a variety of operating
conditions. With proper selection of control equipment,
the operator can change from one fuel to another without a drop in load or boiler pressure. Simultaneous
firing of natural gas and oil in the same burner is
acceptable on burners equipped with the variable-mix
multi-spud arrangement.
The hemispherical gas element (Fig. 12) was developed for use with the low NOx XCL-S and FM-XCL
(package boiler application version of the XCL-S) type
burners. With the exception of the flame retainers, the
hemispherical gas element offers the same features as
the variable mix element design. This gas element,
however, can achieve lower NOx emissions by virtue
of the tip profile, drilling pattern and location within
the burner.
The radial spud design consists of a manifold located
inside the windbox with individual gas elements projecting into the burner throat. Unlike the variable mix
and hemispherical design, the radial spud is not conducive to low NOx emissions. Use of the radial spud is
reserved for applications where coal and gas are fired
in the same burner and where stringent NOx emission
limits are not an issue.
For low NOx gas firing capability in a burner that
must also be capable of firing pulverized coal, a single,
high-capacity gas element (HCGE) is used (Fig. 13).
11-13
The Babcock & Wilcox Company
The HCGE’s drilling pattern and its location on the
axial centerline of the burner inside the coal nozzle
promote lower NOx emissions as a result of slower
mixing of fuel and air. The gas flame associated with
the HCGE tends to be somewhat longer than gas
flames associated with burners having multiple spud
configurations. Consequently, burner capacity and
furnace size must be appropriately matched. If adequate furnace depth is available, the HCGE can also
be used with the low NOx XCL-S and FM-XCL gas or
gas/oil burners to achieve lower NOx emissions than
can be achieved with hemispherical multi-spuds.
The maximum practical limit for gas input per
burner is in the order of 200 × 106 Btu/h (58.6 MWt).
Frequently, physical arrangement of the gas hardware
is a limiting factor in fuel input capability. With all gas
element designs, the spud tip drilling is determined
by adhering to empirical curves aimed at eliminating
the potential for burner pulsation. Allowable gas discharge velocity criteria are established and the resulting required manifold pressure is determined. Gas
pressure at the burner at rated capacity is generally
in the range of 8 to 12 psig (55 to 82 kPa) for multiple
spud configurations and as high as 20 psig (137 kPa)
for the HCGE.
In many respects, natural gas is an ideal fuel since
it requires no preparation for rapid and intimate mixing with the combustion air. However, this characteristic of easy ignition under most operating conditions
has, in some cases, led to operator carelessness and
damaging explosions.
To ensure safe operation, gas flames must remain
anchored to the gas element discharge ports throughout the full range of allowable gas pressures and air
flow conditions. Ideally, stable ignition should be possible at minimum load with full load air flow through
the burner and at full load with as much as 25% excess air. With this latitude in air flow it is not likely
that ignition can be lost, even momentarily, during
upset conditions.
Byproduct gases
Many industrial applications utilize blast furnace
gas, coke oven gas, refinery gas, regenerator offgas,
Fig. 12 Furnace view of hemispherical gas spuds (oil atomizer not
shown).
11-14
landfill gas, or other byproduct gases to produce steam.
(See Chapter 27.)
Burners are designed specifically to fire these
byproduct fuels. For example, blast furnace gas is a
low heating value fuel that typically is available at
relatively low supply pressure. Accordingly, a blast
furnace gas burner utilizes a nozzle designed for low
gas velocity to promote flame stability and to accommodate a high gas flow rate with minimal pressure
loss. A scroll located at the nozzle inlet imparts swirl
to the incoming gas stream thereby improving subsequent mixing of fuel and air. Cleanout doors in the
scroll permit removal of accumulated deposits common
to blast furnace gas. Similarly, the fuel element for any
other byproduct gas must be designed for its particular characteristics, ignition stability, and appropriate
load range.
Some byproduct gases, such as CO gas, are not of
sufficient fuel quality to sustain their own flames. In
CO boilers, supplementary gas and/or oil burners are
used to raise the temperature of the CO gas to the ignition point and to assure complete burning of the combustibles in the CO gas stream. Supplementary fuel
burners and CO gas ports are positioned to ensure thorough mixing and to promote rapid, complete combustion.
Cold start and low load operation
Cold boiler startup requires firing at low heat input for long periods of time to avoid expansion difficulties and possible overheat of superheaters or
reheaters. Low pressure [200 psig (1.38 MPa gauge)]
boilers without superheaters may need only about an
hour of low load operation. Larger high pressure units,
however, may need four to six hours for startup. During startup, combustion efficiency is typically poor,
especially with residual oils, due largely to low furnace
and combustion air temperatures.
Low load operation may also result in poor distribution of air to the burners in a common windbox. Low
air flow and accompanying low windbox to furnace
pressure differentials may result in significant stratification of air in the windbox and adversely affect combustion performance. Stack effect between the bottom
and top rows of burners may further alter the quantity of air reaching individual burners. At extremely
low loads, firing oil or gas, the fuel piping itself can
also introduce poor distribution and accordingly affect
burner operation. For a given supply pressure, some
burners may have adequate fuel while others do not
receive enough fuel for continuous operation.
The low ignition temperature and clean burning
characteristics of natural gas make it an ideal fuel for
startup and low load operation. However, extreme care
must be taken to avoid a momentary interruption in
the flame. Large quantities of water are generated by
the combustion of gaseous fuels with a high percentage of hydrogen. For units equipped with regenerative type air heaters, the air heater should not be
placed in service until the flue gas temperature to the
air heater has reached 400F (204C). This prevents
condensation of water from the flue gas on the air
heater surface and subsequent transport of this waSteam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
Sprayer Cap (side view)
Flange
Sprayer Cap (front view)
Spud Pipe
Spud Tip
Fig. 13 High-capacity gas element (HCGE).
ter to the burners by the combustion air. Water in the
combustion air may cause loss of ignition.
Fuel oil is potentially more hazardous than gas for
startup and low load operation. Although ignition stability is generally not a problem, the low temperature
furnace environment may result in the accumulation
of soot and carbon particles on air heater and economizer surfaces and may also create a visible plume. If
deposits accumulate over an extended period of time
they pose a fire hazard. To reduce the incidence of fires,
some operators use sootblowers that blow steam continuously on the surfaces of regenerative type air
heaters as they rotate in the flue gas stream.
When oil must be used for startup, the following
firing methods are listed in order of preference:
1. Use of dual fluid atomizers and light fuel oil, No.
1 or 2, with steam or compressed air as the atomizing medium. This will provide a clean stack and
limit the deposit of carbonaceous residue on boiler
back-end surfaces.
2. Use of dual fluid atomizers with steam atomization
and fuel oil no heavier than No. 6, heated as required
for reduced viscosity and proper atomization.
3. Use of dual fluid atomizers with compressed air as
the atomizing medium and fuel oil no heavier than
No. 6, heated as required.
Startup with oil using mechanical atomizers is not
recommended due to the inherent lower atomization
quality. Stationary boilers equipped with mechanical
atomizers for oil firing at loads between 20 and 100%
are generally started up with natural gas or a burner
level of dual-fluid startup atomizers.
Steam 41 / Oil and Gas Utilization
Igniters
Lighting a burner requires an independent source
of ignition. The igniters used to provide the necessary
ignition energy range from hand held torches inserted
temporarily, to direct ignition electrical igniters, to
automatically spark ignited oil or gas fired igniters.
Today, the boiler codes require permanently installed igniters in each burner. These are most often
oil or gas fired designs that are ignited by means of
high voltage or high energy spark ignition systems.
The capacity of modern igniters can reach 10% or more
of the main burner. This permits their use in stabilizing the combustion of difficult to burn fuels or in providing support ignition for abnormal main fuel conditions. Their high input capacity may also be used to
warm the furnace prior to starting the main burner system or to synchronize the turbine. Although the igniter
capacity is tailored to meet the specific requirements of
the burner and flame safety system, a maximum input
of approximately 25 × 106 Btu/h (7.3 MWt) is typical.
The National Fire Protection Association (NFPA)
categorizes igniters according to their input capacity
relative to the burner input. Class I igniters generally provide 10% or more of the main burner heat release and may be operated continuously for support
ignition when required under all boiler conditions.
Specifically, the Class I igniter location and capacity
will provide sufficient ignition energy to raise any
credible combination of burner inputs of both fuel and
air above the minimum ignition temperature. Class
II igniters generally provide 4 to 10% of the burner
heat release and may be operated continuously for
11-15
The Babcock & Wilcox Company
ignition support under well defined boiler conditions.
Class III igniters generally provide a heat release less
than 4% of the burner and may not be operated continuously to provide support ignition for the burner.
Most modern utility boilers employ Class I igniters to
warm the boiler, provide support for difficult fuels and/
or poor fuel conditions, and to minimize the complexity of the flame detection system.
Gas provides the most reliable and cleanest burning fuel for high capacity igniters. Gas igniters may
be operated with either natural gas or liquefied petroleum gas (LPG). When operated with LPG, it is
critical that the LPG supply system provide a reliable,
vapor-only flow at the required rate. Oil fired igniters may be used with both distillate and residual fuel
oils. Light oils are favored as they avoid complexities
of oil heating/recirculation, which can impair reliability. Distillate oil can be used with either air or steam atomization with air being preferred. Residual oil igniters
require superheated steam for optimum performance.
Gas and oil igniters are available in both fixed and
retractable designs. Retractable igniters are inserted
to their firing position for ignition of the main burner
and then retracted back into the burner when they
are no longer needed. Retracting the igniter sufficiently reduces radiant heat exposure such that cooling air is not required. Fig. 14 is an example of a typical retractable igniter (B&W CFS gas igniter is shown
and an oil fired version is also available).
Fixed igniters are permanently positioned in the
burner throat at the proper location for ignition of the
burner. Fig. 15 is an example of a stationary igniter
(FPS oil igniter is shown and a gas fired version is also
available). A dedicated supply of air is provided to the
FPS igniter to improve combustion performance and to
cool the igniter when it is out of service.
In addition to these fueled igniters, there is a special Class III igniter which does not burn fuel. These
Fig. 14 CFS retractable gas igniter with high energy spark probe.
11-16
ignite the burner directly with electrical energy. They
are usually high energy, capacitive discharge, spark
ignition systems similar to those that ignite oil and gas
fired igniters, but usually they operate with a higher
energy level. Direct electric ignition can be used on
oil burners which burn distillate and residual fuel oils
having specific characteristics. Direct ignition of gas
burners is recommended only for burners with a
single gas element. Reliable ignition of gas burners
having multiple gas elements spread around the
burner can often be difficult, resulting in potentially hazardous conditions, and is not normally recommended.
Direct electric ignition spark systems generally provide an ignition energy level of at least 8 joules, with
10 to 12 joules used in most applications. The small
spark produced by the direct ignition spark rod must
be carefully positioned in the fuel stream to ensure
rapid ignition of the fuel upon opening of the burner
fuel valve. Direct electric ignition spark systems must
always be retractable.
Safety precautions
NFPA 85 is a standard set of operating codes (procedures, interlocks, and trips) for the safe and reliable
operation of gas and oil combustion processes. Recommendations of this standard along with governing local
codes and ordinances are followed in the design of gas
and oil burner systems, burner interlock and trip systems, and burner sequence control systems.
Five rules of prime importance in safe and reliable
operation of gas and oil fired combustion systems,
whether employing a manual or automatic control
system, are described below.
1. Never allow oil or gas to accumulate anywhere,
other than in a tank or lines that form part of the
fuel delivery system. The slightest odor of gas must
be cause for alarm. Steps should be taken immediately to ventilate the area thoroughly and locate
the source of the leak.
2. A minimum purge rate air flow not less than 25%
of full load volumetric air flow must be maintained during all stages of boiler operation. This
includes pre-purging the setting and lighting of
the igniters and burners until the firing rate air
requirement exceeds the purge rate air flow.
3. A spark producing device or lighted torch must be
in operation before introducing any fuel into the
furnace. The ignition source must be properly
placed with respect to the burner and must continuously provide a flame or spark of adequate size
until a stable main flame is established.
4. A positive air flow through the burners into the
furnace and up the stack must be maintained at
all times.
5. Adequate fuel pressure for proper burner operation must be maintained at all times. In the case
of oil firing, fuel pressure and temperature must
be maintained for proper atomization. In dual
fluid atomizer applications, adequate steam or air
pressure must be available at the atomizer.
Equipment requirements, sequence of operation,
interlock systems and alarm systems are equally imSteam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
Combustion/Cooling
Air Inlet
Combustion/Cooling Air
Regulating Valve
Stationary
Guide Tube
Spark Rod
Connection
Flame Detection
Rod
Atomizing
Air Supply
Internal Guide
Tube Assembly
Seal Air
Connection
Oil
Supply
Flame Rod
Connection
Oil Atomizer
Assembly
Atomizer
Sprayer Plate
PAI Spark Plug
Eddy Plate
Fig. 15 FPS oil igniter.
portant, if not more so, when implementing combustion control techniques to reduce NOx emissions.
In observance of the recommended rules of operation, an automatic control system should include the
following:
1. purge interlocks requiring a specified minimum air
flow for a specific time period to purge the setting
before the fuel trip valve can be opened,
2. flame detectors on each burner, connected to an
alarm and interlocked to shut off the burner fuel
valve upon loss of flame,
3. closed position limit switches for burner shutoff
valves, requiring that individual burner shutoff
valves be closed to permit opening the fuel trip valve,
4. shutoff of fuel on failure of the forced or induced
draft fan,
5. shutoff of fuel in the event of low fuel pressure
(and low steam or air pressure to oil atomizers),
6. shutoff of fuel in the event of low oil temperature,
and
7. shutoff of fuel in gas fired units in the event of
excessive fuel gas pressure.
Any of the commonly used fuels can be safely
burned when using the proper equipment and operating skill. Hazards are introduced when, through
carelessness or mis-operation of equipment, the fuel
is no longer burned in a safe manner. While a malfunction should be corrected promptly, panic must be
avoided. Investigation of explosions of boiler furnaces
equipped with good recording apparatus reveal that
conditions leading to the explosion had, in most cases,
existed for a considerable period of time. Sufficient time
was available for someone to have taken unhurried
corrective action before the accident. The notion that
malfunctions of safety equipment cause frequent, unnecessary unit trips is not consistent with the facts.
FPS is a trademark of Fossil Power Systems, Inc.
Orimulsion is a trademark of Bitumenes Orinoco, S.A.
Steam 41 / Oil and Gas Utilization
11-17
The Babcock & Wilcox Company
Fig. 1 Deepwater oil and gas fields require new floating technology facilities like this Spar being installed in the Gulf of Mexico.
11-18
Steam 41 / Oil and Gas Utilization
The Babcock & Wilcox Company
Chapter 12
Solid Fuel Processing and Handling
Coal remains the dominant worldwide source of energy for steam generation. However, additional solid
fuels such as wood by-products and municipal wastes
are also in use. The large scale continuous supply of
such solid fuels for cost-effective and reliable steam
power generation requires the effective integration of
recovery (e.g., mining), preparation, transportation
and storage technologies. The relationships between
these are illustrated in Fig. 1. While each fuel offers
unique challenges, a discussion of the processing and
handling of coal helps identify many of the common
issues and considerations for all solid fuels. Selected
additional topics about the special aspects of some other
solid fuels are covered in Chapters 28 through 30.
Mining is the first step in producing coal. Raw coal
can be treated to remove impurities and to provide a
more uniform feed to the boiler. The resulting reduction in ash and sulfur can significantly improve overall boiler performance and reduce pollutant emissions.
The transportation of coal to the plant may represent
a major portion of the plant’s total fuel cost, although
mine-mouth generating stations can minimize these
Fig. 1 Fuel supply chains for coal-fired power generation.
Steam 41 / Solid Fuel Processing and Handling
transportation costs. Storage and handling of large
coal quantities at the plant site require careful planning to avoid service disruptions.
The changing nature of electric utility industry
regulation, and the increasingly stringent emissions
control requirements have dramatically changed the
way coal is used to generate electric power in the
United States (U.S.). Where once a new boiler was
dedicated to one or two sources of coal over its lifetime,
today active fuel management with multiple sources
of coal and transport options is a core part of power
plant competition and profitability. The plant objective is to meet the emission control requirements at the
lowest overall power production cost.
Coal source flexibility has become necessary for economic survival. Plant owners have had to meet these
new challenges by employing multiple coal sources,
some very remote from the plant. This typically has
required the installation of new and more flexible coal
handling equipment in the plant storage facilities.
Coal mining
As discussed in Chapter 9, electric utility coal consumption for power generation dominates the market
for coal produced in the U.S. and in the rest of the
world. Coal production in the U.S. reached approximately 1.1 billion short tons per year at the turn of
the 21st century. At the same time, electric utilities
accounted for 92% of the coal consumed. Overall
worldwide production and consumption of coal has
been steadily increasing since the late 1980s, with the
major producers being China, the U.S., India and Australia. Together these countries produced more than
65% of the total amount of coal mined.1-3
U.S. coal production is split between surface mining, which produces 66% of the total and underground
mining, which produces 34% of the total.2 Because of
the geologic locations of coal deposits or seams, and cost
considerations, surface mining dominates coal production west of the Mississippi River and underground
mining dominates in the East. In 2003, Wyoming,
West Virginia and Kentucky led the nation in coal
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The Babcock & Wilcox Company
production with a 59% combined total. The emergence
of large, high volume surface mines producing low
sulfur coal in the west has resulted in a continuing
shift of coal production from the eastern U.S. to the
west.1
Surface mining
Coal may be recovered from relatively shallow
seams by removing the overlying earth, or overburden, to expose the coal seam. Typically, topsoil is first
removed and stored for later use in reclamation of the
site. The remaining overburden is drilled and blasted
to loosen the rock for removal with a dragline or excavating shovel. The overburden is then methodically
stripped away and stored for restoration of the land
to the original contour following removal of the coal.
A dragline is commonly used to expose the coal seam
(Fig. 2). The coal may then be removed using a bulldozer and front-end loader or a shovel. A mobile
crusher and screen may be set up in the mine for initial sizing of the raw coal. The coal is then loaded into
trucks for delivery to a cleaning facility or steam generating plant.
The stripping ratio is defined as the unit amount
of overburden that must be removed to access a unit
amount of coal. In general, surface mines in the western U.S. have lower stripping ratios than mines in the
east.
Strict environmental regulations limit the amount
of land surface area that may be exposed at any one
time, control water runoff, and establish land reclamation procedures.
Underground mining
Many coal reserves are accessible only by underground mining. (See Chapter 9.) Continuous mining,
the most prevalent form of underground mining,
makes use of machines like those in Fig. 3. It accounts
for approximately 55% of the total underground production of coal.
Room and pillar mining Most underground U.S. coal
is produced using a technique known as room and
pillar mining. A series of headings or parallel entries
are cut into the coal seam to provide passages for the
Fig. 2 Large coal dragline in operation (courtesy of National Coal
Association).
12-2
Fig. 3 Continuous mining machine in operation (courtesy of National
Coal Association).
mining machinery, uncontaminated ventilation air,
and conveying equipment. These headings are typically 18 to 20 ft (5.5 to 6.1 m) wide and may be several miles (km) long. Rooms are driven off of the main
headings to the property limits of the mine. Typically,
only about 50% of the coal is removed when the rooms
are first mined. The remaining coal is left in place to
support the roof. Roof bolts are installed where the
coal has been removed for additional roof support. At
the completion of the development cycle, the remaining coal may be removed by retreat mining, and the
unsupported roof is allowed to collapse.
Longwall mining In longwall mining, shearers or
plows are pulled back and forth across a panel of coal
to break it loose from the seam. The coal falls onto a
flight conveyor and is transported to the main haulage line. Because essentially all of the coal is removed,
artificial roof supports, known as shields or chocks, are
used to cover the plow and conveyor. The plow, conveyor and roof supports are advanced using hydraulic jacks as the coal is removed from the mining face.
The unsupported roof is allowed to cave in behind the
supports.
Although more underground mines use the room
and pillar method of mining, longwall mines generally produce more coal because they are larger operations overall. Since the early 1980s, there has been a
significant increase in productivity using longwall
mining. Today, more than one-half of the longwall
mines in the U.S. are located in Appalachia, but this
type of mining is being used more widely in western
coal areas as well.
A key reason for the increase in productivity involves increased panel size of longwall mining sections. The average panel face width is 759 ft (231 m),
and the average panel length is 6853 ft (2089 m).
Some of these operating units reaching 10,000 ft (3048
m).4
Longwall mining can be a very high capacity production system provided the geologic conditions are
suitable and the longwall has been carefully integrated with the existing panel development scheme
and coal haulage infrastructure. Production capacities exceeding 6000 t of raw coal per shift have been
reported. The annual production capacity for a
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
longwall is a function of the seam height, panel width
and length, and the time required to move the equipment between operating panels.
Raw coal size reduction and classification
Sizing requirements
Size reduction operations at steam power plants are
usually confined to crushing and pulverizing, although it is sometimes more economical to purchase
pre-crushed coal for smaller plants, especially stokerfired units. Screening at the plant is generally not
required, except to remove large impurities and trash
using simple grids (or grizzlies) and rotary breakers.
Techniques for determining coal particle size distribution are discussed in Chapter 9.
Coal particle size degradation occurs in transportation and handling and must be considered when
establishing supply size specifications. This may be
critical where the maximum quantity of coal fines is
set by firing equipment limitations.
For stoker-fired installations, it is customary to
specify purchased coal sized to suit the stoker (see
Chapter 16), so that no additional sizing is required
at the plant [typically 1.5 in. × 0 (38.1 mm × 0)].
For pulverized coal-fired boilers, a maximum delivered top size is usually specified with no limitation on
the percentage of fines, so that the delivered coal is
suitable for crushing and pulverizing in the available
equipment. The coal is crushed to reduce particle size
and then ground to a very fine size in the pulverizer.
(See Chapter 13.)
Crushers alone may be used to provide the relatively coarser sizes required for Cyclone furnaces. (See
Chapter 15.) A properly sized crusher efficiently reduces particle size while producing minimal fines.
Size reduction equipment selection
Size reduction equipment is generally characterized
by the maximum acceptable feed size and the desired
product top size. The reduction ratio is defined as follows:
pfeed
pproduct
where
pfeed
pproduct
Fig. 4 Rotary breaker for use at the mine and power plant.
mately 20 rpm. The size of the screen openings determines the top size of the coal. The coal feed at one end
of the cylinder is picked up by lifting shelves and is
carried up until the angle of the shelf permits the coal
to drop onto the screen plate. The coal shatters and is
discharged through the screen openings. The harder
rock does not break as readily; it travels along the
screen and is rejected at the discharge end. Wood,
large rocks, and other trash that do not pass through
the screen are separated from the coal. Rotary breakers may be installed at the mine, preparation plant,
or steam generating plant.
The elements of a single-roll crusher are illustrated
in Fig. 5. This crusher consists of a single, toothed roll
that forces the coal against a plate to produce the
crushing action. The maximum product particle size
is determined by the gap between the roll and the
plate. To prevent jamming by large impurities such
as tramp metal, the roll is permitted to rise or the plate
can swing away, allowing the impurities to pass
through. This is an old type of crusher commonly used
for reducing run-of-mine bituminous coal to a maximum product of 1.25 to 6 in. (31.8 to 152 mm). The
abrasive action between the coal and the plate produces some fines; however, they are discharged with
minimal re-breakage.
In a double-roll crusher, the coal is forced between
two counter-rotating toothed rolls (Fig. 6). The mating faces of both rolls move in a downward direction,
pulling the coal through the crusher. The size of the
roll teeth and the spacing between rolls determine the
(1)
= feed particle size in which 80% of the particles pass a given screen size or mesh
= product particle size in which 80% of the
particles pass a given screen size or mesh
Once-through crushing devices, that discharge the
fines without significant re-crushing, are used to minimize the production of fines. Rotary breakers and roll
crushers are commonly used to reduce the coal top size
without producing a significant amount of fines.
The rotary breaker, illustrated in Fig. 4, reduces the
coal to a predetermined maximum size and rejects
larger refuse, mine timbers, trash, and some tramp
metal. This equipment also breaks apart frozen coal
prior to further coal processing. It consists of a large
cylinder of steel screen plates that rotates at approxiSteam 41 / Solid Fuel Processing and Handling
Fig. 5 Single-roll crusher – diagrammatic section.
12-3
The Babcock & Wilcox Company
Fig. 6 Double-roll crusher – diagrammatic section.
product top size. One of the rolls may be spring loaded
to provide a means for passing large, hard impurities.
Double-roll crushers are used for reducing run-ofmine coal to smaller sizes at preparation and steam
generating plants.
In retention crushers such as hammer mills and ring
crushers, coal is retained in the breakage zone until it
is sufficiently fine to pass through a screen to the discharge. The re-breakage action produces considerable
fines, consequently these mills are not used in applications where fines are objectionable. They are often used
to reduce run-of-mine coal to an acceptable size for feed
to a stoker or pulverizer, e.g., 0.75 in. × 0 (19 mm × 0).
A hammer mill is depicted in Fig. 7. In this mill, the
coal is broken by impact with the hammers mounted
on a central shaft and permitted to swing freely as the
shaft is rotated. The coal is fed at the top of the mill
and is forced down and outward to the grate bars as
it is struck by the hammers. The spacing of the bars
determines the maximum size of the finished product.
The coal remains in the mill, and breakage continues
until the particles are fine enough to pass through the
grate. A trap is usually provided for collection and
removal of tramp metal.
Screen selection
Screening is usually performed at the mine or
preparation plant to remove unwanted material and
size coal for various uses prior to shipment to the steam
generating plant. The run-of-mine coal is usually
passed over a grid of steel bars, or grizzly, to remove
mine timbers, rocks and other trash. The raw coal may
be separated into various size fractions to meet contract specifications or for further processing in a preparation plant by passing the coal through various
screens. Common screen types include gravity bar
screens, trommels or revolving screens, shaker screens,
and vibrating screens.
A gravity bar screen consists of a number of sloped
12-4
parallel bars. The gaps between bars, the slope, and
the length of the bars determine the separating size.
The bars have tapered cross-sections; the gaps between the bars are smaller on the top side than on the
bottom. This design reduces plugging.
A revolving screen consists of a slowly rotating cylinder with a slight downward slope parallel to the axis
of coal flow. The cylinder is comprised of a perforated
plate or a wire cloth, and the size of the openings determines the separating size. Because of the repeated
tumbling as the coal travels along the cylinder, considerable breakage can occur. For this reason, revolving screens are not used for sizes larger than about 3
in. (76.2 mm). Because only a small portion of the
screen surface is covered with coal, the capacity per
area of screen surface is low.
A shaker screen consists of a woven wire mesh
mounted in a rectangular frame that is oscillated back
and forth. This screen may be horizontal or sloped
slightly downward from the feed end to the discharge
end. If the screen is horizontal, it is given a differential motion to help move the coal along its surface.
Bituminous coal generally fractures into roughly
cubicle shapes, while commonly associated slate and
shale impurities fracture to form relatively thin slabs.
This shape difference enables the impurities to be
separated with a slotted shaker.
Vibrating screens are similar to shaker screens except that an electric vibrator is used to apply a high
frequency, low magnitude vibration to the screen. The
screen surface is sloped downward from the feed to the
discharge end. The vibration helps to keep the mesh
openings clear of wedged particles and helps to stratify
the coal so that fine particles come in contact with the
screen surface. For screening fine, wet coal, water
sprays are used to wash fine particles through the coal
bed and the screen surface. Vibrating screens are the
most widely used types for sizing and preliminary
dewatering.
It is common practice to separate the fines from the
coarse coal to improve the efficiency of subsequent
cleaning and dewatering processes. The fines may be
discarded, cleaned separately, or bypassed around the
cleaning process and then blended back into the coarse
clean coal product.
Coal cleaning and preparation
The demand for coal cleaning has increased in response to environmental regulations restricting sulfur dioxide (SO2) emissions from coal-fired boilers. The
demand is also due to a gradual reduction in run-ofmine coal quality as higher quality seams are depleted
and continuous mining machines are used to increase
production. Approximately 70% of coal mined for electric utility use is cleaned in some way.
Coal cleaning and preparation cover a broad range
of intensity, from a combination of initial size reduction, screening to remove foreign material, and sizing
discussed previously, to more extensive processing to
remove additional ash, sulfur and moisture more intimately associated with the coal.
The potential benefits of coal cleaning must be bal-
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
Fig. 7 Ring hammer mill crusher – diagrammatic section (courtesy of
Pennsylvania Crusher Corporation).
anced against the associated costs. The major costs to
consider, in addition to the cleaning plant capital and
operating costs, include the value of the coal lost to
the refuse product through process-related inefficiencies and the cost of disposing of the refuse product.
Generally, the quantity of coal lost increases with the
degree of desired ash and sulfur reduction. An economic optimum level of ash and sulfur reduction can
be established by balancing shipping and post-combustion cleanup costs against pre-combustion coal
cleaning costs.
Coal characterization
Coal is a heterogeneous mixture of organic and inorganic materials as described in detail in Chapter 9.
Coal properties vary widely between seams and within
a given seam at different elevations and locations. The
impurities associated with coal can generally be classified as inherent or extraneous. Inherent impurities
such as organic sulfur can not be separated from the
coal by physical processes. Extraneous impurities can
be partly segregated from the coal and removed by
physical coal cleaning processes. The extent to which
these impurities can be economically removed is determined by the degree of material dissemination throughout the coal matrix, the degree of liberation possible at
the selected processing particle size distribution, and
physical limitations of the processing equipment.
Mineral matter associated with the raw coal forms
ash when the coal is burned. Ash-forming mineral
matter may also be classified as inherent or extraneous. Inherent mineral matter consists of chemical elements from plant material organically combined with
coal during its formation. This mineral matter generally accounts for less than 2% of the total ash. Extraneous mineral matter consists of material introduced
into the deposit during or after the coalification process,
or is extracted with the coal in the mining process.
Sulfur is always present in coal and forms SO 2
when the coal is burned. If the sulfur is not removed
before combustion, the SO2 that forms is exhausted
Steam 41 / Solid Fuel Processing and Handling
through the stack or removed by post-combustion flue
gas treatment, discussed in Chapters 32 and 35. Sulfur is generally present in coal in three forms: pyritic,
organic or sulfate.
Pyritic sulfur refers to sulfur combined with iron
in the minerals pyrite (FeS2) or marcasite. Pyrite may
be present as lenses, bands, balls or as finely disseminated particles. Organic sulfur is chemically combined
with molecules in the coal structure. Sulfate sulfur is
present as calcium or iron sulfates. The sulfate sulfur
content of coal is generally less than 0.1%.
The total sulfur in U.S. coals can vary from a few
tenths of a percent to more than 8% by weight. The
pyritic portion may vary from 10 to 80% of the total
sulfur and is usually less than 2% of the coal by weight
(Table 1).
The larger pyritic sulfur particles can generally be
removed by physical cleaning, but finely disseminated
pyritic sulfur and organic sulfur can not. Advanced
physical and chemical cleaning technologies are under development to remove these sulfur forms.
Moisture can also be considered an impurity because it reduces the heating value of raw coal. Inherent moisture varies with coal rank, increasing from 1
to 2% in anthracite to 45% or more in lignite. Surface
moisture can generally be removed by mechanical or
thermal dewatering. This drying requires an energy
expense at the cleaning plant or the steam generating plant (in pre-drying or during combustion). Drying before shipment reduces transportation costs on
a per-Btu basis. When pre-drying is used, atmospheric
oxidation will tend to be increased for low rank coals
because of the exposure of additional oxidation sites
in the particles.
The distribution of ash and sulfur in a coal sample
can be characterized by performing a washability
analysis. This analysis consists of separating the raw
coal into relatively narrow size fractions and then dividing each fraction into several specific gravity fractions. The coal in each size/specific gravity fraction is
Table 1
Distribution of Sulfur Forms in Various Coals (%)
Mine Location
County, State
Henry, MO
Henry, MO
Muhlenburg, KY
Coshocton, OH
Clay, IN
Clearfield, PA
Franklin, IL
Meigs, OH
Boone, WV
Walker, AL
Washington, PA
Mercer, ND
McDowell, WV
Campbell, WY
Pike, KY
Kittitas, WA
Coal Seam
Bevier
Tebo
Kentucky #11
Ohio #6
Indiana #3
Upper Freeport
Illinois #6
Ohio #8A
Eagle
Pratt
Pittsburgh
Lignite
Pocahontas #3
Gillette
Freeburn
Big Dirty
Total Pyritic Organic
Sulfur Sulfur Sulfur
8.20
5.40
5.20
4.69
3.92
3.56
2.52
2.51
2.48
1.62
1.13
1.00
0.55
0.46
0.46
0.40
6.39
3.61
3.20
2.63
2.13
2.82
1.50
1.61
1.47
0.81
0.35
0.38
0.08
0.14
0.13
0.09
1.22
1.80
2.00
2.06
1.79
0.74
1.02
0.86
1.01
0.81
0.78
0.62
0.46
0.32
0.33
0.31
12-5
The Babcock & Wilcox Company
then analyzed for ash, sulfur and heating value content. The hardness and distribution of the impurities
relative to the coal determine if the impurities are concentrated in the larger or smaller size fractions. Relatively soft impurities are generally found in the finer
size fractions. In general, the lowest specific gravity
fractions have the lowest ash content, as indicated in
Table 2.
The information generated by these float/sink
characterization tests can be used to predict the degree of ash and sulfur reduction possible using various specific gravity based cleaning technologies discussed below. In general, the more material that is
present near the desired specific gravity of separation,
the more difficult it is to make an efficient separation.
Coal cleaning and preparation operations
The initial steps in the coal cleaning process include
removal of trash, crushing the run-of-mine coal, and
screening for size segregation. These preliminary operations and associated hardware were discussed previously. The following operations are then used to
produce and dewater a reduced ash and sulfur product. Fig. 8 provides a general layout of coal cleaning
unit operations.
Gravity concentration Concentration by specific
gravity and the subsequent separation into multiple
products is the most common means of mechanical coal
cleaning. Concentration is achieved because heavier
particles settle farther and faster than lighter particles
of the same size in a fluid medium. Coal and impurities may be segregated by their inherent differences
in specific gravity, as indicated in Table 3.
The fluid separating medium may consist of a suspension of the raw coal in water or air, a mixture of
sand and water, a slurry of finely ground magnetite
(iron oxide, FE3O4), or an organic liquid with an intermediate specific gravity. Aqueous slurries of raw
coal and magnetite are currently the most common
separating media.
If the effective separating specific gravity of the
media is 1.5, particles with a lower specific gravity are
concentrated in the clean coal product and heavier
particles are in the reject or refuse product. Several
factors prevent ideal separation in practice.
Gravity separation processes concentrate particles
by mass. The mass of a particle is determined by its
specific gravity and particle size. Raw coal consists of
particles representing a continuous distribution of
Table 2
Typical Ash Contents of Various
Bituminous Coal Specific Gravity Fractions
12-6
Specific Gravity
Fraction
Ash Content
% by wt
1.3 to 1.4
1.4 to 1.5
1.5 to 1.6
1.6 to 1.8
1.8 to 1.9
Above 1.9
1 to 5
5 to 10
10 to 35
35 to 60
60 to 75
75 to 90
Fig. 8 General layout of coal cleaning operations.
specific gravities and sizes. It is quite possible for a
larger, less dense particle to behave similarly to a
smaller particle with a higher specific gravity. For
example, a relatively smaller pyrite particle may settle
at a similar rate as a larger coal particle. The existence of equal settling particles can lead to separating
process inefficiency. Fine pyrite in the clean coal product and coarse coal in the refuse are commonly referred to as misplaced material. The amount of misplaced material is determined by the quantity and distribution of the raw coal impurities, the specific gravity of separation, and the physical separation efficiency of the segregated material.
A significant amount of material with a specific
gravity close to the desired specific gravity of separation results in a more inefficient separation. If the
amount of near gravity material exceeds approximately 15 to 20% of the total raw coal, efficient gravity separation is difficult.
The most common wet gravity concentration techniques include jigging, tabling, and dense media separation processes. Each technique offers technical and
economic advantages.
Jigging In a coal jig, a pulsating current of water is
pushed upward in a regular, periodic cycle through a
bed of raw coal supported on a screen plate. This upward or pulsion stroke of the cycle causes the bed to
expand into a suspension of individual coal and refuse
particles. The particles are free to move and generally
separate by specific gravity and size, with the lighter
and smaller pieces of coal moving to the upper region
of the expanded bed. In the downward or suction
stroke of the cycle, the bed collapses, and the separation is enhanced as the larger and heavier pieces of
rock settle faster than the coal. The pulsion/suction
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
Table 3
Typical Specific Gravities of Coal
and Related Impurities
Material
Bituminous coal
Bone coal
Carbonaceous shale
Shale
Clay
Pyrite
Specific Gravity
1.10 to 1.35
1.35 to 1.70
1.60 to 2.20
2.00 to 2.60
1.80 to 2.20
4.80 to 5.20
cycle is repeated continuously. The separated layers
are split at the discharge end of the jig to form a clean
coal and a refuse product. The bed depth where the
cut is made determines the effective specific gravity
of separation.
The upward water pulsation can be induced by
using a diaphragm or by the controlled release of compressed air in an adjacent compartment. Operation of
a Baum jig is illustrated in Fig. 9. This type of jig may
be used to process a wide feed size range. Typically,
the specific gravity of separation ranges from 1.4 to
1.8. The separation efficiency may be enhanced by
pre-screening the feed to remove the fines for separate processing.
Tabling A concentrating, pitched table is mounted
so that it may be oscillated at a variable frequency and
amplitude. A slurry of coal and water is continuously
fed to the top of the table and is washed across it by
the oncoming feed. Diagonal bars, or riffles, are spaced
perpendicular to the flow of particles. The coal-water
mixture and oscillating motion of the table create a
hindered settling environment where the lower gravity particles rise to the surface. Higher specific gravity particles are caught behind the riffles and transported to the edge of the table, away from the clean
coal discharge.
Tables are generally used to treat 0.375 in. × 0 (9.53
mm × 0) coal. Three or four tables may be stacked
vertically to increase throughput while minimizing
plant floor space requirements.
Dense media separation In dense or heavy media
separation processes, the raw coal is immersed in a
fluid with a specific gravity between that of the coal
and the refuse. The specific gravity differences cause
Fig. 9 Typical Baum jig for coal preparation.
Steam 41 / Solid Fuel Processing and Handling
12-7
The Babcock & Wilcox Company
the coal and refuse to migrate to opposite regions in
the separation vessel. In coal preparation, the heavy
media fluid is usually an aqueous suspension of fine
magnetite in water.
Flotation Coal and refuse separation by froth flotation is accomplished by exploiting differences in coal
and mineral matter surface properties rather than
specific gravities. Air bubbles are passed through a
suspension of coal and mineral matter in water. This
suspension is agitated to prevent particles from settling out. Air bubbles preferentially attach to the coal
surfaces that are generally more hydrophobic, or difficult to wet. The coal then rises to the surface where
it is concentrated in a froth on top of the water. The
mineral matter remains dispersed (Fig. 10). Chemical reagents, referred to as collectors and frothers, are
added to enhance the selective attachment of the air
bubbles to the coal and to permit a stable froth to form.
Flotation is generally used for cleaning coal finer than
48 mesh (300 microns). The efficiency of the process can
be enhanced by carefully selecting the type and quantity of reagents, fine grinding to generate discrete coal
and refuse particles, and generating fine air bubbles.
Dry processing Dry coal preparation processes account for a small percentage of the total coal cleaned
in the U.S. In general, pneumatic processing is only
applied to coal less than 0.5 in. (12.7 mm) in size with
low surface moisture.
Dewatering Dewatering is a key step in the preparation of coal. Reducing the fuel’s moisture content
increases its heating value per unit weight. Because
coal shipping charges are based on tonnage shipped,
a reduction in moisture content results in lower shipping costs per unit heating value.
Coarse coal, greater than 0.375 in. (9.53 mm) particle size, can be sufficiently dewatered using vibrating screens. Intermediate size coal, 0.375 in. (9.53 mm)
by approximately 28 mesh (600 microns), is normally
dewatered on vibrating screens followed by centrifuges.
Fine coal dewatering often involves the use of a
thickener to increase the solids content of the feed to
a vacuum drum, vacuum disc filter, or high gravity
Fig. 10 Flotation cell.
12-8
centrifuge. The filter cake may be mixed with the
coarser size fractions to produce a composite product
satisfying the specifications. Fine coal dewatering also
serves to clarify the water for reuse in the coal preparation plant. Fines must be separated from the recycled water to maximize the efficiency of the separation processes.
Thermal dewatering may be necessary to meet product moisture specifications when the raw coal is
cleaned at a fine size to maximize ash and sulfur rejection. The various types of thermal dryers include
rotary, cascade, reciprocating screen, suspension and
fluidized-bed dryers. Cyclones or bag filters are used
to prevent fine dust emissions from the dryer. The
collected fine coal may be recycled to support dryer
operation. Thermal drying represents an economic
tradeoff of reduced product moisture content versus
heat required to fire the dryer.
Impact on steam generator system operations
The principal benefit of coal cleaning is the reduction in ash and sulfur content. Reduced ash content
results in lower shipping costs and reduced storage
and handling requirements at the plant on a cost per
unit heating value basis. Boiler heat transfer effectiveness may increase as a result of reduced ash deposition on tube surfaces. A reduction in sulfur content
leads directly to reduced SO2 emissions. Lower sulfur
feed coal may preclude the need for or reduce the performance requirements of post-combustion SO2 emission control systems. A reduction in sulfur content may
also reduce spontaneous combustion during storage,
and corrosion in coal handling and storage equipment.
Reduced ash content can result in reduced maintenance through removal of abrasive pyrite and quartz
from the coal. Reduction of clay in the coal can improve
handling and bunker or silo storage characteristics,
but this may be offset by the effects of higher fines
content and higher surface moisture on cleaned coal.
Coal transportation
The means of transportation and the shipping distance significantly influence the total fuel cost, reliability of supply, and fuel uniformity at the power
plant. In some cases where western U.S. coal is
shipped over an extended distance, freight costs may
represent 75 to 80% of the total delivered fuel cost. At
the other extreme, transportation costs may be negligible for mine-mouth generating stations. In transit,
the coal’s handling characteristics may be changed by
freezing, increased moisture content, or size degradation. When open rail car, truck or barge transport is
used, the moisture content of the delivered coal depends on the initial moisture level, the weather conditions in transit, and the particle size distribution.
Size degradation during shipping is dependent on the
coal friability (ease of crumbling) and the techniques
and number of transfers. As previously stated, for
pulverized coal applications, size degradation is generally not a concern.
Coal is primarily shipped by rail, barge, truck and
conveyor, but can also be transported by pipelines and
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
tramway systems. The volume and distribution of coal
transported by these various means is summarized in
Table 4.5 Combinations of these methods are often used
to obtain the lowest delivery cost. Available transportation infrastructure, haulage distance, required flexibility, capital cost and operating cost are important
factors in selection of a system for delivering coal to
the power plant.
In general, barge transport represents the lowest
unit cost per ton per mile followed by rail, truck and
conveyor in terms of increasing cost. Combinations of
these four transportation systems may be used to move
coal to loading docks for overseas shipment.
Transportation systems are generally designed to
minimize intermediate storage of coal to control inventory costs, reduce insurance costs, and minimize the
effects of changes that can reduce the commercial
value of coal. Potentially harmful changes include a
reduction of heating value, particle size degradation,
and loss due to self-ignition or wind and water erosion.
Rail
Railroads delivered approximately 70% of the coal
transported to electric generating power plants in the
U.S. in 2002, and nearly 95% of this total was shipped
in unit trains. Unit trains travel from the loading facility to the customer without stopping and normally
consist of 50 or more cars with a total of 10,000 t of
coal or more. Bottom dump and rotary dump rail cars
[100 t (91 tm) capacity] are typically used. These high
capacity rail cars are generally not uncoupled from the
time they are loaded at the mine until they arrive at
the plant. In 1999, coal accounted for 44% of the rail
industry’s total freight tonnage and 22% of the revenues for Class I railroads.6
Rail transport provides for the movement of large
quantities of coal over distances ranging from 10 to
1500 mi (16 to 2414 km).7 Dedicated service between
one mine and the steam generating plant simplifies
management of coal deliveries. Improvements in coalcarrying capacity in rail cars and more powerful locomotives have resulted in higher efficiency in rail
transport. In comparison to rail cars in the 1930s,
today’s coal car carries double the capacity.
The advantages of rail transport are offset slightly
by the restricted rail access. Generally only one rail
line is available to transport coal from a mine or to a
specific steam generating plant. The installation of
dedicated rail lines must be included as part of the cost
of the coal handling and storage system. Rail spurs to
a specific mine location are useful only for the life of
the mining activity. Transit time is typically on the
order of 4 to 20 days.7 The rail car unloading system
and intermediate storage facilities must be designed
to quickly process the cars to avoid demurrage (delay)
charges at the plant.
Railroads will continue to play a significant part in
coal transportation as long as coal is used to generate
electricity and remains the greatest and single-most
important commodity.
Barge
Barge transport of coal is the most cost-effective
alternative to rail or truck. Approximately 11% of all
coal shipped to electric generating plants in the U.S.
is delivered by barge. According to the U.S. Army
Corps of Engineers (COE), coal is the largest single
barge commodity. Coal traffic accounted for 176 million tons of the total annual barge tonnage in 1990
(623 million tons).8
The cargo capacity difference between the three
major transportation methods for carrying coal is
shown below:
1 Barge = 15 Rail Cars = 58 Trucks
A key to barge efficiency is the ability of barges to
carry cargo many times their own weight. Additionally, less energy is expended to move cargo by barge
than by rail car or truck. There are several styles of
barges used for transporting various types of cargo,
but standard open-topped jumbo hopper barges are
commonly applied to coal transport.9 (See Fig. 11.)
Export coal is shipped on the Great Lakes by large
bulk carrier ships called colliers, but barges transport
coal within the U.S. by using inland and intracoastal
waterways. The major waterways for coal traffic in the
U.S. are the Ohio, Mississippi and Black WarriorTombigbee Rivers. The quantity of coal shipped in a
Table 4
Distribution of Coal Transportation
Methods for Electricity Generation
(Thousand Short Tons) in the U.S. (2002)5
106 t/yr
106 tm/yr
% of Total
Rail
Barge
Truck
Conveyor/pipeline/
tramway
Other water
shipping methods
615
97
81
558
88
74
70
11
9
79
72
9
11
10
1
U.S. totals
883
802
100
Method
Steam 41 / Solid Fuel Processing and Handling
Fig. 11 Typical barge transport for large quantities of coal.
12-9
The Babcock & Wilcox Company
single tow or string of barges is determined by the lock
requirements of the river system being navigated. For
example, on the Ohio River system, a tow of three
barges wide by five barges long is commonly used because of the River’s lock requirements.10 However, on
the relatively unobstructed lower Mississippi, tows of
30 barges are not uncommon.
There is a significant degree of competition and transport prices are generally stable. Some cost differences
between upstream and downstream travel are common.
Barge transportation of coal to steam generating
plants is constrained by the location and characteristics of the available river systems. Close proximity to
waterways for direct loading and unloading is needed
for efficient barge transportation. Barge delivery must
be supported by truck, rail, or belt conveyor
transloading at the mine location or the steam generating plant. The natural river network is not always
the most direct route and may result in increased delivery time. The channel width and seasonal variability in water level are natural limitations for barge traffic. River lock sizes and condition of repair may restrict
the maximum permitted tow size. Delays due to deteriorating locks and congestion may be significant on some
river systems. In some areas, lock repair costs are recovered through a surcharge on tonnage shipped through
the lock.
Barges are not self-unloading. Barge unloading can
consist of a simple clam-shell crane discharging onto
a take-away conveyor. For large capacities, high-rate
automated bucket-elevator unloaders are often used.
Capacities of these systems range from several hundred to several thousand tons per hour. System capacity must be considered to limit demurrage time for
barge delivery and unloading at large power stations.
The capital investment required for the unloading
facilities may restrict barge deliveries to plants using
more than 50,000 t/yr.7
Truck
For power plants located near mines, trucks loaded
at the mine deliver coal directly to the power plant
storage site. In 2002, trucking accounted for 9% of the
total tonnage of coal delivered to electric generating
plants.5 The truck deliveries may unload directly onto
the coal storage pile or into hoppers feeding the automated conveying system for distribution to the storage pile or silos.
Trucking also plays an important role in both rail
and barge transport. Many times coal transported by
rail or barge is first trucked to the loading dock or involves truck transfer at the mine. Highway trucks
typically carry 15 to 30 t (14 to 27 tm) of coal over distances up to 70 mi (113 km). Off-road vehicles can
handle 100 to 200 t (91 to 181 tm) over a range of 5 to
20 mi (8 to 32 km) at mine-mouth generating stations.
Trucking is the most flexible mode of coal transportation. It is relatively easy to adjust to changes in
demand to meet the generating plant’s variable supply requirements. The short haulage distances, and
therefore short delivery times, can be used to minimize
storage requirements at the generating plant. Trucks
are simple to unload and a minimum of on-site han12-10
dling and distribution is needed. Use of the existing
highway infrastructure provides for flexible delivery
routes and reduces travel restrictions associated with
rail and river transport. Trucks are very efficient for
short haulage distances and for smaller generating
plants. Trucking is the least capital intensive mode of
transporting coal and a high degree of competition
exists.
Truck transportation is characterized by a high
operating cost per ton mile relative to barge or rail
transport. Practical haulage distances are usually limited to 50 mi (80 km). State and local transportation
regulations often limit loads to 25 t (23 tm) or less. A
large generating plant would require a significant
amount of truck traffic and congestion at the delivery site may be severe. Truck deliveries require the
highest degree of monitoring at the plant. Frequently,
every truck must be weighed.
Continuous transport
Coal may be transported from the mine to the generating plant by continuous belt conveyors, slurry
pipelines or tramways. In 2002, continuous transport
systems accounted for approximately 9% of the total
coal deliveries.5 Belt conveyors are normally limited
to lengths of 5 to 15 mi (8 to 24 km). The coal delivery
rate is a function of the belt width, operating speed,
and the number of transfer points. Only one major coal
slurry pipeline is in operation. The 273 mi (439 km)
long Black Mesa Pipeline runs from a mine in Arizona
to a generating plant in Nevada. The coal transport
rate is determined by the pipe diameter, slurry velocity and solids loading.11
Continuous systems can move large amounts of coal
cost-effectively over short distances. Often, continuous systems can be used where the terrain limits the
use of other modes of transport. Social and environmental impacts are minimal.
The application of continuous transportation systems is limited by the proximity to the generating
plant, a low degree of operating flexibility due to the
fixed carrying capacity, the inflexibility of the loading and discharge locations, high capital cost, and a
relatively high energy consumption per ton mile of
coal delivered. Pipeline builders must overcome significant opposition in obtaining rights of way and
water resource allocation. The added costs associated
with dewatering the coal at the generating plant must
also be considered.
Coal handling and storage
at the power plant
Bulk storage of coal at the power plant is necessary
to provide an assured continuous supply of fuel. The
tonnage of coal stored at the site is generally proportional to the size of the boiler. A 100 MW plant burns
approximately 950 t/d (862 tm/d), while a 1300 MW
plant requires approximately 12,000 t/d (10,887 tm/d).
For most power plants, a 30 to 90 day supply is stored
at the plant to assure adequate supply through any
delivery interruptions. Public utilities in the U.S. are
required by law to maintain minimum supplies. HowSteam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
ever, stored coal represents substantial working capital and requires land that may be otherwise productive. Economic considerations are a key factor in determining when to purchase coal and how much coal to
store at the plant. Additional considerations, such as
the changes to coal characteristics due to weathering,
restrict the maximum amount of coal stored on site.
For smaller, industrial boiler applications, bin or silo
storage may be preferred over stockpile storage. The
advantages of bin storage include shelter from the
weather and ease of reclamation. Prefabricated bins
with capacities holding several hundred tons are com-
mercially available as are large, field-erected concrete
silos of several thousand tons capacity. In regions with
severe winter weather, even large power stations use
silo storage to facilitate easier reclamation.
The complexity of the coal storage and handling
operations increases in proportion to the size of the
steam generating plant. Efficient techniques have
been developed for large and small plants. The components of a sophisticated coal storage and handling
system for a large, 1000 MW electric generating plant
are illustrated in Fig. 12. Coal is delivered in self-unloading rail cars and is transferred to a large stock-
Fig. 12 Typical coal handling system and subsystems for a 1000 MW coal-fired power generation plant.
Steam 41 / Solid Fuel Processing and Handling
12-11
The Babcock & Wilcox Company
pile. An automatic reclaim system recovers coal from
the stockpile for crushing and distribution to in-plant
storage silos. The system is automated and a two person crew can handle 7000 t/d (6350 tm/d) of coal. All
the equipment from the reclaim feeders to the in-plant
silos to the boiler is controlled by the central control
room operator.
The storage and handling operations of a utility
boiler are depicted in the chapter frontispiece.
Raw coal handling
An extensive array of equipment is available for
unloading coal at the plant site and distributing it to
stockpile and bin storage locations. Equipment selection is generally based on the method of coal delivery
to the plant, the boiler type, and the required coal
capacity. For small plants, portable conveyors may be
used to unload rail cars, to reclaim coal from yard storage piles, and to fill bunkers. Larger plants require
dedicated handling facilities to meet the demand for a
continuous fuel supply. However, even relatively small
plants may benefit from the improved plant appearance,
cleanliness and reduced coal handling labor requirements associated with mechanical handling systems.
The coal handling system components are determined by the design and requirements of the boiler.
If coal particle size is not specified to the coal supplier,
then a crusher is normally integrated into the system
to generate a uniform top size coal feed to the pulverizer or feeder equipment of circulating fluidized bed
(CFB) or stoker-fired boilers. The system normally
includes a magnetic separator to remove misplaced
mining tools, roof support bolts, and other metallic
debris that could damage the pulverizer or feeder
equipment. Crushing and tramp metal removal needs
are generally less critical for stoker-fired boilers than
for pulverized coal and CFB units.
The coal handling system capacity is determined by
the boiler’s rate of coal use, the frequency of coal deliveries to the plant, and the time allowed for unloading. In most large plants, only four to six hours per
day are dedicated to unloading of coal deliveries.
Rail car unloading
Rail cars can either be of the bottom discharge or
rotary dump type. In automatic rotary car dumping
systems, the rail cars are hydraulically or mechanically clamped in a cradle, and the cradle is rotated
about a rotating track section so the coal falls into a
hopper below the tracks. The rail cars have special
swivel couplings to allow the dumping to be completed
without uncoupling the cars. The rotary dump system
advantages of short cycle time and high capacity are
offset by a relatively high capital cost.
With bottom dump cars, unloading is relatively
simple when the coal is dry and free flowing. However, high surface moisture can cause the coal to adhere within the car and, in cold weather, freeze into a
solid mass. In hot, dry weather, high winds can create severe dust clouds at the unloading station unless
special precautions are taken. The coal supplier frequently sprays the coal with oil or an anti-freezing
chemical such as ethylene glycol as the car is loaded
12-12
to settle the fines and to improve handling in freezing weather. The treatment does not appreciably affect
combustion or cause problems in the pulverizers. There
is also some evidence that the treatment may reduce
adherence and hangups in bunkers and chutes.
A simple bottom dump rail car unloading system
that includes a crusher and magnetic separator is illustrated in Fig. 13. A screw conveyor is used to distribute coal along the length of the bunker. The capacity of the bucket elevator generally limits this system to relatively small plants.
A rotary dump rail car unloading and handling sysMagnetic Belt
Separator
Concrete
Bunker
Pressurized
Coal Valve
Continuous
Bucket Elevator
Gravimetric
Feeder
Grating
Track
Hopper
Discharge
Valve
Apron
Feeder
Crusher
To
Pulverizer
Fig. 13 Rail car dumping system for a small power plant.
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
Bunker Roof Line
Transverse and
Tripper Belt
Bunker
Pressurized
Coal Valve
Car Dumper
Yard
Repair
Shop
Coal
Breaker
Gravimetric
Feeder
Discharge
Valve
To
Pulverizer
Conveyor Belt
Housing
Fig. 14 Rail car unloading and coal handling system for a large
power plant.
tem for a larger plant is shown in Fig. 14. Coal from
the car dump hopper is fed to a rotary breaker, where
the coal breaks into smaller pieces as it is tumbled and
passes through a screen shell. The broken coal can
then be conveyed directly to the storage bunkers, or
to the stockpile.
Barge unloading
The simplest barge unloader consists of a clamshell
bucket mounted on a fixed tower. The barge is positioned under the bucket and is moved as necessary to
allow emptying. With this type of unloader, the effective grab capacity of the buckets is only 40 to 50% of
the nominal bucket capacity. A shore mounted bucket
wheel or elevator unloader can increase the efficiency
and capacity of this unloading operation. Modern
ocean-going vessels are often equipped with a bucket
wheel for self-unloading.
Truck unloading
Trucks may dump coal through a grid into a storage hopper. This grid separates large pieces of wood
and other trash from the coal. At some plants, the
trucks are directed to a temporary storage area, where
coal from various mines can be blended prior to crushing or feeding to the boiler.
An effective truck delivery and coal handling system
for a small to medium size (30 to 300 t/d) stoker coal-fired
boiler is illustrated in Fig. 15. This system provides site
preparation of the coal along with tramp metal removal.
Stockpile storage
Careful consideration should be given to storage pile
location. The site must be conveniently accessible by
barge, rail or truck. Frequently, provisions must be
made for more than one method of coal delivery. The
site should be free of underground power lines. Other
underground utilities that would not be accessible
after the storage pile is constructed must also be
Steam 41 / Solid Fuel Processing and Handling
avoided. A thorough evaluation and environmental
survey of the proposed site topography should include
analysis of the soil characteristics, bedrock structure,
local drainage patterns, and flood potential. Climatic
data, such as precipitation records and prevailing wind
patterns, should also be evaluated. Protection from
tidal action or salt water spray may be needed in
coastal areas. The potential effects of water runoff and
dust emissions from the pile must be considered. Site
preparation includes removing foreign material, grading for drainage, compacting the soil, and providing
for collection of site drainage.
The shape of a stockpile is generally dependent on
the type of equipment used for pile construction and
for reclaiming coal from the pile. Conical piles are
generally associated with a fixed stacker while a radial stacker generates a kidney shaped pile. A rail
mounted traveling stacker can be used to form a rectangular pile. Regardless of the shape of the pile, the
sides should have a shallow slope.
Bituminous coal, subbituminous coal and lignite
should be stockpiled in multiple horizontal layers. To
reduce the potential for spontaneous combustion, coal
piles are frequently compacted to minimize air channels. These channels can function as chimneys that
promote increased air flow through the pile as the coal
heats. For bituminous coal, an initial layer, 1 to 2 ft
(0.3 to 0.6 m) thick, is spread and thoroughly packed
to eliminate air spaces. A thinner layer is required for
subbituminous coal and lignite to assure good compaction. Care should be taken to avoid coal pile size segregation by blending coal during pile preparation.
For long-term storage (see Fig. 16), the top of the
pile may be slightly crowned to permit even rain runoff. All exposed sides and the top may be covered with
a 1 ft (0.3 m) thick compacted layer of fines and then
capped with a 1 ft (0.3 m) layer of screened lump coal.
It is not practical to seal subbituminous and lignite
piles with coarse coal because the coarse coal would
Fuel Unloading Hopper
Tramp Metal
Detector
Slide
Gate
Isolation
Valves
Crusher
Tramp Metal
Detector
Magnetic
Separator
Silo Transfer
Drag Conveyor
Unloading
Belt Feeders
Unloading
Conveyor
Plant
Conveyor
Fuel
Silo
Pneumatic
Operated
Shutoff
Gates
Gravimetric
Feeders
Slide Gate
Isolation
Valves
To
Boiler
Fig. 15 Typical coal handling system for truck delivery.
12-13
The Babcock & Wilcox Company
Fig. 16 Long-term coal storage – typical example of thorough packing
with minimal size segregation. This pile contains about 200,000 t of coal.
weather and break apart to a smaller size in a short
period of time. At smaller industrial plants, where
heavy equipment for compaction can not be justified,
a light coating of diesel oil can help to seal off the outer
surface of the pile.
The quantity of coal stored in a stockpile can be estimated using geometry and some assumptions about
the characteristics of coal. The volume of the pile can
be estimated based on its shape. Approximate values
for the material’s bulk density and its angle of repose are
required to complete tonnage calculations. Both of these
parameters are particle size dependent. For typical utility storage pile applications, a loose coal bulk density of
50 lb/ft3 (801 kg/m3) and a 40 deg angle of repose may
be used. For well compacted piles, a bulk density of 65
to 72 lb/ft3 (1041 to 1153 kg/m3) is more appropriate.
Storage pile inspection and maintenance Visual inspections for hot spots should be made daily. In wet
weather, a hot area can be identified by the lighter
color of the surface coal dried by escaping heat. On
cold or humid days, streams of water vapor and the
odor of burning coal are signs of heating or air flowing through the pile. Hot spots may also be located by
probing the pile with a metal rod. If the portion of the
rod in contact with the coal is too hot to be held as it is
withdrawn, the coal temperature is dangerously high.
It is also important to rotate areas of the storage pile
from long to short term storage on a planned schedule.
This minimizes harmful degradation of the coal.
Bulk storage reclaim and transfer The specific sys-
12-14
tem for reclaiming the stored coal from stockpiles depends upon plant size and economic evaluation of
operating and capital costs. For higher capacity systems of around 200 t/h (181 tm) and greater, automated under-pile or over-pile reclaim systems are
used. Under-pile reclaim systems can consist of underpile hoppers with vibrating or belt feeders discharging onto a take-away belt conveyor. The belt conveyor
travels at an incline through an underground tunnel
until exiting the ground surface and is routed to the
desired elevation. Over-pile reclaimers can be a variety of traveling bucket wheels or flight reclaimers that
discharge onto an above ground take-away belt conveyor. For lower capacity systems, reclaim can be by
bulldozer or front loader into a hopper feeding a takeaway conveyor.
A variety of mechanical conveyors are used for
transfer conveying. These include belt conveyors, drag
(or flight) conveyors, bucket elevators, and screw conveyors. Belt conveyors are generally limited to an incline angle of 15 to 16 deg from horizontal to avoid
roll-back of coal lumps on the traveling belt. Advancements in belt conveyor technology have yielded designs capable of greater incline angles and lateral
routing, however at greater capital cost. Bucket and
drag conveyors provide greater elevation capabilities
over short horizontal distances, but mechanical conveyors inherently have greater wear and associated
maintenance costs than belt conveyors. Screw conveyors are utilized primarily for horizontal, short-length
conveying in low capacity applications. Wear and maintenance costs are also higher with screw conveyors.
Silo storage
Silos are often used where severe winter conditions
can justify the added cost. Power plants with limited
land space for large storage piles can also justify the
expense. Silos are typically large field-constructed
concrete structures of the slip-form or jump-form design. Large silos at central power stations can store
10,000 to 20,000 t (9710 to 18,144 tm) and can be
grouped together for necessary storage capacity. Multiple silos also provide the ability to empty one and
perform maintenance while supporting operations.
The silo hopper design must ensure adequate coal flow
to avoid hide-out and coal hang-ups in the silo.
Bunker storage
Coal bunkers provide intermediate, short term storage, ahead of the pulverizers or other boiler coal feed
equipment. Bunkers (also known as day-bins) are
normally sized for 8 to 24 hours of fuel supply at maximum boiler operation. Normally, there is one bunker
for each pulverizer and boiler coal feed point, but it is
not uncommon to see one bunker with two or more
outlets, feeding multiple points.
Bunker design
Once constructed, the coal bunkers are an integral
part of the boiler house structure. Any redesign or modification to the bunkers can be expensive and difficult,
if not impossible. The bunkers also must be designed
for reliable flow of the stored fuel. (See Fig. 17.)
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
Fig. 17 Four commonly used shapes in coal bunker design.
The flowability characteristics of coal are important
parameters in the design of the hoppers and chutes
in the coal handling system and boiler feed systems.
A shear cell test device measures the resistance of coal
to slide in shear action against itself, and measures
the resistance of the material to slide on a surface such
are steel, stainless steel or other common materials.
This testing can be performed after the coal has consolidated for several days, to simulate storage of the
coal in a silo or bunker. From this data, the optimum
combination of hopper slope angle and minimum outlet opening can be determined to assure reliable flow.
This data can also be used to determine critical chute
angles to assure continuous sliding flow through the
chute, regardless of the cohesive nature of the coal and
tendency to adhere to chute walls. Other factors that
are utilized in optimizing the hoppers or chutes are
the flowability of the coal on varying surfaces. This
information is used in determining the most economic
material to use for fabrication of the hoppers or chutes,
or the liners applied. Materials such as carbon steel,
polished and unpolished stainless steel, abrasion resistant steels, abrasion resistant plastic liner materials, and ceramic are just some of the materials routinely tested.
In bunkers or silos without proper design, reduced
flow or even pluggage can occur. This is the result of
the coal adhering to the hopper walls, especially at the
transition from the straight walls to the angled hopper. This build-up can form a channel of limited crosssection through which the material flows. As the material continues to build-up, this flow channel of small
cross section can bridge over and total pluggage occurs. Flow aids such as air blasters and bin vibrators
Steam 41 / Solid Fuel Processing and Handling
can reduce this pluggage, but many times have limited success. Even with continuous flow, some residual
material will remain in an emptied bunker due to the
adherence in the straight wall to sloped hopper zone.
This residual material can result in bunker fires due
to spontaneous combustion. This is especially problematic with higher volatile coals, such as Powder River
Basin coals.
With proper flow testing and design, complete emptying of the bunker or silo is assured each time the
level is drawn down. The bunker or silo will be designed for funnel flow or mass flow. In funnel flow
there is a stagnant zone (where the material does not
flow) where the bunker vertical wall transitions to the
sloped hopper wall. However, when the level in the
vessel is drawn below this region and the pressure is
reduced on this material, it releases from the hopper
wall and collapses on the material level in the hopper. In a mass flow design, the material draws down
uniformly throughout the vessel, in a pattern down
the vertical walls, then transcends down the sloped
hopper walls. Mass flow requires much steeper hopper slopes. The cohesive nature of the coal and ability
to adhere to the vessel walls determine the design. A
third design, called expanded flow, combines these two.
The hopper is in two sections, the upper section funnel flow and the lower section mass flow.
Downspout design Flow testing data can also be
used to optimize downspout design. Downspouts
should be circular, short and as steep as possible, preferably vertical. Reductions in cross-sectional area and
sudden changes in direction should be avoided.
In pressurized pulverizer feed applications, or coal
feed to the pressurized location of a CFB boiler, special consideration must be given to downspout design
because the coal inside the downspout also serves as
the seal against the pressurized location and air or gas
backflow to the bunker. A minimum required height
(seal height) and a sealed downspout/feeder system
are required. A typical bunker to pulverizer system is
shown in Fig. 18. Vertical, constant-diameter downspouts connect the bunker to the feeder and the feeder
to the pulverizer. Appropriate couplings and valves
complete the system.
Feeder design
Feeders are used to control coal flow from the storage bunker at a uniform rate. Feeder selection should
be based on an analysis of the material properties
(maximum particle size, particle size distribution, bulk
density, moisture content and abrasiveness), the desired flow rate, and the degree of flow control required.
A variety of feeder designs have been used for coalfired applications with increasing sophistication as
more accurate control of coal flow has become necessary. Feeders for modern pulverized coal and CFB
boiler applications can generally be classified as volumetric or gravimetric.
Volumetric feeders, as the name implies, are designed to provide a controlled volume rate of coal to
the pulverizer. Typical examples include drag, table,
pocket, apron and belt feeders. Belt feeders, perhaps
the most accurate type, have a level bar to maintain
12-15
The Babcock & Wilcox Company
or 2) fine tuning the belt speed while the cross-sectional area remains constant. The overall set point flow
rate is adjusted by varying the base belt speed.
Fig. 18 Arrangement of bunker discharge to pulverizer showing
typical feed system.
the flow of coal at a constant height and width while
the belt speed sets the velocity of the coal through the
opening. As with all volumetric designs, however, the
belt feeder does not compensate for changes in coal
bulk density. This results in variations in the energy
input to the pulverizer and ultimately to the burners,
for a pulverized coal unit, or to the bed of a CFB unit.
Gravimetric feeders (see Fig. 19) compensate for
variations in bulk density due to moisture, coal size
and other factors. They provide a more precise weight
flow rate of coal to the pulverizer or CFB boiler bed
feed point and, therefore, more accurate heat input
to the burners and boiler. Even variations in coal moisture have a larger relative impact on coal bulk density than on heating value. Therefore, modern gravimetric feeders offer an accurate, commercially accepted
technology to control fuel and heat input to the burners
and boiler. This can be a very significant issue where
more accurate control of fuel/air ratios is needed to: 1)
minimize the formation of nitrogen oxides (NOx), 2) control furnace slagging, and 3) maximize boiler thermal
efficiency by reducing excess air levels. (See Chapter 14.)
In the most common gravimetric feeder system, coal
is carried on a belt over a load cell that monitors the
coal weight on the belt. The feedback signal is used
to maintain the weight flow by either: 1) adjusting the
height of a leveling bar to control the cross-sectional
coal flow area while the belt speed remains constant,
12-16
Coal blending
When coals from two or more sources fuel a single
boiler, effective coal blending or mixing is required to
provide a uniform feed to the boiler. The use of multiple coals can be driven by economics, coal sulfur content to meet emission requirements, and/or the effects
of different coals on boiler operation. The goal of effective blending is to provide a coal supply with reasonably uniform properties that meet the blend specification typically including sulfur content, heating
value, moisture content, and grindability.
Coal blending may occur at a remote location, such
as the mine or coal washing/preparation facility, or at
the steam generating plant. Off-site blending eliminates the need for separate coal storage and additional
fuel blending facilities. Steam plant on-site blending
may be accomplished through a variety of techniques.
It may be sufficient to provide separate stockpiles for
each coal source and use front-end loaders to transfer the appropriate quantities to a common pile or hopper for blending prior to crushing. Coal may also be reclaimed from the various stockpiles using under-pile or
over-pile reclaim systems transferring to a common conveyor belt. Coal from the various sources may be stored
in separate bins with a feeder from each bin used to
meter the desired quantities onto a common transfer belt.
On-site blending provides more flexibility in coal sourcing and in adjusting to actual on-site coal variations.
Fig. 19 Typical gravimetric feeder (courtesy of Stock Equipment
Company, Inc.).
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
Particular care must be maintained to ensure proper
and complete blending. Significant variations in the
blended coal can have a major impact on operation of
the pulverizers, burners and sootblowers of a pulverized coal unit, and on bed temperature control of a CFB
boiler. If uniform blending does not occur, pulverizer
performance can deteriorate (see Chapter 13), the
boiler may experience excessive slagging and fouling,
and electrostatic precipitator particulate collection efficiency may decline, among other potential problems.
Resolution of common coal
handling problems
Dust suppression
Water, oil and calcium chloride (CaCl2) are common
agents used to suppress fugitive dust emissions on
open coal stock piles and during loading into open
ground hoppers. A water or oil mist may be sprayed
into the discharge area of rail cars as well as open discharges of conveyors onto storage piles. The water or
oil spray reduces dust emissions by causing the dust to
adhere to larger pieces of coal and by forming agglomerates that are less likely to become airborne. Use of
CaCl2 should be limited because of its potentially harmful side effects on boiler operation. (See Chapter 21.)
Dust collection at the transfer points from conveyor
to conveyor in the coal transport system is performed
by a vacuum collection system. These systems consist
of a blower that draws the airborne dust from the discharge chutes, transfer chutes, and loading chutes of
a transfer point. The enclosed chute arrangement is
essentially maintained at a negative pressure. The
dust laden air flow is routed through a bag filter to
collect the dust, with the air discharging to the atmosphere. The collected dust is discharged from the bag
filter hopper through a rotary seal to the continuing
coal conveyer, silo or bunker. For coals with high volatility, the dust is collected with water and sluiced to
waste or reclaim to avoid fire or explosion. These dust
collection systems can also evacuate the methane that
is generated in bunkers and silos.
Oxidation
Coal constituents begin to oxidize when exposed to
air. This oxidation may be considered as a very slow,
low temperature combustion process, because the end
products, carbon dioxide (CO2 ), carbon monoxide,
water and heat, are the same as those from furnace
coal combustion. Furnace combustion of coal may be
viewed as a very rapid oxidation process. Although
there is evidence that bacterial action causes coal
heating, the heating primarily occurs through a
chemical reaction process. If spontaneous combustion
is to be avoided, heat from the oxidation should be
minimized by retarding oxidation or removing the
generated heat.
Coal oxidation is primarily a surface action. Finer
coal particles have more surface area for a given volume and, therefore, oxidize more rapidly. Freshly
crushed coal also has a high oxidation rate. Coal’s
oxygen absorption rate at constant temperature deSteam 41 / Solid Fuel Processing and Handling
creases with time. Once a safe storage pile has been
established through compaction to minimize entrapped
air, the rate of oxidation has been slowed considerably.
Coal should be kept in dead storage undisturbed until it is to be used.
The rate of oxidation also increases with moisture
content. High-moisture western coals are particularly
susceptible to self-heating.
Frozen coal
The difficulties associated with handling frozen coal
may be avoided by thermally or mechanically drying
the fines following coal preparation. Spraying the coal
with an oil or anti-freezing solution mist is one
method, but this can have a negative effect on combustion and emissions performance.
Permanent installations for thawing frozen coal in
rail cars include steam-heated thawing sheds, oil-fired
thawing pits, and radiant electric thawing systems.
Steam-heated systems are reliable and efficient, but
are relatively expensive. Oil-fired systems that prevent direct flame impingement on the cars provide
reliable operation and rapid thawing. Electric thawing systems are used at many plants that handle unit
train coal shipments.
The coal handling system must also be protected. The
chutes and bunker/silo hoppers can be fitted with heating coils to avoid hang-up due to coal freezing on the
metal surfaces. Heating of the buildings enclosing these
transfer chutes or hoppers should also be considered.
Frost and ice can form on belt conveyor surfaces.
As coal is loaded onto the conveyor, it can skid on the
ice and not convey. Systems using ethylene glycol or
salt applications can help alleviate this problem.
Coal pile fires
A primary concern in coal storage is the potential
for spontaneous combustion in the pile as a result of
self-heating properties.
A coal pile fire may be handled in several ways depending on its size or severity. The hot region should
be isolated from the remainder of the pile. This may
be accomplished by trenching and sealing the sides
and top of the hot area with an air tight coating of
road tar or asphalt. Caution should be used in working the hot area with heavy equipment as subsurface
coal combustion can affect the stability and load bearing characteristics of the pile. Water should not be used
unless it is necessary to control flames. Pouring water
on a smoldering pile induces more pronounced channeling and promotes greater air flow through the pile.
Bunker flow problems
Bunkers may be equipped with ports located near
the outlet. These ports permit the use of air lances for
restoring flow. Air lances may also be effectively used
from the top of the bunker. Small boring machines can
be mounted above the bunker to loosen coal jams at
the outlet. Service companies can be contracted to
remove flow obstructions using boring tools. Air blasters or air cannons have been successfully used to promote flow of coal in bunker hoppers. If there is any
possibility of fire, these devices must be charged with
12-17
The Babcock & Wilcox Company
nitrogen or carbon dioxide to prevent triggering a dust
explosion. Bin vibrators can be used to promote flow
similar to air blasters and cannons. Air blasters and
cannons along with bin vibrators must be carefully
evaluated prior to installation as these devices can
further consolidate coal accumulated in the vessel.
Flow testing can be performed to determine if the
current hopper design can be economically modified
for reliable flow of a poorer quality coal. The application of different hopper liner materials can provide a
simple solution to coal flow problems.
Bunker fires
A fire in a coal bunker is a serious danger to personnel and equipment and must be dealt with
promptly. The coal feed to the bunker should be
stopped. An attempt should be made to smother the
fire while quickly discharging the coal. Continuity and
uniformity of the hot or burning coal discharge from
the bunker is especially important; interruption of coal
flow aggravates the danger. The bunker should be emptied completely; no fresh coal should be added until the
bunker has cooled and the cause of the fire determined.
The fire may be smothered using steam or carbon
dioxide. CO2 settles through the coal and displaces
oxygen from the fire zone because it is heavier than
air. Permanent piping connections to the bottom of the
bunker may be made to supply CO2 on demand. The
CO 2 should fill the bunker, displace the air and
smother the fire.
It is highly desirable to completely extinguish the fire
before emptying the bunker. This is rarely possible because of boiler load demands and the difficulty of eliminating air flow to the fire. However, the use of steam or
CO2 to smother the fire can minimize the danger.
Bunker flow problems that result in dead zones may
contribute to fires. Thermocouples installed in the
bunker can monitor the temperature of the stored coal.
The coal feed to the bunkers may also be monitored
to prevent loading the bunker with hot coal.
Additional remarks on dealing with bunker fires in
pulverized coal plants are provided in Chapter 13.
Environmental concerns
Water percolating through the coal storage pile can
become a source of acidic drainage that may contaminate local streams. Runoff water must be isolated by
directing the drainage to a holding pond where the
pH may be adjusted. (See also Chapter 32.)
Airborne fugitive dust from stockpiles and adjacent
haul roads creates a public nuisance, has potentially
harmful effects on surrounding vegetation, and may
violate regulated dust emission standards. To satisfy
environmental regulations, plant haul roads are normally watered frequently during hot, dry, dust seasons.
12-18
Alternate solid fuel handling
Economic and environmental concerns have led to
increasing steam generation from solid fuels derived
from residential, commercial and industrial by-products and wastes. Key among these are municipal solid
waste (MSW), wood and biomass as discussed in
Chapters 29 and 30. The properties of these solid fuels require storage, handling and separation considerations different from those applied to coal.
MSW can either be burned with little pre-combustion processing (mass burn) or as a refuse-derived fuel
(RDF). As-received refuse for mass-burn units is delivered to the tipping area and stored in an open concrete storage pit. The refuse pit is usually enclosed and
kept under a slightly negative pressure to control
odors and dust emissions. The tipping bay is designed
to facilitate traffic flow based upon the frequency of
deliveries and the size of the delivery trucks or trailers. The pit is usually equipped with a water spray
system to suppress fires that may arise in part due to
heat generated from decomposition of the refuse. An
overhead crane is used to mix the raw MSW in the
storage pit, to remove bulky items and to transfer
material to the boiler feed charging hoppers. Large
objects and potentially explosive containers are located
and removed prior to combustion. (See Chapter 29.)
A full capacity spare crane is recommended. Storage
capacity is typically three to five days to accommodate
weekends, holidays and other periods when refuse
delivery may not be available. Longer term storage
of refuse is not normally recommended.
MSW may be processed to yield a higher and more
uniform Btu, lower ash RDF. The degree of processing required is determined by economics and by the
fuel properties necessary for efficient boiler operation.
MSW is usually delivered to an enclosed receiving
floor. Front-end loaders can be used to spread the
refuse, remove oversized and potentially dangerous
items and feed the MSW to the RDF processing system as needed. RDF processing includes an integrated
system of conveying, size reduction, separation, ferrous and non-ferrous metal recovery, sizing and other
equipment discussed in depth in Chapter 29. MSW
may be processed into RDF at the power plant site or at
a remote location. The selection is based upon a number
of economic factors, but operation of the RDF processing system at the boiler site typically will enhance availability to support uninterrupted steam generation.
Wood, forestry and agricultural wastes generally
consist of bark, sawdust, saw mill shavings, lumber
rejects, raw tree trunks and prunings, and straw.
Material is generally shipped by truck to the steam
generator site near the source. Material can be
dumped directly on the storage pile or an unloading
facility can be used. The unloading and handling
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
equipment must be designed to handle very abrasive
material under extremely dusty conditions. Wood
products can be stored in large outdoor piles or inside
bins or silos. This fuel is not typically stored in piles
for more than six months or in silos or bins for more
than three to five days. Wood is typically screened to
remove oversized material for further size reduction.
Oversized material is reduced by a shredding machine,
or hog, and either returned to storage or sent directly
to the combustor. Mechanical belt conveyors are the
most popular method of transporting the fuel on site,
although pneumatic systems can be effective with a
finely ground, clean fuel such as sawdust. Tramp iron
is usually removed by a magnetic separator. This
material is fibrous and very stringy, so careful evaluation must go into the design and selection of the fuel
handling and storage system. While most modern
wood-fired boilers can burn materials with a moisture
content of up to 65% as-received (see Chapter 30), predrying may be required. Mechanical hydraulic presses
or hot gas drying, or both, are used.
Economics
The selection of the fuel source, degree of cleaning,
and transportation system are closely tied to providing the lowest plant fuel cost. The selections must not
be made in isolation, but in concert with evaluating
the impact of the specific fuel on the boiler and bypass system operation, and the environment. For example, use of a new less expensive fuel may result in
significant deterioration in boiler performance and
availability due to more severe slagging and fouling
tendencies of the flyash. (See Chapter 21.) The relative contributions of coal cleaning, transportation and
base fuel price vary widely.
References
1. Freme, F., “U.S. Coal Supply and Demand: 2003 Review,” United States Energy Information Agency, Department of Energy, Washington, D.C., 2004.
2. Bonskowski, R., “The U.S. Coal Industry in the 1990s:
Low Prices and Record Production,” United States Department of Energy, Washington, D.C., September, 1999.
3. International Energy Annual 2001, United States Department of Energy, Energy Information Agency, Washington D.C., March, 2003.
4. “Report on Longwall Mining,” United States Department of Energy, Energy Information Agency, Washington,
D.C., 1994.
5. “Coal Distribution Report,” Form E1A-6A, United
States Department of Energy, Energy Information Agency,
Washington, D.C., 2002.
6. “The Rail Transportation of Coal,” Vol. No. 3, Policy and
Economics Department of the Association of the American
Railroads, January, 2001.
7. Wilbur, L.C., Ed., Handbook of Energy Systems Engineering: Production and Utilization, See chapter entitled, “Coal Transportation,” by R.D. Bessett, John Wiley
& Sons, New York, New York, October, 1985.
8. “Domestic Shipping Inland Waterways,” United States
Maritime Administration (MARAD), Washington, D.C.,
2003.
9. “Advantages of Inland Barge Transportation,” CoosaAlabama River Improvement Association, Inc. (CARIA) and
the U.S. Department of Transportation Maritime Administration, www.caria.org/waterway-facts.
10. Mahr, D., “Coal Transportation and Handling,” Power
Engineering, pp. 38-43, November, 1985.
11. Edgar, T.F., Coal Processing and Pollution Control,
Gulf Publishing, Houston, Texas, 1983.
Bibliography
Elliott, T.C., Chen, K., Swanekamp, R.C., Standard Handbook of Power Plant Engineering, Second Ed., pp. 1.201.44, McGraw-Hill Company, New York, New York, 1998.
Energy Information Administration (EIA), United States
(U.S.) Department of Energy (DOE), www.eia.doe.gov,
2004.
Given, I.A., Ed., Society of Mining Engineers Mining Engineering Handbook, The American Institute of Mining,
Metallurgical and Petroleum Engineers, New York, New
York, 1973.
Heidrich, K., “Mine-Mouth Power Plants: Convenient Coal
Not Always a Simple Solution,” Coal Age, June 1, 2003.
Steam 41 / Solid Fuel Processing and Handling
Leonard, J.W., Ed., Coal Preparation, The American Institute of Mining, Metallurgical and Petroleum Engineers,
New York, New York, 1979.
Lotz, C.W., Notes on the Cleaning of Bituminous Coal,
West Virginia University, Charleston, West Virginia, 1960.
Pfleider, E.P., Ed., Surface Mining, The American Institute of Mining, Metallurgical, and Petroleum Engineers,
New York, New York, 1968.
12-19
The Babcock & Wilcox Company
Coal storage and handling facilities at a utility power plant.
12-20
Steam 41 / Solid Fuel Processing and Handling
The Babcock & Wilcox Company
Chapter 13
Coal Pulverization
The development and growth of coal pulverization
closely parallels the development of pulverized coalfiring technology. Early systems used ball-and-tube
mills to grind coal and holding bins to temporarily store
the coal before firing. Evolution of the technology to
eliminate the bins and direct fire the coal pneumatically transported from the pulverizers required more
responsive and reliable grinding equipment. Vertical
air-swept pulverizers met this need.
The first vertical air-swept pulverizer by The Babcock & Wilcox Company (B&W) was designated the
type E pulverizer, introduced in 1937. Today, B&W offers a broad line of proven B&W Roll Wheel™ pulverizers (see Fig. 1) to meet utility needs, and ball-andrace mills designated EL pulverizers (see Fig. 5) to
meet lower load utility and industrial requirements.
Both use rolling elements on rotating tables to finely
grind the coal which is swept from the mill by air for
pneumatic transport directly to the burners.
Reliable coal pulverizer performance is essential for
sustained full load operation of modern pulverized
coal-fired electric generating stations. Also, an effective
pulverizer must be capable of handling a wide variety
of coals and accommodating load swings. The B&W Roll
Wheel pulverizer, through conservative design, reserve
capacity and long grinding element life, has set the standard for high availability, reliability and low maintenance, contributing to stable boiler performance.
A key difference between much of the boiler system
and the pulverizer is that the pulverizer is sized and
operated as a mass flow machine while the boiler is a
thermal driven machine. Therefore, the heating value
of the fuel plays a key role in integrating these two
components.
Vertical air-swept pulverizers
Principles of operation
The elements of a rolling action grinding mechanism are shown in Fig. 2. The roller passes over a layer
of granular material, compressing it against a moving table. The movement of the roller causes motion
between particles, while the roller pressure creates
compressive loads between particles. Motion under
applied pressure within the particle layer causes atSteam 41 / Coal Pulverization
trition (particle breakup by friction) which is the dominant size reduction mechanism. The compressed
granular layer has a cushioning influence which reduces grinding effectiveness but also reduces the rate
of roller wear dramatically. When working surfaces in
a grinding zone are close together, near the dimensions of single product particles, wear is increased by
three body contact (roller, particle and table). Wear
rates can be as much as much as 100 times those found
Raw Coal
Inlet
Pulverized
Coal Outlet
(Typical)
Knife Gate
Discharge Turret
Stationary
Classifier
Top Housing
Conical Baffles
Spring Frame
Intermediate
Housing
Pressure Frame
Springs
Inerting Steam
Header
Primary Air
Inlet
Rotating
Throat
Assembly
Bottom
Housing
Rejects Cone
Roll Wheel
Seal Air
Supply
Cera-VAM ®
Ceramic
Lining
Roll Wheel
Assembly (3)
Grinding Ring
Segments
Ring Seat
Yoke
Pyrites Plow
(2 Total)
(Upper Shown)
Yoke Seal
Air Supply
External
Loading
Cylinder (3)
Auto-Spring™
System (Optional)
Hydraulic Connections
Pyrites Box
Removable Planetary Gear Drive
Fig. 1 B&W Roll Wheel™ pulverizer.
13-1
The Babcock & Wilcox Company
come out of suspension and fall back into the grinding zone. The finer particles remain suspended in the
air mixture and exit to the fuel conduits.
Pulverizer control
There are two input streams into an air-swept pulverizer, air and coal. Both must be controlled for satisfactory operation. Many older methods of coal flow control are still used successfully. Either volumetric or gravimetric belt feeders are the currently preferred method
of coal flow regulation. Accurate measurement of coal
flow has allowed parallel control of air and coal (Fig. 4).
Fig. 2 Roller mill grinding mechanism.
in normal pulverizer field experience. Wear from the
three body contact has also been observed in operating mills when significant amounts of quartz bearing
rock are present in sizes equal to or greater than the
grinding layer thickness.
As grinding proceeds, fine particles are removed
from the process to prevent excessive grinding, power
consumption and wear. Fig. 3 presents a simplified
B&W Roll Wheel pulverizer, showing the essential elements of a vertical air-swept design. A table is turned
from below and elements, in this case called roll
wheels, rotate against the table. Raw coal is fed into
the mill from above and passes between the rollers and
the rotating table. Each passage of the particles under the rollers reduces the size of the coal. The combined effects of centrifugal force and displacement of
the coal layer by the rollers spills partly ground coal
off the outside edge of the table. An upward flow of
air fluidizes and entrains this coal.
The point where air is introduced is often called the
throat, air port ring, or nozzle ring. Rising air flow,
mixed with the coal particles, creates a fluidized particle bed just above the throat. The air velocity is low
enough so that it entrains only the smaller particles
and percolates with them through the bed. This selective entrainment is the initial stage of size separation or classification. The preheated air stream also
dries the coal to facilitate pulverization and enhance
the combustion process.
Vertical pulverizers are effective drying devices.
Coals with moisture content up to 40% have been successfully handled in vertical mills. Higher moisture
coals could be pulverized, but the very high primary
air temperature needed would require special structural materials and would increase the chance of pulverizer fires. A practical moisture limit is 40%, by
weight, requiring air temperatures up to 750F (399C).
As the air-solids mixture flows upward, the flow
area increases and velocity decreases, allowing gravity to return the larger particles to the grinding zone
for the second stage of size separation. The final stage
of size separation is provided by the classifier located
at the top of the pulverizer. This device is a centrifugal separator. The coal-air mixture flows through
openings angled to impart spin and induce centrifugal force. The larger particles impact the perimeter,
13-2
Pulverizer design requirements
Many different pulverizer designs have been applied to coal firing. Successful designs have met certain fundamental goals and requirements:
1. optimum fineness for design coals over the entire
pulverizer operating range,
2. rapid response to load changes,
3. stable and safe operation over the entire load
range,
4. continuous service over long operating periods,
5. acceptable maintenance requirements, particularly grinding elements, over the pulverizer life,
6. ability to handle variations in coal properties,
7. ease of maintenance (minimum number of moving parts and adequate access), and
8. minimum building volume.
Fig. 3 Pulverizer coal recirculation.
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
Total Fuel
Flow Demand
Fuel Master
Selector Station
Total
Fuel Flow
Controller
Total
Fuel
Flow
Feeder
Speeds
To Other
Pulverizers
Individual
Pulverizer
Bias
Pulverizer
Master
Selector
Station
Key
Pulverizer
Bias
Pitot Tube
Differential
Pulverizer Inlet
Temperature
Primary Air
Flow Bias
Individual
Primary Air
Flow Bias
Temperature
Compensator
Minimum
Primary Air
Flow Limit
Measured Temperature
Measured Flow
Operator Hand/Auto Station
Manual Set Point Station
Measured Feeder Speed
Pulverizer
Outlet
Pulverizer
Temperature
Outlet
Temperature
Set Point
Primary
Air Flow
Controller
Coal-Air
Temperature
Controller
Air Flow
Cross
Limit
Feeder Speed
Selector Station
To Feeder Speed
Controller
Hot Air
Damper
Controller
Tempering
Air Damper
Controller
Fig. 4 Schematic of parallel cross limited pulverizer control system.
Pulverizer designs
Mill development efforts by B&W were, for many
years, based on variations of ball-and-ring (ball-andrace) grinding elements. In the 1930s, B&W introduced the type E pulverizer. During the early 1950s,
a redesign was installed and tested at a textile plant
in Lancaster, South Carolina. This design, which uses
two vertical axis horizontal rings, was designated E
(Lancaster) or EL (Fig. 5). The lower ring rotates
while the upper ring is stationary and is spring loaded
to create grinding pressure. A set of balls is placed between the rings. The force from the upper ring pushes
the balls against the coal layer on the lower ring.
Type E and EL mills have size designations which
indicate approximately the centerline diameter of the
grinding track. Type E mills have been built as large
as the E-70 with a capacity of 12.5 t/h (11.4 tm/h). Type
EL mills have been built as large as the EL-76 with a
nominal capacity of 20 t/h (18 tm/h), and with modern
enhancements, a maximum capacity of 23 t/h (21 tm/
h) is possible. Approximately 1600 E and EL mills have
been installed, with more than 1000 still in service.
The major wear parts of E and EL pulverizers are the
two rings and the balls which are made of abrasion
resistant alloys and are easily replaced.
B&W introduced the roll wheel style coal pulverizer to the North American market in the 1970s and
installed more than 1100 units during the next three
decades. B&W has continuously advanced the design,
Steam 41 / Coal Pulverization
developing a unique product with enhanced performance and reduced operating costs. Having completed
the license agreement, B&W retains all of the original technology as well as all of the design advancements and has changed the name to the B&W Roll
Wheel™ pulverizer. A current configuration is shown
in Fig. 1. B&W continues to fully support the full fleet
of units with state of the art replacement parts and service.
The B&W Roll Wheel pulverizer is an air-swept,
roller type vertical pulverizer; however, it differs in significant ways from other roller mills. The rollers (roll
wheels) of the B&W mill are supported and loaded by
a unique system which loads the three rollers simultaneously. The common loading system allows independent radial movement of each roller. This, in turn,
allows continuous realignment with the grinding track
as rollers wear. The rollers can also accommodate large
foreign objects such as tramp iron or rocks which inadvertently enter the grinding zone. The B&W mill
can maintain design performance with as much as
40% of the roll wheel tires’ weight lost due to wear.
Roll wheel mills operate at speeds which produce
centrifugal force at the grinding track centerline of
about 0.8 times the force of gravity. This very low
speed contributes to low vibration levels and the ability to handle large foreign objects.
This mill also introduced a gear drive module to coal
pulverizer design, where the self-contained gear box
is separate from the pulverizer housing structure. This
feature is now popular with most mill designers in the
United States (U.S.). When the gear drive module
needs repair or preventive overhaul, the pulverizer
is only disabled for the brief time it takes to remove
the drive and install a spare unit. This allows thorough and economic gear drive maintenance, independent of production demands.
Pulverized Coal Outlet
(Typical)
Swing
Valve
Raw
Coal
Inlet
Spring Bolt
Stationary
Classifier
Louver Section
Table
Feeder
Raw
Coal
Diverter
Chute
Cone Section
with
Cera-VAM ®
Ceramic Lining
Housing
Dual Purpose
Spring
Yoke
Bushing
Top Grinding
Ring
Throat
Plate
Pulverizer
Balls
Wedge Ring
Bottom
Grinding Ring
Labyrinth
Air Seal
Yoke
Main Shaft
Air Seal
Housing
Top Bearing
Plate
Pyrites
Slide
Gate
Pyrites
Box
Pinion
Shaft
Main Shaft
Gear Center
with Ring Gear Thrust Plate
Oil Pump
Drive Gear
Spiral Bevel
Pinion Gear
Pinion
Housing
Fig. 5 B&W EL ball-and-race pulverizer.
13-3
The Babcock & Wilcox Company
The major replaceable wear parts of B&W pulverizers include the tires and ring segments plus minor
items such as wear guide plates, ceramic linings, and
parts for the throat or air port ring. Wear life of all
parts in contact with the coal is dependent upon the
coal abrasiveness, and ranges from less than 10,000
to more than 100,000 hours.
The B&W mill size designations are also based upon
the grinding track centerline diameter, in inches. Units
have been furnished ranging from the B&W-56™ to
the B&W-118™ designs with capacities ranging from
15 to 115 t/h (13 to 105 tm/h) respectively.
Table 1 lists important features and characteristics
of B&W Roll Wheel and EL mills for comparison.
Horizontal air-swept pulverizers
High speed pulverizers
One high speed design which has been used in the
U.S. serves the same applications as the vertical types.
This machine operates at about 600 rpm and grinds
by both impact and attrition. Coal and heated air enter at the impact section for initial size reduction then
pass between moving and stationary parts for final
size reduction (Fig. 6). At the final stage, an exhauster
fan draws the air and coal through the mill for drying and transport. There is no classifier and the design relies upon the action of the rotor and stator to
achieve size control in a single pass of the coal. The
coal passes through quickly so there is little storage
in the mill. This pulverizer is limited to coals with
moisture content of 20% or less because of the short
residence time for drying.
Beater mills are used outside North America (Fig.
7). These are similar in some respects to the attrition
mills described above. These mills are used for grinding and drying the fossil fuels referred to as brown
coals. These are very low grade lignite type coals with
high ash and moisture contents and low heating values.
Moisture content of brown coal often exceeds 50% and
combined ash and moisture contents may exceed 60%.
Beater mills grind by impact and attrition with very
rapid drying. They achieve drying despite short residence time by replacing primary air with extremely
high temperature gas extracted from the upper furnace at temperatures about 1900F (1038C). Flue gas
from a cooler location such as the air heater outlet may
be mixed with the hot gas for mill outlet temperature
control. Coal is mixed with the gas stream ahead of
the mill for initial drying to reduce the inlet temperature. The final stage is the fan section which maintains a negative pressure in the mill at all times.
Beater mills operate at variable speed to control grinding performance at varying coal feed rates. One and
two shaft machines are used, trading simplicity in the
former for more flexibility in the latter. Because of the
low coal quality, beater mills must handle huge
amounts of coal and are made in very large sizes. There
are very few coal deposits in North America which would
require this grinding/drying technology. However, significant deposits in Germany, Eastern Europe, Turkey
Table 1
Characteristics of B&W EL and B&W Roll WheelTM Pulverizers
Type EL Ball-and-Race
Type B&W Roll-and-Race
Size range
Capacity, t/h (tm/h)
Motor size, hp (kW)
Speed
Table, rpm
Operates under
Classifier
Classification adjustment
EL-17 to EL-76
1.5 to 23 (1.4 to 21)
25 to 350 (18 to 260)
Medium
231 to 90
Pressure
Internal, centrifugal
Internal
Optional dynamic classifier
Internal, dual stage,
variable speed
40% H2O or 700F (371C) maximum
Primary air temperature
None up to temperature limit
250F (12lC)
None if fill-in balls added
Mill level with table feeders, parallel
control with belt feeders
1.75:1 at full load
Medium, 2 to 3 min of output
> 10%/min
Low, 14 (15) including primary air fan
Above 90 dBA
Moderate
B&W-56 to B&W-118
17 to 115 (15 to 104)
200 to 1500 (149 to 1120)
Slow
32 to 21
Pressure
Internal, centrifugal
Internal (standard)
External (special)
Internal, dual stage,
variable speed
40% H2O or 750F (399C) maximum
Primary air temperature
Load correction above 4% surface moisture
210F (99C)
Power increase up to 15% at fully worn condition
Parallel coal and air flow control
Drying limit
Moisture load correction
Maximum exit temperature limit
Effect of wear on performance
Air-coal control system
Air/coal weight ratio
Internal inventory
Load response
Specific power, kWh/t (kWh/tm)
Noise level
Vibration
1.75:1 at full load
High, 5 to 6 min of output
> 10%/min
Low, 14 (15) including primary air fan
Above 90 dBA, 85 dBA attenuated
Low
Note: Capacities are those for bituminous coal with a 50 HGI and 70% fineness passing through 200 mesh (74 microns).
Specific power is that at full load.
13-4
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
fill 25 to 30% of the cylinder volume. The rotational
speed is 80% of that at which centrifugal force would
overcome gravity and cause the balls to cling to the
shell wall. Grinding is caused by the tumbling action
which traps coal particles between balls as they impact.
Ball-and-tube mills may be either single or double
ended. In the former, air and coal enter through one
end and exit the opposite. Double ended mills are fed
coal and air at each end and ground-dried coal is extracted from each end. In both types, classifiers are
external to the mill and oversize material is injected
back to the mill with the raw feed. Ball-and-tube mills
do not develop the fluidized bed which is characteristic
of vertical mills and the poor mixing of air and coal
limits the drying capability. When coals with moisture
above 20% must be ground in ball-and-tube mills, auxiliary equipment, usually crusher dryers, must be used.
Ball-and-tube mills have largely been supplanted
by vertical air-swept pulverizers for new boilers. They
typically require larger building volume and higher
specific power consumption than the vertical air-swept
pulverizers. They are also more difficult to control and
have higher metal wear rates. They are, however, well
suited for grinding extremely abrasive, low moisture, and
difficult materials such as petroleum coke. Their long coal
residence time makes them effective for fine grinding.
Fig. 6 Horizontal high-speed pulverizer.
and Australia make brown coal a very important fuel
for power generation throughout these regions.
Low speed pulverizers
The oldest pulverizer design still in frequent use is
the ball-and-tube mill. This is a horizontal cylinder,
partly filled with small diameter balls (Fig. 8). The cylinder is lined with wear resistant material contoured
to enhance the action of the tumbling balls. The balls
Fig. 7 Single-shaft beater mill.
Steam 41 / Coal Pulverization
Application engineering
The arrangement of coal-fired system components
must be determined according to economic factors as
well as the attributes of the coal. The performance in
terms of product fineness, mill outlet temperature, and
Fig. 8 Typical pressurized ball-and-tube coal pulverizing system.
13-5
The Babcock & Wilcox Company
air-coal ratio must all be determined as part of overall combustion system design.
Pulverizer systems
Pulverizers are part of larger systems, normally classified as either direct-fired or storage. In direct firing,
coal leaving each mill goes directly to the combustion
process. The air, evaporated moisture, and the thermal energy which entered the mill, along with the
ground coal, all become part of the combustion process. Storage systems separate the ground coal from
the air or gas, evaporated moisture and the thermal
energy prior to the combustion process. Stored ground
coal is then injected with new transport air or gas to
the combustion process. Bin storage systems are seldom used in steam generation today, but are still used
with special technologies such as coal gasification and
blast furnace coal injection. More than 99% of the
B&W Roll Wheel pulverizers in service in the U.S. are
used in direct-fired systems.
The essential elements of a direct-fired system are:
1. a raw coal feeder that regulates the coal flow from
a silo or bunker to the pulverizer,
2. a heat source that preheats the primary air for coal
drying,
3. a pulverizer (primary air) fan that is typically located
ahead of the mill (pressurized mill) as a blower, or
after the mill (suction mill) as an exhauster,
4. a pulverizer, configured as either a pressurized or
suction unit,
5. piping that directs the coal and primary air from
the pulverizer to the burners,
6. burners which mix the coal and the balance of
combustion air, and
7. controls and regulating devices.
Raw Coal
Bunker
These components can be arranged in several ways
based on project economics. With pressurized pulverizers, the choice must be made between hot primary
air fans with a dedicated fan for each mill, or cold fans
located ahead of a dedicated air heater and a hot air
supply system with branches to the individual mills.
Hot fan systems have a lower capital cost because a
dedicated primary air heater is not required. Cold fan
systems have lower operating costs which, on larger
systems, may offset the higher initial cost. Figs. 9 and
10 show these systems.
The terminology for air-swept pulverizers refers to
the air introduced for drying and transport as primary
air. Control of primary air is of vital importance to
proper pulverizer system operation. Primary air must
be controlled for flow rate and pulverizer outlet temperature. This control can be achieved by three interrelated dampers. Hot and cold air dampers regulate air
temperature to the mill and these dampers are often
linked so that as one opens, the other closes. The third
damper independently controls air volume. On cold fan
systems, modern controls allow flow and temperature
control with just the hot and cold air dampers, eliminating the need for the independent flow control damper,
thus reducing cost with no loss of controllability.
Because direct-fired pulverizers are closely linked
to the firing system, engineering must coordinate the
design performance of the mills and burners. A set of
curves can be used to relate important operating characteristics of volume flow, velocities at critical locations,
and system pressure losses through the load range of
the boiler. The curves consider the number of mills in
service and the output range of the individual mills.
An example set of curves is shown in Fig. 11. Study
of these curves provides information on many aspects
Raw Coal
Bunker
Furnace
Wall
Burner
Pulverized
Fuel
Burner
Bin Gate
Bin Gate
Coal Feeder
Isolation
Valves
Pulverized Fuel
and Air Piping
B&W
Roll Wheel TM
Pulverizer
Seal
Air
Fans
Damper
Tight Shutoff
Damper
Primary
Air Fan
Damper
Secondary
Air
Pulverized Fuel
and Air Piping
From Air
Heater
Isolation
Valves
Tempering Air
Damper
Fig. 9 Direct-fired, hot fan system for pulverized coal.
13-6
Coal Feeder
Secondary Air
Hot Primary Air
Hot Air
Damper
Furnace
Wall
Hot Air
Damper
Hot Primary Air
Tight
Shutoff
Damper
Tempering Air
From FD Fan
Seal
Air
Fans
Air Heater
Tempering
Air
Tempering Air
Damper
B&W
Roll Wheel TM
Pulverizer
Primary
Air Fan
Fig. 10 Direct-fired, cold fan, fuel-air system for pulverized coal.
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
of pulverizer and system operation. The lower curve,
labeled A, shows boiler steam flow versus coal output
per pulverizer. The individual lines show the number
of mills in operation. In this example, a full boiler load
of 3.6 × 106 lb/h (454 kg/s) steam flow can be reached
with five mills in service at about 89,000 lb/h (11.2 kg/
s) each. The maximum load also can be reached with
four mills at about 111,000 lb/h (14.0 kg/s) each. The
maximum steam flow with three mills is just over 3.0
× 106 lb/h (378 kg/s). The minimum load line shown is
determined by Curve C. The indicated 36,000 lb/h
(4.54 kg/s) is a very good turndown ratio, but the practical minimum may be higher based on ignition stability or the onset of mechanical vibration.
Curve B shows primary air flow at mill exit conditions. Maximum flow is 55,800 ft3/min (26.34 m3/s) for
a B&W-89TMN mill, corresponding to 124,000 lb/h
(15.6 kg/s) coal flow. The minimum equipment design
flow is approximately 65% of this or 36,300 ft3/min
Burner Line and
Nozzle Velocity,
Thousand ft/min
5
Minimum
Pulverizer Load
4
Curve D
Maximum
Pulverizer Load
3
80
ft3 of Air
at 150F/lb Coal
(17.13 m3/s). However, the exact minimum flow may
need adjustment to permit stable burner operation.
This is illustrated by 39,000 ft3/min (18.41 m3/s) minimum shown in Fig. 11, curve B, and the 3000 ft/min
(15.2 m/s) minimum in curve D.
Curve C is the air/fuel ratio expressed in ft3 of air
per lb of coal. This ratio is critical to stable ignition at
low loads and is influenced by coal rank and fineness.
For this example, the maximum air to fuel ratio is 65
ft3 air per pound fuel, typical of bituminous coal. Dividing the minimum air flow by this ratio establishes
the minimum pulverizer load.
Curve D shows primary air velocity in the burner
pipes versus pulverizer coal flow. This curve is plotted by dividing air volume at mill exit conditions by
the total flow area of the pipes connecting the mill to
the burners. The minimum velocity allowed is 3000
ft/min (15.2 m/s), at which the pulverized coal can be
kept entrained in the primary air stream. The mini-
Minimum
Pulverizer Load
60
Maximum
Pulverizer Load
40
Curve C
Primary Air Flow,
Thousand ft3/min at 150F
20
60
Minimum
Pulverizer Load
Curve B
50
40
Maximum
Pulverizer Load
30
Boiler Steam Flow,
Million lb/h
Maximum Continuous Rating - Boiler Load
Minimum
Pulverizer Load
2
Curve A
ers
lveriz
5 Pu
s
erizer
4 Pulv
rizers
3 Pulve
3
Maximum
Pulverizer Load
1
0
0
10
20
30
40
50
60
70
80
Coal Rate per Pulverizer, 1000 lb/h
90
100
110
120
130
Fig. 11 B&W-89TMN pulverizer-burner coordination curves.
Steam 41 / Coal Pulverization
13-7
The Babcock & Wilcox Company
mum, or saltation, velocity is particularly important
in long horizontal spans of pipe. This velocity limit is
influenced by air density and viscosity, particle loading and particle size. For the relatively narrow range
of density, viscosity and particle size distribution in
burner pipes, the minimum velocity limit is typically
adjusted only for particle loading (see Fig. 12).
An important pulverizer performance requirement
is particle size leaving the mill. There is a mixture of
particle sizes with any pulverizer because of the statistical distribution of particle sizes produced by the
pulverizing process. The most frequently referenced
size fraction for coal combustion is that portion smaller
than a 200 U.S. standard sieve opening (mesh), or 74
microns. The portion passing this sieve size has been
used as a gauge of pulverizer capacity as well as for
assuring good combustion and good carbon burnout.
The required particle size (fineness) is determined by
the combination of coal combustion characteristics and
the combustion chamber.
For bituminous coals burned in water-cooled enclosures, a fineness of 70% passing through 200 mesh (74
microns) or better is traditionally required. The nominal capacity rating of pulverizers in the U.S. is also
based on 70% fineness. This value is suitable for good
combustion efficiency with conventional combustion
systems, but may not be sufficient for low nitrogen
oxides (NOx) systems which delay combustion. Coarse
particles, those larger than 100 mesh (150 microns),
are primary contributors to unburned carbon loss.
With traditional stationary classifiers it may be necessary to maintain fineness above 70% passing 200
mesh for acceptable unburned carbon loss. With modern rotating classifiers, the slope of the particle distribution curve is changed such that very low coarse
particle delivery and acceptable unburned carbon
losses can be achieved with fineness at or below 70%.
Outlet temperature
Coal with low volatile content may require higher
air-coal temperatures to assure stable combustion,
especially at lower burner inputs or low furnace loads.
The typical pulverizer exit temperature is 150F (66C).
Higher temperatures, up to 210F (99C) for coal, may
be used if needed. Higher temperatures require care
in the selection of internal lubricants and soft seal
materials. In addition, high outlet temperatures require high inlet temperatures which increase the risk
of pulverizer fires. Some pulverizer applications, notably bin storage systems, will require high outlet temperatures to assure complete drying and prevent han-
Fig. 12 Correction curve for minimum velocity.
13-8
dling problems with fine coal. Usually, 180F (82C) is
adequate to assure drying of coal having raw coal moisture up to 10%. For direct firing, the outlet temperature requirements are determined by volatile content
and the need for stable combustion. Table 2 lists mill
outlet temperatures for various coal types.
Effects of coal properties
Grindability When determining pulverizer size, the
most important physical coal characteristic to consider
is grindability. This characteristic is indicative of the
ease with which coal can be ground. Higher
grindabilities indicate coals which are easier to pulverize. The test procedure to determine the commonly
used Hardgrove Grindability Index (HGI) is described
in The American Society for Testing and Materials
(ASTM) D 409. The operative principle with this procedure is the application of a fixed, predetermined
amount of grinding effort or work on a prepared and
sized sample. The apparatus shown in Fig. 13 is used
to determine grindability. By rotating exactly 60 revolutions, this miniature pulverizer does a fixed amount
of work on each sample. The amount of new, fine
material produced is a measure of the ease of grinding. The neutral value of grindability used by B&W
is HGI = 50, i.e., at HGI = 50, the capacity correction
factor is 1.0. The index is open ended with no upper
limit on the HGI scale.
Grindability is not strictly a matter of hardness.
Some materials, fibrous in nature, are not hard but
are very difficult to grind. Sticky or plastic materials
can also defy grinding.
The procedure described in ASTM D 409 was originally developed as a purely empirical method but provides a valid capacity calculation for vertical pulverizers when grinding bituminous coal. When lower
rank coals are tested in the Hardgrove apparatus, the
correlation between laboratory tests and field operating equipment is often quite poor. There is a strong
but unpredictable effect of sample moisture on test re-
Fig. 13 Hardgrove grindability testing machine.
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
Table 2
Typical Pulverizer Outlet Temperature
Fuel Type
Lignite
Subbituminous
High volatile bituminous
Medium and low volatile bituminous
Anthracite and coal waste
Petroleum coke
Volatile Content, %*
Exit Temperature F (C)**
All values
All values
Above 31
14 to 31
0 to 14
0 to 8
120 to 140 (49 to 60)
130 to 150 (54 to 66)
140 to 175 (60 to 79)
160 to 200 (71 to 93)
200 to 210 (93 to 99)
200 to 250 (93 to 121)
* Volatile content is on a dry, mineral-matter-free basis.
** The capacity of pulverizer is adversely affected for exit temperatures below 125F (52C) when
grinding high moisture lignites.
sults, illustrated in Fig. 14. For high ash content coals,
the possibility of mineral accumulation in the pulverizer, which hinders the grinding process, is not accounted for in the HGI procedure. A more accurate
index of grindability for low rank coals is determined
in a laboratory sized roll wheel pulverizer. This equipment has all the features of a field installation and
can simulate field conditions. The capacity of the mill
is about 800 lb/h (0.10 kg/s) and a coal capacity test
requires a 3000 lb (1361 kg) sample. Fig. 15 is an arrangement diagram of this test apparatus. Results are
interpreted as apparent grindability and the values
are valid for capacity calculations.
Wear properties Wear in coal pulverizers results
from the combined effects of abrasion and erosion. The
mechanism which dominates in the wear of a particular machine component depends upon the designed
function of the component and on the properties of the
coal being ground. Abrasiveness and erosiveness are
the important properties to be considered when evaluating the influence of a candidate coal on expected
maintenance cost. Unfortunately, these two important
properties are inherently difficult to measure, especially with a material as variable as coal.
Abrasiveness Abrasion is the removal of material by
friction due to relative motion of two surfaces in contact. A coal’s ability to remove metal is primarily related to the quantity and size distribution of quartz
and pyrite found in the as-received coal, especially for
particles larger than 100 mesh (150 microns). While
standard and accepted procedures are available to
determine the quantity of these two minerals in a
sample (ASTM D 2492 and ASTM D 2799 for pyrite and
quartz respectively), procedures to establish quartz and
pyrite particle sizes are not widely accepted.
Unfortunately, direct small-scale laboratory
abrasiveness testing is not satisfactory for correlation
to field wear conditions because of operating differences between small laboratory equipment and power
plant pulverizers. However, satisfactory abrasiveness
measurements have been made using the laboratory
sized roll wheel pulverizer with 4000 lb (1814 kg)
samples. Although expensive, wear life testing with
this procedure can typically predict field performance
with an error of 10% or less. While other abrasiveness
Steam 41 / Coal Pulverization
tests such as Yancy-Geer Price apparatus are used to
provide some insight into relative wear rates, they are
of very limited value in predicting actual field wear rates.
Erosiveness Erosion is not the same as abrasion. It
can be defined as the progressive removal of material
from a target on which a fluid borne stream of solids
impinges. For a given combination of particles and target material, wear rate increases with increasing ve-
Fig. 14 Hardgrove Grindability Index versus fuel moisture.
13-9
The Babcock & Wilcox Company
Raw Coal
Bunker
Particulate
Collector
Classifier
Motor
Gravimetric
Feeder
Air
Heater
Rotary
Valve
Rotary Valve
Screw
Feeder
MPS-32
Orifice
Vent
Collection
Silo
Burner
(Pneumatic)
or
Collection
Vessel
(Gravity)
Primary
Air Fan
Mill Motor
Thermocouple
Pressure Trap
Sampling Port
Fig. 15 B&W’s test apparatus for low rank coals.
locity, particle size, and the solids content of the
stream. For ductile target materials, the wear rate
increases for an impingement angle from parallel up
to approximately 45 deg, at which point wear begins
to decline.1 For brittle materials, the rate of erosion
increases up to the angle of approximately 70 deg,
where rebounding material interferes with the impinging stream and measurement becomes erratic.
Moisture Moisture content in the fuel is a key design parameter. Coal moisture is highly variable and
depends more on coal type than on the amount of water introduced after mining. Coals used in the U.S.
range from inherent moisture levels of 2% for Appalachian bituminous to near 40% for lignites. Brown
coals may range up to 70%. Moisture in coal is determined according to the procedures in ASTM D 3302.
For pulverizer capacity corrections and primary air
system design, the total moisture must be separated
into air dry moisture (air dry loss) and residual moisture (moisture remaining after air drying). For capacity correction, since the air dry moisture is evaporated
from the coal sample before performing the HGI
grindability test, an additional correction factor for air
dry moisture must be included. For the primary air
system design, residual moisture requires just enough
heat to raise it from raw coal temperature to mill outlet temperature. The air dry moisture will be evaporated in the pulverizer, so it requires much more heat.
Pulverizer size selection
The ultimate task in pulverizer application is the
selection of the size and number of mills for the proposed project. The total boiler heat input and coal flow
requirements are established from the combustion
calculations (see Chapter 10) and the specified boiler
steam flow requirements. The coal flow rate is then
divided by the capacity correction factor to establish
the equivalent required pulverizer capacity. The correction factor not only includes the fineness and
grindability factors shown in Fig. 16, but also the appropriate fuel moisture correction.
The number of pulverizers is then evaluated by dividing the equivalent required capacity by the unit
pulverizer rated capacity based upon 70% passing
13-10
through a 200 mesh (74 microns) screen and a
grindability of 50. The unit pulverizer rated capacity
is based upon pulverizer size, type and manufacturer.
The tradeoff between fewer larger mills and more
smaller mills is based upon balancing total capital cost
with the proposed operating requirements such as
boiler turndown. Frequently an extra pulverizer is
specified to permit the boiler to operate at full load
while one mill is out of service for maintenance.
Pulverizer selection and sizing are complicated by
the frequent need to consider various coal sources and
emission requirements. If the coal that determines the
pulverizer size is greatly different from the intended
primary use coal, the result may be oversized mills and
limits on turndown on the primary coal. In such a case,
it may be necessary to consider eliminating this coal,
or accepting a load reduction when burning it.
Performance testing
Acceptance testing will usually be guided by the procedures in The American Society of Mechanical Engineers (ASME) Performance Test Code, PTC 4.2 which
references other applicable codes and standards. Testing may also be done as part of an overall boiler test,
or simply to learn whether maintenance or adjustments are needed.
Fineness testing
The method of fineness sampling is well described
in PTC 4.2 and ASTM D 197. While this procedure
has inherent weaknesses, it is the basis for measuring one of the fundamental performance parameters
to verify pulverizer capacity. Periodically, alternative
sampling procedures or new hardware are proposed
and they may be more accurate or easier to use than
the ASTM method. However, the ASTM probe is the
accepted standard on which capacity correction factors for fineness are based. Any potential improvement
in absolute accuracy does not justify the abandonment of decades of data based on the ASTM method,
nor the cost to establish a new database.
When tests are run to determine the condition of
the pulverizer system or to evaluate a proposed new
coal, comparative values between successive tests may
be adequate. In such cases, alternatives, such as the
ISO probe, may serve well if they provide acceptable
repeatability and are not sensitive to variables such
as velocity or temperature. Panel board instruments,
if they can be read with sufficient precision, will serve
as well as calibrated instruments for periodic testing.
Evaluating test results
The evaluation approach depends on the purpose
of the tests. If the parties have agreed upon test protocols as prescribed by PTC 4.2, results evaluation is
simply a calculation process. When results indicate
that the performance requirements have not been met
but that the shortfall is slight, reference to the ASTM
standards, D 409 and D 197, may show that the shortfall could lie within the limits of laboratory analysis
repeatability. The protocols should provide for resolution of small deviations in the test results.
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
Most testing is to evaluate the equipment or its systems. It is a mistake to try to read excessive precision
into test results. It is more important to track relative
performance to indicate the need for corrective action
or the frequency of retesting. It is useful to develop
checklists or troubleshooting guides to note what each
abnormality indicates. For example, acceptable fineness but excessive pressure differential probably indicates a need to adjust the pulverizer load springs.
Acceptable fine fraction fineness but poor coarse fraction fineness indicates erosion damage and internal
short circuiting through the classifier. Also, it is common to discover that recalibration of primary measuring devices is needed on a regular schedule.
When equipment tests are first undertaken, it is
important to collect all data which could possibly prove
useful. As test experience grows, extraneous data can
be removed. It is usually only a short time before standard data sheets evolve and testing becomes a routine task for an individual plant.
Operations
The main costs of coal pulverizer operation are capital, power consumption, and maintenance. The capital cost is usually an annual levelized charge including capital, taxes, and several other factors. Power and
maintenance are often expressed as costs per ton of coal
ground, and are influenced by plant operating practices.
Power consumption
When comparing pulverizer designs, it is common
to combine primary air fan and pulverizer power consumption. The power consumption for B&W Roll
Fig. 16 Capacity correction factor.
Steam 41 / Coal Pulverization
Wheel or EL pulverizers and their respective fans is
about 14 kWh/t (15 kWh/tm) with coal at 50 HGI and
70% fineness, operating at rated output and with new
grinding parts. These conditions seldom exist for any
length of time during operation. Most modern installations include extra capacity for future coal variation.
For most mills, there will be either a decline in capacity or an increase in power consumed as wear
progresses. Therefore, because of the combined effect
of pulverizer oversizing and wear, a realistic power
value might be 20 kWh/t (22 kWh/tm) for a well sized
mill on a base loaded boiler or 22 kWh/t (24 kWh/tm)
on a load following unit.
There are various ways of calculating the cost of
auxiliary power. The lowest cost which can be calculated is the cost of coal used to generate the power. This
is a heat rate cost and, for a hypothetical boiler using
coal with a 13,000 Btu/lb (30,238 kJ/kg) heating value
and a thermal heat rate of 10,000 Btu/kWh (34.1%
efficiency), 22 kWh/t (24 kWh/tm) is about 0.85% of
the fuel energy input to the boiler. As heating value
declines, more power is spent grinding and moving
material which does not produce thermal input, so the
22 kWh/t (24 kWh/tm) becomes a higher percentage
of thermal input.
Power can be expected to increase as the grinding
parts wear. The depth of the grinding track may play
a part in the power increase as well. There is little information to show whether power increases uniformly with
time or if it takes place mostly at the end of wear life.
Maintenance
Costs for material and labor depend on wear life
which varies with the abrasiveness of the coal. Wear
life on B&W Roll Wheel mills grinding U.S. coals
ranges from less than 10,000 to more than 100,000
hours, and normally between 25,000 and 60,000
hours. Therefore, average annual maintenance costs
can vary widely. Costs will also vary by mill size,
where part costs are proportionately higher for smaller
mills. For a given set of assumptions, the B&W-67™
mill maintenance will cost about 60% of the power
costs cited above at a wear life of 25,000 hours and as
little as 20% at 60,000 hours. Respective values for
B&W-89 are 40% and 10%. For a very rough estimate,
maintenance costs will be about one half the power costs
for small mills and about one third for larger mills.
Maintenance and power costs are also influenced
by operating practices. For example, experienced operators may notice that an increase in pulverizer pressure differential or pulverizer motor power indicates
a need for spring readjustment. There may be cost
effective decisions between maintenance and operations regarding rebuild frequency to minimize the
costly power increases near the end of wear life.
Ceramics The use of ceramic tiles for erosion resistance has reduced repair costs. Erosion resistance of
ceramic is at least eight times greater than an equivalent thickness of carbon steel. Ceramic lined panels are
used in classifier cones, in the housing above the throat,
and in the discharge turret in B&W Roll Wheel mills.
Ceramic lining is used extensively in burner pipe elbows
and for wear shields on roller brackets. When ceramic
13-11
The Babcock & Wilcox Company
tiles are used, they must be carefully fitted to avoid undercutting and loss of the lining. Ceramic tiles are not
suitable for all forms of erosion protection. High angles
of impingement are destructive to brittle materials.
Record keeping Records are useful for pulverizer
maintenance. Critical dimensions as recommended by
the manufacturer should be measured and recorded
during internal inspections. Suspicious wear data
should be recorded and given special attention at the
next inspection. When lubricants are drained, the
amount should be noted and recorded and a sample
obtained for analysis. Many owners are now including periodic gearbox vibration measurements in their
data collection and record keeping. Such data may
provide early warning of bearing or gear failure.
Fires and explosions
It must always be remembered that a coal pulverizer grinds fuel to a form suitable for good combustion. Combustion can and does occur at unplanned locations with costly results. Pulverizer fires are serious
and should be treated with preplanned emergency procedures. The surprising speed with which a fire can
develop requires prompt action.
Pulverizer fires can develop in the high temperature areas of mills or in the coal rich low temperature
areas. Usually, there should be no coal in the areas
upstream of the throat – the high temperature areas.
Excessive spillage, because of insufficient air flow or
throat wear, can cause coal accumulation in the plenum or windbox of the pulverizer. If this coal is not
rejected promptly to the pyrite removal system, it can
be ignited by the high temperature primary air. Coal
will also enter this area when a mill is tripped or shut
down quickly. Coal in the windbox may burn out without damage and, indeed, this form of fire may go undiscovered. Fires in the cooler, fuel rich zones may develop more slowly, but these fires are fed by enormous
amounts of coal and can quickly destroy the internal
pulverizer parts.
The most common fire indicator is mill outlet
temperature. Temperature indicators are slow in response because they are sheltered by erosion protection, but they are inherently reliable and their indications should be taken seriously.
Control room operators can gain useful information
about potential hazards by following consistent operating practices, especially on multiple mill installations. If, for example, all mills are at the same coal feed
rate, and if primary air control is in the automatic
mode, all mills should have the same air/coal ratio.
Under these conditions, a significant temperature difference from inlet to outlet in one mill may indicate a
fire and should be investigated immediately. Of course,
there are other possible causes of inlet temperature
differences such as faulty feeder calibration, faulty air
flow calibration, or coal moisture variation between
the respective mills. The significant point is that there
is important information to be drawn from careful
observation of the vital signs of pulverizer system
performance. Use of all vital signs as leading indicators of potential hazards is important to safe operations.
Severe fire damage has also been caused by feed13-12
ing burning coal from silos or bunkers. All pulverizer
manufacturers prohibit this practice. Silo fires must
be dealt with separately by emptying the fire through
special diverter chutes or by extinguishing agents
applied to the coal surface.
In mill trips, the sudden loss of air flow allows the
collapse of the fluid bed above the throat. The coal
then falls into the windbox and contacts the hot metal
surfaces. Low rank coals can begin smoldering within
a few minutes at temperatures of 450F (232C) or
more, and, upon agitation, dust clouds can be created
leading to explosions. The agitation may be from mechanical action of the pyrite plows upon restart, or
from the start of primary air flow before restart. The
danger of explosion is minimized by removing the coal
under rigidly controlled conditions. It is first necessary
to assure personnel safety by evacuating all workers
from places which could be affected by an explosion if
the enclosures of the mill, ducts or burner pipes are
breached. The mill is isolated from all air flow and an
inert internal atmosphere is created by injecting inert gas or vapor. Brief operation of the mill, while isolated, rejects the coal to the pyrite removal system. The
inert atmosphere prevents any smoldering coal from igniting the dust cloud raised internally by mill operation.
When a mill explosion occurs it is nearly always during changes in operating status, such as during
startup and shutdown.2 During startup, the air-coal
mixture in the mill passes from extremely fuel lean to
fuel rich. There is a transitional mixture which is ideal
for a dust explosion if a sufficiently strong ignition
source exists. One recurring source of ignition is smoldering fires which develop in the residual coal left in
the hot zone of a mill following a trip. The coal removal procedure just described was devised to avoid
or safely remove this ignition source.
Undiscovered fires can cause dust explosions during otherwise normal shutdowns. These are not common, but experience has led many operators to actuate audible and visible alarms before routine starts
and stops. This is a recommended safety precaution
for all coal pulverizer operators.
Controls and interlocks
The most widely followed standard for design and
application of coal pulverizer systems is the National
Fire Protection Association Standard, currently NFPA85. This sets the minimum standards listed below for
safety interlocks to be used with coal pulverizers:
1. failure of primary air flow trips the pulverizer system,
2. failure of the pulverizer trips the coal feeder and
primary air flow,
3. closing of all burner pipe valves trips the pulverizer, the feeder, and the primary air flow, and
4. primary air flow below the manufacturer’s minimum trips the pulverizer.
Other interlocks not mandated by NFPA but required
by B&W are:
1. loss of the lube oil pump, or low oil pressure, trips
the pulverizer (B&W Roll Wheel mill only), and
2. flame safety systems trip the pulverizer if minimum flame detector indications are not met.
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
Additional indications of malfunctions which may require manually tripping a mill include:
1. excessively high or rapidly rising mill exit temperature probably indicates a fire,
2. inability to maintain an exit temperature of at least
125F (52C) may lead to loss of grinding capacity,
3. loss of seal air pressure or flow will eventually lead
to bearing failure, and
4. high lube oil temperature indicates a loss of cooling
water flow which may lead to gear drive damage.
Items 2, 3 and 4 above are not safety related. They
are examples of the designers’ choices to avoid unnecessary mill trips and the resultant special safety procedures required to restart tripped mills as well as to
protect the equipment from damage.
Special safety systems
The procedure for removing coal after a pulverizer
trip requires a separate control system. This system
must bypass the control logic which prevents operation of the pulverizer drive motor without adequate
primary air flow. To prevent misuse of this bypass feature, the coal removal logic (referred to as inert and
clear logic) is enabled by actuation of the mill trip logic.
A typical schematic logic diagram is shown in Fig. 17.
Another special system has been developed to deal
with a phenomenon which has been observed in ducts
after trips. A fine layer of dust is often seen in the clean
air portion of the primary air system. This is thought
to be due to a turbulent dust cloud which persists after collapse of the fluidized bed of coal above the
throat. An array of water fog nozzles under the throat
will intercept this cloud if actuated with the mill trip
signal. Hardware for tangential wash nozzles to enhance the coal removal action of the pyrite plows during the inert and clear cycle can be installed adjacent
to the fogging nozzles. The wash nozzles are actuated
manually at the appropriate time in the cycle.
Advanced designs
Rotating classifiers
As noted under Application engineering, product
fineness is under review after being generally standardized at 70% passing through 200 mesh (74 microns) for direct firing of bituminous coal. Advanced
low NOx combustion systems benefit incrementally
from higher 200 mesh fineness, but very high 100
mesh fineness can sharply reduce unburned carbon
losses. Modern independently driven rotating classifiers can provide up to 95% passing 200 mesh fineness but at a significant reduction in coal flow capacity. Alternately, they can provide excellent 100 mesh
fineness at 70% or less though 200 mesh, with little
or no capacity reduction. While main shaft driven
rotating classifiers were part of the earliest E mill de-
Dirty Mill
Trip
Stop Pulv
Motor
Start Sluice
System
Open Fogging
Valve for
3 Minutes
Isolate
Pulverizer
Shut:
PA Isolation Damper
Seal Air Valve
Feeder Discharge Valve
Initiate Inert
Mode
Flame Safety System
Control Room
Normal/Inert
Switch
Open Pyrite
Gates
1. Pulv Clear
Permitted
Water Flush
for a
Minimum of
3 Minutes
Open Water
Wash Valve
1. Pulv Clear
Permitted
2. Neither Pyrite
Gate Closed
Close Water
Wash Valve
Water Flush
for a
Minimum of
3 Minutes
1. Water Wash
Flow Adequate
Local Logic Panel
Start Pulv
Motor
Open Inert
Valve for
8 Minutes
Pulv Clear
Permitted
1. PA Flow Stopped
2. Switch in Inert
3. Pulv Inert and
Clear Required
Memory Set
1. Inerting Valve Open
2. Inerting Media
Adequate Flow
3. Open Inert Valve
Command 2 Minutes
4. Open Inert Valve
Command or Pyrite
Gate Open Memory
1. Pulv Clear
Permitted
2. Lube Oil
Permit Met
Release
Pyrite Gate
Release
Pulv Group
1. Reset Pulv
Inert and Clear
Required Memory
Local Logic Panel
Swirl Pulv for
>7 Minutes but
<10 Minutes
Flame Safety System
Initiate Normal
Mode
1. Switch to
Normal Position
Inert Pulverizer
for 2 Minutes
During Restart
1. Inerting Valve
Open
2. Inerting Media
Adequate Flow
Fig. 17 Typical safety system logic diagram.
Steam 41 / Coal Pulverization
13-13
The Babcock & Wilcox Company
sign, independently driven variable speed classifiers
were developed in the 1970s, and the two stage design shown in the B&W Roll Wheel mill in Fig. 18 was
developed in the 1990s. A similar dynamically staged
variable speed (DSVS®) classifier for EL pulverizers,
is shown in Fig. 19. The improved particle distribution
achieved with the DSVS classifier is shown in Fig. 20.
Rotating throats
Rotating throat rings were introduced for B&W
Roll Wheel mills in the 1980s, initially to reduce erosive wear. The rotating throat designs have been further enhanced to provide better air distribution and
lower air resistance, as well as better reliability and
easier installation.
Variable spring loading
Also for the B&W Roll Wheel mills, a variable online spring load adjusting system is available. With the
traditional spring loading system, the applied grinding force is a compromise between efficient high load
operation, and smooth operation at low loads, including start and stop. With the Auto Spring™ system, the
spring load can be increased for optimum high load
performance, then reduced for stable low load operation as well as grind out and startup. The typical
spring load control will vary pressure with coal flow,
but it can also vary loading to accommodate wide variations in coal grindability, as shown in Fig. 21.
Fine grinding
Vertical roller mills have a practical limit of about
95% passing through 200 mesh (74 microns) for product fineness. As the product becomes finer, the recirculated material in the grinding chamber also becomes
finer and the compressed layer becomes more fluid and
Variable
Speed Motors
Raw Coal Pipe
Pulverized
Coal Outlet
(Typical)
Electric Classifier
Drive
Discharge
Turret
Raw Coal
Inlet
DSVS ®
ClassifierFirst Stage
(Stationary)
Coal
Chute
DSVS ®
Rotating
ClassifierSecond Stage
Fig. 19 DSVS® rotating classifier for EL mill.
less stable. For very fine grinding other machines are
needed. One of these is the ball-and-tube mill, offering the long residence time needed for an extremely
fine product. In addition, ball-and-tube mills are built
in the large sizes needed for direct firing.
The high capacity of ball-and-tube mills may not
be needed to meet fine grinding applications. One potential application of fine grinding is to provide fuel
for coal-fired lighters to reduce oil consumption for
startup and low load flame stabilization. Another application is firing very fine coal in smaller furnaces,
originally intended for oil or natural gas and not suit99.99
Gear Box
DSVS ®
Rotating
Classifier
Second Stage
Rotating Vanes
99.00
Fineness, % Passing
First Stage
Stationary
Louvers
Stationary
Classifier
95.00
90.00
80.00
Rejects
Cone
70.00
60.00
400
Fig. 18 DSVS® rotating classifier for B&W Roll Wheel™ pulverizer.
13-14
200
100
50
U.S. Standard Sieve Designation
30
Fig. 20 Particle size distribution.
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
Low Grindability
Coal
Spring Force
Standard Spring
Force
High Grindability
Coal
Minimum
0
10
20
30
40
50
60
70
80
90
100
% Coal Flow
Fig. 21 B&W Roll Wheel™ pulverizer variable spring force versus
coal flow.
able for traditional coal firing. Smaller capacity mills
could be used for this application.
Mills for fine grinding have been used to grind pigments, food and pharmaceuticals. These are small
mills, generally 5 t/h (4.5 tm/h) or less. Grinding principles include fluid energy, stirred ball, and high speed
attrition. Fluid energy mills cause solids bearing fluid
streams to impinge; particle impacts cause the size
reduction. Stirred ball mills, usually wet grinders, use
a charge of small balls in a cylindrical vessel which
are agitated by a rotor, grinding the solids flowing
through the charge.
High speed attrition mills grind by the combination
of first stage impact and final stage attrition. It is these
mills which have begun to attract some attention for
preparation of oil or natural gas replacement fuel. The
mill’s rotor is a series of disks, each with impact bars,
and each forming the driver for a grinding stage. The
grinding stages are separated by diaphragms and coal
must move inward against centrifugal force to pass
from one stage to the next. Coal captured in each stage
is said to provide an effective wearing surface to protect the mill shell from rapid wear. These mills are made
in capacities up to about 5 t/h (4.5 tm/h) and may be oncethrough or be equipped with external centrifugal classifiers for size control. Manufacturers of these mills refer to the product as micronized coal. When the term was
adopted in the early 1980s, micronized coal referred to
coal which was 100% finer than a 325 mesh (44 microns). The output of vertical high speed attrition mills
is about 98% passing through 200 mesh (74 microns),
86% passing through 325 mesh (44 microns). However,
this coal is reported to be fine enough to be easily ignited
without the need for preheated primary or combustion
air. These mills are high in power consumption and motor power is said to be sufficient to provide the necessary
energy for drying most coals. The economic attractiveness of finely ground coal as a stabilizing and startup
fuel depends on oil and natural gas prices.
References
1. Johnson, T.D., et al., “Pulverized Fuel System Erosion,”
presented at the Electric Power Research Institute (EPRI)
Conference on Coal Pulverizers, pp. 18-22, Central Electricity Generating Board, England, 1985.
2. Zalosh, R.G., “Review of coal pulverizer fire and explosion incidents,” ASTM STP 958, Cashdollar, K.L., and
Hertzberg, M., eds., American Society for Testing and Materials, Philadelphia, Pennsylvania, p. 194, 1987.
Bibliography
“Coal: Sampling of Pulverized Coal Conveyed by Gases in
Direct Fired Coal Systems,” pp. 18-22, International Standards Organization, 1991.
Donais, R.T., Tyler, A.L., and Bakker, W.T., “The effect
of quartz and pyrite on abrasive wear in coal pulverizers,”
Proceedings of the International Conference on Advances
in Material for Fossil Power Plants, American Society for
Metals, Metals Park, Ohio, p. 643, 1987.
Steam 41 / Coal Pulverization
Piepho, R.R., and Dougan, D.R., “Grindability measurements on low rank fuels,” Proceedings, Coal Technology
’81, Vol. 3, pp. 111-121, 1981.
Wiley, A.C., et al., “Micronized coal for boiler upgrade/
retrofit,” Proceedings of POWER-GEN International
’90, PennWell, Houston, Texas, pp. 1155-1170, 1990.
13-15
The Babcock & Wilcox Company
Coal pulverizers at a modern utility power station.
13-16
Steam 41 / Coal Pulverization
The Babcock & Wilcox Company
Chapter 14
Burners and Combustion Systems
for Pulverized Coal
Advanced low NOx (nitrogen oxides) pulverized coal
(PC) combustion systems, widely in use today in utility and industrial boilers, provide dramatic reductions
in NOx emissions in a safe, efficient manner. These systems have been retrofitted to many existing units and
are reducing NOx emissions to levels which in some
cases rival the most modern units. The challenges are
considerable, given that the older units were not built
with any thought of adding low NOx systems in the
future. Low NOx combustion systems can reduce NOx
emissions by up to 80% from uncontrolled levels, with
minimal impact otherwise on boiler operation; and
they do so while regularly exceeding 99% efficiency
in fuel utilization. These advanced low NOx systems,
depicted in Fig. 1, start with fuel preparation that
consistently provides the necessary coal fineness while
providing uniform fuel flow to the multiple burners.
Low NOx burners form the centerpiece of the system,
and are designed and arranged to safely initiate combustion and control the process to minimize NOx. An
overfire air (OFA) system supplies the remaining air
to complete combustion while minimizing emissions of
NOx and unburned combustibles. Distributed control
systems (DCS) manage all aspects of fuel preparation,
air flow measurement and distribution, flame safety,
and also monitor emissions. Cutting edge diagnostic
Furnace
Front Wall
Furnace
Rear Wall
Advanced OFA
System with
Two Levels of
NOX Ports
Windbox
DRB-4Z Third
Generation Low
NOX Burners
B&W Roll Wheel
Pulverizer
Fig. 1 Advanced low NOx pulverized coal-fired combustion system.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
14-1
The Babcock & Wilcox Company
and control techniques, using neural networks and
chaos theory, assist operators in maintaining performance at peak levels. Like automobiles, the fundamentals go back more than 100 years, but the modern product is dramatically more reliable, more efficient, and
lower in emissions.
The greatest use of coal worldwide is for the energy
source in electric power generation. Coal remains the
dominant fuel for electrical generation in the United
States (U.S.) and in many other countries as well. This
is attributable to both the abundance and relatively
low cost of this fossil fuel. It can be burned in a number of ways depending upon the characteristics of the
coal and the particular boiler application. Cyclone,
stoker, and fluidized-bed firing methods are used for
a variety of applications as discussed in Chapters 15
through 17. However, pulverized coal (PC) firing –
burning coal as a fine powder suspension in an open
furnace – is the most prevalent method in use today.
PC firing has made possible the large, efficient utility
boilers used as the foundation for power generation
in many utilities worldwide.
Pulverized coal firing differs from the other coal
combustion technologies primarily through the much
smaller particle size used and the resulting high combustion rates. The combustion rate of coal as a solid
fuel is, to a large extent, controlled by the total particle surface area. By pulverizing coal to a nominal 50
micron diameter or smaller (see Chapter 13), the coal
can be completely burned in approximately one to two
seconds. This approaches the rate for oil and gas. In
contrast, the other technologies discussed in subsequent chapters use crushed coal of a larger size and
require substantially longer combustion zone residence times (up to 60 seconds or longer).
Pulverized coal was first used in the 1800s as a cost
effective fuel for cement kilns.1 The ash content enhanced the properties of the cement and the low cost
resulted in the rapid displacement of oil and gas as a
fuel. However, early pulverizing equipment was not
very reliable and, as a result, an indirect bin system
was developed to temporarily store the pulverized coal
prior to combustion, providing a buffer between pulverization and combustion steps. Use in the steel industry followed closely. In this application, the importance of coal drying, particle size control and uniform
coal feed were recognized.
Success for boiler PC firing applications required
modification of the boiler furnace geometry to effectively use the PC technology. In the early 1900s, fireboxes and crowded tube banks had to be expanded to
accommodate PC firing. By the late 1920s, the first
water-cooled furnaces were used with pulverized coalfired systems. Burner design progressed, providing
improved flame stability, better mixing, and higher
combustion efficiency. Coupled with improvements in
pulverizer design and reliability, improved PC burners
permitted the use of direct firing with coal transported
directly from the pulverizer to the burner. (See Fig. 2.)
The exponential increase in the U.S. electric power
generation and the increase in boiler size from 100
MW to 1300 MW could not have been achieved economically without the development and refinement of
14-2
Fig. 2 Early pulverized coal-fired radiant boiler.
pulverized coal firing. Today, nearly all types of coal
from anthracite to lignite can be burned through pulverized firing. Combustion efficiencies of most coals approach those of oil and gas. Current research is focusing on further reduction in emissions of nitrogen oxides
(NOx) for environmental protection without sacrificing
boiler performance or availability. (See also Chapter 34.)
Combustion
The manner in which a coal particle burns depends
on how it was pulverized, its inherent characteristics,
and conditions in the furnace. Pulverization obviously
produces fine coal particles, but is also accompanied
by introduction of heated primary air (PA) to the coal
to facilitate grinding and drying, and for transport of
the coal from the pulverizer. The quantity and temperature of PA varies significantly with the type of pulverizer, grinding rate, and coal properties. Hot PA
causes some of the moisture in the coal to evaporate
and raises the temperature of the coal from ambient
to nominally 150F (66C). In a direct fired system, the
pulverized coal is immediately transported to the burners by the moisture laden PA. Secondary air is introduced through a burner to the PA/PC mixture, in a
controlled manner to induce air-fuel mixing in the
furnace. As a coal particle enters the furnace (see Fig.
3), its surface temperature increases due to radiative
and convective heat transfer from furnace gases and
other burning particles. As particle temperature in-
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
Fig. 3 Coal particle combustion.
creases, the remaining moisture is vaporized and volatile matter is released. This volatile matter, which ignites and burns almost immediately, further raises the
temperature of the char particle, which is primarily
composed of carbon and mineral matter. The char particle is then consumed at high temperature, leaving
the ash content and a small amount of unburned carbon. The volatile matter, fixed carbon (char precursor), moisture and ash content of the fuel are identified on a percentage basis as part of the proximate
analysis discussed in Chapter 9.
Volatile matter content
Volatile matter is critical for maintaining flame stability and accelerating char burnout. Coals with minimal volatile matter, such as anthracites and low volatile bituminous, are more difficult to ignite and require
specially designed combustion systems. The amount
of volatile matter evolved from a coal particle depends
on coal composition, the temperature to which it is exposed, and the time of this exposure. The American
Society for Testing and Materials (ASTM) Method D
3175 stipulates a temperature of 950 ±20C for seven
minutes for volatile matter content determination.2
Raising the temperature would increase volatile yield
with other factors held constant. The heat contribution from volatile matter, as a percentage of total coal
heating value, can be less than 10% for anthracites,
reaches 40% for high volatile bituminous and subbituminous coals, and can exceed 50% for lignite. Coals
with higher volatile matter content also benefit from
more effective NOx control by combustion methods, as
discussed later. Ignition is influenced by the quality
and the quantity of volatile matter. Volatile matter
from bituminous and higher rank coals is rich in hydrocarbons and high in heating value. Volatile matter from lower rank coals includes larger quantities
of carbon monoxide and moisture (from thermal decomposition) and consequently has a lower heating
value. Volatile matter from higher rank coals can provide twice the heating value per unit weight as that
from low grade coals.
Char particles
The rate of char particle combustion depends on
several factors including composition, particle size,
porosity, thermal environment, and oxygen partial
Steam 41 / Burners and Combustion Systems for Pulverized Coal
pressure. Char reactions often begin as the coal particle is heated and devolatilizes, but they continue long
after devolatilization is complete. Devolatilization is
mostly completed after 0.1 seconds, but char-based
reactions continue for one to two seconds. The char
particle retains a fraction of the hydrocarbons. Char
reactivity lessens with increasing coal rank due to accompanying changes in composition and structure of
the coal. Younger coals benefit from higher inherent
reactivity and from a structure which more closely
resembles fibrous plant matter than rock. Many coals
go through plastic deformation and swell by 10 to 15%
when heated. These changes can significantly impact
the porosity and reactivity of the coal particle. Char
reactivity drops during the combustion process, which
further extends the time for char burnout.
Char oxidation requires oxygen to reach the carbon in the particle and the carbon surface area is primarily within the particle interior structure. Char combustion generally begins at relatively low particle temperatures. Reaction rates are primarily dependent
upon local temperature as well as oxygen diffusion
and char reactivity. Small char particles, with 10 to
20 micron diameters, benefit from high surface to mass
ratios and heat up rapidly, while coarse particles heat
more slowly. Rapid heat transfer to and combustion
of smaller particles lead to higher particle temperatures. Reaction rates increase exponentially with temperature, and oxygen (O2) for diffusion into the particle becomes the controlling parameter. Particle diameter and density change in the process. At higher particle temperatures, char reactions are so fast that oxygen is consumed before it can penetrate the particle
surface. The particle shrinks as the outer portions are
consumed, and transport of oxygen from the surroundings to the particle is the factor governing combustion
rate.
For larger particles, the solid mass is reduced as
carbon monoxide (CO) and carbon dioxide (CO2) form,
but particle volume is maintained. Coarse particles,
more than 100 micron diameter, burn out slowly as a
result of their lower surface to mass ratios. Longer burnout times cause these larger char particles to continue
reacting downstream where the flame temperature and
oxygen concentration have moderated. A portion of the
carbon may not be oxidized depending on the residence
time and combustion environment. This unburned carbon amounts to an efficiency loss for the boiler.
Effect of moisture content
The moisture content of the coal also influences combustion behavior. Direct pulverized coal-fired systems
convey the moisture evaporated during pulverization
to the burners. This moisture plus that remaining in
the coal particles present a burden to coal ignition. The
water must be vaporized and superheated during the
early stages of the combustion process. Further energy
is absorbed at elevated temperatures as the water
molecules dissociate.
Moisture content increases as rank decreases as
discussed in Chapter 9. 15% moisture is common in
high volatile bituminous coals, 30% is seen in subbituminous, and more than 40% is common in some lig14-3
The Babcock & Wilcox Company
nites. Moisture contents in excess of 40% exceed the
ignition capability of conventional PC-fired systems.
Alternate systems are then required to boost drying
during fuel preparation and/or divert a portion of the
evaporated moisture from the burners. Char burnout
is impaired by moisture which depresses the flame
temperature. This is largely compensated for by the
generally higher inherent reactivities and porosities
of the higher moisture coals.
Effect of mineral matter content
The mineral matter, or resulting ash, of the coal is
inert and dilutes the coal’s heating value. Consequently, more fuel by weight is required as ash content increases in order to reach the furnace net heat
input. Mineral matter content averages about 10% for
U.S. coals but can exceed 30% in some U.S. and a
number of international coals.
The ash absorbs heat and interferes with radiative
heat transfer to coal particles, inhibiting the combustion process noticeably with high ash coals. The forms
of mineral matter determine the slagging tendencies
of the ash. These impact combustion by influencing
the furnace size and burner arrangement and the resulting flame temperatures and residence time. The
additional effects of ash on overall boiler design are
discussed in Chapter 21.
Pulverized coal combustion system
Effect of coal type
A variety of laboratory tests and correlations (Table
1) have been developed to predict combustion performance of coal and other PC-fired hydrocarbons such
as coke. The tests provide basic information on coal
properties and combustion behavior using small
samples of coal. Coal heating value, proximate and
ultimate analyses are fundamental requirements and
essential for performance calculations and emission
predictions. Other tests are performed to better characterize combustion behavior, particularly for unfa-
miliar coals. Correlations predict key aspects of combustion such as ignitability and char reactivity. The
correlations are often functions of proximate and ultimate analyses as these are nearly universally available. They relate experience to coal properties and
assist designers in formulating an appropriate combustion system for the coals in question.
Conventional PC Pulverized coal firing is adaptable
to most types of coal. Its versatility has made it the
most widely used method of coal firing for power generation worldwide. Most PC-fired systems have the
burners located in the lower portion of the furnace.
Wall-fired systems usually have the burners positioned
on either one wall or on two walls in an opposed arrangement as shown in Fig. 4. The other common arrangement positions the burners in the corners of the
lower furnace, and is referred to as corner or tangentially-fired. Primary air typically at 130 to 200F (54
to 93C) conveys pulverized coal directly to the burners at a rate set by the combustion controls based on
steam generation requirements. Secondary air is supplied by the forced draft fans and is typically preheated to about 600F (316C). All or most of the secondary air is supplied to the windboxes enclosing the
burners. A portion of the secondary air may be diverted
from the burners to overfire air (OFA) ports (discussed
later) in order to control the formation of NOx. The
secondary air supplied to the burners is mixed with
the pulverized coal in the throat of the burner. This
permits the coal to ignite and burn.
The combustion process continues as the gases and
unburned fuel move away from the burner and up
Steam
Drum
Table 1
Key Tests and Correlations to Evaluate Coal
Test
Proximate analysis
Ultimate analysis
Drop tube furnace tests
Thermogravimetric
analysis
Free swelling index
Petrographic examination
Correlation
Dulong's heating value
Ignition factor (B&W)
(Volatile matter x coal
oxygen) dry, ash-free
14-4
Windbox
Information
Combustibles: volatile matter, char
Inerts: moisture, ash
Major elements: carbon, hydrogen,
sulfur, nitrogen, oxygen
Ignition and char burnout behavior
Ignition, evaporation and char
burnout behavior
Char reactivity
Char reactivity
Information
Windbox
Coal
Bunker
Coal
Feeder
Burners
Burners
Air
Heater
Coal Pipes
Pulverizer
Estimated heating value of coal
Ignitability of coal
Char reactivity prediction
Fig. 4 Conventional pulverized coal-fired boiler.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
the furnace shaft. Final burnout of the char depends
on the coal properties, particle fineness, excess air, airfuel mixing, and thermal environment. The products
of combustion proceed out of the furnace after being
cooled sufficiently and enter the convection pass. Properly controlled furnace exit gas temperature is critical for achieving the required steam conditions and
efficiency, and to limit slagging and fouling on downstream tube surfaces.
Low volatile coals While the majority of bituminous,
subbituminous, and lignite PC-fired units are arranged in the manner described above, alternate designs are required to accommodate other coals. Coals
with low volatile matter content, notably anthracites,
are difficult to ignite. Their volatile matter provides
insufficient ignition energy for stable combustion with
a conventionally configured system. In addition, their
advanced coalification (see Chapter 9) has reduced
char reactivity, resulting in elevated char ignition and
burnout temperatures. These factors require hotter
furnaces to sustain combustion. A downshot firing
system (see Fig. 5) accomplishes this in combination
with an enlarged, refractory-lined lower furnace. The
downshot arrangement causes the flame to travel
down and then turn upward to leave the lower furnace. The char reactions, which build in intensity
some distance down from the burners, return their
heat near the burners as the gases turn upward to
exit the lower furnace. This heat supplies energy to
ignite the fuel introduced at the burners. The refractory lining in the furnace inhibits heat transfer and
PAX
Burners
Air Staging
Ports
Air Staging
Ports
Refractory
Lining
Fig. 5 Downshot-fired unit with refractory-lined furnace for low
volatile coals and primary air exchange (PAX) burners.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
elevates gas temperatures to sustain combustion. The
enlarged lower furnace also provides increased residence time to accommodate the slower burning char.
In addition, very high coal fineness is used to accelerate char reactions and reduce unburned carbon loss.
Indirect firing systems can provide hotter, fuel-rich
mixtures to the burners to further improve ignition
performance with anthracites. Economics and NOx
emission regulations have limited downshot fired units
in the U.S., although they are applied internationally
where low volatile coals are a major fuel source.
High moisture coals The other main category of nonconventional PC-fired units is that used for lignites
with very high moisture content. Moisture content in
these coals typically ranges from 50 to 70% by weight,
which is well beyond the level that air-swept pulverizers can adequately dry. (See Chapter 13.) Instead,
hot gases, removed from the upper portion of the furnace, are used in combination with beater mills to dry
and prepare the fuel. These hot gases, near 1832F
(1000C), are more suitable for coal drying than preheated air, with a practical upper limit of 752F (400C).
Furthermore, the low oxygen content of the flue gas
provides a relatively inert atmosphere in the grinding equipment, lessening the threat of fire or explosion as the hot gas mixes with these reactive coals. The
fuel is conveyed from the mills to the burners located
on the walls, and combustion proceeds as secondary
air mixes with the fuel in the furnace. Units of this
design are prevalent in parts of Europe and Australia where high moisture brown coals are used.
Combustion system and boiler integration
The most fundamental factors that determine the
boiler design are the steam production requirements
and the coal to be fired. The thermal cycle defines the
heat absorption requirements of the boiler which supplies the rated steam flow at design temperature and
pressure. Gas-side parameters, based on the design
coal, are used to estimate boiler efficiency. Heat input
requirements from the coal can then be determined,
setting the coal firing rate at maximum load. The number and size of pulverizers are then selected. Frequently, the pulverizer selection is based on meeting
maximum requirements with one mill out of operation.
This permits maintenance on one pulverizer without
limiting boiler load.
The size and configuration of the furnace are designed to accommodate the combustion characteristics
and the slagging tendencies of the coal ash as discussed in Chapter 21. NOx emission control factors are
also incorporated into the layouts of modern combustion systems. Furnace volume must provide sufficient
residence time to complete combustion. Heat input per
plan area is a key parameter to gauge thermal loading, and has to be moderated with high or severe
slagging coals. Peak flame temperatures can exceed
3000F (1649C) in the burner zone, well in excess of
ash fusion temperatures. Molten ash accumulations
are controlled by providing a furnace of appropriate
size, and by inclusion of sootblowers. Furnace width
strongly influences the burner arrangement, furnace
depth is critical to gas-side mixing and OFA system per14-5
The Babcock & Wilcox Company
formance, and height is elemental for setting vertical
burner spacing and for residence time. Increasing the
height of the burner zone reduces thermal loading and
tends to reduce NOx formation. However, taller burner
zones tend to reduce upper furnace residence time and
pose problems for completing combustion for a given
furnace volume. The best overall furnace design takes
into consideration many cross-related factors and is
strongly influenced by experience.
The number of burners and the heat input per
burner are selected to minimize flame impingement
on the furnace walls. Multiple burners at moderate
inputs, in an opposed-fired arrangement, are favored
to provide uniform heat distribution across the furnace
and to inhibit localized slagging. The burner design
is based on fuel parameters and NOx emission control
requirements in order to provide complete combustion
and minimum pollutant emissions. An OFA system
may be included to further reduce NOx, depending on
emission limits and coal sulfur content. High sulfur
coals pose corrosion risks to common furnace tube materials under fuel-rich conditions. OFA can still be safely
employed in such cases by use of alloy weld overlay or
similar measures to protect tubes in the burner zone.
Theoretical and excess air quantities are determined for the required coal input rate from combustion air calculations as discussed in Chapter 10. Fans,
ductwork, air heaters, windboxes, and burners are
sized to satisfy flow, pressure loss, air preheat and
velocity requirements for the unit. OFA ports are designed to satisfy jet penetration and dispersion criteria with acceptable pressure drop.
Burner integration
Burners are the central element of effective combustion system designs which include fuel preparation, air-fuel distribution, furnace design and combustion control. Burners can be categorized as pre-mix and
throat-mix types. Pre-mix burners combine secondary
air and fuel upstream of the combustion chamber.
Throat-mix burners, including essentially all PC-fired
burners, introduce secondary air to the fuel in the
burner throat at the entrance to the furnace (Fig. 6).
The secondary air is supplied in a manner to induce
air-fuel mixing and thereby sustain ignition and produce a stable flame. The mixing rate of air and fuel directly affects flame stability, flame shape, and emissions.
Fuel preparation influences Pulverizers are designed
to grind a specific quantity of coal, with given grinding characteristics, to a prescribed level of fineness (see
Chapter 13). The pulverizer type and operating conditions determine the quantity and fineness of pulverized coal supplied to the burner, as well as the required
quantity of primary air. The number of burner lines
per pulverizer varies with the furnace size and design
philosophy, with four to eight as the most common
range for medium and large utility boilers. In practice this results in burner maximum coal rates typically in the range of 10,000 to 30,000 lb/h (1.26 to 3.79
kg/s). Given the normal range of coal heating values,
this translates into maximum burner heat inputs of
100 to 300 million Btu/hr (29 to 88 MWt). In contrast,
small utility and industrial boilers have PC-fired burn14-6
Fig. 6 Circular register pulverized coal burner with water-cooled throat.
ers with maximum inputs commonly in the 50 to 100
million Btu/hr (15 to 29 MWt) range, and may have
only 2 or 3 burners per pulverizer. Pulverizers can
typically operate at grinding rates down to 25 to 40%
of maximum capacity, depending on the design, coal
variability, and control system. Burners are expected
to operate with stable flames over the normal turndown range of the associated pulverizer. This can
usually be accomplished with good coal, but can be
problematic with difficult to ignite coals.
Primary air is supplied to the pulverizer to facilitate coal drying, for circulation within the mill, for classification of coal particles, and for transport of the coal
through the coal pipes to the burners. Primary air temperature to the mill depends on the air preheat capability, moisture content in the coal, primary air to coal
ratio in the mill, and the required mill outlet temperature. Mill inlet temperatures may drop below 300F
(149C) for dry coals, and reach 700F (371C) with lower
rank coals. Resulting mill outlet temperatures, approximately the fuel temperature supplied to the burners, range from 130F (54C) with low rank coals to 200F
(93C) with high rank coals. Primary air leaving the
mill is saturated with moisture with low rank coals,
posing an ignition burden. Pulverizers typically require 40 to 70% of their full load primary air requirements at their minimum output level. In addition, the
PA/PC mixture traveling to the burners must be transported at a minimum of 3,000 ft/min (15 m/s). This
velocity serves to prevent the coal particles from dropping out of suspension in horizontal runs of coal pipe.
Minimum primary air flow is the greater of the minimum PA flow required for the pulverizer or the minimum required to satisfy coal pipe velocity limits.
Stoichiometry refers to the ratio of air supplied to
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
the calculated theoretical air requirement. The primary stoichiometry, from the primary air, can vary by
a factor of three depending on the coal and pulverizer conditions. Primary stoichiometry directly influences combustion conditions in the root of the burner
flame, with strong impacts on NOx formation as discussed later. Further, for a given burner stoichiometry,
increasing PA reduces the available secondary air
(SA). The SA/PA ratio is also seen to vary greatly with
coal and pulverizer conditions. See Table 2. Higher SA/
PA ratios provide greater aerodynamic control of airfuel mixing and improved burner performance. Low
SA/PA ratios can result in flame instability. In summary, fuel preparation issues dramatically vary the condition of the fuel stream supplied to the burner, and
greatly influence the burner performance.
The quantity of coal supplied to the pulverizer is
regulated by a coal feeder (see Chapter 12). Systems
lacking accurate PA or coal measurement and control,
as is commonly the case with ball tube mills, restrain
optimization of combustion equipment and cause operational inconsistencies.
Primary air and pulverized coal exit a pulverizer
and travel through coal pipes to the associated burners. The distribution of the PA/PC mixture among coal
pipes is dependent on air and solids flow patterns at
the pulverizer exit, and by flow resistance in the individual coal pipes. Restrictors or orifices in the coal
piping from the pulverizer to its burners serve to more
evenly distribute coal among several burners. As
burner nozzle velocity increases, the ignition point
gradually moves farther from the burner. Excessive
burner nozzle velocity can result in blowoff of the flame,
a potentially hazardous condition where coal ignition and
flame stability are lost. High burner nozzle velocities also
result in accelerated erosion of burner hardware.
Secondary air supply Forced draft (FD) fan(s) supply the secondary air (SA) for combustion. Total air to
the boiler is basically the sum of primary air and secondary air. The FD fans must supply secondary air
in sufficient quantity to achieve the intended excess
air at the boiler outlet. Modern PC-fired boilers typi-
cally operate with 15 to 20% excess air at full load,
and with higher excess air as load is reduced. Excess
air, that is air beyond theoretical requirements, is
necessary to assure complete combustion in practical
systems given imperfections in air-fuel balance and
unpredictable variations in coal quality. The FD fans
also supply the motive force to pump secondary air
through the various downstream equipment. In pressurized systems, the FD fans provide the pressure to
overcome system resistance from the fans, through the
boiler and all backend equipment. In balanced draft
systems, the FD fans supply sufficient pressure for the
SA to enter the furnace, then are augmented by Induced Draft (ID) fans which draw gases through the
boiler and backend equipment.
Dampers and variable speed motor drives at the FD
fans are used to regulate air flow. Steam coil or glycol
heaters boost air temperature from the FD fans. Tubular or regenerative air heaters (Chapter 20) transfer heat from flue gas leaving the boiler and raise air
temperature to about 600F (316C). In some systems,
a portion of this preheated air is diverted to hot PA fans
to boost pressure for use in the pulverizers. Other
systems use cold PA fans and separate or tri-sector air
heaters to supply PA for the pulverizers. The secondary air flow is measured downstream of the air heaters, then ducted to the windbox(es) which enclose the
burners. The windbox may be partitioned or function
as an open plenum, as discussed later. An overfire air
system, if used, will extract a portion of the secondary air for the OFA ports.
Distribution of SA among burners in a windbox occurs by several means and to varying degrees of uniformity. The physical size of the windbox and the
burner arrangement result in variations in SA pressure and velocity within the windbox which lead to
SA maldistribution. The air flow resistance of the
burners acts to improve distribution among burners
to some extent. The burners may be equipped with
adjustable dampers or registers which provide a
means to further balance SA distribution. Modern burners are equipped with air flow measurement equipment
to facilitate adjustments for uniform SA distribution.
100
1.5
100
1.2
12,000
12,000
7.5
7.5
9.0
9.0
0.17
0.13
1.15
1.15
5.8
7.6
Burner functions
Flame stability A burner introduces the primary air
and pulverized coal to the secondary air in a manner
that establishes a stable flame. This involves producing a flame front close to the burner over a range of
operating conditions. Igniters are used to sustain combustion when flames would otherwise be unstable. Igniters are always required to initiate combustion as
coal is first introduced to the burner, and during a
normal burner shutdown. The burner normally sustains a stable flame by using heat from coal combustion to ignite the incoming pulverized coal. A flame
safety system, included with modern burners, electronically scans the flame to verify stability and triggers corrective action if the flame becomes unstable.
Air-fuel mixing The burner initiates the mixing process of secondary air with the PA/PC mixture. However, overall air-fuel mixing is a combination of several factors. An air staging OFA system, if so equipped,
Steam 41 / Burners and Combustion Systems for Pulverized Coal
14-7
Table 2
Pulverizer Impact on Burners (Unstaged)
Pulverizer Type
Vertical Spindle Attrita Ball Tube
Pulverizer capacity, % 100 100 100
PA/PC
1.8
1.8
1.8
(pulverizer), lb/lb
Coal heating value, 12,000 8000 6000
Btu/lb
Coal theoretical air,
7.5
7.5
7.5
lb/104 Btu
Theoretical
9.0
6.0
4.5
lb air/lb coal, lb/lb
Stoichiometry
0.20 0.30 0.40
to burner nozzle
Total burner
1.15 1.15 1.15
stoichiometry
SA/PA ratio
4.8
2.8
1.9
The Babcock & Wilcox Company
supplies the remaining secondary air to the process.
Flue gas recirculation (FGR) to the furnace hopper or
tempering ports, if so equipped for steam temperature
control, adds additional flow and mixing dynamics to
the furnace. Furnace mixing results from the expansion of high-temperature combustion products and
flow energies of PA, SA, OFA and FGR systems; and
from resulting flow conditions within the specific size
and structure of the furnace enclosure.
The amount of air-fuel mixing produced by the
burner is critical to combustion performance, and varies considerably with burner type. The simplest burners inject the fuel and air in parallel or concentric
streams without the benefit of other burner-induced
mixing. Entrainment of adjacent flow streams occurs
as the jets develop and due to jet expansion from combustion. Corner-fired furnaces operate in this manner, as do some roof-fired designs. Combustion performance greatly depends on mixing subsequently generated in the furnace. Mixing effectiveness decreases
with boiler load as air-fuel flow rates drop. This can
result in poor combustion performance at reduced
boiler loads.
Wall-fired burners may incorporate a variety of airfuel mixing techniques. Burner mixing can be induced
by using the primary air/pulverized coal (PA/PC)
stream, by using the secondary air, or by a combination of the two. Looking first at the PA/PC side, the
most frequently used burner mixing devices are deflectors, bluff bodies, and swirl generators. Deflectors
are frequently installed near the exit of the burner
nozzle to cause the PA/PC stream to disperse into the
secondary air. These deflectors, or impellers, also reduce axial momentum of the fuel jet, reducing flame
length. Impellers may also induce radially-pitched
swirl of the fuel jet to further accelerate mixing. Bluff
bodies are sometimes used in or adjacent to the burner
nozzle exit. Flow locally accelerates around the upstream side of the bluff body and recirculates on the
downstream side. The recirculation promotes mixing.
The bluff body can also be used to increase residence
time for a portion of the fuel near the burner, thereby
improving flame stability. The PA/PC may also be divided and injected as multiple streams in order to increase the surface area of the fuel jets and increase
the rate of combustion.
Secondary air swirl is the most common way to induce air-fuel mixing in circular throat burners. Swirl
generators are used upstream of the burner throat to
impart rotating motion to the secondary air. This air
leaves the burner throat with tangential, radial and
axial velocity components. Radial and axial pressure
gradients form in the flow field downstream of the
throat, with the lowest pressure being near the center of the throat.3 As swirl is increased, the pressure
gradients increase. This causes the flow to reverse and
travel along the axis of the flame toward the low pressure zone. A recirculating flow pattern is then generated near the burner. Deflectors and bluff bodies are
also used to induce localized mixing from the secondary air. Modern low NOx burners frequently subdivide
the secondary air into two or more streams. Swirl may
be imposed at different rates for these SA streams, to
14-8
satisfy flame stabilizing functions while limiting the
overall air mixing rate.
Burner mixing intensity is directly related to burner
throat velocity. This is a key design parameter and
varies considerably from burner type to burner type.
Higher throat velocities promote furnace mixing at the
expense of burner pressure drop. Higher mixing rates
tend to reduce unburned combustibles at the expense
of higher NOx emissions. Throat velocity decreases
with decreasing burner firing rate. Optimal air-fuel
mixing is achieved at reduced boiler loads by operating with fewer burners in service and by operating
those burners at higher firing rates.
Emission control Modern PC-fired burners play a
major role in controlling emissions of NOx (NO and
NO2), in addition to carbon monoxide (CO) and unburned carbon. Unburned combustibles have traditionally been a criterion for efficient burner operation.
Combustion efficiency depends on numerous other
factors, including coal reactivity and fineness, burner
design, OFA design, furnace design, excess air, and
operating conditions. Unburned combustibles are
minimized by rapid thorough mixing of air and fuel
in the furnace. NOx emissions from PC are minimized
in the opposite manner, by gradually combining air
and fuel. Many techniques which serve to lower NOx
tend to raise unburned combustibles and vice versa.
The practical application of these techniques to combustion system design in order to effectively control
emissions is considered in detail below.
Performance requirements
Pulverized coal-fired equipment should meet the
following performance conditions:
1. The coal and air feed rates must comply with the
load demand over a predetermined operating
range. The burners have to operate in a reliable
manner with stable flames. For modern applications with high volatile bituminous or subbituminous coal, flames should be stable without the use
of igniters from about 30 to 100% boiler load. The
minimum load depends on the coal, burner design,
and pulverizer load; operation below this load is
performed in combination with igniters in service.
2. Boiler emissions of NOx, CO, and unburned carbon
comply with design expectations for the particular
application. The actual limits vary considerably due
to regulations, the coal and combustion conditions,
the use of downstream equipment to further reduce
emissions, and ash disposal requirements.
3. The burner should not require continual adjustment to maintain performance. This fundamentally requires consistency in the fuel preparation
system and SA systems supplying fuel and air to the
burners. The unit should be designed to avoid the
formation of localized slag deposits that may interfere with burner performance or damage the boiler.
4. Only minor maintenance should be necessary during scheduled outages. To avoid high temperature
damage, alloy steel should be used for burner parts
exposed to furnace radiative heat transfer. The
burner structure needs to accommodate differen-
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
tial expansion and maintain integrity at high temperature. Burner parts subject to PC erosion should
be protected with wear resistant ceramic materials.
5. Safety must be paramount under all operating conditions. Automated flame safety and combustion control systems are recommended, and often required.
Conventional PC burners
Prior to NOx emission regulations introduced in
1971 in the U.S., the primary focus of combustion system development was to permit the design of compact,
cost effective boilers. As a result, the burner systems
developed focused on maximizing heat input per unit
volume to enable smaller furnace volumes using rapid
mixing burners which generated very high flame temperatures. An unintended side effect was the production of high levels of NOx. Burners used on such boilers include the conventional circular burner, the cell
burner, and the S-type burner. Most of these have been
replaced with low NOx burners in the U.S., but an examination of their designs is useful as it forms a foundation for the more advanced designs which followed.
Conventional circular burner
The circular burner (Fig. 6) was one of the earliest
forms of swirl-stabilized PC-fired burners. Due to its
success, this burner was used for more than six decades firing a variety of coals in many boiler sizes. The
burner is composed of a central nozzle to which PA/
PC is supplied. The nozzle is equipped with an impeller at the tip to rapidly disperse the coal into the secondary air. Secondary air is admitted to the burner
through a register. The register consists of interlinked
doors arranged in a circular pattern between two
plates. The doors are closed to cooling position when
the burner is out of service, are partially open for
lightoff and are more fully open for normal operation.
The registers influence SA swirl as well as quantity. Opening the register doors allows more air into
the burner, but reduces swirl, and vice versa. Moderate swirl produces a well shaped flame plume. Excessive swirl can cause the flame to flatten against the firing wall and cause localized slagging. Inadequate swirl
results in flame instability. Register adjustments to
modify flame shape can result in improper SA supply to
the burner in multi-burner applications. High combustion efficiency depends on uniform air-fuel distribution.
The circular burner can fire natural gas, oil or pulverized coal. Simultaneous firing of more than one fuel
is not recommended due to the potential for over-firing the burners and the resulting combustion problems. Variations of the circular burner are in operation at inputs from 50 to 300 × 106 Btu/h (15 to 88 MWt).
Cell burner
The cell burner combines two or three circular burners into a vertically stacked assembly that operates as
a single unit (Fig. 7). In the 1960s and 1970s, the cell
burner was applied to numerous utility boilers which
had compact burner zones. While highly efficient, the
cell burners produced high levels of NOx emissions and
tended to be mechanically unreliable.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
S-type burner
The S-type burner was developed in the early 1980s
as a functional and mechanical upgrade for the circular burner. The S-type burner separates the functional attributes of the circular burner for improved
SA control in a mechanically superior configuration.
(See Fig. 8.) The burner nozzle is generally the same
as that in the circular burner. However, secondary air
flow and swirl are separately controlled. Secondary air
quantity is controlled by a sliding disk as it moves
closer to or farther from the burner barrel. Secondary air swirl is provided by adjustable spin vanes positioned in the burner barrel. An air-measuring pitot
tube grid is installed in the barrel ahead of the spin
vanes. This provides a local indication of relative secondary air flow to facilitate sliding disk adjustments
to balance SA among burners. Swirl control for flame
shaping is controlled separately by spin vanes. The
S-type burner provides higher combustion efficiency
and mechanical reliability than the circular unit and
requires no pressure part replacement.
Low NOx combustion systems
NOx formation
NOx is an unintended byproduct from the combustion of fossil fuels and its emissions are regulated in
the U.S. and many other parts of the world. While a
number of options are available to control and reduce
NOx emissions from boilers, as discussed in Chapter 34,
the most cost effective means usually involves the use
of low NOx combustion technology, either alone or in
combination with other techniques. The effectiveness
of the pulverized coal NOx control technology depends
primarily upon the fuel characteristics and the combustion system design. For pulverized coal wall-fired
units, NOx emissions from older conventional combustion systems discussed above typically range from 0.8 to
Fig. 7 Conventional two-nozzle cell burner.
14-9
The Babcock & Wilcox Company
Fig. 8 S-type burner and components.
1.6 lb/106 Btu (984 to 1968 mg/Nm3: see Note below). Low
NOx PC combustion systems are capable of reducing NOx
down to 0.15 to 0.5 lb/106 Btu (185 to 615 mg/Nm3).
NOx control by combustion
Approximately 75% of the NOx formed during conventional PC firing is fuel NOx; the remainder is primarily thermal NOx. Consequently, the most effective
combustion countermeasures are those limiting fuel
NOx formation. Fuel NOx is formed by oxidation of fuelbound nitrogen during devolatilization and char burnout. Coal typically contains 0.5 to 2.0% nitrogen bound
in its organic matter. High oxygen availability and
high flame temperatures during devolatilization encourage the conversion of volatile-released nitrogen to
NOx. Nitrogen retained in the char has a lower conversion efficiency to NOx, primarily due to lower oxygen availability during char burnout. Reactive coals
with high volatile matter and low fixed carbon/volatile matter (FC/VM) ratios tend to be the most amenable to NOx control by combustion modification. Coals
with higher FC/VM and nitrogen content tend to produce higher NOx emissions.
The most effective means of reducing fuel-based
NOx formation is to reduce oxygen (air) availability
during the critical step of devolatilization. Additional air
must then be added later in the process to complete char
reactions and maintain high combustion efficiency.
Oxygen availability can be reduced during
devolatilization in two ways. One method is to design
the burner(s) to supply all of the combustion air, but
Note: The International Energy Agency conversion has
been adopted for NOx emission rates: 1230 mg/Nm3 equals
1 lb/106 Btu for dry flue gas, 6% O2, 350 Nm3/GJ for coal.
14-10
in a manner which limits the rate of air introduction
to the flame. Only a fraction of the air is permitted to
mix with the coal during devolatilization. The remaining air is then mixed downstream in the flame to complete combustion. Burners employing this technique
(low NOx burners) can reduce NOx emissions by 30 to
60% relative to uncontrolled levels. However, overall
air-fuel mixing is reduced to some extent and the flame
envelope is larger compared to rapid mixing conventional burners. Reducing the rate of air-fuel mixing
also tends to increase the quantity of unburned combustibles from the process. This strong tendency can
be counteracted by careful control of burner aerodynamics and overall combustion system design. In some
cases, improvements in the fuel preparation/delivery
system and increased coal fineness are required to
limit unburned combustibles to acceptable levels.
A second method of reducing oxygen availability
during the early phase of combustion is to remove a
portion of the combustion air from the burners and
introduce it elsewhere in the furnace. This method is
referred to as air staging. Air staging systems are frequently used in combination with low NOx burners to
multiply the NOx reduction effect. PC combustion systems typically operate with 15 to 20% excess air at
maximum firing rate. (See Chapter 10.) In some staging situations, reducing the air flow by 10% at the
burners is sufficient for a given level of NOx emissions
control. This permits the burners to continue to operate in an excess air condition. Reducing the air flow
to less than stoichiometric (theoretically required for
complete combustion air flow) conditions can further
reduce NOx emissions. This deeper staging minimizes
NOx formation, but inevitably results in more unburned
or partially burned fuel leaving the burner zone. The
remaining theoretical air and excess air must then be
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
supplied through air staging ports (NOx ports or OFA
ports). This can amount to 25% or more of the total air
supplied to the boiler. The introduction of large quantities of staging air to the unburned fuel subsequently
causes NOx reformation to occur. The rate of introduction and mixing of OFA in the furnace are critical to
minimizing NOx reformation in deeply staged systems.
The application of an OFA system can increase unburned combustibles, slagging in the combustion zone
and furnace, and the risks of furnace tube corrosion.
These risks increase with coals having high sulfur content and/or high slagging characteristics, and with less
reactive coals. While technologies exist to address these
risks, the use of OFA may be limited or avoided with
such coals for economic reasons in favor of alternate
NOx reduction methods.
Another method of reducing NOx emissions is referred to as reburning or fuel staging. This control
technique destroys NOx after it has formed. Fuel staging involves introducing the fuel into the furnace in
steps. Typically, the bulk of the fuel is burned in the
furnace at near stoichiometric conditions. The balance
of the fuel, with a limited amount of air, is then injected to create a reducing zone part way through the
combustion process. The reducing conditions form hydrocarbon radicals which strip the oxygen from previously formed NOx, thereby reducing overall NOx
emissions. The balance of the air necessary to complete
the combustion is then added. Some fuel-staged systems involve separate burners or fuel injectors followed by NOx ports which supply the remaining combustion air. The reburn fuel can be coal, but this calls
for special measures to limit unburned combustibles
from the process. Lighter fossil fuels, especially natural gas, generate more hydrocarbon radicals and can
improve emissions reduction, but their cost or avail-
ability can deter usage. Fuel staged systems have
generally not proven to be as cost-effective as other
NOx reduction techniques with PC-firing. However,
some advanced low NOx burners embody fuel staging
while supplying all the fuel to the burners. A portion
of the fuel is introduced in a manner to generate hydrocarbon radicals; these are mixed into the flame
later to reduce previously formed NOx. These burners
can achieve NOx reductions of 50 to 70% from baseline uncontrolled levels.
Dual register burner
The Babcock & Wilcox Company (B&W) began experimenting with techniques to reduce NOx from PCfired burners in the 1950s. A slot burner, which incorporated controlled air-fuel mixing, was first developed.4 The air introduced through the burner throat
mixed rapidly in the flame while air diverted to the
external slots mixed gradually. While effective, the
design with slots external to the burner throat was
difficult to apply to furnaces. In 1972, B&W developed
the dual register burner (DRB) for firing pulverized
coal. The DRB (Fig. 9) provided two air zones, each
controlled by a separate register, around an axially
positioned coal nozzle. A portion of the secondary air
was admitted through the inner air zone and highly
swirled to aid ignition and flame stability. The remainder passed through the outer air zone with moderate
swirl and was gradually mixed downstream in the
flame. The burner nozzle was equipped with a venturi to disperse the primary air-coal mixture. The mixture was then injected into the throat without deflection. The results were a stable flame with a fuel-rich
core and gradually completed mixing downstream. The
first unit retrofit was completed in 1973 and achieved
50% NOx reduction relative to prior circular burners.
Fig. 9 Dual register burner (DRB) and compartmented windbox.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
14-11
The Babcock & Wilcox Company
This retrofit required no modifications to boiler pressure parts, fans, or pulverizers, and NOx ports were
not used. The U.S. government granted a patent to
B&W for the DRB in January 1974. Numerous variations have been used by B&W since its introduction.
The DRB was generally used in combination with
enlarged furnace combustion zones to reduce thermal
NOx and with a compartmented windbox to better control air distribution (Fig. 9). This design has the burners coupled with each pulverizer situated in an individual windbox compartment. Secondary air was metered and controlled separately for each compartment.
This approach corrected some of the SA flow imbalances among burners that were prevalent in open
windbox designs.
The DRB typically reduced NOx 40 to 60% from uncontrolled levels. This efficiency enabled its use on new
boilers without NOx ports or other air diversion systems. Utility boiler NOx emissions with the DRB ranged
from 0.27 to 0.70 lb/106 Btu (332 to 861 mg/Nm3).
DRB-XCL® burner
The Dual Register XCL burner is a second generation low NOx burner which incorporates fuel staging
technology along with the air staging technology
found in the original DRB. The DRB-XCL® is physically arranged as shown in Fig. 10, and draws heavily
on the proven mechanical design of the S-type burner.
Air flow to the burner is regulated by a sliding disk.
Sliding Air
Damper Drive
Sliding Air
Damper
An impact/suction pitot tube grid is located in the
burner barrel to provide a local indication of secondary air flow. With this information, the secondary air
can be more uniformly distributed among all burners
by adjusting the sliding disks or other means. Balanced air and fuel distribution among all burners is
critical to combustion efficiency, particularly with low
NOx systems. Downstream of the pitot tube grid are
the inner and outer air zones. Adjustable vanes in the
inner zone impart sufficient swirl to stabilize ignition
at the burner nozzle tip. The outer zone, the main SA
path, is equipped with two stages of vanes. The upstream set is fixed and improves peripheral air distribution within the burner. The downstream set is adjustable and provides proper mixing of this secondary
air into the flame. The burner nozzle is equipped with
hardware to accomplish the necessary fuel mixing.
This may include a conical diffuser and flame stabilizing ring or an impeller. These combine to improve
flame stability while controlling NOx and flame length.
The DRB-XCL burner reduces NOx 50 to 70%5 from
uncontrolled levels without using NOx ports. This
added level of NOx reduction is possible by the fuel
staging effects generated in the near-flame field.
A plug-in version of the DRB-XCL enables its use
in many retrofit applications without requiring pressure part modifications, and has demonstrated reduced unburned combustibles.6 The burner can be
equipped for firing natural gas and/or fuel oil when
multi-fuel capability is desired.
Air
Measurement
Pitot Grid
Adjustable
Outer Vanes
Adjustable
Inner Vanes
Flame
Stabilizing
Ring
Burner
Elbow
Primary Air/
Pulverized Coal Inlet
Burner
Nozzle
Conical
Diffuser
Fig. 10 DRB-XCL® low NOx burner for pulverized coal firing.
14-12
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
DRB-4Z® burner
B&W’s third generation low NOx burner, the DRB4Z® burner, incorporates even more advanced emission control technology in a well proven mechanical
configuration. The patented DRB-4Z design combines
primary zone stoichiometry control with fuel staging
and air staging technology to achieve very low NOx
emissions along with improved combustion efficiency.
Conceptual development, using Computational Fluid
Dynamics (computer modeling), indicated the benefits
of an additional air zone separating the coal nozzle
from the principal air zones of the burner.7 These concepts were proven through extensive testing8 during
the development of the burner in B&W’s Clean Environment Development Facility.9
This additional air zone, the transition zone, acts as
a buffer between the high temperature, fuel-rich flame
core and the secondary air streams (see Fig. 11). The flow
field produced by the transition zone draws gases from
the outer portions of the flame inward toward the flame
core. NOx formed in the oxygen-rich outer flame region
is reduced back to other nitrogenous species in the process. A further advantage of the transition zone is the
ability to alter primary zone stoichiometry.
Table 2 indicates the variations in primary stoichiometry which are inherent to different coals and pulverizer designs. Inadequate primary zone stoichiometry inhibits combustion during the critical stage of
devolatilization. Air supplied by the transition zone
can compensate for this without flooding the flame core
with secondary air from the main air zones. SA swirled
through the inner air zone serves to anchor and stabilize the flame. SA admitted through the outer air
zone is staged to gradually mix into the flame. NOx
Linear
Actuator
Inner Spin
Vane
Adjustment
Main Sliding
Air Damper
Fixed
Vane
Inner
Spin Vane
reductions of up to 80% from uncontrolled levels are
possible with the DRB-4Z. The burner is well-suited
for use with an OFA system when the lowest NO x
emissions are required.10,11
The physical arrangement of the DRB-4Z is depicted in Fig. 12. The mechanical construction was
adapted from the proven integrity of the DRB-XCL,
while incorporating the advanced aerodynamic features. The coal nozzle strongly resembles the predecessors and is interchangeable in some situations. The
transition zone is supplied with SA by means of slots
and a manually adjustable sliding sleeve. A sliding air
damper is used to regulate SA to the main air zones.
A linear actuator positions this damper in open
windbox applications in order to automatically control
the SA flow to the burner. A pitot tube grid is installed
downstream of the damper to provide a local indication of SA flow. Manually adjustable vanes are located
in the inner and outer air zones to enable optimization of swirl settings during burner commissioning.
Fixed vanes are supplied to improve air flow distribution and reduce pressure drop through these air zones.
The DRB-4Z plugs into wall openings from most existing burners to facilitate its use as a replacement upgrade.
Improved aerodynamics provide better overall air-fuel
mixing which results in significantly lower unburned
combustibles than earlier low NOx burner designs.
The shop-assembled construction of the DRB-4Z is
illustrated in Fig. 13. The one-piece assembly simplifies and quickens installation. Front end components
are fabricated from heavy, high quality stainless steel
and mechanically stiffened in a manner which accommodates differential expansion at elevated temperature while maintaining product integrity. Permanent
thermocouples are supplied to assure components are
Outer
Spin Vane
E
D
B
A
Coal Inlet
Transition Zone
Air Flow Adjustment
F
Transition
Zone
Air Flow
Outer Spin Vane Adjustment
C
Windbox
A
B
C
D
E
F
Oxygen Lean Devolitilization
Recirculation of Products
NOx Reduction Zone
High Temperature Flame Sheet
Controlled Mixing of Secondary Combustion Air
Burnout Zone
Fig. 11 DRB-4Z® low NOx combustion zones.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
14-13
The Babcock & Wilcox Company
Transition Zone
Sliding Air Damper
Air
Measurement
Pitot Grid
Fixed
Vane
Adjustable
Outer Vanes
Sliding Air
Damper Drive
Adjustable
Inner Vanes
Transition
Zone
Burner
Elbow
Sliding
Linkage
Primary Air/
Pulverized Coal Inlet
Main Sliding
Air Damper
Fig. 12 DRB-4Z® low NOx burner for pulverized coal applications.
kept within safe operating temperatures. The burner
is also capable of low NOx firing natural gas, or can
be equipped to fire fuel oil as a primary fuel.
Low NOX cell burner
The cell burners discussed earlier produced high NOx
emissions, but their unique arrangement (Fig. 7) made
it difficult to fit low NOx burners in the existing wall
openings. The Low NOx Cell burner (LNCB) was developed to replace two nozzle cell burners in a plugin design. In essence, all the coal is supplied to one
burner throat with a portion of the secondary air. The
balance of the secondary air is supplied to the other
burner throat, which serves as an integral NOx port for
each burner location. NOx levels can be reduced by 50%
with the LNCB while maintaining high combustion efficiency. Advanced second and third generation low NOx
burners are designed for plug-in use in cell burners and
now provide lower NOx alternatives to the LNCB.
Air staged systems
Air staging involves removing a portion of the air
from the burners to reduce oxygen availability early
in the combustion process, and reintroducing it later
in the combustion process. Often the physical arrangement dictates replacing the staged air through
ports located above the combustion zone, hence the
name overfire air (OFA) is commonly applied to such
systems. The layout of a combustion system and furnace, however, may necessitate supplying staged air
14-14
at the same elevation or below the burner zone, such
that OFA is something of a misnomer. OFA is used here
in its generic sense to refer to any air staged system.
The ports through which the OFA is injected are called
OFA ports or NOx ports.
B&W pioneered the development and application
of NOx ports and air staging as a NOx emission control technique. This work, which began in the 1950s,
was initially directed at NOx reduction for oil- and gasfired boilers in California. R.M. Hardgrove of B&W
filed a patent for a Method for Burning Fuel on June
Fig. 13 Fully assembled DRB-4Z® burner ready for shipment.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
18, 1959, disclosing key aspects of air-staging influences on NOx emissions. The patent was granted in
1962, and NOx ports have been used ever since by
B&W. Today, the NOx reduction effectiveness of OFA
systems is attested to by their widespread use in coal,
oil and gas units, including wall-fired, corner-fired and
Cyclone designs.
The degree of NOx reduction achieved by air staging depends on numerous factors, including fuel properties, burner design and associated NOx emissions,
furnace design, operating conditions, and the OFA system design. Key design issues are the quantity of OFA
and the arrangement and NOx port design. NOx reduction is a function of the percent combustion air removed
from the burners for use as OFA. Consider a typical PCfired situation for a unit operating at 20% excess air at
full load, that is, with 120% theoretical air (Fig. 14).
1. A low NOx burner (LNB) would produce a NOx
emission level noted as a1 for this example.
2. Adding a moderate amount of air staging, in this
case 15 percentage points of air, would still leave
the combustion zone under oxidizing conditions
(above 100% theoretical air). Burner zone stoichiometry (BZS) is 1.05 in this case. NOx emissions
are reduced to level b1. Removing this 15 percentage points of secondary air from an existing combustion system would reduce burner mixing effectiveness to some degree, impairing flame stability, and
may add to slagging tendencies in the burner zone.
3. Increasing the air staging to 30 percentage points
drops the combustion zone to reducing conditions
(less than 100% theoretical air). BZS is now 0.90,
and the greater air staging reduced NOx emissions
to point c1. Notice that some NOx reformation occurred from the introduction of the OFA such that
the exit NOx c2 was somewhat higher than c1. Removing 30 percentage points of SA from an existing combustion system requires new or revised
burners to produce sufficient mixing with lesser
SA. A BZS of 0.90 means only 90% of theoretical
air is supplied to the burners, so at least 10% of
the fuel remains unburned leaving the burner
zone. This raises risk of increased unburned combustibles even after addition of OFA. Reducing conditions in the burner zone also raise risks of furnace
tube corrosion with high sulfur coals, and can be
problematic for slagging.
4. Increasing air staging to 40 percentage points
drops BZS to 0.80, meaning at least 20 percent of
the fuel is unburned leaving the combustion zone.
Actual constraints inherent to the process cause
considerably more than 20% of the fuel to leave
the burner zone unburned. NO x leaving the
burner zone dropped to point d1. In this example,
the rapid addition of 40 percentage points of OFA
to the significant amount of unburned fuel resulted in major NOx reformation. Consequently the
exit NOx d2 actually exceeded the lesser staged case
c2. However, NOx reformation could be lessened by
gradually reintroducing the OFA, and limiting O2
concentrations and combustion rates in the latter
stages of combustion. This results in the lowest level
of exit NOx noted as d3.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
OFA with wall-fired systems The description above
illustrates the advantages of air staging for NOx reduction, but also reveals potential problems which
may result. Application of OFA to an existing wall-fired
system reduces burner-induced mixing, which tends
to impair flame stability and slows the combustion process. This occurs due to lower burner throat velocities
and lower secondary air to primary air ratio. Resulting reductions in burner SA momentum and mixing
energy can best be compensated for by raising burner
throat velocity. Deep staged OFA systems therefore
necessitate the use of new, smaller burners for good
combustion performance. Greater amounts of swirl, for
at least a portion of the SA, further assist in flame stabilization. The burner arrangement and/or swirl orientation may need to be altered to present a more uniform
flow field to the OFA system. Advanced low NOx burners with improved SA control measures can compensate
for these issues with air staged systems, and have demonstrated equal or less furnace slagging tendencies compared to some unstaged conventional designs.
After properly dealing with the wall-fired burners,
the design of the air staging system can proceed. The
major functional issue concerns proper distribution of
the OFA within the furnace, in a manner which minimizes NOx reformation, CO, and unburned char. Minimizing unburned combustibles calls for rapid mixing
of OFA, while minimizing NOx calls for gradual mixing. The OFA port jets have to travel cross flow to the
furnace gases and deliver air in time for combustion
reactions to be completed in the furnace. This favors
fewer ports with high mass flow and velocity. But OFA
must also be adequately dispersed to cover the entire
cross-section of the furnace. This tends to favor a large
number of smaller ports. Ports located closer to the
burners provide more time for mixing and lessen unburned combustibles, while locating ports further
away tends to maximize NO x reduction. Effective
implementation of OFA systems requires the combination of experience, computer modeling, and on-line
adjustability. Computer modeling (see Chapter 6) pro-
a
LNB only
a
b
NOx Reformation
b NO
x
d Leaving
c Furnace
d
c
d
NOx Leaving Burner Zone (1)
1.3
1.2
1.1
1.0
0.9
0.8
0.7
Burner Zone Stoichiometry
0.6
10
0
20
30
40
Minimum Unburned Fuel without OFA, %
Fig. 14 The effects of OFA design on NOx emissions.
14-15
The Babcock & Wilcox Company
vides a means to evaluate the mixing effectiveness of
alternate OFA system designs, with regard to port size,
quantity, placement, and design.12 High grid resolutions
near the burners and OFA ports enable more accurate
assessment of reactions and flow fields, but require larger
model size and computational resources. Validation of
model predictions to field experience is essential. Ultimately, supply of equipment with on-line adjustability
provides the means to tune the OFA system to the actual conditions and minimize emissions in the field.
The Dual Zone NO x port (Fig. 15) provides the
means to vary on-line the jet penetration versus dispersion characteristics of OFA supplied through this
port. A sliding sleeve damper with linear actuator provides the means to regulate OFA to each port. This
enables varying OFA among the various ports to improve distribution, and to vary OFA versus load for
NOx control. A relative indication of air flow is provided
locally at each port by a pitot grid installed inside the
port. The inner zone of the Dual Zone port is comprised of a core pipe with a manually adjustable sliding disk to adjust air flow. The core pipe produces a
high velocity air jet for penetration across the furnace.
The outer zone of the port is equipped with spin vanes.
Increasing the swirl of this air causes more localized
mixing by entraining furnace gases in the recirculation. The vanes can be manually adjusted to vary swirl
over a wide range. The combination of these adjustments has a strong effect on mixing rates and emissions. Dual Zone ports, or other types, can be enclosed
in windboxes in a manner similar to the burners. In
some situations, it is more economical to supply individual air ducts to each port. Performance and repeatability benefit from the inclusion of equipment to
Linear
Actuator
Total Flow
Air Damper
Biasing
Air Damper
(Inner Zone)
measure and regulate air flow to the OFA system distinctly from flow to the burners.
Maximum NOx reduction with air staging requires
operation at low burner zone stoichiometries, e.g. 0.85
or less. NOx reformation becomes a problem if all the
associated OFA is rapidly reintroduced to the furnace.
To avoid this, it is beneficial to employ two levels of
OFA. The level closest to the burner zone supplies a
lesser portion of the OFA to bring the BZS close to 1.00.
This is followed by the second level of OFA which supplies the balance of secondary air. This arrangement
reduces peak O2 levels and moderates combustion
rates in the upper furnace to control NOx, while providing the mixing necessary to limit unburned combustibles.
Most OFA systems draw hot SA from the ducts or
plenums which supply air to the burners. Use of preheated air supplied from the FD fans through the air
heaters helps maintain boiler efficiency, but limits the
available static pressure for the OFA system. The location, quantity, size and design of the OFA ports have
to be compatible with static pressure constraints.
Booster fans can be used to raise static pressure, but
can become massive to accommodate the quantities
and temperature of OFA involved with many utility
boiler applications. Complications with locating such
fans, along with their expense and operating costs,
detract from their use. Most often the FD fans are
suitable as motive sources for proper system design.
OFA with corner-fired systems Overfire air has
proven to be very effective in corner-fired boilers and
is the dominant method of NOx control with modern
systems.13 It is useful to first consider the functionality of the corner-fired combustion system before considering the application of overfire air with such
Inner Air Zone
Pitot Grid
Adjustable
Vane
Outer
Air Zone
Pitot Grid
NO x Port
Support System
Sliding
Linkage
Low
NO x
Burners
Fig. 15 Dual Zone NOx port.
14-16
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
equipment. In a corner-fired system, coal and air are
introduced into the furnace at distinct elevations
through windbox assemblies located in the corners (for
four corner furnaces) and at protrusions midway along
the front and rear walls (for eight corner furnaces).
The windbox nozzles direct the coal and air streams
at slight angles off of the diagonals and tangent to an
imaginary firing circle in the center of the furnace as
shown in Fig. 16. The combination of the firing angles
and momentum of the fuel and air streams create a
rotating or cyclonic fireball that fills the plan area of
the furnace. In this firing system, the furnace acts like
a large burner where each corner provides the ignition energy to the corner downstream and the swirling action of the fireball stabilizes the flames. For
steam temperature control at lower loads, the fuel and
air nozzles are designed to tilt up or down in unison
to raise or lower the fireball and thus increase or decrease furnace exit gas temperatures.
Each windbox is divided along its height into alternating compartments of air and coal as shown in Fig.
17. Each pulverizer serves one complete coal elevation (i.e., all four or eight corners). The windboxes distribute secondary combustion air as fuel air and auxiliary air. Fuel air is the portion of the secondary air
admitted to the furnace through the coal compartments and air annulus around each coal nozzle tip and
is used to support combustion and stabilize flames.
Auxiliary air is the balance of the secondary air which
is admitted into the furnace through air nozzles located in the compartments above and below each coal
elevation to complete the combustion. Primary air is
the balance of air entering through the coal pipes and
nozzles and serves in the same manner as in wall-fired
burner arrangements. Secondary air is distributed in
the windbox by a system of dampers located at the inlet
of each compartment as shown. Fuel air dampers are
controlled based on pulverizer feed rate whereas auxiliary air dampers are controlled based on windbox to
furnace differential pressure. In conventional applications, all of the secondary air enters through the
Windbox #2
corner windbox assemblies. However, these cornerfired combustion systems embody air staging technology by virtue of the layered introduction of fuel and
air. This lowers NOx by slowing the mixing of air and
fuel as they proceed into the flame vortex.
Application of overfire air to a corner-fired system
involves diverting a portion of the auxiliary air to an
overfire air zone located above the combustion zone.
Depending on the required NOx reduction, OFA can
be introduced at the top of the windbox through two
or more air compartments and/or through separate
ports located some distance above the top coal elevation. Increasing the separation between the combustion zone and the OFA ports reduces NOx emissions
most effectively. Therefore, for a given quantity of
OFA, separated OFA is generally twice as effective as
windbox OFA for reducing NOx. Also, since separated
OFA ports require new openings in the upper furnace,
they can be made larger than windbox overfire air for
greater NOx reduction, as windbox compartment sizes
are limited by the existing windbox width and compartment heights.
A proven approach for retrofitting a separated OFA
low NOx system involves the addition of one level of
four to ten ports depending on furnace type. For
smaller four-corner furnaces, the ports are typically
located on furnace corners since adequate coverage
Windbox #3
Primary Air,
Coal and
Secondary Air
Imaginary
Firing Circle
Windbox #1
Windbox #4
Fig. 16 Plan view of corner-firing arrangement.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
Fig. 17 Corner-fired windbox assembly for coal firing (courtesy of
R-V Industries, Inc.).
14-17
The Babcock & Wilcox Company
can be achieved as these furnaces have smaller, more
square cross-sections than the larger eight-corner
units. Also, ductwork for four-corner units is simpler
when the ports are located on the corners. For larger
eight-corner furnaces with center division walls, the
ports may be located on the front and rear walls. They
are arranged in an interlaced fashion from front to
rear and offset in the direction of fireball rotation. This
effectively reduces NOx while providing more complete
coverage of the furnace plan area and corners for
better carbon burnout and CO control. In both furnace types, the ports are located several feet above the
highest coal elevation to allow separation distance for
effective NOx control but low enough to allow ample
furnace residence time for good carbon burnout after
overfire air injection. The location and sizing of ports
are also set to avoid or minimize buckstay modifications when possible. If necessary, computer modeling
serves to optimize port arrangement and performance.
The typical B&W separated OFA port for corner firing shown in Fig. 18 uses an all welded (no refractory), deep throat, perpendicular opening to cool the
air nozzles from the intense radiant heat in the OFA
zone. The port normally has two air compartments
with integral turning vanes and independent flow control dampers to maximize velocity and penetration over
the load range. The air nozzles can be manually tilted
and/or yawed on line for enhanced emissions control. A
small pitot tube grid is located near the inlet of each
nozzle for relative air flow indication and balancing.
Addition of an OFA system reduces secondary air
flow to the main windbox. To compensate for this, the
existing auxiliary air compartment and damper sizes
are reduced using blocking plates and the auxiliary
air nozzles are replaced with smaller ones. These modifications are required to maintain existing injection
velocity, pressure drop and thus, damper controllability over the load range. Adding only OFA has proven
to be the most cost effective and reliable combustion
system modification for reducing NOx emissions in corner-fired boilers.
Fig. 18 Corner-fired overfire air port (courtesy of R-V Industries, Inc.).
14-18
NOx reduction for units with only windbox overfire
air typically ranges from 20 to 30%. For additional NOx
reduction, separated OFA can be added to units with
or without windbox overfire air. NOx reduction with
these arrangements typically ranges from 40 to 60%,
depending on initial NOx levels, boiler size, furnace
type, heat release rate, separation distance and coal
reactivity.
Typical of other air staged systems, NOx reduction
on corner-fired units may be accompanied by some increase in CO emissions and unburned carbon. However, with careful system design and field tuning,
existing CO emissions can normally be maintained
with reasonable unburned carbon (UBC) results.
Burners for difficult coals
A few coals have proven to be considerably more
difficult to burn than others, including unreactive
coals and reactive coals which would burn readily
except for an overabundance of moisture and/or ash.
B&W has developed burners specifically for use with
these problem coals. The selection of burner type is
based on an empirical ignition factor derived from full
scale experience with difficult coals. This factor relates
variations in fuel ratio (FC/VM), moisture content, ash
content, and coal heating value to ignition behavior.
Burner choices for these applications include conventional and low NOx burners discussed above, the enhanced ignition (EI) burner, and the primary air exchange (PAX) burner.
Enhanced ignition burner
The enhanced ignition (EI) burner resembles the
DRB-XCL burner. The nozzle is equipped with a conical diffuser which concentrates the coal particles into
a fuel-rich ring near the walls of the fuel nozzle. However, the EI burner uses a larger coal nozzle tip to reduce the primary air and coal mixture velocity as it
enters the furnace. In addition, the dimensions of the
inner and outer air zones are adjusted relative to the
DRB-XCL burner to produce greater recirculation of
hot gases along the fuel jet. These hot gases accelerate ignition of the dense, low velocity fuel jet and significantly improve burner flame stability. The EI
burner is well suited for firing high moisture (>35%)
lignites and low volatile bituminous coal.
Primary air exchange burner
The primary air exchange (PAX) burner is designed
to fire anthracite and similar coals. Some anthracites
can be wall-fired conventionally with the PAX burner,
while those lowest in volatile matter must be fired in
a downshot arrangement (Fig. 5). The design of the
air zones for the PAX burner is similar to that of the
EI burner. However, in the case of downshot firing,
air staging ports direct air away from the burner to
better sequence air supply with the slower burning
nature of these coals, thus elevating flame temperature.
The anthracite fineness is increased to 90% (or even
higher) through 200 mesh to help accelerate ignition
and to reduce unburned carbon. In addition, mill exit
temperature is increased to the maximum for the pulSteam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
verizer, often limited to 200F (93C) for mechanical
reasons. Tests have shown the benefit of higher temperatures on ignition performance. The PAX burner
raises the primary air and pulverized coal (PA/PC)
temperature by a patented design which separates
half of the primary air from the PA/PC mixture and
vents it into the furnace. This primary air is replaced
by secondary air near 700F (371C), significantly raising fuel temperature as it enters the furnace. In some
situations, indirect firing systems are used for firing
anthracite. Pulverized coal from the storage bin can be
transferred to the burners with hot secondary air to provide a hot, dense fuel mixture. In either case, the PAX
nozzle tip is sized for low velocity to further assist ignition. Even with these techniques, good combustion is
dependent upon high furnace temperatures. Low load
operation still requires igniters for flame stabilization.
Unburned combustibles
Unburned carbon (UBC) in solid form, as distinguished from partially oxidized carbon in gaseous
form (CO), results to varying degrees from all pulverized coal systems. Unburned combustibles represent
an efficiency loss to the process which can vary from
0.05% for lignite, to 0.5% for bituminous coal, and to
5.0% or higher for anthracite. These order of magnitude variations are largely a consequence of inherent
differences in coal reactivity. Variations around these
values can occur due to gradients in coal reactivity,
variations in coal fineness, and variations in how oxygen is made available to the coal during the combustion process.
Fineness
Given a coal of lesser reactivity, one of the most effective techniques to lower UBC is to reduce the quantity of coarse coal particles from the pulverizers. Pulverizer power is dependent on the mean particle size,
which is heavily influenced by the fine particles.
Therefore, the most efficient means of reducing UBC
is to selectively reduce the coarse particles without
over-grinding the fine particles. Advanced pulverizer
classifiers, especially dynamic versions, can essentially
eliminate the large 50 mesh particles and sharply reduce the 100 mesh fraction, with little change to the
dominant smaller 200 mesh size. Such fineness improvements have accomplished significant reductions
in UBC with bituminous and higher rank coals.
Oxygen availability
The influence of oxygen availability on carbon
burnout depends on each coal particle’s history regarding O2 concentration, and the corresponding temperature and time exposures. Global factors include the
excess air level for the process, rate and uniformity of
air-fuel mixing, and residence time. Increasing excess
air increases overall oxygen availability and reduces
UBC, but with some offset in boiler efficiency due to
increased dry gas loss. Increasing excess air also raises
NOx, placing further constraint on this countermeasure. Air infiltration to a boiler tends to indirectly increase unburned combustibles. Balanced draft units
Steam 41 / Burners and Combustion Systems for Pulverized Coal
actually operate under a small vacuum which draws
air into the boiler through cracks, tears, and miscellaneous openings in the structure. This air can enter
the process once gases have cooled and it does not mix
well, such that it provides little or no benefit to combustion. However it is measured as excess air by instruments located at the boiler outlet, which in turn
cause reduction in air to the combustion equipment
to maintain the target excess O2. Inadequate excess
air to the combustion equipment then causes UBC and
CO to increase. Thus, minimizing air infiltration is
important for controlling unburned combustibles.
Air/fuel imbalances
Air/fuel ratio and mixing rates are a consequence of
many factors and vary considerably even within a given
furnace. Fuel imbalance can occur because of variations
in raw coal feed rate to the multiple pulverizers.
Another aspect of fuel imbalance concerns non-uniformities in coal distribution among the multiple burners on a furnace. Techniques for measuring burner
line coal distribution have expanded, but retain a level
of uncertainty and can be time consuming and expensive. This complicates implementing and verifying the
effectiveness of corrective measures. Burner line
restrictors are a proven method of improving coal pipe
fuel distribution, but new techniques are under development to correct fuel distribution exiting the pulverizers. Air imbalances among burners can act to
magnify air/fuel imbalances. Many modern burners
are equipped with air measuring and adjustment
hardware to correct this. Air-fuel mixing rates are directly influenced by interactions induced by the burners and OFA (if so equipped), and consequential flow
patterns in the furnace. Adjustments which increase
mixing rates will tend to reduce UBC while increasing NOx.
Residence time
Furnace residence times combined with oxygen
availability, thermal environment, and coal reactivity ultimately control unburned combustibles. Full
load furnace residence times can vary from 1 to 3 seconds depending on burner location, furnace geometry,
and operating conditions. Adding an OFA system to
an existing furnace further reduces the residence time
for final carbon burnout. Increased air-fuel mixing
rates can help compensate for marginal residence time
and reduce UBC and CO, but with some increase in NOx.
Gaseous losses
CO emissions result from insufficient oxygen and/
or temperature to complete combustion. Localized or
global air deficiency and flame quenching are common causes for CO emissions in practical systems. Air/
fuel balance is difficult to maintain over all combustion conditions. Combustion tuning, to some degree,
involves compensating for errors. Fuel excesses from
one burner are offset by air excesses on another.
Changes in firing conditions, inevitable with different combinations of pulverizers/burners in service,
cause shifts in air-fuel distribution with resultant increases in CO.
14-19
The Babcock & Wilcox Company
Advanced techniques
New diagnostic tools and control systems are providing improved means to reduce unburned combustibles while maintaining low NOx emissions. Flame diagnostic equipment such as the Flame Doctor® system
use non-linear analysis (chaos theory) to provide a
means to better tune individual burners. Diagnostic
instrumentation in the upper furnace or boiler outlet
can more accurately assess excess air and emission
levels, and identify localized areas with high emissions. Automated flow control devices on the burners
and OFA ports enable adjustments with conventional
or neural network control systems to dynamically
minimize emissions.
Auxiliary equipment
Oil/gas firing equipment
In some cases, PC-fired furnaces are required to
burn fuel oil or natural gas up to full load firing rates.
These fuels can be used when the PC system is not
available for use early in the life of the unit, due to
an interruption in coal supply, or as a NOx control strategy. Some operators avoid installing a spare pulverizer by firing oil or gas when a mill is out of service.
To fire oil, an atomizer is installed axially in the
burner nozzle. Erosion protection for the atomizer is
recommended. A source of air is needed when firing
oil or gas to purge the nozzle and improve combustion. This air system must be sealed off prior to PC
firing. Steam-assisted atomizers are recommended for
best performance.
Gas elements of several designs can be used in PCfired burners. These include designs with manifolds
which supply multiple elements in the air zone, or
single element designs mounted axially in the coal
nozzle. Gas manifolds can be located inside or outside
of the windbox. Installation in the windbox clears the
burner front of considerable hardware but prevents
on-line adjustment or repair of gas elements. External manifolds are more complex, but enable rotational
adjustment or replacement of the gas injection spuds.
On-line adjustability is very useful for optimizing
emissions and to counteract any tendency toward
burner rumble. A single axial high capacity gas element (HCGE) in the coal nozzle offers the most effective NOx control in use with advanced low NOx PCfired burners. The HCGE (see Chapter 11) has to be
inserted for operation and has to be retracted and supplied with seal air when out of service. Regardless of
gas element type, the issue of compatibility with the
combustion system has to be considered. Retrofit of gas
or oil elements increases the forced draft fan load in
many cases. Primary air is eliminated which results
in higher quantities of secondary air compared to PC
firing. As a result, fan flow and static margins need to
be considered.
See Chapter 11 for more information on oil and gas
firing equipment.
14-20
Igniters
An igniter is required to initiate combustion as pulverized coal is first introduced to the burner, as the
burners are being normally shut down, and as otherwise required for flame stability. Additionally, the igniters may be used to warm the furnace and combustion air prior to starting the first pulverizer. In some
cases they are used to synchronize the turbine prior
to firing coal. Igniters typically use a High Energy Ignition spark system to ignite the fuel, which is usually natural gas or No. 2 fuel oil. Igniters on utility
boilers and most large industrial boilers are operated
with an input capacity of approximately 10% or more
of the main PC-fired burner. Such igniters are categorized by NFPA (National Fire Protection Association)
as Class I. The use of Class I igniters reduces the complexity of the flame detection system and permits operation of the igniters as desired under any boiler conditions. Modern boilers have automated controls to
start, operate, purge, and shut down the igniters from
the control room. (See also Chapter 11.)
Flame safety system
Modern PC-fired boilers are equipped with a flame
safety system (FSS). The FSS uses one or more flame
scanners at each burner to continuously monitor flame
conditions electronically. The flame scanners are used
to evaluate several characteristics of the igniter and/
or main flames. The lack of satisfactory flame signals
causes the FSS to automatically initiate actions to prevent hazardous operation of the burner and boiler.
The specific actions taken by the FSS can vary with
the boiler design, boiler load, fuel in service, and the
status of the igniters in a burner group. The steps
taken, and their sequence, are designed to prevent
unburned fuel from entering the furnace and avoid
large swings in the total furnace fuel-to-air ratio,
thereby significantly reducing the risk of an explosion.
Safety and operation
Uncontrolled ignition of pulverized coal may result
in an explosion which can severely harm personnel
and destroy equipment. Explosions result from ignition of an accumulated combustible mixture within
the furnace or associated boiler passes, ducts, and
fans. The magnitude and intensity of the explosion
depend on the quantity of accumulated combustibles
and the air-fuel mixture at ignition. Explosions result
from improper operation, design, or malfunction of the
combustion system or controls. The National Fire Protection Association (NFPA) publishes codes to address
these concerns. These have been consolidated into the
NFPA 85 Boiler and Combustion Systems Hazards
Code, which is periodically updated.14 This serves as
an excellent source of information concerning design
and equipment issues, operation and control of PCfired equipment.
Another key source of information is the operating
instructions. Operators of PC-fired equipment should
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
expect the instructions to provide specific information
concerning the purpose, design, calibration and adjustment, startup, operation and shutdown of the
various equipment. The instructions should also provide maintenance and troubleshooting information.
Other PC applications
Pulverized coal in metal and cement industries
The application of pulverized coal firing to copperand nickel-ore smelting and refining has been standard practice for many years. With the use of pulverized coal, high purity metal can be obtained because
the furnace atmosphere and temperature can be easily controlled. Pulverized coal may be favored over
other fuels for several reasons: it may be less expensive, it offers a high rate of smelting and refining, and
it readily oxidizes sulfur.
Copper reverberatory furnaces for smelting and
refining are fitted with waste heat boilers for steam
generation. These boilers supply a substantial portion
of power for auxiliary equipment and also provide the
means for cooling the gases leaving the furnace.
In producing cement, the fuel cost is a major expense item. Except in locations where the cost favors
oil or gas, pulverized coal is widely used in the industry. Direct firing, with a single pulverizer delivering
coal to a single burner, is common practice in the majority of U.S. cement plants. The waste heat air from
the clinker cooler, taken from the top of the kiln hood
through a dust collector, usually serves as the preheated air for drying the coal in the pulverizer.
Pulverized coal is being applied effectively in the
steel industry where it is injected into the blast furnace tuyères. The pulverized coal replaces a similar
weight of higher priced coke. Theoretically, 40% of the
coke could be replaced by pulverized coal.
References
1. Lowry, H.H., Ed., Chemistry of Coal Utilization,
Horizon Publishers & Distributors, Inc., New York, New
York, pp. 1522-1567, January, 1945. See Chapter 34, “The
Combustion of Pulverized Coal,” by A. A. Orning.
2. “Standard test method for volatile matter in the analysis sample of coal and coke,” D3175-89a, Annual Book of
ASTM Standards, Vol. 5.05, American Society for Testing and Materials, Philadelphia, Pennsylvania, pp. 329331, 1991.
3. Beer, J.M., and Chigier, N.A., Combustion Aerodynamics, Chapter 5, Krieger Publishing, Malabar, Florida, 1983.
4. Brackett, C.E., and Barsin, J.A., “The dual register
pulverized coal burner,” presented at The Electric Power
Research Institute NOx Control Technology Seminar, San
Francisco, California, February 1976.
5. LaRue, A.D., “The XCL Burner – Latest Developments and Operating Experience,” presented to Joint Symposium on Stationary NOx Control, San Francisco, California, March 1989.
6. LaRue, A.D. and Nikitenko, G., “Lower NOx/Higher Efficiency Combustion Systems,” presented to the EPA/DOE/
EPRI MegaSymposium, Chicago, Illinois, August 2001.
7. Sivy, J.L., Kaufman, K.C., and McDonald, D.K., “Development of a Combustion System for B&W’s Advanced
Coal-Fired Low-Emission Boiler System,” presented at the
22nd International Technical Conference on Coal Utilization
and Fuel Systems, Clearwater, Florida, March 1997.
8. Sivy, J.L., Sarv, H., and Koslosky, J.V., “NOx Subsystem
Evaluation of B&W’s Advanced Coal-Fired Low-Emission
Boiler System at 100 MBtu/hr,” Proceedings of the EPRIDOE-EPA Combined Utility Air Pollutant Control Symposium, Washington, D.C., August 1997.
9. Flynn, T.J., LaRue, A.D., Nolan, P.S., “Introduction
to Babcock & Wilcox’s 100 MBtu/h Clean Environment Development Facility,” Presented to American Power Conference, Chicago, Illinois, April 1994.
10. LaRue, A.D., Bryk, S.A., Kleisley, R.J., Hoh, R.H.,
Blinka, H.S., “First DRB-4Z Burner Retrofit Achieves Ultra-Low NOx Emission Goal,” Presented to POWER-GEN
International, Orlando, Florida, November 2000.
11. LaRue, A.D., Costanzo, M.A., Fulmer, J.A.,
Wohlwend, K.J., “Update of B&W’s Low NOx Burner Experience,” Presented to ASME International Joint Power
Generation Conference, Miami, Florida, July 2000.
12. Latham, C.E., LaRue, A.D., “Designing Air Staging
Systems with Mathematical Modeling,” Presented to
AFRC/JFRC, Maui, Hawaii, October 1994.
13. Kokkinos, A., Wasyluk, D., Boris, M., “Retrofit Low
NOx Experience for Tangentially-Fired Boilers – 2002 Update,” Presented to ICAC, Houston, Texas, February 2002.
14. NFPA 85–Boiler and Combustion Systems Hazards
Code 2001 Edition, National Fire Protection Association,
Quincy, Massachusetts, 2001.
Flame Doctor is a trademark of the Electric Power Research
Institute, Inc.
Steam 41 / Burners and Combustion Systems for Pulverized Coal
14-21
The Babcock & Wilcox Company
Advanced low NOx B&W DRB-4Z® burners ready for installation.
14-22
Steam 41 / Burners and Combustion Systems for Pulverized Coal
The Babcock & Wilcox Company
Chapter 15
CycloneTM Furnaces
The Babcock & Wilcox Company (B&W) developed
the CycloneTM furnace concept in the 1940s to burn
coal grades that are not well suited for pulverized coal
(PC) combustion. The ash from these coals has a low
melting (fusion) temperature and would enter the superheaters of PC units in a molten state, creating severe slagging.
The Cyclone furnace was originally designed to take
advantage of:
1. lower fuel preparation capital and operating costs
(crushers only),
2. a smaller furnace, and
3. less flyash and convection pass fouling (15 to 30%
of the fuel ash enters the convection pass instead
of 80% for PC firing).
tion in a boiler furnace, the volatiles burn without
difficulty; however, combustion of the fuel carbon char
particles requires special measures that ensure a continuing supply of oxygen to unburned carbon particles. A thorough mixing of coal particles and air must
occur with sufficient turbulence to remove combustion
products and to provide fresh air at the particle surface.
PC firing achieves these requirements by reducing
the coal to a very fine powder, nominally 70% of which
passes through a 200 mesh (74 micron) screen. This
powder then mixes with the turbulent combustion air.
After this initial phase, the small particles are carried
in the air stream with much less mixing. Without the
Cyclone furnace arrangement and basic
operation
As shown in Fig. 1 and the facing page illustration,
the Cyclone furnace consists of a horizontal cylindrical barrel 6 to 10 ft (1.8 to 3.0 m) in diameter, attached
to the side of the boiler furnace. The Cyclone barrel is
of water-cooled tangent tube construction. Inside the
Cyclone barrel, short pin studs are welded to the outside surface of the tubes in a very dense pattern. A
refractory lining material is installed in between the
studs. This insulation maintains the Cyclone at a high
enough temperature to permit adequate slag tapping
from the bottom of the unit and significantly reduces
the potential for corrosion.
Crushed coal and some air (primary and tertiary)
enter the Cyclone through specially designed burners on the front of the Cyclone. In the main Cyclone
barrel, a swirling motion is created by the tangential
addition of the secondary air in the upper Cyclone
barrel wall. A unique combustion pattern and circulating gas flow structure result (discussed below). The
products of combustion eventually leave the Cyclone
furnace through the re-entrant throat. A molten slag
layer develops and coats the inside surface of the Cyclone barrel. The slag drains to the bottom of the Cyclone and is discharged through the slag tap.
Principles of operation
To understand the Cyclone concept, the basics of
solid fuel combustion must first be considered, particularly as they relate to PC firing. During coal combusSteam 41 / Cyclone Furnaces
Fig. 1 CycloneTM furnace boiler showing air, flue gas, water and
steam flows.
15-1
The Babcock & Wilcox Company
continued rapid mixing action, the coal particulate
combustion must be completed through diffusion of the
oxygen and combustion products around the particle.
The relatively large PC furnace provides sufficient
residence time for oxygen to penetrate the combustion
product’s blanket around the particles as well as cooling of the ash to minimize convection pass fouling.
The Cyclone furnace, on the other hand, fires relatively large crushed coal particles of which approximately 95% pass through a 4 mesh screen (nominal
0.187 in. or 4.75 mm) and is dependent upon the fuel
type being fired. Fuel of this size is too large to burn
completely in suspension and would pass through the
PC-fired boiler without burning all of the carbon.
Therefore, the large particles must be retained in place
with the air passing over the particle (air scrubbing)
for complete combustion to occur. The Cyclone furnace
accomplishes this by forming a molten sticky slag layer
which captures and holds the heavier particles. While
the large particles are trapped in the slag layer, the
volatiles and fine coal particles (recommended at about
10+% passing 200 mesh) burn in suspension providing the intense radiant heat required for slag layer combustion. Ideally, all of the large coal particles become
trapped in the molten slag where they complete carbon
burnout, leaving behind ash to replenish the slag layer.
With most of the combustion occurring in the confines of the Cyclone furnace, the main boiler furnace
can be relatively small compared to a pulverized coal
furnace design.
Cyclone combustion
In the Cyclone, fuel is fired at high heat inputs and
under very turbulent operating conditions to maximize combustion efficiency. Injecting the main combustion air tangentially at high velocities creates a swirling motion which throws the large coal particles against
the Cyclone inside surface, where they are trapped in
the slag layer and burn to completion. The hot gases then
exit through the Cyclone core and depart through the
re-entrant throat into the main boiler furnace.
Air distribution
The cyclonic gas flow does not follow a simple corkscrew path from entry to exit. (See Fig. 2.) The main
combustion air (secondary air) enters the Cyclone furnace tangentially at high velocity and passes along
the Cyclone periphery, also known as the recirculation zone. In this zone, the air-gas flow along the
chamber is away from the exit opening and toward
the burner, pulled along by the vortex vacuum created near the burner end of the Cyclone. Closer to the
center of the Cyclone, the general gas flow is toward
the exit (re-entrant throat). Eventually, the hot combustion gases flow from the recirculation zone to the
Cyclone core, known as the vortex. Once in the vortex, the gases and particulate are immediately pulled
out of the Cyclone and into the main furnace. The fuel
residence time in the recirculation zone is affected
directly by the velocity of the secondary air and inversely by the size of the re-entrant throat opening.
The balance of the combustion air is admitted as
primary and sometimes tertiary air as discussed be15-2
low. The air injection locations are identified in Fig. 2
and later in Fig. 5.
The primary air enters the burner tangentially in
the same rotational direction as the secondary air,
carrying the coal into the Cyclone. This primary air
controls the coal distribution within the main Cyclone
chamber. For optimized operation, the primary air is
typically minimized to avoid throwing the raw coal too
deep or near the vortex, but must not be set so low as
to create a fuel buildup near or in the burner. Adequate velocity must be maintained to allow for proper
coal distribution into the cyclone.
The tertiary air enters the center of the burner along
the Cyclone axis, directly into the Cyclone vortex. It
helps keep the cyclone burner door cool and controls
the vortex vacuum which consequently determines
the position of the main combustion zone, the primary
source of radiant heat. As a negative effect, too high
an amount of tertiary air reduces the vortex vacuum
at the burner, allowing the main combustion zone to
move deeper into the Cyclone toward the re-entrant
throat and main boiler furnace.
Heat rates
Within the Cyclone, the fuel burns at a heat release
rate of 450,000 to 800,000 Btu/h ft3 (4.66 to 8.28 MWt
/m3), developing gas temperatures of more than 3000F
(1649C). Heat absorption rates by the water-cooled
walls are relatively low as the unit has a relatively
small surface protected by a refractory coating –
40,000 to 80,000 Btu/h ft3 (414 to 828 kW/m3). The
high heat release and low heat absorption rates combine to ensure the very high temperatures needed to
complete the combustion and maintain the slag layer
in a molten state. The high temperature and high heat
release rate characteristics of Cyclone firing also provide the conditions to produce very high uncontrolled
nitrogen oxides (NOx) emission levels. The Cyclone
furnace traps and burns only as much coal as it can
handle. The excess passes into the main furnace and
boiler back-end as unburned carbon carryover. During overfiring, long term corrosion and/or erosion with
associated tube deterioration could occur in the Cyclone and/or lower furnace regions. In addition,
overfiring may cause problems in the main furnace,
Fig. 2 Cyclone furnace gas recirculation pattern.
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
convection pass, economizer, and other downstream
equipment components.
Slag layer
The intense radiant heat and high temperatures
melt the ash into a liquid slag coating which covers
the entire Cyclone interior surface except for the area
immediately in front of the secondary air opening. The
unit’s refractory lining further assists this molten condition by limiting heat absorption to the water-cooled
walls. The slag coating is kept hot and fluid by combustion and flows constantly from the Cyclone into the
main furnace, where it drains through a floor tap
opening into a water-filled tank. The slag layer must
be constantly replenished by the ash from incoming
coal. For this reason, bituminous coals fired in Cyclones
need a minimum of 6% ash (dry basis); subbituminous
coals must contain at least 4% ash (dry basis).
Optimal combustion conditions are generally
achieved when excess air is maintained at about 10
to 13% at the Cyclone. Cyclone operating temperatures tend to decline at higher excess air levels. In
addition, the adiabatic flame temperatures within the
Cyclone will actually be higher at near theoretical air
operating conditions.
A primary indicator of Cyclone combustion temperature is the slag temperature at the slag tap. Slag temperature is a function of radiant heat input to the Cyclone. The degree of radiant heat input indicates the
portion of the combustion occurring within the Cyclone. Relative slag temperatures can be monitored
with an optical or ultraviolet pyrometer from the furnace side ports or by sighting through an inactive
Cyclone on opposed wall-fired units. Although the traditional method of aiming a pyrometer through the
Cyclone front observation port has not proven to be
as effective, new techniques are being investigated using existing scanners and/or other equipment viewing
from the Cyclone front to help evaluate performance.
Under ideal combustion conditions, the Cyclone can
capture approximately 70 to 75% of the original fuel
ash as slag and drain it to the furnace for disposal in
the slag tank. (See Fig. 3.) Smaller boilers can retain
more of the ash by capturing additional quantities on
the walls and screen tubes. Other details of the Cyclone furnace and boiler arrangements are discussed
under Design features.
Suitable fuels
The Cyclone furnace can handle a wide range of
coals from low volatile bituminous to lignite, depending on the fuel preparation and delivery system. Cyclones have also successfully co-fired solid waste fuels such as wood chips, sawdust, bark, coal chars,
refuse-derived fuel (RDF), petroleum coke, paper and
sewage sludge, and tire-derived fuel (TDF). Fuel oils
or gases (natural gas, coke oven gas, and others) can
be burned in Cyclone furnaces as the primary, contingency or startup fuel.
On a continuous basis, the Cyclone must fire either
a solid fuel or a liquid/gaseous fuel. Long term firing
of oil or gas should only be pursued in a bare tube
Steam 41 / Cyclone Furnaces
Fig. 3 Comparison of ash distribution from a large Cyclone furnace
unit and typical pulverized coal unit.
Cyclone because these fuels can destroy the refractory
lining. The resulting loose slag and/or refractory debris would severely erode the tubing, leading to eventual pressure part failure. Cyclones switching from
coal to oil or gas for an extended period should have
all refractory within the cyclone removed, the slag tap
direction reversed and all air ducts cleaned. The pin
studding can remain, although a study should be performed to evaluate the change in magnitude on heat
absorption profiles. When switching back to coal, the
refractory must be reinstalled and the slag tap must
be set in the correct direction.
Fuel criteria
Coals and co-fired fuels (solid or otherwise) must be
evaluated against several criteria. Volatiles must be
higher than 15% on a dry basis to ensure stable combustion within the Cyclone. The ash content must be
at least 6% for bituminous coals or 4% for subbituminous coals, but should not exceed about 25% on a dry
basis. Higher ash content fuels require special considerations. With low ash coals, the proper slag coating
can not be developed, nor can it be maintained. Thin,
low viscosity slag coatings do not protect the refractory. To compensate for this condition, the slag can be
thickened by increasing excess air and reducing the
Cyclone combustion temperature if other operating
conditions permit.
The moisture content for standard bituminous coal
firing Cyclones should not exceed approximately 20%.
Higher moisture content requires better crushing and
higher secondary air temperatures to dry the fuel for
15-3
The Babcock & Wilcox Company
proper combustion. For subbituminous coals with
moisture contents typically in the 25 to 30% region,
other Cyclone modifications including reduced sized,
tight gap re-entrant throats and segmented secondary air velocity dampers are required to maintain good
Cyclone operating conditions. Improved coal fineness
operation is also imperative to achieve good Cyclone
combustion when firing subbituminous coals. Particularly high moisture fuels may require the pre-dry system used on lignite-fired Cyclone-equipped boilers.
Operating experience demonstrates that coal ash
has a tendency to concentrate iron, initiate slag tapping problems, and/or result in a corrosive iron sulfide attack on the refractory and Cyclone furnace. This
can be evaluated by comparing the total amount of
sulfur to the iron/calcium and iron/magnesium ratios.
(See Fig. 4.) Frozen iron puddles found on the Cyclone
or furnace floor during outages provide an indication
of the magnitude of the potential problems.
Slag viscosity factor – T250 value The most important
evaluation consideration for Cyclone coals is the slag
viscosity characteristic or T250 value. This ultimately
separates coals into categories suitable and unsuitable
for Cyclone operation. The T250 value denotes the temperature at which the coal slag has a viscosity of 250
poise. At this viscosity the slag flows on a horizontal
surface. A slag with a higher viscosity would fail to flow
steadily from the Cyclone and main furnace and
would be too stiff to trap the unburned coal particles
for proper combustion. The currently recommended
maximum T250 value for all Cyclone bituminous coals
is 2450F (1343C). With the advent of increasing low
sulfur subbituminous coal use in the 1990s, B&W
established a T250 limit of 2300F (1260C) for subbituminous coals fired in standard Cyclones. This value
compensates for the effect of increased coal moisture
on Cyclone combustion temperatures.
The preferred method of establishing the T250 value
is by experimental measurements on actual fuel ash
samples. However, due to the large database accumulated from past testing, the T250 value can also be estimated based upon calculations using the coal mineral
ash analysis. (See Chapter 10.)
For some coals and/or other solid fuels, the T250 value
of the slag can be lowered by altering its ash base to
acid (B/A) constituent ratio (discussed in Chapter 21)
through the addition of a fluxing agent (e.g. limestone,
dolomite, etc.). Although B&W does not generally recommend this approach, sometimes it is the only alternative to improve operation. Fluxing system design
considerations must incorporate the capability to accurately, uniformly, and continuously distribute the
flux material with the fuel stream.
If a Cyclone unit must burn high fusion temperature fuel, the best approach is to adjust the T250 value
by blending in a different coal or solid fuel; however,
this usually represents higher fuel handling costs.
Both fuel blending and fluxing create concerns with
maintaining acceptable consistency.
Co-fired fuels must be evaluated on an individual
basis with emphasis placed on the resulting ash content as a percentage of the total heat input.
The general characteristics of coals suitable for Cyclone furnace firing are summarized in Table 1.
Cyclone coal burner types
In the United States (U.S.), Cyclone furnaces have
been equipped with three primary coal burner types
– scroll, vortex and radial (two sub-types), as shown
in Fig. 5. All types inject coal from the front end of the
Cyclone and impart a swirl to the crushed coal in the
same rotation as the secondary (main) combustion air.
To protect the burner coal inlet from excessive erosion,
all utilize a protective wear liner known as the wear
blocks. The material used for these blocks is normally
comprised of metal, ceramic, or a combination of the
two. Finally, the burners are normally kept cool with
the addition of a water-cooled jacket on the burner
door and the burner scroll. The main purpose of the
cooling jacket is personnel protection along with reducing the operating temperatures of the burner itself. Since untreated water is normally used for the
cooling media, corrosion and pluggage can be encountered with time. Although not normally recommended,
this water cooling capability has been removed by some
Table 1
Summary of Cyclone Furnace Coal Suitability
Ash
Bituminous minimum
> 6% dry basis
Subbituminous minimum > 4% dry basis
Maximum
< 25% dry basis
Moisture Bin firing system (Bit.)
< 20% as-fired
Direct firing system (Subb.) < 30% as-fired
Pre-dry firing system
< 42% as-fired
Volatile
T250
Fig. 4 Coal suitability for Cyclone furnaces based on tendency to
form iron and iron sulfide.
15-4
> 15% dry basis
Bituminous
Subbituminous
< 2450F (1343C)
< 2300F (1260C)
Coal type
Bituminous
Subbituminous
Lignite
Coal ash iron/sulfur tendencies
See Fig. 4
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
Cyclone
Furnace
Burner
End Views
Side Views
Primary Air
and
Coal
Tertiary
Air
Tertiary
Air
Orifice
Primary Air and Coal
Scroll Burner
Coal
Coal
Primary
Air
Primary Air
Vortex Burner
Coal
Primary Air
Tertiary Air
Tertiary
Air
Orifice
Primary
Air
Coal
Radial Burner
Coal
Coal
Primary
Air
Primary Air
Tertiary Air
Tertiary Air
Thin Door Radial Burner
Fig. 5 Primary Cyclone coal burner types.
operators. If this is done, the burner material should be
upgraded and insulation should be applied over the
burner to provide personnel protection.
The scroll burner, which was used in the first Cyclones, combines the primary air and coal at the feeder
outlet and injects the mixture into the Cyclone in a
cone shaped distribution pattern. Tertiary air, admitted at the center of the burner, controls the position
of the main flame within the Cyclone. However, this
Steam 41 / Cyclone Furnaces
injection pattern resulted in a high concentration of
recirculating coal particles around the burner outlet,
leading to heavy burner wear-block erosion. The
premixing of primary air and coal required the addition of a rotary seal to protect the feeder from backflow
of hot combustion air. Later scroll burner applications
eliminated the rotary valve by using a higher head
of coal at the feeder inlet to prevent hot air backflow
into the feeder and coal bunker.
The vortex burner eliminated the rotary seal by
feeding coal and primary air to the burner separately.
The primary air entered the Cyclone burner tangentially as with the scroll design, but the coal is gravity
fed (along with feeder seal air) into the backside of the
burner. Although this configuration eliminated the
tertiary air, adjusting feeder seal air has the same effect on the Cyclone vortex zone. The vortex burner
produced a similar cone shaped injection pattern as
the scroll model. Advanced ceramic wear blocks and a
new burner door/coal inlet design have significantly reduced erosion problems encountered with earlier designs.
The development of the radial burner eliminated
the severe wear-block erosion. Like the vortex burner,
the radial version does not combine coal and primary
air until both enter the burner chamber. However, on
a radial burner the coal is introduced tangentially in
the same rotation as the primary air. The coal particles
form a long rope (concentrated stream of coal) as they
are swept across the burner wear blocks and enter the
Cyclone. This approach greatly reduces the concentration of coal recirculating around the burner, effectively reducing wear-block erosion. Similar to the scroll
burner, tertiary air is admitted using the same axial
entry location.
A newer thin door radial burner version with the
option to eliminate tertiary air (and/or redirect how it
is introduced) has been offered since the late 1990s.
The benefits of this design are the potential to minimize and/or eliminate tertiary air without adversely
affecting performance, an improved range of view
within the cyclone, and an overall smaller, easier to
open door.
The radial burner remains the modern standard for
coal-fired Cyclones. The scroll burner is utilized on
modern lignite-fired Cyclone units because the predry system requires mixing of the primary air and coal
during coal preparation, prior to the burner inlet. (See
later discussion.) As the scroll, vortex and radial type
burners have slightly different coal inlet locations,
switching from one burner to another requires a
change in the coal handling system.
Design features
Boiler furnace
Commercial Cyclone furnaces have been built in
sizes ranging from 6 to 10 ft (1.8 to 3 m) in diameter,
with standard maximum heat inputs ranging from 150
to 425 × 106 Btu/h (44 to 124.6 MWt), respectively.
Higher Cyclone heat inputs under peaking conditions
are feasible with the existing equipment, but at the
cost of various operational concerns (such as higher
15-5
The Babcock & Wilcox Company
unburned carbon in the flyash, higher particulate
loadings, increased maintenance, etc.). New larger
diameter, higher capacity Cyclone designs are feasible
and could be incorporated if the additional capital costs
associated with such an overall retrofit can be justified
versus the associated increased boiler/turbine output.
As illustrated in Fig. 6, the Cyclone furnace has
been used on three general boiler arrangements –
single wall firing with screen, open furnace single wall
firing, and opposed wall firing. Full boiler drawings
are provided in Figs. 1, 7 and 8, respectively. Boiler
and Cyclone furnace arrangements have ranged from
one 6 ft (1.8 m) Cyclone on a single wall unit to twentythree 10 ft (3 m) Cyclones on an 1150 MW opposed
wall unit. In all cases, the main furnace is relatively
small to maintain furnace temperature over the furnace floor slag taps and to promote slag flow on the
furnace walls. The lower furnace chamber also contains a protective refractory lining held in place by
thousands of pin studs which are welded to the tubes.
Generally, the Cyclone boiler can be operated continuously down to about 50% of total capacity. Below this
point the slag freezes on the furnace floor and plugs
the floor taps. Many units have been equipped with
larger floor slag taps to improve slag removal.
bin system, a short crusher outage does not interrupt
boiler operations. An existing bin system can be upgraded to fire high moisture coals by converting the
coal piping into a simple pre-dry system (see Fig. 9).
The direct-fired system uses a smaller separate
crusher, sometimes called a coal conditioner, between
the coal feeder and burner on each individual Cyclone
furnace. These crushers are swept by hot air which
removes moisture from the freshly crushed coal. This
produces an advantage by improving crusher performance and fuel ignition when firing coals with a moisture content up to 30%. The direct-fired system has
also been used where the existing plant layout could
not accommodate the bin system.
The direct-fired with pre-dry system represents the
Cyclone fuel preparation system for firing lignite and
other high moisture coals. In addition to the hot airswept individual crushers, this system can also include
crusher classifiers and mechanical cyclone moisture
separators. The classifiers increase the coal fineness
which results in more moisture extraction and better
Coal preparation
The Cyclone equipped boilers feature three fuel delivery systems – bin, direct-fired, and direct-fired with
pre-drying configurations. (See Fig. 9.) The bin system, the simplest, least expensive and most common,
uses a pair of large crushers in a central location to
prepare the coal for overhead storage bunkers (bins).
Because the Cyclone- required crushed coal has a relatively large particle size, the storage hazards as compared with pulverized coal systems are lessened, but
not eliminated. Adequate venting to remove freshly
released combustible gases from the crushed coal systems must still be maintained along with all associated dust control systems. Safety requirements are
imperative for low rank, high volatile coals. With the
(a)
Screened Furnace
Arrangement
Single Wall
(b)
Open Furnace
Arrangement
Single Wall
(c)
Open Furnace
Arrangement
Opposed Wall
Fig. 6 Selected firing arrangements for Cyclone furnaces.
15-6
Fig. 7 Radiant boiler with Cyclone furnaces (one wall) and bin system
for coal preparation and feeding.
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
combustion. The mechanical cyclone separators remove the moisture and fines from the coal-air mixture
and vent the mixture directly to the boiler furnace
through the gas recirculation plenum area. The exclusion of moisture from the main coal increases Cyclone combustion temperatures and subsequently
enhances slag tapping. With moisture separators, this
system, designed for lignites with moisture higher
than 36%, handles poor Cyclone quality, low sulfur
coals as easily as standard bin system Cyclones fire
high grade bituminous coal.
The preferred coal size distribution for various coal
grades is shown in Fig. 10. With high moisture, high ash
fusion or other difficult-firing coals, every attempt should
be made to produce the highest percentage of coal fines.
Coal feeders
A number of different feeders have been used with
Cyclones since their inception. Early units had small
table type feeders, followed by drag types, then volumetric belt types and now gravimetric belt types, some
of which have been upgraded with microprocessor controls. With the introduction of each model, the control
and continuity of the coal flow improved.
The preferred feeder type today is the gravimetric
(weighing) type with a microprocessor control upgrade.
Fig. 8 Universal Pressure (UP®) boiler with opposed-wall Cyclone furnaces and bin system for coal preparation and feeding.
Steam 41 / Cyclone Furnaces
15-7
The Babcock & Wilcox Company
Fig. 10 Crushed coal sizing requirements for Cyclone furnaces.
tions could be generally reduced by installing and
properly maintaining a flue gas vent line on top of the
slag tank. The main purpose of the slag tank vent line
is to maintain a positive flow of hot furnace gases
through the floor tap, which reduces the potential of
the tap from plugging, especially at low boiler loads.
The vent typically either runs from the top of the tank
to the boiler economizer or to an aspirator which utilizes windbox air to vent the flow into the furnace.
Fig. 9 Bin, direct-fired, and pre-drying bypass systems for coal
preparation and feeding to a Cyclone furnace.
Accurate fuel-air control is needed to optimize Cyclone
performance, requiring a modern gravimetric feeder.
Slag handling equipment
Cyclone boilers feature a batch removal system for
disposing of slag after it is discharged from the main
furnace. (See Fig. 11.) The molten slag continuously
flows through the furnace floor tap and into a tank
beneath the floor where it is quenched and solidified
in a water bath. At intervals, the accumulated slag is
broken down by a clinker grinder and removed in
batches. However, combustible gases can build up at
the top of the tank. Similarly, a plugged or partially
closed furnace floor tap can result in carbon monoxide accumulation. Both potentially hazardous situa15-8
Oil and gas burners
Although coal is the primary Cyclone fuel, oil and
gas have been used as startup, auxiliary and main
fuels using the combustion system shown in Fig. 12.
Originally, the oil burner could either be a simple
transverse pipe across the secondary air inlet or a
single oil gun through the coal burner door. The transverse pipe burner, or roof burner, has a single row of
radial holes directed into the Cyclone tangent. This
simple design has proven to be an excellent combustor. Many Cyclones are equipped with this burner and
are typically capable of obtaining full Cyclone rated
capacity. However, injecting the oil directly into the
Cyclone furnace recirculation zone resulted in an extremely high heat release rate and Cyclone tubes
would experience long term thermal damage. The oil
roof burner continues to be used as an emergency
Cyclone furnace deslagger for units firing coals with
high T250 values. It is also used to deslag a Cyclone
prior to a boiler outage. When coal flow to the Cyclone
is interrupted, a heat input of up to about one half of
the Cyclone rating is recommended for continuous load
carrying purposes.
The alternate design uses an oil burner located at
the Cyclone centerline firing directly into the Cyclone
furnace vortex.
If continuous, long-term oil-only firing at full Cyclone rated capacity is required, splitting the heat input 50/50 between the roof burner and the center fired
burner should be considered.
The Cyclone gas burners (capable of firing natural
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
Fig. 11 Batch removal slag handling system for Cyclone furnace boiler.
gas, coke oven gas, or other gaseous fuels) are located
in the secondary air throat, injecting gas normally
through three flat nozzles. Although this also injects
fuel directly into the recirculation zone, the lower radiant heating of natural gas produces a lower heat absorption rate within the Cyclone furnace. Therefore,
long term thermal damage has not been observed with
a gas burner. Natural gas assists in deslagging plugged
Cyclones, but its low radiant heat transfer rate to the
Cyclone does not heat slag deposits as well as oil firing.
Cyclone units firing coal may switch to oil or gas
for a short period without serious damage. However,
for long term gas and oil operation, the Cyclone should
be stripped of all slag and refractory to prevent erosive scrubbing of the tubes as previously discussed.
Waste burning
Due to their high heat release rate, the Cyclone furnaces have always been suited for firing a number of
waste fuels with coal. A nominal blend ratio tested has
been in the range of 5 to 20% heat input from the cofired waste, with a less than 10% level typically being considered acceptable. However, waste or refuse
fuel should first be thoroughly tested on the prospective Cyclone equipped boiler to determine these limits.
Refuse-derived fuel (RDF) RDF consists of the lighter,
more easily burned materials from municipal waste.
The ideal point of injection is the secondary air throat
to maximize fuel particle time in the Cyclone. A scaledup insulated version of the gas burner nozzle provides
the best injector. However, the resistance welded flat
studs found in original Cyclones may not withstand
the associated particulate erosion, and increased furnace slagging are potential negative consequences.
Tire-derived fuel (TDF) Along with stokers and wet
slagging PC units, Cyclones have been viewed as one
of the best proposed methods for disposing of scrap automobile tires. Tire rubber provides an excellent low
sulfur fuel, but the material’s elasticity prevents it
Steam 41 / Cyclone Furnaces
from being crushed or pulverized like coal. It generally appears that a 0.5 to 1.0 in. (13 to 25 mm) sizing
is close to optimum. Smaller grinds can be provided
by the waste rubber industry, but the cost greatly exceeds that of coal. The TDF should fire easily when
mixed with the coal. Although the steel content from
bead and radial ply tires does not affect the iron sulfide
factor noticeably, the bead wiring may be difficult to melt.
Petroleum coke A number of Cyclone operators have
successfully blended petroleum coke with their coal.
However, the lack of volatiles in petroleum coke can
delay fuel burnout, increasing furnace exit gas temperature and resulting in superheater slagging.
Wood chips Wood chips, sawdust, bark and other
similar solid waste products have long been co-fired in
Cyclones. Moisture content and sizing of the prospective
waste fuel helps determine the optimum blend ratios.
Various sludges Paper mill and sewage sludge materials have been successfully co-fired with coal and/
or natural gas in new Cyclone-fired boilers. The Cyclones are designed to utilize a secant firing technique
for the sludge material while the coal and/or natural
gas are introduced according to standard arrangements. Secant firing introduces the fuel through dedicated openings in the Cyclone that are located directly
beneath the secondary air inlet. This approach maximizes the retention time and temperature within the
Cyclone itself to allow for successful operating characteristics at higher than typical waste material heat
inputs (greater than 50% heat input on sludge). As with
any Cyclone-fired application, fuel acceptability criteria
must be closely followed to optimize operation (fuel T250
value, fuel fineness, minimal fuel moisture, etc.).
Combustion controls
The fuel/air ratio at each Cyclone remains the critical item in the combustion control system. When the
Cyclone total air flow becomes too low or too high, operating problems can develop. The balancing of the
fuel/air ratio is relatively easy to accomplish and monitor on smaller boilers with only one to five Cyclones.
On these units, individual ducts supply the total combustion air flow to each Cyclone furnace. On larger
Fig. 12 Arrangement of gas and oil burners in Cyclone furnace.
15-9
The Babcock & Wilcox Company
units, multiple Cyclones are housed within common
windboxes for the supply of secondary air. This arrangement inherently makes it more difficult to accurately monitor air to individual Cyclone furnaces.
As a result, larger Cyclone equipped boilers have typically been operated at higher excess air levels than
smaller units. Modern measurement and control techniques are improving the accuracy of air flow measurement. Although new devices are being designed
with more repeatable measurements, it is still advisable to field-verify the equipment by performing air calibrations after installation. When retrofitted with accurate gravimetric coal feeders for each Cyclone, such devices permit tighter individual Cyclone furnace control.
With the advent of the Cyclone air staging technology to help reduce NOx emission levels, the importance
of maximizing the accuracy of the fuel/air flow measurements and controllability has increased. Improving this accuracy not only enhances the NOx reduction capability of the system, but also maintains the required characteristics for acceptable Cyclone operation.
Operation
Igniters
Cyclones can be equipped with either No. 2 oil or
natural gas igniters, with oil igniters being the more
common option. On coal-fired Cyclones, both igniters
are located at or near the Cyclone front in the secondary air throat outlet. The oil igniter is installed external to the Cyclone and is a retractable design to prevent overheating of the igniter and related problems
with the oil atomizer. The gas igniter is a fixed design
and installed inside the secondary air duct immediately ahead of the exit into the Cyclone. Original Cyclones were equipped with either a 10 × 106 Btu/h (3
MWt) or 17 × 106 Btu/h (5 MWt) oil igniter that employed mechanical atomization, or a 17 × 106 Btu/h (5
MWt) stationary gas igniter. Both fuel igniter designs
made use of high voltage ignition.
Demand for increased oil igniter heat release and
decreased opacity, especially during cold start operations, led to the development of a larger, air atomized
oil igniter with high energy spark ignition system. This
new igniter, the CFS model, is capable of an input rating of 25 x 106 Btu/h (7.3 MWt) under specific conditions. These higher input oil igniters require a slightly
larger tube opening than was supplied on original Cyclones and would require some tube modifications if
installed on these older units.
Minor design changes and field testing of the standard stationary gas igniter led to a revised igniter capacity on natural gas to approximately 30 x 106 Btu/
h (8.8 MWt), thereby providing similar capacity on either gas- or oil-fired Cyclone igniters.
Cyclones firing only oil and natural gas as the main
fuels have additional igniter options with respect to
location. The retractable CFS oil and/or gas igniter can
be located axially down the center of the retired coal
burner or through the modified burner door.
For further information on oil and gas igniters, refer to the igniter section in Chapter 11.
15-10
Sectional secondary air control dampers
Cyclone furnaces can be equipped with sectional
dampers (2 or 3 blade sections) across the width of the
secondary air inlet. This arrangement provides an additional level of control for the Cyclone furnace combustion. Biasing these dampers permits adjustment to
the Cyclone combustion pattern and increases fuel
retention time. The effectiveness of this additional
control technique is greater when difficult to burn fuels are being fired (e.g., high moisture/low sulfur coal,
higher ash fusion fuels, etc.).
Low load operations
Typically, Cyclone furnaces firing a good Cyclone
bituminous coal can not operate below half load without the slag freezing. In addition, the main boiler furnace floor typically stops tapping slag below half load.
When firing subbituminous type coals, this minimum
low load level is higher due to the more difficult nature of firing that fuel in Cyclone boilers. In either
case, the slag taps tend to plug solid. An individual Cyclone can continue to operate and should eventually start
retapping. However, a boiler with a solidly plugged floor
tap must be shut down for manual slag removal.
Power requirements
Cyclone furnace boilers have significantly different
power requirements than do pulverized coal units.
Fuel preparation power consumption for Cyclone boilers is very low because the coal is only crushed, not
pulverized, and the primary air fan is not used. However, the forced draft fan power usage is substantially
higher due to the relatively high Cyclone windbox to
furnace pressure drop [typically 25 to 45 in. wg (6.2
to 11.2 kPa)]. This is illustrated in Fig. 13. The difference between Cyclone and PC firing is dependent
upon the fuel type and heating value. PC firing has
an advantage for high heat content and high
grindability bituminous coal firing applications. Cyclone firing has an advantage for low heat content
and lower rank fuels such as subbituminous, lignite and
brown coals which are also harder to pulverize. In the
case of the high heat content bituminous coals, the lower
operating costs of PC firing must be balanced against
the lower capital costs of Cyclone-based firing systems.
Maintenance
Corrosion and erosion within the Cyclone are the
two most critical maintenance items. The Cyclone’s wet
slagging environment produces a potentially corrosive
iron sulfide attack on the pressure part tubing.
Erosion is also a problem in an area opposite the
secondary air throat where a protective slag coating
can not form. The coal particles wear away the edges
of the protective flat studding and can cut a channel
between the studs and potentially damage the tubes.
Tubing – pin studs and refractory
In areas coated by molten slag, the tubes are protected by a refractory layer held in place by pin studs
(Fig. 14). In addition to retaining the refractory, the
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
resulted in a nickel sulfide attack which consumed the
coating in the same manner as iron sulfide corrodes
studs and tube surfaces. Furthermore, the pin studding does not lend itself to consistent spray applications. Some coatings prohibit installing replacement
pin studs unless the coating and any interacting tube
surface have been removed.
Refractory
Field experience has demonstrated that corrosive
slag in any form should be kept away from the tubes
by a refractory coating. Experience on operating units
has proven that the most durable refractories are ramtype high density formulations. The specific refractory
selection may be contingent upon the specific plant fuel.
Key overall issues to achieve the best potential
chance for increased refractory life include:
1. Ensure proper maintenance/application of studs
(along with maximizing stud density).
2. Choose the proper refractory for the application
(proven positive experience).
3. Use refractory that has not exceeded its shelf life.
4. Follow proper refractory installation and curing
procedures.
5. Follow good Cyclone startup/operation procedures.
Any one of these items done incorrectly can cause
early loss of refractory.
Fig. 13 Auxiliary power requirements for typical high-capacity,
pressure-fired Cyclone furnace and pulverized coal units.
pin studs cool the refractory surface in contact with
the corrosive slag and retard the corrosive chemical
action. The pin studs protect the refractory and the
refractory in turn protects the pin studs. Over time,
experience has demonstrated that tighter, or denser,
pin stud spacing improves refractory performance. The
denser pin stud patterns have provided very good performance in their ability to protect refractory and resist corrosion (Figs. 15a and b).
Tubing – flat studs
An advanced design has been developed and installed by B&W to reduce maintenance (Fig. 16). The
newer flat staggered stud design, using a hand applied fillet weld, offers the following advantages:
Coal crusher
Cyclone coal crushers have generally remained unchanged over the years. With the increased use of difficult to fire subbituminous low sulfur coals and the
need to crush the fuel as fine as possible, a change in
maintenance practice is recommended. Cages should
be adjusted and mills should be reversed more frequently than with standard Cyclone furnace coals. In
addition, the hammers should be discarded at their
half life to maintain adequate striking mass. To improve fineness to a greater degree, fine grind cages
can be installed. This normally reduces the original
capacity of the crushers and requires a motor upgrade
and/or additional installed crusher capacity to restore
system capacity.
1. more precise stud manufacturing and closer spacing,
2. minimum potential for channeling and accelerated wear between studs,
3. excellent heat transfer which reduces metal temperature and erosion rates, and
4. thicker stud sizes to extend life.
Metallization
To enhance tube life, the plasma arc flame spraying of alloy metals onto the tube surface has been used.
Despite a number of experiments with different metallization powders, the results generally remain inconclusive. Some applications using expensive coatings
Steam 41 / Cyclone Furnaces
Fig. 14 Cyclone furnace stud and refractory section.
15-11
The Babcock & Wilcox Company
Fig. 15a High density Cyclone pin studding.
Fig. 16 State-of-the-art flat studs after five years of service.
tion of more slag and less flyash can offer a significant disposal benefit. Furnace slag is much easier to
dispose of than flyash in most cases. The constituent
minerals are tightly bound in Cyclone slag, minimizing any leachate problems if landfilled. Cyclone slag
physical properties have led to its reuse as road bed
fill, shingles in the building industry, and sandblasting material (among other applications).
Fig. 15b Modern super dense pin stud pattern after five years
without maintenance.
Additional advancements
Additional retrofit design features continue to be
developed to improve the performance and reduce
maintenance costs of Cyclone boilers. These features,
based on site-specific needs, include:
1. contoured flat studs designed for the tubes that
make up the Cyclone slag tap,
2. improved seal welding design,
3. tighter gapped and extra reduced size re-entrant
throats,
4. continued wear block development,
5. stainless steel cooling water jackets for burners,
and
6. improved radial and vortex burner design elements.
Air pollution control
Flyash
To meet modern particulate emission standards, a
Cyclone equipped boiler precipitator must be about the
same size as that for a pulverized coal unit. Fabric
filters have also been applied. However, the produc15-12
Sulfur dioxide (SO2) reduction
As with other combustion systems, SO2 emissions
from Cyclone units are a function of the sulfur content in the fuel. One frequently used method for reducing SO2 emissions is to switch to lower sulfur coal.
Changing fuels typically requires a complete review
of the impacts on boiler operation (e.g. slagging, fouling, sootblower capability, main and reheat steam temperatures, economizer outlet gas temperature, flyash
collection, etc.). In the case of Cyclone furnace boilers, additional care is required in such a change because Cyclone furnaces are more sensitive to the ash
composition, ash quantity, heating value and especially moisture in the fuel. If high moisture subbituminous or lignite fuels are to be substituted for low
moisture bituminous coal, installing the direct-fired
pre-dry system could be considered to optimize performance. This system has been successfully used for lignite coal-fired Cyclone furnaces.
Provided that the fuel selected meets the T250 value
discussed earlier, a standard Cyclone equipped boiler
can potentially be modified to handle low sulfur, high
moisture subbituminous or lignite coals through a series of hardware and operational changes. Key
changes focus on improving and maintaining overall
coal fineness, maximizing Cyclone furnace temperatures as high as possible, continuing an aggressive
maintenance program, and making provisions for
rapid deslagging. The actions required are unit specific and are usually established following an engineering study and test fuel burn.
Coal washing systems may be installed to remove
pyritic sulfur. Although washing raises the T250 value
and makes the coal more difficult to burn, SO2 emissions will be reduced.
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
Nitrogen oxides (NOX) reduction
Historically, Cyclone equipped boilers have produced
relatively high uncontrolled levels of NOx emissions,
ranging from 0.70 to 2.6 lb of NOx as NO2 per million
Btu (approximately 1050 to 3900 mg/Nm3 corrected
to 3% O2). Based on ever increasing needs to reduce
NOx emission levels, various commercially available
Cyclone equipped boiler NOx reduction techniques are
available and include, but are not limited to:
1. fuel switching from a bituminous to a subbituminous type coal,
2. air staging,
3. reburning,
4. selective catalytic reduction (SCR) technology, and
5. selective non-catalytic reduction (SNCR) technology.
Switching from a standard Cyclone bituminous coal
to a subbituminous coal has shown that a nominal 10
to 25% NOx reduction can be observed. These reduction levels are due to two factors:
1. reduced thermal NOx component with the high
moisture content of the fuel (lower Cyclone peak
operating temperatures), and
2. lower fuel NOx component due to the inherent constituents in the coal (lower fixed carbon to volatile ratio, lower nitrogen component, etc.).
The most widely used Cyclone boiler NOx control technique is air staging. The basic theory of air staging is to
reduce the fuel NOx component within the burner zone
by reducing oxygen availability. Additionally, numerical modeling activities have shown that due to the unique
combustion characteristics of Cyclone equipped boilers,
some reburning chemical reactions also help to reduce
the overall NOx emissions during air staging operation.
This reburning phenomenon helps to explain the high
percentage NOx reduction that has been identified on
numerous staged-air applications on Cyclone-fired units
(up to 80% reduction).
Cyclone air staging employs multiple combustion
zones within the furnace region (see Fig. 17), defined
as the main combustion zone (Cyclone region) and the
burnout zone (OFA ports to the furnace exit). The
main combustion zone is designed to operate at nominal substoichiometric conditions. Operating at higher
Cyclone stoichiometries is feasible, but at a cost of minimizing the overall NOx reduction capabilities; actual
operating Cyclone stoichiometries would be optimized
during startup to provide the required NOx reduction
while maintaining optimum boiler operation. The balance of the required combustion air is introduced
through overfire air (OFA) ports in the burnout zone.
A satisfactory residence time within the burnout zone
is required for complete combustion.
Experience indicates good NOx reduction without
major negative operational impacts while air staging
on Cyclone units. However, there are potential negative issues that must be addressed. Reducing atmospheres accelerate corrosion, which can lead to significant maintenance problems. Corrosion and iron formation concerns are possible while operating under
reducing/oxidizing conditions. Utilizing lower sulfur/
iron fuels, such as lignite or low sulfur subbituminous
Steam 41 / Cyclone Furnaces
coals, will help reduce, but not eliminate, corrosion and
iron formation concerns. Additional operational issues
may include higher unburned carbon levels, increased
boiler flyash, increased boiler slagging/fouling, steam
temperature reductions, and higher opacity levels.
Low NOx Cyclone reburn technology has been specifically developed to reduce NOx emissions levels from
Cyclone equipped boilers (up to 70% reduction) while
permitting successful Cyclone furnace operation. In
this system, the Cyclone furnace can be operated under fully oxidizing conditions, but at a reduced load –
typically 70 to 85% of full load air and fuel flow. The
balance of the fuel is injected directly into the main
boiler furnace with minimum air for fuel transport to
create a reburning zone. In this zone, the reburn fuel
creates an oxygen deficient or reducing zone where
the NOx created in the Cyclone furnace is reduced or
decomposed into molecular nitrogen through a series
of complex interactions with free hydrocarbon radicals. Overfire air ports located above the reburn zone
permit injection of the balance of the air to produce a
final stoichiometry of 1.15 to 1.20 and complete the
fuel combustion. The use of coal, oil, or gas as the
reburn fuel depends upon an economic evaluation balancing the higher capital cost of a coal based system
against the fuel cost differential for other fuels.
Post-combustion technologies have also been successfully applied to Cyclone boilers and offer varying
degrees of NOx control capability (see Chapter 34).
Applications
The Cyclone boilers gained wide acceptance due to
their ability to burn a substantial reserve of coals
deemed unsuitable for pulverized coal firing. Also, the
unique inherent combustion characteristics of Cyclone
furnaces have proven to be an effective means to safely
fire a variety of waste materials. New Cyclone boiler
applications co-firing sludge materials have been and
continue to be developed.
Flow
Measuring
Device
Air Flow
Control
Damper
Burnout
Zone
Overfire
Air Port
Burnout Zone
• Balance of Combustion Air
• Controlled Fuel Burnout
~20%
~80%
Total
Airflow
SubStoichiometric
Region
Main Combustion Zone
• Lower O
• Lower Fuel/Thermal NO
Existing Cyclone
Fig. 17 Cyclone-equipped boiler air staging NOx control system.
15-13
The Babcock & Wilcox Company
B&W CycloneTM furnace.
15-14
Steam 41 / Cyclone Furnaces
The Babcock & Wilcox Company
Chapter 16
Stokers
Many technologies have evolved to convert a wide
variety of fuels to alternate forms of energy. One important technology is the mechanical stoker. All stokers are designed to feed fuel onto a grate where it
burns with undergrate air (UGA) passing up through
it, and overfire air (OFA) passing over it. The grate is
located within the lower furnace and is designed to
remove the ash residue after combustion. Evolving
from the hand-fired boiler era, mechanical stoker/
grate system designs are available to burn a wide
range of fuels for industrial, small utility and cogeneration applications. In addition to burning all forms
of coal, other fuels burned include sludge, wood waste
and biomass (e.g., wood, bark, straw, bagasse, rice
hulls, peach pits, almond shells, orchard prunings,
coffee grounds), as well as residential, agricultural,
industrial and commercial refuse. Modern mechanical stoker firing systems are composed of:
1. a stoker or fuel feeding system,
2. a stationary or moving grate assembly to support
the burning mass of fuel and admit undergrate air
to the fuel,
3. an OFA system to complete combustion and limit
atmospheric pollutant emissions, and
4. an ash or residual discharge system.
These components are then integrated into the overall furnace design to optimize combustion and heat
recovery while minimizing unburned fuel, atmospheric emissions and cost.
Despite the functional differences stated above, it
is not uncommon to hear or see the term stoker referring to not only the feeding device but also the entire
system, including the grate and air system. The feeding device can also be referred to as a feeder, distributor or spout, as well as a stoker.
A successful installation requires selecting the correct type and size of stoker for the fuel being used and
for the load conditions and capacity being served.
There are two general types of systems: underfeed and
overfeed. Underfeed stokers supply both the fuel and
air from under the grate while overfeed stokers supply fuel from above the grate and air from below the
grate. Overfeed stokers are further divided into two
Steam 41 / Stokers
types: mass feed and spreader. In the mass feed stoker,
fuel is continuously fed to one end of the grate surface and travels horizontally across the grate as it
burns. The residual ash is discharged from the opposite end. Combustion air is introduced from below the
grate and moves up through the burning bed of fuel.
In the spreader stoker, combustion air is again introduced primarily from below the grate but the fuel is
thrown or spread uniformly across the grate area. The
finer fraction of the fuel burns in suspension as it is
lifted by the upward moving flue gas flow. The remaining heavier fraction of the fuel lands and burns
on the grate surface with any residual ash removed
from the discharge end of the grate.
There is little demand in today’s market for the
underfeed and small mass overfeed coal-fired units
because of cost and environmental considerations.
This market has been replaced with shop assembled
oil- and gas-fired units and to some extent, by overfeed spreader stoker systems.
The stoker/grate systems are provided in many
mechanical configurations depending upon the manufacturer. Table 1 summarizes several variations of
basic stoker designs by type, fuel, heat release rate and
approximate largest capacity available. Grate heat
release rate is the fuel input divided by the active or
effective area of the grate upon which fuel burning is
intended to occur.
For a given boiler steam capacity, the typical fuel
burning rates in Table 1 generally determine the plan
area of the grate and furnace in which it is installed.
Practical considerations limit stoker size and, consequently, the maximum steam generation rates. For
coal firing, this maximum steam generation rate is
about 390,000 lb/h (49.1 kg/s); for wood or biomass
firing it is about 900,000 lb/h (113.4 kg/s).
Almost any coal can be burned on some type of stoker.
Many other solid fuels such as refuse and biomass can
be burned alone on a grate or in combination with another fuel such as pulverized coal, oil or natural gas.
The spreader stoker, in combination with the various grate types, is most commonly used for a steaming capacity range from 75,000 to 900,000 lb/h (9.5
to 113.4 kg/s). It responds rapidly to changes in steam
16-1
The Babcock & Wilcox Company
Table 1
Stoker/Grate System Overview
Stoker Type
Underfeed:
Single retort
Double retort
Multiple retort
Overfeed:
Mass
Spreader
Grate Type
Vibrating: water-cooled
Vibrating: water-cooled
Traveling chain
Reciprocating
Vibrating:
air-cooled
water-cooled
Traveling
Typical Release Rate*
1000 Btu/h ft2 (MWt /m2 )
Fuel
Steam Capacity
1000 lb/h (kg/s)
Coal
Coal
Coal
425
425
600
(1.34)
(1.34)
(1.89)
25
30
500
(3.15)
(3.78)
(63.0)
Coal
Straw
Coal
MSW**
400
500
500
300
(1.26)
(1.58)
(1.58)
(0.95)
125
320
310
350
(15.8)
(40.3)
(39.1)
(44.1)
Coal
Wood
Wood
Coal
Wood
RDF***
650
1100
1100
750
1100
750
(2.05)
(3.47)
(3.47)
(2.37)
(3.47)
(2.37)
150
900
900
390
550
400
(18.9)
(113.4)
(113.4)
(49.1)
(69.3)
(50.4)
*
Specific fuel characteristics and firing arrangements may allow higher heat release rates.
** Municipal solid waste
*** Refuse-derived fuel
demand, has good turndown capability and can use
a wide variety of fuels. It is not, however, suitable for
low volatile fuels such as anthracite and petroleum
coke because of carbon burnout problems.
Underfeed stokers
There are two general types of underfeed stokers:
the horizontal feed side ash discharge type shown in
Fig. 1 and the gravity fed rear ash discharge type
shown in Fig. 2.
In the side ash discharge type, coal is fed from a
hopper to a central trough, called a retort, by a screw
or ram pusher. Air is admitted through the tuyères or
air nozzles as shown. In the larger units, a ram assisted by pusher blocks or a sliding retort bottom (fuel
distributors) moves the fuel upward and into the retort. As the coal moves upward and over the retort
edges and spreads out over the active grate area, it is
exposed to air and radiant heat. Drying occurs and
distillation of volatiles begins. As the coal moves to the
sides and/or rear, the distillation is completed, leaving coke which is burned out near the edges or end of
the grate. High pressure OFA is used to produce high
turbulence and reduce smoke.
Burning coal in this fashion increases the probability of clinkering (producing large agglomerates of ash
slag) or matting (layers of ash slag). To reduce this
tendency, alternate fixed and moving grate sections
are applied to the underfeed stoker design to agitate
the fuel. Coal characteristics are critical to underfeed
stoker performance. Table 2 outlines coal specifications
for stationary and moving grates, although underfeed
stokers have burned coals outside of these guidelines.
To burn these coals, some deviation from the normal
maximum grate release rate may be required. A reduction in the percentage of fines helps to keep the
feed bed porous and extends the range of coals with a
higher coking index.
With suitable coal, single and double retort units
are generally limited to 25,000 to 30,000 lb/h (3.2 to
3.8 kg/s) steam flow. Typical grate release rates are
425,000 Btu/h ft2 (1.34 MWt /m2 ) with water-cooled
walls and 300,000 Btu/h ft2 (0.95 MWt /m2 ) with refractory walls. Capacities up to 500,000 lb/h (63 kg/s)
steam are possible with multiple retort rear ash discharge units similar to that shown in Fig. 2. Grate
release rates up to 600,000 Btu/h ft2 (1.89 MWt /m2 )
are practical with a 20 to 25 deg (0.35 to 0.44 rad) grate
inclination from the horizontal.
Fig. 1 Single-retort underfeed stoker with horizontal feed, side ash discharge.
16-2
Steam 41 / Stokers
The Babcock & Wilcox Company
Fig. 2 Multiple-retort, gravity-fed underfeed stoker with rear ash
discharge.
Mass feed stokers
Two types of mass feed stokers are used for coal firing: the water-cooled vibrating grate and the moving
(chain and traveling) grate stokers. Another mass feed
stoker system used for municipal refuse is discussed
in Chapter 29.
Mass feed stokers are characterized by the gravity
feed of fuel onto a stoker via an adjustable gate that
controls fuel bed height. The method of firing involves
a fuel bed that moves along a grate with air being
admitted under the grate perpendicular to the fuel
flow. As it enters the furnace, the layer of coal is heated
by furnace radiation to drive off volatiles and to promote ignition. The coal continues to burn as it is conveyed along the depth of the furnace. The fuel bed
decreases in thickness until all the fuel has burned
and cool ash discharges into a pit. With this method
of fuel entry, the undergrate air must be sectionalized
along the length of the grate because the quantities
of air required for ignition, burning and burnout are
different and must be regulated. This method of fuel
entry and combustion inherently produces low ash
carryover. However, it is more sensitive to variations
in fuel characteristics that affect ignition without a
larger ignition arch (discussed below). Mass feed stokers require nonsegregating coal feed hoppers. Without them, the fines migrate to the side walls and severe clinkering can occur.
A water-cooled vibrating grate stoker is shown in
Fig. 3. The vibrating grate consists of tuyère grate
surface mounted on and in intimate contact with a
grid of water tubes. The grate is connected to the boiler
or feedwater circulation system for cooling. The entire structure is supported by a number of flexing
plates that allow the grid and its grate to move freely
in a vibrating action that conveys the coal from the
feed hopper to the ash discharge. Vibration of the
grates is intermittent and is adjustable to convey fuel
along its length and control ash bed thickness and
discharge as needed. A rear arch extends over approximately the rear third of the grate as shown in
Fig. 3. It assists burnout and directs the higher excess air gases forward to mix with the rich volatile
gases from the ignition zone. A short front arch is
adequate for most coals. If ignition is inadequate due
to low volatile fuel, refractory can be added to the short
Steam 41 / Stokers
arch to increase radiation and assist ignition. This is
referred to as an ignition arch.
High pressure air, up to 30 in. wg (7.5 kPa), is injected through the front arch to promote turbulence
and combustion. Water cooling of the grates makes this
stoker more flexible with gaseous and liquid auxiliary
fuels, because a shift to either does not require special grate protection other than the normal bed of ash
left from coal firing. Burning rates of these stokers
vary with different fuels; in general, the grate heat release rate should not exceed 400,000 Btu/h ft2 (1.26 MWt
/m2). Due to the limited number of moving parts, this
stoker/grate system typically requires little maintenance.
Chain and traveling grate stokers, shown in Fig.
4, are similar to each other. Both form an endless belt
arrangement that passes over drive and idler sprockets or return bends. They both convey coal from the
hopper through the furnace to the ash discharge and
return under the grate. In the chain grate design, the
chain continues around to the return side. The traveling grate unit differs in that it uses a grate bar to
provide better control of siftings (fine ash falling
through the grate) when firing anthracite. The moving chain stoker requires more maintenance than the
water-cooled vibrating grate.
Chain and traveling grate stokers can burn a wide
range of solid fuels including peat, lignite, subbituminous, bituminous and anthracite coals and coke
breeze. Typical coal characteristic ranges are provided
in Table 2. Generally, these stokers use furnace arches
(front and/or rear, not shown in Fig. 4) to improve
combustion by reradiating heat to the fuel bed. When
burning low volatile anthracite or coke breeze, rear
arches direct the incandescent fuel particles and combustion gases toward the front of the stoker, where
they assist ignition of the incoming fuel.
Burning rates on chain and traveling grate stokers
vary with different fuels. The lower ash (8 to 12%) and
lower moisture (10%) fuels permit rates to 500,000 Btu/
h ft2 (1.58 MWt /m2); higher moisture (20%) and higher
ash (20%) fuels would limit the rate to 425,000 Btu/h
ft2 (1.34 MWt /m2 ). For low volatile anthracite, the rate
should not exceed 350,000 Btu/h ft2 (1.10 MWt /m2).
Spreader stokers
In the spreader stoker, the fuel is uniformly thrown
into the furnace across the grate area. Fines ignite and
burn in suspension; the coarser fuel particles fall to
Fig. 3 Water-cooled vibrating grate stoker.
16-3
The Babcock & Wilcox Company
Table 2
Typical Coal Characteristics for Different Stoker Types
Undergrate Feed Systems
Stationary Grate
Moving Grate
Mass Feed Systems
Water-Cooled
Vibragrate
Spreader Systems
Chain/
Traveling Grate
All
Moisture
0 to 10%
0 to 10%
0 to 10%
0 to 20%
25% max.***
Volatile matter
30 to 40%
30 to 40%
30 to 40%
30 to 40%
18% min.
Fixed carbon
40 to 50%
40 to 50%
40 to 50%
Remainder
65% max.
Ash
5 to 10%
5 to 10%
5 to 10%
6 to 20%
15% max.
Btu/lb (kJ/kg),
as fired
12,500
(29,075) min.
12,500
(29,075) min.
12,500
(29,075) min.
10,500
(24,423) min.
Free swelling index
5 max.
7 max.
5 max.
Ash softening
temperature*
2500F
(1371C)**
2500F
(1371C)**
2300F
(1260C)
2100F
(1149C)
2000F
(1093C) min.
Coal size, in. (mm)
1 (25.4) top
size x 0.25 (6.4)
Equal portions:
-0.25, 0.25 to
0.5, 0.5 to 1
1 to 0.75
(25.4 to 19.1) x 0
1 to 0 (25.4 to 0)
top size
1.25 (31.8) max.
top size;
0.75 (19.1)
min. top size
40%
60%
40%
20% max.
20% max.
(-6.4, 6.4 to 12.7,
12.7 to 25.4)
Max. through
0.25 (6.4) screen
Iron oxide, % in ash
20%
* The ash softening temperature here is the temperature at which the height of a molten globule is equal to half its
width under reducing atmosphere conditions.
** Below 2500F (1371C) the moving grate is derated linearly to 70% of its rated capacity at 2300F (1260C) ash fusion
temperature. Stationary grates are derated linearly to 70% at 2100F (1149C) ash fusion temperature and use steam for
tempering below about 2400F (1316C) fusion temperature.
*** Higher moisture may require preheated combustion air.
the grate and combust on a thin, fast burning bed.
Because the fuel is evenly distributed across the active grate area, the air is uniformly distributed under
and through the grate. The undergrate air plenums
may or may not be compartmented depending on the
grate type and application. A portion of the total combustion air is admitted through ports above the grate
as overfire air. The modern spreader stoker is the most
versatile and the most commonly used stoker system.
Spreader coal firing
Fig. 5 shows a modern boiler equipped with a traveling grate spreader stoker and designed to fire an
eastern bituminous coal. A straight, water-cooled membrane furnace wall construction minimizes refractory.
For the typical stoker coal-fired application, ignition
or combustion arches are not used. The installation
consists of:
1. state-of-the-art feeder-distributor units that distribute fuel uniformly over the grate,
2. specifically designed air metering grates,
3. dust collection and reinjection equipment,
4. a combustion air system including forced draft fans
for undergrate and overfire air, and
16-4
5. combustion controls to coordinate fuel and air supply with steam demand.
Feeders for spreader stokers
Spreader feeders have the capability to uniformly
feed coal into a device that can propel it along the
depth of a grate in an evenly distributed pattern.
Many designs have been used successfully over the
Coal Inlet
Chute
Coal Layer
Guillotine
Ignition
Arch
Inspection
Door
Grate Bars
Mounted on Chains
Clinker
Dam
Direction of Travel
Main Shaft with
Worm Gear Drive
Individual Controllable
Primary Air Chambers
Fig. 4 Traveling grate stoker.
Steam 41 / Stokers
The Babcock & Wilcox Company
Fig. 5 Typical spreader stoker coal-fired boiler; 290,000 lb/h (36.5
kg/s) steam.
years. The coal feed mechanisms include gravity, reciprocating plates and metering chain conveyors. The
mechanisms that propel the coal into the furnace include steam and air injection as well as underthrow and
overthrow rotors. Steam or air assist can be used with
the rotor systems. Fig. 6 shows a feeder-distributor with
overthrow rotor. The metering chain moves coal from
a small hopper to an overthrow rotor. The rotor is
equipped with blades shaped to uniformly distribute coal
over the grate area. Although spreader designs vary,
the overthrow design has been the most common.
With increasingly stringent emissions regulations,
stoker manufacturers have been studying design
variations that reduce the formation of nitrogen oxides (NOx ) and carbon monoxide (CO). Fig. 7 depicts
a state-of-the-art mechanical-pneumatic feeder-distributor with underthrow rotor. In this device, the coal
is fed from a hopper by a metering chain into an
underthrow rotor with air assist. This has improved
the feed and distribution capabilities, and 10 to 15%
reductions in NOx have been recorded compared to the
overthrow design.
Grates for spreader stokers
As with mass stokers, there has been a wide range
of grates used in spreader stoker coal firing. Stationary and dumping-type units are no longer installed
as new equipment. Traveling and/or vibrating aircooled grates are the most common. The traveling grate
shown in Fig. 5 is a high resistance air metering grate.
The resistance air metering concept eliminates the
need for undergrate air plenum compartmentation for
good air distribution and control. Moving adjustable
air seals are provided at the front and rear. The grates
are bottom-supported and therefore require an expansion joint at the interface to the water-cooled furnace.
Steam 41 / Stokers
The grate is a continuous moving chain. It consists of
a series of chains to which are attached the grate bars
that contain the air metering holes. The grate bars are
contoured to interface with adjacent bars, minimizing
air leakage between bars. The chains and grate bars
are supported by, and slide on, grate rails. The sliding
interface between the grate bar and rail also serves as a
seal to prevent excessive air from bypassing the air
metering holes in the grate. The grate travels from rear
to front, or towards the fuel feed end. This permits the
optimum fuel distribution pattern and the maximum
residence time for burnout of larger fuel particles. The
ash is continuously conveyed and spills off the end of
the grate into a hopper.
Although the traveling grate is a durable and
proven design, it has many moving parts and is subject to wear. To minimize wear, the speed of the grate
should generally be kept below 40 ft/h (12.2 m/h). This
may limit its use in some high ash fuel applications or
it may require limiting the grate plan area release rate
and input per unit width of stoker.
The grate is typically driven through the front
sprocket and shaft to keep the top of the chain in tension; mechanical and hydraulic drive systems are
available. Some systems use a ratchet concept, which
results in loading and unloading the chain at each
stroke. This leads to higher grate component wear than
does a continuous and uniformly torqued drive system.
Other types of traveling grates are similar to that
shown in Fig. 4. Many of these consist of a chain with
several links to form an endless belt. Air admission is
through the gaps in the links. These types of traveling grates typically have compartmented undergrate
air plenums to control air distribution.
Variable Speed
Coal Feed Drive
Coal
Hopper
Furnace
Front Wall
Header
Coal
Trajectory
Metering
Chains
and Scraper
Overthrow
Rotor
Fig. 6 Feeder-distributor with overthrow rotor.
16-5
The Babcock & Wilcox Company
of 15 to 30 in. wg (3.7 to 7.5 kPa) through a series of
small nozzles arranged along the furnace front and
rear walls. (See Fig. 8.)
Spreader stoker firing, with the air split between
undergrate and overfire, is a form of staged combustion and is effective in reducing NOx. By deeper staging, further reductions are possible. To take advantage of this characteristic, the modern unit shown in
Fig. 5 is designed for a total excess air of 25%. The
total air flow is split 65% undergrate and 35% overfire, which includes any air to the coal feeders. An
additional level of overfire air nozzles is installed in
the furnace front and rear walls above the coal feeder.
(See Fig. 8.) This permits deeper staging and delays
adding the remainder of combustion air until the hot
fuel bed gases have radiated some heat to the
waterwalls and are at a lower temperature. The OFA
is admitted at a maximum static pressure of 30 in. wg
(7.5 kPa) through nozzles designed for high penetration and mixing.
Fig. 7 Chain-type coal feeder with underthrow rotor (courtesy of
Detroit Stoker Company).
Air-cooled vibrating grates, similar to those shown
in Fig. 3, are also used in spreader stoker applications.
Except for a smaller size limitation, the application to
spreader coal firing is similar to that of the traveling
grate.
Carbon reinjection systems
The high degree of suspension burning results in
greater carryover of partially combusted fuel particles.
To achieve the highest boiler efficiency, these particles
are captured in a dust collector, as well as from generating bank, economizer and air heater hoppers, and
returned to the furnace for complete combustion. The
carbon reinjection system on the unit in Fig. 5 is pneumatic. The carbon particles and some ash are captured
by a mechanical dust collector and routed to a pickup
box, where air is injected to convey it back to the furnace. Multiple injection ports are located across the
width of the unit to uniformly mix the unburned carbon into the combustion zone for enhanced burnout.
Reinjection of significant ash is undesirable because it
can contribute to boiler surface erosion and grate clinkering. Because a mechanical dust collector is more effective in collecting larger particles, and because the
majority of the unburned carbon is the larger size fraction of the total carryover, the bias towards collecting
the unburned particles can be effected by limiting the
design efficiency of the mechanical collector. Carbon reinjection improves coal-fired boiler efficiency by 2 to 4%.
Combustion air system
In spreader stoker-fired units, 25% excess air is
typically provided for stoker combustion at the design
full load input. This air is split between the undergrate
air, OFA and fuel distribution air. Due to the high
degree of suspension burning, air is injected over the
fuel bed for mixing to assist fuel burnout and to minimize smoking. This dictates that 15 to 20% of the total air be used as OFA. This air is injected at pressures
16-6
Spreader stoker coal characteristics
As noted earlier, the spreader method of feeding and
combusting coal is versatile. It can operate satisfactorily on the full range of coals from lignite to bituminous.
Fuels having less than 18% volatile matter are not
generally suitable. Table 2 summarizes the range of coal
properties for spreader stoker application.
Bituminous coals readily burn on a traveling grate
without the need for preheated air. However, an air
heater may be required in the unit design for improved
efficiency. In these instances, the design air temperature
should be limited to below 350F (177C). The use of preheated air may limit the selection of fuels to the lower
iron, high fusion coals to prevent undesirable slagging
and agglomerating on the grate. The use of preheated
air at 350 to 400F (177 to 204C) is necessary for the
higher moisture subbituminous coals and lignites.
Higher ash coals can also be satisfactorily burned.
However, to keep grate speeds reasonable, it may be
necessary to lower the grate heat release rate and/or
reduce the input per unit frontal width.
Coal size segregation can present a problem on any
stoker, but the spreader is more tolerant because the
Fig. 8 Stoker overfire air system.
Steam 41 / Stokers
The Babcock & Wilcox Company
feeder rates can be adjusted; much of the fines burn
in suspension and not on the bed. Proper selection of
the coal feed equipment can significantly reduce the
tendency for coal size segregation.
Selection of a spreader stoker
Spreader stoker-fired traveling grates for coal are
typically designed with release rates summarized in
Table 1. Higher heat release rates may be allowed for
specific fuel characteristics and firing arrangements.
The air-cooled vibrating grate is limited to 650,000
Btu/h ft2 (2.05 MWt /m2 ). The length of the grate is limited to that over which the coal can be distributed. For
vibrating grates, the length limit is 18 ft (5.5 m); for
the traveling grate, it is 23 ft (7.0 m). The width of
the grate is the main variable in providing sufficient
total grate area. Sufficient width is also required to
install enough feeders and to keep the heat input per
foot of width below about 13.5 × 106 Btu/h ft (13.0 MWt
/m). A grate heat release rate of 750,000 Btu/h ft2 (2.37
MW/m2 ) or less also applies with full reinjection from
a mechanical dust collector. Higher inputs tend to increase slagging potential and may cause excessive fuel
entrainment and carryover.
Traveling grates are available up to 19 ft (5.8 m)
wide with a single driveshaft. For higher capacities,
two opposite hand grates provide the desired width.
With a practical grate width limit of 38 ft (11.6 m) and
a length limit of about 23 ft (7.0 m), the largest practical grate area is about 880 ft2 (81.8 m2 ).
Bark distributor feeders
Fig. 11 shows a modern air-swept spout. Bark is fed
from a metering bin through a chute into the inlet of
the spout. High pressure 20 in. wg (5.0 kPa) distribution air is introduced through an annulus across the
width of the air-swept spout. In combination with the
momentum of the falling bark, the air propels the bark
into and across the grate depth. The distribution air
is pulsed by rotating dampers or by a preprogrammed
distributor to spread the bark uniformly fore-and-aft
across the grate depth. A portion of the spout air is
injected through small nozzles located at the furnaceside corners of the spout. This air assists the burning
of fines and is adjustable to suit the fuel conditions.
The discharge of the air-swept spout is shaped to
produce the optimum trajectory of the fuel particles.
Some vendors provide an adjustable plate to control
the discharge and subsequent distribution; some also
supply mechanical bark feeders having features similar to those depicted earlier for stoker coal firing. Sufficient spouts are installed across the width of the unit
to feed the necessary quantity of bark and to control
the side-to-side distribution and grate coverage.
Of equal importance is the system that feeds the fuel
to the air-swept spouts. Bark is conveyed across a series of smaller metering bins in a quantity greater
than that needed for combustion; the excess is returned to storage. The individual metering bins are
equipped with screw feeders that convey the bark in
accordance with fuel demand. They are capable of
Ash removal
When properly sized and operated, the ash discharging from a spreader stoker-fired unit is relatively cool
and clinker free. Ash discharges into a hopper and
may be removed by a conventional ash transport system, generally without the need for clinker grinders.
Spreader stoker firing of bark, wood and
other biomass fuels
Several modern boiler designs are available to meet
customer and project-specific requirements to fire
bark, wood and other biomass fuels using a spreader
stoker design. Fig. 9 shows a top supported Stirling
power boiler with a vibrating grate stoker. Fig. 10
shows a bottom-supported power boiler also with a vibrating grate. Both include state-of-the-art air-swept
spouts in widths and numbers required to uniformly
distribute the fuel over the grates. These units feature forced draft fans for undergrate and overfire air,
mechanical dust collectors, and combustion controls to
coordinate fuel and air supply with steam demand.
Several furnace configurations are used to meet
project requirements and are available in either top
or bottom-supported configurations. Fig. 9 shows the
furnace with two arches separating the furnace into
lower and upper zones (CCZ or Controlled Combustion
Zone furnace) while Fig. 10 shows a straight wall furnace without arches, but including an advanced
overfire air injection system. Selection of furnace type
depends upon project requirements, fuel characteristics,
and detailed numerical combustion modeling analyses.
Steam 41 / Stokers
Fig. 9 Typical wood-fired stoker boiler with Controlled Combustion
Zone (CCZ) furnace.
16-7
The Babcock & Wilcox Company
Day Bin/Hydraulic
Fuel Silo
Steam
Drum
Radiant
Superheater
Superheater
Gas
Outlet
Auxiliary
Burners
Air Heater
Furnace
Speed Controlled
Screw Feeders
Economizer
Air-Swept
Spout
Water-Cooled
Vibrating Grate
Individual
Controllable
Primary Air
Chambers
Fig. 10 Bottom-supported boiler with vibrating grate stoker –
biomass firing.
speed biasing across the furnace width. This system
minimizes fuel shortages at the boiler front, uses
smaller bins, has a reduced tendency to have the fuel
hang up or bridge in the bins and hoppers, and provides consistent fuel size distribution to the bins and
across the width of the unit. Other types of feed systems, such as large live-bottom bins, are successful
when applied with the proper fuel characteristics. Some
bark and other biomass fuels are stringy and can agglomerate and segregate. These characteristics must be
considered when designing feed systems for the airswept spout.
Grates for firing bark and other biomass fuels
A traveling grate for bark firing is very similar to
that used for spreader stoker coal firing. The bark is
fed over the fuel bed and distributed uniformly across
the grate area. This design is essentially an air-cooled
grate; therefore, it is important to retain a layer of ash
on the grate to shield the grate bars from furnace
radiation. When firing low ash barks, it is common to
operate the grates intermittently so that an inventory
of ash can build and be retained. In addition, high
alloy grate bars having higher resistance to thermal
degradation can be used.
Bark is a high volatile fuel that, in combination with
the fines, has a high degree of suspension burning.
High volatile and low ash characteristics permit sizing traveling grates with heat release rates to
1,100,000 Btu/h ft2 (3.47 MWt /m2 ). The width limitation of dual traveling grate stokers is also about 38 ft
(11.6 m) and the depth is mechanically limited to about
the equivalent furnace depth of 23 ft (7.0 m). At these
size limits, steam flow capabilities are limited to about
550,000 lb/h (69.3 kg/s).
16-8
The ash in bark, predominately silica, is very abrasive. This, in combination with high temperature grate
bar exposure, causes high maintenance. As a result,
some vendors have reintroduced the water- or aircooled vibrating grate stoker. A water-cooled version
is shown in Fig. 12. The combustion concept is no different than that for traveling grates. A complement
of grate bars with air metering holes is attached to and
supported by a water-cooled tubular grid connected
to the boiler or feedwater circuitry. A heat conducting
cement may be used to enhance grate cooling. The water-cooled grid is then supported by a complement of
flexible straps. To convey ash, a back-and-forth motion is imparted to the grid which, supported on the
flexible straps, imparts a looping motion to the grate.
This motion, at predetermined intervals, is sufficient
to convey and discharge the ash to the hopper. A variant of the water-cooled grate is the air-cooled type. In
the air-cooled grate, the water tube grid is replaced
by a mechanical grid to support the grate bars; components are then cooled by the flow of undergrate air.
The advantages of the water and air-cooled grates are
their simplicity, minimal moving parts, and lower
maintenance. Grate sections generally range in width
from 4 to 11 ft (1.2 to 3.35 m) to meet project functional and economic requirements. Because of their
Fuel
Supply
Counterweight
Back-Fire Damper
Air
Inlet
Pneumatic
Cylinder
Gear
Motor
Air
Inlet
Pulsating
Air Damper
Adjustable Fuel
Distribution Plate
Fig. 11 Air-swept spout.
Steam 41 / Stokers
The Babcock & Wilcox Company
Air-Swept
Spout with
Back-Fire
Damper
Water-Cooled
Grate Panels
Vibration
Units
Leaf Spring
Supports
Individual Controllable
Primary Air Chambers
Submerged Ash Conveyor
Fig. 12 Water-cooled vibrating grate stoker.
independent modular construction, vibrating grate
modules can be installed side by side to the mechanical limits of the boiler. Furthermore, grate depths are
generally permitted to the limit of fuel throw and distribution of 26 ft (7.9 m). The largest vibrating grate
currently in operation is almost 45 ft (13.7 m) wide.
When sized to grate release rate limits of 1,100,000
Btu/h ft 2 (3.47 MW t /m 2), steam flow capacities of
800,000 to 900,000 lb/h (100.8 to 113.4 kg/s) are available on wood, bark and other biomass fuels.
Combustion air system
The excess air for bark, wood and most biomass fuels
ranges from 15 to 50%, depending on stoker type and
firing conditions. Because biomass fuels are typically
highly volatile on a dry basis, heterogeneous in size
and tend to burn more in suspension, combustion air
systems are designed to provide more overfire air than
that used for coal. Modern designs permit undergrate
and overfire quantities of 40 to 60% of total stoker combustion air respectively, excluding any combustion air
used for auxiliary burners. Overfire air system design
and arrangement in combination with furnace geometry play an important role in completely burning the
combustibles liberated from the grate. Fig. 9 shows a
furnace design that promotes recirculation and mixing
at and below the lower furnace bustle (arches). Multiple elevations of large overfire air nozzles allow high
energy jets of air to penetrate and mix, enhancing
combustion. The system is designed to permit flexibility in distributing the air within the overfire air system as fuel characteristics vary.
Numerical modeling techniques (see Chapter 6)
have advanced OFA system design for biomass fuels.
Today, fewer levels of OFA with very large ports are
arranged to more effectively create turbulence for
mixing gaseous combustibles with air without the
Steam 41 / Stokers
need for a lower furnace bustle. Fewer ports mean
lower initial cost and simplified operation. Port
elevation(s) can be located to optimize CO and NOx
performance. The ports also serve as convenient injection sites for non-combustible/malodorous waste
gases. Fig. 13 shows a horizontal rotary overfire air
system designed to create a double rotating circulation zone within the furnace. Fig. 14 depicts a B&W
PrecisionJet™ air system with ports arranged in an
interlaced pattern. Both systems typically require air
pressures of less than 20 in. wg (5.0 kPa) and result
in both exceptional combustion performance and
fairly uniform gas distribution leaving the combustion
section. Because the highly turbulent air zone is located well above the fuel feed and grate area, less ash
and char are carried out of the furnace.
Combustion carryover and flyash reinjection
Fig. 15 shows the recommended sizing distribution
for wood or bark. The degree of grate or suspension
burning varies with fuel size. A portion of the fuel that
ignites in suspension may be too large to complete
burning; it therefore goes out with the flue gas as
unburned carbon. Many factors such as fuel sizing,
grate release rates, moisture content and reinjection
affect the unburned carbon loss. In addition, furnaces
sized to a maximum liberation rate of about 18,000
Btu/h ft3 (186 kWt /m3 ) can control unburned carbon
losses to 1 to 3%. Further reductions can be attained
with flyash reinjection in certain biomass-fired units.
Because of high maintenance costs due to the high
silica content and abrasiveness of wood and bark
flyash, reinjection systems are not frequently used
with these fuels unless sand classifiers are also installed. As one example, the unit shown in Fig. 9 does
not feature a flyash reinjection system.
In cases where the unburned carbon carryover
must be further controlled, mechanical particulate
collectors can be installed downstream of the generating bank. These collectors are sized to take advantage of the fact that the carbon particles are typically
larger and heavier than the inerts in the flyash. This
permits a carbon-rich stream to be reinjected into the
furnace for further combustion. This mechanical collection and reinjection reduces the ultimate carbon
loading in the downstream equipment and the possibility of fires.
Front
Wall
OFA
OFA
Rear
Wall
OFA
Fig. 13 Furnace plan view showing horizontal rotary overfire air
system.
16-9
The Babcock & Wilcox Company
Front
Wall
Rear
Wall
OFA
OFA
Fig. 14 Furnace sectional side view showing single level air system
with PrecisionJet™ ports.
Grate sizing
For wood and bark firing with moisture contents at
or below 50%, it is common practice to select a grate
area that results in a design heat release rate of
1,100,000 Btu/h ft2 (3.47 MWt /m2 ). At 35% moisture,
the release rate may approach 1,250,000 Btu/h ft2
(3.94 MWt /m2 ). At moisture levels higher than 55%,
the fuel becomes more difficult to ignite and burn.
Traveling grate stokers are mechanically limited to
about 23 ft (7.0 m) of equivalent furnace depth and
about 38 ft (11.6 m) in width. Grates are generally
longer than they are wide because this design is the
least expensive. For a water-cooled grate, the depth
is limited by the feeder’s ability to distribute the bark
over the grate depth. This distance is about 26 ft (7.9
m). Because of its modular construction, the maximum
width of a water-cooled grate assembly is limited only
by mechanical limits of the boiler.
Combustion air temperature
When firing wood, bark and other biomass fuels, it
is necessary to consider the fuel moisture content to
determine the need for preheated combustion air.
Undergrate air temperatures in excess of that needed
for the moisture content of the as-fired fuel contribute to NOx and particulate emissions. Biomass fuels
with less than 35% moisture content do not require
preheated air. With seasonal variation in fuel moisture and the growing interest in co-firing wood and
bark with sludges, the air heating system should be
sized and selected for the maximum expected moisture.
16-10
The temperature limit for the air-cooled traveling grate
with ductile iron bars is generally 550F (288C). If
higher temperatures are needed, the water-cooled
vibrating grate can withstand air temperatures to
650F (343C). In some cases, a steam or water coil air
heater can provide variable undergrate air temperature when needed.
The decision of whether to use heated or unheated
air for the OFA system must consider the overall
project goals and economics. Hot OFA is preferred for
new systems when maximum heat recovery is of singular importance. Hot air achieves greater penetration than cold air at the same mass flow rate, tends to
burn out CO and hydrocarbons better, and reduces
the chances for acid dewpoint corrosion of non-condensable gases in port boxes. Cold OFA systems are
lower cost to retrofit because they do not require insulated ducts for personnel protection. Because cold
OFA requires smaller ports, it is preferred where vertical clearance is tight.
There are many other biomass fuels such as rice
hulls, bagasse, peach pits, coffee grounds and demolition debris, that may be fired on spreader-type stokers. Most of the criteria for sizing and using a spreader
stoker are similar to those for wood and bark. Loose
straw, however, should be mass fed. Use of a spreader
stoker can cause uncontrolled carryover of burning
lightweight particles into the convection section.
Ash removal
The ash content in wood and bark is only a few
percent by weight and predominantly composed of
silica. Because it is very abrasive, slow grate speeds
and abrasion resistant materials should be used. Bottom ash typically drops into a refractory lined hopper
from which it is intermittently removed. Submerged
chain conveyors are also suitable. Due to the carbon
content and the tendency for fires, the flyash from the
hopper and dust collecting equipment is removed continuously. Wet sluice or inert gas (flue gas) systems
are generally used to convey the flyash to the storage
silos. Wet systems are preferred due to fire and dusting resistance.
Emissions
The installation of any new steam generator or a
major rebuild or upgrade to an existing one requires
environmental permitting. Therefore, the ability to
predict and control the various emissions is important.
Add-on pollution control equipment is generally required to meet the increasingly stringent regulated
levels. However, it is also important to control or minimize the source emissions where possible to reduce the
cost of this add-on equipment.
Table 3 lists typical uncontrolled emission values for
spreader stoker firing of various coals and wood/bark.
These values will vary with fuel composition and
equipment selection.
NOx is formed from the oxidation of the nitrogen
compounds in the combustion air and in the fuel. With
stoker firing it is believed that most of the NOx is de-
Steam 41 / Stokers
The Babcock & Wilcox Company
Fig. 15 Recommended sizing for wood or bark spreader stoker
firing (courtesy of Detroit Stoker Company).
rived from fuel-bound nitrogen (fuel NOx); the contribution due to oxidation of the nitrogen in the air
(thermal NOx) is small due to relatively low furnace
temperatures. NOx emissions can be effectively reduced by staging combustion, inherent in spreader
stoker firing, and by controlling excess air levels. For
both coal and wood/bark stoker firing, the excess air
level in low NOx stoker systems is about 25%. To reduce NOx to the lower end of the range shown in Table
3, designers are now using deeper staging, i.e., lower
undergrate and higher overfire air flows, as well as
flue gas recirculation. For spreader firing, feeders are
also designed to improve fuel distribution and combustion on the grates. Other factors that reduce NOx formation include controlling the quantity of fines in the
fuel and using ambient temperature combustion air.
Many waste fuels such as straw and other nonwood
fibers have high fuel nitrogen content. Commercial
wastes such as demolition debris are dry and will combust at higher temperatures, producing higher NOx.
It is therefore important that a thorough investigation of the fuel be made to assess its potential effect
on emissions.
For most stoker-fired units burning coal or biomass
that contains sulfur, sulfur dioxide (SO2) will be present
in the flue gas. For prediction purposes and for sizing of
SO2 control equipment, it is assumed that all the fuel
sulfur becomes SO2.
Carbon monoxide (CO) and volatile organic compound emissions are generally a function of the quality of the combustion process and the quantity and
control of fines and excess air. CO will tend to increase
as NOx is reduced.
Table 3
Typical Post Combustion Emissions for Spreader Stoker Firing
Fuel
Bituminous
Subbituminous
Lignite
Wood/bark
NOx (as NO2 )
lb/106 Btu
0.35 to
0.3 to
0.3 to
0.1 to
0.5
0.5
0.5
0.35
CO
lb/106 Btu
0.05 to
0.05 to
0.10 to
0.05 to
0.30
0.30
0.30
0.50
Unburned Carbon Loss (% of Heat Input)
With
Without
Reinjection
Reinjection
0.5 to 2.0
0.5 to 1.5
0.5 to 1.5
0.2 to 2.0
3 to 6
3 to 5
3 to 5
2 to 5
Approximate conversion: 1 lb/106 Btu = 1230 mg/Nm3 (dry flue gas 6% excess O2, 350 Nm3/GJ).
Includes applicable overfire air systems.
Steam 41 / Stokers
16-11
The Babcock & Wilcox Company
Vibrating grate stoker.
16-12
Steam 41 / Stokers
The Babcock & Wilcox Company
Chapter 17
Fluidized-Bed Combustion
In the 1970s, fluidized-bed combustion technology
was first applied to large-scale utility boiler units to
explore new ways of burning solid fuels, especially
high-sulfur coal, in an environmentally acceptable
and efficient manner. In concept, fluidized beds burn
fuel in an air-suspended mass (or bed) of particles. By
controlling bed temperature and using reagents such
as limestone as bed material, emissions of nitrogen oxides (NOx) and sulfur dioxide (SO2) can be controlled.
Additional benefits of fluidized-bed combustion include wide fuel flexibility and the ability to combust
fuels such as biomass or waste fuels, which are difficult to burn in conventional systems because of their
low heating value, low volatile matter, high moisture
content or other challenging characteristics. In coalfired systems, the fuel is burned in an air-suspended
bed of limestone and inert ash particles where SO2 is
absorbed by the limestone, and NOx formation is limited by lower operating temperatures and staged combustion, when used. This technology is now used in a
variety of industrial and utility boiler applications.
Today, bubbling fluidized-bed (BFB) boilers, with
a bed of fluidized particles that remain in the lower
furnace, are used primarily in specialty fuel applications such as coal wastes and biomass fuels. Circulating fluidized-bed (CFB) boilers, with solids circulating through the entire furnace volume, address most
larger steam generator applications and a broader
range of fuels.
The fluidized-bed process
The fluidizing process induces an upward flow of a
gas through a stacked height of solid particles. At high
enough gas velocities, the gas/solids mass exhibits liquid-like properties, thus the term fluidized bed.
The following example helps illustrate the process.
Fig. 1a shows a container with an air supply plenum
at the bottom, an air distributor that promotes even
air flow through the bed, and a chamber filled with
sand or other granular material.
If a small quantity of air flows through the air distributor into the sand, it will pass through the voids
of an immobile mass of sand. For low velocities, the
air does not exert much force on the sand particles and
they remain in place. This condition is called a fixed
bed and is shown in Fig. 1b.
Steam 41 / Fluidized-Bed Combustion
Fig. 1 Typical fluidized-bed conditions.
By increasing the air flow rate/velocity, the air exerts greater forces on the sand and reduces the contact forces between the sand particles caused by gravity. By increasing the air flow further, the drag forces
on the particles will eventually counterbalance the
gravitational forces, and the sand particles become suspended in the upward stream. The point where the
bed starts to behave as a fluid is called the minimum
17-1
The Babcock & Wilcox Company
fluidization condition. The increase in bed volume is
insignificant when compared with the non-fluidized
case (Fig. 1c).
As the air flow increases further, the bed becomes
less uniform, bubbles of air start to form, and the bed
becomes violent. This is called a bubbling fluidized bed
(BFB), shown in Fig. 1d. The volume occupied by the
air/solids mixture increases substantially. There is an
obvious bed level and a distinct transition between the
bed and the space above.
By increasing the air flow further, the bubbles become larger and begin to coalesce, forming large voids
in the bed. The solids are present as interconnected
groups of high solids concentrations. This condition is
called a turbulent fluidized bed.
A further increase in air flow causes the particles
to blow out of the bed and the container. If the solids
are caught, separated from the air, and returned to
the bed, they will circulate around a loop, defined as
a circulating fluidized bed (Fig. 1e). Unlike the bubbling bed, the CFB has no distinct transition between
the dense bed in the bottom of the container and the
dilute zone above. The solids concentration gradually
decreases between these two zones.
The pressure differential between the top and the
bottom of the container changes with air flow, as
shown in Fig. 2. At low air flow, the pressure differential increases with flow through the static bed until reaching the minimum fluidization velocity. At this
point, the sand is supported by the air, and the pressure differential is determined only by the mass of bed
material. The pressure differential is independent of
further increases in air flow until the air velocity becomes high enough to convey material out of the container. Then the pressure differential decreases as
mass is lost from the system, which is represented by
the entrained flow portion of the curve in Fig. 2.
An important parameter for evaluating hydrodynamic and heat transfer performance of particle mixtures is the Sauter (also called volume-surface or harmonic) mean diameter (SMD):
SMD =
where
X1 to XN = weight fraction of first to last size cut
D1 to DN = average diameter of first to last size cut,
microns
Of these fluidization conditions described above,
only bubbling and circulating beds are currently used
by the power industry to generate steam.
Bubbling fluidized-bed (BFB) boilers
Fig. 3 shows the main features of a bubbling fluidized-bed boiler while Fig. 4 shows a typical furnace
bulk density profile curve. The sharp drop in density
indicates the top of the bed.
The bottom of the furnace in a BFB boiler consists
of a horizontal air distributor with bubble caps. This
provides the fluidizing air to the bed material in the
lower furnace. As discussed later, The Babcock & Wilcox Company (B&W) offers two air distributor systems
depending upon the fuel and application. The bubble
caps are closely spaced so that air flow is distributed
uniformly over the furnace plan area. The lower furnace is filled with 2 ft (0.6 m) of sand or other noncombustible material such as crushed limestone or bed
material from prior operation. Air flow is forced upward through the bed of material, and the bed expands to a depth of about 3 ft (0.9 m) taking on most
of the characteristics of a fluid. The air flow through
the bed is very uniform due to a high number of air
distributors (bubble caps) and bed pressure drop. The
Secondary
Superheater
Primary Superheater
Economizer
1
X1
X
X
+ 2 +… + N
D1
D2
DN
(1)
Gas
Water Cooled
Walls
Freeboard
(Area Above
Bed Surface)
Gas
Flow
Mechanical
Dust Collector
(Multiclone)
Top of Bed
Bubbling
Bed
Recycle
Furnace
Superheater and
Boiling Surface
(Selected Fuels)
Air
Air Distributor
(with Bubble Caps)
Fig. 2 Effect of velocity on bed pressure drop.
17-2
Windbox
Fig. 3 Typical bubbling fluidized-bed boiler schematic.
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
Bubble
Cap
Air from
Duct
Fuel Feed
Bubble
Caps
Air
Duct
Fig. 4 Typical atmospheric pressure bubbling-bed furnace density
profile.
typical slumped (non-fluidized) density of a sand bed
is 90 lb/ft3 (1442 kg/m3 ). The voidage or volume between the particles in the fluidized bed is 65% and the
bulk density is 58 lb/ft3 (929 kg/m3 ). The gas flow rate
through the bed is defined as the superficial bed velocity, which is calculated by dividing the volumetric
gas flow rate at the bed temperature by the plan area
of the bed without the solids. A typical nominal design
superficial velocity of 8 ft/sec (2.4 m/sec) is enough to
fluidize BFB bed material with a particle size distribution between 500 and 1400 microns. The boiler
enclosure is made of water-cooled membrane panels.
B&W offers two air distributor systems for its BFB
boilers: open bottom and flat floor systems. The open
bottom system shown in Fig. 5 is characterized by the
fluidizing air bubble caps and pipes mounted on
widely spaced distribution ducts (see also Fig. 6) located in the bottom of the BFB furnace. Stationary
bed material fills the hoppers and furnace bottom up
to the level of the bubble caps, above which the bed
material is fluidized by the air flow. The open spacing
is effective in removing larger rocks and debris from
the active bed area as bed material moves down
through hoppers. This design is particularly attractive in biomass and waste fuel applications, which
contain non-combustible debris. In the flat floor system shown in Fig. 7, the floor of the furnace is formed
by horizontal water-cooled membrane panels with
bubble caps. Air passes from a windbox below the
water-cooled panel through the bubble caps to enter
and fluidize the bed material. Separate bed drains are
provided. The membrane panel floor must form an airtight seal with the furnace walls, must support the
weight of a slumped bed, and must resist the uplift
generated from the air pressure drop during operation. This design is attractive for firing coal where
there is much less large debris present.
Coal-fired bubbling-bed boilers normally incorporate a recycle system that separates the solids leavSteam 41 / Fluidized-Bed Combustion
Header
Table
Maintenance
Slide Gate
Dome Valve
Fig. 5 Open bottom air distributor system with bubble caps.
ing the economizer from the gas and recycles them to
the bed. This maximizes combustion efficiency and
sulfur capture. Normally, the amount of solids recycled
is limited to about 25% of the combustion gas weight.
For highly reactive fuels such as biomass, this recycle
system is usually omitted.
The typical operating temperature range of a bubbling bed is 1350 to 1650F (732 to 899C), depending
on the fuel moisture, ash content, and alkali content
Fig. 6 Air distributor ducts and bubble cap system.
17-3
The Babcock & Wilcox Company
tributor, fluidized bed of material, and overfire air systems are clearly identified.
Fig. 10 shows a sectional side view of a small BFB
boiler firing wood, wood waste and byproduct sludge.
This Towerpak ® boiler design is a version of the
Stirling® power boiler (SPB, see Chapter 27) with two
drums and bottom support for ease of installation. This
unit is capable of supplying 120,000 lb/h of steam flow
(15.12 kg/s).
All fossil fuel boilers require closely coordinated control of fuel, air, water and steam parameters. Fluidizedbed boilers require additional control. Selected key parameters for fluidized-bed boiler design include: bed temperature control (fuel dependent), bed inventory control,
bed density (for heat transfer control), and emissions.
Bed temperature control and fuel feed
The most fundamental control function of a BFB
combustion process is bed (combustion) temperature
control. The control method depends upon the fuel
Steam Drum
Attemperator
Generating
Bank
Superheater
Screen
Fig. 7 Furnace distributor plate and bubble caps for a flat floor system.
in the ash. Even at these low combustion temperatures, the high convective and radiative heat transfer from bulk bed material to the fuel particles provides sufficient ignition energy to evaporate moisture,
heat the ash, and still combust the remaining fuel
without significantly changing the instantaneous bed
temperature. This is why the bubbling bed can burn
low-grade fuels, which burn at low combustion temperatures due to their high moisture and ash contents.
Heat transfer surface may be placed within the bed
depending upon the fuel being burned. For biomass
and other low heating value fuels, no in-bed surface
is usually required because other methods of bed temperature control can be used. For coal firing with its
high heat content and lower relative volatility, the
heat transfer surface, in the form of a tube bundle, is
placed in the bed to achieve the desired heat balance
and bed operating temperature. The bed temperature
is uniform, plus or minus 25F (14C), as a result of the
vigorous mixing of gas and solids.
BFB combustion systems are attractive retrofits to
older boiler designs where a change in fuels or wider
fuel flexibility is required. Fig. 8 shows a sectional side
view of a process recovery (PR) boiler that was retrofitted with a B&W open bottom BFB combustion system. The black liquor firing capacity was no longer
needed and the owner wanted a power boiler capable of
firing wood waste, primary clarifier sludge, and tirederived fuel. Fig. 9 shows an isometric of the BFB combustion system in the bottom of the boiler. The air dis17-4
Economizer
Ammonia/Urea
Injectors
(SNCR)
Burners
Refractory
Line
Overfire
Air
System
Startup
Burners
Fuel
Spouts
Fluidized
Bed
Ash
Conveyors
Fig. 8 B&W open bottom BFB furnace retrofit of a process recovery
boiler.
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
Auxiliary
Burner
Overfire
Air
Fuel
Chute
Startup
Burner
Fluidized Bed
Open Bottom/Bubble Cap
Air Distribution System
Fig. 9 Isometric of BFB furnace bottom.
being fired. Bed temperature is controlled to limit
emissions of NOx and SO2, and to limit bed material
agglomeration. Agglomeration is caused by sodium and
potassium combining with alumina and silica to form
low melting point eutectics that can coat the bed particles. If the alkali concentration in the coating is too
high, the coating can start to melt and cause particles
to stick together. As a result, the larger particles do not
fluidize and, if the process continues, the bed can solidify and the combustion process can stop. The agglomeration process is quite temperature-sensitive and
some fuels have strict requirements for the maximum
Steam 41 / Fluidized-Bed Combustion
peak bed temperatures. Also, some fuels have such
high alkali contents that the fuel can not be fired in a
fluidized bed combustion process. Such fuels are typically agro-based where the plants are fertilized or the
ground is rich in alkali. Some process waste can also
contain high alkali concentrations.
Biomass firing Biomass firing begins with an inert
bed of solid particles in the bottom of the furnace preheated to 1500F (816C) using oil or gas startup burners. Air flows into this bed at 68 to 392F (20 to 200C)
and fuel at 68F (20C). The bed material must heat the
incoming air and fuel to the bed temperature and the
17-5
The Babcock & Wilcox Company
Attemperator
Limestone, Sludge
and Wood
Superheater
Fuel Mixing
Screw
Economizer
Metering
Bin
Generating
Bank
Gas
Air
Tubular
Air Heater
Rotary Airlocks
Overfire Air System
Burners
Fuel Spouts
Fluidized Bed
Ash
Conveyors
Steam Coil
Air Heater
Silencer
Forced
Draft Fan
Fig. 10 Towerpak® bottom supported BFB.
fuel must release the same amount of heat back into
the bed to maintain a constant temperature. Too much
heat release increases bed temperature, while too little
heat release reduces bed temperature. Three methods
of bed temperature control are used in biomass firing:
primary/overfire air split adjustment, flue gas recirculation (FGR), and fuel feeder selection and operation.
Primary/overfire air split adjustment Biomass bubbling
beds operate substoichiometrically with less than theoretical combustion air. In the bed, all available oxygen is completely used. Any additional oxygen would
oxidize more fuel and increase the in-bed heat release,
while lower oxygen levels would have the reverse effect. Because of this repeatable relationship, an increase in air flow from the windbox through the bed
will raise bed temperature while a decrease in air flow
will lower bed temperature at steady-state conditions.
Overfire air flow increases or decreases in the opposite direction to maintain constant total combustion air
flow to the boiler.
Shifting the air flow between the bed and overfire
air system shifts the combustion or heat release be-
17-6
tween the two. At steady-state conditions, the flue gas
temperature above the overfire air nozzles can be varied by 360F (200C) just by shifting air between the
bed and the overfire air. The bed temperature is rather
slow to respond to changes in the bed air flow. The
cycle of increasing the bed temperature 27F (15C)
above the set point and returning back to the set point
can take 20 minutes or more.
Flue gas recirculation (FGR) When changing the air
flow through the bed is not sufficient or fast enough
for acceptable bed temperature control, flue gas can
be recirculated back from the induced draft (ID) fan
outlet into the bed. This flue gas recirculation is another mass flow stream entering the bed at a temperature below bed operating temperature. Energy transferred from the bed material to the incoming flue gas
to heat it to the new bed equilibrium temperature is
greater than the heat released by incremental combustion from the low level of FGR oxygen. As a result,
the equilibrium bed temperature declines. The bed
temperature response rate for this control method is
much more rapid and, at steady-state conditions, FGR
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
can control the bed temperature to within 20F (11C)
of the set point bed temperature.
Fuel feeder selection and operation Two types of feeders are commonly used for biomass fuels in BFB combustion: 1) chute-type feeders that deposit fuel in small
areas of the bed, and 2) air distribution feeders that
distribute fuel over a wider area. There is a relationship between in-bed heat release and distribution of
fuel over the bed plan area. This is because the high
volatile matter content and low-density char escape
from the bed before the inherent churning motion of
the bed material can distribute the fuel within the bed.
If the fuel is not distributed evenly, some air simply
passes through the bed without contributing to the inbed combustion process. To obtain the highest amount
of in-bed heat release, the fuel must be distributed as
widely and uniformly as possible to match the uniform
air flow. The lowest in-bed heat release results from
dumping fuel to one spot. Therefore, the fuel feeder
should be able to function as either a chute or as an
air distribution feeder. When the fuel is dry, the feeder
air flow can be reduced and the fuel falls into a small
portion of the bed. When the fuel is wet, the feeder
air flow can be increased and the fuel distributed over
the plan area. The in-bed heat release change rate
from low- to high-feeder air flows can be as much as
20% of the fuel’s heating value.
Coal firing Bed stoichiometry adjustment is not effective for coal-fired BFB combustor temperature control because carbon builds up in the bed when there
is less than theoretical combustion air. When the air
flow is increased for load, the bed temperature increases rapidly and uncontrollably. In an extreme
case, the pressure parts could be damaged, and more
commonly, the bed could agglomerate. Therefore,
BFBs firing coal are limited to no less than stoichiometric conditions in the bed.
The coal can be blown into the bed from below using pressurized feed pipes, or can be fed over the bed
using common rotary flipper-type feeders. The underbed feed system is more expensive and the coal must
be dry and less than 0.25 in. (6.35 mm). The feed pipes
are prone to erosion and plugging, and the nozzles at
the ends of the pipes erode. The in-bed heat release is
higher and the carbon loss is lower using the underbed feed system, but the disadvantages typically cause
the over-bed system to be preferred.
With the overfeed system, the in-bed heat release
is 75 to 85% of the coal’s heating value. For the coal
falling on the bed, all of the fixed carbon and 70% of
the volatile matter combusts while in the bed. The
fines burn in suspension and reduce the overall inbed heat release. With this high in-bed heat release,
the adiabatic bed temperature would be significantly
higher than the desired 1500 to 1600F (815 to 871C)
range. To lower the bed temperature to the desired
range, tube bundles are submerged in the bed. This
in-bed surface can be either steam-generating surface
or superheater surface. Water circulation in the steamgenerating surface can be either natural or forced.
The fluidizing air is provided from a windbox
mounted below the bed. The windbox is typically compartmentalized, with individual air flow control to each
Steam 41 / Fluidized-Bed Combustion
compartment. Bed temperature varies with the firing
rate. Therefore, as the boiler load is reduced, the firing rate is reduced, and the bed temperature declines.
When the bed temperature reaches a certain minimum, an outer portion of the bed is shut down by shutting off the air flow and fuel flow to that portion of
the bed. The air flow and fuel flow to the remaining
active bed area is increased which raises the bed temperature in the operating beds. Boiler load is increased
by re-fluidizing out-of-service (slumped) compartments and firing to larger portions of the bed.
Bed inventory control
The air/flue gas pressure drop through the bed is
directly related to the bed material mass when the bed
is fluidized. Pressure drop through the bed is approximately 0.75 to 1.0 in. wg (0.19 to 0.25 kPa) per inch
(2.54 cm) of bed height. For biomass-fired systems, the
bed inventory is set to a pressure drop of 30 to 36 in.
wg (7.5 to 9 kPa). This is sufficient mass to prevent
the bed temperature from significantly changing in a
short period following a sudden large change of fuel
properties, such as moisture content. For a coal-fired
BFB, the bed height must ensure that the in-bed surface is submerged. If the bed height is below the top
of the in-bed tube bundle, heat transfer decreases significantly and bed temperature increases. Pressure
taps in the bed enclosure walls provide the measurement of the bed pressure drop over a known height.
Bed inventory can change over time. The ash and
tramp material that enter with the fuel can increase
the overall inventory when these materials are too
large to be blown out of the bed. The bed material can
break down due to mechanical or thermal attrition and
leave the bed with the flue gas. Oversized particles,
such as rocks and metal, are removed by the bed drain
system and attrited material is replaced with new
(makeup) material when necessary.
Bed density and heat transfer (in-bed)
The following equations are for the bed pressure loss
and the overall in-bed heat transfer coefficient used
to size in-bed surface.
Equation 2 is used to calculate the flue gas bed pressure loss across a bubbling bed.
∆P = (C ) (1 − e ) ( ρ s − ρ g ) ( L )
(2)
where
∆P =
C =
e =
ρs =
ρg =
L =
pressure loss
units conversion constant
bed void fraction
particle density
gas density at bed conditions
bed height
The void fraction, e, is primarily a function of particle size, particle density, bed gas velocity and gas
viscosity. Various methods are used to predict bed
voidage or void fraction, including those proposed by
Leva,1 Babu,2 and Staub and Canada.3
The equation for the overall heat transfer coefficient
for any tube bundle immersed in the bed is:
17-7
The Babcock & Wilcox Company
Uo =
where
1
1
+ Rm + Rft
hc + hr
(3)
where
Uo = overall heat transfer coefficient, Btu/h ft2 F
(W/m2 K)
h c = convection heat transfer coefficient for the
tube bank, Btu/h ft2 F (W/m2 K)
h r = radiation heat transfer coefficient for the tube
bank and walls, Btu/h ft2 F (W/m2 K)
Rm = metal wall resistance, h ft2 F/Btu (m2 K/W)
Rft = tube fluid film resistance, h ft2 F/Btu (m2 K/W)
The convection heat transfer coefficient hc is given
by Equation 4. Two equations are used to evaluate the
convective heat transfer coefficient (hst ) for an isolated
or single tube depending upon average bed particle
size. Equation 5 is a modified Vreedenberg4 form and
applies primarily to beds with particles less than an
800-micron average. Equation 6, a Glicksman-Decker5
type, applies well when the average particle size in
the bed exceeds 800 microns.
hc = ( hst ) ( FAB )
k Gd ρ
hst = 900 (1 − e ) t s
dt ρ g µ
µ 2
3 2
D p ρ s g
(4)
( Pr )
0.3
(5)
k (1 − e )
3600 D p ρ g C p V
C1 + (C2 )
Dp
k
(6)
for Dp > 800 microns
where
hst = convective heat transfer coefficient for a
single tube, Btu/h ft2 F
e = bed voidage, dimensionless
k = gas thermal conductivity, Btu/h ft F
d t = tube outside diameter, ft
G = mass velocity or flux of the gas, lb/s ft2
ρ s = particle density, lb/ft3
µ = gas viscosity, lb/ft s
ρ g = gas density, lb/ft3
Dp = average particle diameter, ft
g = acceleration constant, 32.2 ft/s2
Pr = Prandtl number, dimensionless
C1 = experimental constant, dimensionless
C2 = experimental constant, dimensionless
Cp = gas specific heat, Btu/lb F
V = nominal bed gas velocity, ft/s
To convert the single-tube heat transfer coefficients
to those suitable for tube banks, the following equation is applied:
D 2 Do + S p
FAB = 1 − o
Sn Do + S p
17-8
Other variables are as defined previously. The equation for FAB is as derived by Gel’perin.6
For the radiation heat transfer component, hr, the
following equation can be used:
4
4
hr = (σ ) (ε ) (Tb ) − (Tw ) / (Tb − Tw )
(8)
where
σ
ε
Tb
Tw
=
=
=
=
0.1713 × 10-8 Btu/h ft2 R4
average overall emissivity, dimensionless
absolute bed gas temperature, R
absolute wall temperature, R
The average overall emissivity in bubbling beds will
be about 0.8 depending on wall emissivity and particle size. Typically, the overall heat transfer coefficient
(Equation 3) for an in-bed tube bundle is between 40
and 60 Btu/h ft2 F (227 and 341 W/m2 K).
0.326
for Dp < 800 microns
hst =
FAB = bank arrangement factor (staggered arrangement only), dimensionless
Do = tube outside diameter
Sn
= tube spacing normal to flow
= tube spacing parallel to flow
Sp
0.25
(7)
BFB emissions
Biomass firing can require the control of carbon
monoxide (CO), volatile organic compounds (VOCs),
NOx, SO2 and hydrochloric acid (HCl). The CO and
VOCs are controlled by good fluidization, uniform fuel
distribution and high-velocity overfire air nozzles, and
are easily controlled below 100 ppm and 10 ppm respectively at 7% O2 dry. NOx is controlled by bed temperature control with a two-stage overfire air system
and/or a selective non-catalytic reduction (SNCR) system (see Chapter 34). The staged overfire air system
provides approximately 15 to 25% reduction, and the
SNCR system provides approximately 55 to 60% reduction. SO2 and HCl are controlled by adding limestone to the bed. SO2 can be reduced 80% with a significant Ca/S molar ratio because of the very low sulfur content in most biomass fuels. However, the air
flow through the bed must be high enough to complete the sulfation process. HCl is reduced by the excess lime leaving the bed and by using a fabric filter
baghouse for particulate collection, providing the
proper temperature and solids/gas contact. See the CFB
emissions section for the limestone and sulfur reactions.
Coal firing requires SO2 emission control. SO2 reduction can be as high as 90% with a high-solids recycle rate from a multi-cyclone dust collector (MDC).
NOx is only moderately low from a coal-fired BFB boiler.
The bed and furnace temperatures are low, which
reduces thermal NOx formation. However, air flow
through the bed is at or above theoretical combustion
air. Therefore, the NOx reduction possible by staging
the combustion air is not available for coal-fired BFB
boilers. Typical NOx values are 0.4 to 0.5 lb/106 Btu (0.47
to 0.59 g/Nm3 at 7% O2 dry). Additional information on
NOx control is provided in the CFB discussion.
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
Circulating fluidized-bed (CFB) boilers
Fig. 11 shows the main features of a circulating fluidized-bed boiler and Fig. 12 shows the furnace density profile. 50 to 70% percent of the total combustion
air enters the furnace through the windbox and air
distributor with the balance of the combustion air injected through overfire air (OFA) ports. A typical flue
gas superficial velocity at full load, thereby converting the process to a circulating bed above the OFA
ports, is 16 to 17 ft/s (4.9 to 5.2 m/s). While single
particles reaching the furnace exit could be up to 2000
microns in size, typical average particle size (SMD) is
100 to 200 microns in the upper furnace and 300 to
400 microns in the dense bed.
Fig. 12 Typical atmospheric pressure circulating-bed furnace
density profile.
Gas
WaterCooled
Walls
U-Beams
In-Furnace U-Beams
Furnace
Overfire Air
Supply Ducts
Gas and
Solids
Flow
Air Distribution Grid
Primary Air
Fig. 11 Typical circulating-bed boiler schematic.
Steam 41 / Fluidized-Bed Combustion
The upward flow of solids decreases with increased
furnace height as heavier particles recirculate back
down the furnace, resulting in declining local density
with increasing furnace height. In the B&W internal
recirculation (IR-CFB) design, U-beam collectors (see
Fig. 13) located in the top of the furnace enclosure
collect most (up to 97%) of the solids that remain in
the flue gas and return them to the furnace (recirculation) while passing the flue gas to the convection
pass heat transfer surfaces. Most of the remaining
solids entrained in the flue gas are then collected in
multi-cyclone dust collectors (MDC) located in the
backpass, providing up to 99.7% overall particle recycle to the furnace. The furnace enclosure is watercooled membrane panels.
Unlike coal-fired BFB boilers, the dense bed does
not contain any in-bed tube bundle heating surface.
The furnace enclosure and in-furnace heating surfaces (water-cooled panels or water/steam wing walls)
provide the required heat removal surface. This is possible because of the large quantity of solids that are
recycled internally within the furnace. Because the
mass flow rate of recycled solids is many times the mass
flow rate of the incoming fuel, limestone, air and resultant combustion gas, the bed solids temperature remains
relatively uniform throughout the furnace height.
Also, the heat transferred to the furnace walls is adequate to provide the heat absorption required to
maintain the target bed temperature of 1500 to 1600F
(816 to 871C).
B&W IR-CFB boilers use a single chute-type feeder
installed above the air distributor. The upward action of
the bed inventory and the intense mixing of the incoming fuel, with the large mass of active inventory, adequately distributes the fuel as compared to the BFB.
The B&W coal-fired CFB uses the flat floor air distributor system shown in Fig. 7, with the horizontal
water-cooled membrane panel floor and bubble caps
discussed previously. Separate bed drains are provided.
17-9
The Babcock & Wilcox Company
Gas
Plus
Solids
Flow
Gas
Flow
Gas
Flow
U-Beams
In-Furnace
U-Beams
tenance. This construction is possible due to the U-beam
particle collectors integrated into the boiler enclosure.
Fuel and sorbent are fed to the bed through the
lower furnace walls. Ash and spent sorbent are removed through drain pipes in the floor or lower walls.
Solids collected by the U-beams are returned directly
to the furnace and solids collected in the multi-cyclones
are returned to the lower furnace through the rear wall.
Primary air enters the furnace through the air distributor and secondary air is injected above the air distributor.
The lower furnace above the air distributor is covered by a thin layer of highly conductive refractory
held to the water wall tubes by pin studs. Refractory
in the lower furnace protects the tubes from corrosion
and erosion. The remaining portion of the furnace
enclosure consists of bare tubes.
Selected key issues for CFB design include: furnace
temperature and heat transfer control, solids separation, solids inventory control, and emissions.
Furnace temperature and heat transfer control
A CFB furnace contains a substantial solids inventory that is distributed over the entire furnace volume.
Fig. 15 shows the solids flow streams. Although the
solids concentration or solids bulk density in the upper portion of the furnace is much less than that in
the furnace bottom, the solids still represent a significant mass fraction of the gas/solids mixture at any
given furnace location. For example, in a pulverizedcoal (PC) furnace, the combustion gas carries a portion of the fuel ash as it flows through. In general,
this PC fuel ash represents less than 10 lb (4.54 kg)
of solids per 1000 lb (454 kg) of gas. Also, the PC heat
transfer from the gas to the furnace enclosure walls
is predominately by radiation. In a CFB furnace, the
amount of solids in the gas leaving the furnace may
Furnace
Steam Drum
In-Furnace
U-Beams
U-Beams
Fig. 13 CFB primary particle collection system.
Cold
Reheat
Hot
Reheat
Downcomer
Key operating requirements for a CFB are controlling furnace temperature and maintaining the vertical temperature distribution within a relatively narrow temperature window for SO2 absorption (a temperature-dependent process). To accomplish this, the
solids inventory is distributed throughout the furnace
with a large amount of solids recirculation. A major
portion of the heat transfer in a CFB is controlled by
the solids inventory in the furnace. Therefore, by
changing furnace inventory, the heat transfer from
the gas and solids to the furnace walls can be varied
and the furnace temperature can be controlled.
Fig. 14 shows the side view of a B&W 150 MW IRCFB utility unit designed to burn bituminous coal, providing main and reheat steam to the turbine island. The
unit contains full-height, water-cooled panels and
steam-cooled wing walls in the upper furnace. Boiler
design is based on a completely water-cooled setting.
This feature provides a gas-tight enclosure suitable for
operating with a positive pressure in the furnace. The
B&W IR-CFB has no high-temperature refractory-lined
flues, and thus has reduced furnace refractory main17-10
Secondary
Superheater
Internal
Evaporative
Circuit
Feedwater
to Drum
Superheater
(Wingwalls)
Multi-Cyclone
Dust
Collector
Fuel Bunker
Economizer
Ash
Recycle
System
Air
Heater
Gravimetric
Feeder
Fuel
Chute
Flue
Gas
Refractory
Line
Fluid Bed
Cooler
Secondary Primary
Air Duct to
Steam Coil
Air Duct Air Duct Fluid Bed Cooler Air Heater
Fig. 14 150 MW utility reheat internal recirculation circulating
fluidized-bed (IR-CFB) boiler.
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
60
(340.7)
Overall Heat Transfer Coefficient, Btu/h ft2 F (W/m2 C)
exceed 5000 lb (2268 kg) of solids per 1000 lb (454 kg)
of gas. As a result, the heat transfer to the walls of a
circulating bed includes significantly higher solids/gas
convection and less solids/gas radiation.
Furnace temperature is primarily controlled by furnace heat transfer to the pressure parts. Most of the
furnace heat absorption is accomplished by the surface located in the zone above the overfire air level.
The main factor controlling furnace heat transfer rate
is local solids bulk density; the greater the bulk density, the higher the heat transfer rate (see Fig. 16) and
the lower the furnace exit gas temperature. Most of
the solids leaving the furnace are captured by the Ubeams and returned to the upper portion of the furnace by gravity.
A secondary solids collection device, or multi-cyclone, is located downstream in the convection pass.
The solids from the multi-cyclone hoppers are returned
to the furnace, and this recycle stream controls the
solids bulk density in the upper furnace. As more
multi-cyclone solids are returned to the furnace, the
upper furnace bulk density increases and the furnace
exit gas temperature is reduced. At steady-state boiler
operation, a balance is maintained between the solids flow to the multi-cyclone hoppers and the solids
170
Micron
50
(283.9)
250
Micron
40
(227.1)
30
(170.4)
20
(113.6)
1562F (850C) 32.8 ft/s (10 m/s)
1562F (850C) 40.34 ft/s (12.3 m/s)
1562F (850C) 56.42 ft/s (17.2 m/s)
10
(56.8)
0
0
1
(16)
2
3
4
(32)
(48.1)
(64.1)
Bulk Density,lb/ft3 (kg/m3)
5
(80.1)
6
(96.1)
Fig. 16 Heat transfer coefficient versus density in a circulating
fluidized bed for 170 and 250 micron mean diameter sand.
flow to the furnace, with any excess solids purged to
the plant ash disposal system.
The solids recycle flow to the furnace can be limited by not having enough solids caught by the multicyclone. If, after reaching the maximum recycle rate,
the upper furnace temperature is still high, increasing the primary air flow entrains more solids from the
lower bed to the upper furnace. This increases the
upper furnace bulk density and heat transfer rate.
Changes in bed air flow can have an additional impact on the temperature in the lower furnace, which
is fuel dependent. For some fuels, the increase in bed
air flow causes an increase in the lower furnace temperature due to higher local fuel burnout. For others,
the diluting effect of greater bed air flow prevails,
causing the local temperature to decline.
U-Beams
(Primary Particle Collector)
Solids
to
MDC
U-Beam
Recycle
Fig. 15 CFB boiler solid material flows.
Solids separation
A unique feature of B&W’s CFB boiler design is the
two-stage solids separation system shown in Fig. 15.
The primary solids separator is an array of U-shaped
beams (U-beams) located in the high temperature region at the furnace exit, with the secondary stage located downstream of the convection surfaces in a low
gas temperature region, which varies from 400 to 900F
(204C to 482C) depending upon unit design. As the
gas flow passes the U-beams, the momentum of the
particles causes a large fraction to be collected within
the U-beam channel while the gas and remaining fine
particulate fraction flows around the beams. As shown
in Fig 13, the first two rows of U-beams are installed
in the furnace (in-furnace) and the collected material
is returned directly to the furnace, falling down along
the rear wall. The second group of two to four U-beam
rows after the furnace exit plane (external U-beams)
collects additional material that falls down and also
returns to the furnace.
Steam 41 / Fluidized-Bed Combustion
17-11
Bed
Solids
Solids to
ESP or
Baghouse
Multi-Cyclone
Dust Collector
(MDC)
(Secondary
Particle
Collector)
Sorbent
Fuel
MDC
Purge
MDC
Recycle
Bed Drain
Air
The Babcock & Wilcox Company
Solids inventory control
The measure of furnace solids inventory is by air/
flue gas pressure loss. The total furnace pressure loss
or solids inventory is important. The typical overall
furnace pressure loss is 42 in. wg (10.5 kPa). The upper furnace (above the air ports) pressure loss should
be at least 17 in. wg (4.2 kPa), which results in adequate inventory in the upper furnace to maintain a
constant furnace temperature profile.
Flue gas pressure loss in a CFB furnace conforms
to the basic equation:
∆P = (C ) ( ρb ) ( L )
(9)
where
∆P = pressure loss
C = units conversion constant
ρ b = average bulk density in the furnace segment
associated with L
L = height of the furnace segment of interest
To use Equation 9, a density profile as shown in Fig.
12 is developed. This curve is a function of many variables and has been derived from empirical data. The
important variables are:
Dp
DDB
V
T
WS
ρs
ø
De
= average particle size above the dense bed
zone
= average particle size in the dense bed zone
= nominal gas velocity
= nominal furnace temperature
= external solids flux, lb/h ft2 (kg/s m2)
= particle density
= particle shape factor
= furnace equivalent diameter
For a fluidized bed to operate properly, there must
be a continuous and sufficient supply of particles of
the proper size distribution. If the particles are too
coarse, the lower furnace bed will be too deep and
defluidize, or slump. If the particles are too fine, they
will blow out of the furnace making it impossible to
maintain an adequate overall solids inventory. There
is a range of bed particle size distribution that is
needed to maintain a stable fluidized-bed process in the
lower furnace and an adequate inventory in the upper furnace to control the furnace exit gas temperature.
The supply and retention of these particles must be
controlled to provide the required inventory.
The solids inventory is maintained by adding
makeup material, typically limestone or sand of the
proper size distribution or bed material that had previously been drained and saved. When firing coal,
17-12
limestone will normally be used for both the inventory control or makeup material. However, there
needs to be enough sulfur to continuously generate
material that will stay in the system. Calcium oxide is
quite soft and does not hold up well in the fluidized
bed environment. Once sulfated, the calcium sulfate
is hard enough to maintain a solids inventory.
The amount of makeup material needed depends
on whether, or to what degree, the fuel ash is contributing to the inventory and how well the inventory material maintains its integrity. For example, coal may
contain very fine ash as well as large diameter particles or small rocks. A portion of the larger particles
will remain in the lower portion of the furnace and
provide stable fluidization in the dense bed portion.
The small particles can be so small that the U-beams
and multi-cyclone dust collector do not capture and
return them back to the process. The intermediate size
particles blow out of the dense bed, are large enough
to be captured by the U-beams or dust collector, and
return to the furnace for solids inventory. If the coal
ash and reacted limestone particles continuously provide the proper amount of large and intermediate size
particles, purchased makeup material for inventory
control will not be required.
CFB emissions
Sulfur dioxide emissions control When sulfur-bearing fuels burn, most of the sulfur is oxidized to SO2.
Limestone can be added as a sorbent for sulfur capture. When limestone is added to the bed, it undergoes a transformation called calcination and then reacts with the SO2 in the flue gas to form calcium sul100
90
80
Efficiency, %
The range of overall IR-CFB solids collection efficiency by particle size is shown in Fig. 17. The U-beams
and MDC effectively collect and recycle all particles
greater than 80 microns. The overall efficiency of the infurnace and external U-beams is 97% or greater.
The fine particles fraction that passes the U-beams
is collected in the secondary stage of solids separation,
the mechanical dust collection multi-cyclones. These
collect 90 to 95% of the remaining particles, for an
overall collection efficiency of up to 99.7%.
70
60
50
40
0
20
40
60
Particle Size, Micron
80
100
Fig. 17 Overall grade efficiency range of B&W IR-CFB solids
collection system.
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
fate (CaSO4) through sulfation. The calcining reaction is endothermic and is described by:
CaCO3 ( s ) + 766 Btu/lb ( of CaCO3 ) →
CaO(s) + CO2 (g )
(10)
Once formed, solid CaO (lime) reacts with gaseous SO2
and oxygen exothermically to form CaSO4 according
to the following reaction:
SO2 ( g ) +
1
2
O2 ( g ) + CaO ( s ) →
CaSO4 ( s ) + 6733 Btu/lb ( of S )
(11)
SO2 reductions of 90 to 95% are typically achieved
in a circulating bed with calcium to sulfur (Ca/S) mole
ratios of 1:1.8 to 1:2.5, depending on the sulfur content of the fuel and the reactivity of the limestone. The
lower the sulfur concentration in the fuel, the greater
the calcium-to-sulfur mole ratio must be for a given
removal in the furnace. Systems external to the CFB
process can be applied to further enhance SO2 capture
and limestone utilization.
Certain temperature limitations affect the sulfur
capture process. If the furnace temperature is below
1470F (799C), calcination of CaCO3 is not complete and
results in less CaO yield from a given amount of limestone, thereby increasing limestone consumption. If
the furnace temperature is above 1650F (899C),
CaSO4 dissociates to CaO and SO2 which again reduces
sulfur capture efficiency. Therefore, it is important to
maintain the furnace within a certain temperature
window to reach minimum limestone consumption and
not exceed a specified level of SO2 emissions. This is a
primary reason the IR-CFB combustion process controls
furnace temperature over the entire furnace height.
Limestone properties such as reactivity, attrition,
and size distribution have a major effect on limestone
consumption. These parameters are carefully considered when providing recommendations for limestone
selection and preparation. The IR-CFB process also
allows for post-furnace SO2 capture through various
flyash recirculation schemes.
Nitrogen oxides emissions control The nitrogen oxides present in the flue gas come from two sources: the
oxidation of nitrogen compounds in the fuel (fuel NOx)
and the reaction between nitrogen and oxygen in the
combustion air (thermal NOx). See Chapter 34. By
maintaining the furnace temperature below 1650F
(899C), thermal NOx formation is low in CFB boilers.
Fuel NOx can be reduced through combustion controls. The following operating parameters have a significant effect on emissions:
1. lowering primary air,
2. lowering overall excess air, and
3. minimizing limestone input or Ca/S molar ratio.
When burning fuels containing nitrogen, volatile
nitrogen is released in a very unstable monatomic
state. The monatomic nitrogen atom will either combine with another nitrogen atom to form N2, or will
react with oxygen to form NOx. Part of the NOx can
be reduced back to N2 when NOx is in the presence of
Steam 41 / Fluidized-Bed Combustion
char and/or CO in a reducing atmosphere. Reducing
the primary air to substoichiometric conditions increases the concentration of carbon and CO in the
lower furnace and limits the availability of oxygen in
the presence of monatomic nitrogen. This effect is more
pronounced for high-volatile fuels.
Limestone is a catalyst for the nitrogen and oxygen
reaction, which increases the fuel NOx emissions. Controlling to a low Ca/S ratio minimizes this reaction.
Higher overall excess air means higher oxygen concentration in furnace gases and increased NOx emissions. Limiting the overall excess air below 3% O2
minimizes NOx formation while providing low carbon
loss due to high solids recycle to the furnace.
The combination of low temperatures and staged combustion allows fluidized-bed boilers to operate with low
NOx emissions. Typical uncontrolled values are within
0.1 to 0.15 lb/106 Btu (126 to 188 mg/Nm3 at 6% O2 dry)
for coal-fired CFB boilers. Further NOx can be controlled
to lower values through the use of a selective noncatalytic
reduction (SNCR) system consisting of ammonia injection near the U-beam elevation (see Chapter 34).
Carbon monoxide and hydrocarbons When designing a boiler, it is necessary to maximize combustion
efficiency by minimizing unburned carbon and the
quantity of CO and hydrocarbons in the flue gas. This
is accomplished by choosing the proper number of fuel
feed points, by proper design of the overfire air system, and by providing sufficient furnace residence
time for combustion. Typical flue gas concentrations
are less than 0.15 lb/106 Btu (188 mg/Nm3) for CO and
0.005 lb/106 Btu (6.3 mg/ Nm3) for hydrocarbons, both
at 6% O2 dry, in a CFB boiler burning coal.
Pressurized fluidized-bed combustion
(PFBC)
BFB and CFB boilers discussed above operate effectively at atmospheric pressure and are generally referred
to as atmospheric fluidized-bed combustors (AFBC).
Pressurized fluidized-bed combustors (PFBC) are an
outgrowth of this technology. The underlying concept is
to create a combined cycle plant where a coal-fired system with a steam turbine is combined with a gas turbine to increase overall cycle efficiency. A simplified schematic and process explanation is shown in Fig. 18. In its
simplest form, a compressor pressurizes the combustion
air to 12 to 20 atmospheres (174 to 232 psi or 1.2 to 2.0
MPa). This air is then fed to a pressure vessel that fully
encloses a fluidized-bed combustor where coal is burned
in a bed of limestone (removing the SO2) to produce steam
plus a pressurized gas stream. The steam is used in a
conventional steam turbine cycle to generate part of the
electric power, and the pressurized gas is cleaned sufficiently of particulate and other key contaminants
and used in a gas turbine to generate the balance of
the electric power and compressed air for the combustion process.
Three basic cycle configurations have been proposed: 1) turbocharged cycle, 2) combined cycle, and
3) advanced combined cycle. The major differences
involve how the gas from the pressurized fluidizedbed combustor is treated prior to use in the gas tur17-13
The Babcock & Wilcox Company
Fig. 18 Simplified combined cycle PFBC diagram and process overview.
bine. In the turbocharged cycle, the gas is cooled to
between 800 and 1000F (427 and 538C) so that current state-of-the-art hot gas cleanup technology can
be used to remove the particulate and other contaminants. This increases the steam production capacity
but reduces the power from the gas turbine. This cycle
incorporates more conventional technology at the expense of cycle efficiency. In the full combined cycle
system, advanced hot gas cleanup technology is used
to clean the gas from the fluidized bed at approximately 1580F (860C) so that hotter and higher pressure gas can be sent to the gas turbine. In this case,
80% of the power is produced in the steam turbine and
the balance is produced in the gas turbine. Finally, in
the advanced combined cycle, a partial coal gasification process is added. The char from gasification is
burned in the fluidized-bed combustor. The clean gas
leaving the PFBC boiler, which still contains oxygen,
can be mixed with the fuel gas (from the partial gasifier) and then burned in a gas turbine combustor at
temperatures of 1800 to 2500F (982 to 1371C) for even
higher efficiencies.
The bubbling fluidized bed operating inside the
pressure vessel behaves basically the same as the atmospheric fluidized bed although the higher pressure
(and higher gas density) combustion affects three key
areas: fluidization, heat transfer, and combustion. The
overall effect is to provide a very compact and cleaner
combustion system. A more complete summary of this
17-14
technology is provided in the 40th edition of this text.7
B&W designed, fabricated and installed a 70 MW
PFBC system as a demonstration to repower one unit
at the American Electric Power, Ohio Power Company
Tidd plant near Brilliant, Ohio, in the United States
(Fig. 19). The design was based on the combined cycle
configuration utilizing the bubbling fluidized-bed combustion process. This PFBC combined cycle system
consisted of a gas turbine, boiler, and associated systems including hot-gas cleaning, load control, fuel
Fig. 19 Pressure vessel arrival at Tidd site.
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
preparation and feeding, sorbent preparation and
feeding, and ash removal. Many of these systems were
either partially or totally contained in the pressure
vessel. This system operated on an experimental basis in the 1990s to demonstrate the feasibility of the
process and to define and overcome the challenges in
a new first-of-a-kind engineered power system.
PFBC technology offers the prospect of improving
cycle efficiency and reducing emissions while reducing power plant size and initial plant cost. In concept,
PFBC boiler modules could be barge-shipped to sites
effectively ready for installation or in a few large
pieces to minimize erection expense. This technology
awaits further development and evaluation.
References
1. Leva, M., Canadian Journal of Chemical Engineering,
Vol. 35, pp. 71-76, August, 1957.
2. Babu, S.P., Shah, B., and Talwalkar, A., “Fluidization
Engineering,” Second Ed., AIChE Symposium Series No.
176, Vol. 74, pp. 176-186, American Institute of Chemical
Engineers, and Kunii, D., Levenspiel, O., ButterworthHeinemann Series in Chemical Engineering, 1991.
3. Staub, F.W., and Canada, G.S., Fluidization, Cambridge University Press, London, United Kingdom, pp.
339-344, 1978.
Steam 41 / Fluidized-Bed Combustion
4. Vreedenberg, H.A., Chemical Engineering Science, Vol.
9, pp. 52-60, 1958.
5. Glicksman, L.R., and Decker, N.A., Proceedings of the
Sixth International Fluidized-Bed Combustion Conference, Atlanta, Georgia, pp. 1152-1158, 1980.
6. Gel’perin, N.I., Ainshtein, V.G., and Korotyanskaya,
L.A., International Chemical Engineering, Vol. 9, No. 1,
pp. 137-142, January, 1969.
7. Stultz, S.C., and Kitto, J.B., Eds., Steam/its generation and use, 40th Ed., The Babcock & Wilcox Company,
Barberton, Ohio, 1992.
17-15
The Babcock & Wilcox Company
Circulating fluidized-bed power plant by B&W.
17-16
Steam 41 / Fluidized-Bed Combustion
The Babcock & Wilcox Company
Chapter 18
Coal Gasification
What is gasification
Coal gasification is a process that converts coal from
a solid to a gaseous fuel through partial oxidation.
Once the fuel is in the gaseous state, undesirable substances, such as sulfur compounds and coal ash, may
be removed from the gas by various techniques to produce a clean, transportable gaseous energy source.
When coal is burned, its potential chemical energy
is released in the form of heat. Oxygen from the air
combines with the carbon and hydrogen in the coal
to produce gaseous carbon dioxide (CO2) and water
plus thermal energy. Under normal conditions, when
there is sufficient oxygen available, nearly all of the
chemical energy in the coal is converted into heat and
the process is called combustion.
However, if the available oxygen is reduced, less
energy is released from the coal and new gaseous reaction products appear from the incomplete combustion. These byproducts, including hydrogen (H2), carbon monoxide (CO) and methane (CH 4 ), contain
unreleased or potential chemical energy which can be
transported and used to provide energy to other processes such as combustion to power a gas turbine,
chemical synthesis for use in fuel cells, or as a substitute for natural gas. If the objective is to maximize the
chemical energy in the gas byproducts, it would appear logical to continue decreasing the available oxygen. However, a point is reached where an increasing percentage of the carbon in the coal remains
unreacted, and less is converted to gas, rendering the
process inefficient. When the oxygen supply is controlled such that both heat and a new gaseous fuel
are produced as the coal is consumed, the process is
called gasification.
Coal gasification has been practiced for more than
200 years and until the 1940s was a major industry.
The most significant advances leading to current gasification technologies occurred during World War II
in Germany, where coal was used to derive liquid fuels for military use. Following this, the increased availability of natural gas and petroleum products in the
industrialized nations resulted in a decline of gasification until the oil embargo of 1973 and concerns
about natural gas supply. Major efforts to develop gasification systems to produce synthetic natural gas
(SNG) and liquid fuels were made in the United States
Steam 41 / Coal Gasification
(U.S.) and Europe during the 1970s and 1980s, but
declines in gasoline and natural gas prices curtailed
many of these efforts as economic justification declined. Recently, a desire for high-efficiency electric
power generation to reduce emissions, availability of
high-performance gas turbines, and the introduction
of fuel cells have resulted in a resurgence of interest
in gasification systems.
By recovering waste heat from a gasifier and gas
turbine exhaust for steam production, a gas turbine
(Brayton) cycle and steam turbine (Rankine) cycle can
be efficiently combined into an integrated gasification
combined cycle (IGCC). Although technically viable,
this approach to power generation from coal has been
demonstrated but not applied commercially because
conventional combustion systems are less costly and
less complicated. However, further development continues as increasingly stringent environmental regulations
and interest in production of hydrogen for fuel cells and
other co-products have renewed interest in IGCC.
Basic gasification reactions
Combustible gases such as carbon monoxide and
hydrogen are the most common products of incomplete
combustion. With partial combustion, only a fraction
of the carbon in the coal is completely oxidized to CO2.
The heat released provides most of the energy necessary to break chemical bonds in the coal and raise the
products to reaction temperature.
Although the chemistry of coal gasification is complex, the following are the major reactions involved:
Exothermic reactions – releasing heat
Carbon combustion:
C + O2 = CO2 (1)
C + 1 / 2 O2 = CO (2)
CO + H2O = CO2 + H2 (3)
Water-gas shift:
Methanation:
CO + 3H2 = CH4 + H2O (4)
Direct Methanation:
C + 2H2 = CH4 (5)
Endothermic reactions – absorbing heat
Boudouard reaction:
C + CO2 = 2CO (6)
Steam-carbon reaction: C + H2O = H2 + CO (7)
Hydrogen liberation: 2H (in coal) = H2 (gas) (8)
18-1
The Babcock & Wilcox Company
Many fuel and operating variables, such as fuel
composition, operating pressure, and steam and oxygen inputs influence the final gas composition. Gasifiers are designed for pressures ranging from atmospheric to 600 psi (4140 kPa) and higher. The methanation reactions are important in lower temperature
systems and are favored by high pressures as shown in
Fig. 1.1 The other reactions are more prominent in high
temperature, lower pressure systems. The combination
of these reactions is autothermic, meaning sufficient heat
is initially released by the carbon combustion reactions
to provide energy for the endothermic reactions.
Sulfur in coal is converted primarily to hydrogen
sulfide (H2S) and a small amount of carbonyl sulfide
(COS). High temperatures and low pressures favor
coal nitrogen conversion to N2, while the opposite conditions favor some ammonia (NH3) formation and
small amounts of hydrogen cyanide (HCN). In lower
temperature processes [< 1200F (<649C)], tars, oils
and phenols are not destroyed and therefore exit with
the raw gas. Many other minor impurities are produced depending on their presence in the raw fuel.
These include chlorides, vaporous alkali species and
heavy metals. Heavy hydrocarbons are also produced
in lower temperature gasifier processes.
The gasification reactions occur in two main stages:
devolatilization and char gasification. Devolatilization
is a transition stage in which coal becomes char, or
fixed carbon, as the temperature rises. Weaker chemical bonds are broken and tars, oils, phenols and hydrocarbon gases are formed. The char that remains
after devolatilization is gasified by reaction with oxygen, steam, carbon dioxide and hydrogen.
The type of gasification process has a strong bearing on the devolatilization products. In fixed-bed or
moving-bed gasifiers (see below), these products exit
the gasifier with the product gas due to the low temperatures and lack of oxygen. In fluidized-bed and entrained-flow processes, uniform high temperature
causes hydrocarbon cracking, or breaking down the
more complex molecules to simpler ones. Also, oxygen
is available to react with the devolatilization products,
producing H2, CO and CO2. These reactions are most
complete in an entrained-flow process.
The basic objective of gasification is to convert coal
into a combustible gas containing the maximum remaining heating value. If the gas is used for chemical synthesis rather than fuel for combustion, its composition must be adjusted for the stoichiometry of the
synthesized product. Hydrogen for synthesis gas
(syngas) production must be provided by the steamcarbon reaction or by the water-gas shift. The influence of the end product may affect the choice of gasification process. The water-gas shift reaction can be
promoted by supplying extra steam in the fuel bed or
in a separate catalytic conversion stage downstream.
This produces increased hydrogen. Where hydrogen
is the only product required, CO2, which is an inevitable product of splitting water by reaction with carbon, must be removed. Limestone may also be injected
along with the coal and/or steam to capture sulfur.
In the case of synthetic natural gas (SNG) production with low temperature, high pressure moving-bed
processes, much of the methane can be produced in
the fuel bed by carbon hydrogenation (Reaction 5).
However, all of the methane can not be produced by
direct hydrogenation. Some must be produced indirectly
in a separate catalytic stage, e.g., by Reaction 4.
Oxygen for the gasification process can be supplied
either in pure form (oxygen-blown) or in air (airblown). There are advantages and disadvantages to
both methods. Oxygen-blown gasification results in
smaller components, higher cold gas efficiency and
purer gas composition, but requires additional oxygen
separation and safety systems. The cold gas efficiency
is defined as the ratio of the heating value of sulfurfree gas to coal heat content expressed as:
HHV of sulfur-free gas at 60F
× 100
HHV of feed coal
(9)
where
HHV = higher heating value
Fig. 1 Methane formation with pressure.1
18-2
Raw gas from an oxygen-blown unit consists primarily of CO, H2, CO2, CH4 and H2O, while N2 is a major
constituent when air is used as the oxidant.
Coal gas has traditionally been classified by heating value, expressed in Btu per dry standard cubic foot
[Btu/DSCF (MJ/Nm3)].1 Air-blown gasification produces a low Btu gas due to nitrogen dilution. This gas
ranges from 90 to 200 Btu/DSCF (3.5 to 7.9 MJ/Nm3).
Oxygen-blown units produce a medium Btu gas at the
lower end of the 270 to 600 Btu/DSCF (10.6 to 23.6
MJ/Nm3) range. Post-gasifier shift and methanation
reactions are required to produce heating values at
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
the higher end of the medium Btu range and ultimately to produce high Btu gas of approximately 1000
Btu/DSCF (39.3 MJ/Nm3). High Btu gas is pipeline
quality and is therefore referred to as synthetic natural gas (SNG).
Raw gas composition as a function of gasifier type
and oxidant is listed in Table 1. Heating values vary
widely between product gases from air- and oxygenblown moving-bed gasifiers, which can influence the
combustion characteristics of the gas. Raw gas from a
moving-bed gasifier contains significant quantities of
ammonia and heavy condensable organics such as
tars, oils and phenols. It also has a higher heating
value than gas from entrained-flow processes due to
the increased methane content. The two advanced
entrained-flow gasifiers produce negligible quantities
of organics due to their high temperature operation.
The slurry-fed process produces a product gas lower
in CO and higher in H2, CO2 and H2O compared to the
dry feed process. The data presented in Table 1 also
contrast different gasification conditions.
Gasifier types and applications
Gasifier types (see Table 2) are described in terms
of two parameters: 1) the direction of flow of the incoming oxidant relative to the outlet gas flow (up-flow,
down-flow and cross-flow), and 2) the relative velocity of the solids (fixed or moving, fluidized, entrained,
and transport).
Up-flow (countercurrent)
The oldest and simplest type of gasifier is the upflow (countercurrent) gasifier as shown in Fig. 2a and
2d. The oxidant enters at the bottom of the gasifier
vessel and the gas leaves at the top (up-flow), while
the fuel flows in the opposite direction (countercurrent)
of the gas. The combustion reactions occur near the
grate at the bottom, followed by reduction reactions
somewhat higher up in the gasifier. In the upper part
of the gasifier, heating and pyrolysis of the feedstock
occur as a result of heat transfer by forced convection
and radiation from the lower zones. The tars and volatiles
Table 1
Raw Gas Composition for Selected Gasifier Types
Gasifier Type
Moving Bed,
Dry3
Moving Bed,
Slagging2
Fluidized
Bed2
Air
Subbituminous
Oxygen
Bituminous
Oxygen
LigniteNote 3
41.1
4.6
0.8
20.5
0.6
16.1
16.3
11,258
(26,189)
61.2
4.7
1.1
8.8
3.4
8.8
12.0
11,235
(26,136)
Fuel feed method
Dry
Dry
Dry
Operating pressure, psi
(kPa)
295
(2034)
465
(3206)
145
(1000)
615
(4240)
46.0
26.4
2.9
16.3
2.8
4.2
1.1
0.3
333
(13.1)
48.2
30.6
8.2
9.1
0.7Note 4
2.8
0.4
-- Note 2
309
(12.2)
41.0
29.8
10.2
17.1
0.8Note 4
0.3
1.1
0.2
278
(10.9)
Oxidant:
Fuel type:
Fuel analysis, % by wt
C
H
N
O
S
Ash
Moisture
HHV, Btu/lb
(kJ/kg)
Raw gas composition, % by vol
CO
H2
CO2
H2O
N2
CH4 + CnHm
H2S + COS
NH3+ HCN
HHV, Btu/dscf
(MJ/Nm3)
17.4
23.3
14.8
-- Note 1
38.5
5.8
0.2
-- Note 2
196
(7.7)
56.9
3.8
0.8
15.9
1.0
9.6
12.0
9,914
(23,063)
Entrained
Flow (Slurry)2
Oxygen
Bituminous
61.2
4.7
1.1
8.8
3.4
8.8
12.0
11,235
(26,136)
Slurry
(66.5 wt %
solids)
Entrained Flow
(Dry Feed)2
Oxygen
BituminousNote 3
66.1
5.0
1.2
9.5
3.7
9.5
5.0
12,128
(28,213)
Dry
365
(2516)
60.3
30.0
1.6
2.0
4.7Note 4
-1.3
0.1
297
(11.7)
Notes:
1. Dry analysis
2. Not reported
3. Dried fuel
4. Includes argon
Steam 41 / Coal Gasification
18-3
The Babcock & Wilcox Company
Table 2
Gasifier Comparison
Parameter
Gas flow
Fuel size
Coal rank
Oxygen required
Steam required
Gas velocity
Typical
temperature
Types
Key technical
challenges
Key developers
Fixed (Moving) Bed
Fluidized Bed
Up-flow
(countercurrent)
Coarse < 2 in. (5 cm)
Low
Low
High
Low
800 to 1200F
(427 to 649C)
Dry ash or slagging
Up-flow
(countercurrent)
< 0.25 in. (6 mm)
Low
Moderate
Moderate
Moderate
1700 to 1900F
(927 to 1038C)
Dry ash or
agglomerating
Carbon conversion
Up-flow or down-flow
(counter or co-current)
Pulverized
Any
Large
Low
Medium
2300F
(1260C)
Slagging
Raw gas cooling
Coal feeding
Raw gas cooling
Winkler, Kellogg
Rust Westinghouse
Up-flow: Dow, Uhde,
B&W
Down-flow: Texaco, Shell
Kellogg Brown &
Root (formerly
MW Kellogg)
Utilization of fines
and hydrocarbon
liquids
Lurgi, British
Gas/Lurgi
produced during this process remain in the gas stream
while ashes are removed from the bottom.
The advantages of up-flow gasifiers are: 1) simplicity, 2) fuel flexibility, 3) high cold gas efficiency, and
4) high char burnout and internal heat exchange
leading to low gas exit temperatures. Major drawbacks
are: 1) potential for channeling that can lead to oxygen breakthrough and dangerous, explosive conditions, and 2) difficulty in disposing of tar-containing
condensates resulting from the gas cleaning (except
when the gas is used for direct heat applications where
the tars are burned).
Down-flow (co-current)
In down-flow (co-current) gasifiers, the oxidant and
fuel are introduced at the top of the gasifier. The product gas and ash or slag are removed at the bottom of
the vessel. This solves the problem of tar entrainment
in the gas stream. The down-flow configuration is
shown in Fig. 2b. Depending upon where the oxidant
is introduced (below the coal feed or with the coal feed
as shown), there may be some or no (plug-flow) mixing of the gas with the particles.
As the gas flows downward, the acid and tarry distillation products from the fuel pass through the bed
of burning char where they are converted to hydrogen, carbon dioxide, carbon monoxide and methane
gases. The efficiency of this conversion depends on the
temperature and residence time.
The advantage of down-flow gasifiers is the potential to produce tar-free gas. However, it is very difficult to achieve this goal over the entire operating
range and turndown ratios of 3:1 are common; 5-6:1
is considered excellent. There are also some environmental advantages because the down-flow gasifiers
produce a lower level of organic compounds in the condensate. The disadvantages are: 1) reduced fuel flexibility due to co-current flow, 2) greater susceptibility
18-4
Entrained Flow
Transport
Up-flow
(countercurrent)
Any
Moderate
Moderate
High
1600F
(871C)
Dry ash
to slagging with high ash fuels, 3) lower cold gas efficiency due to poorer internal heat exchange resulting in a lower heating value of the gas, and 4) the need
to maintain uniform high temperatures over the gasifier cross-sectional area.
Cross-flow
Cross-flow gasifiers, shown in Fig. 2c, are an adaptation for gasification of high fixed carbon, low volatile coals or char. Char gasification produces very high
temperatures [2730F (1499C) and higher] in the oxidation zone, which can be a problem for materials of
construction. In cross-flow gasifiers, insulation against
these high temperatures is provided by the fuel (char)
itself. Due to cross-flow gasifiers’ inability to convert
tars, only low volatile fuels can be used, making this
type of gasifier unsuitable for power generation applications.
Fixed (Moving) bed
In a fixed-bed gasifier (Fig. 2a), also referred to as
moving-bed, a column or bed of crushed coal is supported by a grate while the oxidant flows upward
through the coal column at a velocity relative to the
particle size and insufficient to lift or fluidize the particles. The gasification process involves a series of
countercurrent reactions. At the top, the coal is heated
and dried while cooling the product gas. The coal is
further heated and devolatilized as it descends
through the carbonization zone. Below this area, the
devolatilized coal is gasified by reaction with steam and
CO2. The highest temperatures are reached in the
combustion zone near the bottom of the gasifier. The
char-steam reaction together with the presence of
excess steam keeps the temperature in the combustion zone below the ash slagging temperature. Both
the Lurgi (dry ash) and the British Gas/Lurgi
(slagging) designs are fixed-bed gasifiers.
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
(a) Moving-Bed Gasifier (Dry Ash)
(b) Entrained-Flow Gasifier
Coal
Gasifier
Top
Coal
Steam,
Oxygen
or Air
Gas
Gasifier
Bottom
Ash
Gas
0
500 1000 1500 2000 2500
(-18) (260) (538) (816) (1093) (1371)
Temperature, F (C)
Steam,
Oxygen Ash
or Air
(c) Cross-Flow Gasifier
(d) Fluidized-Bed Gasifier
Fig. 2 Typical reactors for coal gasification (courtesy of Electric Power Research Institute).2,3
The distinguishing characteristics of a fixed-bed
gasifier are:
1.
2.
3.
4.
5.
produces hydrocarbon liquids such as tars and oils,
has limited ability to handle fine particles,
requires special steps to handle caking coals,
produces relatively high gas methane content, and
has low oxidant requirements.
The main differences among these gasifiers are the
ash conditions (dry or slagging) and design provisions
for handling fines, caking coals and hydrocarbon liquids. The first full scale fixed (moving)-bed coal gasification plant was constructed in 1936. Since then,
164 Lurgi gasifiers have been built by a number of companies. All of these gasifiers except one have been oxygen-blown units. The SASOL plant in South Africa uses
97 units to produce motor fuel from coal. In addition, the
Dakota Gasification Company (Great Plains Synfuels
Plant) at Beulah, North Dakota, has 14 gasifiers.
The configuration of the moving-bed dry ash gasifier is shown in Fig. 3. It is a high pressure cylindrical unit, operating at 350 to 450 psig (2410 to 3100
kPa). The main gasifier shell is surrounded by a cooling water jacket. Sized coal enters the top through a
lock hopper and moves down the bed under the conSteam 41 / Coal Gasification
trol of a rotating grate. The temperature in the combustion zone near the bottom is about 2000F (1093C),
whereas the gas leaving the drying and
devolatilization zone near the top is approximately
1000F (538C). This moving-bed process is capacity
limited. Almost all of these units have a diameter of 13.1
ft (4 m) and a nominal dry gas capacity rating of 33,333
SCFM (14.9 Nm3/s). This is equivalent to about 650 t/
d (590 tm/d) of MAF (moisture- and ash-free) coal. Lurgi
and SASOL are operating a 16.4 ft (5 m) diameter Mark
V gasifier having a capacity of 1000 t/d (907 tm/d) and
generating about 50,000 SCFM (22.35 Nm3/s).
Fluidized bed
In a fluidized-bed gasifier (Fig. 2d), the oxidant
flows upward through the feed coal particles at a sufficient velocity relative to the particle size that, although a discrete bed level exists, the particles are suspended or fluidized by the gas flow, producing good
mixing and constant motion. The fluidized bed is
maintained below the ash fusion temperature to avoid
clinkers which could cause defluidization. (A clinker
is a large solid mass of coal ash agglomerated by ash
slagging.) Char particles entrained with the hot, raw
gas are recovered and recycled to the gasifier. Fluid18-5
The Babcock & Wilcox Company
Entrained flow
In an entrained-flow gasifier (Fig. 2b) fine coal particles are fed with the oxidant in such a way that they
are suspended, or almost sprayed, co-currently into the
process and mixed similar to a pulverized coal burner.
The fine pulverized coal particles react with steam and
oxidant with very short residence time. They can be
up-flow (usually slurry fed) such as the ConocoPhillips/
E-Gas [formerly Destec (DOW)], Uhde (Prenflo) and
The Babcock & Wilcox Company (B&W) processes or
down-flow such as the General Electric (GE)/Texaco
and Royal Dutch Shell processes.
An entrained-flow gasifier has the following characteristics:
1. can gasify all coals regardless of rank, caking characteristics or amount of fines,
2. requires substantial heat recovery due to the large
amount of sensible heat in the raw gas,
3. is a high temperature slagging operation,
4. has a large oxidant requirement, and
5. requires special steps to avoid molten slag
carryover to downstream heat recovery surfaces.
Fig. 3 Moving-bed dry ash gasifier (courtesy of Dravo Corporation).
ized-bed gasifiers, such as KRW’s (Kellogg Rust
Westinghouse) design, are always up-flow.
The distinguishing characteristics of a fluidized-bed
gasifier are:
1. has large char recycle,
2. requires special steps to obtain high carbon conversion of high rank coals,
3. requires special steps to handle caking coals,
4. features uniform and moderate temperature, and
5. requires moderate oxygen and steam inputs.
The main differences among fluidized-bed gasifiers are the ash conditions (dry or agglomerated) and
design provisions for char recycle. An agglomerated
fluidized bed contains a hot zone where the ash particles are caused to cluster into small pellets prior to
removal. Agglomerated ash operation enables the gasification of high rank coals. Dry ash fluidized-bed
gasifiers operate most efficiently on low rank coals.
The fluidized-bed gasifier was the first commercial
coal gasification unit and was the initial application
of fluidized-bed technology. The first of these gasifiers was put into operation in Leuna, Germany in
1926. Since then, about 70 Winkler gasifiers have
been constructed worldwide. However, these units
were superseded by entrained-flow gasifiers and by
pressurized moving-bed units. Only three of these
gasifiers at two plants remain in operation today.4 Low
capacity and high operating costs have limited further
use of the conventional Winkler gasifier.
18-6
The main differences among entrained-flow gasifiers are the coal feed system (slurry or dense phase)
and the design configurations for raw gas cooling and
sensible heat recovery. This unit is also called a suspension gasifier because it consists of a two-phase
system of finely divided solids dispersed in a gas. No
distinct bed level exists.
The entrained-flow technology began as an atmospheric pressure process for producing synthesis or fuel
gas from solid or liquid carbonaceous fuels. The original bench-scale development of this gasifier type was
done by Dr. Friedrich Totzek in the late 1930s while
working for Heinrich Koppers GmbH of Essen, Germany. The process was jointly piloted in the U.S. by
H. Koppers GmbH; Koppers Company, Inc. of Pittsburgh; and the U.S. Bureau of Mines. The first commercial entrained-flow gasification plant was built in
France in 1949. Since then, 39 units have been built
in various countries with most still in operation. The
primary application is hydrogen production for ammonia synthesis.
Fig. 4 shows the entrained-flow atmospheric pressure gasifier. The coal is pulverized and fed by screw
conveyors through opposing burners into a horizontal, elliptically-shaped gasifier. The fuel is oxidized,
producing a flame zone temperature of about 3500F
(1927C). Heat losses and endothermic reactions reduce
the gas temperature to about 2700F (1482C). The hot
product gas is further cooled by direct water quenching to about 1700F (927C) to solidify entrained liquid
slag particles before they enter the heat recovery
(waste heat) boiler.
The cold gas efficiency of the original KoppersTotzek oxygen-blown gasifier was 67%. Although this
appears to be low, an additional portion of the coal’s
energy was converted into heat which was recovered
by the cooling jacket and heat recovery boiler. Combining these energy sources yielded an overall efficiency of 85%. More recent improvements in modern
entrained-flow gasification systems can increase the
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
Fig. 5 U.S. Department of Energy’s (DOE) Power Systems Development Facility.
Fig. 4 Entrained-flow gasifier (courtesy of Dravo Corporation).
total efficiency into the high 90s. Most gasifiers use a
design featuring two opposing burners. These have a
total capacity of 10,583 SCFM (4.73 Nm3/s), which is
equivalent to about 230 t/d (209 tm/d) of MAF coal. Two
plants with four headed designs have about twice this
capacity each. Current demonstration plants are exceeding 2500 t/d (2268 tm/d) coal.
Transport
A transport gasifier is a circulating fluidized-bed
gasifier in which the oxidant flows upward through
the feed coal particles at a velocity high enough that
no discrete bed level exists. The particles are fully
suspended or highly fluidized by the gas flow, producing excellent mixing. As with the fluidized bed, the
process is maintained below the ash fusion temperature to avoid clinkers which could cause defluidization.
Due to the greater degree of mixing and the circulating loop inherent in the design, and particle size, char
burnout is excellent. This type of gasifier, initially developed by MW Kellogg (now Kellogg Brown & Root), is
now being tested at the U.S. Department of Energy’s
(DOE) Power Systems Development Facility (PSDF)
near Wilsonville, Alabama. (See Fig. 5.)
The distinguishing characteristics of a transport
gasifier are:
high carbon conversion (> 95%),
cold gas efficiency of 70-75%,
handles a broad range of coals,
uniform and moderate temperature [1600F
(871C)], and
5. requires moderate oxygen and steam inputs.
Major gasifier process developers
GE/Texaco
The GE/Texaco entrained-flow coal gasification process is shown in Fig. 6. The downflow gasifier is fed
with a coal-water slurry of 60 to 65% solids by weight,
and oxygen. It operates at up to 900 psi (6205 kPa)
and is refractory lined. The raw gas leaves the unit
at 2300 to 2700F (1260 to 1482C) and is separated
from the slag. The syngas is cooled by a radiant boiler,
followed by a convection boiler, which generates 1600
psi (11,031 kPa) saturated steam. These boilers are
called syngas coolers.
There are several options for gas cooling. One is to
use the radiant and convection coolers (as shown in
Fig. 6) which results in maximum efficiency. A second
1.
2.
3.
4.
Steam 41 / Coal Gasification
Fig. 6 Typical entrained-flow process (courtesy of Texaco Development Corporation).
18-7
The Babcock & Wilcox Company
involves replacing the radiant cooler with a direct
water syngas quencher and eliminating the convection cooler, which minimizes cost. A third option is to
use the radiant cooler only, which provides partial
recovery of the syngas heat and is intermediate in
efficiency and cost.
The cold gas efficiency for the process shown in Fig.
6 is 77%. If the energy of the steam produced is added
to that of the fuel gas, the unit efficiency increases to
95%. Overall carbon conversions of 96.9% and 97.8%,
respectively, are obtained with Illinois No. 6 and Pittsburgh No. 8 coals.2,5 Carbon conversion is defined as
the percent of carbon in the coal converted to gases or
liquid (tar) products.
Royal Dutch Shell
The Shell gasification process is shown in Fig. 7.
The coal is pulverized, dried, and fed to lock hoppers
for pressurization. An operating pressure of 350 psig
(2410 kPa) is lower than that of the GE/Texaco unit.
The membraned walls are water cooled. Burners are
opposed and in a reactor configuration similar to that
of the Koppers-Totzek design. The raw gas leaves the
unit at 2500 to 3000F (1371 to 1649C) and most of
the coal ash exits through the slag tap in molten form.
The syngas contains a small quantity of unburned
carbon and a significant fraction of molten ash. To keep
the ash particles from sticking together, the hot exiting gas is quenched with cold recycle gas. Further
cooling takes place in the syngas cooler, consisting of
radiant and convective sections. Some steam superheating is achieved with the hot, raw syngas.
The Shell gasifier cold gas efficiency is at least 80%.
The combined chemical and thermal energy recovery
is at least 97%. Feed coal drying reduces the net efficiency for low rank coals. The efficiency is also reduced
when direct coal combustion is not used for drying. The
effect of coal drying could lower the efficiency to approximately 94%. Finally, the net efficiency is about
84% when the energy required for oxygen production
is also included.2,6 Better than 99% carbon burnout
has been obtained for most coals.7
ConocoPhillips/E-Gas [Destec (Dow)]
The ConocoPhillips/E-Gas gasifier is a two-stage,
slurry feed, entrained-flow, slagging gasifier unit.
Coals are slurried with water to produce a solids loading of 50 to 55% by weight. About 75% of the slurry is
gasified with oxygen in the first stage. The hot gas leaving this stage at 2400 to 2600F (1316 to 1427C) is used
to gasify the remaining 25% of the coal in the second
stage. Both stages are refractory lined and uncooled. The
first stage reactor is similar to the Koppers-Totzek unit
with two opposing burners and slag removal. This arrangement assures high carbon conversion and optimal
slag removal.
The direct injection of coal slurry at the second stage
entrance quenches the hot gas and gasifies the additional coal, providing an exit gas temperature of about
1900F (1038C). This eliminates the need for a radiant boiler and requires reduced heat recovery downstream. There is no requirement for quench recycle
gas or the compression energy associated with recy18-8
Fig. 7 Typical process with syngas cooler (courtesy of Synfuels
Business Development, a division of Shell Oil Company).
cling large volumes of cooled gas. The ConocoPhillips/
E-Gas unit includes a fire tube boiler followed by a
steam superheater and economizer to recover heat
from the raw product gas.8
British Gas/Lurgi
Lurgi has worked with the British Gas Corporation
(BGC) in developing the BGC/Lurgi process. This
gasifier, shown in Fig. 8, is very similar to the conventional dry ash Lurgi process. The key difference is that
the BGC/Lurgi process slags the coal ash. This process partly alleviates the coal acceptability problems
associated with the dry ash Lurgi process by permitting the use of higher rank, low ash coals. Tars and
oils are re-injected, providing a cold gas efficiency of
88%. The value rises to about 90% when considering
additional hydrocarbon liquids.2 A substantial advantage of slagging the coal is that the steam requirement
is only about 15% of that for the conventional Lurgi
process when gasifying bituminous coal.
Winkler
The High Temperature Winkler (HTW) process is
an extension of the old Winkler fluidized-bed technology. The HTW process is being developed by
Rheinbraun (Rheinische Braunkohlenwerke AG) in
Cologne, Germany in cooperation with its engineering partner, Uhde GmbH, Dortmund. The dry ash
gasification of reactive German brown coal along with
peat and wood is being researched. Recycling of fines
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
entrained with the raw gas results in better carbon
conversion. Furthermore, by operating at an increased
pressure of 130 psig (896 kPa), the synthesis gas production rate for a given gasifier diameter more than
doubles. A 580 t/d (526 tm/d) HTW plant has been operating since 1986 at Huerth (Berrenrath brown coal
plant), Germany, producing 22,917 SCFM (10.24 Nm3/
s) of synthesis gas from brown coal.
The HTW unit relies on the use of non-caking coals
to achieve high carbon conversion. Approximately
95% conversion can be reached with very reactive German brown coals. The bed operates at temperatures
of 1400 to 1500F (760 to 816C). Cold gas efficiency is
about 82% for the oxygen-blown HTW; the efficiency
increases to 85% if the net steam generation (deducting energy for coal drying and steam fed to gasifier)
is added.2 There is a high energy requirement for drying the high moisture, low rank coal.
The gas-tight membrane wall enclosure provides an
annular space which separates the gasification reactor and the pressure vessel. Therefore, the pressure
vessel, at a relatively low temperature, is not in contact with the corrosive raw gas. In the lower portion
of the unit (the gasification zone), the tubes are stud-
Babcock & Wilcox gasifier development
As the firing and operation of an entrained-flow
gasifier are somewhat similar to that of a pulverized
coal-fired boiler9,10 all of B&W’s gasification processes
are entrained-flow gasification systems featuring
pulverized coal feed. As a result, there are inherent
advantages in using pulverized coal as a fuel for entrained-flow gasifiers. A pressurized 850 to 1000 t/d
(771 to 907 tm/d) gasifier design with a waste heat
recovery boiler is shown in Fig. 9.
Fig. 8 Slagging gasifier (courtesy of British Gas PLC).
Steam 41 / Coal Gasification
Fig. 9 Typical 1000 t/d entrained-flow design.
18-9
The Babcock & Wilcox Company
ded and covered with refractory to maintain the high
temperatures necessary to keep the slag fluid. In the
upper portion of the gasifier (the freeboard zone), the
tubes are exposed to provide maximum cooling. Use
in Cyclone wet bottom boilers (see Chapter 15) has
proven the durability of this construction. This gasifier, featuring a 2 in. (51 mm) thick vessel wall, is
designed for relatively low pressure operation [50 psig
(345 kPa)]. Temperature in the combustion zone is
about 3400F (1871C) and the gas leaving the unit is
at 1800F (982C).
The advantages of the dry feed, entrained-flow gasifier include:
1. Insensitivity to coal characteristics – Unlike moving-bed or fluidized-bed gasifiers, it can accept caking coals, fines and any rank coal. With dense-phase
coal feed, as contrasted to slurried coal, it can accommodate the wide range of coal moisture contents.
2. Larger unit size potential due to ease of handling
and mixing of the coal – Basically, as in pulverized coal-fired boilers, unit size can be increased
by adding burners. The higher throughput velocity allows a high quantity of coal per hour to be
treated in a given size gasifier.
3. Rapid control response – This is due to its low solids inventory compared to other gasifiers.
4. Easy disposal of the dense granular slag – Similar material from slag-tap boilers has been used
as road fill. It does not create a dust or water pollution problem.
5. High yield of synthesis gas (CO + H2) – Conversely,
the yield of CO2 and H2O is low. For example, the
dry-bottom, moving-bed product gas can contain
60% (by volume) H2O and 10% CO2 as contrasted
to about 2% each of these components in a dry feed
entrained gasifier.
6. No hydrocarbon liquids generated – Tars, phenols
and oils are absent. Special handling problems associated with production of such chemicals and
special treatment requirements for scrubber water are avoided. Re-injection of unreacted char is considerably simpler than such tar-like streams.
7. High reliability (no moving parts in furnace) – The
requirement for mechanical devices, such as a rotating grate, is eliminated because the pulverized
coal is dispersed through the gasifier and rapidly
heated through the plastic temperature range without coming into contact with adjacent coal particles.
8. Reduced maintenance due to the cooled membrane
wall construction – The durability of the studded
tube, refractory-coated gasifier cooling enclosure
has been proven in Cyclone furnace and slag-tap
boilers. This contrasts to the higher maintenance requirements of non-cooled, refractory-lined gasifiers.
The disadvantages are:
1. May not be economical for very small sizes – With
its high gasification capacity for a given size vessel, fewer gasifiers are needed to supply the required gas. Scaledown would require a detailed
evaluation of the scaling factors for the pressure
vessel, up front coal preparation plant (pulverizers), and downstream heat recovery equipment.
18-10
2. Generates negligible methane (if methane is desired) – Methane production is generally favored
in a lower temperature, high pressure, moving-bed
type gasifier.
3. Control of coal feed rate is more complex – Maintenance of uniform heat release and slagging conditions requires precise control of coal flows.
Dense-phase pulverized coal feed systems require
inerting for safety. Coal feed and char recycle are
simplified with coal slurries and higher pressures
are possible, but there are associated penalties in
carbon burnout and flexibility of coal feed sourcing.
4. Turndown may be limited with some coals – Turndown to approximately 25% of capacity should
generally be possible, but certain high ash-fusion
temperature coals may constrain proper slagging
at low loads.
5. Relatively high oxygen and waste heat recovery
duty – These characteristics are associated with
the high temperature of the entrained-flow process. Heat recovery costs exceed those of the fluidized or moving bed. Because the gasifier walls
and heat recovery boiler absorb about 85% of the
energy released as sensible heat (25% of the energy in the coal), it has been estimated that the
total recovered and chemical energy efficiency of
the gasifier can exceed 96% for most coals.
B&W gasifier development dates back to 1951. Several pilot plants were built in-house and a full scale
commercial gasifier was built to produce synthesis gas.
The first gasifier designed and constructed by B&W
(Fig. 10) was put into operation in 1951 at the U.S.
Bureau of Mines station at Morgantown, West Virginia
(currently DOE’s National Energy and Technology
Laboratory). Operating at atmospheric pressure, this
unit was oxygen-blown and was capable of gasifying
500 lb/h (0.063 kg/s) of coal, producing about 330,000
ft3/d (147.3 Nm3/h) of synthesis gas. It was refractory
lined and was comprised of a primary and secondary
reaction zone. The primary zone produced temperatures exceeding 3000F (1649C) and the secondary
zone operated at about 2200F (1204C). The unit was
operated successfully for more than 1200 hours.
B&W also assisted the U.S. Bureau of Mines in its
early pressurized gasification studies. One unit designed by B&W featured a down-fired axial coal feed
[500 lb/h (0.063 kg/s)] with tangential steam and oxygen feeds. This unit was designed for operation at 450
psig (3100 kPa). It was operated during the 1950s and
1960s and was occasionally used in the 1980s.
A reduced-scale gasifier was constructed at Belle,
West Virginia in 1951.11 This unit was rated at 3000
lb/h (0.38 kg/s) of coal and produced 1389 SCFM (0.62
Nm3/s) of synthesis gas. When installed, it was the
largest pulverized coal gasifier in the U.S. The unit
operated for more than 5000 hours and established the
design basis for a full scale gasifier at the same plant.
In 1955, a full scale gasifier began operation at
Belle, West Virginia. The unit was 15 ft (4.6 m) in diameter and 88 ft (26.8 m) tall. It was designed to gasify 17 t/h (15.4 tm/h) of coal, producing 17,360 SCFM
(7.75 Nm3/s) of carbon monoxide and hydrogen. The
gasification zone was refractory lined and the floor
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
cool the gas leaving the gasifier to remove sulfur and
particulates prior to entering the gas turbine (resulting in an efficiency penalty). In addition, these coolers have experienced failures resulting in plant downtime. Ideally, the sulfur and particulates would be
removed with minimal cooling of the gas.
Gas cooling
Syngas cooler material failures have accounted for
a substantial percentage of downtime at the IGCC
demonstration plants. Material selection in syngas
coolers requires special attention.12,13
There are major differences between syngas coolers and coal-fired boilers:
1. The highly reducing and corrosive raw syngas presents a different environment for material qualification. Protective oxide scales which usually form
on low alloy boiler steels do not readily form in
syngas coolers, where H2S and HCl are present.
2. Because of the high operating pressure, generally
300 to 600 psi (2070 to 4140 kPa), the syngas dew
point is generally much higher than that in atmospheric pressure boilers. This is especially true
when the steam content of the syngas is high, as with
a coal-water slurry feed system. Precautions are required to prevent operation below the acid dew point
and to avoid aqueous corrosion during downtime.
3. Pressurized operation, requiring a vessel enclosure for the exchangers, constrains the design
layout. This requires special attention to assure
accessibility for inspection and repair.
Fig. 10 Early B&W oxygen-blown gasifier.
and walls were water cooled. The gasifier operated for
more than a year, then shut down when low cost
natural gas became available.
In the early 1960s, another pilot unit was constructed by B&W at its research facility in Alliance,
Ohio (Fig. 11). This air-blown unit was used in a cooperative program with General Electric to study combined gas turbine/steam turbine cycles. It consisted of
a 3 t/h (2.7 tm/h) gasifier with char recycle, mechanical gas cleanup equipment, and a gas-cooled cyclone
combustor. This facility was operated for three years
beginning in 1960, and horizontal and vertical slagtap, vortex-fired gasifiers were studied.
B&W also built a 5 t/h (4.5 tm/h), 1500 psig (10,340
kPa) gasifier for the Bi-Gas pilot plant at Homer City,
Pennsylvania (Figs. 12 and 13). This plant, which
opened in 1976, demonstrated the production of synthetic natural gas from coal. The project was sponsored
by the Office of Coal Research, the U.S. Department
of Interior, and the American Gas Association.
Low alloy steels are not suitable for syngas coolers
because of excessive corrosion rates caused primarily
by sulfidation, and also by chlorination. For low alloy
steels, the sulfidation rate is dependent on the H2S
partial pressure and the rate is higher with high sulfur coals. Iron sulfide (FeS) and mixed sulfide-oxide
Development issues
Although there are other issues such as removal of
acids from the gas, as well as solid and liquid effluents, there are three primary areas where further
development is needed for integrated gasification combined cycle (IGCC) to achieve its potential. Due to
materials issues, current systems must significantly
Steam 41 / Coal Gasification
Fig. 11 Pilot plant for gasification research.
18-11
The Babcock & Wilcox Company
The presence of HCl in syngas increases its dew point
54 to 90F (30 to 50C).
Preliminary material selection guidelines aimed at
a 25 year service life have been formulated by the
Electric Power Research Institute (EPRI) based on
currently available laboratory and field data.12,13 Actual service life will depend on the severity of the conditions to which the individual material components
are exposed, which in turn are dependent on the specific design, fuel used, and operating conditions.
Fig. 12 B&W bi-gas gasifier.
scales form; these are generally less protective than
oxide scales. Because low alloy steels experience excessive corrosion rates, stainless steels are used. Corrosion rates must be less than about 4 mils/yr (0.1 mm/
yr) to obtain a service life of 25 years.
The effects of syngas chlorides are not clearly defined. Sulfidation rates in syngas with 300 to 500 ppm
HCl become variable and are generally higher, presumably because of FeCl2 formation and spalling during thermal cycling. Chlorides greatly accelerate aqueous corrosion during downtime if condensation occurs.
18-12
Particulate removal
Particulate removal at as high a temperature as
practical is desirable to avoid significant heat losses
and resulting loss of efficiency. Rigid, porous ceramic
barrier filters have been the focus of development for
hot particulate removal at temperatures around 1800F
(982C). The ceramic material must be porous enough
to allow gas penetration while capturing fine particulate, permitting solids removal and pressure drop recovery. It must also be resistant to chemical attack from
the high temperature reducing environment and have
sufficient ductility to resist the thermal and mechanical shocks imposed during operation. A variety of filter arrangements have been developed with these
objectives including candle, granular bed, cross-flow
and tubular designs (see Fig. 14). Although much testing has been done and applications have been attempted at a few of the IGCC demonstration facilities,
ceramic filtration remains incapable of commercial
reliability and all of the gasification plants to date cool
the product gas to 1000F (538C) or lower to utilize
lower temperature sintered metal filters to remove
particulates.
Candle filters consist of thousands of ceramic or sintered metal candles, which are hollow tubes closed at
one end, with the other end suspended from a tube
sheet within a pressure vessel. The dirty gas enters
the pressure vessel and flows around the outside of
the candles and through the filter wall to the inside,
leaving the entrained dust on the outside of the candle.
The clean gas flows up through a common collector
and out the top of the vessel. When the pressure drop
through the candles reaches a prescribed value, pressurized gas is pulsed in the reverse direction to the
normal gas flow (back-pulse), loosening the filter cake
from the outside of the candles and allowing it to fall
into an ash hopper. It is then removed through lock
hoppers. High temperature ceramic candle filters have
received a great amount of testing. The greatest
hurdles to reliability have been cracking due to thermal shock from back pulsing, from thermal upsets
caused by carbon carryover, or from ash that has been
allowed to accumulate until it reached the candles.
Most ceramic filter medium is monolithic and very
brittle. In the late 1980s, B&W developed a continuous fiber ceramic composite (CFCC) material to provide more ductility than monolithic ceramic tubes.
CFCC is woven from ceramic fibers and offers predictable permeability with considerable flexibility.
In granular bed filters, dirty gas is forced to pass
through a moving bed of solids that traps the particulate. The bed material enters at the top and is removed
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
Fig. 13 Bi-gas gasifier prepared for shipment.
at the bottom. The ash is then cleaned and the filtration medium is returned to the process.
Cross-flow filters are composed of an array of ceramic structures much like a honeycomb with passages
perpendicular to each other separated by ceramic
walls. The dirty gas flows into the filter through one
set of passages, permeates the ceramic wall to the
perpendicular path, and flows out. Cross-flow filters
have been arranged in several ways, usually within
a pressure vessel utilizing a back-pulse cleaning system as previously described.
Tubular filters are made up of hundreds of ceramic
tubes, open at both ends and sealed at both ends to a
tube sheet. Dirty gas enters the vessel surrounding
the outside of the tubes, flows through the ceramic tube
wall and leaves the entrained dust on the surface of
the tube. The clean gas passes up the center of the
tube and out the top of the vessel. As with candle filters, the tubes are cleaned by back pulsing.
Until there is a breakthrough in hot gas filtration,
gasification processes will be forced to cool the gas and
suffer an efficiency penalty.
Sulfur removal
The U.S. DOE has funded research on hot gas desulfurization since the 1970s, testing mixed metal oxide sorbents such as zinc ferrite (ZnFe2O4), titanate
(ZnTiO3), copper oxide (CuO) and iron oxide (Fe2O3)
as candidates for regenerable systems. At small scale,
Steam 41 / Coal Gasification
most have shown high removals of gas phase sulfur
species and can still be regenerable.14
The general process consists of metal oxide pellets
housed in a reactor vessel through which the sulfurladen acid gas passes. Some systems are fixed beds in
parallel, with hot valves diverting gas between beds
as they absorb and regenerate. Other systems use a
moving-bed or a fluidized concept, as shown in Fig.
15. The sorbent is regenerated by passing a controlled
flow of air through the pellet bed; the air reacts exothermically to produce a concentrated SO2 off gas
which must be further treated. Depending on the
metal oxide used, the temperature must be carefully
controlled between 1200F (649C) and 1400F (760C)
to prevent potentially hazardous zinc vaporization
and sintering.15 Sorbent life is the critical operating
consideration due to its high cost.
Zinc ferrite has been tested in bulk removal and
polishing modes. Bulk removal uses the sorbent to
perform the total sulfur removal duty. In the polishing mode, the sorbent is a secondary means of sulfur
removal; primary removal is achieved within the gasifier. Fluidized-bed gasifiers using a throwaway sorbent such as limestone or dolomite can capture some
sulfur. Entrained-flow units have been fed with iron
oxide or dolomite to capture sulfur in the slag.16
Many development issues must be resolved before
hot gas cleanup systems can be offered commercially.
In addition to particulate and sulfur removal issues,
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The Babcock & Wilcox Company
Pulse
Nozzle
Gas
Outlet
Pellet
Inlet
Pulse
Nozzle
Gas
Outlet
Gas
Inlet
Gas
Outlet
Back Pulse
Gas
Outlet
Gas
Inlet
Back Pulse
Gas
Inlet
Gas
Outlet
Gas
Inlet
Ash Outlet
Candle Filter
Ash Outlet
Granular Bed Filter
Ash Outlet
Cross Flow Filter
Ash Outlet
Tubular Filter
Fig. 14 Ceramic filter arrangements.
the effects of raw gas chlorides, alkali species and other
trace volatile elements on the performance of downstream equipment must be addressed. Ammonia in the
gas will not be condensed and may result in high NOx
emissions from a gas turbine combustor. The challenge
is to achieve the excellent environmental performance
of conventional processes while being reliable, efficient and economical.
IGCC for power generation
Production of power from gasifying coal and combusting the fuel gas in a combined cycle power plant
requires a high degree of component integration, as
shown in Fig. 16. In simple terms, the hot, combusted
fuel gas is expanded in a gas turbine to drive the air
compressor and generator, with some of the compressed air used to gasify the coal. The byproducts,
such as char, are often burned in secondary processes
to produce additional steam and/or power. The gas
turbine exhaust, hotter than 1000F (538C) with modern machines, passes through a heat recovery steam
generator (HRSG) to produce superheated steam to
drive a steam turbine-generator (see Chapter 27) comprising a combined cycle. The gasification process releases significant thermal energy which must also be
recovered into the steam cycle to achieve high overall
plant efficiency.
Demonstrations of coal gasification processes in the
1980s and early 1990s include plants at Plaquemine,
Louisiana (155 MW Destec or Dow process), Cool
Water at Daggett, California (92 MW Texaco process),
Puertollano, Spain (288 MW ELCOGAS or Prenflo
process), and the first fully integrated IGCC plant at
Buggenum in the Netherlands (250 MW Shell process). Significant investment was made to commercialize IGCC plants for power generation in the DOE’s
18-14
Clean Coal program from in the mid-1980s to 1990s
including plants at Wabash River near Terra Haute,
Indiana (262 MW Destec/Dow process), the Polk
Power Station near Tampa, Florida (250 MW Texaco
process), the Piñon Pine project at Sierra Pacific
Power’s Tracy station near Reno, Nevada (99 MW KRW
process), and the Kentucky Pioneer Energy project near
Trapp, Kentucky (400 MW British Gas/Lurgi process).
The design of an IGCC system is quite complex, with
many factors to consider to achieve the right balance
of capital cost, plant efficiency, operability, and environmental requirements for a given application. For
example, the choice of gasifier type affects the amount
of fuel gas heat recovery duty.
An oxygen-blown, entrained-flow gasifier with its
high operating temperature requires more raw gas
cooling in efficiently designed cycles. These coolers
Fig. 15 Moving-bed zinc ferrite process schematic (courtesy of GE
Environmental Services, Inc.).
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
must perform in a harsh gas environment and are a
critical component in plant reliability. Integrating this
large quantity of lower level steam energy (limited by
metal temperatures) into the steam cycle tends to complicate plant control and operation. In contrast, cooling the raw gas by quenching eliminates the capital
cost and complexity of heat recovery, but at a substantial efficiency penalty (as much as 10% less efficient
than with total heat recovery).
Oxygen plant integration is another design issue.
Fig. 16 shows the turbine-driven air compressor directly feeding the oxygen plant, which produces oxygen more efficiently by reducing external compression
requirements. However, this imposes more demand on
turbine controls due to the large system volume between the compressor and turbine.
Other technical factors, such as fuel characteristics,
influence process design. A high inherent moisture
fuel such as lignite may not be a good candidate for a
coal-water slurry fed gasifier due to reduced efficiency.
Gas turbines have varied abilities concerning fuel gas
minimum heating value, emissions performance, and
compressor range for handling the larger mismatch
between air flow and gas flow when firing relatively
high volume, low Btu coal gas. Ambient temperature
effects and utility load demand characteristics add to
the list of design considerations.
Plant size is determined by the available size of the
gas turbine. A single gas turbine/steam turbine installation can produce more than 250 MW, with about 60%
of the power from the gas turbine. Larger plants require multiple gas turbines, with economies of scale
realized in maintaining a single steam turbine and in
larger balance-of-plant systems such as fuel handling,
electrical and controls, and water treatment. Phased
construction of an IGCC plant by incrementally installing a natural gas-fired turbine (simple cycle), then
steam turbine and HRSG (combined cycle) and finally
a gasification system (IGCC) has been proposed to
provide owner flexibility in meeting changing power
demands from peaking to base load and accommodating a relative rise in fuel costs of natural gas versus
coal. However, this apparently simple concept has
proven impractical due to the significant modifications
to the gas turbine and steam side heat balance necessary to switch from natural gas to coal gas.
The myriad of technologies available and the external design factors combine to make IGCC plant design a complex, site- and fuel-specific process. Concurrently, this flexibility offers opportunity to produce a
highly optimized system for each application.
Future IGCC development
The major force behind development and implementation of IGCC is the demand for a cleaner environment. Conventional pulverized coal (PC) plants continue to add environmental controls to meet ever-tightening emissions requirements (see Chapters 32
through 36). An IGCC plant has the potential to
achieve very low emissions. Oxygen-blown gasifiers
with a cold gas cleanup system are particularly well
suited to deliver low emissions of SO2, NO x, solid
wastes, and air toxins such as mercury.
Steam 41 / Coal Gasification
Sulfur removal efficiencies in excess of 99% are
possible with an IGCC plant equipped with a H2S removal process, a Claus (elemental sulfur recovery)
plant, and a tail-gas cleanup system. Wet scrubbers
in a PC plant can be practically designed with equivalent performance through use of more enhanced sorbents and/or increased sorbent-to-gas interaction.
With fuel nitrogen compounds removed in the cold
gas cleanup system, NOx emissions from an IGCC system are strictly determined by gas turbine combustor
performance. NOx values less than 0.05 lb/106 Btu
(21.5 g/GJ) are feasible with state-of-the-art combustors, depending on fuel gas fired heating value (moisture and/or nitrogen can be added) and turbine inlet
temperature, both of which affect peak flame temperature and thermal NOx generation. By comparison, PC
plants can also reach such values through low NOx
combustion techniques (see Chapter 14) in combination with post-combustion NOx controls (see Chapter 34).
Solid byproducts from an IGCC plant with an entrained-flow gasifier consist primarily of non-reactive
quenched slag and elemental sulfur. If the sulfur is
sold as a byproduct, the disposal stream is reduced to
the fuel ash. Depending on fuel sulfur content, a PC
plant may produce up to twice as much solid waste due
to sulfur dioxide (SO2) byproducts. (See Chapters 1
and 32.) However, this may be partially offset by the
production of saleable gypsum in conventional scrubber
systems or other byproducts from regenerable scrubber
systems (such as fertilizer from sodium-based systems).
The environmental impacts of heavy metals in fuel
Fig. 16 Integrated coal gasification combined cycle schematic.
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The Babcock & Wilcox Company
ash, emissions of air toxins, especially mercury, and
extremely fine particulate matter are now being scrutinized. Techniques for mercury removal in PC plants
are nearing commercial application and use of wet
electrostatic precipitation can reduce sulfuric acid and
fine particulate emissions to very low amounts, similar to what is possible in IGCC systems with high efficiency filters.
Because a gas turbine is employed in IGCC, the net
plant efficiency is usually expressed in terms of the
coal’s lower heating value (LHV). It should be noted
that due to the difference in the way the heat of vaporization of water is considered in the heat rate calculation, there is a significant difference (2-3%) between efficiencies on a lower versus higher heating
value basis (HHV being the lesser). Net plant efficiencies as high as 45% LHV (42 to 43% HHV) have been
reported, but most plants have actually achieved efficiencies in the range of 38 to 43% depending on capital cost tradeoffs, degree of plant integration, fuel type,
and other specifics. Higher efficiencies are possible as
gas turbines with higher firing temperatures are developed. Current projections of efficiency using advanced high temperature gas turbines not yet commercially available and supercritical heat recovery
steam cycles are in the mid to upper 50% LHV range
(high 40% range with HHV). Operational success of
IGCC plants has varied widely, primarily depending
on the degree of integration and the method of gas
cleaning (hot or cold).
With heightened awareness worldwide of CO2 emissions, efficiency is becoming as much an environmental issue as an economic factor related to fuel costs. A
large state-of-the-art supercritical Rankine cycle
steam plant operating at steam temperatures of 1100F
(593C) (single reheat) with environmental controls
can achieve an efficiency of 40% (HHV) or higher (depending on cooling water temperature and condenser
backpressure and turbine cycle configuration), while
modern subcritical steam cycles have achieved efficiencies of 37% (HHV).
Modern supercritical pulverized coal fired plants
with advanced steam conditions provide very attractive economics, heat rate (efficiency) similar to current
state-of-the art IGCC plants (which determines CO2
emissions), and comparable emissions of SOx, NOx,
mercury and particulates. Considering the state-ofthe-art and the fact that development of gasification
systems has been driven by chemical production
rather than the utility power generation industry, coal
gasification is likely to develop as a co-production
plant. The DOE’s Vision 21 program promotes this
approach of using gasification systems to produce high
value chemicals with electricity as a byproduct rather
than a workhorse technology for power generation.
Ultimately, the cost of producing power with an IGCC
system, advanced Rankine cycle steam plants and
other competing systems, such as pressurized fluidized-bed power systems, will determine the extent to
which each system will be used in the future.
References
1. Meyers, R.A., Ed., Handbook of Synfuels Technology,
Part 3, McGraw-Hill, New York, New York, 1984.
2. “Coal Gasification Systems: A Guide to Status, Applications, and Economics,” Electric Power Research Institute (EPRI) Report AP-3109, June 1983.
3. Elliot, M.A., Ed., Chemistry of Coal Utilization, Second Supplementary Volume, Chapters 23, 24, 25, Wiley,
New York, New York, 1981.
4. Huebler, J., and Janka, J.C., “Fuels, Synthetic,” Encyclopedia of Chemical Technology, Third Ed., Volume 11,
Wiley-Interscience, New York, New York, 1983.
5. “Cool Water Coal Gasification Program: Fifth Progress
Report,” EPRI Report AP-5931, Palo Alto, California, October 1988.
6. “Dry Feed Entrained-Flow Coal Gasification Processes:
Technology Status,” The SFA Quarterly Report, SFA Pacific, Inc., Mountain View, California, December 1988.
7. Krewinghaus, A.B., and Richards, P.C., “Coal Flexibility of the Shell Coal Gasification Process,” Pittsburgh Coal
Conference, Pittsburgh, Pennsylvania, September 25-29,
1989.
8. “Dow Coal Gasification Project and Technology Analysis,” The SFA Quarterly Report, SFA Pacific, Inc., Mountain View, California, April 1987.
9. Probert, P.B., “Industrial Fuel Gas from Coal,” American Ceramic Society, Washington, D.C., May 5-8, 1975.
18-16
10. James, D.E., and Peterson, M.W., “Suspension Type
Gasifiers,” American Institute of Chemical Engineers
(AIChE), Los Angeles, California, November 16-20, 1975.
11. Grossman, P.R., and Curtis, R.W., “Pulverized-CoalFired Gasifier for Production of Carbon Monoxide and
Hydrogen,” Transactions of the American Society of Mechanical Engineers (ASME), Paper No. 53-A-49, July 1953.
12. Bakker, W.T., “Materials for Coal Gasification, an
EPRI Perspective,” EPRI Conference on Gasification Power
Plants, Palo Alto, California, October 18, 1990.
13. Bakker, W.T., “Materials for Syngas Coolers in Integrated Gasification-Combined Cycle (IGCC) Power Plants,”
EPRI Technical Brief RP2048, 1988.
14. Bajura, R.A., and Bechtel, T.F., “Update on DOE’s
IGCC Programs,” Ninth Annual EPRI Conference on Coal
Gasification Power Plants, Palo Alto, California, October
17-19, 1990.
15. Notestein, J.E., “Update on Department of Energy Hot
Gas Cleanup Programs,” Eighth Annual EPRI Conference
on Coal Gasification, Palo Alto, California, October 19-20,
1988.
16. Robin, A.M., “Integration and Testing of Hot Desulfurization and Entrained-Flow Gasification for Power Generation Systems,” Tenth Annual Gasification and Gas
Stream Cleanup Systems Contractors Review Meeting,
Morgantown, West Virginia, August 28-30, 1990.
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
Bibliography
Coal: Energy for the Future, National Research Council,
Committee on the Strategic Assessment of the U.S. Department of Energy, National Academies Press, August
1, 1995.
Handbook of Gasifiers and Gas Treatment Systems, USERDA
Report FE-1772-11, Dravo Corporation, February, 1976.
Kirk, R.E., and Othmer, D.F., Kirk-Othmer Encyclopedia of Chemical Technology, Fifth Ed., John Wiley & Sons,
New York, New York, 2003.
Steam 41 / Coal Gasification
May, M.P., “Suspension Gasifier Offers Economics of
Scale,” Iron and Steel Engineer, pp. 46-52, November,
1977.
“Piñon Pine IGCC Power Project, A DOE Assessment,”
DOE/NETL-2003/1183, United States (U.S.) Department
of Energy (DOE), Morgantown, West Virginia, December,
2002. See also www.netl.doe.gov.
“Wabash River Coal Gasification Repowering Project: A
DOE Assessment,” DOE/NETL-2002-1164, U.S. DOE,
Morgantown, West Virginia, January, 2002. See also
www.netl.doe.gov.
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The Babcock & Wilcox Company
Portion of an entrained-flow gasifier under fabrication at B&W.
18-18
Steam 41 / Coal Gasification
The Babcock & Wilcox Company
Chapter 19
Boilers, Superheaters and Reheaters
In a modern steam generator, various components
are arranged to efficiently absorb heat from the products of combustion and provide steam at the rated
temperature, pressure, and capacity. These components include the boiler surface, superheater, reheater,
economizer, and air heater. They are supplemented
by systems for steam-water separation (see Chapter
5) and the control of steam outlet temperature. The
steam generator can be divided into two general sections, the furnace and the convection pass. The furnace provides a large open volume with water-cooled
enclosure walls inside of which combustion takes
place, and the combustion products are cooled to an
appropriate furnace exit gas temperature (FEGT). The
convection pass contains tube bundles, which compose
the superheater, reheater, boiler bank, and economizer.
The air heater usually follows the convection pass. The
boiler, or evaporation-circulation system, typically
includes one or more of the following subsystems: the
furnace enclosure walls, mix headers, steam drum,
steam-water separation equipment, boiler bank, and
associated connecting piping (downcomers, supplies,
and risers as discussed in Chapter 1). This chapter focuses on the boiler, superheater, and reheater components, plus systems for steam temperature control, steam
bypass, and unit startup. Chapter 20 discusses economizers and air heaters.
water tube type. In the water tube boiler, the water
and steam flow inside the tubes and the hot gases flow
over the outside surfaces. The boiler circulation system is constructed of tubes, headers, and drums joined
in an arrangement that provides water flow to generate steam while cooling all parts. The water tube
construction allows greater boiler capacity and higher
pressure than shell or fire tube designs. The water tube
boiler also offers greater versatility in arrangement; this
permits the most efficient use of the furnace, superheater, reheater, and other heat recovery components.
Boiler configurations
Modern high capacity boilers come in a variety of
designs, sizes, and configurations to suit a broad range
of applications. Sizes range from 1000 to 10,000,000
lb/h (0.13 to 1260 kg/s) and pressures range from one
atmosphere to above the critical pressure.
The combustion system, fuel, ash characteristics,
operating pressure, and total capacity largely determine the boiler configuration. Figs. 1 through 5 illustrate the diversity in configurations.
Boilers
Boiler surface is defined as the tubes and drum shells
that are part of the steam-water circulation system,
and that are in contact with the hot gases (flue gas).
Although the term boiler now frequently refers to the
overall steam generating system, the term boiler surface excludes the economizer, superheater, reheater,
or any component other than the steam-water circulation system itself.
While boilers can be broadly classified as fire tube
and water tube types, as discussed in the Introduction to Steam, modern high capacity boilers are of the
Steam 41 / Boilers, Superheaters and Reheaters
Fig. 1 Integral Furnace industrial boiler for oil and gas firing.
19-1
The Babcock & Wilcox Company
Typical industrial and small power boilers The Integral Furnace boiler shown in Fig. 1 is an oil- and gasfired, low pressure two drum package boiler. In small
capacities, it can be entirely shop assembled and
shipped to the site. (See Chapter 1, Fig. 1.) Because it
burns a clean fuel, there is no provision made for flyash collection or surface cleaning, and a small furnace
volume can be used. A boiler bank (closely spaced tubes
between a steam drum and lower drum) provides the
heat transfer surface necessary for the rated steaming capacity. Fig. 2 illustrates a two drum Stirling
power boiler (SPB) designed for effective firing of high
moisture wood and biomass. (See also Chapter 30.) A
stoker (see Chapter 16) firing system is supplied and
a boiler bank is provided for sufficient steam generating surface.
Additional unique designs include fluidized-bed boilers, process recovery boilers, and waste-to-energy boilers discussed in Chapters 17, 28 and 29, respectively.
Large utility boiler designs As discussed in Chapter
26, all utility boilers feature gas-tight, fully watercooled furnace enclosure walls and floors made of allwelded membrane panel construction. Each design
normally includes a single reheat section, although the
supercritical once-through boiler has also been supplied as a double reheat unit. Fig. 3 is a supercritical
750 MW pulverized coal unit for variable pressure operation. Sloped tubes, commonly angled at 25 degrees
Attemperator
Steam Drum
Lower Drum
Boiler
Bank
Superheater
Economizer
Furnace
Air
Heater
PrecisionJet
Overfire Air
Gas
Burners
Bark
Chute
Air-swept
Spout
Water-cooled
Vibrating
Grate
Fig. 2 Two drum Stirling® power boiler for bark firing.
19-2
Steam
Separator
Final
Final
Superheater Reheater
Water
Collection Tank
Platen
Superheater
Primary
Superheater
Intermediate
Superheater
Primary
Reheater
Economizer
Catalyst
Spiral
Transition
Headers
Overfire
Air Ports
Low NOX
Burners
Furnace
Ammonia
Injection
Grid
SCR
B&W
Roll Wheel
Pulverizers
Air
Heater
Circulation Forced Steam Coil
Pump
Draft Air Heater
Fan
Flue Primary
Gas
Air
Outlet
Fan
Fig. 3 Variable pressure 750 MW boiler for pulverized coal firing.
Design pressure 3825 psig (26.4 MPa); 1054F (568C) superheat and
1105F (596C) reheat steam temperatures; capacity 5,000,000 lb
steam/h (630 kg steam/s).
from horizontal, wrap around the lower furnace in a
single pass (spiral wound construction). Each tube
passes through the various heat flux patterns typically encountered in the lower furnace, creating an
essentially uniform heat absorption profile. At a point
below the furnace nose, the furnace tubes transition
to the vertical tube arrangement for the lower heat
flux zone of the upper furnace. The consistency of the
heat absorption profiles and outlet enthalpy patterns
of the furnace afforded by the spiral wound construction allows for true variable pressure operation and
on/off cycling by reducing thermal upsets. The inclined tube arrangement also reduces the number of
flow paths through the furnace. Other Universal Pressure (UP®) designs are available for supercritical pressure operation with vertical tubing in both the lower
and upper furnace. (See Chapter 26.)
Figs. 4 and 5 illustrate two variations of The Babcock & Wilcox Company’s (B&W) Radiant boiler (RB)
for natural circulation drum type steam generating
systems. Fig. 4 shows an RB unit for coal firing. This
is the Carolina-type design (RBC) with downflow convection backpass, which minimizes overall steam generator height. Provision is made for sootblower surface cleaning and for flyash collection. A Tower-type
(RBT) configuration is also available that features
fully drainable convection pass surfaces and a minimum plan area. (See Chapter 26.) A special type of
radiant boiler, the RBW, is available for anthracite
combustion. The RBW, named for the W shape its
flame forms during combustion, has a similar design
to the RBC, with the exception of the lower furnace
and combustion system. (See Chapter 26.) Fig. 5 is a
Radiant boiler of the El Paso (RBE) configuration for
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
Reheat
Superheater
Steam
Drum
Primary
Superheater
Economizer
Platen
Secondary
Superheater
Downcomers
Primary Air Heater
Secondary
Superheater
Secondary
Air Heater
Furnace
C
Burners
Secondary
Air Duct
Cross
Duct
Feeder
Gas
Outlet
Pulverizers
Primary Air
Primary Air Fan
Hot Cross Duct
Primary Air
Forced Draft Fan
Primary Air Duct Cold Cross Duct
Tempering Air Duct
Fig. 4 Carolina-type Radiant boiler for pulverized coal firing. Design
pressure 2975 psig (20.61 MPa); superheat and reheat steam
temperatures 1005F (541C); capacity 6,600,000 lb steam/h (832 kg
steam/s).
oil and gas firing. The relatively clean liquid or gaseous fuels normally burned in this unit allow for a very
compact design that minimizes the boiler footprint
(plan area) and support steel. The RBE design excludes ash hoppers and ash pits, but provision may
be made for cleaning equipment.
Boiler design
Regardless of the size or configuration, modern
boiler design remains driven by four key factors: 1)
efficiency (boiler and cycle), 2) reliability, 3) capital and
operating cost, and 4) environmental protection. These
factors, combined with specific applications, produce
the diversity of designs presented above and discussed
at length in Chapters 26 through 31. However, all of
these units share a number of fundamental elements
upon which the site- and application-specific design
is based.
The boiler evaluation begins by identifying the overall application requirements specified in Table 1. These
are generally selected in an iterative process balancing initial capital cost, operating costs (especially fuel),
steam process needs, and operating experience. The
selection of these parameters can dramatically affect
cost and thermal efficiency. Chapters 1 and 37 address
these further.
From a boiler evaluation perspective, the temperature-enthalpy diagram shown in Fig. 6 (for a typical
high pressure, single reheat unit) provides important
design information about the unit configuration. In
this example, the relative heat absorption for water
preheating, evaporation, and superheating are 30%,
Steam 41 / Boilers, Superheaters and Reheaters
32%, and 38%, respectively. Reheating the steam increases the total heat absorption by approximately
20%. For cycles at supercritical operating pressures,
a second stage of reheat may be added. For process
applications, only the preheating and evaporation
steps may be required.
Boilers can be designed for subcritical or supercritical
pressure operation. At subcritical pressures, constant
temperature boiling water cools the furnace enclosure,
and the flow circuits must be designed to accommodate
the two-phase steam-water flow and boiling phenomena
addressed in Chapter 5. At supercritical pressures, the
water acts as a single-phase fluid with a continuous increase in temperature as it passes through the boiler.
These designs require special consideration to avoid excessive unbalances in tube metal temperatures, caused
by variations in heat pickup across different flow circuits.
In addition, special heat transfer phenomena must also
be addressed. (See Chapter 5.)
Two basic fluid circulation systems are used, natural circulation and once-through. In natural circulation systems, which operate at subcritical pressures,
water only partially evaporates in the boiler circuits
producing a steam-water mixture at the tube outlets.
Steam-water separation equipment is provided to
separate the steam and water, supply saturated (dry)
steam to the superheater, and recirculate water back
to the boiler circuits. Natural circulation is the result
of the density difference between the colder, denser
fluid in the downcomers and the hotter, less dense fluid
in the upflow portion of the boiler. In B&W UP oncethrough designs, the steam drum and internal steam
separation equipment are eliminated and a separate
startup system is added. UP boilers have been designed for both subcritical and supercritical operation.
Supercritical pressures increase overall power cycle
efficiency, but at a higher initial capital cost.
Fig. 5 El Paso-type Radiant boiler for gas firing. Design pressure
2550 psig (17.58 MPa); superheat and reheat steam temperatures
955F (513C); capacity 3,825,000 lb steam/h (482 kg steam/s).
19-3
The Babcock & Wilcox Company
Table 1
Use-Derived Specifications for Boiler Design
Specified Parameter
Comments
Steam use
Flow rates, pressures, temperatures for utility boilers,
the particular power cycle
and turbine heat balance.
Fuel type and analysis
Combustion characteristics,
fouling and slagging characteristics, ash analysis, etc.
Feedwater supply
Water source, analysis
and economizer inlet
temperatures.
Pressure drop limits
Gas side and steam side.
Government regulations
Including emission control
requirements.
Site-specific factors
Geographical and seasonal
characteristics.
Steam generator use
Base load, cycling, etc.
Customer preferences
Specific design guidelines
such as flow conditions,
design margins, equipment
preferences and steam
generator efficiency.
Economic evaluation
criteria
Efficiency, fan power, reheat
pressure drop and spray flows.
Design criteria Within the preceding framework, the
important items in boiler design are the following:
1. Define the energy input based upon the steam flow
requirements, feedwater temperature, and an
assumed or specified boiler thermal efficiency.
2. Evaluate the energy absorption needed in the
boiler and other heat transfer components.
3. Perform combustion calculations to establish fuel,
air, and gas flow requirements. (See Chapter 10.)
4. Determine the size and shape of the furnace, considering the location and space requirements of
the burners or other combustion system, and incorporating sufficient furnace volume for complete
combustion and low emissions. Provision must be
made for handling the ash contained in the fuel
and cooling the flue gas so that the furnace exit gas
temperature (FEGT) meets design requirements.
5. Determine the placement and configuration of
convection heating surfaces. For utility applications, the superheater and reheater, when provided, must be placed where the gas temperature
is high enough to produce effective heat transfer,
yet not so high as to cause excessive tube metal
temperatures or ash fouling. All convection surfaces must be designed to minimize the impact of
slag or ash buildup and permit surface cleaning
without erosion of the pressure parts.
6. For industrial applications, provide sufficient saturated boiler surface to generate the remainder of
the steam not generated in the furnace walls. This
19-4
can be accomplished, for example, with the addition of saturated enclosure surface, a boiler (generating) bank, an economizer, or a combination of
these items.
7. Design pressure parts in accordance with applicable codes using approved materials.
8. Provide a gas-tight boiler setting or enclosure
around the furnace, boiler, superheater, reheater,
and economizer.
9. Design pressure part supports and the setting for
expansion and local conditions, including wind
and earthquake loading.
Fuel selection and specification are particularly
important. Boiler systems are designed for specific
fuels and frequently encounter combustion, slagging,
fouling, or ash-handling problems if a fuel with characteristics other than those originally specified is fired.
All potential boiler fuels must be assessed to determine
the most demanding fuel.
Chapter 37 outlines procedures for optimizing the
steam cycle and for evaluating the value of specific auxiliary equipment in a given application.
As discussed in Chapter 10, the boiler or combustion efficiency is usually evaluated as 100 minus the
sum of the heat losses and credits, expressed as a percentage. Chapter 10 provides procedures for calculating the corresponding fuel, air, and gas flow rates.
Enclosure surface design
The furnace of a large pulverized coal-, oil-, or gasfired boiler is essentially a large enclosed volume
where fuel combustion and cooling of the combustion
products take place prior to their entry into the convection pass. Excessive gas temperatures entering the
convection pass tube banks could lead to elevated tube
metal temperatures or unacceptable fouling and slagging. Radiation basically controls heat transfer to the
furnace enclosure walls. These walls are typically
cooled with boiling water (subcritical pressure) or high
Fig. 6 Temperature-enthalpy diagram for subcritical pressure boiler
absorption – one reheat section.
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
Steam 41 / Boilers, Superheaters and Reheaters
120
Relative Absorption, %
velocity supercritical pressure water. Occasionally,
superheat or reheat steam is used.
The convection pass enclosure contains most of the
superheater, reheater, and economizer surfaces. (See
Fig. 4.) These enclosure surfaces can be water or steam
cooled.
The furnace enclosures and convection pass enclosures are usually made with all-welded membrane
construction. These enclosures have also been made
from tangent tube construction or closely spaced tubes
with an exterior gas-tight seal. For a membrane construction, the tube wall and membrane surfaces are
exposed to the combustion process on the furnace side,
while insulation and lagging (sheet metal) on the
outside protect the boiler, minimize heat loss, and protect operating personnel. (See Chapter 23.)
Furnace size versus cycle requirements Besides providing the volume necessary for complete combustion
and a means to cool the gas to an acceptable FEGT,
the furnace enclosure also provides much of the steam
generating surface in a boiler. These roles may not
perfectly match one another. In coal-fired units, the
minimum furnace volume is usually set to provide the
fuel ash specific FEGT. Frequently this results in too
much evaporator surface in high pressure boilers and
too little surface in low pressure units to meet the thermodynamic requirements for the desired steam exit
temperature.
Fig. 7 illustrates the effect of the steam cycle and
the operating pressure and temperature on the relative energy absorption between the boiler/economizer
and superheater/reheater. As the pressure and temperature increase, the total unit absorption for a given
power production progressively declines because of
increased cycle efficiency. The boiler and economizer
absorption represents the relative amount of heat
added to the entering feedwater to produce saturated
steam or reach the critical point in a supercritical pressure UP boiler. As the operating pressure increases,
the amount of heat required to produce saturated
steam declines. Conversely, the amount of heat required for the superheater and reheater increases. The
change in required boiler/economizer absorption may
not seem significant. However, a 1% shift in absorption is equivalent to approximately 10F (6C) of superheat or reheat temperature.
On low pressure units, the furnace and economizer
surfaces are typically not adequate to produce all of
the required saturated steam. As a result, a boiler
bank with water cooled walls is usually installed after the superheater. (See Figs. 1 and 2.) On a highpressure unit, the heat absorbed by the furnace and
economizer is adequate to produce all the saturated
steam required.
Furnace design criteria The furnace is a large open
volume enclosed by water-cooled walls for combustion.
Fuel and combustion system selection establish the
shape and volume of the furnace. For wall firing using circular burners (see Chapter 14), minimum clearances between individual burners, between burners
and walls, as well as between burners and the furnace floor, are established based upon physical clearances and functional criteria for complete combustion.
100
80
Required for
Superheater
and Reheater
60
40
20
0
Required for
Boiler and
Economizer
Throttle
Conditions
1250
(8.62)
950
(510)
1800 1800 2400 3500 3500 4500
(12.41) (12.41) (16.55) (24.13) (24.13) (31.03)
psig
(MPa)
950 1000 1000 1000 1100 1100 SH deg F
(C)
(510) (538) (538) (538) (593) (593)
950 1000 1000 1000 1100 1100 RH deg F
(C)
(510) (538) (538) (538) (593) (593)
1100 RH2 deg F
(C)
(593)
Fig. 7 Relative heat absorption for selected power cycle operating
conditions normalized to absorption per kWh in the 2400 psig cycle.
These clearances prevent fuel stream and flame interaction, assure complete combustion, avoid unacceptable flame impingement on the walls (which could lead
to tube overheating or excessive deposits), and minimize the formation of nitrogen oxides (NOx). The maximum fuel input rate, number of burners, and the associated clearances establish: 1) the furnace cross-sectional area, 2) the height of the combustion zone, 3)
the height of the overfire air injection zone (if used),
and 4) the distance between the burner zone and the
furnace hopper or floor. Where the fuel is burned on
stokers, the furnace cross-sectional area is established
by a specified heat release rate per unit bed area. (See
Chapter 16.)
As discussed in detail in Chapter 14, combustion
system design and its impact on furnace volume and
shape have become complex and critical as emissions
limits have been reduced. Use of low NOx burners,
such as the B&W DRB-4Z®, reduce NOx emissions.
Other techniques, such as in-furnace staging with
overfire air (NOx ports), fuel reburning, and reactant
injection are also successful in further reducing NOx
emissions. Some techniques for furnace sorbent injection to reduce sulfur dioxide (SO2) emissions have also
been developed. (See Chapter 35.) Each technique can
have an impact on the furnace size and configuration.
Several criteria establish the overall furnace height
and volume. For clean fuels, such as natural gas, the
furnace volume and height are generally set to cool
the combustion products to an FEGT that will avoid
superheater tube overheating. For fuels such as coal
and some oils that contain significant levels of ash, the
furnace volume and height are established to cool the
products of combustion to an FEGT that will prevent
excessive fouling of the convection surfaces. Chapter
4 explores the relationships between furnace volume
and FEGT. The specific effects of ash on furnace design are discussed below and in Chapter 21. The furnace height must also be set to provide at least the
minimum time to complete combustion and to meet
minimum clearance requirements from the burners
19-5
The Babcock & Wilcox Company
and NOx ports to the arch and convective surface.
Ash effects In the case of coal and to a lesser extent with oil, an extremely important consideration is
the ash in the fuel. If this ash is not properly considered in the unit design and operation, it can deposit
on the furnace walls, sloping surfaces, and throughout the convection pass tube banks. Ash not only reduces the heat absorbed by the unit, but it increases
gas-side resistance (draft loss), erodes pressure parts,
and eventually can result in unit outages for cleaning and repairs. (See Chapter 21.)
Ash problems are the most severe in coal-fired furnaces. There are two general approaches to ash handling: the dry-ash, or dry-bottom, furnace and the
slag-tap, or wet-bottom, furnace.
In the dry-ash furnace, which is particularly applicable to coals with high ash fusion temperatures, a
hopper bottom (Figs. 3 and 4) and sufficient cooling
surface are provided so that the ash impinging on
furnace walls or the hopper bottom is solid and dry; it
can be removed essentially as dry particles. When
pulverized coal is burned in a dry-ash furnace, about
80% of the ash is carried through the convection
banks. The chemistry of the ash can have a dramatic
impact on the furnace volume necessary for satisfactory dry-bottom unit operation. Fig. 8, which compares
the furnace volume required for a nominal 500 MW
boiler burning a low slagging bituminous or subbituminous coal to that for a high slagging lignite coal,
illustrates this. Chapter 21 discusses the relationships
defining the furnace size requirements in detail.
With coals having low ash fusion temperatures, it
can be difficult to use a dry-bottom furnace because
Fig. 8 Boiler size comparison for alternative coal types.
19-6
the slag is molten or sticky; it clings and builds up on
the furnace walls and hopper bottom. The slag-tap or
wet-bottom furnace was developed to handle these
coals. The most successful form of the slag-tap furnace
is that used with Cyclone furnace firing. (See Chapter 15, Figs. 7 and 8.) This furnace comprises a twostage arrangement. In the lower part of the furnace,
sufficient gas temperature is maintained so that the
slag drops onto the floor in liquid form. Here, a pool
of liquid slag is maintained and tapped into a slag
tank containing water. In the upper part of the furnace, the gases are cooled below the ash fusion point,
so ash carried over into the convection banks is dry
and does not cause excessive fouling. Because of high
NOx emissions, slag-tap designs became less popular
for new boiler designs. Recently, however, considerable reductions in NOx levels have been demonstrated
in Cyclone units firing western fuels and employing
staged combustion.
Water-cooled walls Most boiler furnaces have all
water-cooled membrane walls. In this type of construction, furnace wall tubes are spaced on close centers to
keep membrane temperatures and thermal stresses
within limits. The membrane panels (see Fig. 9) are
composed of tube rows spaced on centers wider than
a tube diameter and joined by a membrane bar securely welded to the adjacent tubes. This results in a
continuous wall surface of rugged, pressure-tight construction capable of transferring the radiated heat
from the furnace gas to the water or steam-water mixture in the tubes. The width and length of individual
panels are suitable for economical manufacture and
assembly, with bottom and top headers shop-attached
prior to shipment for field assembly. Shipping clearances and erection constraints frequently govern size
limitations. The lower furnace walls of Cyclone-fired,
refuse, and fluidized-bed units use membrane construction with refractory lining.
Convection boiler surface
Some designs include boiler tubes as the first few
rows of tubes in the convection bank. The tubes are
spaced to provide gas lanes wide enough to prevent
ash and slag pluggage and to facilitate cleaning for dirty
fuels. These widely spaced boiler tubes, known as the
slag screen or boiler screen, receive heat by radiation
from the furnace and by both radiation and convection
from the combustion gases passing through them. Another option is the use of wide spaced water- or steamcooled surface (see Fig. 4) in the upper furnace. This
provides additional radiant heat transfer surface in the
furnace while allowing the furnace size to be optimized.
In the larger high pressure units, superheater surface generally forms the furnace outlet plane. The gas
temperature entering the superheater must be high
enough to give the desired superheat temperature with
a reasonable amount of heating surface and the use
of economical materials. The arrangements in Figs. 1
through 5 illustrate various configurations of superheater surface at the furnace outlet. To optimize superheater design, the furnace may also incorporate
widely spaced steam-cooled platens, as shown in Figs.
3 and 4, or wingwalls in the upper furnace. Fig. 10
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
Fig. 9 Membrane wall construction at burner openings.
Steam 41 / Boilers, Superheaters and Reheaters
Chapter 22 illustrates the determination of the
amount of radiation and convection boiler surface
required for a specified heat transfer.
Numerical analysis
When one-dimensional analysis and experimental
data are insufficient for design alone, three-dimensional numerical computer modeling can be used to
determine local heat transfer and flue gas conditions
in boilers, superheaters, and reheaters. These numerical tools are complex, multi-dimensional computer
Surface Spacing Perpendicular to Gas Flow (Plan View)
54 in.
(1372 mm)
24 in.
(610 mm)
12 in.
(305 mm)
9 in.
(229 mm)
4.5 in.
(114 mm)
Pendant
Reheater
Horizontal Banks
(Reheater and Primary
Superheater)
4.5 in.
(114 mm)
Gas
Flow
Platen
Primary
Radiant
Superheater
Pendant Secondary
Superheater
Furnace
Temperature
shows a plan arrangement of convection surface and
the change in average gas temperature.
Design of boiler surface after the superheater depends on the type of unit (industrial or utility), desired
flue gas temperature drop, and acceptable draft loss
through the boiler surface. The preceding Boiler design section of this chapter illustrates typical arrangements of boiler and superheater surface for various
types of boilers. The objective of convection heating
surface design is to establish the proper combination
of diameter, length, spacing, number, and orientation
of tubes, as well as gas baffling, to provide the desired
gas temperature drop with allowable flue gas resistance.
The quantity of heating surface (ft2 or m2) needed
in the gas-side design of convection surfaces for a
given load or duty (Btu/h or W) often inversely relates
to gas side flow resistance or pressure loss. Design
changes that increase resistance, such as tightening
tube spacing perpendicular to flow, result in higher
heat transfer rates (Btu/h ft2 or W/m2). This in turn
reduces the amount of heating surface needed to carry
the desired total thermal load. An optimal gas mass
flux and design result from balancing the capital cost
of the heating surface against the operating cost of fan
power and the maintenance costs due to flyash erosion.
For a given flue gas flow rate, a considerably higher
gas film heat transfer coefficient, heat absorption, and
draft loss result when the gases flow at right angles
to the tubes (cross flow) compared to flow parallel to
the tubes (long flow). Gas turns between tube banks
generally add draft loss and poor distribution with little
benefit to heat absorption. Turns leaving the upstream
bank and entering the downstream bank of tubes
should then be designed for minimum resistance and
optimum distribution.
Convection Pass
Average Gas Temperature
Outlet
Surface Location
Fig. 10 Schematic plan arrangement of convection surface and
change in average gas temperature.
19-7
The Babcock & Wilcox Company
codes that solve conservation equations for mass, momentum, energy, and species.
A numerical model of the superheater and/or reheater regions generally includes the boiler enclosure,
burners, and any other geometric aspects which may
affect the flow. Required numerical inputs include:
1. geometric data – boiler and heat exchanger surface configurations,
2. performance data – heat exchanger pressure drops
and heat absorptions,
3. operating data – stoichiometry and furnace exit
gas temperature,
4. burner setup – vane angles and turbulence intensity, and
5. fuel properties – fuel and flue gas quantities, composition and coal fineness, if applicable.
Numerical analyses fall into three general categories: 1) verification of proposed designs, 2) evaluation
of design modifications, and 3) investigation of localized
problems. Fig. 11 illustrates the use of numerical analysis to characterize the temperature profiles that exist at
the furnace exit of a typical coal-fired utility boiler.
Accurate modeling of boilers and boiler components
depends heavily upon the availability of information
to determine the proper inlet conditions, boundary
conditions, and fluid properties. Careful qualification
of the model is required and is augmented by known
global characteristics such as pressure drop and heat
absorption. Correct application of accurate information to develop numerical models will improve designs
and determine the cause of localized problems. See
Chapter 6 for an in depth discussion of three-dimensional numerical modeling.
Design of pressure parts
Boilers have achieved today’s level of safety and
reliability through the use of sound materials and safe
practices for determining acceptable stresses in drums,
headers, tubes, and other pressure parts. Boilers must
be designed to applicable codes. Stationary boilers in
the United States (U.S.) and many parts of the world
are designed to the American Society of Mechanical
Engineers (ASME) Boiler and Pressure Vessel Code.
(See Chapter 8 and Appendix 2.) The allowable design stress depends on the maximum temperature to
which the part is subjected; therefore, it is important
that pressure part design temperatures are known and
not exceeded in operation. Drum boiler enclosure
material temperatures are a function of upset spot
heat flux, design pressure, metal conductivity, and the
saturation temperature corresponding to the maximum boiler operating pressure. These parameters also
determine each tube’s outside diameter and thickness.
For boiler tubes, temperatures are maintained at
known levels by providing a sufficient flow of water to
prevent the occurrence of CHF, or critical heat flux phenomena. (See Chapter 5.) An adequate saturated water velocity must exist for each tube, and particular attention must be given to high heat flux zones and sloped
tubes with heat on top, such as furnace floor tubes.
Because steam drums have thick walls, it is necessary to limit the heat flow through them to avoid ex19-8
cessive thermal gradients during startup, shutdown,
and normal operation. This is particularly important
where the drum is exposed to flue gas. A number of
tube holes penetrate the drum, and the flow of water
through these holes serves to cool the drum wall.
Where the heat input through a drum would be too
high because of high gas temperature or velocity, insulation may be provided on the outside of the drum,
or the drum could be relocated out of the heat.
The required steam purity is dependant on the intended use of the steam being produced. The most
stringent requirements are typically associated with
power generation applications. Fundamental to maintaining steam purity is maintaining the feedwater
quality. (See Chapter 42.) In a drum boiler it is also
important to properly design the steam separation
equipment because entrained moisture will contain
dissolved solids. (See Chapter 5.) In a once-through unit
all of the moisture evaporates in the tubes, and steam
separation equipment is not a factor in steam purity.
Boiler safety valves constitute very important protection items to ensure the safe design and operation
of pressurized boiler components. (See Chapter 25.)
Before drum safety valve set pressures are established,
steam drum design pressure is determined by the pressure required at the point of use and the intervening
pressure drop. As an example, where the steam is used
in a turbine, the boiler operating pressure is determined by adding the turbine throttle pressure to the
pressure drop through the steam piping, nonreturn
valve, superheater, and drum internals at maximum
unit steam flow. As a practical matter, to avoid unnecessary losses and maintenance from frequent popping
of the safety valves, the first drum safety valve should
then be set to relieve at least 5% higher than drum
operating pressure. The ASME Code stipulates that the
boiler design pressure must not be less than the lowset safety valve relief pressure.
Boiler enclosure
Chapter 23 describes the methods used to provide
a tight boiler setting and a tight enclosure around the
superheater, reheater, economizer, and air heater.
Boiler supports
Furnace wall tubes are usually supported by the
headers to which they are attached, and generating
bank tubes and screens are supported by the drum or
headers to which they are connected. As discussed in
Chapter 8, the following considerations for proper
support design are important:
1. The tubes must be arranged and aligned so that
they are not subjected to excessive bending-moment stresses in supporting the weight of the
tubes, headers, drums, attachments, and fluid
within. When the unit is bottom supported, the
tubes must satisfy column buckling requirements.
2. The holding strength of the tube seats must not
be exceeded.
3. Provision must be made to accommodate the expansion of the pressure parts. For a top supported
unit, the hanger rods which support the pressure
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
Fig. 11 Numerical modeling results – flue gas temperatures at furnace exit.
parts from the structural steel must be designed
to swing at the proper angle. They must be long
enough to withstand the movement without excessive stresses in the rods or the pressure parts.
Bottom supported boilers should be anchored only
at one point, guided along one line, and allowed
to expand freely in all other directions. To reduce
the frictional forces and resultant stresses in the
pressure parts, roller saddles or mountings are desirable for bottom supported heavy loads.
Superheaters and reheaters
Advantages of superheat and reheat
When saturated steam is used in a turbine, the work
done results in a loss of energy by the steam and subsequent condensation of a portion of the steam, even
though there is a drop in pressure. The amount of
moisture the turbine can handle without excessive
turbine blade wear limits the amount of work the turbine can do. This is normally between 10% and 15%
moisture. It is possible to increase the amount of work
done with moisture separation between turbine
stages, but this is economical only in special cases.
Even with moisture separation, the total energy that
can be transformed to work in the turbine is small
compared to the amount of heat required to raise the
water from feedwater temperature to saturation and
then evaporate it. Therefore, moisture content constitutes a basic limitation in turbine design.
Because a turbine generally transforms the energy
of superheat into work without forming moisture, this
energy is essentially all recoverable in the turbine. The
temperature-entropy diagram of the ideal Rankine
cycle (shown in Chapter 2, Fig. 6) illustrates this.
While this is not always entirely correct, the Rankine
cycle diagrams in Chapter 2 indicate that this is essentially true in practical cycles.
Steam 41 / Boilers, Superheaters and Reheaters
The foregoing discussion is not specifically applicable at steam pressures at or above the critical pressure. In fact, the term superheat is not truly accurate
in defining the temperature of the working fluid in
this region. However, even at pressures exceeding
3200 psi (22.1 MPa), heat added at temperatures above
705F (374C) is essentially all recoverable in a turbine.
The reduction of cycle heat rate when steam temperatures entering the turbine are raised is an indication of the benefit of superheat. For example, in a
simple calculation of a 2400 psig (16.5 MPa) ideal
Rankine cycle with a single reheat stage, an increase
in superheat temperature from 900 to 1100F (482 to
593C) reduces the gross heat rate from approximately
7550 to 7200 Btu/kWh. This is more than a 4.5% efficiency improvement attributable to the superheat.
Superheater types
Two basic types of superheaters are available depending upon the mode of heat transfer from the flue gas.
One type is the convection superheater, for gas temperatures where the portion of heat transfer by radiation from
the flue gas is small. Convective heat transfer is highly
dependent on the characteristics of gas flow (i.e., quantity and velocity). At maximum load, or 100% steam
output, the gas weight is highest; therefore, heat transfer is also high. The higher heat absorption results in
higher steam temperatures leaving the superheater and
a higher boiler output, or higher total absorption in the
superheater per pound of steam. (See Fig. 12.)
A radiant superheater receives energy primarily by
thermal radiation from the furnace with little energy
from convective heat transfer. Radiant heat transfer
is highly dependent on the high flue gas temperatures
produced by the combustion of fuel. The steam temperature leaving the radiant superheater is lowest at
higher loads for two reasons. Radiant absorption does
not increase as rapidly as boiler output, and at higher
loads there is more steam to cool the effects of the ra19-9
The Babcock & Wilcox Company
diant absorption. (See Fig. 12.) The radiant superheater usually takes the form of widely spaced [24 in.
(609.6 mm) or larger side spacing] steam-cooled
wingwalls or pendant superheat platens located in the
furnace. It is sometimes incorporated into the furnace
enclosure as curtain walls.
In certain cases, the series combination of radiant
and convection superheaters coordinates the two opposite sloping curves to give a flat superheat curve
over a wide load range, as indicated in Fig. 12. A separately fired superheater can also be used to produce a
flat superheat curve.
The design of radiant and convective superheaters
requires extra care to avoid steam and flue gas distribution differences that could lead to tube overheating. Superheaters generally have steam mass fluxes
of 100,000 to 1,000,000 lb/h ft2 (136 to 1356 kg/m2 s)
or higher. These are set to provide adequate tube cooling while meeting allowable pressure drop limits. The
mass flux selected depends upon the steam pressure and
temperature as well as superheater thermal duty. In
addition, the higher pressure loss associated with higher
velocities improves the steam-side flow distribution.
Tube geometry
Cylindrical tubes of 1.75 to 2.5 in. (44.5 to 63.5 mm)
outside diameter are typical in current superheaters
and reheaters. Steam pressure drop is higher and alignment is more difficult with the smaller diameters, while
larger diameters result in thicker tubes.
Superheaters and reheaters are almost exclusively
made of bare tubes (see Fig. 13). Extended surface on
superheater tubes in the form of fins, rings, or studs
can increase metal temperature and thermal stress beyond tolerable limits.
Fig. 12 A substantially uniform final steam temperature over a range
of output can be attained by a series arrangement of radiant and
convection superheater components.
19-10
Relationships in superheater design
Effective superheater design must consider several
parameters including:
1. the outlet steam temperature specified,
2. the range of boiler load over which steam temperature is to be controlled,
3. the superheater surface required to give the specified steam temperature,
4. the gas temperature zone in which the surface is
to be located,
5. the type of steel, alloy or other material best suited
for the surface and supports,
6. the rate of steam flow through the tubes (mass flux
or velocity), which is limited by the permissible
steam pressure drop but that, in turn, exerts a
dominant control over tube metal temperatures,
7. the arrangement of surface to meet the characteristics of the anticipated fuels, with particular reference to the spacing of the tubes to prevent accumulations of ash and slag or to provide for easy
removal of these formations in their early stages,
and
8. the physical design and type of superheater as a
structure or component.
A change in any of these items may require a counterbalancing change in some or all of the other items.
The steam temperature desired in advanced power
station design is typically the maximum for which the
superheater designer can produce an economical component. Economics in this case requires the assessment
of two interrelated costs – initial investment and the
subsequent cost of upkeep to minimize operating problems, outages, and replacements. The steam temperature desired is based upon an iterative evaluation of
variations in parameters 3 through 7, past operating
experience, and the requirements of the particular
project. Operating experience has resulted in the use
Fig. 13 Typical superheater elements for a replacement project.
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
of 1000F (538C) to 1050F (566C) steam temperatures
for the superheat and reheat in many large utility
boilers. However, advances in tube materials have allowed designers to increase these temperatures without compromising the reliability or economics of the
units.
After the steam temperature is specified, the
amount of surface necessary to provide this superheat
must be established. This is dependent on parameters
5 through 8. Because there is no single correlation,
this quantity must be determined by iteration, locating the superheater in a zone of gas temperature that
satisfies the design criteria. In standard boilers, unit
arrangement and the space designated for superheater surface basically establishes the zone.
After the amount of surface is established for the
optimum location and tube spacing, the steam mass
flux or velocity, steam pressure drop, and superheater
tube metal temperatures are calculated considering
material options and thickness requirements. The
material determination is then made based on economic and functional optimization of the tubes, headers, and other components. It may be necessary to compare several arrangements to obtain an optimum combination that:
4 to 5% pressure drop for the reheat piping and valves
without exceeding the usual 8 to 10% total allowable
pressure loss. For economic reasons, the pressure drop
allocated for piping is usually distributed with onethird to the cold (inlet) reheat piping and two-thirds
to the hot (outlet) reheat piping.
1. requires an alloy of less cost,
2. gives a more reasonable steam pressure drop without jeopardizing the tube metal temperatures,
3. gives a higher steam mass flux or velocity to lower
tube temperatures,
4. gives the tube spacings that minimize ash accumulations and flyash erosion potential with various types of fuel,
5. permits closer spacing of the tubes, thereby making a more economical arrangement for a favorable fuel supply,
6. gives an arrangement of tubes that reduces the
draft loss for an installation where this parameter
evaluation is crucial, and
7. permits the superheater surface to be located in a
zone of higher gas temperature, with a subsequent
reduction of required surface.
Supports for superheaters and reheaters
Because superheaters and reheaters are located in
zones of relatively high gas temperature, it is preferable to have the major support loads carried by the
tubes themselves. For pendant superheaters, the
major support points are located outside of the gas
stream, with the pendant loops supporting themselves
in simple tension. Fig. 15 illustrates standard support
arrangements for a pendant superheater outlet section with major section supports above the roof line.
Tube materials
Oxidation resistance, allowable stress, and economics determine the materials used for superheater and
reheater tubes. The design process requires careful
attention to all of these criteria to develop an economical and reliable configuration. Chapter 7 gives additional information on these materials, including maximum metal temperatures.
Fig. 14 shows variations in basic superheater heat
transfer surface arrangements. These variations in
surface arrangement permit the economic tradeoff
between material unit costs and differences in the
quantity of surface required due to thermal-hydraulic considerations. The comparison of counter flow
versus parallel flow designs defines the basic relationships between heat transfer surface requirements and
the corresponding tube metal temperatures and requirements.
It is possible to achieve a practical design with optimum economic and operational characteristics and with
all criteria reasonably satisfied, but a large measure of
experience and the application of sound physical principles are required for best results. Chapter 22 gives the
calculation methods for superheater performance.
Relationships in reheater design
The fundamental considerations governing superheater design also apply to reheater design. However,
the pressure drop in reheaters is critical because too
much pressure loss through the reheater system can
nullify the gain in heat rate attained with the reheat
cycle.
Steam mass fluxes or velocities in reheater tubes
should be sufficient to keep the difference between the
bulk steam and metal surface temperature below 150F
(83C). As a result of the high velocities required, the
pressure drop through the reheater tubes is ordinarily
4 to 5% of reheater inlet pressure. This allows another
Steam 41 / Boilers, Superheaters and Reheaters
Fig. 14 Typical superheater heat transfer surface arrangements.
19-11
The Babcock & Wilcox Company
Where adequate side spacing is available, high chromium-nickel alloy ring-type guides are used. In addition, in the higher gas temperature zones, steamcooled side-to-side ties are used to maintain side spacings. For closer side spaced elements, steam-cooled
wraparounds are not practical and mechanical ties,
such as D-links, are used to maintain alignment as
shown in Fig. 16. In this case, the clear backspacing
between tubes and the size of attachments have been
kept to a minimum. This serves to reduce the thermal
stresses imposed on the tube wall. Fig. 16 also shows
a typical arrangement of a pendant reheater section
and illustrates the support of a separated bank by a
special loop of reheater, which permits all major supports to remain above the roof and out of the gas stream.
In horizontal superheaters, the support load is usually transferred to boiler or steam-cooled enclosure
tubes or economizer stringer tubes by lugs, one welded
to the support tubes and the other to the superheater
tubes as indicated in Fig. 17. These lugs are made of
carbon steel through high chromium-nickel alloy.
Depending upon design considerations, they must
slide on one another to provide relative movement
between the boiler tubes and the superheater tubes.
Saddle-type supports, also shown in Fig. 17, provide
for relative movement between adjacent tubes of the
superheater.
As units grow in size, the span of the superheater
tubes may become so great that it is impossible to endsupport these tubes. Most of the larger units use
stringer tubes (see Chapter 20 frontispiece), generally
hung from the economizer outlet, to support the superheater tubes. Saddle-type supports maintain tube
spacing within the section.
Internal cleaning
The internal cleaning of superheater and/or reheater surfaces is not normally required; however,
under certain circumstances these surfaces have been
chemically cleaned. Chapter 42 discusses this in depth.
During startup, steam line blowing is used to remove
residual scale, oils, and residual debris.
External cleaning and surface spacing
Most customers today are striving for long periods
of continuous operation, in some cases as long as 18
to 24 months between outages, so gas side cleanability
is critical. To enhance cleanability, the superheater sections (platens) of modern utility boilers are spaced according to the gas temperature and the fuel fired. Fig.
10 illustrates the spacing for pulverized coal-fired
units. The backspacing in the direction of gas flow is
usually set at 0.50 to 0.75 in. (12.7 to 19.1 mm) clear
space between tubes. These spacings are empirical;
they are based on tube fouling and erosion experience
and on manufacturing requirements. Chapter 24 discusses surface arrangement and cleanability under
Sootblowers.
Steam temperature adjustment and control
Fig. 15 Pendant superheater section with split ring casting supports.
19-12
Improvement in the heat rate of modern boiler units
and turbines results mostly from the high cycle efficiency possible with high steam temperatures.
Important reasons for accurate steam temperature
regulation are to prevent failures due to excessive
metal temperatures in the superheater, reheater, or
turbine; to prevent thermal expansion from dangerously reducing turbine clearances; and to avoid erosion
from excessive moisture in the last stages of the turbine.
The control of temperature fluctuations from variables of operation, such as slag or ash accumulation,
is also important.
With drum-type boilers, steam output is maintained
by firing rate, while the resulting superheat and reheat steam temperatures depend on basic design factors, such as total surface quantity and the ratio of
convection to radiant heat absorbing surface. Steam
temperatures are also affected by other important operating variables such as excess air, feedwater temperature, changes in fuel that affect burning characteristics, ash deposits on the heating surfaces, and the
specific burner combination in service. In the once-
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
The gas recirculation fan is used for controlling reheat steam temperature by extracting flue gas from the
economizer and injecting it into the furnace.
Fig. 16 Pendant reheater section with supports.
through boiler, which has a variable steam-water
transition zone, coordination of the firing rate and the
boiler feedwater flow rate control steam output pressure and temperature, leaving reheat steam temperature as a dependent variable. (See Chapter 26.) Standard performance practice for steam generating equipment usually permits a tolerance of ±10F (6C) in a
specific steam outlet temperature.
Definitions of terms
Adjustment is a physical change in the arrangement of heating surface that affects steam temperature, but can not be used to vary steam temperature
during operation. This could be the addition or deletion of component surface or boiler surface ahead of
the superheater and/or reheater.
Control is the regulation of steam temperature during operation without changing the arrangement of
surface. Examples are operation of attemperators, gas
proportioning dampers, and gas recirculation fans.
The attemperator is an apparatus for reducing and
controlling the temperature of a superheated fluid
passing through it. This is accomplished by spraying
high purity water into an interconnecting steam pipe
usually between superheater stages or upstream of a
reheater inlet.
The gas proportioning damper is used to control reheat
steam temperatures. The damper opens to split the flow of
hot flue gas between the superheater and reheater.
Steam 41 / Boilers, Superheaters and Reheaters
Effect of operating variables
Many operating variables affect steam temperatures in drum-type units. To maintain constant steam
temperature, means must be provided to compensate
for the effect of these variables.
Load As load increases, the quantity and temperature of the combustion gases increase. In a convection
superheater (see Superheater types), steam temperature increases with load with the rate of increase being less for superheater surfaces located closer to the
furnace. In a radiant superheater (see Superheater
types), steam temperature declines as load increases.
Normally a proportioned combination of radiant and
convection superheater surface is installed in series in a
steam generating unit to maintain steam temperature
as constant as possible over the load range. (See Fig. 12.)
Excess air For a change in the amount of excess
air entering the burner zone there is a corresponding
change in the quantity of gas flowing over the convection superheater; therefore, an increase in excess
air generally raises the steam temperature. However,
the degradation of boiler efficiency due to the addition of excess air usually more than offsets the improvement in heat rate, making this technique uneconomical other than in special circumstances.
Feedwater temperature Decreasing the feedwater
temperature by taking a feedwater heater out of service will increase the fuel input required to generate
a given amount of steam. This will result in high gas
weights and temperatures, which will yield higher
steam temperatures in the superheater.
Heating surface cleanliness Removal of ash deposits from heat absorbing surfaces ahead of the superheater reduces the temperature of the gas entering
the superheater and, subsequently, the steam temperature. Removal of deposits from the superheater
surface increases superheater absorption and raises
steam temperature.
Use of saturated steam If saturated steam from the
boiler is used for sootblowers or auxiliaries, such as
pump or fan drives, an increased firing rate is required to maintain constant main steam output. This
raises the steam temperature.
Fig. 17 Horizontal superheater section end supports on walls.
19-13
The Babcock & Wilcox Company
Blowdown The effect of blowdown (water bled from
the boiler drum or steam supply system to reduce contaminants) is similar to the use of saturated steam, but
to a lesser degree because of the low enthalpy of water as compared to steam.
Burner operation The distribution of heat input
among burners at different locations or a change in
burner adjustment usually has an effect on steam
temperature due to changes in furnace heat absorption rate.
Fuel Variations in steam temperature may result
from changing the type of fuel burned or from day to
day changes in the characteristics of a given fuel.
Adjustment
Steam generating equipment represents a large,
long-term capital investment. Over the life of the
equipment, it is not unusual for the quality of the fuel
or even the steam requirements to change. Ideally,
provisions would be made in the original design to
accommodate the modifications required by such
changes. However, economics and space limitations
often limit the designers ability to incorporate these
provisions. As a result, if such changes do occur during the life of the equipment, it will usually be necessary to have the new conditions and/or fuel reviewed
to determine what design changes can be made within
the constraints imposed by the existing equipment.
Control
Control is necessary to regulate steam temperature
within required limits in order to correct fluctuations
caused by operating variables – particularly boiler
load. Besides boiler load variation, ash deposition on
heat transfer surfaces and fuel variations are the most
frequent cause of steam temperature fluctuations.
Changes in the sequence or frequency of sootblower
operation can usually correct this condition. Selective
operation of furnace wall blowers or implementation
of unit load reductions to induce slag shedding from
the furnace walls can reduce gas temperatures entering the superheater surfaces. The removal of feedwater heaters or pulverizers from service can also impact
steam temperature and require steam temperature
control.
The turbine manufacturer in accordance with a safe
steam temperature-time curve establishes the time in
which a turbine may be brought to full load. Because
the temperature of the steam is directly related to the
degree of expansion of the turbine elements and, consequently the maintenance of safe clearances, this
temperature must be regulated within permissible limits by an accurate control device.
Among the means of control for regulating steam
temperature are: attemperation, gas proportioning
dampers, gas recirculation, excess air, burner selection, movable burners, divided furnace with differential firing, and separately fired superheaters. With
attemperation, diluting high temperature steam with
low temperature water or removing heat from the steam
regulates steam temperature. By comparison, the other
methods of control are based on varying the amount of
heat absorbed by the steam superheating surfaces.
19-14
Attemperation Attemperators may be classified as
two types – direct contact and surface. The spray type
exemplifies the direct contact design, where the steam
and the cooling medium (water and saturated steam)
are mixed. In the surface design, which includes the
shell type and the drum type, the steam is isolated from
the cooling medium by the heat exchanger surface.
Spray attemperators are usually preferred on all units
that have attemperation requirements; however, surface type attemperators are occasionally used on some
industrial units.
The superheater attemperator may be located either at some intermediate point between two sections
of the superheater, or at the superheater outlet. The
ideal location for the superheater attemperator for the
purpose of process control is at the superheater outlet. Control would be direct and there would be no time
lag. However, problems with this location include possible water carryover into the turbine and overheating of superheater tubes. Placing the superheater
attemperator between superheater stages addresses
these concerns, and is generally preferred. In addition, the attemperation fluid so thoroughly mixes with
steam from the first stage superheater that it enters
the second stage superheater at a uniform temperature. For reheat superheater applications, the
attemperator is typically located at the reheater inlet.
The superheater spray attemperator, illustrated in
Fig. 18, has proven most satisfactory for regulating
steam temperature. High purity water is introduced
into the superheated steam line through a spray
nozzle at the throat of a venturi section within the line.
Because of the spray action at the nozzle and the high
velocity of the steam passing through the venturi
throat, the water vaporizes and mixes with the superheated steam reducing the steam temperature. An
important construction feature is the continuation of
the venturi section into a thermal sleeve downstream
from the spray nozzle. This protects the high temperature piping from thermal shock. This shock could result from non-evaporated water droplets striking the
hot surface of the piping. The reheat attemperator is
similar but does not have a venturi section.
The spray attemperator provides a quick acting and
sensitive control for regulating steam temperature. It
is important that the spray water be of highest purity, because solids entrained in the water enter the
Fig. 18 Spray attemperator showing thermal sleeve.
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
steam and may cause troublesome deposits on superheater tubes, piping, or turbine blades. High-pressure
heater drains are a source of extremely pure water, but
require a separate high pressure corrosion resistant
pump if used for attemperator supply. Normally, boiler
feedwater is satisfactory, provided condenser leakage and
makeup do not introduce too much contamination.
Three attemperator arrangements are possible, depending on the boiler performance requirements:
1. Single-stage attemperator A single attemperator
may be installed in each of the connecting pipes
between two stages of superheat.
2. Tandem attemperator A single-stage attemperator
with two spray water nozzles may be installed in
series in the connecting pipe between two stages
of superheat. This arrangement is used where the
spray quantity exceeds the capacity of a single
nozzle or where the required turndown can not be
achieved with a single spray water nozzle. The
usual application requires a spray control valve
for each spray nozzle. The operation is sequential
with the control valve for the downstream spray
nozzle opening first and closing last.
3. Multiple-stage attemperator Multiple single-stage
attemperators are used. A spray control valve is
required for each stage of spray. The first stage
spray attemperator is used first, with the maximum
spray flow based on a minimum allowable difference between the temperature of the steam leaving the attemperator and the saturation temperature. When the flow limit is reached on the first stage,
the subsequent stages are activated sequentially.
The attemperation system branches from the feedwater piping. The boiler feed pump provides water
pressure for all of the piping to the steam drum and
the line to the attemperation system. In most instances, the pressure loss from the boiler feed pump
through the feedwater heaters, piping, economizer
and primary superheater to the attemperator location
inside the connecting piping results in a boiler feed
pump discharge pressure high enough to provide the
required pressure differential in the attemperator
system. The attemperator system pressure must be
higher than the superheater steam pressure for
proper operation. In certain cases, the feed pump discharge pressure is not sufficient due to low pressure
loss in the boiler and feedwater system, or due to the
high pressure differential the spray systems require
to suit particular boiler characteristics. For these situations, a booster stage in the boiler feed pump is desirable to raise the spray water to the required pressure. Other options are a separate spray water booster
pump or an additional feed line valve to increase boiler
side resistance at the required loads.
In the past, there were problems in industrial steam
power cycles involving deposits in the superheater and
on turbine blading, which resulted in failures. Many
of these problems were due to impurities in the
attemperator spray water. To assure high quality spray
water, additional cleanup equipment can be installed
on the condensate return and feedwater makeup.
For low-pressure units with feedwater purity less
Steam 41 / Boilers, Superheaters and Reheaters
than that required for spray attemperation, the condenser attemperator system is an economical and reliable system used to produce high quality spray water. (See Chapter 27.)
Drum and once-through boilers may use steam
attemperation at very low loads, as described in the
Bypass and startup section of this chapter.
UP boiler attemperator applications UP boilers are
supplied with superheater spray attemperators to reduce variations in superheater outlet temperatures
during transients. These attemperators may be single
or multiple stage. Spray water is supplied from the UP
boiler economizer inlet or directly from the boiler feed
pump. Spray attemperation corrects main steam temperature deviations only on a temporary basis and is
not the primary means of steam temperature control.
Under steady-state conditions, the ratio of firing rate
to feedwater flow determines steam temperature.
Gas proportioning dampers As shown in Fig. 4, the
horizontal convection tube banks in the back end of a
boiler can be divided into two or more separate flue
gas passes separated by a baffle wall. The use of dampers in these gas passes then permits proportioning of
the gas over the heat transfer surfaces and the control of reheat and superheat temperatures.
Design considerations for such systems include the
following:
1. Dampers must be placed in a cool gas zone to assure maximum reliability (typically downstream
of all boiler heat transfer surfaces).
2. Draft loss through the unit could increase for some
designs, particularly with alternate fuels, so this
parameter must be optimized.
3. Control system design and tuning are critical because
damper control response is slower than with spray
attemperators. Therefore, spray attemperators are
used for transient control.
4. Under maximum bias conditions, when one
damper is almost completely closed and the other
is open, the gas temperatures at the dampers and
the heat transfer surfaces nearest the dampers will
be at their highest. These temperatures then set
the tube metal design requirements.
Gas proportioning dampers are combined with spray
attemperation for overall optimal steam temperature
control systems. Spray attemperators provide for shortterm transient temperature control. The gas proportioning dampers provide longer-term control and adjustment
between superheat and reheat temperatures with a
minimum impact on overall unit efficiency.
Gas recirculation Another method of controlling
superheat or reheat is flue gas recirculation. As the
name implies, gas from the boiler, economizer, or air
heater outlet is reintroduced to the furnace by fans
and flues. For the sake of clarity, recirculated gas introduced in the immediate vicinity of the initial burning zone of the furnace and used for steam temperature control is referred to as gas recirculation, and
recirculated gas introduced near the furnace outlet
and used for control of gas temperature is referred to
as gas tempering. Fig. 19 shows an application of gas
recirculation through the hopper bottom and gas tem19-15
The Babcock & Wilcox Company
pering in the upper furnace of a Radiant boiler. In
most instances, the gas is obtained from the economizer outlet. The recirculated gas must be introduced
into the furnace in a manner that avoids interference
with the fuel combustion. The amount of recirculated
gas is expressed as a percentage of the sum of combustion gas weight and setting infiltration.
While recirculated gas may be used for several purposes, its basic function is to alter the heat absorption
pattern within a steam generating unit. Recirculated
gas has the special advantage of providing heat absorption adjustment for use as a design factor in initial surface arrangement, and as a method of controlling the heat absorption pattern under varying operating conditions.
Excess air An increase in the amount of excess combustion air in a drum type unit decreases the furnace
heat absorption. At fractional loads, the increase in
excess air and the decrease in absorption work together
to increase the steam outlet temperature of a convection superheater. The resulting greater weight of gas sent
to the stack increases the stack loss; however, the increase
in turbine efficiency can offset some of this loss.
Burner selection It is often possible to regulate
steam temperature by selective burner operation.
Higher steam temperatures may be obtained at less
than full load by operating only the burners giving
the highest furnace outlet temperature. When steam
temperature reduction is required, firing may be
shifted to the lower burners. Distributing the burners over an extended height of the burner wall can
improve this method of control.
Movable burners Using movable burners to raise
or lower the main combustion zone in the furnace can
also affect the regulation of steam temperature by
changing the furnace absorption pattern. Tilting
burners are used for this purpose.
Differentially-fired divided furnaces In some divided
furnaces, the superheater receives heat from one section of the furnace only, while the other section of the
furnace generates only saturated steam or may include a reheater. Changing the proportion of fuel input between the two furnace sections regulates the
steam temperature. This arrangement, similar in principle to the separately-fired superheater, was formerly
widely used in marine practice. The differentially-fired
divided furnace method of steam temperature control
is no longer in use today.
Separately-fired superheaters A superheater that is
completely separate from the steam generating unit
and independently fired may serve one or more saturated steam boilers. This arrangement is not economical for power generation, where a large quantity of
high temperature steam is needed.
Bypass and startup systems
High pressure drum and once-through boilers must
be capable of rapid, frequent, and reliable unit
startups, and rapid load changes, to provide the most
economical electrical production. During startup or low
load (less than 20%) conditions in which outlet steam
temperature tends to follow flue gas temperature,
regular water attemperator steam temperature control systems are not sufficiently sensitive to cool the
steam, as only a small amount of attemperation is
required at low steam loads. However, provisions must
still be made to match the differing flow, pressure, and
temperature needs of the steam turbine and boiler. To
address these special requirements, a variety of bypass and startup systems have been developed for
drum and once-through boilers.
Fig. 19 Radiant boiler with gas tempering for gas temperature
control and gas recirculation for control of furnace absorption and
reheat temperature.
19-16
UP boiler startup systems
A key requirement of UP startup and bypass systems is the need for minimum design circulation flows
in high heat absorbing circuits for cooling before the
unit can be fired. Additional important features include
providing a turbine bypass until steam pressures and
temperatures are matched, reducing the bypass flow
pressure and temperature before condenser and auxiliary equipment steam admission, recovering heat
during startup, providing clean water for full startup,
accelerating the startup processes, and providing
greater unit flexibility through dual pressure boiler
operation. UP boilers, while originally designed for
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
base load operation, have been adapted to daily load
and on/off cycling. The variable furnace pressure system is capable of on/off cycling, while the constant
furnace pressure system is capable of daily low load
operation on the bypass system.
Three different UP systems are available – one for
constant furnace pressure operation over the load
range and two for variable furnace pressure operation over the load range; however, only one variable
furnace pressure system will be discussed in detail.
Spiral wound variable pressure startup system For
variable furnace pressure systems, the startup system
is equipped with pipes, valves, steam-water separators, and a water collection tank. Fig. 20 shows the
general arrangement. The startup system controls operation during startup, shutdown, and minimum load
operation. The spiral wound universal pressure
(SWUP™) once-through boiler requires a minimum
flow in the furnace circuits before the boiler can be
fired. The flow must remain above this minimum flow
during boiler operation. For loads where the steam flow
falls below the minimum, the startup system maintains
the necessary minimum steam flow through the boiler
circuitry and supplies steam to the turbine that was
provided to the superheater from the vertical steam
separators.
Typical operation Using the boiler feed pump (BFP),
water fills the economizer, furnace, vertical steam separator (VSS), and water collecting tank (WCT) until the
WCT reaches normal level. The economizer vent valve
(302) opens to vent air from the economizer to the separators. If the WCT water level rises above normal, the
separator (WCT) high level control valves (341) will open
to control the WCT water level.
During cold startup, the water must circulate
through the water cleanup system until feedwater
impurities reach an acceptable level before the boiler can
be fired. Water flows through the condenser, polishers,
and heaters to the boiler, and returns to the condenser
by way of the 341 valves. Flow rate is approximately
30% maximum continuous rating (MCR) from the BFP
to the condenser at this stage.
After water quality is established, the feedwater
flow from the BFP to the boiler is reduced to about 7%
MCR flow, where about 4% MCR flows into the economizer to avoid steaming economizer conditions, and
about 3% MCR flows to the water collecting tank
(WCT) through the subcooling control valve (383). The
383 valve controls the amount of subcooled water to
the WCT, protecting the boiler circulation pump (BCP).
Provided that the pump cooling system is in service,
temperatures are within limits, the BCP inlet shutoff
valve (380), the BCP recirculation valve (382), and
the 383 valves are all open, the BCP is started, supplying flow to the economizer. The flow from the BFP
combined with flow from the BCP provides minimum
flow to the boiler. The WCT level control valve (381),
which ensures flow to the furnace is over the mini-
Boiler System
Reheat
Superheater
Spray Water
Attemperator
Water
Attemperator
Secondary
Superheater
Low Pressure
Turbine
Primary
Superheater
Vertical
Steam
Separators
Convection
Pass
Enclosure
Furnace
Enclosure
Economizer
Legend
101
Control Valve
Turbine
Throttle
Valves
High Pressure
Turbine
302
Water Collecting
Tank
384 384C
381
382
380
Generator
341B 341
383C
Condenser
Strainer
Boiler
Circulation
Pump
Economizer
Nonreturn Valve
Intermediate
Pressure
Turbine
383
383B
Condensate
Pump
100
Shutoff Valve
Nonreturn Valve
Main Flow
Feedwater
Control
Valves
High
Pressure
Feedwater
Heater
Boiler
Feed
Pump
Deaerator
Low
Pressure
Feedwater
Heater
Startup System
Polishing
System
Fig. 20 Spiral wound universal pressure boiler startup system – variable pressure furnace operation.
Steam 41 / Boilers, Superheaters and Reheaters
19-17
The Babcock & Wilcox Company
culation valve (382) opens to protect the BCP by providing sufficient flow, while the 383 valve begins to
close. The BCP flow to the economizer inlet decreases,
requiring the flow from the BFP to increase. When
steam load reaches approximately 15%, the spray
water attemperators release to control steam temperature for the cold turbine. Firing rate and steam temperature control operate in a manner similar to that
of a steam drum boiler until the boiler transition point,
the load at which the boiler becomes once-through and
the startup system is no longer required.
At the transition to once-through, the fluid to the
VSS is all steam, causing the WCT level to drop. As the
WCT goes dry, the 381 valve closes to maintain WCT
level. The BCP shuts down and the 383 valve closes.
The 341 opens if the WCT level briefly becomes high.
All steam is sent to the VSS and the BFP provides feedwater flow equal to the steam flow to the VSS; thus,
the unit is in once-through operation.
Beyond the boiler transition point the startup system is no longer necessary, and the startup system
warming system is placed into service. At 35% load the
separator high level control block valve (341-B) closes.
The warming system control valve (384) opens fully
at 40% load to keep the startup system warm, and
mum flow required, opens, and tries to maintain the
WCT level. With no steam flow, the 381 valve will not
be able to regulate the fluid level of the WCT; therefore, the 341 valve controls the level until steam flow
exceeds feedwater flow. When the BCP flow is above
minimum, the 382 valve will close.
Once the circulation is established, the boiler is fired.
A short time after firing, steam bubbles start forming
in the furnace, causing a rapid expulsion of excess
water to the vertical steam separator and WCT. The
341 valves will open quickly to control the WCT level.
As steam begins to form, some is contained for pressure, some is sent to boiler drains and vents, and the
balance is used for steam line warming and eventually flows to the turbine. Once the steam production
exceeds the total feedwater flow from the BFP, about
7% MCR, the WCT level will fall causing the 341
valves to close and the 381 valves to take control of
the WCT level. The separator high level control block
valves (341) are open in the event that an upset causes
a high fluid level in the WCT and the 341 valves are
forced to open. The feedwater pump system maintains
the furnace flow at a minimum.
As steam production continues to increase, the 381
valve closes to control the WCT level. The BCP recir-
Boiler System
Reheat Steam Attemperator
Reheat
Superheater
Water
Attemperator
Superheat Steam Attemperator
401
Secondary
Superheater
Low
Pressure
Turbine
Turbine
Throttle
Valves
200
Water
Attemperator
Intermediate Pressure
Turbine
High Pressure
Turbine
Primary
Superheater
Convection
Pass
Enclosure
205
218B
205C
218
Generator
219B
219
Steam
Drain
Line
207
Furnace
Enclosure
210
Flash Tank
Economizer
242
240 240B
Condenser
Economizer
Nonreturn Valve
220
220B
Legend
230
231
241 241B
231B
230B
Condensate
Pump
Control Valve
Shutoff Valve
Nonreturn Valve
Main Flow
Startup System
Feedwater
Control
Valves
Auxiliary Steam
High
Pressure
Feedwater
Heater
Boiler
Feed
Pump
Deaerator
Low
Pressure
Feedwater
Heater
Polishing
System
Fig. 21 Universal pressure boiler startup system – constant pressure furnace operation.
19-18
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
closes with increasing load, as more pressure differential is available to drive the warming flow. The 384
valve provides warm flow to the BCP, the 380 line, the
382 line, and the 341 line.
Constant furnace pressure startup system For constant furnace pressure the startup system has the
steam separator (flash tank) located in a bypass that
can be isolated from the boiler during normal operation. Fig. 21 shows the general arrangement.
Typical operation The boiler feed pump supplies the
minimum required flow of feedwater during startup
and low load operation to protect the furnace circuitry.
Included in the startup circuitry are the economizer,
furnace, and convection pass enclosures, and primary
superheater.
The fluid leaving the primary superheater, at full
pressure, is diverted through the pressure reducing
valve (207) to the flash tank, where the steam-water
mixture is separated during startup.
Drain valves 230 and 241 control the water level
in the flash tank, with the 230 valve controlling flow
to the deaerator for maximum heat recovery. Excess
water above the capability of the deaerator is discharged to the condenser through valve 241. If the
drains are not within water quality limits (see Chapter 42), all of the flow is through valve 241 to the condenser and polishing system. When water quality is
acceptable, the 230 valve provides flash tank water
to the deaerator for maximum heat recovery.
The 242 block valve remains closed until a level is
established in the flash tank to assure that water does
not enter the steam lines. Once a level is established, the
242 valve is opened and flash tank steam is provided to
the deaerator for heat recovery and replacing deaerator
auxiliary steam. The deaerator pressure is controlled
with the 231 valve. Any excess steam not needed by the
deaerator is first sent to the high pressure heater (220
valve), then excess steam not needed by the high pressure heater is sent to the condenser (240 valve).
Flash tank steam is provided to the secondary superheater inlet by the low pressure superheater
nonreturn valve (205), secondary superheater low
pressure control valve (205C), and associated piping.
The 205 valves normally open at 300 psig (2.07 MPa),
sending dry steam to the secondary superheater for
warming steam lines. The turbine bypass valve (210)
normally opens at 300 psig (2.07 MPa) main steam
pressure to assist with warming and boiling out the
superheater during the initial stage of startup. When
sufficient steam is available, the turbine is rolled and
placed on line.
The 240 valve relieves excess steam separated in
the flash tank to the condenser. This valve also acts
as an overpressure relief valve to avoid tripping spring
loaded safety valves on the flash tank. The 240 valve
has an adjustable set point, which can be set to hold
various flash tank pressures at particular load points
during startup.
The entire bypass system is sized to handle minimum required flow during startup and to permit operating up to the once-through load on the flash tank.
Turbine load is increased from synchronization to
once-through by increasing the boiler firing rate. As
Steam 41 / Boilers, Superheaters and Reheaters
load is increased, the 220, 230, 231, 240, and 241
valves will close to provide a higher and higher percentage of the minimum boiler flow as steam from the
flash tank to the turbine.
The transition from bypass system to once-through
operation is made at the load corresponding to the
minimum required flow, typically 25%. At this load,
the steam entering and leaving the flash tank is
slightly superheated, and all steam entering the flash
tank goes to the superheater and turbine. By this load,
the 220, 230, 231, 240, and 241 valves are all closed.
The transition is made, at constant load, by slowly
opening the superheater division valve (401). Opening the 401 causes the 200 block valve to go fully open,
and the 207 valve to close to maintain boiler pressure.
When the 207 valve is fully closed, the boiler is off the
bypass system and the load can be increased. This
method provides a very smooth and controlled transition from bypass to once-through operation.
Variable throttle pressure Above the minimum oncethrough load, the unit can be operated at constant or
variable throttle pressure. To operate with variable
throttle pressure, the 401 valve is used to vary throttle
pressure across the load range, while maintaining full
boiler pressure in the upstream circuits. This is called
dual or split pressure operation. To operate with constant throttle pressure, the 401 valve is fully opened,
with all throttling done by the turbine control valves.
The variable throttle pressure feature permits operating the unit with the throttle valves essentially
wide open, and has three main advantages. First, this
eliminates turbine metal temperature changes resulting from valve throttling and permits rapid load
changes without being limited by turbine heating or
cooling rates. Second, there can be a low load plant heat
rate benefit. Third, shutdown with variable pressure
maintains high temperatures in the turbine metals at
low loads for reduced turbine stress from load cycling.
Steam temperature control The means for controlling
main steam and reheat temperatures at normal operating loads are not effective during startup or very low
loads. The startup system shown in Fig. 21 includes
provision for steam attemperation from the flash tank
to the main and reheat steam outlet headers. Steam
attemperation precisely controls steam conditions during startup to meet the turbine metal temperature
requirements.
The superheater outlet steam attemperator valve
(218) is used at loads less than 20% to introduce saturated steam from the flash tank to the superheater
outlet header. Initial rolling of the turbine, for a cold
start, may be done with saturated steam passing from
the flash tank through the 218 valve. This steam may
be mixed with a limited quantity of steam passing
through the 205 valves and the secondary superheater to control the high pressure turbine inlet temperature down to about 550F (288C). The 205C control valve achieves the necessary pressure drop between the flash tank and the secondary outlet header
to allow steam attemperation to work.
The reheat outlet steam attemperator valve (219)
is used at loads below about 20% of full load to introduce flash tank steam to the reheat outlet header. The
19-19
The Babcock & Wilcox Company
ratio of flow through the attemperator valve to that
through the high pressure turbine is limited mainly
for turbine and turbine control considerations.
Overpressure relief The bypass system is also used
to relieve excessive pressure in the boiler during a load
trip. The use of the 207 valve, which sends excess
steam to the flash tank, accomplishes this.
Bypass retrofits The above bypass system would be
provided with any new UP constant furnace pressure
boiler. Currently in operation are a variety of UP bypass systems that range from similar to vastly different than those described above. Many of these older
units had their bypass systems retrofitted to incorporate some or all of the above features to improve operational flexibility and ease of startup.
Drum boiler bypass system
The B&W Radiant boiler bypass system minimizes
startup time, controls shutdowns in anticipation of
restarts, provides control of steam temperature to
match turbine metal temperature, and allows dual
pressure operation of the boiler and turbine for better load response. These features reduce stresses in
the turbine for improved turbine availability and reduced maintenance costs. The drum boiler bypass
system consists of an engineered system of steam
valves and piping, as shown in Fig. 22.
This flexible bypass system can conform to most
operating changes. For example, it can adapt to a turbine malfunction by adjusting the steam temperature
and flow through any load range from synchronization to high load points. Although the bypass system
enhances unit operation, the boiler can be operated
as a conventional non-bypass unit at any time.
Operation
Dual pressure The drum boiler bypass system has
a combination of valves consisting of a superheater
stop valve (500) and a superheater stop valve bypass
valve (501), which allows dual pressure operation.
During dual pressure operation, the 501 valve controls the throttle pressure independently from the
drum pressure. This permits constant pressure operation of the major boiler components and variable pressure operation of the turbine. A dual pressure shutdown
keeps the boiler near full pressure and the turbine metal
near maximum temperature in preparation for a quick
restart, thus minimizing thermal stresses in the boiler
and turbine. In addition, it allows more rapid load
changes than full variable boiler pressure operation.
The 501 valve is a control valve typically sized for
about 70% of full load steam flow. This permits dual
pressure operation up to approximately 70% load. This
percentage will vary depending on the specifics of the
542
High
Pressure
Turbine
Boiler System
Low
Pressure
Turbine
Intermediate
Pressure
Turbine
Steam Drum
Water
Attemperator
519
Primary
Superheater
518
Generator
519B
501
518B
Turbine
Throttle
Valves
500
Superheat
Steam
Attemperator
Secondary
Superheater
Turbine
Throttle
Valve
Condenser
Water
Attemperator
Reheat
Superheater
Reheat
Steam
Attemperator
Economizer
Legend
502
Economizer
Nonreturn Valve
Control Valve
Condensate
Pump
Shutoff Valve
Nonreturn Valve
Main Flow
Startup System
Feedwater
Control
Valves
High
Pressure
Feedwater
Heater
Boiler
Feed
Pump
Deaerator
Low
Pressure
Feedwater
Heater
Fig. 22 Drum boiler bypass system schematic.
19-20
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
steam turbine. The 500 valve is a stop valve, which is
pulsed open after the 501 is open. Once the 500 valve
is completely open, the unit will operate in a constant
pressure mode, with the turbine control valves opening to provide the increase from 70 to 100% load.
Steam attemperation The main steam outlet
attemperator valve (518) and reheat outlet
attemperator valve (519) are used for steam
attemperation at low loads, when the normal water
attemperation is not effective. Slightly superheated
steam is mixed in the outlet headers, via special header
internal nozzles, to produce a lower main and reheat
steam temperature. Thus, the boiler can be fired to
produce drum pressure and steam quickly without
concern for the steam temperature to the turbine, reducing startup time and thermal stress in the turbine.
The 518 and 519 valves are used for cold and warm
Steam 41 / Boilers, Superheaters and Reheaters
startups, when the turbine metal temperature is low.
Drum pressure control The primary superheater
bypass valve (502) controls drum pressure independent of firing rate. This allows the boiler to be fired to
maximum furnace exit gas temperature producing the
high steam temperature needed by the turbine for a
hot startup, without concern for the drum pressure rising above maximum allowable pressure. The excess
steam bypasses the primary and secondary superheater, to help provide maximum steam temperature.
A primary superheater bypass shutoff valve (542)
assures tight shutoff when the 502, 518, and 519
valves are closed.
Startup without bypass system The unit can be
started and operated without use of the bypass system. Fully opening the 500 valves allows a conventional drum boiler startup.
19-21
The Babcock & Wilcox Company
Superheater installation in a coal-fired utility boiler.
19-22
Steam 41 / Boilers, Superheaters and Reheaters
The Babcock & Wilcox Company
Chapter 20
Economizers and Air Heaters
Economizers and air heaters perform a key function in providing high overall boiler thermal efficiency
by recovering the low level (i.e., low temperature) energy from the flue gas before it is exhausted to the
atmosphere. For each 40F (22C) that the flue gas is
cooled by an economizer or air heater in a conventional boiler, the overall boiler efficiency increases by
approximately 1% (Fig. 1). Economizers recover the
energy by heating the boiler feedwater; air heaters
heat the combustion air. Air heating also enhances the
combustion of many fuels and is critical for pulverized
coal firing to dry the fuel and ensure stable ignition.
In contrast to the furnace waterwalls, superheater
and reheater, economizers and air heaters require a
large amount of heat transfer surface per unit of heat
recovered. This is because of the relatively small difference between the flue gas temperature and the temperature of either the feedwater or the combustion air.
Use and arrangement of the economizer and/or air
heater depend upon the particular fuel, application,
boiler operating pressure, power cycle, and overall
minimum cost configuration.
Increasingly stringent environmental regulations
limiting nitrogen oxides (NOx) and sulfur dioxide (SO2)
emissions can also affect economizer and air heater
design. Selective catalytic reduction (SCR) systems for
NOx control operate within an optimal flue gas temperature range, and the arrangement and/or operation of the economizer may need to be modified accordingly. In the United States (U.S.), there has been a
substantial increase in the use of low-sulfur Powder
River Basin (PRB) coal to reduce SO2 emissions. However, PRB coal ash has high fouling and plugging
characteristics that prohibit extended surface economizers and require the use of sootblowers throughout
the boiler.
Economizers
Economizers are basically tubular heat transfer
surfaces used to preheat boiler feedwater before it
enters the steam drum (recirculating units) or furnace
surfaces (once-through units). The term economizer
comes from early use of such heat exchangers to reduce operating costs or economize on fuel by recovering extra energy from the flue gas. Economizers also
reduce the potential of thermal shock and strong water temperature fluctuations as the feedwater enters
the drum or waterwalls. Fig. 2 shows an economizer
location on a coal-fired boiler. The economizer is typically the last water-cooled heat transfer surface upstream of the air heater. (See chapter frontispiece.)
Economizer surface types
Fig. 1 Approximate unit efficiency increase due to an economizer and
air heater in conventional boilers.
Steam 41 / Economizers and Air Heaters
Bare tube
The most common and reliable economizer design
is the bare tube, in-line, crossflow type. (See Fig. 3a.)
When coal is fired, the flyash creates a high fouling
and erosive environment. The bare tube, in-line arrangement minimizes the likelihood of erosion and
trapping of ash as compared to a staggered arrangement shown in Fig. 3b. It is also the easiest geometry
to be kept clean by sootblowers. However, these benefits must be evaluated against the possible larger
weight, volume and cost of this arrangement.
20-1
The Babcock & Wilcox Company
Steam Platen Secondary Secondary
Drum
Superheater
Superheater
Reheat
Superheater
Attemperator
Primary
Superheater
Economizer
Furnace
SCR
Gas
Outlet
Air Heater
Fig. 4 Longitudinal fins, staggered tube arrangement. (Fin width
exaggerated for clarity.)
Pulverizer
Forced Draft Primary Air
Fan
Fan
Fig. 2 Economizer and air heater locations in a typical coal-fired boiler.
Fig. 3 Bare tube economizer arrangements.
20-2
Extended surfaces
To reduce capital costs, most boiler manufacturers
have built economizers with a variety of fin types to
enhance the controlling gas-side heat transfer rate.
Fins are inexpensive parts which can reduce the overall size and cost of an economizer. However, successful application is very sensitive to the flue gas environment. Surface cleanability is a key concern. In
selected boilers, such as PRB coal-fired units, extended
surface economizers are not recommended because of
the peculiar flyash characteristics.
Stud fins Stud fins have worked reasonably well in
gas-fired boilers. However, stud finned economizers
can have higher gas-side pressure drop than a comparable unit with helically-finned tubes. Studded fins
have performed poorly in coal-fired boilers because of
high erosion, loss of heat transfer, increased pressure
loss and plugging resulting from flyash deposits.
Longitudinal fins Longitudinally-finned tubes in
staggered crossflow arrangements, shown in Fig. 4,
have also not performed well over long operating periods. Excessive plugging and erosion in coal-fired
boilers have resulted in the replacement of many of
these economizers. In oil- and gas-fired boilers, cracks
have occurred at the points where the fins terminate.
These cracks have propagated into the tube wall and
caused tube failures in some applications. Plugging
with flyash can also be a problem (tight spaces).
Fig. 5 Helically-finned tube.
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
Helical fins Helically-finned tubes (Fig. 5) have
been successfully applied to some coal-, oil- and gasfired units. The fins can be tightly spaced in the case
of gas firing due to the absence of coal flyash or oil
ash. Four fins per inch (1 fin per 6.4 mm), a fin thickness of 0.06 to 0.075 in. (1.5 to 1.9 mm) and a height
of 0.75 in. (19.1 mm) are typical. For 2 in. (51 mm)
outside diameter tubes, these fins provide ten times
the effective area of bare tubes per unit tube length.
If heavy fuel oil or coal is fired, a wider fin spacing
must be used and adequate measures taken to keep
the heating surface as clean as possible. Economizers
in units fired with heavy fuel oil can be designed with
helical fins, spaced at 0.5 in. (13 mm) intervals.
Smaller fin spacings promote plugging with oil ash,
while greater spacings reduce the amount of heating
surface per unit length. Sootblowers are required and
the maximum bank height should not exceed 4 to 5 ft
(1.2 to 1.5 m) to assure reasonable cleanability of the
heating surface. An in-line arrangement also facilitates cleaning and provides a lower gas-side resistance.
Rectangular fins The square or rectangular fins, arranged perpendicular to the tube axis on in-line tubes
as shown in Fig. 6, have been used occasionally in
retrofits. The fin spacing typically varies between 0.5
and 1 in. (13 and 25 mm) and the fins are usually
0.125 in. (3.18 mm) thick. There is a vertical slot down
the middle because the two halves of the fin are welded
to either side of the tube. Most designs are for gas
velocities below 50 ft/s (15.2 m/s). However, because
of the narrow, deep spaces, plugging with flyash is a
danger with such designs.
Baffles The tube ends should be fully baffled (Fig.
7) to minimize flue gas bypass around finned bundles.
Such bypass flow can reduce heat transfer, produce
excessive casing temperatures, and with coal firing
can lead to tube bend erosion because of very high gas
velocities. Baffling is also used with bare tube bundles
but is not as important as for finned tube bundles. Tube
bend erosion can be alleviated by shielding the bends.
Fig. 7 Baffling of bare tube return bends for finned tube bundles.
maximum economical pressure loss. For high ash oil
and coal, gas-side velocities are limited by the erosion
potential of the flyash. This erosion potential is primarily determined by the percentage of Al2O3, and
SiO2 in the ash, the total ash in the fuel and the gas
maximum velocity. Experience dictates acceptable flue
gas velocities. Fig. 8 provides sample base velocity limits as a function of ash characteristics. Note: PRB coal
contains ash with low erosion potential. Velocities above
70 ft/s (21.3 m/s) can typically be allowed for such coals.
Further criteria may also be needed. For example,
a 5 ft/s (1.5 m/s) reduction in the base velocity limit is
recommended when firing coals with less than 20%
volatile matter. In other cases, such as Cyclone boilers, high flue gas velocities can be used because much
Velocity limits
The ultimate goal of economizer design is to achieve
the necessary heat transfer at minimum cost. A key
design criterion for economizers is the maximum allowable flue gas velocity (defined at the minimum
cross-sectional free flow area in the tube bundle).
Higher velocities provide better heat transfer and reduce capital cost. For clean burning fuels, such as gas
and low ash oil, velocities are typically set by the
Fig. 6 Rectangular fins, in-line tube arrangement.
Steam 41 / Economizers and Air Heaters
Fig. 8 Base maximum allowable velocity for pulverized coal-fired
boiler economizers.
20-3
The Babcock & Wilcox Company
less flyash is carried into the convection pass, as much
of the ash (> 50%) is collected in the bottom of the boiler
as slag. Particles that enter the boiler furnace are also
less erosive. (See Chapter 15.)
For a given tube arrangement and boiler load, the
gas velocity depends on the specific volume of flue gas
which falls as the flue gas is cooled in the economizer.
To maintain the gas velocity, it can be economical to
decrease the free flow gas-side cross-section by selecting a larger tube size in the lower bank of a multiple
bank design. This achieves better heat transfer and
reduces the total heating surface.
Other types of economizers
Fig. 9 depicts an industrial boiler with a longflow
economizer, often used in chemical recovery boilers.
Such heating surfaces consist of vertical, longitudinally-finned (membraned) tubes through which the
feedwater flows upward. The gas flows downward in
pure counterflow, outside the tubes and fins. While
the heat transfer is less efficient than crossflow banks
of tubes, there is minimal gas-side resistance and fouling products are removed through hoppers at the bottom of the enclosure.
Steaming economizers
Steaming economizers are defined as meeting the
following enthalpy relationships:
H 2 − H1 ≥ 2
3
(H
f
− H1 )
(1)
where
H2 = enthalpy of fluid leaving economizer (to drum)
H1 = enthalpy of fluid (water) entering economizer
H f = enthalpy of saturated water at economizer
outlet pressure
These economizers can be economical in certain
boilers. They require careful design and must be oriented so the water flows upward and the outlet is below drum level. This avoids water hammer and excessive flow instabilities. The enthalpy equation accounts
for possible steaming due to flow imbalances and differences in individual circuit heat absorptions.
High-pressure, drum-type units are usually sensitive to feedwater temperatures close to saturation. To
enhance circulation, feedwater temperature to the
drum should normally be at least 50F (28C) below
saturation temperature. However, for some applications, due to specific design conditions, use of Equation 1 may result in a feedwater temperature slightly
greater than 50F (28C) below saturation temperature.
Performance
Heat transfer
Bare tubes The equations discussed in Chapter 4
can be used to evaluate the quantity of surface for an
economizer. For the economizer shown in Fig. 2 with
the upflow of water and downflow of gas and
nonsteaming conditions, the bundle can be treated as
an ideal counterflow heat exchanger with the following characteristics:
1. bundle log mean temperature difference correction
factor = 1.0,
2. heat absorbed by the tube wall enclosures and
heat radiated into the tube banks from various
cavities can generally be neglected,
3. all of the energy lost by the flue gas is absorbed
by the water, i.e., no casing heat loss,
4. the water-side heat transfer coefficient is typically
in the range of 2000 Btu/h ft2 F (11,357 W/m2 K)
and has only a small overall impact on the economizer performance, and
5. the effect of gas-side ash deposition can be accounted
for by a cleanliness factor based upon experience.
In general the heat transfer rate is primarily limited by the gas-side heat transfer for in-line bare tube
bundles. In this case, the overall heat transfer coefficient (flue gas to feedwater) used in the heat exchanger calculation can be approximated by the following relationship:
U = 0.98 ( hc + hr ) kf
Fig. 9 Longflow economizer for a chemical recovery boiler.
20-4
(2)
where
U = overall heat transfer coefficient, Btu/h ft2 F
(W/m2 K)
h c = gas-side heat transfer coefficient for a bare
tube bundle, Btu/h ft2 F (W/m2 K) (Chapter
4, Equations 60 and 61)
h r = inter-tube radiation heat transfer coefficient,
Btu/h ft2 F (W/m2 K) ≈ 1.0 for coal firing (for
finned tubes hr, is very small and is assumed
to be 0)
kf = surface effectiveness factor = 0.7 for coal, 0.8
for oil and 1.0 for gas
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
Finned tubes Heat transfer performance of finned
tube economizers can be evaluated in a similar fashion except that appropriate relationships for extended
surfaces should be used. In addition, because the gasside heat transfer has been enhanced, the water-side
heat transfer coefficient and tube wall thermal resistance are more significant and must be included in the
evaluation. (See Chapter 4.) As a general guideline,
the overall heat transfer coefficient can be approximated by the following relationship for most types of
economizer fins:
U = 0.95 ( hg kf )
(3)
where hg is the gas-side heat transfer coefficient for
the heat transfer across finned tube bundles evaluated with the procedures defined in Chapter 4. A calculated example is provided in Chapter 22 for a bare
tube economizer tube bundle.
Gas-side resistance
The gas-side pressure loss across the economizer
tube bank can be evaluated using the crossflow correlations presented in Chapter 3. The pressure loss
should be adjusted for the number of tube rows using
the correction factors provided. The gas-side resistance
across the in-line finned tube banks is approximately
1.5 times the resistance of the underlying bare tubes.
Water-side pressure drop
The water-side pressure loss can be evaluated using the procedures in Chapter 3 where the total pressure loss ∆PT is calculated:
∆PT = ∆Pf + ∆Pl + ∆Pz
(4)
∆Pf = friction pressure loss
∆Pl = sum of the local losses
(entrance, bends and exits)
∆Pz = static head loss
Ch. 3, Eq. 47
Ch. 3, Eq. 52
where
Fig. 10 Economizer supports – sample waterwall support arrangement.
analyzing the allowable deflection in the tubes and
tube assemblies. Deflection is important for tube
drainability. Figs. 10 through 12 show typical support
arrangements for bare tube economizers.
Wall or end supports are usually chosen for relatively short spans and require bridge castings or individual lugs welded or attached to the tube wall enclosures. (See Fig. 10.) Another possibility exists if enclosure wall (usually primary superheater circuitry)
headers are present above the economizer (for example, Fig. 11).
Quarter point stringer supports are used for spans
exceeding the limits for end supports (Fig. 12). The
stringers are mechanically connected to the economizer
sections, which are held up by ladder type supports.
The supports exposed to hot inlet gases may be made
Ch. 5, Eq. 10
The design pressure is then evaluated by the sum
of the drum design pressure and the total pressure loss
∆PT rounded up to the nearest 25 psig (172 kPa).
If the calculated water-side pressure drop is excessive, the number of parallel flow paths must be increased. If the flue gas velocity can be increased, the
water-side pressure drop can also be reduced by increasing the tube size, usually in increments of 0.125
in. (3 mm). As indicated in Chapter 3, the dynamic
pressure drop is inversely proportional to the fifth
power of the inside tube diameter.
Economizer support systems
Economizers are located within tube wall enclosures
or within casing walls, depending on gas temperatures. In general, casing enclosures are used at or
below 850F (454C) and inexpensive carbon steel can
be used. If a casing enclosure is used, it must not support the economizer. However, tube wall enclosures
may be used as supports.
The number of support points is determined by
Steam 41 / Economizers and Air Heaters
Fig. 11 Economizer supports – sample lower waterwall header
arrangement.
20-5
The Babcock & Wilcox Company
cated inside the gas stream and may receive feedwater
through one or both ends. Regardless of design, it is
necessary to properly seal the inlet pipe where it penetrates the enclosure by using brackets and flexible
seals. The seal becomes especially important in pressurized (forced draft) units. Other important considerations are tube leg flexibility, differential expansion
and potential gas temperature imbalances and upsets.
The outlet headers, not to be confused with intermediate or transition headers seen in larger boilers
and stringer supports, receive the heated feedwater
and convey it to the drum or, in the case of oncethrough boilers, to the downcomer(s) supplying the
furnace circuitry. Inlet and outlet headers must be
large enough to assure reasonable water flow distribution in the economizer banks. Flow velocities in
headers are typically less than 20 ft/s (6.1 m/s).
Vibration ties
Fig. 12 Economizer supports – sample stringer support arrangement.
of stainless steel, while lower grade material is normally used to support the lower bank which is exposed
to reduced gas temperatures. In The Babcock & Wilcox Company (B&W) designs, stringer tubes also usually support other horizontal convection surfaces
above the economizer. (See frontispiece.) Bottom support is sometimes used if the gas temperature leaving
the lowest economizer bank is low enough.
Bank size
The bank size is limited by the following constraints:
1.
2.
3.
4.
5.
type of fuel,
fabrication limits,
sootblower range,
maximum shipping dimensions,
construction considerations, especially for retrofits,
and
6. maintenance.
Bank depths greater than 6 ft (1.83 m) are rare in
new boilers, while carefully designed larger banks can
be tolerated in retrofits.
Access requirements
Cavities around the banks are needed for field welding, tube leg maintenance and sootblower clearance.
A sufficient number of access doors must be arranged
in the enclosure walls to access these cavities. Cavity
access can be provided from the outside through individual doors or from the inside through special openings across stringers or collector frames. The minimum
cavity height should be 2 ft (0.6 m) of crawl space.
Headers
B&W economizer header designs are typically based
on American Society of Mechanical Engineers (ASME)
Code requirements. Inlet headers are frequently lo20-6
Vibration ties or tube guides are required on some
end-supported tube sections. These ties may be needed
if the natural frequencies within the boiler load range are
in or near resonance with the vortex shedding frequency.
Stringer tubes are also subject to vibration. This vibration is magnified by long unsupported stringer tube
lengths near the large cavity below the convection
pass roof.
Tube geometry, materials and code
requirements
Economizer tube diameters typically range between
1.75 and 2.5 in. (44.5 and 63.5 mm). Tubes outside this
range are sometimes used in retrofits. Smaller tubes are
normally used in once-through, supercritical boilers
where water-side pressure drop is less of a consideration.
In these units, tube wall thicknesses are minimized.
The ASME Code requires that the design temperature for internal boiler pressure parts is at least 700F
(371C). The calculated mean tube wall temperature
in economizers seldom reaches this temperature. It
usually lies 10 to 20F (6 to 11C) above the fluid temperature, which seldom exceeds 650F (343C) along
any economizer circuit.
The minimum tube wall thickness is determined in
accordance with procedures outlined in Chapter 8.
In coal-fired boilers, the side spacing is usually determined by the maximum allowable gas velocity and
gas-side resistance, which are functions of a given tube
size. If fins are used, the side and back tube spacings
should permit the fin tips to be at least 0.5 in. (13 mm)
apart. For bare tubes, a minimum clear spacing of 0.75
in. (19 mm) is desirable.
PRB coal firing usually calls for increased clear side
spacing to avoid plugging and bridging with flyash
in the horizontal spaces.
The minimum back (vertical) spacing of the tubes
should be no less than 1.25 times the tube outside diameter. Smaller ratios can reduce heat transfer by as
much as 30%. Ratios larger than 1.25 have relatively
little effect on heat transfer but increase the gas-side
resistance and bank depth.
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
SCR considerations
SCR systems are normally located between the
economizer and the air heater. NOx reduction reactions
take place within an optimal temperature range as the
flue gas passes through the catalyst reactor (see Chapter 34). Therefore, flue gas temperature entering the
SCR is critical to system performance.
Typical temperature control methods include:
1. Gas bypass The goal is to maintain a minimum
gas temperature to the SCR, typically 600F (316C)
to 650F (343C) for coal-fired applications, over the
boiler load range in which the SCR will be operated. This can be achieved by extracting flue gas
from a cavity above the economizer or between
economizer banks, and routing the higher temperature gas to a point upstream of the SCR where
it is mixed with lower temperature gas from the
economizer outlet. The gas flow through the bypass flue is controlled by a damper.
In retrofits, the bypass gas flow is usually limited by the available gas-side pressure differential and maximum allowable gas velocity through
the bypass flue. Existing physical constraints limit
the maximum flue size. The increase in flue gas
temperature entering the SCR reduces boiler efficiency due to an increase in flue gas temperature leaving the unit. To reduce this loss in boiler
efficiency, a separate economizer bank can be installed downstream of the SCR or additional air
heater surface can be added if space is available.
2. Water-side bypass Water-side parameters (i.e.,
mass flow) indirectly control the flue gas temperature exiting the economizer by reducing the water flow through some of the economizer surface,
thus reducing economizer heat absorption. (Instead of a gas-side damper controlling the gas
bypass flow, several control valves regulate water flow to the various economizer banks.) Economizer water outlet temperature should not exceed
certain limits dictated by furnace circulation.
3. Duct burners Special duct burners (usually natural gas fired) are sometimes used to raise the gas temperature entering the SCR. However, the economics of natural gas firing must be carefully evaluated.
heaters enhances combustion of all fuels and is
needed for drying and transporting the fuel in pulverized coal-fired units.
Classification of air heaters
Air heaters are classified according to their principle
of operation as recuperative or regenerative.
Recuperative
In a recuperative heat exchanger, heat is transferred continuously and directly through stationary,
solid heat transfer surfaces which separate the hot
flow stream from the cold flow stream. The most common heat transfer surfaces are tubes and parallel
plates. Recuperative heat exchangers function with little
cross-contamination, or leakage, between streams.
Tubular air heaters In a typical tubular air heater,
energy is transferred from the hot flue gas flowing
inside many thin walled tubes to the cold combustion
air flowing outside the tubes. The unit consists of a
nest of straight tubes that are roll expanded or welded
into tubesheets and enclosed in a steel casing. The
casing serves as the enclosure for the air or gas passing outside of the tubes and has both air and gas inlet and outlet openings. In the vertical type (Fig. 13),
tubes are supported from either the upper or lower
tubesheet while the other (floating) tubesheet is free
to move as tubes expand within the casing. An expansion joint between the floating tubesheet and casing
provides an air/gas seal. Intermediate baffle plates
parallel to the tubesheets are frequently used to separate the flow paths and eliminate tube damaging flow
induced vibration.
Carbon steel or low alloy corrosion resistant tube
materials are used in the tubes which range from 1.5
to 4 in. (38 to 102 mm) in diameter and have wall
Air heaters
Air heaters are used in most steam generating
plants to heat the combustion air and enhance the
combustion process. Most frequently, the flue gas is
the source of energy and the air heater serves as a
heat trap to collect and use waste heat from the flue
gas stream. This can increase the overall boiler efficiency by 5 to 10%. Air heaters can also use extraction steam or other sources of energy depending upon
the particular application. These units are usually employed to control air and gas temperatures by preheating air entering the main gas-air heaters.
Air heaters are typically located directly behind the
boiler, as depicted in Fig. 2, where they receive hot flue
gas from the economizer and cold combustion air from
the forced draft fan(s). The hot air produced by air
Steam 41 / Economizers and Air Heaters
Fig. 13 Vertical type tubular air heater.
20-7
The Babcock & Wilcox Company
thicknesses of 18 to 11 gauge [0.049 to 0.120 in. (1.24
to 3.05 mm)]. Larger diameter, heavier gauge tubes
are used when the potential for tube plugging and corrosion exists. Tube arrangement may be in-line or staggered with the latter being more thermally efficient.
Tubular air heaters may be fitted with steam or air
sootblowers to remove ash accumulations from the gasexposed side of tubing during operation. Permanent
water wash piping above gas-side tube banks may
also be used off line to soak and wash tube internal
or external surfaces.
The most common flow arrangement is counterflow
with gas passing vertically through the tubes and air
passing horizontally in one or more passes outside the
tubes. A variety of single and multiple gas and air path
arrangements are used to accommodate plant layouts.
Designs frequently include provisions for cold air bypass or hot air recirculation to control cold end corrosion and ash fouling. Modern tubular air heaters are
shop assembled into large, transportable modules.
Several arrangements are shown in Fig. 14.
Cast iron air heaters Cast iron tubular air heaters
are heavy, large and durable. Their use is mainly limited to the petrochemical industry, but some are used
on electric utility units. Cast iron is used because of
its superior corrosion resistance. Rectangular, longitudinally split tubes are assembled from two cast iron
plates and individual tubes are assembled into air
heater sections. Air heaters are usually arranged for
a single gas pass and multiple air passes with air flow
inside the tubes. Heat transfer is maximized by fins
cast into inside and outside tube surfaces.
Plate air heaters Plate air heaters transfer heat from
hot gas flowing on one side of a plate to cold air flowing on the opposite side, usually in crossflow. Heaters
consist of stacks of parallel plates. Sealing between air
and gas streams at plate edges is accomplished by
welding or by a combination of gaskets, springs and
external compression of the plate stack. Plate materials and spacing can be varied to accommodate operating requirements and fuel types.
Steel plate air heaters were some of the earliest types
Fig. 14 Various tubular air heater arrangements.
20-8
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
used, but their use declined due to plate to plate sealing problems. However, sealing developments have
prompted increased use in industrial and small utility applications. Plate modules may be combined to
make different size air heaters with a variety of flow
path arrangements. A single gas pass, two air pass
plate air heater is shown in Fig. 15. Modern plate units
are somewhat smaller than tubular units for a given
capacity and exhibit minimal air to gas leakage.
Steam coil air heaters Steam coil and water coil recuperative air heaters are widely used in utility steam
generating plants to preheat combustion air. Air preheating reduces the corrosion and plugging potential
in the cold end of the main air heater. Occasionally,
they serve as the only source of preheated combustion air. These heaters consist of banks of small diameter, externally finned tubes arranged horizontally or
vertically in ducts between the combustion air fan and
main air heater. Combustion air, passing in crossflow
outside the tubes, is heated by turbine extraction
steam or feedwater flowing inside the tubes. Ethylene glycol is sometimes used as the hot fluid to prevent out of service freezing damage.
Regenerative
Regenerative air heaters transfer heat indirectly by
convection as a heat storage medium is periodically
exposed to hot and cold flow streams. A variety of
materials can be used as the medium and periodic
exposure to hot and cold flow streams can be accomplished by rotary or valve switching devices. In steam
generating plants, tightly packed bundles of corrugated steel plates serve as the storage medium. In these
units either the steel plates, or surface elements, rotate
through air and gas streams, or rotating ducts direct air
and gas streams through stationary surface elements.
Regenerative air heaters are relatively compact and
are the most widely used type for combustion air preheating in electric utility steam generating plants.
Their most notable operating characteristic is that a
small but significant amount of air leaks into the gas
stream due to the rotary operation.
Ljungström The most common regenerative air
heater is the Ljungström ® type (Figs. 16 and 17),
which features a cylindrical shell plus a rotor which
is packed with bundles of heating surface elements
and is rotated through counterflowing air and gas
streams. The rotor is enclosed by a stationary housing which has ducts at both ends. Air flows through
one half of the rotor and gas flows through the other
half. Metallic leaf-type seals minimize air to gas leakage and flow bypass around the rotor. See Fig. 18.
Bearings in upper and lower beam assemblies support
and guide the rotor at the central shaft. A rotor speed
of one to three rpm is provided by a motor driven pinion engaging a rotor encircling pinrack. Both vertical
and horizontal shaft designs are used to accommodate
various plant air and gas flow schemes. The vertical
shaft design is more common.
The most prevalent flow arrangement has the hot
gas entering the top of the rotor as cold air enters the
bottom in counterflow fashion, as shown in Fig. 16.
Heaters employing this flow scheme are identified as
Steam 41 / Economizers and Air Heaters
Fig. 15 Single gas pass, two air pass plate air heater.
hot end on top and cold end on bottom. In operation,
the rotor is subjected to a temperature differential, hot
top and cold bottom, causing the rotor to expand and
bow (or distort) upward. This rotor distortion opens
gaps between the rotor and stationary parts through
which objectionable air-side to gas-side leakage occurs.
Air to gas leakage is controlled by cold-presetting
axial and radial seal plates to minimize gaps at the
hot operating condition (Fig. 19). Note that a significant radial gap remains at the hot end which is tolerated in industrial and small utility boiler air heaters.
However, for controlling leakage in larger units the
hot end radial sealing plate is designed to adjust automatically during operation to follow rotor distortion
and maintain a minimum seal gap.
Sootblowing devices in the gas outlet are used to
direct superheated steam or dry air via nozzles into
the rotor heating surface elements to periodically clean
them of fuel residue accumulations during operation.
For especially heavy or tenacious deposits, sootblowers may also be used at the air heater gas inlet.
Air heaters operating in dirty flue gas streams (coal,
oil, waste, biomass, etc.) are also fitted with permanent water wash piping for soaking and cleaning
heavy heating surface ash accumulations. The wash
piping is located in the top of the heater above the rotor
with nozzles arranged such that all heating surface
elements are exposed to the nozzle spray pattern as
the rotor turns. Air heaters are normally washed off-
20-9
The Babcock & Wilcox Company
Fig. 16 Ljungström-type air heater.
Fig. 17 Air heater service project at a midwest U.S. power plant.
20-10
line as the rotor is turned via an auxiliary drive. Air
heater washing through sootblowers may also be done
with appropriate piping and valves.
Rothemühle The Rothemühle®-type regenerative
air heater uses stationary surface elements and rotating ducts (Fig. 20). The surface elements are supported
and contained within a stationary cylindrical shell
called the stator. On both sides of the stator, a double
wing symmetrical hood rotates synchronously on a
common vertical shaft. The central shaft is supported
by bearings within the stator and the hoods are driven
slowly by a pinion which engages a pinrack encircling
the lower hood. Stationary housings surround the
hoods. Heat is transferred as flow streams are directed
through the heating surface in counterflow fashion,
one flow stream inside the hoods and the other outside.
Either air or gas may pass through the hoods. However,
air is more common because it requires less fan power.
Rothemühle air heater stators distort in a manner
similar to Ljungström rotors. Special sealing systems
mounted to rotating hoods at the interface with the stator are used to control leakage. Both preset and automated seal systems are used. Sealing at the rotating hood
to stationary duct interface is maintained by a ring of
spring-backed cast iron seal shoes and a rotating race.
Sootblowers mounted to the outside of rotating
hoods are employed on cold and hot ends as fuels dictate. Water wash piping both inside the hoods (rotat-
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
Radial Leaf Seal
Cold Condition
Hot Operation
Automatic Radial Seal
Plate Drive
Sealing Surface
Adjuster or Actuator
Radial
Seal Plate
Radial Sealing Plate
Axial
Seal
Plate
Cold End Radial Seal Plate
Axial Seal
Fig. 19 Cross-section through air heater rotor and seal plates.
Circumferential
Bypass Seal
Sealing Surface Adjuster
Radial Leaf Seal
ment. Heavy gauge, open profile elements are used for
corrosion resistance and cleanability. Practically all cold
layer elements are low alloy corrosion resistant steel or,
when high corrosion potential exists, porcelain enamel
coated steel. Hot and intermediate surface layers are
more compact than cold layers and use thinner plates.
Fig. 21 illustrates several heating surface element profiles and air heater surface arrangements.
Axial Sealing Plate
Axial Leaf Seal
Fig. 18 Ljungström-type air heater seals.
ing piping) and outside the hoods (stationary piping)
assures complete coverage of the heating surface.
Special sootblower and rotating wash piping seals are
used at the rotating-stationary interface.
Regenerative heating surface Regenerative air
heater surface elements are a compact arrangement
of two specially formed metal plates. Each element
pair consists of a combination of flat, corrugated or undulated plate profiles. The roll formed corrugations
and undulations serve to separate the plates to maintain flow paths, increase heating surface area and
maximize heat transfer by creating flow turbulence.
The steel plates, 26 to 18 gauge thick, are typically
spaced 0.2 to 0.4 in. (5 to 10 mm) apart. Closely spaced,
highly profiled element pairs exhibit a high heat
transfer rate, pressure drop and fouling potential while
widely spaced element combinations, where one plate
is flat, exhibit a low heat transfer rate, low pressure
drop and reduced fouling potential. The combination
of plate profile, material and thickness is selected for
maximum heat transfer, minimum pressure drop,
good cleanability and high corrosion resistance.
Surface elements are stacked and bundled into selfcontained baskets and are installed into air heater
rotors and stators in two or more layers. The surface
layer at the air inlet side, designated the cold layer, is
distinguished from other layers by design. Cold layers, which are subject to corrosion and ash fouling, are
typically 12 in. (305 mm) deep for economical replace-
Steam 41 / Economizers and Air Heaters
Fig. 20 Rothemühle-type air heater.
20-11
The Babcock & Wilcox Company
and radiation components as well as the appropriate
gas- and air-side fouling factors. U typically ranges
from 3 to 10 Btu/h ft2 F (17 to 57 W/m2 K).
Performance verification Thermal performance is
measured by comparing the test gas outlet temperature to its design value. The true outlet temperature
is obtained by correcting the measured temperature for
air heater leakage and deviations from design conditions.
The ASME Performance Test Code, Section 4.3 (PTC
4.3), provides the following equation which is based
on an air heater mass flow heat balance and assumes
that the source of all leakage is from the entering air:
% lkg c pa
T2 = T2m +
100 c pg
(T2m − T1 )
(6)
where
= air heater gas outlet temperature corrected for leakage, F (C)
T2m
= measured gas temperature leaving air
heater, F (C)
% lkg = percent air leakage with respect to inlet
gas flow
cpa, cpg = specific heat of air and gas respectively,
Btu/lb F (J/kg C)
T1
= air inlet temperature, F (C)
T2
The measured gas outlet temperature must also be
corrected for deviations in various operating parameters such as mass flow rates and operating temperatures in order to accurately assess performance. Suppliers and the ASME Performance Test Codes provide
various correction curves and factors for this purpose.
Fig. 21 Regenerative air heater surface element profiles.
Advantages and disadvantages
Many subtle differences exist between air heater
designs within a particular type. However, there are
some general advantages and disadvantages associated with each type which are listed in Table 1.
Performance and testing
Air heaters are designed to meet performance requirements in three areas: thermal, leakage and pressure
drop. Low performance in any area increases boiler operating costs and may cause unit load curtailment.
Thermal performance
The thermal performance and surface area (A) of a
recuperative air heater can be evaluated by:
A = q / (U LMTD F )
(5)
where q is the rate of heat transfer [Btu/h (W)], U is
the overall heat transfer coefficient, LMTD is the log
mean temperature difference between the hot and
cold fluids, and F is the heat exchanger arrangement
factor. The performance, U, LMTD and F can be evaluated using the correlations and methodology presented
in Chapter 4. The overall U should include convection
20-12
Leakage
Air flow passing from the air side to the gas side is
called leakage. It is quantified in pounds per hour (kg/s)
but is frequently expressed as a percentage of the gas
inlet flow. Leakage is undesirable primarily because
it represents fan power wasted in conveying air which
bypasses the boiler combustion zone. Leakage can also
reduce an air heater’s thermal performance.
Recuperative units may begin operation with essentially zero leakage, but leakage occurs as time and
thermal cycles accumulate. With regular maintenance, leakage can be kept below 3%. Air heater leakage is inherent with the rotary regenerative design.
There are two types of leakage, gap and carryover.
Table 1
Advantages and Disadvantages of Air Heater Types
Type
Advantage
Disadvantage
Recuperative
Low leakage
No moving parts
Large and heavy
Difficult to replace
surface
Regenerative
Compact
Easy to replace
surface
Leakage
High maintenance
Fire potential
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
Gap leakage occurs as higher pressure air passes to
the lower pressure gas side through gaps between
rotating and stationary parts. Its rate is given by the
following general expression:
wl = KA ( 2 gc ∆P ρ )
1/2
(7)
the square of the mass flow rate. Typical values at full
load flows are 2 to 7 in. wg (0.5 to 1.7 kPa).
Air- and gas-side pressure drop values are the differences between terminal inlet and outlet static gauge
pressures. Correction of measured pressure drops for
deviations from design flows and temperatures is
necessary before comparison to design values.
where
wl = leakage flow rate, lb/h (kg/s)
K = discharge coefficient, dimensionless (generally 0.4 to 1.0)
A = flow area, ft2 (m2)
g c = 32.17 lbm ft/lbf s2 × (3600 s/h)2 =
4.17 × l08 lbm ft/lbf h2 (1 kg m/N s2)
∆P = pressure differential across gap, lb/ft2 (kg/m2)
ρ = density of leaking air, lb/ft3 (kg/m3)
Carryover leakage is the air carried into the gas
stream from each rotor (stator) heating surface compartment as the surface passes from the air stream to
the gas stream. This leakage is directly proportional
to the void volume of the rotor and the rotation speed.
Regenerative air heater design leakage ranges from
5 to 15% but increases over time as seals wear. Effective automatic sealing systems, which nearly eliminate leakage rise due to seal wear, have been successfully applied. These systems monitor and adjust rotating to stationary seals on-line.
Another source of boiler air to gas flow leakage,
which appears as air heater leakage, is outside air infiltration into lower pressure gas streams. Infiltration
may occur at casing cracks or holes, flue expansion
joints and access doors or gaskets. This sometimes neglected source can be significant and difficult to detect if leaks occur under lagging and insulation.
Air heater leakage can be obtained directly as the
difference between air- or gas-side inlet and outlet
flows based on velocity measurements. However, because velocity measurements are difficult to obtain
accurately in large duct cross-sections, air heater leakage is more accurately based on calculated gas weights
using gas analysis, boiler efficiency and fuel analysis
data. (See Chapter 10.) Approximate air heater leakage can be determined by the following formula based
on gas inlet and outlet oxygen (O2) analysis (dry basis).
% Leakage =
% O2 Leaving − % O2 Entering
× 90
21 − % O2 Leaving
Operational concerns
There are several operating conditions and maintenance concerns common to most air heaters. These
include corrosion, plugging and cleaning, leakage performance degradation, erosion and fires. Air heaters
used with high ash and/or high sulfur content fuels
require more attention and maintenance than those
firing clean fuels such as natural gas.
Corrosion
Air heaters used on units firing sulfur bearing fuels are subject to cold end corrosion of heating elements
and nearby structures. In a boiler, a portion of the
sulfur dioxide (SO2) produced is converted to sulfur
trioxide (SO3) which combines with moisture to form
sulfuric acid vapor. This vapor condenses on surfaces
at temperatures below its dew point of 250 to 300F
(121 to 149C). Because normal air heater cold end
metal temperatures are frequently as low as 200F
(93C), acid dew point corrosion potential exists. The
obvious solution would be to operate at metal temperatures above the acid dew point but this results in unacceptable overall boiler heat losses. Most air heaters
are designed to operate at minimum metal temperatures (MMTs) somewhat below the acid dew point,
where the efficiency gained more than balances the
additional maintenance costs. B&W recommends limiting MMTs to the values in Figs. 22 and 23 when
burning sulfur bearing fuels.
When fuel sulfur levels are high, or ambient temperatures or operating loads are low, MMTs may be
unacceptably low. These situations dictate the use of
active or passive cold end corrosion control methods.
Active systems used to raise MMT include: 1) steamor water-coil air heaters to preheat inlet air, 2) cold
air bypass, in which a portion of the inlet air is ducted
around the air heater, and 3) hot air recirculation, in
which a portion of the hot outlet air is ducted to combustion air fan inlets.
(8)
Test air heater leakage should be corrected for deviations from design cold end air to gas differential
pressure and inlet air temperature before comparison
to design leakage.
Pressure drop
In recuperative air heaters, gas- or air-side pressure drop arises from frictional resistance to flow, inlet and exit shock losses and losses in return bends between flow passes. In regenerative air heaters, the
main cause is heating surface frictional flow resistance. In both cases, pressure drop is proportional to
Steam 41 / Economizers and Air Heaters
Fig. 22 Recuperative air heater cold end MMT limits when burning
sulfur-bearing fuels.
20-13
The Babcock & Wilcox Company
continuously until the surface is deemed clean. Cleanliness may be proven by observed clarity of wash outlet water or by the ability to see light directed through
the surface bank.
In cases where low pressure washing is not effective, high pressure washing is done. Power plant operators employ air heater washing specialists and
equipment with water jets at nozzle pressure above
5000 psi (34.5 MPa). Special care must be taken to avoid
breaking and/or flattening regenerative element plates.
Fig. 23 Regenerative air heater cold end MMT limits when burning
sulfur-bearing fuels.
Passive corrosion control methods incorporated in air
heater design include: 1) thicker cold end materials, such
as 11 or 14 gauge (3 or 2 mm) tubes and 18 gauge (1
mm) regenerative surface elements, 2) low or high alloy
cold end surface materials which have at least twice the
corrosion life of carbon steel, 3) nonmetallic coating, such
as porcelain enamel, Teflon, or epoxies on cold elements,
4) nonmetallic cold end surface materials such as extruded ceramic in regeneratives and borosilicate glass
tubes in tubulars, and 5) tubular air heater cold end tube
arrangements which maximize MMT by providing
higher gas flow and lower air flow velocities.
Plugging and cleaning
Plugging is the fouling and eventual closing of heat
transfer flow passages by gas-entrained ash and corrosion products. It can occur at the air heater hot end
but is most common at the cold end where ash particles adhere to acid moistened surfaces. Plugging increases air heater pressure drop and can limit unit
load when fan capacity is reached at less than full load.
Air heater deposits are controlled and removed by
periodic on-line sootblowing, and by various methods
of cold end temperature control as described above to
control corrosion. Deposits may also be controlled by
employing regenerative heating surface designs with
easier-to-clean, less tortuous flow paths, and by using smooth enamel coated regenerative surface elements that resist particle adherence.
When on-line cleaning methods are no longer able
to stop or reverse fouling, off-line cleaning is necessary. Regenerative and recuperative air heater surface is normally washed off-line with permanent, low
pressure wash piping. The surface is deluged (washed)
20-14
Erosion
Heat transfer surfaces and other air heater parts
can suffer erosion damage through impact of high
velocity, gas-entrained ash particles. Erosion usually
occurs near gas inlets where velocities are highest.
However, areas near seals in regenerative air heaters can also be damaged as ash is accelerated through
seal gaps. The undesirable effects of erosion are structural weakening, loss of heat transfer surface area and
perforation of components which can cause air to gas
or infiltration leakage. Erosion rate is a function of velocity, gas stream ash loading, physical nature of ash
particles and angle of particle impact. It is controlled
by reducing velocities, removing erosive elements from
the gas stream, or using sacrificial material.
In the design stage, air heaters used with fuels containing highly erosive ash can be sized to limit gas
inlet velocities to 50 ft/s (15 m/s). Inlet flues can also
be designed to evenly distribute gas over the air
heater inlet to eliminate local high velocity areas. Dust
collectors, or strategically located screens and hoppers,
may be used ahead of air heaters to remove some of the
ash. In existing problem air heaters, flow distribution
baffles may be installed to eliminate local high velocities, sacrificial materials such as abrasion resistant steel
or ceramics may be placed over critical areas, or parts
can be replaced with thicker materials for longer life.
Erosion in tubular air heaters frequently occurs
within about 1 ft (0.3 m) of the gas inlet end due to
turbulence as gas enters the tubes. Replaceable sacrificial sleeves may be installed in tube ends or egg
crate-type flow straightening grids can be installed at
tubular air heater inlets to reduce erosion.
Fires
Air heater fires are rare but do occur, particularly
in regenerative units, and may be severe enough to
completely destroy an air heater. Fires are detected by
thermocouples in gas and air outlet ducts as well as
with special early warning systems. Fires usually start
near the cold end, which can be fouled with unburned
combustible materials. Most fires occur during startup
as unburned fuel oil deposited on ash fouled heating
surfaces is ignited. Leaking bearing lubrication equipment and heavy accumulations of flyash are also fire
hazards. Fires can be avoided by maintaining a clean
air heater and proper tuning of boiler firing equipment. Frequent sootblowing during startup and just
before shutdown is a strongly recommended fire prevention practice.
After a fire is confirmed, typical practice is to trip
the boiler to stop air flow through the heater, to keep
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
the air heater rotating, and to introduce as much water
as possible through the permanent water wash system. Drains in air- and gas-side duct hoppers below the
air heater must be opened to remove water and ash.
Hot
Gas In
Secondary
Air Out
Primary
Air Out
Utility applications
Gas to air recuperative and regenerative air heaters are usually used in utility units, primarily to enhance unit efficiency. Small increments of increased
efficiency in large units amount to substantial fuel
savings. Utility units generally use multiple air heaters for plant arrangement convenience, type of firing
and maximum unit availability.
Pulverized coal-fired units require two streams of
hot combustion air, i.e., primary air supplied at high
pressure to pulverizers and secondary air supplied at
lower pressure directly to burners. Two basic air flow
systems are used, hot primary air and cold primary
air. Each system uses air heaters. In the hot primary
air scheme, used for smaller units, about one third of
the combustion air heated in a secondary heater is
ducted to hot primary air fans, where it is boosted in
pressure and passed to the pulverizers; the remaining two thirds is ducted to the burners. The cold primary air system uses separate air heaters supplied by
separate primary and secondary (forced draft) fans.
In some units, both primary and secondary air are
heated in a single regenerative unit which is more cost
effective than separate air heaters. Fig. 24 shows a
schematic Ljungström-type air heater for primary and
secondary air, referred to as a tri-sector.
If separate regenerative primary and secondary air
heaters are used, the primary air heaters, which operate at high air to gas pressure differentials, exhibit
twice as much leakage as the secondary units. For this
reason, low leakage recuperative air heaters may be
used for primary air heating and regeneratives may
be used for secondary air heating.
Recuperative and regenerative air heaters are used
on oil- and gas-fired units. In general, regardless of
fuel type, larger units use regenerative air heaters
because of their smaller size and lower initial cost.
However, for air to gas pressure differentials above
40 in. wg (10 kPa), in fluidized-bed applications for example, recuperative air heaters are usually preferred.
Industrial applications
Industrial units fire a variety of fuels such as wood,
municipal refuse, sewage sludge and industrial waste
gases as well as coal, oil and natural gas. As a result,
many air heater types are used. In the small units,
tubular, plate and cast iron heaters are widely used.
Fuels fired on stoker grates, such as bituminous coal,
wood and refuse, do not require high air temperatures,
therefore water- or steam-coil air heaters can be used.
Environmental air heater application
For environmental reasons, emission of certain fossil-fired combustion products may be limited by law. (See
Chapter 32.) Systems developed to limit emissions of two
Steam 41 / Economizers and Air Heaters
Rotation
Cool
Gas Out
Secondary
Air In
Primary
Air In
Fig. 24 Ljungström-type tri-sector air heater.
objectionable flue gas constituents, NOx and SO2, may
require the use of specially modified heat exchangers.
NOx removal
When selective catalytic reduction (SCR) technology is used on a boiler to control NOx emissions, air
heaters operating downstream of the SCR require
special consideration. A typical, popular arrangement
is to place the SCR reactor in the boiler flue gas stream
between the economizer outlet and air heater inlet
(high dust arrangement).
The SCR reduces NOx by injecting ammonia (NH3)
into the flue gas just upstream of a catalyst which
converts the NOx to water and elemental nitrogen (N2).
However, the catalyst also converts some of the sulfur dioxide (SO2) in the flue gas to sulfur trioxide (SO3)
which combines with unreacted NH3 to form ammonium bisulfate (NH4HSO 4). This condenses on air
heater surface elements in the 510 to 340F (266 to
171C) temperature range. The objectionable
NH4HSO4 fouling and corrosion in regenerative air
heaters can be controlled to manageable levels by
design features including:
1. Arranging heating surface basket layers so that
NH4HSO4 deposition occurs within a layer rather
than between layers. Deposition in the space between basket layers is more difficult to remove
and keep clean. It is typical to provide two rather
than three air heater basket layers.
2. Employing a closed profile heating element which
allows deeper and more effective sootblower cleaning. Closed profile elements are designs in which
20-15
The Babcock & Wilcox Company
individual flow passages are closed through the
depth of the element layer and do not allow sootblowing media to quickly dissipate.
3. Using porcelain enamel coated bottom layer heating surface which resists corrosion and deposition,
and is easier to clean because of the smooth surface.
4. Fitting the heater with hot and cold end sootblowers which can be used to water wash heating surface off-line.
Heat exchangers with these features can typically
operate reliably without off-line water washing for a
year or more. As discussed in Chapter 34, some regenerative air heaters have been modified to simultaneously
serve as selective catalytic NOx reduction systems.
SO2 reduction
When sulfur emission reduction is required, flue gas
desulfurization (FGD) systems are frequently used.
These systems remove SO2 from the flue gas by reaction with injected compounds such as limestone. In
most cases, the scrubbed flue gas exits the FGD system at a saturation temperature of 120 to 130F (49 to
54C) before entering the stack. In cases where acid
dew point corrosion of flues and stack liners is a concern or increased gas buoyancy is needed to improve
stack plume dispersal, gas exiting the FGD system is
reheated to 180F (82C) or higher.
Regenerative heat exchangers similar to those for
combustion air heating are used in FGD systems. The
heat exchangers, referred to as gas-to-gas heaters
(GGH), extract heat from untreated warm flue gas to
heat treated (scrubbed) flue gas leaving an FGD tower
before it enters the stack. A typical arrangement with
gas temperatures is shown in Fig. 25.
Several necessary GGH design features distinguish
them from air heaters and permit them to operate in
a very corrosive environment without compromising
FGD system SO2 removal performance. Measures taken
to protect a GGH from the corrosive flue gas include:
1. Fabricating rotors of low alloy corrosion-resistant
steel and adding a corrosion margin to all rotor
plate thicknesses.
2. Using porcelain enamel coated heating surface element plates.
3. Using stainless and/or non-metallic circumferential, radial and axial leaf seal materials.
4. Applying a layer of vinyl ester flake glass on internal surfaces of the untreated gas outlet duct,
treated gas inlet duct, treated gas outlet duct, and
rotor housing.
5. Employing hot and cold end air sootblowers for online cleaning, fitted with water wash nozzles for
off-line washing.
Leakage of the untreated gas into the treated gas
reduces FGD SO2 reduction performance and must be
20-16
Flue Gas
from
Particulate
Collector
Stack
ID Fan
Untreated
Hot Gas
Treated
Warm Gas
277F
(136C)
194F
(90C)
Gas-to-Gas Heater
Untreated
Cool Gas
Treated
Cool Gas
197F
(92C)
115F
(46C)
Demister
FGD
Spray Tower
Fig. 25 Gas-to-gas heater in an FGD system.
controlled to low levels. The following features incorporated into GGH design can reduce the leakage to
less than 1% of the untreated inlet gas flow:
1. Designing the rotor with radial heating surface division plates so that, during operation, there are
always two under the radial and axial seal plates.
Leakage flow, in this case, is forced to pass two
seals rather than one seal producing a labyrinth
effect which lowers leakage flow.
2. Employing an automatic sealing system to hot end
radial seal plates that follows stator distortion to
minimize seal leakage at all loads.
3. Purging stator compartments of untreated gas
with treated gas just before they pass under radial seals and into the treated gas stream. Purging minimizes carryover leakage which is a component of total leakage. A purge system consists
of a dedicated purge fan and associated ducting
and controls.
4. Reducing rotor speed to the lowest possible level
without significantly compromising thermal performance. Operation at low speed reduces
carryover leakage.
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
Bibliography
Dubbel, H., Taschenbuch für den Maschinenbau, 11th
Ed., Springer Verlag GmbH & Company, Berlin, Germany, 1958.
Ledinegg, M., Dampferzeugung, Dampfkessel, Feuerungen
Springer Verlag-Wien, 1952.
Mayer, E.H., and McCarver, G.M., Economizer Technology for Utility and Industrial Boilers, Course for the
Center for Professional Advancement, East Brunswick,
New Jersey, 1991.
McAdams, W.H., Heat Transmission, Third Ed., McGrawHill Company, New York, New York, 1954.
Ljungström is a trademark of Alstom Power Inc.
Rothemühle is a trademark of Balcke-Dürr GmbH.
Steam 41 / Economizers and Air Heaters
20-17
The Babcock & Wilcox Company
Typical utility boiler economizer.
20-18
Steam 41 / Economizers and Air Heaters
The Babcock & Wilcox Company
Chapter 21
Fuel Ash Effects on Boiler
Design and Operation
The effective utilization of fossil fuels for power generation depends to a great extent on the capability of
the steam generating equipment to accommodate the
inert residuals of combustion, commonly known as ash.
The quantity and characteristics of the ash inherent
to a particular fuel are major concerns to both the designer and the operator of the equipment.
With few exceptions, most commercial fuels contain
sufficient ash to warrant specific design and operating considerations. The following focuses on these
design and operating considerations, primarily as they
relate to pulverized coal firing. Fuel ash characteristics relating to petroleum fuels are also discussed.
Ash dilutes the heating value of fuel, placing additional burdens on fuel storage, handling and preparation equipment. Extensive facilities are also needed
to collect, remove and dispose of the ash. These material handling requirements represent significant costs
in terms of equipment and real estate which are directly proportional to the amount of ash in the fuel. In
the case of coal, ash quantities can be substantial. Consider, for example, a 650 MW utility steam generator firing a coal with a heating value of 10,000 Btu/lb (23,250
kJ/kg) containing 10% ash by weight. The unit would
burn approximately 300 tons per hour (272 tm/h) of coal,
generating more than 700 tons per day (635 tm/d) of ash.
In pulverized coal-fired boilers, most of this ash is
carried out of the furnace by the gaseous products of
combustion (flue gas). Abrasive ash particles suspended in the gas stream can cause erosion problems
on convection pass heating surfaces. However, the
most significant ash-related problem is deposition.
During the combustion process, the mineral matter
that forms ash is released from the coal at temperatures in the range of 3000F (1649C), well above the
melting temperature of most mineral matter compounds. Ash can be released in a molten fluid or sticky
plastic state. A portion of the ash, which is not cooled
quickly to a dry solid state, impacts on and adheres to
the furnace walls and other heating surfaces. Because
such large total quantities of ash are involved, even
a small fraction of the total can seriously interfere with
boiler operation. Accumulation of ash deposits on furnace walls impedes heat transfer, delaying cooling of
the flue gas and increasing the flue gas temperature
leaving the furnace. Elevated temperatures at the furnace exit raise steam temperature and can extend
deposition problems to pendant superheaters and
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
other heat absorbing surfaces in the convection pass.
In extreme cases, uncontrolled ash deposits can develop to the point where flow passages in tube banks
are blocked, impeding gas flow and ultimately requiring the unit to be shut down for manual removal.
Large deposits in the upper furnace or radiant superheater can become dislodged and fall, damaging pressure parts in the lower furnace. Under certain conditions, ash deposits can also cause fireside corrosion on
tube surfaces.
Minimizing the potential for these ash-related problems is a primary goal of both the designers and operators of coal-fired boilers. The extent to which coal
ash characteristics affect boiler design is illustrated in
Fig. 1 which compares the relative size of a gas-fired
and coal-fired boiler. Both are sized for the same steam
generating capacity and similar steam conditions.
While the combustion characteristics of coal play a role
in sizing the furnace, the deposition and erosion potential of the ash are the primary design considerations driving the overall size and arrangement.
The variability of ash behavior is one of the biggest
problems for boiler designers and operators. Although
boilers are often designed to burn a wide range of
coals satisfactorily, no unit can perform equally well
with all types of coal.
Ash content of coal
The ash content of coal varies over a wide range.
This variation occurs not only in coals from different
geographical areas or from different seams in the same
region, but also from different parts of the same mine.
These variations result primarily from the wide range
of conditions that introduced foreign material during
or following the formation of the coal. (See Chapter
9.) Ash content can also be influenced by extraneous
mineral matter introduced during the mining operation. Before being sold, some commercial coals are
cleaned or washed to remove a portion of what would
be labeled ash in the laboratory. However, the ash content of significance to the user is the content at the
point of use. The values noted below are on that basis.
Most of the coal used for power generation in the
United States (U.S.) has an ash content between 6 and
20%. Low values of 3 to 4% in bituminous coals are
rare and these coals find other commercial uses, particularly in the metallurgical field. On the other hand,
21-1
The Babcock & Wilcox Company
Fig. 1 Size comparison of gas-fired and coal-fired utility boilers.
some coals may have ash contents as high as 40%. Many
high ash fuels can be successfully burned in utility (electric power generation) boilers. Their use has increased
in areas where they offer an economic advantage.
Evaluation of ash content on a weight percentage
basis alone does not take into account the heat input
associated with the coal, which is also related to moisture content. It is common, for design and fuel evaluation purposes, to consider ash content on the basis
of weight per unit of heat input, generally expressed
as pounds of ash per million Btu. This factor is calculated as follows:
Ash (% by weight)
× 104 = lb ash/106 Btu
HHV ( Btu/lb)
or
(1)
Ash (% by weight)
× 103 = kg ash/MJ
HHV (kJ/kg)
where HHV is the higher heating value of the fuel.
The relevance of this factor is illustrated in Table 1,
which provides proximate analyses for three selected
coals. Each coal has a moderate ash content of 9 to 10%
by weight. However, on a heat input basis, ash quantities vary significantly. The lignite in this example would
introduce almost three times as much ash as the high
volatile bituminous coal at an equivalent heat input.
bottom arrangement. The coal-fired boiler in Fig. 1 is
typical of this design. In a dry-bottom unit most of the
ash, typically 70 to 80%, is entrained in the flue gas
and carried out of the furnace. This portion of the ash
is commonly known as flyash. Some of the flyash is
collected in hoppers arranged under the economizer
and air heaters, where coarse particles drop out of suspension when gas flow direction changes. The finer
ash particles remain in suspension and are carried out
of the unit for collection by particulate control equipment. (See Chapter 33.) The remaining 20 to 30% of
the ash that settles in the furnace, or is dislodged from
the furnace walls, is collected in a hopper formed by
the frontwall and rearwall tube panels at the bottom
of the furnace. This bottom ash is discharged through
a 3 to 4 ft (0.9 to 1.2 m) wide opening that spans the
entire width of the hopper.
Slag-tap furnaces were originally developed to resolve ash deposition and removal problems when firing coals with low ash fusion temperatures in drybottom furnaces. These units are intentionally de-
Table 1
Proximate Analyses of Three Selected Coals
Ash Content as Weight Per Unit of Heat Input
Rank
Furnace design for ash removal
Historically, two distinctly different types of furnace
design were used to handle the ash from coal firing
in large utility boilers. These are commonly referred
to as the dry-ash or dry-bottom furnace and the slagtap or wet-bottom furnace.
All modern pulverized coal-fired boilers use the dry-
21-2
Moisture, %
Volatile matter, %
Fixed carbon, %
Ash, %
Heating value,
Btu/lb
lb Ash/106 Btu
High Volatile
Bituminous Subbituminous Lignite
3.1
42.2
45.4
9.4
23.8
36.9
29.5
9.8
45.9
22.7
21.8
9.6
12,770
7.4
8683
11.3
4469
21.5
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
signed to maintain ash in a fluid state in the lower
furnace. Molten ash is collected on the furnace walls
and other surfaces in the lower furnace and drained
continuously to openings called slag-taps in the furnace floor. Water tanks positioned beneath the slagtaps solidify the liquid ash for disposal.
Slag-tap furnaces have been used with both pulverized coal and CycloneTM furnace firing systems.
(See Chapter 15.) Application is limited to coals having ash viscosity characteristics which would ensure
that ash fluidity could be maintained over a reasonable boiler load range. Much of the coal ash research
conducted by The Babcock & Wilcox Company (B&W)
concerning the viscosity-temperature relationship of
coal ash was initially directed at defining coal ash
suitability limits for wet-bottom and Cyclone furnace
applications. A minimum coal ash content was also
specified to ensure sufficient ash quantities to maintain the required slag coating. One benefit of wetbottom firing was a significant reduction in flyash
quantity. In pulverized coal wet-bottom applications,
as much as 50% of the total ash was collected in the
furnace. Units equipped with Cyclone furnaces could
retain up to 80% of the ash in the furnace.
The application of slag-tap units for pulverized coal
firing began to decline in the late 1940s, primarily due
to design improvements in dry-bottom units that minimized ash deposition problems. Slag-tap units
equipped with Cyclone furnaces continued to be applied until the early 1970s when the federal Clean Air
Act mandated control of nitrogen oxides (NOx) emissions.
The high furnace temperatures required for wet-bottom
operation were highly conducive to NOx formation.
Ash deposition
Regardless of the firing method, when coal is burned,
a relatively small portion of the ash will cause deposition problems. Ash passing through the boiler is subject
to various chemical reactions and physical forces which
lead to deposition on heat absorbing surface. The process of deposition and the structure of deposits are variable due to a number of factors. Particle composition,
particle size and shape, particle and surface temperatures, gas velocity, flow pattern and other factors influence the extent and nature of ash deposition.
Due primarily to the differences in deposition
mechanisms involved, two general types of high temperature ash deposition have been defined as slagging
and fouling.
Slagging is the formation of molten, partially fused
or resolidified deposits on furnace walls and other surfaces exposed to radiant heat. Slagging can also extend into convective surface if gas temperatures are
not sufficiently reduced.
Most ash particles melt or soften at combustion temperatures. The time-temperature history or cooling
rate of the particle determines its physical state (solid,
plastic or liquid) at a given location in the furnace.
Generally, in order to adhere to a clean surface and
form a deposit, the particle must have a viscosity low
enough to wet the surface.
Slag deposits seldom form on clean tube surfaces.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
A conditioning period is required before significant
deposition occurs. Assuming there is no direct flame
impingement, as ash particles approach a clean tube,
most tend to be resolidified due to the relatively lower
temperature at the tube surface. The particles fracture on impact and partially disperse back into the flue
gas stream. Over a period of time, however, a base deposit begins to form on the tube. The base deposit may
be initiated by the settling of fine ash particles or the
gradual accumulation of particles with very low melting point constituents. As the base deposit thickens,
the temperature at its outside face increases significantly above the tube surface temperature. Eventually, the melting point of more of the ash constituents
is exceeded and the deposit surface becomes molten.
The process then becomes self-accelerating with the
plastic slag trapping essentially all of the impinging
ash particles. Ultimately, the deposit thickness reaches
an equilibrium state as the slag begins to flow, or the
deposit becomes so heavy that it falls away from the
tubes. Depending on the strength and physical characteristics of the deposit, sootblowers using steam,
compressed air or water as cleaning media (see Chapter 24) may be able to control or remove most of the
deposit. However, the base deposit can remain attached to the tube, allowing subsequent deposits to
accumulate much more rapidly.
Fouling is defined as the formation of high temperature bonded deposits on convection heat absorbing
surfaces, such as superheaters and reheaters, that are
not exposed to radiant heat. In general, fouling is
caused by the vaporization of volatile inorganic elements in the coal during combustion. As heat is absorbed and temperatures are lowered in the convective section of the boiler, compounds formed by these
elements condense on ash particles and heating surface, forming a glue which initiates deposition.
Areas where slagging and fouling can occur are
shown in Fig. 2. Figs. 3 and 4 show heavily slagged
and fouled surfaces. The characteristics of coal ash and
their influence on slagging and fouling are discussed
in the following sections.
Characteristics of coal ash
Sources of coal ash
Mineral matter is always present in coal and forms
ash when the coal is burned. This mineral matter is
usually classified as either inherent or extraneous.
(See Chapter 9.) Inherent mineral matter is organically combined with the coal. This portion came from
the chemical elements existing in the vegetation from
which the coal was formed and from elements chemically bonded to the coal during its formation. Extraneous mineral matter is material that is foreign to the
organic structure of the coal. This includes airborne
and waterborne material that settled into the coal
deposit during or after formation. It usually consists
of mineral forms associated with clay, slate, shale,
sandstone or limestone and includes pieces ranging
from microscopic size to thick layers. Other extraneous
material may be introduced through the mining process.
21-3
The Babcock & Wilcox Company
niques, have identified an enormous variety of mineral species in coal, encompassing the entire spectrum
of major mineral forms found in the earth’s crust. Most
of these minerals fall into one of several groups: clay
minerals (aluminosilicates), sulfides/sulfates, carbonates, chlorides, silica/silicates and oxides. Some of the
more common minerals in these groups are shown in
Table 2.
Mineralogical composition
There are no standardized methods that are used
routinely for determining the specific mineral constituents of coal. Mineralogical analysis requires the use
of a low temperature ashing technique to separate the
mineral matter from the organic portion of the coal.
Standard high temperature ashing procedures would
significantly alter the mineral forms. However, a number of researchers, using a variety of low temperature
ashing methods and sophisticated analytical tech-
Chemical composition
Because both quantitative and qualitative evaluation of mineral matter forms are extremely difficult,
relatively simple chemical analyses are commonly used
to determine the percentages of the major elements
in the ash. Elemental ash analysis is performed on a
coal ash sample produced in accordance with the
American Society for Testing and Materials (ASTM)
D 3174 ashing procedure. Pulverized coal is burned
in a furnace with an oxidizing atmosphere at 1292 to
1382F (700 to 750C). The elements present in the ash
are quantitatively measured using a combination of
emission spectroscopy and flame photometry and are
reported as weight percents of their oxides. Coal ash
is consistently found to be composed mainly of silicon,
aluminum, iron and calcium with smaller amounts of
magnesium, titanium, sodium and potassium. The
elemental analysis also identifies phosphorus as P2O5
and sulfur as sulfur trioxide (SO3). Phosphorus is usually present in very small quantities and is sometimes
omitted. Sulfur is reported as SO3 because it is normally present as the sulfate form of one of the metals.
Percentages of the individual elements vary over a
wide range for different coals; however, characteristic differences are evident between the older, high
rank coals common in the Eastern U.S. and the
younger, low rank Western coals. Bituminous coals
typically have higher levels of silica, aluminum and
iron, while the lower rank subbituminous coals and lignites generally have higher levels of the alkaline earth
metals, calcium and magnesium, and the alkali metal
sodium. These trends are evident in the ash analyses
shown in Table 3.
Although the ash constituents are reported as oxides, they actually occur in the ash predominately as
Fig. 3 Heavily slagged surface.
Fig. 4 Heavily fouled surface.
Fig. 2 Deposition zones in a coal-fired boiler.
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Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Table 2
Common Minerals Found in Coal
Clay minerals:
Montmorillonite
Illite
Kaolinite
Al2Si4O10(OH)2 • H2O
KAl2(AlSi3O10)(OH2)
Al4Si4O10(OH)8
Sulfide minerals:
Pyrite
Marcasite
FeS2
FeS2
Sulfate minerals:
Gypsum
Anhydrite
Jarosite
CaSO4 • 2H2O
CaSO4
(Na,K)Fe3(SO4)2(OH)6
Carbonate minerals:
Calcite
Dolomite
Siderite
Ankerite
CaCO3
(Ca,Mg)CO3
FeCO3
(Ca,Fe,Mg)CO3
Chloride minerals:
Halite
Sylvite
NaCl
KCl
Silicate minerals:
Quartz
Albite
Orthoclase
SiO2
NaAlSi3O8
KAlSi3O8
Oxide minerals:
Hematite
Magnetite
Rutile
Fe2O3
Fe3O4
TiO2
a mixture of silicates, oxides and sulfates, with smaller
quantities of other compounds. The silicates originate
mainly from quartz and the clay minerals which contribute silicon, aluminum, sodium and much of the
potassium. A principal source of iron oxide is pyrite
(FeS2) which is oxidized to form Fe2O3 and sulfur oxides. Part of the organic and pyritic sulfur that is oxidized combines with calcium and magnesium to form
sulfates. Calcium and magnesium oxides result from
the loss of carbon dioxide from carbonate minerals such
as calcite (CaCO3) and dolomite [(Ca, Mg)(CO3)]. In
low rank coals, a major portion of the sodium, calcium
and magnesium oxides can originate from organically
bound elements in the coal.
Laboratory ash is prepared from a coal sample in a
controlled atmosphere at controlled temperatures to
provide a reproducible and uniform ash. The actual
ashing process during combustion in a pulverized coalfired furnace is a much more complex process. In a
boiler furnace, pulverized coal is burned in suspension as discrete particles. If all of the mineral matter
were evenly distributed through the coal, the composition of each resulting ash particle would be the same
as the bulk ash composition determined by the analysis of ASTM ash. A coal with no extraneous mineral
matter might approach this hypothetical case, because
organically combined inherent material would be expected to be evenly distributed. In reality, however,
all coals contain non-uniformly distributed extraneSteam 41 / Fuel Ash Effects on Boiler Design and Operation
ous mineral matter in some of the wide variety of mineral forms shown on Table 2. When the coal is pulverized, some of the particles will be mostly coal with
only inherent mineral matter, some will be pure mineral matter, and others will be combinations of both.
Because the coal particles are burned discretely in suspension, the composition of an individual ash particle
will depend on the specific mineral form or forms that
were included in the coal particle. As a result, individual particle composition can vary significantly from
the bulk ash composition.
During combustion, ash particles are exposed to
temperatures as high as 3000F (1649C) and a variety of heating and cooling rates. The atmosphere in
the burner zone can range from highly oxidizing to
highly reducing. Depending on the composition of the
specific particle, mineral forms in the ash can react
with each other, with the organic and inorganic constituents of the coal, and with gaseous elements, such
as sulfur dioxide (SO2), in the flue gas. The compounds
that are ultimately formed by these interactions are
the materials that cause deposition problems. The compounds can have a wide variety of melting temperatures and viscosity-temperature characteristics. Some
compounds combine to form eutectic mixtures that
have melting temperatures lower than either of the
original compounds. Particles that melt at lower temperatures and stay sticky long enough to reach a furnace wall become slag deposits. Volatile compounds
that vaporize in the furnace tend to condense on and
foul cooler convective heating surfaces.
Elemental ash analyses do not directly identify the
compounds that cause deposition, or directly identify
the mechanisms of deposit formation. Despite these
limitations, no other data pertaining to coal ash composition are as widely available as the chemical analyses of ASTM ash. A large part of the coal ash research
that has been conducted over the last sixty years has
been directed at correlating analysis data and other
characteristics of ASTM ash to observed ash behavior
both in full scale boilers and in test facilities that closely
simulate full scale conditions. Various evaluation
methods have been developed based on these correlations to characterize ash behavior and predict deposition potential.
Ash fusibility
The measurement of ash fusibility temperatures is
by far the most widely used method for predicting ash
behavior at elevated temperatures. The preferred procedure in the U.S. is outlined in ASTM Standard D
1857, Fusibility of Coal and Coke Ash. An ash sample
is prepared by burning coal under oxidizing conditions
at temperatures of 1470 to 1650F (799 to 899C). The
ash is pressed in a mold to form a triangular pyramid
(cone) 0.75 in. (19 mm) in height with a 0.25 in. (6.35
mm) triangular base. The cone is heated in a furnace
at a controlled rate to provide a temperature increase
of 15F (8C) per minute. The atmosphere in the furnace is regulated to provide either oxidizing or reducing conditions. As the sample is heated, the temperatures at which the cone fuses and deforms to specific
21-5
The Babcock & Wilcox Company
Table 3
Rank:
Ash Content and Ash Fusion Temperatures of Some U.S. Coals and Lignite
Low Volatile
SubBituminous
High Volatile Bituminous
bituminous
Seam
Pocahontas No. 3
Location
West Virginia
Ash, dry basis,%
12.3
Sulfur, dry basis, %
0.7
Analysis of ash, % by wt
SiO2
60.0
Al2O3
30.0
TiO2
1.6
Fe2O3
4.0
CaO
0.6
MgO
0.6
Na2O
0.5
K2O
1.5
SO3
1.1
P2O5
0.1
Ash fusibility
Initial deformation temp, F
Reducing
2900 +
Oxidizing
2900 +
Softening temp, F
Reducing
Oxidizing
Hemispherical temp, F
Reducing
Oxidizing
Fluid temp, F
Reducing
Oxidizing
No. 9
Ohio
14.1
3.3
No.6
Illinois
17.4
4.2
47.3
23.0
1.0
22.8
1.3
0.9
0.3
2.0
1.2
0.2
47.5
17.9
0.8
20.1
5.8
1.0
0.4
1.8
4.6
0.1
2030
2420
Utah
17.1
0.8
Antelope
Wyoming
6.6
0.4
Texas
12.8
1.1
37.6
20.1
0.8
29.3
4.3
1.3
0.8
1.6
4.0
0.2
61.1
21.6
1.1
4.6
4.6
1.0
1.0
1.2
2.9
0.4
28.6
11.7
0.9
6.9
27.4
4.5
2.7
0.5
14.2
2.3
41.8
13.6
1.5
6.6
17.6
2.5
0.6
0.1
14.6
0.1
2000
2300
2030
2265
2180
2240
2280
2275
1975
2070
2450
2605
2160
2430
2175
2385
2215
2300
2290
2285
2130
2190
2480
2620
2180
2450
2225
2450
2245
2325
2295
2290
2150
2210
2620
2670
2320
2610
2370
2540
2330
2410
2315
2300
2240
2290
shapes, as shown in Fig. 5, are recorded. Four deformation temperatures are reported as follows:
1. Initial deformation temperature (IT or ID) – the
temperature at which the tip of the pyramid begins to fuse or show signs of deformation.
2. Softening temperature (ST) – the temperature at
which the sample has deformed to a spherical shape
where the height of the cone is equal to the width at
the base (H = W). The softening temperature is commonly referred to as the fusion temperature.
3. Hemispherical temperature (HT) – the temperature at which the cone has fused down to a hemispherical lump and the height equals one half the
width of the base (H = 1/2 W).
4. Fluid temperature (FT) – the temperature at
which the ash cone has melted to a nearly flat layer
with a maximum height of 0.0625 in. (1.59 mm).
The determination of ash fusion temperatures is
strictly an empirical procedure, developed in standardized form, which can be duplicated with some degree
of accuracy. Strict observance of test conditions is required to assure reproducible results. ASTM specified
tolerances on reproducibility of the individual temperature measurements range from 100 to 150F (56
to 83C) when the test is performed by different operators and apparatus.
An earlier version of the ASTM D 1857 procedure
21-6
Pittsburgh
West Virginia
10.9
3.5
Lignite
specified the use of only a reducing atmosphere and
had loosely defined criteria for identifying the softening and fluid points. When the atmosphere is not specified, it is generally assumed to be reducing. Reported
softening temperatures are assumed to be the ST (H
= W) point unless otherwise specified. Methods for determining fusibility of ash used by other countries are
similar to the ASTM procedure but results may vary
considerably due to differences in procedures or the
definition of terms.
The gradual deformation of the ash cone is generally considered to result from differences in melting
characteristics of the various ash constituents. As the
temperature of the sample is increased, compounds
with the lowest melting temperatures begin to melt,
causing the initial deformation. As the temperature
continues to increase, more of the compounds melt and
the degree of deformation proceeds to the softening and
hemispherical stages. The process continues until the
Fig. 5 Specific shapes as ash fuses and deforms with temperature.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
temperature is higher than the melting point of most of
the ash constituents and the fluid stage is reached.
Fusibility testing was originally developed to evaluate the clinkering (agglomerating) tendency of coal ash
produced by combustion on a grate. In several respects, the test method is a somewhat better simulation of stoker firing than suspension burning of pulverized coal. During the fusion test, at a heating rate
of 15F (8C) per minute, the transition from the IT to
the FT stage may take up to two hours or more for a
high fusion ash. Rather than slow heating and
gradual melting of the ash, the process in a pulverized coal furnace is essentially reversed. Ash particles
are rapidly heated, and then cooled at a relatively slow
rate, as they pass through the furnace. During combustion, coal particles are heated almost instantaneously
to temperatures ranging up to 3000F (1649C). As heat
is removed from the flue gas, the ash is cooled over a
period of less than two seconds to temperatures around
1900 to 2200F (1038 to 1204C) at the furnace exit.
In practical terms, for dry-bottom furnaces, fusion
temperatures provide an indication of the temperature
range over which portions of the ash will be in a molten fluid or semi-molten, plastic state. High fusion
temperatures indicate that ash released in the furnace
will cool quickly to a nonsticky state resulting in minimal potential for slagging. Conversely, low fusion temperatures indicate that ash will remain in a molten or
plastic state longer, exposing more of the furnace surface or convective surface to potential deposition.
When temperatures in the furnace are below the
measured initial deformation temperature, the majority of the ash particles are expected to be in a dry solid
state. In this form, particles impacting on heating surface will bounce off and be re-entrained in the gas
stream, or, at worst, settle on the surface as a dusty
deposit which can be readily removed by sootblowers.
At temperatures above the IT, the ash becomes increasingly more plastic in nature and impacting particles have
a greater potential to stick to heating surfaces.
Fusibility temperatures also provide an indication
of deposit characteristics as they relate to control and
cleanability. When the temperature at a deposit surface is at or above the fluid temperature of the ash,
slag will tend to flow or drip from the surface. While
fluid slag can not be controlled with sootblowers, the
deposits tend to be self-limiting in thickness and do
not interfere significantly with heat transfer effectiveness. However, if the deposit surface temperature is
in the plastic range, between the initial deformation
and hemispherical temperatures, the slag will be too
viscous to flow and will continue to build in thickness.
Wide IT to HT differentials can result in deposits that
build quickly to large proportions and are difficult to control, because sootblowers can be ineffective in penetrating the plastic shell that forms on the deposit surface.
In practice, very high and very low fusion values
are relatively easy to interpret as being troublesome
or non-troublesome with respect to slagging. Unfortunately, however, most coals fall in an intermediate
range where evaluations can be much more difficult.
Fusion temperatures have their most valid significance when used on a comparative basis against cor-
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
responding data from other fuels of known full-scale
performance. Even comparisons can be misleading,
however, when differences in data are within the range
of reproducibility of the test. Actual ash viscosity measurements (described later) provide a much more accurate and less subjective definition of the viscosity/temperature relationship and are considered by B&W to
provide a better assessment of slagging potential.
Influence of ash elements
Ash classification
Coal ash is classified into two categories based on
its chemical composition. Lignitic ash is defined as
having more (CaO + MgO) than Fe2O3. Bituminous
ash is defined as having more Fe2O3 than the sum of
CaO and MgO. Bituminous ash is generally characteristic of higher rank coals from the eastern U.S.
Lower rank western coals typically have lignitic ash.
As a result, bituminous ash is sometimes referred to
as eastern ash and lignitic ash is sometimes referred
to as western ash. However, ash classification is not
specific to ASTM rank or geographical origin. In rare
cases, lignites and subbituminous coals can have bituminous ash and bituminous coals can have lignitic
ash. For example, the Utah coal shown in Table 3 is
classified a bituminous, but has lignitic ash.
Effect of iron
Iron has a dominating influence on the slagging
characteristics of coals with bituminous type ash. As
shown in Table 2, iron can be present in coal in several mineral forms. These include pyrite (FeS2), siderite (FeCO3), hematite (Fe2O3), magnetite (Fe3O4)
and ankerite [(Ca, Fe, Mg)CO3]. Pyrite is the major
form of iron in most Eastern coals. In areas of the
furnace where there is sufficient oxygen, pyrite is
converted to Fe 2O3 and SO2. If the local atmosphere
is reducing, however, pyrrhotite (FeS) is formed
along with the lesser-oxidized iron forms such as
FeO and metallic iron, Fe. The reduced forms have
significantly lower melting temperatures than the
oxidized forms. When completely oxidized to Fe2O3
iron tends to raise all four values of ash fusion temperatures: initial deformation, softening, hemispherical and fluid. In the lesser oxidized form (FeO)
it tends to lower all of these values. The effect of iron
in each of these forms is indicated in Fig. 6, plotted
for a large number of ash samples from U.S. coals.
The data show that as the amount of iron in the ash
increases, there is a greater difference in ash fusibility between oxidizing and reducing conditions.
These effects may be negligible with coal ash containing small amounts of iron. Coals with lignitic ash
generally have small amounts of iron and the ash fusion temperatures are affected very little by the state
of iron oxidation. In fact, lignitic ash containing high
levels of calcium and magnesium may have ash fusion temperatures that are lower on an oxidizing basis than on a reducing basis. The ash analysis and
fusion temperatures shown for the subbituminous coal
in Table 3 illustrate this effect.
21-7
The Babcock & Wilcox Company
Fig. 6 Influence of iron on coal ash fusion temperatures.
Base to acid ratio
The constituents of coal ash can be classified as either basic or acidic. The basic constituents are iron,
the alkaline earth metals calcium and magnesium, and
the alkali metals sodium and potassium. Acidic constituents are silicon, aluminum and titanium. Bases
and acids tend to combine to form compounds with
lower melting temperatures. Experience has shown
that the relative proportions of basic and acidic constituents provide an indication of the melting behavior and viscosity characteristics of coal ash.
The elemental analysis is used to calculate the percent base, percent acid and the base to acid ratio as
follows:
Percent base =
( Fe2 O3 + CaO + MgO + Na2O + K 2O )
× 100
SiO2 + Al 2 O3 + TiO2 + Fe2 O3 + CaO + MgO + Na2 O + K 2 O
(2)
Percent acid =
(SiO2 + Al2O3 + TiO2 )
× 100
SiO2 + Al 2 O3 + TiO2 + Fe2 O3 + CaO + MgO + Na2 O + K 2 O
Base/acid ratio =
Fe2 O3 + CaO + MgO + Na2 O + K 2 O
SiO2 + Al 2 O3 + TiO2
(3)
(4)
The range of base to acid ratio extends from approximately 0.1 for highly acidic ash to 9.0 for ash that
is high in base content.
Ash that is either highly acidic or highly basic generally has high ash fusion and melting temperatures.
21-8
However, the presence of basic constituents in an
acidic ash tends to flux or reduce the melting temperature and viscosity of the mixture. Conversely, the
melting temperature and viscosity of a basic ash are
reduced by relative proportions of acidic constituents.
When the percent base and percent acid are nearly
equal, fusion temperatures and ash viscosity tend to
be reduced to minimum levels. The general trend is
shown in Fig. 7. Minimum fusion temperatures typically occur at approximately 40 to 45% base which
equates to base to acid ratios in the range of 0.7 to 0.8.
Ratios in the range of 0.5 to 1.2 are generally considered to indicate high slagging potential.
The base to acid ratio considers all of the basic and
acidic constituents to have equal effects on ash melting characteristics. However, research has shown that
the various acids and bases have different fluxing
strengths which must also be considered.
Studies conducted by B&W on the relationship of
ash composition to ash viscosity have provided additional factors which improve the simple base to acid
relationship. Ash viscosity is an important criterion for
determining the suitability of a coal ash for use in a
slag-tap furnace. Experience has shown that slag will
flow readily at or below a viscosity of 250 poise. The
temperature at which this viscosity occurs is called the
T250 temperature of the ash. The preferred maximum
T250 for wet-bottom applications is 2450F (1343C).
Trends in T250 temperatures have been shown to correlate with ash fusion temperatures. Low T250 temperatures indicate low fusion temperatures and increased
slagging potential.
Ash viscosity can be measured directly in a high temperature viscometer. Because viscosity measurements
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Fig. 7 Fusion temperatures and viscosities versus acidic constituents.
require a considerable amount of coal ash that may
not be readily available and are costly and time consuming, methods were developed to determine viscosity from chemical analysis of the coal ash. Based on a
large number of direct viscosity measurements of bituminous and lignitic ash samples, T250 temperatures
were related to ash composition as shown in Figs. 8
and 9. Fig. 8 is for bituminous ash and lignitic ash with
an acidic content above 60%. At base to acid ratios less
than 0.3, the silicon (SiO2)/aluminum (Al2O3) ratio is
taken into account. Silicon and aluminum are both acidic
constituents; however, higher percentages of silicon tend
to raise the T250 and the melting temperature.
Fig. 9 is for lignitic ash with an acidic content less
than 60%. T250 is a function of both the percent base
and the dolomite percentage which is defined as:
Fig. 8 Plot of temperature for 250 poise viscosity versus base to
acid ratio – based on ferric percentage of 20.
tend to reduce fusion temperatures and slag viscosity
at a given temperature. The degree of iron oxidation
is normally expressed as the ferric percentage where:
Ferric percentage =
Fe2O3 × 100
Fe2O3 + 1.11FeO + 1.43Fe
(6)
Dolomite percentage =
(CaO + MgO )
× 100
Fe2 O3 + CaO + MgO + Na2O + K 2O
(5)
At a given percent base, higher dolomite percentages increase the T250 temperature, indicating that
calcium and magnesium tend to raise ash viscosity and
fusion temperature. Increasing amounts of the other
base constituents (iron, sodium and potassium) tend
to lower the T250 temperature.
Taken together, these trends indicate higher melting temperatures and higher viscosities at a given temperature for ash that is predominately composed of
either silicon and aluminum or calcium and magnesium. Lower melting temperatures result from intermediate mixtures of these elements. However, in all
combinations, iron, sodium and potassium act to flux
the ash and increase the slagging potential.
As previously noted, the fluxing strength of iron is
related to its state of oxidation. Metallic iron (Fe) and
ferrous iron (FeO) are stronger fluxes than Fe2O3 and
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
Fig. 9 Basic content and dolomite percentage of ash versus temperature for 250 poise viscosity.
21-9
The Babcock & Wilcox Company
The effect of ferric percentage on slag viscosity for
a typical bituminous ash is shown in Fig. 10. Note that
the T250 temperature can vary over a wide range depending on the degree of iron oxidation. Experience
has shown that slag from boiler furnaces operating
under normal conditions with 15 to 20% excess air has
a ferric percentage of approximately 20%. The curves
in Fig. 8 are based on this value.
Influence of alkalies on fouling
The alkali metals, sodium and potassium, have long
been associated with the fouling tendencies of coal ash.
Volatile forms of these elements are vaporized in the
furnace at combustion temperatures. Subsequent reactions with sulfur in the flue gas and other elements
in the ash form compounds that contribute to the formation of bonded deposits on convection heating surface.
Research conducted by B&W dating back to the
1950s identified a relationship between the total alkali content in bituminous coals and fouling potential.
The specific laboratory procedure developed to establish this relationship, called the sintering strength test,
is described in detail later in this chapter. Basically,
the test involves measuring the compressive strength
of flyash pellets heated in air for a period of time at
temperatures of 1500 to 1800F (816 to 982C). The application of this method, combined with observations
of fouling conditions in operating boilers, showed that
high fouling coals produced flyash with high sintered
strength. Conversely, low strength flyash was associated with low fouling coals. Correlation of standard
ASTM ash analysis data with the sintering test results
indicated a significant relationship (Fig. 11) between
total alkali content (Na 2O and K 2O, expressed as
equivalent total Na2O) and flyash sintered strength.
These correlations formed the basis for the first foul-
Fig. 10 Viscosity-temperature plots of a typical slag showing effect
of ferric percentage.
21-10
ing index for bituminous coals which used the total
alkali content in the coal to predict fouling potential.
Because ASTM ash produced in the laboratory
could not be expected to represent the physical and
chemical properties of flyash produced by full scale
combustion, sintering strength testing required actual
flyash samples aspirated from the flue gas in operating boilers. This meant full scale tests under steadystate conditions with a consistent coal supply, which
became increasingly more difficult as unit size increased. To improve the efficiency and accuracy of obtaining data, a small laboratory ashing furnace (LAF)
was constructed to burn pulverized coal at controlled
conditions similar to those in a commercial boiler.
Subsequent tests on flyash produced in the LAF
from a wide variety of bituminous coals demonstrated
that sodium was the most important single factor affecting ash fouling. Potassium, which had been included in the previous alkali fouling indices, was
found to make no significant contribution to sintering strength. Additionally, it was found that water
soluble sodium, which was related to the more readily
vaporized forms of sodium, had a major effect on sintered strength. This result was obtained by washing
coals with hot condensate in the laboratory to remove
the water soluble sodium. The washed coals were
ashed in the LAF and sintered at various temperatures. Results for a high fouling Illinois coal are shown
in Table 4. Water washing decreased the sodium content in the ash by approximately 70%, while the potassium content, which was initially higher than the
sodium content, decreased by only 4%. Removing the
soluble sodium resulted in a reduction in sintering
strength at 1700F (927C) from 17,300 psi (119.3 MPa)
for the raw coal to 550 psi (3.8 MPa) for the washed
coal. Because the coal had a high chlorine content, it was
concluded that most of the volatile sodium was probably
in the form of NaCl. The insoluble potassium was likely
associated with clay minerals or feldspar which would
not readily decompose and vaporize during combustion.
The relationship of sintering strength to the percentage of soluble sodium in the ash was also found
to be a function of the base to acid ratio, as shown in
Fig. 11 Effect of alkali content in coal.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Table 4
Effect of Soluble Sodium on Sintered Strength
Ash Analysis
SiO2
Al2O3
Fe2O3
TiO2
CaO
MgO
Na2O
K2O
Ash sintered
strength, psi
(MPa)
Raw Coal
Washed Coal
45.0
18.0
21.0
0.8
8.8
0.9
1.6
2.4
49.8
20.9
22.9
1.0
1.6
1.0
0.5
2.3
17,300
(119.3)
550
(3.8)
Fig. 12. The combination of high sodium and high base
to acid ratios resulted in the highest sintering
strengths. Low ratios and sodium contents resulted in
reduced flyash strength at the same sintering temperature. Similar trends were noted for variations in
sintering strength as a function of base to acid ratio
and total Na2O in the ash. Statistical evaluations of
these relationships were used to develop the fouling
index currently used for coals with bituminous ash.
Similar tests on the sintering characteristics of lignitic ash indicated that the sintering criteria associated with fouling for bituminous ash did not apply to
lignitic ash with high alkaline (CaO, MgO) contents.
However, sintering strength was found to be directly
proportional to the total sodium content in the ash
shown in Fig. 13. Full scale and pilot scale tests conducted by the U.S. Bureau of Mines at the Grand
Forks Coal Research Laboratory in North Dakota also
established a correlation between fouling rate and sodium content for coals with lignitic ash. As shown in
Fig. 14, deposition rates were found to increase sharply
as the Na2O content increased up to approximately 6%
and then level off at higher percentages of sodium.
Fig. 12 Bituminous (Eastern) ash fouling effect of base to acid ratio
and soluble sodium on sintered strength.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
As previously noted, in low rank coals, a major portion of the alkali and alkaline earth metals can be organically bound in the coal. Because they are intimately mixed with the coal, it is believed that alkalies
in this form are readily vaporized during combustion
and play a dominating role in fouling. The organically
associated elements occur in the form of cations chemically bonded to the organic structure of the coal. Ion
exchange techniques have been developed to remove
the cations from the coal for measurement. The
method employed by B&W uses an ammonium acetate
solution to provide a source of NH4+ ions which extract
the ion-exchangeable cations. The laboratory procedure is described later in this chapter. Ion exchange
data for a high fouling North Dakota lignite and a
severe fouling Montana subbituminous coal are
shown in Table 5. The data show that essentially all
of the sodium in both coals is organically bound. In
the lignite, the ion-exchangeable sodium actually
exceeded the total sodium measured in ASTM ash.
The difference most likely results from a loss of sodium
due to vaporization during the high temperature
ashing procedure. The relatively low percentages of
ion-exchangeable K2O indicate that most of the potassium exists in stable mineral forms.
Viscosity-temperature relationship
of coal ash
The characteristics of slag deposits which form on
furnace walls and other radiant surface are a function of deposit temperature and deposit composition.
Fig. 13 Effect of Na2O on sintering strength (North Dakota lignite ash).
21-11
The Babcock & Wilcox Company
Fig. 14 Effect of Na2O on deposition rate.
Deposit composition, in turn, is a function of the local
atmosphere, particularly for ash with a significant
iron content. Relationships between these factors determine the physical state of the deposit, which can
range from a dry solid to plastic or even a viscous liquid if temperatures are sufficiently high. Dry deposits are usually not troublesome; they tend to be loosely
bonded to the tube surface and relatively easy to remove by sootblowing. If deposits are allowed to build
in thickness, the temperature increases and the surface of the deposit can become semi-molten or plastic.
The plastic slag traps other transient ash particles and
continues to build more and more rapidly as the surface temperature continues to increase. Ultimately, the
deposit reaches an equilibrium state as the slag begins to flow.
Field experience has shown that plastic slag tends
to form large deposits that are highly resistant to removal by conventional ash cleaning equipment. This
observation led to an extensive study of the relationship between ash viscosity and potential slagging tendency. Viscosity measurements that had previously
been used to determine flow characteristics for wetbottom furnace applications were extended to higher
viscosity ranges to define the temperature range
where a given ash would exhibit plastic characteristics.
As liquid ash is cooled, the logarithm of its viscosity
increases linearly with decreasing temperature as
shown in Fig. 15. At some point, the progression deviates from the linear relationship, and viscosity begins
to increase more rapidly as the temperature continues to decrease. This transition into the plastic region
is caused by the selective separation of solid material
from the liquid, resulting from crystallization of the
higher melting point constituents of the ash. The temperature at which this deviation takes place is called
the temperature of critical viscosity (Tcv). Tcv varies depending on ash composition but normally occurs in a
range between 100 and 500 poise. The end of the plastic region is the point of solidification, or freeze point,
of the slag. The freeze point typically occurs at a viscosity of approximately 10,000 poise. For convenience
in comparing the viscosity-temperature relationship
of various ashes, the viscosity range of 250 to 10,000
poise has been defined as the plastic region.
The temperature at which the plastic region begins
and the range of temperature over which the ash is
plastic provide an indication of the slagging tendency.
The lower the temperature within this range and the
wider the range, the greater the potential for slagging.
Viscosity-temperature curves for a high slagging Illinois coal and a low slagging east Kentucky coal, shown
in Fig. 16, illustrate this effect. The plastic range for
the Illinois coal begins at a relatively low temperature
and extends over a wide temperature range. In contrast, the east Kentucky coal has a very narrow plastic range which begins at a much higher temperature.
In comparison to the Illinois coal, the Kentucky coal
ash would be expected to cool quickly below the temperature where the ash is plastic, exposing much less
of the furnace to potential deposition.
As previously noted, the iron content of coal ash and
its degree of oxidation have a significant influence on
Table 5
Ion Exchange Data High and Severe Fouling Coals
Source:
Rank:
Ion exchangeable
alkali, dry coal
basis, %
Relative ion
exchange alkali, %
21-12
Montana
Lignite
Subbituminous
11.2
5.4
Na2O
K2O
4.25
0.37
6.74
0.65
Na2O
K2O
4.52
0.10
6.37
0.13
Na2O
K2O
106%
27%
95%
20%
Ash, dry basis, %
Total alkali, dry
coal basis, %
North Dakota
Fig. 15 Viscosity increase with decreasing temperature.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
the viscosity of the ash. This effect is illustrated in Fig.
17 which shows the viscosity-temperature relationship
for the high iron Illinois coal under both oxidizing and
reducing conditions. Under reducing conditions, the
viscosity at a given temperature is significantly lower
and the ash remains plastic over a much wider temperature range.
Ash reflectivity
Ash from certain coals produces furnace deposits
that have reflective rather than insulating properties.
This is particularly true of low sulfur, low sodium coals
found in the western U.S., from the Powder River Basin in Wyoming and Montana. Reflective deposits can
significantly reduce furnace heat absorption and increase furnace exit gas temperature even when only
a very thin deposit is present. This can result in excessive radiant superheater slagging and fouling of
convection surfaces. Experience has shown that reflective ash deposits can be difficult to remove and require special considerations in selection of ash cleaning equipment and media. (See Chapter 24.) Proprietary methods based upon field experience and laboratory studies are used to evaluate the potential for
reflective ash formation, and to address the impact on
furnace design and boiler performance.
Ash characterization methods
Several slagging and fouling indices have been developed by B&W to provide criteria for various aspects
of boiler design. Slagging indices establish design criteria for the furnace and other radiant surface while
fouling indices establish design criteria for convective
Fig. 17 Ash viscosity comparison – oxidizing and reducing conditions.
surface. Deposition characteristics are generally classified into four categories: low, medium, high and severe.
For the most part, the indices described below are
based on readily available ASTM ash analysis and fusibility data. In actual practice, when evaluating coals,
designers take into account full scale experience on
similar fuels and results of non-routine testing which
can, in some cases, modify the classification. These indices can also be used on a comparative basis to rank
coals with respect to their slagging and fouling potential
when evaluating a new coal supply for an existing unit.
Ash classification
Because the characteristics of bituminous and lignitic ash vary significantly, the first step in calculating slagging and fouling indices is the determination
of ash type. In accordance with the criteria previously
described, ash is classified as bituminous when:
Fe2 O3 > CaO + MgO
(7)
Ash is classified as lignitic when:
Fe2O3 < CaO + MgO
(8)
Slagging index – bituminous ash (Rs) Calculation of
the slagging index (Rs) for bituminous ash takes into
account the base to acid ratio and the weight percent,
on a dry basis, of the sulfur in the coal. The base to
acid ratio indicates the tendency of the ash to form compounds with low melting temperatures. The sulfur content provides an indication of the amount of iron that
is present as pyrite. The calculation is as follows:
Fig. 16 Ash viscosity comparison for a high slagging and low slagging
coal (oxidizing atmosphere).
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
Rs =
B
×S
A
(9)
21-13
The Babcock & Wilcox Company
Fouling index – bituminous ash (Rf ) The fouling index for bituminous ash is derived from sintering
strength characteristics using the sodium content of
the coal ash and the base to acid ratio as follows:
where
B = CaO + MgO + Fe2O3 + Na2O + K2O
A = SiO2 + Al2O3 + TiO2
S = weight % sulfur, on a dry coal basis
Classification of slagging potential using Rs is as follows:
Rs < 0.6 = low
0.6 < Rs < 2.0 = medium
2.0 < Rs < 2.6 = high
2.6 < Rs
= severe
( Max HT ) + 4 ( Min IT )
5
(10)
where
Max HT = higher of the reducing or oxidizing
hemispherical softening temperatures, F
Min IT = lower of the reducing or oxidizing initial deformation temperatures, F
Classification of slagging potential using Rs* is as follows:
= low
2450 < Rs*
2250 < Rs* < 2450 = medium
2100 < Rs* < 2250 = high
Rs* < 2100 = severe
(T
250 oxid
) − (T
10 ,000 red
97.5 ( fs )
)
(11)
where
T250 oxid
T10,000 red
= temperature, F, corresponding to a viscosity of 250 poise in an oxidizing atmosphere
= temperature, F, corresponding to a viscosity
of 10,000 poise in a reducing atmosphere
and fs is a correlation factor based on the average of
the oxidizing and reducing temperatures (Tfs) corresponding to a viscosity of 2000 poise. Values for fs as
a function of Tfs are provided in Fig. 18.
Classification of slagging potential using Rvs is as follows:
Rvs < 0.5 = low
0.5 < Rvs < 1.0 = medium
1.0 < Rvs < 2.0 = high
2.0 < Rvs
= severe
21-14
(12)
B
= CaO + MgO + Fe2O3 + Na2O + K2O
A
= SiO2 + Al2O3 + TiO2
Na2O = weight % from analysis of coal ash
Classification of fouling potential using Rf is as follows:
Rf < 0.2 = low
0.2 < Rf < 0.5 = medium
0.5 < Rf < 1.0 = high
1.0 < Rf
= severe
Fouling index – lignitic ash The fouling classification for lignitic ash coals is based on the sodium content in the ash as follows:
When CaO + MgO + Fe2O3 > 20% by weight of coal ash
Na2O < 3 = low to medium
3.0 < Na2O < 6 = high
Na2O > 6 = severe
When CaO + MgO + Fe2O3 < 20% by weight of coal ash
Na2O < 1.2 = low to medium
1.2 < Na2O < 3 = high
Na2O > 3 = severe
Coal ash effects on boiler design
Slagging index – viscosity (Rvs) As previously noted,
B&W’s most accurate method for predicting slagging
potential is based on the viscosity-temperature relationship of the coal ash. This index (Rvs) is applicable
to both bituminous and lignitic ash coals; however,
measured ash viscosities are required.
Rvs =
B
× Na 2O
A
where
Slagging index – lignitic ash (Rs*) The slagging index for lignitic ash (Rs*) is based on ASTM ash fusibility temperatures. As previously noted, fusibility
temperatures indicate the temperature range where
plastic slag is likely to exist. The index is a weighted
average of the maximum hemispherical temperature
(HT) and the minimum initial deformation temperature (IT) as follows:
Rs * =
Rf =
Furnace design
The key to a successful overall gas-side design is
proper sizing and arrangement of the furnace. As a
first priority, the furnace must be designed to minimize slagging and to provide effective control of slag
where and when it does form.
Ash deposition in the furnace can cause a number
of problems. Slag deposits reduce furnace heat absorption and raise gas temperature levels at the furnace
exit. This, in turn, can cause slagging and can aggravate fouling in the convection banks where ash deposits become increasingly more difficult to control as
gas temperatures increase. The shift in heat absorption from the furnace to the superheater and reheater
results in increased attemperator spray flow for control of steam temperatures, reducing cycle efficiency.
Slag buildup at the top of a tall furnace is dangerous.
Large deposits can become dislodged and fall, causing failures of furnace hopper tubes and loss of availability. Excessive slagging in the lower furnace can
interfere with ash removal.
Experience has shown that several interrelated furnace design parameters are critical for slagging control. These parameters focus on keeping ash particles
in suspension and away from furnace surfaces, distributing heat evenly to avoid high localized temperatures, and removing enough heat to achieve temperaSteam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Fig. 18 Slagging index correction factor fs.
tures at the furnace exit that will minimize deposition
on convection surface.
In the context of gas-side design, the furnace basically serves three functions. It must provide sufficient
volume to completely burn the fuel, provide sufficient
heat transfer surface to cool the flue gas and ash particles to a temperature suitable for admission to the
convection surface, and minimize the formation of NOx
emissions (see Chapter 34). In general, for a coal-fired
unit, it is the second criterion that determines the
minimum furnace size.
The slagging classification of the coal establishes
the upper limit on furnace exit gas temperature
(FEGT) required to minimize the potential for slagging both in the radiant superheater and the closespaced convection surface. As described in Chapter 22,
furnace exit gas temperature is a function of furnace
heat release rate. Limiting the FEGT, therefore, limits the heat release rate, resulting in lower average
temperatures in the furnace. FEGT limits and corresponding heat release rates have been established by
experience for different types of coal. In general, units
using coals with low or medium slagging tendencies
can have higher heat release rates and higher FEGTs.
Units firing coals with high or severe slagging potential require lower heat release rates and lower FEGTs.
Ideally, the furnace would be an open box, sized
with sufficient wall surface to cool the furnace gas and
ash particles to the desired temperature before they
reached any superheater surface. However, thermodynamic considerations in modern high pressure and
high temperature cycles require that a significant portion of the total heat absorption be accomplished in
the superheater and reheater. This requirement places
a practical limit on the amount of furnace wall surface which, in a drum boiler, is dedicated to generating saturated steam. In order to achieve the required
FEGT it becomes necessary to replace water-cooled
furnace wall surface with steam-cooled superheater
surface. These surfaces are generally in the form of
widely spaced platens (see Chapter 19) located in the
upper radiant zone of the furnace. Because platen
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
surface is located in a relatively high gas temperature
zone and subject to ash particle impaction, the side
spacing must be sufficient to limit the potential for
bridging and provide a degree of self-cleaning. Typical side spacing between platen sections is 4 to 5 ft (1.2
to 1.5 m). When platen superheater surface is used,
the slagging classification of the coal establishes the
upper limit on platen inlet gas temperature, in addition to limiting the FEGT.
An alternate method of controlling furnace exit gas
temperature that has been widely used is gas tempering by flue gas recirculation. In this method, relatively
cool gas from the economizer outlet is mixed with hot
furnace gas near the furnace exit. Gas tempering offers a number of advantages. The FEGT can be limited with less furnace surface while the increased gas
weight improves the thermal head for heat transfer,
reducing the surface requirements in the convection
pass. Proper introduction of the tempering flue gas
provides a flat temperature profile at the furnace exit,
reducing the possibility of localized slagging and fouling. Once the choice of gas recirculation is made, the
system can also be used to control reheat steam
temperature at partial loads. For this purpose, flue gas
from the economizer outlet is introduced into the furnace through the furnace hopper opening. The cool
gas reduces furnace heat absorption and makes more
heat available to the reheater which offsets its natural characteristic of decreasing outlet steam temperature at partial loads.
The major disadvantages of gas recirculation are
fan maintenance and power requirements. Fan erosion can be minimized to some extent by proper design and operation of a mechanical dust collector ahead
of the fan. Extracting the recirculated gas after a hot
precipitator offers the best potential for a relatively
clean recirculated gas source.
In addition to having sufficient volume and heating surface, the furnace also must be correctly proportioned with respect to width, depth and height to minimize slagging. A significant design parameter in this
regard is heat input from fuel to the furnace per unit
of furnace plan area at the burners. Maximum limits
on plan area heat release rate are a function of the
slagging potential of the coal. Limits typically range
from 1.5 to 1.8 × 106 Btu/h ft2 (4.7 to 5.7 MWt/m2) for
severe slagging and low slagging coals respectively.
The furnace must also be designed to limit the potential for ash particle impaction on furnace surfaces.
Ample clearance must be provided between the burners and furnace walls as well as the furnace hopper
and arch. These critical dimensions have been established by operating experience and keyed to the slagging classification of the coal.
The slagging classification also determines the locations, quantity and spacing of furnace wall blowers and long retractable sootblowers in the pendant
radiant surface. (See Chapter 24.) These allow control of the deposition that inevitably occurs and are
essential for maintaining furnace surface effectiveness
and furnace exit gas temperature within the range
provided for in the design. Some degree of slagging
may be permitted above the burner zone but only to
21-15
The Babcock & Wilcox Company
the extent that it can be controlled by selective operation of the wall blowers. The control of these deposits
can help maintain steam temperature at reduced loads.
Slag deposits on furnace walls must be avoided below
and between burners, however, where they can not
be controlled by sootblowers.
Effect of slagging potential on furnace sizing
Referring to Fig. 19, three large utility boilers are
shown sized for 660 MW at maximum continuous load.
The boilers are assumed to have the same width for
purposes of illustration, with the boiler setting height
and furnace depth varied to accommodate the slagging characteristics of the different fuels. Boiler (a) is
designed to fire a bituminous coal having a low to
medium slagging potential. The slightly larger boiler
(b) is designed to fire a subbituminous coal classified
as having a high slagging potential. The difference
in size can be attributed primarily to the difference in
slagging potential. The furnace (b) depth has been
increased to control slagging by reducing the input per
plan area. The input and gas weight are higher for
the subbituminous coal due to its higher moisture content and resulting lower boiler efficiency. This increases
the required furnace surface and the furnace exit area
to maintain acceptable gas velocities entering the convection pass. Comparing boiler (c), firing a severe slagging lignite, to boiler (b), the furnace depth has again
been increased due to the increased slagging potential. The furnace surface has also been increased to
reduce the gas temperature leaving the furnace. The size
differential of the three units is quantified in Table 6.
This table shows the proportionate differences or increases using boiler (a) as a base. Boiler (a) is assigned
a size factor of 1.0 for the various parameters shown.
Convection pass design
The key to successfully preparing a design that will
control convection pass fouling reverts back to a furnace design that will maintain the furnace exit gas
temperature at predicted levels. Temperature excursions at the furnace exit result in corresponding
higher temperature levels throughout the convection
pass which can cause deposition problems even with
coals which normally would be considered to have a
low or moderate fouling tendency.
In general, convective heating surface, both pendant and horizontal, is arranged to minimize the potential for bridging and obstruction of the gas lanes
between adjacent sections. The minimum clear side
spacing (measured perpendicular to the gas flow) between sections in a bank varies as a function of the
average flue gas temperature entering the bank. The
widest spacing is required in the superheater banks
which are in close proximity to the furnace exit, where
the gas temperature and fouling potential are high.
As the flue gas temperature is reduced, the side spacing in succeeding banks can also be reduced. The specific side space dimensions at a given temperature
entering the bank depend on the fouling classification
of the coal. Severe fouling coals require the widest
spacing. Adequate side spacing must be maintained
even in low temperature horizontal banks such as
economizers. While these surfaces are not normally
subject to bonded deposits, sufficient clear space must
be maintained between sections to ensure that accumulations of ash dislodged from upstream surfaces will
not bridge and plug the gas lanes. (See Chapter 20.)
Bank depths (measured parallel to the direction of
gas flow) are established as a function of fouling potential, clear side spacing and the temperature enter-
Fig. 19 Influence of slagging potential on furnace size. (See Table 6.)
21-16
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Table 6
Boiler Size Versus Slagging Classification
Boiler
(a)
(b)
(c)
Bituminous
Subbituminous
Lignite
Low/Med
High
Severe
Furnace plan
area
1.0
1.11
1.24
Furnace surface
1.0
1.18
1.50
No. of furnce
wall blowers
30
36
70
Coal Rank
Slagging
ing the bank. Cavities between the banks provide locations for long retractable sootblowers. At high gas
temperatures, shallow bank depths are required to
ensure adequate sootblower effectiveness. Sootblower
jet penetration increases as temperatures are reduced
and bank depths can be increased incrementally in
cooler areas.
Flyash erosion
The metal loss on convection pass tubes due to flyash
erosion is proportional to the total ash quantity passing through the boiler and is an exponential function
of flue gas velocity. While with a given fuel there is
no control of the ash quantity, erosion problems can
be eased by reducing flue gas velocities. Velocity limits are determined based on the ash quantity on a
pounds per million Btu (kg/MWt) basis and the relative proportion of abrasive constituents in the ash.
Typical limits range from 65 ft/s (19.8 m/s) for relatively
non-abrasive low ash coals to 45 ft/s (13.7 m/s) or less
for coals with high ash quantities and/or abrasive ash.
Effect of operating variables
Although the predominant factors affecting deposition are ash characteristics and boiler design, operating variables can also have a significant impact on
slagging and fouling.
In general, operating variables associated with
combustion optimization (see Chapter 14) tend to reduce the potential for deposition problems. These variables include air distribution, fuel distribution, coal
fineness and excess air.
Air and fuel imbalances can result in high excess
air at some burners while others operate with less than
theoretical air. This, in turn, results in localized reducing conditions in the burner zone which can aggravate slagging, especially with coals having high iron
content. High coal/air ratios can also delay combustion and upset heat distribution, resulting in elevated
temperatures in the upper furnace and at the furnace
exit. Long burnout times also increase the potential
for burning particles to contact furnace walls and
other heat transfer surfaces.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
Secondary air imbalances can be minimized by adjusting individual burner flows to provide a flat O2 profile at the economizer outlet. Care must be exercised
to avoid burner adjustments that cause flame impingement on furnace walls. On the fuel side, burner
line resistances should be balanced to maintain uniform coal flow to each burner. Coal feeders should be
calibrated and adjusted to provide uniform coal flow
to each pulverizer.
Low pulverizer fineness (see Chapter 13) can also
cause problems associated with delayed combustion.
Coarse particles require longer residence times for
burnout and can cause slagging in the lower furnace.
Excess air has a tempering effect on average temperatures within the furnace and on furnace exit temperature. Excess air also reduces the potential for localized reducing conditions in the furnace when it is
introduced through the burners. Air infiltration into
the furnace or convection pass is far less beneficial and
should be corrected or taken into account when establishing excess air requirements. While there is an associated efficiency loss, raising excess air above normal design levels is usually an effective tool for controlling deposition problems. In some cases, high excess air may also upset superheater/reheater absorption and steam temperatures.
Sootblowers (see Chapter 24) are the primary
means of dealing directly with furnace wall slagging
and convection pass fouling. The most important fundamental requirement is to use this equipment in a
preventive, rather than corrective, manner.
Sootblowers are most effective in controlling dry,
loosely bonded deposits which typically occur in the
early stages of deposition. If furnace slag is allowed
to accumulate to the point that it becomes plastic or
wet, or if convection pass deposits are allowed to build
and sinter for long periods of time, removal becomes
much more difficult. Sootblower sequencing requirements must be established by initial operating experience and updated when required, especially when
fuel characteristics change. Boiler diagnostic systems,
which are discussed in the following section, can assist in optimizing sootblower operation.
The least desirable operating technique for controlling deposition problems is load reduction. The most
severe situations may require a permanent derate.
However, in many marginal situations, temporary
load reductions during off peak periods may provide
sufficient cooling to shed slag and allow sootblowers
to regain effectiveness.
Application of advanced diagnostic and
control systems
Awareness of slagging and fouling conditions is
critical to achieving reliability and availability on a
coal-fired utility boiler. However, boiler surface cleanliness has been, traditionally, one of the most difficult
operating variables to quantify. Typical indications of
surface fouling appear to the operator indirectly in the
form of steam temperatures, spray attemperation
flows and draft losses (gas resistance). In some cases,
experienced operators who are familiar with the op21-17
The Babcock & Wilcox Company
erating characteristics of a unit can make judgments
on slagging and fouling conditions based on operating conditions, but these secondary indications can be
misleading. For example, the furnace can be slagged,
causing undesirably high gas temperatures entering
the convection surface. However, the steam temperatures and spray attemperation may be normal if the
convection surfaces are also fouled.
Another indication of surface cleanliness is draft
loss. By watching draft loss across a bank, an alert
operator can determine that sootblowing is probably
required. Usually, however, by the time a change in
draft loss is detected across widely spaced pendant
sections, the banks are already bridged and it may be
too late for removal by the sootblowers.
Visual observation is frequently used to further
quantify cleanliness conditions. In many instances,
however, access is limited and subjective evaluations
can leave considerable room for error. Advanced methods have been developed to overcome these shortcomings and to improve upon traditional time-based
sootblowing control.
Computer based performance monitoring systems
can provide a direct and quantitative assessment of
furnace and convective surface cleanliness. B&W’s
Heat Transfer Manager™ (HTM) program is based on
the heat transfer analysis program developed over
many years for boiler design and validated by extensive empirical data. The HTM program is configured
on a boiler-specific basis, taking into account the arrangement of the furnace and all convective surface.
Measurements of temperatures, pressures, flows, and
gas analysis data are used to perform heat transfer
analysis in the furnace and convective section on a
bank by bank basis.
Advanced intelligent sootblowing systems have also
been developed to combine this real time assessment
of furnace and convective surface cleanliness with
closed loop control of the cleaning equipment. B&W’s
Powerclean™ system automatically determines where
and when sootblowing should occur in the furnace and
convection pass. Powerclean uses cleanliness data
from the HTM program in an expert decision making
structure that dictates when blowers should be cycled.
Intelligent systems such as Powerclean recognize
problem areas early in their development, so that selective sootblowing can be directed at a specific problem area and ash cleaning equipment is operated
based on need. Intelligent sootblowing systems can
optimize blowing medium use and improve performance while reducing tube damage and providing
consistency to boiler operations.
Slagging can be particularly troublesome in localized areas of the furnace. To help optimize wall cleaning, heat flux sensors can be used. These sensors are
installed in the waterwalls of the furnace and provide
a differential temperature across the wall which
changes in proportion to the amount of deposition.
Sensor data is integrated into the overall intelligent
sootblowing system so that cleanliness can be optimized
in the furnace region. If an array of sensors is installed,
the furnace can be broken into regions for better control
of wall cleaning equipment and to optimize operation.
21-18
Additional discussion of the application of control
systems to local sootblower cleaning requirements is
provided in Chapter 24.
Non-routine ash evaluation methods
The following describes the laboratory equipment
and test procedures, referenced earlier, that are used
to supplement the standard ASTM coal ash characterization methods.
Laboratory ashing furnace
As noted, the ASTM ashing procedure does not
duplicate the ashing process that actually occurs in a
boiler. A laboratory ashing furnace (LAF) provides a
means to obtain flyash and deposit samples that are
comparable to those obtained from full scale installations operating under similar conditions.
B&W’s LAF, shown in Fig. 20, is designed to fire
pulverized coal at rates typically between 5 and 10 lb/
h (2.3 and 4.5 kg/h). The facility consists of a fuel feed
system, pulverized coal burner and a refractory lined
chamber. The combustion chamber is surrounded by
an electrically heated guard furnace which controls
the rate of heat removal from the chamber to simulate full scale furnace temperatures. The firing rate
is established to approximate full scale furnace residence time. A deposition section located at the furnace
exit contains air- or water-cooled probes. The surface
temperature of the probes can be adjusted to simulate
furnace and superheater tube operating temperatures.
Fig. 20 Schematic of laboratory ashing furnace (LAF).
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
The probes are instrumented to allow measurement
of metal temperatures, cooling fluid flow rates, and
cooling fluid inlet and outlet temperatures. These data
permit calculation of the total heat flux from the flue
gas through the deposit and into the probe. The deposition section is also fitted with sootblowers to evaluate the effectiveness of ash removal equipment. Fig.
21 shows ash particles impacting a simulated superheater tube during a deposition test. The B&W LAF
was used to develop extensive data which has now
been correlated to the ash characteristics. These correlations have largely replaced the need for routine
laboratory testing.
Measurement of ash viscosity
Viscosity of coal ash is measured in a high temperature rotating-bob viscometer (Fig. 22). The ash under
study is contained in a cylindrical platinum-rhodium
crucible, and a cylindrical bob is rotated in the liquid
at a constant speed through a calibrated suspension
wire. The torque or amount of twist produced in the
suspension wire is proportional to the viscosity. The
amount of twist is measured and recorded as the interval between impulses from light beams reflected
from mirrors attached to the ends of the wire. The
suspension wires are calibrated against viscosity standard oils obtained from the Bureau of Standards.
The electrically heated furnace is of the Globar tube
type with temperature regulation provided through
a controlling type potentiometer actuated by a thermocouple located in the furnace adjacent to the sample
crucible. A thermocouple imbedded in the ash crucible
support indicates sample temperature. Provision is
made for controlling the atmosphere within the furnace. Ash is introduced into the crucible at an elevated
temperature [2600 to 2800F (1427 to 1538C)] and
held at that temperature until it becomes uniformly
fluid. The temperature is then decreased in predeter-
Fig. 21 Deposit formation on simulated superheater tube.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
Fig. 22 Section through furnace of high temperature viscometer.
mined steps and the viscosity of the ash is measured
at each temperature.
Ash sintering strength
The sintering strength test is performed on a flyash
sample prepared in the LAF under a standard set of
firing conditions. The flyash is passed through a 60
mesh (U.S. standard) (250 micron) screen to remove
any particles of slag and then ignited to constant
weight at 900F (482C) to remove any carbon that
might be present. The ignited ash is then reduced to
a minus 100 mesh size and at least 24 cylindrical specimens [0.6 in. (15.2 mm) diameter by 0.85 in. (21.6 mm)
long] are formed in a hand press at a pressure of 150 psi
(1034 kPa). At least six specimens are heated in air, usually at each of four temperature levels [1500, 1600, 1700
and 1800F (816, 871, 927 and 982C)] for 15 hours.
After the specimens have cooled slowly in the furnace, they are removed, measured and then crushed
in a standard metallurgical testing machine. The sintered or compression strength is then computed from
the applied force and the cross-sectional area of the
sintered specimen. The average strength of six specimens is used as the strength of the sintered flyash at
a particular sintering temperature.
Measurement of ion exchangeable cations in coal
Twenty grams of an air-dried minus 60 mesh coal
sample are mixed with 100 ml of 1 N ammonium acetate in a 300 ml three-neck round bottom flask. A
thermometer is inserted into the slurry. The slurry is
stirred constantly and heated to 60 ±5C. The coal
slurry sample is refluxed for 18 hours. The sample is
filtered through a cellulosic filter media with 0.45 µ
21-19
The Babcock & Wilcox Company
average pore size and washed twice with 25 ml of 1 N
ammonium acetate solution.
The above procedure is repeated on the filtered coal
except that the time is shortened to three hours. The
combined filtrates are acidified by adding 2% by volume of glacial acetic acid and stored for inductive
coupled plasma atomic emission spectrometric
(ICPAES) analysis of Na, K, Ca and Mg.
Coal ash corrosion
Serious external wastage or corrosion of high temperature superheater and reheater tubes was first
encountered in coal-fired boilers in 1955. Tube failures resulting from excessive thinning of the tube
walls, as shown in Fig. 23, occurred almost simultaneously in the reheater of a dry ash furnace boiler and
the secondary superheater of a slag-tap furnace unit.
Corrosion was confined to the outlet tube sections of
the reheater and the secondary superheater, which
were made from chromium ferritic and stainless steel
alloys, respectively.
Significantly, these boilers were among the first to
be designed for 1050F (566C) main and reheat steam
temperatures; also, both units burned high sulfur,
high alkali Central and Southern Illinois coals, which
were causing chronic ash fouling problems at the time.
Early investigations showed that corrosion occurred
where complex alkali sulfates concentrated on tube
surfaces beneath bulky layers of ash and slag. When
dry, the complex sulfates were relatively innocuous; but
when semi-molten [1100 to 1350F (593 to 732C)], they
corroded the alloy steels used in superheater construction, and also other normally corrosion resistant alloys.
At first, it appeared that coal ash corrosion might
be confined to boilers burning high alkali coals, but
complex sulfate corrosion was soon found on super-
Fig. 23 Typical corroded 18Cr-8Ni tube from secondary superheater.
21-20
heaters and reheaters of several boilers burning low
to medium alkali coals. Where there was no corrosion,
the complex sulfates were either absent or the tube
metal temperatures were moderate [less than 1100F
(593C)]. The general conclusions drawn from this
survey of corrosion were:
1. All bituminous coals contain enough sulfur and
alkali metals to produce corrosive ash deposits on
superheaters and reheaters, and those containing
more than 3.5% sulfur and 0.25% chlorine may
be particularly troublesome.
2. Experience has shown that corrosion rate is affected by both tube metal temperature and gas
temperature. Fig. 24, which is used as a guide in
design, indicates stable and corrosive zones of fuel ash
corrosion as a function of gas and metal temperatures.
Based on this information, B&W modified the design of its boilers to greatly reduce the corrosion of
superheaters and reheaters. These modifications included changes in furnace geometry, burner configuration, superheater arrangement and the use of gas
tempering, all of which reduced metal and gas temperatures and reduced temperature imbalances. Experience from these installations has shown that it is
possible to operate boilers with main and reheat steam
temperatures up to 1050F (566C) with little, if any,
corrosion from most coals.
Meanwhile, there was a gradual return to the
1000F (538C) steam conditions, due primarily to economic factors and secondarily to coal ash corrosion.
This temperature level has permitted the use of lower
cost alloys in the boiler, steam piping and turbine, with
substantial savings in investment costs; it also has
provided a greater margin of safety to avoid corrosion.
Steam temperatures remained on the 1000F (538C)
plateau for several decades. However, improved alloy
creep and corrosion resistance and the potential for
Fig. 24 Coal ash corrosion – stable and corrosive zones.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
cycle efficiency improvement have led to increased
steam temperatures in the newest generation of utility boilers. Some recent boilers have been designed
with main and reheat steam temperatures at and above
1100F (593C), and temperatures of 1200F (640C) and
above are envisioned.
General characteristics of corrosion
External corrosion of superheaters and reheaters
is concentrated on the upstream side of the tube, as
shown in Fig. 25. The greatest metal loss usually occurs on the 10 and 2 o’clock sectors of the tubes, and
it tapers off to little or none on the back side of the
tubes. The corroded surface of the tube is highly sculptured by a shallow macropitting type of attack. The
amount of corrosion, as measured by reduction in tube
wall thickness, varies considerably along the length
of the tube, depending on local conditions, i.e., the
position of the tube in the bank or platen, the proximity of sootblowers, the composition of ash deposits and,
most importantly, the gas and metal temperatures.
The corrosion rate is a nonlinear function of metal
temperature (Fig. 26). Typically, the corrosion of both
chromium ferritic and 18Cr-8Ni stainless steels increases sharply above a temperature of 1150F (621C),
passes through a broad maximum between 1250 and
1350F (677 and 732C) and then decreases rapidly at
still higher temperatures. However, the corrosion behavior varies depending on gas and ash chemistries
and other factors, as well as temperatures.
The highest corrosion rates are generally found on
the outlet tubes of radiant superheater or reheater
platens opposite retractable sootblowers. Values ranging from 50 to 250 mils/yr (1.27 to 6.35 mm/yr) have
been observed on 18Cr-8Ni stainless steel tubes under these adverse conditions. When similar high temperature surfaces [1100 to 1175F (593 to 635C)] are
arranged in convection tube banks so they are
shielded from direct furnace radiation and sootblower
action, corrosion rates are much lower, ranging between 5 and 20 mils/yr (0.13 to 0.51 mm/yr).
Fig. 26 Effect of temperature on corrosion rate.
to that of flyash. Though often hard and brittle, this
layer is a porous structure through which gases may
diffuse. Innocuous by itself, it plays an important part
in the formation of an intermediate layer that contains
the corrosive agents.
The intermediate layer, frequently called the white
layer, is a white to yellow colored material which varies in thickness from 0.03 to 0.25 in. (0.76 to 6.35 mm).
It usually has a chalky texture where corrosion is mild
or nonexistent, but is fused and semi-glossy where corrosion is severe. In the latter condition this layer is difficult to remove as it is so firmly bonded to the corroded
surface beneath.
Corrosive ash deposits
Corrosion is rarely found on superheater or reheater
tubes having only dusty deposits. It is nearly always
associated with sintered or slag type deposits that are
strongly bonded to the tubes. Such deposits consist of
at least three distinct layers. The outer layer, shown
diagrammatically in Fig. 27, constitutes the bulk of
the deposit and has an elemental composition similar
Fig. 25 Transverse sections of corroded tubes from secondary
superheater platens.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
Fig. 27 Analyses of typical ash deposit from 18Cr-8Ni superheater tube.
21-21
The Babcock & Wilcox Company
Upon heating in the air, the intermediate layer
melts around 1000F (538C) and slowly discolors and
hardens into a hard mass resembling rust. Chemical
analyses of this layer show that it contains higher concentrations of potassium, sodium and sulfur than does
the parent coal ash. A large part of this deposit is water
soluble and the water soluble fraction is always acidic.
The most common compounds found are Na3Fe(SO4)3
and KAl(SO4)2.
Complex alkali sulfates, when molten, rapidly corrode most, if not all, superheater alloys. Corrosion
begins between 1000 and 1150F (538 and 621C), depending on the relative amounts of complex sodium
and potassium sulfates present and whether these are
predominantly iron or aluminum base compounds.
Corrosion usually begins at the lower temperature
where the sodium-iron-sulfate system is the major part
of the intermediate layer, but corrosion is more severe
and persists into a higher temperature range when
the potassium-aluminum-sulfate system dominates.
If the intermediate layer is carefully removed, a
black, glassy inner layer is revealed, which appears
to have replaced the normally protective oxide on the
tube. This layer is composed primarily of corrosion
products, i.e., oxides, sulfides, and sulfates of iron and
other alloying constituents in the tube metal. It seldom exceeds 0.063 in. (1.59 mm) thickness on corroded
18Cr-8Ni stainless steel tubes, probably because of its
strong tendency to spall when the tubes cool. The layer
containing corrosion products from chromium ferritic
steels often reaches 0.125 in. (3.18 mm) thickness and
exhibits little tendency to spall as the tube cools.
Corrosion mechanisms
The elements in coal ash corrosion (sodium, potassium, aluminum, sulfur and iron) are derived from the
mineral matter in coal. The minerals supplying these
elements include shales, clays and pyrites which are
commonly found in all coals.
During the combustion of coal, these minerals are
exposed to high temperatures and strongly reducing
effects of carbon for very short periods of time. Although comparatively stable, the mineral matter undergoes rapid decomposition under these conditions.
Some of the alkalies are released or volatilized as relatively simple compounds, which have dew points in
the 1000 to 1300F (538 to 704C) range. Furthermore,
sulfur in the coal is oxidized, releasing SO2 with the
formation of a small amount of SO3, leaving a residue
of iron oxide (Fe2O3).
By far the largest portion of the mineral matter or
its derived species react to form the glassy particulates
of flyash. The flyash and volatile species in the flue
gases deposit on the tube surfaces. Slowly, over a period of weeks, the alkalis and the sulfur oxides diffuse
through the layer of flyash toward the tube surface.
In the lower temperature zone of the ash deposit,
chemical reactions between the alkalis, the sulfur oxides, and the iron and aluminum components of the
flyash form complex alkali sulfates as follows:
3K 2 SO4 + Fe2 O3 + 3SO3 → 2K 3 Fe ( SO4 )3
21-22
and
K 2 SO4 + Al 2 O3 + 3SO3 → 2KAl ( SO4 )2
(13)
Similar reactions occur with sodium sulfate (Na2SO4),
although the complex sodium sulfates are less apt to form
at high temperatures because of their lower stability.
Work at B&W has shown that SO3 concentrations
in ash deposits must be very high (1000 to 1500 ppm)
compared to the level in the flue gas (10 to 25 ppm) in
order to form the complex alkali sulfates in the intermediate layer. Therefore, the bulk of the SO3 must
come from the catalytic oxidation of SO2 in the outer
layer of the deposit.
When the SO3 produced in the outer deposit exceeds
the partial pressure of SO3 necessary for stability, the
complex sulfates form through the above reactions.
When the opposite is true, the complex sulfates begin
to decompose according to the reverse of these reactions until a new equilibrium is reached. Because the
formation of SO 3 is temperature dependent, the
reversibility of these reactions is also temperature
dependent. As shown in Fig. 26 the corrosion rate increases with temperature, passes through a maximum
between 1250 and 1350F (677 and 732C), and then falls
to a comparatively low level at higher temperatures.
The temperature range of this rapid liquid-phase
attack is bracketed by: 1) the melting temperature of
the mixture of complex alkali sulfates present, and 2)
their thermal stability limits. The extreme width of this
temperature band is approximately 400F (222C); corrosion due to the complex alkali sulfates may range
from as low as 1000F (538C) to a maximum of 1400F
(760C), depending on the species present in the intermediate layer.
Corrective measures
Various methods of combating corrosion of superheater and reheater tubes have been used or suggested, including the following:
1. the use of stainless steel shields to protect the most
vulnerable tubes,
2. coal selection,
3. improvement of combustion conditions, i.e., providing proper coal fineness, fast ignition, good mixing and proper excess air, and
4. the use of more corrosion resistant alloys and alloy cladding on the most vulnerable superheater
and reheater tubes. (See Chapter 19.)
New high chromium content stainless steels are
generally more resistant to coal ash corrosion, but
added chromium tends to degrade other metallurgical properties. New modified 25% chromium 20%
nickel stainless steels offer improved performance for
moderate conditions. Higher chromium nickel-based
alloys and cladding offer maximum resistance for the
most severe conditions.
Fuel oil ash
The ash content of residual fuel oil seldom exceeds
0.2%, an exceedingly small amount compared to that
in coal. Nevertheless, even this small quantity of ash
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
is capable of causing severe problems of deposition and
corrosion in boilers. Of the many elements that may
appear in oil ash deposits, the most important are vanadium, sodium and sulfur. Compounds of these elements are found in almost every deposit in boilers fired
by residual fuel oil and often constitute the major portion of these deposits.
Origin of ash
As with coal, some of the ash-forming constituents
in the crude oil had their origin in animal and vegetable matter from which the oil was derived. The
remainder is extraneous material, resulting from contact of the crude oil with rock structures and salt
brines, or is picked up during refining processes, storage and transportation. (See Chapter 9.)
In general, the ash content increases with increasing asphaltic constituents in which the sulfur acts
largely as a bridge between aromatic rings. Elemental sulfur and hydrogen sulfide have been identified
in crude oil, and simpler sulfur compounds are found
in the distillates of crude oil including thioesters, disulfides, thiophenes and mercaptans.
Vanadium, iron, sodium, nickel and calcium in the
fuel oil were probably derived from the rock strata but
some elements, such as vanadium, nickel, zinc and
copper, probably came from organic matter from which
the petroleum was derived. Vanadium and nickel especially are known to be present in organo-metallic
compounds known as porphyrins which are characteristic of certain forms of animal life. Table 7 indicates
the amounts of vanadium, nickel and sodium present
in residual fuel oils from various crudes.
Crude oil as such is not normally used as a fuel but
is further processed to yield a wide range of more valuable products. For example, in a modern U.S. refinery, 92.4% of the crude is converted to lighter fraction
fuels and products such as gasoline, leaving 7.6% of
Table 7
Vanadium, Nickel and Sodium
Content of Residual Fuel Oils
(ppm by wt)
Source of
Crude Oil
Africa:
1
2
Middle East:
3
4
5
U.S.:
6
7
8
Venezuela:
9
10
11
12
13
residual fuel oil or distillate residue. Virtually all metallic compounds and a large part of the sulfur compounds are concentrated in the distillation residue.
Where low sulfur residual fuel oils are required, they
are obtained by blending with suitable stocks, including both heavy distillates and distillation from low
sulfur crudes. This procedure is also used occasionally
if a residual fuel oil must meet specifications such as
vanadium or ash content.
Release of ash during combustion
Residual fuel oil is preheated and atomized to provide enough reactive surface so that it will burn completely within the boiler furnace. (See Chapter 11.)
The atomized fuel oil burns in two stages. In the first
stage the volatile portion burns and leaves a porous
coke residue and in the second stage the coke residue
burns. In general, the rate of combustion of the coke
residue is inversely proportional to the square of its
diameter, which in turn is related to the droplet diameter. Therefore, small fuel droplets give rise to coke
residues that burn very rapidly, and the ash forming
constituents are exposed to the highest temperatures
in the flame envelope. The ash forming constituents
in the larger coke residues from the larger fuel droplets are heated more slowly, partly in association with
carbon. Release of the ash from these residues is determined by the rate of oxidation of the carbon.
During combustion, the organic vanadium compounds in the residual fuel oil thermally decompose
and oxidize in the gas stream to V2O3, V2O4 and finally
V2O5. Although complete oxidation may not occur and
there may be some dissociation, a large part of the
vanadium originally present in the oil exists as vapor
phase V 2O 5 in the flue gas. The sodium, usually
present as chloride in the oil, vaporizes and reacts
with sulfur oxides either in the gas stream or after
deposition on tube surfaces.
Subsequently, reactions take place between the vanadium and sodium compounds, with the formation
of complex vanadates having melting points lower
than those of the parent compounds; for example:
Na2 SO4 + V2O5 → 2Na VO3 + SO3 ↑
Melting points: 1625F
Vanadium
Nickel
Sodium
5.5
1
5
5
22
−
7
173
47
−
51
10
1
−
8
13
6
11
−
2.5
−
350
120
84
−
57
380
113
93
6
13
60
21
−
480
72
70
49
38
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
1275F
1165F
(14)
Excess sodium or vanadium in the ash deposit, above
that necessary for the formation of the sodium vanadates (or vanadylvanadates), may be present as
Na2SO4 and V2O5, respectively.
The sulfur in residual fuel oil is progressively released during combustion and is promptly oxidized to
SO2. A small amount of SO2 is further oxidized to SO3
by a small amount of atomic oxygen present in the
hottest part of the flame. Also, catalytic oxidation of
SO2 to SO3 may occur as the flue gases pass over vanadium rich ash deposits on high temperature superheater tubes and refractories. (See Chapter 35.)
Oil slag formation and deposits
The deposition of oil ash constituents on the furnace
walls and superheater surfaces can be a serious problem. This deposition, coupled with corrosion of super21-23
The Babcock & Wilcox Company
heater and reheater tubes by deposits, was largely
responsible for the break in the trend towards higher
steam temperatures that occurred in the early 1960s.
Practically all boiler installations are typically designed for steam temperatures in the 1000 to 1015F
(538 to 546C) range to minimize those problems and
to avoid the higher capital costs of the more expensive alloys required in the tubes, steam piping and turbine for 1050 to 1100F (566 to 593C) steam conditions.
There are many factors affecting oil ash deposition
on boiler heat absorbing surfaces. These factors may
be grouped into the following interrelated categories:
characteristics of the fuel oil, design of the boiler, and
operation of the boiler.
Characteristics of fuel oil ash
Sodium, sulfur and vanadium are the most significant elements in the fuel oil because they can form
complex compounds having low melting temperatures,
480 to 1250F (249 to 677C), as shown in Table 8. Such
temperatures fall within the range of tube metal temperatures generally encountered in furnace and superheater tube banks of many oil-fired boilers. However, because of its complex chemical composition, fuel
oil ash seldom has a single sharp melting point, but
rather softens and melts over a wide temperature
range.
An ash particle that is in a sticky, semi-molten state
at the tube surface temperature may adhere to the
tube if it is brought into contact by the gas flow over
the tube. Even a dry ash particle may adhere due to
mutual attraction or surface roughness. Such an initial deposit layer will be at a higher temperature than
that of the tube surface because of its relatively low
thermal conductivity. This increased temperature promotes the formation of adherent deposits. Therefore,
fouling will continue until the deposit surface temperature reaches a level at which all of the ash in the
gas stream is in a molten state, so that the surface is
merely washed by the liquid without freezing and
continued buildup.
In experimental furnaces, it has been found that
the initial rate of ash buildup was greatest when the
sodium-vanadium ratio in the fuel oil was 1:6, but an
equilibrium thickness of deposit [0.125 to 0.25 in.
(3.175 to 6.35 mm)] was reached in approximately 100
hours of operation. When the fuel oil contained more
refractory constituents, such as silica, alumina and
iron oxide, in addition to sodium and vanadium, an
equilibrium condition was not reached and the tube
banks ultimately plugged with ash deposits. However,
these ash deposits were less dense, i.e., more friable,
than the glassy slags encountered with a 1:6 sodiumvanadium fuel oil. Both the rate of ash buildup and
the ultimate thickness of the deposits are also influenced by physical factors such as the velocity and temperature of the flue gases and particularly the tube
metal temperature.
In predicting the behavior of a residual oil insofar
as slagging and tube bank fouling are concerned, several fuel variables are considered including: 1) ash
content, 2) ash analysis, particularly the sodium and
vanadium levels and the concentration of major con21-24
stituents, 3) melting and freezing temperatures of the
ash, and 4) the total sulfur content of the oil. Applying this information in boiler design is largely a matter of experience.
Boiler design
Generally speaking, progressive fouling of furnaces
and superheaters should not occur as long as the ash
characteristics are not severe compared to the tube
metal temperatures. If such trouble is encountered,
the solution can usually be found in improving combustion conditions in the furnace and/or modifying the
sootblowing procedures.
Studies on both laboratory and field installations
have shown that the rate of ash deposition is a function of the velocity and temperature of the flue gases
and the concentration of oil ash constituents in the flue
gases. The geometry of the furnace and the spacing
of tubes in the convection banks are selected in the
design of a boiler to minimize the rate of deposition.
It is common practice to use in-line tube arrangements
with wider lateral spacings for tubes located in higher
gas temperature zones. This makes bridging of ash
deposits between tubes less likely and facilitates cleaning of tube banks by the sootblowers.
Boiler operation
Poor atomization of the fuel oil results in longer
flames and frequently increases the rate of slag
buildup on furnace walls which, in turn, makes it more
difficult to keep the convection sections of the boiler
clean. Completing combustion before the gases pass
over the first row of tubes is especially important.
Table 8
Melting Points of Some Oil Ash Constituents
Compound
Melting Point, F (C)
Aluminum oxide, Al2O3
Aluminum sulfate, Al2(SO4)3
Calcium oxide, CaO
Calcium sulfate, CaSO4
Ferric oxide, Fe2O3
Ferric sulfate, Fe2(SO4)3
Nickel oxide, NiO
Nickel sulfate, NiSO4
Silicon dioxide, SiO2
Sodium sulfate, Na2SO4
Sodium bisulfate, NaHSO4
Sodium pyrosulfate, Na2S2O7
Sodium ferric sulfate, Na3Fe(SO4)3
Vanadium trioxide, V2O3
Vanadium tetroxide, V2O4
Vanadium pentoxide, V2O5
Sodium metavanadate,
Na2O V2O5(NaVO3)
Sodium pyrovanadate, 2Na2O V2O5
Sodium orthovanadate, 3Na2O V2O5
Sodium vanadylvanadates,
Na2O V2O4 V2O5
5Na2O V2O4 1V2O5
•
•
•
•
•
•
•
3720
1420 *
4662
2640
2850
895 *
3795
1545 *
3130
1625
480 *
750 *
1000
3580
3580
1275
(2049)
(771)
(2572)
(1449)
(1566)
(479)
(2091)
(841)
(1721)
(885)
(249)
(399)
(538)
(1971)
(1971)
(691)
1165
1185
1560
(629)
(641)
(849)
1160
995
(627)
(535)
* Decomposes at a temperature around the melting point.
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Relatively large carbonaceous particles have a far
greater tendency to impinge on the tubes than do the
smaller ash particles. If these larger particles are in a
sticky state, they will adhere to the tubes where oxidation will proceed at a slow rate with consequent
formation of ash. Fouling from this cause is difficult
to detect by inspection during boiler outages because
the carbonaceous material has usually disappeared
completely. It can generally be detected during operation because flames are usually long and smoky, and
sparklers may be carried along in the flue gases.
Regular and thorough sootblowing can have a decisive effect on superheater and reheater fouling. (See
Chapter 24.) To be fully effective, however,
sootblowing cycles should be frequent enough so that
ash deposits can not build to a thickness where their
surfaces become semi-molten and difficult to remove.
In instances of extreme slagging, it is sometimes necessary to relocate sootblowers, to install additional
sootblowers to control deposition in a critical zone, or
to use additives.
The boiler load cycle can also have a significant effect on the severity of slagging and superheater fouling. A unit that is base loaded for long periods is more
apt to have fouling problems on a borderline fuel oil
than a unit that takes daily swings in load. In the latter instance, the furnace generally remains cleaner
due to periodic shedding of slag, with the result that
the gas temperatures through the superheaters are
appreciably lower. This eases the burden on the
sootblowers and substantially controls ash deposit formation in the superheater-reheater tube banks. Overloading the boiler, even for an hour or two a day,
should be avoided, especially if excess air has to be
lowered to the point where some of the burners are
starved of air. The furnace is apt to become slagged
and ash deposition can creep into the superheater and
reheater tube banks.
tubes. High chromium contents, greater than 30%,
give added corrosion resistance but at the expense of
physical properties; 25Cr-20Ni has been used as a tube
cladding but even this alloy has not provided complete
protection. High-nickel high-chromium alloys may be
more resistant to oil ash attack under oxidizing conditions, but the higher material cost must be justified
by longer life, which is not always predictable.
Low temperature corrosion
In oil-fired boilers, the problem of low temperature
corrosion resulting from the formation and condensation of sulfuric acid from the flue gases is similar to
that previously described for coal firing.
Oil-fired boilers are more susceptible to low temperature corrosion than are most coal-fired units for
two reasons: 1) the vanadium in the oil ash deposits
is a good catalyst for the conversion of SO2 to SO3, and
2) there is a smaller quantity of ash in the flue gases.
Ash particles in the flue gas react with and reduce the
amount of SO3 vapor in the gas, and oil has considerably less ash than coal. Furthermore, coal ash is more
basic than oil ash and more effectively neutralizes acid.
Methods of control
The methods of control that have been used or proposed to control fouling and corrosion in oil-fired boilers are summarized in Table 9, but in every instance
economics govern their applicability. There is no doubt
that reducing the amount of ash and sulfur entering
Oil ash corrosion
High temperature corrosion
The sodium-vanadium complexes, usually found in
oil ash deposits, are corrosive when molten. A measurable corrosion rate can be observed over a wide range
of metal and gas temperatures, depending on the
amount and composition of the oil ash deposit. Fig. 28
shows the combined gas and metal temperature effects
on corrosion for a specific fuel oil composition of 150
ppm vanadium, 70 ppm sodium and 2.5% sulfur. As
the vanadium concentration of the fuel oil varies, the
amount of corrosion, compared to a 150 ppm vanadium
fuel, will increase or decrease according to the curve
shown in Fig. 29. The effect of the sodium level in the
fuel oil is not as clear. The sodium content does, however, definitely affect the minimum metal temperature
at which corrosion will be significant.
At the present time there appears to be no alloy that
is immune to oil ash corrosion. In general, the higher
the chromium content of the alloy, the more resistant
it is to attack. This is the main reason for the use of
18Cr-8Ni alloys for high temperature superheater
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
Fig. 28 Effect of gas and metal temperatures on corrosion of 304,
316 and 321 alloys in a unit fired with oil containing 150 ppm vanadium, 70 ppm sodium and 2.5% sulfur. Test duration 100 hours.
21-25
The Babcock & Wilcox Company
Fig. 29 Effect of vanadium concentration on oil ash corrosion.
the furnace is the surest means of control and that
minimizing the effects of the ash constituents, once
they have deposited on the tubes, is the least reliable.
Because the severity of fouling and corrosion depends
not only on the fuel oil characteristics but also on boiler
design and operating variables, a generalized solution
to these problems can not be prescribed.
Fuel oil supply
Although fuel selection and blending are practiced to
some extent in the U.S., the common purpose is to provide safe and reliable handling and storage at the power
plant rather than to avoid fouling difficulties. Because
the threshold limits of sodium, sulfur and vanadium are
not well defined for either fouling or corrosion, use of
these means of control can not be fully exploited.
Fuel oil additives
An approach that is effective where the fuel oil ash
is most troublesome involves adding, to the fuel or
furnace, small amounts of materials that change the
character of the ash sufficiently to permit its removal
by steam or air sootblowers or air lances.
Additives are effective in reducing the problems
associated with superheater fouling, high temperature ash corrosion and low temperature sulfuric acid
corrosion. Most effective are alumina, dolomite and
magnesia. Kaolin is also a source of alumina. Analyses of typical superheater deposits from a troublesome
fuel oil, before and after treating it with alumina or
dolomite, are shown in three bar graphs on the left of
Fig. 30. The results for a different oil treated with
magnesia are shown in the bar graph on the right.
The reduction of fouling and high temperature corrosion is accomplished basically by producing a high
melting point ash deposit that is powdery or friable
and easily removed by sootblowers or lances. When
the ash is dry, corrosion is considerably reduced.
21-26
Low temperature sulfuric acid corrosion is reduced
by the formation of refractory sulfates by reaction
with the SO3 gas in the flue gas stream. By removing
the SO3 gas, the dew point of the flue gases is sufficiently reduced to protect the metal surfaces. The sulfate compounds formed are relatively dry and easily
removed by the normal cleaning equipment.
In general, the amount of additive used should be
about equal to the ash content of the fuel oil. In some
instances, slightly different proportions may be required for best results, especially for a high temperature corrosion reduction, in which it is generally accepted that the additive should be used in weight ratios of 2:1 or 3:1 (additive/ash), based on the vanadium content of the oil.
Several methods have been successfully used to introduce the additive materials into the furnace. The
one in general use consists of metering a controlled
amount of an additive oil slurry in the burner supply
line. The additive material should be pulverized to
100% through a 325 mesh (44 micron) screen for good
dispersion and minimum atomizer wear.
For a boiler fired by a high pressure return flow oil
system (Chapter 11), it has been found advantageous
to introduce the additive powders by blowing them
into the furnace at the desired locations. The powder
has to be reduced in size to 100% through a 325 mesh
(44 micron) screen for good dispersion.
The choice of a particular additive depends on its
availability and cost to the individual plant and the
method of application chosen. For example, alumina
causes greater sprayer plate wear than the other materials when used in an oil slurry.
The quantity of deposit formed is, of course, an important consideration for each unit from the aspect of
cleaning. A comparison of the amounts of deposit
Table 9
Classification of Methods for Controlling Fouling
and Corrosion in Oil-Fired Boilers
Fuel Oil Supply
Reduce amount of fuel ash
constituents to the furnace
Selection
Blending
Purification
Design
Minimize amounts of fuel
ash constituents reaching
heat transfer surfaces
Furnace geometry
Tube bank arrangement
Metal temperature
Gas temperature
Sootblower arrangement
Operation
Minimize effects of bonding
and corrosive compounds in
ash deposits
Load cycle
Sootblowing schedule
Combustion excess air
Additives
Water washing
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Fig. 31 Effect of low excess air combustion on high temperature oil
ash corrosion.
Fig. 30 Effect of fuel oil additives on composition of oil ash deposit.
formed with different additives shows that dolomite
produces the greatest quantity because of its sulfating ability, magnesia is intermediate, and alumina and
kaolin form the least. However, when adequate cleaning facilities are available, the deposits are easily removed
and the quantities formed should not be a problem.
Excess air control
As mentioned previously the problems encountered
in the combustion of residual fuel oils – high temperature deposits (fouling), high temperature corrosion and
low temperature sulfuric acid corrosion – all arise from
the presence of vanadium and sulfur in their highest
states of oxidation. By reducing the excess air from
7% to 1 or 2%, it is possible to avoid the formation of
fully oxidized vanadium and sulfur compounds and,
thereby, reduce boiler fouling and corrosion problems.
In a series of tests on an experimental boiler, it was
found that the maximum corrosion rate of type 304
stainless steel superheater alloy held at 1250F (677C)
in 2100F (1149C) flue gas was reduced more than
75% (Fig. 31) when the excess air was reduced from
an average of 7% to a level of 1 to 2%. Moreover, the
ash deposits that formed on the superheater bank
were soft and powdery, in contrast to hard, dense deposits that adhered tenaciously to the tubes when the
excess air was around 7%. Also, the rate of ash buildup
was only half as great. Operation at the 1 to 2% excess air level practically eliminated low temperature
corrosion of carbon steel at all metal temperatures
above the dew point of the flue gases (Fig. 32). However, much of the beneficial effects of low excess air
combustion are lost if the excess air at the burner fluctuates even for short periods of time to a level of about
5%. Carbon loss values for low excess air were ap-
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
proximately 0.5%, which is generally acceptable for
electric utility and industrial practice.
A number of large industrial boilers both in the U.S.
and in Europe have been operating with low excess
air for several years. As a result, the benefits of reducing low temperature corrosion are well established.
However, the benefits on high temperature slagging
and corrosion are not wholly conclusive. In any event,
great care must be exercised to distribute the air and
fuel oil equally to the burners, and combustion conditions must be continuously monitored to assure that
combustion of the fuel is complete before the combustion gases enter the convection tube banks.
Fig. 32 Effect of excess air on low temperature corrosion of carbon steel.
21-27
The Babcock & Wilcox Company
Two coal-fired boilers: one 685 MW pulverized coal unit and one 844 MW unit with CycloneTM furnaces.
21-28
Steam 41 / Fuel Ash Effects on Boiler Design and Operation
The Babcock & Wilcox Company
Chapter 22
Performance Calculations
The evaluation of boiler performance involves many
complex factors as indicated in preceding chapters.
Only a few of these factors are subject to precise analysis; many others are the result of data taken from
operating units. Ash in the fuel has perhaps the most
dramatic impact on boiler performance as discussed
in Chapter 21. In spite of the large number of variables, boilers are designed, built and operated in conformance with design specifications.
A well-designed and operated boiler completes combustion within the furnace. Flue gas temperatures
leaving the furnace can be predicted by the methods
presented in Chapter 4. Beyond the furnace, heat
transfer surface arrangements represent a balance of
temperature difference, space, pressure drop and draft
losses. The final selection of these surface arrangements represents a compromise on the designer’s part
in meeting performance requirements while controlling ash deposition, corrosion, and erosion.
This chapter introduces the basic principles of boiler
performance calculations. It illustrates the use of heat
transfer, thermodynamics and fluid mechanics to determine heat and material balances for given boiler
heat transfer components through practical application. These principles, as well as fundamental relationships, experimental data, operational experience and
designer knowledge, are being incorporated into advanced numerical computational models for boiler
evaluation. As discussed in Chapter 6 and elsewhere
in Steam, these models are becoming increasingly
useful in the design of boilers.
For the fossil fuel-fired steam generators being considered, the hotter heat transfer medium consists of the
products of combustion, or flue gases. The cooler meNote: To avoid the confusion of dual units, this chapter
is provided in English units only. See Appendix 1 for SI
conversion factors.
Steam 41 / Performance Calculations
dium is superheated steam, steam-water mixtures at
saturation, water or air depending upon the heat transfer component under consideration. Heat transfer surfaces can be categorized into one of four cases according to relative hot and cold medium flow direction and
temperature as shown in Fig. 1. Typically, boiler banks
or screens are Case I, superheaters and reheaters are
either Case II or III, economizers are Case II or III,
and air heaters are generally Case IV.
Performance calculations are typically used to establish one of three parameters: temperature, heat
transfer surface area, or surface cleanliness. As in most
thermal analysis problems, the evaluation of boiler
performance is an iterative process. To evaluate flue gas
and steam temperatures for a known boiler design arrangement, the surface area and surface cleanliness
are normally known while the temperatures are assumed. The outlet temperature calculation updates
subsequent iterations until convergence between assumed and calculated temperatures is achieved.
Heat transfer surface area or sizing can be determined for given fluid temperatures and surface cleanliness by assuming an initial surface arrangement and
then confirming the desired thermal performance by
calculation. High calculated outlet flue gas temperatures indicate the need for additional surface whereas
low calculated outlet flue gas temperatures indicate
the need to remove surface. Surface area is adjusted
until calculated and specified temperatures converge.
Finally, for a given boiler configuration, measured
temperatures can be used to assess surface cleanliness. An initially assumed cleanliness is used with the
measured temperatures and known surface to verify
the temperature data. The cleanliness factors are varied until temperature convergence is achieved.
When calculating the thermal performance of heat
transfer equipment, initial temperatures are selected
in part based upon past experience. These are used
to establish the thermophysical properties, calculate
mean temperature differences and solve the problem.
22-1
The Babcock & Wilcox Company
The specific analysis procedure is started at slightly
different steps depending upon whether an existing
piece of equipment is being analyzed or a new plant
is being designed. For an existing installation, boiler
performance calculations begin by confirming heat
transfer equipment geometry and by defining the required operating conditions. Heat and material balances, including combustion calculations for the steam
generator as a whole, are then determined. These
calculations provide the information required to analyze each heat recovery component. The performance
of each component is often intimately tied to other
components within the boiler. As discussed in Chapter 1, the calculation process normally follows the direction of flue gas flow from furnace to stack and that
is the approach used in the following example. Predictions of boiler performance are only complete when the
performance of all devices within the boiler envelope
agrees with the overall unit heat and material balances.
If a new plant is being analyzed, the process begins with the heat and material balances to establish
air, fuel, feedwater and flue gas handling requirements. The process then continues with the iterative
determination of heat transfer surface and equipment
sizing as discussed above.
Because air resistance and draft loss calculations,
including stack effects, are dependent on established
air and gas temperature profiles through the boiler
and accessories, they are determined after any thermal analysis. Pressure drop calculations are included
in each component’s evaluation. Flue and duct resistance calculations and the evaluation of stack effects
are the final steps in the performance calculations.
For the example considered here, dimensional pa-
Fig. 1 Log mean temperature difference (LMTD) for selected heat
exchanger configurations – single phase except for Case I colder
fluid. (*As discussed in Chapter 4, a configuration factor F is needed
for the case of crossflow.)
The resulting final temperatures are compared to the
original assumptions. Generally, if an error of 5F or
less is observed between iteration steps, the solution
is considered complete. Otherwise, the new temperature is used to repeat the analysis.
To illustrate performance calculations, a small boiler
(Fig. 2) with a simplified furnace and heating surface
arrangement will serve as an example. The objective
is to evaluate the outlet flue gas temperatures for the
given surface area and cleanliness. The procedures
developed here are fundamental and as such can be
used on a wide range of boiler applications.
Operating conditions
Boiler performance specifications are defined by the
customer. These specifications normally include: steam
output conditions – pressure, temperature and flow;
feedwater conditions; fuel and ash analysis; load
range; capability; and efficiency. The final boiler design efficiently meets the specifications with a minimum of surface, materials and flow losses.
22-2
Fig. 2 Example of a coal-fired industrial boiler, sectional side view.
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
rameters are contained in Table 1, while Table 2 contains the specified operating conditions. The remainder of this chapter focuses on predicting performance
for the hypothetical boiler.
Heat and material balances
Heat and material balances begin with combustion
calculations. For this example, combustion calculations are determined by the Btu method as presented
in Chapter 10. For the fuel analysis and losses specified in Table 2, the combustion calculations are summarized in Table 3.
The unit is expected to produce 250,000 lb/h superheated steam at 450 psig and 650F with feedwater
conditions of 470 psig and 220F entering the economizer. The energy output, or heat in steam, is calculated to be 285.6 × 106 Btu/h (See Table 3, line 10).
The combustion calculations of Table 3 also define
key parameters which guide much of the subsequent
equipment design – heat input (328.6 × 106 Btu/h,
Table 3, line 54), gas weight (324,100 lb/h, Table 3,
line 56), air weight (302,500 lb/h, Table 3, line 58) and
heat available (1034 Btu/lb Table 3, line 60). These
values are noted for future reference.
This completes the heat and material balances and
combustion calculations for the defined boiler envelope. As shown in Fig. 3, all pressures, temperatures
and flows crossing the unit boundaries are established
and calculations can now proceed on each component.
A more detailed analysis would also account for items
such as air infiltration, continuous boiler water dis-
charge (blowdown), saturated steam extractions and
steam reheaters, if applicable.
Component performance calculations
Furnace
Furnace exit gas temperatures must be determined
to design downstream heat transfer components.
Through testing and correlation of gas temperature
data, furnace exit gas temperature has been found to
have a relationship to the heat input of the fuel and
to the effectiveness of the furnace walls. In Chapter
4, furnace exit gas temperature curves for various
fuels are approximated. This extended family of curves
represents the accumulation of extensive field experience and analytical evaluation. They are dependent
on fuel and furnace geometry.
The heat which can be absorbed by the furnace was
determined from the combustion calculations to be
1034 Btu/lb of flue gas. The layout of the furnace
(Table 1) provides a flat projected surface of 4100 ft2.
For 2.5 in. outside diameter (OD) furnace tubes on 3 in.
centers, Chapter 4, Fig. 33 indicates an effectiveness factor of 1.0. The heat release rate to the furnace is then:
Heat release rate =
Heat available × Gas mass flow rate
Flat projected area × Effectiveness factor
3
= 81.7 × 10 Btu/h ft
(1)
2
Table 1
Physical Arrangement - Furnace
Construction: 2.5 in. outside diameter (OD) tubes on 3 in. centers with membrane construction. (See Chapter 23 for description.)
Width: 12 ft
Volume: 13,275 ft3 to superheater entrance plane
Depth: 15 ft
Surface: 4100 ft2 flat projected area, not including superheater exit plane
Physical Arrangement - Components
Parameter
Units
Screen
Superheater
(Note 1)
Tube OD
Backspacing (centerline)
Sidespacing (centerline)
Rows deep
Rows wide
Tube length
Heating surface (Note 3)
Free flow area (Note 4)
Gas
Air
in.
in.
in.
2.5
6
6
2
23
18
542
2.5
3.25
6
12
23
18
3169
2.5
4
4
28
35
18 (Note 2)
11,545
2
3
3
10
47
10
2456
2.25
4
3
29
47
19.5
15,656
130
130
85
42
32
62
ft
ft2
ft2
Boiler
Bank
Economizer
Air
Heater
Notes:
1. The superheater is a counterflow configuration; however, the steam flows in two parallel paths from steam drum to
superheater outlet header. This is also called a two-flow arrangement.
2. Boiler bank tubes vary in length; the value listed represents an average length.
3. Heating surface is the external surface area of the tubes exposed to the flue gas except for the air heater where the flue
gas flows through rather than over the tubes.
4. Free flow area is the minimum clear area between tubes, perpendicular to the direction of gas or air flow except for air
heaters. The gas side free flow area for air heaters is the area defined by the inside diameter (ID) of the air heater tubes.
Steam 41 / Performance Calculations
22-3
The Babcock & Wilcox Company
calculations that follow account for bituminous coal
ash deposition and cleanliness factors have been omitted for simplicity. If the calculation procedures developed here are used with other dirty fuels, then commensurate cleanliness factors are required to accurately predict thermal performance.
Table 2
Operating Conditions
Fuel: Bituminous Coal, Virginia
Analysis As-Fired
Ultimate, % by wt
C
H2
S
O2
N2
H2 O
Ash
Proximate, % by wt
80.31
4.47
1.54
2.85
1.38
2.90
6.55
100.00
Moisture
Volatiles
Fixed carbon
Ash
2.90
22.05
68.50
6.55
100.00
Screen
Heat transfer
In this boiler design, the gases leaving the furnace
first pass across the screen tubes. In this case, the tubes
contain boiling water. These tubes control the amount
of furnace radiation reaching the superheater surface.
The heat transfer relationship for this surface is as
follows:
Higher heating value (HHV), as-fired: 14,100 Btu/lb
Excess air
Unburned carbon loss
Unaccounted loss (Table 3, Line 45)
ABMA radiation loss (see Chapter 23)
Furnace exit gas temperature
20.0% by wt
0.4% by wt
1.5% by wt
0.40% by wt
2000F
Superheater outlet:
Steam flow
Steam temperature
Steam pressure
Steam enthalpy
250,000 lb/h
650 F
450 psig
1331 Btu/lb
Economizer inlet:
Water flow
Water temperature
Water pressure
Water enthalpy
250,000 lb/h
220 F
470 psig
189 Btu/lb
Air heater:
Air temperature entering
Barometric pressure
Gas temperature leaving
g c p ∆Tg = m
g c p (T1 − T2 )
q = U A ( LMTD ) = m
where
= heat transfer rate, Btu/h
= hg = combined heat transfer coefficient or
overall heat transfer coefficient, Btu/h ft2 F
where the boiling water film and tube wall
resistances are assumed negligible
hg
= hrg + hcg = overall gas side heat transfer
coefficient, Btu/h ft2 F
hrg
= radiation heat transfer coefficient (gas
side), Btu/h ft2 F
hcg
= convection heat transfer coefficient (gas
side), Btu/h ft2 F
A
= total surface area, ft2
LMTD = log mean temperature difference, gas
and saturated water (Ts′), F
m g
= gas mass flow rate, lb/h
= mean specific heat of gas, Btu/lb F
cp
∆Tg
= T1 − T 2
T1
= gas temperature entering tube bank, F
T2
= gas temperature leaving tube bank, F
= saturation temperature of boiler water, F
Ts′
q
U
80 F
30 in. Hg
390 F
where
Heat available
Gas mass flow rate
Flat projected area
Effectiveness factor
=
=
=
=
1034 Btu/lb
324.1 × 103 lb/h
4100 ft2
1.0
Furnace exit gas temperature is 2000F from Chapter 4, Fig. 34. Sufficient information is now known to
begin analysis of the convection pass, i.e., screen, superheater, boiler bank, economizer and air heater.
The performance of the convection pass, however,
is a function of the cleanliness, or effectiveness, of the
heat transfer surfaces. The values of the heat transfer coefficient, as described in Chapter 4, apply to heat
transfer surfaces free from ash and slag deposits. For
calculation purposes, the effect of ash or other deposits on the heat transfer surfaces can be accounted for
with a cleanliness factor:
Cleanliness factor =
Actual heat transfer rate
Clean surface heat transfer rate
(2)
where gas side heat transfer coefficients are multiplied
by the cleanliness factor to reproduce a given fuel’s
fouling characteristics. Unless specifically noted, the
22-4
(3)
Using the nomenclature listed above, the log mean temperature difference for Case I of Fig. 1 is defined by:
LMTD =
(T1 − T2 )
n
T1 − Ts′
T2 − Ts′
(4)
Heat is transferred to the screen by direct furnace
radiation, intertube radiation and convection. Furnace radiation to the screen is considered first. Radiation from the furnace to the screen is calculated from
relationships developed in Chapter 4 using an effectiveness of 0.3 which approximates flue gas and screen
surface emissivities. The temperature differential (T14
−T24) is defined by the furnace exit gas temperature
and the screen tube temperature. Due to the large
difference between gas and screen tube temperatures
and the exponents in the formulation, it is sufficiently
accurate to assume that the screen tube temperature
is equal to the saturation temperature.
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
Table 3
Combustion Calculations
1
2
3
4
5
6
7
8
9
10
11
12
13
14
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
INPUT CONDITIONS − BY TEST OR SPECIFICATION
Excess air: at burner/leaving boiler/econ, % by weight
Entering air temperature, F
Reference temperature, F
Fuel temperature, F
Air temperature leaving air heater, F
Flue gas temperature leaving (excluding leakage), F
Moisture in air, lb/lb dry air
Additional moisture, lb/100 lb fuel
Residue leaving boiler/economizer, % Total
Output, 1,000,000 Btu/h
Corrections for sorbent (from Chapter 10, Table 14 if used)
Additional theoretical air, lb/10,000 Btu Table 14, Item [21]
Table 14, Item [19]
CO2 from sorbent, lb/10,000 Btu
Table 14, Item [20]
H2O from sorbent, lb/10,000 Btu
Spent sorbent, lb/10,000 Btu
Table 14, Item [24]
Btu Method
FUEL − Bituminous coal, Virginia
20/20/20
80
80
80
366
390
0.013
0
85
285.6
A
B
C
D
E
F
G
H
Constituent
C
S
H2
H2O
N2
O2
Ash
Total
0
0
0
0
18
19
20
21
Higher heating value (HHV), Btu/lb fuel
Unburned carbon loss, % fuel input
Theoretical air, lb/10,000 Btu
Unburned carbon, % of fuel
15
Ultimate Analysis
COMBUSTION GAS CALCULATIONS, Quantity/10,000 Btu Fuel Input
Theoretical air (corrected), lb/10,000 Btu
[20] − [21] x 1151 / [18] + [11]
Residue from fuel, lb/10,000 Btu
([15G] + [21]) x 100 / [18]
Total residue, lb/10,000 Btu
[23] + [14]
A At Burners B Infiltration
Excess air, % by weight
20.00
0.0
Dry air, lb/10,000 Btu
(1 + [25] / 100) x [22]
[26] x [7]
H2O from air, lb/10,000 Btu
Additional moisture, lb/10,000 Btu
[8] x 100 / [18]
[17H] x 100 / [18]
H2O from fuel, lb/10,000 Btu
Wet gas from fuel, lb/10,000 Btu
(100 − [15G] − [21]) x 100 / [18]
[12]
CO2 from sorbent, lb/10,000 Btu
[13]
H2O from sorbent, lb/10,000 Btu
Total wet gas, lb/10,000 Btu
Summation [26] through [32]
Water in wet gas, lb/10,000 Btu
Summation [27] + [28] + [29] + [32]
Dry gas, lb/10,000 Btu
[33] − [34]
[100] x [34] / [33]
H2O in gas, % by weight
Residue, % by weight
[9] x [24] / [33]
EFFICIENCY CALCULATIONS, % Input from Fuel
Losses
Dry gas, %
Enthalpy of steam at 1 psi, T = [6]
Water from
fuel, as fired
Enthalpy of water at T = [3]
%
Moisture in air, %
Unburned carbon, %
Radiation and convection, %
Other, % (include manufacturers margin if applicable)
Sorbent net losses, % if sorbent is used
Summation of losses, %
Credits
Heat in dry air, %
Heat in moisture in air, %
Sensible heat in fuel, %
Other, %
Summation of credits, %
Efficiency, %
KEY PERFORMANCE PARAMETERS
Input from fuel, 1,000,000 Btu/h
Fuel rate, 1000 lb/h
Wet gas weight, 1000 lb/h
Air to burners (wet), lb/10,000 Btu
Air to burners (wet), 1000 lb/h
Heat available, 1,000,000 Btu/h
Ha =
66.0 Btu/lb
Heat available/lb wet gas, Btu/lb
Adiabatic flame temperature, F
Steam 41 / Performance Calculations
16 Theo Air, lb/100 lb fuel
% by weight
80.31
1.54
4.47
2.90
1.38
2.85
6.55
100.00
C
K1
11.51
4.32
34.29
[15] x K1
924.4
6.7
153.3
− 4.32
−12.3
Air
1072.1
[15] x K2
8.94
1.00
39.96
2.90
H2O
42.86
[16H] x 100 / [18]
[19] x [18] / 14,500
14,100
0.40
7.603
0.39
7.02
1237.1
48.0
3.61
0.16
0.40
0.40
1.50
0.00
13.09
From Chapter 10, Table 14, Item [41]
Summation [38] through [46]
0.00
0.00
0.00
0.00
0.00
86.91
0.0
Summation [48] through [51]
100 − [47] + [52]
Leaving Furnace
100 x [10] / [53]
1000 x [54] / [18]
[54] x [33] / 10
(1 + [7]) x (1 + [25A] / 100) x [22]
[54] x [57] / 10
[54] x {([18] − 10.30 x [17H]) / [18] − 0.005
x ([44] + [45]) + Ha at T[5] x [57] / 10,000}
1000 x [59] / [56]
From Chapter 10, Fig. 3 at H = [60], % H2O = [36]
K2
7.572
0.049
0.049
Leaving Furnace
D Leaving Blr/Econ
20.0
20.0
9.086
9.086
0.118
0.118
0.118
0.118
0.000
0.000
0.000
0.000
0.304
0.304
0.660
0.660
0.000
0.000
0.000
0.000
0.000
0.000
9.864
9.864
0.422
0.422
0.422
0.422
9.442
9.442
4.28
4.28
0.42
0.42
0.0024 x [35D] x ([6] − [3])
H1 = (3.958E − 5 x T + 0.4329) x T + 1062.2
H2 = [3] − 32
[29] x ([39] − [40]) / 100
0.0045 x [27D] x ([6] − [3])
[19] or [21] x 14,500 / [18]
ABMA curve, Chapter 23
0.0024 x [26D] x ([2] − [3])
0.0045 x [27D] x ([2] − [3])
(H at T[4] − H at T [3]) x 100 / [18]
17 H2O, lb/100 lb fuel
324.1
9.204
302.5
Leaving Blr/Econ
328.6
23.3
324.1
335.2
1034.0
3560
22-5
The Babcock & Wilcox Company
Second screen row absorption:
0.55 × 1.79 × 106 Btu/h =
Furnace radiation to
superheater:
0.99 × 106 Btu/h
0.81 × 106 Btu/h
Furnace radiation does not affect the flue gas temperature drop across the screen; however, the furnace
radiation absorbed by the screen is taken into account
when determining screen steam generation rate. Furnace radiation passing through the screen will be
absorbed by the superheater. The evaluation of furnace radiation on superheater performance will be
addressed in the superheater section.
The heat transfer to the screen tubes is by convection and intertube radiation, and is calculated from
the formulas provided below. Calculations start by
assuming a gas temperature leaving the screen. This
assumption is verified later. In this case, 1920F is assumed. Log mean temperature difference:
LMTD =
(T1 − T2 )
n
T1 − Ts′
T2 − Ts′
= 1498F
(6)
where
Fig. 3 Example of boiler fuel, air, gas, water and steam flow streams.
T1 = furnace exit gas temperature = 2000F
T2 = gas temperature leaving screen = 1920F
Ts′ = saturation temperature = 462F
Gas mass flux:
(
)
q′′ = σ Fe T14 − T24 = 18, 420 Btu/h ft2
q ″ = heat flux, Btu/h ft2
σ = Stefan-Boltzmann constant
= 1.71 × 10-9 Btu/h ft2 R4
Fe = effectiveness factor = 0.3
T1 = furnace exit gas temperature
= 2000F = 2460R
T2 = saturation temperature
= 462F = 922R
The entrance to the screen is 18 ft high and 12 ft
wide for a flat projected area of 216 ft2. The heat transferred to the screen by furnace radiation is 216 ft2 ×
18,420 Btu/h ft2 or 3.98 × 106 Btu/h.
Based on the configuration of the screen (two rows
deep on 6 in. side- and back-spacing), some of the radiant heat is absorbed by the screen and the remainder
is absorbed by the superheater. From Chapter 4, Fig.
33, Curve 1, an effectiveness factor of 0.55 (i.e., 55%
of the radiant energy entering any row is absorbed)
is used to determine radiant screen absorption. On a
row by row basis, the radiation from the furnace is distributed as follows:
22-6
(7)
where
where
Furnace radiation to
first screen row:
First screen row absorption:
0.55 × 3.98 × 106 Btu/h =
Furnace radiation to
second screen row:
g / Ag = 2498 lb/h ft2
Gg = m
(5)
3.98 × 106 Btu/h
2.19 × 106 Btu/h
1.79 × 106 Btu/h
m g = gas mass flow rate = 324,100 lb/h
Ag = minimum gas free flow area
= 130 ft2
Table 3
Table 1
Gas film temperature:
Tf = Ts′ + ( LMTD / 2 ) = 1211F
(8)
where
= 462F
Ts′
LMTD = 1498F
Gas Reynolds number:
Re = K Re Gg = 5745
(9)
where
KRe = gas properties factor = 2.3 h ft2/lb
Gg = 2498 lb/h ft2
Fig. 4
Gas film convection heat transfer coefficient from
Chapter 4, Equation 61:
hcg = hc′ Fpp Fa Fd = 7.53 Btu/h ft2 F
(10)
where
hc′ = basic convection crossflow
geometry and velocity factor
= 69.9 Btu/h ft2 F
Ch. 4, Fig. 18
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
where
hr′
pr
L
K
Fs
=
=
=
=
=
8.2 Btu/h ft2 F
partial pressure = 0.19 atm
mean radiating length = 1.42 ft
fuel factor = 0.42
0.681
Fig. 5
Fig. 6
Fig. 7
Fig. 8
Combined heat transfer coefficient:
hg = hcg + hrg = 9.88 Btu/h ft2 F
(13)
where
hcg = 7.53 Btu/h ft2 F
hrg = 2.35 Btu/h ft2 F
Overall heat transfer rate:
q = U A ( LMTD ) = 8.02 × 106 Btu/h
(14)
where
Fig. 4 Determination of Reynolds number, Re.
Fpp =
=
Fa =
Fd =
=
physical properties factor
0.133
arrangement factor = 0.81
heat transfer depth factor
1.0
Ch. 4, Fig. 19
Ch. 4, Fig. 22
Ch. 4, Fig. 23
U
= hg = 9.88 Btu/h ft2 F
A
= 542 ft2
LMTD = 1498F
To verify the flue gas exit temperature assumption
of T2 = 1920F for the screen tubes, the gas temperature leaving the screen can be calculated by an en-
In this calculation, Fd is 1.0 because the furnace
flue gases turn prior to entering the screen.
The total radiation absorption in the screen is comprised of direct furnace radiation and intertube radiation. Direct furnace radiation affects screen steam
generation rate, but does not affect the gas temperature leaving the screen. The intertube radiation, however, is a direct function of flue gas temperature leaving the bank. Also, direct furnace radiation is proportional to the planar area it crosses while intertube radiation is proportional to the total bank heating surface.
To determine intertube radiation, the radiation
heat transfer coefficient must be adjusted to eliminate
direct furnace radiation through the use of an effectiveness factor based on areas.
Fs =
A − Ap
Effective surface
=
= 0.681
Total surface
A
(11)
where
A = total bank heating surface = 542 ft2 Table 1
Ap = planar area of the bank credited with
radiation absorption. In this example,
80% of the direct furnace radiation
was absorbed by the screen.
= 0.8 × 12 × 18 = 172.8 ft2
Because this calculation subtracts the effect of direct furnace radiation, it will be added back in when
the total screen absorption is finally determined.
Gas side radiation heat transfer coefficient adjusting for effective surface:
hrg = hr′ K Fs = 2.35 Btu/h ft2 F
Steam 41 / Performance Calculations
(12)
Fig. 5 Basic radiation heat transfer coefficient, hr′, for Equations 12,
32, and 44.
22-7
The Babcock & Wilcox Company
screen absorption of 11.20 × 106 Btu/h.
Draft loss
Screen gas side draft loss is calculated from Chapter 3, Equations 52 and 56:
30 T + 460 G
∆P = ( f N Fd )
5
3
B 1.73 × 10 10
= 0.04 in. wg
2
(16)
where
f = friction factor = 0.23
Ch. 3, Fig. 15
N = number of tube rows = 2
Table 1
Fd = tube bundle correction factor
= 1.12
Ch. 3, Fig. 14
B = barometric pressure
= 30 in. Hg
Table 2
T = 0.95 (T1 + T2)/2 = 1862F
(Note 1 below)
G = 2498 lb/h ft2
Eq. 7
Pressure drop
The screen tubes are part of the furnace circuitry
and tube side pressure drop calculations for this surface are included in a circulation analysis. Refer to
Chapter 5 for circulation information.
Superheater
Heat transfer
The next component in the direction of flue gas flow
is the superheater. Saturated steam from the steam
drum is heated to the outlet conditions shown in Table 2.
Fig. 6 Partial pressure, pr, of principal radiating constituents (CO2 +
H2O) of combustion gases in atmosphere for various fuels, heat
values and excess air.
ergy balance between the energy absorbed by the
screen tubes (excluding furnace radiation) and the
energy lost by the flue gas.
g c p = 1920F
T2 = T1 − q / m
(15)
where
T1
q
m g
cp
=
=
=
=
2000F
8.02 × 106 Btu/h
324,100 lb/h
0.31 Btu/lb F
Eq. 3
Fig. 9
Solving the heat balance for T2 indicates agreement
with the earlier assumption of 1920F, and no recalculation is required. Otherwise, T2 from Equation 15 would
be used in Equation 6 and the calculation repeated.
To complete the screen heat transfer analysis, the
total screen absorption is determined. Screen absorption is the sum of the convection and intertube radiation heat transfer rates (8.02 × 106 Btu/h) and direct
furnace radiation rate (3.18 × 106 Btu/h) for a total
22-8
Fig. 7 Mean radiating length, L, for various tube diameters and
arrangements or pitches – in-line tubes.
Note 1: Under most conditions, this equation is a good
approximation of effective flue gas temperature.
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
The governing heat transfer equations for superheater surfaces are:
q = U A ( LMTD )
LMTD =
(T1 − T2′) − (T2 − T1′)
(T − T2′)
n 1
(T2 − T1′)
(17)
(18)
Fig. 1, Case III
q = mg c p ∆Tg = mg c p (T1 − T2 )
(19)
s ∆H
q = m
(20)
where
= heat transfer rate, Btu/h
= (hg hs)/(hg + hs) = combined heat transfer
coefficient, Btu/h ft2 F (assuming negligible wall resistance)
hg
= hrg + hcg = overall gas side heat transfer
coefficient, Btu/h ft2 F
hrg
= radiation heat transfer coefficient (gas
side), Btu/h ft2 F
hcg
= convection heat transfer coefficient (gas
side), Btu/h ft2 F
hs
= convection heat transfer coefficient
(steam side), Btu/h ft2 F
A
= total surface area, ft2
LMTD = counterflow log mean temperature difference, gas and steam, F
T1
= gas temperature entering superheater, F
T2
= gas temperature leaving superheater, F
= steam temperature entering superheater, F
T1′
= steam temperature leaving superheater, F
T2′
m g
= mass flow of gas, lb/h
cp
= mean specific heat of gas, Btu/lb F
= T1 − T2, gas temperature differential, F
∆Tg
m s
= mass flow of steam, lb/h
∆H
= steam enthalpy difference, Btu/lb
q
U
Superheater steam side design conditions are:
Outlet:
T2′ = 650F, P2′ = 450 psig, H 2′ = 1331 Btu/lb
Fig. 9 Approximate mean specific heat, cp, of flue gas.
Inlet:
T1′ = 462F, P1′ = 460 psig, H1′ = 1205 Btu/lb
∆H = 126 Btu/lb
The outlet conditions are specified in Table 2 while
the inlet conditions are assumed to be saturated steam
at the drum pressure. Drum pressure is determined
by superheater pressure drop and is assumed here
based upon experience and verified later.
The heat transfer rate to the superheater is calculated as follows:
s ∆H = 31.50 × 106 Btu/h
q = m
(21)
where
s = 250,000 lb/h
m
∆H = 126 Btu/lb
Table 2
Previous calculations determined that the superheater will receive 0.81 × 106 Btu/h furnace radiation.
Therefore, the heat transferred by convection and
intertube radiation is:
qci = q − qr = 30.69 × 106 Btu/h
(22)
where
q = 31.50 × 106 Btu/h
q r = 0.81 × 106 Btu/h
By rearranging Equation 19, the gas temperature
leaving the superheater can be determined:
g c p ) = 1608 F
T2 = T1 − qci / (m
where
qci =
T1 =
=
m g =
cp =
(23)
30.69 × 106 Btu/h
gas temperature entering superheater
gas temperature leaving screen =1920F
324,100 lb/h
0.303 Btu/lb F
Fig. 9
Superheater log mean temperature difference is:
LMTD =
Fig. 8 Effect of fuel, partial pressure (H2O and CO2) and mean
radiating length on radiation heat transfer coefficient.
Steam 41 / Performance Calculations
(T1 − T2′) − (T2 − T1′)
(T − T2′)
n 1
(T2 − T1′)
= 1207F
(24)
22-9
The Babcock & Wilcox Company
where
T1
T2
T1′
T2′
=
=
=
=
where
1920F
1608F
462F
650F
m g = 324,100 lb/h
Ag = 130 ft2
Gas side Reynolds number:
The average gas side film temperature is approximated by (see Note 2 below):
Tf = (T1′ + T2′ ) / 2 + LMTD / 2 = 1160F
(25)
where
Re = K Re Gg = 6495
where
KRe = 2.6 h ft2/lb
Gg = 2498 lb/h ft2
Fig. 4
hcg = hc′ Fpp Fa Fd = 5.91 Btu/h ft2 F
Superheater tube material and thickness are selected according to the American Society of Mechanical Engineers (ASME) Code and manufacturing capabilities which are discussed in Chapters 7 and 8. For
this example, a 2.50 in. OD carbon steel seamless tube
with 0.220 in. wall thickness has been selected. Thickness is set by tube bending limitations and is normally
greater than that required by Code. Allowing for
manufacturing tolerances (+15% for pressure tubing),
the average inside diameter (ID) of the tube is calculated to be 1.99 in. The flow area corresponding to this
diameter is 3.12 in.2. The total steam flow area is 1.0
ft2 (2 flow × 23 rows × 3.12 in.2 × ft2 /144 in.2 ).
Steam mass flux:
s / As = 250, 600 lb/h ft2
Gs = m
(26)
hc′
Fpp
Fa
Fd
=
=
=
=
69.9 Btu/h ft2 F
0.133
0.635
1.0
(27)
A
= 0.986
Fig.
Fig.
Fig.
Fig.
18
19
22
23
(31)
Fig. 2
Gas side radiation heat transfer coefficient:
hrg = hr′ K Fs = 2.81 Btu/h ft2 F
(32)
where
Ch. 3, Fig. 5
Gas mass flux:
g / Ag = 2498 lb/h ft2
Gg = m
A − Ap
A = 3169 ft2
Ap = 0.2 (12 × 18) = 43.2 ft2
where
D e = 1.99 in. = 0.166 ft
µ = steam absolute viscosity
= 0.048 lb/h ft
G s = 250,600 lb/h ft2
4,
4,
4,
4,
where
Steam Reynolds number:
Gs De
= 867, 600
µ
Ch.
Ch.
Ch.
Ch.
To obtain the gas side radiation heat transfer coefficient (hrg), a factor, Fs, must be included to account
for the furnace radiation absorbed in the superheater.
In the screen calculations, it was shown that 80% of
the furnace radiation was absorbed in the screen while
20% passed through the screen and was absorbed by
the superheater. Similar to the screen calculations,
superheater intertube radiation will be determined by
eliminating direct furnace radiation from the radiation heat transfer coefficient through the use of an
effectiveness factor:
Fs =
m s = 250,000 lb/h
As = 0.998 ft2
(30)
where
where
(28)
Note 2: This approximation applies when one working
fluid controls the overall heat transfer coefficient.
22-10
(29)
Gas film convection heat transfer coefficient from
Equation 61 in Chapter 4:
= 462F
T1′
= 650F
T2′
LMTD = 1207F
Re =
Table 1
hr′ = 9.5 Btu/h ft2 F
pr
L
K
Fs
=
=
=
=
Fig. 5
Fig. 6
Fig. 7
Fig. 8
0.19 atm
0.85 ft
0.30
0.986
In a superheater, the resistance to heat transfer
through the steam film inside the tubes can not be
assumed to be negligible as was done with the screen.
Steam film convection heat transfer coefficient from
Chapter 4, Equation 58, corrected to the OD surface
area:
hs = hl′ Fpp FT Di / Do = 148 Btu/h ft2 F
(33)
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
where
hl′
Fpp
FT
Di
Do
where
=
=
=
=
=
687 Btu/h ft2 F
0.33
temperature factor = 0.82
1.99 in.
2.50 in.
Ch. 4, Fig. 13
Ch. 4, Fig. 16
Ch. 4, Fig. 17
Overall heat transfer coefficient:
U =
hg hs
hg + hs
=
(h
rg
+ hcg ) hs
hrg + hcg + hs
(34)
= 8.23 Btu/h ft2 F
where
hrg = 2.81 Btu/h ft2 F
hcg = 5.91 Btu/h ft2 F
h s = 148 Btu/h ft2 F
Overall heat transfer rate:
q = U A ( LMTD ) = 31.48 × 106 Btu/h
where
U
= 8.23 Btu/h ft2 F
A
= 3169 ft2
LMTD = 1207 F
(35)
Table 1
Because this agrees with 31.50 × 10 Btu/h from
Equation 21, no iteration is required. If these heat
transfer rate calculations do not agree, then the steam
outlet temperature or the superheater surface must
be re-estimated and the calculations repeated until
agreement is achieved.
6
Draft loss
Superheater gas side draft loss is determined by
combining Equations 52 and 56 in Chapter 3.
30 T + 460 G
∆P = ( f N Fd )
5
3
B 1.73 × 10 10
= 0.06 in. wg
2
(36)
where
f
N
Fd
B
T
G
=
=
=
=
=
=
0.06
12
1.0
30 in. Hg
0.95 (T1 + T2)/2 = 1676F
2498 lb/h ft2
Ch. 3, Fig. 15
Table 1
Ch. 3, Fig. 14
The superheater is a two-flow design. Steam side
pressure drop will be determined for the steam path
with the highest bend loss factors which, in this example, is the path with three short radius 180 degree
bends. A composite bend loss factor for this path is
determined as follows:
Nb: Three 180 degree bends,
R/D = 0.81, 3 × 0.6 = 1.80
Two 180 degree bends,
R/D = 2.44, 2 × 0.28 = 0.56
Two 90 degree bends,
R/D = 2.44, 2 × 0.22 = 0.44
Composite Nb
= 2.80
Ch. 3, Fig. 9
Ch. 3, Fig. 9
Ch. 3, Fig. 9
Drum pressure and saturation temperature can
now be determined and verified. The steam drum pressure is equal to the outlet steam pressure plus the
superheater pressure loss calculated above, plus the
steam separation equipment loss. Note, the steam
separation equipment loss is manufacturer specific.
Superheater outlet pressure
450 psig Table 2
Superheater-to-terminal
+ 0 psi (assumed)
pipe loss
Superheater pressure drop
+ 8 psi
Steam separation equipment + 2 psi (assumed)
Drum pressure
460 psig
Sat. temperature (at 460 psig) 462 F
This saturation pressure is in agreement with that
originally assumed.
Boiler bank
Steam pressure drop
Superheater steam side pressure drop is the sum
of friction or straight-flow losses, entrance and exit
losses, and bend losses. Equations 47 and 51 in Chapter 3 can be combined as follows:
∆P = ∆Pf + ∆Pe + e + ∆Pb
2
fL 1.5 Nb G
=
+
+
= 8.24 psi
υ
12
12 105
Di
Steam 41 / Performance Calculations
∆Pf = frictional pressure drop (fL/Di)
∆Pe+e = entrance (1/12) and exit (0.5/12)
pressure drop
∆Pb = bend loss (Nb /12)
G
= steam mass flux
= 250,600 lb/h ft2
f
= 0.012
Ch. 3, Fig. 1
L
= length of one continuous
superheater tube from steam
drum to superheater outlet
header = 130 ft
Di
= 1.99 in.
υ
= average steam specific volume
= 1.15 ft3/lb
Nb = bend loss factor = 2.8
(37)
Heat transfer
The function of the boiler bank, like the screen
tubes, is to boil water, and the governing heat transfer equations defined for the screen are also applicable.
Heat is transferred by convection, intertube radiation,
and radiation from the rear cavity. In this example
there are no cavities in the screen or superheater;
however, in many applications cavities exist to accommodate sootblowers. Whenever cavities surround a
bank of tubes, whether front or rear, the impact of the
cavities on heat transfer must be considered (see discussion on cavity heat transfer).
22-11
The Babcock & Wilcox Company
Calculations begin by assuming the gas temperature leaving the boiler bank to be 818F based upon
prior experience. The log mean temperature difference
is calculated from Fig. 1, Case I:
LMTD =
(T1 − T2 )
T − Ts′
n 1
T2 − Ts′
= 676F
(38)
where
T1 =
=
=
T2 =
Ts′ =
gas temperature entering the boiler bank
gas temperature leaving the superheater
1608F
assumed bank exit temperature = 818F
saturation temperature = 462F
Ag = 85 ft
where
hr′
pr
L
K
Fs
=
=
=
=
=
4.0 Btu/h ft2 F
0.19
0.47 ft
0.212
0.98
Overall heat transfer rate assuming negligible wall
and boiling resistances:
q = U A ( LMTD ) = 72.4 × 106 Btu/h
(40)
where
U
= hg = 9.29 Btu/h ft2 F
A
= 11,545 ft2
LMTD = 676F
g c p ) = 818F
T2 = T1 − q / (m
Gas Reynolds number:
Re = K Re Gg = 10,700
(41)
where
KRe = 2.8 h ft2/lb
Gg = 3813 lb/h ft2
Fig. 4
Gas film heat transfer coefficient:
hcg = hc′ Fpp Fa Fd = 8.45 Btu/h ft F
2
(42)
where
90.7 Btu/h ft2 F
0.118
0.79
1.0
Ch.
Ch.
Ch.
Ch.
4,
4,
4,
4,
Fig.
Fig.
Fig.
Fig.
18
19
22
23
For the screen, it was determined that 80% of the
direct furnace radiation is absorbed in a two-row bank.
It can be shown that all rear cavity radiation is absorbed in the boiler bank because it is 28 rows deep.
To calculate intertube radiation, an effectiveness factor must again be determined:
A − Ap
A
= 0.98
(43)
where
A
= 11,545 ft2
Ap at 100% = 12 × 18 = 216 ft2
22-12
Table 1
Checking the gas temperature leaving the boiler bank:
= 462F
Ts′
LMTD = 676F
Fs =
(46)
where
Tf = Ts′ + LMTD / 2 = 800F
=
=
=
=
(45)
hcg = 8.45 Btu/h ft2 F
hrg = 0.83 Btu/h ft2 F
Table 1
Gas film temperature:
hc′
Fpp
Fa
Fd
Fig. 5
Fig. 6
Fig. 7
Fig. 8
where
where
2
(44)
hg = hcg + hrg = 9.29 Btu/h ft2 F
(39)
m g = 324,100 lb/h
hrg = hr′ K Fs = 0.83 Btu/h ft2 F
Combined heat transfer coefficient:
Gas mass flux:
g / Ag = 3813 lb/h ft2
Gg = m
Gas side radiation heat transfer coefficient:
Table 1
Fig. 2
(47)
where
T1
q
m g
cp
=
=
=
=
1608F
72.4 × 106 Btu/h
324,100 lb/h
0.283 Btu/lb F
Fig. 9
This agrees with the original outlet temperature assumption and therefore no recalculation is required.
Otherwise, T2 would be used in Equation 38 and the
calculations repeated.
Draft loss
The governing equation for the gas side draft loss
in the boiler bank is:
30 T + 460 G
∆P = ( f N Fd )
5
3
B 1.73 × 10 10
= 1.03 in. wg
2
(48)
where
f
N
Fd
B
T
G
=
=
=
=
=
=
0.27
28
1.0
30 in. Hg
0.95 (T1 + T2)/2 = 1152F
3813 lb/h ft2
Ch. 3, Fig. 15
Table 1
Ch. 3, Fig. 14
Table 2
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
Pressure drop
As with the screen tubes, the boiler bank is integral to the furnace circuitry. Pressure loss to the steamwater flow is discussed in Chapter 5.
LMTD = (T1 + T2 ) / 2 − T2′ = 535F
Heat transfer
Heat is transferred from each cavity to the cooler
banks which form its boundaries. Cavity radiation is
most significant at higher gas temperatures. In this
example, cavity radiation has little impact on the overall results, but is included to illustrate the procedure
for evaluating other configurations.
Assume the gas temperature leaving the cavity,
entering the economizer to be 815F and the water temperature leaving the economizer to be 280F. Both assumptions are verified later. Consider cavity radiation
to the boiler bank first.
Log mean temperature difference is approximated by:
LMTD = (T1 + T2 ) / 2 − Ts′ = 355F
(49)
where
Gas side radiation heat transfer coefficient:
(51)
where
hr′
pr
L
K
=
=
=
=
2.4 Btu/h ft2 F
0.19 atm
7.1 ft
0.95
Fig. 5
Fig. 6
Fig. 8 (Extrapolated)
Because radiation is the only significant mode of
heat transfer in the cavity, the overall heat transfer
coefficient U = hrg. The overall heat transfer rate to
the boiler bank is then:
q = U A ( LMTD ) = 174, 600 Btu/h
Steam 41 / Performance Calculations
gas temperature entering the cavity
818F
gas temperature leaving the cavity
815F
assumed economizer water outlet temperature
282F
hrg = hr′ K = 1.90 Btu/h ft2 F
(54)
where
hr′ = 2.0 Btu/h ft2 F
pr = 0.19 atm
L = 7.1 ft
K = 0.95
q = U A ( LMTD ) = 121, 900 Btu/h
(50)
volume of the cavity
12 ft × 18 ft × 10 ft = 2160 ft3
Fig. 2
area = 2 (12 × 18 + 12 × 10 + 10 × 18)
1032 ft2
Fig. 2
hrg = hr′ K = 2.28 Btu/h ft2 F
T1 =
=
T2 =
=
T2′ =
=
Fig. 5
Fig. 6
Fig. 8
(55)
Fig. 2
Total heat transfer is the sum of the rates to the
boiler bank and economizer, or 296,500 Btu/h. Checking the gas temperature leaving the cavity:
where
VL =
=
A =
=
(53)
where
U
= hrg = 1.90 Btu/h ft2 F
A
= 12 × 10 = 120 ft2
LMTD = 535F
By definition, mean radiating length:
VL
= 7.1 ft
A
Fig. 2
where
gas temperature entering the cavity
gas temperature leaving the boiler bank
818F
815F (assumed)
saturation temperature = 462F
L = 3.4
U
= hrg = 2.28 Btu/h ft2 F
A
= 12 × 18 = 216 ft2
LMTD = 355F
Radiation to the economizer follows the same logic.
Cavity between boiler bank
and economizer
T1 =
=
=
T2 =
Ts′ =
where
(52)
g c p ) = 815F
T2 = T1 − q / (m
(56)
where
T1 = 818F
q = 296,500 Btu/h
m g = 324,100 lb/h
cp = 0.27 Btu/lb F
Fig. 9
This is the same as the assumed value and further
iteration is not needed. Otherwise, T2 from Equation
56 would be used in Equation 49 and the calculations
repeated. Verification of the economizer water outlet
temperature is shown in the next section.
The total boiler bank absorption can now be determined. Absorption due to convection and intertube
radiation is 72.4 × 106 Btu/h (Equation 46) while that
from cavity radiation is 0.17 × 106 Btu/h (Equation 52)
for a total boiler bank absorption of 72.6 × 106 Btu/h.
Economizer
The next component in the direction of flue gas flow
is the economizer. The economizer heats the feedwater
before it enters the steam drum.
22-13
The Babcock & Wilcox Company
Heat transfer
Economizer heat transfer follows the same formulations established for the superheater:
q = U A ( LMTD )
(57)
g c p ∆Tg = m
g c p (T2 − T1 )
q = m
(58)
∆H
q = m
(59)
where the terms are generally defined after Equations
17 to 20 except the tube side fluid is water instead of
steam.
Economizer outlet water temperature was previously assumed to be 282F. It was also established that
121,900 Btu/h is transferred from the cavity preceding the economizer. The total heat transfer rate to the
economizer is calculated to be:
∆H = 15.70 × 106 Btu/h
q = m
(60)
=
=
=
=
=
=
m
T2′
H2
T1′
H1
∆H
250,000 lb/h
282F
252 Btu/lb
220F
189 Btu/lb
H2 − H1 = 63.0 Btu/lb
Table 2
Ch. 2, Table 3
Table 2
Table 2
The heat transfer by convection and intertube radiation is:
6
qci = q − qr = 15.58 × 10 Btu/h
(61)
where
q = total heat transfer rate = 15.70 × 106 Btu/h
q r = cavity radiation = 121,900 Btu/h
As can be seen from this result, cavity thermal radiation at low temperatures is not usually significant.
By rearranging Equation 58, the gas temperature
leaving the economizer can be determined:
g c p ) = 635F
T2 = T1 − qci / (m
(62)
where
=
=
=
=
15.58 × 10 Btu/h
324,100 lb/h
0.268 Btu/lb F
815F
6
Table 3
Fig. 9
From Fig. 1, Case III, for counterflow heat exchanger, the log mean temperature difference is:
LMTD =
22-14
T1 =
=
T2 =
=
T1′ =
=
T2′ =
=
economizer inlet gas temperature
815F
economizer outlet gas temperature
635F
economizer water inlet temperature
220F
Table 2
economizer water outlet temperature
282F
Average gas film temperature is approximated by (See
previous Note 2):
Tf = (T1′ + T2′ ) / 2 + LMTD / 2 = 487F
(64)
where
T1′
= 220F
= 282F
T2′
LMTD = 472F
Gas mass flux:
where
qci
m g
cp
T1
where
(T1 − T2′) − (T2 − T1′)
(T − T2′)
n 1
(T2 − T1′)
= 472F
g / Ag = 7780 lb/h ft2
Gg = m
(65)
where
m g = 324,100 lb/h
Ag = 42 ft2
Table 3
Table 1
Reynolds number:
Re = K Re Gg = 23,300
(66)
where
KRe = 3.0 h ft2 /lb
Gg = 7780 lb/h ft2
Fig. 4
Gas film heat transfer coefficient:
hcg = hc′ Fpp Fa Fd = 13.14 Btu/h ft2 F
(67)
where
hc′
Fpp
Fa
Fd
=
=
=
=
152.6 Btu/h ft2 F
0.105
0.82
1.0
Ch.
Ch.
Ch.
Ch.
4,
4,
4,
4,
Fig.
Fig.
Fig.
Fig.
18
19
22
23
As for the preceding components, an effectiveness
factor based on the total economizer surface area is
determined:
Fs =
A − Ap
A
= 0.951
(68)
where
A
= 2456 ft2
Ap at 100% = (12 ft) (10 ft) = 120 ft2
Table 1
Fig. 2
Gas side radiation heat transfer coefficient:
(63)
hrg = hr′ K Fs = 0.30 Btu/h ft2 F
(69)
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
where
hr′
pr
L
K
Fs
=
=
=
=
=
1.6 Btu/h ft2 F
0.19
0.30 ft
0.20
0.951
Fig. 5
Fig. 6
Fig. 7
Fig. 8
The water film and tube wall resistances are negligible
so the total heat transfer coefficient is:
2
U = hg = hcg + hrg = 13.44 Btu/h ft F
(70)
where
Water side pressure drop
In this example, the economizer tubes are 2 in. OD
with 0.148 in. wall thickness. Considering the manufacturing tolerance of plus 15% in the pressure tubing wall thickness, the tube inside diameter is 1.66 in.
Water flow area is 2.16 in.2/tube and the total flow area
is 0.706 ft2 (2.16 in.2/tube × 47 tubes × 1.0 ft2 /144 in.2).
Water mass flux is:
where
m = 250,000 lb/h
A = 0.706 ft2
hcg = 13.14 Btu/h ft2 F
hrg = 0.30 Btu/h ft2 F
Water side Reynolds number:
Overall heat transfer rate:
q = U A ( LMTD ) = 15.57 × 10 Btu/h
6
Re =
(71)
GDi
= 98, 000
µ
(75)
where
where
U
= 13.44 Btu/h ft F
A
= 2456 ft2
LMTD = 472F
2
Table 1
After adding cavity radiation (121,900 Btu/h), the
total heat transfer rate to the economizer is 15.69 ×
106 Btu/h.
Verifying the water outlet temperature assumption,
the outlet enthalpy is evaluated from:
= 252 Btu/lb or T2′ = 282F
H 2 = H1 + q / m
(72)
where
G = 354,100 lb/h ft2
Di = 1.66 in. = 0.138 ft
µ = 0.5 lb/h ft
From steam tables at an enthalpy of 252 Btu/lb, the
water temperature is verified to be 282F. Therefore, the
total economizer absorption is 15.69 × 106 Btu/h.
Draft loss
Economizer gas side draft loss is calculated from
Chapter 3, Equations 52 and 56.
30 T + 460 G
∆P = ( f N Fd )
5
3
B 1.73 × 10 10
= 1.57 in. wg
2
Ch. 3, Fig. 3
Economizer pressure drop is the sum of friction losses,
entrance and exit losses, and bend losses.
2
fL 1.5 Nb G
∆P =
+
+
υ 5 = 0.36 psi
Di 12 12 10
(76)
where
=
=
=
=
=
υ =
G =
f
L
Di
Nb
q = 15.69 × 106 Btu/h
m = 250,000 lb/h
H1 = 189 Btu/lb
0.018
Ch. 3, Fig. 1
101 ft
1.66 in.
nine 180 degree 0.79 R/D bends
9 × 0.61 = 5.49
Ch. 3, Fig. 9
specific volume = 0.017 ft3/lb Ch. 2, Table 3
354,100 lb/h ft2
The total pressure drop (economizer inlet to the
steam drum) must include the static head of water for
that elevation difference (25 ft) plus fittings and friction losses. Assuming the feedwater pipe diameter is
large and fitting losses are negligible (∆Ppiping = 0), then
the static head is calculated by:
(73)
∆Pstatic =
∆Z
= 10.0 psi
144υ
(77)
where
where
f
N
Fd
B
T1
T2
T
G
(74)
/ A = 354,100 lb/h ft2
G = m
=
=
=
=
=
=
=
=
0.39
10
1.0
30 in. H2O
815F
635F
0.95 (T1 + T2)/2 = 689F
7780 lb/h ft2
Steam 41 / Performance Calculations
Ch. 3, Fig. 15
Table 1
Ch. 3, Fig. 14
∆Z = elevation between drum centerline and economizer inlet header
= 25 ft
υ = 0.0173 ft3/lb
Ch. 2, Table 3
Total pressure drop from economizer inlet to drum is:
∆P = ∆Peconomizer + ∆Pstatic + ∆Ppiping = 10.4 psi
(78)
22-15
The Babcock & Wilcox Company
film temperatures are approximated by the following
calculations.
where
∆Peconomizer = 0.36 psi
= 10.0 psi
∆Pstatic
∆Ppiping
= 0 (assumed)
Heat transfer
The air heater is the last heat transfer component
before the stack. In the overall heat and material balances, the air heater exit gas temperature is assumed
to be 390F. The air heater, when sized properly, will
have sufficient surface to provide the required air temperature to the fuel equipment (burners, pulverizers,
etc.) and lower the gas temperature to that assumed
in the combustion calculations. For the air heater, the
heat transfer rate is determined as follows:
g c p (T1 − T2 ) = 21.09 × 106 Btu/h
q = m
(79)
where
324,100 lb/h
Table 3
0.265 Btu/lb F
Fig. 9
gas temperature entering the air heater
gas temperature leaving the economizer
635F
assumed air heater exit temperature
390F
For the air side, the temperature rise is:
a c p ) = 366F
T2′ = T1′ + q / (m
(80)
where
T1′
q
m a
cp
=
=
=
=
80F
21.09 × 106 Btu/h
302,500 lb/h
0.244 Btu/lb F
Table 2
Table 3
Fig. 10
The tubular air heater in this example is a crossflow
design. The log mean temperature difference is determined from Fig. 1, Case IV. This requires not only the
two inlet and two outlet temperatures, but also a
crossflow correction factor, F:
LMTD =
(82)
where
Air heater
m g =
cp =
T1 =
=
=
T2 =
=
Tf = (T1 + T2 ) / 2 − LMTD / 4 = 448F
Gas:
(T1 − T2′) − (T2 − T1′) × F
(T − T2′)
n 1
(T2 − T1′)
= 260F
T1
= 635F
T2
= 390F
LMTD = 260F
Air:
Tf = (T1′ + T2′ ) / 2 + LMTD / 4 = 288F
(83)
where
= 80F
= 366F
T2′
LMTD = 260F
T1′
The flue gas flows through 1363 tubes (29 rows of
47 tubes per row). The air heater tubes are electric resistance welded (ERW), 2.25 in. OD with a 0.083 in.
wall thickness. Allowing for manufacturing tolerances
(9% for nonpressure tubing), the average tube inside
diameter is 2.07 in. Gas flow area is 3.36 in.2/tube for
a total of 31.8 ft2. The gas mass flux is:
g / Ag = 10,185 lb/h ft2
Gg = m
(84)
where
g = 324,100 lb/h
m
Ag = 31.8 ft
Table 3
2
Gas Reynolds number:
Re = K Re Gg = 30, 600
(85)
where
KRe = 3.0 h ft2/lb
Gg = 10,185 lb/h ft2
Fig. 4
Gas film heat transfer coefficient is the sum of the
convection heat transfer coefficient from the longitu-
(81)
where
T1 =
T2 =
T1′ =
T2′ =
F =
=
635F
390F
80F
366F
crossflow correction factor
0.90
Fig. 3
Ch. 4, Fig. 26
In an air heater, gas and air film heat transfer coefficients are approximately equal. For this example,
22-16
Fig. 10 Mean specific heat, cp, of air at one atmosphere.
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
dinal gas flow inside the air heater tubes and a small
gaseous radiation component from within the tube.
The gas convection heat transfer coefficient hcg is calculated from Equation 58 in Chapter 4. However,
recognize that these coefficients do not account for
fouling. To properly account for the ash layer inside
the tubes, the gas side heat transfer coefficients will
be multiplied by a cleanliness factor in the overall heat
transfer calculation, Equation 91.
hcg = hl′ Fpp FT Di / Do = 9.91 Btu/h ft2
(86)
where
=
=
=
=
=
52.6 Btu/h ft2 F
0.188
1.09
2.07 in.
2.25 in.
Ch. 4, Fig. 13
Ch. 4, Fig. 14
Ch. 4, Fig. 17
Table 1
Gas side radiation heat transfer coefficient:
hrg = hr′ K = 0.18 Btu/h ft2 F
q = U A ( LMTD ) = 20.69 × 106 Btu/h
U
= 5.07 Btu/h ft2 F
A
= 15,656 ft2
LMTD = 260F
Table 1
Air heater exit gas temperature is calculated to be:
g c p ) = 390F
T2 = T1 − q / (m
(93)
where
=
=
=
=
1.0 Btu/h ft2 F
0.19
0.17 ft
0.18
Fig. 5
Fig. 6
Tube ID
Fig. 8
From Table 1, the air side free flow area is 62 ft2, hence
the air mass flux is calculated to be:
(88)
a / Aa = 4866 lb/h ft2
Ga = m
where
a = 302,500 lb/h
m
Aa = 62 ft2
Table 3
Air Reynolds number:
T1
q
m g
cp
= 635F
= 20.69 × 106 Btu/h
= 324,100 lb/h
= 0.26 Btu/lb F
Draft loss (gas inside tubes)
Air heater draft loss is comprised of friction (∆Pf )
plus entrance and exit losses (∆Pe+e ). Modifying and
combining Chapter 3, Equations 47 and 52 for average gas temperatures, draft loss can be expressed as
follows:
fL
30
∆P = ∆Pf + ∆Pe + e = 12
+ 1.5
Di
B
where
KRe = 3.5
Ga = 4866 lb/h ft2
Fig. 4
2
T + 460 Gg
= 2.35 in. wg
×
5
3
1.73 × 10 10
The crossflow convection heat transfer coefficient for
air is obtained from Chapter 4, Equation 61.
hca = hc′ Fpp Fa Fd = 11.50 Btu/h ft2 F
(90)
where
=
=
=
=
109.4 Btu/h ft2 F
0.104
1.01
1.0
Ch.
Ch.
Ch.
Ch.
4,
4,
4,
4,
Fig.
Fig.
Fig.
Fig.
18
20
21
23
Assuming negligible wall resistance, the overall heat
transfer coefficient is:
U =
FFR ( hcg + hrg ) hca
FFR ( hcg + hrg ) + hca
= 5.07 Btu/h ft2 F
Steam 41 / Performance Calculations
(91)
Fig. 9
which is in agreement with the temperature assumed.
Otherwise, T2 would be substituted into Equation 81
and the calculations repeated.
(89)
Re = K Re Ga = 17, 000
hc′
Fpp
Fa
Fd
(92)
where
(87)
where
hr′
pr
L
K
0.90
9.91 Btu/h ft2 F
0.18 Btu/h ft2 F
11.50 Btu/h ft2 F
The cleanliness or fouling resistance factor, FFR, is
empirically derived from field test data; 0.9 is representative of bituminous coal. The total heat transfer
rate for the air heater is:
where
hl′
Fpp
FT
Di
Do
=
=
=
=
FFR
hcg
hrg
h ca
(94)
where
f
L
Di
T1
T2
T
Gg
B
= 0.024
Ch. 3, Fig. 1
= 19.5 ft
Table 1
= 2.07 in.
= 635F
= 390F
= (T1 + 2T2)/3 = 472F (Note 3 below)
= 10,185 lb/h ft2
= 30 in. Hg
Note 3: An approximation used for mean gas temperature.
22-17
The Babcock & Wilcox Company
where
Air resistance (air crossflow over tubes)
a = 302,500 lb/h
m
Aa = 10 × 12 = 120 ft2
The draft loss due to air flow across the air heater tubes
is calculated from Chapter 3, Equations 52 and 56.
30 T + 460 Ga
∆P = ( f N Fd )
5
3
B 1.73 × 10 10
= 1.52 in. wg
Reynolds number:
2
=
=
=
=
=
=
=
=
Re =
(95)
where
f
N
Fd
B
T1′
T2′
T
Ga
0.55
Ch. 3, Fig. 15
29
Table 1
1.0
Ch. 3, Fig. 14
30 in. Hg
80F
366F
1/0.95 (T1 + T2)/2 = 235F (Note 4 below)
4866 lb/h ft2
Boiler thermal performance summary
Fig. 11 summarizes thermal performance. This figure illustrates the relative component absorption and
temperature profiles. The furnace and boiler bank
absorb the most heat. The furnace, screen and boiler
bank are utilizing the heat available to generate saturated steam. The superheater raises the steam temperature to the desired outlet condition. The economizer is controlling gas temperature. The air heater
is providing hot air for combustion and together with
the economizer, is minimizing the flue gas temperature to the stack, reducing the sensible heat loss and
increasing overall boiler efficiency.
(97)
fL
30 T + 460 Ga
∆P =
+N
5
3
D
e
B 1.73 × 10 10
04 in. wg
= 0.0
where
f
L
De
B
T
Ga
=
=
=
=
=
=
0.0134
25 ft
10.9 ft
30 in. Hg
366F
2520 lb/h ft2
2
(98)
Ch. 3, Fig. 1
4500
Absorption
4000
Furnace
Air side loss – forced draft fan outlet
to furnace
Air resistance calculations for forced draft fan outlet to windbox inlet are considered first. Static pressure at the windbox for this example is set at 5 in. wg.
Windbox pressure is normally a function of the burner
or fuel equipment design and is specified to assure
proper operation. Starting at the windbox and working toward the forced draft fan:
3500
Air
Heater
3000
Temperature, F
Performance calculations are not yet complete. Component draft loss and air resistance calculations have
been made, but air and gas side performance still requires the evaluation of flues, ducts and stack effects.
Once these are established, the designer can evaluate forced draft and induced draft fan conditions.
2500
Economizer
Screen
Superheater
(SH)
Boiler
Bank
Temperature
Profiles
2000
Flue Gas
1500
1000
Air mass flux:
Superheated
Steam
(96)
500
Saturated Steam
and Water
0
Note 4: Under most conditions, this equation is a good
approximation for effective air temperature.
22-18
Ga De
= 4.4 × 105
µ
where
Ga = 2520 lb/h ft2
De = hydraulic diameter
= 4 × area/perimeter
= 4 × 120/44 = 10.9 ft
µ = 0.062 lb/h ft
Ch. 3, Fig. 4
The air resistance from windbox inlet to air heater
outlet is:
Flues, ducts and stack
a / Aa = 2520 lb/h ft2
Ga = m
Table 3
Fig. 1
Furnace Screen
Saturated
Steam and
Water
SH
Water
Boiler
Econ
Bank
Heat Transfer Surface
Air
Air
Heater
Fig. 11 Example boiler thermal performance summary.
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
N
= Nbend + Nexpansion = 1.41
Nbend
= 1.32
Nexpansion = 0.09
Ch. 3, Fig. 10
Ch. 3, Fig. 7
The frictional component of this equation (fL/De) is negligible. The draft loss from the air heater inlet to the forced
draft fan transition outlet, neglecting friction, is:
2
30 T + 460 Ga
∆P = N
= 0.03 in. wg (99)
5
3
B 1.73 × 10 10
where
N
Ncontraction
Nbend
B
T
Ga
=
=
=
=
=
=
Ncontraction + Nbend = 1.54
0.22
Ch. 3, Fig. 6
1.32
Ch. 3, Fig. 10
30 in. Hg
Table 2
T1′ for the air heater = 80F
2520 lb/h ft2
The net static pressure at the forced draft (FD) fan
outlet transition is then:
Ptotal = Pwindbox + ∆Pwindbox to air heater + ∆Pair heater to FD fan
+ ∆Pair heater = 6.59 in. wg
=
=
=
=
(100)
Gas side loss – furnace to stack
The draft loss calculations begin at the furnace exit
and work their way back to the induced draft fan.
However, the net ID fan conditions must also include
the draft loss for the downstream flues and the stack
effect. The static pressure at the furnace exit in balanced draft boilers is controlled to be slightly negative; a value of − 0.1 in. wg is used in this example.
Although it doesn’t affect the ID fan size evaluation, there may be a need to determine the furnace
pressure at the burner level. The calculation that follows is provided for information and illustrates stack
effect. Stack effect for the furnace is determined from
methods developed in Chapter 25 as follows:
(101)
where
Z = centerline of furnace exit to
centerline of windbox = −50 ft
Fig. 2
SE = stack effect
= 0.0116 in. wg/ft
Ch. 25, Eq. 3
and Ch. 25, Table 3
T1 = adiabatic temperature
= 3560F
Table 3
T2 = furnace exit gas temperature = 2000F
By controlling the furnace outlet to −0.1 in. wg, the
net static pressure in the furnace at the burner elevation is approximately −0.68 in. wg.
From screen, superheater, and boiler bank component calculations, gas side draft losses were deterSteam 41 / Performance Calculations
− ∆Pboiler bank = −1.23 in. wg
(102)
where
Pfurnace
= −0.10 in. wg
∆Pscreen
= 0.04 in. wg
∆Psuperheater = 0.06 in. wg
∆Pboiler bank = 1.03 in. wg
The calculations for the boiler bank outlet flue to
the economizer inlet are handled the same as those
for the air resistance calculations.
Gas mass flux:
g / Ag = 2700 lb/h ft2
Gg = m
(103)
where
Ag = 120 ft2
Fig. 2
Reynolds number:
5.0 in. wg (set by burners)
0.04 in. wg
0.03 in. wg
1.52 in. wg
∆PSE = SE × Z = − 0.58 in. wg
Pboiler outlet bank = Pfurnace − ∆Pscreen − ∆Psuperheater
m g = 324,100 lb/h
where
Pwindbox
∆Pwindbox to air heater
∆Pair heater to FD fan
∆Pair heater
mined to be 0.04, 0.06 and 1.03 in. wg, respectively.
The net static pressure at the boiler bank outlet is:
Re =
Gg De
µ
= 368, 000
(104)
where
Gg = 2700 lb/h ft2
De = hydraulic diameter
= 4 × area/perimeter
= 4 × 120/44 = 10.9 ft
µ = 0.08 lb/h ft
Ch. 3, Fig. 4
Draft loss:
fL
30 T + 460 Gg
∆P =
+N
5
3
De
B 1.73 × 10 10
07 in. wg
= 0.0
2
(105)
where
f
L
De
N
T
Gg
B
=
=
=
=
=
=
=
0.014
15 ft
10.9 ft
1.35
1/2 (818 + 815) = 817F
2700 lb/h ft2
30 in. Hg
Ch. 3, Fig. 1
Ch. 3, Fig. 10
From the economizer component calculations, draft
loss was calculated to be 1.57 in. wg. Stack effect from
the boiler bank outlet to economizer outlet is:
∆PSE = SE × Z = 0.11 in. wg
(106)
where
SE = 0.0071 in. wg/ft
Z
= 15 ft
Ch. 25, Eq. 3
and Ch. 25, Table 3
22-19
The Babcock & Wilcox Company
The net static pressure at the economizer outlet is then
calculated:
Peconomizer outlet = Pboiler bank outlet − ∆Pboiler bank to economizer
− ∆Peconomizer − ∆PSE = − 2.98 in. wg
(107)
2
30 T + 460 Gg
= 0.22 in.wg (112)
∆P = N
5
3
B 1.73 × 10 10
where
Pboiler bank outlet
∆Pboiler bank to economizer
∆Peconomizer
∆PSE
A straight flue runs from the induced draft fan outlet to the stack breaching. Friction again is negligible;
however, an expansion loss at the stack breaching is
included:
= −1.23 in. wg
= 0.07 in. wg
= 1.57 in. wg
= 0.11 in. wg
where
The flue gas resistance from the economizer outlet to
the air heater is due to friction only. However (fL/De)
for this flue run is small, hence the resistance is negligible. Air heater gas side draft loss was previously
calculated to be 2.35 in. wg. Referring to Fig. 2, the
flue cross-section from the air heater outlet to the induced fan inlet decreases from 120 ft2 to 48 ft2. Again,
as discussed above, frictional losses are negligible.
The mass flux is:
g / Ag = 6750 lb/h ft2
Gg = m
(108)
N
B
T
Gg
=
=
=
=
∆PSD = 7.84 Z ( 0.00179 − 1 / T )( B / 30 )
= 0.45 in. wg
m g = 324,100 lb/h
Ag = 6 ft × 8 ft = 48 ft2
Table 3
Fig. 2
Draft loss:
2
30 T + 460 Gg
= 0.07 in. wg (109)
∆P = N
5
3
B 1.73 × 10 10
where
=
=
=
=
0.30
30 in. Hg
T2 for the air heater = 390F
6750 lb/h ft2
Ch. 3, Fig. 6
∆PSE = SE × Z = 0.30 in. wg
(110)
where
SE = 0.0059 in. wg/ft
Z = 50 ft
Ch. 25, Eq. 3
Fig. 2
The net static pressure at the induced draft fan inlet
is calculated:
PID fan inlet = Peconomizer outlet − ∆Peconomizer to air heater − ∆Pair heater
− ∆Pair heater to ID fan inlet − ∆PSE = − 5.69 in. wg
where
Peconomizer outlet
∆Peconomizer to air heater
∆Pair heater
∆Pair heater to ID fan inlet
∆PSE
(113)
where
Fig. 2
Di = stack diameter = 8 ft
Z = stack height = 100 ft
Fig. 2
T1 = stack inlet gas temperature
= 390F
T2 = stack exit gas temperature
= 340F
Ch. 25, Fig. 11
T = (390 + 340)/2 = 365F = 825R
B = 30 in. Hg
The stack resistance is calculated from Chapter 25,
Equation 7.
Gas mass flux:
The stack effect from the economizer outlet to the
induced draft (ID) fan inlet is determined to be:
22-20
Ch. 3, Fig. 7
For the stack, two components must be determined:
stack draft and stack resistance. For standard air with
0.013 lb wg/lb dry air (υ = 13.70 ft3/lb at 80F and 30
in. Hg) and a typical flue gas (υg = 13.23 ft3/lb at 80F
and 30 in. Hg), Chapter 25, Equation 3 and the ideal
gas law (Chapter 3, Equation 16a) can be combined
to calculate the stack draft, ∆PSD:
where
N
B
T
Gg
1.0
30 in. Hg
390F
6750 lb/h ft2
(111)
g / Ag = 6449 lb/h ft2
Gg = m
(114)
where
m g = 324,100 lb/h
Ag = π Di2/4 = 50.3 ft2
Table 3
Reynolds number:
Re =
Gg Di
µ
= 8.9 × 105
(115)
where
Gg = 6449 lb/h ft2
Di = 8 ft
µ = 0.06 lb/h ft
Ch. 3, Fig. 4
Stack resistance:
= −2.98 in. wg
=
0.0 in. wg
= 2.35 in. wg
= 0.07 in. wg
= 0.30 in. wg
2
∆PSR
g fL
2.76 T m
=
+ Ne
4
B Di 105 D
= 0.22 in. wg
(116)
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
where
B
T
Di
g
m
f
L
Ne
=
=
=
=
=
=
=
30 in. wg
(390 + 340)/2 = 365F = 825R
8 ft
324,100 lb/h
0.012
100 ft
stack exit loss = 1.0
Table 4
Fan Operating Conditions
Fans
Table 3
Ch. 3, Fig. 1
Fig. 2
The net static pressure at the induced draft fan outlet is calculated:
PID fan outlet = ∆PSD − ∆PID fan outlet tobreaching − ∆PSR
= 0.01 in. wg
Units Forced draft Induced draft
Flow
Static pressure rise
Inlet temperature
lb/h
in. wg
F
302,500
6.59
80
324,100
5.70
390
Summary
(117)
where
= 0.45 in. wg
∆PSD
∆PID fan outlet to breaching = 0.22 in. wg
∆PSR
= 0.22 in. wg
The net operating conditions for the fans are summarized in Table 4.
Fan purchasing specifications add test block factors
to each net condition to accommodate deviations from
design. See Chapter 25 for further discussion.
Steam 41 / Performance Calculations
Net design conditions
This chapter is intended to be an introduction. The
approach is to give the reader a realistic yet basic overview of boiler performance calculations. Although
there are many variables in these calculations, the
designer must pay particular attention to fuel ash
characteristics. Ash laden fuels will degrade heat
transfer, increase draft loss and promote erosion. The
principles presented in this chapter are sound but the
impact of ash can dramatically change a given result.
Whether analyzing existing equipment or sizing new,
be sure to understand the slagging and fouling characteristics of the specified fuel. (See Chapter 21.)
22-21
The Babcock & Wilcox Company
Midwest power station burning bituminous coal.
22-22
Steam 41 / Performance Calculations
The Babcock & Wilcox Company
Chapter 23
Boiler Enclosures, Casing
and Insulation
Boiler setting
The term boiler setting originally applied to the brick
walls enclosing the furnace and heat transfer surfaces
of the boiler. Today, boiler setting comprises all the
water-cooled walls, casing, insulation, outer covering
and reinforcement steel that form the outside envelope of the boiler and furnace enclosure. The term
enclosure may refer to either the entire setting or to a
part of it.
As larger capacity steam generating units were demanded, boiler settings underwent a long evolution
from uncooled brick surfaces to today’s water-cooled
walls. Water-cooled walls began as widely spaced tubes
exposed to the furnace and covered with insulating
block. These progressed to tangent tubes covered with
refractory. They gradually evolved to the present day
construction of membrane tubes.
Design requirements
The boiler settings must safely contain high temperature pressurized gases and air. Leakage, heat loss
and maintenance must be reduced to acceptable values. The following factors must be considered in the
setting design:
1. Enclosures must withstand the effects of temperatures up to 3500F (1927C).
2. The effects of ash and slag, or molten ash, must
be considered because:
a. destructive chemical reactions between slag
and metal or refractory can occur under certain conditions,
b. accumulation of ash on the waterwalls can significantly reduce heat absorption,
c. ash accumulations can fall causing injury to
personnel or damage to the boiler, and
d. high velocity ash particles can erode the pressure parts and refractory.
3. Provisions must be made for the thermal expansion of the enclosure and for differential expansion of attached components.
4. The buckstay system must accommodate the effects of thermal expansion, temperature and pressure stresses, as well as wind and earthquake
loading appropriate to the plant site.
Steam 41 / Boiler Enclosures, Casing and Insulation
5. The effect of explosions and implosions must be
considered to lessen the risk of injury to personnel and damage to equipment.
6. Vibrations caused by combustion pulsations and
the flow characteristics of flue gas and air must
be limited to acceptable values.
7. Insulation of the enclosures should limit the heat
loss to an economical minimum.
8. Neither the exterior surface temperature nor the
ambient air temperature should cause discomfort
or hazard to operating personnel.
9. Enclosures must be gas-tight to minimize leakage into or out of the setting.
10. Settings of outdoor and indoor units that require
periodic washdown must be weatherproof.
11. Settings must be designed for economic fabrication, erection and service life.
12. Serviceability, including access for inspection and
maintenance, is essential.
13. Good appearance, in conjunction with cost and
maintenance requirements, is desirable.
Tube wall enclosures
In today’s units, water- or steam-cooled tubes, or
both, are used as the basic structure of the enclosure
in high temperature areas of the setting. Important
types of water-cooled enclosures are membrane tubes,
membrane tubes with refractory lining, flat stud tubes
and tangent tubes. The facing page illustrates present
day construction for tube wall enclosures.
Membrane tubes
Fig. 1 illustrates a typical furnace wall with membrane
construction. These walls are water-cooled and constructed of bare tubes joined by thin membrane bars.
The walls are gas-tight and do not require an exterior
casing to contain the products of combustion. Insulation
is placed on the outside of the wall and sheet metal or
lagging is installed over the insulation to protect it.
Membrane tubes with refractory lining
There are several locations in selected types of boilers that require refractory lining on the furnace side
of the tubes to protect the tubes from either erosion or
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The Babcock & Wilcox Company
Fig. 1 Membrane wall construction.
corrosion from the products of combustion. Some of the
most common applications are:
1. Cyclone-fired units: lower furnace and cyclone
burner walls. (See Chapter 15.)
2. Circulating fluidized-bed boilers: lower furnace.
(See Chapter 17.)
3. Refuse boilers: lower furnace. (See Chapter 29.)
4. Pulverized coal-fired boilers: burner throats. (See
Chapter 26.)
Cylindrical pin studs, welded on the hot side of the
tubes at close intervals, hold the refractory in place
(Fig. 2). Lining the wall with refractory can also increase furnace temperature by reducing heat absorption where this is desired. The increase in temperature helps to maintain the coal, peat, or lignite ash in
a liquid state, thereby preventing large ash buildup
and allowing better removal of slag. These issues are
discussed in more depth in Chapter 21. However, because of maintenance problems it is usually desirable
to avoid refractory where technically acceptable.
inner casing is reinforced with stiffeners. Stiffener
spacing and size are set by the design pressure of the
walls between buckstays. This system provides a better gas-tight enclosure than the former method.
In former practice, as shown in Fig. 4, the tubes are
backed with refractory, followed by a dense insulation
and an outer cold casing. The casing is supported from
the buckstays with expansion folds at the attachments.
These folds minimize stresses in the casing caused by
differential expansions between the hot tube wall and
cold casing. This method is now obsolete, but found
on many old boilers that are still in service.
While the construction of the casings described in
the preceding paragraphs applies to areas of horizontal buckstay reinforcement, some industrial boiler
designs require a vertical casing that is welded vertically to a bar located between two tubes (Fig. 5).
Tangent tube walls
These walls are constructed of bare tubes placed
next to each other with a typical gap of 0.03125 in.
(0.7937 mm). The refractory backup, casing and insulation system design, similar to that described for
flat stud tube walls, has also been used with tangent
tube walls. These walls are typically found in the furnace area of older boiler designs (Fig. 4).
Flat stud and tangent tube wall upgrades
In recent years, two methods have been used to
provide a better enclosure seal on units with either
inner (hot) or outer (cold) casing as the gas seal. In
one method, on boiler enclosure areas with tangent
tubes, a round bar is seal welded between each tube
for the full length (Fig. 6). In the other method, where
boiler enclosure areas have widely spaced tubes with
flat studs, a flat bar is seal welded between the tubes
just behind the flat studs over the full length (Fig. 7).
These methods have been effective on many boilers, providing an improved gas seal with considerably
less maintenance and longer life than the casing seal
Flat stud tube walls
These walls consist of tubes with small, flat bar studs
welded at the sides (Fig. 3). These walls are typically
backed by one of two construction methods which are
usually found in the convection pass enclosure.
In the current method, the flat studded tubes are
backed with refractory covered with a welded inner
hot casing that is insulated and covered with metal
lagging for protection. The casing is supported from
channel tie bars welded to the tubes at each buckstay
row. The walls are reinforced with buckstays and the
Fig. 2 Fully studded membrane walls.
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Fig. 3 Flat stud tube wall construction with inner casing shown.
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The Babcock & Wilcox Company
Windbox
The windbox is a reinforced, metal-cased enclosure
that attaches to the furnace wall, houses the burners, and distributes the combustion air. It may be located on one furnace wall, on two opposite furnace
walls, or on all furnace walls using a wraparound configuration. The attachments to the furnace walls must
be gas-tight and permit differential thermal expansion between the tubes and casing.
For large capacity boilers, the windbox may be compartmented and placed only on the front and rear furnace walls. The windboxes are compartmented (internally separated with horizontal division plates) for
better combustion air control.
Tempering gas plenum
This enclosure, located above the windbox, provides
for the distribution and injection of flue gas which is
used to temper the furnace gases and control the ash
fouling of heating surfaces. It is constructed similarly
to the windbox, but is normally protected on the inside by a combination of refractory and stainless steel
shields opposite the gas ports.
Fig. 4 Tangent tube wall construction with outer casing shown.
they replaced. Their biggest drawback is high installation costs because the entire boiler must be stripped
of its existing casing and insulation, then a new insulation and lagging system must be installed.
Casing enclosures
The casing is the sheet or plate attached to pressure parts for supporting, insulating, or forming a gastight enclosure.
A boiler unit contains many cased enclosures that
are not water-cooled. These enclosures must be designed to withstand relatively high temperatures while
having external walls that minimize heat loss and
protect operating personnel.
Casings are constructed of sheet or plate reinforced
with stiffeners to withstand the design pressures and
temperatures. When the casing is directly attached to
the furnace walls, expansion elements are added to
allow for differential thermal expansion of the tubes
and casing. The frontispiece shows typical enclosures
including the hopper casing, windbox, tempering gas
plenum and penthouse casing.
Hopper
Hopper enclosures are used in various areas of the
boiler setting that may include the economizer hopper, furnace hopper enclosure and the wash hopper
for dry bottom units.
The enclosure provided by the hopper casing may
also serve as a plenum for the recirculating gas which
leaves the economizer hopper through ports and enters the furnace through openings between tubes in
the furnace hopper.
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Penthouse
The penthouse casing forms the enclosure for all miscellaneous pressure parts located above the furnace
and convection pass roofs. It is a series of reinforced
flat plate panels welded together and to the top perimeter of the furnace pressure parts. Various seals
are used at the penetrations through the penthouse
walls, roof and roof tubes. Some examples are cylindrical bellows or flexible cans sealing the suspension
hangers, large fold (pagoda) seals around the steam
piping and refractory or casing seals around heating
surface tube penetrations through the roof tubes. On
many utility and some industrial boilers a gas-tight
roof casing is used on top of the roof tubes as the priMembrane Wall
Flat Stud Tubes
Seal Weld
Fig. 5 Casing attachment to membrane wall.
Seal Weld
Round Rod
Fig. 6 Tangent tubes with closure rods.
Flat Studs
Seal Weld
Flat Bar
Fig. 7 Widely spaced tubes with flat studs and closure bars.
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The Babcock & Wilcox Company
mary gas seal (pressure boundary). Penthouses may
or may not be designed as pressure-tight enclosures
with seal air. It depends upon whether the boiler is a
pressure fired or a balanced draft unit and whether
the roof seals are seal welded gas-tight or are the refractory type.
Design considerations
Resistance to ash, slag and erosion
Ash has a tendency to shed from a water- or steamcooled metal surface, particularly when its temperature is well below the ash softening point. Wall type
sootblowers remove ash in high temperature areas
where it tends to adhere to the walls. (See Chapter 24.)
Extensive areas of exposed refractory must be
avoided because large accumulations of ash could fall
into the furnace damaging equipment or causing injury to personnel. Also, crotches in the tube wall should
be designed to prevent ash and slag accumulation.
Pressure part erosion is reduced to acceptable levels by limiting the gas velocity through the unit. However, local high velocities can still occur in areas where
gas bypasses baffles or heating surfaces. These high
velocity lanes are best eliminated by proper design,
baffle installation and routine maintenance.
Some unit designs such as process recovery, refuse
and circulating fluidized-bed boilers require large
areas of refractory on tube surfaces. In these units,
the refractory system is designed to eliminate the effects of corrosion or erosion, or both, on pressure parts
while minimizing the reduction in heat absorption by
pressure parts.
Expansion
With the inner cased unit, Fig. 3, temperature differentials can occur between the casing and the tubes
during startup. Expansion of the wall in the horizontal direction is governed by the temperature of the
channel tie bar. Because the casing and the channels
are at the same temperature, they can be welded together. Vertical expansion differences are accommodated by flexing of the casing flanges at the top and
bottom of each casing section.
With a bottom supported unit, such as the PFI integral furnace boiler (Fig. 8) which is designed for
pressure firing, the structure is fixed at a point at one
end of the lower drum. Clearances, seals and supports
are designed for known expansions in all directions
from the fixed point.
With a top supported unit (see frontispiece), the
expansion occurs downward from one elevation. The
horizontal expansion of a boiler in both the fore and
aft as well as in the side to side direction is determined
by the location and method in which the hot boiler is
tied to cold building steel. Typically, a combination of
link ties and bumper ties is used to attach the hot boiler
walls, via the buckstay system, to cold building steel.
Flues and ducts, piping, ash tanks and burner lines
must be designed with expansion joints or seals to
accommodate movement. Flexible metal bellows, metallic box fold joints, or non-metallic belts are used in
23-4
Fig. 8 Bottom supported unit.
flues and ducts while metal hoses and sliding or
toggled gasketed couplings are used in piping. Water
seals are generally used between ash hoppers or slag
tanks and the associated furnace. With large units,
the expansion may be as great as 12 in. (305 mm)
between adjacent parts yet the joints must remain
pressure-tight.
Support
The support of boilers is discussed in Chapter 40.
It is generally more economical to support the smaller
units from the bottom and the larger units from the
top. In either case, the boiler setting is formed by the
waterwalls when these are available.
For bottom supported units, the enclosure is usually supported from a common foundation with the
boiler as shown in Fig. 8. For top supported units, cased
enclosures are supported from the pressure parts with
the exception of the penthouse enclosure which is supported directly from the structural steel by the hanger
rods.
Explosions
In the design of settings, the effect of possible explosions must be considered to minimize the possibilities of personnel injury and serious equipment damage. It is imperative that all types of boilers be designed to minimize the risk and effect of explosion.
This requires that all new boilers and boilers undergoing major alterations be designed and evaluated so
that they are in compliance with the National Fire Protection Association (NFPA) 85 Standard, Boiler Combustion Systems Hazards Code. On units with fluid
or fluidized fuels, care must be taken to avoid puffs
that can occur from improper fuel and air mixture
during startup. (See Chapter 11.) A better understanding of the technical problems and the development of
adequate design and operating codes have eliminated
most explosions.
The enclosure is designed to withstand common
puffs and large transient gas-side pressure excursions.
A design can be provided that results in the failure of
Steam 41 / Boiler Enclosures, Casing and Insulation
The Babcock & Wilcox Company
studs, stud attachments and welds rather than failure of tube walls in the event of a major furnace explosion. This minimizes the risk of release of large
quantities of high pressure steam. Unfortunately, this
design may also result in extremely hot gases being
directed at platforms and steel in areas that were not
designed to accommodate high temperature gases.
Explosion doors were once used on small furnaces
to relieve excessive internal furnace pressure. These
doors are no longer used because the rapid internal
pressure increase from a fuel explosion is not significantly relieved by opening one or more doors. Explosion doors may also be more of a hazard than a safety
margin because, in the event of a puff, they may discharge hot gases that would otherwise be completely
contained within the setting.
The forces from normal operating negative or positive furnace gas-side pressures and from transient
negative or positive furnace gas-side pressures, as
defined by NFPA 85, are contained by rectangular bars
called tie bars and/or channel tie bars attached to wall
tubes to form continuous bands around the setting.
Cold beams (buckstays), which are attached to the
tie bars with slip connections, accommodate the gasside pressure loadings and limit the inward and outward deflection of the wall tubes.
Because the buckstays are outside of the insulation,
special corner connections are required that allow the
walls to expand (Fig. 9). Forces generated by furnace
gas-side pressures concentrate at the corner connections. These connections must be tight during startup
when the walls have not fully expanded and during
the normal operating fully expanded position.
The vertical tubes that span between the buckstays
act as a beam to resist the internal furnace pressure.
The larger the tube diameter and the heavier the tube
wall, the farther apart the buckstays may be spaced,
provided that allowable wall tube vibration limits are
not exceeded. Permissible deflections and/or combinations of the positive or negative pressure loadings with
wind or seismic loadings determine the size of the
buckstay beam.
Implosions
Implosions are usually caused by an extremely
rapid decay of furnace pressure due to sudden loss of
fuel supply or by the improper operation of dampers
Fig. 9 Tie bar and buckstay arrangement at corner of furnace.
Steam 41 / Boiler Enclosures, Casing and Insulation
on units with high static pressure induced draft fans.
The risk of furnace implosions exists whenever a fan
is located between the furnace and the stack. This risk
exists even if the furnace is not normally being operated at a negative pressure since the rapid furnace
temperature decay occurring on a Master Fuel Trip
(MFT) results in the furnace being exposed to the
maximum head capacity of the fan on a transient basis during the fuel trip. This risk is also increased where
axial flow forced draft (FD) fans are used since they
can go into stall on the negative transient, blocking
air flow into the furnace which is needed to restore
the furnace pressure. The rules for determining minimum continuous and transient design pressures for
the furnace enclosures can be found in the NFPA 85
Standard. In addition, induced draft fan controls are
specified in NFPA 85 to minimize possible operating
or control errors and to reduce the degree of furnace
draft excursion following a fuel trip.
Vibration
Excessive vibration can cause failures of the tubes,
insulation, casing and supports. These vibrations can
be produced by external rotating equipment, furnace
pulsations from the uneven combustion of the fuel, or
turbulence in the flowing streams of air or gas in flues,
ducts and tube banks.
Tube walls, flues and ducts are designed to limit
vibration during normal operating conditions. In regard to wall tube vibrations, buckstays are typically
spaced to ensure that the natural frequency of the wall
tubes is greater than or equal to 6 hertz. The moment
of inertia of a buckstay must be chosen to ensure that
the buckstay natural frequency is greater than or
equal to 3 hertz, based on a simply loaded uniform
beam. Flues, ducts and casings are similarly stiffened
by bars or structural shapes to limit vibration. This
stiffening is particularly necessary in sections of flues
and ducts where the flow is highly turbulent, as in
the fan discharge connecting piece. Every effort should
be made to eliminate the sources of severe vibration,
such as unbalanced rotating equipment, poor combustion and highly turbulent or unbalanced air or gas flow.
Heat loss
Heat loss from a boiler setting is reduced by insulation, usually as an integral part of the boiler enclosure. (See Figs. 1 through 4.) There is an economical
balance between the value of the heat loss and the
cost of the insulation and installation.
The insulation system is designed to provide both
safety for personnel and minimal heat loss. In addition, indoor units require ventilation for both operator comfort and room air change.
The materials used most frequently for heat insulation are listed below.
Mineral wool
This material is comprised of molten slag, glass or
rock, blown into fibers by steam or an air jet or spun
by high speed wheels.
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The Babcock & Wilcox Company
Mineral wool base block Mineral wool fibers and
clay, molded under heat and pressure to form blocks,
are used to insulate membrane tube walls and boiler
casings up to temperatures of 850, 1200 or 1900F (454,
649 or 1038C) depending upon the grade.
Mineral wool blanket Mineral wool fibers, compressed into blanket form and held in shape between
hexagonal wire mesh or expanded metal lath, are
used on all types of enclosures with external metal lagging or casing and for piping inside cased enclosures.
The temperature limit is normally 1200F (649C).
Calcium silicate block
Reacted hydrous calcium silicate block is used on
enclosures and piping, generally below 1200F (649C).
High temperature plastic
Insulating cement made of mineral wool fibers processed into nodules and dry mixed with clay forms a
tough, fibrous monolithic insulation in final dried condition. Drying shrinkage is as much as 40%, but there
is a tendency to crack upon drying. This material is
used principally on irregularly shaped valves and fittings and to fill gaps between block insulation. Insulating cement is available in grades useable up to
1900F (1038C).
Ceramic fiber
High purity ceramic fibers, with melting points
above 3000F (1649C), are occasionally used for tube
enclosure seals where resiliency or high temperature
insulation is required.
Heat loss calculations
Calculations of the heat flow through a composite
wall are discussed in Chapter 4. Thermal conductivities of a wide range of commercial refractory and insulating materials, at the temperatures for which they
are suitable, are given in Fig. 10. Combined heat losses
(radiation plus convection) per square foot (square
meter) of outer wall surface are given in Fig. 11 for
various ambient air velocities and surface air temperature differences. The American Boiler Manufacturers Association (ABMA) Radiation Loss Chart provides a quick approximation for radiation loss, expressed as a percentage of gross heat input (Fig. 12).
Ventilation, surface temperature, conditions
To maintain satisfactory working conditions for
personnel around a boiler, a cold face temperature of
135F (57C) or less is considered satisfactory. Heat
losses, corresponding to these surface temperatures,
range from 90 to 130 Btu/h ft2 (284 to 410.1 W/m2), which
can be readily absorbed by the air circulation generally
provided in present day boiler rooms.
Insulating a boiler to reduce heat loss to a value
that can readily be absorbed by the total volume of
room air does not in itself assure comfortable working
conditions. Proper air circulation around all parts of
the boiler is also necessary to prevent the accumulation of heat in the areas frequented by the operating
23-6
Fig. 10 Thermal conductivity of various refractory materials.
personnel. This can be helped by using grating rather
than solid floors, by ample aisle space between adjacent boilers, by the location of fans to assist the circulation of air around the boiler and by installing ventilating equipment to assure adequate air exchange.
Good ventilation does not greatly increase overall
heat loss. Air velocity affects the surface heat transfer coefficient. This can be verified by data from Fig.
11. However, surface conductance is only a small part
of the total resistance to heat flow. For example, an
increase in air velocity from 1 to 10 ft/s (0.3 to 3 m/s),
for the conditions given in Fig. 13, will increase the
heat loss rate through the wall by only 2%.
Unlike heat loss, outer surface temperature is considerably affected by the surrounding conditions. In
the situation shown in Fig. 14, where two walls of
similar temperatures are close together, the radiant
heat transfer from either wall is negligible. The natural
circulation of air through such a cavity is inadequate
to cool the walls to a temperature suitable for personnel working in the vicinity. From Fig. 15 it can be seen
that a considerable change in surface film resistance
will cause an appreciable change in lagging or surface temperature while not affecting the heat loss
through the wall to any extent.
Increased insulation thickness would not significantly reduce the surface temperature in the cavity
shown in Fig. 14. Cavities should therefore be avoided
in areas where operators work. Ventilating ducts to
reduce the air temperature in such a cavity can be
installed if necessary.
Steam 41 / Boiler Enclosures, Casing and Insulation
The Babcock & Wilcox Company
Leakage
Continuing efforts have been made over the years to
reduce air infiltration into boiler settings. Such in-leakage increases gas flow and the heat rejected to the stack,
thereby lowering boiler efficiency and increasing the
amount of induced draft fan power. (See Chapter 10.)
Corrosion
Fig. 11 Heat loss from wall surfaces (radiation + convection)
(Source – ASTM Standards, Part 13, 1969).
One of the advantages of membrane walls compared
to cased walls is that they eliminate flue gas corrosion
on the cold face of the enclosure walls. Most flue gases
contain sulfur; therefore, metal parts of the setting
must either be kept above the dew point of the gases
or out of contact with the gases. (See Chapter 21.) The
dew point generally ranges between 150 and 250F (66
and 12lC) and is dependent on the fuel, its sulfur content and the firing method.
Flues carrying low temperature spent gases should
be insulated on the outside to inhibit corrosion. This
is particularly necessary on outdoor units. Watercooled doors and slag tap coils require water temperatures above 150F (66C) to keep the cooling coils above
the dew point of the gases.
When casing is located outside of insulation or refractory, it is still subject to the action of the flue gases.
When this type of casing is subjected to a temperature below the dew point, an asphalt mastic or other
type of coating is needed to protect it from corrosion on
the inside. This problem requires special attention in the
design of outdoor installations where temperatures may,
at times, be below flue gas dew point temperatures.
Fig. 12 Radiation loss in percent of gross heat input (American Boiler Manufacturers Association).
Steam 41 / Boiler Enclosures, Casing and Insulation
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The Babcock & Wilcox Company
Fig. 13 Temperature gradients through tube and brick wall.
With the use of externally insulated casing, corrosion problems are greatly reduced because the flue
gases are completely contained by a metal skin, which
is well above the dew point temperature. However,
even with the inner casing, seals and expansion joints
must be insulated properly to avoid cold spots and
consequent corrosion.
Fig. 14 Cavities tend to raise wall surface temperatures.
23-8
Fig. 15 Effect of surface film resistance on surface temperature and
heat loss rate.
Resistance to weather
Outdoor boiler installations are possible in mild climates. While the initial cost of the plant is reduced,
maintenance of the boiler and auxiliary equipment
must be considered. Severe weather can extend outage time and increase maintenance expenses. These
units must also have sufficient reinforcement to withstand the pressure and suction forces of the wind.
Lagging is an outer covering over a wall used for
protecting the insulation from water or mechanical
damage. It is relatively simple to make a metal lagged
unit rainproof. Joints and flange connections are overlapped and flashings are used around openings. Welding of joints or the use of mastic compounds is necessary in areas which are difficult to seal.
Sloping roofs are required and are particularly
important on aluminum lagging where pockets of
water would eventually stain the surface. Direct contact between aluminum and steel must be avoided to
prevent galvanic corrosion of the aluminum in the
presence of moisture. Roof flashings should be designed so that water runoff does not wet the aluminum.
Weather hoods should be used to keep rain, snow
and ice from contacting outdoor safety valves. Nozzle
and valve necks must be insulated and protected with
sheet metal or outer waterproof covering. Outdoor
control lines containing air or flue gas, drain and sampling lines and intermittently operated steam and
water lines should be insulated and protected by electric resistance heating tape. Steam pipe tracer lines
may also be used in some cases. Dry air should be supplied for control lines and sootblowers. Steam and water lines outside the setting must be completely drainable.
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The Babcock & Wilcox Company
Fabrication and assembly
Appearance
The setting must be designed for economical fabrication and assembly. This requires integration of all
shop and field methods and practices. Small units can
be completely shop assembled. For larger units the trend
has been toward shop subassembly of large components.
Shipping clearances usually limit the size of shopassembled wall panels to 16 ft (4.9 m) in width or 105
ft (32 m) in length. These size criteria can not be used
simultaneously. That is, as the panels are made longer,
the maximum width will be less and as the width is
increased the maximum length decreases. Shop assembly of components permits better quality control of the
more complicated parts.
Casing enclosures, tube connections to headers, tie
bars, doors and other attachments are normally of
welded construction. New and improved materials and
attachment methods reduce the manhour requirements for insulating boilers/auxiliary equipment and
installing metal lagging.
The setting should present a good appearance and
be designed so that it can be retained indefinitely with
a minimum of housekeeping. The outer surface should
be easy to clean. Equipment handling flue gas, coal,
ash or oil should be designed to minimize leakage.
Light gauge metal lagging is generally used as an
outer covering. This is particularly true for outdoor
units where it is relatively simple to make the metal
lagging water-tight. Many types of covering are found
in older installations including plastic insulation, insulating cement, canvas and welded steel casing.
Figs. 1, 2 and 3 show metal lagging. Light gauge
galvanized steel or clad aluminum sheets are commonly used. Galvanized steel is generally less expensive than aluminum, but for outdoor units it may be
necessary to paint the galvanized steel after weathering, unless the climate is dry. The clad aluminum
may be preferable because it only requires painting
under more severe conditions.
Serviceability
Many setting details must be designed to simplify
operation and maintenance. Working areas around
the unit should have adequate lighting and comfortable temperatures. Clearances for servicing and removing parts should be provided. Access through the
setting is necessary for inspection of boiler internals.
Suitable platforms for access doors, sootblowers, instruments and controls are essential.
Inspection doors allow observation of combustion
conditions and the cleanliness of heat absorbing surfaces. Figs. 16 and 17 illustrate inspection doors for balanced draft and pressurized settings. Safety is provided
by two types of interlocks which assure that compressed
air is properly aspirating the aperture before the door is
opened. A feature of this door is that the aspirating jet
does not restrict the comparatively wide view angle.
The tube bends that form openings must have the
smallest possible radius. The length of the stud plate
closures around the opening is minimized so that the
plates can be adequately cooled by welded contact to
the tubes, thereby preventing burn back and subsequent overheat of seals.
Steam 41 / Boiler Enclosures, Casing and Insulation
Fig. 16 Inspection door for balanced draft furnace.
Fig. 17 Inspection door for pressurized furnace.
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The Babcock & Wilcox Company
Typical coal-fired utility boiler setting and enclosure.
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The Babcock & Wilcox Company
Chapter 24
Boiler Cleaning and Ash
Handling Systems
The combustion of virtually all fuels generates ash,
or inert residuals of combustion. As discussed in Chapter 21, the ash can accumulate on surfaces exposed
to the flue gas stream causing reduced performance,
flow obstruction, accelerated corrosion and increased
mechanical loadings. Specialized boiler cleaning systems are installed in boilers and environmental control systems to permit on-line deposit removal and
control for optimized overall system operation. In addition, specialized ash handling systems are incorporated into the power plant designs to collect and remove the ash from the boiler and emissions control systems for safe and environmentally acceptable disposal.
Boiler cleaning systems
Steam generating plants are cleaned on-line by
regularly removing ash deposits that accumulate on
heat transfer surfaces. This maintains maximum thermal efficiency of the boiler (optimizes heat rate) and
maintains flue gas temperatures within design conditions at key locations. This, in turn, supports the
optimum operation of air pollution control equipment.
On-line cleaning also prevents the blockage and plugging of gas passages in the boiler.
This chapter discusses the methods and types of equipment used for on-line cleaning (see Fig. 1). For this purpose, it is convenient to separate the discussion by regions
of the boiler and downstream equipment, since these generally require different cleaning methods and devices.
The following terminology and definitions are useful to the discussions of regional cleaning.
Superheated steam is the most widely used medium
for several reasons. Boiler-generated steam avoids the
cost and maintenance of a compressor. Because it is
generally extracted from a high pressure steam outlet and its pressure reduced by regulating valves,
steam provides flexibility in case more aggressive
cleaning is required. Superheated steam is generally
recommended over saturated steam to avoid condensation in the cleaning flow, which can accelerate boiler
tube erosion or result in thermal cracking.
Compressed air is often used as the cleaning medium
on larger boilers. The source may be high pressure 250
to 500 psig (1.7 to 3.4 MPa) reciprocating compressors
or high flow rate centrifugal compressors discharging at
pressures from 150 to 225 psig (1.03 to 1.55 MPa).
Water is used in the most aggressive cleaning situations, such as removing more tenacious slag from furnace walls, or cement-like deposits in air heater baskets.
Sootblower terminology
Cleaning medium
An effective method of on-line boiler cleaning is to
direct a concentrated jet of cleaning medium against
the soot or ash buildup. The cleaning medium may be
saturated steam, superheated steam, compressed air
or water. Combinations of water with other media,
such as steam or air, have also proven effective but
can cause boiler tube damage.
Steam 41 / Boiler Cleaning and Ash Handling Systems
Fig. 1 Long retractable IK sootblower used to remove ash deposits
in utility boilers.
24-1
The Babcock & Wilcox Company
Peak impact pressure
Peak impact pressure (PIP) is the stagnation pressure
measured directly along the centerline of the sootblower
nozzle at distances downstream of the nozzle outlet. Peak
impact pressure is maximized by designing the nozzle
to achieve a highly concentrated jet at the greatest possible distance from the nozzle outlet. Because most
sootblowers are operated with supersonic flow exiting the
nozzles, ideal nozzle design involves the avoidance of
shock waves at the nozzle outlet and minimum shear
interaction with the flue gas environment.
Jet progression velocity
Jet progression velocity is the linear velocity at which
the jet passes over a surface, directing a concentrated
jet of cleaning medium. This is a function of the nozzle
rotational speed and distance from the surface.
Cleaning radius and tube bank penetration
The cleaning radius refers to the distance to which
a particular sootblower can clean a surface, when the
path between the sootblower nozzle outlet and the surface is unobstructed. Although commonly used, this
term is misleading because the area cleaned is not often
circular. Tube bank penetration is the maximum effective
cleaning distance when directed into a bank of tubes.
Wall box
A wall box attaches to the boiler side wall at the
opening made for the cleaning device. The wall box
provides structural support for the front end of long
retractable sootblowers, or the entire weight of furnace
wall blowers. The wall box provides an opening for the
lance tube to pass into the boiler, and a sleeve and seal
plate to minimize flue gas escape to the atmosphere
when the lance is retracted from the boiler.
Lance tube
The lance tube is the tubular component of a retractable-type sootblower that travels into and out of
the combustion zone and flue gas passages. The lance
tube is fitted with nozzles at the tip and possibly along
its length to accelerate and direct cleaning flow onto
the surface to be cleaned.
Feed tube
The feed tube is the stationary tube that feeds cleaning medium to the moving lance tube or rotating element. The outer surface of the feed tube serves as a
sealing surface for the packing assembly that slides
and/or rotates with the lance tube.
Element
An element serves the same function as the lance tube,
but remains inside the flue gas passage permanently.
Furnace cleaning
The furnace is a large unobstructed chamber where
fuel and air are mixed and nearly all of the combustion occurs. The walls, slopes and floor tend to collect
the non-combustible fuel components. In most power
boilers (particularly pulverized coal-fired units), effi24-2
cient heat transfer is necessary for effective boiler circulation, an efficient heat balance, and to minimize
pollutant gas species. However, in some boiler types,
such as black liquor recovery boilers and fluidized
beds, little or no on-line furnace cleaning is attempted
because of adverse impact on the combustion process.
Principles
Ash deposits on the side walls and hopper slopes are
generally heavier than those found elsewhere in the
boiler. When removed, these deposits fall and contribute to bottom ash.
Because these ash deposits collect on surfaces that
are exposed to intense heat, they may melt at their
surface after building to a sufficient thickness. Depending on chemical composition, the ash may collect
in a loosely bound, porous layer that can be relatively
easy to remove by on-line steam cleaning, or the ash
may fuse into a dense sheet-like deposit known as slag.
Slag removal often requires on-line water cleaning.
The rapid quenching creates cracks and fissures, dislodging the slag in pieces or patches as the water jet
continues its travel across the surface. The water jet
also provides significant mechanical impact energy.
This technique is not used on boiler surfaces lined with
refractory.
Cleaning devices
Short retractable furnace wall sootblower When the
furnace wall ash deposits are loosely adhered, a short
travel retractable-type sootblower (called an IR or wall
blower) directs steam or compressed air to remove the
deposits. This design (see Fig. 2) consists of a poppet
valve, feed tube, lance tube, and a drive mechanism
for inserting the sootblower tube and rotating it in the
fully inserted position. The lance tube has one nozzle
near the tip. When at rest, the nozzle is located outside of the boiler and within a sleeve (a short segment
of pipe welded to a wall box) to protect it from the furnace radiated heat. When the sootblower is activated,
the lance tube is advanced to where the nozzle is about
1.5 in. (38 mm) from the face of the boiler tubes. The
feed tube remains stationary while the lance tube telescopes to extend the nozzle.
The poppet valve is mechanically opened by the
advancing lance tube drive mechanism and cleaning
flow begins. Steam flows through the poppet valve,
into the feed tube, to the lance tube and out through
the nozzle. Once fully inserted, the lance tube is rotated one, two, or three revolutions while blowing a
high pressure cleaning medium aimed nearly parallel to the boiler side wall. The cleaning radius is a function of the cleaning medium’s pressure, the type of
nozzle, the nature of the deposit, and the boiler surface. In general, on bituminous coal deposits, the normal effective cleaning area of an IR sootblower is elliptical with a vertical axis of 12 ft (3.66 m) and a
horizontal axis of 10 ft (3.05 m). This area is typical when
supplying either 150 psig (1034 kPa) air or 200 psig
(1379 kPa) steam. For subbituminous or lignite deposits, the effective cleaning area may be much smaller.
Waterlance When ash deposits consolidate into a
dense slag layer, mechanical impact energy alone may
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Fig. 2 Model IR wall blower (on newer designs, the control box is
mounted separately).
not be sufficient to clean effectively. A waterlance removes slag by directing a concentrated water jet and
precisely controlling the pattern and progression velocity of the water.
Shown in Fig. 3, the waterlance consists of a lance
tube with a single nozzle, a drive assembly for inserting the lance tube into the boiler, and valves for turning a high pressure water source on and off. At rest,
the nozzle is located inside a wall box sleeve. When
activated, the lance tube is advanced along a helical
path. Water flow is delayed until the nozzle is about
19 in. (48 cm) from the rest position. The nozzle is installed at a backrake angle to direct the water jet back
toward the wall. Once water flow is established, the
helical path creates a spiral cleaning pattern on the
furnace wall.
The total travel length is about 3 ft (0.91 m). The
most common backrake angles are 15 and 20 deg (0.26
and 0.35 rad) as measured from the perpendicular to
the lance tube axis. These nozzle orientations achieve
a typical cleaned area of 175 and 350 ft2 (16.3 and
32.5 m2), respectively.
Once the lance reaches its fully inserted position,
water flow is shut off, compressed air is delivered to
the lance tube to purge water from the lance, and the
lance is removed as quickly as possible.
A partial arc waterlance operates similarly, except
that the water is turned on and off during each rotation so that the water jet cleans a partial circle. Examples of cleaning patterns achieved by a partial arc
waterlance compared to the standard waterlance are
shown in Fig. 4. The partial arc waterlance avoids
water jet impingement on corner wall tubes, around
burners, or in other sensitive regions.
Selective pattern waterlance Because of the relatively low flow rate of its water jet, waterlance cleaning is generally effective up to 30 ft (9.14 m) from the
nozzle. The selective pattern waterlance is designed
to accommodate this distance limitation (between the
nozzle and cleaning surface) by using a much longer
lance tube and cleaning surfaces other than the wall
through which the waterlance was inserted. This approach is particularly well-suited for the underside of
the furnace’s nose arch and hopper slopes. It has also
been used effectively to clean wing walls and surfaces
between wing walls, division panels, and the leading
edge of tube pendants at the top of the furnace.
To maintain a constant jet progression velocity on
the surfaces, drive motor control programming may
be extensive. In addition, the water may be turned
on and off one or more times within each revolution
Water Trajectory
Lance Tube
Area Cleaned
255 ft2
Water Jet Nozzles
165 ft2
IK-4M-PA
Nozzles on
Opposite Side
Control Valves
for Water Flow and
Purge Air
346 ft2
IK-4M-PA
Nozzles on
Same Side
IK-4M-WL
Furnace Wall
Wall Box Sleeve
Lance Tube Furnace Wall
Fig. 3 Waterlance.
Steam 41 / Boiler Cleaning and Ash Handling Systems
Fig. 4 Partial arc waterlance cleaning patterns.
24-3
The Babcock & Wilcox Company
to achieve a desired cleaning pattern. The selective
pattern waterlance frequently uses more than a single
nozzle in the lance tube to achieve close side-to-side
spacing of the cleaning jet patterns, and for lance tube
cooling. During the retraction of the lance tube, the
water flow may be pulsed and is eventually terminated.
HydroJet ® A more recently adopted technology is
the HydroJet® boiler cleaning system shown in Fig.
5. The HydroJet directs a jet of water through a side
wall opening to clean surfaces on the opposite side of
the furnace. The lance tube on a HydroJet remains
outside the boiler. Its nozzle is installed in the leading tip of the lance tube and the lance tube is articulated by a two-axis drive system to aim the nozzle at
the surface to be cleaned.
The water flow required to deliver a concentrated
jet across the width of the furnace and still achieve
effective cleaning is greater than that of the
waterlance. Overall, this injection of a sufficient volume of cold water into the flue gas significantly affects the boiler heat rate. However, the HydroJet offers several advantages that make it an attractive
cleaning option. With a range of motion of ±45 deg
(0.79 rad) in both the horizontal and vertical directions, a single HydroJet can provide the cleaning coverage equivalent to many waterlances, depending on
the size and layout of the furnace. Without a traversing lance tube, this device requires much less outboard
space on the side of the boiler and is tolerant of lowquality water.
The heat rate penalty of either a waterlance or
Hydrojet can be estimated by calculating the heat energy required to evaporate the water jet. See Equation 1.
w ( H1 − H 2 )
Qloss = m
Lance Tube
HydroJet Nozzle
(Opposite Side)
Mounts to Exterior Surface
of Furnace Wall
Two-axis
Drive
System
Water Supply Connection
(Flexible Hose)
to Lance Tube
Fig. 5 HydroJet® boiler cleaning system.
24-4
(1)
where
Qloss = heat penalty, Btu/h (kw)
w = mass flow rate of the water jet, lb/h (kg/s)
m
H1 = enthalpy of the water leaving the HydroJet
nozzle, Btu/lbm (kJ/kg)
H2 = enthalpy of steam at the pressure and temperature of the flue gas exiting the air
heater, Btu/lbm (kJ/kg)
Generally, atmospheric pressure and the flue gas exit
temperature from the air heater are a good approximation for determining H2 for this purpose. Although
the evaporated water is heated to superheated temperatures in the furnace, this steam is cooled along
with the flue gas through the remainder of the flue
gas path and useful energy is extracted.
The boiler operator must also consider the impact on
superheat temperatures, water wall circulation, furnace
pressure, and burner tilts if the boiler is fitted with this
feature. Each time the HydroJet is operated, excursions
of these parameters are possible. This is managed by
minimizing required flows through advanced nozzle
designs, operating the HydroJet for short periods of time,
cleaning small areas, and pausing between areas.
Control considerations
Permanently installed sensors have improved substantially and are successfully used in feedback control algorithms. Heat flux sensors may be installed in
furnace wall tubes and monitored to detect heat
transfer reduction associated with ash or slag buildup
and the thermal shock incurred during cleaning.
Emissivity probes can also be used to detect highly
reflective deposits that will degrade radiative heat
transfer to the furnace wall tubes. Optical pyrometers
for measuring flue gas temperature can assess local
or overall gas temperatures.
Control systems address furnace cleaning by dividing the surfaces that can be reached into relatively
small segments or zones. In the case of a waterlance
or an IR wall blower, a zone is the entire area that
can be cleaned by one device. In the case of a
HydroJet, a zone may be 5 to 10% of the total area
that is within the reach of a single device. The division of the furnace area is made by observations to
identify areas that generally accumulate deposits at
about the same rate. Judgment is applied to ensure
that cleaning a zone will not create an upset large
enough to destabilize the boiler’s overall operation.
In addition to using sensors to signal the control system when a particular area in the furnace requires cleaning, the control logic will employ permissives. Permissives
are additional conditions that must be satisfied before
the boiler cleaning device is activated. Permissives that
are included in a furnace cleaning control system are
specific to each boiler, and may include the following:
1. minimum elapsed time since the last cleaning of a
particular zone,
2. furnace exit gas temperature, above the minimum
recommended point for furnace cleaning,
3. superheat temperature, above the minimum recommended operating point,
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
4. reheat temperature, above the minimum recommended operating point,
5. superheater spray flows, above the minimum recommended operating point,
6. boiler load, above the minimum recommended
load for furnace cleaning, and
7. burner tilts, lower than the recommended degree
for furnace cleaning.
Unique applications
Hopper slopes High ash content fuels, in particular brown coal, tend to accumulate ash at such a high
rate on the hopper slopes that it can bridge over the
bottom opening in a matter of hours. This has been
effectively avoided by installing selective pattern
waterlances directly above the bottom ash opening
and controlling the water jets to sweep the hopper slope
on both sides.
Wing walls Tube sections that extend from the front
wall of the furnace to the roof, referred to as wing
walls, are cleaned by selective pattern waterlances.
Slag accumulation on wing walls not only renders
needed heat transfer surface ineffective, but is also a
common source of major slag falls leading to boiler
hopper damage. The face of these tube walls is only
accessible by inserting a lance tube from the front wall
in between adjacent wing walls. The selective pattern
waterlance is often configured to continue past the
wing walls to clean superheater pendants or division
walls, maintaining the required jet progression velocity control despite the complex geometry changes between wing walls and other surfaces.
Overfire air ports When using overfire air ports to
stage combustion and reduce nitrogen oxides (NOx),
a heavy slag buildup could accumulate above and
around each air port. This slag accumulation can affect the flow distribution and penetration of overfire
air into the furnace. This accumulation also presents
a personnel hazard during an outage.
A water cleaning device, designed specifically for
overfire air ports, has been used to remove this slag
while the boiler is on-line. This special waterlance is
referred to as an eyebrow cleaner because of the physical appearance of the slag accumulation pattern. The
unit has a retractable lance tube that sits at rest inside a sleeve passing through the air duct to the overfire air ports. A high velocity water jet is used as the
cleaning medium, and safeguards are included to ensure that refractory installed in the air ports is not
damaged by the waterlance’s operation.
Convection pass cleaning
Downstream of the furnace, heat is removed from
the flue gas by steam-cooled or boiling-water cooled
wall tubes and tube banks contained in the convection pass. (See Chapter 19.) In these tube banks, heat
absorption is dominated by convection heat transfer
from the flue gas to the outer surface of the tubes. Individual tube banks in this region may include primary and secondary superheaters or reheater.
The first segment of the convection pass is a critical region for on-line boiler cleaning because this is
Steam 41 / Boiler Cleaning and Ash Handling Systems
the first point at which the flue gas encounters narrow passageways between the tubes. At this point, the
flue gas often contains a substantial concentration of
ash particles, and the gas temperature may be high
enough that the particles are in a semi-molten state.
Under these conditions, deposits tend to collect on the
leading edge of each tube bank and between tubes
that are lined up behind one another. Deposits that
collect between the tubes are referred to as platenized
buildup, and are difficult to remove with on-line
cleaning. Fortunately, it is usually leading edge
buildup that has the more pronounced effect on gas
path blockage.
Principles
Deposits in the convection pass are removed primarily by the mechanical impact energy delivered by a
retractable sootblower. At the highest temperature
locations, the outermost surface of the deposits may
be in a semi-molten state, for which mechanical impact alone may not be sufficient. This condition is addressed in the section that describes Precision Clean®
sootblower control technology. Throughout most of the
convection pass, gas temperatures are lower and the
deposits are relatively brittle if removed periodically
to preclude sintering. In this case, the impact energy
of a sootblower nozzle creates cracks and fissures in
the deposits. Deposits break off in relatively large
pieces, often from their own weight, once deep cracks
have been created by the impact energy.
At even lower temperatures, the deposits are much
more porous and are only loosely adhered to the tube
surface, and to one another. In this case, cleaning is
accomplished by the abrasion-like action of the cleaning medium. Ash particles are removed as small particles being swept off the surface, for as long as the
nozzle is aimed at the surface.
The challenge in the convection section is to properly sequence the delivery of cleaning media at sufficiently high velocity to tube surfaces located within
an array of tightly spaced rows and columns. The
impact energy required to break up the deposits generally requires nozzle exit velocities well above the
speed of sound. Immediately after exiting the nozzle,
the cleaning media begins to decelerate. Depending
on the strength of the deposits, this can limit the effective range of sootblower nozzles to between 2 and
13 ft. (0.6 to 4 m).
Cleaning devices
Long retractable sootblower Two common long retractable sootblowers, the IK-500 and IK-600®, are
shown in Figs. 6 a and b. Each has a lance tube with
nozzles near the front tip, a carriage for inserting the
lance tube into the boiler, and a poppet valve for turning the cleaning medium on and off. A stationary feed
tube delivers cleaning flow from the poppet valve to
the lance tube as it slides over the feed tube. The carriage contains a gear set that drives the lance into and
out of the boiler along a helical path.
The nozzles are commonly installed perpendicular
to the longitudinal axis of the lance tube. As the cleaning media jet leaves the nozzle, it spreads outward and
24-5
The Babcock & Wilcox Company
Fig. 6b Model IK-600® sootblower.
is effective at removing some of the platenized buildup
in addition to deposits in the direct line of sight of the
nozzle centerline. This perpendicular nozzle orientation is preferred when the side-to-side spacing between tube rows is less than 18 in. (46 cm). With
smaller spacing between tubes, deposits can build up
and bridge the gap to close off the gas passageway.
The perpendicular nozzles provide the deepest penetration to ensure that the gas path remains unobstructed.
When the side-to-side spacing between tube rows
is greater, the nozzles may be oriented 5 or 10 deg
(0.088 to 0.175 rad) from the perpendicular axis. This
configuration is referred to as lead-lag nozzles, since
one will be oriented forward of the perpendicular and
the other slightly backward. This design has greater
potential for removing the platenized deposit buildup
between tubes within a row, and is used when there
24-6
Peak Impact Pressure, in. Hg (kPa)
Fig. 6a Model IK-525 sootblower.
is little or no potential for deposits to bridge from row
to row. Lead-lag nozzles have been particularly effective at cleaning division panels and pendant sections
at the entrance to the convection pass.
Sootblower nozzle performance In long retractable
sootblowers, nozzles are installed in the side wall of the
lance tube. Within the lance tube, the compressible
cleaning media travels at subsonic speed, generally
Mach 0.3 or lower. Most sootblower nozzles are designed
to accelerate the flow to supersonic conditions.
Nozzle performance is assessed by measuring the
peak impact pressure of the cleaning media jet at
points downstream of the nozzle outlet. Within limits,
the higher the impact energy, the more effective the
nozzle will be at fracturing and removing ash deposits.
The effect that nozzle design has on peak impact
pressure is illustrated by the comparison of three sootblower nozzles in Fig. 7. All three nozzles have the same
throat diameter, and because all three accelerate the
fluid to the speed of sound at the throat, the flow rates
are identical at any pressure shown on the graph. In
this figure, the peak impact pressure measured at a
distance of 30 in. (76 cm) from the nozzle outlet is plotted as a function of supply pressure for each nozzle. The
supply pressure at the nozzle inlet can be altered by adjusting the pressure drop in the sootblower’s poppet valve.
The development of high performance nozzles has
changed the previous operating approach. When using nozzles that were only slightly supersonic (Ground
Flush and Hi-PIP, for example), it was generally true
that the higher the density of the cleaning media, the
better the cleaning. For a system using steam, this
meant that less superheat was better for cleaning, and
saturated steam was better than superheated steam.
However, the performance of the newer class of supersonic nozzles depends on having no water droplets in the divergent section of the nozzle body to avoid
the flowfield disturbances and to achieve full expansion of the steam jet. To avoid water droplets, it is generally necessary to have 25 to 50F (14 to 28C) of superheat at the inlet to the sootblower. The presence of
condensate in the steam supply, or the formation of
condensation in the sootblower lance tube, has a significant degrading effect on high performance nozzles.
It can be severe enough to negate the benefit of a
nozzle replacement project.
200
(677)
Gemini
160
(542)
120
(406)
Hi-PIP
80
(271)
40
(135)
0
(0)50
(345)
Ground Flush
100
(689)
150
(1034)
200
(1379)
250
(1724)
300
(2068)
350
(2413)
400
(2758)
Nozzle Pressure, psig (kPa)
Fig. 7 Sootblower nozzle performance comparison at 30 in. (76.2
cm) from outlet.
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Precision Clean® sootblower control A standard soot-
blower translates and rotates the lance tube at a constant speed throughout its travel. As the lance tube
rotates, the nozzles sweep along the face of the tube
bank. With constant speed rotation, the jet progression velocity (inverse of dwell time) varies significantly
as the nozzle sweeps along the face of the convection
tube bank, from a point close to a point far away.
The required dwell time varies with deposit types
and deposit surface condition. Surface condition becomes particularly important when the deposit is semimolten. In this situation, dwell time becomes one of
the most significant factors in deposit removal.
A field-proven technique to address the dwell time
issue is to control the rate of lance tube rotation to
achieve a constant jet progression velocity within a
defined arc. The arc includes surfaces that are within
the effective range of the sootblower nozzle’s impact
energy. Outside this arc, the lance tube is simply rotated as quickly as possible until the next control segment (arc) for constant jet progression velocity is
reached. This technique, referred to as Precision Clean
sootblower control, significantly improves and extends
the cleaning effectiveness of a sootblower and can be
retrofit to existing sootblowers.
One way cleaning At the cooler end of the convection pass, sootblowers often clean adequately during a
single pass of the lance tube alone. This is almost always
the case in the economizer, and often in the primary superheater of a power boiler. In an industrial boiler, this
may apply to the entire convection pass.
With one way cleaning, flow is most often low during lance insertion and high during lance withdrawal
from the boiler. This patented technique most often
involves a remotely activated isolation valve in the
cleaning media supply line, with a bypass containing
a flow orifice. The orifice provides a minimum amount
of cleaning media flow when the isolation valve is
closed, sufficient to keep the lance tube from overheating. The poppet valve remains unchanged. A transient
heat transfer calculation is performed to determine the
bypass cooling flow rate.
Oscillator sootblowers Sootblowers are often installed in locations where a high energy cleaning jet
can cause damage. This might include the attachment
point of generating bank tubes to the steam drum, locations near the face of a tube bank, and areas prone
to sootblower-induced tube erosion or tube vibration.
Oscillator sootblowers have a mechanical linkage
on the carriage that causes the lance tube to sweep a
limited arc back and forth as it travels into and out of
the boiler. The arc can be altered by gear set changes.
Generally, the lance is fitted with pairs of nozzles so
that cleaning is two-sided and the thrust of one nozzle
jet is balanced by the thrust of the other. In some applications the lance tube may be fitted with a nozzle
on only one side and thrust-balancing orifices on the
other. A typical cleaning pattern is shown in Fig. 8.
Extended lance sootblowers As the flue gas temperature is lowered in the convection pass, additional
cleaning options become available. Generally, when
the gas temperature is below 1100F (593C), extended
lance or fixed position sootblowers can be used. Use
Steam 41 / Boiler Cleaning and Ash Handling Systems
Steam Drum
Area Cleaned
Cleaning
Medium
Trajectory
Lance Tube
Oscillation (Arc)
Sootblower
Lance Tube
Boiler Tubes
Fig. 8 Cleaning pattern of oscillator sootblower.
of specialized materials can permit the use of extended
lance or fixed position sootblowers at higher temperatures. Both are distinguished by their lance tube design, that continuously remains inside the flue gas
pathway. Fixed position sootblowers are discussed
under Back pass/economizer cleaning.
An extended lance sootblower is still a retractable
sootblower, although the beam and drive assembly are
only long enough to translate the lance tube a fraction of its length. The extended lance tube is fitted with
more than one nozzle assembly. A half-travel version,
for example, has two nozzle assemblies: one at the
front tip of the lance tube and the second at midlength. Each assembly may consist of a pair of identical nozzles diametrically opposed to balance the thrust,
or can have a single nozzle with or without thrust
balancing orifices on the opposite side. Extended lance
sootblowers fitted with 2, 3 and 4 nozzle assemblies
are common.
Bearing plates support the lance tube inside the
boiler. These plates are mounted to structural members inside the boiler, and the lance passes through
an oversized opening in the plate to limit tube deflection. The most distant bearing is installed so that the
lance tip is supported in the rest position (when the
lance is retracted to the rear stop of the carriage travel).
Additional bearings may be used if the gas temperature is high enough to induce stress relaxation in the
lance tube material (sagging).
The extended lance sootblower is generally used to
accommodate exterior space constraints. This
sootblower is also used to address unique design challenges posed when the convection section is partitioned, and it is not permissible to expel a cleaning jet
24-7
The Babcock & Wilcox Company
into a cavity or sleeve between the partitioned chambers. Extended lance sootblowers are used when a
concentrated jet of supersonic cleaning media is
needed for effective cleaning.
Diagnostic and sootblower control techniques
Modern boiler cleaning systems often incorporate
on-line diagnostic sensors and advanced control algorithms to increase cleaning effectiveness and boiler
efficiency while reducing the consumption of
sootblower media and reducing potential damage to
the boiler
Flue gas temperature is commonly monitored at the
furnace exit to detect general fouling on the furnace
walls. Load (fuel firing rate) and burner tilt position
must be considered. Flue gas temperature is also useful for detecting fouling in segments of the convection
pass. This is done with heat balance and heat transfer calculations for a particular tube bank to determine
a fouling factor. Deposit accumulations are detected
by tracking the fouling factor over time.
Pressure drop of the flue gas across tube banks is
an indication of deposit accumulation. Unfortunately,
by the time the deposit accumulation results in a measurable pressue drop increase, the deposits are already
heavy and are likely difficult or impossible to remove
with on-line cleaning alone. In recovery boilers, an operation called chill-and-blow can often disrupt the deposits enough that sootblowers can remove them, or
can at least extend the time until the boiler must be
shut down for a water wash.
The motor current on the forced or induced draft fan
can also be monitored to detect deposit accumulation.
Similar to flue gas pressure drop, by the time this parameter shows a measurable change the boiler deposits
may be too extensive to remove with on-line cleaning.
Centralized and distributed computerized control
systems can monitor fouling, verify that permissives
have been satisfied, and activate sootblowers one by
one through a prescribed sequence. Sequencing in the
convection pass is situation-specific. Generally, the final sequence is selected by the boiler operators based
on observed fouling patterns, accumulation rate, degree of difficulty in removing deposits in the various
regions and temperature zones, and sootblowing system constraints. Constraints might include steam capacity (number of sootblowers that can be operated simultaneously) and the time it takes for each sootblower
to run. These constraints may lengthen the elapsed
time before critical sootblowers can be repeated.
The following guidelines are recommended as a
starting point.
Convection pass deposits are easier to remove when
they are fully solid and brittle. Even a thin layer of
semi-molten deposits coating a thick and otherwise solid
base increases the amount of impact energy required.
For this reason, it is generally recommended to sequence
sootblowers from front to back of the boiler. Starting at
the positions nearest the furnace, each sootblower operation improves heat transfer at that point and makes
it easier to remove deposits at points downstream, by
lowering the gas temperature at these positions.
Among positions that are essentially at the same
24-8
point (temperature) in the gas stream, the choices are
bottom to top, or top to bottom. In convection pass sections where the gas flow is predominantly upward
(such as tube pendants suspended over the furnace
and before the arch), progressing from lower to upper elevations is recommended. However, when deposits weighing several hundred pounds could be dislodged, the recommendation would be top to bottom.
This reduces the chance that a slag fall from an upper
location would land on a lower sootblower’s lance tube.
Back pass/economizer cleaning
Later segments of the convection pass generally require a denser heat transfer surface arrangement due
to the lower gas temperature. Tube spacing is generally smaller as there is a lower likelihood of deposit bridging. For many fuels, tubes may be finned and positioned
in a staggered arrangement rather than simple rows and
columns. Deposit characteristics are clearly different in
this region, dusty and non-sintered for some fuels, and
sometimes accompanied by lightweight clumps of ash
(commonly referred to as popcorn ash). However, the
denser tube arrangement can be problematic for many
units firing western United States (U.S.) coals. This back
pass region includes the economizer.
Principles
Ash deposits in this region often begin as a thin
layer of dust on the tubes, which may eventually accumulate as unstable flags (wedge-shaped ash
buildup) built up on the leading edge of the tubes. Fixed
position sootblowers may be used where the deposits are
dusty or loosely adhered. Only a portion of the cleaning
is actually accomplished by impact energy of the nozzle
jet. Most cleaning is accomplished by the momentary increase in gas flow past the deposits when the cleaning
media combines with the flue gas flow to disrupt the flow
pattern. This is referred to as mass blowing.
When a greater degree of energy is required, for
example due to ash compacted between radial fins on
the boiler tubes, rake-type sootblowers may be used.
When ash deposits are loose or accumulated in unstable buildups, sonic horns operated at optimal frequencies may be effective.
Cleaning devices
Fixed position sootblowers This type of sootblower
is characterized by a tubular element fitted with a
number of nozzles along its length, usually positioned
along one side of the element. The nozzles are generally spaced to correspond to the boiler tube spacing
and aligned so that one nozzle is aimed between each
row of tubes. The element serves as a lance tube, but
remains permanently inside the boiler flue gas. The
fixed position sootblower with a rotating element is
also called a rotary sootblower. One common rotary
sootblower, the model G9B, is shown in Fig. 9.
The element is supported along its length with bearings, similar to the extended lance sootblower. When
the sootblower is activated, the element is rotated. The
rotating motion operates a cam which mechanically
opens the poppet valve, and cleaning medium flows
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Fig. 9 Model G9B electric motor driven rotary sootblower.
into a short feed tube and then into one end of the
element to distribute among the nozzles. The cam can
be configured to close the poppet valve after a prescribed arc or after a full revolution of the element.
To clean effectively, the rotary sootblower must provide sufficient flow to all nozzles in the element. The
nozzles nearest the feed tube entrance receive a
slightly higher portion of the flow. Design guidelines
are established to limit the flow maldistribution to less
than approximately 10% between the closest and farthest nozzle. However, to accomplish this, the size of
the nozzles must be restricted and thereby tube bank
penetration is limited. Nozzles are a convergent/divergent design with throat diameters ranging from 0.25
to 0.375 in. (6.35 to 9.53 mm).
A non-rotating version of the fixed position sootblower omits the feed tube and gear drive assembly.
An isolation valve simply turns flow on and off, and
the isolation valve must be opened and closed with an
electric or pneumatic actuator.
Rake-type sootblowers The rake-type sootblower is
particularly effective at removing deposits from tightly
spaced tubes with radial fins. This is a retractable sootblower with no lance rotation; the lance tube design
is T-shaped as shown in Fig. 10. The nozzles are located in the rake segment of the lance tube after the
tee, which is the section oriented perpendicular to the
direction that the lance travels. This lance is never fully
retracted from the flue gas. Also, the lance tube may
have more than one rake. The rake provides the ability to traverse a relatively low number of nozzles
across a large area of tube surface. The nozzles will
always be pointed directly into the tube bank and can
not contribute to cleaning the tube bank upstream of
the sootblower. They can, however, deliver more cleaning energy than a rotary sootblower.
Traveling crosswise to the economizer tubes is preferable, since this provides the maximum opportunity
for cleaning flow to attack tube deposit buildup from
Steam 41 / Boiler Cleaning and Ash Handling Systems
both sides (because of the diverging trajectory of
cleaning flow) in addition to head on. However, the
rake-type sootblower is still an effective approach to
cleaning difficult ash buildups even if space constraints outside of the boiler dictate that the rake travel
must be parallel to the economizer tubes. Nozzles
range from 0.25 in. to 0.625 in. (6.35 to 15.9 mm).
Sonic horns The use of acoustic energy to propagate sound waves within the boiler enclosure can also
dislodge deposits in the back pass regions of the boiler.
Sonic horns produce acoustic waves at frequencies
ranging from 20 to 200 hertz. Their use is generally
limited to locations where the deposits are dry and
loosely adhered. Example locations include a finned tube
economizer with dry deposits trapped between the fins,
and plates of an electrostatic precipitator. Fog horns have
been used to clean deposits in fabric filter baghouses.
At present, most sonic horns operate at mid-range
frequencies of about 75 hertz. At this frequency, a number of relatively closely spaced horns must be installed
around the periphery of the boiler enclosure; each is
operated intermittently, and operation alternates from
one to the next. Their effectiveness is limited by the
tendency for the sound pressure level to attenuate a
short distance into the flue gas. A smaller number of
horns is required when the operating frequency is lower,
around 20 hertz, because of the ability of the long wavelength unit to establish acoustic resonance if the sound
wave generator is carefully installed and adjusted.
Lower frequencies are also more effective at extending
the cleaning range deep into a staggered tube array.
SCR catalyst cleaning
The more common and reliable cleaning method for
selective catalytic reduction (SCR) system catalyst is
by sootblowing with steam or air. Catalyst plates have
been cleaned by acoustic devices where site-specific
conditions allow.
Principles
Sootblowers clean ash and ammonia salt particulate from the catalyst by providing a relatively low velocity of steam to each channel of the catalyst assemLance Tube
Nozzle Trajectory
(Cleaning Medium)
Rake Arm
Finned
Economizer Tubes
Fig. 10 Rake-type sootblower.
24-9
The Babcock & Wilcox Company
bly. The cleaning medium is almost always steam, but
air can be used as an alternative. The steam velocity
is low compared to sootblowers used for boiler cleaning to avoid mechanical or erosive damage to the catalyst substrate, yet high enough to dislodge loose particles in the catalyst channels and re-entrain them in
the flue gas flow. Sootblowers cleaning the catalyst are
designed to deliver steam in the range of 80 to 120 ft/
s (24.4 to 36.6 m/s) to the catalyst surface. However,
even at this relatively low velocity, it is critical to avoid
moisture in the steam flow. Water droplets are erosive,
can cause thermal shock on some catalyst designs, and
could dissolve the thin vanadium pentoxide coating
on the ceramic substrate.
Cleaning devices
Straight line sootblower The IK-525 Straight Line
Cleaner is a retractable sootblower designed for applications where the lance tube is inserted and retracted without rotation. It is used with rake-type
lance tube assemblies that reside permanently inside
the flue gas. This sootblower cleans SCR catalyst assemblies, economizers, and air heaters, and is occasionally
used for applications where lance tube rotation is undesirable or unnecessary, such as air duct cleaning.
SCR catalyst assemblies and air heaters are cleaned
by directing steam or air flow directly into the narrow
passages. An array of nozzles is positioned directly
above or in front of the leading edge of the assembly.
The nozzles are positioned in rake arms attached at
right angles to a central lance tube. A single lance
tube may be fitted with one to twelve rake arms. The
lance tube is supported inside the flue gas chamber
such that it holds the rake arm nozzles at a fixed distance from the leading edge of the catalyst or air
heater assembly. The lance tube is inserted and retracted such that each rake arm advances to the starting position of the rake arm ahead of it. Cleaning can
be during both the insert and retract pass of the rake
arm, or during only the retract pass.
When the lance tube has a number of rake arms, it
may be necessary to minimize the difference in cleaning medium flow as it is distributed to the arms. Therefore, the lance tube itself may consist of an upper and
lower lance tube. The upper lance tube is aligned with
the side wall penetration, and is the tube that penetrates the wall and telescopes over the stationary feed
tube. Flow distribution pipes deliver cleaning medium
flow to the lower lance tube. The rake arms are attached to the lower tube.
Flow distribution among the rake arms of each sootblower and among the nozzles is a primary consideration
in the design of an SCR sootblower. The goal is to provide a uniform curtain of steam flow from each rake arm.
Various methods help avoid moisture, beginning
with using a sufficiently superheated steam source.
To avoid moisture from the enthalpy decrease associated with pressure drop and velocity increase between
steam source and sootblower nozzles, it is generally
recommended that the steam source for SCR applications be on the order of 50 to 100F (28 to 56C) superheated. The goal is to have the steam remain above
saturation throughout the sootblower to the rake arm
24-10
nozzles, while satisfying thermal shock criteria imposed by the catalyst design. A common requirement
is that the cleaning medium temperature at the point
of contact with the catalyst surface must be within
100F (56C) of the catalyst (i.e., flue gas) temperature
to avoid thermal shock.
A superheated steam source can still produce condensate if precautions are not taken to drain condensate collected in the sootblower supply piping, and
preheat the steam header piping before operating the
sootblowers. Condensate drain control systems are
recommended in the sootblower piping system to ensure that the sootblower piping is maintained free of
condensate between sootblower operations. In addition, the control system should include steam header
warm-up before the sootblowers are operated. Generally this would consist of opening the steam isolation and control valves and a sootblower piping drain
valve for about five minutes before permitting the first
sootblower in a sequence to operate.
Catalyst manufacturers have established maximum sootblower pressures for each of their designs.
Generally, these fall into two groups: one recommends
supply pressures from 80 to 100 psig (552 to 689 kPa),
and the other prefers supply pressures of 10 to 20 psig
(69 to 138 kPa). The latter has become more common.
Popcorn ash
Some of the ash that makes its way past the boiler
arch is the result of small agglomerations referred to
as popcorn or large particle ash. Most of this is removed
from the hopper underneath the economizer, but some
could be carried to the SCR. SCR designs include a
screen positioned immediately above the inlet face of
the catalyst bank or at the outlet of the economizer.
The screens protect the catalyst from this ash. Because
most of these particles will not pass through the screen,
they must be removed by manual vacuuming during
an outage. Aerodynamic devices have also been used at
the outlet of the economizer to trap these large particles.
Air heater cleaning
Regenerative air heaters
Regenerative air heaters, common in large electric
utility steam generating plants, are susceptible to ash
particles collecting between the corrugated plates that
form the heat storage elements or baskets (see Chapter 20). Some flow path blockage occurs at the leading edge of the element. Some particles collect loosely
on the upper surface, and smaller particles become
wedged between the plates. Most of the pluggage that
occurs in the baskets, however, is an accumulation of
fine particles that adhere to moistened surfaces near
the cold end of the channels. The moisture is generally a result of acid precipitation from the flue gas. Ash
particles may also attach to ammonia salt deposition
associated with an SCR upstream of the air heater.
Regenerative air heater elements are made of thin,
corrugated steel plates. Deposits are removed by
means similar to that described in SCR cleaning.
Cleaning media must be aimed directly at the top surSteam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
face at relatively low velocities, to prevent the thin
metal plates from being deformed or fatigued by flowinduced vibration. Unlike the SCR catalyst, the regenerative air heater is in motion.
Cleaning devices
Straight line sootblower The version of the straight
line sootblower used in air heater cleaning applications
is the model IKAH. The lance tube is shown in Fig.
11. It contains one small rake, so it is not fully retractable, although the components outside the boiler are
similar to the fully retractable sootblower. The six
nozzles located along the length of the lance tube provide five cleaning bands as the air heater rotates.
When activated, the lance is slowly inserted and retracted while each nozzle traces a spiral cleaning path
along the face of the air heater baskets. Generally,
cleaning flow is only provided during the insertion
pass. A pneumatic actuator opens and closes the poppet valve, directed by the sootblower control system.
Swing arm sootblower A swing arm sootblower was
often included as part of the original equipment by
the air heater manufacturer. The arm consists of a pivoting pipe extending into the space upstream of the
air heater baskets with the tip turned to aim directly
into the face of the baskets. A nozzle is installed in the
tip to direct cleaning media into the baskets with sufficient flow to flush ash particles that have collected
between the corrugated plates. The arm is slowly swiveled as the baskets are rotated past the nozzle. The
cleaning path is spiral. The gear driven assembly that
controls the arm movement is external to the air
heater, and is located in the stationary part of the air
heater element enclosure, ahead of the rotating basket segment.
Dual media air heater cleaner With increased use of
low sulfur western North American coals and SCR systems, fouling of air heaters has become more difficult to
manage. The high calcium content of western coals can
lead to cementacious ash deposits if moisture is present,
especially at the cold end of the air heater. Ammonia slip
from the SCR can lead to tenacious salt deposits.
The dual media air heater cleaner has been used
Upper Lance Tube
Air Heater Basket Elements
Support Tube
Steam
Flow
Lower Lance Tube
(with Nozzles)
in recent years because of a superior cleaning capability with compressible media (steam or air), and a
built-in capability to switch to high pressure water
cleaning with highly precise nozzle position control.
Dual media air heater cleaners have been installed
at both the inlet and outlet face of the baskets on
Ljüngstrom-type air heaters.
The lance tube of the dual media cleaner is fully
retractable, or if external clearance is not available,
the lance tube can be configured with multiple nozzle
assemblies and partial travel, making the sootblower
beam much shorter. The nozzle assembly provides an
array of converging/diverging nozzles for directing a
jet of compressible cleaning media to the face of the
baskets, and a second array of water jet nozzles. The
lance tube does not rotate and is installed so that the
nozzles are between 12 and 30 in. (30 to 76 cm) from
the basket inlet. Cleaning is carried out during the
retract pass of the lance, and the lance is controlled
in a stepping mode; the lance tube advances one step
and holds position for one, two, or three revolutions
of the air heater before moving to the next position.
The number of passes that the nozzle is held stationary
is a function of radial position and operator selection.
The compressible flow nozzles are generally arranged in one of two possible arrays. The positioning
of these nozzles provides a nearly uniform flow field
between them and therefore thorough cleaning of the
air heater basket channels that pass underneath the
nozzle assembly. This allows for a substantial step size
because of the wide cleaning band provided. Still, in
this mode, the dual media sootblower typically requires
45 minutes to cover a 22 ft. (6.7 m) travel of the nozzle
head. The compressible flow nozzle jets are typically
supplied with steam or air at pressures ranging from
90 to 150 psig (621 to 1034 kPa).
The nozzle assembly also has a water jet nozzle
array generally installed in pairs. The spacing between the pairs of water jet nozzles and the step size
used during high pressure water wash ensure that
every channel in the basket is cleaned by a water jet
aimed directly at that single channel.
The compressible flow nozzles are occasionally supplied with low pressure, 100 psig (689 kPa) water to
provide a soaking-type cleaning action. This is particularly effective when the material being removed
is primarily salt deposits, and the dual media cleaner
is positioned on the cold side (downstream) of the air
heater baskets. With this flexibility, the dual media
cleaner accommodates three modes of operation: high
pressure steam cleaning for day-to-day cleaning maintenance, low pressure water wash for dissolving deposits, and high pressure water for semi-annual wash
down. The high pressure water capability minimizes
boiler down time and costly off-line water wash service contracts.
Fig. 11 Model IKAH sootblower for air heater cleaning.
Tubular air heaters
Tubular air heaters are generally not as heavily
fouled as regenerative air heaters, because their design affords less opportunity for deposits to collect.
Most commonly, the flue gas passes through the tube
side of this air heater design. Ash particles collect
Steam 41 / Boiler Cleaning and Ash Handling Systems
24-11
Rotation of Air Heater
The Babcock & Wilcox Company
loosely on the inside walls of these tubes although
there is the potential for moisture from acid precipitation to act as a wetting agent.
Cleaning devices
Rake-type sootblower for tubular air heaters The IK525 straight line sootblower is used to pass a rake-type
lance tube over the face of the tubesheet that forms
the tubular air heater inlet. Nozzles direct cleaning
media (steam or compressed air) directly into the air
heater tubes as the lance advances and retracts. The
lance tube may have multiple rakes to shorten the
length of the sootblower needed on the outside of the
air heater. The lance tube travel achieves complete
cleaning coverage of the air heater tubes, with only
minimal overlap at the start and stop positions of the
adjacent rake arms.
Air puff sootblowers Fixed position sootblowers with
a pulsating output are occasionally used to clean tubular air heaters when external clearance is not available for a rake-type sootblower. The model A2E air
puff sootblower includes a gear driven mechanism that
abruptly turns the flow on and off 20 times during each
main drive rotation. A fixed position tubular element
installed above the face of the tubesheet has nozzles
installed along its length directed at the tube inlets.
An abrupt and repetitive disruption of the flue gas
flow into the tubes, along with modest impact energy,
is accomplished by pulsing the cleaning medium flow.
The most aggressive cleaning is achieved by a nonrotating element, but the number of A2E sootblowers
can be reduced by rotating the element to direct cleaning flow into tube rows on either side of the element.
Supply pressures of 125 to 150 psig (862 to 1034 kPa)
are typical for coal-fired boilers.
The air puff sootblower is also used to clean the back
pass regions of oil-fired boilers, including the economizer. Supply pressures up to 200 psig (1379 kPa) are
generally required.
Other cleaning applications
This chapter focuses primarily on cleaning equipment found on large coal-fired utility boilers. While
the same cleaning equipment is generally applicable
to all boiler designs, a few additional special application features include:
Coal-fired (and biomass-fired) industrial boilers These
units also usually have a boiler or generating bank
located in the convection pass. (See Chapters 27 and
30.) Boiler banks are generally cleaned with retractable IK-type sootblowers.
Oil-fired boilers As discussed in Chapter 21, oil firing produces significantly less ash than coal firing
though the ash is often more corrosive. Generally,
fewer sootblowers are needed for oil versus coal firing. In these units, G9B sootblowers may replace some
of the IK retractable blowers in the convection section
upstream of the economizer.
Process recovery (PR) boilers As discussed in Chapter 28, deposits are often more extensive and harder to
remove in PR boilers. As a result, IK sootblowers are used
in larger quantities throughout all of the boiler surfaces
and are cycled more frequently.
24-12
Waste-to-energy (WTE) boilers Because of the very
corrosive nature of the WTE boiler environment, special care in cleaning of the surfaces is needed as outlined in Chapter 29. It is very desirable to not clean
the superheater tubes completely to expose bare metal
as this will accelerate corrosion. To address this, a rapping cleaning system is employed in the superheater
along with carefully applied sootblowers in a range
of units. Where sootblowers are used, tube shields are
frequently employed to provide additional sacrificial
metal on the tubes closest to the sootblower installation. More detail is provided in Chapter 29.
Fluidized-bed boilers Lower operating temperatures
generally make cleaning these units easier than pulverized coal-fired units, reducing the sootblower requirements. In circulating fluidized-bed units, sootblowers are not installed in the vertical furnace shaft.
(See Chapter 17.)
Ash handling systems
The ash handling systems of a steam generating
plant collect the ash and residue from the combustion
of solid fuels from different points along the boiler flue
gas stream (see Fig. 12), transport it to storage bins
or silos, and prepare the ash for transport or disposal.
Because the characteristics of ash are very different
from the front to the back of the boiler, the collection,
transport, and storage systems are usually separate
for the furnace and collection points downstream.
In a coal-fired boiler, the general categories of ash are:
1. Bottom ash − the material that collects at the bottom of the furnace, possibly a heavy slag.
2. Mill rejects − the heavy pieces of stone, slate and
iron pyrite that are discharged from the coal pulverizer.
3. Economizer ash or popcorn ash − the course and
comparatively dense particles that drop out of the
flue gas when the gas changes direction abruptly,
such as in the back pass and air heater ducts.
4. Flyash − the fine ash particles that are collected
in the dust collection equipment.
Although bottom ash and mill rejects are unique to
pulverized coal-fired boilers, the above classification
is generally useful for describing the different types
of ash handling equipment. Common terms and definitions are provided in Table 1.
Boiler
SCR
ESP or
Fabric Filter
Pulverizers
To
Stack
Air
Heater
Pyrite Bottom Ash
<2%
15 to 40%
Backpass
Ash ¯ 5%
Air Heater
Flyash ¯ 5%
Flyash
50 to 75%
Fig. 12 Typical pulverized coal-fired boiler ash discharge locations
and approximate amounts.
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Bottom ash systems
Bottom ash is most often conveyed in a hydraulic
system in which the ash is entrained in a high flow,
circulating water system and delivered to either an ash
pond or to dewatering storage bins. Alternatively,
mechanical drag systems have been used to convey
bottom ash to the dewatering storage bin because they
use less water and usually have a lower initial cost.
Both systems are designed to handle ash dropping into
the conveyance system at temperatures as high as
2400F (1316C), requiring each system to have a
quenching volume of water at the initial collection
point. It is common for the bottom ash system to store
as much as three days of ash output from the boiler.
Hydraulic bottom ash systems
The first component of the hydraulic conveying system is the water-filled hopper shown in Fig. 13. The
bottom of the furnace terminates in a rectangular
opening running across the width of the boiler (the
floor of the boiler itself being a hopper). The bottom
ash hopper fits up to this with its own sloped wall
chamber so that ash and slag feed by gravity to a
single outlet. On larger boilers, the bottom ash hopper may be divided into parallel chambers, referred
to as pant legs, each having an outlet at its bottom as
shown in Fig. 13. The outlet is sealed with a hydraulically driven gate controlled to open when the hopper is
full, and coordinated with other hoppers so that only one
hopper at a time empties into the conveying line.
The bottom ash hopper is filled with water to
quench the hot ash as it enters, and is usually lined
with refractory. The connection between the ash hopper and the bottom of the boiler seals the boiler gases
and accommodates thermal expansion of the boiler.
This is accomplished by a water trough design around
the top of the hopper that keeps a steel plate skirt
immersed in water. The skirt is attached to and moves
up and down with the boiler, while the bottom ash
hopper rests on the ground. Exposed refractory is kept
cool by continuous water flow over the refractory surface. Cooling water supply is furnished either as overflow from the seal water trough or through embed-
Fig. 13 Typical gravity feed bottom ash hopper.
Steam 41 / Boiler Cleaning and Ash Handling Systems
Table 1
Ash Handling Terminology
Slag
Characteristic ash removed from
furnace walls
Bottom ash
Ash removed from the bottom of the
furnace
Clinker
Large piece of bottom ash that must
be broken up before transport
Flyash
Ash carried by the flue gas into the
backpass region and beyond
Popcorn ash
Characteristic ash collected in
economizer and air heater hoppers
Dust
Fine ash particulate, typically 50 to
75% of all ash from boiler
Hydroejector
Venturi device that pulls bottom ash
into hydraulic transport system
Hydrobin
Dewatering bin for removing water
from bottom ash
Hydrovactor
Venturi device that provides
vacuum source for pneumatic
transport
Airlock valve
Two chamber device for feeding ash
into higher pressure transport line
Materials
handling valve
Valve that admits flyash and air
flow into vacuum transport line
Collector
Ash/air separator and transfer tank
from vacuum system to silo
Transporter
Flyash collection and aeration
vessel for dense phase pneumatic
transport
Vacuum/pressure Collection and transfer vessel from
transfer station
vacuum line to pressurized line in
combination vacuum/pressure
pneumatic system
Drag chain
Primary mover in mechanical drag
conveyor system
Flights
Attached to drag chain to push ash
along stationary platform
Unloader
Device to unload dry ash storage silo
into transport vehicles
Conditioner
Adds water to flyash during
unloading to minimize airborne dust
Pugmill
One version of combined silo
unloader/conditioner
ded refractory cooling water distribution piping. The
cooling method selected is determined by the boiler operating pressure.
When the boiler is a continuously slagging wet bottom design, the ash hopper is replaced with a slag tank.
The wet bottom boiler terminates in a cooling trough
for the flowing slag. To break up strings of slag forming at this point, the cooling trough has a slag swiper
that swings a water-cooled arm back and forth across
the inlet opening. The slag tank may include agitat-
24-13
The Babcock & Wilcox Company
ing jets in the water pool to granulate the slag as it
solidifies. The remaining features of the slag tank are
generally the same as a bottom ash hopper.
The bottom ash hopper or slag tank is sized to hold
about eight hours of ash produced by the boiler. To
empty the hopper, the discharge gate opens and the
contents enter a gate housing, which directs the ash
into a clinker grinder where the slag is crushed. Clinker grinders have a variety of designs classified in
terms of the maximum particle size that remains after passing through the grinder. Specified particle sizes
range from cubes measuring 0.75 in. (1.9 cm) on all sides,
to pieces 2.5 in. (6.4 cm) in diameter. Smaller particles
require a lower water flow rate to transport them and
have a lower tendency to plug the line, particularly in
the valves and fittings of the transport piping. However,
smaller particle sizes also tend to make it more difficult
to separate the water at the end of the conveyance line.
Clinker grinders are either single or double roll design. The rolls are the elements that rotate and grind
the slag with protruding teeth. A double roll design
rotates the shafts counter to one another so that particles are pulled in and crushed as they pass through
the grinder. A single roll design uses a stationary
breaker bar for the opposing force.
The crushed particles are fed into the conveying line
both by gravity and pump suction. The pump may be
a centrifugal slurry pump or an ejector (jet pump).
Slurry pumps are used to transport the ash longer
distances, in particular when the frictional and elevation head loss exceeds about 150 ft. (45.7 m). Ejectors
are often chosen for their ease of maintenance because
they have no moving parts. A centrifugal pump is still
required to produce the high pressure water that supplies the ejector and the energy efficiency of the system is lower, but by using the ejector, the course ash
and slag particles do not pass through the pump itself.
In both cases the ash particles are diluted into a
slurry that is about 20% solids by weight entering the
piping system. The goal of the piping layout is to use
the least number of bends possible because of the extremely erosive nature of this mixture, and the need
to minimize pressure drop. The piping is either hard
iron alloy or lined pipe. Lining materials include basalt and ceramics. Elbows and lateral fittings (used to
merge two lines) are usually made of harder material,
and are uniquely made with extra material thickness
at points where solid particles tend to impact the pipe.
When additional material is cast into the design, it is
referred to as integral wear back fitting.
The piping system delivers the mixture to an ash
pond or a Hydrobin dewatering storage bin (Fig. 14
and chapter frontispiece). Two dewatering bins are
used in each installation. One receives ash from the
boiler while the other is draining or decanting water
from the collected solid material.
A Hydrobin is initially filled partially with water.
Incoming ash slurry is dropped into the center onto a
sloped bar screen that acts as a partial classifier.
Coarser material is forced to the sides of the cylindrical bin while the finer particles drop into the center.
Later, while draining, the coarser particles act as a
filter to trap fines before they reach the decanting el-
24-14
ements along the wall.
The bin quickly fills with water from the incoming
slurry, although it may take a day or more to fill to
capacity with solid material. Until the bin is filled with
solids, loading continues and excess water is extracted
from the top and returned for reuse in the conveying
lines. At the top of the Hydrobin, an underflow baffle
directs all incoming material downward and helps
prevent the fines from simply floating across the surface to the overflow. After the water flows under the
baffle, it flows over a serrated weir as overflow. The
concentration of suspended solids contained in the
overflow return line is dependent on ash particle size
distribution in the slurry, ash particle density, and the
water flow rate going over the weir. The larger or
denser the particles, the greater their tendency to sink
rapidly to the bottom of the bin.
Mechanical drag systems for bottom ash
The first element of a mechanical drag system is a
transition chute that mates up to the bottom opening
of the boiler. The transition chute uses a water-filled
trough to seal boiler gases by immersing the seal plate
at the bottom of the boiler in the trough. The remainder of the transition chute provides storage volume for
bottom ash, mainly for periods when the drag system
is unavailable. The bottom of the chute funnels down
with its sloped side walls to drop ash onto the center
of a conveyor. For bottom ash, the conveyor itself is always submerged in water, but the transition chute may
be dry or filled with water up to the top of the sloping
side walls. These two types of transition chutes are
shown in Fig. 15. When it is water-filled, the transition
chute is referred to as a hopper and the overall system is
referred to as a submerged chain conveyor (SCC).
The drag conveyor consists of two chains traveling
horizontally underneath the chute, and once past the
chute, turning upward along a dewatering incline.
Flight bars are attached to the chains at regular intervals. The flight bars drag across a stationary plate
while the bottom ash drops from the transition chute.
The ash lands between the flight bars and gets pushed
from underneath the chute, then up the incline to lift
the ash from the quenching water pool. At the end of
the incline, the residual moisture in the ash is generally about 20 to 30% by weight.
At the top of the incline, the ash is dumped into
either a bunker or a discharge chute and onto another
conveyor or series of conveyors. If necessary, a clinker grinder may be installed at the discharge end of
the first conveyor. Ultimately, the bottom ash is
dumped into a storage bin or dewatering bin. Normally,
ash removal from the boiler is continuous, but the storage or dewatering bins may provide up to three days
storage to accommodate pickup schedules. If a dewatering bin is used, a settling tank and surge/storage tank
may be used to clarify the drained water for reuse.
To maintain the water trough seal at the boiler hopper skirt, water must be continuously circulated. Because of the low water inventory, a heat exchanger is
commonly needed in the recirculation line to keep the
water below about 140F (60C).
The submerged mechanical drag system requires
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Underflow
Baffle
Bar Screen
Classifier
Serrated
Overflow
Weir
Stationary
Decanting
Elements
Floating
Decanter
Hydrobin
Gate
Fig. 14 Hydrobin® dewatering bin.
approximately 12 to 15 ft (3.7 to 4.6 m) height under
the furnace throat opening on large utility boilers;
smaller boilers require less distance. This allows the
boiler to be located closer to the ground and reduces the
cost of structural steel and other supporting components.
The drag chain system is typically installed on
wheels in a rail or track system underneath the boiler,
and one or both of the side plates at the bottom of the
boiler are hinged. This allows the conveyor system to
be removed for service (such as chain or flight replacement) and provides open access to the bottom of the
boiler during outages.
mill outlet spouts with seals that can accommodate
positive pressure and pressure surges that occur when
the mill is purged with inert gas.
When the bottom ash is conveyed with a hydraulic
system, ejectors are used at each mill storage hopper
to pull the dry mill rejects into the high velocity water
flow for transport. The resulting slurry from each mill
is piped into a common pyrites holding bin as shown
in Fig. 16. The common holding bin is generally emptied at the same time that the boiler’s bottom ash hoppers are emptied, using the same transport piping to
the dewatering bin or pond.
Although it is common for mill rejects to be conveyed
in the bottom ash hydraulic transport system, the
much heavier pyrites impose a substantial burden on
the hydraulic system. Often, the water flow must be
increased to entrain these heavier particles. An economic tradeoff is made between the cost of an independent mill reject transport or a shared system. The
shared system must include pumps selected for transporting the most difficult material, and the dewatering bins must be sized for higher water flow when mill
rejects are transported with the bottom ash.
Economizer ash systems
The flyash removed from hoppers under the economizer, SCR, and air heater tends to contain larger
particles along with the fine dust-like ash collected in
air cleaning devices. The larger particles (popcorn ash)
may contain concentrations of unburned carbon. Because of the high gas temperatures at these points,
the ash may tend to sinter and become difficult to remove if permitted to sit for long periods. For this reason, it is common to provide crushers to reduce the
particle sizes to about 0.25 in. (0.6 cm) in diameter for
pneumatic transport. Alternatively, small, dry secondary hoppers can be installed under each economizer
Transition Chute
Dewatering
Incline
(Typ.)
Mechanical Drag Unit for Continuous Removal
Plunger ash extractor
The ash discharged from the stoker on mass burn
municipal solid waste (MSW) units consists of ash and
slag similar to that derived from other combusted fuels, except that the MSW fuel has a high ash content
and includes oversize bulky wastes (OBW). This system is discussed in more detail in Chapter 29.
Mill rejects
Pulverizer rejects (often called pyrites) are commonly dumped into the bottom ash conveyance system. A mill storage hopper is installed at each pulverizer to collect the rejects. This hopper is sealed to the
Steam 41 / Boiler Cleaning and Ash Handling Systems
Water Impounded Storage Hopper
Side View
Ash Gates
Mechanical Drag Unit with Hopper Storage Capability
Fig. 15 Transition chutes for mechanical drag systems.
24-15
The Babcock & Wilcox Company
Water Clarifying and Storage
Furnace Bottom
Ash Hoppers
Bottom Ash
Optional Closed Loop
Recirculating System
High Pressure
Recirculating Pump
Ejector
Clear Water Return
Optional Basin System
Pulverizers
Mill Rejects Pipe
to Holding Bin
Pyrites
Holding Bin
Ejector
Fig. 16 Basic ash system including mill rejects.
or air heater hopper to continuously receive the ash.
By removing the ash from the hot gas stream, the
tendency to sinter is eliminated and the ash remains as
primarily a fine dust with some popcorn ash particles.
This ash is generally combined with the flyash
transport system, whether vacuum or pressurized
pneumatic. A pressurized system requires an airlock
valve to discharge the ash into the conveyance piping. A materials handling valve is used to dump ash
into a vacuum system.
Economizer ash is occasionally mixed with a hydraulic bottom ash conveyance system. Because water is very difficult to remove from this ash, this is
generally done only when the bottom ash is being
disposed of in a fill area. Dewatering bins are not well
suited to handling economizer ash.
Mechanical drag systems may also be used for
economizer ash, and are particularly suitable when
the ash is to be reinjected into the furnace. In this
application, the drag unit is dry and sealed. A single
drag unit will normally collect from all economizer
hoppers. The ash is then discharged through a rotary
feeder into a storage tank. If the ash is to be combined
with the flyash transport, the storage tank discharges
into the pneumatic system with an airlock valve or
materials handling valve.
Flyash systems
Most of the ash from a pulverized coal-fired boiler
is carried through the boiler and air heater by the flue
gas. As much as 50 to 70% of the ash generated by
24-16
combustion of pulverized coal is removed from the flue
gas by an air cleaning device, such as a filter baghouse
or electrostatic precipitator. (See Chapter 33.) Baghouses and precipitators have rows of collection hoppers that are emptied regularly by the flyash transport system.
Flyash consists of fine particles with low density.
These particles are rarely transported in a water slurry
because they can not be easily separated from the
water at the end of the transport process. For this reason, flyash is almost always transported pneumatically. Pneumatic transport systems generally fall into
three general types:
1. vacuum systems,
2. pressure systems, or
3. combination vacuum/pressure systems.
Vacuum systems
A vacuum system uses air, below atmospheric pressure, to entrain and convey ash particles. For systems
with short transport distances, this often provides the
lowest initial cost. A vacuum system uses fewer components and requires less clearance under the precipitator or baghouse. A vacuum system operates cleaner
because any leaks merely pull ambient air into the
system. Because of the low pressure of air in the system, transport distances are limited and larger line
sizes may be necessary to avoid excessive piping wear.
The first point in the vacuum transport system is a
material handling valve, attached to the outlet of each
hopper. These valves empty the hoppers into the conSteam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
veying system and in their full open position regulate
the flow of ash to provide a quick but steady dispensing of the collected ash. A single pipe runs underneath
each row of hoppers collecting the flow from the material handling valves. At one end, an air inlet valve
opens to supply air for transporting the ash when a
vacuum is applied at the other end of the pipe. Then,
one at a time, the material handling valves are opened
and ash flows into the pipe. Each material handling
valve may use integrally mounted air inlet check
valves. These are located just behind the gate so that
they are opened by vacuum after the material handling valve itself is opened. These air inlet valves improve ash flow from the hopper into the conveying line.
The material handling valve can serve as a tee connection to the conveyance pipe, or may be connected
to the conveying line with a short length of pipe. Integral wear back fittings or fittings with a replaceable
wear back are commonly used in vacuum systems.
At the silo, the ash is separated from the conveying air in a two-chamber collection vessel. The collection vessel allows continuous collection of ash from the
conveying line at vacuum pressures, and facilitates
the gravity feed transfer of this ash into a silo at atmospheric pressure.
The vacuum source is located at the discharge end
of the piping system, downstream of the separation
equipment on the silo, to minimize the amount of abrasive ash that is drawn through the vacuum producer. The
vacuum may be produced hydraulically or mechanically.
Pressure systems
Pressurized conveying of flyash offers some advantages over vacuum systems. Because they are not limited by one atmosphere of pressure differential from
pickup point to the silo and vacuum producer, these
systems can convey over longer distances. Also, the
ash/air separation equipment can be simplified at the
storage silo. However, because the feeding device at
each pickup point is complicated by the need to transfer ash from the low pressure hoppers into the high
pressure conveying line, the feeding device is larger.
This requires more space under the precipitator or
baghouse, and has a higher initial cost because the
transfer equipment must be provided at each of the
numerous pickup points. This offsets the cost savings
of the simpler silo separation equipment. Pressurized
systems are generally chosen with conveying distances
greater than 750 ft (228 m), and considering the lower
operating costs of a pressurized system. Pressurized
systems may also be required at higher altitudes, because of the lower differential pressure available for a
vacuum system.
The starting point for a pressurized system is a positive displacement blower which provides air flow and
pressure for conveying the flyash. The blower feeds a
piping system that branches out to collect ash from the
numerous hoppers under the precipitator or baghouse.
An airlock valve dumps ash from each hopper into
the conveying line (see Fig. 17). This valve consists of
two chambers, upper and lower, with three gates: one
to close off the opening to the hopper, one between the
upper and lower chamber, and a cut-off gate to empty
Steam 41 / Boiler Cleaning and Ash Handling Systems
the lower chamber of each airlock into the conveying
pipe one at a time.
An equalizer valve is required for each airlock
valve. The equalizer valve has two positions: one to
equalize the pressure between the hopper and upper
chamber of the airlock, and the other to equalize pressure between the conveying pipe and the upper chamber. It is inevitable that some of the abrasive ash flows
through the equalizer valve each time it changes position, so it is designed to be self-cleaning and includes
wear resistant surfaces at key points.
To operate the airlock valve, all three gates are initially closed. The pressure of the upper (primary)
chamber is equalized with that of the overhead hopper. The gate valve above the primary chamber is then
opened for a preset period of time. This dwell time allows a measured amount of flyash to flow by gravity
into the primary chamber. At the end of the loading
cycle the upper gate is closed to isolate the chamber
from the hopper. The upper chamber is then pressurized to a level slightly greater than the conveying line
pressure. Finally, the gate between the upper and
lower chamber is opened and ash is forced down into
the conveying line through an intake tee. The intake
tee imparts swirl within the lower chamber for better
ash pickup performance. The cut-off gate below the
lower chamber is a manual gate used to isolate the
airlock for maintenance.
In some cases, it is necessary to include an aeration device to counteract the tendency of the ash to
compact in the hopper and the upper chamber of the
airlock valve. The design of the airlock is modified
slightly as shown in Fig. 18.
To Flyash
Hopper
Flyash
Hopper
To
Conveying Pipe
Equalizer Valve
Top Gate
Upper Chamber
Lower Gate
Cut-off Gate
Lower Chamber
Conveying Pipe
(Intake Tee)
Fig. 17 Airlock valve (without aeration).
24-17
The Babcock & Wilcox Company
When the airlock valve is attached to an economizer
hopper, the top gate is commonly left open until the
upper chamber is ready to be emptied. This allows the
much hotter economizer ash to collect in the upper
chamber of the airlock valve to get the ash out of the
hot flue gases and reduce the tendency of the ash to
sinter and form large chunks. If this occurs despite the
use of the airlock as a collection device, then a rotary
feeder may be used to break the ash into smaller,
transportable pieces.
Automatic butterfly valves at the heads of the branch
lines provide branch isolation when ash is being removed
from the other branches. Manually operated knife gate
valves are provided at the ends of each branch line for
maintenance purposes. An overall schematic of a pressurized conveyance system is shown in Fig. 19.
With a pressurized system, the conveying air and
entrained ash are simply dumped into a dry storage
silo. Ash settles in the silo and air is removed from the
top through a self-cleaning bag vent filter. In some
cases, the air flow is routed through a duct to the precipitator inlet.
Combination vacuum/pressure systems
Combination systems are used to transport ash
longer distances than a vacuum system alone can accommodate, while keeping some of the advantages of
the vacuum system, such as its lower space requirement. In the combination system, the initial withdrawal of ash from the hoppers is by a vacuum sys-
Flyash
Hopper
To Flyash
Hopper
Aeration Stone
To
Conveying
Pipe
Top
Gate
Equalizer Valve
Upper Chamber
Aeration Stone
Cut-off Gate
Lower Gate
Lower Chamber
Conveying Pipe
(Intake Tee)
Fig. 18 Airlock valve (with aeration).
24-18
Fig. 19 Pressure flyash system.
tem. Ash is delivered to an intermediate collection
vessel where it is transferred to a pressure conveying
system for final delivery to a distant dry storage silo.
The vacuum system is the same as that described
from hopper pickup to the intermediate collection vessel. The intermediate collection vessel can be either a
transfer tank or a surge bin. In principle, the surge
bin is identical to a dry storage silo, including the primary and secondary separation equipment on the roof.
The surge bin is smaller than a storage silo, but provides an intermediate storage volume for ash. The
surge bin dumps into airlock valves underneath the
bin, which feed ash into the higher pressure line of
the pressure conveying system. The pressurized conveying system is the same as described earlier, except
that the airlock valves collect from a surge bin.
A vacuum-pressure transfer tank is often used as
the intermediate collection vessel. As shown in Fig. 20,
the transfer tank is a vessel with three chambers: upper, middle, and lower. The upper chamber is always
at the vacuum pressure of the vacuum conveying line,
and the lower chamber is always at the higher pressure of the pressurized conveying line. Dump valves
are located between the chambers. Ash continuously
collects in the upper chamber, which also serves as the
primary stage of air/ash separation with the centrifugal separator design of the upper chamber. After a preset period of time, the pressure in the upper and middle
chamber is equalized, and the dump valve between
the upper and middle chamber is opened. When the
middle chamber has emptied the upper chamber, the
upper dump valve closes. Another valve equalizes the
pressure between the middle and lower chamber, and
the lower dump valve is opened.
Air that is separated from the ash in the upper
chamber is sent to a secondary collector, which includes a fabric bag filter, and then to the inlet of the
vacuum producer.
A variation of the vacuum-pressure transfer tank
is available for high temperature material separation
and transfer. The high temperature tank has a single
chamber that provides a centrifugal separator incorporated in the top of the tank, and a bottom section.
The tank is constructed with materials and wear surfaces suitable for handling material up to 750F
(399C). This tank dumps into airlock valves as shown
in Fig. 21. The airlock valves are used as pickup points
for the pressurized conveying system.
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Continuous
3-Cell Vacuum-Pressure
Collector and
Transfer Unit
Vacuum
Conveying
Line
Vacuum
Chamber
Incoming
Flyash
From
Hoppers
Equalizer
Valves
Bag
Filter
Equalizing
Chamber
To
Vacuum
Producer
Secondary
Collector
Pressurizing
Air Line
Air Lock
Valve
Pressurized
Air From
Blower
Pressurized
Conveying
Line
To
Disposal
Pressure Reducing Orifice
Fig. 20 Collection equipment for vacuum-pressure flyash system.
Dense phase systems
An option available for pressurized transport systems is to operate at higher ash to air ratios, which
uses less air, smaller transport pipe sizes, and potentially causes less wear of system components. When
the weight ratio of flyash to air exceeds about 15 to 1,
the transport is referred to as dense phase.
In the systems described up to this point (dilute
phase), the ash feed regulating valves were designed
to deliver ash into the conveying line as individual
particles that would become thoroughly entrained in
the air flow. The air flow velocity would generally be
maintained above the point where particles would drop
out of the flow and drag along the bottom of the pipe.
In dense phase transport, the ash is initially fluidized and transported at lower velocities. The ash is
transported through the line in a dense fluid-like condition, often dropping from suspension and resembling moving and shifting sand dunes as the ash
moves along the pipe. The key to dense phase transport is that the ash must have a consistency that lends
itself to fluidization. Different ash types have different tendencies.
The facilitating element of a dense phase system is
the fluidizing vessel commonly called a transporter.
Ash is delivered to this vessel in batches from the hoppers. When filled with ash, the inlet valve is closed and
compressed air is pumped into the vessel.
The transporter vessel can be a top or bottom discharge design. A top discharge, fluidizing transporter
vessel is shown in Fig. 22. Compressed air is pumped
Steam 41 / Boiler Cleaning and Ash Handling Systems
into the vessel through an aeration device (stone, ceramic, or metal element) in the bottom of the vessel.
The ash becomes fluidized and the pressure in the
transporter vessel builds. The aerated ash begins to
flow into the conveying line soon after the compressed
air is pumped into the transporter vessel. Elastomerlined pinch valves (not shown) admit ash to the conveying line from one transporter vessel at a time.
A bottom discharge transporter vessel is shown in
Fig. 23. In this design, compressed air is also pumped
into the vessel, forcing ash into the conveying line.
Transport is enhanced by pulsing the air flow into the
vessel, and alternating between an injection point in
the side of the transporter vessel and an injection point
in the conveying line itself. The ash is also fluidized
in this design before entering the conveying line, but
not in the transporter vessel. Instead, the fluidization
with compressed air is done in a holding bin above the
transporter vessel so that the ash is already fluidized
when it enters the transporter vessel.
A primary advantage of dense phase transport is
lower air velocity. This allows use of less expensive,
unlined steel pipe. However, much longer radius turns
must be used in place of elbows or standard fittings to
avoid plugging.
Separation and storage
At the end of the transport piping, ash is separated
from the conveying air flow and collected in a dry storage silo. In a pressurized system, the air and ash flow
empties into the silo and the air flow is vented from
the top of the silo. A fabric (bag) filter may be used to
capture any fine dust that is not separated by gravity in the silo, or a vent fan may be used to draw the
air from the roof of the silo and pump it back into the
Water Operated Air Cooler
(Option)
Incoming
Flyash From
Hoppers
To
Vacuum
Producer
Bag
Filter
Vacuum
Conveying
Line
Vacuum
Collector
Secondary
Collector
Pressurizing
Air Line
Air
Lock
Valves
Pressurized
Air From
Blower
Pressure Reducing Orifice
To
Disposal
Pressurized Conveying Line
Fig. 21 Vacuum-pressure system for hot flyash.
24-19
The Babcock & Wilcox Company
To Pressurized
Ash Transport
Line
Discharge Pipe
Incoming
Flyash
From Hoppers
Inlet Valve
Transporter
Aeration
Stone
Compressed
Air Inlet
the secondary and primary collectors serves as the motive force for the vacuum transfer system.
Storage silos are usually sized to store three days
of ash produced by the boiler at full load. Larger boilers have ash silos installed in pairs, so that one can
be unloaded or serviced while the other collects ash.
Silos may be made of carbon steel or reinforced concrete construction. The silo has either a cone-shaped or
flat bottom, with aeration devices installed inside along
the bottom to ensure that the ash will flow freely when
the silo is unloaded. Silos may be as tall as 75 ft (23 m).
This height tends to compress the ash if well-distributed
aeration is not maintained. Heaters may be used to heat
the aeration air flow and prevent moisture.
The silo itself is elevated to provide clearance for rail
cars or disposal trucks. When the ash is loaded into a
closed transport, the silo is fitted with an unloader
consisting of a retractable chute. The central telescoping pipe directs ash down into the vehicle’s storage
tank, while the chute provides a vent path for displaced air from the tank. An exhaust fan pumps the
displaced air and dust back into the silo.
Silo unloading equipment
When flyash is to be hauled away by open trucks,
dust conditioning is added to the silo unloading equipment. Most commonly, this is simply the addition of
water during silo unloading to moisten the ash and
minimize the fine particulate that otherwise becomes
airborne. The challenge is to add and mix sufficient
Fig. 22 Top discharge transporter vessel for dense phase system.
precipitator or baghouse. This venting system must
accommodate both the conveying air flow rate and
compressed air that is pumped into the silo to aerate
the stored ash.
In a vacuum system, a primary collector transfers
the ash from the low pressure of the vacuum transport
line to the silo, which is at or slightly above atmospheric
pressure. The collector is a two chamber device installed
on the roof of the silo (Fig. 24). The upper chamber is a
centrifugal separator and storage reservoir. A gate between the upper and lower chambers opens periodically
to empty ash to the lower chamber, after the chamber
pressures have been equalized. Then, the gate is closed,
the pressure in the lower chamber is raised to that of
the silo, and a gate valve between the lower chamber
and the silo is opened. The collected ash flows into the
silo by gravity. Therefore, the upper chamber can continuously collect ash from the transport line.
An alternate primary ash collector design replaces
the centrifugal separator section shown in Fig. 24 with
a stone box inlet pipe that directs the ash downward
into the storage section of the upper chamber.
Mounted directly above the upper chamber is the
pulse-jet style bag filter that removes any fine dust
from the transport air stream as the air travels to the
vacuum source.
Air removed by the centrifugal separator of the primary collector is sent to a bag filter to remove any fine
dust. A secondary collector is sometimes installed upstream of the bag filter. The vacuum source draws air
from the bag filter, which by connection back through
24-20
Incoming Ash
from Hoppers
Holding
Bin
Fluidizing
Element
Valve
Transporter
Vessel
Compressed
Air
Pressurized Ash
Transport Line
Fig. 23 Bottom discharge transporter vessel for dense phase
system.
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
water to keep the dust down, while avoiding the potential to make cement by adding too much water to
the calcium compounds. The appropriate amount of
moisture is highly dependent on ash composition.
Dust conditioning equipment falls into two general
types: batch mixers and continuous mixers. Batch
mixers are vessels that collect a load of ash based on
weight, stir the ash with mixing paddles and wall
scrapers, and slowly add water until a well mixed batch
of moistened ash is ready for unloading. Because the
ash is weighed as it is loaded into the mixer, the moisture content can be carefully controlled to avoid problems such as cementing, dry pockets of ash, or freestanding water.
Batch mixers may not be rapid enough to support
transport schedules. Continuous mixers are smaller and
less expensive, and have capacities that allow trucks
to be filled in a matter of minutes, one after another.
When the first several truckloads of ash are unloaded from the silo, the head of ash in the silo can be
on the order of 40 to 50 ft (12 to 15 m). Simply opening a valve at the bottom of the silo would discharge
at too high of a rate to be practical for an operator to
control or condition. Continuous mixers use a motordriven rotary feeder or metering feed gate at the inlet, or an inlet design that limits the input rate.
In high capacity, rotating drum continuous
unloaders, incoming ash is aerated in the feed chute
before entering the drum. The rotating drum tumbles
the ash past a series of scrapers and a spray nozzle
manifold. This type of continuous unloader can condition up to 8000 ft3 (226 m3) of flyash per hour, but
can be more susceptible to dust bypass.
A lower cost option for continuous conditioning and
unloading is referred to as a pugmill. A metering feed
gate admits ash into the pugmill’s mixing chamber.
The mixing chamber is a U-shaped channel with two
motor driven shafts with paddles for mixing and propelling the ash from inlet to exit. Spray nozzles are
distributed within the chamber for thorough wetting.
The chamber is oriented with a slight downward slope
to assist ash movement and to drain the pugmill when
it is manually cleaned. The top cover of the pugmill is
hinged so that the entire chamber is accessible when
Air Flow to Secondary Separator
and Vacuum Producer
Incoming
Ash
from
Vacuum
Transport
Line
Centrifugal
Separator
(Internal)
Upper
Chamber
Equalizer
Valve
Gate
Valve
Lower
Chamber
Gate
Valve
Storage Silo
Roof Line
Ash to Storage Silo
Fig. 24 Primary ash collector.
out of service. For ash that has a high tendency to become cement-like, the mixing chamber can be lined
and the paddles can be constructed of a high strength,
non-stick polymer material.
HydroJet, IK-600, Precision Clean and Hydrobin are trademarks
of Diamond Power International, Inc.
Steam 41 / Boiler Cleaning and Ash Handling Systems
24-21
The Babcock & Wilcox Company
Hydrobin® dewatering storage bins.
24-22
Steam 41 / Boiler Cleaning and Ash Handling Systems
The Babcock & Wilcox Company
Chapter 25
Boiler Auxiliaries
A variety of auxiliary components are needed for
the modern steam generating system to function effectively and efficiently. While space prevents an indepth review of all items, several deserve special attention. Safety and relief valves are critical to assure
the continued safe operation of the boiler. The interplay of dampers, stack design, and fans ensures
proper air and gas flow for optimum combustion. Finally, a specialty condenser is used to supply high
purity water for attemperator spray in industrial boilers where such water is not typically available.
initial opening at the upstream static pressure set
point and for maximum discharge capacity at 3%
above set point pressure.1
Fig. 2 shows a typical power actuated type safety
valve that may be used in some Code approved applications. Power actuated valves are fully opened at the
set point pressure by a controller with a source of power
such as air, electricity, hydraulic fluid, or steam.
Fig. 3 shows a typical spring loaded relief valve for
liquid service designed for a small initial opening at
the upstream static pressure set point. The valve will
Safety and relief valves
The most critical valve on a boiler is the safety valve.
Its purpose is to limit the internal boiler pressure to a
point below its safe operating level. To accomplish this
goal, one or more safety valves must be installed in
an approved manner on the boiler pressure parts so
that they can not be isolated from the steam space.
The valves must be set to activate at approved set point
pressures (discussed below) and then close when the
pressure drops below the set point. When open, the set
of safety valves must be capable of carrying all of the
steam which the boiler is capable of generating without exceeding the specified pressure rise.
The American Society of Mechanical Engineers
(ASME) Boiler and Pressure Vessel Code, Section I,
outlines the minimum requirements for safety and
safety relief valves applying to new stationary water
tube power boilers. The Code also covers requirements
for safety and safety relief valves for other applications beyond the scope of this text. By Code definition,
a safety valve is used for gas or vapor service, a relief
valve is used primarily for liquid service, and a safety
relief valve may be suitable for use as either a safety
or a relief valve.1
Fig. 1 shows a typical Code approved spring loaded
safety valve for steam service. No other valves may
be installed between the pressure vessel and the safety
valve, nor on the discharge side of the safety valve.
The inlet nozzle opening must not be less than the area
of the valve inlet, and unnecessary pipe fittings must
not be installed. These valves are designed for large
Steam 41 / Boiler Auxiliaries
Fig. 1 Spring loaded safety valve (courtesy of Dresser Industries, Inc.).
25-1
The Babcock & Wilcox Company
modified existing boilers or new boilers installed in
parallel with old boilers, or boilers operated at an initial low pressure but designed for future high pressure (increases or decreases in operating pressure).
Additional requirements, including mounting, operation, mechanical, material, inspection and testing of
safety and safety relief valves are specified in the Code.
Code requirements for once-through boilers
For safety valve requirements on once-through
boilers, the Code allows a choice of using the rules for
a drum boiler or special rules for once-through boilers. Power operated valves may be used as Code required valves to account for up to 30% of the total required relief valve capacity. If the power relief valve
discharges to an intermediate pressure (not atmospheric), the valve does not have to be capacity certified, but it must be marked with the design capacity
at the specified relieving conditions. However, it is
important to remember that, in order for a power relief valve discharging to an intermediate pressure to
be counted as part of the required safety valve relieving capacity, the intermediate pressure zone must be
fully protected with its own relieving capacity.
The power relief valve must be in direct communication with the boiler, and its controls must be part of
the plant’s essential service network, including required pressure recording instruments. A special isoFig. 2 Typical power actuated safety valve (courtesy of Dresser
Industries, Inc.).
continue to open as pressure increases above set point
pressure to prevent additional pressure rise.
Because of variations in power boiler designs, Code
interpretations are sometimes necessary. It is also necessary to comply with local ordinances. The owner’s
approval must be obtained for all safety valve settings.
For drum boilers with superheaters, The Babcock
& Wilcox Company (B&W) follows the Code procedure
in which the safety valves are set such that the superheater valve(s) lift first at all loads. This maintains
a flow of steam through the superheater(s) to provide
a measure of overheat protection. This method permits the piping and valves downstream of the superheater to be designed for a lower pressure than other
methods. This method is required on hand controlled
units, stoker or other fuel-bed-fired units, and brick
set units. Another method may be used for all other
types of boilers that permits the drum safety valves to
lift first. This method could allow a reduced flow condition to occur in the superheater while the boiler is still
at a high heat input level. As a result, some superheater
materials can exceed temperature limits.
The required valve relieving capacities for waste
heat boiler applications are determined by the manufacturer. Auxiliary firing must be considered in the
selection of safety or safety relief valves. The Code
required relieving capacity must be based on the
maximum boiler output capabilities by waste heat
recovery, auxiliary firing, or the combination of waste
heat recovery with auxiliary firing.1
Additional Code requirements are applicable for
25-2
Fig. 3 Spring loaded pressure relief valve (courtesy of Crosby Valve
& Gage Company).
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
lating stop valve may be installed for power relief
valve maintenance provided redundant relieving capacity is installed. Provided all the Code requirements
are met or exceeded, the remaining required relief capacity is met with spring loaded valves set at 17%
above master stamping pressure. The superheater
division valves (Chapter 19) are part of the power
relief valve system so that credit may be taken for the
spring loaded superheater outlet valve(s) relieving
capacity as part of the total required relieving capacity. With a superheater division valve, the code requires
6 lb/h relieving capacity per each square foot of superheater heating surface (0.008 kg/s per m2). The
blowdown of the spring loaded valves shall not be less
than 8% nor more than 10% of set pressure. (See
Code, Section 1.)1
Air and flue gas dampers
Dampers are used to control flow and temperature
of air and flue gas. They can also be used to isolate
equipment in the air or flue gas streams when such
equipment is out of service or requires maintenance.
The Air Movement and Control Association in Publication 850-02, Application and Specification Guide
for Flue Gas Isolation and Control Dampers, defines
both the isolation and control functions for the selection of dampers.2
Isolation dampers may be the nominal shutoff or
zero leakage type. Shutoff dampers are used in applications where some limited leakage is tolerable. All
types of dampers, with appropriate blade seals, can
be used. Zero leakage dampers are designed to prevent any flow media leakage past the closed damper.
This is accomplished by overpressurizing the blade
seal periphery with seal air, which leaks back into the
system. Guillotine-type dampers are best suited for
this service. A pair of dampers or pairs of blades within
one damper with an overpressurized air block between
them can also be used. In heat recovery steam generator (HRSG) applications, diverter dampers are often used along with stack cap dampers to assist in
maintaining boiler temperature during overnight
shutdowns.
Control dampers are capable of providing a variable
restriction to flow and may be of several varieties.2
Balancing dampers are used to balance flow in two
or more ducts. Preset position dampers are normally
open or normally closed dampers which move to an
adjustable preset position on a signal. Modulating
dampers are designed to assume any position between
fully open and fully closed in response to a varied signal (either pneumatic or electric). A positioner with
feedback indication is normally required.2
Dampers may also be classified by shape or configuration. Damper shape classifications that are commonly
used in the fossil fuel-fired steam generation industry
are louver, round (or wafer) and guillotine (or slidegate).
Louver dampers
A louver damper, as shown in Fig. 4, is characterized by one or more blades that mount into bearings
Steam 41 / Boiler Auxiliaries
located in a rigid frame. They are generally rectangular in shape. One blade shaft end extends far
enough beyond the frame so that a drive can be
mounted for damper operation. Ideally, blade shape
is determined by the amount of pressure drop that can
be tolerated across the open damper. In reality, it is
usually a compromise among the following design
goals: the ideal shape required for minimizing pressure drop, the ideal shape for minimizing initial cost,
and the ideal shape to attain the required structural
strength to withstand pressure and temperature conditions. An unreinforced flat plate is the simplest shape
but is relatively weak and offers the greatest pressure
drop. Air foil shaped blades have lower pressure losses
and have somewhat greater strength. If uniform downstream flow distribution is required, opposed blade rotation is used; otherwise, parallel blade rotation may
be used. (See Fig. 5.)
If the louver damper is to be used for isolation purposes, thin, flexible metallic seal strips are mounted
on the blades to minimize leakage around the closed
blades. Seal strips are not required in applications
where louver dampers are used for flow control.
Depending on the application, louver dampers may
have internal or external bearings. External bearings
are of the self-aligning and self-lubricating ball or
sleeve type, which require a mounting block and packing gland. In extreme conditions, packing glands may
have a seal air provision. Internal bearings are machined castings with a self-cleaning feature. These
types of bearings do not require lubrication and elimiDamper
Frame
Actuator
Bearing
Shaft
Linkage
Packing Box
Airfoil
Blade
Fig. 4 Opposed-blade louver damper (adapted from Mader Damper
Co.).
25-3
The Babcock & Wilcox Company
Housing
Blade
Fig. 5 Louver damper blade arrangement options (courtesy of Air
Movement and Control Association, Inc.).
nate the need for the damper shaft to penetrate the
frame, eliminating the maintenance associated with
shaft seals.
Bar Stop Seal
Operator Mount
Round or wafer dampers
Round dampers, as shown in Fig. 6, can be used
for control or shutoff service. Due to higher allowable
velocity limits, they are usually smaller than louver
dampers and have a smaller seal edge to area ratio,
which makes them more efficient for shutoff applications. They can also be configured in a two or more
blade configuration with opposed operation for flow
control as shown in Fig. 7, although this arrangement
tends to reduce sealing efficiency.
Guillotine or slidegate dampers
Guillotine dampers have an external frame and
drive system that can insert and withdraw the blade
which acts as a blanking plate in the full cross-section of the duct. This minimizes the sealing edge required for any given duct size. The blade periphery is
surrounded by, and forced between, flexible metal
sealing strips. On zero leakage dampers, such as
Fig. 6 Wedge seat round damper (courtesy of Damper Design, Inc.).
25-4
Operator
Fig. 7 Two-bladed wafer damper.
shown in Fig. 8, the blade edge extends through the
frame into a seal chamber that is pressurized by a seal
air blower. Seals for this type of damper are normally
designed to eliminate reverse flexing. The blade is
actuated by a chain and sprocket, pneumatic cylinder, hydraulic cylinder, or screw-type mechanism, connected to a drive which is mounted on the frame.
Guillotines are typically large and used for isolation service, preferably in horizontal ducts. It is not uncommon
for blade thickness to reach 0.75 in. (19 mm), and blade
thicknesses exceeding 1 in. (25.4 mm) have been used.
Fig. 8 Guillotine damper (courtesy of Effox, Inc.).
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Expansion joints
Expansion joints are used in duct systems, windboxes, and other areas of the boiler and air quality
control system islands to allow for relative movement
between components of a system. This relative movement is usually caused by thermal expansion and contraction. Expansion joints are available in various
configurations and can feature flow liners and insulation pillows to allow for a wide range of temperature
and dust conditions. They are generally of metal construction or constructed of elastomers and composite
materials, and are designed for maximum flexibility
under the required service conditions.
The most common configuration for a metallic expansion joint is the multi-leaf or box fold joint. (See
Fig. 9.) The box fold is normally external but can be
internal if space considerations require. However, if
an internal fold is used, the additional pressure drop
caused by the flow area restriction must be accounted
for when sizing the draft equipment. Also, internal
folds could be subject to erosion damage in a dirty gas
environment. If the external fold expansion joint is
placed in a dirty environment, the folds are packed
(intermediate temperature fiberglass insulating block
is a typical packing) and the packed folds are shielded,
typically with 10 gauge sheet of the same class material as the duct. Hinged shields are often used to permit field packing of the joint folds. The extent and
location of packing and shielding are dictated by the
joint designer’s field experience. Nonmetallic joints also
require packing and shielding as dictated by the
designer’s field experience.
A metallic expansion joint can accept toggle and
axial motion but is unable to accept significant shear
motion. For that reason, whenever two components
must be connected that are displacing relative to one
another in a shear plane, two metallic expansion joints
must be employed by placing them at opposite ends
of a duct toggle section as shown in Fig. 9. A metallic
joint has a pinned support connection which defines
its toggle axis. Side pins are used to transmit gravity
loads across a joint and may pass through either round
or slotted holes. Center pins may also be used to transmit loads of pressure and to actuate another expansion joint in series.
Nonmetallic joints (Fig. 10) are able to accept shear
(three-way) motion, which is their primary advantage
over metallic joints. For this reason, nonmetallic joints
do not require a toggle section and only one joint is
required for most applications. Nonmetallic joints are
made with reinforced elastomers or Teflon coated woven fiberglass, and are normally the plain flat belt
type. Flanged or U-type joints are also available. If
design temperatures are above the use limit of the belt
material, composite belts with an insulation liner are
used and may include an insulation pillow for the
higher temperatures.
It is essential that all relative motions between components be completely accounted for when designing
Bolt and Washer
Retainer Bar
Pin
Adjustable
Flange
Slot
Breach
Opening
Adjustable
Flange
Pressure
Load
Flow
Duct 2
Toggle
Section
Duct 1
Fig. 9 Multi-leaf metallic expansion joint with pinned support connection.
Steam 41 / Boiler Auxiliaries
Fig. 10 Nonmetallic expansion joint.
25-5
The Babcock & Wilcox Company
the connecting expansion joint, and that design pressures and temperatures appropriate for the type of service be used for material and thickness selection. Failure to do so can result in premature failure of the expansion joint.
Stacks and draft
An adequate flow of air and combustion gases is
required for the complete and effective combustion of
fossil and chemical fuels. Flow is created and sustained
by stacks and fans. Either the stack alone, or a combination of stack and fans, produces the required pressure head to generate the required flow.
Draft is the difference between atmospheric pressure and the static pressure of combustion gases in a
furnace, gas passage, flue or stack. The flow of gases
through the boiler can be achieved by four methods
of creating draft, referred to as forced draft, induced
draft, balanced draft and natural draft.
Forced draft boilers operate with the air and combustion products (flue gas) maintained above atmospheric pressure. Fans at the inlet to the boiler system provide sufficient pressure to force the air and flue
gas through the system. Any openings in the boiler
settings, such as opened doors, allow air or flue gas to
escape unless the opening is also pressurized.
Induced draft boilers operate with air and gas static
pressure below atmospheric. The static pressure is
progressively lower as the gas travels from the air inlet
to the induced draft fan. The required flow through
the boiler can be achieved by the stack alone when
the system pressure loss is low or when the stack is
tall; this is called natural draft. For most modern boilers, a fan at the boiler system outlet is needed to draw
flow through the boiler. Unlike forced draft units, air
from the boiler surroundings enters through (infiltrates) any openings in the boiler setting.
Balanced draft boilers have a forced draft air fan
at the system inlet and an induced draft fan near the
system outlet. The static pressure is above atmospheric
at the forced draft fan outlet and decreases to atmospheric pressure at some point within the system (typically the lower furnace). The static pressure is subatmospheric and progressively decreases as the gas travels from the balance point to the induced draft fan.
This scheme reduces both flue gas pressure and the
tendency of hot gases to escape. There are also power
savings for this method because forced draft air fans
require smaller volumetric flow rates and therefore
less energy for a given mass flow. Most modern boilers are balanced draft for these reasons.
Draft loss is the reduction in static pressure of a gas
caused by friction and other nonrecoverable pressure
losses associated with the gas flow under real conditions. As discussed in Chapter 3, static pressure is related to the total pressure at a location by the addition of the velocity or dynamic pressure.
Ptotal = Ps + Pv = Ps +
25-6
V2
2 g cv
(1)
where
Ptotal
Ps
Pv
V
v
gc
=
=
=
=
=
=
=
total pressure, lb/ft2 (N/m2 )
static pressure, lb/ft2 (N/m2 )
velocity pressure, lb/ft2 (N/m2 ) = V 2/2gcv
average gas velocity
specific volume of the gas
conversion constant
32.17 lbm ft/lbf s2 = 1 kgm/Ns2
Stack effect
Stack effect (SE), or chimney action, is the difference in pressure caused by the difference in elevation
between two locations in vertical ducts or passages
conveying heated gases at zero gas flow. It is caused
by the difference in density between air and heated
gases, whether air or flue gas. The stack effect is independent of gas flow and can not be measured with
draft gauges. Draft gauges combine stack effect and
flow losses. The intensity and distribution of this pressure difference depends on the height, the arrangement of ducts, and the average gas temperature in the
duct and ambient air temperature.
Based upon this definition, the overall stack effect
in its most general form is defined as:
∆PSE =
1
g
g
1
Z
Z ( ρa − ρ g ) =
−
gc va vg
gc
(2)
where
∆PSE = stack draft effect driving pressure, lb/ft2 (N/
m2)
g
= acceleration of gravity = 32.17 ft/s2 (9.8 m/
s2)
= 32.17 lbm ft/lbf s2 (1 kgm/Ns2 )
gc
Z
= elevation between points 1 and 2, ft (m)
ρa
= density of air at ambient conditions, lb/ft3
(kg/m3)
ρg
= average density of flue gas, lb/ft3 (kg/m3)
va
= specific volume of air at ambient conditions,
ft3/lb (m3/kg)
vg
= average specific volume of flue gas, ft3/lb
(m3/kg)
The customary English units used for draft calculations are inches of water for draft pressure loss and
feet for stack height or elevation. Using this system of
units, the incremental stack effect (inches of pressure
loss per foot of stack height) can be evaluated from:
1
1 1
SE =
−
va vg 5.2
(3)
where
SE = stack effect, in./ft
For convenience, Table 1 provides the specific volume of air and flue gas at one atmosphere and 1000R
(556K). Assuming air and flue gas can be treated as
ideal gases, the ideal gas law in Chapter 3 permits
calculation of the specific volume at other conditions:
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
ture. There is also some infiltration of cold air. The total
loss in temperature in a stack depends upon the type
of stack, stack diameter, stack height, gas velocity, and
a number of variables influencing the outside stack
surface temperature. Fig. 11 indicates an approximate
stack exit temperature relative to height, diameter,
and inlet gas temperature.
Table 1
Sample Specific Volumes at 1000R (556K)
and One Atmosphere
Gas
vb
(ft3/lb)
vb
(m3/kg)
25.2
1.57
25.4
24.3
24.7
25.7
1.58
1.5
1.54
1.60
Dry air
Combustion air (0.013 lb
water/lb dry air)
Flue gas (3% water by wt)
Flue gas (5% water by wt)
Flue gas (10% water by wt)
T
v = vR f
TR
BR
B
Sample stack effect calculation
(4)
where
v = specific volume at Tf and B, ft3/lb (m3/kg)
vR = specific volume at TR and BR, ft3/lb (m3/kg)
T f = average fluid temperature, R (K)
= Tf (F) + 460 (Tf (C) + 256)
B = barometric pressure (see Table 2), in. Hg
(kPa)
TR = 1000R (556K)
BR = 30 in. Hg (101.6 kPa)
Fig. 12 illustrates the procedure used in calculating stack effect. The stack effect can either assist or
resist the gas flow through the unit. The three gas
passages are at different temperatures and the example is at sea level. For illustrative purposes, assume
atmospheric pressure, i.e., (draft = 0) at point D.
Stack effect always assists up-flowing gas and resists
down-flowing gas. Plus signs are assigned to up flows
and minus signs to down flows. Using values from Table
3 for an ambient air temperature of 80F (27C), the stack
effect in inches of water for each passage is:
Stack effect C to D = + (110 × 0.0030) = +0.33 in. H2O
Stack effect B to C = − (100 × 0.0087) = −0.87 in. H2O
Stack effect A to B = + (50 × 0.0100) = +0.50 in. H2O
Table 3 provides a reference set of values for SE at
one atmosphere. The total theoretical draft effect of a
stack or duct at a given elevation above sea level can
be calculated from Equation 1 or from:
B
Stack draft = Z ( SE ) elevation
Bsea level
(5)
where
Z
SE
Belevation
Bsea level
=
=
=
=
stack height, ft (m)
stack effect, in./ft (Table 3 or Equation 2)
barometric pressure at elevation (Table 2)
barometric pressure at sea level (Table 2)
The average gas temperature in these calculations
is assumed to be the arithmetic average temperature
entering and leaving the stack or duct section. For
gases flowing through an actual stack, there is some
heat loss to the ambient air through the stack strucTable 2
Barometric Pressure, B
Ft Above
Sea Level
0
1000
2000
3000
4000
5000
Pressure
in. Hg
kPa
29.92
28.86
27.82
26.82
25.84
24.90
760
733
707
681
656
632
Effect of Altitude
Ft Above
Sea Level
6000
7000
8000
9000
10,000
15,000
Pressure
in. Hg
kPa
23.98
23.09
22.22
21.39
20.58
16.89
609
586
564
543
523
429
Values from Publication 99, Air Moving and Conditioning
Association, Inc., 1967.
Steam 41 / Boiler Auxiliaries
Fig. 11 Approximate relationship between stack exit gas temperature and stack dimensions.
25-7
The Babcock & Wilcox Company
Table 3
Reference Set of Stack Effect (SE) Values
in. of H2O/ft of Stack Height English Units Only
Reference Conditions:
Air 0.013 lb H2O/lb dry air: 13.7 ft3/lb, 80F, 30 in. Hg
Gas 0.04 lb H2O/lb dry gas: 13.23 ft3/lb, 80F, 30 in. Hg
Barometric pressure 30 in. Hg
Avg. Temp in
Flue or Stack, Tg
Ambient Air Temperature, Ta, F
F
40
60
80
100
250
500
1000
1500
2000
2500
0.0041
0.0070
0.0098
0.0112
0.0120
0.0125
0.0035
0.0064
0.0092
0.0106
0.0114
0.0119
0.0030
0.0059
0.0087
0.0100
0.0108
0.0114
0.0025
0.0054
0.0082
0.0095
0.0103
0.0109
If draft gauges are placed with one end open to the
atmosphere at locations A, B, C and D of Fig. 12, the
theoretical zero flow draft readings are:
Draft at D =
Draft at C =
=
Draft at B =
=
Draft at A =
=
0 in. H2O
draft at D minus stack effect C to D
0 − ( + 0.33) = − 0.33 in. H2O
draft at C minus stack effect B to C
− 0.33 − ( − 0.86) = + 0.53 in. H2O
draft at B minus stack effect A to B
+ 0.53 − ( + 0.50) = + 0.03 in. H2O
Note that because the calculation of stack effect in
this example is opposite to the gas flow, stack effects
are subtracted in calculating static pressures or drafts.
If the stack effect is in the direction of gas flow, stack
effects should be added.
The net stack effect from A to D in Fig. 12 is the sum
of all three stack effects and is −0.03 in. For this reason, fans or stack height must be selected not only to
provide the necessary draft to overcome flow loss
through the unit, but also to allow for the net stack
effect of the system.
In some boiler settings, gases leak from the upper
portions when the unit is operating at very low loads
or when it is taken out of service. The leakage can
occur even though the outlet flue may show a substantial negative draft. The preceding example illustrates this type of low to no flow condition with a suction or negative pressure at the bottom of the uptake
flue C-D and positive pressures at both points A and
B in Fig. 12.
combination of only an induced draft fan and stack is
not commonly used.
The required height and diameter of stacks for
natural draft units depend upon:
1. draft loss through the boiler from the point of balanced draft to the stack entrance,
2. average temperature of the gases passing up the
stack and the temperature of the surrounding air,
3. required gas flow from the stack, and
4. barometric pressure.
No single formula satisfactorily covers all of the
factors involved in determining stack height and diameter. The most important points to consider are: 1)
temperature of the surrounding atmosphere and temperature of the gases entering the stack, 2) drop in
temperature of the gases within the stack because of
heat loss to the atmosphere and air infiltration, and
3) stack draft losses associated with gas flow rate (due
to fluid friction within the stack and the kinetic energy of gases leaving the stack).
Stack flow loss
The net stack draft, or available induced draft at
the stack entrance, is the difference between the theoretical draft calculated by Equations 2, 3 and 4 and
the pressure loss due to gas flow through the stack.
From Equation 46 in Chapter 3 for friction loss, plus
one velocity head exit loss (G2υ /2gc):
∆Pl = f
G2
L G2
v
v +
D 2 gc
2 gc
(6)
Chimney or stack
Early boilers operated with natural draft caused by
the stack effect alone. However, for large units
equipped with superheaters, economizers and especially air heaters, it is not practical or economical to
operate the entire unit from stack induced draft alone.
These units require fans to supplement the stack induced draft. The entire unit might be pressurized by
a forced draft fan or the unit might use both induced
and forced draft fans for balanced draft operation. The
25-8
Fig. 12 Diagram illustrating stack effect, or chimney action, in three
vertical gas passes arranged in series.
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
where
∆Pl = stack flow loss, lb/ft2 (N/m2)
f
= friction factor, dimensionless (Chapter 3, Fig.
1: ≈ 0.014 to 0.017)
L = length of stack = Z, ft (m)
D = stack diameter, ft (m)
G = mass flux = m /A, = lb/h ft2 (kg/m2 s)
m = mass flow rate, lb/h (kg/s)
A = stack cross-sectional area, ft2 (m2)
v = specific volume at average temperature, ft3/
lb (m3/kg)
g c = 32.17 lbm ft/lbf s2 (1 kgm/Ns2)
For English units this reduces to:
Stack flow loss =
2
∆Pl =
fL
2.76 Tg m
+ 1
4
5
B Di 10 Di
(7)
where
∆Pl =
m
=
B =
Tg =
Di =
f
=
L
stack flow loss, in. of water
mass flow rate, lb/h
barometric pressure, in. Hg
average absolute gas temperature, R
internal stack diameter, ft
friction factor from Chapter 3, Fig. 1, dimensionless
= stack height above gas entrance, ft
The equation user is reminded that there is a gasflue-to-stack-entrance exit loss that is not included in
the above equation, which must be accounted for when
determining overall system pressure losses.
Stack flow losses for natural draft units are typically less than 5% of the theoretical stack draft. Also,
that part of the loss due to unrecoverable kinetic energy of flow (exit loss) is from three to seven times
greater than the friction loss, depending on stack
height and diameter.
Sample stack size selection
Tentative stack diameter and height for a given
draft requirement can be calculated using English
units with Figs. 11, 13 and 14 and an assumed stack
exit gas temperature. Adjustments to these values are
then made as required, by verification of the assumed
stack exit temperature, a flow loss check and altitude
correction, if necessary. The following example illustrates this sizing procedure:
Unit Specifications:
Fuel
Steam generated, lb/h
Stack gas flow, lb/h
Stack inlet gas temp., F
Required stack draft (from
point of balanced draft to
stack gas entrance), in. H2O
Plant altitude
1.0
Sea level
Initial Assumption:
Stack exit gas temperature, F
450
Steam 41 / Boiler Auxiliaries
Pulverized coal
360,000
450,000
550
Fig. 13 Stack height required for a range of stack drafts and
average stack gas temperatures.
If the stack gas flow is not specified, the following
approximate ratios may be used:
Type of Firing
Oil or gas
Pulverized coal
Stoker
Gas Weight/Steam Flow Ratio
1.15
1.25
1.50
The stack diameter to the nearest 6 in. increment
from Fig. 14 for 450,000 lb/h stack gas flow is 14 ft 6
in. For the required stack draft of 1.0 in. (increased to
1.1 in. for safety) and an average stack gas temperature of 500F, based on the specified inlet temperature
of 550F and assumed exit temperature of 450F, Fig.
13 gives an approximate height of 187 ft. A check of
the assumed stack exit temperature is obtained from
Fig. 11, with the tentative height of 187 ft, diameter
of 14 ft 6 in. and inlet temperature of 550F. This result is 430F, or an average stack temperature of 490F
and draft of 1.1 in. H2O. Fig. 13 is again used to establish a stack height neglecting stack flow losses. This
height is 190 ft.
Assuming a stack flow loss of 5%, the final required
stack height is 200 ft (190/0.95). This represents the
active height of the stack. The height of any inactive
section from foundation to stack entrance must also
be included.
The stack flow loss is checked using the above values for diameter, height, average gas temperature and
gas flow in Equation 6. A check of available net draft,
using Equation 2, indicates that the 1.0 in. draft requirement is amply covered.
If the plant is not located at sea level, the draft re-
25-9
The Babcock & Wilcox Company
gas temperature and the stack effect. Leaks also increase the gas flow and erosion potential in the stack.
A stack is subjected to the erosive action of particulate, acid corrosion from sulfur products, and weathering. Erosion is most common at the stack entrance,
throats, necked down (reduced diameter) sections, and
locations where the direction or velocity of gas changes.
Abrasion resistant materials or erosion shields at these
locations can reduce stack maintenance.
Fans
A fan moves a quantity of air or gas by adding sufficient energy to the stream to initiate motion and
overcome resistance to flow. The fan consists of a
bladed rotor, or impeller, which does the actual work,
and usually a housing to collect and direct the air or
gas discharged by the impeller. The power required
depends upon the volume of air or gas moved per unit
of time, the pressure difference across the fan, and the
efficiency of the fan and its drives.
Power
Fig. 14 Recommended stack diameter for a range of gas flows.
quirement of the unit must be increased by multiplying the draft by the altitude factor 30/B and the theoretical stack draft decreased by multiplying the theoretical draft by B/30, where B is the normal barometric
pressure, inches of mercury, at the boiler site (Table 2).
External factors affecting stack height
The stack also functions to disperse combustion
gases. Increasing stack height enlarges the area of
dispersion. In narrow valleys or locations where there
is a concentration of industry, it may be necessary to
provide increased stack height.
Some power plants located near airports are prohibited from using stacks high enough to provide adequate dispersion. In such cases, the stack may be
reduced in diameter at the top to increase the discharge velocity, simulating the effect of a higher stack.
However, necking down the stack adds an appreciable
amount of flow resistance which can only be accommodated by a mechanical draft system.
Stack design
After the correct stack height and diameter are established, there are economic and structural factors
to consider in designing the stack. Stack material selection is influenced by material and erection costs,
stack height, means of support (i.e., whether the stack
is supported from a steel structure or a foundation),
and erosive and corrosive constituents in the flue gas.
After selecting the material, the stack is checked for
structural adequacy, making both a static and a dynamic analysis of the loads.
Stack operation and maintenance
All connections to the stack should be air tight and
sealed with dampers when not in use. Cold air leaks
into the stack during operation, reducing the average
25-10
Power may be expressed as shaft horsepower, input horsepower to motor terminals if motor driven, or
theoretical horsepower which is computed by thermodynamic methods.
Fan power consumption can be expressed as:
Power = k
∆ P V
ηf C
(8)
where
Power = shaft power input, hp (kW)
∆P
= pressure rise across fan, in. wg (kPa)
=
inlet volume flow rate, ft3/min (m3/s)
V
ηf
= fan mechanical efficiency, 100% = 100
k
= compressibility factor, dimensionless
(see equation 9 below and Table 4)
C
= constant of 6354 (1.00 for SI)
The compressibility factor k is calculated using the
following formula:
γ −1
γ P2 γ
− 1
γ − 1 P1
k =
P2
−1
P1
(9)
where
γ = specific heat ratio (1.4 for air)
P1 = absolute inlet pressure (any unit)
P2 = absolute outlet pressure
(any unit, P2 = P1 + PT)
An approximate value for k can be calculated by using:
kapprox = 1 −
PT
CEST
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
where
Table 4
PT
= fan total pressure, in. wg
CEST = 1150 for PT < 10 in. wg
1200 for PT < 40 in. wg
1250 for PT < 70 in. wg
Mechanical Efficiency
All fluids and especially gases are compressible. The
effects of compressibility are accounted for in the fan
laws by including a compressibility coefficient.
Approximate ranges of fan efficiencies and compressibility factors for use in Equation 8 are provided
in Table 4. The term fan efficiency can be misleading
because there are a number of ways it can be defined.
Fan efficiency can be calculated across the fan rotor
only, across the fan housing (inlet to outlet) with no
allowance for efficiency losses caused by inlet or outlet duct configuration, or across the housing with losses
induced by inlet and outlet ducting included. The fan
vendor can usually recommend the best duct arrangement at the fan inlet and outlet to minimize these
losses. To select the proper fan motor, shaft input
power must be calculated using the efficiency that
accounts for all of the losses associated with the fan
type, including losses caused by inlet and outlet duct
arrangement.
In order to use the above formula, the volume flow
must be known. Since the engineer often calculates
boiler air and flue gas flows in mass units (lb/h, kg/s,
etc.) by using the various heat and material balances
published in performance test codes or other standards, it is advantageous to have a quick conversion
method for calculating volume flow (cfm, m3/s). The
conversion formula for arriving at volume flow when
mass flow is known is:
T
× ρ ref × a
V ( cfm ) = m
Tref
Pref
×
×F
Pa
(10)
where
3
3
V = volumetric flow rate, cfm or ft /min (m /s)
= gas flow, lb/h (kg/s)
m
ρ ref = gas density at reference temperature, lb/ft3
(kg/m3)
T a = actual temperature, R (K)
T ref = reference temperature, R (K)
Pref = reference pressure, psi (Pa)
Pa = actual pressure, psi (Pa)
F = time unit correction factor
= 1/60 English Units (1.00 for SI)
Another method used to calculate power consumption involves the concept of adiabatic head. If total
pressure rise is known, adiabatic head can be calculated using the following formula:
Hd =
( k ) ( ∆ P ) (C )
ρ
(11)
where
Hd = developed adiabatic head of gas column, ft (m)
k = compressibility factor
Steam 41 / Boiler Auxiliaries
Approximate Ranges ( f )
Centrifugal fan
Paddle blade
Foward curved blade
Backward curved blades
Radial tipped blades
Air foil
Axial flow fan
45 to 60%
45 to 60%
75 to 85%
60 to 70%
80 to 90%
85 to 90%
Approximate compressibility factors (air)
∆P/P
0
0.03
0.06
0.09
0.12
0.15
0.18
k
1
0.99
0.98
0.97
0.96
0.95
0.94
∆P = total pressure increase, in. wg (kPa)
ρ = actual density, lb/ft3 (kg/m3)
C = constant of 5.20 (1.00 for SI)
Using the adiabatic head concept as defined by Equation 11, fan shaft input power can be calculated as:
Power =
(m ) ( H d ) (C )
ηf
(12)
where
= gas flow, lb/h (kg/h)
m
C = constant of 0.505 × 10−6 (2.724 × 10−6 for SI)
Fan performance
Stacks seldom provide sufficient natural draft to
cover the requirements of modern boiler units. These
higher draft loss systems require the use of mechanical draft equipment, and a wide variety of fan designs
and types is available to meet this need.
Fan performance is best expressed in graphic form as
fan curves (Fig. 15) which provide static pressure (head),
shaft horsepower and static efficiency as functions of
capacity or volumetric flow rate. Because fan operation for a given capacity must match single values of
head and horsepower on the characteristic curves, a
balance between fan static pressure and system resistance is required.
Varying the operating speed (rpm) to yield a family of curves, as shown in Fig.16, will change the numerical performance values of the curve characteristics. However, the shape of the curves remains substantially unaltered. Changes in operation of fans can generally be predicted from the Laws of Fan Performance:
1. Fan speed variation (for constant fan size, density and system resistance)
a) Capacity [ft3/min (m3/min)] varies directly with
speed.
b) Pressure varies as the square of the speed.
c) Power varies as the cube of the speed.
2. Fan size variation (geometrically similar fans, constant pressure, density and rating)
a) Capacity varies as the square of wheel diameter.
b) Power varies as the square of wheel diameter.
c) Rpm varies inversely as wheel diameter.
25-11
The Babcock & Wilcox Company
should be taken into account when designing flues, ducts,
expansion joints, dampers, and other components.
In summary, as temperature decreases, density increases, and pressure rise of the fan increases. As an
example:
Temperature
Density
(lb/ft3)
300F
250F
100F
0.0504
0.0538
0.0684
Static pressure rise
(in. wg)
30.0
32.1
40.8
Geometrically similar fans have similar operating
characteristics. Therefore, the performance of one fan
can be predicted by knowing how a smaller or larger
fan operates. The two main performance factors (speed
and head) are linked in the concept of specific speed
and specific diameter.
Specific speed is the rpm at which a fan would operate if reduced proportionately in size so that it delivers 1 ft3/min of air at standard conditions, against
a 1 in. wg static pressure.
Fig. 15 Characteristic curves for two types of centrifugal fans
operating at 5500 ft (1676 m) elevation and 965 rpm.
3. Gas density variation (constant size and speed
plus constant system resistance or point of rating).
a) Capacity remains constant.
b) Pressure varies directly as gas density.
c) Power varies directly as gas density.
Operating a fan at a temperature below design temperature will cause the shaft horsepower requirement
to increase as a function of density ratio or absolute temperature ratio. In addition, if a different gas of a higher
density is handled, the shaft horsepower will increase
with the ratio of the densities. Because such operating
conditions typically occur at startup, the inlet vanes or
inlet louvers should be closed before the fan is started up.
The pressure increase of the fan also will rise as a
function of the higher gas densities. This condition
25-12
Fig. 16 Graph showing how desired output and static pressure can
be obtained economically by varying fan speed to avoid large
throttling losses.
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Specific diameter is fan diameter required to deliver
1 ft3/min standard air against a 1 in. wg static pressure at a given specific speed. The fan laws lead to
these equations:
Specific speed ( N ) =
(
rpm ft3 /min
(SP )
3
4
)
1
2
(13)
Typical fan applications
1
Specific diameter ( D ) =
D ( SP ) 4
( ft /min )
3
The fan manufacturer can review the proposed
ductwork layout and offer suggestions to minimize
these effects. Of particular importance are effects
caused by improper design of the transition duct from
fan outlet(s) to final duct cross-section downstream of
fan outlet. The ideal evase shape for low pressure drop
may not be attainable in the space available.
1
2
(14)
where flow in ft3/min is at standard conditions, SP is
static pressure (in. wg) and D is fan diameter (in.).
Because there is only one value of specific speed at
the point of maximum efficiency for any fan design,
that value serves to identify the particular design. The
same is true for specific size. If either specific speed or
specific size can be established from the requirements
of an application, only those designs with corresponding identifying values need to be considered.
Fan capacity margins
To make sure that the fans will not limit boiler performance, margins of safety are added to the calculated or net fan requirements to arrive at a satisfactory test block specification. These margins are intended to cover conditions encountered in operation
that can not be specifically evaluated. For example,
variation in fuel ash characteristics or unusual operating conditions slag or foul heating surfaces. The unit
then requires additional draft. Air heater leakage can
increase to higher than expected levels because of
incorrect seal adjustment or seal wear. Stoker-fired
boilers, burning improperly sized coal, may require
more than normal pressure to force air through the
fuel bed. A need for rapid load increase or a short
emergency overload often calls for overcapacity of the
fans. The customary margins to allow for such conditions include: 1) 15 to 20% increase in the net weight
flow of air or gas, 2) 20 to 30% increase in the net
head, and 3) 25F (14C) increase in the air or gas temperature at the fan inlet.
Forced draft fan
Boilers operating with both forced and induced
draft use the forced draft fan to push air through the
combustion air supply system into the furnace. (See
Fig. 17.) The fan must have a discharge pressure high
enough to equal the total resistance of air ducts, air
heater, burners or fuel bed, and any other resistance
between the fan discharge and the furnace. This
makes the furnace the point of balanced draft or zero
pressure. Volume output of the forced draft fan must
equal the total quantity of air required for combustion plus air heater leakage. In many installations,
greater reliability is obtained by dividing the total fan
capacity between two fans operating in parallel. If one
fan is out of service, the other usually can carry 60%
or more of full boiler load, depending on how the fans
are sized.
To establish the required characteristics of the
forced draft fan, the system resistance from fan to
furnace is calculated for the actual weight of air required for combustion plus the expected leakage from
System effects and fan margin
System effects is a label given to adverse conditions
at the fan inlet and outlet that can cause increased
static pressure losses. These conditions may not have
been foreseen by the fan purchaser or the fan supplier. It is important to account for all system effects
and to ensure that they are included in the fan’s net
static pressure requirements. If system effects are not
fully considered, fan margins will be less than anticipated. System effects may include:
1. elbows located close to fan discharge,
2. insufficient duct length at the fan discharge,
3. improper inlet conditions, e.g. elbow located too
close to the fan inlet, or
4. elbows without turning vanes or splitters.
Steam 41 / Boiler Auxiliaries
Fig. 17 Forced draft centrifugal fan for a 364 MW outdoor unit.
25-13
The Babcock & Wilcox Company
the air side of the air heater. It is design practice to base
all calculations on 80F (27C) air temperature entering
the fan. The results are then adjusted to test block specifications by the margin factors previously discussed.
Forced draft fan selection should consider the following general requirements:
Reliability Boilers must operate continuously for
long periods (up to 18 months in some instances) without shutdown for repairs or maintenance. Therefore,
the fan must have a rugged rotor and housing and
conservatively loaded bearings. The fan must also be
well balanced and the blades shaped so that they will
not collect dirt and disturb this balance.
Efficiency High efficiency over a wide range of output is necessary because boilers operate under varying load conditions.
Stability Fan pressure should vary uniformly with
volumetric flow rate over the capacity range. This
facilitates boiler control and assures minimum disturbance of air flow when minor adjustments to the fuel
burning equipment change the system resistance.
When two or more fans operate in parallel, the pressure output curves should have characteristics similar to the radial tip or backward curved blade fans in
order to share the load equally near the shutoff point.
Overloading It is desirable for motor driven fans to
have self-limiting horsepower characteristics, so that
the driving motor can not overload. This means that
the horsepower should reach a peak and then drop
off near the full load fan output (Fig. 16).
Induced draft fan
Units designed to operate with balanced furnace
draft or without a forced draft fan require induced
draft to move the gaseous products of combustion.
The gas weight used to calculate net induced draft
requirements is the weight of combustion product gas
at maximum boiler load, plus any air leakage into the
boiler setting from the surroundings and from the air
side to the gas side of the air heater. Net gas temperatures are based on the calculated unit performance at
maximum load. Induced draft fan test block specifications of gas weight, negative static pressure and gas
temperature are obtained by adjusting from net values
by margins similar to those used for forced draft fans.
An induced draft fan has the same basic requirements
as a forced draft fan except that it handles higher temperature gas which may contain erosive ash. Excessive
maintenance from erosion can be avoided by protecting
casing and blades with replaceable wear strips. Because
of their lower resistance to erosion, air foil blades should
be treated with caution when considering an induced
draft application. Air foil blades are very susceptible to
dust erosion and, if hollow, they can fill with dust and
cause rotor imbalance should the blade surface wear
through. Bearings, usually water-cooled, have radiation
shields on the shaft between the rotor and bearings to
avoid overheating.
Gas recirculation fans
As discussed in Chapter 19, gas recirculation fans
are used in various boiler arrangements for controlling steam temperature, furnace heat absorption,
25-14
slagging of heating surfaces, and control of NOx emissions in oil- or gas-fired burners. They are generally
located at the economizer outlet to extract gas and inject it into the furnace at locations dependent on the
intended function. These multiple purposes are also
an important consideration in properly sizing and
specifying gas recirculation fans. Selection may be
dictated by the high static pressure required for tempering furnace temperatures at full load on the boiler
unit, or by the high volume requirement at partial
loads for steam temperature control.
Even though gas recirculation fans have the same
basic requirements as induced draft fans, there are additional factors to consider, such as being subjected to
large amounts of abrasive ash. The gas recirculation
fan typically operates at higher gas temperatures, so intermittent service may cause thermal shock or unbalance. When the fan is not in service, tight shutoff dampers and sealing air must be provided to prevent the back
flow of hot furnace gas, and a turning gear is often used
on large fans to turn the rotor slowly to avoid distortion.
Primary air fans
Primary air fans on pulverized coal-fired boilers
supply pulverizers with the air needed to dry the coal
and transport it to the boiler. Cold primary air fans
should be designed for duty similar to forced draft
fans. Primary air fans may be located before the air
heater (cold primary air system) or downstream of the
air heater (hot primary air system). The cold primary
air system has the advantage of working with a
smaller volumetric flow rate for a given mass flow rate.
This method will pressurize the air side of the air
heater and encourage leakage to the gas side. The hot
primary air system avoids primary air heater leakage,
but requires a higher fan design temperature and
larger volumetric flow rate.
Fan maintenance
Fans require frequent inspection to detect and correct irregularities that might cause problems. However, they should also have long periods of continuous operation compared with other power plant equipment. This can be assured by proper lubrication and
cooling of fan shafts, couplings and bearings.
A fan should be properly balanced, both statically
and dynamically, to assure smooth and long-term service. This balance should be checked after each maintenance shutdown by running the fan at full speed,
first with no air flow and second with full air flow.
Fans handling gases with entrained abrasive dust
particles are subject to erosion. Abrasion resistant
materials and liners can be used to reduce such wear.
In some cases, beads of weld metal are applied to build
up eroded surfaces.
Fan testing
It is difficult to obtain consistent data from a field
test of fans installed in flue and duct systems because
it is seldom possible to eliminate flow disturbances
from such things as bends, change in flow area, and
dampers. Structural arrangements at the fan entrance
and discharge also materially affect field performance
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
results. The consistent way to verify fan performance
is on a test stand. (See Fig. 18.)
Fan types
There are essentially two different kinds of fans:
centrifugal and axial flow. In a centrifugal fan, the
air or gas enters the impeller axially and is changed
by the impeller blades to flow radially at the impeller’s
discharge. The impeller is typically contained in a volute-type housing. In an axial flow fan, the air or gas
is accelerated parallel to the fan axis.
Centrifugal fans
Centrifugal fans can utilize several types of impellers: airfoil, backward inclined, radial tipped, and forward curved. Fans with forward curved impellers are
typically used for low-capacity applications and are seldom found in industrial applications. Characteristic
traits of centrifugal fan impellers are:
Airfoil This impeller is capable of attaining the highest efficiency. It has the highest specific speed (it must
run faster to develop a given pressure at a given diameter). Sound levels tend to be lower than the other
types. It is not satisfactory for high dust loads; the
blades can not easily be made wear resistant and it is
prone to dust buildup on the backs of blades. The hollow blades have potential for water and dust ingress.
Tip speed limits increase with reduced tip width.
Backward inclined
Curved backward inclined (CBI) offers high effi-
ciency (although not as high as airfoil impellers). This
design is satisfactory for dust loads and can accept
removable wear plates. This design is prone to buildup
on the backs of blades. It is economical to manufacture and sound levels are marginally lower than airfoil impellers. Specific speed is high.
Flat backward inclined is excellent for high dust
loads and can easily accept removable wear plates.
Efficiency is lower than for a curved backward design.
It is economical to manufacture, has a high specific
speed, and is prone to dust buildup on the backs of blades.
Radial tipped This design is excellent for dust loading, can accommodate removable wear plates satisfactorily, and has very few dust buildup problems. However, it has the lowest efficiency of the four types. This
impeller has tip speed limitations and therefore is not
suitable for very high pressure rise applications.
A further summary of these impeller types is given
in Table 5.
3. least expensive type of fan drive; a constant speed
induction type AC motor may be used, and
4. continuous rather than a step-type control making this method effective throughout the entire fan
operating range.
The primary disadvantage of damper control is
wasted power. Excess pressure energy must be dissipated by throttling. Outlet damper control (usually
with opposed blade type dampers) is inefficient and is
not often used. Inlet box damper control with parallel
blades pre-spins the entering air or gas in the same
direction as impeller rotation, making this method
more efficient than outlet damper control.
The most economical control is accomplished with
variable inlet vanes (VIVs), designed for use with both
dirty air and clean air. These vanes change position
with flow and produce a more efficient pre-spin than
inlet dampers. VIVs are the most common type of flow
control for constant speed fans. The relative location
and types of flow control devices are shown in Fig. 19.
Operating experience on forced draft, primary air
and induced draft fans has proven that inlet vane
control is reliable and reduces operating cost. It also
controls stability, controls accuracy, and minimizes
hysteresis. Inlet vane control (Fig. 20) regulates air
flow entering the fan and requires less horsepower
than outlet damper control at fractional loads. The
inlet vanes give the air a varying degree of spin in
the direction of wheel rotation, enabling the fan to produce the required head at proportionally lower power.
Although vane control offers considerable savings in
efficiency at any reduced load, it is most effective for
moderate changes close to full load operation. The
initial cost is greater than damper control and less
than variable speed control.
Control of centrifugal fan output
Very few applications permit fans to always operate
at the same pressure and volume discharge rate. Therefore, to meet requirements of the system, some means of
varying the fan output are required such as damper
control, inlet vane control, and variable speed control.
Damper control introduces sufficient variable resistance in the system to alter the fan output as required.
The advantages are:
1. lowest initial capital cost of all control types,
2. ease of operation or adaptation to automatic control,
Steam 41 / Boiler Auxiliaries
Fig. 18 Full-scale testing of variable-pitch axial flow fan.
25-15
Utilizes the same housing
configuration as the airfoil
design.
Scroll-type, usually the
narrowest design of all
centrifugal fan designs
described here because of
required high velocity
discharge. Dimensional
requirements of this
housing are more critical
than for airfoil and
backward-inclined blades.
Scroll is similar to other
centrifugal fan designs. The
fit between the wheel and
inlet is not as critical as on
airfoil and backwardinclined bladed fans. Uses
large cut-off sheet in
housing.
Efficiency is only slightly less
than that of airfoil fans.
Backward-inclined or
backward-curved blades are
single thickness. 9 to 16 blades
curved or inclined away from
the direction of rotation.
Efficient for the same reasons
given for the airfoil fan above.
Simplest of all centrifugal fans
and least efficient. Has high
mechanical strength and the
wheel is easily repaired. For a
given point of rating, this fan
requires medium speed. This
classification includes radial
blades and modified radial
blades, usually 6 to 10 in
number.
Efficiency is less than airfoil
and backward-curved bladed
fans. Usually fabricated of
lightweight and low cost
construction. Has 24 to 64
shallow blades with both the
heel and tip curved forward. Air
leaves wheel at velocity greater
than wheel. Tip speed and
primary energy transferred to
the air is by use of high velocity
in the wheel. For given duty,
wheel is the smallest of all
centrifugal types and operates
at lowest speed.
Housing Design
Highest efficiency of all
centrifugal fan designs. 9 to 16
blades of airfoil contour curved
away from the direction of
rotation. Air leaves the
impeller at a velocity less than
its tip speed and relatively
deep blades provide for
efficient expansion within the
blade passages. For given duty,
this will be the highest speed of
the centrifugal fan designs.
Impeller Design
Scroll-type, usually designed
to permit efficient conversion
of velocity pressure to static
pressure, thus permitting a
high static efficiency;
essential that clearance and
alignment between wheel
and inlet bell be very close
to reach the maximum
efficiency capability.
Concentric housings can also
be used as in power roof
ventilators, because there is
efficient pressure conversion
in the wheel.
Type
Table 5
Backward-Inclined
Backward-Curved
Radial
Airfoil
Forward-Curved
0
2
4
6
8
10
0
2
4
6
8
10
0
2
4
6
8
10
0
2
4
6
8
10
0
0
0
0
HP
HP
HP
SP
HP
2
4
6
8
Volume Flow Rate
ME
SP
2
4
6
8
Volume Flow Rate
ME
2
4
6
8
Volume Flow Rate
ME
SP
2
4
6
8
Volume Flow Rate
ME
SP
10
8
6
4
2
0
10
10
8
6
4
2
0
10
10
8
6
4
2
0
10
10
8
6
4
2
0
10
Performance Curves
Pressure - HP
Pressure - HP
Pressure - HP
Pressure - HP
Efficiency
Efficiency
Efficiency
25-16
Efficiency
Centrifugal Fans3
Used primarily in lowpressure heating,
ventilating, and airconditioning applications
such as domestic
furnaces, central station
units, and packaged airconditioning equipment
from room airconditioning units to roof
top units.
Higher pressure
characteristics than the
above mentioned fans.
Power rises continually to
free delivery.
Pressure curve is less steep
than that of backwardcurved bladed fans. There is
a dip in the pressure curve
left of the peak pressure
point and highest efficiency
occurs to the right of peak
pressure, 40 to 50% of wide
open volume. Fan should be
rated to the right of peak
pressure. Power curve rises
continually toward free
delivery and this must be
taken into account when
motor is selected.
Same heating,
ventilating, and airconditioning applications
as the airfoil fan. Also
used in some industrial
applications where the
airfoil blade is not
acceptable because of
corrosive and/or erosive
environment.
Operating characteristics
of this fan are similar to
the airfoil fan mentioned
above. Peak efficiency for
this fan is slightly lower
than the airfoil fan.
Normally unstable left of
peak pressure.
Used primarily for
material handling
applications in industrial
plants. Wheel can be of
rugged construction and
is simple to repair in the
field. Wheel is sometimes
coated with special
material. This design also
used for high pressure
industrial requirements.
Not commonly found in
HVAC applications.
General heating,
ventilating and airconditioning systems.
Used in large sizes for
clean air industrial
applications where power
savings are significant.
Applications
Highest efficiencies occur
50 to 65% of wide open
volume. This is also the
area of good pressure
characteristics; the
horsepower curve reaches
a maximum near the
peak efficiency area and
becomes lower toward
free delivery, a selflimiting power
characteristic as shown.
Performance
Characteristics
The Babcock & Wilcox Company
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Inlet Box DamperOpposed Blades
Evase
Inlet Box Damper- Inlet Box
Parallel Blades
Outlet DamperHorizontal
Opposed Blades
Cylindrical
Type FanVariable Inlet
Vanes
Outlet DamperHorizontal
Parallel Blades
Cone
Type FanVariable Inlet
Vanes
Outlet DamperVertical Opposed Blades
Outlet DamperVertical Parallel Blades
Fig. 19 Centrifugal fan flow control devices.3
Electric motors are normally used for fan drives
because they are less expensive and more efficient
than other types of drives. For fans of more than a
few horsepower, squirrel cage induction motors predominate. This type of motor is relatively inexpensive,
reliable, and highly efficient over a wide load range.
It is frequently used in large sizes and can be used
with a magnetic or hydraulic coupling for variable
speed installations.
Variable speed motors are attractive because they
reduce shaft speed (saving operating power) at reduced flow rates. However, variable speed motors require a higher initial cost which may not be offset by
the lower power requirements at reduced fan load
conditions. Speed control also results in some loss in
motor efficiency because no variable speed driver
works as efficiently throughout the entire fan load
range as a direct connected, constant speed AC motor. The efficiency loss depends upon the type of speed
variation equipment being used.
Variable speed control for centrifugal fans can be
achieved by use of hydraulic couplings, variable speed
DC motors, two-speed motors, and variable speed
steam turbines. Hydraulic coupling losses can become
quite severe at low loads, to where a thorough evaluation of power savings over the boiler operating load
range does not produce enough monetary savings in
power consumption to justify the high initial cost.
For some variable speed installations, particularly
in the smaller sizes, wound rotor (slip-ring) induction
motors are used. If a DC motor is required, the compound type is usually selected. The steam turbine drive
costs more than a squirrel cage motor, but is less expensive than any of the variable speed electric motor
Steam 41 / Boiler Auxiliaries
arrangements in sizes above 50 hp (37 kW). A steam
turbine may be more economical than the electric
motor drive in plants where exhaust steam is needed
for process, or on large utility units using the extraction steam for feedwater heating.
Two-speed motor drives can be a reasonable alternative because initial cost is more attractive when
compared to the variable speed alternatives. Advantages offered by a two-speed motor drive over a single
speed drive are:
1. sound level is lower at maximum continuous rating (MCR),
2. the rate of wear on impeller and other fan components is substantially reduced,
3. bearing life is increased,
4. impeller stresses are reduced and fatigue life is
extended, and
5. power consumption at net and reduced load conditions is reduced.
Disadvantages of the two-speed motor drives are:
1. larger fans have higher initial cost,
2. higher motor cost,
3. plant operators are sometimes uncomfortable with
shifting to alternate speeds,
4. if reserve margins on flow and pressure at net conditions are not sufficient, the fan may shift to high
speed too often or at too low an operating load; anticipated power savings at high boiler loads may
not be realized, and
5. if reserve margins at the low speed are too high,
power savings at the normal operating condition
are not enough to offset the increased initial cost
of the two-speed system.
Fan curves for a unit set for both high and low speed
operation are shown in Fig. 21.
Axial flow fans
In an axial flow fan, the impeller is predominantly
parallel to the axis of rotation. The impeller is contained in a cylindrical housing. Axial fans for indus-
Fig. 20 Inlet vane control.
25-17
The Babcock & Wilcox Company
52
Efficiency Line
48
84% 85%
Test Block
@ 890 RPM
Static Pressure Rise (in. wg)
44
40
77%
36
82%
71%
32
15
66%
28
0
MCR @ 890 RPM
61%
51%
24
40%
20
16
-20
30%
12
-40
20%
8
10%
4
0
0
-89
-60
-80
200
100
-70
500
400
300
Volume Flow (1000 ACFM)
600
700
800
(a) High Speed Operation
33
84%
30
85%
MCR @ 710 RPM
Static Pressure Rise (in. wg)
27
24
21
51%
18
61%
15
71%
77%
40%
12
30%
9
20%
6
9%
3
0
82%
66%
-40
-80
-70
-60
-89
0
80
240
160
400
320
Volume Flow (1000 ACFM)
480
560
(b) Low Speed Operation
Fig. 21 Fan curves for high and low speed operation.
trial use are normally of the vane axial type, meaning they have either inlet or discharge guide vanes,
or both. There are three types of vane axial fans:
Performance and control characteristics
Fig. 23 shows the characteristic performance field
of a variable pitch axial flow fan. Several major benefits observed from this figure for axial flow fans include:
1. The areas of constant efficiency run parallel to the
boiler resistance line resulting in high efficiency
over a wide boiler load range.
2. There is also a large control range above, as well
as below, the area of maximum efficiency permitting the fan to be designed for net boiler conditions, while the test block point remains within the
control range.
3. The lines of constant blade angle are actually individual fan curves for a given blade setting. Because the curves are very steep, a change in resistance produces very little volume change.
4. As the blade angle is adjusted from minimum to
maximum position, the flow change is nearly linear, as shown in Fig. 24.
These last two characteristics provide stable fan and
boiler control.
Parallel operation
Variable pitch axial flow fans can be operated in
parallel provided care is taken to avoid operating either fan in the stall area discussed below. With two
fans in operation, the resistance line for one fan is
influenced by the other fan as well as by the boiler
conditions. Two fans together will develop the pressure required to overcome the boiler resistance, but individual volume flows need not be equal. However, to
obtain the most efficient fan operation and to avoid operation in a range close to the stall line, it is best to keep
both fans operating in parallel in their design condition.
The suggested control logic for starting, stopping
and supervising the operation of variable pitch axial
flow forced draft and induced draft fans is very similar to that of centrifugal fans. An additional requirement of the logic is to prevent damage to the fan while
1. Fixed pitch: Impeller blades are permanently secured at a given angle on the impeller hub.
2. Adjustable pitch: Impeller blade angle can by mechanically altered when the impeller is at a standstill.
3. Variable pitch: Impeller blade angle can be mechanically or hydraulically altered while the impeller is rotating.
Variable pitch axial flow fans used in fossil power
generating systems can be more energy efficient than
equivalent centrifugal type fans. Fig. 22 compares the
power consumption of the primary air, forced draft and
induced draft fans for a typical 500 MW coal-fired unit
using variable pitch axial flow fans with the same unit
using backward curved, inlet vane controlled centrifugal fans. At 100% unit load, auxiliary power savings using a variable pitch axial flow fan will be 4000 kW, or
about 7% of the total auxiliary power consumption.
25-18
Fig. 22 Power savings.
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Fig. 23 Performance field for variable pitch axial flow fan.
maintaining an open flow path through the boiler to
prevent furnace pressure excursions.
Stall characteristics
Axial flow fans have a unique characteristic called
stall. Stall is the aerodynamic phenomenon which
occurs when a fan operates beyond its performance
limits and flow separation occurs around the blade. If
this happens, the fan becomes unstable and no longer
operates on its normal performance curve. Extended
operation in the stall region should be avoided. Unpredictable flow vibrations occur which can damage
the rotating blades.
The curves in Fig. 25, marked A, are the normal fan
performance curves for a constant blade angle. Each
blade angle curve has an individual stall point, identified as S on the diagram. The curve C connects all
the stall points S and is generally referred to as the
stall line.
The dashed curves B are the characteristic stall
curves for three different blade angles. The curves
show the path that the fan will follow when operating in a stalled condition.
Fig. 26 explains the stall phenomenon in relation
to the fan and boiler system. If the normal boiler system resistance (curve B) increases for any reason (for
instance, a furnace pressure excursion caused by a
main fuel trip), the normal operating point X will
change to meet a new higher system resistance (curve
B1) by traveling along the fan performance curve A.
If the operating point arrives at point S, the fan will
stall. Because of the relationship between the fan performance curve D in the stall area and the upset system resistance (curve B1), a new operating point X1 will
be found where the system resistance (curve B1) and
the stall curve B intersect. When the system resistance
is reduced to curve B, the fan will recover from the
stall and return to its normal performance curve A.
In the case of an upset as described above, the blade
angle can be reduced until the fan regains stability.
The fan will be stable when the new performance
curve A1 provides a stall point S, which is higher than
the system resistance (curve B1).
Steam 41 / Boiler Auxiliaries
Fig. 24 Variable pitch blade control characteristics.
Stall prevention
When axial fans are sized properly and the system
resistance line is parabolic in shape, the probability
of experiencing stall is low. The possibility of a stall
increases if a fan is oversized in regard to volume capacity, if the system resistance increases significantly,
or if the fans are operated improperly.
The degree of stall protection desired in the control
system depends on individual owner philosophy. A
visual indication of head and volume (or blade angle)
in the control room is a minimum requirement for
satisfactory operation.
Fan arrangement
Axial flow fans designed for today’s large fossil fueled steam generating systems are compact and rela-
Fig. 25 Actual stall curves.
25-19
The Babcock & Wilcox Company
Fig. 26 Stall as related to the boiler.
tively light. By concentrating the load carrying parts
of the rotor on a small radius, a low flywheel effect or
moment of inertia (Wk2) is obtained. The low weight,
unbalanced forces and inertia of the axial flow fan
permit either horizontal or vertical arrangement on
steel construction using a dampening frame. This provides greater arrangement flexibility. Axial fans installed at grade require less of a concrete foundation
than centrifugal fans.
A horizontal fan arrangement is generally the economic preference for forced draft and primary air fans.
Induced draft fans can be arranged horizontally, or
vertically inside the stack should available plant space
be at a premium.
Induced draft fan blade wear
Fan blade wear for induced draft fans is a function
of dust loading (including excursions due to particulate collection equipment malfunction), particle hardness, particle size distribution, the relative blade to
particle velocity, the blade material, and the angle of
attack. The fan designer has little control over the first
three and must therefore look to other areas to address
blade wear issues. Wear is inherently more uniform
over variable pitch axial flow fan blades. By selecting
a two-stage fan at a lower speed (rpm) instead of a
faster one-stage fan, the tip velocity can be reduced.
Abrasion resistant material coatings can also be added
to the blade wear areas. Additionally, the blades can
be made easily removable for fast replacement.
Aerodynamic characteristics
Fig. 27 shows a fan selection diagram used to determine the most economical fan for a given set of performance conditions. The performance requirements
for a 500 MW coal-fired boiler using pairs of induced,
forced and primary fans are superimposed on the fantype selection diagram.
When specific speed increases, the diameter ratio of a
centrifugal fan increases toward unity. As unity is approached, the design becomes less practical in the high
specific speed range because the diameter ratios decrease.
25-20
System resistance is plotted in Figs. 16 and 20 along
with the fan characteristic of static pressures at various speeds. If the fan operates at constant speed, any
flow rate less than that shown at the intersection of
the system resistance and specified rpm curves must
be obtained by adding resistance through throttling
the excess fan head.
Plotting characteristics on a percentage basis shows
some of the many variations available in different fan
designs. Fig. 28 is such a plot with 100% rated capacity selected at the point of maximum efficiency. Some
fans give steep head characteristics, while others give
flat head characteristics. Some horsepower characteristics are concave upward, others are concave downward. The latter have the advantage of being self-limiting, so that there is little danger of burning out the
driver or little need for oversizing the motor.
Centrifugal fans have a steep head characteristic
and are attractive for high static, low flow rate applications. Fans with steep head characteristics also require high tip speeds for the specified head. Therefore,
centrifugal fans are usually equipped with wear liners when there is heavy dust loading in the gas. In
contrast, axial flow fans are more suitable for use
where static pressure requirements tend to decrease
as flow requirements decrease. Application of axial
flow fans to systems where pressure requirements may
suddenly increase at reduced flow conditions must be
carefully reviewed to ensure that the change in static
requirements does not cause the fan to stall.
Types of fan shaft bearings
The types of bearings used in fans are anti-friction
(grease lubricated roller or oil lubricated roller) and
sleeve.
The choice in a given fan application depends
largely on the end user. In most centrifugal fan applications, the industry prefers sleeve bearings for their
reliability and for the ease of replacing worn liners. In
some instances, anti-friction bearings, either grease or
oil lubricated, may be chosen. Smaller higher speed fans
and axial flow fans usually employ anti-friction bearings. Larger lower speed fans and fans with high moments of inertia will more often use sleeve bearings, as
will centrifugal fans with large diameter impellers.
Sleeve bearings rely on a continuously maintained
oil film to provide a very low friction protective layer
between shaft and bearing surface. When the fan is
at rest, there is contact between the shaft and bearing surface. Shortly after shaft rotation begins, an oil
film is established (by the lubrication system) that
prevents contact between metal surfaces.
Acoustic noise
Fans produce two distinct types of noise as follows:
1. Single tone noise is generated when the concentrated
fluid flow channels leaving the rotating blades pass
a stationary object (straightener vanes or nose). The
distance from the rotating blades to stationary objects
affects the sound intensity, with the blade-passing frequency and its first harmonic being most dominant.
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Fig. 27 Fan type selection diagram.
2. Broad band noise is produced by high velocity
fluid rushing through the fan housing and, as the
name implies, covers a wide frequency range.
From the outside, the apparent source of both types
of fan noise is the fan housing. The sound travels out
of the inlet box opening, through the discharge
ductwork and through the casing of the fan. All three
areas must be acoustically analyzed and individually
treated to achieve an acceptable installation. Fig. 29
illustrates noise distribution characteristics around a
fan.
Inlet sound levels from forced draft and primary air
fans are most commonly controlled by the installation
of an absorption-type silencer. Fan casing noise can
usually be effectively controlled by the use of mineral
wool insulation and acoustic lagging. Fan discharge
noise, however, requires a more detailed evaluation
to determine the most cost-effective method of control.
For forced draft and primary air fans, insulating the
outlet ducts or installing an absorption-type discharge
silencer can be effective. For induced draft fans, installation of thermal insulation and lagging on the outlet
flues will generally be sufficient. For situations where
stack outlet noise must be reduced, an absorption-type
discharge silencer can be used. However, this will not
work on coal-fired units as the sound absorbing panels
Steam 41 / Boiler Auxiliaries
will become plugged with flyash. In this instance, a resonant-type discharge silencer with a self-cleaning design
must be used. Typical noise attenuation devices are
shown in Fig. 30.
Condensing attemperator system
Superheater spray water attemperation is the primary method of steam temperature control on most
boilers. This spray water is introduced between stages
of the superheater or, in some cases, immediately
downstream of the superheater outlet. If feedwater is
used as the source for this attemperation, it must have
very low solids content in order to avoid introducing
potentially damaging deposits in the superheater or
in the turbine.
Many industrial plants do not have the water treatment facilities capable of meeting the low solids feedwater
requirements for spray attemperation. If feedwater
quality does not meet the solids criteria established for
spray water, a condensing attemperator system can be
used to provide a low solids spray water source.
A schematic diagram of a typical condensing
attemperation system is shown in Fig. 31. The system
typically consists of a condensing heat exchanger (condenser), spray water flow control valve, spray water
25-21
The Babcock & Wilcox Company
Sound
Radiated
Into Inlet
Ductwork
Sound
Radiated
Through
Flexible
Connections
Transition
Sound
Radiated
Into Outlet
Ductwork
Sound
Radiated
From
Casing
Outlet
Duct
Sound
Radiated
From Drive Train
Structurally
Transmitted
Sound Energy
Fig. 29 Fan sound patterns.4
Boiler feedwater is the cooling medium that flows
through the tube side of the condenser. Fig. 31 shows
the feedwater flowing from the economizer outlet to the
condenser and from the condenser to the drum. Alternate locations may be upstream of the economizer inlet
or an intermediate header in a multi-bank economizer.
The spray water condenser is a vertical, head down
shell and tube heat exchanger arrangement (Fig. 32).
The feedwater tube bundle is of the inverted U-tube
type construction. Feedwater enters and leaves the
tube bundle at the bottom of the inverted U-tubes. The
cylindrical shell enclosure features a drum steam inlet near the top of the shell and a condensate outlet
close to the bottom of the shell.
During normal operation, the condenser system will
experience cyclic operation. At times there will be no
spray flow demand and the condensate level on the
shell side of the condenser will rise to the top of the
tube bundle. This is a desirable operating characteristic of the inverted U-tube arrangement. It prevents
Silencer
Silencer
Fig. 28 Selected centrifugal and axial flow fan characteristic curves.
Transition
attemperator and occasionally, a condensate storage
tank and a condensate pump. The basic design philosophy of this system is that saturated steam from the
boiler steam drum is routed to the shell side of a vertical condenser, where it is condensed and subcooled. This
condensate then flows through the spray water piping
and control valve to an interstage attemperator or to a
terminal attemperator.
Most condensing attemperation systems are driven
by the pressure differential between the drum and the
point in the steam path where the spray water is introduced. Condensers are normally located above the
steam drum in order to increase the hydrostatic head
available to the attemperator. If the available pressure differential is not sufficient to overcome the system resistance developed at the design spray water
flow, then a condensate pump must be used. In order
to avoid the need for a condensate pump, system resistance losses are usually minimized by using a low
pressure drop attemperator if system spray characteristics over the boiler operating range permit its use.
25-22
Forced Draft Fans
In Acoustical
Enclosure
Inlet Box
Diffuser
Axial Forced Draft
Fan With Inlet Box
Silencers
Possible Locations
Absorptive Silencing
Centrifugal Fans
Transition
Inlet Box
Centrifugal
Forced Draft Fan
With Inlet Box
Silencers
Axial Fans
Fig. 30 Fan noise attenuation devices.4
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Fig. 31 Schematic arrangement of vertical condenser system.
steam pockets from being trapped at the top of the
condenser shell which could cause water hammer and
subsequent cracking of the shell.
The spray water condenser must be designed to
withstand significant temperature transients and gradients. At times the condenser will be almost flooded
with water and the whole assembly will be close to
feedwater temperature. A sudden requirement for spray
water can drop this water level quickly, exposing significant lengths of shell and internals to saturated steam
temperature. In some cases this can mean a sudden rise
in shell temperature of as much as 300F (167C).
Fig. 32 General arrangement of vertical head down condenser.
References
1. 2004 ASME Boiler and Pressure Vessel Code, Section
I: Power Boilers, American Society of Mechanical Engineers, New York, New York, September 1, 2004.
2. AMCA Publication 850-02, “Industrial Process/Power
Generation Heavy Duty Dampers for Isolation and Control,” Air Movement and Control Association International,
Inc., Arlington Heights, Illinois, 2004.
Steam 41 / Boiler Auxiliaries
3. AMCA Publication 201-02, “Fans and Systems,” Air
Movement and Control Association International, Inc.,
Arlington Heights, Illinois, 2004.
4. AMCA Publication 801-01, “Industrial Process/Power
Generation Fans: Specification Guidelines,” Air Movement
and Control Association International, Inc., Arlington
Heights, Illinois, 2004.
25-23
The Babcock & Wilcox Company
Fan housing being prepared for installation (courtesy of TLT-Babcock).
25-24
Steam 41 / Boiler Auxiliaries
The Babcock & Wilcox Company
Section III
Applications of Steam
The six chapters in this section illustrate how the subsystems described in
Section II are combined to produce modern steam generating systems for specific applications. A number of steam generating unit and system designs for
various applications are described and illustrated.
Chapter 26 begins the section with a discussion of large fossil fuel-fired equipment used to generate electric power. Both large and small industrial units, as
well as those for small electric power applications, are then described in Chapter 27. The next four chapters address specialized equipment for specific applications. Unique designs for steam producing systems are used in pulp and paper
mills, waste-to-energy plants, biomass-fired units, and marine applications.
Biomass-fired systems in particular are receiving increased interest as renewable energy resources grow in importance.
Steam 41
The Babcock & Wilcox Company
Chapter 26
Fossil Fuel Boilers for Electric Power
Most of the electric power generated in the United
States (U.S.) is produced in steam plants using fossil
fuels and high speed turbines. These plants deliver a
kilowatt hour of electricity for each 8500 to 9500 Btu
(8968 to 10,023 kJ) supplied from the fuel, for a net
thermal efficiency of 36 to 40%. They use steam driven
turbine-generators of up to 1300 MW capacity with
boilers generating from one million to ten million
pounds of steam per hour. A typical coal-fired facility
is shown on the facing page.
Modern fossil fuel steam plants use reheat cycles
with nominal steam conditions of 3500 psi/1050F/
1050F (24.1 MPa/566C/566C) for supercritical pressure systems, and 2400 psi (16.5 MPa) with superheat
and reheat steam temperatures ranging from 1000 to
1050F (538 to 566C) for subcritical pressure systems.
For some very small units, lower steam conditions may
be applied. In selected global locations where higher
cycle efficiencies are required, supercritical pressure
steam conditions on the order of 4300 psi/1075F/1110F
(29.6 MPa/579C/599C) and 3626 psi/1112F/1130F
(25.0 MPa/600C/610C) have been used.
Most power plants in the U.S. and around the world
are owned and operated by: 1) investor owned electric companies, 2) federal, state or local governments,
or 3) finance companies.
These owners, whether public or private, have been
generally known as utilities. During the 1980s and
1990s, there was a trend toward new types of companies supplying significant portions of new generation.
However, the fundamental approach to selecting
power generation equipment will remain unchanged.
Selection of steam generating equipment
The owner has several technologies to choose from
based upon fuel availability, emissions requirements,
reliability, and project timing. One of the common
choices for modern electric power generation is the
high pressure, high temperature steam cycle with a
fossil fuel-fired boiler.
Each new electric generating unit must satisfy the
user’s specific needs in the most economical manner.
Steam 41 / Fossil Fuel Boilers for Electric Power
Achieving this requires close cooperation between the
equipment designers and the owner’s engineering
staff or consultants. The designers, owner and engineering group must identify those equipment features
and characteristics that will reliably produce low cost
electricity. The primary costs of electricity include: 1)
capital equipment, 2) financing charges, 3) fuel, and
4) operation and maintenance. The owner, prior to
issuing equipment specifications, reviews and surveys
all cost factors. (See Chapter 37.)
The capital cost survey must include all direct costs
such as the boiler, steam turbine and electric generator, emissions control equipment, condenser, feedwater
heaters and pumps, fuel handling facilities, buildings,
and real estate. In addition, finance charges, including interest rates, loan periods, source of funds and
tax considerations must be added. Fuel and emission
control reagent costs need to be evaluated based on
the initial costs, plant capacity variations expected during the life of the plant, and forecasts of cost changes
during plant lifetime. The operation and maintenance
costs should be estimated based on other current
plants with similar equipment, fuels and operating
characteristics. Operating and maintenance costs are
heavily affected by personnel requirements, and consideration should be given to the availability of skilled
labor as well as to the cost of retaining the skilled staff
during the plant lifetime.
Plant efficiency, fuel use and capital cost are critically related. Higher plant thermal efficiency obviously reduces annual fuel costs; however, fuel savings
are partially offset by the associated higher capital
costs. Therefore, selection of the desired plant efficiency should carefully consider the economic tradeoffs
between capital and operating costs.
Other important criteria are the location of the electric generating plant with respect to fuel supply and
the areas where electricity is used. In some cases, it is
more economical to transport electricity than fuel.
Some large steam generating stations have been built
at the coal mine mouth to generate electricity which
is then used several hundred miles away. If the user
is a member of a broader grid of interconnected util26-1
The Babcock & Wilcox Company
ity companies, the future requirements of other system members may also be an important factor.
In power plant planning, substantial time and effort are required to establish accurate basic plant assessment data with comprehensive consideration of engineering factors and plans for future expansion or
changes. The accuracy of these data is critical if the
experience and craftsmanship of the boiler manufacturer and other suppliers are to fully benefit the plant
designer and owner. The owner should, at the outset,
decide who is to prepare these data. If the owner lacks
personnel with the necessary qualifications, consulting engineers should be used. A thorough discussion
with the boiler manufacturer will provide many details to help the owner make correct decisions.
Before the boiler and other major equipment items
can be selected, the basis of operation and arrangement of the entire steam plant must be planned. Ultimately the available data must be translated into the
form of equipment specifications so that the manufacturers of various components can provide apparatus
in accordance with the user’s requirements. After
equipment selection, construction drawings must be
prepared for the foundations, building, piping and
walkways. The construction work must be coordinated
utilizing modern schedule and control techniques for
effective management and completion of erection.
Ideally, the construction planning begins at the start
of the conceptual engineering so that the site arrangement and project schedule facilitate efficient construction practices. Modularization of major components can be incorporated into the design where site
conditions permit.
Boiler designer’s requirements
The most important factors to the boiler designer
are the steam conditions, fuel, project load service, and
environmental constraints. Steam conditions identify
the amount of steam required, the temperature and
pressure of the main and reheat steam, and the
feedwater temperature. Of equal importance is the
type and chemical composition of the fuel, the ash
characteristics, and the emissions control requirements for the specified plant site.
The boiler designer needs a complete set of data
pertinent to steam generation to produce the most
economical steam generating equipment and satisfy
the needs of the user.
The requirements and conditions that form the basis for the designer’s equipment selection can be outlined as follows:
1. Fuels – sources presently available or planned for
future use; proximate, ultimate and ash analyses
of each fuel as well as costs and future trends.
2. Steam requirements – ideally steam turbine heat
balances should be provided for a more comprehensive understanding of the cycle design requirements. At a minimum the flow, pressure and temperature at each terminal location (main steam,
feedwater, cold reheat, hot reheat, auxiliary
steam, etc.) must be given for the various loads
where performance is to be evaluated.
3. Boiler feedwater – source, chemical analysis and
26-2
temperature of the feedwater entering the steam
generating unit.
4. Environmental requirements – site limitations; permissible levels for nitrogen oxides (NOx), sulfur
dioxide (SO2), particulate and other atmospheric
emissions; solid waste specifications; and all other
regulatory and commercial requirements.
5. Dispatch requirements – turndown, rate of load
change, and on/off cycling.
6. Space and geographical considerations – space
limitations, relation of new equipment to existing
equipment, earthquake and wind resistance requirements, elevation above sea level, foundation
conditions, climate, and accessibility for service
and construction.
7. Auxiliary power – medium used and evaluated cost
of energy.
8. Operating personnel – experience level of operating and maintenance personnel as well as the cost
of labor.
9. Guarantees.
10. Evaluation basis – for unit efficiency, auxiliary
power required, building volume, and various
fixed charges.
With this information, the boiler designer is able to
analyze the user’s specific needs. As a result, an economical, reliable steam generator can be built and initial costs can be balanced with long-term savings. Setting these requirements based on anticipated future
needs will provide a flexible boiler design within the
constraints of cost and technical criteria.
Design practice
Utility boiler design is a custom design process due
to the uniqueness of each project. Variations in
projects are a result of the following fundamental differences: steam cycles, types and range of fuels, site
conditions, emissions requirements, and the user’s
operating plans. Such variations require custom design in the overall arrangement of boiler components.
The boiler designer works with standardized component concepts which are assembled to provide the
optimum design arrangement to satisfy the unique
requirements of the project.
While the overall design is customized, component
design concepts are highly standardized and make use
of pre-engineered elements where possible (attachment
clips, access doors, etc.). In addition, some components,
such as pulverizers, are largely pre-engineered.
At the start of a project, the designer reviews the
available database and past experience to determine
which large shop-fabricated components, called modules, may be applied to the design. Reviewing shipping sizes, traffic methods and routing, and the general economic tradeoff of greater shop assembly versus reduced field erection time are standard project
practices. Modularization is now common practice but
needs to be assessed on each project to determine the
optimum cost and schedule impact.
Fuels
The basic types of fuels used for U.S. electricity
generation are shown in Fig. 1. The dominant fuel in
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
modern U.S. central stations is coal, either bituminous,
subbituminous or lignite. A similar picture emerges for
worldwide electric power production. (See Fig. 2.)
While natural gas, and possibly fuel oil, used with gas
turbine and combined cycle technology may be the
fuel of choice for many new fossil fuel power plants,
coal is expected to continue its important role in supplying energy to new, base-loaded utility power station boilers. The following material focuses primarily
on coal-fired utility boilers but includes selected comments and discussion of other fossil fuels. General discussion of steam production as part of combined cycle
and waste heat recovery applications is provided in
Chapter 27. Specialized designs for unique, smaller
power production facilities are also discussed.
Coal Coal is the most abundant fuel in the U.S. and
in many parts of the world. The U.S. leads the world
in coal production followed by China, India, South
Africa and Australia. However, of the major fossil fuels, coal is also the most complicated and troublesome
to burn. In the U.S., Europe, Japan, and increasingly
in other parts of the world, there are also societal and
political difficulties in locating, siting and permitting
coal-fired power plants, especially considering the airborne, liquid and solid emissions compared to other
fossil fuels. Coal use involves unloading, storage and
handling facilities; preparation before firing using
crushers and pulverizers; ash disposal equipment;
emissions control equipment; and sootblowers. There
is a wide variation in the properties of coal and its ash.
As a result, while the design of the steam-producing
unit must provide optimum performance when firing
the intended coals, it must also accommodate reasonable alternate coals if necessary.
The coals selected for a prospective installation should
be tabulated to indicate chemical analysis, heating value
and grindability. In addition, each coal’s ash analysis
and ash temperature profile should be listed. The ash
composition has a marked effect on a coal’s slagging and
fouling characteristics; the analysis must be provided to
the boiler supplier for proper selection of unit geometry,
features and surfaces. (See Chapter 21.)
Hydro
6%
Oil Other
3% 2%
Gas
17%
Coal
51%
Nuclear
21%
Fig. 1 U.S. electricity generation in 2001, by fuel.
Steam 41 / Fossil Fuel Boilers for Electric Power
Oil
7%
Other
2%
Hydro
17%
Coal
39%
Nuclear
17%
Gas
18%
Fig. 2 Worldwide electricity generation in 2001, by fuel.
Steam requirements
Modern turbines are designed for nominal conditions of 3500 psi/1050F/1100F (24.1 MPa/566C/593C)
for supercritical systems and 2400 psi/1000F/1000F
(16.5 MPa/538C/538C) for subcritical systems. For
some very small units, lower steam conditions such as
1800 psi (12.4 MPa) pressure may be selected. As noted
earlier, some advanced steam pressure and temperature conditions may also be applied.
The steam temperature specified at the superheater
outlet is generally considered to be equal to that required at the turbine plus 5F (3C). While there is very
little heat loss in the well-insulated steam lines, the
pressure loss in the piping results in a temperature
change at constant enthalpy. For optimum performance and turbine maintenance, the steam temperature should remain constant over a broad load range.
Means for controlling steam temperatures are required in utility practice. Steam temperature variation and control are discussed in Chapters 19 and 41.
The steam pressure at the superheater outlet is
normally specified by the plant designer after evaluating the economics of pressure drop versus pipe sizing. Typically, the allowance for the main steam line
pressure loss is 5% of the throttle pressure and the total
allowance for the hot and cold reheat line loss is 5%
of cold reheat pressure.
It has been customary stationary-boiler practice in
the U.S. to hold the main steam pressure constant for
all loads, on the premise that this condition satisfies
all pressure and quantity requirements of the steamusing equipment (constant pressure). This is particularly the case where the unit is base loaded and significant cycling operation is not anticipated. In addition, constant pressure operation permits more rapid
load transients while minimizing transient stresses in
the boiler. However, constant pressure operation assesses some heat rate penalty at partial load conditions
26-3
The Babcock & Wilcox Company
and results in some additional stresses in the turbine
during rapid load changes.
Alternately, the system can be operated so that
steam pressure varies with boiler load (variable pressure). This is more energy efficient at reduced load
conditions and permits better temperature control to
the turbine under load transients. However, the system may be less responsive due to the need to change
the thermal inventory of the boiler during load changing, and additional stress is placed on the unit under
transient conditions due to the saturated water temperature change. The thermal transient response may
be improved by operating with throttle valve reserve
where, for partial arc turbines, the turbine is controlled with constant throttle pressure until the first
valve is closed and then operated with variable pressure. This allows the turbine valve to be opened for
rapid load increase, essentially borrowing energy from
the boiler system. This mode of operation is sometimes
called turbine hybrid variable pressure operation.
Another mode of operation is boiler hybrid variable
pressure or split pressure operation. In this mode, the
turbine is operated variable pressure while the boiler
through the primary superheater is operated at constant pressure. Pressure is controlled by a reducing
valve located between the primary and secondary superheaters. The boiler can be maintained at a constant
pressure, thereby minimizing stress and maximizing
response to load changes. The temperature of the
steam entering the turbine can be separately maintained, minimizing stress and maximizing load response of the steam turbine. This mode of operation
provides the maximum responsiveness to load transients. While this mode of operation has a thermodynamic advantage at reduced loads compared to constant pressure operation, it is not as efficient as variable pressure operation.
These control approaches and their implications are
addressed in Chapters 19 and 41.
Central station units use the reheat cycle for increased station thermal efficiency. The reheater, located within the boiler enclosure, receives steam exhausted from an intermediate pressure stage of the
turbine. The steam temperature is raised and the
steam is returned to the low pressure section of the
turbine. The cold reheat enthalpy is impacted by the
mode of turbine operation (constant vs. variable pressure) and this must be considered in the boiler design.
The cold reheat enthalpy is greater under variable
pressure operation (due to the increased main steam
enthalpy at constant temperature but lower pressure
at the throttle and reduced throttling loss) and therefore the heat absorption required of the reheater is
reduced with variable pressure operation.
The double reheat cycle, where steam is returned
to the boiler twice for reheating and then delivered to
low pressure sections of the turbine, results in even
higher station thermal efficiency than the single reheat cycle. However, the gain in plant efficiency must
be weighed against the cost of additional piping systems and turbine and boiler equipment used to accommodate the flow of low pressure steam.
26-4
Steam flow requirement
Steam producing equipment must be of sufficient
capacity, range of output and responsiveness to ensure prompt response to the turbine steam demand.
The demand may be steady, as in base loaded systems,
or it may fluctuate widely and rapidly, as in cycling
units. The steam flow requirements should therefore
be accurately established for peak flow, maximum continuous flow (usually steady maximum flow), minimum flow, and rate of change in flow. The peak load
establishes the capacity of the steam producing equipment and all its auxiliaries.
Often the turbine is designed for 5% overpressure
operation (operation at a pressure 5% greater than the
nominal throttle pressure). This permits a 5% higher
steam flow through the turbine and results in greater
unit output. This design concept will determine both
the boiler maximum capacity and the boiler maximum
operating and design pressures.
Occasionally, the specification will require that the
system be capable of peaking by removing one or more
of the top feedwater heaters from service. The steam
normally supplied to this feedwater heater then flows
through the turbine, thereby increasing its output.
The source of that steam is from extraction on the high
pressure turbine and potentially the intermediate
pressure turbine depending on the heaters removed
from service. This method results in higher than normal heat rates (i.e. lower efficiencies) while overpressure operation reduces heat rate. This condition impacts the boiler design in determining the maximum
output and because the change in turbine extraction
impacts both the feedwater temperature and the reheat flow, thereby changing the required heat absorption in various boiler components.
The range from minimum to maximum output is an
important factor in selecting the boiler’s firing equipment. To maintain stable ignition and optimal combustion, this range must also be considered in designing
the furnace.
The required rate of change in turbine load (steam
flow) may affect the entire design of the steam producing equipment. Within a specified load range, good
response is easily obtained with well-designed firing
equipment for pulverized coal, oil and natural gas. A
multiplicity of burners (and pulverizers, where used)
widens the available range, but if there is a frequent
change in load, remote manual on/off operation of
burners and pulverizers may be objectionable. It is
therefore important that the designer, manufacturer
and operator understand what can be done by full automatic firing and what is required beyond that.
In selecting equipment to produce steam at minimum total cost, it is also necessary to establish the
probable capacity factor – the ratio of the average
output to the rated output. This capacity factor serves
as a basis for establishing the value of incremental increases in steam generating efficiency. For example,
the initial cost necessary to achieve high efficiency in
a plant operating continuously at high output may not
be justified for a plant operating as a cycling unit
where the average capacity factor is relatively low.
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Boiler feedwater
The steam passing through the turbine is condensed in the condenser. This condensate is the primary source of feedwater for the boiler. Makeup water is also required to be added to the system due to
cycle losses. High purity makeup water is supplied by
a comprehensive water treatment system which removes troublesome compounds, and oxygen normally
found in raw water from surface or subsurface sources.
Dissolved oxygen will attack steel and the rate of attack increases sharply with a rise in temperature. High
chemical concentrations in the boiler water and
feedwater cause furnace tube deposition and allow solids carryover into the superheater and turbine, resulting in tube failures and turbine blade deposition or erosion.
As steam plant operating pressures have increased,
the water treatment system has become more critical.
This has led to the installation of more complete and
refined water treatment facilities. (See Chapter 42.)
Environmental considerations
Environmental protection is an integral part of the
boiler and power system design process. As outlined
in Chapters 1 and 32, boilers emit varying levels of
NOx, SO2, particulate, and other compounds into the
air and they discharge ash. Government regulations
tightly control these emissions in most parts of the
world. The specific local regulations will govern the
extent of back-end cleanup equipment required and
many of the boiler design parameters. A new unit
burning coal in the U.S. today might look like the unit
shown in Fig. 3. The boiler is designed with low NOx
burners, an enlarged furnace, staged combustion
(with overfire air or NOx ports) to minimize NOx emissions, and a selective catalytic reduction (SCR) system for further NOx control. (See Chapters 14 and 34.)
An electrostatic precipitator or fabric filter collects
particulate (Chapter 33), while either a wet flue gas
desulfurization system (wet scrubber) or a spray dryer
absorber (dry scrubber) removes most of the SO 2
(Chapter 35). Careful review and economic evaluation of all local regulations and permitting requirements are needed to achieve the required environmental protection in the most cost effective manner.
Space and geographical considerations
Space and geographical considerations are extremely site specific and can dictate the equipment
arrangement and even the construction sequence. In
some cases, a new boiler is added to an existing plant
to maximize the use of existing equipment and plant
infrastructure. The most extreme case involves repowering an existing plant, where the old boiler is removed
and a newer unit is installed in the same space.
The boiler and its support structures must be designed to accommodate expected seismic forces and
wind loadings, in accordance with local structural laws
and regulations. The site elevation above sea level significantly affects the design and sizing of ducts, fans
and the stack due to the impact of site barometric pressure on the air and flue gas specific volume. Fan power
consumption is also influenced by site elevation. Finally, boilers can be designed for indoor or outdoor
installation, depending upon the prevailing climate.
Universal Pressure Boiler
Stack
NO Ports
SCR
Low NO
Burners
Wet Flue Gas
Desulfurization
System
Air
Heater
Enlarged
Furnace
Volume
Coal Pulverizers
Particulate Collection
Electrostatic Precipitator
or Fabric Filter
Forced Draft Fans
Induced Draft Fan
Fig. 3 Integrated pulverized coal-fired boiler power system with emissions control.
Steam 41 / Fossil Fuel Boilers for Electric Power
26-5
The Babcock & Wilcox Company
Power for driving auxiliaries
Modern practice in central stations generally calls
for electric motor drives for rotating auxiliaries such
as pumps, fans, pulverizers and crushers (although
the boiler feed pump is usually turbine driven). The
convenience and cost of the electrical drive substantiate this preference. The available plant voltage levels can determine the maximum motor size and may
impact the number of forced draft and/or induced draft
fans required.
Guarantees
It is common practice to obtain performance guarantees from component suppliers to provide a means
to evaluate offerings and to validate the actual performance of the unit during operation.
The boiler manufacturer is usually requested to provide the following guarantees, depending on the arrangement, type of fuel and type of boiler.
1. For a given load point and fuel:
a. efficiency,
b. superheater steam temperature,
c. reheater steam temperature,
d. pressure drop from feedwater inlet to superheater outlet and from reheater inlet to
reheater outlet,
f. solids in steam (for drum boilers),
g. auxiliary power consumption (fans, pulverizers
and drives), and
h. air heater leakage.
2. Unit maximum capacity (which is often greater
than the turbine maximum capacity).
3. Superheater and reheater temperature control
ranges.
4. Pulverizer capacity and fineness (where applicable).
5. NOx and other emissions depending on project requirements.
Pulverized coal firing
The size of large pulverized coal-fired boilers and
turbine-generators has peaked at 1300 MW. The
equipment can be designed to burn practically any bituminous coal, subbituminous coal or lignite commercially available. Anthracite can be successfully burned
in pulverized form, but requires a specialized boiler
arrangement. While the special attention and additional expenses associated with plants designed for
this fuel preclude its use in North America, anthracite is used today in parts of China, Vietnam and
Europe.
The overall aspects of pulverized coal firing, as applied to boiler units, are as follows:
1. is suitable for almost any coal mined throughout
the world,
2. is economically suitable for a very wide range of
boiler capacities,
3. provides wide flexibility in operation and high
thermal efficiency,
4. must have proper coal preparation and handling
equipment, including moisture removal,
26-6
5. must have proper means of handling the ash
refuse, and
6. must have controls for atmospheric emissions arising from elements in the coal and from the combustion process.
Babcock & Wilcox pulverized coal-fired
boiler types for electric power
Prior chapters provide information on steam generation and power plant design and include fundamentals that are applied by designers and manufacturers worldwide. In particular, Chapter 19 discusses
general boiler design, while Chapters 13 and 14 address the preparation and combustion of pulverized coal.
This chapter concentrates on The Babcock & Wilcox
Company (B&W) design philosophy which integrates
these technologies into large reheat steam generators for
electric power generation.
B&W has a broad base of experience that can be
applied to most owner needs. B&W’s basic design philosophy focuses on the key operating issues of availability and reliability, and on incorporating technology advances into each new unit design. Examples of
the company’s strengths include rapid startup and load
shedding features, extended control ranges for superheater and reheater outlet temperatures, and experience in burning a wide variety of coals.
Supercritical (once-through) boilers
The B&W boiler for supercritical applications is the
Universal Pressure (UP®) boiler. Originally designed
for both supercritical and subcritical applications, this
design is now used for supercritical applications; the
drum boiler is used for subcritical applications. The
supercritical application is usually applied to systems
with a capacity of 300 MW or larger due to steam turbine considerations.
The original UP boiler design dates back to the mid1950s when the 125 MW advanced supercritical boiler
was provided for American Electric Power’s Philo station. This pioneering boiler/turbine system, with advanced steam conditions of 4500 psi/1150F/1050F/
1000F (31 MPa/621C/566C/538C), was the first
supercritical system. The boiler design rapidly evolved
to units as large as 1300 MW in the late 1960s. These
boilers, nine of which are in operation, are among the
largest capacity fossil fuel boilers in the world.
In modern units, the furnace is completely fluidcooled, designed for balanced draft operation, and usually features dry ash removal. Superheater and
reheater components are of the vertical pendant and/
or horizontal design. Superheat temperature is controlled by the firing rate to feedwater flow ratio with
typically one or more stages of attemperation for transient control. Reheat temperature control is by gas proportioning dampers.
Range in capacity, steam output – from 2,000,000
lb/h (252 kg/s) steam output to more than
10,000,000 lb/h (1260 kg/s).
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Operating pressure – usually at 3500 psi (24.1
MPa) throttle pressure with 5% overpressure;
higher pressures available.
Superheater steam temperatures – as required,
usually 1050F (566C).
The principle of operation is that of the oncethrough or Benson cycle. The water, pumped into the
unit as a subcooled liquid, passes sequentially
through all the pressure part heating surfaces where
it is converted to superheated steam as it absorbs heat;
it leaves as steam at the desired temperature. There
is no recirculation of water within the unit and, for
this reason, a conventional drum is not required to
separate water from steam.
The furnace is completely fluid-cooled and is usually designed for balanced draft operation. Heat transfer surface for single or two-stage reheat may be incorporated in the design. (See Chapter 2.)
Firing rate, feedwater flow, and turbine throttle
valves are coordinated to control steam flow, pressure,
and superheater steam temperature. Reheater steam
temperature is controlled by gas proportioning dampers at the outlet of the steam and water heating surfaces.
The UP boiler is designed to maintain a minimum
flow inside the furnace circuits to prevent furnace tube
overheating during all operating conditions. This flow
must be established before boiler startup. A startup
system (boiler bypass), integral with the boiler, turbine, condensate and feedwater system, is provided.
This system assures that the minimum design flow is
maintained through pressure parts that are exposed
to high temperature combustion gases during the
startup operations and at other times when the required minimum flow exceeds the turbine steam demand. (See Chapter 19.)
Two types of UP boilers are available. The original
design (UP) features the vertical tube furnace arrangement with high mass flux within the furnace
tubes. This boiler is designed for load cycling and base
load operation; fluid pressure in the furnace is at
supercritical pressure at all loads. More recently, there
has been demand for supercritical boilers capable of
variable pressure operation and on-off cycling, as well
as load cycling and base load operation. This boiler is
the SWUP™, or spiral wound tube geometry UP boiler.
Spiral wound UP boiler – variable pressure
operation with pulverized coal
The steam generating unit shown in Fig. 4 is a balanced draft coal-fired B&W Spiral Wound Universal
Pressure (SWUP™) boiler, comprising a water-cooled
dry-bottom furnace, superheater, reheater, economizer, and air heater components. The unit is designed
to fire coal usually pulverized to a fineness of at least
70% through a 200 mesh (75 micron) screen. The
B&W SWUP unit is designed for both base load and
variable pressure load cycling operation as well as onoff cycling operation.
The unique feature of this boiler, compared to other
boilers, is that the tubes in the furnace, from the lower
furnace inlet headers to a location near the furnace
Steam 41 / Fossil Fuel Boilers for Electric Power
arch, are wound around the furnace circumference
rather than being vertical (see Fig. 5). With this arrangement, each tube in the furnace passes through
similar heat absorbing areas so that the heat absorption from tube to tube is reasonably uniform. In addition, because the tubes are at an angle (typically 10
to 25 degrees from horizontal), the number of individual flow paths is reduced, compared to a vertical
tube geometry. A high mass flux within the tube is
obtained to maintain nucleate boiling during subcritical operation (Chapter 5).
Therefore, the water introduced from the economizer piping is heated at essentially the same rate to
the same temperature, minimizing thermal upsets
which restrain rapid load change. The capability of
this design to operate at variable pressure is further
enhanced by using a startup and bypass system specifically designed for rapid load change. (See Chapter 19.)
Fuel flow Raw coal is discharged from the feeders
to the pulverizers. Pulverized coal is transported by
the primary air to the burners through a system of
pressurized fuel and air piping. The burners are located on the furnace walls with opposed firing (burners on the front and rear walls).
Air and gas flow Air from the forced draft fans is
heated in the air heaters, then routed to the windbox
where it is distributed to the burners as secondary air.
In the arrangement shown in Fig. 4, high pressure
fans provide air from the atmosphere to a separate
section of the air heater known as the primary section. A portion of the air from the primary fans is
passed unheated around the primary air heater as
tempering primary air. Controlled quantities of preheated and tempering primary air are mixed before
entering each pulverizer to obtain the desired pulverizer fuel-air mixture outlet temperature. The primary
air is used for drying and transporting fuel from the
pulverizer through the burners to the furnace.
Hot flue gas from the furnace passes successively
across the finishing banks of the superheater and
reheater. Before exiting the boiler, the gas stream is
divided into two parallel paths, one gas stream passing over a portion of the reheater and the other stream
passing over a portion of the superheater. Proportioning the gas flow between these two paths as unit load
changes provides a tool for reheat steam temperature
control. The flow quantities are adjusted by a set of
dampers at the boiler exit. A controlled amount of gas
passes over a portion of the reheater to obtain the
reheater steam temperature set point, and the remaining gas travels a parallel path across the superheater
surface. Attemperators are provided in the reheater
and superheater systems. The reheater attemperator
is used during transient loads and upset conditions,
with reheater spray quantities held to a minimum to
maximize cycle efficiency. The superheat attemperator
spray is used to help control main steam temperatures
during transient operation. This arrangement of convection surface and damper system provides extended
capability to obtain design steam temperatures in the
superheater and reheater over a broad load range.
The gases leaving the superheater and reheater sections of the convection pass cross the economizer, pass
26-7
The Babcock & Wilcox Company
to the air heater(s) and then travel to the appropriate
environmental control equipment. In areas where
tight NOx emissions requirements have been established and post-combustion control is needed, selective
catalytic reduction (SCR) NOx removal systems are frequently installed between the economizer and air
heater (see Chapter 34).
Water and steam flow Feedwater (Fig. 6) enters the
bottom header of the economizer and passes upward
through the economizer tube bank into support tubing located between tube rows of the primary superheater. The heated feedwater is collected in outlet
headers at the top of the unit. It is then piped to the
lower furnace area from which multiple connecting pipes
Final
Superheater
(supplies) are routed to the lower furnace headers.
From the lower furnace wall headers the fluid
passes upward through the spiral furnace tubes to a
transition section located below the furnace arch. From
the transition section the tubes are routed vertically
up the front and side walls and up the rear wall and
furnace arch.
After discharging to the upper furnace wall headers,
all of the fluid is piped to a fluid mix bottle, then to the
front roof header, then through the roof tubes to the rear
roof header. Pipes then convey the fluid to the vertical
steam separators. The vertical steam separators are a
part of the boiler startup system (see Chapter 19).
As illustrated in Fig. 7, steam from the vertical
Final
Reheater
Steam
Separator
Platen
Superheater
Water
Collection
Tank
Intermediate
Superheater
Primary Superheater
Primary Reheater
Economizer
Catalyst
Spiral
Transition
Headers
Overfire
Air Ports
Furnace
Ammonia
Injection
Grid
SCR
Low NOX
Burners
B&W
Roll Wheel™
Pulverizers
Air
Heater
Flue Gas
Outlet
Circulation
Pump
Forced Draft
Fan
Steam Coil
Air Heater
Primary Air
Fan
Fig. 4 750 MW once-through spiral wound universal pressure (SWUP™) boiler for pulverized coal firing.
26-8
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Front Wall
Rear Wall
Left Side Wall
Right Side Wall
Fig. 5 Typical spiral wound tube arrangement for a 420 MW coal-fired boiler.
steam separator passes to the convection pass enclosure wall lower headers. The fluid flows up through
the wall tubes and the baffle wall and is collected into
the downcomer supplying the primary superheater inlet header. The steam rises through the primary superheater, discharges to its outlet header and flows
through connecting piping equipped with a spray
attemperator. The partially superheated steam then
enters the platen secondary superheater and flows
through the various superheater sections to its outlet
headers. The steam flows through connecting pipes
and the second set of spray attemperators to the finishing portion of the secondary superheater and finally to the outlet header and discharge pipes, which
terminate at points outside of the unit penthouse. The
superheated steam is directed to the high pressure
section of the steam turbine. After partial expansion
in the steam turbine (see Chapter 2), the low pressure
steam is returned to the boiler for reheating.
The low pressure steam is reintroduced to the boiler
at the reheater inlet header (RHSH inlet) and flows
through the reheater tube bank to the reheater outlet header (RHSH outlet). Reheated steam is then
routed to the intermediate pressure and then low pressure sections of the steam turbine-generator set.
Universal Pressure boiler for load cycling
operation with pulverized coal
The steam generating unit shown in Fig. 8 is a balanced draft B&W Universal Pressure coal-fired Carolina-type boiler (UPC), comprising a water-cooled drybottom furnace and superheater, reheater, economizer
Steam 41 / Fossil Fuel Boilers for Electric Power
and air heater components. The unit is designed to fire
coal, usually pulverized to a fineness of at least 70%
through a 200 mesh (75 micron) screen. The B&W UPC
unit is particularly suited for base load duty and constant boiler pressure, load cycling operation.
Fuel flow Raw coal is discharged from the feeders
to the pulverizers, which can be located at the front
or sides of the unit. Pulverized coal is transported by
the primary air to the burners through a system of
pressurized fuel and air piping.
Air and gas flow The air flow arrangement and
routing are similar to that used on the SWUP design
previously discussed.
As indicated in Fig. 8, hot flue gases leaving the furnace pass successively across the fluid-cooled surface
at the top of the furnace (wing walls), the secondary
superheater and the pendant reheater, which are located in the convection pass out of the high radiant
heat transfer zone of the furnace. The gas turns downward (convection pass) and crosses the horizontal primary superheater, horizontal reheater and economizer before passing to the air heaters. In areas where
tight NOx emissions requirements have been established and post-combustion control is needed, SCR
NOx control systems are frequently installed between
the economizer and the air heater (see Chapter 34).
Water and steam flow Feedwater enters the bottom header of the economizer and passes upward
through the economizer to the outlet header. It is then
piped to the lower furnace area from which multiple
connecting pipes (supplies) are routed to the lower
furnace headers.
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The Babcock & Wilcox Company
Mix Bottle
Steam Separator
Roof Tubes
Economizer
Inlet
Economizer
Lower
Furnace
Headers
pletes the furnace tube pass and the fluid exits to the
upper furnace wall headers.
After discharging to the upper furnace wall headers, the fluid is piped to the front roof header, then
through the roof tubes to the rear roof headers where
mixing again takes place. It is then passed through a
pipe distribution system to the convection pass enclosure wall lower headers. The fluid flows up through
the wall tubes and the superheater screen. Pipes then
convey the fluid to a common header and then to the
primary superheater inlet header.
The fluid is collected and partially mixed before entering the primary superheater, then partially mixed
again as it flows from the primary superheater
through connecting piping to the secondary superheater. The furnace pressure control valves and connections to the boiler startup system (Chapter 19) and
the spray attemperator are contained in this connecting piping. The steam flows through connecting piping to the secondary superheater and finally to the
outlet header and discharge pipes, which terminate
at points outside of the unit penthouse. The superheated steam is directed to the high pressure section
of the steam turbine. After partial expansion in the
steam turbine (see Chapter 2), the low pressure steam
is returned to the boiler for reheating.
Advanced supercritical boiler designs
Vertical tube variable pressure boiler While the spiral wound furnace (SWUP) meets today’s market
needs for variable pressure operation, B&W is continuing the research and development of advanced
supercritical boiler designs.
The ideal furnace design would have vertical tubes
and be capable of variable pressure operation over the
load range while exhibiting natural circulation flow
characteristics (flow increasing as heat absorption increases), thus protecting the tubes from overheating.
The high mass fluxes required by the ribbed tubes used
Fig. 6 Typical fluid flow for a SWUP™ boiler.
From the furnace wall headers the fluid is then
passed upward through the first pass of vertical furnace tubes (Fig. 8). A transition section (Fig. 9) is provided some distance below the furnace arch and the
first pass tubes exit the furnace enclosure and connect to headers at this location. The fluid from the
various headers around the furnace circumference is
mixed together in common piping. This equalizes the
temperature of the fluid before it passes down to the
second set of lower furnace inlet headers and flows
upward through the second pass of vertical furnace
tubes. The second pass tubes exit the furnace enclosure at the transition section and connect to another
set of headers. The first and second pass are alternated
around the furnace circumference to maintain uniform wall temperatures.
From the second pass outlet headers, the fluid flows
through mix piping and on to the third pass inlet headers. The third pass furnace tubes form the furnace
enclosure from the transition section to the furnace
roof. In addition, furnace wing walls may be in a parallel flow circuit with the third pass tubes. This com26-10
Steam
Separator
Final
Superheater
Platen
Superheater
Intermediate
Superheater
Primary
Superheater
Primary
Superheater
Inlet
Fig. 7 Typical steam flow for a SWUP™ boiler.
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Fig. 8 1300 MW Universal Pressure (UPC) boiler for pulverized coal firing.
in the current UP boilers do not provide this characteristic. Instead, a ribbed tube design (Fig. 10) capable
of preserving the desirable departure from nucleate
boiling (DNB) characteristics (Chapter 5) at low mass
fluxes in the high heat flux zones is necessary. The
low mass flux is required to achieve the low dynamic
pressure loss necessary to achieve the self-compensating, natural circulation characteristic. A secondary benefit is a reduction in pressure loss through the boiler so
that the feed pump power is reduced and cycle efficiency
is slightly increased. Research continues in ribbed tube
development and the application of the advanced ribbed
tube designs to the boiler. (See Chapter 19.)
Higher temperature and pressure The supercritical
steam cycle provides an improvement in heat rate (efficiency) as compared to the subcritical steam cycle.
Steam 41 / Fossil Fuel Boilers for Electric Power
Additional gains in efficiency are possible as the cycle
temperature and pressure are further increased. Research continues in tube materials to develop higher
efficiency boiler and turbine systems.
Subcritical (drum) boilers
The B&W boiler for subcritical applications is the
Radiant boiler (RB), so named because the steam generation is by radiant heat transfer to the furnace enclosure tubes. Its components are pre-engineered with
sufficient flexibility to adapt the design to various fuels and a broad range of steam conditions.
In modern units, the furnace is a natural circulation, water-cooled, balanced draft design and usually
features dry ash removal. Superheater and reheater
surfaces are of the vertical pendant and/or horizon26-11
The Babcock & Wilcox Company
1st Pass
2nd Pass
3rd Pass
Bottle
2nd Pass
Outlet Header
Furnace
Membrane Wall
1st Pass
Outlet Header
Downcomer
From
Economizer
To Downcomer
and 2nd Pass
Inlet Header
Water/Steam Flow
Direction, Typical
3rd Pass
Intlet Header
Fig. 9 UP boiler furnace tube arrangement.
tal designs. Superheat temperature control is accomplished by an attemperator. Reheat temperature control is by gas proportioning dampers.
Range in capacity, steam output – about 700,000
lb/h (90 kg/s) to a maximum that may exceed
7,000,000 lb/h (880 kg/s).
Pressure – subcritical, usually 1800 to 2400 psi (12.4
to 16.5 MPa) throttle pressure with 5% overpressure capability.
Superheater and reheater outlet temperatures – as
required, usually in the range of 1000 to 1050F
(538 to 566C).
Radiant boiler for pulverized coal – Carolina
The steam generating unit shown in Fig. 11 is a balanced-draft Carolina-type Radiant boiler (RBC). It is
arranged with a natural circulation, water-cooled drybottom furnace, and superheater, reheater, economizer and air heater components. The unit is designed
to burn coal, usually pulverized to a fineness of which
at least 70% passes through a 200 mesh (75 micron)
screen. The horizontal convection pass and vertical
pendant heat transfer surfaces provide the benefits
of: 1) high temperature supports outside of the flue
gas stream, 2) minimal motion between the boiler roof
penetrations, and 3) more control over pendant section spacing in the design. The lower furnace height
compared to other pulverized coal designs also reduces
structural steel and erection costs.
Fuel flow Raw coal is discharged from the feeders
26-12
to the pulverizers. The pulverized coal is transported
by the primary air to the burners through a system
of pressurized fuel and air piping. The burners are located on the furnace walls with opposed firing (burners on the front and rear walls) being used for all but
the smallest units.
Air and gas flow Air from the forced draft fans is
heated in the air heaters, then routed to the windbox
where it is distributed to the burners as secondary air.
In the arrangement shown in Fig. 11, high pressure
fans provide air from the atmosphere to a separate
section of the air heater known as the primary section. A portion of the air from the primary fans is
passed unheated around the primary air heater as
tempering primary air. Controlled quantities of preheated and tempering primary air are mixed before
entering each pulverizer to obtain the desired pulverizer fuel-air mixture outlet temperature. The primary
air is used for drying and transporting fuel from the
pulverizer through the burners to the furnace.
Hot gases from the furnace pass successively across
the finishing banks of the superheater and reheater.
Before exiting the boiler, the flue gas stream is divided
into two parallel paths – one gas stream passing over
a portion of the reheater and the other stream passing over a portion of the superheater. Proportioning
the gas flow between these two paths as unit load
changes provides a tool for reheat steam temperature
control. The flow quantities are adjusted by a set of
dampers at the boiler exit. A controlled amount of gas
passes over a portion of the reheater to obtain the
reheater steam temperature set point and the remainSteam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Fig. 10a Single-lead ribbed tube.
Fig. 10b Multi-lead ribbed tube.
Fig. 10c Optimized multi-lead ribbed tube.
ing gas travels a parallel path across the superheater
surface. Attemperators are provided in the reheater
and superheater systems. The reheater attemperator
is used during transient loads and upset conditions,
with reheater spray quantities held to a minimum to
maximize cycle efficiency. Superheater spray is used
to maintain main steam temperatures. This arrangement of convection surface and damper system proSteam Platen Secondary Secondary
Drum
Superheater
Superheater
vides extended capability to obtain design steam temperatures in the superheater and reheater over a
broad load range.
The flue gases leaving the superheater and
reheater sections of the convection pass cross the
economizer. In new or recently retrofitted units, the
gas leaves the economizer and passes through an SCR
system to reduce NOx emissions before the gas travels
to the air heater. After the air heater, the gas passes
to the appropriate environmental control equipment.
Water and steam flow Feedwater enters the bottom
header of the economizer. The water passes upward
through the economizer tube bank into support tubing that is located between tube rows of the primary
superheater. The heated feedwater is collected in outlet
headers at the top of the unit, then routed into the
steam drum. As shown in Fig. 12, natural circulation
provides water flow from the steam drum down
through large diameter downcomer pipes to multiple
supply distributor tubes or supplies connecting to the
individual lower furnace headers. The fluid rises as it
is heated in the furnace tubes and passes through
riser tubes back into the steam drum.
The mixture entering the steam drum is separated
into steam and water flows by cyclone separators.
These provide essentially steam-free water to the
downcomer inlets. The steam is further purified by
passing it through the primary and secondary steam
scrubbers as discussed in Chapter 5.
As illustrated in Fig. 13, steam from the steam
drum passes through multiple connections to a header
supplying the furnace roof and convection pass rear
Final Reheat
Superheater
Primary
Superheater
Primary
Reheater
Economizer
SCR
Furnace
Catalyst
Air Heater
Pulverizer
Forced Draft Primary Air
Fan
Fan
Fig. 11 Carolina-type Radiant boiler (RBC) for pulverized coal firing.
Steam 41 / Fossil Fuel Boilers for Electric Power
Fig. 12 Typical furnace circulation diagram for a Radiant boiler (RB).
26-13
The Babcock & Wilcox Company
flows through the reheater tube bank to the reheater
outlet header (RHSH outlet). Reheated steam is then
routed to the intermediate pressure and then low pressure sections of the steam turbine-generator set.
Fig. 13 Typical steam-cooled roof and convection pass enclosure
wall circuits for a Radiant boiler (RB).
wall tubes, which directly connect to the primary superheater inlet header. Steam leaving the drum is also
routed to a series of headers, which provide cooling
steam for the convection pass side walls, before being
directed to the primary superheater inlet header.
As shown in Fig. 14, the steam rises through the
primary superheater, discharges to its outlet header
and flows through connecting piping equipped with
a spray attemperator. The partially superheated steam
then enters the secondary superheater and flows
through the various superheater sections to its outlet
headers and discharge pipes, which terminate at
points outside of the unit penthouse. The superheated
steam is directed to the high pressure section of the
steam turbine. After partial expansion in the steam
turbine (see Chapter 2), the low pressure steam is
returned to the boiler for reheating.
The low pressure steam is re-introduced to the
boiler at the reheater inlet header (RHSH inlet) and
Fig. 14 Superheater, reheater and economizer circuits for a
Radiant boiler (RB).
26-14
Radiant boiler for pulverized coal – Tower
An alternate configuration of the Radiant boiler is
the Tower design (RBT) shown in Figs. 15 and 16. A
special feature of this design is that all surfaces are
drainable. This feature was initially designed for service in northern latitudes to provide freeze protection
by arranging the superheater, reheater and economizer sections so that they are drainable. The Tower
design is a single gas path, as compared to the parallel gas path of the RBC, and therefore, has no inherent provision for steam temperature control other than
spray attemperation. The Tower design may be
equipped with gas recirculation and tempering for
extended superheater and reheater temperature control range. Additional advantages of the Tower design
include more uniform gas flow entering all convection
sections, minimum tube bend erosion potential because of no convection pass turns, and removal of most
of the ash and slag through the main furnace hopper. However, the Tower design requires a much taller
structure and generally results in a longer erection
schedule due to the single erection path as compared
to the RBC design.
General characteristics of the design are watercooled furnace, balanced draft, natural circulation, top
supported and drainable. The draining feature is accomplished by placing all steam- and water-contained
Fig. 15 400 MW Tower-type Radiant boiler (RBT) for pulverized
coal firing.
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
for superheater steam temperature control. Steam enters the secondary superheater and flows through the
tube sections to the outlet header, which discharges
to a terminal located outside of the unit. The superheated steam is directed to the high pressure section
of the steam turbine. After partial expansion, low pressure steam is then returned to the boiler for reheating.
Steam returned to the boiler is introduced at the
reheater inlet header. The steam flows through the
reheater tube bank and is then routed to the outlet
header and steam piping connection before being sent
to the intermediate and low pressure sections of the
steam turbine-generator.
Fig. 16 Four 400 MW RBT boilers and three 600 MW RBC boilers in
Southeast Asia.
surfaces in the horizontal position so that they may be
completely drained when the unit is taken out of service.
Fuel flow Similar to the RBC, the RBT is arranged
so that raw coal is discharged from the feeders to the
pulverizers. Primary air is used to transport the pulverized coal from the pulverizers to the burners
through a system of pressurized fuel and air piping.
Air and gas flow Air is introduced to the RBT in the
same pattern as the RBC. The geometric differences
of the two units create varying paths for gas flow. The
hot gases from the furnace pass vertically up and over
the superheater and reheater banks located in the
upper section of the boiler. The flue gas is then directed
down to the economizer located outside of the boiler
setting, finally passing to the SCR (if required) and
air heater system, and then to the environmental control equipment for cleanup.
Water and steam flow Feedwater is introduced to the
boiler system through the economizer where it is
heated and discharged through a header/piping system to the steam drum. With this natural circulation
system, the furnace circuitry follows the same general
flow patterns as the RBC described above.
Saturated steam from the steam drum is directed
through a series of pipes down to the outlet of the furnace, where a small bank of primary superheater
tubes (primary superheater 1) is placed with its outlet tubing forming the internal steam-cooled support
structure for the other banks of surface located farther up in the gas stream.
Steam from the support tubing is collected and directed to the finishing banks of primary superheater
2. The primary and secondary superheaters are connected with piping that contains a spray attemperator
Steam 41 / Fossil Fuel Boilers for Electric Power
Radiant boiler for anthracite – Downshot
The use of anthracite is limited to a relatively few
locations in the world, mainly Spain and parts of Asia.
Anthracite presents a special challenge for combustion due to its very low volatile matter content. As a
result, a special furnace configuration is used to improve combustion. The furnace is arranged so that the
burners fire downward into the lower furnace. The
flame shape in this opposed-firing arrangement is in
the form of a W, hence the name of the boiler style,
the RBW. A typical steam generating unit is shown in
Fig. 17.
Except for the lower furnace and the combustion
system, this design is very similar to the RBC. The
downshot firing arrangement provides increased residence time in the lower furnace. The lower furnace is
refractory lined to minimize heat loss and to maintain
peak flame temperature for high combustion efficiency. In addition, the anthracite fineness is increased, compared to normal coal, to 90% passing
through a 200 mesh (75 micron) screen, to further
enhance combustion efficiency.
The boiler is arranged with a water-cooled dry-bottom furnace, and superheater, reheater, economizer
Steam Drum
Platen
Superheater
Final
Reheater
Intermediate
Superheater
Final
Superheater
Primary
Reheater
Primary
Superheater
Economizer
Refractory
Coal
Bunker
Burners
Furnace
Air
Heater
Coal
Feeder
Gas
Outlet
Coal
Pulverizer
Primary
Air Fan
Forced
Draft Fan
Fig. 17 300 MW RBW boiler for pulverized anthracite (downshot).
26-15
The Babcock & Wilcox Company
and air heater components. The horizontal convection
pass and vertical pendant heat transfer surfaces provide the benefits of: 1) high temperature supports outside of the flue gas stream, 2) minimal motion between
the boiler roof penetrations, and 3) more control over
pendant section spacing in the design. The lower furnace height compared to other pulverized coal designs
also reduces structural steel and erection costs.
Fuel flow Raw coal is discharged from the feeders
to the pulverizers. The pulverized coal is transported
by the primary air to the burners through a system
of pressurized fuel and air piping. The burners are located on the shelves of the furnace front and rear wall
so that they fire downward giving a flame pattern in
the shape of a W.
Air and gas flow Air from the forced draft fans is
heated in the air heaters, then routed to the windbox
where it is distributed to the burners as secondary air.
In addition, a portion of the air is introduced to the
lower portion of the lower furnace as staging air. The
staging air both increases the peak flame temperature
near the burners by decreasing the amount of excess
air and helps to draw the flame path down into the
furnace to increase residence time.
In the arrangement shown in Fig. 17, high pressure fans provide air from the atmosphere to a separate section of the air heater known as the primary
section. A portion of the air from the primary fans is
passed unheated around the primary air heater as
tempering primary air. The primary air is used for
drying and transporting fuel from the pulverizer
through the burners to the furnace. Generally, it is
desirable to achieve the maximum pulverizer fuel-air
mixture temperature possible. However, provisions are
included for mixing the preheated and tempering primary air before entering each pulverizer to provide
control of pulverizer fuel-air mixture temperature
during pulverizer start up and shut down. In addition, special provisions may be included for further increasing the temperature of the fuel/air mixture to
further enhance combustion.
Hot gases from the furnace pass successively across
the finishing banks of the superheater and reheater
in the same manner as described for the RBC boiler.
Water and steam flow The water and steam flow arrangement is the same as for the RBC boiler discussed
earlier.
Oil- and gas-fired utility boilers
The use of oil and gas as fuels for new utility boilers has declined except for selected locations and conditions, primarily the oil producing nations. This is due
in part to the price of these premium fuels and their
availability. At the same time, advancements in gas
turbine and gas turbine combined cycle systems
(Chapter 27) have made the use of oil and gas in these
systems more cost effective.
However, in selected cases, the proposed boiler location, fuel availability, local price or existing facility
constraints may make oil or gas the preferred fuel. In
addition, low sulfur oil- and natural gas-fired new utility boilers have the distinct advantage of low environ-
26-16
mental emissions; NOx, SO2 and particulate emissions
are less in these units.
Both the SWUP (and UP) and the RBC boiler designs can be used for oil and gas firing. However, for
subcritical applications a design different than the
RBC is normally used.
Fuels
Natural gas Natural gas (see Chapter 11) has the
fewest design restrictions of the major fuels because
it is relatively clean and easy to burn. If only natural
gas is burned, fuel storage facilities, ash hoppers, ash
pits and ash handling equipment are unnecessary.
Sootblowers can be omitted and dust collectors are not
needed. Control of heat input to the boiler furnace is
simplified. Heating surfaces can be arranged for optimum heat transfer and gas resistance (draft loss)
without consideration of ash deposits and erosion. The
total enclosure volume is at a minimum and the adaptability for outdoor service is increased.
Fuel oil Fuel oil (see Chapter 11) has many of the
desirable features of natural gas, including ease of
handling and elimination of ash hoppers and ash pits.
However, it requires storage, heating and pumping
facilities. Oils with high sulfur and vanadium contents
can cause troublesome deposits on surfaces throughout the unit. (See Chapter 21.) These deposits can be
minimized by arranging the heating surfaces for optimum cleaning by sootblowing equipment. Provision
should be made for water washing the furnace and
all convection surfaces when the unit is shut down for
maintenance. Air heater protection devices (a steam
coil or hot water coil) should be installed to prevent
gas condensation and acid attack on the gas side of
the air heater surfaces (see Chapter 20) and in the
equipment downstream of the air heater.
B&W Radiant boiler for natural gas and oil
The steam generator shown in Figs. 18 and 19 is
an El Paso-type Radiant boiler (RBE) unit. It is arranged with a water-cooled hopper-bottom furnace
and superheater, reheater, economizer and air heater
components. The unit is designed to use natural gas
and oil separately or in combination. The general characteristics of the Radiant boiler are discussed in Pulverized coal firing. The unique aspects of the El Paso
design are the elimination of the pendant convection
pass and the inclusion of the upflow and downflow
convection passes within the footprint occupied by the
boiler furnace. The flow rates and pressure ranges for
the coal-fired Radiant boiler are also applicable here.
Air and gas flow Air from the forced draft fan is
heated in the air heater and is distributed to the
burner windbox. Hot gases from the furnace pass successively over the horizontal secondary superheater
and reheater sections and one bank of the primary superheater. The gas then turns, flows downward and
crosses the remainder of the primary superheater and
economizer sections. It then travels out of the watercooled enclosure to the air heater. In new or recently
retrofitted units, the gas leaves the economizer and
passes through an SCR system to reduce NOx emissions before the gas travels to the air heater. After the
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Fig. 19 Two 300 MW RBE boilers in Egypt.
Fig. 18 El Paso-type Radiant (RBE) boiler for oil and gas firing.
air heater, the gas passes to the appropriate environmental control equipment.
Water and steam flow Feedwater enters the bottom
header of the economizer. The water flows upward
through the economizer and discharges through the
outlet header into piping that directs it to the steam
drum. By means of natural circulation, water flows
downward through downcomer pipes, then through
supply distributor tubes to the lower furnace headers.
It then rises through the furnace tubes (which enclose
the convection area) and flows to the upper headers
and through connecting riser tubes into the steam drum.
The steam-water mixture in the steam drum is
passed through cyclone separators, which provide
essentially steam-free water for the downcomers. The
Steam 41 / Fossil Fuel Boilers for Electric Power
steam is further purified by passing it through the primary and secondary steam scrubbers within the drum.
Steam from the drum passes through multiple connections at the rear of the convection enclosure into
the primary superheater inlet header.
The steam rises through part of the primary superheater and, by means of connecting tubes, is directed
into the remainder of the primary superheater in the
first gas pass. The flow discharges through the primary superheater outlet header into connecting piping equipped with a spray attemperator. The steam
enters the secondary superheater inlet header and
flows through the secondary superheater sections to
the outlet header and to a discharge pipe, which terminates outside the casing at the front of the unit.
Low pressure steam, introduced to the reheater inlet
header, flows through the reheater sections and out
through the reheater outlet header to a connection terminating outside the casing, also at the front of the unit.
26-17
The Babcock & Wilcox Company
This power plant features two B&W 420 MW variable pressure, supercritical boilers burning pulverized coal.
26-18
Steam 41 / Fossil Fuel Boilers for Electric Power
The Babcock & Wilcox Company
Chapter 27
Boilers for Industry and Small Power
Most manufacturing industries require steam for
a variety of uses. Basic plant heating and air conditioning, prime movers such as turbine drives for blowers and compressors, drying, constant temperature reaction processes, large presses, soaking pits, water
heating, cooking and cleaning are all examples of how
steam is used.
Steam produced by industrial boilers can also be
used to generate electricity in a cogeneration mode
which uses a conventional steam turbine for electric
power generation and low pressure extraction steam
for the process. The electricity is then used by the plant
or sold to a local electric utility company. As an alternate cogenerating system, a gas turbine can be used
for power generation with a heat recovery steam generator for steam.
Thousands of boilers are installed in industrial and
municipal plants, providing lower pressure and temperature steam than utility boilers dedicated to large,
central station electric power generation. In an industrial plant, the dependability of steam generating
equipment is critical. Most often, the industrial operation has a single steam plant with one or more boilers. If the steam flow is interrupted, production can
be seriously impacted. Accordingly, industrial boilers
must be very reliable because plant productivity relies
so heavily on their availability. Loss of a boiler for a short
time can stop production for days if, for example, materials cool and solidify in process lines. For this reason,
some industries prefer multiple smaller units.
The principles governing the selection of boilers and
related equipment are discussed in Chapter 37.
Proper equipment selection can be accomplished only
in the framework of a sound technical and cost evaluation. This requires a working knowledge and understanding of the performance of the different steam
generating unit components under various conditions,
including the significance of the many different arrangements of heat absorbing surfaces, the characteristics of available fuels, combustion methods and
ash handling. The owner must also establish the
present and future steam conditions and requirements. All pertinent environmental regulations must
also be considered. A brief summary of boiler specifications is provided in Table 1.
Steam 41 / Boilers for Industry and Small Power
Industrial boiler design
Industrial boilers generally have different performance characteristics than utility boilers. These are
most apparent in steam pressures and temperatures
as well as the fuel burning equipment.
Industrial units are built in a wide range of sizes,
pressures and temperatures – from 2 psig (13.8 kPa)
and 218F (103C) saturated steam for heating to 1800
psig (12.4 MPa) and 1000F (538C) steam for plant
power production.
In addition, industrial units often supply steam for
more than one application. For some applications, steam
demand may be cyclic or fluctuating, thereby complicating unit operation and control of the equipment.
The Babcock & Wilcox Company (B&W) industrial
boilers, such as the unit shown in Fig. 1, are water
tube design and generally rely upon natural circulation for steam-water circulation.
Most utility boilers are designed to burn pulverized
or crushed coal, oil, gas, or a combination of oil or gas
with a solid fuel. Industrial boilers can be designed for
the above fuels as well as coarsely crushed coal for stoker
firing and a wide range of biomass or byproduct fuels.
Table 1
Typical Industrial Boiler Specification Factors
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
Steam pressure
Steam temperature and control range
Steam flow
Peak
Minimum
Load patterns
Feedwater temperature and quality
Standby capacity and number of units
Fuels and their properties
Ash properties
Firing method preferences
Environmental emission limitations sulfur
dioxide (SO2), nitrogen oxides (NOx),
particulate, other compounds
Site space and access limitations
Auxiliaries
Operator requirements
Evaluation basis
27-1
The Babcock & Wilcox Company
Many industrial processes generate byproducts
which can serve as boiler fuels, significantly contributing to the plant operating efficiency and effectively
reducing product cost. Examples of these are gas products from the steel industry (blast furnace and coke
oven gas), products from the petroleum industry (carbon monoxide (CO), refinery gas, petroleum coke),
products from agriculture (sugar mill bagasse, peanut
hulls, coffee grounds), waste from the pulp and paper industry (wood, bark, process chemicals, sludge)
and municipal solid waste. Steam generation and fuel
handling for some of these fuels and applications have
become quite specialized. This chapter and the following chapters are devoted to these units:
Chapter 28 – Chemical and Heat Recovery in the
Paper Industry
Chapter 29 – Waste-to-Energy Installations
Chapter 30 – Wood and Biomass Installations
Chapter 31 – Marine Applications
One of the distinguishable features of most industrial boilers is a large saturated water boiler bank between the steam drum and lower drum. (See Figs. 1
and 2.) The boiler bank serves the purpose of preheating the inlet feedwater to the saturation temperature and
then evaporating the water (generating steam) while
cooling the flue gas to a cost effective exit temperature.
In lower pressure boilers, insufficient heating surface is available in the furnace enclosure to absorb all
of the energy needed to accomplish this function. Therefore, a boiler bank located downstream of the furnace
and superheater (if included) in the flue gas stream
provides the rest of the necessary heat transfer surface.
As shown in Fig. 3, as pressure increases, the
amount of heat absorption required to evaporate water declines rapidly, and the absorption required for
superheating and water preheating increases. In
some modern very high pressure industrial units, a
smaller boiler module separate from the steam drum
provides the same function as the traditional boiler
bank (see Fig. 4), but at a lower cost.
A separate economizer and/or air heater can be used
downstream of the boiler bank to further reduce the
flue gas exit temperature to a more economic value.
Steam requirements
To assure prompt fulfillment of all steam demands,
i.e., the delivery of heat to all points of use at the required rates, it is necessary to select steam producing
equipment of sufficient capacity, range of output and
responsiveness. The demand may be steady, as in most
space heating systems, or it may fluctuate widely and
rapidly, as in a heavy forging plant. Many steam
heated processes, as in the initial heating of a liquid
batch, require high peak flows of short duration. Rapidly changing rates of steam flow characterize requirements to produce the electrical power to drive a steel
rolling mill. Combined cycle systems often require
rapid steam load responses during cycle transients.
The steam flow requirements should, therefore, be
accurately established for a number of conditions to
ensure that the boiler system selected will meet all of
Fig. 1 Two drum Stirling® power boiler system for pulverized coal with environmental control equipment.
27-2
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
Fig. 3 Effect of steam pressure on evaporation in industrial boilers –
100F (56C) constant superheat.
Fig. 2 Two drum Stirling® boiler for spreader-stoker firing.
its demand conditions, i.e., peak flow, maximum continuous flow (the usual steady maximum flow), minimum flow, and rate of change in flow.
The peak load will, of course, establish the top capacity for the steam producing equipment and all of its
auxiliaries. For widely fluctuating loads, it is advisable
to establish the 15 minute peak. In most systems, peaks
of shorter duration can be met by the storage of heat
inherent in the steam generating equipment.
Steam for process and heating The pressure of saturated steam (no superheat) used for process heating
is such that the corresponding condensing steam temperature is somewhat above the required temperature
of the materials to be heated. Generally, superheat is
of no value for this kind of service and is often undesirable because of its interference with temperature
control. Reclaiming or devulcanizing rubber, where
the rubber in a caustic solution is heated to 400F
(204C) by condensing saturated steam at 250 psig
(1724 kPa) and 407F (208C) in the jacket of the
devulcanizer, is a typical example of process heating
with steam.
Pressures of saturated steam for comfort heating of
buildings range from 2 psig (13.8 kPa) to as high as
Steam 41 / Boilers for Industry and Small Power
80 psig (0.55 MPa) in the case of space heaters. It is
seldom economical to distribute steam through long
lines at pressures below 150 psig (1.0 MPa) because
of piping costs. Furthermore, the usual requirements
for steam within the boiler house for sootblowers, feed
pumps and other auxiliaries make it desirable to operate boilers at a minimum of 125 psig (0.86 MPa).
Consequently, few steam plants of any size are operated below this pressure. If the pressure required at
points of use is lower, it is common practice to use pressure reducing stations at or near these locations.
The pressure required at the outlet of steam produc-
Fig. 4 Single drum Stirling® boiler for spreader-stoker firing.
27-3
The Babcock & Wilcox Company
ing equipment for process heating service usually
ranges from 125 to 250 psig (0.86 to 1.7 MPa) and superheat is usually not required. For this service, boiler
manufacturers have generally standardized on a pressure of 250 psig (1.7 MPa) for small water-tube boilers.
It is customary American stationary boiler practice
to hold the main steam line pressure practically constant for all loads, on the premise that this condition
satisfies all pressure and quantity requirements of the
steam-using equipment. Automatic combustion control apparatuses are accordingly designed to function
on this basis.
Cogeneration Many manufacturing operations,
such as in paper and textile mills, in the production
of chemicals and in processing rubber, require mechanical or electrical power as well as steam for process heating. For such cogeneration applications, studies are made of the relative merits and costs of: 1) a
plant where the power is purchased and steam is generated to supply the heating requirements only, and
2) a plant where steam and power are generated in
the same system. A sound appraisal of the relative
merits of the two alternatives requires knowledge of
the steam and power requirements, ability to correlate these requirements, economic studies and good
judgement. The following general summary may be
of assistance.
1. The basic economic advantage in generating steam
and power in the same system arises from the use
of a much larger portion of the heat supplied in
the fuel. When generating electricity alone, as
much as 60% of the heat supplied in the fuel is
lost to the condensing system, even in a modern
central station. (See Chapter 2.)
2. Despite this fundamental thermodynamic advantage, it is frequently more economical to purchase
power when it is available at reasonable rates from
a dependable source, except where:
a. waste fuels and waste heat, such as bagasse,
blast furnace gas, sawdust or hogged wood, and
hot gases are available at low cost from the plant
process, and
b. the steam heating and power demands are reasonably parallel and relatively large, i.e., 50,000
lb/h (6.3 kg/s) of steam or more.
3. Two approaches are used for cogeneration. Where
natural gas is available on site, a gas turbine can
be used to generate power, with the waste heat in
the turbine exhaust gas used to produce steam in
a heat recovery steam generator (HRSG). HRSGs are
discussed in more detail later in this chapter. Where
a waste fuel such as petroleum coke, bark, biomass,
tires or other fossil fuel such as coal is the economic
fuel of choice, a steam turbine topping cycle is used.
Here, high pressure high temperature steam is produced in the boiler system and is first passed through
a steam turbine to generate power. The exhaust steam
is then conditioned (brought to appropriate temperature and pressure) and sent to the process.
4. Variations in process heat and power demands
usually do not coincide. To compensate for the differences, a variety of options can be used depending upon the economic evaluation:
27-4
a. for a gas turbine-based system
1. If steam demand typically exceeds power demand, auxiliary burners are supplied with
the HRSG.
2. If electrical load demand typically exceeds
the steam demand requirements, the remainder of the power may be purchased
outside.
b. for a steam-based power system
1. If steam demand typically exceeds power demand, the turbine exhaust steam flow can
be supplemented with boiler auxiliary firing,
and then the additional steam can be passed
through a pressure reducing and attemperating
system.
2. If power demand is typically higher, either
an extraction condensing turbine system
can be used or the incremental power can
be purchased outside.
If the process requirements for steam and power
are reasonably parallel and steady, cogeneration, including capital, operating and maintenance costs, can
be beneficial. Where discontinuous service, low capacity factor or significantly different steam and power
requirements exist, electrical supply from the local
power grid and on-site steam generation is frequently
more cost effective.
Power generation Except for small isolated installations, the high speed turbine is the prime mover of
choice for steam power generation because of its efficiency, compactness and low cost. Continued improvement in reliability, reduction in cost, and availability
of packaged systems have made on-site power generation more popular. Where natural gas is available and
cost effective, simple gas turbines, especially package
units, have tended to dominate on-site power production needs. Where a waste fuel (or low cost coal) is
available, a boiler and steam turbine system can prove
to be the most economic system to supply on-site power.
The selection of steam pressure and temperature for
such systems depends upon an economic evaluation
along the guidelines presented in Chapter 37. Steam
temperature control using one or more of the methods outlined in Chapter 19 is usually provided when
electrical output exceeds 25 MW. Steam temperature
control is also very important where variations in the
flow of the fuel and the fuel quality would otherwise
lead to wide swings in power output.
Combined cycles
The concept of using waste energy for increased
steam generation in industry has been around for
many years. The progressive increase in fuel costs, the
need to capture heat from various industrial processes,
and the increasingly stringent environmental regulations have created the need for using waste heat to
its fullest potential.
In the power industry, the waste heat from one
power system such as a gas turbine can serve as the
heat source for a steam turbine cycle. Such combined
cycles can push overall electrical power cycle efficiency
to nearly 50%. Overall energy use can substantially
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
exceed even this level when electrical generation is
combined with process steam use.
Industries such as steel making, oil refining, pulp
and paper, and food processing have used many
unique steam generating systems to get the most out
of their waste heat. These systems allow reduced consumption of traditional fuels, recovery of waste heat
for safety and economy, and elimination of process
byproducts.
In its broadest terms, a combined cycle plant consists of the integration of two or more thermodynamic
power cycles to more fully and efficiently convert input energy into work or power. With the advancements
in reliability and availability of gas turbines, the term
combined cycle plant today usually refers to a system
composed of a gas turbine, heat recovery steam generator and a steam turbine. Thermodynamically, this
implies the joining of a high temperature Brayton gas
turbine cycle with a moderate and low temperature
Rankine cycle – the waste heat from the Brayton cycle
exhaust serves as the heat input to the Rankine cycle.
The challenge in such systems is the degree of integration needed to maximize efficiency at an economic
cost. Chapter 2 discusses the thermodynamic processes
and benefits of this application.
The following brief discussion focuses on the combination of a gas turbine with a heat recovery steam
generator and steam turbine.
Simple combined cycle system
As shown schematically in Figs. 5a and 5b, the
simple combined cycle system can consist of a single
gas turbine-generator, HRSG, single steam turbinegenerator, condenser, and auxiliary systems. In addition, if the environmental regulations require, a
selective catalytic reduction (SCR) system to control
emissions of nitrogen oxides (NOx) can be directly integrated within the steam generator. (See Chapter 34.)
This is particularly attractive because the SCR catalyst can be positioned in an optimal temperature window within the HRSG. The gas temperature leaving
the gas turbine is usually in the range of 950 to 1050F
(510 to 566C) while the optimal SCR catalyst temperature is 650 to 750F (343 to 399C).
A variety of more complex configurations are possible. A key improvement in the steam cycle efficiency
can be obtained by adding multiple separate pressure
circuits to the HRSG to supply low pressure steam for
deaeration and feedwater heating. This replaces the
steam extraction regenerative feedwater heating used
in conventional steam power cycles.
Commercial combined cycle systems
Actual configurations are typically more complex
because of application requirements and the degree
of integration. The gas turbine-generators and steam
turbine-generators are commercially available in a
number of specific sizes and arrangements. HRSGs
are built from standardized components to suit a wide
variety of steam uses and turbine exhaust conditions.
Frequently, multiple gas turbines with HRSGs may
feed a single steam turbine system. A gas bypass stack
and silencer are typically installed downstream of the
gas turbine so that it can be operated independently
of the steam cycle. With the high levels of oxygen remaining in the gas turbine exhaust, supplemental firing systems can be installed upstream of the HRSG.
This permits greater operating flexibility, improved
steam temperature control, and higher overall power
capacity. The HRSG can be designed with one to four
separate operating pressure circuits to optimize heat
recovery and cycle efficiency. In selected cases, further
cycle efficiency gains are possible with the addition of
steam reheat.
A range of cycle efficiencies is possible depending upon
the complexity of the system and components. Sample
overall electrical power generation cycle efficiencies for
a system using a gas turbine with a 2200F (1204C) turbine inlet temperature are provided in Table 2. These
are based upon the fuel higher heating value.
The environmental emissions from combined cycle
systems are generally low. If natural gas is fired, sul-
Fig. 5 Simplified combined cycle system schematics.
Steam 41 / Boilers for Industry and Small Power
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The Babcock & Wilcox Company
Table 2
Sample Cycle Efficiencies and Heat Rates
System
Efficiency (%)
Simple gas turbine
Gas turbine plus unfired
single pressure steam cycle
Advanced gas turbine plus
unfired multiple pressure
steam system
Gas turbine plus dual pressure
steam system plus process
steam use (cogeneration)
Heat Rate
(Btu/kWh)
32
10,700
42
8200
48
7100
61
Note: All values are calculated using the higher heating
value (HHV) of the fuel. Use of the lower heating value
(LHV) of the fuel would increase the efficiencies listed.
fur dioxide (SO2) and particulate emissions will be negligible. With current gas turbine combustor designs,
NOx emissions from the gas turbine will be low, ranging generally between < 9 and 70 ppm. The final NOx
emissions then depend upon the supplemental firing
system used (if any) and the potential incorporation
of an SCR NOx control system.
Beyond thermal efficiency and low environmental
emissions, potential benefits of a gas turbine combined
cycle plant include:
Schedule
Depending upon equipment size and complexity, delivery and construction of the
gas turbine can take about one year. The
steam turbine cycle system delivery and
erection can frequently be completed in an
additional year. (See Fig. 6.)
Flexibility The gas turbine can be used alone for
rapid startup and peaking service. The
HRSG boiler system can usually be
brought from a cold start to full load steam
generation in about 60 minutes.
Capital
The system capital cost is typically low as
a result of smaller standardized components, modular construction, prompt delivery, rapid erection, and minimum support system costs.
Boiler reliability is directly related to water quality,
as discussed in Chapter 42. The lack of proper water
quality is frequently the cause of failure and lack of
availability in industrial boilers. As pressures and temperatures have increased, so has the required level of
water quality. However, the need for water quality is
often underestimated and the result is expensive downtime for pressure part replacement. Higher water quality translates to higher steam quality, which is needed
to protect superheaters and turbines.
The use of a spray water condenser (see Chapter
25) was a step taken to produce higher quality spray
water to minimize the steam contamination that is
often prevalent when using feedwater for spray
attemperation. A sample condenser installation is
shown in Fig. 7.
The maximum allowable boiler-water concentration
(total solids in boiler water) in relation to the pressure
at the outlet of a steam generating unit (applicable to
the boiler types in the following descriptive outlines)
is given in Table 3.
It is evident that good water treatment practice
requires the proper attention be given to water quality throughout the boiler system. This includes makeup
water, steam condensate, feedwater and boiler water.
One of the major concerns in boiler operation is the
prevention of fouling, regardless of operating pressure.
This becomes more severe as operating pressures increase; conditions which are not regarded as troublesome at lower pressures may be entirely unsatisfactory at higher pressures.
Other design requirements
The other factors affecting industrial boiler evaluation and selection as outlined in Table 1 are addressed in depth in Chapter 37. Key among these are
fuel and ash identification and evaluation. Chapters
9 and 21 address the characterization of fuels and the
effect of the noncombustible residue or ash on boiler
design. Chapters 11 through 17 discuss the various
fuel preparation and combustion systems which may
be used. The designs of the boiler, superheater, economizer and air heater systems are covered in Chapters
19 and 20 while auxiliaries are addressed in Chapters 24 and 25.
In the system selection, these benefits must be
weighed against the usually higher cost of the cleaner
premium fuels needed for the gas turbine, potential maintenance and availability issues, and load requirements.
Water treatment
Industry today is intensely competitive, and a
company’s survival may often depend on uninterrupted production. When industrial plants generate
their own power or when steam is required for the
manufacturing process, the availability of the boiler
becomes a very important consideration.
27-6
Fig. 6 Rapid installation of modular components minimizes schedules.
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
Fig. 7 B&W condenser-attemperator system supplies pure attemperator spray water by condensing steam from the steam drum with
incoming boiler feedwater.
Environmental control
Atmospheric emissions from industrial boilers and
other combustion sources have come under increasingly stringent regulation over the past 30 years. Pollutants emitted from fossil fuel fired industrial boilers
can include particulate matter (PM), nitrogen oxides
(NO x), sulfur oxides (SO x), carbon monoxide (CO),
volatile organic compounds (VOCs), and other compounds commonly referred to as HAPs (hazardous air
pollutants). These include hydrogen chloride and hydrogen fluorides (HCl and HF), mercury and other trace
metals, and trace organic compounds. The emissions
characteristics of industrial boilers are largely dependent on the type of fuel(s) combusted and the use of
selected air pollution control systems and technologies.
The United States (U.S.) Environmental Protection Agency (EPA) has promulgated various environmental performance standards that apply to different
sizes and classes of boilers firing both fossil and nonfossil fuels. The Federal New Source Performance
Standards (NSPS), codified under Title 40, Part 60 of
the Code of Federal Regulations (CFR), establish minimum requirements for many air emission sources
Table 3
Limits for Solids Content of Boiler
Water in Drum Boilers, ppm
Pressure at Outlet
of Steam Generating
Unit, psi
Total
Solids
51 to 325
326 to 450
451 to 600
601 to 750
750 to 900
900 to 1000
1000 to 1500
1501 to 2000
3500
3000
2500
2000
1500
1250
100
50
Total Suspended
Alkalinity Solids
700
600
500
400
300
250
20
10
Steam 41 / Boilers for Industry and Small Power
15
10
8
6
4
2
1
1
throughout the U.S. In 40 CFR Part 60, Subparts Db
and Dc specifically apply to fossil-fuel fired industrial
steam generating units with heat input capacities
greater than 100 million Btu per hour and greater
than 10 million Btu per hour respectively (2.9 and 29.3
MWt). The industrial boiler NSPS set minimum requirements governing allowable emissions of PM, SO2,
and NOx from units constructed or substantially modified after June 19, 1984. Additional subparts under 40
CFR 60 set emissions standards for other classes of
boilers including, but not limited to, electric steam generating units (40 CFR 60, Subpart Da), municipal waste
combustors (40 CFR 60 Subpart(s) Eb, Cb, AAAA and
BBBB), and chemical recovery boilers used in the pulp
and paper industry (40 CFR 60, Subpart BB).
A large industrial power boiler with environmental control equipment is shown in Fig. 1. This pulverized coal-fired Stirling® power boiler (SPB), discussed
below, is equipped with low NOx burners to reduce NOx
emissions, an electrostatic precipitator (ESP) to control particulate emissions, and a wet flue gas desulfurization (FGD) system to control emissions of SO2.
The most common methods employed to control NOx
emissions from industrial boilers involve combustion
modifications using low NOx burner designs, staged
combustion with overfire air ports, and flue gas recirculation techniques (see Chapters 11 and 14). Fluidized bed boilers, discussed in Chapter 17, can achieve
very low NOx emission rates due, in part, to the inherently low furnace combustion temperatures. If
needed, post-combustion control technologies, including selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR) systems (see Chapter 34), can be used to achieve additional NOx reductions on many industrial boiler applications.
CO and VOC emissions are best controlled by employing prudent combustion system design and operating practices The combustion system should facilitate good air/fuel mixing and allow for adequate residence time at required temperatures. Traditionally this
has been referred to as the three Ts of combustion:
time, temperature, and turbulence. Any combustion
technique used to achieve low NOx levels must be balanced to account for associated (negative) impacts on
CO and VOC emissions.
To achieve compliance with current day particulate
emission standards, most industrial boilers firing fuels other than a clean gas must utilize high efficiency
particulate control equipment; typically a fabric filter
(baghouse) or an electrostatic precipitator (ESP). (See
Chapter 33.) Baghouses and ESPs can also effectively
control HAPs (trace organic and metal compounds)
that are affixed to the particulate matter.
The required levels and methods of SO2 control are
primarily driven by fuel choice. SO2 controls are generally not needed if an industrial unit burns a clean
fuel such as natural gas or a low sulfur fuel oil. While
the use of low sulfur coal is still feasible for many older
or smaller industrial boilers, the current NSPS regulation applicable to large industrial coal-fired boilers
mandate the use of SO2 control technologies capable
of achieving 90% removal efficiency. Available postcombustion SO2 controls include both dry and wet
27-7
The Babcock & Wilcox Company
FGD systems. (See Chapter 35.) Fluidized-bed boilers, discussed in Chapter 17, offer an alternative to
FGD systems. These boilers are capable of achieving
very high SO2 removal rates via limestone addition directly into the combustion process (bed).
The combination of FGD systems with efficient particulate control has shown the potential for effective
control of many HAPs. It is anticipated that the EPA’s
future HAP regulations may require retrofits of these
combined controls on most large (new and existing)
coal-fired industrial boilers.
B&W boilers for solid and multifuel applications
Brief descriptions of the boiler types that follow are
intended to introduce the types of steam generating
units that meet the wide range of fuel and performance requirements of the industrial sector.
Stirling® power boilers
Description The Stirling Power Boiler (SPB) is a top
supported, two drum, single gas pass unit. (See Figs.
1 and 2.) In some cases, it is cost effective to replace
the two drum design with a single drum and a smaller
shop-assembled boiler module. (See Fig. 4.)
The furnace is completely water cooled using membrane wall construction [normally 3 in. (76.2 mm) tubes
on 4 in. (101.6 mm) centers] and is satisfactory for either pressurized or balanced draft operation. Shop assembly of wall panels is maximized to facilitate field erection. Wall panels always come with the headers attached,
regardless of the number of shipping pieces.
Cyclone steam-water separators, discussed in Chapter 5, along with primary and secondary steam scrubbers, are included in the steam drum to provide the
high quality dry steam needed for present day superheater and turbine designs.
Furnaces include a nose arch which serves to direct gas flow over the superheater section and to shield
the superheater.
SPBs are capable of firing solid, liquid or gaseous
fuels. There are several furnace configurations to
complement the type of fuel fired, as shown in Fig. 8.
A hopper-bottom furnace is used for pulverized coal
firing; a flat floor for gas or oil firing; and an open
bottom to receive a stoker for stoker coal, wood, bagasse, biomass, refuse-derived fuel (RDF) and as-received municipal solid waste (MSW).
Furnaces for fuels having a significant amount of
fines and/or high moisture such as wood, biomass,
bagasse and RDF are arranged with an overfire air
system consisting of multiple rows of nozzles. These
nozzles inject air at various locations above the grate
to provide the turbulence necessary for combustion.
The SPB is equipped with an economizer and/or air
heater to provide economical heat recovery. For many
fuels, air heating is important for combustion. Pulverized coal requires hot air to dry the fuel, and hot air is
required to promote combustion of moist fuels such as
wood, bagasse and biomass.
Because of the design features, the SPB is the preferred industrial boiler for many applications. There
27-8
are some other designs that serve special fuels, capacities, pressures and temperatures, making them a good
alternative under special conditions.
Pre-engineering While the SPB is custom designed
to meet specific steam and fuel conditions, the design
is done within a framework of pre-engineered components to minimize engineering costs and delivery time.
The furnace width and depth are pre-engineered
in 1 ft (0.3 m) increments so that all of the closures at
the corners are established. Drum centerlines, in 2 ft
(0.6 m) increments between 16 and 32 ft (4.9 and 9.8
m), have been pre-engineered to locate all of the access doors, sootblower openings, buckstays and platforms. Combinations of steam and lower drum sizes
are designed so that all of the bend angles for drum
entry are established.
These pre-engineered increments allow flexibility
in the design to satisfy the job-specific requirements
of furnace exit gas temperature, burner clearances,
residence time, grate size, gas velocity, convection
surface spacing, etc.
SPB design range
Steam capacity
pulverized coal, oil, gas up to 1,200,000 lb/h
(151.2 kg/s)
stoker coal
150,000 to 400,000 lb/h
(18.9 to 50.4 kg/s)
stoker wood, bagasse, 180,000 to 600,000 lb/h
and biomass
(22.7 to 75.6 kg/s)
Steam pressure to
2200 psig (15.2 MPa)
design
Steam temperature to
1000F (538C)
Towerpak® boiler
Description The Towerpak is a version of the SPB
designed for lower capacities that are often required
by smaller industrial plants. (See Fig. 9.) It incorporates many of the features of the SPB including membrane walls, cyclone steam-water separators, and stokers for wood or biomass combustion.
Towerpak boilers are one drum or two drum bottom
supported units. For the smaller sizes, they can be
shipped in a single unit or in modules for ease of field
assembly (see Fig. 10). Larger units follow the SPB
format of maximum subassembly of wall panels,
again for ease of field assembly. This unit is a preferred
design at low steam capacity for hard to burn solid
fuels such as wood, biomass and stoker coal.
Pre-engineering Like the SPB, these units are custom
designed to meet specific conditions for each application,
but within the framework of pre-engineered components.
Towerpak design range
Steam capacity
40,000 to 300,000 lb/h
(5.0 to 37.8 kg/s)
Steam pressure to
1800 psig (12.4 MPa)
design
Steam temperature to 1000F (538C)
Circulating fluidized-bed boiler
Description Fluidized-bed boilers feature a unique
concept of burning fuel in a bed of particles to control
the combustion process and, when required, control
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
SO2 and NOx emissions. Two options are offered – the
circulating fluidized-bed boiler (CFB) and the bubbling fluidized-bed boiler (BFB). (See Figs. 11 and 12.)
Both options can be used in new as well as in retrofit
applications. Fluidized-bed technologies are discussed
in depth in Chapter 17.
The CFB is a top supported boiler. (See Fig. 11.) One
or two drums are used depending on the need for a
generating bank to absorb heat. Fuel is admitted to the
lower part of the furnace by screws, air-assisted gravity chutes or pneumatic feed, depending on fuels fired
and plant design.
The bed medium is typically composed of fuel ash
and sulfated limestone particles (limestone is used as
a sorbent for SO2 removal). When firing low-ash and
low-sulfur fuel, additional inert bed material (typically
sand) may be introduced into the furnace. Compared
to the fuel quantity present in the unit, the circulating bed material is many times greater. Total solids in
the flue gas passing upwards through the furnace are
a function of how much heat must be absorbed by the
waterwalls.
Varying the bed density maintains the desired constant temperature necessary for maximum SO2 removal [about 1550F (843C)]. The B&W Internal Recirculation CFB (IR-CFB) design features a two-stage
Fig. 8 Typical Stirling® power boiler furnace configurations.
Steam 41 / Boilers for Industry and Small Power
27-9
The Babcock & Wilcox Company
solids collection system comprising U-beam particle
separators (U-beams) at the furnace exit and a multicyclone dust collector (MDC) at the top of the convection downpass. Solids laden flue gas exits the furnace
to U-beams where 90 to 95% of the solids are collected
and directly (internally) returned to the furnace. Flue
gas exiting the U-beams proceeds over convection
surfaces, similar to other boiler designs. About 90% of
the solids passing the U-beams are further collected
by the MDC. The recirculation rate from the MDC is
controlled to provide the flow necessary to maintain
the required bed temperature and density.
The CFB has been selected for application with
high-sulfur, high-ash and various waste fuels such as
petroleum coke, waste coal, sludge, oil pitches, etc. It
is also used for wood and other biomass fuels, howFig. 10 Field assembly of a Towerpak® boiler.
Steam Drum
Boiler
Bank
ever the bubbling fluidized bed is often a more economical choice for these fuels. The CFB, because it
operates at a reduced combustion temperature, inherently generates about one half the NOx as the other solid
fuel-fired industrial boilers previously described.
The CFB is an alternative to the pulverized coal or
stoker coal-fired SPB which frequently must be
equipped with a wet or dry scrubber (for SO2 removal)
and ammonia injection, catalytic or non-catalytic reduction (NOx removal) equipment. The choice of technologies requires in depth evaluation of a number of
factors including required amount of emissions removal, fuel cost, reagent cost and capital cost.
Pre-engineering The CFB is custom designed to meet
each specific application, but like the SPB, it is designed
within a framework of pre-engineered components to
minimize engineering costs and delivery time.
Burners
In-Furnace
U-Beams
U-Beams
Superheater
Steam Drum
PrecisionJet
Air System
Fuel
Chute
Lower
Drum
PrecisionJet
Air System
Feedwater
to Drum
Downcomer
Internal
Evaporative
Circuit
Multi-Cyclone
Dust
Collector
Wingwall
Fuel Bunker
Economizer
Ash
Recycle
System
Air
Heater
Gravimetric
Feeder
Fuel
Chute
Flue
Gas
Refractory
Line
Fluid Bed
Cooler
Secondary Primary
Air Duct to
Steam Coil
Air Duct Air Duct Fluid Bed Cooler Air Heater
Fig. 9 Towerpak® boiler.
27-10
Fig. 11 Top supported circulating fluidized-bed boiler.
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
Superheater
Generating Bank
Economizer
Load
Burners
Sludge Bin
Coal
Chutes
Steam
Coil
Air Heater
Sludge
Chutes
Startup
Burners
Fluidized
Bed
The combustion process uses an inert material, typically sand, and fuel to form a bed in the bottom of the
furnace. This bed is suspended by a stream of upwardly flowing fluidizing air. Fuel introduced to the
bed is quickly volatized. A significant amount of volatiles escape the bed and are burned in the freeboard
area above the bed using overfire air. The remaining
volatiles and fixed carbon burn in the bed. To achieve
efficient combustion and low emissions, the bed temperature is controlled in the range of 1350 to 1650F
(732 to 899C).
The BFB is particularly well suited for high moisture waste fuels such as sewage sludge, and various
sludges produced in pulp and paper mills and recycle
paper plants, but can also burn a variety of other fuels including wood wastes, bark, coal, tire derived fuel,
oil and natural gas.
Pre-engineering The BFB is custom designed to meet
each specific application, but like the SPB and
Towerpak, this is done within a framework of pre-engineered components.
Steam Drum
Attemperator
Generating
Bank
Ash
Conveyors
Secondary
Air Fan
Fluidizing
Air Fan
Superheater
Fig. 12 Bottom supported bubbling fluidized-bed boiler.
CFB design range
Steam capacity
Steam pressure to
Steam temperature to
Screen
up to 1,500,000 lb/h
(189 kg/s) or greater
2850 psig (19.7 MPa)
design
1040F (560C)
Economizer
Bubbling fluidized-bed boiler
Description The bubbling fluidized-bed (BFB) boiler
is also a version of the Stirling power boiler in many
ways. The unit can be top supported or bottom supported, can be a one or two drum design, and can burn
a wide variety of fuels cleanly and efficiently. A bottom supported design similar to a Towerpak boiler (see
Fig. 12) can be supplied for steam flow capacities up
to 300,000 lb/h (37.8 kg/s). BFB technology is ideal
for repowering an existing facility, recovery boiler conversion (Fig. 13), or when changing fuel or firing techniques of an existing boiler. It is particularly attractive in retrofit applications where the bottom of an
existing furnace (including a stoker) can be removed
and replaced with a bubbling fluidized-bed without
major modifications to the balance of the furnace, convection pass enclosures and heat transfer surfaces.
Such conversions have been effective in regaining
boiler capacity lost because of a fuel change or a change
in ash characteristics which are not compatible with
the original boiler furnace design. Such retrofits also
provide one option to reduce sulfur dioxide and nitrogen oxides emissions from industrial and small utility
boilers.
Steam 41 / Boilers for Industry and Small Power
Ammonia/Urea
Injectors
(SNCR)
Burners
Refractory
Line
Overfire
Air
System
Startup
Burners
Fuel
Spouts
Fluidized
Bed
Ash
Conveyors
Fig. 13 Bubbling fluidized-bed retrofit of a recovery boiler.
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The Babcock & Wilcox Company
BFB design range
Steam capacity
Steam pressure to
Steam temperature to
60,000 to 700,000 lb/h
(7.5 to 88.2 kg/s)
2400 psig (16.5 MPa)
950F (510C)
B&W boilers for oil and gas applications
Boilers in this category have several similarities
attributable to the fuel characteristics of oil and natural gas. Unlike coal-fired boilers, distillate oil and gas
units do not have to consider slagging and fouling issues. Furnaces and convection banks can be arranged
for optimum heat transfer. Some residual oils can be
erosive and can contribute to fouling which is addressed in unit selection. The boilers in this section are
all bottom supported.
FM boiler
Fig. 15 FM O-type boiler.
Description The FM is a shop-assembled (package),
two drum, bottom supported boiler. (See Fig. 14.) Package boilers can be shipped by rail, truck or barge. Most
FM units are a D-type boiler design and have the furnace on one side and boiler bank on the other, separated by a baffle wall. In a D-type unit, firing is parallel
to the drums toward the rear wall where the gas turns
180 degrees and flows frontward to the gas outlet.
B&W also provides an O-type FM boiler design
where the furnace is located between the two drums.
(See Fig. 15.) The flue gas splits at the rear of the furnace and flows forward through generating tube sections on each side of the furnace. Compared to the Dtype boiler layout, the O-type boiler has a center of
gravity that is on the unit centerline, which provides
advantages for shipping.
Gas-tight furnaces, using membrane construction,
are features of both the O and D boilers for pressurefired (forced draft fan only) operation. With today’s
advanced low NOx burner designs and steam separation technology, B&W offers rail-shippable units to
230,000 lb/h (29 kg/s).
In addition to burning oil and natural gas, these
units can burn a variety of gaseous and liquid fuels
such as landfill gas, refinery gas, and various waste
liquid fuels. Emissions on natural gas are typically 30
ppm NOx (0.036 lb/106 Btu), and 80 ppm NOx (0.1 lb/
106 Btu) on distillate oil. When required, 9 ppm NOx is
achievable on gas with advanced burners.
Pre-engineering The FM is totally pre-engineered
in frame sizes to satisfy the capacity range of this
package design. Series available are FM9, FM10,
FM103, FM106, FM117 and FM120. Pre-engineered
set furnace depths are the only variables in this series.
FM design range
Steam capacity
10,000 to 230,000 lb/h
(1.3 to 29.0 kg/s)
Steam pressure to
1250 psig (8.62 MPa)
Steam temperature to 800F (427C) on oil
850F (454C) on natural
gas (higher pressures and
temperatures available)
High Capacity FM boiler
Description The High Capacity FM (HCFM) boilers are extensions of the FM D-type boiler design. (See
Fig. 16.) High capacity boilers can be assembled in the
shop, at a barge dock or in the field. Shipping dimensions of these units require that they be shipped by
barge or ocean vessel.
The design is for oil and gas firing and uses membrane furnace walls for pressurized operation. Multiple burners are used for the increased capacity.
Pre-engineering Like the FM, these boilers are completely pre-engineered and set furnace depths are the
only variable.
HCFM design range
Steam capacity
HCFM
200,000 to 350,000 lb/h
(25.2 to 44.1 kg/s)
Steam pressure to
1050 psig (7.24 MPa) design
Steam temperature to 825F (441C)
PFM boiler
Fig. 14 Type FM integral furnace boiler – membrane wall construction.
27-12
Description Another higher capacity and design
pressure D-type boiler, the Power for Manufacturing
(PFM), is also designed for dock or field assembly. If
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
Fig. 16 High Capacity FM boiler.
shipped assembled, the size of these units requires
special handling at the installation site. (See Fig. 17.)
This design is also for gas and oil firing and uses a
membrane furnace for pressure operation. Again, multiple burners are used for the increased capacity.
Pre-engineering Like the FM and HCFM, this boiler
series, which includes PFM 140, 180, 220, 250 and
280, is completely pre-engineered and set furnace
depths are the only variable.
PFM design range
Steam capacity
200,000 to 600,000 lb/h
(25.2 to 75.6 kg/s)
Steam pressure to
1800 psig (12.4 MPa) design
Steam temperature to 1000F (538C)
perheater. A unique plenum encloses the upper front
wall, roof and rear of the unit. This plenum serves as
an integral air duct to the windbox and, with a division plate in the rear, a flue gas outlet. Either an air
heater or economizer is used to reduce exit gas temperature and heat recovery.
This design features a gas pass extending the full
length of the boiler bank. Flue gas flows horizontally
and parallel to the drums through the bank. A gas
baffle is used to direct the gas across the tubes in
multiple passes to maximize heat transfer.
An inverted loop, drainable superheater is located
behind a screen at the furnace outlet to protect it from
direct furnace radiation. This superheater location
gives a semi-radiant heat transfer characteristic that
produces a relatively flat temperature curve across the
load range. This temperature profile minimizes
attemperation for steam temperature control.
Cyclone steam separators with primary and secondary scrubbers are included in the steam drum to produce the high quality steam needed for present day
superheaters and turbines.
Pre-engineering The PFI unit is totally pre-engineered in a number of frame sizes to satisfy the capacity range of this boiler design. Several superheater arrangements are also pre-engineered for each frame size.
Units come in three different drum centerlines.
Each centerline has a specific furnace depth and three
or four furnace widths.
PFI design range
Steam capacity
100,000 to 700,000 lb/h
(12.6 to 88.2 kg/s)
Steam pressure to
1150 psig (7.9 MPa) design
Steam temperature to 960F (516C)
PFT boiler
Description The Power for Turbine (PFT) boiler was
developed as an extension of the PFI design to accommodate the development of higher pressure and temperature turbine cycles. This unit incorporates many
of the PFI features including: two drum, bottom supported, modularized furnace membrane walls [3 in.
PFI boiler
Description The Power for Industry (PFI) boiler is
a two drum, bottom supported, multiple gas pass unit
designed specifically to burn liquid and/or gaseous fuels. (See Fig. 18.) Due to the large furnace enclosure,
the PFI is an excellent choice for harder to burn
byproduct fuels such as blast furnace gas and refinery catalytic cracker CO gas.
The furnace is completely water cooled using membrane wall construction [2.5 in. (63.5 mm) tubes on 3
in. (76.2 mm) centers].
The PFI was developed for maximum shop assembly of components. For example, the furnace is shipped
in as few as ten membrane wall panels with headers
attached at the top and bottom. The panels include
two for each side wall and two each for roof, front wall
and floor. The burner throats are integral with the
front wall panel. The unit is bottom supported on
simple concrete piers and incorporates a drainable suSteam 41 / Boilers for Industry and Small Power
Fig. 17 PFM boiler in transit.
27-13
The Babcock & Wilcox Company
PFT design range
Steam capacity
300,000 to 800,000 lb/h
(37.8 to 100.8 kg/s)
Steam pressure to
1800 psig (12.4 MPa) design
Steam temperature to 1000F (538C)
Fig. 18 Type PFI integral furnace boiler.
(76.2 mm) tubes on 3.75 in. (92.25 mm) centers], drum
cyclones and a drainable superheater. (See Fig. 19.)
Some of the differences include an alternate pendant superheater (as shown in Fig. 19) and gas flow
path the full width of the boiler bank with flow in
vertical directions.
PFT units are particularly well suited to burn high
ash liquid fuels, blast furnace gas and CO gas because
cavities provide space for retractable sootblowers for
cleaning requirements.
Pre-engineering The PFT, like the PFI, is totally preengineered in a number of frame sizes. The unit is designed with two drum centerlines and several furnace
depths and widths to satisfy the capacity range of this
design.
Fig. 19 PFT integral furnace boiler.
27-14
Enhanced Oil Recovery steam generator
Description The Enhanced Oil Recovery (EOR)
steam generator (Fig. 20) was developed to meet a
market need, as the name implies. High pressure, wet
steam (approximately 80% quality) is produced by the
unit and then injected into underground strata containing heavy oils. The steam enhances the recovery
of oil by heating the heavy oil which reduces its viscosity and thereby aids in moving the oil to the producing wells.
A once-through steam water circuitry featuring all
series flow coils is used for smaller units. Feedwater
flows continuously in a single tube circuit through the
convective (economizer) section to the radiant (furnace) section where the water is boiled to 80% (by
weight) steam quality level. A multiple pass parallel
flow design is used on larger units.
By maintaining wide flame clearances from the radiant walls (i.e., no direct flame impingement) and low
heat releases, relatively poor feedwater (5000 ppm
solids) can be tolerated. This permits minimal
feedwater treatment and allows the water that is separated from the recovered oil to be recycled to the boiler
with minimum cleanup. As stated, high solids content
water is tolerable, however, near zero hardness is required to minimize the probability of solids depositing
in the tubes. Only about 80% of the feedwater is vaporized to provide sufficient liquid at the steam outlet
to keep water-soluble solids in solution.
Control of the process is achieved by pumping the
required amount of feedwater at the specified pressure [up to 2500 psig (17.2 MPa)] into the convective
section and by regulating the burner firing rate to
maintain measured outlet steam quality.
Units are typically fired with natural gas or heavy oil.
Pre-engineering and design range Units come in
pre-engineered sizes from 5 to 50 × 106 Btu/h (1.5 to
14.7 MWt) output. The units are shop-assembled with
units through 40 × 10 6 Btu/h (11.7 MW t) trailer
Fig. 20 Enhanced oil recovery boiler on location.
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
mounted in one piece for shipment. Larger sizes are
shop-assembled in several sections for final field assembly. Unit capacities are limited by shipping constraints and not because of design limitations.
EOR design range (oil and gas)
Steam capacity
up to 250,000 lb/h (31.5 kg/s)
Steam pressure to 2500 psig (17.2 MPa) design
Low
High
Intermediate
Pressure
Pressure Pressure
Drum
Drum
Drum
Stack
Duct
Burner
Non-Metallic
Expansion
Joint
B&W boilers for specialty and waste
heat applications
Heat recovery steam generator
The heat recovery steam generator (HRSG) is sometimes referred to as a waste heat recovery boiler
(WHRB) or turbine exhaust gas (TEG) boiler. The latter designation indicates the main application for these
units today – waste heat recovery and steam generation from gas turbine exhaust gas. The HRSG is a key
element in a combined cycle plant affecting initial capital cost, operating cost, and overall cycle efficiency.
HRSGs are flexible in design depending upon the
specific application. The gas flow through the unit can
either be horizontal or vertical with a tradeoff being
made between the cost of floor space for the horizontal flow unit and structural steel requirements of the
vertical flow unit. The horizontal flow case is the most
common in North America, while the vertical design
is popular in Europe. The HRSG may be designed for
operation with multiple, separate pressure steam-water loops to meet application requirements and maximize heat recovery. Superheater or reheater surface
may also be employed to further increase cycle efficiency. Circulation may be forced or natural (see Chapter 5) with most horizontal gas flow units using natural circulation. HRSGs may be unfired, i.e., only use
the sensible heat of the gas as supplied, or may include supplemental fuel firing to raise the gas temperature to reduce heat transfer surface requirements,
increase steam production, control superheat steam
temperature, or meet process steam temperature requirements. Finally, HRSGs may be designed to incorporate an SCR or CO catalyst. (SCR catalysts are
discussed in Chapter 34.)
HRSGs are suitable for use with gas turbine sizes
from a small 1 MW unit up to modern machines exceeding 250 MW. See Figs. 21 and 22 for typical arrangements.
Heat recovery steam generators are designed to
handle the unique requirements of a variety of combined cycle systems. Depending on the cycle configuration, the HRSG may consist of one to four separate
boiler circuits (high pressure, two types of intermediate pressure and low pressure) within the same casing. The high pressure boiler is used for power generation [up to 1005F (541C) superheat]. The intermediate pressure boilers can be used for power generation, steam injection for NOx control (water or steam
injected into the gas turbine combustor to limit NOx
formation) and/or process steam. The low pressure
boiler is normally used for feedwater heating and/or
deaeration. Operating pressures can range from 300
Steam 41 / Boilers for Industry and Small Power
CO
Ammonia
Catalyst Injection Grid
SCR
Catalyst
Non-Metallic
Expansion
Joint
Fig. 21 Heat recovery steam generator (HRSG) arrangement.
to 1800 psig (2068 to 12,410 kPa) for the high pressure and intermediate pressure sections and 30 to 100
psig (206.8 to 689.5 kPa) for the low pressure section.
To accommodate rapid startup, the design includes
provisions for differential expansion between pressure
parts and nonpressure parts. Expansion joints are
used where a gas-tight seal is required.
HRSGs are designed to handle large gas flows with
minimal pressure drop, resulting in greater gas turbine net electrical output. Special consideration is also
given to the configuration of the interconnecting flue
gas ductwork, transitions, and diverter valves to minimize pressure losses caused by changes in flow patterns or excessively high velocities. Heat losses
through the boiler casing and ductwork are minimized
through the use of an insulation system.
In the natural circulation design, the vertical tubes
provide the pumping head necessary to develop sufficient circulation ratios for stable circulation. Circulation pumps are eliminated, therefore allowing plant
efficiency to be maximized. The forced circulation design consists of horizontal tubes with gas flowing vertically. Floor space requirements are minimized. However, the additional load imposed by the circulation
pumps reduces cycle efficiency.
Fig. 22 Large HRSG for enhanced oil recovery/cogeneration.
27-15
The Babcock & Wilcox Company
Once-through HRSG designs are also available. In
a once-through design, feedwater is converted directly
to superheated steam without the need for a drum.
As a result, there is no distinction between economizer,
evaporator or superheater surface. The water-to-steam
transition point is variable within the unit and is dependant upon the heat input and mass flow of the water.
Most heat recovery steam generators are too large
to permit shop assembly of an entire unit. Therefore,
most HRSG components are shop fabricated to the
maximum extent possible and delivered to the site as
modules. Typically, each module is structurally independent and includes lifting lugs and temporary steel
so that field transport and setting is readily accomplished. Some of the smaller HRSG units can be entirely shop-assembled and skid mounted.
Typical parameter ranges for HRSG units are summarized in Table 4.
Special HRSG designs are also available for enhanced oil recovery applications. The gas turbine exhaust gas is used in the HRSG to generate wet steam
(approximately 80% quality) at pressures up to 2500 psig
(17.2 MPa). The steam is injected into wells to enhance
heavy oil recovery. A unique feature is that relatively
dirty (up to 10,000 ppm dissolved solids) feedwater is used
in a once-through steam generator design.
Technical considerations The HRSG is basically a
counterflow heat exchanger composed of a series of
superheater, reheater, boiler (or evaporator), and
economizer sections positioned from gas inlet to gas
outlet to maximize heat recovery and supply the rated
steam flow at proper temperature and pressure. To
provide the most economical and reliable design, it is
necessary to evaluate the following:
1. Allowable back-pressure – Back-pressure is significantly influenced by the HRSG cross-sectional
flow area. Higher back-pressures reduce HRSG
cost but also reduce gas turbine efficiency. Backpressures are typically 10 to 15 in. wg (2.5 to 3.7
kPa) in most units.
2. Steam pressure and temperature – The steam
pressure and temperature are selected to provide
an economical design. In general, higher steam
pressures increase system efficiency but can limit
total heat recovery from the flue gas in single pressure HRSGs due to the higher saturation temperature. To overcome this problem, multiple pressure
HRSGs are offered. One to four separate pressure
sections may be used. The superheater, reheater,
boiler and economizer sections at each pressure are
arranged to reduce overall cost and increase heat
recovery.
3. Pinch point and approach temperatures – The
pinch point temperature and approach temperatures have a significant impact on overall unit
size. They are illustrated in Fig. 23 for a single
pressure HRSG. Small pinch point and superheater approach temperatures result in larger heat
transfer surfaces and higher capital costs, while
the economizer approach temperature is typically
set to avoid economizer steaming at the design
point. Experience has generally indicated that the
following ranges provide economical and technically satisfactory designs, although lower values
may be appropriate in specific applications:
Pinch point = ∆Tp = 20 to 50F (11 to 28C)
Superheater approach =∆TSH = 40 to 60F (22 to 33C)
Economizer approach = ∆TE = 10 to 30F (6 to 17C)
4. Stack outlet temperature – As with feedwater temperature, the minimum flue gas exit or stack temperature needs to be controlled to avoid corrosion
due to acid condensation. Typical values are identified in Chapter 20.
5. Load response and cycling requirements – Many
HRSGs today are cycled. That is, they are brought
up and down in load on a daily basis, thus requiring frequent warm-ups and cool-downs. As a re-
Table 4
HRSG Parameters
Turbine application:
Gas turbine sizes
Gas flow
Gas turbine outlet
temperature
Supplemental firing
temperature
1 MW to 220 MW
25,000 to 5,000,000 lb/h (0.32 to
630 kg/s)
≤ 1200F (≤ 649C)
≤ 1650F (≤ 899C)
Steam flow:
15,000 to 600,000 lb/h (1.9 to 76 kg/s)
Operating pressures:
High
Intermediate
Low
≥400 psig (2.76 MPa)
50 to 400 psig (0.34 to 2.76 MPa)
15 to 50 psig (0.10 to 0.34 MPa)
Steam temperature
up to 1005F (541C)
Supplemental fuels
#2 oil, natural gas
Fig. 23 Temperature profile in single pressure HRSG.
27-16
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
sult, special consideration must be given to the
thermal and mechanical stresses associated with
this type of operation. Pressure parts and their attachments must be designed in a manner which
allows them to expand freely. Steaming in the
economizer is inevitable at off-design points. As a
result, economizers must incorporate up-flow tube
circuitry, recirculation lines, steam-water separation equipment in the drum, or gas bypasses.
Stack dampers may also be necessary to keep the
HRSG warm if it is to be brought off line for short
periods of time.
6. Emissions – Emission requirements can have a
physical impact on the design of an HRSG. Depending on permit requirements and the type of
fuels fired in the duct burner, an SCR or CO catalyst may be required. In some instances, it may
be necessary to have both. The location of either
is driven by temperature (see Chapter 34). Therefore, tube banks must be arranged to accommodate the SCR and/or CO catalyst blocks which are
sized to meet the removal efficiency required at the
design conditions specified. It may also be necessary to install a distributor grid upstream of the
catalyst section to distribute the flue gas evenly
across the catalyst.
CO boiler
In the hydrocarbon processing industry, the operation of a fluid catalytic cracking (FCC) unit, depending on the FCC arrangement, produces gases rich in
carbon monoxide (CO). To reclaim the thermal energy
in these gases, the FCC unit can be designed to include a CO boiler to generate steam.
For refineries generating large quantities of CO,
field-erected boilers such as the PFI boiler are used.
There are also many smaller refineries that have
cracking units in the general range of 12,000 barrels
(1908 m3) per day or less which produce from 75,000
to 175,000 lb/h (9.5 to 22.1 kg/s) of CO gas. CO boilers for this capacity are often small enough to be shop
assembled. A shop-assembled boiler modified for CO
firing is shown in Fig. 24. CO gas is admitted through
ports in the side walls and front wall to promote mixing and rapid combustion. The burners, for firing
supplementary fuel, are located in a refractory front
wall and fire into a horizontal furnace.
The maximum steam requirements of the cracking
unit may occur at normal, full load operation or during startup of the cracking unit, depending on the
plant steam cycle. The supply of CO is normally not
sufficient to generate the maximum amount of steam
required; supplementary fuel is then needed.
Supplementary fuel is also required to raise the temperature of the CO gases to the ignition point and to
assure complete burning of the combustibles in the CO
gas stream. The following design criteria have been
established:
1. The basic firing rate should produce a temperature of 1800F (982C) in the furnace for a suitable
residence to provide safe and stable combustion of
the fuels.
2. Air is supplied by the forced draft fan to provide
2% oxygen leaving the unit when burning CO
gases and supplementary fuel.
3. Supplementary firing equipment is provided
which is capable of raising the temperature of the
CO gases to 1450F (788C), the temperature
needed for ignition of the combustibles.
Because of possible variations in the combustible
and oxygen content of the CO gases, the sensible heat
of the CO gases and the amount of supplementary fir-
Fig. 24 Shop-assembled CO boiler.
Steam 41 / Boilers for Industry and Small Power
27-17
The Babcock & Wilcox Company
ing, it is impractical to set up a fuel-air relationship.
Consequently, it is necessary to directly determine the
amount of excess oxygen leaving the unit. This may
be determined intermittently by a portable oxygen
analyzer, or continuously by an oxygen analyzer or
combination oxygen-combustible recorder.
Water seal tanks are installed upstream of the CO
boiler to act as shutoff valves in the large gas lines so
that the CO gases from the catalyst regenerator may
be passed through the boiler or sent directly to the
stack. This permits independent operation of the CO
boiler without interfering with the operation of the regenerator. Water seal tanks are preferred to mechanical shutoff dampers because of the high gas temperature, the size of the CO ducts, and the need for leak
proof construction.
The operation of the CO boiler is coordinated with
that of the catalytic cracker. Normally, the boiler will
be required to supply steam for the operation of the
catalytic cracking unit and will be started using
supplementary fuel. The CO boiler should always be
started using only the supplementary fuel burners
and bypassing the gases from the regenerator to the
atmosphere. CO gases should not be introduced into
the boiler until it is brought up to temperature because
these gases usually are at or below 1000F (538C) and,
consequently, tend to cool the furnace. They ignite
quite readily and burn with a non-luminous flame.
As the CO is introduced to the boiler, it is necessary to
reduce the supplementary fuel and the combustion air.
This readjustment in the air requirement is determined from the oxygen recorder reading.
Because there are only slight variations in the operation of the catalytic cracking unit, the CO boiler is
normally base loaded. It handles all the gases from
the regenerator regardless of the carbon dioxide (CO2)
to CO ratio. A change in this ratio merely affects the
quantity of supplementary fuel necessary to maintain
the required furnace temperature of 1800F (982C).
This temperature provides a reasonable operating
margin for possible variation in the operation of the
regenerator or the boiler. Stable operation can be
maintained at a furnace temperature as low as 1500F
(816C), but the margin above the ignition temperature of the CO gas is considerably reduced.
The economics of the CO boiler depend on the
amount of available heat in the regenerator exhaust
compared with an equivalent amount of heat from an
alternate fuel. The heat from the CO gases is calculated by taking the sensible heat above an assumed
boiler stack temperature plus all of the heat from the
combustibles. The additional steam generated in the
CO boiler by the supplementary fuel is comparable
with the steam generated in a conventional power
boiler. Normally, the supplementary fuel requirement
will account for one fourth to one third of the output
when the temperature of the entering CO gas is maintained at 1000F (538C).
Changes in FCC catalysts and in process conditions
have permitted reductions in the CO content of the
gases leaving the unit. These changes also result in
the gas temperature to the CO boiler increasing from
the 1000F (538C) level to as high as 1450F (788C).
27-18
Many existing CO boilers have been upgraded to
handle the new conditions. Changes have included
elimination of combustion zone refractory, use of membraned water walls, and resizing of heat transfer surface. (See Fig. 25.) New heat recovery boilers on FCC
units are designed for these new process conditions.
General waste heat boiler
The progressive increase in the cost of fuel has fostered technical progress in the utilization of waste
energy, including specialized designs and applications
of boilers. There are many industries or processes that
generate large quantities of high temperature gases
from which the sensible heat may be extracted for
steam generation. Such gases are produced in catalytic regenerators; blast furnaces; copper reverberatory furnaces; annealing, forge and billet heating furnaces; and fired kilns of many types.
The heat contained in these exhaust gases can often generate all the steam required for an industrial
process via properly designed boiler equipment.
Where the waste gases carry some of the noncombustible process material in suspension, suitable hoppers
will collect a portion of the material, and the cooled
gases leaving the boiler may be passed through dust
collectors to recover the remaining particulate. Many
types of boilers are necessary to meet the wide range
of requirements in this field. Boiler design depends on
the chemical nature of the gases and their temperature, pressure, quantity and dust loading.
Heat transfer from waste gases
The rate of heat transfer from the gas to the boiler
water depends on the temperature and thermophysical
properties of the gases, velocity and direction of flow
over the absorbing surfaces, and the surface cleanliness, as discussed in Chapter 4. Temperatures of many
process gases are relatively low as shown in Table 5.
To obtain the proper velocity of the gases over the
surfaces, a sufficient pressure difference or draft must
be provided, either by a stack or a fan. The draft must
overcome the pressure losses caused by the flow of
gases through the unit, with adequate allowance for
normal heating surface fouling.
The radiation heat transfer component is low and
the tendency is to design many waste heat boilers for
higher gas velocities than prevail on fuel-fired units.
However, high velocities with dust-laden gases can
cause tube erosion, particularly where there are
changes in gas flow direction. Therefore, process-specific velocity limits must be met.
Diagrams A and B, Fig. 26, show the approximate
convection heating surface required for usual conditions in waste heat boilers.
A water-cooled furnace is a feature of some waste
heat boiler applications where it is necessary to cool
the furnace gases to the temperature required to prevent slagging in the following tightly spaced convection surfaces. The approximate amount of surface required for such furnace applications is given in Diagram C of Fig. 26.
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
Fig. 25 Circular CO boiler modernization.
Application factors
The design of a boiler for a particular application
depends on many factors, most of which vary from
process to process and even within an industry. The
cost of equipment, auxiliary power and maintenance
must be compared with the expected savings. The
boiler design depends somewhat on the cost of power
at the plant. A smaller unit with closely spaced tubes
will cost less but will require more fan power, because
of high draft loss. A larger unit will be more expensive but have a lower draft loss and therefore a lower
fan power requirement. Other important factors are
the available space, locations for the proper flue connections, the corrosive nature of the gases, the effect
of dust loading on erosion, and the process operating
pressure conditions, i.e., pressurized or induced draft.
If the gases carry dust, attention must be given to
tube spacing and to removal of dust dislodged from
the heating surfaces. The tubes must be spaced reasonably close for good heat transfer yet far enough
apart to prevent bridging of deposits which can lead
to excessive gas-side pressure loss. Often the boiler is
arranged for wide tube spacing where the gases are
hottest, with spacing reduced where the gases are cooler
to maintain gas velocities and good heat transfer.
Sometimes the particulate or dust carried into the
boiler from the process can be removed by mechanical cleaners or sootblowers (see Chapter 24). In other
Steam 41 / Boilers for Industry and Small Power
cases, deposits from processes may require periodic
manual cleaning with high pressure air, steam or
water to keep the boiler passes open. In either case,
suitable hoppers should be provided to collect the deposit material removed from the tubes.
Table 5
Temperature of Waste Heat Gases
Temperature
Source of Gas
Ammonia oxidation process
Annealing furnace
Cement kiln (dry process)
Cement kiln (wet process)
Copper reverberatory
furnace
Diesel engine exhaust
Forge and billet heating
furnaces
Open hearth steel furnace,
air blown
Open hearth steel furnace,
oxygen blown
Basic oxygen furnace
Petroleum refinery
Sulfur ore processing
F
C
1350 to 1475
1100 to 2000
1150 to 1500
800 to 1100
732 to 802
593 to 1093
621 to 816
427 to 593
2000 to 2500
1000 to 1200
1093 to 1371
538 to 649
1700 to 2200
927 to 1204
1000 to 1300
538 to 704
1300 to 2100
3000 to 3500
1000 to 1400
1600 to 1900
704 to 1149
1649 to 1927
538 to 760
871 to 1038
27-19
The Babcock & Wilcox Company
also be done through the roof and above the lower
drums, making all absorbing surfaces accessible with
a short hand lance.
With high solids content gases, it is often possible
to reduce the amount of hand lancing by using long
retractable sootblowers. These are located at one or
sometimes two elevations along the depth of tube banks
at gaps formed by eliminating a single row of tubes.
To maintain optimum heat transfer conditions without changing the direction of gas flow, the tubes in
the rear sections of the boiler are more closely spaced
than those at the inlet.
Circulation in this boiler is simple, with the boiler
tubes in the hot gas end acting as risers and the tubes
in the cooler gas zones acting as downcomers or supply tubes. The boiler has a relatively long drum in
which steam separation takes place without the use
of baffles. The steam is collected in a dry pipe located
in the quiet, cool gas end of the drum. Feedwater is
thoroughly mixed with the boiler water rising into the
steam drum.
Expansion and contraction of the drums and tubes
have no effect on the steel casing, firebrick, or insulation. The most common source of brickwork trouble is
therefore eliminated and air infiltration is reduced to
a minimum. All pressure parts rest on supports located
below the lower drums.
The location of the superheater can be altered for
superheat temperature requirements. To increase heat
absorption further, an economizer can be installed in
the flue leaving the boiler. The economizer is arranged
for downward flow of gases to aid in the collection of
solids.
Solids collected in the hoppers under the boiler and
economizer can be readily removed while the boiler is
in service. In a single boiler behind a cement kiln, from
20 to 40 t (18.14 to 36.3 tm) of cement dust may be recovered each day from these hoppers.
Basic oxygen furnace/oxygen
converter hood
Fig. 26 Approximate surface required in convection tube bank and
vestibule for various entering and leaving waste gas temperatures.
The basic oxygen furnace (BOF) used in the steel
industry is blown with pure oxygen through a retractable water-cooled lance mounted vertically above the
Gases from oil- or gas-fired process furnaces are
relatively clean and, therefore, can be used in units
with 1.0 in. (25.4 mm) clear spacing between bare
tubes with little likelihood of deposit bridging and
plugging.
Three-drum waste heat boiler An example of a simple
three-drum waste heat boiler, specially designed to
operate with dust-laden gases, is shown in Fig. 27.
This type of unit is particularly well suited for use with
high solids content waste gases from cement kilns.
Maximum precipitation of solids is assured by the horizontal flow of the gases through the vertical tube
banks and by the effective arrangement of baffles.
With this tube arrangement, hand lancing is possible
from both sides of the unit. Every space in the full
width of the boiler can be lanced. Hand lancing can
Fig. 27 Three-drum waste heat boiler with lance ports and
sootblowers.
27-20
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
furnace. After each charge of molten iron, scrap steel
and fluxing material are loaded into the furnace, the
oxygen lance is lowered into position above the
charged material, and a blowing period of 15 to 20
minutes begins.
During the blowing time, the oxygen starts a chemical reaction which brings the charge up to temperature by burning out the silicon and phosphorous impurities and reducing the carbon content, as required,
for high grade steel. Large amounts of carbon monoxide gas, at 3000 to 3500F (1649 to 1927C), are released in this conversion process. The gas is collected
in a water-cooled hood and burned with air introduced
at the mouth of the hood. The products of combustion
are then cooled by adding excess air, injecting spray
water, or water cooling of the hood. Combinations of
these cooling methods may be used.
The high temperature of the gases discharged from
the BOF and their high carbon monoxide content
(about 70% by volume) make them ideal for burning
in the water-cooled hood located above the BOF. While
there are basic similarities to usual boiler service, there
are also significant differences, particularly the
carryover of iron-bearing slag from the BOF and the
short, intermittent operating periods.
The basic oxygen furnace (BOF) hoods are fabricated from membrane wall panels (Fig. 28). The membrane wall can be formed into a variety of hood configurations depending on plant layout. The hood may
be a long flue type used to transport the gases to an
evaporation or quench chamber, or it may be a bonnet type that collects the gases and immediately discharges them into a spark box where the temperature
is sufficiently reduced with spray water for use in the
gas cleanup system.
Steam generator hood The oxygen converter hood,
when equipped with a steam drum, boiler circulation
pumps, boiler mountings and controls, is an effective
steam generator during the oxygen blowing portion
of the converter cycle. Steam generation is limited to
the time of the oxygen blowing period, which is intermittent or cyclical in operation because of the steel-
Steam 41 / Boilers for Industry and Small Power
Fig. 28 Oxygen converter hood arrangement.
making process. The rate of steam generation varies from
zero to a maximum and back to zero during this period
which is normally about 20 minutes for a converter cycle
of 40 to 45 minutes. This cyclic operation, coupled with
the outage time required for relining the converter vessel every few weeks, limits the steam production of a
single hood to 12 to 15% of the life of the lining.
27-21
The Babcock & Wilcox Company
Type PFI Integral Furnace boiler installed in an industrial plant.
27-22
Steam 41 / Boilers for Industry and Small Power
The Babcock & Wilcox Company
Chapter 28
Chemical and Heat Recovery
in the Paper Industry
In the United States (U.S.), the forest products industry is the third largest industrial consumer of energy, accounting for more than 11% of the total U.S.
manufacturing energy expenditures. In 2002, 57% of
the pulp and paper industry relied on cogeneration
for their electric power requirements.
Approximately one-half of the steam and power consumed by this industry is generated from fuels that
are byproducts of the pulping process. The main
source of self-generated fuel is the spent pulping liquor, followed by wood and bark. The energy required
to produce pulp and paper products has been significantly reduced. Process improvements have allowed U.S.
pulp and paper manufacturers to reduce energy consumption to 2.66 × 1012 Btu (2806.5 × 1012 J), a significant reduction.
Pulp and paper mill electric power requirements
have increased disproportionately to process steam
requirements. This factor, coupled with steadily rising fuel costs, has led to the greater cycle efficiencies
afforded by higher steam pressures and temperatures
in paper mill boilers. The increased value of steam has
produced a demand for more reliable and efficient heat
and chemical recovery boilers.
The heat value of the spent pulping liquor solids is
a reliable fuel source for producing steam for power
generation and process use. A large portion of the
steam required for the pulp mills is produced in highly
specialized heat and chemical recovery boilers. The
balance of the steam demand is supplied by boilers
designed to burn coal, oil, natural gas and biomass.
ing its name from the use of sodium sulfate (Na2SO4)
as the makeup chemical. The paper produced from this
process was originally so strong in comparison with
alternative processes that it was given the name kraft,
which is the Swedish and German translation for
strong. Kraft is an alkaline pulping process, as is the
soda process which derives its name from the use of
sodium carbonate, Na2CO3 (soda ash), as the makeup
chemical. The soda process has limited use in the U.S.
and is more prominent in countries pulping nonwood
fiber. Recovery of chemicals and the production of
steam from waste liquor are well established in the
kraft and soda processes. The soda process accounts
for less than 1% of alkaline pulp production and its
importance is now largely historic.
Kraft pulping and recovery process
Kraft process
The kraft process flow diagram (Fig. 2) shows the
typical relationship of the recovery boiler to the overall pulp and paper mill.1 The kraft process starts with
feeding wood chips, or alternatively a nonwood fibrous material, to the digester. Chips are cooked under pressure in a steam heated aqueous solution of
USA
31%
All Other
Countries
30%
Major pulping processes
The U.S. and Canada have the highest combined
consumption of paper and paperboard in the world
(Fig. 1), consuming 105.6 million tons each year. With
a base of more than 800 pulp, paper and paperboard
mills, the U.S. and Canada are also the leader in the
production of paper and paperboard. North America
accounts for 32% of the total world output; pulp production is nearly 43%.
Total pulp production in the U.S. is divided among
the following principal processes: 85% chemical,
groundwood and thermomechanical; 6% semi-chemical; and 9% mechanical pulping. The dominant North
America pulping process is the sulfate process, derivSteam 41 / Chemical and Heat Recovery in the Paper Industry
Canada
2%
Italy
3%
France
3%
United Kingdom 4%
Germany
6%
Peoples Republic
of China
11%
Japan
10%
Fig. 1 World paper and board consumption by country, 2000.
28-1
The Babcock & Wilcox Company
Fig. 2 Kraft process diagram.
sodium hydroxide (NaOH) and sodium sulfide (Na2S)
known as white liquor or cooking liquor. Cooking can
take place in continuous or batch digesters.
After cooking, pulp is separated from the residual
liquor in a process known as brown stock washing. The
most common method features a countercurrent series of vacuum drum washers which displace the liquor with minimum dilution. Following washing, the
pulp is screened and cleaned to remove knots and
shives and to produce fiber for use in the final pulp
and paper products.
The black liquor rinsed from the pulp in the washers is an aqueous solution containing wood lignins,
organic material, and inorganic compounds oxidized
in the cooking process. Typically, the combined organic
and inorganic mixture is present at a 13 to 17% concentration of solids in weak black liquor. The kraft
cycle processes this black liquor through a series of operations, including evaporation, combustion of organic
materials, reduction of the spent inorganic compounds,
and reconstitution of the white liquor. The physical
and chemical changes in the unit operations are
shown in Fig. 3.2
The unique recovery boiler furnace was developed
for combusting the black liquor organic material while
reducing the oxidized inorganic material in a pile, or
bed, supported by the furnace floor. The molten inorganic chemicals or smelt in the bed are discharged to
a tank and dissolved to form green liquor. Green liquor active chemicals are Na2CO3 and Na2S.
Green liquor contains unburned carbon and inorganic impurities from the smelt, mostly calcium and
iron compounds, and this insoluble material, or dregs,
must be removed through clarification. This operation
is basically settling of sediment and decantation of
28-2
Fig. 3 Kraft process cycle.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
clear green liquor that can be pumped to the slaker.
The dregs are pumped out of the clarifier as a concentrated slurry. Normal operation is to water wash the
dregs before landfill disposal. The water wash liquid
containing the recovered sodium chemical is known
as weak wash. The sodium chemicals are recovered by
using the weak wash to dissolve the smelt in the dissolving tank.
Clarified green liquor and lime (CaO) are continuously fed to a slaker where high temperature and
agitation promote rapid slaking of the CaO into calcium hydroxide (Ca(OH)2). The liquor from the slaker
flows to a series of agitated tanks that allow the relatively slow causticizing reaction to be carried to
completion. The function of the causticizing plant is
to convert sodium carbonate into active NaOH. The
calcium carbonate (CaCO3) formed in the conversion
reaction precipitates in the causticizing operation to
form a suspended lime mud.
The causticizing product must be clarified to remove
the CaCO3 precipitate and produce a clear white liquor
for cooking. This clarification is carried out by either
settling and decanting, in a manner similar to green
liquor clarification, or by using pressure filters. In
pressure filtration, the white liquor is filtered through
a medium to provide a separation of clear white liquor
from the lime mud. The lime mud is then washed to
remove sodium chemicals that can lead to increased
kiln emissions and clinkering, and further filtered to
obtain the desired consistency for feed to the kiln.
The lime kiln calcines the washed lime mud feed into
reburned lime. Calcination is the chemical breakdown
with heat of the CaCO3 into active lime and carbon
dioxide (CO2). The calcined lime is then slaked as previously described.
The reactions occurring in the solids cycle operations
are as follows:
Slaking: CaO + water = Ca(OH)2 + heat
Causticizing: Ca(OH)2 + Na2CO3 = CaCO3 + 2NaOH
Calcination: CaCO3 + heat = CaO + CO2
The combination of these process steps is referred to
as recausticization.
In parallel with the reduction of sulfur compounds
to form smelt, energy is released in the recovery furnace as the black liquor organic compounds are combusted. This combustion energy is used in the process
recovery boiler to produce steam from feedwater. The
steam can be introduced to a turbine generator to
supply a large portion of the energy demand of the
pulp and paper mill. Steam extracted from the turbine
at low pressure is used for process requirements such
as cooking wood chips, evaporation, recovery furnace
air heating, and drying the pulp or paper products.
Rated capacity of a recovery unit
The capacity of a pulp mill is based on the daily tons
of pulp produced. The primary objectives of a recovery boiler are to reclaim chemicals for reuse and to
generate steam by burning the black liquor residue.
Accordingly, the capacity of the recovery boiler should
be based on its ability to burn or process the dry solSteam 41 / Chemical and Heat Recovery in the Paper Industry
ids contained in the recovered liquor. Because the
proper measure of recovery boiler capacity is the heat
input to the furnace, The Babcock & Wilcox Company
(B&W) has established a 24 hour heat input unit of
19,800,000 Btu (20,890 MJ). This unit, known as a
B&W-Btu ton, corresponds to the heat input from
3000 lb (1361 kg) of solids (approximately equivalent
to one ton of pulp produced) having a heating value
of 6600 Btu/lb (15,352 kJ/kg) of solids. These were
averages for the typical black liquor solids generated
from a ton of kraft pulp production when this unit was
originally defined. The black liquor solids produced
from modern operations generally are characterized
by considerable variation in the quantity of the solids
per ton of pulp product and somewhat lower heating
values. For this reason, a more common rating term
applied to current recovery boilers is the amount of
dry solids processed over a given period of time (hour
or day). The recovery boiler is a heat input machine,
and as such, The B&W-Btu rating recognizes the true
indication of the unit’s design capacity to process that
energy input.
The nominal size of a B&W kraft recovery boiler can
be determined by application of a simple formula as
follows:
Nominal size =
A × B × C
, B&W-Btu tons (1)
19, 800, 000
where
A = dry solids recovered, lb/t of pulp
B = pulp output of mill, t/24 h
C = heating value of dry solids, Btu/lb
and 19,800,000 is the product of 3000 lb/t and 6600
Btu/lb.
Today’s recovery furnace is conservatively designed
for a heat release rate (heat input rate divided by
furnace plan area) of approximately 0.90 × 106 Btu/h
ft2 (2.84 MW/m2 ). This heat release has increased over
time, but was always kept below 1.0 × 106 Btu/h ft2
(3.15 MW/m2 ). Although new recovery boiler furnaces
are sized for a low heat release rate, there are many
recovery boilers that have experienced successful capacity increases at much higher heat release rates.
Mills historically have increased pulp production making the recovery boiler a limiting factor at the mill. In
order to maintain increased pulp production, the recovery boiler has been called upon to process an ever
increasing amount of black liquor solids. Today it is
common for a recovery boiler to successfully process
solids that result in heat release rates up to 1.25 × 106
Btu/h ft 2 (3.94 MW/m 2 ). This has been achieved
through improvements to the combustion air and liquor delivery systems, sootblower systems, reduction
of chlorine in the as-fired liquor, and changes to convection pass arrangements.
There are several criteria commonly used to evaluate the potential success of capacity increases for recovery boilers. In addition to the heat release rate, the
furnace exit gas temperature, superheater exit gas
temperature, flue gas velocity, and furnace volume
are important criteria. Depending on the extent of the
28-3
The Babcock & Wilcox Company
capacity increase, most of these criteria can be met with
changes to the original design. For example, flue gas
temperatures can be reduced with furnace screen and
superheater changes. Furnace volume has been modified by expanding the furnace forward, relocating the
furnace front wall forward and making the side walls
wider thus providing a greater furnace volume for
higher rates of liquor solids.
The criteria B&W uses to predict recovery boiler
performance is based on operating experience. Some
of this has changed over time as equipment improvements have affected operation.
Process flows through the recovery boiler
The kraft process recovery boiler is similar in many
respects to a conventional fossil fuel-fired boiler. The
concentrated black liquor fuel is introduced into the
furnace along with combustion air. Inside the furnace,
the residual water is evaporated and the organic
material is combusted. The inorganic portion of the
black liquor solids is recovered as molten smelt. Most
of the sulfur is in the reduced form of Na2S and most
of the remaining sodium is Na2CO3. The requirement
to recover sulfur in a reduced state is the most unique
aspect of recovery boiler design. Fig. 4 illustrates a typical modern recovery boiler.
Combustion air is introduced into the furnace at
staged elevations: primary, secondary, tertiary, and at
times, quaternary. One-fourth to one-half of the air
enters at the primary level near the furnace floor. The
balance is staged at the secondary, tertiary and quaternary levels. Heavy black liquor (solids greater than
60%) is fed to the furnace through multiple burners
between the secondary and tertiary air levels.
The gases generated by the black liquor combustion rise out of the furnace and flow across convection
heat transfer surface. Superheater surface is arranged at the entrance to the convection pass, followed
by steam generating surface and finally the economizer. In designs featuring direct contact evaporators,
the flue gas may flow from the boiler bank to the
evaporator with no economizer surface provided, or a
relatively small economizer may be required.
Feedwater enters the recovery boiler at the bottom
of the first pass economizer. Heated water from the
second pass economizer is discharged into the steam
drum. From the drum, saturated water is routed
through pipe downcomers to lower furnace enclosure
wall headers and the boiler bank. From these steam
generating circuits, the steam-water mixture is returned by natural circulation to the steam drum
where the mixture is separated. From the drum,
steam-free water is again returned to the furnace and
boiler bank circuits, and water-free steam is directed
to the superheater. After flowing through the superheater sections, the steam leaves the recovery boiler
and is typically piped to a turbine-generator.
to the feedwater in generating steam and can be expressed as:
, Btu/h ( J / s )
Output = ( H s − H fw ) m
(2)
where
H s = enthalpy of steam leaving superheater, Btu/
lb (J/kg)
Hfw = enthalpy of entering feedwater, Btu/lb (J/kg)
m = steam or water flow rate, lb/h (kg/s)
Boiler water is frequently withdrawn from the
steam drum as blowdown to maintain steam purity.
Steam may also be withdrawn prior to the final superheater stage for use in sootblowing. In these instances, the output expression must be corrected to
account for the energy leaving the boiler prior to the
superheater outlet.
Boiler thermal performance
The thermal efficiency of a recovery boiler is defined
as the ratio of energy output to energy input. The
boiler output is a measure of the energy transferred
28-4
Fig. 4 Typical modern recovery boiler.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
The portion of the input energy available to generate
steam can be determined by calculating a steady-state
heat and material balance around the boiler. Because
steady-state output must equal the input less energy
losses, boiler efficiency can also be expressed as:
Boiler efficiency =
Output
Input − Losses
=
(3)
Input
Input
Fig. 5 illustrates the major streams crossing the heat
and material balance boundaries. The total heat input can be calculated by summing the chemical and
thermal energy contained in the streams entering the
boundary. The total losses are then calculated by summing the heat losses due to endothermic reactions
occurring within the boiler and the thermal energy
losses of the exiting streams.
In practice, it is not feasible to precisely measure all
streams entering and leaving the system boundaries.
An unaccounted for heat loss and a manufacturer’s
margin are added to the total losses to correct the calculated efficiency for these limitations.
The gross heating value or chemical energy of black
liquor is determined by combusting a black liquor
sample with an excess of oxidant, under pressure, in
a bomb calorimeter. Under these laboratory conditions, the combustion products predominantly exist as
CO 2 , H 2O, Na 2 CO 3 , Na 2 SO 4 and sodium chloride
(NaCl). A key process in black liquor combustion is the
reclamation of sodium compounds in a reduced state.
The reduction reactions occurring in the recovery furnace result in different combustion products than
those resulting from the bomb calorimeter procedure.
These endothermic reactions account for a portion of the
black liquor heating value that is not available in the
recovery furnace to generate steam. To accurately determine recovery boiler efficiency, the bomb calorimeter
gross heating value must be corrected for the heats of
reaction of these different combustion products.
Fig. 6 Determination of black liquor heat of reaction correction.
The heat of reaction correction is the difference
between the standard heat of formation of the bomb
products and the heat of formation of the furnace
products. Application of the heats of formation to determine a reaction correction is illustrated for kraft liquor in Fig. 6.
Step 1 This is the gross heating value of the black
liquor sample determined in the bomb calorimeter.
Step 2 From the quantitative analysis of the fully
oxidized bomb calorimeter compounds, the
heat required to convert these products to
their elemental state can be calculated from
the standard heats of formation of the compounds from their elements.
Step 3 Similarly, from the quantity of each chemical compound present in the furnace combustion products, the heat of formation for the
actual furnace products can be calculated.
Fig. 5 Plant heat balance diagram. (See also Table 2.)
Steam 41 / Chemical and Heat Recovery in the Paper Industry
28-5
The Babcock & Wilcox Company
The difference between Step 2 and Step 3 is the heat
of reaction correction.
Sulfur dioxide (SO2 ) and Na2S are the most significant recovery furnace combustion products that differ from those formed under bomb calorimeter conditions. The heat of reaction correction for Na2S is calculated as follows:
Na 2 SO4 = 2Na + S + 2O2 (Step 2)
(4)
2Na + S = Na 2S (Step 3)
The calculation is simplified by combining Steps 2
and 3 and using standard heats of formation:
Na 2 SO4 = Na2 S + 2O2
∆Hf (Na2S)
∆Hf0 (O2)
∆Hf0 (Na2SO4)
Heat of reaction
correction
0
=
=
=
=
=
(5)
89.2 kcal/gmole
0.0
−330.9
−241.7 kcal/gmole
−5550.0 Btu/lb Na2S
(−12,909.0 kJ/kg)
Similarly, the heat of reaction correction for sulfur
dioxide can be determined from standard heats of formation from the bomb calorimeter combustion products:
Na 2 SO4 + CO2 = SO2 + Na2 CO3 +
∆Hf0 (SO2)
∆Hf0 (Na2CO3)
∆Hf0 (O2 )
∆Hf0 (Na2SO4 )
∆Hf0 (CO2 )
Heat of reaction
correction
=
=
=
=
=
1
2
O2
(6)
71.0 kcal/gmole
270.3
0.0
−330.9
−94.1
=
−83.7 kcal/gmole
= −2360.0 Btu/lb SO2
(−5489.0 kJ/kg)
In actual furnace operations, there is a variety of partially reduced, partially oxidized combustion products.
However, accounting only for the presence of SO2 and
Na2S in correcting the bomb calorimeter gross heating value closely approximates black liquor combustion in a recovery furnace.
Salt cake makeup and other additives to the black
liquor are treated in a manner similar to the heat of reaction correction in calculating recovery boiler efficiency.
The heat of formation or gross heating value of the
Na2SO4 salt cake is accounted for as a contribution to the
total system energy input. The subsequent reduction of
Na2SO4 to Na2S and O2 is then taken as a heat loss.
The black liquor elemental analysis and gross heating value are used to determine the chemical and thermal performance of the recovery boiler. A typical black
liquor analysis is presented in Table 1.
Table 2 lists the inputs and losses for a recovery unit
firing 250,000 lb/h (31.5 kg/s) dry solids at 70% black
liquor concentration based on the composition and
heating value given in Table 1. Industry practice is
to express the various heat losses as a percentage of
the total heat input, also shown in Table 2. The system boundaries for the heat and material balance are
shown diagrammatically in Fig. 5.
28-6
Table 1
Black Liquor Analysis
Dry solids, % by wt
Nitrogen (N)
Sodium (Na)
Sulfur (S)
Hydrogen (H2 )
Carbon (C)
Oxygen (O2 )
Inerts
Potassium (K)
Chlorine (Cl)
Total solids
0.10
19.77
4.36
3.86
35.14
34.74
0.30
1.31
0.42
100.00
Solids gross heating value = 5985 Btu/lb (13,921 kJ/kg)
The black liquor gross heating value is the predominant energy input to the recovery boiler system. The
balance of the input is the sum of the sensible heats
contributed by those process streams entering the
boiler above a base reference temperature. The black
liquor is typically preheated to 230 to 270F (110 to
132C) prior to firing. The majority of the combustion
air (primary and secondary) is also generally preheated to promote stable furnace conditions.
The heat of reaction correction is expressed as a heat
loss due to the endothermic reduction reactions in
calculating recovery boiler efficiency. To determine
this heat loss, the fraction of sodium and sulfur converted to Na2S, Na2SO4 and SO2 must be calculated
from the chemical analysis of the smelt and flue gas
leaving the recovery boiler. For the example presented
in Table 2, 0.099 lb of Na2S is formed for each pound
of black liquor solids entering the recovery boiler. The
heat of reaction correction or heat loss associated with
the formation of Na2S is calculated as follows:
0.099 lb Na 2S
5550 Btu
250, 000 lb solids
×
×
lb solids
lb Na2S
h
= 137.36 × 106 Btu/h
(7)
In addition, 0.0017 lb of SO2 is formed in the reduction of Na2SO4 to Na2CO3:
0.0017 lb SO2
2360 Btu
250, 000 lb solids
×
×
lb solids
lb SO2
h
= 1.0 × 106 Btu/h
(8)
The heat loss due to the reduction reactions is the sum
of these heat of reaction corrections:
Reduction reaction heat loss =137.36 × 106 + 1.0 × 106
=138.36 × 106 Btu/h
In addition to the heat of reaction correction and
the heat loss attributed to reducing salt cake makeup,
energy is lost from the boiler in the form of sensible
heat. Heat is also lost through water vaporization and
through the molten smelt. Typically, smelt leaving the
recovery furnace represents 532 Btu/lb (1237 kJ/kg)
of heat consumed to melt the smelt and raise its temSteam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
Table 2
Material and Energy Balances for a Recovery Boiler Firing
250,000 lb/h Dry Solids at 70% Liquor Concentration
Material balance:
Entering combustion air
Entering infiltration air
Entering black liquor
Total in
=
=
=
1,176,620 lb/h
20,550 lb/h
357,143 lb/h
1,554,313 lb/h
Smelt leaving
Wet gas leaving
Particulate leaving
Total out
=
=
=
111,200 lb/h
1,442,290 lb/h
823 lb/h
1,554,313 lb/h
Energy balance:
106 Btu/h
% Total
Chemical heat in liquor
Sensible heat in liquor
Sensible heat in air
Input
=
=
=
1496.25
37.47
49.59
1583.31
94.50
2.37
3.13
100.00
Sensible heat in dry gas
Moisture from air
Moisture from hydrogen
Moisture from liquor
Reduction reactions
Heat in smelt
Radiation
Unaccounted for and
manufacturer's margin
Losses
=
=
=
=
=
=
=
101.49
2.37
104.82
129.20
138.36
71.25
4.75
6.41
0.15
6.62
8.16
8.74
4.50
0.30
=
15.83
568.07
1.00
35.88
Boiler efficiency =
Input − Losses
1583.31 − 568.04
=
= 64.12%
Input
1583.31
Output = Efficiency x Input =
64.12
6
x 1583.31 x 106 = 1015.22 x 10 Btu/h
100
Steam flow =
Output
1015.22 x 106
= 847,970 lb/h
=
(1444.16 − 246.93)
Hs − Hfw
perature to a nominal 1550F (843C). The balance of
the heat losses are determined in a manner similar to
those for conventional power boilers. (See Chapter 22.)
The contribution to boiler efficiency offered by the
remaining streams crossing the recovery unit heat and
material balance is primarily established by their sensible heat content at the temperature at which they
cross the system boundary. The minimum temperature of the flue gas leaving the boiler is selected to
minimize corrosion. The heat transfer surface arrangement and thermodynamic considerations then dictate
the economic limit for the flue gas exit temperature,
typically 350 to 400F (177 to 204C).
The gross heating value of a given black liquor
sample is strongly influenced by its carbon content.
As this content increases, the heating value typically
increases, as illustrated in Fig. 7. An increased liquor
heating value also generally corresponds to an increased hydrogen content, with a corresponding decrease in inorganic sodium and sulfur contents. These
Steam 41 / Chemical and Heat Recovery in the Paper Industry
factors result in an increased quantity of theoretical
air (see Chapter 10) required to combust the black liquor. The overall trends can be summarized as follows:
1. Carbon (and hydrogen) content increases with increasing heating value.
2. Inorganic sodium and sulfur contents decrease
with increasing heating value.
3. Theoretical air increases with increasing carbon
and hydrogen contents.
4. Theoretical air increases with increasing heating
value.
These trends can be used as quick checks on laboratory results for a given black liquor sample chemical
analysis and gross heating value.
Black liquor as a fuel
Black liquor
Black liquor is a complex mixture of inorganic and
organic solids partially dissolved in an aqueous solution. Heavy or strong black liquor introduced to the
recovery furnace ranges from 60 to 80% solids by
weight. The organic fraction of the solids is principally
derived from the hemicellulose and the lignin removed
from the cellulose strands of the wood chips. The solids’
inorganic fraction is primarily Na 2 CO 3 , sodium
hydrosulfide (NaHS) and oxidized sulfur compounds.
Black liquor also contains various chemical elements
which enter the process with the wood, as impurities
in makeup limestone and salt cake, and as contaminants in makeup water. These elements include potassium, chlorine, aluminum, iron, silicon, manganese,
magnesium and phosphorous. The waste stream from
a chlorine dioxide generator in a bleached mill can also
contribute NaCl. Potassium and chlorine directly impact the recovery boiler design and operation if they
are present in the black liquor in sufficient quantities.
It is not uncommon for many other waste streams
and effluents from the mill to be added to the black liquor. This may include soap, various brines or other
effluents from the bleach plant, or a variety of other
streams. These may significantly affect the chemical composition or heating value of the black liquor fuel, which
can have major impacts on performance, operations,
emissions and/or cleanability of the recovery boiler.
Black liquor is sprayed into the furnace as coarse
droplets which fall to the floor in a dry and partially
combusted state to form a char bed. The mounded bed
Fig. 7 Black liquor high heating value as a function of carbon
content in dry solids.
28-7
The Babcock & Wilcox Company
Reduction efficiency =
Na 2 S + NaHS
× 100%, Na 2O (9)
Total sodium sulfur compounds
A common industry simplification is as follows:
Reduction efficiency =
Na 2 S
× 100%, Na 2O
Na 2 S + Na2 SO4
(10)
The industry practice is to express the compounds
in the equations as the equivalent weight of Na2O.
Emissions
The black liquor combustion process is never theoretically complete. This results in small concentrations
of unburned combustibles, typically carbon monoxide
(CO), organic and sulfur compounds, and hydrogen
sulfide (H2S), being discharged to the atmosphere. The
volatile organic compounds, or VOC, are generally
expressed in terms of equivalent methane (CH4) and
are sometimes more specifically referred to as
nonmethane volatile organic compounds (NMVOC).
H2S and sulfur-bearing organic compounds such as
mercaptans are grouped together as total reduced sulfur (TRS). Trace amounts of SO2 also exist in addition
to TRS-bound sulfur. As in most combustion processes,
nitrogen oxides (NOx) are present and are expressed in
terms of equivalent nitrogen oxide (NO2). Black liquor
combustion also creates particulate matter.
The modern recovery boiler achieves effective NOx control by staged air combustion, control of excess air, and a
uniform distribution of the black liquor through multiple
burners. A recovery furnace inherently produces lower
NOx emissions compared to fossil fuel boilers. Burning 68
to 75% solids concentration black liquor, NOx levels
would normally be expected to be below 100 ppm.
Recovery boilers can often be upgraded in capacity
with little or no increase in NOx emissions, as air port
sizes and locations can be modified to allow adequate
control of operations, and emissions, when increasing
solids input. Numerical modeling of the existing air
system using actual operating data provides the engineer with accurate predictions of NOx and particulate
emissions before hardware is installed.
SO2 emissions are a function of the sulfidity of the
smelt. Fig. 8 shows the general variation of SO2 with
28-8
350
Lower Solids
Black Liquor
(<70% Solids)
300
Sulfur Dioxide (at 8% O ), ppm
consists of a matrix of carbon and inorganic sodium
chemicals rising 3 to 6 ft (0.9 to 1.8 m). The black liquor droplets sprayed into the furnace must be large
enough to minimize droplet entrainment in the rising
combustion gases, yet small enough so that they fall
to the bed nearly dry. Wet liquor droplets reaching the
bed can quench the burning char and cause a bed
blackout, or can result in high sulfur emissions.
The design of the recovery furnace must promote
combustion of the black liquor in parallel with the
efficient reduction of sodium compounds. The absolute
reduction efficiency is determined by the degree, on a
weight percent, to which sulfur is present in the smelt
in a reduced state, such as Na2S and NaHS.
250
200
150
100
Higher Solids
Black Liquor
(>70% Solids)
50
0
14
18
26
22
30
34
38
42
Smelt Sulfidity, %
Na2S
Na2S + Na2CO3 + NaOH
Expressed as Na2O in the Smelt
Where Smelt Sulfidity is Percentage Ratio (weight, %) of:
Fig. 8 Sulfur dioxide emissions.
sulfidity. An environmental benefit of increased black
liquor concentrations fired in recovery boilers is a reduction in SO2 emissions.
Concentrations of TRS in the combustion gases
leaving a modern boiler are readily controlled below
5 ppm, as the H2S and volatile organic sulfide compounds are oxidized in the high temperature furnace.
VOC and CO emissions can be controlled by proper
furnace design and operation. VOC can be maintained
below approximately 80 ppm (current Environmental Protection Agency/EPA limit) while CO emissions
are controllable to less than 500 ppm. A hot furnace
and thorough mixing of combustion air with the generated volatiles are essential in minimizing VOC, TRS
and CO emissions. Particulate is removed from the
combustion gases in a high efficiency electrostatic precipitator, which can control the stack discharge particulate to the current EPA limit of 0.044 gr/dscf.
Ash
Ash accumulations on heat transfer surfaces create an insulating barrier that reduces heat transfer
to the boiler tubes. Consequently, as the ash deposits
build and heat transfer decreases, steam outlet temperatures decay and the flue gases retain higher temperatures as they pass through the boiler surfaces.
Higher flue gas temperatures lead to more ash in its
molten phase being carried further back in the boiler
convection pass where it adds to already present accumulations. As ash deposits grow, they also begin
restricting gas flow through the boiler, plugging the
gas passes, and eventually increasing the furnace
draft loss to inoperable levels.
The characteristics of ash from black liquor combustion impact the design of the process recovery boiler.
Approximately 45% by weight of the dry, as-fired solids is inorganic ash. The majority of these inorganics
are removed from the furnace as Na2S and Na2CO3 in
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
Steam 41 / Chemical and Heat Recovery in the Paper Industry
stack. More fuming than that sufficient to capture the
sulfur causes the excess alkali to be converted to carbonate in the ash. Less fuming than that sufficient to
capture sulfur causes excess sulfur to be released as SO2,
and chlorine to be released as HCl in the stack gas,
rather than being converted to chloride in the ash.
As potassium (K) has a higher vapor pressure than
sodium (Na), the fume contains a higher ratio of K/
Na than that found in smelt or black liquor. This is
referred to as potassium enrichment. Chlorides are also
found at higher concentrations in fume. Potassium and
chlorides can contribute to severe plugging in the recovery boiler convection surfaces.
Ash fouling and gas path plugging within recovery boilers are directly related to the melting properties of the ash in the boiler. Chloride and potassium
concentrations within the liquor cycle are the most significant factors affecting ash melting points. High
chloride concentrations are the result of high chloride
sources such as in the wood supply or makeup chemicals. Environmental improvements within the last
decade have reduced chemical losses throughout the
system, and increased various dead-load chemicals,
including chlorides, within the liquor stream.
One of the main factors in determining ash deposition rates is the ash stickiness.3 Ash stickiness is a function of the amount of liquid phase present in the ash,
that is dependent upon ash chloride content and temperature.
A simplified relationship between the ash chloride
content and the sticky temperature is shown in Fig.
9. This graph may be used to illustrate the anticipated
effects of elevated ash chloride levels in general terms.
The conditions of this particular graph are at a 5%
potassium molar ratio. Notice that the sticky band on
this graph covers the widest temperature range from
5 to 10% molar chloride levels and would be in a narrow range at higher and lower chloride levels.
Ash enrichment by chloride reduces the ash melting point and increases the deposit sintering rate. The
characteristic sticky temperature has been defined as
the temperature where 15% of the alkali salt mixture
is liquid. The presence of K in combination with chlorides further reduces the sticky temperature of depos850
5 Mole% K/(Na+K)
Radical
Deformation
800
750
Temperature, C
the molten smelt. A significant amount of ash is
present as particulate entrained in the existing flue
gases. Generally, about 8% by weight of the entering
black liquor dry solids leaves the furnace as ash.
Ash is generally categorized as fume or carryover.
Carryover consists of char particles and black liquor
droplets that are swept away from the char bed and
liquor spray by the upward flue gas flow. Entrainment occurs when small particles caught in the furnace gases are not of sufficient size, shape or density
to fall back into the furnace. Entrainment results in
combustion of black liquor in the upper furnace which
affects temperature and ash deposit properties. Entrainment of smelt and char materials is a major cause
of convection surface plugging.
Once entrained, the black liquor carryover droplet
follows the gas flow. When complete particle burnout
occurs, the entrained droplet can settle out of the gas
flow as a smelt bead. Otherwise, the partially combusted particles form sparklers that deposit on tubes
as char, then continue to burn and yield a smelt deposit. At low loads with lower furnace gas flow rates,
entrained droplets have time to burn out, and only
small smelt droplets show up as carryover. As load is
increased, larger drops can be entrained by the correspondingly increased gas flow. The particles can
then include small smelt droplets and large char particles. Carryover can be controlled by furnace size and
by proper design and operation of the firing and combustion air systems.
Fume consists of volatile sodium compounds and
potassium compounds rising into the convection sections of recovery boilers. These volatiles condense into
submicron particles that deposit onto the superheater,
boiler bank and economizer surfaces. Fume particles
in kraft recovery boilers are usually 0.25 to 1.0 microns in diameter and consist primarily of Na2SO4 and
a lower content of Na2CO3. Fume also contains potassium and chloride salts.
The much larger carryover particles, typically greater
than 100 microns, are easily distinguishable from the
submicron fume particles. Fume and carryover ash are
also different in their chemical analyses. Carryover is
similar in composition to the smelt (see comments above).
Fume is mostly Na2SO4 and is enriched in potassium and
chloride relative to their concentration in the smelt.
Fume can contribute to deposit formation and plugging in the convection heat transfer sections of the
boiler, particularly if allowed to sinter and harden.
Fume particles are also the predominant source of
particulate emissions from recovery boiler stacks.
A third category of ash is represented by intermediate size particles (ISP), a class of particles between
carryover (> 100 microns) and submicron fume, which
are produced during combustion of black liquor droplets and the char bed. While ISPs are abundant, exist everywhere, and are potentially important to fouling in recovery boilers, the mechanisms by which these
particles are formed are not yet well understood.
Char bed temperature controls the fuming rate. A
rate just sufficient to capture the sulfur released during combustion should be established. This minimizes
the dust load to the precipitator and the SO2 to the
Slagging
700
Sticky
650
Not
Sticky
600
550
First Melting
500
0
2
4
6
Fig. 9 Sticky temperature.4
8
10
12
14
16
18
20
CI/(Na+K) Mole %
28-9
The Babcock & Wilcox Company
its. The recovery boiler should be designed to reduce
the gas temperature entering the boiler bank to below the ash sticky temperature to avoid bank plugging. Decreasing the Cl level in the black liquor can
also decrease the plugging tendency of the resulting
ash. The successful reduction of chloride levels has
been achieved by ash purging. When purging ash (see
Ash system), ash is removed periodically to maintain
chloride levels at a specified target. For the most part,
maintaining a chloride level in the precipitator ash of
1.5% or less has proven to be successful in reducing fouling and plugging within recovery boilers.
Recovery boiler design evolution
The kraft recovery process evolved in Danzing,
Germany approximately 25 years after the soda process was developed in the United Kingdom in 1853.
In 1907, the kraft recovery process was introduced in
North America. From its inception, a variety of furnace types competed for a successful commercial design, including rotary and stationary furnaces. During the late 1920s and early 1930s, significant design
developments were achieved by G.H. Tomlinson,
working in conjunction with B&W engineers.
The first Tomlinson recovery boiler was supplied by
B&W Canada in 1929, at the Canada Paper
Company’s Windsor Mills, Quebec plant (Fig. 10). This
black liquor recovery boiler had refractory furnace
walls that proved costly to maintain. The steam generated with the refractory furnace was also much less
than that theoretically possible. Tomlinson decided that
the black liquor recovery furnace should be completely
water-cooled, with tube sections forming an integral
part of the furnace. This new concept boiler, designed
Fig. 10 First Tomlinson recovery boiler.
28-10
in cooperation with B&W, was installed at Windsor
Mills in 1934. The water-cooled design was a complete
success, and the boiler operated until 1988. The first
Tomlinson recovery boilers in the U.S. were two 90
B&W-Btu t/day units sold to the Southern Kraft Corporation in Panama City, Florida in 1935.
The Tomlinson design evolved with a technique of
spraying black liquor onto the furnace walls. The liquor is dehydrated in flight and on the furnace walls,
where pyrolysis begins with the release of volatile
combustibles and organically bound sodium and sulfur. As the liquor mass builds on the furnace walls,
its weight eventually causes it to break off and fall to
the hearth. There, pyrolysis is completed and the char
is burned, providing the heat and carbon required in
the reduction reaction.
By the end of World War II, the recovery boiler design (Fig. 11) had evolved to the general two-drum
arrangement that represented B&W’s standard product until the mid-1980s. Retractable sootblowers using steam as a medium eliminated hand lancing in the
1940s; this significant development made large recovery boiler designs practical.
Fig. 11 General two-drum arrangement of the 1940s.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
Wall and floor construction
By 1946, furnace wall construction had evolved
from tube and refractory designs to a completely water-cooled furnace enclosure, using flat plate studs to
close the space between tubes and to minimize smelt
corrosion and the resultant smelt leaks. The flat stud
design was superseded in 1963, with membrane tube
construction where the gas-tight seal is along the plane
of the wall rather than formed by casing behind the wall.
The 1963 furnace wall construction had 3 in. (76
mm) outside diameter (OD) tubes on 4 in. (102 mm)
centers. The advantages of this construction included
less air infiltration, reduced refractory maintenance,
and a completely gas-tight unit. The design used cylindrical pin studs for corrosion protection of the tubes
in the reducing zone of the lower furnace. The pin
studs held solidified smelt, forming a barrier to the
corrosive furnace environment. The current construction calls for 64 half-inch (13 mm) diameter studs per
linear foot (0.3 m) of tubing.
The lower furnace design continued to evolve in the
1980s from the traditional pin stud arrangement to
the use of composite or bimetallic tubes. The composite tubes are comprised of an outer protective layer of
AISI 304L stainless steel and an inner core layer of
standard American Society of Testing and Materials
(ASTM) A 210 Grade A1 carbon steel. The composite
tube inner and outer components are metallurgically
bonded. The outer layer of austenitic stainless steel,
which is also used to cover the furnace side of the carbon steel membrane bar, protects the core carbon steel
material from furnace corrosion.
Not long after the introduction of 304L composite
tubes, issues with sodium hydroxide attack of the
stainless layer near air ports, and cracking of the 304L
layer and tube-to-membrane weld, were discovered.
The cracking and corrosion have typically been specific to the floor and primary air ports. Considerable
investigation has occurred with other materials identified as probable substitutes for 304L. Differential
expansion of the two layers has been identified as an
issue. Table 3 shows the coefficients of expansion and
tensile strength for different materials commonly used
to protect recovery boiler lower furnace tube surfaces.
Several methods are used for lower furnace corro-
Carbon Steel
with Pin Studs
(<900 psig/6.2 MPa)
Properties of Materials Used to Protect
Recovery Boiler Lower Furnace Tube Surfaces
Carbon
Steel
Type Incoloy Inconel
304L
825
625
Alloy 625, 825
(>900 psig/6.2 MPa)
Expansion coefficient
Mean to 700F (371C) x
10−6 (in./in. F)
7.59
9.69
8.3
7.5
Thermal Conductivity
at 700F (371C)
(Btu/h ft2 F)
320
142
115
117
56
86
132
Ultimate Tensile Strength
ksi at 1000F (538C)
Enhanced
Tube Materials
or Bare
Carbon Steel
Coextruded 304L
(>900 psig/6.2 MPa)
Table 3
Property
sion protection. Lower furnace protection should be
determined from criteria such as steam pressure, the
history of furnace corrosion, capital budget, and maintenance expectations. The list of common means of
protection includes chromized carbon steel tubes,
chromized pin studs, carbon steel pin studs, metallic
spray coatings, high density pin studs, 304L, Alloy 825
and Alloy 625 composite tubes, and weld overlay of
carbon steel tubes. Normally, carbon steel tubes are
used below 900 psig (6.2 MPa) and tubes with an alloy outer surface are used above this pressure.
A new or rebuilt high pressure recovery boiler may
have several different tubes in the lower furnace (see
Fig. 12). The floor may be carbon steel with pin studs.
To provide additional circulation margin in the floor,
and protect against extreme heat absorption upset
conditions, the use of multi-lead ribbed (MLR) tubing
has become common, and has become the norm in
carbon steel floors regardless of whether the floor is
sloped or flat. It is also common for carbon steel floors
to use tubes with an alloy outer surface for the first 3
ft (0.9 m) from each side wall, as these tubes can have
accelerated corrosion rates over the remainder of the
floor due to the continued exposure to molten smelt.
The vertical walls from the floor to an elevation above
the primary air port elevation would normally be 825
composite or 625 weld overlay. Above this elevation,
up to approximately 3 to 15 ft (0.9 to 5 m) above the
tertiary air ports (or quaternary zone), 304L can be
used to reduce costs.
Materials continue to be studied and evaluated in
the laboratory and in operating recovery boilers for
corrosion protection.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
Carbon Steel
with Pin Studs
(<900 psig/6.2 MPa)
Alloy 625, 825
Smelt Runs
Carbon Steel
with Pin Studs
Fig. 12 Material zones in lower furnace.
28-11
The Babcock & Wilcox Company
Increased industry emphasis on high pressure and
temperature operation, along with the higher availability demanded of large boilers and the trend of
many mills being dependent upon a single recovery
boiler, have required the decreased maintenance afforded by modern composite tubes. The single-drum
boiler designed in 1987 featured readily available 2.5
in. (64 mm) OD composite tubes with 0.5 in. (13 mm)
wide membrane bars. Fig. 13 chronicles the evolution
of furnace wall construction with the decreasing width
between tube seal bars.
Two-drum generating bank
The two-drum generating bank has evolved from
a multi-pass design to a single pass design, common
since the early 1960s. The multi-pass design generally had two flue gas passes, with the gases entering
the bank near the top, being directed downward with
a tile baffle wall integral to the bank, then turning
and flowing upward, exiting the bank near the top
and flowing out to the economizer.
In the 1960s, the generating bank became a single
gas pass bank. The flue gas enters and traverses the
entire generating bank height in one horizontal
crossflow pass to the outlet flue. The tube spacing is 5
in. (127 mm) side spacing using 2.5 in. (64 mm) tubes.
The generating bank screen, tubes between the superheater and generating bank, was also originally
on 5 in. (127 mm) side spacing and became an area
for pluggage, especially when the original capacity of
the recovery boiler was exceeded. Today, an existing
generating bank screen can be rearranged to provide
a wider 10 in. (254 mm) side spacing to alleviate this
pluggage potential.
In the 1980s, a corrosion phenomenon was discovered in the lower portion of the generating bank just
outside the lower drum. Near-drum corrosion could
result in rapid corrosion of the generating bank tubes
immediately above the lower drum surface. The corroded area is typically 0.25 to 0.50 in. (6 to 12 mm) in
diameter and can be located 180 degrees apart on the
sides of the tubes. The corrosion is normally within 1
in. (25 mm) of the lower drum top surface. The corrosion rate can be very high and is identified through
ultrasonic testing of the tubes from inside the lower
drum. In 2001-2002, B&W developed and patented a
new product called GenClad® to protect the carbon steel
tube surface immediately above the lower drum (see
Fig. 14). The generating bank tube is coated with
309H stainless steel, approximately 0.050 in. (1.27
mm) thick, using a laser fusion method. The tube is
then swaged to reduce the tube outside diameter to
match the drum hole and the cladding is smoothed in
the process, ready for rolling into the lower drum. The
cladding is put on the tube in an area that is swaged
and is extended into the gas stream several inches to
provide protection from near-drum corrosion.
Evolution of the modern, single-drum design
The 1980s saw an increase in the pulp and paper
industry’s need for high pressure and temperature
steam generation from the recovery boiler. This trend
was paralleled by the demand for large, conservatively
sized furnaces and general acceptance of the singledrum, all welded boiler design. B&W commissioned its
first modern single-drum boiler in 1989, at Gaylord
Container Corporation in Bogalusa, Louisiana.
In the two-drum design arrangement, the drums
are exposed to combustion gases which limit the drum
length that can be effectively supported. This maximum length established the design capacity of the twodrum arrangement at about 5 × 106 lb (2.3 × 106 kg)
of dry solids per day. In the single-drum arrangement,
the steam drum is moved out of the gas flow path,
thereby removing this limitation and allowing recovery
boilers designed to process daily solids rates of up to 9 to
10 × 106 lb (4.1 to 4.5 × 106 kg) of dry solids per day.
Black liquor solids concentration
The air pollution legislation of the mid-1960s forced
major changes in recovery boiler design. To reduce
malodorous emissions, the direct contact evaporator
was replaced by additional multiple effect evaporator
capacity to obtain the optimum liquor concentration.
Economizer surface was added for flue gas cooling that
was previously accomplished in the direct contact
evaporator.
Fig. 13 Evolution of wall construction.
28-12
Floor design
There are two generally accepted floor arrangements for recovery boilers: a full sloped floor design
and a flat or decanting style. The full sloped design
slopes the entire floor at 4 to 6 degrees, and is intended
to produce an arrangement that results in a complete
drainage of the smelt. The flat or decanting style has
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
Lower
Drum
GenClad
Protective
Layer
tainer Corporation) in Hodge, Louisiana; it generated
steam at 1250 psig (8.6 MPa) and 900F (482C).
B&W’s high steam temperature design philosophy
is reflected in the arrangement of superheater surface.
The inlet primary superheater bank is placed following the furnace cavity, with steam flowing through
the bank parallel to the gas flow. This results in the
coolest available steam flowing through the superheater tubes exposed to the hottest gas temperatures
and the radiant heat from the furnace. This arrangement minimizes the metal temperature of the superheater tubes.
Early recovery boilers had front superheater sections spaced on 10 in. (254 mm) side spacing and rear
sections spaced on 5 in. (127 mm) side spacing. This
arrangement was used when the furnace construction
Lower
Drum
Fig. 14 Carbon steel tube surface protected with GenClad®.
Burners
little or no slope, and is intended to maintain a pool of
smelt in the lower furnace. B&W traditionally provided
only the sloped floor for all two-drum units and all
single-drum units. Sloped tubes provide positive circulation and greater margin for waterside operational
upsets in this high heat input area of the furnace.
Floor arrangements are shown in Fig. 15.
Flat or decanting floors may be modified to incorporate some sloping capabilities, primarily at the front
and rear of the furnace and along the side walls. B&W
has a dual-sloped dihedral design, sloped at the sides,
which can increase flow and circulation margin when
conditions require. From an operational standpoint,
the sloped or decanting styles allow some inventory
of smelt in the lower furnace. Some operators feel this
improves operation and reduces smelt spout and opening issues. Existing fully-sloped floors may be modified to achieve a partial decanting effect by dual sloping the floor from the front and rear. This provides
the desired smelt inventory while maintaining sloped
tubes for circulation. Smelt spouts may also be raised
slightly above the floor level to provide a pool of molten smelt immediately in front of the smelt openings.
Lower furnace floor support design has evolved over
the years. Floor beams under the floor tubes have increased in number to help strengthen the floor and
reduce the potential for damage that can result from
heavy salt cake falls from the upper furnace elevations. Floor beam end connections at the side walls
have been redesigned for additional strength, to hold
side walls against the floor in the event of a major
furnace upset or explosion. These improvements have
led to a more rigid design able to withstand a variety
of operational conditions.
Superheater design
B&W’s first recovery boiler designed for elevated pressure and temperature was placed in operation in 1957,
at Continental Can Company (now Smurfit-Stone ConSteam 41 / Chemical and Heat Recovery in the Paper Industry
Secondary
Air Ports
Primary
Air Ports
Sloped Furnace Bottom
Burners
Secondary
Air Ports
Primary
Air Ports
Decanting Floor
Fig. 15 Recovery boiler floor arrangements.
28-13
The Babcock & Wilcox Company
was 3 in. (76 mm) tubes on 5 in. (127 mm) centers.
The closer spaced 5 in. (127 mm) side spaced sections
may be modified to 10 in. (254 mm) side spacing to
alleviate a potential pluggage area, particularly at
higher loads. When these superheater components are
replaced for any reason, consideration should be given
to make the banks consistent with all 10 in. (254 mm)
side spacing. This may require a change in superheater surface area, but will result in a superheater
that offers improved cleanliness.
Ash buildup and superheater surface plugging have
frequently limited availability of the recovery boiler. To
avoid these conditions, in 1968 B&W established a 12
in. (305 mm) side spacing for the entire superheater
bank, abandoning the conventional 5 and 6 in. (127
and 152 mm) spacing in the secondary superheater construction. This increased the clear side spacing in the
superheater from 3.5 to 9.5 in. (89 to 241 mm).
Superheater tie arrangements have evolved as tube
backspacing has changed and improved surface configurations have been adopted. Pendant superheaters (see Fig. 18) have utilized D-links or tongue and
groove ties in the fore and aft direction. The tongue and
groove tie allows for greater tube differential expansion
and improved welding capabilities. Platen superheaters
(see Fig. 18) have used pin and pipe ties, or a slip spacer
type of tie, to restrain the tubes.
Economizer design
The recovery boiler economizer has evolved several
times over the years in response to the change to low odor
operation, cleanliness, increased heat utilization (effi-
ciency), and reliability. There are several current designs
which meet the needs of the industry (see Fig. 16).
The close side-spaced, horizontal, continuous-tube
economizer was an early design used to reduce the
temperature going to the direct contact evaporator or
air heater. To keep gas temperatures high for the direct contact evaporator or air heater (600F/316C or
greater), the economizer was small. This economizer
was always a crossflow arrangement with the gases
flowing perpendicular to the tube surface. This was
an efficient method of heat absorption, but presented
a cleaning problem. Instead of sootblowers, B&W developed and used shot systems for cleaning gas side
deposits. This system took small pieces of metal, such
as blanks from the manufacture of nuts and bolts, and
dropped them across the economizer surface. The shot
was collected in a hopper and returned to drop on the
economizer surface. This was done repeatedly to clean
any salt cake deposits from the outer surface of the
tube. This method of cleaning was not as effective as
sootblowing and presented problems with both the
return system and tube damage over time.
When direct contact evaporators were discontinued,
the economizer size needed to increase. The gas temperature exiting the direct contact evaporator is normally around 400F (204C) and a new, larger economizer was designed to provide the same exit temperature. Gas flow across the tubes (perpendicular) was
maintained due to its efficient heat transfer, but to
accommodate the increased economizer size necessary,
the economizer arrangement was changed to vertical
tubes with multiple (three or five) crossflow gas paths.
Boiler
Bank
Gas Flow
Boiler
Bank
Gas
Inlet
Gas
Inlet
Water
Outlet
Gas
Inlet
Water
Inlet
Gas
Outlet
(a) Horizontal
Gas
Outlet
Gas
Outlet
(b) Five-Pass Crossflow
(c) Longflow
Gas
Outlet
(d) Three-Pass
Cascading Longflow
Fig. 16 Recovery boiler economizer arrangements.
28-14
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
The five-pass bare tube economizer design contained
much greater heating surfaces than would have been
available with the close side-spaced horizontal surface,
and was designed to improve gas-side cleanliness.
As new recovery boilers became larger in capacity
or existing boilers underwent capacity increases, the
higher flue gas quantities, velocities and carryover
made cleanliness an issue. This promoted the development of the longflow economizer (Figs. 4 and 20).
The longflow economizer is a two gas/two water pass
arrangement that has some limited amount of
crossflow surface at entrances and exits of the banks,
but primarily relies on the parallel flow of gases across
the tubes for heat transfer. Because the flow of gases
parallel to tube surfaces is less efficient than gas flow
across tubes, longitudinal fins were added to the tube
to enhance the effective tube surface area and improve heat transfer. Minor revisions have occurred to
the longflow economizer over the years to make all
tubes straight along with improving the tie design and
arrangement. Water flow is always from bottom to top.
The economizer bank closest to the gas outlet is the first
water pass. The feedwater enters the bottom of this
bank, exits the top, and is piped to the bottom of the
bank closest to the generating bank. The water exits
the top of this second water pass and is directed to the
steam drum.
Space may sometimes be limited for a longflow economizer retrofit without major building modifications. An
alternative finned tube design was developed by B&W
for this condition, the three-pass cascading longflow
arrangement. This design incorporates considerable
crossflow effectiveness while opening up the bank to
reduce gas-side velocity and improving the overall
cleanliness.
The horizontal continuous tube economizer was reintroduced in a version that has increased the tube
spacing and provided for effective sootblowing. This
economizer can be supplied when space limitations
dictate a more compact design to reduce building modifications. It is used primarily when large regenerative
air heaters are replaced with an economizer.
The choice of economizers for retrofitting existing
recovery boilers should be made by the boiler designer,
working with the mill and the existing arrangement.
New recovery boilers will be arranged with straight
tube longflow designs, while retrofits may use any of the
designs identified in the evolution discussion. Regardless of arrangement, the economizer must have good
sootblower coverage and personnel access for inspection.
Combustion air system
The first recovery boiler to introduce air at three
furnace levels – primary, secondary and tertiary – was
built by B&W in the late 1940s. In 1956, a concentrated development effort was successful in providing
fuller utilization of tertiary air, which had been largely
ineffective in earlier designs. Today’s advanced air
management system is a result of extensive laboratory scale and computer flow modeling, theoretical
consideration for the air penetration across the furnace at the secondary and tertiary air levels, and testing of different air system configurations on operatSteam 41 / Chemical and Heat Recovery in the Paper Industry
ing boilers. Several features resulting from this development program include the use of variable velocity
control dampers on the secondary and tertiary air
ports to better regulate air penetration across the furnace area, an interlaced port arrangement to provide
better gas mixing within the furnace, and optimization of port location.
Design considerations for B&W
recovery boiler
Furnace design
The design of the modern recovery boiler and its
associated equipment systems must first consider efficient black liquor combustion.
The overall black liquor composition (chemistry,
percent solids, and heating value) determines how the
liquor dries in the furnace. Some compositions of liquor characteristics (higher solids and heating values)
are more conducive to in-flight, suspension drying of
the droplets, while other characteristics (lower heating values or solids) may require additional droplet drying time. In these instances, spraying liquor on the
walls between the secondary and tertiary air port levels can provide greater dehydration prior to falling onto
the hearth char bed. Flexibility in operating parameters
(combustion air quantities, distribution and temperatures, liquor spray methods and characteristics) is required to accommodate potentially varying conditions.
Primary air enters the furnace around the perimeter of the hearth bed. The controlled reducing atmosphere at the hearth burns the char at the bed surface to maximize reduction of Na2SO4 to Na2S in the
smelt. The remaining air is admitted at the secondary and tertiary air zones. The total air admitted
through the primary and secondary air ports is approximately the stoichiometric requirement for black
liquor combustion. High pressure air entering through
large secondary ports penetrates across the furnace
to assure mixing with the volatile gases rising from
the char bed. Combustion at the secondary air level
achieves a maximum furnace temperature zone below the liquor spray for drying the liquor. Secondary
air also limits the height of the char bed by providing
air for combustion across the bed surface.
Further turbulence and mixing are created by admission of tertiary air, which assures complete combustion of unburned gases rising from the secondary
zone and of volatiles escaping from the sprayed liquor.
Tertiary air mass penetration also provides a uniform
temperature and velocity profile of combustion gases
entering the convection surface. Quaternary air is a
fourth level of air which is sometimes applied above
the tertiary zone. Quaternary air has been shown to
lower NOx and particulate emissions, and is being
applied to recovery boilers in original design or as retrofits and upgrades.
The recovery boiler furnace must also be designed
for efficient removal of the molten inorganic chemicals as smelt. Finally, the combustion gases and particulate carryover must be adequately cooled in the
28-15
The Babcock & Wilcox Company
furnace to minimize deposition on convection surfaces.
The first step in the design of a new recovery boiler
is the selection of furnace plan area, defined as the
furnace width times depth. The plan area is generally set to achieve a black liquor solids heat input of
900,000 to 950,000 Btu/h ft2 (2.83 to 2.99 MW/m2). As
the solids heating value decreases, a larger furnace
plan area is desirable. However, an oversized plan
area can lead to local cold spots on the smelt bed, which
in turn limit reduction efficiency. Cold spots can also
lead to unstable furnace blackouts. A large plan area
further constrains load turndown with stable combustion. An undersized plan area generally leads to increased fume and particle carryover.
Once the plan area is established, the width and
depth dimensions are selected. Maintaining a depth
to width ratio between 1.0 and 1.15 allows an effective arrangement of the combustion air ports and generally permits an economical arrangement of convection pass heat transfer surfaces. In smaller recovery
furnaces designed for high steam temperature, a
higher aspect ratio permits increasing the depth to
accommodate the large superheater surface. Furnace
height is then determined by the radiant furnace heat
transfer surface required to cool the combustion gases
below 1700F (927C).
The surface of the floor and wall tubes in the lower
furnace must be protected against the corrosiveness
of the smelt and partially combusted gases. The most
widely accepted approach today is to build the furnace
and floor of composite tubes (alloy tube material over
a base carbon steel tube). This tube construction
should extend to 3 ft (0.9 m) above the tertiary air
ports. Above this elevation, carbon steel tube and
membrane construction is adequate.
Wide closure plates attached to tubes bent to form
air ports and other openings can result in potentially
high localized stress areas. Wide closure plates suffer
from corrosion, burn back and cracking. This adversely affects the air flow area of the port opening
and has the potential for closure plate cracking that
propagates into the furnace wall tubes. The modern
furnace openings are designed without closure plates
to minimize this potential (Fig. 17).
Structural attachments must also minimize tube
stresses. In high stress areas, a plate stamping is
welded to the tubes, and the structural member is
attached to this plate. This plate stamping is contoured
to provide additional weld carrying load into the tube
wall, permit flexibility for the absorption of thermally
induced loads, and lower the potential for fatigue and
stress corrosion related failures. The windbox attachment to the tube wall, shown in Fig. 17, uses plate
stampings that are shop-attached, which permits field
erection without having to make any field attachment
welds directly to the pressure part. This design and
construction philosophy is applied throughout the
pressure part enclosure for all attachment welds.
Upper furnace and arch arrangement
Combustion is completed in the tertiary zone. The
water-cooled furnace walls and volume above this zone
provide the necessary surface and retention time to cool
28-16
Fig. 17 Burner and secondary air port windbox attachments.
the gas to temperatures where sootblowers can effectively remove the chemical ash from convection surfaces.
The furnace arch, or nose, serves several important
functions. The arch shields the superheater from the
radiant heat of the furnace. The high temperature
steam loops of the superheater are completely protected. Penetration of the arch into the furnace uniformly distributes the gas entering the superheater.
An eddy above and behind the arch tip causes the gas
to recirculate in the superheater tube bank, with a
reverse gas flow between the superheater and the
upper arch face preventing hot gas from bypassing
the superheater surfaces. The angle of the arch is set
to minimize the repose of deposited ash on its surface.
Furnace screen
In some recovery boilers, the superheater surface
is insufficient to adequately cool the combustion gases
before they enter the boiler bank. This is common in
boilers designed for low steam temperature or when
a recovery boiler’s liquor burning capacity is significantly increased resulting in an increase in furnace
exit gas temperature. A furnace screen can be used
to absorb the additional heat, thereby maintaining an
acceptable temperature of the gas entering the boiler
bank section. When designing a new recovery boiler,
the required heat absorption can often be accomplished through added furnace surface (height) and/
or an oversized superheater. Larger furnaces can impact the overall building size and therefore increase
the cost of the project. The furnace screen represents
an economical alternative to a larger furnace or superheater component.
When a furnace screen is required, the screen tubes
are in line with the superheater sections to reduce
pluggage potential. The sloped section of the screen
originates inside the furnace arch to protect the tubes
from falling salt cake deposits and to add strength to
the sloped tubes. Tubes in the sloped section of the
screen were originally attached to each other using
round bars on either side of the tubes, welded parallel to the tubes to provide structural integrity. Current
retrofit designs use membrane bar similar to furnace
wall construction (see Chapter 23). The top most tube
currently has a half-wide membrane bar on the top
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
surface to improve structural integrity and further reduce potential tube damage caused by salt cake falls.
Convection surface
After leaving the furnace, the flue gases pass across
the steam-cooled superheater banks to the longflow
boiler bank and finally to the economizer sections. (See
Fig. 4.) As the gas is cooled, entrained ash becomes
less sticky and adheres less to the tube surfaces. As a
result, it is possible to space the tubes in the convection banks progressively closer together. The closer
spacing results in higher gas velocities and improved
convection heat transfer rates, which in turn permit
a more economical design as less heat transfer surface
area is required.
Superheater
The superheater surfaces are exposed to the highest
gas temperatures and, consequently, are arranged on a
12 in. (305 mm) side spacing. This results in very low
gas velocities and prevents the bridging of deposits.
In arranging superheater surface, it is desirable to
maintain low tube temperatures. Lower temperatures
reduce the potential for high temperature corrosion
and allow the use of less expensive low alloy steel.
Temperatures are reduced by establishing a high
steam flow through each tube, by arranging the
coolest steam to flow through the superheater tubes
exposed to the hottest gas temperatures, and by locating the majority of the superheater tube banks
behind the furnace arch tip, shielded from furnace
radiation. Superheater surface behind the furnace
arch tip is considered convective surface and does not
experience furnace radiation. Superheater surface
types and arrangements are shown in Fig. 18.
From the drum, saturated steam enters the front
tube row in the first or primary inlet superheater bank
and flows through successive tube loops in parallel
with the flue gas flow. (See Fig. 18.) The secondary
superheater is located in the cooler gas region between
the primary banks or behind the primary banks, depending upon final steam temperature. Steam flow in
this secondary superheater is generally opposite to the
gas flow to achieve a higher steam temperature. The
superheater surface, steam direction and bank placement are determined by engineering and balancing
steam temperature and flue gas temperature. Using
these design guidelines for superheater design, arrangement, and materials selection permits final
steam temperatures up to 950F (510C).
The superheater banks are top supported with the
tube elements expanding downward. The tubes are
interconnected with flexible support ties which allow
independent tube expansion. Tube movement is critical to effective sootblowing. However, lack of tube restraints within a bank can lead to failure at the bank’s
top supports.
The superheater can be arranged as pendant surface (clear backspace between tubes) or platen surface
(near-tangent backspace between tubes). Different
heat transfer methods are used when calculating pendant and platen arrangements. The pendant arrangement has greater effective surface area due to a greater
Steam 41 / Chemical and Heat Recovery in the Paper Industry
amount of the tube circumference available to absorb
heat from the flue gases. This results in fewer superheater rows in depth for the same steam temperature
rise. Superheater banks can be radiant, convective,
or a combination (see Chapter 19). Radiant surface is
in front of the furnace arch tip. This surface is the first
steam pass after leaving the steam drum in order to
utilize non-stainless steel tubing.
Boiler bank
Today’s kraft recovery boiler generally incorporates
a single steam drum, with a longflow boiler bank arranged downstream of the superheater. In passing
across the superheater and rear wall screen tubes, the
flue gas should be cooled below the ash sticky temperature prior to entering the boiler bank. For ashes with
extremely low sticky temperatures, particular attention must be given to sootblower locations.
The boiler bank is constructed of shop-assembled
tube sections arranged as modules inside a watercooled enclosure (Fig. 19). Tubes in each section are
connected to headers, with water entering the lower
header and the steam-water mixture exiting the upper headers. As the flue gas enters the bank, it turns
downward and flows parallel to the tube length, providing easy cleanability. Within the bank, a central
cavity accommodates fully retractable sootblowers.
The cavity permits personnel access for visual tube
inspection adjacent to sootblower lance entry. Ash
deposits dislodged during sootblowing are collected in
≤0.75 in.
(19.05 mm)
SSH
PSH1
SSH
Boiler
Bank
PSH2
Platen
>0.75 in.
(19.05 mm)
Pendant
Fig. 18 Superheater arrangements.
28-17
The Babcock & Wilcox Company
retractable sootblowers. Trough hoppers are attached
to the economizer casing to collect dislodged ash deposits.
The economizer surface area is set to achieve a final gas outlet temperature approximately 100F (56C)
higher than the feedwater temperature. Although it
is possible to achieve an exit gas temperature closer
to that of the feedwater, the decreased temperature
differential results in substantially increased surface
requirements for small improvements in end temperature. In addition to this thermodynamic limitation,
concern for cold end corrosion generally establishes a
minimum gas exit temperature around 350F (177C).
The minimum recommended temperature of the feedwater entering the economizer is 275F (135C) for corrosion protection of the tube surface. With special considerations, the feedwater entering the economizer
can be designed for as low as 250F (121C).
Fig. 19 Boiler bank isometric.
a trough hopper connected to the bank enclosure. Tube
section inlet headers are widely spaced and vertically
staggered to facilitate ash dropping into the hopper.
Impact-type particle deposition on the boiler bank
tubes is less likely to occur with the gas longflow orientation. As a result, the allowable gas velocity in the
downflow portion of the bank can be increased.
To improve heat transfer, longitudinal fins are
welded to the front and back of each tube. Fins are
tapered at the ends and welded to the tube on both
sides. The welds are terminated by wrapping around
the end of the fin. This combination of welding technique and tapered ends assures minimal stress concentration at fin termination for fins as large as 1.5
in. (38 mm).
Economizer
The boiler bank surface area is typically set to
achieve a nominal exit gas temperature of about 800F
(427C). This temperature maintains a reasonable differential with the saturated steam temperature [610F
(321C) for a 1650 psig (11.4 MPa) drum pressure] and
allows the use of carbon steel casing to enclose the
downstream economizer banks. The modular economizer has vertical finned tubes arranged in multiple
sections with upward water flow and downward
longflow of gas (Fig. 20). The common arrangement
features two banks. The flue gas enters at the upper
end and discharges at the lower end of each bank. Gas
flows down the length of the bank to provide good
cleanability. As in the boiler bank, a central cavity dimensioned for personnel access accommodates fully
28-18
Emergency shutdown system
An emergency shutdown procedure for black liquor
recovery boilers has been adopted by the Black Liquor
Recovery Boiler Advisory Committee (BLRBAC) in the
U.S. An immediate emergency shutdown must be performed whenever water enters the furnace and can
not be stopped immediately, or when there is evidence
of a leak in the furnace setting pressure parts. The
boiler must be drained as rapidly as possible to a level
8 ft (2.4 m) above the mid point of the furnace floor.
An auxiliary fuel explosion can occur when an accumulated combustible mixture is ignited within the
confined spaces of the furnace and/or the associated
boiler passes, duct work and fans which convey the
combustion gases to the stack. A furnace explosion will
result from ignition of this accumulation if the quantity of the combustion mixture and the proportion of
air to fuel are within the explosive limit of the fuel
involved. The magnitude and intensity of the explosion will depend upon both the quantity of accumulated combustibles and the proportion of air in the
mixture at the moment of ignition.
Contacting molten smelt with water can also result
in a very powerful explosion. The mechanism for a
smelt-water explosion is keyed to the contact of water
with hot liquid smelt. Rapid water vaporization causes
the propagation of a physical detonation or shock wave.
In the design and operation of black liquor recovery boilers, every effort is made to exclude water from
any source from getting to the furnace, or introducing liquor at less than 58% solids. For example, furnace
attachment details are designed to prevent external tube
loads, which can lead to stress assisted corrosion.
Recovery boiler auxiliary systems
Black liquor evaporation
The high black liquor solids concentration required
for efficient burning is achieved by evaporating water from the weak black liquor. Large amounts of water
can be economically evaporated by multiple effect
evaporation. A multiple effect evaporator consists of
a series of evaporator bodies, or effects, operating at
different pressures.5 Typically, low or medium presSteam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
vessel with the flue gas admitted through a tangential
inlet near the conical bottom. The gas flows in a whirling helical path to the cylinder’s top and leaves through
a concentric re-entrant outlet. Black liquor is sprayed
across the gas inlet to obtain contact with the gas. The
liquor droplets mix intimately with the high velocity gas
and are centrifugally forced to the cylinder wall. Recirculated liquor flowing down the cylinder wall carries the droplets and any dust or fumes from the gas to
the conical bottom, out through the drain, and into an
integral sump tank. Sufficient liquor from the sump
tank is recirculated to the nozzles at the top of the
evaporator to keep the interior wall wet, preventing ash
accumulation or localized drying.
In the cascade evaporator, horizontally spaced tubular elements are supported between two circular side
plates to form a wheel that is partially submerged in
a liquor pool contained in the lower evaporator housing. The wetted tubes are slowly rotated into the gas
stream. As the tubes rise above the liquor bath, the
surface coated with black liquor contacts the gas
stream flowing through the wheel.
Fig. 20 Economizer isometric.
sure steam is utilized in the first evaporator effect and
then the vapor from one body becomes the steam supply to the next, operating at a lower pressure. Modern evaporator systems integrate a concentrator into
the flow sequence to achieve the final liquor concentration. As a general rule, each pound of water evaporated from the weak liquor results in one additional
pound of high pressure steam generation in the recovery boiler.
For many years, direct contact evaporation was the
technology used to achieve firing solids to the recovery boiler, and may still be necessary to evaporate liquor from some special fiber sources. In the direct contact evaporator, liquor and flue gas are brought together, heat is transferred from flue gases to the liquor, and mass transfer of liquor water vapor to the
gas occurs across the liquor-gas interface. Adequate
liquor surface must be provided for the heat and mass
transfer. The gas contact acidifies the liquor by absorbing CO2 and SO2, which decreases the solubility
of the dissolved solids and requires continuous agitation. The acidification also results in the release of malodorous compounds into the flue gas, a negative aspect of direct contact evaporation.
There are two types of direct contact evaporators
used in the recovery unit, cyclone and cascade. The
cyclone evaporator (Fig. 21) is a vertical, cylindrical
Steam 41 / Chemical and Heat Recovery in the Paper Industry
Black liquor oxidation
When a direct contact evaporator is used, odor can
be reduced by oxidation of sulfur compounds in the
liquor before introduction to the evaporator. The oxidation stabilizes the sulfide compounds to preclude
their reaction with flue gas in the evaporator and the
consequent release of reduced sulfur gases. Oxidation
can effectively reduce, but does not eliminate, discharge of these reduced sulfur gases. The direct contact evaporator is the prime source of odor.
Odor is generated in direct contact evaporators
when the hot combustion gases strip hydrogen sulfide
gas from the black liquor:
2NaHS + CO2 + H2O = Na 2 CO3 + 2H2 S
(11)
Fig. 21 Cyclone evaporator.
28-19
The Babcock & Wilcox Company
Oxidation stabilizes the black liquor sulfur by converting it to thiosulfate:
2NaHS + 2O2 = Na 2 S2 O3 + H2O
(12)
Black liquor oxidation involves high capital and operating costs; the oxidation step also robs the liquor of
heating value. Modern recovery facilities incorporate
multiple effect evaporators, and the low odor design, which
eliminates the need for a direct contact evaporator.
Black liquor system
Recovery boilers are operated primarily to recover
pulping chemicals. This objective is best realized by
maintaining steady-state operation. Recovery boilers
are base loaded at a selected black liquor feed flow or
heat input, in contrast to power boiler applications
where fuel flow is varied in response to demand for
steam generation.
The black liquor solids concentration can vary with
the rate that recirculated ash sheds from heat transfer surfaces, the rate it is collected in the precipitator,
and the rate it is returned to the black liquor stream
system. Considerable fluctuations can occur, depending on which surface is being cleaned by sootblowers,
the frequency of sootblower operation, and the rapping sequence of precipitator collection surfaces. The
black liquor system design should provide uniform
dispersion of the ash into the liquor to minimize the
fluctuation of solids at the burner. This is increasingly
important as the liquor solids concentration is increased into the regime where burners are maintained
in a fixed position and liquor drying is in-flight (not
on the walls). A fluctuation in ash flow would change
the solids concentration by several percent, significantly impacting the characteristics of the liquor.
A heater is used to adjust the black liquor temperature to that required for optimum combustion and
minimum liquor droplet entrainment in the gas
stream. The black liquor is typically heated in a tubeand-shell heat exchanger, using low pressure steam
on the shell side and black liquor on the tube side.
There are two general categories of heater designs that
can be operated with minimum scaling of the heat transfer surface. The first uses a conventional heat exchanger with once-through flow of liquor at high velocity in the tubes. The tubes have polished surfaces to
inhibit scale formation. This heat exchanger is satisfactory for long periods of operation without cleaning.
The second approach is to recirculate liquor through
a standard heat exchanger with stainless steel tube
surface to maintain high velocities that inhibit scale
formation. This approach also permits long periods of
operation without cleaning.
As the liquor solids concentration increases above
70%, storage can become a problem. Moreover, it becomes increasingly difficult to blend recycled ash into
the highly concentrated liquor. Recycled ash can be
returned to an intermediate concentration liquor
stream (of about 65% concentration) prior to final
evaporation in a concentrator. In this type of arrangement, liquor is routed to the recovery furnace from an
evaporator system product flash tank. The as-fired
28-20
liquor temperature is established by controlling the
flash tank operating pressure.
There are two designs of liquor burners, the oscillator and the limited vertical sweep (LVS). Oscillators
are generally applied to liquors of lower heating values or percent solids where longer droplet drying time
is necessary. LVS burners are best used for higher
percent solids and heating value liquors where inflight, suspension drying of the droplets works well.
Both types of burners utilize a nozzle splash plate to
produce a sheet spray of coarse droplets.
The oscillator sprays the black liquor on the furnace
walls, where it is dehydrated and falls to the char bed.
The oscillator burners, located in the center of the furnace wall between the secondary and tertiary air ports,
are continuously rotated and oscillated, spraying liquor
in a figure eight pattern to cover a wide band of the
walls above the hearth. Oscillators work well on smaller
units, or with a wide range of liquor characteristics.
With LVS burners (Fig. 22), black liquor is sprayed
into the furnace for in-flight drying and devolatization
of the combustible gas stream rising from the char bed.
The objective of the LVS burner is to minimize the liquor on the wall. The LVS gun is normally used in a
fixed position, but can also sweep vertically to burn
low solids liquor or those with poor burning characteristics. LVS burners are normally applied to larger
sized, heavier loaded units.
The temperature and pressure of atomized liquor
directly impact recovery furnace operations. Lower
temperature and pressure generally create a larger
Fig. 22 Limited vertical sweep burner.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
particle or droplet of atomized liquor. This minimizes
the entrainment of liquor in the combustion gases
passing to the heat absorbing surfaces. Where wall
drying is carried out, large liquor droplets maximize
the liquor sprayed on the wall and minimize in-flight
drying. For oscillator firing, liquor at approximately
230F (110C) and 30 psig (207 kPa) generally provides
the most satisfactory operation. For LVS burners, liquor with a slightly lower pressure of 25 psig (172 kPa)
and higher temperature of 250F (121C) provides acceptable results.
As the liquor sprayed on the walls builds, it eventually falls to the char hearth. The majority of the char
falling from the wall is deposited in front of the primary air ports, requiring 30 to 50% of the total air to
be introduced through the primary ports.
In-flight drying deposits a minimum of char in the
primary air zone around the periphery of the unit, as
all the drying and a majority of the devolatization are
in-flight over the furnace area. Consequently, less
primary air flow is required to keep the char from in
front of the primary air ports. Because the higher liquor solids concentration dictated by in-flight drying
translates into less water evaporated in the furnace,
a greater fraction of the combustion heat released is
available to maintain bed temperatures. Less primary
air is therefore required when burning liquor in-flight
in contrast to the lower concentration liquors encountered in oscillator burner applications.
Ash system
The sodium compounds entrained in the flue gas
originate from fume generation and liquor droplet
carryover from the lower furnace. The resultant ash
drops out of the flue gas stream and is collected in
trough hoppers located below the boiler and economizer modules. The electrostatic precipitator removes
nearly all the remaining ash.
The majority of the entrained ash is Na2SO4, and is
commonly referred to as salt cake ash, or simply, salt
cake. The ash collected in the trough hoppers and
precipitator must be returned to the black liquor to
recover its significant sodium and sulfur contents. This
is accomplished by mixing the ash into the liquor in a
specially designed tank. The salt cake ash is transferred to the mix tank through a wet ash sluice system or a drag chain ash conveyor system.
With a dry ash system (Fig. 23), mechanical drag
chain conveyors are bolted to the bottom of the boiler
and economizer trough hoppers, which extend across
the full unit width. The drag chain conveyors are
equipped with heat treated, high alloy forged link
chains to support and convey the flights. The conveyors discharge through rotary seal valves into a collection conveyor. The collection conveyor discharges to
the mix tank where the ash is uniformly mixed with
the liquor.
Drag chain conveyors are also provided across the
floor of the electrostatic precipitator, beneath the collecting surfaces. The conveyors discharge to mechanical combining conveyors, which in turn discharge the
salt cake ash through rotary valves into the mix tank.
Frequently, the dry ash system is arranged with two
Steam 41 / Chemical and Heat Recovery in the Paper Industry
Fig. 23 Dry ash system.
mix tanks, one serving the boiler and economizer hopper ash system and one dedicated to the precipitator.
As discussed previously, successful reductions of
chloride and potassium levels in the ash and black liquor have been achieved through precipitator ash
purging. Ash can be removed periodically to maintain
chloride or potassium concentrations at a specified
level. An ash chute with a rotary valve is added to the
back end of an existing precipitator ash transfer conveyer. When ash purging is desired, the ash conveyer
is reversed and the ash falls through the chute into a
sluice tank.
In a wet ash removal system, black liquor is circulated through the hoppers to sluice the collected ash.
The sluice discharges directly from the hoppers
through large pipes to the mix tank. However, these
pipes can become plugged with ash and overflow liquor which create safety and cleanliness problems.
This has led to wider acceptance of the dry ash mechanical conveyor system. However, the mechanical
conveyors generally require more maintenance than
the wet ash sluice designs.
The mix tank (Fig. 24) includes a mechanically
scraped screen to assure that all material which passes
to the fuel pumps is small enough to readily pass
through the burner nozzles. Scraping is provided by
flights on a low horsepower, slow moving agitator. The
tank is designed to receive salt cake from the generating bank, economizer or precipitator hoppers, mixing it with the incoming black liquor.
Combustion air system
B&W’s advanced air management system provides
combustion air at three, and sometimes four, elevations of the furnace: primary, secondary, tertiary, and
potentially quaternary (Fig. 25). The use of at least
three levels allows performance optimization of the
respective furnace zones – the lower furnace reducing zone, the intermediate liquor drying zone, and the
upper furnace burnout or combustion completion zone.
A quaternary air level may also be applied above the
tertiary zone for additional NOx or particulate control.
28-21
The Babcock & Wilcox Company
Fig. 24 Salt cake mix tank.
The primary air flow quantity must be sufficient to
produce stable combustion and to provide the hot reducing zone for the molten smelt. Increasing primary
air flow beyond the level required to achieve these
objectives increases the amount of Na2S re-oxidized
to Na2SO4. The balance of the air at or less than the
stoichiometric requirement is introduced above the
char bed at the secondary level to control the rate at
which the liquor dries and the volatiles combust, and
to minimize the formation of NOx. The additional air
required to complete combustion is introduced at the
tertiary level (and quaternary if supplied).
The air system may be arranged as a single-fan, twofan (one primary and one secondary/tertiary/quaternary) or three-fan system. On larger systems, additional
provisions are made to bias the air flow between respective air levels, from side to side on the primary and secondary air, or from front to rear on the tertiary air. This
gives additional flexibility to the operator.
The primary air ports are arranged on all four furnace walls about 3 ft (0.9 m) above the floor. Air is
introduced at a low velocity and 3 to 4 in. wg (0.75 to
1.0 kPa) static pressure which prevents it from penetrating the bed. The air lifts the carbon char in front
of the port back onto the bed and maintains ignition.
Approximately 40% of the total air is admitted at
the secondary zone. The air is introduced at the pressure and velocity needed to penetrate the furnace 4
to 6 ft (1.2 to 1.8 m) above the primary air ports. A
velocity damper is used on each port.
Proper secondary air mixing with the gases rising
from the char bed results in volatile combustion generating the heat required for in-flight liquor drying. This
secondary zone typically exhibits the highest temperatures in the recovery furnace. The quantity of secondary air is dictated by the amount of burning required
28-22
to dry liquor and control bed height, and decreases as
the black liquor solids concentration increases.
The balance of the air is admitted at ambient temperature through the tertiary air ports located above
the liquor guns, and through quaternary ports, if supplied. A velocity damper is again used on each port.
The tertiary (and quaternary) flow increases proportionately as the solids increase.
The secondary air ports are normally arranged on the
longest furnace wall, generally the side walls, as the
furnace is deeper than it is wide. In contrast, the tertiary air ports are arranged on the front and rear walls.
Buildup of smelt and char that restricts the air port
openings can cause a performance deterioration. A
reduction in port area affects air pressure at the port
or air flow through the port, depending on which is
being controlled. When air flow is controlled, the effect of plugged ports is to increase air pressure and
push the bed farther from the wall. If pressure is controlled, the effect is a resultant decrease in air flow.
This results in less effective burning of the primary
zone with a decrease in furnace temperature and increased emissions.
Primary air port openings are generally cleaned
(rodded) every two hours to maintain proper air distribution and bed height. Automatic port rodders provide continuous cleaning to maintain a constant flow
area. The automatic port rodding system stabilizes
lower furnace combustion for maximum thermal efficiency and is vital in achieving low emissions.
Secondary and tertiary air ports also require periodic rodding, although the plugging that occurs at
these ports is generally less severe than at the primary
air ports. In the secondary and tertiary ports, the
rodding equipment can be integrated with the velocity control damper. This is necessary to provide synchronization of the damper and rodder drives.
Carbon Burnout,
NO / Particulate
Reduction
Quaternary
Air (0-10%)
Liquor
Firing
Equipment
Tertiary Air
(10-20%)
Devolatilization
and Drying Zone
Chemical
Reduction Zone
(Maximum
Na So Na S)
Secondary Air
( 40%)
Primary Air
( 40%)
Fig. 25 Advanced air management system.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
To further enhance stability in the lower furnace,
the primary and secondary air is preheated in a steam
coil air heater. Low pressure steam, normally 50 to 60
psig (345 to 414 kPa) is used for preheating. Additional preheating is provided by steam at 150 to 165
psig (1034 to 1138 kPa), typically achieving a 300F
(149C) combustion air temperature. When burning
liquors with a low heating value or from a nonwood
fiber, air should be preheated to about 400F (204C).
Water coil air heaters, sometimes used within the
feedwater circuit around the economizer, may also be
used to provide these air temperatures.
Flue gas system
Combustion gas exiting the economizer is routed
through flues to the electrostatic precipitator and induced draft fan before discharge through a stack to
the atmosphere.
The induced draft fan speed controls the pressure
inside the furnace. The fan is normally located after
the precipitator, allowing the fan to operate in the
cleaner gas.
A two-chamber precipitator is normally used. Each
chamber is equipped with isolation gates or dampers
and a dedicated induced draft fan discharging to a
common stack. Flue gas exiting the economizer is divided into two flues, which route the gases to the
precipitator’s two chambers. Each chamber typically has
sufficient capacity to operate the recovery boiler at 70%
load, corresponding to a stable black liquor firing mode.
When designing the precipitator chamber, the expected
gas flow rate should include that of the sootblower steam
and the increased excess air under which the boiler
would operate at a reduced rating. The maximum permissible particulate discharge rate then establishes the
electrostatic precipitator size.
Cleaning system
Ash entrainment in furnace gases is affected by gas
velocity, air distribution and liquor properties. The
design of all recovery unit heating surfaces should
include sootblowers using steam as the cleaning medium. Gas temperatures must be calculated to make
certain that velocities and tube spacings are compatible with the sootblowers.
High levels of chloride and potassium in the black
liquor may require greater cleaning frequency. As unit
overload is increased, additional entrainment of ash
and sublimated sodium compounds also leads to more
frequent water washing. This term describes an offline cleaning procedure which uses high pressure
water to eliminate excessive deposits or buildups on
the boiler’s convection surfaces. In addition to excess
quantities of flue gas ash, velocities and temperatures
throughout the unit are increased, making ash deposits more difficult to remove.
Auxiliary fuel system
The primary objective of the recovery boiler is to
process black liquor. However, the unit can fire auxiliary fuel, usually natural gas and/or fuel oil. This fuel
is fired through specially designed burners, arranged
at the secondary air level. These burners raise steam
Steam 41 / Chemical and Heat Recovery in the Paper Industry
pressure during startup, sustain ignition while building a char bed, stabilize the furnace during upset conditions, carry load while operating as a power boiler,
and burn out the char bed when shutting down.
In some installations, the recovery boiler must be
able to generate full load steam flow and temperature
on auxiliary fuel. These applications typically arise in
mills that cogenerate electricity and/or have limited
power boiler steam generating capability. Increased
auxiliary fuel capacity can be accommodated by adding auxiliary burners above the secondary air level
(typically at or above the tertiary air level).
Upper level burners allow combination black liquor
and auxiliary fuel firing with minimal interference
with lower furnace operations. This is not possible
when operating the secondary level auxiliary burners. Also, the upper level burners can provide higher
steam temperatures at lower loads during startup,
which can be important in mills operating high steam
temperature turbine-generators.
The auxiliary fuel burners are in a very hostile
environment that compromises burner reliability and
increases burner maintenance. B&W has always utilized rectangular shaped bent tube openings for burners to reduce accumulations of salt cake in the burner
windbox and to keep the damaging furnace radiant
heat away from vulnerable burner and lighter components. The oil atomizer or gas pipe elements are manually retracted when not in use. They would then be
manually inserted when needed to start the burners.
The LM2100 auxiliary burner (Fig. 26) is designed
to retract the burner and lighter elements into the
windbox and insert them again to the same location
using locally activated air cylinders. In addition to
protection from radiant heat, the use of air cylinders
also keeps the fuel elements at the correct position
when inserted. The LM2100 improves burner reliability and maintenance. The LM2100 is standard design
for new recovery boilers and can be retrofit to existing recovery boilers of any manufacturer.
Non-condensable gases/waste streams
Within the typical pulp and paper mill, there are
numerous liquid and gaseous waste streams that are
subject to stringent environmental disposal regulations. These waste streams are commonly incinerated
on site. One simple and effective incineration method
is to introduce these streams into an operating boiler.
Gaseous streams are typically characterized as noncondensable gas (NCG) or stripper off gas (SOG). NCG
is a mixture of sulfur compounds and hydrocarbons
mixed with air and is either dilute (DNCG) or concentrated (CNCG). These terms refer to the concentration
of active compounds within the NCG. If the percentage of sulfur compounds and hydrocarbons is below
the lower explosion limit (LEL) in air, the NCG is considered dilute, is essentially foul air, and is relatively
easy to handle. It does, however, present minor challenges. It can be corrosive and is unpleasant to smell.
If the percentage of active compounds is above the upper explosion limit (UEL) in air, the NCG is considered
concentrated. CNCG should be treated as a corrosive fuel
stream. These streams require added precautions.
28-23
The Babcock & Wilcox Company
Fig. 26 B&W’s LM2100® burner.
The explosion limits for some representative gases
found in NCG are shown in Table 4. The generally
accepted LEL for mixtures of gases in air is 2% by
volume, and the generally accepted UEL is 50%. SOG
is usually a mixture of methanol in air, and is typically handled like CNCG.
These gases require special safety precautions for
collection and handling. Their escape must be prevented in and around the boiler building for personnel and equipment protection, and condensate must
not be allowed to enter the furnace. For CNCG gases,
additional precautions are required to avoid fire and
explosion in equipment and transport systems. Positive ignition systems are required for gases entering
the furnace.
It is generally preferred that these non-condensable gases be burned in mill power boilers, as these
units can more easily include the appropriate safety
equipment. One disadvantage to using power boilers
is the requirement to capture the SO2 generated by
combustion of the sulfur compounds, unless the boiler
is equipped with a scrubber. For recovery boilers, the
explosion potential due to tube failures does not make
this type of boiler a good application to introduce foreign streams. BLRBAC does not encourage the introduction of waste streams into recovery boilers. It has,
however, become more commonplace in recent years
to utilize recovery boilers for this disposal, as mills are
Table 4
NCG Gases Explosion Limits
Constituent
Gas
Turpentine
Methanol
Hydrogen Sulfide
Methyl Mercaptain
Dimethyl Sulfide
Dimethyl Disulfide
28-24
Lower Explosion
Limit (LEL)
% Volume in Air
Upper Explosion
Limit (UEL)
% Volume in Air
0.8
7.3
4.3
3.9
2.2
1.1
Not established
36.0
45.0
21.8
19.7
16.1
required to meet more stringent regulations. Recovery boilers can have the ability to capture the SO2 from
NCG combustion. Significant caution and special system design are necessary to safely burn NCG in a recovery boiler.
DNCGs can often be mixed with the combustion air
for the tertiary air port level on a recovery boiler, or
for the stoker on a power boiler. The primary concern
is to assure adequate main fuel, usually equal to or
above 50% of load, to assure burnout of the gases. To
avoid odor problems, the ducts, windboxes and other
air transport components must be air tight. Corrosion
in the feed ducts can be reduced by mixing the gases
with hot air or heating the mixture. For power boilers, if the sulfur input is high, boiler exit corrosion and
emissions can increase. The corrosion rate can be reduced by upgrading alloys and/or coatings or by increasing the gas temperature to stay above the dew point.
For CNCG gases, transport must avoid air leakage
that could move the mixture into the explosive range.
Typically, these gases are fired with a support combustion source, such as an igniter in close proximity,
to assure burnout. Stainless steel piping is used to
avoid corrosion. One stream explicitly excluded from
any boiler incineration consideration is terpenes (turpentine vapor). The UEL of these streams is not defined, and terpenes have been the most prevalent
causes of explosions in non-condensable gas collection,
transport and combustion systems.
For either gas, provision must be made to avoid slugs
of liquid entering the furnace. System design uses flame
propagation arresters to avoid explosions, and safety
interlocks must be integrated into the existing controls.
For any type of waste gas, it is important that a
complete analysis of the fuel parameters (constituents,
amounts, moisture, etc.) be understood so that the
appropriate systems and safeguards can be designed.
It is then possible to determine the proper furnace
temperatures and residence times required to assure
complete combustion.
There are also several liquid waste streams with
disposal requirements. These include soap, tall oil,
methanol, spent acid and secondary sludge. These are
normally blended and combusted with the black liquor
fuel. Under specific circumstances, they may be fired
in a separate, dedicated burner. Turpentine, another
liquid stream, is extremely unpredictable and generally restricted from either of the above methods. Handling and combusting recommendations and cautions
can be found in BLRBAC guidelines.
Smelt spout system
Smelt exits the furnace through specially designed
openings at the low point of the floor and is conveyed
to the dissolving tank in a sloped water-cooled trough,
or smelt spout (Fig. 27). The spout is bolted to the furnace wall mounting box. Most original spout designs
had the machined face of the spout positioned against
the outside of the furnace wall tubes surrounding the
opening. While many of this arrangement are still in
operation, the fully insertable spout has become common. This type of spout inserts directly into the spout
opening, where the spout taps the smelt directly from
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
Fig. 27 Integral smelt spout hood with shatter jet assembly.
the furnace and no smelt contacts the spout opening
tube surface. This has helped alleviate significant
spout opening wear and deterioration.
Insertable spouts use a round-shaped trough. For
noninserted spouts, the trough is V-shaped to correspond to the V-shaped bottom of the wall opening. Either spout design is constructed of a double wall carbon steel trough, with a continuous flow of cooling
water passing between the inner and outer walls.
Given the explosive nature of smelt-water reactions
and the extreme temperature of the molten smelt, the
spout must receive adequate cooling water. A dedicated cooling system with built in redundancy and
multiple sources of backup water assures system reliability (Fig. 28). This system may either be a pressurized cooling system, or more commonly a gravity flow,
induced vacuum system where the water in the smelt
spout is at less than atmospheric pressure. The cooling water is treated in a dedicated, closed cycle to minimize scale-forming contaminants.
Green liquor system
The smelt is dissolved in green liquor in an agitated
tank. Green liquor is withdrawn from the tank at a
controlled density and the volume replaced with weak
wash. The entering smelt stream must be finely dispersed, or shattered, to control the smelt-water reaction by rapid dissolution of the smelt into the green
liquor. Excessively large smelt particles entering the
tank can lead to explosions. The outer surface of a large
smelt particle cools quickly as it contacts the green liquor, forming an outer shell around its hot core. As
the shrinking forces build, the particle shell explodes,
exposing the hot core to water and resulting in the
sudden release of steam. To eliminate large smelt particles from reaching the dissolving tank contents,
Steam 41 / Chemical and Heat Recovery in the Paper Industry
steam shatter jets are located above the smelt stream
to disperse the flow into the tank.
The smelt spout discharge is enclosed by a hood
(Fig. 27). The steam shatter jets are mounted on the
top of the hood, with the nozzle angle adjusted to direct the jet at the smelt stream cascading off the spout
end. The periphery of the hood is equipped with wash
headers to flush the hood walls and prevent smelt
buildup. A door is provided in the hood for operator
access to inspect and to rod the spout and opening.
The dissolving tank is of heavy construction and is
equipped for agitation. One or more agitators, either
side or top entering, are generally used, including an
emergency backup system, such as steam nozzles. A
stainless steel band is commonly used in the carbon steel
tank at the liquor level for corrosion protection, while the
floor is protected with steel grating or poured refractory.
As the smelt is cooled and dissolved into the green
liquor, large quantities of steam are released. The
steam vapors are pulled through an oversized atmospheric vent on the tank to quickly relieve pressure
in the event of a surge or explosion. Smelt particles
and green liquor droplets are entrained in the steamair mixture vented from the tank. These vented gases
also contain H2S that must be removed prior to discharge to the atmosphere. Typically, a vent stack scrubber (Fig. 29) is used to reduce H2S emissions and to
trap entrained particulates. Weak wash is used as the
scrubbing medium to take advantage of its residual
NaOH, which absorbs the malodorous gases.
Alternate processes and liquors
Soda process
With few exceptions, the requirements and features
of the kraft recovery boiler apply to the soda recovery
boiler. Because sulfur is not present in the soda pro-
Fig. 28 Smelt spout cooling system.
28-25
The Babcock & Wilcox Company
The liquor is generally characterized by high viscosity and high silica content. The high viscosity limits the level at which liquor can be concentrated in
multiple effect evaporators, and direct contact evaporators are generally required. Higher combustion air
temperatures are used to compensate for the low liquor concentrations while allowing flexibility in adjusting the firing conditions.
Fig. 29 Vent stack scrubber.
cess, there is no sulfur reduction in the recovery furnace. Soda ash (Na2CO3) is added to the recovered green
liquor. The ash collected from the boiler hoppers and the
electrostatic precipitator is in the form of Na2CO3 and can
be added directly to the green liquor in the dissolving
tank. A salt cake mix tank is not required.
In the furnace, the soda liquor does not form a suitably reactive char for burning in a bed. It is finely
atomized and sprayed into the furnace by multiple
soda liquor burners. The fine spray dehydrates in
flight and combustion takes place largely in suspension in an oxidizing atmosphere. Combustion air is
admitted through primary and secondary air ports
around the furnace periphery, with the hottest part
of the furnace just above the hearth. The Na2CO3 collects in molten form on the hearth and discharges
through the smelt spouts.
The Na2CO3 smelt has a higher melting point than
the kraft process smelt. This makes the soda smelt
more difficult to tap from the furnace and shatter.
Auxiliary fuel burners can be located low in the side
walls, close to the spout wall, to keep the smelt hot for
easier tapping.
Nonwood fiber liquor
Many countries do not have adequate forest resources
for pulp production. As a result, alternative fiber sources
are used, such as bamboo, sugar cane bagasse, reeds and
straw. Black liquor from these fibrous materials requires
special consideration in recovery system design.
28-26
Sulfite process
Pulp produced by the sulfite process is divided into
two broad categories, semi-chemical and chemical.
Semi-chemical pulp requires mechanical fiberizing of
the wood chips after cooking. Chemical pulp is largely
manufactured by the acid sulfite and bisulfite processes, which differ from the alkaline processes in that
an acid liquor is used to cook the wood chips. The acid
sulfite process is characterized by an initial cooking liquor pH of 1 to 2. The bisulfite process operates with a
pH of 2 to 6. Cooking liquor used in a neutral sulfite
process for manufacture of semi-chemical pulps has an
initial pH of 6 to 10. Spent sulfite liquor, separated from
chemical and semi-chemical pulp and containing the
residual cooking chemicals and dissolved constituents
of the wood, is evaporated and burned, and the chemicals are recovered in a system particular to each base.
Sulfite process pulp mills normally use one of four
basic chemicals for digestion of wood chips to derive a
large spectrum of pulp products: sodium, calcium, magnesium or ammonium. The principal differences in the
sulfite waste liquor of the four bases are the physical
properties of the base and the products of combustion.
Sodium This system reconstitutes the base in a form
suitable for reuse in the pulping cycle. The sodium-base
liquor may be burned alone or in combination with
black liquor in a kraft recovery unit. The base chemical is recovered as a smelt of Na2S with some Na2CO3
which would be a suitable makeup chemical for a
nearby kraft mill. The combination of sulfite liquor and
kraft liquor, referred to as cross recovery, is common to
pulp mill operations. The proportion of sulfite liquor in
cross recovery is generally the equivalent of the sodium
makeup requirement of the kraft mill cycle.
Calcium Calcium-base liquor is concentrated and
burned in specially designed furnaces. The furnace and
boiler design applicable to magnesium-base liquor combustion can also be applied to calcium. This process is
largely historic today due to its unacceptable effluents.
Magnesium With the magnesium base, a simple
system is available for recovery of heat and total
chemicals. This is due to the chemical and physical
properties of the base. The spent liquor is burned at
elevated temperatures in a controlled oxidizing atmosphere, and the base is recovered in the form of an
active magnesium oxide (MgO) ash. The oxide can be
readily recombined in a simple secondary system with
the SO2 produced in combustion, thereby reconstituting the cooking acid for pulping.
Industrial interest in the improved pulp from a variety of wood species stimulated the development of
pulping techniques using a magnesium base. The two
major pulping procedures, whereby a variety of pulps
can be produced, are magnesium acid sulfite and
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
bisulfite, or magnefite. The basic magnesium recovery system is appropriate for each of the pulping processes.
The heavy liquor is fired with steam-atomizing
burners located in opposite furnace walls (see Fig. 30).
The combustion products of the liquor’s sulfur and
magnesium are discharged from the furnace in the gas
stream as sulfur dioxide and solid particles of MgO
ash. Most of the MgO is removed from the gas stream
in a mechanical collector or electrostatic precipitator
and is then slaked to magnesium hydroxide, or
Mg(OH)2. In the complex secondary recovery system,
the SO2 is recovered by reaction with the Mg(OH)2 to
produce a magnesium bisulfite acid in an absorption
system. This acid is passed through a fortification or
bisulfiting system and is fortified with makeup SO2.
The finished cooking acid is filtered and placed in storage for reuse in the digester.
Ammonium Ammonium-base liquor is the ideal fuel
for producing a low ash combustion product. Burning
can be accomplished in a simple recovery boiler. The
ammonia decomposes on burning to nitrogen and
hydrogen, the latter oxidizing to water vapor and thus
destroying the base. Concentrated ammonium sulfite
liquor is burned in a furnace and recovery system similar to magnesium-base liquor. SO2 produced in combustion can be absorbed in a secondary system to yield
cooking acid for pulping. The SO2 reacts in an absorption system with an anhydrous or aqueous ammonium
makeup chemical to produce ammonium bisulfite acid.
In a neutral sulfite semi-chemical plant, the absorption system produces cooking liquor consisting essentially of ammonium sulfite.
BLG, integrated with combined cycle power production, may offer increased cycle efficiencies and electricity production.
Process flexibility Gasification technology can return sulfur to the pulping process in a variety of forms
(sulfide, elemental sulfur, polysulfide, and/or sulfite).
This provides opportunities to produce pulp with substantially improved yields and properties.
Availability The fouling of convection pass surfaces
can reduce recovery boiler availability. BLG may provide a greater availability in that heat transfer surface fouling in either a power boiler or gas turbine
heat recovery steam generator might be lower. Intermediate cleanup equipment removes sulfur compounds and alkali fume from the product gas.
Safety Smelt-water reactions are largely unpredictable and continue to pose a risk when operating kraft
recovery boilers. Low-temperature BLG produces no
molten smelt, eliminating the potential of smelt-water reactions, and high-temperature BLG at elevated
pressure is expected to significantly reduce the likelihood and resultant force of an explosion.
Black liquor gasification
Advanced technologies – gasifier development
A new technology being investigated for the combustion/reduction of black liquor (and thus replacing
the process recovery boiler) is black liquor gasification
(BLG). This technology involves the partial oxidation
of the black liquor to produce a fuel gas that can be
burned in a gas turbine/electric generator or fired in
a power boiler. In the process, sulfur and sodium compounds are recovered from the fuel gas, before it is
sent to the turbine or boiler, for regeneration of the
pulping chemicals.
Potential BLG advantages
The pulp and paper process requires high capital
investment in plant equipment, high internally generated energy consumption, and high purchased
power consumption. BLG may have the potential to
favorably impact mill energy efficiency, environmental performance, operating costs and pulp yields.
Energy efficiency The amount of electricity pulp
mills need to import varies considerably from mill to
mill and is dependant on the power/steam cycle used
and on the type of pulp produced. Electrical loads have
increased relative to steam loads as more electricity is
needed to operate recycling, mechanical pulping, and
pollution control equipment. Most mills import a significant portion of the mill’s electricity demand, and
Steam 41 / Chemical and Heat Recovery in the Paper Industry
Fig. 30 MgO recovery boiler.
28-27
The Babcock & Wilcox Company
Emissions BLG processes require that sulfur and
particulate emissions be removed from the fuel gas.
As a result, overall emissions from a BLG-based process are expected to be low.
BLG processes
Black liquor gasification technologies can be classified by operating temperature. Low-temperature
BLG is operated below the first melting temperature
of the inorganic salts, typically 1112 to 1292F (600 to
700C), to produce a solid inorganic ash. High-temperature BLG is operated above the final melting temperature of the inorganic salts, typically 1652 to 1832F (900
to 1000C), to produce a molten smelt. Black liquor gasifiers have utilized either the fluidized-bed (for low-temperature BLG) or entrained-flow designs (for high-temperature, molten-phase designs), as described in Chapter 18. Typical BLG processes are shown in Fig. 31.
Low temperature gasifiers operate at 1292F (700C)
or lower so that the organics leave as dry solids. This
type of gasification process is normally conducted at
atmospheric pressure and produces a product gas of
approximately 200 to 300 Btu/DSCF (11.8 MJ/Nm3 ).
Minimal gas cleanup is required, and the product gas
is generally fired to offset auxiliary fuel in a power
boiler. This allows additional black liquor processing
capacity, provides a useful product gas for auxiliary
fuel use, and is well suited for incremental capacity
additions at existing mills.
High temperature gasifiers generally operate at
1742F (950C) or higher and produce a product gas of
approximately 85 to 100 Btu/DSCF (3.9 MJ/Nm3 ) and
a molten smelt of inorganic chemicals. High-temperature BLG can be pressurized and integrated with a
combined cycle system for power generation. Product
gas cleanup systems are required for the removal/reduction of sulfur and particulate emissions before the
gas turbine. These systems can also separate the sul-
Product Gas
to Process or
Power Boiler
600-700C
Black
Liquor
Gasifier
fur compounds from the product gas and return them
to the pulping process.
Status and development needs
Atmospheric pressure BLG has had the most development to date. Various concepts, both high and low
temperature, have been in design and pilot stages
since the early 1990s. The first fully commercial process is an air-blown, high-temperature entrained flow
gasifier with a processing capacity of 15 t/h of dry solids. This process provides incremental recovery capacity with product gas burned in a boiler.
High-temperature BLG with combined-cycle power
generation is in development. Various pilot work is
being done for pressurized, oxygen-blown entrainedflow reactors and large-scale commercial units are
contemplated for the near future.
Black liquor gasification is a promising technology, but
key issues must be resolved before full commercialization. While current Tomlinson technology is capital intensive, early BLG installations are expected to be quite
expensive. Capital costs must be reduced, positive economics must result and the overall economic case must
be strengthened for BLG to provide superior returns.
Specific gasifier design and process integration issues
exist, including gasifier materials selection, refractory
corrosion, product gas cleanup equipment, tar formation, sulfur removal, and an increased causticizing load.
Many activities are underway within the industry to
investigate and resolve these and other issues.
An important aspect of the overall process and economics is the effect of integrating higher yield pulping
technologies into the BLG cycle (split sulfidity, polysulfide, etc.), as these can have significant positive impact on overall economics. They, too, are capital intensive and will take some development, but integrating them into the process is the key to providing acceptable, positive economic returns.
Steam
O2
Gasifier
Black
Liquor
Gas
Cooling / Heat
Recovery
900-1000C
Green
Liquor
Raw
Gas
Sulfur
Chemicals
Gas
Cleanup
Gas
Cooling
Clean Fuel Gas
Steam
Bed
Solids
Particulate / Gas
Cleanup
H 2S
Absorber
Green
Liquor
Sodium
Sulfide
HRSG
Electricity
Gas Turbine
Low-Temperature, Atmospheric
Black Liquor Gasification
Feedwater
Flue
Gas
High-Temperature, Pressurized
Combined Cycle Black Liquor Gasification6
Fig. 31 Black liquor gasification processes.
28-28
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
References
1. Adapted from Hough, G.W., “Chemical Recovery in the
Alkaline Pulping Processes,” Technical Association of the
Pulp and Paper Industry, Inc., (TAPPI), p. 197, 1985.
2. Adapted from Smook, G.A., Handbook for Pulp and
Paper Technologists, Joint Textbook Committee of the Paper Industry TAPPI/CPPA, p. 69, 1986.
3. Wiggins, D., et al., “Liquor Cycle Chloride Control Restores Recovery Boiler Availability,” TAPPI Engineering
Conference, Atlanta, Georgia, Sept. 17-21, 2000.
Steam 41 / Chemical and Heat Recovery in the Paper Industry
4. Tran, H.N., “Kraft Recovery Boiler Plugging and Prevention,” Notes from the Tappi Kraft Recovery Short
Course, pp. 209-218, Orlando, Florida, January, 1992.
5. Adapted from Whitney, R.P., Chemical Recovery in Alkaline Pulping Processes, TAPPI, Monograph Series No.
32, p. 40, 1968.
6. Taken from Air Products & Chemicals, Inc. presentation at the American Institute of Chemical Engineers
(AIChE) Annual Meeting, Miami Beach, Florida, November 15-20, 1998.
28-29
The Babcock & Wilcox Company
Pulp and paper facility.
28-30
Steam 41 / Chemical and Heat Recovery in the Paper Industry
The Babcock & Wilcox Company
Chapter 29
Waste-to-Energy Installations
The disposal of garbage is a problem that has existed since civilization began. At various times
throughout history, composting, animal feed, landfill
and incineration have all been popular disposal methods. Today, refuse disposal methods are determined by
cost and the effect on our environment.
The most common means of refuse disposal is still
landfilling. Even in the late 1970s, nearly all of the
refuse generated in North America was landfilled.
Incineration with no heat recovery was a popular option that became economically unacceptable with the
advent of environmentally responsible air pollution
regulations and inexpensive landfill alternatives.
In Europe and Japan, where new landfill sites were
less available, incineration continued as a viable option and those plants became the predecessors of
today’s refuse-to-energy plants. Heat recovery was
added in the form of waste heat boilers which were
originally hot water boilers and later low pressure and
temperature steam boilers. These incinerators with
waste heat boilers then evolved into waterwall boilers with integral stokers.
Refuse-fired boiler design parameters and operating characteristics are strongly affected by the components of the refuse, which change with time. The
components also vary greatly by location. In North
America, typical municipal solid waste (MSW) is high
in paper and plastics content (Fig. 1) and typically has
a lesser moisture content and greater heating value
than that found worldwide. In a less industrialized
country the refuse tends to have a greater moisture
and ash content and lesser heating value. Table 1
shows representative refuse analyses ranging from
3000 to 6000 Btu/lb (6978 to 13,956 kJ/kg) higher
heating value (HHV) basis.*
In the United States (U.S.) and North America, the
refuse characteristics have changed dramatically in
a short period of time. With more and more convenience foods, plastics, packaging, containers, and less
food scraps due to home garbage disposals, the average refuse heating value has increased and the moisture content has decreased (Table 2). As more recycling programs are implemented, the analysis will
continue to change. As glass, aluminum and other
metals are recycled, the refuse heating value will increase; as paper and plastics are recycled the heating
value will decrease.
In 2000, approximately 232 million tons (210 million tm) of MSW were generated in the U.S. About 30%
of that total was recycled (including composting), 15%
sent to refuse-to-energy facilities, and the balance
landfilled. The growth of refuse-to-energy facilities in
the U.S. accelerated in the 1980s and early 1990s (Fig.
2) due to the growing disposal costs for landfills and a
government-created market for the sale of electric power.
As old landfills closed, new landfills became more
difficult and costly to open and tended to be located
farther from the source of the refuse, increasing transportation costs. Concerns about ground water contamination resulted in more expensive landfill designs with
several containment layers and leachate monitoring
and control systems. The passage of the Public Utility
Wood
6%
Other
3%
Glass
6%
Rubber, Leather
and Textiles
7%
Paper
36%
Metals
8%
Plastics
11%
* Throughout this chapter, fuel energy content, or heating value, is stated as the higher (or gross) heating value
which includes the total energy in the fuel without correcting for losses due to water evaporation.
Steam 41 / Waste-to-Energy Installations
Food Scraps
11%
Yard Trimmings
12%
Fig. 1 U.S. municipal solid waste generation – 2001.
29-1
The Babcock & Wilcox Company
Table 1
Range Of As-Received Refuse Fuel Analysis
Weight Percent As-Received
HHV, Btu/lb
(kJ/kg)
3,000
(6,978)
3,500
(8,141)
4,000
(9,304)
4,500
(10,467)
5,000
(11,630)
5,500
(12,793)
6,000
(13,956)
Carbon
Hydrogen
Oxygen
Nitrogen
Sulfur
Chlorine
Moisture
Ash
Total
16.88
2.33
12.36
0.22
0.15
0.34
35.72
32.00
100.00
19.69
2.72
14.42
0.26
0.18
0.38
32.35
30.00
100.00
22.50
3.10
16.49
0.30
0.21
0.42
29.98
27.00
100.00
25.32
3.49
18.55
0.34
0.24
0.46
28.60
23.00
100.00
28.13
3.88
20.62
0.38
0.27
0.50
25.22
21.00
100.00
30.94
4.27
22.68
0.42
0.30
0.54
22.85
18.00
100.00
33.76
4.66
24.75
0.46
0.33
0.58
21.46
14.00
100.00
Regulatory Policies Act of 1978 (PURPA) required
public utilities to purchase the electric power generated by refuse-to-energy plants. This created a revenue flow that helped offset the inherent high capital cost of these plants. These market forces resulted
in a proliferation of refuse-to-energy facilities in the
northeast U.S. where the costs of landfill and other
disposal options were the highest, and selectively
throughout North America in response to local environmental or economic factors.
Refuse disposal is a major problem worldwide and
there is no single solution. An environmentally sound
refuse disposal program includes generating less
refuse, recycling components that can be economically
reused, combustion of the balance of the refuse (including the efficient generation of electric power), and
the landfill of the resulting ash.
Refuse combustion alternatives
Two main techniques are used for burning municipal refuse, distinguished by the degree of fuel preparation. The first technique, known as mass burning,
uses the refuse in its as-received, unprepared state
(Fig. 3). Only large or non-combustible items such as
tree stumps, discarded appliances, and other bulky
items are removed. Refuse collection vehicles dump the
refuse directly into storage pits. Overhead cranes
equipped with grapples move the refuse from the pit
to the stoker charging hopper. Hydraulic rams located
in the charging hopper move the refuse onto the stoker
grates. The combustible portion of the refuse is burned
off and the non-combustible portion passes through and
drops into the ash pit for reclamation or disposal.
The second burning technique uses prepared refuse,
or refuse-derived fuel (RDF), where the as-received
refuse is first separated, classified, and reclaimed in
various ways to yield salable or otherwise recyclable
products (Fig. 4). The remaining material is then
shredded and fed into the furnace through multiple
feeders onto a traveling grate stoker. The RDF is
burned, part in suspension and part on a stoker. The
RDF can also be used as a fuel in circulating fluidized-bed (CFB) boilers and in bubbling fluidized-bed
(BFB) boilers. More finely shredded RDF can be fired
in suspension to supplement conventional fuels in
large boilers used for power generation.
Corrosion
Combustion products from municipal refuse are
very corrosive. The components that are present in
coal, oil and other fuels that contribute to corrosion,
as well as to high slagging and high fouling, are all
present in refuse (Table 3). Corrosion in refuse-fired
boilers is usually caused by the chloride compounds
which deposit on the furnace, superheater and boiler
tubes. Several modes of chloride corrosion may occur:
Table 2
U.S. Refuse Trends
Increasing heating value per ton of refuse
1960 4,200 Btu/lb (9,769 kJ/kg)
1980 4,500 Btu/lb (10,467 kJ/kg)
2000 5,200 Btu/lb (12,095 kJ/kg)
More paper and paperboard
33% in 1970
37% in 2000
More plastics
2.7% in 1970
10.7% in 2000
29-2
Fig. 2 U.S. refuse-to-energy market.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
1. corrosion by hydrochlorides (HCl) in the combustion gas,
2. corrosion by NaCl and KCl deposits on tube surfaces,
3. corrosion by low melting point metal chlorides
(mainly ZnCl2 and PbCl2), and
4. out-of-service corrosion by wet salts on the tube
surface.
The rate of tube metal loss due to corrosion is temperature dependent with high metal temperatures
correlating with high rates of metal loss (Fig. 5).
Refuse boilers operating at higher steam pressures
have higher temperature saturated water in the furnace tubes and, therefore, these furnace tubes have
higher metal temperatures. Superheater tube metal
temperatures are directly related to the steam temperature inside the tubes. In both cases, it is the temperature of the water or steam inside the tube that largely
controls the tube metal temperature, rather than the
temperature of the flue gas outside of the tube.
Furnace-side corrosion can be aggravated by poor
water chemistry control. If water-side deposits are
permitted to form, tube wall metal temperatures will
rise and furnace corrosion will be accelerated. Standards for feedwater and boiler water quality are based
on boiler operating pressures. These standards are no
more stringent for refuse-fired units than for other
fuels. However, the maintenance of feedwater and
boiler water quality, and adherence to those standards, is more critical on refuse-fired boilers due to the
highly corrosive nature of the fuel.
Lower furnace corrosion
The lower furnace environment of both mass-fired
and RDF-fired units is constantly changing between
an oxidizing atmosphere (an excess of O2 beyond that
needed for combustion) and a reducing atmosphere
(a deficiency of O2 below that needed for combustion)
Refuse
Feed Hopper
Boiler
Refuse
Receiving Area
Refuse
Pit
Plunger
Ash Extractor
Ash Removal
Fig. 3 Mass burning schematic.
which can rapidly accelerate corrosion. Therefore, some
form of corrosion protection is needed. Typically, the
area of protection will encompass all four walls up to
30 ft (9.1 m) above the grate where there is reasonable
assurance that an oxidizing atmosphere is prevalent
and that combustion has been substantially completed.
Mass-fired units
A variety of solutions have been developed and
used to address the issue of corrosion in the lower furnace. The lower furnace walls of virtually all massfired units have been protected by one or more of the
following three systems: 1) pin studs with silicon carbide (SiC) refractory, 2) ceramic tiles manufactured
from SiC (see Fig. 6), or 3) Inconel® weld cladding of
the membrane tube panels.
The quality and physical characteristics of the sili-
Fig. 4 RDF burning schematic.
Steam 41 / Waste-to-Energy Installations
29-3
The Babcock & Wilcox Company
Silicon
Carbide
Tiles
Table 3
Corrosive Constituents in Fuels
Coal
Oil
Sodium
Sulfur
Potassium
Sodium
Sulfur
Vanadium
Furnace
Wall Panel
Refuse
Sodium
Sulfur
Potassium
Vanadium
Chloride
Lead
Zinc
con carbide refractory placed over the pin studs must
be maintained through proper application and curing.
Lack of control during installation will result in refractory spalling, deterioration, and increased maintenance. The refractory material should have a high
rate of thermal conductivity to maximize the effectiveness of the water-cooled surface it is protecting. The
pin stud pattern, pin stud length and pin stud diameter must be carefully chosen for its ability to hold the
refractory in place and to maximize the heat transfer
through the stud to the furnace wall tubes. This, in
turn, serves two purposes. One is to provide maximum
cooling to keep as low a refractory temperature as
possible. Maintaining a low refractory surface temperature has a dramatic effect on refractory life, furnace wall fouling and maintenance costs. Second, with
more heat removed in this lower furnace area, less heating surface is required in the upper furnace to achieve
the desired flue gas temperature leaving the furnace.
SiC tiles have a much harder and smoother surface
than that produced with the pin studs and refractory;
therefore, the tiles are more resistant to spalling and
less prone to slag buildup. The attachment system
used to anchor the ceramic tiles to the furnace walls
must keep the tiles in contact with the furnace walls
in order to cool the tiles. The anchors must also permit movement between the tiles to minimize expansion stresses that may damage the tiles.
Inconel weld overlay has gained general acceptance since the year 2000 for application in the lower
furnace walls of large mass-fired boilers, as it had earlier for RDF-fired boilers. The good corrosion resistance, high thermal conductivity, metallurgical bond
to the base tube and membrane bar metals, and wear
resistance have made Inconel overlay the primary ap-
Fig. 5 Corrosion rate of carbon steel in chlorine and hydrogen chloride.
29-4
Fig. 6 Silicon carbide tiles for lower furnace wall corrosion protection.
proach for lower furnace corrosion protection in new
European designs. In such units, high temperature
gunned-on and cast refractory systems also continue
to be used in selected areas of the furnace where heat
absorption must be limited or heat must be radiated
back into the combustion zone while still providing
corrosion protection. Typically, refractory is used on:
1) furnace arch areas over the grate feed and burnout zones, 2) on the intermediate elevation furnace
walls where heat absorption must be minimized to
maintain adequate furnace temperatures during continuous low-load firing, and 3) on the furnace walls
in smaller boilers where the ratio of furnace wall area
to furnace volume is so high that the gas temperature
within the furnace is suppressed below the point required for optimal combustion (see Fig. 7).
The furnace side walls along the grate line generally experience the most erosion due to the scrubbing
action of the refuse fuel and ash as it moves along the
grate to the ash discharge. Increased erosion-resistant
SiC materials are available for these zones. They do,
however, have lower thermal conductivities.
An alternative near the grate line is the use of
armour blocks or refractory blocks, rigidly attached to
the furnace walls. These blocks extend up the full
height of the charging hopper opening which is about
4 ft (1.2 m) high at the front of the furnace and tapers
off to about 1 ft (0.3 m) high at the ash discharge end
(Fig. 8).
Another method used for protection of the furnace
walls immediately adjacent to the grate is the use of a
separate water-cooled wear zone panel placed horizontally along the grate line and in front of the lower
furnace walls as shown in Fig. 7. A flexible tight seal
is created between the wear zone panel and the vertical furnace wall to accommodate expansion between
the top-supported boiler and the bottom-supported
grate structure. Depending upon the cooling water
temperature and corrosion potential, the water-cooled
wear zone panel may be protected from corrosion by
Inconel weld overlay similar to the boiler walls. This
low maintenance design provides a relatively cool
surface which resists the buildup of significant slag
while also providing corrosion protection and wear
resistance with little demand for maintenance.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
Fig. 7 Corrosion protection and design of a 26 t/h mass-fired unit.
RDF-fired units
Prior to the late 1980s, RDF boilers were installed
with bare carbon steel tubes in the lower furnace and
no corrosion protection. It was thought that with the
more even combustion with a processed fuel, corrosion
would not be a concern in the lower furnace. Early
units, operating at low steam pressures and temperatures, did not experience corrosion problems. However,
as higher pressure and temperature units went into
operation, corrosion increased and lower furnace protection was needed.
The same pin stud and refractory design used on
mass-fired units has also been tried on RDF units. This
solved the corrosion problem but created another. Inherent in the RDF combustion process is a high degree of suspension firing and high flame temperatures
in the lower furnace. When pin studs and refractory
are applied, the lower furnace tubes are insulated, resulting in less heat transfer and hotter flue gas temperatures in the lower furnace. This, in turn, can result in
significant slagging on the refractory wall surface. Pin
studs and refractory were tried at two RDF facilities.
However, increased furnace slagging resulted, and eventually the pin studs and refractory were removed.
The industry needed a material that was resistant
to the chloride corrosion found in refuse boilers while
not insulating the lower furnace tubes. The Babcock
& Wilcox Company (B&W) pioneered the use of
Steam 41 / Waste-to-Energy Installations
Inconel material as a solution to this lower furnace
corrosion problem. In 1986, following rapid corrosion
of the bare carbon steel tubes, the lower furnace of the
Lawrence, Massachusetts unit was covered with a weld
overlay of Inconel material. This overlay proved to be
effective in minimizing corrosion in the lower furnace.
Based on this early experience, the industry followed
B&W’s lead and Inconel weld overlay was subsequently field applied to the lower furnace of a number
of operating boilers.
For the RDF boilers supplied as part of the refuseto-energy plant in Palm Beach County, Florida, the
decision was made to add the Inconel protection prior
to manufacture. A bimetallic tube construction was
used consisting of a carbon steel inner tube co-extruded
with an Inconel outer tube (Fig. 9). These boilers went
into operation in 1989 and the Inconel bimetallic tubes
have proven to be an effective means of reducing lower
furnace corrosion. Today, Inconel bimetallic tubing and
carbon steel tubing with an Inconel weld overlay are
the industry standard for lower furnace corrosion protection in RDF-fired boilers.
Mass burning
Mass burning is the most common refuse combustion technology worldwide. When the market for
refuse-to-energy facilities expanded rapidly in the
29-5
The Babcock & Wilcox Company
The net result of these characteristics of the market resulted in many early refuse units experiencing
operating problems related to:
1. high rates of slagging in the furnace,
2. higher gas temperature leaving the furnace resulting in overheating of superheaters and excessive fouling in the convection section,
3. tube failures from accelerated corrosion that were
metal temperature related, and
4. concerns about the creation of dioxins (polychlorinated dibenzoparadioxin, PCDD) and furans
(polychlorinated dibenzofurans, PCDF) during
the combustion process that were related to less
than optimum combustion systems, particularly
less than optimum turbulence and mixing of fuel
and air in the lower furnace.
Superheater
Boiler
Bank
Each of these problems has been taken into consideration as the design of mass-fired boilers has evolved.
Overall boiler design and gas flow path
Top of
Refractory
(Rearwall)
Top of Refractory
(Frontwall and
Sidewalls)
Legend
Pin Studs
and Refractory
SiC Tile
SiC Block
Stoker Grate
Fig. 8 Refractory type and location, mass-fired unit.
U.S. in the early 1980s, many of the U.S. refuse plants
(Fig. 10) adopted the well-proven mass burning technology that had been developed in Europe. A modern
B&W European mass burn power plant is shown in Fig.
11. The boiler is a multi-pass, top-supported design.
Some major differences in the application of the
European technology in the U.S. resulted in several
operational problems. U.S. applications tend to require
large units to accommodate larger regional facilities
than European and Japanese applications. U.S.
plants were designed to operate at significantly higher
operating pressures and temperatures to take advantage of the economics of production and sale of electric power while typical non-U.S. applications produced hot water and low pressure steam for heating
applications. U.S. refuse fuel typically had a higher
heating value and lower moisture content. Finally,
these units were first installed at a time when environmental concerns were increasing.
29-6
B&W offers two basic designs for large mass-fired
boilers. Fig. 12 shows a typical mass burn unit supplied in the U. S. while Fig. 13 illustrates a horizontal
convection pass unit supplied in Europe. Both are
single drum, top-supported, natural circulation boilers capable of supplying superheated steam at a range
of pressures and temperatures to meet individual site
requirements. The steam drums are supplied with the
appropriate steam separation equipment to supply
high purity dry steam to the superheater while spray
attemperators closely control the steam temperature.
The furnaces are fully water-cooled with membrane
wall construction using the appropriate corrosion protection system (see earlier discussion). Cleaning of
boiler surfaces is accomplished by a combination of
mechanical rapping and sootblowers as discussed later
in this chapter. Both designs utilize a reciprocating
combustion grate and similar lower furnace configurations to provide efficient burnout of the fuel before
the ash is discharged. The gas flow paths of the two units
differ to meet market requirements and preferences.
As shown in Fig. 12 for the U.S. market design, the
combustion products from the grate flow upward
through the single furnace pass to provide sufficient
residence time and temperature to burn the fuel con-
Inconel® Outer Layer
Carbon
Steel
Core
Furnace Side
Fig. 9 Bimetallic tube.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
Fig. 10 Typical U.S. mass burning refuse-to-energy system.
Steam
Drum
Secondary
Superheater
Tertiary
Superheater
Primary
Superheater
Electrostatic
Precipitator
Stack
Economizer
Furnace
Scrubber
Modules
Charging
Crane
Fuel
Feed
Grate
Ash Extractor
Silencer
Induced
Draft Fan
Fig. 11 B&W European mass burning power plant.
Steam 41 / Waste-to-Energy Installations
29-7
The Babcock & Wilcox Company
Attemperator
Penthouse
Superheater
Outlet Header
Steam Drum
Superheater
Inlet Header
Boiler Bank
Economizer
Superheater
Top of
Refractory
Refuse
Feed
Hopper
Furnace
Auxiliary
Burners
Ram
Feeder
Downcomer
Overfire
Air System
Grate
the third pass to cool the flue gas to the required gas
temperature before entering the horizontal convection
pass. Additional parallel flow boiler circuits or baffles
in the form of widely spaced tube panels are typically
used in the third pass to increase the heat absorption.
The flue gas flow path is designed to provide reasonably uniform cross-section flow and temperature distributions throughout by the use of physical and numerical computational fluid dynamics (CFD) modeling (see Chapter 6). Noses or arches (not shown) are
used at the first pass exit, second pass inlet and third
pass inlet, while inclined walls and roofs are used in
each pass to achieve the desired flue gas distribution.
The bottom-supported convection pass contains a
series of convection heat transfer surface sections in
the direction of gas flow: steam generating surface,
secondary superheater, tertiary superheater, primary
superheater, more steam generating surface in some
cases, and finally the economizer before the gas exits
the boiler enclosure. The convection pass surfaces are
arranged to minimize corrosion, and are widely spaced
to prevent pluggage and allow adequate space for
mechanical sootblowing equipment. The first steam
generating surface protects the superheater from high
temperature peaks. The secondary and tertiary superheaters are designed for parallel steam and flue gas
flow to minimize metal temperatures and corrosion. The
second optional steam generating surface may be used
to cool the flue gas to avoid steaming in the economizer.
Boiler plant sizing
Primary Air
Ash Extractor
Fig. 12 Typical U.S. mass burning unit.
stituents and other hydrocarbons, and cool the flue
gas to the required furnace exit gas temperature before entering the superheater. Where required, the
design provides the necessary reaction time for a selective non-catalytic reduction (SNCR) process to control nitrogen oxides (NOx). The flue gas then turns 90
degrees around a large furnace arch to pass through
the crossflow superheater section before turning downward to flow parallel through the longflow boiler
steam generating bank. The flue gas then flows upward through the crossflow economizer section and
exits the boiler enclosure.
As shown in Fig. 13 for the European market design, a multiple pass furnace is used to cool the flue
gas. The combustion products leave the grate and lower
furnace to pass upward through the first open furnace
pass and then downward through the second open
pass. As noted earlier, a portion of the first pass may
be covered with high SiC cast refractory to reduce heat
absorption and permit the flue gas to maintain a suitable high temperature for a specified period of time
for complete combustion of the fuel constituents and
other hydrocarbons in smaller boilers and at lower load
in larger units. At the bottom of the second open pass,
the flue gas turns 180 degrees to pass upward through
29-8
A refuse plant must be sized to handle the physical
amount of refuse that is delivered to that plant, regardless of the refuse heating value. A refuse boiler,
on the other hand, is a heat input device and must be
sized for the maximum heat input expected. When
designing a refuse boiler, consideration must be given
to both the design tons per day of refuse to be combusted and the typical range of heating values that
is expected for the refuse in that location.
The boiler is typically designed for the maximum
ton per day input at the maximum refuse heating
value. A 1000 t/d (907 tm/d) refuse plant is actually not
the same size plant in all locations. As an example, a
plant in an industrialized country might be designed
to handle refuse with a heating value of approximately 5500 Btu/lb (12,793 kJ/kg), or 458 × l06 Btu/h
(134 MWt) total heat input to the boilers. At the other
extreme, a plant in a less industrialized country might
be designed to handle refuse with a heating value in
the range of 3500 Btu/lb (8141 kJ/kg), or 292 × 106
Btu/h (85.6 MWt) total heat input. Both are 1000 t/d
(907 tm/d) plants, but one has refuse boilers that have
a 50% larger capacity in terms of heat input.
For many of the early U.S. plants, good data were
not available on the true range of heating values of
the refuse. Refuse boilers were sized for typical heating values of 4500 Btu/lb (10,467 kJ/kg). When the
actual heating values were found to be as high as 5200
to 5500 Btu/lb (12,095 to 12,793 kJ/kg), the boilers
were actually undersized and could not process the
available refuse on a ton per day basis.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
Steam
Drum
Tertiary
Superheater
Boiler
Circuit
Secondary
Superheater
Primary
Superheater
Economizer
Enclosures-Steam
Generating Surface
Gas
Outlet
Second
Pass
First
Pass
Refuse
Charging
Hopper
Gas
Auxiliary
Burner
Feeder
Third
Pass
Additional
Boiler
Circuits
(In Third
Pass)
Overfire
Air
Lower Furnace
Grate
Downcomers
Ash
Extractor
Fig. 13 Typical European mass burning unit.
Stoker capacity
A refuse stoker has both a heat input limit and a
ton per day refuse throughput limit. If a typical 1000
t/d (907 tm/d) refuse plant has two 500 t/d (454 tm/d)
boilers, and the design refuse heating value is 5000
Btu/lb (11,630 kJ/kg), each boiler would have a maximum heat input limit of 208.3 × l06 Btu/h (61.1 MWt).
If the actual refuse heating value is above 5000 Btu/lb
(11,630 kJ/kg), the unit’s ton per day capacity would
be reduced below 500 t/d (454 tm/d) so not to exceed the
maximum heat input limit. On the other hand, if the
actual refuse heating value is below 5000 Btu/lb (11,630
kJ/kg), then the unit could actually process more than
500 t/d (454 tm/d) of refuse, up to the maximum ton per
day limit of that stoker.
The ton per day limit is usually set by a refuse capacity per unit of stoker width, a limit for optimum fuel
feed and distribution, or a structural limit based on
refuse weight per square foot (m2). These limits are in
the range of 30 t/d (27 tm/d) per front foot (0.3 m) of
Steam 41 / Waste-to-Energy Installations
width and 65 lb/h ft2 (2.74 kg/h m2) of grate area. The
grate surface area is set by a grate release rate generally in the range of 270,000 to 350,000 Btu/h ft2 (852
to 1104 kW/m 2), but may be lower for low heating
value, high moisture fuels. The design limits stated
above represent typical values for equipment installed
in North America. Stokers supplied for European and
Asian refuse installations have typically used lower
design limits, especially with respect to the grate heat
release rate.
The stoker width and depth are also related to the
specific fuel. A high heating value, low moisture fuel
would require a wider, less deep stoker because the
fuel will tend to burn more rapidly. A low heating value,
high moisture fuel would require a narrow, deeper
stoker because more residence time on the stoker is
usually needed. The combination of all these criteria
will set the maximum ton per day rating of the stoker.
There is also a minimum load that can be effectively
handled on a given stoker. This load is also set by both
29-9
The Babcock & Wilcox Company
a ton per day limit (minimum fuel inventory on the
grate) and a heat input limit (minimum heat input for
good combustion).
All of these limits can be incorporated into a capacity
diagram, which provides the operator with the boundary limitations around a family of heating value curves.
Fig. 14 is such a diagram for a typical 500 t/d (454 tm/d)
boiler burning 5000 Btu/lb (11,630 kJ/kg) refuse.
Stoker design
The combustion of MSW requires a rugged, reliable
stoker to successfully convey and burn unsorted
refuse. Most stokers use some variation of a reciprocating grate action, with either forward moving or
reverse acting grate movement. Some arrangement
of moving and stationary grates is used to move the
refuse through the furnace and allow time for complete combustion.
A reciprocating grate stoker is typically designed
with alternating moving and stationary rows of grate
bars in a stairstep construction with a downward slope
to help move the refuse along the length of the grate.
Each row of grate bars overlaps the row beneath it
and the alternate rows are supported from a moving
frame driven by hydraulic cylinders. The moving rows
of grate bars push the refuse over the stationary bars
where it is picked up by the next row of moving bars.
Fig. 15 shows a pivoting grate design where each row
of grate bars is mounted on individual transverse
shafts moving slowly 60 deg forward and backward
so that the entire grate surface is in constant motion.
The reciprocating grate shown in Fig. 16 has longitudinal grate girder assemblies filled with grate bars. Every other grate girder assembly is resting on a transverse shaft at the upper end, moving slowly 30 deg
forward and backward so that the grate surface moves
like a walking beam floor. The remaining assemblies
are stationary. The typical grate drive units are
equipped with hydraulic cylinders with a piston moving forward and backward and thereby creating the
grate movement. The motion of these grates rolls and
mixes the refuse, constantly exposing new material to
the high temperatures in the fuel bed and allowing the
combustion air to contact all of the burning refuse.
Fig. 14 Stoker capacity diagram.
29-10
Furnace
Waterwalls
Individual
Water-Cooled
Grate Bars
Mechanical
Seal
Assembly
Fuel
Travel
Grate Bar
Hydraulic Actuators
(Typ.)
Individual
Air-Cooled
Grate Bars
Ash
Discharge
Fig. 15 Pivoting refuse grate.
More recently, MSW heating values have increased
to levels where water cooling of the grate has become
more common for new mass-fired units. Typically, the
upper half of the grate, nearest to the fuel feed point
and most intense combustion zone, is water-cooled
while the balance of the grate is air-cooled. The grates
in Figs. 15 and 16 can be supplied with either wateror air-cooled versions. Water cooling also has the operational advantage that combustion air temperature
can be preheated as required for combustion without
consideration for grate cooling, which is controlled by
the water flow.
For lower heating value, high moisture refuse, dropoff steps are often incorporated into the stoker design.
The steps are located at the end of each grate module
resulting in one to three steps depending on the overall stoker length. These steps promote a tumbling and
rolling action as the burning refuse falls off the step.
This type of design was used on a number of the early
refuse units in the U.S. but was found to be unnecessary with the higher heating value and lower moisture refuse. In fact, it can be a detriment as the tumbling can also result in excursions of high carbon
monoxide (CO) emissions.
The grates are usually constructed in a series of
standard modules with independent drives and air
plenums. This allows the individual grate modules to
be factory-assembled to limit field construction time
and provide complete duplication of parts for easy
maintenance and repair. This modular construction
allows any size stoker to be constructed from a small
number of standard modules. A typical stoker is usually from two to four modules in length and one to four
modules in width.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
Modular construction provides the operator with
complete control over the amount of undergrate air
introduced through each module. This ability to control the undergrate air in multiple air zones along the
width and depth of the stoker is an important factor
in minimizing CO and nitrogen oxides (NOx) emissions. This method of construction also provides complete freedom in the operating speed of the individual
grate modules to provide the required feed rate along
the grate for complete burnout of the fuel.
Fuel handling
The MSW delivered to the refuse plant is generally
dumped directly into the storage pit. This large pit also
provides a place to mix the fuel. This mixing is done
using the crane and grapple to move and restack the
refuse as it is dumped into the pit. This produces a
fuel, in both composition and heating value, that is
as consistent as possible for the boilers. This is an essential job for the crane operator and any time not required to feed the furnaces is used to mix the fuel. It
is not uncommon for the crane operator to mix four
grapple loads back into the pit for every one load that
goes to a charging hopper.
Fuel feed system
Controlled feed of the fuel is necessary for good combustion to minimize CO and NOx emissions and to
maintain constant steam output. At the bottom of the
charging hopper feed chute, a hydraulic ram pushes
the fuel into the furnace and onto the stoker grates
at a controlled rate. On larger units, multiple charging rams are used across the width of the unit to provide a continuous fuel feed with optimum side to side
distribution. The hydraulic rams stroke forward
slowly and then retract quickly to provide the positive
continuous fuel feed. These rams are simple to conLongitudinal Grate Girder Assembly
(With Grate Bars Removed)
Transverse
Actuator
Shaft
trol with feed rate adjustments made by either the
speed of travel or the number of strokes per hour.
Combustion air system
The primary combustion air, or undergrate air, is
fed to the individual air plenums beneath each grate
module. A control damper at the entrance to each air
plenum controls the undergrate air to each section of
the grate (Fig. 17). The grate surface is designed to
meter the primary combustion air to the burning
refuse uniformly over the entire grate area. This is
accomplished by providing small air ports or tuyères
in the surface of the individual grate bars. These air
ports provide openings equal to approximately 3% of
the grate area which results in sufficient pressure drop
of air resistance across the grate to assure good distribution of the air flow through the grate, regardless of
the depth of refuse on the grate. Undergrate air systems are generally designed for 70% of the total combustion air flow with expected normal operation at
60% of total air flow.
Because refuse contains a high percentage of volatiles, a large portion of the total combustion air should
enter the furnace as secondary, or overfire, air through
ports in the furnace walls. These secondary air ports
are located only in the front and rear furnace walls
so that the air flow parallels the normal flow pattern
through the unit. Older design units generally provided 25 to 30% of the total air as overfire air. With
today’s emphasis on better combustion and lower
emissions, the overfire air systems are designed for
50% of the total air to be overfire air with expected
normal operation at 40%.
The basic function of the overfire air system is to
provide the quantity of air and the turbulence necessary to mix the furnace gases with the combustion air
and to provide the oxygen necessary for complete combustion of the volatiles in the lower furnace. Excess
air in the furnace is usually maintained in the range
Fuel
Travel
E
D
C
Hydraulic
Unit
B
A
Grate Blocks
(Fitted To Girder Assembly)
Ash
Discharge
Moving Grate Assembly
(B and D)
Stationary Grate Assembly
(A, C and E)
Individual Grate
Bars With Air Holes
(Replaceable)
Fig. 16 Reciprocating refuse grate.
Steam 41 / Waste-to-Energy Installations
Fig. 17 Combustion air system.
29-11
The Babcock & Wilcox Company
of 80 to 100% and complete combustion is generally
indicated by a CO value in the range of 10 to 100 ppm.
The high percentage of excess air needed to ensure
proper combustion can be reduced through flue gas
recirculation. Flue gas recirculation involves the use
of cooled flue gas, generally extracted from the system down stream of the baghouse, to offset a certain
portion of the fresh air used in the overfire air system. The recirculated flue gas maintains the total flow
volume in the combustion air system while reducing
the percentage of excess O2, which improves boiler
efficiency. Flue gas recirculation also reduces the production of NOx by limiting the amount of O2 present in
the high temperature region of the furnace where NOx
is formed. The advantages of using flue gas recirculation can be offset by its disadvantages which include
the capital cost of the system, power consumption of the
recirculation fan, and overall system maintenance.
To aid in the combustion of wet fuels during extended periods of rainy weather, the air system includes steam coil air heaters designed to provide air
temperatures in the range of 300 to 350F (149 to
177C) to help dry these fuels and maintain furnace
temperature. These steam coil air heaters are commonly used only for the undergrate air because this
is the air flow which directly aids in drying wet fuel.
These air heaters must be conservatively designed
with fin spacing not exceeding 4 to 5 fins/in. (1 fin/
6.4 to 5.1 mm). Most plants take combustion air from
the storage pit area to help minimize odors. This air is
normally contaminated with dust and lint which could
plug the steam coil. Some type of cleaning arrangement or filters must therefore be included to keep the
steam coil clean.
When high moisture fuels are encountered, the first
action by the operator is to use the steam coil air
heater to provide hot air. However, for very high moisture fuels it may also be necessary to use the auxiliary fuel burners to stabilize combustion in the furnace. These cases are the exception, and in normal
operation neither the auxiliary burners nor the steam
coil air heater are needed for good combustion.
Ash handling systems
When refuse is burned, the ash takes the form of
either light ash, called flyash, or coarse ash, which
comes off the stoker. The flyash is entrained in the gas
stream until it is removed in the particulate collection
device or falls out into the boiler, economizer, or air
heater hoppers. The stoker ash consists of ash from the
fuel, slag deposits on the grate, ash from the furnace
walls and, in some designs, ash from the superheater.
The stoker ash is discharged through the stoker discharge chute and from the stoker siftings hoppers.
Ash extractor
The ash from the stoker discharge on mass-fired
units may contain large pieces of non-combustible
material, in addition to the normal ash from combustion. Ash consistency can vary from fine particles to
large and heavy non-combustible objects in the fuel.
The ash from the stoker discharge chute falls into a
water bath in the ash extractor that quenches the ash
29-12
Fig. 18 Plunger ash extractor.
and controls dusting. In the plunger ash extractor (Fig.
18), the ash is quenched, a slow moving, hydraulically
operated ram cycles forward and back to push and
squeeze the accumulated ash up an inclined dewatering section to the discharge of the extractor. The ram
cycles continuously at a slow speed to push the ash out
of the extractor. The dewatered ash has a moisture content of 15 to 20% as a result of the squeezing process on
the incline. The lower moisture content can have an economic advantage as the cost of landfilling ash is based
on total weight, which includes the weight of water in
the ash. Another option is a wet conveyor ash extractor.
This is a water-filled conveyor trough where noncombustible items, ash and grate siftings are transported on
a steel apron belt submerged in water. As with the chain
conveyor discussed later in the chapter, the belt carries
the noncombustibles, ash and siftings up an incline, effectively dewatering the material before it is discharged
from the belt to a bin or hopper, and the belt cycles around
to the water-filled trough to collect more material.
To keep the ash system simple and to minimize
costs, ash from the extractor can discharge directly into
a truck or bin for final disposal. To move the ash away
from the vicinity of the stoker discharge, vibrating and
belt-type conveyors are used. A short vibrating conveyor
is placed at the discharge of the ash extractor; its metal
trough can withstand the impact of the oversized, noncombustible material falling from the extractor. The vibrating conveyor then transfers the ash to a belt conveyor, minimizing the wear on the belt conveyor that
would occur if the extractor discharged directly onto it.
Scrubber, precipitator, and baghouse flyash
The flyash collected in the scrubber, precipitator, or
baghouse hoppers can be handled by dry mechanical
screw or chain-type conveyors. These conveyors opSteam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
erate continuously to minimize hopper pluggage problems and they discharge onto a collecting conveyor,
which is usually a dry chain type. Because the mechanical conveyors are dust-tight, but not designed
to be gas-tight, separate sealing devices such as rotary seals or double flop valves are used. The collecting conveyor will collect the flyash discharged by all
the conveyors under the rows of hoppers, and move it
to a single collection point for ultimate disposal.
RDF firing
RDF technology was developed in North America
as an alternative to the mass burning method. Initially, RDF was used as a supplementary fuel for large,
usually coal-fired, utility boilers. For this application,
the RDF is finely processed and sized to 1.5 in. (38.1
mm) maximum size. The resulting RDF is nearly all
light plastics and paper.
For supplemental firing, B&W recommends a maximum RDF input of 20% on a heat input basis, and no
RDF input until the boiler is operating above 50% load.
In most cases the RDF is blown into the furnace at
the pulverized coal burner elevation through an RDF
burner with a fuel distribution impeller. Most of the
RDF burns in suspension in the high heat input zone
of the pulverized coal fire while the heavier fuel fraction falls out in the lower furnace. A dump grate stoker
located in the neck of the ash hopper allows more complete burnout of the heavier fuel particles before they
are discharged into the ash system (Fig. 19). RDF has
been successfully co-fired in B&W boilers at Lakeland,
Florida; Ames, Iowa; and Madison, Wisconsin.
RDF has also been successfully co-fired in B&W
Cyclone furnaces where the finely processed and sized
RDF is injected into the Cyclone secondary air stream
moving tangentially inside of the Cyclone barrel. (See
Chapter 15.) This method of RDF combustion has
been used in Baltimore, Maryland.
Dedicated RDF-fired boilers
From this supplemental fuel experience, RDF then
became the main fuel for boilers specifically designed
to generate full load steam flow when burning RDF
(Fig. 20). In some cases where steam flow was required
even when refuse was not available, the boiler was
Fig. 19 Typical B&W RB-type utility boiler firing RDF as a supplementary fuel.
Steam 41 / Waste-to-Energy Installations
29-13
The Babcock & Wilcox Company
Fig. 20 Typical RDF refuse-to-energy system.
designed so that it could also reach full load on wood,
coal or natural gas. More commonly there would only
be auxiliary gas or oil burners for startup and shutdown.
The first boilers in the world to fire RDF as a dedicated fuel were B&W units which began operation in
1972 in Hamilton, Ontario, Canada. The first of such
boilers in the U.S. went into operation in 1979 in Akron, Ohio. The boiler design was highly influenced by
the proven technology of wood-fired boilers with respect
to their fuel feed system, stoker design, furnace sizing,
and overfire air system. The transfer of this technology
from wood firing to RDF firing was successful in many
areas, but in other areas design adjustments were
needed to accommodate the unique aspects of RDF.
The operating experience from the first generation
designs at Hamilton, Akron and other plants led to
second generation designs with improved RDF processing systems, fuel feed systems and boiler design.
Specific improvements included the first fuel feeder
designed specifically for RDF and the use of alloy weld
overlay in the lower furnace for corrosion protection.
The third generation of facilities is essentially
today’s state-of-the-art design. (See Fig. 21.) This
boiler design has an enhanced overfire air system to
significantly improve combustion efficiency. These
third generation designs also incorporate dramatically
improved fuel processing systems.
RDF processing
The first generation RDF processing systems were
referred to as crunch and burn systems. The incom29-14
Steam Drum
Superheater
Economizer
From RDF
Storage
Building
Feed
Bin
Start-Up
Burner
Air
Heater
Ram
Lower Hopper
Conveyor
Submerged Chain
Ash Conveyors
Forced
Draft
Fan
Fig. 21 Third generation RDF unit and fuel feeding system.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
ing refuse first went to a hammer mill type shredder
that produced an RDF with 6 by 6 in. (152 by 152 mm)
top size. Ferrous metal was removed by magnetic separators. There was no other material separation and
many undesirable components entered the boiler such
as shredded particles of glass that became embedded
in wood and paper resulting in a very abrasive fuel
entering the boiler in suspension. Following the practice of wood-fired boilers, the RDF was generally
stored in a hopper or bin. RDF, however, is much more
compactible than wood and in nearly every case, significant problems were encountered getting the RDF
out of the storage bins.
Second generation RDF processing systems recognized and corrected some of the problems. The shredder for final fuel sizing was moved to the back of the
processing system and a rough sizing shredder was
used as the first piece of equipment in the system. This
reduced, but did not eliminate, the problem of abrasive particles embedding in the fuel. Size separation
equipment was introduced, generally removing the
small size fraction which is less than 1.5 in. (38.1 mm)
composed mostly of broken glass, ceramics and dirt,
which was sent to landfill. RDF was stored on the floor
rather than in bins or hoppers and was moved by
front-end loaders to conveyor belts. This greatly improved the reliability of fuel flow to the boiler.
In third generation RDF processing systems (Fig.
22) the first piece of equipment became a flail mill or
similar equipment whose main function was to break
open the garbage bags. The refuse is still size-separated
using a trommel disk screen with the minus 1.5 in. (38.1
mm) size destined for landfill. Generally, a device such
as an air density separator is added to collect the light
fraction (paper, plastics, etc.) from this stream to achieve
maximum heat recovery. Where it is economically attractive, separation of aluminum and other non-ferrous
metals is added to the plus 1.5 in. (38.1 mm.) minus 6
in. (152 mm) stream.
RDF yield
RDF yield is defined as the percentage of RDF produced from a given quantity of MSW. For instance, a
70% yield means that 70 t (63 tm) of RDF are produced
for every 100 t (90 tm) of incoming MSW. The ash content of RDF is directly related to the yield of the processing system. In a processing system with a lower
yield, the portion of the MSW that is rejected is gen-
erally high in ash and inerts content and, therefore,
the resulting RDF is low in ash content. When an RDF
processing system is designed to obtain a higher yield,
more of the ash is carried over into the RDF fuel fraction and the ash content is increased.
The RDF heating value is inversely related to the
yield; the lower the yield, the higher the heating
value. A sophisticated RDF processing system will
have multiple stages of material separation that remove a very large percentage of the metals, inert
material, and high moisture organic material. Since
a relatively large portion of the incoming MSW is removed by this processing system, the RDF yield is significantly lower than the yield produced by a less sophisticated crunch and burn system. The resultant
RDF, however, will have a high heating value corresponding to its low percentage of non-combustible
material (ash) and high-moisture organic material.
A typical MSW might have a composition comparable to the reference waste shown in Table 4. The
majority of the waste is combustible materials, which
have ash contents ranging from approximately 4% for
wood to 12% for glossy magazine paper. The glass frac-
Table 4
Typical Reference Refuse
Component Analysis
Corrugated board
Newspapers
Magazines
Other paper
Plastics
Rubber, leather
Wood
Textiles
Yard waste
Food waste
Mixed combustibles
Ferrous
Aluminum
Other nonferrous
Glass
Total
Carbon
Hydrogen
Sulfur
Water
Ash
Total
Heating value
Steam 41 / Waste-to-Energy Installations
5.53
17.39
3.49
19.72
7.34
1.97
0.84
3.11
1.12
3.76
17.75
5.50
0.50
0.32
11.66
100.00
Ultimate Analysis
Nitrogen
Oxygen
Chlorine
Fig. 22 Third generation RDF processing system.
Reference
MSW
RDF
(% by wt)
(% by wt)
26.65
3.61
0.17
(max. 0.30)
0.46
19.61
0.55
(max. 1.00)
25.30
23.65
100.00
31.00
4.17
0.19
(max. 0.36)
0.49
22.72
0.66
(max. 1.20)
27.14
13.63
100.00
4,720 Btu/lb
(10,979 kJ/kg)
5,500 Btu/lb
(12,793 kJ/kg)
Fuel value recovery, % MSW
Mass yield, % RDF/MSW
96
83
29-15
The Babcock & Wilcox Company
tion, yard waste and mixed combustibles may also
contain varying quantities of sand, grit and dirt. The
predicted composition of the RDF will vary depending on the type of processing system and the resulting yield. Table 5 shows how the ash content in the
fuel and the heating value of the fuel will vary as the
RDF yield varies with different processing systems.
Two cases are considered, one which assumes no front
end recycling (curbside recycling or separate recycling
facility), and a second case which assumes that such
a system is in place in the community.
RDF quality
RDF used to supplement pulverized coal in utility
boilers should be very low in ash; contain the least
possible amount of ferrous metal, aluminum, and other
nonferrous metal; and be small enough in particle size
to be fed pneumatically to the boiler. The processing
system for such a fuel would generally be a very low
yield system, between 40 and 60%.
RDF for dedicated traveling grate stoker boilers
should be low in ash; as free as possible of ferrous
metal, aluminum and other nonferrous metals; and
have a particle size distribution that is considerably
larger than the particle size of RDF for use in Cyclone
or pulverized coal boilers. The processing system for
such a fuel will have a higher yield, around 70 to 85%.
RDF produced in a crunch and burn system, in
which solid waste is shredded and only the ferrous
metal removed, has a yield of about 93%; an inherently high ash content; and contains 100% of the aluminum, other non-ferrous metals, glass, stones and
ceramics in the original MSW. The large quantities of
aluminum, glass, and other inerts that remain in the
RDF will result in higher wear on the stoker and lower
furnace. The economic advantage of installing a less
sophisticated crunch and burn processing system is
generally offset by the need to provide a more conservatively designed stoker and furnace as well as a
larger ash handling system.
RDF processing systems
An optimum RDF processing system for a dedicated
boiler application achieves the highest yield with the
Table 5
RDF Yield Versus Ash Content and Fuel Heating Value
Mode
RDF Yield %
Ash
Btu/lb (kJ/kg)
Without front-end recycling:
Mass burn
Crunch and burn
RDF
100%
93%
83
to 70%
23.64
19.87
11.72
to 8.87
4814
5146
5641
to 5834
(11,197)
(11,970)
(13,121)
(13,570)
19.58
17.16
9.91
to 6.59
5513
5898
6328
to 6491
(12,823)
(13,714)
(14,719)
(15,098)
With front-end recycling:
Mass burn
Crunch and burn
RDF
29-16
100%
93%
85
to 71%
Fig. 23 Components of a complete RDF processing system.
highest heat recovery, while removing ferrous, aluminum and other non-ferrous materials, and glass. Such
a system (Fig. 23) includes the following:
In-feed conveyors From the tipping floor, the solid
waste is fed by front-end loaders or excavators to steel
pan apron conveyors which feed the flail mill in-feed
conveyors.
Initial size reduction The flail mill tears open the
plastic garbage bags, coarsely shreds the refuse, and
also breaks glass bottles to a size of approximately 1.5
in. (38.1 mm) or less.
Ferrous metal recovery Ferrous metal is extracted
from the coarsely shredded MSW in each line by a
single-stage overhead magnet. Recovered ferrous
metal is moved to a ferrous air classifier where tramp
materials such as paper, plastics or textiles are removed, thereby providing a clean ferrous product. A
ferrous recovery of 90% is possible.
Size classification and final size reduction After ferrous removal, shredded waste is fed into a rotating
trommel screen, a size separating device about 10 ft
(3.0 m) in diameter by 60 ft (18.3 m) long. The
trommel performs the following functions:
1. removes glass, sand, grit and nonferrous metal
less than 1.5 in. (38.1 mm) in size, and
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
2. removes the minus 6 in. (152 mm), plus 1.5 in.
(38.1 mm) fraction and contains the bulk of the
aluminum cans.
The trommel oversize material, plus 6 in. (152 mm),
is then shredded in a horizontal secondary shredder.
Because the secondary shredder is a major consumer
of energy and has high hammer maintenance costs,
the RDF process is specifically designed to reduce the
secondary shredder’s load by shredding only those
combustibles too large for the boiler. Particle size is
primarily controlled by the design of the secondary
shredder grate openings. Additional particle size control may be achieved by adding a disc screen downstream of the secondary shredder to recycle any oversized material back to the secondary shredder.
Separation of glass, stones, grit and dirt Trommel
undersize material, minus 1.5 in. (38.1 mm), passes
over an air density separator (ADS) designed to remove dense particles from less dense materials
through vibration and air sweeping. This device can
efficiently remove glass, stones, grit and dirt, as well
as nonferrous metals. The light fraction, which can
range from approximately 50 to 90% of the ADS feed,
consists essentially of combustibles with high fuel
value which are recovered and blended into the main
fuel stream.
Aluminum can recovery To optimize aluminum can
recovery, an air classifier is provided for the plus 1.5
in. (38.1 mm), minus 6 in. (152 mm) undersize fraction. The air classifier removes the light organic portion of the stream, allowing aluminum cans to be more
visible for hand pickers. The air classifier heavy fraction drops onto a conveyor moving at approximately
2.5 ft/s (0.76 m/s) with numerous hand-picking stations on either side of the belt. Cans go into hoppers
and, by conveyor, to a can flattener. A pneumatic conveyor then transfers the flattened cans into a trailer.
An eddy current separator, for the removal of aluminum cans, can replace hand picking if the expected
amount of cans is high enough to justify the additional capital cost. Aluminum recovery of 60% is possible with hand picking, while up to 90% recovery is
possible with the eddy current separator.
Oversized bulky waste (OBW) The OBW shredder is
generally a horizontal hammer mill used to shred ferrous metal recovered by the RDF processing lines and
pre-separated oversized material which includes white
goods such as refrigerators, washing machines, furniture and tree limbs. The ferrous metal is magnetically recovered and given a final cleaning by an air
scrubber to remove tramp materials. The nonferrous
material is integrated into the RDF stream.
Tire shredding line If there is a sufficient supply of
tires, a separate tire shredding line can be included.
A shear shredder, used specifically for shredding tires,
can shred 500 passenger car tires per hour. The shredder includes a rotary screen classifier (trommel) for
returning shredded tire chips above 2 in. (51 mm) back
to the shredder. A tire chip 2 by 2 in. (51 by 51 mm) or
less is the final product which is then blended in with
the RDF stream.
RDF storage building RDF from each processing line
is conveyed to an RDF storage building. From there,
Steam 41 / Waste-to-Energy Installations
it is either fed directly to the boiler or fed directly to a
shuttle conveyor and storage pile. When RDF feed is
direct to the boiler, excess RDF from the boiler feed
system is returned to the RDF storage building. RDF
not being fed directly to the boiler is retrieved from
the storage pile by a front-end loader and loaded onto
inclined conveyors which transport the RDF to the
boiler feed system.
Fuel feed system: metering feeders
A successful RDF metering feeder must meet the
following design criteria:
1. controlled fuel metering to meet heat input demand,
2. homogenization of material to produce even density,
3. adequate access to deal with oversized material,
4. maintainability, in place, and
5. fire detection and suppression devices.
A reliable RDF metering feeder (see Fig. 21) is a key
feature of the second generation RDF boiler design.
One feeder is used for each air-swept fuel distributor
spout. Each feeder has an upper feed bin which is kept
full at all times by an over-running conveyor to ensure a continuous fuel supply. The fuel in this hopper
is transferred to a lower hopper by a hydraulic ram.
The ram feed from the upper hopper is controlled by
level control switches in the lower hopper. The RDF is
fluffed into a uniform density by a variable speed inclined pan conveyor which sets up a churning motion
in the lower hopper. The pan conveyor delivers a constant volume of RDF per flight which is carried up the
pan conveyor and deposited into the air-swept spout.
The rate at which the fuel is deposited into the spout
is based on fuel demand.
Air-swept distributor spouts
Air-swept fuel spouts, used extensively in the pulp
and paper industry, proved to be equally effective for
RDF firing. (See Chapter 28.) Lateral fuel distribution on the grate is achieved by locating multiple
spouts across the width of the furnace. Longitudinal
distribution is achieved by continuously varying the
pressure of the air sweeping the spout floor. A major
feature of this design is its simplicity.
Traveling grate stoker
To date, only traveling grates have been used for
spreader-stoker firing of RDF. These grates move from
the rear of the furnace to the front, into the direction
of fuel distribution. A single undergrate air plenum is
used. There is a wealth of experience worldwide with
traveling grate stokers burning a myriad of waste and
hard to burn fuels. The parameters for unit design
shown in Table 6 were developed from this experience
and the uniqueness of the RDF. (See also Chapter 16.)
On mass-fired stokers, a large volume of fuel at the
front slowly burns down to a small volume of ash at
the back. For an RDF stoker the key is to maintain
an even 8 to 10 in. (203 to 254 mm) bed of fuel and
ash over the entire stoker area. Grate problems are
usually due to a shallow ash bed or localized piling of
fuel. Operator tendency, when confronted with poor
metering and/or fuel distribution, is to run the grates
29-17
The Babcock & Wilcox Company
Table 6
Stoker Design Criteria (English units)
Parameters
RDF
Wood
Grate heat release, 10 Btu/h ft
0.750
Input per ft of grate width, 106 Btu/h
15.5
Fuel per in. of distributor width, lb/h
450
Feeding width as % of grate width
45 to 50
Grate speed, ft/h
25
1.100
29
1000
45 to 50
N/A
6
2
faster. While this technique can minimize bed upset, it
will shorten grate life due to higher wear rates and the
overheating of the grate bars. With the recommended
ash bed thickness, tramp material is minimized, grate
temperatures are lowered, wear is reduced, and grate
life is increased. To achieve this optimum ash bed requires controlled metering of the RDF and proper distribution of the fuel to the grates, as previously described.
A second problem is the accumulation of melted aluminum and lead on the grate. The best solution is total removal of these metals from the fuel stream. If
this is not practical, experience has shown that maintaining proper ash bed thickness will cause the aluminum and lead to solidify in the ash bed rather than
on the grate.
Fluidized-bed combustion
Beginning in the 1980s, fluidized-bed combustion
technologies, both bubbling bed and circulating bed,
had proven themselves to be efficient and cost-effective technologies for the combustion of waste fuels
such as biomass, sludge, and waste coals. (See Chapters 17 and 30.) In the mid-1990s, there was growing
interest in applying these fluidized-bed technologies
to the combustion of RDF based upon higher efficiency, reduced emissions, and lower capital costs.
While a number of waste-to-energy facilities were
installed that utilized fluidized-bed technology, few of
these facilities were able to achieve these high expectations due to several unique characteristics of RDF:
1. The quality and particle size of RDF is more critical for fluidized-bed combustion than for stoker
firing to ensure fluidization of the fuel within the
bed and to avoid plugging of the bed drain system. The fuel processing system needed to produce
RDF suitable for fluidized bed combustion has a
higher capital cost plus higher operating and
maintenance costs.
2. A coal-fired fluidized-bed power generation facility can have a lower capital cost than a pulverized coal facility due to the in-bed capture of sulfur dioxide. This eliminates the need for a separate flue gas scrubbing system. The combustion
of RDF, however, produces HCl as well as sulfur
dioxide (SO2) and a fluidized-bed boiler can not
capture a sufficient amount of the HCl to meet current emissions limits. Therefore, a separate flue
gas scrubbing system is required with significant
capital and operation/maintenance costs.
3. Furnace and superheater tube corrosion is a major concern for any refuse-fired boiler; erosion is a
29-18
major concern for a fluidized-bed boiler. One form
of protection against corrosion in a refuse-fired
boiler is the formation of an oxide layer on the
surface of the tubes. This oxide layer acts as a
barrier against continual contact between the corrosive flue gas and the tube material. The erosive
action of the bed material in a fluidized-bed boiler
will continuously remove this protective oxide
layer as it is being formed, thereby accelerating
the corrosion rate.
Fluidized-bed combustion technology is capable of firing RDF. However, the advantages of the technology must
be carefully weighed against its disadvantages.
Lower furnace design configuration
The lower furnace designs of early RDF boilers were
largely based upon technology used for wood-fired
boilers. This included modest overfire air (OFA) systems with multiple small diameter nozzles designed
for 25 to 30% of the total air supply, straight wall furnaces, and carbon reinjection systems. The result was
less than desired combustion performance due to inadequate turbulent mixing in the furnace. Today’s
RDF units are designed with fewer large diameter OFA
nozzles designed for 50% of the total air supply with
nominal operation at 40%. This design has proven
itself capable of injecting OFA deep into the combustion chamber for improved turbulent mixing of air
with combustibles released from the grate. The Controlled Combustion Zone (CCZ) lower furnace design
with twin arches for wood and biomass firing (see
Chapters 16 and 30) has also been applied to some
limited RDF applications.
Furnace exit gas temperature
Gas temperatures leaving the furnaces of first and
second generation designs were higher than anticipated. There were not enough data on RDF firing to
accurately predict the relationship between furnace
surface area and furnace exit gas temperature. Compounding this problem was a continual increase in the
heating value of the RDF due to changes in the composition of the raw refuse and the development of more
efficient processing equipment. To achieve the desired
furnace exit gas temperatures, the size of the third
generation furnace has increased significantly. The
furnace width and depth are set by the size of the
stoker, therefore the furnace height has increased to
achieve the required furnace exit gas temperatures.
Ash handling systems
Much of the non-combustible material in the RDF
system is removed before it is fed to the boiler. Although systems vary, there is generally some effort
made to remove ferrous metals and aluminum, both
of which can be troublesome once they reach the
stoker grates. Non-combustibles and most of the ash
from combustion collect on the traveling grate stoker
and discharge off the front into a submerged chain
conveyor system.
The submerged chain conveyor (Fig. 24) is a mechanical conveyor that consists of a water-filled trough
and a dry return trough, with two endless chain
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
flyash from the scrubber, baghouse or precipitator
hoppers are all handled the same way as previously
discussed for mass-fired boilers.
Fig. 24 Submerged chain conveyor for RDF stoker ash.
strands with flights connected between the strands.
The return trough can be either above or below the
water-filled trough. Ash from the stoker discharge
chute drops into the water-filled trough. The water
absorbs the impact of any larger ash pieces, quenches
the ash, and provides a gas-tight seal with the stoker
discharge chute.
The chains are usually driven by a variable speed
drive to handle varying ash rates. The ash residue is
conveyed from the bottom of a water-filled trough up
an incline section where the ash dewaters and discharges directly into a truck, a storage bin, or onto
another type of conveyor for final transport and disposal. Because this conveyor uses a dragging action
to convey the ash, it is not used on mass-fired units
where it can have problems in dragging the large noncombustible items up the incline section.
Fine ash from the boiler siftings hopper, flyash from
the boiler, economizer and air heater hoppers, and
Retrofits to RDF
Most dedicated RDF boilers are new installations.
However, it is possible to retrofit existing boilers to
become dedicated RDF boilers. To be candidates, the
existing boilers must be conservative designs for solid
fuels, such as wood or coal. Typically, these are older
units which are underutilized or used as standby
units. These plants are often located near large metropolitan areas, sources of large quantities of refuse.
The conversion of such an older power plant could
represent a cost-effective solution to a community’s
refuse disposal problems.
B&W has converted several such boilers from coalfired to dedicated RDF. Each retrofit is unique in that
each of the coal-fired boilers was of different design
and originally supplied by different manufacturers.
Each retrofit was also the same in that all were designed to the same standards as new RDF units.
The principal modification involves enlarging the
furnace to obtain the proper furnace volume for combustion. Although coal-fired boilers have conservatively sized furnaces, refuse firing requires even
larger volumes. This is achieved by removing the existing stoker and lower furnace and installing new
membrane furnace wall panel extensions (Fig. 25). The
new lower furnace is protected from corrosion using either Inconel weld overlay or Inconel bimetallic tubes.
Fig. 25 Coal-fired unit converted to RDF.
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The Babcock & Wilcox Company
Other pressure part modifications could include:
1. converting the superheater to a parallel flow design while adding the proper metals for corrosion
protection,
2. modifying the boiler, economizer and air heater
surface for the proper heating surface distribution
and to meet refuse standards for velocities, tube
spacing, etc., and
3. possibly adding screen surface to lower the flue gas
temperature entering the superheater.
In some cases, the coal stoker can be reused for RDF
firing; in other cases it must be replaced. In either case
the grate release rate, and other design criteria, must
be set to the same design standards as new refuse
boilers. Properly executed, the retrofit of an existing
boiler to RDF firing will result in an RDF boiler as
conservative as a new RDF boiler and capable of operating equally well.
Boiler components
Fig. 26 Parallel flow superheater (SH).
Superheater
Superheater design is critical in both mass burn and
RDF-fired refuse boilers because of the highly corrosive nature of the products of combustion. This is compounded in the U.S. by the desire for the highest possible steam temperature and pressure to maximize
income from power production sales while still disposing of refuse in an environmentally safe manner. B&W
has pioneered both the 900 psig (6.2 MPa) 830F (443C)
and 1300 psig (8.96 MPa) 930F (499C) high pressure,
high temperature steam cycles for refuse boiler application. This noteworthy increase in pressure and temperature over the more conventional refuse boiler steam conditions of 600 psig (4.14 MPa) and 700F (371C) has resulted in a significant improvement in cycle efficiency.
To accomplish this improvement, the superheater
must be specifically designed for corrosion protection.
Superheater corrosion is a function of many variables
including flue gas temperature, flue gas velocity, tube
spacing, tube metal temperature, tube metallurgy, and
ash cleaning equipment. Each of these variables must
be taken into consideration to avoid rapid superheater
corrosion, even if the superheater steam outlet temperature is relatively low. For example, specifying only
a low furnace exit gas temperature will not assure long
superheater life.
Of these criteria, tube metal temperature and tube
material are most critical. To obtain satisfactory refuse
boiler superheater performance, two key design features are needed:
1. a parallel flow superheater design as shown in Fig.
26 where the coolest steam conditions are exposed
to the hottest gas temperatures and the hottest
steam temperatures are matched with the coolest
gas temperatures. The result is a design with the
lowest maximum superheater metal temperatures.
2. use of Incoloy tube material in the highest tube
metal temperature sections of the superheater.
Carbon steel is still used in the superheater sections with lower superheater metal temperatures.
B&W refuse boilers were the first to demonstrate
successful commercial operation at the 900 psig (6.2
MPa), 830F (443C) steam cycle with the first three
units going into operation at the Westchester County,
New York refuse-to-energy facility in 1984. As of 2004,
there were 21 B&W refuse boilers in operation at these
steam conditions with more than 320 cumulative years
of operating experience.
B&W extended this leadership position in superheater design in 1992 with the development of the first
refuse boiler design to use the 1300 psig (8.96 MPa)
and 930F (499C) steam cycle. This design was based
on laboratory corrosion research and full scale superheater test sections installed in operating refuse boilers. In one test, two full scale superheater sections,
composed of a variety of tube metallurgies, were installed in an operating 900 psig (6.2 MPa), 830F
(443C) design refuse boiler with steam flow through
the sections controlled to simulate 1000F (538C) operation. One section was removed after one year of
operation and the second after 26 months. This test
provided the basis for tube metallurgy selection for the
1300 psig (8.96 MPa), 930F (499C) design. In 1994,
two mass-fired refuse boilers located in Falls Township,
Pennsylvania, were placed into operation generating superheated steam at 1300 psig (8.96 MPa) 930F (499C).
These boilers continue to operate successfully.
In addition to corrosion concerns, the superheater
must be designed to minimize fouling and the potential
for erosion due to excessively high flue gas velocities.
Maximum design velocity is 30 ft/s (9.1 m/s), but in practice it is usually in the 10 to 15 ft/s (3 to 4.6 m/s) range.
Minimum superheater side spacing is 6 in. (152 mm).
29-20
Boiler design
The lower furnace design, refuse stokers and refuse
feed systems are markedly different for mass-fired and
RDF boilers. However, the design requirements for the
upper furnace, generating surface and economizer are
the same. This is also true for auxiliary equipment
such as burners and ash cleaning equipment.
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
Upper furnace design The upper furnace must be
sized to provide adequate heat transfer surface to reduce the flue gas temperature entering the superheater to an acceptable level. This helps minimize fouling in the superheater and maintain low superheater
tube metal temperatures to minimize corrosion. A certain amount of furnace volume is required for complete burnout of the fuel in the furnace and minimum
CO emissions. The required volume should be measured from the point where all the combustion air has
entered the furnace (the highest level of overfire air
ports) to the point where the flue gas enters the first
convective heating surface (at the tip of the furnace
arch at the bottom of the superheater). Measured in this
manner, the required furnace volume per unit of heat
input is the same for both mass-fired and RDF boilers.
The furnace must also contain sufficient heating
surface to lower the flue gas temperature to help reduce fouling and corrosion in the superheater and
boiler bank. The gas temperature should be limited
to 1600F (871C) entering the superheater and 1400F
(760C) entering the boiler bank. Lower temperature
values may be appropriate in certain geographic areas where the refuse composition is known to be highly
corrosive. As a general rule, the furnace size is set by
volumetric requirements in smaller capacity boilers
and by maximum gas temperature limits in larger
capacity boilers.
Boiler generating bank Refuse boilers in operation
use both the one-drum and two-drum design. In the
two-drum design there is both a steam drum (upper
drum) and a lower drum, interconnected by the boiler
generating bank tubes.
In the one-drum design the steam drum is located
outside of the flue gas stream; there is no lower drum.
The steam generating bank tubes are shop-assembled
modules. These modules may be of either the vertical
longflow (see Fig. 12) or a vertical crossflow design.
Minimum side spacing in the two-drum design and for
the generating bank modules used with the one-drum
design is 5 in. (127 mm). Maximum design flue gas
velocity is set at 30 ft/s (9.1 m/s).
Economizer The economizers can be either vertical longflow or horizontal crossflow. Economizer side
spacing should be no less than 4 in. (102 mm) with a
maximum flue gas velocity of 45 ft/s (13.7 m/s).
Air heater
Air heaters may be used for two reasons: 1) to supply preheated air to help dry and ignite the refuse on
the stoker, and/or 2) to increase thermal efficiency
where high feedwater temperatures preclude designing to lower exit gas temperatures with economizers.
RDF-fired units have typically used air heaters to
preheat the combustion air to the 300 to 350F (149 to
177C) range. Both tubular and regenerative air heaters have been used successfully. Due to air leakage
into the air heater and the potential for fouling, regenerative types have been limited to the outlet side
of hot electrostatic precipitators where the flue gases
are relatively clean.
When either tubular or regenerative air heaters are
used, the design and arrangement should minimize
Steam 41 / Waste-to-Energy Installations
the potential for low-end temperature corrosion. To
some extent, the surface arrangement in a tubular air
heater will maintain adequate protection. Steam coil
air heaters are required at the air inlet, on either type,
to preheat the incoming ambient air and maintain the
average metal temperature above acid dew points.
(See also Chapter 20.)
Ash cleaning equipment
To maintain the effectiveness of all convective heating surfaces and to prevent pluggage of gas passages,
it is necessary to remove ash and slag deposits from
external tube surfaces. Steam or air sootblowers are
most commonly used. Saturated steam is preferred for
its higher density and better cleaning ability. One disadvantage of sootblowing is that localized erosion and
corrosion can occur in areas swept too clean by the
blowing medium. This problem can be addressed by
installing tube shields on all tubes adjacent to each
sootblower for localized protection.
A mechanical rapping system (Fig. 27) can be used
to complement the sootblowers. In this system, a number of anvils strike designated pins to impart an acceleration through the superheater tube assembly. The
purpose is to remove the bulk of the ash while leaving a light layer of ash on the tubes for corrosion protection. Mechanical rapping systems will not eliminate
the need for sootblowers, but will reduce the number
of sootblower cleaning cycles required.
Auxiliary input burners
Auxiliary fuel burners are used to maintain furnace
temperature during startup, shutdown, and upset
conditions to minimize the release of unburned hydrocarbons. In most cases, the auxiliary fuel (oil or gas)
burners are designed for only 25 to 30% of the boiler’s
maximum heat input.
When not in service, the typical gas- or oil-fired
burner requires some amount of air flow through the
idle burner for protection against overheating. Because this air leakage represents an efficiency loss,
Fig. 27 B&W mechanical rapping system for cleaning superheaters.
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The Babcock & Wilcox Company
and because these burners are used infrequently, a
special design auxiliary input burner (AIB) is used for
refuse boilers. The AIB is designed with a retractable
burner element which is inserted toward the furnace
when in use, and retracted when out of service. There
is also a movable ceramic shutoff damper which provides protection against furnace radiation and debris
when the burner is out of service. When the burner
is put into service, this ceramic damper is retracted to
one side and the burner element is inserted through
an opening in the damper (Fig. 28).
maintenance. Either retractable or light weight aluminum support beams are inserted into the furnace
from access doors in the front wall to the superheater
arch, where the beams are locked in place. Corrugated
decking material is then inserted into the furnace
through special side wall access doors, and arranged
on top of the support beams. This system provides both
a platform for working in the superheater and upper
furnace and some overhead protection to those working in the lower furnace.
Upper furnace maintenance platforms
Because refuse is a high fouling fuel, it is necessary
to have good access to the convection sections. Maintenance platforms (Fig. 29) are often used to allow
access to the superheater area for inspection and
Air pollution control equipment
Fig. 28 Auxiliary input burner (out-of-service and in-service positions).
29-22
Various boiler fuels have specific components
unique to that fuel. Some of these components, such
as sulfur, create specific air pollution emissions that
require unique boiler designs or specific air pollution
control equipment. These fuels, such as high sulfur
coal, are homogenous. This means the fuel will be the
same in the future as it is today, and will be the same
from one day to the next.
Refuse is a nonhomogenous fuel. It not only changes
over the long term, but can change from day to day.
Nearly every component of a fuel that can result in
an unwanted air pollutant is present in refuse. However, in the early 1980s when the number of refusefired boilers began to rapidly grow in the U.S., the only
emissions requirements were on particulates, NOx and
SOx. Refuse boilers, due to their relatively cool burning systems and the generally low level of fuel bound
nitrogen, are low NOx generators. There are also very
low levels of sulfur in refuse. Therefore, early boilers
were generally equipped only with an electrostatic precipitator (ESP) for particulate control. As more boilers
went into operation and further air emissions data were
obtained, additional emissions requirements were applied. Initially, hydrochlorides were targeted for control. Soon the various state air pollution agencies set
regulations for the control of dioxins and furans as well
as a long list of heavy metals.
Dry systems
Dry scrubbers, used for years to control SO2 emissions from coal-fired units, were found to be equally effective in controlling HCl emissions from refuse units.
With the initial use of dry scrubbers, there was a
split in the preferred particulate collection system between the ESP and baghouse. ESPs were used in
earlier applications due to their more extensive history of proven performance. However, it has been
fairly well documented that the layer of ash and lime
that collects on the bags themselves improves sorbent
utilization and increases the removal of SO2 and HCl
in a baghouse. This allows better capture of pollutants
for the same lime slurry rates, or the same level of
pollutant capture at slightly reduced lime slurry rates.
Dry scrubbers and baghouses were also found to be very
effective in controlling dioxin, furan and heavy metal
emissions. Today, the preferred system for nearly all
refuse boilers in North America is the dry scrubber/
baghouse combination. (See Chapters 33 and 35.)
To enhance the capture of mercury contained in the
flue gas, refuse-fired boilers are typically equipped
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
The SCR systems have been demonstrated to achieve
up to 90% NOx reduction on fossil fuel boilers. However, the catalyst itself is fairly easily poisoned, and
therefore rendered less effective, by a multitude of
substances, all of which are found in refuse to various degrees. At this time it is not clear what the longterm life of the SCR catalyst would be on a refuse-fired
boiler. (See Chapters 33 through 35.)
During this same time period, the emission requirements for CO have also been driven to lower levels.
These requirements have been met by a combination of:
1. better overfire air system,
2. more control of undergrate air (more compartments with individual air control),
3. better combustion control systems,
4. larger furnace volumes, and
5. operator training.
Fig. 29 Upper furnace maintenance platform.
with an activated carbon injection system that works
in conjunction with a dry scrubber and baghouse. The
process involves the injection of powdered activated
carbon into the flue gas upstream of the dry scrubber. As the activated carbon mixes with the flue gas,
it captures the mercury through adsorption. The activated carbon is then collected in the baghouse and
removed along with the flyash.
NOx and CO control
The permissible level of NOx emissions has also been
significantly reduced since the late 1980s. The lower
NOx limits can generally be achieved by installing an
in-furnace ammonia or urea injection system. The
ammonia injected into the furnace reacts with the NOx
contained in the flue gas to produce nitrogen and
water. This form of NOx control technology is known
as selective non-catalytic reduction (SNCR) and can
reduce the flue gas NOx concentration by as much as
60%. In certain geographical nonattainment areas for
NOx emissions, selective catalytic reduction (SCR) systems may be required for even greater NOx control.
Wet systems
Wet emissions control systems are also used. A typical
wet gas cleaning system is designed for the removal
of HCl, SO2, hydrogen fluoride, mercury, dioxins and
solid particle pollutants from MSW-fired systems. A
sample process used in Europe includes six major
steps:
1. an ESP collecting most of the particles,
2. a heat exchanger that cools the gas to recover energy before the first scrubber,
3. a first spray scrubber to quench the gas further
to saturated conditions and remove HCl and mercury,
4. a second spray scrubber to remove SO2,
5. a third spray scrubber to allow removal of the dioxins, and
6. final filtering modules to remove excess dust particles coming from the ESP and other scrubbers.
An optional condensing heat exchanger can be
used for additional heat removal if a hot water heating system is associated with the plant. Water treatment units process the liquid bleeds and overflows to
yield a cake containing the solids for disposal.
Inconel is a trademark of the Special Metals Corporation group of
companies.
Steam 41 / Waste-to-Energy Installations
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The Babcock & Wilcox Company
This facility features three 750 ton per day mass-fired units by B&W.
29-24
Steam 41 / Waste-to-Energy Installations
The Babcock & Wilcox Company
Chapter 30
Wood and Biomass Installations
The category of wood and biomass covers a wide
range of material that can be used as a source of
chemical energy. Wood encompasses a number of
sources such as bark, wood sticks, sawdust, sander
dust, over- and under-sized wood chips rejected from
the pulping process, whole tree chips, and scrap shipping pallets. Biomass is anything that is or recently
was alive such as straw, vine clippings, leaves, grasses,
bamboo, sugar cane (called bagasse after the sugar
has been extracted), palm oil, coffee grounds, and rice
hulls from the food processing industry. All of these
materials can be used as a fuel source to generate steam.
While wood and other biomass fuels were some of
the first materials used as energy sources, their use
declined around the early 1900s, when more consistent and easily transportable fossil fuels such as coal,
oil and natural gas became more available. Nevertheless, there have always been applications where wood
and biomass have been the preferred fuels. There has
therefore been slow but steady progress in the development of equipment for firing these fuels.
Many factors have led to a recent, rapid development in this area. Some of these factors include the rising cost of certain fossil fuels, renewable energy options,
development of new technology that allows better use
of industrial byproducts, and the trend toward cogeneration in many industries. This includes industries that
produce both electric power and process steam. Wood
and biomass are used in many municipal combined heat
and power (CHP) installations, particularly in Europe.
Biomass gasification is a relatively new technology
being explored to supply fuel gas for power production by gas engines or gas turbines.
Equipment for chemical and heat recovery in the
paper industry is discussed in Chapter 28. Equipment
for using municipal solid waste as a fuel is discussed
in Chapter 29. Stoker-related information is discussed
in Chapter 16.
Steam supply for power production
Cogeneration in industry
Most heating requirements can be met with saturated steam at 150 psig (1.03 MPa) or less. Cogeneration, or the simultaneous production of electrical or
Steam 41 / Wood and Biomass Installations
mechanical energy and heat energy to a process, has
very high thermal efficiency. Thus, waste heat from
electricity production becomes part of a usable process
rather than being rejected into the atmosphere.
In a cogeneration facility, relatively high pressure
superheated steam passes through a steam turbine or
steam engine where energy is extracted. The exhaust
steam is then used as a heat source in a process. The
conversion efficiency, or the amount of heat absorbed
in the steam turbine plus the heat absorbed in the process, versus the amount contained in the steam, approaches 100%. The overall thermal efficiency of a cogeneration process is closely approximated by the thermal efficiency of the boiler alone.
As well as providing high energy efficiency, there
is a second and often more compelling reason for industries, especially the pulp and paper industry, to
practice cogeneration. These industrial plants are often located far from economical and reliable sources
of electricity and conventional fossil fuels in order to
be close to their source of fiber, the forests. Cogeneration facilities equipped with wood-fired power boilers,
for example, are therefore often justified.
Biomass-fired utilities
Changing economic conditions and environmental
regulations have made utility plants fired by biomass
fuels a practical source of electrical energy, in spite of
their relatively high capital costs. Sometimes the plant
is built with a condensing turbine and other times it
is built beside or within a plant that can use exhaust
steam. Economic conditions favoring such facilities
include the unpredictable and sometimes high cost of
conventional fossil fuels, the relatively low cost of wood
waste and other biomass fuels, and the high cost to transport and dispose of biomass in a landfill.
Occasionally an installation is justified with regard
to the high cost of emissions control equipment. Most
wood and biomass fuels generate lower nitrogen oxides (NOx) and sulfur dioxide (SO2) emissions than conventional fossil fuels. In one installation in California,
for example, it was found that the amount of NOx produced by incinerating grapevine clippings and other
biomass could be substantially reduced by burning the
material in a wood-fired utility installation in a controlled manner. This produced environmental benefits
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The Babcock & Wilcox Company
while generating electricity that would otherwise be
produced by burning traditional fossil fuels.
The Babcock & Wilcox Company (B&W) operation
in Europe completed a significant biomass-fired installation that burns straw in an ultra-supercritical power
plant application. (See Fig. 1.) This straw-fired boiler
consumes 105 MWt of fuel producing 35 MW of electricity and 50 MWt of heat. In this advanced design,
carded (loosened by mechanical raking) straw is fed
by screw feeders onto a water-cooled gasification grate
where a high percentage of the energy content is released by pyrolysis and gasification. The remaining
straw/carbon burns on a water-cooled vibrating grate.
A bag filter removes more than 99% of particulates from
the flue gas, and the plant operates within strict European emissions regulations.
Steam supply to process
Pulp and paper
The pulp and paper industry is the major consumer
of biomass fuels because wastes such as bark, sawdust,
shavings, lumber rejects and clarifier sludge are byproducts of the pulping, paper-making and lumber
manufacturing processes. There is a great amount of
heat energy available in these products, making them
useful energy sources. (See Figs. 2 and 3.)
The production of pulp and paper requires large
quantities of mechanical energy for grinding, chipping, cooking and refining. To produce a marketable
product, the pulp must be dried using steam or heated
surfaces such as paper machine dryer rolls. These energy
needs are met by using steam in a variety of equipment
(steam engines or turbines, steam coil air heaters, dryer rolls,
and/or indirect heaters) and by direct steam injection.
Fig. 2 Wood-fired two-drum Stirling® power boiler.
These requirements, coupled with the availability
of the waste products, make boilers fired by wood and
wood waste a logical choice for the pulp and paper industry. Most of the developments and improvements
in equipment for these boilers have been driven by
this industry’s needs.
Superheater
Straw
Carding
Rake
Conveyor
System
Screw
Feeders
Gas
Outlet
Water-Cooled
Vibrating Grate
Fig. 1 Straw-fired ultra-supercritical boiler (courtesy Energi E2 A/S).
30-2
Food processing
The food processing industry also has energy needs
that are provided by steam. Mechanical preparation,
cooking, drying and canning all require a source of
energy. Many foods leave behind waste byproducts
rich in cellulose or other organic (hydrocarbon) material. Instant coffee production generates coffee
grounds, sugar-making leaves bagasse from sugar
cane, coconut preparation discards husks, rice has its
hulls removed before packaging, and many types of
nuts are sold roasted with their shells removed.
Many producers have installed boilers that burn
such biomass materials, usually based very closely on
equipment originally designed for the pulp and paper industry. These boilers produce steam that is then
used as an energy source for the plant.
Steam 41 / Wood and Biomass Installations
The Babcock & Wilcox Company
Fuels
Constituents
Wood and most biomass fuels are composed predominantly of cellulose and moisture. The high proportion
of moisture is significant because it acts as a heat sink
during the combustion process. The latent heat of evaporation (Hfg) depresses the flame temperature, contributing to the difficulty of efficiently burning biomass fuels.
Cellulose, as well as containing the chemical energy
released during combustion, contributes fuel-bound
oxygen. This oxygen decreases the theoretical air required for combustion and therefore the amount of
nitrogen included in the products of combustion.
Most natural biomass fuels contain little ash. However, some byproducts, such as de-inking sludges, do
Day Bin/Hydraulic
Fuel Silo
Steam
Drum
contain a great deal of ash, in some cases up to 50% ash
on a dry basis. De-inking sludges are particularly difficult to burn because they usually have high moisture
and ash contents and low fuel-bound oxygen content.
Burning wood and biomass
The following general guidelines for wood and biomass combustion have been developed from experience:
1. Stable combustion can be maintained in most water-cooled furnaces at fuel moisture contents as
high as 65% by weight, as-received.
2. The use of preheated combustion air reduces the
time required for fuel drying prior to ignition and
is essential to spreader-stoker combustion systems.
The design air temperature will typically vary directly with fuel moisture content.
Radiant
Superheater
Gas Outlet
Auxiliary
Burners
Air Heater
Superheater
Furnace
Economizer
Speed Controlled
Screw Feeders
Air-Swept
Spout
Water-Cooled
Vibrating Grate
Individual
Controllable
Primary Air Chambers
Fig. 3 Multifuel single-drum, 141,000 lb/h (17.8 kg/s) steam flow, bottom-supported boiler with vibrating grate stoker.
Steam 41 / Wood and Biomass Installations
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The Babcock & Wilcox Company
3. A high proportion of the combustible content of
wood and biomass fuels burns in the form of volatile compounds. A large portion of the combustion
air requirement is therefore added above the fuel,
as overfire air (OFA).
4. Solid chars produced in the initial stages of combustion of these fuels are of a very low density.
Conservative selection of furnace size and careful placement of the OFA system are used to reduce gas velocity and keep char entrainment at
an acceptable level. Typical furnace selection criteria include a grate heat release rate of 0.47 to 1.1
× 106 Btu/h ft2 (1.5 to 3.5 MWt/m2) of grate surface
area, a furnace liberation rate of 17,000 Btu/h ft3
(176 kW/m3) of furnace volume, and an upward gas
velocity of 20 ft/s (6.1 m/s). This results in furnace
residence times of approximately three seconds for
larger units to enhance particulate burnout and
minimize emissions.
Burning in combination with traditional fuels
Biomass can be burned on a traveling grate with
stoker coal. The biomass is introduced to the furnace
through a separate conveying system and either a
separate windswept spout below the coal feeder or
through a combination feeder. (See Chapter 16.)
Biomass can be burned with pulverized coal, oil or
natural gas, using dedicated burners for the latter. In
this case, the grate is selected for wood firing.
When burning biomass with substantial quantities
of stoker or pulverized coal, the amount of ash from
the coal is greater than the amount from the biomass. Therefore, the design parameters for the coal
(slagging and fouling index) will govern the design.
When burning biomass with heavy fuel oil having
high sulfur and vanadium content, the ash that forms
on the convective surfaces can be tenacious and, once
removed, can be very abrasive. It is preferred to design for low flue gas temperatures and low flue gas
velocities, regardless of the specified contaminants in
the heavy oil and in the biomass, as both flue gas parameters can vary widely over the typical range of
boiler operating conditions. (See Chapter 10.)
Sludge burning
As mentioned above, paper mill sludges, especially
de-inking sludges, are difficult fuels to burn. Their
high moisture and ash content and low fuel-bound
oxygen may limit their allowable proportion of the
total heat input to the furnace.
Specific limits will vary with the sludge composition
and combustion system. Higher sludge inputs for a
given system can normally be achieved by combined
firing with better quality fuels.
Wood waste mixed with sludge can prove difficult
for the fuel handling system. Frequently, the sludge
segregates from the other fuels (at transfer points on
belt conveyors, for example) and can be fed preferentially to one feeder.
In spreader-stoker applications, the wet, dense
sludge can pile up in one place on the grate very
quickly. Therefore, when a portion of the fuel is sludge,
30-4
the boiler operator must continually inspect the grate to
determine whether adjustments are required.
Combustion systems
Many methods have been developed to burn wood
and other biomass fuels. The best known and most
successful methods use the following equipment.
Dutch oven
A dutch oven is a refractory-walled cell connected
to a conventional boiler setting. Water cooling is sometimes provided to protect and extend the life of the
refractory walls. Wood and other biomass fuels are
introduced through an opening in the roof of the dutch
oven and burn in a pile on its floor. OFA is introduced
around the periphery of the cell through rows of holes
or nozzles in the refractory walls.
The principal advantage of the dutch oven is that
only a small portion of the energy released in combustion is absorbed because of its high percentage of refractory surface. Therefore, it is able to burn high
moisture fuels (up to 60% moisture). In addition, as
the fuel is pile-burned, there is a high thermal inventory in the cell that makes the unit less sensitive to
interruptions in the fuel supply.
The dutch oven has distinct disadvantages when
compared to more modern methods. The unit operates
best when at a steady load and when burning a consistent fuel. It does not respond quickly to load demand.
The refractory is subject to damage from the following sources: spalling and erosion caused by rocks or
tramp metal introduced with the fuel, rapid cooling
from contact with very wet fuels, and overheating
when very dry wood is fired.
The dutch oven cell must be shut down regularly
to allow manual removal, or rake out, of the accumulated ashes. During this period, either load must be
drastically reduced as is done with multiple cell units,
or auxiliary fuel must be fired as is required for units
equipped with a single dutch oven.
Pinhole grate
The pinhole grate (Fig. 4) is a water-cooled grate
formed by cast iron grate blocks, sometimes referred
to as Bailey blocks, that are clamped and bonded to
the spaced floor tubes of a water-cooled furnace. The
grate blocks have venturi-type air holes to admit
undergrate air to the fuel on the grate. This grate is
used in conjunction with either mechanical fuel distributors or air-swept fuel spouts. Both produce a
semi-suspension mode of burning, wherein the finer
portion of the fuel is burned in suspension and the
heavier fraction accumulates and burns on the grate.
The ash and foreign material that stay on the grate are
removed by raking. Typically, 25% of the air for combustion of wood is introduced as OFA through nozzles in the
lower furnace walls and 75% is undergrate air.
This combustion system can follow minor load
swings by varying both the fuel flow and air flow, and
is suitable for biomass fuels containing up to approximately 55% moisture. A small amount of refractory is
used and maintenance requirements are low.
Steam 41 / Wood and Biomass Installations
The Babcock & Wilcox Company
ity to follow load swings and the automatic ash discharge
that permits continuous operation on biomass fuels.
The traveling grate was originally developed for
spreader-stoker firing of bituminous and subbituminous coals. With coal, the quantity of OFA required
for efficient combustion can be as low as 15% of the
total air. The quantity of ash in coal is also much
higher than in wood. It is therefore possible to develop
a relatively large bed of ash on the grate in order to
protect the grate from high temperatures, and to help
distribute the undergrate air flow. Lower moisture coal
can often be burned without air preheating and rarely
requires air temperatures in excess of 350F (177C).
The traveling grate, while an improvement over the
pinhole grate, must be considered a compromise design for the burning of biomass because the use of preheated air and the usually low ash content of biomass
reduce the cooling available to the grate. This grate has
many moving parts that are subjected to the furnace
heat, resulting in higher maintenance costs.
Vibrating grate
The vibrating grate allows intermittent, automatic ash
discharge. The grate consists of cast iron grate bars or
bare tube panels attached to a frame that vibrates on
an intermittent basis, controlled by an adjustable timer.
Fig. 4 Wood-fired boiler with pinhole grate.
The main disadvantage of this method is that the
grate requires manual raking of the ashes. Therefore,
biomass firing must be stopped on a regular basis.
Manual raking also limits the depth of the furnace and
therefore the steam capacity that can be economically
built. Mechanical raking machines have been developed to increase the allowable furnace depth and to
speed the raking process, while providing a certain
degree of protection to the operator from hot gas,
flames and hot ash.
Traveling grate
The traveling grate was introduced as an improvement over the pinhole grate. (See Fig. 5.) It is a moving grate that allows continuous automatic ash discharge and consists of cast iron or ductile iron grate
bars attached to chains that are driven by a slow
moving sprocket drive system. The grate bars have
holes in them to admit undergrate air that is also used
to cool the grate bar castings. The split between
undergrate and overfire air flows depends largely
upon fuel size, volatility and moisture content, while
also meeting the grate cooling requirements. For coal
firing, 60 to 85% of the air is typically supplied as
undergrate with the balance used for OFA. For biomass
firing, 25 to 50% of the air is typically supplied as
undergrate. Rows of nozzles in the furnace front wall
and rear wall are used for OFA. Fuel spreaders and
burning mode are identical to those used with the pinhole grate. The main advantages of this grate are its abilSteam 41 / Wood and Biomass Installations
Fig. 5 Wood-fired boiler with traveling grate.
30-5
The Babcock & Wilcox Company
There are two major types that have been used for biomass fuels, one water-cooled and the other air-cooled.
The water-cooled vibrating grate (see Fig. 6) is used
in conjunction with the semi-suspension firing mode.
Because the grate is water-cooled, high temperature
undergrate air, up to 650F (343C), can be used along
with very high percentages of OFA and a relatively
thin fuel bed. A key advantage of the vibrating grate
is the low number of parts that are highly stressed,
moving or in sliding contact. This results in reduced
maintenance requirements. The vibration is intermittent and several vibration sequences (vibration frequency, duration, and time span between vibrating
periods) are used. A common vibration sequence includes six cycles per second for a short duration of
about two seconds every two minutes. The vibration
time and the dwell time can be adjusted to suit the fuel
characteristics. The vibrating action can help improve
fuel distribution on the grate by causing fuel piles to
Fig. 6 Water-cooled vibrating grate unit with CCZ furnace.
30-6
collapse. This style of biomass combustion system is
being used very successfully at a number of installations for a wide range of wood fuel moisture contents.
The air-cooled vibrating grate can be used for applications similar to those suitable for the water-cooled
vibrating grate, but the maximum allowable
undergrate air temperature is 550F (288C), even with
the use of stainless steel components. Because it can
be installed with a horizontal grate surface, the aircooled vibrating grate can be a very effective replacement for a traveling grate, when the traveling grate
has been deemed unacceptable due to high maintenance or repair costs.
Furnace configurations
A variety of furnace configurations can be found
in wood and wood-waste boilers. In the late 1970s, the
controlled combustion zone or CCZ furnace was developed by B&W specifically for biomass combustion.
As shown in Figs. 2 and 6, the CCZ design uses arches
in the front and rear walls of the furnace to create a
lower furnace zone in which combustion of biomass
can be confined. OFA from nozzles located above and
below the arches penetrates and burns off the volatile fuel released from the bed, as well as particles
entrained in the upward flow. This furnace design
incorporates a range of OFA systems that had multiple elevations of large ports and increased the OFA
capacity to 40 to 50% of the total combustion air flow.
Tighter emission control regulations and advancing computational technology have stimulated the development and deployment of a straight-wall furnace
design with fewer, larger OFA ports that can be more
precisely located and operated. As shown in Fig. 7, the
arches and multiple levels of OFA ports for the CCZ
can be replaced with straight furnace walls and one
level (sometimes two) of OFA ports. The B&W
PrecisionJet™ OFA system has high velocity ports that
include velocity dampers to fine-tune the combustion
process. Computational models (see Chapter 6) permit the positioning and sizing of the higher velocity
OFA ports to better complete the combustion process
in a controlled fashion, thereby reducing NOx, CO and
particulate. OFA capacity of up to 60% of the combustion air flow can be used. As discussed in Chapter 16,
a second option is a horizontal rotary overfire air system designed to create a double rotating circulation zone
in the straight-wall furnace. (See Chapter 16, Fig. 13.)
This can also increase turbulence and mixing of air and
gaseous combustibles for enhanced performance. With
a straight-wall design and fewer ports, these furnace configurations usually have lower initial capital costs.
Process recovery (PR) boilers (see Chapter 28) and
coal-fired power boilers at pulp and paper mills have
been retrofitted for wood and wood-waste firing capability as mill power and PR needs have evolved. Rising energy prices have also increased the benefit of
higher internal power generation from waste product
fuels. To accommodate the heat release rates discussed
earlier, the furnace plan area of the original boiler
must typically be enlarged to accommodate the grate
area for the desired heat input. The new enlarged
lower furnace is then tapered to connect with the origiSteam 41 / Wood and Biomass Installations
The Babcock & Wilcox Company
Superheater
Tubular
Air
Heater
Generating Bank
Bark Bin
Mechanical
Dust
Collector
Overfire Air
PrecisionJet
Overfire
Air Ports
Undergrate
Air
Forced Draft
Fan
Submerged
Drag Chain Conveyor
Fig. 7 Wood-fired boiler with straight furnace walls and overfire air.
nal upper boiler furnace to take full advantage of the
original heating surfaces and boiler capacity. The same
type of tapered furnace design may also be found
where bubbling fluidized-bed combustion systems are
retrofitted to PR or coal-fired boilers (see Fig. 8).
Dryers and pulverizers
If the biomass fuel available is particularly high in
moisture, or if the capacity of an existing installation
is to be increased, it is sometimes more economical to
dry the fuel with boiler flue gas before firing it in the
boiler furnace, rather than pressing the fuel to remove
moisture or modifying the boiler for increased capacity. Dryers of the rotating drum type and cascading
fuel type are available from several manufacturers.
The dried fuel is then fired using one of the previously
mentioned combustion systems.
Another means of burning biomass is by pulverizing/drying. This can be accomplished by mixing the biomass with hot gases removed from the boiler exit, pulverizing it in a fan/beater mill, and returning the mixture to the furnace through a burner. Milled peat is
fired in several installations in the Nordic countries
using this process. The milled peat, except for larger
pieces, does not undergo much size reduction. Most other
types of pulverizing systems have proven to require very
high maintenance and to have poor availability and significant power consumption in biomass applications.
Fluidized-bed combustion
Fluidized-bed combustion has been successfully applied to a range of wood and biomass fuels and offers a
number of features that may be advantageous in specific applications.
Only 2 to 3% of the bed is carbon; the remainder is
Steam 41 / Wood and Biomass Installations
comprised of inert material (sand). This inert material provides a large inventory of heat in the furnace,
thereby dampening the effect of brief fluctuations in
fuel heating value on steam generation.
Fluidized beds typically operate at 1350 to 1650F
(732 to 899C), a range considerably lower than combustion temperatures for spreader stoker units [2200F
(1204C)]. The lower temperatures produce less NOx
and would be expected to provide the most benefit on
high nitrogen wood and biomass fuels.
SO2 emissions from wood and biomass firing are
generally considered insignificant, but where sulfur
contamination of the fuel stream is a problem, limestone can be added to the fluid bed to achieve a high
degree of sulfur capture. Fuels that are typically sulfur contaminated include tire-derived fuel and coal.
The type of fluidized bed selected will be a function
of the as-fired calorific value of the wood waste or biomass fuel. Bubbling bed technology is generally selected
for fuels of lower calorific value. For fuels of higher
calorific value, the circulating fluid bed may be suitable.
Designs for fluidized-bed combustion are discussed
in Chapter 17. Bubbling fluidized beds have been
applied to retrofit (Fig. 8) and new installations (see
Chapter 17, Fig. 10).
Boiler component design for wood and
biomass burning
Grate
The grate forms the furnace floor and provides a
surface on which the larger fuel particles burn. The
grate may be air-cooled or water-cooled and stationary or arranged for automatic, continuous ash removal. Most grates consist of some form of cast iron or
cast alloy grate bars. (See Chapter 16.)
Ammonia/Urea
Injectors
(SNCR)
Burners
Refractory
Line
Overfire
Air
System
Startup
Burners
Fuel
Spouts
Fluidized
Bed
Ash
Conveyors
Fig. 8 Retrofit of process recovery boiler for wood-firing capability.
30-7
The Babcock & Wilcox Company
Fuel distributor
The two most common devices for introducing fuel
into the furnace for semi-suspension firing are mechanical distributors and air-swept spouts. They are
both designed to distribute fuel as evenly as possible
over the grate surface.
The mechanical distributor uses a rotating paddle
wheel to distribute the fuel. The speed of the wheel is
varied to suit the fuel characteristics. In some installations, a continually varying speed is used to ensure
good fuel distribution.
The air-swept spout uses high pressure air that is
continuously varied by a rotary damper to distribute
the fuel. Adjustments to the supply air pressure are
made by the operator as the characteristics of the fuel
change. The trajectory of the fuel leaving the spout is
altered by an adjustable ramp at the bottom of the spout.
Burners
Burners are sometimes used to burn all or a portion
of the biomass fuel. The burners are somewhat similar
in design to a pulverized coal burner. (See Chapter 14.)
Fuels that can be fired in a burner include sander dust,
sawdust of less than 35% moisture content, and the fine
material collected from a fuel dryer. Due to the possibility of inconsistent fuel flow and quality, a continuously
operated auxiliary fuel pilot flame is recommended.
Furnace
A properly designed furnace has two main functions. The first is to provide a volume in which the fuel
can be burned completely. The second is to absorb
sufficient heat to cool the flue gas to a temperature at
which the entrained flyash will not foul the convective surfaces. This must be accomplished while matching the dimensions of the grate and while providing
sufficient clearance dimensions from auxiliary burners to prevent flame impingement on furnace walls.
Modern boilers are typically of membrane wall construction, but in certain limited cases, such as installations in developing countries, reverting to a tube
and tile type of furnace construction may be appropriate. In such circumstances, the frequent maintenance requirement is outweighed by the reduction in
first cost and the ease of operation due to the higher
temperatures in the furnace.
Superheater
The sizing of the superheater on a wood-fired boiler
can be complicated by several factors. For a given fuel
being fired, the setting of the surface depends on the final steam temperature and on the control range required. The side and back spacing are selected to minimize
fouling and erosion potential. (See Chapters 19 and 21.)
However, a wood-fired boiler rarely burns a consistent fuel. Variable moisture content and fuel analyses
affect the steam-to-flue gas ratio, and a variety of auxiliary fuels, e.g., oil, gas or coal, may be available. Therefore, when designing a superheater, the full range of operating conditions must be completely understood.
Constituents in the ash can affect superheater design. For example, high levels of chloride are often
30-8
found in bark from logs floated in sea water and can
require the use of high alloy materials such as 310
stainless steel to minimize the corrosion rate of the superheater tubes in the high temperature zones.
Boiler bank
Due to the relatively high ratio of flue gas flow to
steam flow and the relatively low pressures and temperatures at which most wood-fired boilers are operated,
a large amount of saturated (boiling) surface is required.
Furthermore, due to relatively low adiabatic flame temperatures, the amount of heat absorption in the furnace
is usually low compared to fuels such as oil or natural
gas. Therefore, a large portion of the total heating surface in a wood-fired boiler is usually provided as boiler
bank.
In some cases, the amount of furnace surface is augmented by water-cooled screens in front of superheaters to lower flue gas temperatures entering the superheater and to protect it from thermal radiation or from
the active burning areas in the furnace.
The amount of boiler bank surface is usually very
substantial. This surface can be arranged as cross flow
surface as normally found in a two-drum Stirling
boiler (see Fig. 2), or may be arranged for longitudinal flow as found in a smaller bottom-supported
Towerpak® boiler. (See Fig. 9.)
Because wood fuels frequently contain sand or
other mineral matter in addition to the ash, flue gas
velocities in the convection pass or boiler bank must
be kept low, typically below 60 ft/s (18.3 m/s).
Economizer
In most cases, when an economizer is required to reduce the back-end temperature to a specified level, it is
located between the boiler bank and the tubular air
heater. The economizer is designed to reduce the flue gas
temperature to that required at the air heater gas inlet.
Occasionally, the positions of the economizer and air
heater need to be reversed. For example, it may be
necessary to provide a higher gas temperature to the
air heater as part of an installation that includes a fuel
dryer. The dryer needs the hotter gas to remove moisture from the fuel. This same system may also be required to maintain a specified exit gas temperature
entering the stack even when the dryer (and its thermal load) is out of service for maintenance or repair.
For such a system to work effectively under both operating conditions, the economizer needs to be the final heat trap. In addition, a bypass, preferably on the
economizer gas side, is needed to permit exit gas temperature control.
In the above example, it should be remembered
that the economizer gas exit temperature would be
lower when burning dry fuel from the dryer and
would be higher with the dryer out of service, if no
control method was provided.
There are no special mechanical design considerations
for economizers on wood-fired units, other than to limit
the flue gas velocity. In virtually all cases, a continuous
bare tube economizer is used. (See also Chapter 20.)
Steam 41 / Wood and Biomass Installations
The Babcock & Wilcox Company
Fig. 9 Towerpak® boiler with longitudinal flow boiler bank.
Air heater
Due to the requirement to provide hot air to burn
all but the driest of wood fuels, wood-fired boilers are
usually equipped with air heaters. Because of the ash,
sand and char in the flue gas, a recuperative type is
normally selected, usually tubular. (See Chapter 20.)
It is B&W practice to provide the tubes on square or
rectangular pitch, rather than on triangular pitch, to
lower air-side resistance and allow easier maintenance.
The common arrangement is for the flue gas to pass
through the tubes and for the air to flow around the
outside of the tubes. A two-gas pass design is favored
for economic reasons. The low flue gas velocity in the
hopper and the 180 deg change in direction also promote the separation of large, heavier particles of char
and sand. The tubular air heater, when arranged for
two gas passes, can act as a low efficiency (approximately 50%) mechanical dust collector.
Experience has shown the use of 2.5 in. (63.5 mm)
outside diameter (OD) tubes to usually be the most cost
effective. Available space limitations may require the
use of smaller 2 in. (50.8 mm) OD tubes. In cases with
a history of plugging by contaminants in the flue gas, it
may be necessary to use 3 in. (76.2 mm) OD tubes.
Auxiliary equipment
Fans Wood-fired boilers require forced draft (FD),
induced draft (ID) and usually overfire air (OFA) fans.
(See Chapter 25.)
Steam 41 / Wood and Biomass Installations
Forced draft fans require no special design considerations other than determining the required capacity and static pressure. The design may be determined
by wood firing alone, wood firing in combination with
auxiliary fuel, or auxiliary fuel alone, depending on
the quantity and pressure of air required for each of
these conditions. Normal test block margins for FD
fans are sufficient. Usually these fans are controlled
to maintain a constant pressure at the tubular air
heater air outlet plenum.
ID fans must be designed to take into account the
abrasiveness of the flue gas, the quantity of flue gas
to be handled, the draft losses to be overcome, and the
temperature of the flue gas. The abrasiveness of the
flue gas depends on the type and efficiency of the dust
collection equipment installed and whether the fan is
located before or after this equipment. The ID fans are
used to control the furnace pressure to a set point,
usually at –0.1 to –0.5 in. wg (–0.025 to –0.12 kPa).
The quantity of gas and the draft loss used to specify
the ID fan must take into account not only the expected operation of the boiler, but also possible wide
variations in heating value, theoretical air, and moisture content of the fuel.
OFA fans are often exposed to severe service, as
typically the air to be brought to 30 in. wg (7.5 kPa)
has already been heated in the tubular air heater to
as high as 650F (343C) before reaching the fan inlet.
When specifying an OFA fan, it is particularly important to specify the maximum air temperature that it
must be capable of handling.
Sootblowers Because biomass-fired boilers are susceptible to ash and carbon carryover, the convective
heat transfer surfaces must be designed to accommodate sootblowers. Retractable sootblowers must be
used for the superheater and high temperature boiler
bank surfaces. Rotary sootblowers can be used for the
low temperature boiler bank areas and the economizer, but retractable sootblowers are preferred, provided there is sufficient space. Traveling rake type
sootblowers are typically used above the tubular air
heater tubesheets on the flue gas side. (See Chapter 24.)
These sootblowers use either saturated or superheated steam to clean the gas lanes between the tubes.
Blowing pressures are typically 150 to 250 psi (1034 to
1724 kPa) and the blowing sequence is usually initiated once per working shift. The high pressure jet of
steam from the sootblower nozzle cleans the tube surfaces
with a set radius around the sootblower lance depending
on sootblower design [usually about 5 ft (1.52 m)].
The ash is typically nonsticky and is relatively easy
to remove by sootblowing. If allowed to accumulate,
the ash can plug gas passages, cause flow unbalances,
affect boiler circulation and heat transfer, and ultimately lead to a forced outage of the boiler. If unburned carbon particles are allowed to accumulate,
they can create a fire potential, particularly in the
back-end equipment.
Fuel handling systems Biomass fuel systems can be
quite complicated and maintenance-intensive due to the
varying characteristics of the fuel. Typically, the fuel is
continuously conveyed from storage to small surge bins
at each fuel distributor that are kept full, with any over30-9
The Babcock & Wilcox Company
feed returned to storage. The surge bins are equipped with
variable speed screw feeders or chain feeders to control
the rate of biomass fuel fed into the furnace.
These variable speed feeders must be capable of
operation over a turndown range of four-to-one on
automatic control. They must also be able to operate
at very low speeds during startup conditions to build
a fuel bed on the grate. The feeder drives must be of
sufficient horsepower to allow the feeder to be started
when the surge bin is full of fuel.
Upstream of the surge bins, it is common to have a
large live-bottom storage bin with four to eight hours
of biomass fuel inventory. This is to avoid interruptions in the fuel feed to the boiler when there are problems with the outside fuel handling equipment. (See
Chapter 12.)
For many biomass fuels, special fuel preparation equipment may be needed to provide effective overall combustion. As an example, for the straw-fired unit shown in
Fig. 1, the straw bale is carded or raked to loosen the
straw before it is fed to the grate by screw feeders.
Ash handling Ash handling systems on biomassfired boilers can be divided into two main areas, bottom ash and flyash.
Bottom ash is the ash that is raked or conveyed off
the grate, plus the ash that falls through the grate
bar holes into the undergrate hopper, called a riddlings
or siftings hopper. Bottom ash consists mainly of sand
and stones. The ash at the grate discharge is typically
collected using a submerged drag chain conveyor with
a dewatering incline at the discharge end. The siftings
can be collected with drag chain or screw conveyors.
Flyash is the fine ash and unburned carbon that is
collected from all the boiler bank, economizer, air
heater and emissions control equipment hoppers. The
ash handling equipment can be drag chains, screw
conveyors or wet sluicing systems. Because the flyash
contains a high percentage of hot carbon, it is important that rotary seal valves be used at each hopper
discharge to prevent air infiltration that could create
a fire in the hopper. For the same reason, all ash conveyors should be sealed.
In some instances, the flyash from the boiler bank
and air heater hoppers is reinjected into the furnace
to lower the unburned carbon loss and to reduce the
quantity of material that must be disposed. However,
the high maintenance requirements of these systems
have limited their use.
Air systems
Air systems can be categorized as undergrate or
underfire air and overfire air.
Undergrate air is typically low pressure [3 in. wg
(0.75 kPa)] and, depending on the type of grate used,
can be anywhere between 40 and 60% of the total air
required for combustion. The purpose of undergrate
air is to help dry the fuel, promote the release of the
volatiles, provide the oxygen necessary for the combustion of the devolatilized char resting on the grate
and, in the case of an air-cooled grate, cool the grate
bars. The pinhole grate and vibrating grate can be
provided with multiple undergrate air compartments
30-10
with separate dampers for the operator to bias the
undergrate air to the area of the furnace where the
fuel is concentrated. Traveling grates can be provided
with only one compartment per drive section.
OFA system capacities are varied and can range
from 25 to 60% of the total air. Varying air port or
nozzle sizes and air pressures are used to obtain adequate penetration of the air into the rising stream of
volatiles from the grate. Typically, modern OFA nozzles
are 3 to 6 in. (76.2 to 152.4 mm) in diameter or rectangular with velocity dampers (PrecisionJet™) and use
air pressures up to 20 in. wg (4.98 kPa). Levels of
nozzles are controlled independently such that the OFA
can be varied with load and fuel characteristics. Where
very high temperature OFA is used and it constitutes
more than 40% of the total air flow, it is usually economical and energy efficient to provide a high pressure
FD fan, rather than a low pressure FD fan plus a large
high pressure OFA fan. The OFA ports can be designed
to provide a double rotating circulating zone to further
enhance combustion. (See Chapter 16.)
Emissions control equipment
Dust collector Mechanical dust collectors are used
after the last heat trap on the boiler to collect the larger
size flyash particulate, sometimes as protection for the
ID fan. They typically consist of multi-cyclone tubes
enclosed in a casing structure. The tubes consist of
outer inlet tubes with spin vanes and inner tubes used
without recovery vanes. The dust collector efficiency
is in the range of 65 to 75% at an optimum draft loss
of 2.5 to 3.0 in. wg (0.62 to 0.75 kPa). Due to the abrasive nature of the flyash, the outer collection tubes and
cones are made of high hardness (450 Brinell) abrasion resistant material. (See Chapter 33.)
Precipitator Electrostatic precipitators are typically
used after the mechanical collector to reduce the particulate concentration in the flue gas and to meet environmental requirements. Due to the high carbon content
in the flyash, it is important to reduce the fire potential
in the precipitator. It is necessary to ensure no tramp
air enters the precipitator and that the flyash is continuously removed from the hoppers. Hopper level detectors
and temperature detectors alert the operator.
Installations can be equipped with fire fighting apparatus such as steam inerting. Other suppliers recommend de-energizing the precipitator if a predetermined oxygen content in the flue gas is exceeded.
Fabric filter or baghouse Due to the fire potential,
baghouse collectors have been rarely used for biomass
fuels to date.
Wet scrubbers Wet scrubbers have also been used
to control particulate emissions on biomass-fired boilers. Their main disadvantages are the high flue gas
pressure drop, which increases the ID fan horsepower
requirements, and high water consumption. Also,
there is the need for a wet ash collection system and a
water separation and clarification system. Wet scrubbers have given way to electrostatic precipitators as
the preferred means of final flue gas cleanup, provided
there is no need for a scrubber to reduce SO2 emissions
from auxiliary fuels.
Steam 41 / Wood and Biomass Installations
The Babcock & Wilcox Company
Wet scrubbers with numerous small spray nozzles
in a chamber can be used where low pressure drop and
low water consumption are required. This is particularly well suited to retrofit applications where the
scrubber can replace the mechanical dust collector for
improved collection efficiency.
Environmental impact
Particulate emissions
About 80 to 95% of the total ash residue produced
by a bark- and wood-fired spreader stoker is in the
form of gas-borne particulate. This particulate is composed of a number of materials, including ash, sand
contaminants introduced during fuel handling, unburned char from the furnace, and salt fume (usually
present only where logs are seawater flumed).
The ash content of wood and bark fuels is low (0.2
to 5.3%, dry basis). Therefore, if fuel ash contaminants
are not appreciable, the particulate will usually contain high percentages of unburned char.
The particulate loading in the flue gas exiting the
boiler is influenced by factors related to both combustion and aerodynamics. Combustion-related factors
affect particulates by determining the degree of burnout for the entrained char. They include plan and
volumetric heat release rate (two design parameters
that affect furnace temperature), residence time, and
consequently, char burnout.
The importance of aerodynamic factors is based on
the fact that bark- and wood-fired spreader-stoker
units are designed to operate with some degree of suspension burning. Variables that would tend to increase the ratio of furnace velocity to mean char particle size would therefore tend to increase flue gas
particulate loading.
Some of these factors include fuel moisture and fines
content, boiler plan area, air staging, and excess air level.
For wood and bark fuels not containing appreciable
quantities of sand, particulate loading at the air heater
exit of a modern spreader-stoker unit would typically
be in the range of 1 to 3 grains/DSCF (2.4 to 7.2 g/Nm3).
Nitrogen oxides
NOx emissions from wood and bark firing are low
compared with those from traditional fossil fuels. Combustion temperatures in wood firing are sufficiently
low, and little thermal NOx is formed from the nitrogen in the combustion air. Corresponding NOx emissions are therefore predominantly a function of the
fuel nitrogen content. (See also Chapter 34.)
Conversion of fuel bound nitrogen to NOx is dependent
Steam 41 / Wood and Biomass Installations
on a number of operating conditions including excess air,
air staging, heat release rate, and fuel sizing and moisture content. Empirical studies have also found NOx to
vary inversely with fuel moisture content, although the
magnitude of this correlation is less significant.
All factors considered, NOx emissions from stoker firing of most wood and bark vary between 0.1 and 0.35
lb/106 Btu (0.04 to 0.15 g/MJ) heat input, expressed
as nitrogen dioxide. Fuel contaminants that may introduce nitrogen compounds (glues and chemicals, for
example) should receive special consideration.
Sulfur dioxide
Wood and bark typically contain 0.0 to 0.1% elemental sulfur on a dry basis. During the combustion process
some of this sulfur can be converted to flue gas SO2, but
the conversion ratio is typically low (10 to 30%). Because
the quantities of both wood sulfur and flue gas SO2 are
near the low end detection limit of corresponding analytical instruments, correlation of the two is not practical.
Typically, SO2 emissions for stoker-fired wood and
bark fuels do not exceed 0.03 lb/106 Btu (0.01 g/MJ) heat
input. Special consideration should be given to fuels
where sulfur bearing contaminants may be present.
Carbon monoxide
Of all emissions commonly associated with wood
and bark firing, carbon monoxide (CO) is usually the
most variable. As a gaseous product of incomplete combustion, CO is dependent on time, temperature and
turbulence considerations.
At normal excess air levels, consistency of both fuel
heating value and fuel distribution are considered the
most important determinants of CO emissions. Typically, test data showing the highest standard deviation in CO correspond to the highest mean CO.
Conditions of high excess air, low excess air, high
fuel moisture and reduced load (<70% of the maximum
continuous rating) have all been demonstrated to increase flue gas CO concentration.
Modern spreader-stoker units firing wood and bark
only, and operating at steady-state conditions, typically emit CO in the range of 0.05 to 0.5 lb/106 Btu
(0.04 to 0.22 g/MJ) heat input.
Volatile organic compounds
Volatile organic compounds (VOCs) are also gaseous
products of incomplete combustion. As such, the emission of VOCs during wood firing is influenced by the
same factors affecting CO.
Typically, VOC emissions while stoker-firing wood
and bark fuels do not exceed 0.05 lb/106 Btu (0.02 g/
MJ) heat input, expressed as methane.
30-11
The Babcock & Wilcox Company
Combined heat and power plant with straw-fired ultra-supercritical boiler (courtesy of Kastrup Luftfoto A/S, Denmark).
30-12
Steam 41 / Wood and Biomass Installations
The Babcock & Wilcox Company
Chapter 31
Marine Applications
The ingenuity of many inventors and engineers has
been devoted to the application of fossil fuel-fired
steam boilers and engines to ship propulsion. The need
for higher power, lower weight and smaller volume designs for ships drove many of the boiler system advances that ultimately appeared in stationary boilers
designed and used today.
The primary propulsion systems in ships today, however, have progressed to diesel engines, gas turbines
and even nuclear power systems in naval applications.
(See Chapter 46.) Nevertheless, there remain requirements aboard new ships to produce steam for a variety of needs. In addition, a large existing population
of contemporary ships, such as the LASH (lighter
aboard ship) class container ships (Fig. 1), continues
to use steam boilers as their primary source of power.
Finally, increasing fuel costs have led to investigations
of burning coal-water mixtures, coal-oil mixtures and
other fuels in steam-based systems for use in the future.
The Babcock & Wilcox Company (B&W) marine boilers have established a reputation for dependability
and efficiency. The history of these boilers reflects
sound principles of design and fabrication. Since the
first installation in the S.S. Monroe in 1875, B&W boilers have been installed in more than 4000 ships of the
United States (U.S.) Navy and the Merchant Marine.
During World War I, B&W boilers were installed in
50 mine sweepers, 100 destroyers, and 500 Shipping
Board vessels. During World War II, B&W boilers
were furnished to the Navy for all but two battleships
(such as the U.S.S. Missouri, shown in the chapter
frontispiece), all the cruisers, all aircraft carriers (see
U.S.S. John F. Kennedy in the chapter frontispiece),
90% of the destroyers, 33% of the destroyer escorts and
numerous miscellaneous small craft.
such as groundings and collisions. Special steam drum
design requirements must be met to accommodate roll
of the ship from side to side, pitch variations from bow
up to bow down, permanent list to either side and permanent trim to either bow or stern. In the case of naval vessels, the shock effects of the detonation of explosives must also be considered. Operation over a wide
load range with operating characteristics compatible
with a high degree of automation is also required. Finally, the factors used in both the thermal and structural design must be conservative so that continuous
operation over extended periods of time will be provided with minimum maintenance. These factors combined with the use of several different fuels have led
to a variety of B&W marine boiler designs.
Integral Furnace naval boiler
The Integral Furnace naval type boiler (Fig. 2) is
fitted with welded high strength, low weight stainless
or low-alloy steel casings. Furnace roof, side and rear
walls are water-cooled by 2 in. (50.8 mm) outside diameter (OD) close-spaced tubes. Front (burner) wall
and floor are usually refractory, but some recent boilers have water-cooled front walls. Steam drum diameters range from 54 to 60 in. (1.37 to 1.52 m) and water drums vary from 27 to 36 in. (0.69 to 0.91 m). Two
to four rows of 2 in. (50.8 mm) OD tubes form the superheater screen. The superheater has 1.00 or 1.25
in. (25.4 or 31.8 mm) OD tubes arranged in a maximum of 8 rows deep with provision for complete
drainability. The boiler bank is usually inclined and
General design considerations
Steam generating equipment for marine service is
designed in accordance with the principles and considerations that apply to stationary units with modifications to meet specific requirements for operation
at sea. The boiler must fit within a minimum engine
room space, yet be accessible for operation, inspection
and maintenance. Although lightweight, it must be
sufficiently rugged to operate dependably under adverse sea conditions and to absorb vibration and forces
resulting from rolling and pitching in heavy seas or
from shocks that may result from accidental causes
Steam 41 / Marine Applications
Fig. 1 S.S. President Tyler, LASH Class container ship (courtesy of
American President Companies, Ltd.).
31-1
The Babcock & Wilcox Company
Fig. 2 Two-drum boiler, naval type.
has from 18 to 23 rows of 1.00 in. (25.4 mm) OD tubes.
For maximum efficiency, the boiler is fitted with a studtube economizer and in some cases, steam air heaters.
Range in size, steam output:
To 350,000 lb/h (44.1 kg/s) in no fixed increments
Operating pressure:
Up to 1200 psig (8.27 MPa)
Steam temperature:
Saturation to 1000F (538C)
Fuel:
Navy special fuel oil (residual)
Multipurpose fuel oil
Operational control:
Manual to complete automatic, combustion and
feedwater regulation.
Draft loss at maximum output:
Up to about 75 in. wg (18.7 kPa) total through
all components
Dimensions outside setting:
Smallest – 14 ft 2 in. high × 15 ft 1 in. wide × 10
ft 6 in. deep (4.32 m × 4.60 m × 3.20 m)
Largest – 21 ft 5 in. high × 18 ft 11 in. wide × 16
ft deep (6.53 m × 5.77 m × 4.88 m)
Indicated field of application
The primary use of these boilers is for combat or
auxiliary naval vessels or special installations.
General comments
The nature of the construction and the rating at
which these boilers operate limit their use to naval or
high speed naval auxiliary vessels requiring maximum
power in minimum space. They are designed for maximum efficiency at cruising speed, and some attainable
efficiency is sacrificed to develop high power-to-weight
and power-to-boiler volume ratios. The construction in31-2
cludes lightweight tubes, high-tensile drum plates, and
other special features to minimize weight.
Integral Furnace merchant boiler
The Integral Furnace merchant boiler became the
marine industry standard after World War II. The
boilers were originally designed as tangent tube (Figs.
3 and 4) and refractory construction (water-cooled furnace) and more recently, membrane furnace construction (water-cooled, welded-wall furnace). Both types
have a single gas pass with a 2 row, 2 in. (50.8 mm)
OD screen before the superheater, steam drum diameters ranging from 54 to 72 in. (1.37 to 1.83 m) and
water drums from 30 to 36 in. (0.76 to 0.91 m).
The tangent tube furnace is water-cooled by closely
spaced 2 in. (50.8 mm) OD tubes on the side, roof, front
and rear walls. Recent designs have sloped and bare
furnace floor tubes with consequent reduction in exposed refractory. In designs with refractory floors, the
tubes are usually buried in the floor to reduce refractory temperature and increase refractory life.
The membrane furnace is water-cooled by welded-wall
construction consisting of 2.75 in. (69.9 mm) OD tubes
on 3-9/16 in. (90.5 mm) centers. This applies to the furnace floor, front, rear and side walls. The floor is covered
with firebrick to protect the tubes from overheating.
In either style boiler, an inclined or vertical boiler
tube bank, composed of 2 to 4 rows of 2 in. (50.8 mm)
OD screen tubes and 17 to 24 rows of 1.25 in. (31.8
mm) OD generating tubes, may be used. The superheater consists of either horizontal or vertical 1.25 in.
(31.8 mm) OD tubes and has one or two access cavities to facilitate water washing, cleaning, inspection,
and maintenance of the superheater and boiler bank.
A single cavity is normally provided when the fouling
characteristics of Bunker C oil are average, and two
Steam 41 / Marine Applications
The Babcock & Wilcox Company
cavities are used when fouling characteristics are
more severe. The boiler is generally equipped with
steam atomizing burners, retractable sootblowers, and
an air heater or an economizer.
Indicated field of application
These designs are primarily used for propulsion
power, although they are also used without a superheater for auxiliary or heating service in the smaller sizes
where space is at a premium, a compact lightweight
design is needed, and feedwater is of good quality.
Range in size, steam output:
To 400,000 lb/h (50.4 kg/s) in no fixed increments
Operating pressure:
up to 1200 psig (0.69 to 8.27 MPa)
Steam temperature:
Saturation to 1000F (538C)
Fuel:
Oil (light fractions to heavy residuals) and
liquified natural gas (LNG)
Operational control:
Manual or completely automatic, including feedwater flow, combustion and steam temperature
controls
Draft loss at maximum output:
From 15 to 30 in. wg (3.7 to 7.5 kPa) total through
all components
Dimensions outside setting:
Smallest – 7 ft 8 in. high × 5 ft 5 in. wide × 5 ft 6
in. deep (2.34 m × 1.65 m × 1.68 m)
Largest – 41 ft 6 in. high × 34 ft 3 in. wide × 24
ft 1 in. deep (12.65 m × 10.44 m × 7.34 m)
Fig. 3 Two-drum Integral Furnace boiler with vertical superheater.
General comments
Designs of this type are suitable for vessels where
large power plants must be installed in a minimum of
space, and where weight saving is a vital consideration. Many possible variations in configuration permit application under limited space conditions. Mass
action retractable sootblowers are recommended for
the superheater zones.
Reheat boilers
Although reheat boilers have not been extensively
used in the marine industry, there have been several
applications. In considering a reheat boiler for shipboard
applications, one design feature must be considered.
That feature is the protection of the reheater tubes when
the main propulsion turbine is in astern operation or
stopped. B&W has designed the boiler with damper and
bypass systems, as well as with extensive screen tube
protection systems in front of the reheater.
The marine reheat boiler is of the two-drum divided
inclined boiler bank type, capable of burning fuel oil
or natural gas. Other than the reheater, reheat screen,
baffle wall and damper system, the reheat boiler is
similar to the tangent tube boiler.
Coal-fired marine boilers
Up until the late 1970s, coal-fired marine boilers
put into service were for vessels on the Great Lakes.
Steam 41 / Marine Applications
Fig. 4 Two-drum Integral Furnace boiler with horizontal superheater.
31-3
The Babcock & Wilcox Company
These units were built in the late 1950s, and were for
relatively low-pressure and low-temperature conditions. The boiler designs were either the sectional
header type or the two-drum type. This two-drum
boiler had the same physical appearance as many of
the newer oil-fired two-drum boilers. However, because
coal firing requires a much lower furnace heat release
rate than oil firing for proper combustion, the result
was less steam generating capacity for the same shipboard space availability.
As with a land-based unit, boiler design begins with
the stoker. The maximum stoker grate release rate for
good operation and for prevention of grate overloading is 750,000 Btu/h ft2 (2.37 MWt /m2) of grate surface. Another requirement for good stoker operation,
particularly when flyash and unburned carbon are
re-injected into the furnace, is a limit of input to the
stoker of 13 × 106 Btu/h ft (12.5 MWt /m) of stoker
width. Exceeding this limit can cause poor fuel distribution on the grate, resulting in uneven burning.
The furnace volume should be set so that the furnace liberation does not exceed 30,000 Btu/h ft3 (0.31
MWt /m3). Adherence to this value will ensure sufficient residence time in the furnace to properly burn
the fuel and minimize slagging and fouling.
The coal-fired marine boiler has a totally different
appearance than that of the customary oil-fired marine boiler. The furnace extends considerably below
the centerline of the lower drum. This dimension, commonly called the setting height of the furnace, is the
dimension from the top of the stoker to the centerline
of the water drum. Generally, on units of this capacity,
setting heights range from 16 to 20 ft (4.9 to 6.1 m).
This boiler has been specifically designed to make
full power by either burning 100% coal or 100% oil.
When burning coal and with a grate release rate of
750,000 Btu/h ft2 (2.37 MWt /m2), the approximate
turndown ratio of the stoker will be 3:1. However, with
the oil burners, the turndown ratio can be as high as
16:1. Therefore, if required during maneuvering
modes of operation, the boiler can be readily fired by
oil and have the full flexibility and response time
needed for this condition. The design operating conditions are 875 psig (6.03 MPa) and 900F (482C) with
steam capacity ranging from 60,000 to 150,000 lb/h
(7.6 to 18.9 kg/s).
Additional features of this design address other
impacts of coal and its associated ash loading. Retractable sootblowers, hoppers, dust collection equipment
and flyash re-injection are all included.
Guard (USCG) and American Bureau of Shipping (ABS)
Rules. The unit is shop-assembled, including furnace
and firing equipment. It is not intended for ship propulsion, but as a means of supplying auxiliary steam.
The boiler incorporates a compact vertical bank of
2 in. (50.8 mm) OD tubes arranged between and terminating in an upper and lower drum. The tube ends
are expanded into tube seats that are grooved to obtain maximum tightness.
A 54 in. (1.37 m) nominal diameter steam drum is
required to promote water level stability even during
wide variations in load, and helps to ensure dry, saturated steam. The requirements for this drum include
satisfactory operation under the following conditions:
30 degree roll to each side for a 15 second period,
10 degree pitch from bow up to bow down for a 6
second period,
15 degree permanent list to either side, and
5 degree permanent trim to either the bow or stern.
Under any of these adverse conditions, the downcomers and boiler bank generating tubes will not uncover.
The furnace and boiler are covered by a 20 gauge
(0.9 mm) nonpressurized galvanized steel ribbed lagging except in areas such as the steam drum joints and
bent tube portions of the walls, which are covered by
a 12 gauge (2.7 mm) carbon steel casing.
The boiler furnace unit is arranged for upward expansion and is mounted on a welded structural base
frame, ready for positioning on the ship’s foundations.
The unit has a furnace with a refractory covered flat
floor, and a boiler bank. The furnace side wall, roof,
floor and rear wall are completely water-cooled and
form an integral part of the boiler circuitry. One burner
is used in the refractory front wall.
Water-cooled furnace wall tubes, comprising the side
wall, roof and floor, are of membrane construction. The
rear furnace wall is 2 in. (50.8 mm) OD flat-studded
tubes on 4 in. (101.6 mm) centers. A 10 gauge (3.4 mm)
steel inner casing backs the flat-studded wall. The furnace wall tubes receive their flow from the lower drum
Auxiliary package marine boilers
As the marine industry has shifted its emphasis
from main steam propulsion systems to diesel propulsion, the need developed for a simple, low-cost, selfcontained auxiliary boiler.
B&W developed an Integral Furnace, two-drum Dtype package boiler (FMB) that could operate as a
stand-alone unit or in conjunction with a diesel or gas
turbine exhaust waste heat boiler.
The boiler in Fig. 5 represents the marine package
design conforming to the requirements of U.S. Coast
31-4
Fig. 5 Auxiliary package marine boiler.
Steam 41 / Marine Applications
The Babcock & Wilcox Company
and discharge the steam-water mixture into the steam
drum. The 2.75 in. (69.9 mm) OD furnace, roof and floor
tubes are a part of the furnace side wall circuitry. The
furnace front wall (burner wall) is of refractory anchored construction and is backed by insulation and a
gas-tight casing.
These marine auxiliary package boilers are designed to provide unattended operation with controls
that are fully automatic after the boiler is on line.
Range in size, steam output:
To 100,000 lb/h (12.6 kg/s) in no fixed increments
Operating pressure:
225 psig (1.55 MPa)
Steam temperature:
Saturation only
Fuel:
Oil, light fractions to heavy residuals
Dimensions outside setting:
Overall width is 12 ft 6.25 in. (3.82 m), overall
height (base to face of steam outlet flange) is
16 ft 9.75 in. (5.12 m) with drum centers at 12
ft 10 in. (3.91 m). These dimensions are constant for all boiler sizes. The length is variable
to establish the various boiler sizes and ranges
from about 12 to 18 ft (3.66 to 5.49 m).
Waste heat marine boilers
With the use of diesel or gas turbine propulsion systems, such as aboard the LaJolla class ship, shown in
Fig. 6, it is often advantageous to incorporate a waste
heat (exhaust gas) boiler system that, in addition to
an auxiliary boiler, supplies saturated steam and improves overall plant efficiency.
The waste heat boiler system is composed of a forced
circulation, spiral wound, finned tube or studded tube
boiler (Fig. 7); auxiliary steam drum; and control
equipment.
The waste heat boiler unit is arranged for upward
expansion and is ready for positioning on the ship’s
foundation. It is designed to operate under either a wet
or dry condition and can serve as a muffler or sound
reducer whether filled with water or in a dry state.
The horizontal waste heat boiler uses the B&W continuous stud tube extended surface or a spiral wound,
finned type surface. The elements including the inlet
and outlet headers are located inside a welded gas-tight
casing, arranged for bottom support. This boiler consists
of 1.5 in. (38.1 mm) OD steel tubes and studs or fins.
The boiler elements, headers, casing, integral support steel and framing angles are shop-assembled. The
tubes are supported by tube support plates. The unit
is single-cased and of welded construction. The casing provides a gas-tight seal and is fitted with access
panels for inspection purposes. Support of the exhaust
gas boiler is on the ship’s structural members.
A 36 or 42 in. (0.91 or 1.07 m) nominal diameter
auxiliary steam drum is provided to meet anticipated
list and trip operating conditions as well as to promote
water level stability. The effect of shrink and swell is
controlled by forced circulation with a minimum 4:1
circulation ratio, cyclone steam separators and the
large diameter steam drum.
Steam 41 / Marine Applications
Fig. 6 M.V. Potomac Trader, LaJolla Class vessel with diesel
propulsion plus waste heat and auxiliary steam boilers (courtesy
Penn-Attransco Corp.).
One mode of operation has an auxiliary boiler operating in conjunction with the waste heat boiler system. (See Fig. 8.) The main diesel engine exhaust gas
is directed to the waste heat boiler. The gas then enters the boiler and crossflows over the in-line extended
surface to the waste heat boiler exit where it is then
sent to the stack.
The auxiliary boiler feed pump supplies condensate
to the auxiliary boiler steam drum. The circulating
pumps take suction from the auxiliary boiler lower
drum and feed the waste heat boiler. Flow is upward
through the waste heat boiler to its outlet where the
resulting steam-water mixture is conducted through
piping to the auxiliary boiler’s steam drum. All steam
for ship services is drawn through the auxiliary boiler’s
cyclone steam separators so that the auxiliary boiler
acts as the steam drum of the exhaust gas boiler. The
auxiliary boiler will fire automatically to maintain the
steam pressure within an adjustable band.
The alternate mode of operation for this system, with
the auxiliary boiler, has the boiler feed pump supply
condensate to the auxiliary steam drum. The circulating pumps take suction from the auxiliary steam
Fig. 7 Waste heat marine boiler.
31-5
The Babcock & Wilcox Company
Fig. 8 Shipboard steam system combining auxiliary boiler and waste heat boiler.
drum and feed the waste heat boiler. Flow is upward
through the boiler to its outlet, where the resulting
steam-water mixture is conducted through piping to
the auxiliary steam drum. The auxiliary boiler may
be isolated and unfired in this condition for maintenance or to accommodate steam demand. It may also
be fired automatically to maintain the steam pressure
within an adjustable band.
Marine boiler design
The techniques used in the design of marine boilers are similar to those applied to stationary units
(Chapters 19, 20 and 21). However, the design of
marine boilers is also subject to constraints and requirements that are specific to marine plants. These
include space conditions, fireroom configuration, list
and trim, pitch and roll, and ship maneuverability. In
addition to the codes and standards used for stationary boilers (i.e., ASME, ANSI), other codes apply. Examples include the United States Coast Guard Marine
Engineering Regulations, subchapter F and other
subchapters, American Bureau of Shipping (ABS)
Rules, and Lloyd’s Register of Shipping Rules.
Design procedures and guidelines for marine boilers are generally set in the Society of Naval Architects
and Marine Engineers (SNAME) Technical Bulletin
No. 3-32 (Furnace Performance Criteria for Gas, Oil
and Coal Fired Boilers, 1981) and No. 3-11 (Marine
Steam Plant Heat Balance Practices).
Fuel characteristics can have considerable bearing
on the design. Regardless of whether oil or coal is used,
the chemical analysis and ash characteristics are particularly important and should be specified so that heat
transfer surface can be arranged to minimize corrosion and deposition from ash and slag.
Boiler design for a particular application starts by
establishing the dimensions and arrangement of the
furnace. Within this volume the desired fuel-burning
equipment can be installed and the fuel burned effi-
31-6
ciently, without exceeding allowable furnace heat absorption rates. This is a major concern where small
furnaces are needed to fit into restricted shipboard
engine room space.
The furnace arrangement and dimensions generally establish the overall size of the boiler bank. Therefore, the first step in designing a new boiler is to prepare a preliminary layout of a suitable furnace. To do
this, the amount of fuel to be fired is calculated based
on the required steam flow, pressure and temperature,
as well as on feedwater temperature and efficiency. It
is then possible to estimate the type and number of
burners to be used, the allowable pressure drop
through the burners for good combustion conditions,
the size and shape of the furnace to properly accommodate the burners for good combustion, and the allowable furnace heat absorption rate.
Oil burners
The type and number of oil burners selected depend
on the fuel rate and the allowable air resistance. The
number is usually not less than two, so that at least
one burner operates at all times, even when changing sprayer plates or cleaning atomizers of the idle
burners. Many types of oil burners are available. The
burners described in Chapter 11 are for stationary
boilers and are for burning natural gas and oil, as well
as other gaseous type fuels or mixtures.
Marine burners are generally designed solely for
burning oil. Since World War II, three types or sizes
of registers were applied to most merchant marine and
naval vessels. They were the Iowa, Saratoga and
Progress types and covered oil flow rates up to 7000
lb/h (0.9 kg/s) or 130 × 106 Btu/h (38.1 MWt) input per
register with excess air of 10 to 20%.
With the pursuit of more efficient steam propulsion
systems in the 1970s, B&W developed a low excess air
burner (5 to 10%) to be used on merchant ships. These
burners were designed to burn natural gas or oil up
to 130 × 106 Btu/h (38.1 MWt) input. The burners are
Steam 41 / Marine Applications
The Babcock & Wilcox Company
available in throat sizes from 15 to 30 in. (381 to 762
mm) (Fig. 9) and have pressure drops of 8 in. wg (2
kPa) at normal operating conditions.
Prior to 1970, most steam ships used a mechanical
atomizer. However, B&W developed and introduced the
wide range Racer® steam atomizers or sprayer plate.
This steam atomizing sprayer plate provided coverage
over the full range of operation. The properly sized and
selected sprayer plate will cover the range from minimum to the designed maximum overload firing rate as
long as atomizing steam is available. This steam atomizer and burner are capable of operating at extremely
low firing rates without loss of good combustion or ignition as long as proper fuel oil temperature and proper
air flow (air/oil ratio) are maintained.
When maneuvering, or at any time during port operation or normal operation at sea, it should not be
necessary to secure burners unless the steam demand
is less than that produced with all burners in service
at the minimum fuel oil pressure. During normal operation, all burners should be kept in use for all rates
of operation.
For all fuel oil pressures, the atomizing steam pressure should be constant and should be maintained at
135 psig (0.93 MPa) at the burner. Due to the pressure drop between the atomizing steam header and
the burner, this is equivalent to a steam pressure of
approximately 150 psig (1.03 MPa) at the atomizing
steam header.
When burning heavy residual fuel oil, certain minimum clearances are required around the burners to
prevent flame impingement and carbon deposits. To
assure complete combustion of the fuel, the furnace
depth is usually limited to a minimum of 6 ft (1.83 m),
although both diesel and bunker oils have been
burned successfully in furnaces 5 ft (1.52 m) or less
in depth.
Furnace heat absorption
In the marine field, the heat release rate per unit
furnace volume is frequently used for comparing boilers without regard to similarity of design. This ratio is
not an important design criterion as it provides only an
approximation of the time required for the products of
combustion to pass through the furnace. However, it
may be used to indicate the operating range for which
the firing equipment is to maintain satisfactory combustion conditions. In naval vessels, the availability of
suitable oil burners has permitted the installation of
high capacity lightweight boiler units with heat released
at a rate of 200,000 Btu/h ft3 (2.07 MWt /m3) of furnace
volume at cruising conditions and more than 1,000,000
Btu/h ft3 (10.3 MWt /m3) at the maximum evaporative
condition with satisfactory results. For merchant ships,
arbitrary limits of 75,000 to 90,000 Btu/h ft3 (0.77 to
0.93 MWt /m3) at the normal rate of operation are commonly specified.
A more meaningful criterion of furnace design is the
heat absorbed by the cold surfaces of the furnace, expressed as the amount of heat absorbed per square
feet of radiant heat-absorbing surface as discussed in
Chapter 19. The considerations described also apply
to marine units, with particular emphasis on the deSteam 41 / Marine Applications
termination of the furnace exit gas temperature to
assure satisfactory superheater design and to establish the heat absorption by the furnace wall tubes for
adequate circulation margins.
Marine boilers operate with higher heat input rates
per square foot of boiler and superheater surfaces than
stationary boilers designed for the same steam outputs.
They have less heating surface and smaller overall dimensions. Flame temperatures more closely approach
the adiabatic temperature, and furnace exit gas temperatures are considerably higher than those encountered in stationary boilers. Fig. 10a indicates the effect
of excess air on furnace temperature.
The effectiveness of the water-cooled surface in the
furnace is determined by applying the factors shown
in Chapter 4 to the flat projected areas of the furnace
walls and tube banks facing the furnace. Bare tangent tubes or membrane tubes are used wherever
possible in furnace waterwalls. Where tubes must be
spaced to facilitate replacement, it is preferable to limit
the width of the exposed refractory areas between
tubes to 1 in. (25.4 mm) or less to avoid wastage resulting from sodium compounds in the oil ash. The
effect of wall tube spacing, or the ratio of water-cooled
surface to refractory surface, on furnace heat absorption is shown in Fig. 10b. The heat absorption rate in
the furnace increases with increased firing rate. However, furnace absorption as a percentage of the total
boiler absorption decreases with increased firing rate
as indicated in Fig. 10c.
Furnace tube temperatures
In all boiler tubes and particularly in tubes exposed
to the high heat absorption rates of marine furnaces,
adequate circulation must be provided to avoid critical heat flux (CHF) or departure from nucleate boiling (DNB) as discussed in Chapter 5. This is generally accomplished by empirical data and methods
based on tests and operating experience. Tube wall
thickness is usually set close to the minimum required
for the design pressure, because weight is a primary
consideration and excess thickness increases external
tube temperature. The heat transfer coefficient across
the boiling water film in the furnace steam generating tubes can be as high as 20,000 Btu/h ft2 F (114
kW/m2 K). However, in estimating tube temperature,
a conservative value may be used, e.g., 2000 Btu/h
ft2 F (11.4 kW/m2 K), to obtain a somewhat higher
estimated tube temperature, resulting in lower allowable stress in the tube metal and therefore a somewhat
more conservative tube thickness.
Fig. 9 B&W Progress-type oil burner with Racer ® steam atomizer.
31-7
The Babcock & Wilcox Company
Fig. 10 General effect of excess air (a), ratio of heat-absorbing to refractory surface (b), and firing rate (c) on furnace heat absorption and
temperature based on 18,500 Btu/lb (43 MJ/kg) fuel oil.
Scale deposits on the water side of boiler tubes are
a long recognized cause of tube failure. These deposits can be particularly serious in the furnace tubes of
marine units because of the high heat absorption
rates. As an example, a calcium sulfate scale deposit
on the inside of a tube with a thickness of only 0.024
in. (0.61 mm) and a thermal conductivity of 0.83 Btu/
h ft F (1.44 W/m K) results in a 362F (201C) temperature differential across the scale. For a boiler operating at 665 psig (4.59 MPa), this scale would increase
the tube outside metal temperature to 1004F (540C).
This temperature exceeds the oxidation limit for steel,
and oxidation and ultimate tube burnout will likely
occur, even though boiler circulation may be adequate.
Scale must be avoided by proper water conditioning.
(See Chapter 42.)
Boiler tube banks
The boiler bank, composed of multiple rows of tubes
where steam is generated, generally consists of a
screen ahead of the superheater and a convection
bank behind it. Both sections generate saturated
steam but they are considered separately during the
design stage. The screen tubes, by virtue of their location, absorb heat at a considerably higher rate than
the main bank tubes. Consequently, to assure an adequate flow of water, the furnace screen tubes should
be larger in diameter. For this reason, marine boilers
are designed with two sizes of steam generating tubes.
The diameters of screen tubes are generally 2 in. (50.8
mm) while those of the other generating tubes are 1,
1.25 or 2 in. (25.4, 31.8 or 50.8 mm), swaged to 1.5 in.
(38.1 mm) at the drums. Circulation and the amount
of heating surface required to obtain the desired gas
temperature leaving the tube bank are the major factors in determining the tube size and the number of
tube rows to be installed, although resistance to gas flow
is also a factor.
31-8
In the design of the superheater screen, consideration must be given to the effect of tube spacing and
the number of rows, the desired superheater outlet
temperature and the maximum allowable superheater
tube metal temperatures. The screen must be designed
so that the gas temperature entering the superheater
and the radiant heat penetration from the furnace will
provide the desired steam temperature with a superheater of reasonable size and arrangement. Fig. 11
shows the effect of radiant heat penetration on the
performance of the superheater over the designed load
range of the boiler. The number of rows in the boiler
bank is usually established by analyzing the economic
advantages of economizers and air heaters as compared
with boiler surface. The proper proportions of boiler
surface and additional heat-absorbing surface beyond
the boiler bank are based on the efficiency desired.
Superheaters
Superheaters of the convection type are generally
used in marine boilers. While some radiant superheaters have been used, the difficulty of providing adequate
cooling during fast startups and under maneuvering
conditions has severely limited their application.
In the convection superheater, there is usually
enough absorption by radiant heat penetration of the
screen to give a flatter steam temperature characteristic than would be obtainable by convection alone.
The characteristic steam temperature curves of radiant
and convection superheaters are shown in Chapter 19.
With a properly designed screen between the convection superheater and the furnace, it is possible to
maintain a high temperature differential between the
gas and the steam. This minimizes the amount of heating surface necessary to obtain the desired steam temperature and reduces the size and weight of the superheater. Superheater heating surface usually consists of U-shaped tubes connected to headers at each
Steam 41 / Marine Applications
The Babcock & Wilcox Company
end, although continuous tube superheaters are used
in special designs.
Either a vertical or a horizontal arrangement may
be used in drum-type boilers. The horizontal arrangement can be vented, drained, and readily cleaned by
mechanical or chemical means. However, complete
draining and venting is possible only with the vessel
on an even keel. Vertical superheaters have inverted
loops and, although drainable at all times, they can
not be vented. Typical superheater arrangements for
a two-drum boiler are shown in Figs. 3 and 4.
Superheater surface is arranged in loops of in-line
tubes (usually one to four loops), and the most commonly used tube size is 1.25 in. (31.8 mm) OD. Because
the tubes are relatively short, adequate strength is
available in the usual range of thicknesses to maintain
proper alignment with a minimum of supports. The
number of steam passes is selected to provide sufficient
pressure drop to obtain proper steam distribution and
to assure satisfactory tube metal temperatures.
Good practice requires that maldistribution of gas and
steam be kept to a minimum to maintain proper superheater tube temperatures. However, with various fuels
and operating demands it is not possible to maintain the
conditions necessary for perfect distribution. To provide
a satisfactory margin when calculating steam and tube
temperatures, the average gas side heat transfer rate is
increased and the steam side rate is reduced.
For steam temperatures below 850F (454C), tubes
are usually expanded into headers to minimize leakage and to reduce maintenance costs. For temperatures above 850F (454C), rolled and seal welded joints,
or joints of the stub welded type, are necessary for satisfactory service.
In addition to being supported by the headers, superheater tubes may also be supported at one or more
Fig. 11 Typical curves showing the effect of superheater location and
firing rate on superheat.
Steam 41 / Marine Applications
points by alloy castings dovetailed into brackets
welded to water-cooled support tubes. With these designs, the superheater tubes can be replaced without
removing the supports.
Superheater fouling and high
temperature corrosion
The use of higher steam temperatures has resulted
in rapid fouling of superheater surfaces and corrosion
and wastage of superheater supports. The heavy ash
deposits come from burning oils with 0.05 to 0.20% or
more ash by weight. The most significant constituents
of the ash are vanadium, sodium and sulfur. Experience indicates that heavy deposits occur with a combination of high gas and heat-receiving surface temperatures. The heaviest ash accumulations occur on the furnace side of a superheater, where the gas temperatures
are relatively high, while less ash forms at the back side,
where the gas temperatures are much lower. Because
of the potential of high corrosion rates, superheater metal
temperatures should not exceed 1100F (593C). For further discussion of high temperature corrosion in oil-fired
boilers, see Oil ash corrosion in Chapter 21.
Steam temperature control
In the marine power plant, just as in the stationary
power plant, accurate control of steam temperature is
required. In most cases steam temperature controls are
used to assure that the allowable metal temperatures
of the main steam piping and the main turbine are not
exceeded. Close control of the maximum steam temperature permits the use of less expensive alloys in the superheater and piping. Several methods are used for
superheat control, as described in Chapter 19. One or
more methods may be used to alter the characteristic
steam temperature curve of a particular unit design.
One method used in marine boilers is the dual or
two-furnace boiler design. As shown in Fig. 12, the furnace is divided into two sections separated by a superheater and screen tube section. The flue gas flows
successively through the superheat furnace (left hand
furnace), the superheater heat transfer surfaces, the
second furnace (where fuel and air are burned) and,
finally, the boiler bank before being exhausted to the
stack. By varying the oil firing rate in the superheater
furnace, the quantity and temperature of the gases
flowing across the superheater are controlled to obtain the desired steam temperature. At the same time,
the firing rate in the saturated furnace, which contains no superheater surface, is adjusted to hold the
desired steam pressure.
In most modern two-drum boilers, steam temperature is controlled, where required, through the use of
a drum-type surface attemperator. With this type of
control, all of the flue gas passes over the superheater,
but a portion of the steam is passed through the
attemperator, which is a steam-to-water heat exchanger submerged in boiler water in the steam or
water drum. Fig. 13 indicates two piping arrangements for control attemperators. In a submerged
attemperator where the inlet steam temperature exceeds 850F (454C), 16Cr-1Ni alloy should be considered to protect against methane gas corrosion.
31-9
The Babcock & Wilcox Company
Fig. 12 Twin furnace design used for marine boiler superheat
temperature control.
Auxiliary desuperheaters
Steam for auxiliary use may be required at a lower
temperature than that delivered by the superheater to
the main engine. To satisfy these demands, auxiliary
desuperheaters are used, often in conjunction with
pressure reducing stations. These desuperheaters may
be inside the drum as discussed above or separate external spray types.
added. The choice of which to use depends on the design of the power plant and the desired performance
characteristics of the unit.
Where the design includes a deaerating feedwater
heater and a single stage of feedwater heating to supply water at 240 to 280F (116 to 138C), an economizer
can be used to provide reasonably high boiler efficiency. The economizer can be used either alone or in
conjunction with a steam air heater. In this range of
feedwater temperature, an economizer can be economically designed to reduce the products of combustion to within 30F (17C) of the inlet water temperature at the normal rating. Therefore, with 280F (138C)
feedwater, a boiler efficiency of 88.6% can be attained
with an economizer alone and about 88.8% if a steam
air heater is added.
When the feedwater temperature to the economizer
is higher, the efficiency is limited, because the temperature of the gas leaving the economizer can not be
lower than the inlet feedwater temperature. Consequently, when additional stages of regenerative feedwater heating are used, the inlet feedwater to the
economizer may be at a temperature of 300 to 450F
(149 to 232C), and it may not be economical to use an
economizer unless it is followed by an air heater. Cycle
efficiency is increased approximately 1% for each 100F
(56C) rise in feedwater temperature through regenerative feedwater heating.
An air heater contributes additional efficiency even
when the maximum practical amount of regenerative
feedwater heating is used. At normal operating rates
and an inlet air temperature of 100F (38C), exit gas
temperatures of 300 to 320F (149 to 160C) are readily
Reheaters
The use of steam reheat in a marine plant is more
attractive as the speed and power requirements of the
ship increase. Although reheaters increase the complexity of the boiler design and the first cost of the plant,
fuel savings in high horsepower, high utilization plants
can be significant. Design considerations are similar to
those for superheaters but must be augmented by the
requirements to protect the reheater from overheating
during periods when there is no steam flow during
maneuvering, running astern or at a stop bell.
Economizer and air heater cycles
Economizers or air heaters, and in some instances
both, are required if a high boiler efficiency is to be
obtained. The temperature of flue gas leaving the
boiler bank at full power (the design rate) is a function of the saturation temperature corresponding to
the drum pressure at which the unit is operating.
Space, weight and economic considerations usually
result in a boiler bank sized to reduce the exit gas temperature to within 50 to 100F (28 to 56C) of the saturation temperature. Gas temperatures in the range of
550 to 650F (288 to 343C) leaving the boiler bank are
typical of merchant ship boilers. To reduce this flue
gas temperature sufficiently in order to obtain acceptable efficiency, economizers and/or air heaters may be
31-10
Fig. 13 Internal attemperators – (a) inter-pass, (b) after-pass.
Steam 41 / Marine Applications
The Babcock & Wilcox Company
obtained, corresponding to 88.5 to 88.0% efficiency. Air
temperatures leaving air heaters are normally in the
range of 300 to 450F (149 to 232C).
As an alternate to the standard economizer/air heater
cycle, a dual economizer steam air heater cycle (DESAH),
using a primary and secondary economizer, can be used.
This arrangement will improve the cycle efficiency and
reduce the fuel rate by utilizing turbine bleed steam to
a high pressure feedwater heater. The actual cycle improvement will depend on the turbine characteristics
with the additional bleed for the high pressure heater.
The overall boiler efficiency will remain essentially unchanged over that with the regular economizer cycle;
however, the fuel oil consumed will decrease because of
additional heat added to the feedwater.
The cycle would use a feedwater temperature leaving the deaerator feedwater heater of about 285 to
300F (141 to 149C), presently being used on single
economizer, steam air heater cycles. A feedwater temperature lower than this could result in economizer
corrosion and plugging problems. If higher feedwater temperatures are desired in order to more efficiently use turbine bleeds, it should be pointed out
that the boiler efficiency will correspondingly decrease.
This is due to the higher gas temperatures occurring at
the secondary economizer outlet because a terminal end
temperature difference of 25F (14C) is required.
The feedwater would pass through the secondary
economizer and be heated to about 335F (168C). It
would then pass through a high pressure feedwater
heater, that would raise the feedwater temperature
about 50F (28C) before returning the water to the
primary economizer and the steam drum (Fig. 14).
This cycle shows a reduction in all purpose fuel use
over that associated with the single economizer steam
air heater cycle while being only slightly more complicated. Equipment costs rise somewhat due to the addition of a high pressure feedwater heater and its control. In addition, in order to realize the same exit gas
temperature, the economizer heating surface would
have to be increased 1.5 times the surface amount
used with the single economizer cycle.
Economizers Two general types of economizers, the
bare tube and extended surface types, are used in
marine service. Both are nonsteaming and are almost
always arranged for counterflow of water and flue gas
to obtain the best possible heat transfer characteristics. (See Chapter 20.) The bare tube type is used
where high feedwater temperature makes the application of both an economizer and air heater desirable.
These economizers are designed to reduce the gas temperature about 100F (56C), with the remainder of the
required temperature drop obtained with an air
heater. All are drainable and ventable.
The second and more common type uses extended
surface to reduce the size of the economizer. There are
many types of extended surface, including cast iron
or aluminum gill rings, spiral fins and small metal studs
welded to the tubes. B&W has chosen the latter for its
marine economizers due to the shape and size of the stud
and because the method of attachment eliminates sootcollecting crevices where corrosion usually begins.
Extended surface economizers are usually conSteam 41 / Marine Applications
Fig. 14 Dual economizer steam air heater (DESAH) cycle schematic.
structed of 1.5 in. (38.1 mm) OD tubes formed into continuous loops. This construction requires only two
headers. Tube-to-header joints are welded, or expanded
and seal welded, to eliminate seat leakage. In the most
recent designs, handhole fittings, except those required
for inspection, are eliminated by externally welding the
tubes in sockets or to stubs on the headers. A typical
arrangement of an extended surface economizer with
studded tubes is shown in Fig. 15.
When used alone, economizers are generally designed to reduce gas temperatures by 200 to 300F (111
to 167C), with a corresponding increase in the water
temperature of 70 to 100F (39 to 56C). If the inlet
water temperature is 280F (138C), the exit water temperature normally will range from 350 to 365F (177
to 185C), far enough below saturation temperature at a
pressure of 600 psig (4.14 MPa) to prevent steaming.
In designing an economizer, the possibility of sulfuric acid corrosion of the economizer tubes must be
considered. (See Chapter 20.) The tube metal temperature of bare tube economizers is essentially the same
as that of the water within the tube. This is also true
for the tube metal of extended surface elements, but
the tip temperature of the studs is considerably higher.
In order to minimize gas side corrosion of carbon
steel economizer tubes, B&W recommends that feed
31-11
The Babcock & Wilcox Company
Fig. 15 Extended surface stud tube economizer.
temperature be kept above 246F (119C) when burning Navy Special Fuel Oil (NSFO) and above 270F
(132C) when burning Bunker C oil. Where these temperatures are not obtainable, the use of a corrosion
resistant alloy tube is advised. The use of cast iron is
not recommended as the corrosion resistance of cast
iron is less than that of standard carbon steel, and any
improvement in tube life with cast iron cladding is only
due to its greater mass.
A bypass line is usually provided for operation of
the boiler with the economizer out of service. During
such operation, it is necessary to fire more fuel to
maintain the required evaporative rating because of
the decreased efficiency. This increases the steam temperature and requires either more attemperation or a
reduction in rating to prevent overheating of superheater tubes or turbine. Normally there is no danger
of metal oxidation in the economizer during bypass
operation, because the gas temperatures entering the
economizer are usually less than 850F (454C).
When economizers are included in the design, deaerating feedwater heaters should be installed to remove all traces of oxygen from the feedwater and to
prevent internal corrosion of tubes and headers.
Air heaters (gas to air) Tubular and regenerative air
heaters (see Chapter 20) have both been used for marine boiler applications. However, the tubular air heaters have become virtually obsolete due primarily to
their extremely large space requirements and their
relatively poor metal temperature characteristics.
Air heater corrosion can be reduced or practically
eliminated by several means. For a given exit gas temperature, metal temperatures are somewhat higher
with a regenerative air heater than with a recuperative type. Therefore, for a given satisfactory metal temperature, a lower exit gas temperature and a higher
unit efficiency can be obtained with a tubular type air
heater. With a regenerative air heater, air temperatures
of 550F (288C) or higher can be produced with a resulting exit gas temperature of 235F (113C) or less. This
in turn can result in a boiler efficiency of about 90.3%
when using low excess air values.
31-12
As with the tubular air heater, corrosion can be a
problem when the regenerative air heater is designed
for low exit gas temperature and the corresponding
high air temperature. This can result in an average
cold-end metal temperature well below the acid dew
point of the combustion gas. Corrosion can be reduced
by the use of porcelain-enameled cold-end surface.
Another alternative available when using a rotary
regenerative air heater is to place a small economizer
in the gas stream and/or a steam air heater on the air
side ahead of the regenerative air heater. Without the
economizer, the regenerative air heater becomes large
due to the relatively low heat transfer rates inherent
in a gas-to-air heat exchanger. Often space and
weight limitations, along with the increased cost associated with a large air preheater, dictate a reduction in its size. The addition of an economizer designed
to reduce the gas temperature entering the air heater
by 100 to 125F (56 to 69C) reduces the size of the air
heater; the air temperature to the furnace is correspondingly reduced. This can frequently provide a
better arrangement and at a lower overall cost.
Boiler casing
In marine service, the walls that form the boiler and
furnace enclosure, together with those surrounding the
economizer and air heater, are normally made gas-tight
by using metal casing. Therefore, the term casing is
generally used for the walls surrounding a marine unit.
To provide a comfortable fireroom, an outer casing
temperature of 130F (54C) is usually specified. In the
double case arrangement used for tangent tube boiler
construction, the space between the inner and outer
casing is pressurized with air at or near the forced
draft fan discharge pressure to prevent leakage of combustion gases into the fireroom and to help maintain
the desired outer casing temperature. With welded
wall construction the boiler is, for the most part, singlecased and pressure-sealed to prevent leakage of combustion gases into the fireroom.
Circulation and steam separation
Satisfactory circulation characteristics and efficient
steam separation are of prime importance in the successful operation of any boiler. These factors take on
increased importance in a marine boiler that is rolling and pitching in a seaway or undergoing rapid load
changes. In analyzing circulation, the procedures outlined in Chapter 5 are applied to the design at the
maximum anticipated rate of evaporation.
Generally, steam drum diameters range from 54 to 72
in. (1.37 to 1.83 m) for merchant vessels and from 54 to
60 in. (1.37 to 1.52 m) for naval units. The drum must
accommodate the desired number of tube rows and provide sufficient space for steam separation, feedwater
introduction, distribution and treatment, and water level
fluctuations caused by sudden load variations.
Marine steam drum baffling for lower rated boilers
is usually simple in construction and arrangement. A
V-type baffle using a triple layer of perforated steel
plates is used in moderately-rated drum boilers. With
relatively small clearances between the plates, it is
installed (Fig. 15) just below the normal water level
Steam 41 / Marine Applications
The Babcock & Wilcox Company
to break up steam and water jets issuing from the riser
circuits. The duplex compartment baffle is more effective in higher-rated two-drum boilers. In current B&W
marine boiler designs, horizontal steam separators and
scrubbers are used (Fig. 16). Cyclone separators and
scrubbers are used to ensure that dry steam is sent to
the superheater where moisture and dissolved boiler
water containment carryover would not be acceptable.
The principles of these cyclone separators are similar
to those of the vertical cyclones used in stationary
units. (See Chapter 5.)
Drum boilers are generally rated conservatively
and do not require external downcomers. Adequate circulation can be maintained by the rear rows of boiler
bank tubes as downcomers, where the gas temperature is 850F (454C) or less. At low loads, the first several rows of tubes act as risers, and the remaining
tubes serve as downcomers. As the firing rate increases, the high temperature gas zone moves deeper
into the tube bank, the number of tubes acting as risers increases, and the number of downcomers declines.
Excessive firing rates and rates beyond those contemplated in the design can reduce the number of downcomers below the minimum requirements. For highly
rated units, it is necessary to install unheated
downcomers to supplement the number of boiler bank
tubes acting as downcomers. Circulation is benefited by
interposing a convection superheater in the boiler bank
because the heat absorbed by the superheater reduces
the temperature of the gas flowing over the boiler tubes
beyond it. More boiler tubes consequently act as downcomers over a wide operating range. In vertical superheater units, external downcomers are also required
because of physical arrangement constraints.
In most horizontal superheater drum boilers (Fig.
4), furnace waterwall supply headers receive water
from the lower drum through supply tubes located
below the furnace floor. These tubes are spaced along
the length of the waterwall headers to assure even
distribution of water to the high duty furnace tubes
and provide cooling for the furnace floor refractory.
Naval and other high-rated designs have external
downcomer tubes from the steam drum to the lower
wall header because the supply of water from the boiler
Steam 41 / Marine Applications
Fig. 16 Arrangement of horizontal cyclone separators in a marine
boiler drum.
bank alone would be inadequate. In vertical superheater drum boilers (Fig. 3), furnace waterwall supply headers receive water from the steam or lower
drum through external downcomers or feeder tubes.
Drum boilers should not be located with the drum
longitudinal axis athwart ship. In such a design, rolling motion may stop circulation in some riser tubes located in the sides of the boiler. This can result in tube
overheating and failures. While this difficulty is alleviated by locating the drums fore and aft, ship rolling
can still affect boiler circulation. During rolling, some
of the rear boiler tubes in the drum may become uncovered and the overall downcomer water flow to the
lower drum reduced. However, marine boilers operating at conservative load ratings are usually able to
accommodate such conditions.
31-13
The Babcock & Wilcox Company
Naval steam power then and now: U.S.S. Missouri (top) and U.S.S. John F. Kennedy.
31-14
Steam 41 / Marine Applications
The Babcock & Wilcox Company
Section IV
Environmental Protection
Environmental protection and the control of solid, liquid and gaseous effluents or emissions are key elements in the design of all steam generating systems. The emissions from combustion systems are tightly regulated by local
and federal governments, and specific rules and requirements are constantly
changing. At present, the most significant of these emissions are sulfur dioxide (SO2), oxides of nitrogen (NOx), and fine airborne particulate. All of these
require specialized equipment for control.
Chapter 32 begins this section with an overview of current regulatory requirements and overall emission control technologies. The chapter concludes
with a discussion of mercury emissions control which is expected to become an
integral part of overall plant multi-pollutant control strategy. Following this
overview, Chapters 33, 34 and 35 discuss specific equipment to control atmospheric emissions of particulate, NOx and SO2 respectively. The NOx discussion focuses on post-combustion technologies; combustion-related control options are addressed in Chapter 11 and Chapters 14 through 18.
Finally, a key element in a successful emissions control program is measurement and monitoring. Chapter 36 addresses a variety of issues and outlines a number of technologies for flue gas monitoring.
Steam 41
The Babcock & Wilcox Company
Chapter 32
Environmental Considerations
Since the early 1960s, there has been an increasing worldwide awareness that industrial growth and
energy production from fossil fuels are accompanied
by the release of potentially harmful pollutants into
the environment. Studies to characterize emissions,
sources and effects of various pollutants on human
health and the environment have led to increasingly
stringent legislation to control air emissions, waterway
discharges and solids disposal.
Comparable concern for environmental quality has
been manifest worldwide. Since the 1970s, countries
of the Organization for Economic Cooperation and
Development have reduced sulfur dioxide (SO2) and
nitrogen oxides (NOx) emissions from power plants in
relation to energy consumption. In at least the foreseeable future, emission trends are expected to continue downward due to a combination of factors: change
in fuel mix to less polluting fuels, use of advanced technologies, and new and more strict regulations. In Japan,
the reductions in SO2 emissions were particularly pronounced due to strong environmental measures taken
in the 1970s. As an example, in the United States (U.S.)
between 1980 and 2001, electricity generation increased
by 56%, while SO2 emissions declined 38%.
Environmental control is primarily driven by government legislation and the resulting regulations at
the local, national and international levels. These have
evolved out of a public consensus that the real costs
of environmental protection are worth the tangible
and intangible benefits now and in the future. To
address this growing awareness, the design philosophy of energy conversion systems such as steam generators has evolved from providing the lowest cost
energy to providing low cost energy with an acceptable impact on the environment. Air pollution control
with emphasis on particulate, NOx, SO2, and mercury
emissions is perhaps the most significant environmental concern for fired systems and is the subject of Chapters 33 through 36. However, minimizing aqueous discharges and safely disposing of solid byproducts are
also key issues for modern power systems.
Sources of plant emissions
and discharges
Fig. 1 identifies most of the significant waste
streams from a modern coal-fired power plant. Typical discharge rates for the primary emissions from a
new, modern 615 MW coal-fired supercritical pressure
boiler are summarized in Table 1.
Atmospheric emissions arise primarily from the
Steam 41 / Environmental Considerations
byproducts of the combustion process (SO2, NOx, particulate flyash, and some trace quantities of other
materials) and are exhausted from the stack. A second source of particulate is fugitive dust from coal piles
and related fuel handling equipment. This is especially
significant for highly dusting western U.S. subbituminous coals. Some low temperature devolatilization
of the coal can also emit other organic compounds. A
final source of air emissions is the cooling tower and
the associated thermal rise plume which contains
water vapor.
Solid wastes arise primarily from collection of the
coal ash from the bottom of the boiler, economizer and
air heater hoppers, as well as from the electrostatic precipitators and fabric filters. Pyrite collected in the pulverizers (see Chapter 13) is usually also included. Most
of the ash is either transported wet to an ash settling
pond where it settles out or is transported dry to silos
from which it is taken by truck for beneficial use (e.g.,
cement additive). The chemical composition and characteristics of various ashes are discussed in Chapter 21.
The second major source of solids is the byproduct from
the flue gas desulfurization (FGD) scrubbing process.
Most frequently, this is a mixture containing primarily
calcium sulfate for wet systems and calcium sulfite for
dry systems. After dewatering, the wet system byproduct
may be sold as gypsum or landfilled. Additional sources
of solids include the sludge from cooling tower basins,
wastes from the water treatment system and wastes from
periodic boiler chemical cleaning.
Aqueous discharges arise from a number of sources.
These include once-through cooling water (if used),
cooling tower blowdown (if used), sluice water from the
ash handling system (via the settling pond), FGD waste
water (frequently minimal), coal pile runoff from rainfall, boiler chemical cleaning solutions, gas-side water
washing waste solutions, as well as a variety of low volume wastes including ion exchange regeneration effluent, evaporator blowdown (if used), boiler blowdown
and power plant floor drains. Many of these streams
are chemically characterized in Chapter 42. Additional
discussions of these systems as well as the controlling
regulations are provided in References 1 and 2.
Air pollution control
U.S. legislation – Clean Air Act
The Federal Clean Air Act (CAA) is the core driving force for all air pollution control legislation in the
United States (U.S.). The original CAA was first en32-1
The Babcock & Wilcox Company
HeatThermal Rise
Plume
Flue Gas
Fugitive Dust
SO2
NOX
Particulate
VOC
CO
CO2
Other
Coal Pile
Coal Pile
Water Runoff
Boiler
Turbine
WESP
Fabric Filter
or
Precipitator
SCR
Condenser
Cooling
Tower
Hopper
Ash
Cooling
Tower
Blowdown
Stack
FGD Waste
Treatment
and
Dewatering
FGD
Waste
Water
Bottom
Ash
Noise
Sludge / Landfill
FGD
Air
Heater
Blowdown
Water
Chemical Cleaning
Waste Liquid
Gas Side Washing
Waste Water
Saleable
Ash
Note: SCR-Selective Catalytic
Reduction System
FGD-Flue Gas
Desulfurization System
WESP-Wet Electrostatic Precipitator
FGD Byproduct
Gypsum or
Landfill Sludge
Fig. 1 Typical bituminous coal-fired power plant effluents and emissions.
acted in 1963, and since that time the Act has evolved
through five significant amendment cycles in 1965,
1967, 1970, 1977, and 1990.
The primary objective of the CAA is to protect and
enhance the quality of the nation’s air resources to
promote the public health and welfare and the productive capacity of its population.3 The legislation generally provides for the U.S. Environmental Protection
Agency (EPA) to set national air quality standards and
other minimum regulatory requirements through federal regulations and guidance to state and local regulatory agencies. The individual states are required to
develop state implementation plans (SIPs) to define how
they will meet the minimum federal requirements. However, state and local government agencies may also develop and implement more stringent air pollution control requirements. The CAA as amended prior to 1990
included the following regulatory elements of potential
interest to boiler owners and operators.
National Ambient Air Quality Standards (NAAQS) Federal standards were developed to define acceptable air
quality levels necessary to protect public health and
welfare. The EPA promulgated National Ambient Air
Quality Standards for six Criteria Pollutants: sulfur
dioxide (SO2), nitrogen dioxide (NO2), carbon monoxide (CO), ozone (O3), particulate matter and lead. Two
levels of standards have been established: primary
standards aimed at prevention of adverse impacts on
human health and secondary standards to prevent
damage to property and the environment. All geographic areas of the country are divided into a number of identifiable areas known as air quality control
regions which are classified according to their air quality. Air quality control regions that meet or better the
NAAQS for a designated pollutant are classified as
32-2
attainment areas for that pollutant, and regions that fail
to meet the NAAQS are classified as nonattainment areas for that pollutant.
New Source Performance Standards (NSPS) Federal
New Source Performance Standards were established
for more than 70 categories of industrial processes and/
or stationary sources. The NSPS rules set source-specific emission limitations and corresponding monitoring, recordkeeping and reporting requirements that
must be met by new sources constructed on or after
the effective date of an applicable standard. Sources
constructed prior to the promulgation of an applicable
NSPS are generally grandfathered and are not subject to the standards until such time that the source
undergoes major modification or reconstruction. The
EPA’s NSPS regulations are published under Title 40,
Part 60 of the Code of Federal Regulations.4 Table 2
provides reference to select Subparts of 40 CFR 60
applicable to a variety of industrial and utility boilers. The various NSPS rules governing fossil fuel-fired
boilers include emission limitations for NOx, SO2, particulate and opacity. The NSPS emission limits are
based on the EPA’s evaluation of best demonstrated
technology, and these limits are subject to periodic
review and revision. Finally, the NSPS rules generally establish the least stringent emission limitation a
new source would have to meet. Typically, more stringent emission limitations are necessary to meet other
federal, state or local permitting requirements. For
example, any significant new source or major modification to an existing source of emissions may be subject
to the federal New Source Review rules discussed below.
New Source Review (NSR) New Source Review regulations were established to: 1) preserve existing air
quality in areas of the U.S. that are in compliance with
Steam 41 / Environmental Considerations
The Babcock & Wilcox Company
Table 1
Modern 615 MW Supercritical Coal-Fired Steam Generator Emissions and Byproducts*
(2.3% Sulfur, 7.7% Ash, 13,100 Btu/lb Fuel)
Emission
SO2
SO3
NOx as NO2
CO2
Thermal discharge to water sources
Flyash to air***
Ash to landfill
WFGD gypsum byproduct
Typical Control Equipment**
Discharge Rate t/h (tm /h)
Uncontrolled
Controlled
WFGD
9.1
ESP or BH in conjunction
with WFGD and WESP
0.2
SCR (with LNB)
0.8
None (except cycle efficiency improvement)
536
Natural draft cooling tower
2.6 x 109 Btu/h
ESP or BH in conjunction
with WFGD and WESP
13.0
Landfill or saleable product
2.6
Landfill or saleable product
0.0
(8.3)
0.27
(0.25)
(0.2)
(0.7)
(487)
(750 MWt )
0.03
0.08
∼0
(0.03)
(0.07)
(∼0)
(11.8)
(2.3)
(0.00)
0.03
16
24
(0.02)
(14)
(22)
*
**
See Table 1 in Chapter 1 for a typical 500 MW subcritical coal-fired steam generator.
Definitions:
WFGD − Wet flue gas desulfurization (limestone reagent with forced oxidation)
ESP
− Electrostatic precipitator
BH
− Baghouse fabric filter
WESP − Wet electrostatic precipitator
SCR
− Selective catalytic reduction
LNB
− Low NOx burners with overfire air
*** As flyash emissions to the air decline, ash shipped to landfills or alternate uses increases.
the NAAQS, and 2) avoid further degradation and improve air quality in those areas of the U.S. that do not
meet the NAAQS. NSR as discussed herein refers to
two separate and distinct regulatory programs: Prevention of Significant Deterioration (PSD) and
nonattainment NSR. In general, the NSR process requires any major new source or major modification to
an existing source, which exceeds certain specified
emission thresholds defined in the regulations,5 to
obtain permits and undertake other obligations prior
to construction. A new or modified source subject to
NSR generally must: 1) evaluate its potential impact
on existing air quality, and 2) evaluate and utilize
state-of-the-art air pollution control technologies.
Under NSR, an affected project must conduct a pollutant-by-pollutant emissions evaluation. If a source
is located in (or is impacting) an area which is in attainment with the NAAQS, the PSD rules apply. If the
source is located in (or is impacting) a nonattainment
area, the nonattainment NSR rules apply. Because a
source may be located in an attainment area for one or
more designated pollutants and in a nonattainment area
for other designated pollutants, both the PSD and
nonattainment NSR rules can apply simultaneously.
The PSD permitting process typically requires an
air quality modeling analysis (which may require more
than a year’s worth of ambient air monitoring data)
to demonstrate that new emissions will not cause a
violation of the NAAQS or result in a significant deterioration of the existing air quality. Numerical limits (air quality increments) have been established by
regulation for NOx, SO2 and fine particulate matter
that restrict how much of the existing ambient air
quality (µg/m3) can be consumed by a new or modified emission source. All areas in the U.S. that meet
Steam 41 / Environmental Considerations
the NAAQS are ranked into one of three classifications which determine the allowable increment consumption. Class I areas (national parks and designated
wilderness areas) are to be kept in a pristine condition, whereas Class II or III areas allow for some further industrial growth. As might be expected, Class I
areas allow almost no degradation of existing air quality. In addition to air quality impact analyses, the PSD
process requires the use of Best Available Control
Technology (BACT). A permit applicant must conduct
a thorough evaluation of available control technologies (considering energy, environmental and economic
impacts) for each pollutant subject to PSD review. The
permitting authority then evaluates, accepts or rejects
the proposed control technology. Once the control technology is agreed upon, the applicant and permitting
authority determine a final permit limit that represents
BACT. As part of this process, BACT limits contained in
other PSD permits issued to similar sources throughout
the U.S. must be considered and final BACT limits can
not be less stringent than any applicable NSPS limit.
Unlike the PSD permitting process, nonattainment
NSR does not require ambient air modeling or monitoring; however, a new or modified source subject to
nonattainment NSR must offset the impact of new
emissions by securing emission reductions from other
sources in the area. The amount of reduction (offset)
must be as great as, or greater than, the new increase
in emissions, and the required offset is based on the
severity of the area’s air quality issues. The more polluted the air, the greater the required emissions offset. Offsets must be real reductions in existing emission rates, not otherwise required by regulations under the Clean Air Act, must be enforceable by the EPA,
and must result in a positive net air quality benefit.
32-3
The Babcock & Wilcox Company
Table 2
Selected Categories − New Source Performance Standards (40 CFR Part 60)4
40 CFR Part 60
Subpart
Title/Description
D
Performance Standards for Fossil Fuel Fired Steam Generators (≥250 x 106 Btu/h) constructed after
08/17/71 (Note: generally superceded by Subparts Da or Db)
Da
Performance Standards for Electric Utility Steam Generating Units constructed after 09/18/78
Db
Performance Standards for Industrial, Commercial, Institutional Steam Generating Units
(≥100 x 106 Btu/h) constructed after 06/19/84
Dc
Performance Standards for Small (<100 x 106 Btu/h) Industrial, Commercial, Institutional Steam
Generating Units constructed after 06/09/89
Cb
Emission Guidelines for Large Municipal Waste Combustors constructed on or before 09/26/94
Ea
Performance Standards for Municipal Waste Combustors constructed after 12/20/89 and on or before
09/20/94
Eb
Performance Standards for Large Municipal Waste Combustors constructed after 09/20/94 or modified
after 06/19/96
Y
Performance Standards for Coal Preparation Plants
BB
Performance Standards for Kraft Pulp Mills (Note: includes kraft recovery boilers)
AAAA
Performance Standards for Small Municipal Waste Combustors constructed after 08/30/99 or modified
after 06/06/01
BBBB
Emission Guidelines for Small Municipal Waste Combusion Units constructed on or before 08/30/99
In general, offsets must be secured for the life of the
source. In addition to achieving a net improvement
in air quality through offsets, an affected source must
utilize state-of-the-art controls to achieve the Lowest
Achievable Emission Rate (LAER). LAER is based on the
most stringent emission limitation contained in any SIP,
contained in an existing permit, or achieved in practice
by a similar source, regardless of cost or other economic
consideration. Final LAER emission limits are established as an integral part of the NSR permitting process.
For further details and current information regarding the NSR rules, including NSR reforms that may
impact the utility industry, see the following EPA Web
page: www.epa.gov/nsr/
The 1990 Clean Air Act Amendments
The 1990 Clean Air Act Amendments added many
new provisions to the existing Act, several of which
have significantly impacted the electric utility industry. Under Title I of the Act, areas of the country that
do not meet the National Ambient Air Quality Standards (NAAQS) were given new classifications and
deadlines to achieve compliance. This provision of the
Act has forced a dramatic reduction in NOx emissions
from utility and large industrial boilers located in the
eastern U.S. because large portions of the northeast
are ozone nonattainment areas and NOx is a primary
precursor to the formation of ozone. Title III of the Act
authorized a new regulatory scenario for controlling
188 hazardous air pollutants (HAPs) from a wide
range of industrial and commercial sources. Title IV
of the Act established a new Acid Deposition Control
program principally aimed at reducing SO2 and NOx
emissions from older electric utility plants.
32-4
SO2 and NOx control under the 1990 Clean Air Act Prior
to the 1990 CAA, a large population of existing electric utility boilers, generally built before 1971, were
grandfathered and did not have to meet NSPS emission limits or comply with NSR requirements unless
they were significantly modified or upgraded. Coalfired utility boilers built between 1971 and 1978 were
required (by promulgation of New Source Performance Standards) to limit SO2 emissions to 1.2 lb/106
Btu heat input and compliance could be achieved by
utilizing low-sulfur coals. However, coal-fired utility
boilers built after 1978 were further required (by promulgation of additional New Source Performance
Standards) to install scrubbers to achieve between 70
and 90% SO2 removal efficiency.
Under the 1990 Amendments, Title IV of the Act
(Acid Deposition Control) established a new SO2 control program aimed at reducing emissions from all
existing electric utility boilers through an innovative
cap-and-trade program. The Acid Deposition Control
program (commonly referred to as the Acid Rain program) set a goal of reducing annual SO2 emissions by
10 million tons in a two-phased process. Phase I of the
SO2 program began in 1995 and initially affected 263
units at 110 mostly coal-burning electric utility plants
located in 21 eastern and mid-western states. Phase
II, which began in 2000, tightened the annual emissions
limits imposed on the Phase I units and set limitations
on smaller, cleaner plants fired by coal, oil, and natural
gas, ultimately impacting more than 2,000 total units.
Under the SO2 cap-and-trade program, an affected
unit must hold (own) one SO2 Allowance to cover each
ton of SO2 emitted in a given year. Existing units were
initially given a pre-determined allocation of yearly
Steam 41 / Environmental Considerations
The Babcock & Wilcox Company
allowances based on historical fuel consumption rates
(heat input) and a mandated SO2 emission rate (lb per
million Btu heat input). A source owner has various
options available to demonstrate compliance including: 1) reducing emissions through fuel switching, 2)
adding more control equipment or improving the performance of existing control equipment, or 3) acquiring (purchasing) SO2 allowances from other units. The
bottom line compliance measure is straight forward;
total SO2 emissions from a unit in any given year must
be covered by an equivalent number of SO2 allowances. Once an allowance is used it is retired and any
unused allowances may be sold or held (banked) with
certain restrictions for future use. The total number
of yearly SO2 allowances allocated nationwide under
Phase II of the program is fixed at 8.95 million tons
and new power plants do not receive allowances. This
effectively caps yearly SO2 emissions from utility boilers at 8.95 million tons and ensures that the mandated
reductions are maintained over time.
The Acid Rain program also mandated NOx emission reductions from all existing utility boilers through
a more traditional command-and-control approach
where different types of boilers or combustion equipment were required to meet specified performance levels (i.e., a NOx limit in pounds per million Btu of heat
input). The NOx command-and-control requirements
were also implemented in a two-phased process with
a goal of reducing utility boiler NOx emissions by 2
million tons from 1980 levels.
The EPA’s rules governing the Acid Rain program
are published in the Code of Federal Regulations,
under Title 40, Part(s) 72 through 78.
Further to the NOx reductions mandated under the
Acid Rain program, the EPA also implemented additional control measures (as authorized under Title I
of the Act) to reduce interstate transport of NOx emissions that contribute to ozone nonattainment problems
in the eastern part of the U.S. These additional NOx
control measures (referred to herein as the NOx Budget programs) are structured similarly to the SO2 capand-trade program discussed above. However, unlike
the SO2 program which applies to all utility boilers year
round, the NOx Budget programs only apply to specified sources in the eastern part of the U.S. during the
five month ozone season extending from May through
September. As of this writing, the EPA has implemented the broadest of these NOx Budget programs
through a SIP Call (request for State Implementation
Plans) mandating further NOx reductions from electric utility boilers and other large industrial sources
located in 21 eastern states and the District of Columbia (see Fig. 2).
For further details and current information regarding the SO2 and NOx trading programs see the following EPA Web page: www.epa.gov/airmarkets/
Control of air toxics under the 1990 Clean Air Act The
1990 CAA Amendments significantly changed the preexisting regulatory structure for addressing air toxics.
Prior to the 1990 amendments, the Act required the
EPA to identify and regulate, on a pollutant-by-pollutant basis, each non-criteria air pollutant that in its
judgment caused significant health risks. This regu-
Steam 41 / Environmental Considerations
latory approach was largely ineffective as the EPA
became involved in many legal, scientific, and policy
debates over which pollutants to regulate and how
stringently to regulate them. As a result, only seven
pollutants had been regulated by 1990.
The 1990 CAA redirected the EPA to impose tighter
controls for a broad range of air toxics through a twophase approach. The first phase requires the EPA to
develop technology-based standards for categories of
sources that have the potential to emit significant
quantities of 188 (originally 189) HAPs which were
specifically identified in the Act. The second phase
requires the EPA to impose further controls, beyond
the initial technology-based standards, as necessary
to address any remaining health risk concerns. Under the first phase, the EPA must develop Maximum
Achievable Control Technology (MACT) standards for
different classes or categories of sources that could be
considered major emitters of HAP as well as other
smaller area HAP sources. A major HAP source is defined as any type of stationary source with the potential to emit 10 tons per year of a single HAP or 25 tons
per year of a combination of HAPs. An area source is
defined to include smaller source categories (such as
dry cleaners, gas stations, etc.) that are not by themselves a major source, but may collectively emit HAPs
in sufficient quantities to warrant regulation. The
applicable MACT standard for a given type or category
of source must reflect emission performance levels that
are already being achieved in practice by the better
controlled, lower emitting units within a common
source category. As of this writing, the EPA has proposed or promulgated MACT standards for more than
80 different source categories including but not limited to industrial, commercial and institutional boilers and process heaters; combustion sources at kraft,
soda, and sulfite pulp and paper mills; and fossil fuelfired electric utility boilers. The EPA’s final MACT rules
Fig. 2 Area covered by NOx SIP Call is shown in gray.
32-5
The Babcock & Wilcox Company
for various categories of sources are published in the
Code of Federal Regulations, under Title 40, Part 63.
The 1990 CAA specifically directed the EPA to study
hazardous air emissions, including mercury, from electric utility plants and to regulate such emissions as
necessary to protect public health. In December 2000,
the EPA issued a formal determination that regulation of HAP emissions, principally mercury from coalfired electric utility boilers and nickel from oil-fired
utility boilers, was appropriate and necessary. As discussed later in this chapter in the mercury emissions
and control technologies section, several regulatory
options are being proposed to address mercury control as of the date of this publication.
For further details and current information regarding the HAP regulations, including source-specific
MACT standards and proposed alternatives for regulating mercury from electric utility boilers, see the following EPA Web page(s): www.epa.gov/ttn/atw/
index.html and www.epa.gov/mercury/
Pending legislation/regulation As of the date of this
publication, a number of U.S. Federal and State legislative and regulatory initiatives are underway to
further reduce air emissions from fossil fuel-fired
power plants. The most significant of the near-term
initiatives are addressed in an inter-related suite of
proposed rules collectively known as the Clean Air
Rules. This suite of rules includes the proposed mercury cap-and-trade program discussed later; proposed
rules to achieve further reductions in emissions of SO2
and NOx from power plants; and additional measures
to address ozone and fine particle pollution throughout the U.S. While the final form of these regulatory
initiatives can not be determined at the time of this
writing, the direction of future regulatory actions will
no doubt focus on achieving further improvements in
air quality in the most effective way possible. For further details and current information regarding these
initiatives and others, see the following EPA Web
page: www.epa.gov.
International regulations – air pollution control
The passage of the Clean Air Act in the U.S. in 1963,
marked the first enactment of air pollution control
legislation by a major industrial nation. Since that
time, air pollution control regulations have become
more widespread in industrial and developing nations,
particularly in Japan, Canada, and the European
Union.6,7 Many of the rapidly developing nations such
as Korea, Taiwan, China, and the countries of former
Eastern Europe are also aggressively controlling power
plant emissions as their rapidly growing economies
strain local ecosystems. As in the U.S., steam generating plants have been one focus of these regulatory
measures, and the most common emissions of concern
from combustion processes are SO2, NOx, particulates,
and air toxics. The detailed regulations continue to
evolve rapidly and are quite country specific. However,
two trends are widespread:
1. Allowable emission limits for controlled pollutants
will continue to decline with time.
2. A wider array of species will be considered for control.
32-6
Without attempting to be comprehensive, the following items provide a brief overview of worldwide
SO2 and NOx regulatory efforts. These items provide
a general indication of the range and application of
control measures.
Control approaches One or more of the following measures have typically been adopted to control emissions:
1. Emission standards These limit the mass of SO2,
NOx, or other pollutant emitted by volume, by heat
input, by electric energy output, or by unit of time
(hourly, daily, annually).
2. Percent removal requirements These specify the
portion of the uncontrolled emissions that must be
removed from the flue gas.
3. Fuel requirements Primarily aimed at SO2 control,
these either limit the type of fuel that can be
burned or the fuel sulfur content.
4. Technology requirements These typically indicate
the type of control technology specifically required
or indicate the use of the best available control technology or reasonably available control technology at
the time of installation. These requirements depend
in many cases on some level of economic feasibility.
The most widely used control approach is emission
standards, although this is usually combined with one
or more of the other approaches. Emissions from new
plants are usually more tightly controlled than emissions from existing capacity. Occasionally, older plants
are not controlled, although this is changing, especially with the application of national cap-and-trade
policies in the U.S. There have also been significant
discussions on the applicability of international capand-trade programs that will link two or more national
cap-and-trade programs together. The international
cap-and-trade programs are proposed in the European
Union (EU) Directive.
Emission control legislation and regulations
throughout the world are currently in a state of flux
as a variety of new and increasingly stringent regulations are phased in. Reference 6 provides a comprehensive and detailed summary of regulatory measures
and current trends as of the end of 2003. The resulting compilation is quite complex as countries and areas consider the most effective alternatives. Reference
7 provides more detail for NOx control.
Emissions standards worldwide are stated in a variety of units. See Appendix 1, Conversion Formulae
for Emission Units.
Kinds of pollutants, sources and impacts
Air pollutants are contaminants in the atmosphere
which, because of their quantity or characteristics,
have deleterious effects on human health and/or the
environment. The sources of these pollutants are classified as stationary, mobile or fugitive. Stationary
sources generally include large individual point
sources of emissions such as electric utility power
plants and industrial furnaces where emissions are
discharged through a stack. Mobile sources are those
associated with transportation activities. Fugitive
emissions generally include discharges to the atmosphere from conveyors, pumps, valves, seals and other
Steam 41 / Environmental Considerations
The Babcock & Wilcox Company
process points not vented through a stack. They also
include emissions from area sources such as coal piles,
landfills, ponds and lagoons. They most often consist
of particulates and occur in industry-related activities
in which the emissions are not collected.
The focus of this chapter is stationary emission
sources, particularly fired utility and industrial boiler
systems. Key pollutants from these sources are SO2,
SO3, NOx, CO and particulate matter. Another class
of emissions is called air toxics. These are potentially
hazardous pollutants that generally occur in only
trace quantities in the effluents from fired processes.
However, they are undergoing more intense examination because of their potential health effects.
Sulfur dioxide Most of the sulfur in fuel converts to
SO2 with small quantities of sulfur trioxide (SO3). The
main source of sulfur oxides is from the combustion
of coal, with lesser amounts from other fuels such as
residual fuel oil. Based upon the August 2003 revision of the U.S. EPA National Emissions Inventory
(NEI) program, the utility and industrial sectors
(smelters, iron and steel mills, refineries) remain the
largest emitters of sulfur oxides (see Table 3).8 Sulfur
oxides have been related to irritation of the human
respiratory system, reduced visibility, materials corrosion and varying effects on vegetation. The reaction
of sulfur oxides with moisture in the atmosphere has
been identified as contributing to acid rain.
Sulfur trioxide Some of the sulfur dioxide that forms
converts to sulfur trioxide (SO3). The typical conversion rate is 1% or less in the boiler. However, the catalytic process that is frequently used to control NOx levels has the undesirable side effect of converting additional SO2 to SO3, which can range from 0.5 to 2%
additional conversion. The SO3 readily combines with
water to form sulfuric acid (H2SO4) at flue gas temperatures less than 500F (260C). This acid can create
extremely corrosive conditions. The sulfuric acid condenses to form a fine mist when the flue gas passes
through a wet flue gas desulfurization system that is
used to remove sulfur dioxide (SO2). This sulfuric acid
mist contributes to the total stack particulate loading.
Such mist is extremely fine, less than 0.5 micron, and
very small amounts of this mist (5 ppm or less) can cause
visible, bluish stack plumes, even in the absence of solid
particulate.
Nitrogen oxides (NOx ) This category includes numerous species comprised of nitrogen and oxygen, although nitric oxide (NO) and nitrogen dioxide (NO2)
are the most significant in terms of quantity released
to the atmosphere. NO is the primary nitrogen compound formed in high temperature combustion processes where nitrogen present in the fuel and/or combustion air combines with oxygen. The quantity of
NOx formed during combustion depends on the quantity of nitrogen and oxygen available, the temperature, the intensity of mixing and the time for reaction.
Control of these parameters has formed the basis for
a number of control strategies involving combustion
process control and burner design. Based on the most
recent EPA emissions inventory, utilities account for
22% of NOx emitted in the U.S., with the transportation sector emitting 56%. Of the total utility NOx emisSteam 41 / Environmental Considerations
sions, approximately 90% comes from coal-fired boilers. The most deleterious effects come from NO2 which
forms from the reaction of NO and oxygen. NO2 also
absorbs the full visible spectrum and can reduce visibility. NOx has been associated with respiratory disorders, corrosion and degradation of materials, and
damage to vegetation. NOx has also been identified as
a precursor to ozone and smog formation.
Carbon monoxide This colorless, odorless gas is
formed from incomplete combustion of carbonaceous
fuels. CO emissions from properly designed and operated utility boilers are a relatively small percentage
of total U.S. combustion source CO emissions, most of
which come from the internal combustion engine in
the transportation sector. The primary environmental significance of CO is its effect on human and animal health. It is absorbed by the lungs and reduces
the oxygen carrying capacity of the blood. Depending on the concentration and exposure time, it can
cause impaired motor skills and physiological stress.
Particulate matter Solid and liquid matter of organic
or inorganic composition which is suspended in flue
gas or the atmosphere is generally referred to as particulate. Particle sizes from combustion sources are in
the 1 to 100 µm range, although particles smaller than
1 µm can occur through condensation processes.
Among the effects of particulate emissions are impaired visibility, soiling of surrounding areas, aggravation of adverse effects of SO2, and human respiratory problems.
PM10 and PM2.5 Subsets of particulate matter, PM10
is particulate matter 10 µm and finer and PM2.5 is particulate matter 2.5 µm and finer. Fine particles are
emitted from industrial and residential oil combustion
and from vehicle exhaust. Fine particles are also
formed in the atmosphere when gases such as SO2,
NOx and VOCs, emitted by combustion processes, are
transformed into fine particulate by chemical reactions
in the air (i.e., sulfuric acid, nitric acid, and photochemical smog). PM2.5 is considered to have more deleterious health affects than coarser particulate.
VOC Volatile organic compounds represent a wide
range of organic substances. These compounds con-
Table 3
2002 U.S. Emissions
U.S. EPA National Emission Inventory8
Category
Emissions (103 short tons)
SO2
NOx
VOC
TSP
Utility combustion
10,293
Industrial combustion 2,299
Other combustion
575
Industrial process
1,399
Transportation
696
Other
91
Total
15,353
Notes: SO2
NOx
VOC
TSP
4,699
52
2,870
170
725
790
1,000
7,418
11,452
7,231
356
883
21,102 16,544
695
269
405
1,127
515
19,142
22,153
Sulfur dioxide
Nitrogen oxides as NO2
Volatile organic compounds
Total solid particulate (PM-10)
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The Babcock & Wilcox Company
sist of molecules containing carbon and hydrogen, and
include aromatics, olefins and paraffins. A major
source is the refining and use of petroleum products.
Also included among VOCs are compounds derived
from primary hydrocarbons including aldehydes, ketones and halogenated hydrocarbons. The major
source of these compounds is the transportation and
the commercial/residential combustion sectors. VOCs
are environmentally significant because of their role
in the formation of photochemical smog through photochemical reactions with NOx. Control of VOCs has
been a primary means of addressing areas of ozone
nonattainment. Smog arising from VOC emissions can
cause respiratory problems, eye irritation, damage to
vegetation and reduced visibility.
Toxic air pollutants This is a large category of air
pollutants that could have hazardous effects.9 The
EPA had only promulgated standards for arsenic, asbestos, benzene, beryllium, mercury, radionuclides
and vinyl chlorides for certain defined industries before the passage of the 1990 Amendments to the Clean
Air Act. The 1990 Act first identified 189 toxic pollutants for which emissions are to be regulated. The list
includes a wide range of simple and complex industrial organic chemicals and a small number of
inorganics, particularly heavy metals. The EPA has
identified hundreds of categories of air toxics sources,
among which are municipal solid waste combustors, industrial boilers, and electric utility boilers. For these combustion sources, mercury has been the primary focus.
Mercury Present in only trace amounts in coal,
mercury is released during the combustion process as
elemental mercury, and is predominantly in the vapor phase at the exit of the furnace. Emissions from
utility plants are extremely low. While other pollutants are recorded in pounds per million Btu (mg/Nm3),
mercury emissions are typically six orders of magnitude less and are frequently expressed in units of
pounds per trillion Btu or µg/Nm. Fig. 3 indicates that
the utility emissions account for approximately onethird of the U.S. manmade emissions of mercury or
48 tons/year (43.5tm/year). (See Reference 10.)
Mercury in some chemical forms is very toxic. From
whatever source, mercury can find its way into water
sources where it can be converted into water soluble
species such as methyl-mercury by microorganisms and
accumulate in the fatty tissues of fish. Consumption of
contaminated fish is the main identified risk to humans.
Carbon dioxide During the 1980s, concern increased about the potential impact of carbon dioxide
(CO2) emissions from manmade sources. CO2 is one of
several so-called greenhouse gases which may impact
the climate and contribute to global warming. CO2 is
emitted from a variety of naturally occurring and
manmade sources including the combustion of all fossil
and hydrocarbon based fuels.
Greenhouse gas emissions in the U.S. totaled 1906
million metric tons in 2000, of which 83% or 1583
million metric tons was CO2. CO2 from the electric
power sector totaled 642 million metric tons or 33.6%
of total greenhouse gas emissions.11
Improving the power cycle efficiency (more power
from less fuel) and the use of fuels with less carbon
32-8
content are potential methods to address CO2 emissions from any combustion source. Another option is
separation and capture followed by sequestration.
However, technology similar to SO2 scrubbers or particulate collectors does not exist for carbon dioxide.
Although CO2 separation technologies exist, they are
at present not economically viable for the large volumes of flue gas produced by electric power generation. Geologic, terrestrial, or ocean sequestration have
their own technical and political challenges. Geologic
sequestration holds considerable potential, as the storage capacity is estimated to be centuries of emissions, and
this route may be the most environmentally acceptable.
Air pollution control technologies
The strategies for control of all emissions from a utility or industrial boiler are formulated by considering
design fuels, kind and extent of emission reduction mandated, and economic factors such as boiler design, location, new or existing equipment, age and remaining life.
SO2 control strategies and technologies SO2 emissions
from coal-fired boilers can be reduced using pre-combustion techniques, combustion modifications and
post-combustion methods.
Pre-combustion These techniques include the use of
natural gas or low sulfur oil in new units or the use of
cleaned (beneficiated) coal or fuel switching in existing units. By using natural gas, sulfur emissions can
be reduced to almost zero while the use of low sulfur
oil will minimize SO2 emissions. While the low sulfur
content of oil and gas is advantageous, the price volatility and availability of these fuels make them less attractive. Switching to oil and gas in existing boilers
requires attention be given to receiving equipment,
storage facilities, combustion equipment including
safety systems and boiler design. In the case of new
systems, oil or gas firing can significantly reduce steam
system capital costs. Even switching from one coal to
another lower sulfur coal can have a dramatic impact
on fuel handling, combustion and particulate collection equipment. These effects are explored in more
detail in Chapters 21 and 44.
Other
Hazardous Waste
Combustors
Utility Plants
Chlor-Alkali
Plants
Medical
Waste
Incinerators
Commercial
and
Industrial Boilers
Municipal Waste
Combustors
Fig. 3 Anthropogenic (manmade) emissions of mercury in the U.S.
Steam 41 / Environmental Considerations
The Babcock & Wilcox Company
Combustion modifications These techniques are primarily used to reduce NOx emissions but can also be
used to control SO2 emissions in fluidized-bed combustion where limestone is used as the bed material. The
limestone can absorb up to 90% of the sulfur released
during the combustion process. (See Chapter 17.)
Sorbent injection technologies Sorbent injection, while
not involving modification of the combustion process,
is applied in temperature regions ranging from those
just outside the combustion zone in the upper furnace
to those at the economizer and flue work following the
air heater. Sorbent injection involves adding an alkali
compound to the coal combustion gases for reaction
with the SO2. Typical calcium sorbents include limestone [calcium carbonate (CaCO3)], lime (CaO), hydrated lime [Ca(OH)2] and modifications of these compounds with special additives. Sodium or magnesium
based compounds are also used.
Wet and dry scrubbing technology Worldwide, wet and
dry scrubbing or flue gas desulfurization (FGD) systems are the most commonly used technologies in the
coal-fired electric utility industry. 2003 data indicate
that in the U.S. more than 30% of the coal-fired utility capacity have SO2 emission control. In contrast,
more than 90% of coal-fired utility boilers in Germany
and Japan have SO2 control. Both wet and dry scrubbing use slurries of sorbent and water to react with
SO2 in flue gas, producing wet and dry waste products.
(See Chapter 35.)
In the wet scrubbing process, a sorbent slurry consisting of water mixed with limestone, lime, magnesium promoted lime or sodium carbonate (Na2CO3) is
contacted with flue gas in a reactor vessel. Wet scrubbing is a highly efficient (> 97% removal at calcium/
sulfur molar ratios close to 1.0), well established technology which can produce usable byproducts.
Dry scrubbing involves spraying an aqueous sorbent slurry into a reactor vessel so that the slurry
droplets dry as they contact the hot flue gas [~300F
(~149C)]. The SO2 reaction occurs during the drying
process and results in a dry particulate containing
reaction products and unreacted sorbent entrained in
the flue gas along with flyash. These materials are
captured downstream in the particulate control equipment. Dry scrubbing is a well established technology
with considerable operational flexibility. The waste
residue is dry.
NOx control technologies NOx emissions from fossil
fuel-fired industrial and utility boilers arise from the
nitrogen compounds in the fuel and molecular nitrogen in the air supplied for combustion. Conversion of
molecular and fuel nitrogen into NOx is promoted by
high temperatures and high volumetric heat release
rates found in boilers. The main strategies for reducing NOx emissions take two forms: 1) modification of
the combustion process to control fuel and air mixing,
and reduce flame temperatures, and 2) post-combustion treatment of the flue gas to remove NOx. (See
Chapters 11, 14, 16, and 34.)
Combustion modification This approach to NOx reduction can include the use of low NOx burners, combustion staging, gas recirculation or reburn technology.
Low NOx burners slow and control the rate of fuel and
Steam 41 / Environmental Considerations
air mixing, thereby reducing oxygen availability in the
ignition and main combustion zones. Low NOx burners
can reduce NOx emissions by 50% or more, depending
upon the initial conditions, are relatively low cost, and
are applicable to new plants as well as retrofits.
Staged combustion uses low excess air levels in the
primary combustion zone with the remaining (overfire) air added higher in the furnace to complete combustion. In some cases, the primary combustion zone
may be operated substoichiometrically. Significant NOx
reductions are possible with staged combustion, although reducing zones and potential for corrosion and
slagging exist.
Flue gas recirculation reduces oxygen concentration and combustion temperatures by recirculating
some of the flue gas to the furnace without increasing total net gas mass flow. Large NOx reductions are
possible with oil and gas firing while only small reductions at best are possible with coal firing. Modifications to the boiler in the form of ducting and an efficiency penalty due to power requirements of the recirculation fans can make the cost of this option higher than
some of the other in-furnace NOx control methods.
Reburning is a technology used to reduce NOx emissions in selected applications. In reburning, 75 to 80%
of the furnace fuel input is burned in the primary combustion zone with minimum excess air. The remaining fuel (gas, oil or coal) is added to the furnace above
the primary combustion zone. This secondary combustion zone is operated substoichiometrically to generate hydrocarbon radicals which reduce NO formed in
the initial combustion to N2. The combustion process
is then completed by adding the balance of the combustion air through overfire air ports in a final burnout zone further up the furnace.
Post-combustion The two main post-combustion
techniques for NOx control are selective noncatalytic
reduction (SNCR) and selective catalytic reduction
(SCR). In SNCR, ammonia or other compounds such
as urea (which thermally decomposes to produce ammonia) are injected downstream of the combustion
zone in a temperature region of 1400 to 2000F (760
to 1093C). SCR systems remove NOx from flue gases
by reaction with ammonia in the presence of a catalyst (see Chapter 34). SCR is being used worldwide
where high NOx removal efficiencies are required in
gas-, oil- or coal-fired industrial and utility boilers.
Particulate control technologies Particulate emissions from boilers arise from the noncombustible, ash
forming mineral matter in the fuel that is released
during the combustion process and is carried by the
flue gas. Another source of particulate is the incomplete combustion of the fuel which results in unburned
carbon particles. A brief description of the principal
options for particulate emissions control in industrial
and utility boilers follows while Chapter 33 provides
an in-depth discussion.
Coal cleaning Historically, physical coal cleaning has
been applied to reduce mineral matter, increase energy content and provide a more uniform boiler feed.
Although reduction in flue gas particulate loading is
one of the potential benefits, coal cleaning has been
driven by the many other boiler performance benefits
32-9
The Babcock & Wilcox Company
related to improved boiler maintenance and availability and, more recently, the reduction in SO2 emissions.
Mechanical collectors These are generally cyclone
collectors and have been widely used on small boilers
when less stringent particulate emission limits apply.
Cyclones are low-cost, simple, compact and rugged devices. However, conventional cyclones are limited to collection efficiencies of about 90% and are poor at collecting the smallest particles. Improvements in small particle collection are accompanied by high pressure drops.
Fabric filters These filters, also commonly referred
to as baghouses, are available in a number of designs
(reverse air, pulse jet, and shake/deflate), each having advantages and disadvantages in various applications. Applications include industrial and utility
power plants firing coal or solid wastes, plants using
sorbent injection and spray dryer FGD, and fluidizedbed combustors. Collection efficiency can be expected
to be at least 99.9% or greater. Fabric filters have the
potential for enhancing SO2 capture in installations
downstream of sorbent injection and dry scrubbing
systems as discussed in Chapter 35.
Electrostatic precipitators (ESP) ESPs are available
in a broad range of sizes for utility and industrial
applications. Collecting efficiency can be expected to
be 99.8% or greater of the inlet dust loading. ESPs are
considered to be less sensitive to plant upsets than
fabric filters because their materials are not as sensitive to maximum temperatures. They also have a very
low pressure drop. ESP performance is sensitive to
flyash loading, ash resistivity and coal sulfur content.
Lower sulfur concentrations in the flue gas can lead
to lower ESP collection efficiency. ESPs tend to collect
coarser particulate more easily, whereas a fabric filter tends to have a more uniform collection efficiency
across the particle size range. Therefore, a fabric filter has higher collection efficiency of fine particulate
than an ESP. The desire to further control sulfuric
acid mist emissions and very fine flyash has led to the
utilization of wet ESPs downstream of wet flue gas desulfurization systems.
Mercury emissions and control
technologies
Regulatory considerations
As discussed earlier in this chapter, mercury emissions are regulated under the hazardous air pollutants (HAPs) sector of the Clean Air Act. Mercury
emission regulations are already in place for municipal solid waste (MSW) combustors, medical waste incinerators, and cement plants with the following levels as of this writing:
Source
MSW combustion
Medical waste
incinerators
Cement plants
Regulation
0.08 mg/DSCM or 85% reduction
0.55 mg/DSCM or 85% reduction
0.12 mg/DSCM (existing plants),
0.056 mg/DSCM (new plants)
Note: DSCM = dry standard cubic meter (at 32F/0C)
32-10
The EPA has also determined that it is both appropriate and necessary to regulate utility units for emissions of mercury. As of this writing, the EPA has proposed several regulatory alternatives for controlling
mercury emissions from new and existing electric utility boilers which generally fall into two categories: 1)
MACT standards as discussed above, or 2) alternate
performance standards coupled with a market based
cap-and-trade program. EPA has promulgated rules
for a cap-and-trade program where mercury reductions would occur over a two-phase process. When
fully implemented by 2018, this would result in estimated mercury emission reductions of 33 tons (30.0
tm) per year or approximately 70%. As of this writing,
the pros and cons associated with the regulatory alternatives are the subject of extensive debate and the
final outcome and timing are uncertain. However, mercury will be controlled and emissions reduced over time.
Mercury in U.S. coals
Coals vary in mercury content by rank, seam, mine,
and mine internal location. Table 4 summarizes the
mercury content data obtained for U.S. bituminous,
subbituminous and lignite coals fired at U.S. utilities
as part of an EPA study (see Reference 12). There are
only modest differences between the average mercury
contents of the three ranks of coal. However, the variation in mercury content among coals within a given
rank is much larger.
Mercury in coal combustion flue gas
Mercury appears in coal combustion flue gas in both
the solid and gas phases (particulate-bound mercury
and vapor-phase mercury, respectively). Due to the
high volatility of mercury and many of its compounds,
most of the mercury found in flue gas is vapor-phase.
Vapor-phase mercury, in turn, can appear as elemental mercury (elemental, metallic mercury vapor) or as
oxidized mercury (vapor-phase species of various compounds of mercury). The form of mercury present,
commonly referred to as speciation, is a key factor in
the development of emissions control strategies.
Mercury speciation and emissions data have been
gathered under an EPA study, wherein a subset of
the U.S. boiler population was selected for flue gas
emissions sampling on the basis of fuel type, boiler configuration, particulate control device, and SO2 control
technology (see Reference 12). This EPA study is
known as the Information Collection Request (ICR).
Flue gas sampling, in triplicate, was performed at
approximately 84 U.S. plants to quantify total mercury and mercury speciation at the inlet and outlet of
the last emission control device. The EPA Preliminary
Test Method 003 [PRE-003: Standard Test Method for
Elemental, Oxidized, Particle-Bound, and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method)] was used to
determine the particulate-bound and vapor-phase
mercury emissions. In the Ontario Hydro Method, flue
gas samples are withdrawn isokinetically from the
flue. The mercury species are collected on a quartz
fiber filter, in potassium chloride (KCl) solutions, and
in acidic peroxide and acidic potassium permanganSteam 41 / Environmental Considerations
The Babcock & Wilcox Company
Coal Type
Bituminous
Subbituminous
Lignite
lb Hg/trillion Btu (HHV)
Number of
Analyses
Low
High Median
27,884
8,193
1,047
0.04
0.39
0.93
103.81
71.08
75.06
8.59
5.74
10.54
ate (KMnO4) solutions. Mercury speciation is reported
on the basis that the oxidized form of mercury is collected in the KCl impingers, and the elemental form
of mercury is collected in the peroxide and potassium
permanganate impingers.
Results of these extensive studies indicated that the
speciation of vapor-phase mercury depends on coal
type and other factors. Eastern U.S. bituminous coals
tend to produce a higher percentage of oxidized mercury than do western subbituminous and lignite coals.
Western coals have low chloride content compared to
typical eastern bituminous coals. It has been recognized for several years that an empirical relationship
holds between the chloride content of coal and the
extent to which mercury appears in the oxidized form.
Fig. 4 illustrates the relationship between coal chlorine content and vapor-phase mercury speciation for
the plants and coals tested in the EPA study. An important reason for the significant uncertainty (scatter) is that mercury oxidation proceeds by both homogeneous (gas-to-gas) and heterogeneous (gas-to-solid)
reaction mechanisms. Boiler convection pass and air
heater temperature profiles, flue gas composition,
flyash characteristics, and the presence of unburned
carbon have all been shown to affect the conversion
of elemental mercury to oxidized mercury species.
Table 5 provides a summary of general mercury speciation by coal type.
Mercury control technologies
For industrial sources, such as MSW combustors,
the typical mercury control technology is activated
carbon injection in conjunction with a spray dryer
FGD system and fabric filter. Activated carbon injection is used to reduce both mercury and dioxin emissions. The system is comprised of a series of injection
nozzles located in the flue gas stream between the last
boiler heat trap (economizer or air heater) and the entrance to the spray dryer absorber (SDA). At this location, the injected carbon particles adsorb both mercury and dioxin onto their surfaces by direct contact.
When the carbon particles become trapped in the downstream fabric filter, additional adsorption takes place. A
typical carbon injection rate is 0.2 lb (0.09 kg) of carbon
per ton of MSW combusted. Thus, for a 750 t/d (680 tm/
d) refuse boiler, approximately 150 lb (68 kg)/day of
activated carbon would be used. Long-term experience
reveals that mercury reduction without carbon injection
averages around 70% for a system with only a spray
Steam 41 / Environmental Considerations
1. Choice of a coal with as low a mercury concentration as possible. The degree to which the coal has
been characterized and represents the inlet conditions for the emissions control devices is the first
step in setting the expectations for equipment
performance. The potential effectiveness of emission control devices is influenced most directly by
the form of the mercury, either solid or vapor
phase, and the vapor phase mercury speciation,
elemental mercury versus oxidized mercury. The
presence of a selective catalytic reduction system
(SCR) for NOx emission control upstream of the
particulate control device tends to increase the
oxidized mercury present, which is subsequently
easier to control in a downstream FGD system.
2. Use of a suitably injected sorbent for mercury capture, such that the sorbent particulate matter is
captured with the flyash. Powdered activated carbon is the most likely sorbent and can be effective
for both elemental and oxidized mercury capture,
though the costs can be significant. Typically, the
amount of activated carbon needed with downstream fabric filtration is less than that required
when using electrostatic precipitation. Flyash from
coal-fired utility boilers frequently is sold for
byproduct uses such as cement manufacturing.
However, flyash contaminated with activated carbon is generally not marketable. One solution is
to inject the powder activated carbon downstream
of the primary dust collector and add a separate
dust collector to trap the injected activated carbon.
100
% Hg as Elemental Hg
Table 4
Mercury in Selected U.S. Coals12
dryer FGD with fabric filter and about 90% with carbon injection added. Most of the mercury produced by
these MSW combustors is oxidized mercury.
For utility coal-fired boilers, the development of
mercury emissions control technology in the U.S. over
the past decade has progressed from a very limited
database to one in which utilities, various government
agencies, and system suppliers have increasingly
quantified various parameters that influence mercury
emissions control. This work is ongoing and reflects
the complexity of the measurement and control issues.
There are three basic methodologies for controlling
mercury stack emissions from coal-fired power plants:
50
0
10
100
1000
CI in Coal (ppm, dry basis)
10000
Fig. 4 Relationship between coal mercury content and mercury
speciation for U.S. EPA Information Collection Request.
32-11
The Babcock & Wilcox Company
Table 5
Typical Mercury Speciation by Coal Type
Coal Type
Bituminous (Eastern U.S.)
Bituminous (Western U.S.)
Subbituminous (Powder River Basin)
Lignite
Relative Content
Mercury
Chlorine
Intermediate
Low
Low
High
3. Use of the dry or wet FGD system to provide substantial mercury removal from the gas stream.
This approach is particularly suitable if the vapor
phase mercury contains a relatively high proportion of oxidized mercury species.
Mercury capture in conventional
coal-fired systems
Mercury removal efficiency across air pollution control devices at existing U.S. coal-fired plants was also
quantified under EPA’s ICR study.12 Average mercury
removal for bituminous coals was higher than that
achieved for the subbituminous coals and lignites. This
is due to the higher percentage of oxidized mercury
produced by eastern coals, but also may result, in part,
from differences in flyash properties and the tendency
of bituminous coals to produce higher levels of unburned carbon.
FGD systems Both wet and spray dryer FGD systems perform better at removing mercury with bituminous coal than with the low rank fuels. The difference is due almost entirely to the higher percentage
of oxidized mercury produced by the bituminous coals.
Oxidized mercury, typically mercuric chloride, is
soluble in water, making it amenable to removal in
SO2 scrubbers. Elemental mercury, insoluble in water, passes through most scrubbers. In the scrubber,
the soluble mercury species react with the slurry to
produce insoluble mercuric sulfide that is collected as
a solid waste byproduct. There is a growing body of
evidence that a phenomenon known as mercury reemission can exist in a wet FGD system. Some of the
captured oxidized mercury is actually reduced back
to elemental mercury and released into the outlet flue
gas. The Babcock & Wilcox Company (B&W) has developed a patented additive for wet FGD systems to
minimize re-emission.
SCR systems The same catalysts that reduce NOx
to N2 in SCR systems also help oxidize elemental mercury. As the flue gas passes through the SCR reactor
and over the catalyst, a portion of the elemental mercury is converted to mercury oxidized species, for example mercuric chloride and mercury oxides, which
can then be more readily removed in the FGD system.
The current data suggests that the presence of HCl
in the flue gas is needed for mercury oxidation to occur across the SCR.
Fabric filter systems Fabric filters tend to remove
significantly more mercury than do ESPs. Both systems are capable of high-efficiency removal of particu32-12
High
Intermediate
Low
Low
Primary Mercury
Form in Flue Gas
Oxidized
Mixture
Mixture, more elemental
Primarily elemental
late-bound mercury. Fabric filters may perform better on the same flue gas by providing more intimate
contact between the flue gases and flyash as the flue
gases pass through the filter cake on the filter bags.
This intimate contact may promote the adsorption of
mercury species onto the flyash or unburned carbon
particles in the filter cake. While providing many insights into the behavior of mercury species in coal-fired
systems, it should be noted that the EPA ICR data are
subject to a variety of limitations. The individual plant
data represent a brief period in time and give little insight into the variability of mercury emissions due to
variability in coal properties, impacts of plant operating conditions, or mercury sampling uncertainties.
Enhanced mercury capture
Numerous other studies have been and continue to
be conducted by B&W and others to shed additional light
on the behavior of mercury in coal-fired systems, and to
develop cost-effective approaches to its control.
Powdered activated carbon (PAC) Many studies have
focused on the injection of some form of PAC. Adsorption is a technique that has often been successfully
applied for the separation and removal of trace quantities of undesirable components. PAC injection is used
to remove mercury in municipal waste combustor exhaust gases, as discussed above. Although this approach appeared attractive for coal-fired boilers in
early work, the economics of high injection rates can
be prohibitive when applied to these plants. More refined studies are now in progress to define more precisely what can and can not be achieved with PAC.
Other studies seek to enhance PAC technology by
impregnation with additives such as halides to yield
improved chemisorption of the mercury species that
may be present.
Enhanced scrubbing As noted above, conventional
emissions control system components are capable of
removing oxidized mercury due to its water solubility. A variety of advanced technologies are currently
under development to enhance the performance of
these systems. Some of these increase the effectiveness
of the wet scrubbing systems in capturing the mercury
once it is in the soluble state. Others introduce oxidizing agents to the flue gas to increase the conversion of
elemental mercury to soluble oxidized species.
Commercial demonstration Efforts to develop mercury emission control technology have progressed to
full-scale limited-term demonstration tests. During
2001, full-scale PAC injection tests were run at Alabama Power’s Plant Gaston and at We Energies’ PleasSteam 41 / Environmental Considerations
The Babcock & Wilcox Company
ant Prairie Power Plant. At about the same time, B&W
conducted full-scale tests of its enhanced wet FGD process at both Michigan South Central Power Agency’s
Endicott Station and at Cinergy’s Zimmer Station.
Such demonstrations are an important step in gaining commercial acceptance of the technologies. As of
this writing, additional testing is ongoing.
Water pollution control
U.S. legislation – Clean Water Act
In 1972, the U.S. Congress enacted landmark legislation that greatly expanded existing laws designed
to control water pollution. Commonly referred to as the
Clean Water Act (CWA),13 the Federal Water Pollution Control Act of 1972 and successive amendments,
the Clean Water Act of 1977, and the Water Quality
Act of 1987 provide the basic framework for protecting the quality of surface waters in the United States.
The stated objective of the CWA is to restore and maintain the chemical, physical and biological integrity of
the nation’s waters.
Two significant elements of the 1972 Act were the
creation of the National Pollution Discharge Elimination System (NPDES), a permitting program to regulate pollutant discharges from industrial and municipal sources, and the establishment of technologybased end of pipe effluent standards for specified industries and processes.
Requirements under the Act The NPDES permit program requires that every industrial or municipal facility or other point source discharging into public waters
obtain a NPDES permit. The NPDES program also
regulates wet weather discharges including storm water runoff associated with many industrial activities.
NPDES permits include specific numerical limits for
a wide range of conventional, toxic and other nonconventional pollutants to ensure that discharges to
receiving waters are protective of human health and
the environment. NPDES permits may contain technology-based effluent limits (generally industry/process specific standards), water quality-based effluent
limits (as may be necessary to protect the quality of
the receiving waters according to designated use classifications), or a combination of both.
The intent of technology-based effluent limits is to
establish a minimum level of treatment or control of
pollutants in point source discharges using available
treatment technologies. In 1982, the EPA promulgated technology-based effluent limits and pretreatment standards for 21 major industrial categories including new and existing steam power facilities [Note:
pretreatment standards apply to any indirect discharges to publicly owned treatment works (POTWs)
that are not otherwise covered under a facility’s
NPDES discharge permit]. The key effluent limits
applicable to steam power plants are summarized in
Table 6. The detailed requirements are set forth in the
Code of Federal Regulations – 40 CFR Part 423.
Another provision of the CWA, initially focused on
large steam electric facilities, required the EPA to develop regulations governing the capacity, location,
Steam 41 / Environmental Considerations
design and construction of water intake structures
used to draw large volumes of cooling water from
lakes, rivers, estuaries and oceans. This CWA requirement is unique in that it applies to the intake and not
the discharge of water. The major goal of the requirement is to protect aquatic life by minimizing the impingement and entrainment of fish and other organisms into cooling water systems. Phase I rules, applicable to new utility facilities with a water intake flow
of greater than two million gallons per day and using
25% or more for cooling purposes, were promulgated
in December 2001 (Re: 40 CFR Part 125). Phase II
rules governing cooling water intake structures at
existing electric utility plants withdrawing 50 million
gallons or more of water per day were promulgated
in July of 2004. Phase III rules governing water intake structures at certain other existing utility and industrial facilities (not covered under the Phase II rules)
were proposed in November of 2004 and are due to
be finalized by June of 2006.
Visit the EPA’s home page on the World Wide Web
at www.epa.gov for further information regarding the
CWA and related regulatory programs.
Power plant discharge sources
The following describes the principal aqueous discharge streams from utility power plants.
Once-through cooling water Water from rivers,
lakes or oceans is used to absorb heat from the steam
condenser. The cooling water exiting the steam condenser is at an elevated temperature and can be returned to the source or pumped to a cooling tower for
evaporative cooling before being returned to the steam
condenser. In the former case, the cooling water contains significant concentrations of only one principal
regulated pollutant, total residual chlorine (TRC),
which arises out of chlorine addition for condenser
fouling control. The duration of each chlorination
event is limited. The concerns over TRC discharge
include toxicity to living organisms and the generation of halogenated hydrocarbons.
Cooling tower blowdown When the heated cooling
water from the steam condenser is cooled in an evaporative cooling tower, a buildup of dissolved solids and
suspended matter occurs. Most of this buildup is removed from the system by cooling tower blowdown.
Some of the suspended matter can settle out in the
cooling tower basin and is removed at infrequent intervals. All of the dissolved solids and the remaining
suspended solids are removed largely by cooling tower
blowdown. Blowdown flow is adjusted to keep the concentration of dissolved and suspended solids below the
limits required to control condenser tube fouling and
corrosion. Other sources of chemical pollutants in
blowdown include chlorine and organic chemicals for
control of biofouling, corrosion inhibitors (consisting
of chromate, zinc, polyphosphates, etc.), chemicals for
scale control and products of corrosion. Some of these
maintenance chemicals appear on the EPA’s regulated
toxic pollutants list and none are permitted to be
present in detectable levels in cooling tower blowdown
after treatment (except for chromium and zinc, which
are separately regulated).
32-13
The Babcock & Wilcox Company
Table 6
Aqueous Discharge Limits for
New Steam Power Generating Systems (Note 4)
Source and Pollutant
(Note 1)
NSPS Effluent Limits, mg/l
(Notes 2 and 3)
Maximum Average
All discharges
pH (unitless)
6 to 9
PCBs
No discharge
Low volume waste (Note 5):
TSS
100
30
OG
20
15
Chemical metal cleaning
wastes:
TSS
100
30
OG
20
15
Copper
1.0
1.0
Iron
1.0
1.0
Bottom ash transport water:
TSS
100.0
30.0
OG
20.0
15.0
Once-through cooling water:
Total residual chlorine (TRC)
0.2
Free available chlorine
0.5
0.2
Cooling tower blowdown:
Free available chlorine
0.5
0.2
Zinc
1.0
1.0
Chromium
0.2
0.2
Other 126 priority
pollutants
No detectable amount
Coal pile runoff:
TSS (1980)
50
Notes:
1. Nomenclature: TSS − total suspended solids; OG − oil
and grease.
2. New Source Performance Standards.
3. 30 day rolling daily average (Average); maximum any
one day (Maximum).
4. Adapted from Reference 1.
5. Low volume wastes include ion exchange, water
treatment, evaporator blowdown, boiler blowdown,
lab and floor drains, plus FGD waste water.
Ash handling water waste Ash produced from the
combustion of fuel, whether oil or coal, is collected at
different points in the combustion process. Flyash is
the finer size ash collected by particulate collection
systems and bottom ash is removed from hoppers at
the furnace bottom. Additional hoppers at intermediate points also accumulate ash. In many cases, ash is
moved from these points with sluice water, which then
goes to a settling pond and can typically contain 5%
suspended solids by weight.
The ash settling pond overflow contains dissolved
and suspended solids, the quantities of which will
depend on the source of the ash, the type of combustion process and the point from which it is extracted
from the combustion process. Coal ash contains, in
addition to the eight or nine major elemental constitu-
32-14
ents, a number of trace elements that can appear in
pond overflow and which may need to be treated.
Coal pile runoff Open storage of large quantities of
coal is required for an uninterrupted fuel supply to
utility plants [on the average, 800 to 2400 yd3 (611 to
1834 m3) per megawatt of rated capacity is kept on
hand]. The water and oxygen from the air react with
the minerals in bituminous coal to produce a leachate
contaminated with ferrous sulfate and sulfuric acid.
The low pH from the acid accelerates dissolution of
many of the metals present in the coal minerals.
FGD blowdown In wet FGD systems, a portion of
the absorber slurry that is sprayed into the flue gas
stream to remove SO2 is removed from the absorber
tank for dewatering. In the dewatering process, the
solid reaction products are separated from the liquor.
The liquor is recycled to the absorber tank where additional sorbent is added. Recycling of the liquor can
result in chloride buildup which, in turn, can cause
increased corrosion to the alloys in the system. This
buildup can be controlled by the loss of liquor retained
in the dewatered sludge or by a blowdown. An aqueous blowdown discharge would typically contain calcium sulfate, calcium sulfite and calcium chloride. Also,
depending on flyash carryover, traces of metal ions
could also be present. In setting effluent limitations
in 1982, the EPA reserved regulating FGD aqueous
discharge to a future date.
Metal cleaning wastes These aqueous wastes can
arise from either chemical or nonchemical cleaning of
metal heat transfer surfaces in the boiler.
Chemical metal cleaning uses chemical solvents for
water-side cleaning of boiler system components to
remove corrosion products. Cleaning intervals are
measured in years for large utility boilers, and produce
three to four boiler water volumes [20,000 to 100,000
gal (75,707 to 378,533 l)] of waste water per cleaning.
The composition of the waste solvents depends on the
construction material of the boiler system, but largely
consists of iron with lesser amounts of copper, nickel,
zinc, chromium, calcium and magnesium. The disposal
method for the spent solvent depends on the type of
chemical cleaning solvents used. When hydrochloric
acid based solvents are used, spent solvent is treated
on-site by neutralization and is discharged subject to
the effluent limits in Table 6 or more stringent water
quality standards. With approval from appropriate
regulating bodies, organic-based solvent wastes are
often incinerated in other operating boilers at the site.
The metals in the chemical cleaning wastes are retained with the normal boiler ash.
Nonchemical water cleaning is used to remove fireside deposits by means of high pressure jets of water.
The waste water can contain the same metals and
pollutants contained in the ash deposits being removed. Because the deposit composition varies with
location in the boiler, the wash water composition will
depend on the location of the area being cleaned.
These waste waters may be classified as either low volume wastes or metal cleaning wastes and are treated
according to the corresponding effluent limits.
Low volume wastes These include discharges from
ion exchange water treatment, evaporator blowdown,
Steam 41 / Environmental Considerations
The Babcock & Wilcox Company
boiler blowdown, cooling tower basin cleaning, laboratory and floor drains, and drains and losses from
house service water systems. FGD blowdown is also included until the EPA develops specific regulations for this
stream. By EPA definition, low volume wastes are those
from all sources taken collectively as if they were from
one source. Excluded are those wastes for which specific
effluent limits are established.
Water pollution control technologies
The technologies for waste water treatment used to
meet limits for discharge include clarification and filtration.
Clarification This process is used to settle out larger
suspended particles and condition smaller colloidal particles to make them settle and allow filtration for removal. A pond, reservoir or tank is used to allow larger
particles to settle in a matter of hours. The finer particles overflow and are made to settle more quickly by
the addition of chemical agents, coagulants and polymers that cause agglomeration to sizes large enough
to settle out of suspension.
Filtration This uses a porous barrier across flowing
liquid to remove suspended materials. Filtration can
be used to supplement clarification and permits reducing suspended solids to the parts per million level.
Filter types include sand filters that are generally slow
and do not handle fine clay well. Preconditioning with
coagulants can improve filtration rates. Dual media
filters improve on sand filters by superimposing a
coarse, granular material over the fine bed. This allows more of the filter bed to be used, reduces head
loss, and provides higher flow rates and longer operating cycles before cleaning.
As required, and with approvals from appropriate
regulating bodies, final waste stream pH is controlled
by combining various plant streams to provide a neutral pH product. Where needed, acid or alkali addition can be used to achieve the final pH. Other treatments are also available to address other criteria pollutants where concentration warrants.
In selected cases, zero discharge water management
is provided which does not return any waste water to
water sources. Effectively all water brought into the
plant is evaporated through cooling towers, ponds,
evaporators, or the stack. Residual solids are then sent
to disposal.
Solid waste disposal
The Resource Conservation and Recovery Act
The rapid growth of industrial activity and use of
consumer goods by society have resulted in an explosive growth in the generation of solid wastes. The EPA
has estimated that over 100 million tons of fossil fuel
combustion wastes are generated annually in the
U.S., principally from coal ash residues generated at
utility power plants.
In 1976, the U.S. Congress passed the Resource
Conservation and Recovery Act (RCRA) 14 as an
amendment to the Solid Waste Disposal act of 1965.
The RCRA establishes the regulatory framework to enSteam 41 / Environmental Considerations
sure that solid and hazardous wastes are properly
managed to protect human health and the environment. Subtitle C of the Act establishes a comprehensive management system to regulate hazardous waste
from the time it is generated until its final disposal,
commonly referred to as a cradle to grave approach.
Subtitle D of the Act directs states to develop and
implement solid waste management plans and regulations to promote environmentally sound management practices for non-hazardous wastes which address landfill performance standards and recycling/
beneficial use programs. Subtitle I of the Act regulates
petroleum products and other hazardous substances
that are stored in underground tanks.
As originally drafted, RCRA did not clearly address
how fossil fuel combustion wastes should be regulated
and in 1980, the U.S. Congress passed the Solid Waste
Disposal Act Amendments which included what is
commonly referred to as the Bevill Exemption. The
Bevill Exemption excluded, among other things, fossil fuel combustion wastes from being regulated as
hazardous waste under RCRA Subtitle C, pending
completion of a report to Congress and a formal determination by the EPA as to whether regulation under Subtitle C is warranted.
In August 1993, the EPA published the first of two
regulatory determinations concerning fossil fuel combustion wastes. This first determination applied only
to separately managed, large volume wastes including flyash, bottom ash, boiler slag and flue gas emission control waste generated at coal-fired electric utilities and independent power facilities. The EPA determined that if managed properly, these materials
would remain exempt from regulation as a hazardous waste under Subtitle C of the RCRA. The EPA’s
second ruling, published in May 2000, generally extended the hazardous waste exemption to other defined categories of low volume wastes generated at
electric utilities and industrial facilities that combust
coal, oil, natural gas, petroleum coke or mixtures of
coal and other fuels. These low volume wastes, when
properly co-managed with large volume combustion
wastes, would typically include (but are not limited to)
coal pile runoff, coal mill rejects/pyrite, water treatment sludge, and boiler chemical cleaning waste.
However, if certain wastes are managed independently and exhibit the characteristics of a hazardous
waste, they are subject to the hazardous waste regulations. For more detailed information refer to the
EPA’s final regulatory determination published in the
Federal Register on May 22, 2000 (65 FR 32213).
While the EPA has concluded that fossil fuel combustion wastes do not warrant regulation as hazardous waste, the agency further determined that national
non-hazardous waste standards under RCRA Subtitle
D are needed for coal combustion wastes disposed in
landfills and surface impoundments, or used in minefill
applications. However, national regulations have yet
to be developed under Subtitle D; therefore, the management and regulation of combustion waste products
are currently handled by the individual states.
Finally, the EPA has concluded that beneficial uses
of coal combustion waste (other than for minefill) pose
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The Babcock & Wilcox Company
no significant risk and no additional national regulations are needed. The EPA has stated they do not want
to add any unnecessary barriers to the beneficial uses
of combustion waste products because such uses conserve
natural resources, reduce disposal costs and reduce the
total amount of waste ultimately destined for disposal.
Solid combustion wastes
The principal solid waste streams in coal- and oilfired utility boilers include the following:
1. Bottom ash is the portion of fuel ash that falls to
the bottom of the furnace or from the stoker discharge. In coal-fired Cyclone furnace boilers, the
bottom ash consists of slag that drops from the bottom of the furnace into a slag tank for solidification.
2. Flyash is the finer ash material that is borne by
the flue gas from the furnace to the back end of
the boiler; it drops out in the economizer and air
heater hoppers or is collected by particulate control equipment.
3. Pyrite is iron sulfide, an impurity which is separated from coal in the pulverizer and which is combined with bottom ash for disposal.
FGD waste characteristics depend on the particular technology used:
1. Wet scrubbing (calcium-based system) A natural
oxidation system produces a wet sludge containing a mixture of calcium sulfite and calcium sulfate reaction products, trace amounts of flyash and
unreacted limestone. In a forced oxidation system,
the principal difference is that the reaction product is almost totally in the form of calcium sulfate
or gypsum, which is more easily dewatered to a
filter cake for wallboard, landfill or other use.
2. Dry scrubbing Waste is dry and contains calcium
sulfite, calcium sulfate, flyash and unreacted sorbent (hydrated lime). The potential uses for this
material are more limited.
3. Dry lime injection Waste is dry and contains calcium sulfite, calcium sulfate, flyash and a large
proportion of calcium oxide (CaO).
Solid waste treatment methods
To dispose of waste materials from wet FGD systems,
treatment methods are applied to ultimately produce
a solid. These methods include dewatering, stabilization and fixation, and are designed to achieve waste
volume reduction, stability and better handling, and
liquid recovery for reuse.
Dewatering This process is used to physically separate water from solids to increase the solids content of
the product and recover water for reuse and further
treatment.
A settling pond is the simplest method for dewatering, is not sensitive to inlet solids content, requires low
maintenance and is highly reliable. Ponds are often
used for ash or wet FGD scrubber slurries. Sizing provides low flow velocity so that solids can settle undisturbed by gravity. Settling ponds are unpopular with
regulatory agencies, require substantial acreage and
must be shut down for solids removal.
32-16
Thickeners are large cylindrical tanks with radial
rakes at the bottom. The rakes carry plows to push
material on the bottom that slopes toward the center.
The plows push settled material toward the underflow
discharge. Thickeners rely on gravity to separate high
specific gravity solids. Although thickeners are complicated and have high capital and maintenance costs,
they have high throughput rates and require less land
area than settling ponds.
Liquid cyclones or hydroclones are now commonly
used in place of thickeners to remove solids from slurries by centrifugal and liquid shear effects.
Hydroclones separate and collect particles down to a
particular size, with finer particles staying with the
liquid overflow. Hydroclones do not separate material
less than 5 µm effectively and are not efficient with
slurries containing more than 20% solids. They are low
in cost, have low space requirements, and produce low
solids content in the overflow and a high solids fraction in the underflow.
Vacuum filters, either of the drum or belt type, are
generally used for second stage dewatering of wet
scrubber slurries. They take little space and produce a
high solids content product, up to 95% for FGD slurry.
Centrifuges are also an option for second stage dewatering.
Stabilization This process increases the solids content of scrubber waste by adding dry solids such as
flyash. Stabilization is applied to impart greater
physical stability to the waste, making it easier to place
in the landfill and making it less susceptible to future
problems. Stabilization and fixation are generally applied to scrubber wastes as the final treatment step
after dewatering. Bottom ash and flyash, because of
their more granular nature, generally dewater easily
and do not require stabilization for disposal. For stabilization, a dry solid such as soil or flyash is mixed
with the waste slurry, spreading the water in the
waste over a larger mass of solids. Also, there is improvement in particle size distribution that leads to
closer packing, lower permeability and lower combined
volume. Stabilization can be reversible and if the
waste is rewetted, it may fluidize and fail structurally.
Fixation This process involves the addition of an
agent such as lime to produce a chemical reaction to
bind free water and produce a dry product. Fixation
includes a number of processes. Mixing suitable proportions of scrubber slurry with alkaline flyash containing sufficient CaO produces chemical reactions
that result in a material with compressive strength
comparable to low-strength concrete and with very low
permeability. Both characteristics contribute to ease
of placement and minimal leaching problems.
When the flyash does not have sufficient alkalinity, lime may be added to the flyash and scrubber
slurry mixture to produce the cementitious reaction.
Four percent addition of lime has produced material
with the necessary physical properties for disposal or
use. The cured material is suitable for structural fill,
providing a site that can be used for building construction after completion of the landfill. Comparable fixation reactions with scrubber sludge have been obtained with additions of 5 to 10% blast furnace slag.
Steam 41 / Environmental Considerations
The Babcock & Wilcox Company
Disposal and utilization methods
and requirements
Ultimate disposition of utility plant wastes (ashes and
FGD residues) is by disposal (in landfills or impoundments) or by utilization. Where disposal is used, the
waste stream is analyzed, and the site is permitted and
approved by the appropriate regulatory agencies.
Disposal methods These can be either wet or dry,
depending on the physical condition of the material.
Wet disposal requires construction of a pond which
may be below or above grade with impermeable barriers or dikes. Below grade construction may be considered and depends on suitable geology and hydrology at the site. With wet disposal, the waste is placed
in slurry or liquid form. After settling, the liquid that
has separated is collected, treated and either released
or recycled. Dry disposal can use a simple method of
landfill construction in which the waste is placed and
compacted to form an artificial hill. The trend is toward dry disposal because of smaller volumes and more
options for site or material reclamation.
Utilization methods These become more attractive
as waste management costs increase. Bottom ash,
flyash and boiler slag are used in applications where
they can be substituted for sand or gravel. The characteristics of boiler slag and bottom ash also make
these materials useful for blasting grit, roofing gran-
ules and controlled fills. Flyash, because of its chemistry and physical properties, is applicable in the
manufacture of Portland cement and concrete mixes.
The value of these materials is so low that the cost of
transportation severely limits their use to applications
close to the producing power plant.
With the increased use of ammonia reagents for NOx
emissions control, flyash (particularly from bituminous
coal) can adsorb excess ammonia present in the flue
gas and this adsorption may hinder the beneficial use
or end disposal of flyash or FGD byproduct streams.
Ammonia absorbed by flyash can be released (offgassed) when coming in contact with water. Currently, there are various processes in development to
remove residual ammonia from flyash.
FGD byproduct use is potentially in the areas of
agriculture, sulfur recovery and gypsum. Agricultural
use is limited. Trace elements from flyash contamination could have an unacceptable impact and make
wide use doubtful. Use for sulfur recovery is limited
by incomplete technology development, high capital
cost, and the low market price of sulfur.
FGD byproduct from forced oxidation wet scrubbing
systems, primarily gypsum, has seen extensive commercial use in wallboard production. However, gypsum byproduct specifications may vary significantly
by end user and must be established and confirmed
prior to FGD system design.
References
1. Elliot, T.C., Ed., Chen, K., Swanekamp, R.C., Standard
Hankbook of Power Plant Engineering, Second Ed.,
McGraw-Hill Company, New York, New York, 1998. See
chapter entitled, “Legislation and pollution sources,” by
D.A. Kellermeyer.
2. Corbitt, R.A., Ed., Standard Handbook of Environmental Engineering, Second Ed., McGraw-Hill Company, New
York, New York, 1998.
3. Clean Air Act, 42 USCA S7401 et seq., Sec. 101 (b) (1).
4. Title 40, Code of Federal Regulations, Part 60, United
States (U.S.) Government Printing Office, Washington,
D.C., July, 2004.
5. Title 40, Code of Federal Regulations, Parts 51 and 52
(51.165, 51.166, and 52.21), United States (U.S.) Government Printing Office, Washington, D.C., July, 2004.
6. Lesley, S., “Trends in Emissions Standards,” Report
CCC/77, International Energy Agency (IEA), Clean Coal
Centre (CCC), London, England, United Kingdom, November, 2003.
7. Wu, Z., “NOx Control for Pulverized Coal-Fired Power
Stations,” Report CCC/69, International Energy Agency,
Clean Coal Centre, London, England, United Kingdom,
December, 2002.
Steam 41 / Environmental Considerations
8. United States (U.S.) Environmental Protection Agency
(EPA), National Emissions Inventory Criteria Pollutant
Data: Current Emissions Trends Summary 1970-2002,
Accessed August 28, 2003. Available online at:
www.epa.gov/ttn/chief/trends/index.html
9. Patrick, D.R., Toxic Air Pollution Handbook, Van
Nostrand Reinhold, New York, New York, 1994.
10. “Mercury Study Report to Congress,” United States
(U.S.) Environmental Protection Agency (EPA) Report
EPA-452/R-97-2003, December, 1997.
11. “Emissions of Greenhouse Gases in the United States
(U.S.), 2000 Summary,” Report DOE/EIA-0573, Department of Energy (DOE) Energy Information Agency (EIA),
U.S. Department of Energy, February 22, 2002.
12. Senior, C.L., “Behavior of Mercury in Air Pollution
Control Devices on Coal-Fired Utility Boilers,” Power Production in the 21st Century: Impacts of Fuel Quality and
Operations Conference, Engineering Foundation, New
York, New York, 2001.
13. Clean Water Act, 33 U.S.C., S1251 et seq., Section
101(a), United States (U.S.) Environmental Protection
Agency (EPA).
14. The Resource Conservation and Recovery Act (RCRA),
42 Act, 42 U.S.C., S9601 et seq., Section 1004(5).
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The Babcock & Wilcox Company
Integrated emission control systems on this western U.S. power plant include low NOx burners, SCR, dry scrubber, and baghouse.
32-18
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The Babcock & Wilcox Company
Chapter 33
Particulate Control
As steam is widely generated by the combustion of
most fossil fuels, the flue gas carries particulate matter, principally ash, from the furnace. Except for natural gas, all other fossil fuels contain some quantity of
non-combustibles which form the majority of the particulate. Unburned carbon also appears as particulate.
Particulate control is needed to collect this material
and to limit its release to the atmosphere.
All coals contain some amount of ash. The amount
of ash varies depending on the type of coal, location,
depth of mine and mining method. In the United
States (U.S.), eastern bituminous coals typically contain 5 to 15% ash while the western subbituminous
coal ash content may range from 5 to 30% ash by
weight. Texas lignites also contain up to 30% ash.
Mining methods on thin seams of coal may also contribute to higher ash quantities (see Chapter 9).
When coal is burned in conventional boilers, a portion of the ash drops out of the bottom of the furnace
(bottom ash) while the remainder of the ash is carried
out of the furnace in the flue gas. It is this remaining
ash (flyash) that must be collected after the furnace
and before exhausting the flue gas to the atmosphere.
Different combustion methods contribute different
proportions of the total coal ash content to the flue gas.
With pulverized coal firing, 70 to 90% of the ash is
carried out of the boiler with the flue gas. A stokerfired unit will emit about 40% of its ash in the flue
gas along with some amount of unburned carbon. With
Cyclone firing, only 15 to 40% of the ash is normally
carried by the flue gas. On circulating fluidized-bed
boilers, all of the ash, along with the fluidized-bed
material, is carried by the flue gas. Therefore, the selection and design of particulate control equipment are
closely tied to the type of firing system.
An American Society for Testing and Materials
(ASTM) ash composition analysis test (ASTM D-368201) of a coal ash sample reveals the major ash components. Proximate and ultimate coal analyses commonly
offer additional insight and also provide total ash content. Ash components are typically reported in the oxide form and include silicon dioxide, titanium dioxide,
iron oxide, aluminum dioxide, calcium oxide, magnesium oxide, sodium oxide, potassium oxide, sulfur trioxide and diphosphorous pentoxide. Trace quantities
Steam 41 / Particulate Control
of many more elements are also found in ash. The proportion of the major constituents varies significantly
between coal type and mine location. The analysis and
composition of flyash are discussed in greater detail
in Chapters 9 and 21.
Other significant coal ash properties are particle size
distribution and shape, both of which are dependent
on the type of firing method. Stoker-fired units generally produce the largest particles. Pulverized coal-fired
boilers produce smaller, spherical shaped particles of 7
to 12 microns (Fig. 1). Particles from Cyclone-fired units,
also mostly spherical, are among the smallest. Fluidized-bed units produce a wide range of particles that
are generally less spherical and are shaped more like
crystals. Knowledge of ash properties is important in
the selection of the correct particulate control equipment.
Regulation of particulate emissions
Particulate control equipment was first used by
utilities in the 1920s and before that time in some industrial applications.1 Prior to 1971, however, controls
were installed largely on a best effort basis. In 1971,
the first Environmental Protection Agency (EPA) performance standard limited outlet particulate emissions
to 0.1 lb/106 Btu (123 mg/Nm3 at 6% O2) heat input
Fig. 1 Flyash from pulverized coal (magnified X 1000).
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The Babcock & Wilcox Company
and stack opacity to 20% for those units larger than
250 × 106 Btu/h (73.3 MWt) heat input. Opacity, measured by an instrument called a transmissometer, is
the portion of light which is scattered or absorbed by
particulate as the source of light passes across a flue
gas stream. Therefore, both the amount and appearance of the stack emissions are regulated. Since 1979,
the EPA New Source Performance Standards (NSPS)
for particulate control permit a maximum of 0.03 lb/
106 Btu (36.9 mg/Nm3 at 6% O2) heat input for these
units. A 20% opacity is still permissible.
Federal and state EPA regulations set the primary
guidelines for particulate emissions. In addition, many
local regulatory bodies have generally stricter regulations than those set by the federal EPA. There are
separate emissions standards for a variety of combustion processes including steam generators firing coal,
oil, refuse and biomass. Currently there are three major classification levels for steam generating units: one
for units greater than 250 × 106 Btu/h (73.3 MWt), one
for the 100 to 250 × 106 Btu/h (29.3 to 73.3 MWt) units,
and a third for those units less than 100 × 106 Btu/h (29.3
MWt) heat input.2,3 Finally, if a new plant is in a
nonattainment area, the permissible particulate emissions and opacity may be significantly reduced from
nominal control levels.
Particulate control technologies
Particulate emissions from the combustion process
are collected by particulate control equipment (Fig. 2).
This equipment must remove the particulate from the
flue gas, keep the particulate from re-entering the gas,
and discharge the collected material. There are several major types of equipment available including
electrostatic precipitators, fabric filters (baghouses),
mechanical collectors and venturi scrubbers. Each of
these uses a different collection process with different
factors affecting the collection performance. Prior to the
1990s, the technology of choice for large coal-fired utility
plants was the dry electrostatic precipitator, with fabric
filters a distant second. Today, preference is given to the
fabric filter (pulse jet type) for reasons described below.
Dry electrostatic precipitators
A dry electrostatic precipitator (ESP) electrically
charges the ash particles in the flue gas to collect and
remove them. The unit is normally comprised of a series of parallel, vertical metallic plates (collecting electrodes or CEs) forming ducts or lanes through which
the flue gas passes. Centered between the CEs are discharge electrodes (DEs) which provide the particle
charging and electric field. Fig. 3 is a plan view of a typical ESP section which indicates the process arrangement.
Charging The CEs are typically electrically grounded
and connected to the positive polarity of the high voltage power supply. The DEs are suspended off of electrical insulators in the flue gas stream and are connected to the output (negative polarity) of a high voltage power source, typically 55 to 85 average kV DC. An
electric field is established between the DEs and the CEs,
and the DEs will exhibit an active glow, or corona. As the
flue gas passes through the electric field, the particulate
takes on a negative charge which, depending on particle
size, is accomplished by field charging or diffusion.
Collection The negatively charged particles are attracted toward the grounded CEs and migrate across
the gas flow. Some particles are difficult to charge,
requiring a strong electric field. Other particles are
charged easily and driven toward the plates, but also
may lose the charge easily, requiring recharging and
recollection. Gas velocity between the plates is also an
important factor in the collection process since lower
velocities permit more time for the charged particles
to move to the CEs and reduce the likelihood of loss
back into the gas stream (re-entrainment). In addi-
Stack
Low NOX
Burners
SCR
Furnace
Absorber
Air Heater
Precipitator
Pulverizers
Forced
Draft
Fans
Fig. 2 Particulate control equipment – plant side view.
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The Babcock & Wilcox Company
Fig. 3 Particle charging and collection within an ESP.
tion, a series of CE and DE sections is generally necessary to achieve overall particulate collection requirements. In modern ESPs designed for utility flyash,
four or more sections in series are required to achieve
design collection levels.
The ash particles form an ash layer as they accumulate on the collection plates. The particles remain on the
collection surface due to the forces from the electric field
as well as the molecular and mechanical cohesive forces
between particles. These forces also tend to make the
individual particles agglomerate, or cling together.
Rapping The ash layer must be periodically removed.
The most common removal method is rapping which consists of mechanically striking the collection surface; this
rapping force dislodges the ash. Because particulate
tends to agglomerate, the ash layer is removed in sheets.
This sheeting is important to prevent the re-entrainment
of individual particles into the flue gas stream, requiring recharging and recollection downstream.
While most of the particles are driven to the CEs, some
positively charged particles attach to the DEs. A separate rapping system is therefore used to remove deposits from these electrodes and maintain proper operation.
Ash removal The dislodged particulate falls from
the collection surface into hoppers. Once the particulate has reached the hopper it is important to ensure,
by proper design, that it remains there in bulk form
with minimal re-entrainment until the hopper is emptied. (See Chapter 24 for hopper ash removal methods and equipment.)
Dry ESP applications
Utility Because coal is the most common fuel for
steam generation, collection of the coal ash particles
is the greatest use of a particulate collector. The electrostatic precipitator has been the most commonly used
collector. To meet the particulate control regulations
for utility units and considering the resulting high collection efficiency, special attention must be given to
details of precipitator sizing, rapping, flow distribution and gas bypass around the collector plates. The
result will then be a collector that can be confidently
and consistently designed and operated to meet the
outlet emissions requirements. Operating collection efficiencies which exceed 99.9% are common on the meSteam 41 / Particulate Control
dium and higher ash coals with outlet emissions levels
of 0.01 to 0.03 lb/106 Btu (12.3 to 36.9 mg/Nm3 at 6% O2)
heat input common on all coals. ESPs are also widely installed on utility boilers that fire oil as their principal fuel.
Industrial Other common noncoal-fired industrial
units where ESPs are successfully being applied include municipal refuse incinerators and wood, bark,
and oil-fired boilers. For these, the ash in the flue gas
is typically more easily collected than coal flyash so
an ESP of modest size will easily collect the particulate. The moisture content in the refuse, wood and bark
is the major contributor to the low resistivity. The carbon content of the residue, ash and unburned combustibles also contributes to low resistivity. (See note
below.)
Pulp and paper In the pulp and paper industry, precipitators are used on power boilers and chemical recovery boilers. The power boiler particulate emissions
requirements are the same as those for the industrial
units using the same fuels. For the recovery boilers,
precipitators are used to collect the residual salt cake
in the flue gas. Chapter 28 contains further information on the recovery boiler processes and the reuse of
the collected material.
A recovery boiler is a unique application for a precipitator due to the small particulate size and the tendency for the cohesive ash particles to stick together.
The resistivity of the particulate is low so it is collected
easily in the ESP. However, the fine particulate can
also cause problems with the generation of effective
corona by the DEs due to an effect called space charge.
Because the particulate is so small, gas bypass around
collector plates and re-entrainment of rapped particulates in the flue gas are more of a design concern. Reentrainment is minimized by proper gas flow control
and by lower gas velocities. Precipitator collection efficiencies are 99.7 to 99.8% to meet the 20% opacity
and the local emissions requirements. Due to the characteristics of the salt cake particulates, a drag chain
conveyor across a precipitator floor, rather than a
Note: Resistivity is an inverse measure of a particle’s ability
to accept and hold a charge. Lower resistivity indicates improved ability to accept a charge and be collected in an ESP.
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The Babcock & Wilcox Company
normal hopper, is used for salt cake removal. In addition, casing corrosion is a more significant concern
and as a result more insulation is required to reduce
casing heat loss. Finally, in order to improve system
reliability, two precipitator chambers are commonly
used, each capable of handling 70% of the gas flow and
each equipped with separate isolation capabilities.
Precipitators have also been applied in the steel industry to collect and recover the fine dust given off
by some processes.
Dry precipitator components
All ESPs have several components in common (Fig.
4) although there is some shape and size variation between units.
Casing As shown in Fig. 4, the structure forming
the sides and roof of an ESP is a gas-tight metal cased
enclosure. The structure rests on a lower grid, which
serves as a base and is free to move as needed to accommodate thermal expansion. All of the collecting
plates and the discharge electrode system are top supported from the plate girder assemblies. The entire
enclosure is covered with insulation and lagging. Access doors in the casing and adequately sized walkways
between the fields assist in maintenance access for the
internals.
Materials for the precipitator enclosure and internals are normally carbon steel, ASTM A-36 or equivalent, because gas constituents are noncorrosive at normal operating gas and casing temperatures. Projects
with special conditions may warrant an upgrade in
some component materials.
Hoppers For utility flyash applications, metal inverted pyramid-shaped hoppers are supported from
the lower grid and are made of externally stiffened
casing. The hoppers provide the lower portion of the
overall enclosure and complete the gas seal. Their
sides are designed with an inclination angle of at least
60 deg from horizontal. Hoppers are generally designed as particulate collection devices that can store
Fig. 4 B&W rigid frame electrostatic precipitator.
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The Babcock & Wilcox Company
ash for short periods of time when the ash removal
system is out of service.
Because many ash removal systems are noncontinuous, the following items are normally supplied with the
precipitator hoppers to ensure good particulate removal:
hopper heaters, electromagnetic vibrators, poke holes,
anvil bars and level detectors. Hot air fluidizing systems
are also sometimes supplied to assist in ash removal.
For non-utility flyash applications, the use of alternative ash holding/removal designs are common.
These include flat-bottom with drag scrapers, wetbottom, and trough-type hoppers.
Collecting electrodes As shown in Fig. 4, the CE surface typically consists of a series of roll-formed collector plates assembled into a CE and supported from the
top. CEs are also widely referred to as plates or curtains. The CEs are spaced in rows across the width of
the precipitator, typically on 12 or 16 in. (305 or 406
mm) centers in modern designs that also use rigid DEs.
In older designs, CE spacings of 9 or 10 in. (229 or
254 mm) were generally seen when used with wire
(0.109 in./2.8 mm diameter typical) DEs. In the direction of gas flow, the CE sections are arranged into
fields which are normally powered by separate and
dedicated power supplies. The collection surface area
in the Deutsch-Anderson equation (see Equation 1)
is the total CE plate area required for particulate collection. For calculating surface area, the CE assembly is treated as a plane and includes both sides of the
CE where exposed to gas flow. The rolled plates can
be up to 50 ft (15.2 m) in length with a shop straightness
tolerance of 0.5 in. (12.7 mm). CEs may also be large
flat plates with stiffener bars added to maintain
straightness. For optimum performance with a uniform
electric field and with minimal inter-electrode sparkover or electrical arcing (high current spark), the alignment of collection surface and electrodes must be maintained within tight tolerances.
Discharge electrodes and insulators As described in
the section on charging, the DEs, connected to the high
voltage power source, are located in the gas stream
and serve as the source of the corona discharge. These
electrodes are the central components of the discharge
system which is electrically isolated from the grounded
portions of the ESP. An electrical clearance gap of 6 to
8 in. (152 to 203 mm), depending on CE spacing, must
be maintained throughout the ESP between the DE
system and any grounded components.
Discharge electrodes are found in several shapes.
Common types include the rigid frame, rigid electrode
and weighted wire. The rigid frame, shown in Fig. 5,
consists of strips of electrode supported between sections of frame tubing. Each frame is attached to a
structural carrier, both front and rear. This assembly
is supported by insulators forming a four point suspension system. The rigid electrode consists of a member with proprietary shape that is top supported and
hangs the full height of the precipitator. The typical
rigid electrode top support is also a frame hanging
from insulators. The lower ends of the rigid electrode
have a guide bar and side to side spacers. The third type
of discharge electrode, weighted wire, consists of a
round or barbed wire supported at the top and held
Steam 41 / Particulate Control
straight and in tension with a weight at the bottom. The
upper frame is supported from insulators and there is a
lower steadying frame to guide and space the electrodes.
For highest equipment reliability, either the rigid
frame or rigid electrode is the most common configuration. Discharge electrode failure in the form of broken
wires has been a recurring problem with the weighted
wire electrodes, particularly with lengths of 30 ft (9.1
m) or more, resulting in performance deterioration.
Gas flow control devices ESPs operate most efficiently when the gas flow is distributed evenly across
the ESP cross section. Flow control devices such as
turning vanes, flow straighteners and perforated
plates are frequently installed in the inlet and outlet
flues, and flow transition pieces, to provide the desired
degree of flow uniformity while optimizing resultant
pressure drop.
Rapping systems As shown in Fig. 4, the most effective method of cleaning the collector curtains is to
rap each one separately and in the direction of gas
flow. This method assures that each curtain receives
a rapping force. The rapping system shown is a tumbling hammer type, where the hammer assemblies are
mounted on a shaft extending across the ESP in a staggered arrangement. The shaft is turned slowly by an
external drive controlled by timers for rapping fre-
Fig. 5 Rigid frame discharge electrode and rapping system for an ESP.
33-5
The Babcock & Wilcox Company
quency and optimum cleaning. Hammer size is selected
to match the application and size of the collector curtain. External, top-mounted rapping technology has
also been widely used, principally in the U.S. Typically, more than one collector curtain is rapped at a
time with this method, and the rapping force is in the
downward direction on the top edge of the curtains.
Both a drop rod and magnetic impulse are the drive
mechanisms used.
Due to the difficulty of cleaning high resistivity flyash
from the collection surface, considerable tests have been
performed to ensure that adequate rapping forces are
transmitted across the entire collection surface. A minimum acceleration of 100 g applied at the farthest point from
impact has been established as an industry standard.
Typically, rapping of the rigid frame discharge electrodes is accomplished using a tumbling hammer system as shown in Fig. 5. The hammer assemblies are
mounted in a staggered arrangement on a shaft
across the width of an electrical section. Note that a
smaller hammer than that used for the collector system is required for proper cleaning of the discharge
electrodes. An external drive unit mounted on the
precipitator roof is used to slowly turn the rapper shaft
and, because it is attached directly to the carrier frame,
the drive shaft must also be electrically isolated with an
insulator. As with the collector system, top rapping of the
discharge electrodes is another method of cleaning that
is typically used with the rigid electrode designs.
A rapping system is sometimes used on the flow distribution devices at the precipitator inlet.
Power supplies and controls A transformer rectifier
(TR) set along with a controller supply the high voltage power to the discharge electrode system. Several
TR sets are normally needed to power a precipitator.
With this combination of electrical components, the
single-phase 480 V AC line voltage is regulated in the
controller and then transformed into a nominal 55,000
to 75,000 V before being rectified to a negative DC
output for the discharge system. Electrically, a precipitator most closely resembles a capacitive load. Due to
the capacitive load and the nature of the precipitator
internals, the TR set must be designed to handle the
current surges caused by arcs between the discharge
electrodes and the grounded collection surface. A current-limiting reactor in series with the TR set primary
also helps to temporarily limit the current surges.
Traditionally, a voltage controller tries to maximize
the voltage input to the precipitator. To achieve this
input and when operating as designed, the controller
must periodically raise the voltage to the point of
sparking between the discharge electrode and the
collection surface. The controller must then also detect the sparks and reduce the voltage to avoid an arc.
Today’s microprocessor TR controls with quick response times, interface advantages and programming
capabilities provide many functions to optimize particulate collection.
Dry precipitator sizing factors
An ESP is sized to meet a required performance or
particulate collection efficiency. The sizing procedure
determines the amount of collection surface to meet
33-6
the specified performance. An equation which relates
the collection efficiency (E) to the unit size, the particle charging and the collection surface is the DeutschAnderson equation: l
Inlet dust loading − Outlet dust loading
E = 100% ×
(1)
Inlet dust loading
1−
− wA
E
= e V
100
(2)
or
V
1
A = n
1 − ( E / 100 ) w
(3)
where
E = ESP removal efficiency, % of inlet particulate
removed
w = migration velocity, ft/min (m/s)
A = collection surface area, ft2 (m2)
V = gas flow, ft3/min (m3/s)
Migration velocity is the theoretical average velocity at which the charged particles travel toward the
collection surface. This velocity is dependent upon how
easily the particulate is charged, and the value is normally selected by empirical means based on experience. The factors which affect migration velocity are
the fuel and ash characteristics, the operating conditions, and the effects of gas flow distribution.
These factors also have an effect on the ability of the
particulate to accept a charge. A commonly used indication of this effect is resistivity, measured in ohm-cm. Fig.
6 illustrates typical resistivity curves for two fuel ashes.
High resistivity ashes result in low migration velocities
and large collection surface areas while average resistivity ashes result in moderately sized surface areas, i.e.,
lower resistivity indicates improved collection.
As previously discussed, the flue gas will pass
through a series of collection fields. ESPs collect particulate in geometric fashion meaning each field will
tend to collect very roughly 80% of the particulate
entering that particular field. Therefore, the inlet field
will collect the vast majority of the total mass particulate with each successive field collecting geometrically
less of the total. For example, the first field could collect 80% of the total particulate loading while the second field would collect 80% of the remaining 20% or
16% of the total particulate loading, etc.
Fuel and ash characteristics The fuel and ash constituents which reduce resistivity or that are favorable
to ash collection in an ESP include moisture, sulfur,
sodium and potassium. Applications with sufficient
quantities of these components usually result in moderately sized precipitators. Constituents which hamper ash collection and increase outlet emissions include
calcium and magnesium. High percentage concentrations of these items without offsetting quantities of the
favorable constituents result in poorer collection and
larger precipitators. The fuel and ash constituents and
their relative quantities must be reviewed in the sizSteam 41 / Particulate Control
The Babcock & Wilcox Company
ing process to determine the overall effect on migration velocity. The migration velocity/resistivity can then
be altered to some extent by controlling the content
of the critical constituents.
Gas temperature, volume and distribution As indicated in Fig. 6, gas temperature has a direct effect on
resistivity and on the gas volume passing through the
ESP. Gas flow from the boiler also has an effect on sizing as indicated by the Deutsch-Anderson equation.
There is an optimum gas velocity range within an ESP
for maximum performance which must be considered
as part of the design selection. Maximum ESP efficiency is achieved when the gas flow is distributed
evenly across the unit cross section. Uniform flow is
assumed in the ESP sizing calculations and should be
verified during the design stage by using a flow model.
These models should include the precipitator as well
as the inlet and outlet flues. Flow uniformity is typically achieved by installing distribution devices in the
flue transition sections immediately upstream and
downstream of the ESP. Hopper design must also prevent high velocity areas to avoid flyash re-entrainment.
The industry standard for flow distribution and modeling is the Institute of Clean Air Companies EP-7.5
Particle size distribution Particle size also affects
ESP design and performance. A particle size distribution versus collection efficiency curve (Fig. 7) indicates
that an ESP is less efficient for smaller particles (less
than 2 microns) than for larger ones. Therefore, ESP
applications with a high percentage of particles less
than 2 microns will require more collection surface
and/or lower gas velocities.
Sectionalization Sectionalization refers to how many
or how few independent high voltage power supplies are
installed on an ESP. ESP performance improves with
additional, independently energized sections, but improving performance must be weighed against additional capital and operating costs. Proper sectionalization
can overcome the effects of a poorly operating section(s) due
to adverse process or mechanical/electrical conditions.
Fig. 6 Typical ash resistivity.
Steam 41 / Particulate Control
Fig. 7 Summary of fine particulate collection (adapted from Reference 4).
Rapping effects Rapping causes some amount of
particulate re-entrainment in the flue gas flow. Given
the nature of the precipitation process, adjustment of
rapping (how often and how intense) can greatly impact outlet emissions, either positively or negatively.
Proper rapping adjustment in the outlet sections is
especially important because there are no downstream
sections to handle re-entrainment due to over-rapping.
There are no set industry standards for rapping adjustments although many suppliers begin with proprietary guidelines. Effective fine-tuning is usually
based upon the supplier’s field experience or plant
personnel familiar with the specific ESP.
Ash removal Proper ESP design will prevent operational issues associated with re-entrainment from the
hoppers. However, a malfunctioning ash removal system can also cause problems. High ash levels can permit excessive re-entrainment, and can cause electrical malfunction if the ash pile contacts the discharge
electrode system (high resistance grounding). If not
corrected, ash removal malfunction can also cause the
ash pile to float upward and distort the DEs.
Performance enhancements
A change in fuel, a boiler upgrade, a change in
regulation, or performance deterioration may call for
a precipitator performance enhancement. Enhancement techniques include additional collection surface,
flue gas conditioning, improved/modified gas flow distribution, additional sectionalization, additional rapping, control upgrades and internals replacement. Gas
conditioning alters resistivity by adding sulfur trioxide (SO3), ammonia, moisture, or sodium compounds
while the other modifications involve only mechanical and/or electrical hardware changes.
After identifying the causes of current or anticipated performance deterioration, the equipment is
surveyed to determine the need for replacement or
upgrade. Additional collection surface, in series or in
parallel with existing surface, may be needed to meet
improved particulate collection needs. Gas condition33-7
The Babcock & Wilcox Company
ing may be used to offset some collection surface deficiency or to enhance the performance of a marginal
precipitator. Large dust accumulations near the precipitator entrance, flow patterns on the collection surface, and a velocity traverse across the precipitator face
indicate possible flow maldistribution. In addition, TR
set controllers made before the mid-1980s can potentially benefit from an upgrade to improve performance. Finally, a detailed internal inspection will determine a possible need for replacement of collection
surface and discharge electrodes and the need to upgrade the rapping system. A combination of enhancement techniques may be needed.
Wet electrostatic precipitators6
The collection of acid mists consisting of fine particulate has been accomplished with wet electrostatic
precipitators (WESPs) for nearly 100 years, principally
on industrial processes. These WESPs differ from the
dry ESPs in both materials and configuration; however, the collection mechanism is basically the same.
Typical operation is at or below the flue gas acid moisture dew point temperature for the gas being filtered,
and particulate loading is low compared to normal coalfired dry ESP applications. Collection efficiencies of
99% have been reported with wet ESPs when precipitator sections or modules are placed in series. (See
Chapter 35, Fig. 15.)
Boiler applications Wet ESPs have not historically
been used for utility or industrial boiler emissions control when firing coal, oil or gas. However, with the
emergence of expanded emission control requirements,
reduced emission limits, use of non-traditional fuels
and the interactions of other emissions control equipment, there has been renewed interest in the use of
WESPs to control selected emissions, especially of sulfuric acid mist and fine dry particulates. Firing of petroleum coke and Orimulsion fuel can result in elevated levels of SO3 in the flue gas. In addition, as
noted in Chapter 34, SCRs on coal-fired systems have
a tendency to increase the concentration of SO3 in the
flue gas due to the oxidation action of the catalyst. Depending upon the catalyst selection, this oxidation can
increase the SO3 significantly on the higher sulfur fuels. As the SO3 is carried through the cooler backend
equipment, it condenses and becomes an acid mist
(H2SO4). When wet flue gas desulfurization systems
are used for sulfur control, significant levels of SO3/
acid mist tend to pass through the system and result
in opacity/visibility problems at the stack. (See Chapter 35.) Acid mist has also been noted on some units
without the wet FGD systems. WESPs have demonstrated the ability to effectively collect the H2SO4 and
other aerosols in such environments.
Wet precipitator design The WESP design generally follows that of dry ESPs. However, WESPs differ
from dry ESPs in three key areas. First, the physical
arrangement of WESPs can be non-standard compared to dry ESPs. The WESP configuration and
shapes of the key components can be adapted to integrate the WESP with other system equipment, such
as the case of the integration of a WESP in a wet flue
gas desulfurization system discussed in Chapter 35.
33-8
The components can also be configured in a more conventional stand-alone arrangement. Second, the moist
corrosive atmosphere present requires careful selection of material in critical areas. Third, instead of a
rapping system to remove the collected particulate,
water spray or a water film removes the material deposited on the collection surfaces and discharge system.
The physical arrangement of the bottom of the WESP is
then adapted to collect the water film discharge.
Fabric filters
A fabric filter, or baghouse, collects the dry particulate matter as the cooled flue gas passes through the filter material. The fabric filter is comprised of a multiple
compartment enclosure (see Fig. 8 and chapter frontispiece) with each compartment containing up to several
thousand long, vertically supported, small diameter fabric bags. The gas passes through the porous bag material which separates the particulate from the flue gas.
Operating fundamentals
With the typical coal-fired boiler, the particle laden
flue gas leaves the boiler and air heater and enters
the filter inlet plenum which in turn distributes the
gas to each of the compartments for cleaning. An outlet plenum collects the cleaned flue gas from each
compartment and directs it toward the induced draft fan
and the stack. Inlet and outlet dampers then allow isolation of each compartment for bag cleaning and maintenance. Each compartment has a hopper for inlet gas flow
as well as for particulate collection and removal by conventional equipment, as discussed further in Chapter 24.
The individual bags are closed at one end and connected
to a tubesheet at the other end to permit the gas to pass
through the bag assembly. The layer of dust accumulating on the bag is usually referred to as the dustcake.
Collection of the particulate on the bag fabric is the
heart of the filtering process. The major forces causing this collection include impingement by either direct contact or impaction and dustcake sieving. Minor
forces which assist in the collection are diffusion, electrostatic forces, London-Van der Waal’s forces and
gravity.7 The dustcake is formed by the accumulation
of particulate on the bags over an operating period.
Once formed, the dustcake, and not the filter bag
material, provides most of the filtration. Some filter
media such as membrane and tight needle felts provide
higher removal efficiency than normally achieved by
filter cake alone. Although impingement collection is
most effective on the larger particles and the sieving
process collects all particle sizes, a dustcake must form
to maximize overall collection.
As the dustcake builds and the flue gas pressure
drop across the fabric filter increases, the bags must
be cleaned. This occurs after a predetermined operating period or when the pressure drop reaches a set
point. Each compartment is then sequentially cleaned
to remove the excess dustcake and to reduce the pressure drop. A residual dust coating is preferred to enhance further collection. In pulse jet fabric filters (discussed below), it is common to perform cleaning online
which maintains all compartments in operation.
Steam 41 / Particulate Control
The Babcock & Wilcox Company
Penthouse
Pulse
Air
Valve
Roof
Access
Hatch
Outlet
Poppet
Damper
Pulse Air
Blowpipe
Pulse Air
Header
Outlet
Manifold
Tubesheet
Filter Bag
With
Internal
Cage
Inlet
Manifold
Inlet
Louver
Damper
Fig. 8 Pulse jet fabric filter.
Initial filter bags have a pre-coat filter media. The
pre-coat is an optimum particle size mixture which aids
in developing the first filter cake and tends to stay
within the outer surface of the filter media.
Types of fabric filters
Bag cleaning methods distinguish the types of fabric filters, with the three most common types being reverse air, shake deflate and pulse jet. The cleaning
method also determines the relative size by the air/
cloth (A/C) ratio and the filtering side of the bag. Both
the reverse air and the shake deflate are inside-thebag filters with gas flow from inside the bag to outside; the pulse jet is an outside-the-bag filter with the
flow from outside to inside (Fig. 9). Note that the
tubesheet on the inside-bag filtering is located below the
bags; for the pulse jet the tubesheet is above the bags.
Steam 41 / Particulate Control
A reverse air, more correctly termed reverse gas, filter reverses the flow of clean gas from the outlet plenum back into the bag compartment to collapse the
bags in an isolated compartment and dislodge the
dustcake. This is a gentle cleaning motion. Once the
dislodged particulate falls to the hopper, the bags are
gently reinflated before full gas flow is allowed for filtering. This system requires a reverse gas fan to supply the cleaning gas flow along with additional dampers for flow control. This type of filter system has been
used in most large utility power plant fabric filters in
the U.S. to date. Experience with this type of fabric
filter on some coal flyash applications has demonstrated that reverse gas cleaning alone does not provide an acceptable operating pressure drop. Therefore,
some units have added sonic air horns to each compartment to assist in the cleaning.
33-9
The Babcock & Wilcox Company
Shake deflate (shaker) filters are similar to reverse
air units in that the cleaning occurs in an isolated compartment and a small amount of cleaned flue gas is
used to slightly deflate the bags. In addition, a mechanical motion is used to shake the bags and dislodge
the accumulated dustcake.
Pulse jet technology is a more rigorous cleaning
method and can be used when the compartment is either isolated or in service. A pulse of compressed air is
directed into the bag from the open top which causes
a shock wave to travel down its length, dislodging the
dustcake from the outside surface of the bag. A unique
aspect of the pulse jet system is the use of a wire cage
in each bag to keep it from collapsing during normal
filtration. The bag hangs from the tubesheet. A series
of parallel pulse jet pipes are located above the bags
with each pipe row having a solenoid valve. This permits the bags to be pulsed clean one row at a time. Use
of pulse jet units with utility boilers is increasing and
they are expected to be the major contributor for retrofit or new units.
A variant of the pulse jet fabric filter called
COHPAC® (compact hybrid particulate collector) is the
unique use of a high velocity fabric filter commonly
installed after a malperforming electrostatic precipitator. This arrangement reduces particulate emissions and
may prove to be a good solution in special applications.
Design parameters
Three key fabric filter design parameters are air/cloth
(A/C) ratio, emission rate and drag. A/C ratio is the gas
volumetric flow rate divided by the exposed bag surface area and is commonly referred to as the filtration
velocity. Industry standards, along with operating experience, establish the design A/C ratios. The A/C has
a significant impact on useful bag life. Lowering the A/
C ratio for a specific fabric filter design tends to increase
bag life and conversely increasing A/C ratio decreases
bag life. A/C ratios are typically stated with one compartment out of service for cleaning (net condition).
A/C ratios commonly applied to coal-fired boilers
may range from 1.5 to 2.3 ft/min (0.45 to 0.7 m/min)
with reverse air fabric filters and 3.0 to 4.0 ft/min (0.9
to 1.2 m/min) for pulse jet fabric filters. The type of
firing and ranges in fuel significantly affect the appropriate filtration velocity.
The emission rates are generally established based
upon historical data. Several prediction models have
been developed but they are of limited use. Bench tests
using collected particulate samples have proven beneficial as an indicator for media selection.
The pressure drop includes the drop across the
bags, the dustcake and the attachment of the bag to
the tubesheet. The calculation of drag is useful in
evaluating performance.
The general equation for drag can be expressed as
follows:
∆P = a × V + b × c × t × V 2
(4)
where
∆P = pressure drop, in. wg (kPa)
a = constant with units of in. wg-min/ft (kPa-min/
33-10
V
b
=
=
c
=
t
=
m) (This value is determined based upon actual
operating data. This constant increases as the
fabric filter media ages. The product of a × V is
referred to as the effective residual pressure
drop.)
the filtration velocity, ft/min (m/min)
the cake coefficient with units of in. wg-minft/lb. Values range significantly from 0.1 to
700. Flyash from coal ranges from 5 to 20.
(kPa-min-m/kg)
the inlet dust concentration with units of lb/
ft3 (kg/m3)
time, min.
Applications
The Babcock & Wilcox Company (B&W) participated
in the first U.S. utility fabric filter installation in the
1960s, on an oil-fired boiler in southern California.8
Several utilities followed by the late 1970s. Interest in
these systems continues to grow due to the high particu-
Tension
Support
Reverse
Flow
Anti-Collapse
Ring
Reverse Gas
Tubesheet
Normal
Operation
Reverse Gas
Cleaning
Support / Shake
Mechanism
Deflation
Flow
Shaker
Tubesheet
Normal
Operation
Shake
Cleaning
Tubesheet
Pulse Jet
Cleaning
Air
Pulse
Wire
Cage
Normal
Operation
Pulse
Cleaning
Fig. 9 Fabric filter types.
Steam 41 / Particulate Control
The Babcock & Wilcox Company
late removal efficiency. Well designed filters routinely
achieve greater than 99.9% particulate removal, meeting all current U.S. EPA and local regulations.
Besides standard utility coal-fired applications, fabric filters are used on circulating fluidized-bed boilers,
industrial pulverized and stoker coal units, refusefired units in combination with a dry flue gas scrubber, and in the cement and steel industries. Fabric filters are not currently used on oil-fired units due to the
sticky nature of the ash.
A unique advantage with fabric filters is that all of
the flue gas passes through the dustcake as it is
cleaned. When the dustcake has high alkalinity, it can
be used to remove other flue gas constituents and acid
gases, such as sulfur dioxide (SO2). (See Chapter 35.)
Addition of activated carbon into the flue gas has been
used to control mercury emissions. Fabric filters generally are better collectors of the carbon and mercury
components than are electrostatic precipitators.
Fabric filter components
Configurations Pulse jet fabric filters have two general arrangements. The first is called hatch style, that
has large horizontal covers used to access the area
above the tubesheet for bag replacement. The most
common arrangement includes a penthouse above the
hatch covers. The second type, called walk-in, has a
gas-tight compartment above the tubesheet with vertical doors to access the area above the tubesheet for
bag replacement. Walk-in arrangements are more
common for industrial sized units with shorter bags.
Reverse air and shaker units generally have access
through vertical doors located at the tubesheet level
and also located at a level near the top of the bags.
All styles of fabric filters can be provided with integral compartments sharing common division walls or
with separate walls forming the compartments. The
latter style is commonly referred to as modular and
generally used on small industrial units.
The gas conveying flues of all styles of fabric filters
can be of a design integral to the compartment casing
walls or totally separated. Most utility size fabric filters utilize common wall construction.
Casing, hoppers and dampers
Enclosure or casing The fabric filter is a metal encased structure with individual bag compartments.
The inlet and outlet plenums are typically located
between two rows of compartments to provide short
inlet and outlet flue connections (see Fig. 8). This enclosure rests on a support steel structure. For reverse
air units, interior access is required at both the lower
tubesheet and bag support elevations. In a pulse jet
filter, access is required above the tubesheet for bag
cage removal. This is provided by large roof access doors
or by a top plenum and a side manway. Typical enclosure materials are carbon steel ASTM A-36 or equivalent under normal coal-fired boiler conditions. The entire enclosure is covered with insulation and lagging
to keep metal temperatures high and to minimize corrosion potential.
Hoppers Each filter compartment has a hopper to
collect the dislodged particulate and to channel its flow
Steam 41 / Particulate Control
to the ash removal system. Most filters also use the hopper as part of the flue gas inlet to each compartment.
Therefore, the hopper is designed with steep sides for ash
removal along with considerations for proper gas flow
distribution. Hopper heaters, level detectors, poke holes
and an access door are common hopper features.
Dampers Each filter compartment may be provided
with both inlet, outlet and on reverse air filters, deflation dampers. These dampers may be manual or
automated. Louver and poppet dampers are normally
used. Dampers allow isolation of compartments for
offline cleaning and online service entry. Some units
include bypass dampers.
Bag materials and supports
Substantial research and development on bags and
their materials have taken place to lengthen their life
and to select bags for various applications. (See Table
1.) The flexing action during cleaning is the major factor affecting bag life. Bag blinding, which occurs when
small particulate becomes trapped in the fabric interstices, limits bag life by causing excessive pressure drop
in the flue gas. Finishes on the bag surface are also
used to make some bags more acid resistant and to
enhance cleaning.
The most common bag material in coal-fired utility
units with reverse fabric filters is woven fiberglass.
Typical bag size is 12 in. (305 mm) diameter with a
length of 30 to 36 ft (9.1 to 11.0 m). Bag life of three
to five years is common. The shake deflate filters also
use mostly fiberglass bags. On both of these units, the
fiberglass bag is fastened at the bottom to a thimble
in the tubesheet. At the top, a metal cap is fitted into
the bag and the bag has a spring loaded support for
the reverse air filters. The bags are attached to the
tubesheet commonly using a thimble and clampless
designed bag. The upper operating temperature limit
is 500F (260C) for most fiberglass bags.
The most common bag material in coal-fired utility
units with pulse jet fabric filters is polyphenylene sulfide (PPS) needled felt. In addition to polyphenylene
sulfide, fiberglass, acrylic, polyester, polypropylene,
Nomex®, P84®, special high temperature fiberglass media, membrane covered media, and ceramic are used
in various applications. For the pulse jet filters, the
typical bag size is 5 or 6 in. (127 or 152 mm) diameter
round or oval with a length of 10 to 26 ft (3 to 8 m).
Advances in cleaning technology are increasing the
ability to provide longer bags. Pulse jet bags are commonly sealed to the tubesheet using a snap-band seal.
The bag is supported internally from a metal wire cage
to prevent bag collapse during operation. Cages are
normally carbon steel and may include a variety of
coatings from pre-galvanized to coated wire. Some applications use a stainless steel cage.
Filter media cleaning
Reverse air fabric filters employ the most gentle form
of cleaning. The method dislodges collected particulate
by closing compartment dampers and, with the use of a
reverse air fan, reversing the direction of gas flow. During reverse flow, gas passes from the outside of the bag
to the inside, dislodging the collected ash from the in33-11
The Babcock & Wilcox Company
side surface of the bag. Sonic horns have proven successful is certain applications to assist in reverse air cleaning.
The shaker style of cleaning begins with the isolation of a compartment. Next, mechanical energy in the
form of sinusoidal acceleration is applied to the top of
the bag and travels along the bag to dislodge the material caked on the filter.
Pulse jet cleaning can be accomplished with all compartments operating, which is more normal, or by removing a compartment from service. Pulse air varies
from low pressure, high volume to high pressure, low
volume. The components of most pulse cleaning systems are similar. Blowers or air compressors are used
to supply the cleaning air. Pulse valves are rapid opening and closing valves. Air is discharged from the outlet of the pulse valve along a supply pipe to nozzles or
holes for discharge into the top of the bag. This air inflates the bag, dislodging collected filter cake from the
outside surface of the bag. The more common style of
pulse system has fixed supply pipes called blowpipes. An
alternate type of pulse system has a rotating blowpipe.
A wet scrubber can be used to collect particulate
from a flue gas stream with the intimate contact between a gas stream and the scrubber liquid. The venturi-type wet scrubber (Fig. 11) is used to transfer the
suspended particulate from the gas to the liquid. Collection efficiency, dust particle size and gas pressure
drop are closely related in the operation of a wet scrubber. The required operating pressure drop varies inversely with the dust particle size for a given collection
efficiency; or, for a given dust particle size, collection
efficiency increases as operating pressure drop increases.
Due to the excessive pressure drop and the stringent particulate regulations, wet particulate scrubbers
are now infrequently used as a primary collection device. However, on most coal-fired applications where
wet FGD scrubbers are required in series with a high
efficiency collector for control of acid gas emissions, the
extra particulate removal of the FGD scrubber is an
added benefit.
Mechanical collectors
Equipment selection
Mechanical dust collectors, often called cyclones or
multiclones, have been used extensively to separate
large particles from a flue gas stream. The cyclonic
flow of gas within the collector and the centrifugal
force on the particulate drive the particulate out of the
flue gas (Fig. 10). Hoppers below the cyclones collect
the particulate and feed an ash removal system. The
mechanical collector is most effective on particles
larger than 10 microns. For smaller particles, the collection efficiency drops considerably below 90%.
Mechanical collectors were adequate when the emissions regulations were less stringent and when popular firing techniques produced larger particles. These
collectors were frequently used for reinjection to improve unit efficiency on stoker firing of coal and biomass.
With stricter emissions regulations, mechanical collectors
can no longer be used as the primary control device.
However, with the onset of fluidized-bed boilers, there
has been a resurgence of mechanical collectors for recirculating the bed material. A high efficiency collector
is then used in series with the mechanical one to meet
particulate emissions requirements. (See Chapter 17 for
more information on fluidized-bed combustion.)
Major evaluation factors to consider when selecting particulate control equipment include emissions
requirements, boiler operating conditions with resulting particulate quantity and sizing, allowable pressure drop/power consumption, combined pollution control requirements, capital cost, operating cost, and
maintenance cost. For new units that must meet the
stringent federal, state and local regulations, the selection is reduced to a comparison of electrostatic precipitators and fabric filters because these are the only
high efficiency, high reliability choices. For retrofits
on operating units, the performance of existing control equipment as well as unique flue gas conditions
may require specialized equipment.
The advantages of a well designed ESP are high
total collection efficiency, high reliability, low flue gas
pressure loss, resistance to moisture and temperature
upsets, and low maintenance. Advantages of a fabric
filter include high collection efficiency throughout the
particle size range, high reliability, resistance to flow
upsets, little impact of ash chemical constituents on
performance, and good dustcake characteristics for
combination with dry acid gas removal equipment.
Wet particulate scrubbers
Table 1
Fabric Filter Typical Media Applications
Fabric
Filter Type
33-12
Construction
Materials
Reverse gas
Shake deflate
Woven
Treated
fiberglass
Pulse jet
Felted
PPS
Nomex
P84
Acrylic
Polyester
Typical Maximum
Operating Temperature
Chemical
Resistance
500F (260C) ±
Acid resistant
coatings available
Ambient to 350F (177C) ±
depending on specific
media selected
Highly variable
consult manufacturer
Steam 41 / Particulate Control
The Babcock & Wilcox Company
Fig. 11 Venturi-type wet scrubber.
Fig. 10 Mechanical collector.
Plants equipped with dry scrubbing systems will typically require a fabric filter if high SO2 collection efficiencies (greater than 90%) are required due to the
secondary scrubbing effect of the fabric filter. A comparison of overall and particle size collection efficiencies for precipitators and fabric filters is shown in Fig.
7. An application where small particulate dominates
would favor a fabric filter for maximum control as long
as bag blinding does not occur.
For those applications where an ESP or fabric filter is technically acceptable and high collection efficiencies are required, some general guidelines on initial capital costs are: 1) on small units, a pulse jet fabric filter is generally more economical, 2) on units with
medium or high sulfur coal, an ESP is economical, and
3) on low sulfur coal-fired large units, a pulse-jet fabric filter may again be more economical. However, when
operating and maintenance costs are also considered,
the lowest capital cost may not provide the lowest overall
cost. Therefore, it is important to perform a detailed
engineering study to quantify all of the variables for a
specific site to obtain a true assessment of the real cost.
References
1. White, H.J., Industrial Electrostatic Precipitation,
Addison-Wesley Publishing Company, Reading, Massachusetts, 1963.
2. United States Code of Federal Regulations, Title 40, Vol.
6, Part 60, Subparts D, Da, Db and Dc, Revised July 1,
2003.
3. Federal Register, Environmental Protection Agency, 40
CFR Part 60, Vol. 55, No. 177, September 12, 1990.
4. Lane, W.R., Khosla, A., “Comparison of Baghouse and
Electrostatic Precipitator Fine Particulate, Trace Element
and Total Emissions,” ASME-IEEE Joint Power Conference, Indianapolis, Indiana, September 27, 1983.
5. Electrostatic Precipitator Gas Flow Model Studies,
Publication No. EP-7, Institute of Clean Air Companies,
Washington, D.C., Revised 1997.
6. Staehle, R.C., Triscori, R.J., Kumar, K.S., et al., “The
Past, Present and Future of Wet Electrostatic Precipitators in Power Plant Applications,” Paper 207 presented to
the Combined Power Plant Pollution Control Mega Symposium, Washington, D.C., May, 2003.
7. Bustard, C.J., et al., Fabric Filters for the Electric Utility Industry, Vol. 2, EPRI CS-5161, Electric Power Research Institute, Palo Alto, California, 1988.
8. Bagwell, F.A., Cox, L.F., and Pirsh, E.A., Design and
Operating Experience With a Filterhouse Installed on an
Oil-Fired Boiler, Air Pollution Control Association, June,
1969.
COHPAC is a trademark of Electric Power Research Institute, Inc.
Nomex is a trademark of E.I. du Pont de Nemours Company.
Orimulsion is a trademark of Bitumenes Orinoco, S.A.
P84 is a trademark of Inspec Fibres GmbH.
Steam 41 / Particulate Control
33-13
The Babcock & Wilcox Company
Pulse jet fabric filter under construction at a 550 MW power plant.
33-14
Steam 41 / Particulate Control
The Babcock & Wilcox Company
Chapter 34
Nitrogen Oxides Control
Nitrogen oxides (NOx) are one of the primary pollutants emitted during combustion processes. Along
with sulfur oxides (SOx) and particulate matter, NOx
emissions contribute to acid rain and ozone formation,
visibility degradation, and human health concerns. As
a result, NOx emissions from most combustion sources
are regulated, monitored, and require some level of
control. This control is closely tied to the combustion
process and to various boiler system components.
NOx formation mechanisms
NOx refers to the cumulative emissions of nitric oxide (NO), nitrogen dioxide (NO2), and trace quantities
of other nitrogen-bearing species generated during combustion. Combustion of any fossil fuel generates some
level of NOx due to high temperatures and the availability of oxygen and nitrogen from both air and fuel.
NOx emissions from fired processes are typically 90
to 95% NO with the balance NO2. However, once the
flue gas leaves the stack, most of the NO is eventually oxidized in the atmosphere to NO2. It is the NO2
in the flue gas which contributes to the brownish
plume sometimes seen in a power plant stack discharge.
There are two principal mechanisms of NOx formation in steam generation: thermal NOx and fuel NOx
which are explored more in depth below. An additional
source is prompt NOx. Prompt NOx is produced in fuelrich conditions by a complex series of reactions between
hydrocarbon radicals and molecular nitrogen in the
flame zone, resulting in the formation of amines and
cyano compounds and their subsequent oxidation to
NO.1 It is a relatively small contributor to total NOx
formation, especially in the combustion of coal and
other nitrogen-containing fuels.
Thermal NOx
Thermal NOx refers to the NOx formed through
high temperature oxidation of the nitrogen found in
the combustion air. The formation rate is a function
of temperature as well as residence time at temperature. Significant levels of NOx are usually formed
above 2200F (1204C) under oxidizing conditions, with
exponential increases as the temperature is increased.
At these high temperatures, molecular nitrogen (N2)
Steam 41 / Nitrogen Oxides Control
and oxygen (O2) dissociate into their atomic states and
participate in a series of reactions.2,3 One product of
these reactions is NO. Since the traditional factors
leading to complete combustion (high temperatures,
long residence time, and high turbulence or mixing)
all tend to increase the rate of thermal NOx formation,
some compromise between effective combustion and
controlled NOx formation is needed.
Thermal NOx formation is typically controlled by
reducing peak and average flame temperatures. Controlled mixing burners can be used to slow the combustion process. A second approach is staged combustion, where only part of the combustion air is initially
added to burn the fuel; the remaining air is added
separately to complete the combustion process. A third
method is to mix some of the flue gas with the combustion air at the burner, referred to as flue gas recirculation (FGR). This increases the gas weight which must
be heated by the chemical energy in the fuel, thereby
reducing the flame temperature. Refer to Chapters 10
through 17 for more detail on the combustion processes
and the fuel effects on NOx formation.
Fuel NOx
The major source of NOx emissions from nitrogenbearing fuels such as coal and oil is the conversion of
fuel-bound nitrogen to NOx during combustion. Laboratory studies indicate that fuel NOx contributes approximately 50% of the total uncontrolled emissions
when firing residual oil and more than 80% when firing coal. Nitrogen found in these fuels is typically
bound to the fuel as part of organic compounds. During combustion, the nitrogen is released as a free radical to ultimately form NO or N2. Although it is a major
factor in NOx emissions, only 20 to 30% of the fuelbound nitrogen is converted to NO.
The majority of NOx formation from fuel-bound nitrogen occurs through a series of reactions that are
not fully understood. However, it appears that this
conversion occurs by two separate paths (see Fig. 1).
The first path involves the oxidation of volatile nitrogen species during the initial phase of combustion.
During the release and prior to the oxidation of the
volatile compounds, nitrogen reacts to form several
intermediate compounds in the fuel-rich flame re34-1
The Babcock & Wilcox Company
estimated that NOx contributes less than one-third of
the acid rain generated.
Particulate matter
NOx emissions can also contribute to fine, ambient
particulate matter. In the atmosphere, NOx reacts with
other airborne chemicals to form nitrates, which contribute to the less than 2.5 micron particulate
(inhalable portion of the ambient pollutants). NOx also
promotes the transformation of SO2 into sulfate particulate compounds that can also be less than 2.5 microns in size.
Fig. 1 NOx formation from nitrogen contained in coal during combustion.
gions. These intermediate compounds are then oxidized to NO or reduced to N2 in the post-combustion
zone. The formation of either NO or N2 is strongly
dependent on the local fuel/air stoichiometric ratio. It
is estimated that this volatile release mechanism accounts for 60 to 90% of the fuel NOx contribution.
The second path involves the release of nitrogen
radicals during combustion of the char fraction of the
fuel. These reactions occur much more slowly than the
reactions involving the volatile species.
Conversion of fuel-bound nitrogen to NOx is strongly
dependent on the fuel/air stoichiometry but is relatively independent of variations in combustion zone
temperature. Therefore, this conversion can be controlled by reducing oxygen availability during the
initial stages of combustion. Techniques such as controlled fuel-air mixing and staged combustion provide
a significant reduction in NOx emissions by controlling stoichiometry in the initial devolatilization zone.
Global effects of NOx in atmosphere
Once in the atmosphere, the NO2 is involved in a
series of reactions that form secondary pollutants. The
NO2 can react with sunlight and hydrocarbon radicals to produce ground level ozone/photochemical (urban) smog, acid rain constituents, and particulate
matter.4 Each of these formations can have a significant effect on human health and on the environment.
Automobiles and other vehicles are the major source
of NOx emissions with greater emissions concentration
in the large metropolitan areas (see Fig. 2). Utility
power plants and other fossil fuel burning steam generation sources also contribute to global NOx emissions.
Acid rain
NOx and sulfur dioxide (SO2) contribute to the formation of acid rain, which includes a dilute solution
of sulfuric and nitric acids with small amounts of carbonic and other organic acids. The NOx and SO2 react
with water vapor to form acidic compounds; these acids account for more than 90% of acid rain. Nitric acid
is formed through the reaction:
NO2 + OH → HNO3
(1)
Most acid rain control has concentrated on SO2 contributions instead of those due to NOx because it is
34-2
NOx control technologies in steam generation
Combustion technology-based NOx control (see Chapters 11 through 16) is typically the lowest cost solution,
provided it meets local and federal emissions requirements. Where further control is needed, fuel switching
is used and/or post-combustion control is added.
Pre-combustion fuel switching
Unlike sulfur and particulate constituents in coal,
nitrogen species contained in the fuel can not be easily reduced or removed. Therefore, the most common
pre-combustion option for reducing NOx levels is to
switch to a fuel with inherently lower nitrogen content. For boilers capable of firing multiple fuels with
minimal impact on the steam cycle, this may be the
most cost-effective solution.
Coal combustion generally produces the highest
NOx emissions. Oil combustion generates less NOx
while gas firing produces even less. When firing oil
fuels, a reduction in fuel nitrogen content results in
reduced NOx emissions. However, there does not appear
to be a similar correlation between coal nitrogen content
and NOx formation. Other factors in coal chemistry, including volatile species, oxygen, and moisture content,
appear to dominate the formation of NOx during coal
combustion. Therefore, reducing coal nitrogen content
may not provide a corresponding NOx reduction.
Other
6%
Other Combustion
5%
Transportation
55%
Industrial
Combustion
12%
Utility
Combustion
22%
Fig. 2 Sources of United States NOx emissions – 2001.
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
Combustion control
NOx formation is promoted by rapid fuel-air mixing.
This produces high peak flame temperatures and excess available oxygen which, in turn, promotes NOx
emissions. Combustion system developments responsible for reducing NOx formation include low NOx burners (see Fig. 3), staged burning techniques, and FGR.
The specific NOx reduction mechanisms include controlling the rate of fuel-air mixing, reducing oxygen
availability in the initial combustion zone, and reducing peak flame temperatures. These are explored further in Chapters 11 through 16.
Transition Zone
Sliding Air Damper
Sliding Air
Damper Drive
Fixed
Vane
Adjustable
Inner Vanes
Air
Measurement
Pitot Grid
Adjustable
Outer Vanes
Transition
Zone
Burner
Elbow
Post-combustion reduction
With current and proposed regulations, it is economically logical to consider NOx controls that achieve
the lowest emission levels possible. Additional NOx
control techniques can be applied downstream of the
combustion zone to achieve the further reductions.
These post-combustion control systems are referred to
as selective catalytic reduction (SCR) and selective
noncatalytic reduction (SNCR). In either technology,
NO x is reduced to nitrogen (N 2 ) and water (H 2 O)
through a series of reactions with a reagent (or reagents) injected into the flue gas. The most common
reagents used in commercial applications are ammonia and urea for both SCR and SNCR systems.
SCR can effectively reduce NOx levels leaving the
boiler by 90% or greater depending on the specific
project and space availability. SNCR typically is limited to lower NOx reduction levels but may be the more
economical choice depending on the required NOx reduction or the unique project requirements. Both technologies have been successfully applied for NOx reduction on multiple fuels and boiler types.
A combination of combustion and post-combustion
NOx control is frequently the most economical approach for existing installations and is the favored
approach for installations that can not achieve emissions by combustion alone.
Selective catalytic reduction
Selective catalytic reduction technology is currently
the most effective method of post-combustion NOx reduction. SCR technology has been applied to a variety of fuels including natural gas, refinery gas, coals
(bituminous, subbituminous, and lignite), fuel oils, petroleum coke, Orimulsion®, biomass, and refuse. It has
been applied with conventional boilers as well as fluidized-bed boilers, process heaters, steel mill furnaces,
and combined cycle gas turbines. SCRs have also
been successfully installed on gas turbine based systems, reciprocating engines, and nitric acid plants. The
technology and performance are sensitive to temperature and flue gas constituents and therefore are more
closely related to boiler operation than are other types
of environmental control equipment.
Initial development of SCR technology began in Japan around 1963. Early laboratory tests included the
evaluation of many catalyst formulations and their life
expectancies, as well as process design optimizations.
Steam 41 / Nitrogen Oxides Control
Primary Air/
Pulverized Coal Inlet
Main Sliding
Air Damper
Sliding
Linkage
Fig. 3 DRB-4Z® low NOx burner for coal firing.
Development tests were followed by several catalytic
pilot plant installations during the early 1970s; the
first commercial installations occurred in 1978.
NOx reduction process
In the SCR process, a catalyst facilitates a chemical reaction between NOx and a reagent (usually ammonia) to produce nitrogen and water vapor. The most
common and predominant reactions are represented
by the following equations. While the reactions are
exothermic, the temperature rise across the catalyst is
typically negligible due to the low NOx concentrations.
4NO + 4NH3 + O2 → 4N 2 + 6H2O
(2)
NO + NO2 + 2NH3 → 2N 2 + 3H2O
(3)
As shown in Fig. 4, the ammonia (NH3) is injected
into the hot flue gas through an injection grid, the flue
gas with the ammonia passes across the catalyst surface, and the NOx reactions occur within the micropores
of the catalyst. Nitrogen oxides are present in flue gas in
the form of both NO and NO2 with NO being the greater;
however, NO2 is preferentially reduced in this process.
SCR system description
While the main component of the SCR process is the
catalyst, the full system contains a variety of components and subsystems. The catalyst is housed in a
Fig. 4 Principles of NOx removal process for SCR.
34-3
The Babcock & Wilcox Company
large reactor. Flue gas is directed to and from the reactor by large flues that may contain control and shutoff dampers as well as flow distribution devices and
static mixers, depending upon project-specific requirements. The reactor is a gas-tight steel enclosure that
permits the flue gas and reagent to contact the catalyst for the required residence time to achieve design
performance. The reactor structure includes internal
stiffeners and a catalyst support system that also permits rapid loading and unloading of catalyst materials. The design includes a sealing system to avoid flue
gas bypass, and may include catalyst cleaning devices
(sootblowers and/or sonic horns). The reactor can be
configured for vertical or horizontal flue gas flow depending upon the fuel, space availability, and upstream and downstream equipment. Separate economizer and SCR flue gas bypass flues are frequently
included.
The reagent (usually ammonia) subsystems include
truck or rail unloading, storage, vaporization or hydrolysis equipment, flow control, dilution air supply
and mixing, and reagent distribution and injection
components. Each subsystem contains piping valves,
instrumentation, controls and safety equipment for
appropriate ammonia handling and material compatibility. Further details are provided in subsequent sections of this chapter.
A critical part of SCR system design is integration
into the overall boiler system. This is particularly important because the SCR system is normally integrated into the heat recovery portion of the boiler system between the close-coupled economizer and air
heater. As a result, SCR system design must accommodate swings in flue gas temperature while maintaining the desired performance, without affecting
boiler operation.
Hot side/high dust The ideal gas temperature for NOx
reduction ranges from 700 to 750F (371 to 399C). In
utility boilers, this places the typical SCR system at
the economizer outlet, preceding the air heater. (See
Fig. 5.) This is the hot side location for all fuel types
and the high dust location for ash-laden fuels. Units
with hot side electrostatic precipitators (ESPs) can locate the SCR between the ESP and air heater to take
advantage of the ideal temperature and to avoid ash
effects on the catalyst. This has been labeled hot side/
low dust. For some boiler applications, the ideal temperature range does not occur at a convenient location, and system design therefore requires special accommodations, such as a split economizer.
Cold side/low dust An alternative SCR location is
after the air heater and particulate collection or flue
gas desulfurization (FGD) systems, as shown in Fig.
6. SCRs installed in these arrangements are designated as cold side/low dust. These systems include all
of the components referenced previously, but must also
include a method to increase the flue gas temperature.
On utility boiler applications, the cold side location has
been reserved for retrofit installations where lack of
space and outage duration have driven the decision.
The additional equipment required for this design may
include gas-to-gas air heaters, high pressure steam
heat exchangers, duct burners, or a combination of
34-4
Ammonia
Injection
Grid
Furnace
Future
Catalyst
Catalyst
SCR
Air Heater
Flue
Gas
Outlet
Fig. 5 New utility boiler with SCR.
these components. When installed after an FGD system or on a low sulfur fuel and after the particulate
collector, this typically results in a design gas temperature of 600 to 650F (316 to 343C). This arrangement
also allows a constant operating gas temperature
throughout the boiler load range.
Industrial boiler applications may have a greater
need for this arrangement. Package boilers may require
a duct burner to achieve the required gas temperature.
Boiler systems for biomass or refuse/waste fuels that
contain rapid catalyst deactivation components should
also consider the cold side/low dust arrangement.
Sonic Horn
SCR
Gas
Flow
Mixer
Gas
Flow
Ammonia
Injection
Mixer
Duct
Burners
Catalyst
Stack
Gas-to-Gas
Air Heater
Gas
Flow
Gas Flow
Gas
Flow
Fig. 6 SCR located after air heater.
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
Catalyst
Catalyst formulation, pitch and sizing are the keys
to successful SCR system application and performance. Although catalyst formulations are proprietary, the most common components in steam generation applications use titanium dioxide with small
amounts of vanadium, molybdenum, tungsten, or a
combination of other active reagents. Formulation is
matched to the flue gas conditions based on ash-free
flue gas, low-ash flue gas, high-dust flue gas and the
ash constituents.
Catalyst types Catalyst types and materials typically
fall into one of three categories: base metal, zeolite,
and precious metal.
Most steam generation experience has been with
base metal catalysts. These are typically described as
titania-vanadia and can be provided as plate type,
honeycomb type, or corrugated fiber type (see below).
All three are similar in performance characteristics and
can be supplied in a homogeneous construction or as
a coated active layer on a base material.
The plate type catalyst (Fig. 7) is manufactured from
a roll of stainless steel expanded metal substrate. The
homogeneous catalyst is paste-pressed into and
around the substrate to form a catalyst plate of 0.9 to
1.0 mm thickness. After cutting to length, correctly
sized undulations, to set the catalyst pitch, are formed
onto each plate prior to final processing and drying.
The completed plates are then assembled into encased
blocks; multiple blocks are packaged into a metalframe shipping module. (See Fig. 8.)
Homogeneous honeycomb catalyst (see Fig. 9) is
formed in an extrusion process that produces a catalyst log approximately 6 in. × 6 in. (152 × 152 mm) in
cross section with the selected honeycomb cell pitch,
and cut to proper length. After final processing and
drying, the logs are assembled and packaged into
metal-frame shipping modules.
Corrugated catalyst (Fig. 10) consists of a corrugated glass fiber substrate coated with titanium dioxide. After further processing, the base is impregnated
with the active components. This catalyst is more porous and lighter than either the honeycomb or plate
type. The resulting catalyst is cut to size and assembled
into encased blocks and metal-frame shipping modules.
Fig. 7 Plate-type catalyst block.
Steam 41 / Nitrogen Oxides Control
Fig. 8 Installation of catalyst blocks.
Zeolite catalysts are less common than the base
metal catalysts but are effective in certain applications.
These are aluminosilicate materials which function
similarly to base metal catalysts. One advantage is the
higher allowable operating temperature of greater than
1000F (538C). This catalyst will also oxidize SO2 to SO3,
is more sensitive to ash-laden flue gas, and is best applied to clean flue gas projects. Zeolite catalysts offer
advantages for simple cycle gas turbines.
Most precious metal catalysts are manufactured
from platinum and rhodium. There is little operating
experience with these catalysts in steam generation
systems. They also require careful consideration of flue
gas constituents and operating temperatures. While
effective in reducing NOx at gas temperatures below
Fig. 9 Honeycomb catalyst geometry.
34-5
The Babcock & Wilcox Company
Fig. 10 Corrugated catalyst geometry (courtesy of Haldor Topsoe, Inc.).
550F (288C) without reagent, these catalysts can also
be used as oxidizing catalysts, converting CO to CO2
under proper temperature conditions. However, SO2
oxidation to SO3 and high material costs often make
these catalysts less attractive and limit the application
to clean flue gas. Some catalyst manufacturers have
combined the precious metal and base metal catalysts
to allow both NOx reduction and CO oxidation within
one catalyst chamber.
Sizing criteria Catalyst performance depends on the
surface area velocity, enabling the NOx reduction reactions to occur. A common term that relates catalyst
volume with a specific surface area is space velocity
(Sv), expressed as Equation 4.
Sv = flue gas flow (Nm3 / hr)
/ catalyst volume (m3 )
(4)
Thus, the greater the space velocity the less catalyst
required. Each catalyst configuration and formulation
has a unique base space velocity. Catalyst pitch (plate
centerline or cell spacing dimension) and catalyst type
contribute to this space velocity.
A project’s design space velocity is dependent on
many factors. Primary factors include required NOx
reduction, flue gas flow, ammonia slip, gas velocity, flue
gas constituents, required catalyst life, and distribution profiles (gas temperature, velocity, NOx and NH3/
NOx). An iterative process optimizes the selected catalyst volume and arrangement, accounting for gas
velocity, pressure drop and fan adequacy. Typical performance guarantees include NOx reduction/NOx emissions, ammonia slip, catalyst life, pressure drop, ammonia consumption and SO2 oxidation.
Operating issues Catalyst is not consumed during
operation but does deteriorate. Deterioration is typically caused by poisoning, masking or blinding, and
is most pronounced in the high dust arrangement.
Deterioration occurs when the active sites within the
catalyst micro-pore structure become contaminated
and inactive. Moisture in liquid form can accelerate
the deterioration. Operation at gas temperatures
greater than 800F (427C) can also accelerate deterioration due to sintering of the pore structure. In some
cases, poisoning from coal constituents like arsenic can
34-6
be eliminated with limestone addition to the coal. Catalyst management recommendations to address the deterioration issues are provided in a later section.
Catalyst protection is needed for extended boiler
outage periods and when the catalyst is isolated during the periods when high NOx control is not required.
Humidity control and ash removal are necessary.
On projects with SO3 in the flue gas, ammonium
sulfates can deposit on the catalyst surface when gas
temperature is below the precipitation temperature,
as determined by capillary condensation at the ammonia concentration entering the catalyst. Therefore,
a minimum continuous operating temperature is required. At the catalyst outlet there is a concern for
deposits formed by the combination of ammonia slip
and available SO3 in the flue gas. This precipitation
temperature typically occurs within the air heater.
Remedies are provided later in this chapter. SO2 oxidation to SO3 across the catalyst may also increase the
possibility of ammonia bisulfate formation and can
affect downstream corrosion concerns; however, the
amount of deposit is ammonia-limited.
Ammonia reagents and control
Reagents most commonly used today are anhydrous
ammonia, aqueous ammonia, and urea. When urea
is used, it is typically decomposed on site to ammonia,
CO2 and water. Regardless of the source, once the
ammonia is in vapor form, it is common to dilute the
ammonia stream with air to assist with transport, flow
control and injection functions.
A typical ammonia control and supply system is
shown in Fig. 11.
Anhydrous ammonia reagent systems Various grades
of anhydrous ammonia are available. Commercial
grade ammonia is the most common grade used for
SCR systems. It is approximately 99.5 to 99.7% pure
NH3. The remaining fraction is water with a small
amount of oil. The water component helps combat
stress corrosion cracking, which is more likely to occur when the highest metallurgical grade ammonia
at 99.995% pure NH3 is used with standard carbon
steel storage tanks.
Anhydrous ammonia is the purest form of ammonia available and allows the greatest storage volume
efficiency. The storage tanks are typically horizontal,
consisting of a cylindrical section with elliptical ends.
These tanks are designed for the high pressures exhibited by the ammonia vapor at normal ambient conditions. Tank design pressure ratings are usually in
the range of 250 to 265 psi (1724 to 1827 kPa) while
normal operating pressures are generally between 80
and 120 psi (552 to 827 kPa). Storage and use of anhydrous ammonia are considered more hazardous
compared to other reagent systems. This is primarily
due to high concentrations, pressures, volatility, and
explosiveness once it is evaporated to gaseous form.
The typical tank capacity ranges from 10,000 to
100,000 gallons. In the United States (U.S.), federal
and potentially state and local regulations may affect
storage system design. To supply ammonia from the
storage tank to the ammonia injection grid (AIG), the
ammonia is typically vaporized and diluted with the
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
Outlet NO X
Signal
Inlet NOx
Signal
To
NH 3 /Air
Injection Grid
X
Flue Gas Flow
Signal
FC
Mole Ratio Set
Point
NH 3 /Air
Mixer
Flow Control
Valve
Dilution
Air Fan
Ammonia
Storage Tank
Fig. 11 NH3 /dilution air supply and control system.
air transport media. Vaporization can be integral to
the storage tank or separate and closer to the SCR system. Sufficient dilution air is added to produce an
ammonia-air mixture that is not within the combustible
limits of approximately 15 to 30% NH3 in air and to provide sufficient transport media volume for the injection
process. The typical dilution air quantity will yield an
approximate concentration of 5% NH3 in air by volume.
In most cases, the dilution air flow is constant and
the ammonia flow is adjusted to satisfy SCR system
demand based on operating load, flue gas flow, inlet
NOx concentration, and the design or set point NOx
removal or SCR outlet concentration. An in-line static
mixer is typically provided immediately downstream
of the point where ammonia and dilution air combine.
This ensures the mixture is adequately blended prior
to its arrival at the manifold valve station. The manifold valve station controls the flow of this uniform
ammonia-air mixture to individual ammonia injection
locations within the SCR system inlet flue.
Aqueous ammonia reagent systems Aqueous ammonia is a diluted form of ammonia with NH3 dissolved
in water to form NH4OH. Aqueous ammonia is typically available at concentrations up to a maximum of
29.4% [solubility limit at ambient conditions of 86F (30C)
and 1 atm] by weight of NH3 equivalent. This concentration is also frequently described as 26oBé, where degrees baumé is an alternate measurement of density.
In the past, the 29.4% solution was typically preferred to minimize storage volume, cost associated with
transportation weight of water, and cost of water vaporization. However, a legal classification change in the
U.S. now lists ammonia-water solution concentrations
below 20% as non-hazardous. This has encouraged the
industry to consider a 19% concentration. This, however,
increases storage tank volume and vaporization energy
requirements due to the increased water content.
The storage tanks are typically horizontal, similar
to those for anhydrous ammonia. Where anhydrous
ammonia vessels are typically designed for approximately 250 psi (1724 kPa), aqueous tanks are normally rated at 20 to 50 psi (138 to 345 kPa). Tank
material is typically carbon steel. Some installations
utilize stainless steel to avoid startup problems asso-
Steam 41 / Nitrogen Oxides Control
ciated with rust. Most storage system designs will also
incorporate a containment basin in case of a ruptured
line or vessel.
The delivery method and unloading equipment are
typically the same as for anhydrous systems. However,
while the vapor pressure of ammonia in the water solution can present similar vapor lock or cavitation problems when using pumps, the problem potential is less
severe. Therefore, pumped delivery is more common.
Various vaporization methods exist for aqueous
ammonia. Many utilize a spray nozzle to atomize the
aqueous ammonia into a hot dilution air stream in an
evaporation chamber. The vaporized mixture is then
transported to the manifold valve station which in
turn supplies the AIG. Kettle-type systems that utilize an alternate heat source independent of the dilution air have also been used. These systems essentially
boil off the ammonia, which is subsequently mixed
with hot dilution air at a downstream location. The
dilution air is hot in all cases, as it is important to
maintain a stream temperature above the water saturation point during transport to the AIG. Transport
lines are often heat traced and/or heavily insulated
to prevent heat loss along the travel length. When the
dilution air is the source of the heat of vaporization,
the supply temperature must be even higher to account for vaporization and heat loss along the travel
distance. Hot combustion air or flue gas is often used
as the source of dilution medium on clean-fuel applications. Even so, it is sometimes necessary to incorporate electric or steam heaters to maintain minimum
temperature requirements. When dilution air is pulled
from ambient, heater cost and power consumption can
become significant.
Similar to anhydrous systems, the dilution air
quantity is typically that sufficient to provide an approximate 5% by volume NH3 in air. If the design air
temperature is lower than desired and/or the design
ammonia flow demand is high, it can become necessary to dilute to lower NH3 concentrations to maintain
minimum transport temperatures. As with anhydrous
systems, the dilution air flow is typically constant and
the ammonia flow is modulated to satisfy the SCR
system ammonia demand.
Ammonia from urea reagent systems Due to reduced
handling concerns, urea has gained popularity. These
systems utilize the relatively benign urea as the
source of ammonia. Urea is commonly available in
either liquid solution or solid form. The systems attempt to produce ammonia at a rate as close to demand
as possible to essentially eliminate storage issues associated with large quantities of ammonia.
Most of these systems are designed to produce a
gaseous mixture of ammonia, carbon dioxide and
water by the hydrolysis of a urea-in-water solution.
Often, the urea solution is produced at the site by
blending deionized water and solid urea. Solutions are
typically maintained in the 40 to 50% by weight range
to avoid crystallization. Urea has an ammonia equivalence of approximately 53% by weight. The hydrolysis reaction is also endothermic and thus requires heat
input to maintain the reaction. The basic hydrolysis
reaction is as follows:
34-7
The Babcock & Wilcox Company
NH2 CONH2 + H2O → 2NH3 + CO2
(5)
Other processes utilizing either variations on the hydrolysis process, high temperature flash vaporization, or
catalysts are in initial commercial use. The primary goal
among all of these systems is improved safety in transportation, storage, and handling of the required bulk reagent.
While solid urea is less costly to transport, it does
present material handling challenges. The material
tends to melt and break, leading to compaction and
cohesive/adhesive handling and storage problems.
These processes typically produce a moist gaseous
product of approximately 20 to 30% ammonia. Similar to aqueous systems, the presence of water vapor
requires a hot dilution air stream to prevent water
condensation during transport to the AIG. Depending on system design, the dilution air may also be used
to maintain line temperatures above those of undesirable corrosive substances. System capabilities to
produce ammonia at changing demand rates can impact plant operation. The ramp rates of ammonia production may not closely follow the plant boiler load
and subsequent ammonia demand. Due to these variations in system designs, operation and production capabilities, a thorough review is typically needed on a
case-by-case basis.
Ammonia flow controls
As indicated in the equations for the ammonia reaction with the NOx, one mole of ammonia is required
to reduce one mole of NOx and thus the required injection mole ratio of ammonia to NOx is equal to the
required NOx reduction plus the ammonia slip value
(ppm) divided by the inlet NOx concentration (ppm).
The control system logic uses a feed forward and feed
back input with this equation, along with a flue gas
flow input, to provide the ammonia flow control demand. The feed forward input is determined by either
an inlet NOx analyzer or a curve-generated value for
repeatable boiler conditions. The feed back input can
use the output of an SCR outlet analyzer or in some
cases the stack continuous emissions monitor (CEM).
Because of the hazardous nature of the ammonia,
typically there are several interlocks that will interrupt ammonia flow upon upset conditions.
Distribution requirements
SCR reactor performance is influenced by the distribution of velocity, temperature and reacting gas
components through the catalyst bed (see Fig. 12). The
degree of a given profile uniformity can be generally
described by the coefficient of variation (Cv), commonly reported as the percentage of the profile standard deviation from the arithmetic mean value.
σ
100%
x
(6)
n
1
( xi − x )2
( n − 1) ∑
i =1
(7)
Cv =
σ =
34-8
Fig. 12 Typical downflow SCR reactor module.
x =
1 n
∑ xi
n i =1
(8)
where
σ = standard deviation
x = arithmetic mean
SCR reactor distribution goals for flow and molar
ratio are commonly stipulated in this coefficient of
variation format. Temperature distribution criteria is
the exception by typically being expressed as a minimum and maximum (±) deviation about the arithmetic mean. The goal is to achieve the most uniform
profile possible at the SCR catalyst inlet for NOx concentration, ammonia to NOx molar ratio, velocity and
temperature. The degree of uniformity required for
each parameter, coupled with the physical space and
arrangement limitations presented, drives the level of
complexity and intricacy of a successful design. Numerical or physical flow model studies are almost always used to determine the necessary distribution
devices to achieve the desired uniformities.
Velocity distributions Velocity distributions are typically reviewed at two primary locations, at the inlet
to the AIG and at the inlet to the catalyst. The velocity distribution at the AIG can impact the injection and
subsequent or dosing concentration profile of ammo-
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
nia into the flue gas. This is where the initial NH3/NOx
molar ratio variance is produced. Independently controllable AIG injection zones are often incorporated to
allow some compensation for imperfect flow profiles.
These designs offer the ability to improve the ammonia concentration profile by reducing flow to low gas
velocity areas and increasing flow to high velocity
regions.
Variations in flow across the reactor cross section
produce variations in local space velocities. The effect
of this on the overall NOx removal and NH3 slip is
negligible if the Cv is less than 15%.
The high flow zones increase the localized catalyst
operating space velocity. This reduces the residence time
in that region of the catalyst bed. The result is a localized reduction in reagent utilization and efficiency while
producing a corresponding increase in the local ammonia slip concentration. The low velocity areas exhibit the
opposite. These areas allow excess ammonia to be more
effectively utilized. The result is increased local efficiency
and reduced local ammonia slip. The ultimate amount
of excess ammonia in any zone is, however, limited to
that of the local NOx concentration.
When systems process dust-laden gases, the concern for velocity maldistribution extends to the potential for particulate deposition and particle impact induced erosion. The pressure drop across the catalyst
bed can act to rebalance the flow distribution approaching the catalyst bed inlet. Thus, the actual flow
through the catalyst may improve from that measured
upstream. However, when gas approaches with a poor
velocity distribution, the redistribution effect can aggravate erosion and deposition potential. The typical
value for the catalyst inlet velocity coefficient of variation is 15% or less.
Temperature distributions Temperature distribution
concerns are usually associated with the extremes in
the profile. Concerns for reduced catalyst activity and/
or ammonium bisulfate precipitation are associated
with the low temperature zones, while catalyst degradation is a concern in the high temperature areas.
Due to this interest in the extremes, the temperature
distribution requirements are typically expressed as
an allowable range and are often specified as a specific minimum and maximum (±) deviation about the
arithmetic mean.
A commonly specified limit for profile extremes is
±20F (11C). This range is fairly strict when compared
to typical mean values of 550 to 750F (288 to 399C)
and at times can be difficult to satisfy. This is especially true for sulfur-laden gases, which during lowload conditions require a portion of the flue gas to
bypass the economizer to maintain a minimum operating reactor temperature. A review of the specific
catalyst temperature requirements against the expected mean operating temperature can potentially
allow for an increased deviation range.
Ammonia-to-NOx molar ratio distribution Multiple
factors determine the allowable NH3/NOx variation at
the catalyst. These factors include the design NOx removal efficiency, allowable ammonia slip, inlet NOx
concentration, and amount of excess catalyst.
NOx removal efficiency is a significant factor. The
Steam 41 / Nitrogen Oxides Control
ability to satisfy low average and peak ammonia slip
concentrations by the addition of extra catalyst volume becomes exceedingly difficult at high removal
efficiencies. As 100% NOx removal is approached, the
problem is exemplified by the potential for a given
deviation in the mole ratio distribution to produce localized zones in the reactor where the ammonia concentration exceeds that of the NOx concentration. At
these locations, once all of the NOx is removed, no further ammonia can be utilized; the overall average
removal efficiency becomes limited and average slip
is increased. This is particularly problematic for coal
or other sulfur-containing fuel systems where the
average slip is more limited.
While there are no specific break points, systems
designed for NOx removal efficiencies below 80% can
often allow a molar ratio coefficient of variation of 10%
for both coal- and gas-fired projects. In the range of
approximately 80 to 90% NOx removal, the assessment
becomes more complex. Coal or sulfur-laden gas
projects typically require a molar ratio Cv of 5%, where
gas-fired projects may still allow a Cv of 10%. The difference is due to the level of average excess ammonia
reagent. Gas-fired designs usually have higher allowable ammonia slip values, typically on the order of 10
ppm. The resulting increase in excess reagent makes
operation at higher inlet molar ratio maldistributions
more practical. Above 90% removal, the performance
becomes very sensitive to the precise design efficiency,
design slip and inlet NOx level, and a molar ratio Cv
of 5% is typically required. For lower ammonia slip
designs and/or when approaching 95% removal, the
molar ratio Cv may need to move toward values of 3%
or better. Such uniformity levels can require significant mixing and/or flue length.
Injection design and mixing
Two principal factors affect ammonia distributions
prior to the catalyst. One is the degree with which
ammonia disperses or merges from one injection point
to another. The other is the dispersed, but locally
imbalanced, concentrations produced by the imperfect
injection of local ammonia flux to local NOx flux within
the duct. An additional factor, to be discussed later, is
the degree of turbulent mixing occurring in the downstream flue, either naturally or by a forced action (i.e.,
mixing devices). (See Fig. 13.)
The first factor of dispersing ammonia from pointto-point can be improved by increasing the injection
point area concentration or the number of injection
points per square foot (meter). The quantity of injection points required considers the distance from grid
to catalyst and the degree of mixing along that path.
Obviously, there is a point of diminishing returns. The
second factor can be improved by locally adjusting the
ammonia flow to more uniformly inject ammonia flow
into the local NOx mass flux across the injection plane.
Local NOx mass flux is determined by the local volumetric gas flow times the local NOx concentration.
Designing the injection grid with independently controllable zones allows adjustment of the ammonia flow
based on the gas flow variance and NOx concentration variance across this injection plane. This can lead
34-9
The Babcock & Wilcox Company
Ammonia
Injection Grid
Mixing Vanes
Flow
Fig. 13 Turbulent flow model.
to improved final mixtures through better injection,
and a reduced initial molar ratio variance.
Imbalances due to flow and NO x concentration
variations across the plane of ammonia injection are
best addressed by upstream flue gas flow correction,
independently controllable injection zones, and/or
downstream mixing.
Static mixing (blending of multiple fluids across
fixed vanes and/or obstructions) is often incorporated
for high uniformity levels. Static mixing devices (see
Fig. 14) vary in shape, size and functionality. In many
cases, a coordinated approach between the ammonia
injection grid design and the static mixers is required.
The use of static mixers is not without consequences.
The general pros and cons are:
Pros:
1. higher level of achievable uniformity in temperature and/or chemical component distributions,
2. increased stability in the degree of uniformity
achieved, and
3. simpler ammonia injection grid design and/or operation.
agglomerate particles, often referred to as popcorn ash
or large particle ash (LPA), can rapidly cover and block
the inlet catalyst surface if allowed to reach the reactor. Flow model studies and arrangement design reviews are required to address these issues.
Sulfur-containing gases will experience a partial
oxidation of SO2 to SO3 across the catalyst surface.
While typically low, this oxidation level can influence
air heater plugging when ammonium bisulfate is
formed. It is also important when downstream scrubber systems are used and acid mist plume generation
is of concern. Accurate ammonia flow control is required to minimize ammonia slip, and air heater design should consider the recommended features for
reducing sulfate compound deposits.
Retrofit and general equipment issues
When an SCR system is retrofit on an existing
plant, boiler modifications may be necessary for optimum performance. (See Figs. 15, 16 and 17.) Burner
alterations/replacements to reduce furnace outlet NOx
can reduce reactor requirements. However, these same
burner changes may increase furnace outlet NO x
maldistribution, and thus impact ammonia injection
and/or mixing.
Physical space requirements of the reactor are often significant, and can require relocation of existing
plant equipment. Air heaters are sometimes moved to
allow proper flues between the upstream economizer
outlets, the reactor, and the downstream air heaters.
Arrangements become further complicated if economizer flue gas bypass is needed to sustain low load
temperatures.
Air heater cold end surfaces can be enameled for
ease of cleaning and to reduce corrosion. Changes in
air heater surface design, as well as sootblower design
and application, are often considered. These changes
relate to ammonium bisulfate deposition and clean-
Mixing Vanes
Cons:
1. a need for sufficient downstream flue length to
ensure mixer performance,
2. additional pressure drop attributed to the mixer(s),
3. reduced traceability of the injected ammonia path
from a particular injection grid zone to the catalyst, and
4. production of velocity disturbances downstream of
the mixer(s).
Operating issues
In addition to the catalyst operating issues discussed previously, general operating issues and system effects must also be considered.
Ash accumulation in horizontal flues during periods of reduced gas flow can cause buildup to form,
move, and accumulate above the catalyst. Larger ash
34-10
Gas Flow
Fig. 14 Static mixing device for utility boiler SCR.
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
ing concerns when handling sulfur-laden gases and
increased SO3 concentrations.
The source of ammonia dilution air will vary depending on the ammonia system chosen and the nature of the boiler fuel being fired. Gas-fired systems
produce a hot secondary air source that is essentially
free of particulate. The coal-fired systems can exhibit
sufficient entrainment of ash and traces of SO3 into
the secondary air stream of regenerative type air heaters; ammonia vaporization and injection system fouling can preclude using this source of heated air. Ambient air can be used in combination with steam or
electric heaters. Designing for SCR reactor bypass can
present additional arrangement challenges and costs.
A catalyst protection system is also required to maintain dry catalyst conditions.
Pressure drop increase associated with the addition
of flues, ammonia injection systems, mixers and catalyst can exceed existing fan limitations. Higher upstream static pressures in the boiler may also require
costly furnace modifications to raise the design pressure. When new induced draft (ID) fans are added,
other equipment such as precipitators may require a
design pressure review.
The existing sale and/or disposal of flyash can be
influenced by the retrofit. Flyash can absorb a portion of the ammonia, influencing its value as a saleable byproduct. Ammonia off-gassing can also occur
when ammoniated high alkaline ash is wetted, as in
the cement industry.
Whether a retrofit or a new system installation,
structural design costs can be considerable. Catalyst
weights and reactor spans are significant and the reuse and attachment to existing steel can complicate
the analysis and the final design.
Operating system service needs
Due to the effects of flue gas (especially ash-laden),
changes in control valve settings, or subtle changes
in distribution, performance will change with operation. An increase in ammonia slip is the major indicator of this change. Therefore, catalyst activity, AIG
valve settings, ash accumulation, and reactor pressure
loss must be closely monitored.
The catalyst bed will typically contain samples
which can be removed and tested during a short unit
outage. Yearly sample analysis will establish an activity deterioration curve to establish a catalyst man-
Economizer
Bypass
SCR
Bypass
Ammonia Injection
System
Seal Air
Piping
SCR
Reactor
Catalyst
Layer
Sootblower
Damper
Damper
Economizer
Furnace
Low NOX
Burners
Dampers
Future
Catalyst
Seal
Air
Damper
Air Heater
Existing
Structural
Steel
From Ammonia
Storage System
To
Precipitator
New
Structural
Steel
Fig. 15 SCR retrofit on a 655 MW coal-fired boiler.
Steam 41 / Nitrogen Oxides Control
34-11
The Babcock & Wilcox Company
SCR Mixer
Inlet
Damper
Ammonia
Injection
System
SCR
Reactor
Catalyst
Layer
Hot ESP
Future
Catalyst
Economizer
Sonic
Horns
Damper
Flyash
Silo
Economizer
Bypass
From Ammonia
Storage System
SCR
Outlet
Damper
Hot ESP
Furnace
Damper
Damper
SCR
Bypass
Damper
Stack
Air
Heater
Low NOX
Burners
FD Fan
Fig. 16 SCR retrofit on two 600 MW coal-fired boilers.
agement plan. Frequent measurement and tracking
of ammonia in most fly ashes can also be used to monitor reactor and catalyst performance.
Catalyst management activities include catalyst
addition or replacement, depending on reactor design,
and catalyst regeneration. Regeneration techniques
include in-situ washing and catalyst layer removal for
washing by specialists. Regeneration involves the re-
ID Fan
moval of ash from the catalyst surface and, in some
cases, addition of active catalyst components. Some
management plans will require a combination of methods. The cost of regeneration is generally less than the
cost of new catalyst.
Eventually, the catalyst or a potion of the modules
will require disposal due to erosion or unrecoverable
poisoning. Since the catalyst is contaminated with the
Fig. 17 Oil- and gas-fired utility boiler SCR retrofit.
34-12
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
constituents from some fuels, the spent catalyst may
require special landfill disposal procedures. Crushing
of the honeycomb modules to reduce volume, sale of
plate catalyst to steel mills, or negotiating disposal as a
condition of new catalyst purchase are common solutions.
Re-optimization of the AIG control valve settings
may also be required. A potential cause is a change in
flow characteristics throughout the dilution medium
and ammonia systems. Changes in the uniformity of
gas flow, NOx and gas temperature may also lead to
re-optimization.
On high dust applications, cleaning during outage
periods is recommended. Other periodic checks include
removal of water accumulations from anhydrous
ammonia systems, instrument and NO x analyzer
maintenance, and cleaning of impurities from aqueous ammonia and urea systems.
Technology enhancements
SCR advancements have centered on catalyst development for improved erosion resistance, resistance to
chemical deactivation, lower SO2 to SO3 conversion,
greater activity configurations, and an expanded temperature performance range. Catalyst materials such as
zeolite and precious metals are more recent innovations.
Application of neural network control technology
offers the potential to further optimize NOx reduction
for load-following operation.
are needed to assist the reactions. As the temperature
increases within this range, the ammonia or urea may
react with available oxygen to form NOx. This reaction becomes significant at temperatures above 2000F
(1093C) and may become dominant as temperatures
approach 2200F (1204C).
The application of SNCR technology to boilers which
by design have the suitable gas temperatures in the
upper furnace is an attractive use of the technology.
Examples of this boiler type are those applied to municipal solid waste and biomass firing. (See Fig. 18.)
Multiple injection levels are used to maintain NOx
reduction efficiencies at acceptable levels as boiler load
changes. Based on operating experience, four or more
injection levels may be required for larger units. Multiple levels are required because the flue gas temperature profile changes with boiler load and the reagent
injection point must be adjusted accordingly. To determine the most appropriate and effective injection locations, it is common practice to perform both numerical and chemical kinetics modeling of the furnace and
combustion.
When using ammonia reagents with SNCR, it is
important to control the excess unreacted ammonia.
As flue gas temperatures are reduced, the excess
ammonia can react with other combustion species,
primarily sulfur trioxide (SO3), to form ammonium
salts. The major ammonium products formed are ammonium sulfate [(NH4)2SO4] and ammonium bisulfate
Selective noncatalytic reduction technology
There are currently two basic selective noncatalytic
reduction (SNCR) processes available. An ammoniabased system and a urea-based technology have been
developed and commercially operated for many years.
Although there are distinct differences to each technology, the overall processes are similar and will be
presented as the same in the following sections. While
the current emphasis in NOx control has centered on
the SCR technology, SNCR is an effective control technology for certain applications or in combination with
combustion and control system techniques.
NOx reduction reaction
SNCR technologies inject a reducing agent into
NOx-laden flue gas within a specific temperature zone.
In addition, it is important to properly mix the reagent
with the flue gas. Finally, the mixture must have adequate residence time at temperature for the reduction reactions to occur. The chemical reactions for the
processes are represented by:
Ammonia
Urea
4NO + 4NH3 + O2 →
4N 2 + 6H2O
2NO + ( NH2 )2 CO + 1 2 O2 →
2N 2 + 2H2O + CO2
(9)
(10)
The acceptable temperature range for either reaction is 1400 to 2000F (760 to 1093C), although temperatures above 1700F (927C) are preferred. Below
1600F (871C), chemical enhancers, such as hydrogen,
Steam 41 / Nitrogen Oxides Control
Fig. 18 Typical SNCR application for a municipal solid waste boiler.
34-13
The Babcock & Wilcox Company
(NH 4HSO4). Ammonium sulfate, typically formed
when ammonia concentration exceeds SO3 concentrations, is a dry, fine particulate (1 to 3 microns in diameter) that may contribute to plume formation. The
ammonium bisulfate, typically formed when SO3 concentration exceeds the ammonia concentration, is a
highly acidic and sticky compound which, when deposited on downstream equipment such as economizers and air heaters, contributes to significant fouling
and corrosion. The ammonia may also attach to the
ash and affect its reuse or market value.
While NOx reduction levels of 70% are possible under carefully controlled conditions, 30 to 50% reductions in NOx emissions are more typically used in practice to maintain acceptable levels of reagent consumption and ammonia slip.
Most of the current applications for these technologies have been on stoker-fired and fluidized-bed boilers, where the appropriate temperature range and
residence time are available. (See also Chapters 16 and
17.) In large utility units (see Fig. 19), the proper temperature range occurs in the convection pass cavities,
making application, especially on retrofits, more challenging. For these applications, overall control may be
limited to the 20 to 30% range. New boiler applications
may require special design of the boiler convection pass
with a dedicated open cavity in an optimal temperature window for the reactions to occur, although with
current NOx emission requirements this technology
may be limited to lower NOx fuels and processes. Other
flue gas constituents, such as CO, may also affect the
potential reduction achievable with SNCR.
Most SNCR process development has centered on
optimization of the basic process. The use of natural
gas or other injection agents above the reagent injection zone have been studied and installed with some
success to extend the useful NOx reduction temperature range and achieve greater NOx reduction. A combination of SNCR and SCR catalyst to control ammonia slip has also been studied.
Reagent equipment and injection
The SNCR system consists of storage and handling
equipment for the ammonia or urea, equipment for
mixing the chemical with the carrier (compressed air,
steam or water), and the injection equipment. Much
of the equipment is similar to the SCR storage and
handling equipment. The key component, the injection system, consists of nozzles generally located at
various elevations on the furnace walls to match the
expected flue gas operating temperature. The number and location of the nozzles are established by the
supplier and are based on obtaining good reagent distribution within the flue gas.
One major difference between the ammonia and urea
based processes is that the ammonia is usually injected
34-14
into the gas stream in a gaseous state, whereas the
urea is injected as an aqueous solution. The urea technology requires a longer residence time for reactions
due to the time required to vaporize the liquid droplets
once they are in the gas stream. Aqueous ammonia
systems may also be injected as a liquid with additional
residence time required for vaporization.
Emerging technologies
A variety of advanced post-combustion NOx control
systems are at various stages of development and
demonstration. Many of these are combined NOx and
SO2 control systems. While the SNCR and SCR systems discussed here basically feature dry reduction of
NOx by ammonia or urea, advanced systems under
development offer a variety of options, for example wet
(aqueous) or dry absorption by solids, absorption plus
oxidation by a liquid, and absorption plus reduction by
a liquid. Technologies include low temperature NOx
oxidation with injection of an oxidizing agent like
ozone, where NOx is converted to soluble species that
are easily removed with a water wash. Another example
is the injection of a chelating agent to flue gas desulfurization (FGD) slurry to enable NOx scrubbing. Although high NOx reduction is claimed, further development and demonstration of these systems are required.
Fig. 19 Coal-fired utility boiler with SNCR temperature window
location at full and part (control) load.
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
References
1. Miller, J.A., and Bowman, C.T., “Mechanism and Modeling of Nitrogen Chemistry in Combustion,” Presented
at the 1988 Fall Meeting of the Western States Section of
the Combustion Institute, Dana Point, California, October 17-18, 1988.
2. Zeldovich, Y.B., “Oxidation of Nitrogen in Combustion and
Explosion,” Academic des Sciences de L’URSS Comptes
Rendus (Doklady), Vol. 51, No. 3, pp. 217-220, January 30,
1946.
3. Sarofim, A.F., and Pohl, J.H., “Kinetics of Nitric Oxide Formation in Premixed Laminar Flames,” Proceedings
of the 14th International Symposium on Combustion, pp.
739-754, The Combustion Institute, Pittsburgh, Pennsylvania, 1973.
4. “Why NOx? The Costs, Consequences and Control of
Nitrogen Oxides in the Human and Natural Environment,” American Lung Association Report, Washington,
D.C., April, 1989.
Bibliography
Campbell, L.M., Stone, D.K., and Shareef, G.S.,
Sourcebook: NOx Control Technology Data, Publication No.
EPA-600/2-91-029, Prepared for the U. S. Environmental
Protection Agency (EPA), Research Triangle Park, North
Carolina, July, 1991.
Gouker, T.R., and Brundrett, C.P., “SCR Catalyst Developments for the U.S. Market,” Presented at the Joint EPA/
EPRI DeNOx Symposium, Washington, D.C., March 2528, 1991.
Hurst, B.E., and White, C.M., “Thermal DeNOx: A Commercial Selective Non-Catalytic NOx Reduction Process for
Waste-to-Energy Applications,” proceedings of the ASME
Twelfth Biennial National Waste Processing Conference,
Denver, Colorado, June 2, 1986.
Lim, K.J., et al., “Environmental Assessment of Utility
Boiler Combustion Modification NOx Controls,” U.S. Environmental Protection Agency Report, Contract No. 6802-2160, April, 1980.
Perhac, R.M., “Environmental Effects of Nitrogen Oxides,”
1989 Symposium on Stationary Combustion Nitrogen
Oxide Control, Report GS-6423, Vol. 1, Electric Power
Research Institute, Palo Alto, California, July, 1989.
Pohl, J.H., and Sarofim, A.F., “Devolitilization and Oxidation of Coal Nitrogen,” Sixteenth Symposium on Combustion, Massachusetts Institute of Technology, Cambridge, Massachusetts, pp. 491-501, August 15, 1976.
“Selective Catalytic Reduction (SCR) Controls to Abate NOx
Emissions,” A white paper prepared by the SCR Committee of the Institute of Clean Air Companies, Inc. (ICAC),
Washington, D.C., November, 1997.
“Selective Non-Catalytic Reduction (SNCR) for Controlling
NOx Emissions,” A white paper prepared by the SNCR
Committee, of the Institute of Clean Air Companies, Inc.
(ICAC), Washington, D.C., May, 2000.
“Standard on the Storage and Handling of Anhydrous
Ammonia: Extension of the Office of Management and
Budget’s Approval of Information Collection (Paperwork)
Requirements,” 69:42781-42782, OSHA Standards 29 CFR,
1910.111, Occupational Safety and Health Association,
United States (U.S.) Department of Labor, Washington,
D.C., July 16, 2004.
Orimulsion is a trademark of Bitumenes Orinoco, S.A.
Steam 41 / Nitrogen Oxides Control
34-15
The Babcock & Wilcox Company
Coal-fired utility boiler selective catalytic reduction system retrofit.
34-16
Steam 41 / Nitrogen Oxides Control
The Babcock & Wilcox Company
wheel, and associated hardware. Rotary atomization
far dominates (90+%) the utility and large industrial
installed technology base. This is primarily because
the rotary design provides higher slurry flow capacity per atomizer and better performance with higher
solids slurries. Both systems have proven reliable and
capable of consistently achieving low SO2 emissions. Key
performance requirements for SDA atomizers include:
1.
2.
3.
4.
5.
ability to handle variable slurry flow rates,
rapid response to flow rate changes,
uniform spray coverage of the SDA chamber,
low susceptibility to pluggage and build-up, and
ease of removal for servicing.
For rotary atomizers, the spray droplet size distribution is a function of the speed of rotation, wheel diameter and wheel design as well as, to a lesser extent,
reagent slurry feed properties including the flow rate,
viscosity, density, and surface tension.4 Increasing the
wheel speed reduces the droplet size at the cost of
higher power consumption. Note that for a rotary unit,
atomization quality is not sensitive to the diameter of
the exit nozzles and so does not degrade as the nozzles
wear from erosion by the reagent slurry. In addition
to the slurry properties, key design criteria for dualfluid nozzle atomizers include the nozzle exit orifice
dimensions and orientation, air pressure, and air-toslurry ratio. Water spray from a typical dual-fluid
atomizer with multiple exit orifices is shown in Fig.
11. For this system, minimizing formation of large
(+100 micron) drops from primary atomization or the
coalescence of sprays from multiple atomizers is a key
criteria for successful operation.
Fig. 12 shows a compact selective catalytic reduction/SDA/BH installation for a 550 MW power plant.
At this site, the two SDA chambers, each with a single
rotary atomizer, treat approximately 1,800,000 ACFM
(850 m3/s) of flue gases from a pulverized coal-fired
boiler burning Powder River Basin coal to reduce SO2
emissions by 94%.
Process description
The quantity of water in the reagent slurry introduced into the SDA is controlled so that it almost completely evaporates in suspension, leaving the solids
exiting the spray chamber with a free moisture content of 1 to 2%. SO2 absorption takes place primarily
while the water is evaporating and the flue gas is adiabatically cooled by the spray. The difference between
the temperature of flue gas leaving the dry scrubber
and the adiabatic saturation temperature is known as
the approach temperature. Flue gas saturation tem-
Inlet Flue
Gas (Upper)
Rotary
Atomizer
Central
Gas
Disperser
To
Particulate
Collection
Inlet Flue
Gas (Lower)
Fig. 9 Spray dryer absorber cutaway.
35-14
Fig. 10 Rotary atomizer assembly.
Steam 41 / Sulfur Dioxide Control
The Babcock & Wilcox Company
peratures are typically in the range of 115 to 125F (46
to 52C) for low moisture bituminous coals and 125 to
135F (52 to 57C) for high moisture subbituminous
coals. The stoichiometry is the molar ratio of the reagent consumed to either the inlet SO2 or the quantity of SO2 removed in the process. Both definitions are
in common use. Reagent stoichiometry and approach
temperature are the two primary variables that control the scrubber’s SO2 removal efficiency. The optimal
conditions for SO2 absorption must be balanced with
practical drying considerations. The approach temperature selected must be consistent with the atomizer feed slurry solids loading for efficient drying of
the reagent solids. The spraydown, or difference between the inlet and outlet flue gas temperatures, and
the solids loading of the atomizer feed slurry, determine
how much reagent may be introduced to the process.
The predominant reagent used in dry scrubbers is
lime slurry produced by slaking a high-calcium pebble
lime. The slaking process can use a ball mill or a simple
detention slaker. SDA systems that use only lime slurry
as the reagent are known as single pass systems.
Some of the lime remains unreacted following an initial pass through the spray chamber and is potentially
available for further SO2 collection. Solids collected
in the ESP or baghouse may be mixed with water and
reinjected in the spray chamber. This solids recycle system is used at most utility SDA installations to make
use of the available alkalinity inherent in the flyash
and to minimize reagent use. Some of the recycled
Fig. 11 Dual-fluid atomizer.
Fig. 12 B&W’s SDAs and fabric filter baghouse provide an integrated SO2 and particulate removal process.
Steam 41 / Sulfur Dioxide Control
35-15
The Babcock & Wilcox Company
solids form an inert core supporting the finer lime solids on the surface, thereby exposing more lime surface area for SO2 absorption. The flyash may be removed from the flue gas before the SDA by a pre-collector. This is common practice in Europe where marketing of the flyash from coal-fired utility boilers is a
well-established industry practice. Even with flyash
pre-collection, a recycle system results in more efficient
lime utilization.
The process is controlled by monitoring the flue gas
temperature at the SDA outlet to control the amount
of water or recycle slurry added to the atomizer feed.
SO2 emissions at the stack are compared to a desired
operating set point and the lime slurry flow to the atomizers is adjusted to reduce the outlet SO2 as necessary. For a rotary atomizer, the atomizer spindle, which
connects the motor to the atomizer wheel, is monitored
continuously for vibrations to provide an early indication of unbalance or pluggage of the wheel.
Process flow diagram and mass balance
A typical SDA process flow diagram is shown in Fig.
13. The flue gases, with or without pre-collection of
the flyash, enter the spray dryer absorber where the
gas stream is cooled by the reagent slurry spray. The
mixture then passes on to the baghouse for removal
of particulate before entering the ID fan and passing
up the stack. Pebble lime (CaO) is mixed with water
at a controlled rate to maintain a high slaking temperature that helps generate fine hydrated lime
(Ca(OH)2) particles with high surface area in the hydrated lime slurry (18 to 25% solids). A portion of the
flyash, unreacted lime and reaction products collected
in the baghouse is mixed with water and returned to
the process as a high solids (35 to 45% typical) slurry.
The remaining solids are directed to a storage silo for
byproduct utilization or disposal. The fresh lime and
recycle slurries are combined just prior to the
atomizer(s) to enable fast response to changes in gas
flow, inlet SO2 concentrations, and SO2 emissions as
well as to minimize the potential for scaling.
Process mass balances for recycle and single pass
SDA system designs for a typical application are presented in Table 8 while the power requirements are
provided in Table 9. In this example, use of the recycle
system reduces lime consumption by 3141 lb/h (1424.7
kg/h), or 42% over that expected with single-pass operation. The stoichiometry for the single pass system
is 1.78 on an inlet SO2 basis compared to 1.04 for the
recycle system. Note the difference in acceptable approach temperatures for long-term operation of the two
systems. The 7% solids feed slurry with the single pass
system requires operation at a 45F (25C) approach temperature or above for adequate drying while a 30F (17C)
approach is used with the recycle system.
Dry scrubber chemistry
The mechanism of SO2 absorption in an SDA is similar to that attained by wet scrubbing when viewed on
the level of what takes place in the individual slurry
droplets. Most of the reactions take place in the aqueous phase; the SO2 and the alkaline constituents dissolve into the liquid phase where ionic reactions pro35-16
Head Tank
Flue
Gas
Inlet
ESP
Spray
Dryer
Absorber
Baghouse
Stack
Ash
Market
Disposal
Optional Flyash
Pre-Collection
Lime
Recycle
Solids
Process
Water
Water
Recycle
Feed
Lime Feed
Optional Solids Recycle
Fig. 13 Dry scrubber FGD system flow diagram (see Table 8 for
mass balance).
duce relatively insoluble products. The reaction path
can be described as follows:
SO2 ( g ) SO2 ( aq )
Dissolving gaseous SO2
Ca(OH)2 ( s ) → Ca ++ + 2OH−
Dissolution of lime
SO2 ( aq ) + H2O HSO−3 + H+
Hydrolysis of SO2
(24)
(25)
(26)
SO2 ( aq ) + OH− HSO−3
(27)
OH− + H+ H2O
(28)
HSO−3 + OH− SO3= + H2O
Neutralization
Ca ++ + SO3= +
1
2
H2O → CaSO3 ⋅ 1 2 H2O ( s )
Precipitation
(29)
(30)
These reactions generally describe activity that
takes place as heat transfer from the flue gas to the
slurry droplet is evaporating water from the droplet.
The rate-determining reaction may vary at different
stages of the drying and absorption process. The high
pH in the droplet environment (10 to 12.5) helps maintain a low concentration of acid in the liquid phase
that enhances SO2 absorption from the gas stream.
Rapid SO2 absorption occurs when liquid water is
present. The drying rate can be slowed down to prolong this period of efficient SO2 removal by adding deliquescent salts to the reagent feed slurry. Salts such
Steam 41 / Sulfur Dioxide Control
The Babcock & Wilcox Company
Table 8
Mass Balance for Process Flowsheet Shown in Fig. 13
Recycle System Design
Flue gas stream
SDA Inlet
BH Inlet
ID Fan Inlet
A
B
C
Flow rate, ACFM
Flow rate, lb/h
SO2, ppmv
SO2, lb/h
Particulate, lb/h
Temperature, F
Pressure, in. wg
1,729,848
5,244,973
380
4,381
26,835
275
−16.0
1,571,675
5,454,664
89
1,086
148,511
163
−19.5
1,609,250
5,508,400
21
263
76
159
−27.0
Solids/slurry streams
Pebble
Lime
Slaking
Water
Lime
Slurry
Recycle
Solids
Process
Water
Recycle
Slurry
Atomizer
Feed
Byproduct
Solids
1
2
3
4
5
6
7
8
4,394
4,394
48
24,069
0
50
28,463
5,693
114,384
112,096
269
134,747
0
363
249,132
112,096
413
277,594
117,789
100
24,069
0
22,770
20
2,288
98
134,747
0
137,036
45
159,805
42
34,861
34,167
24,273
9,894
694
98
Stream designation
Stream designation
Total flow rate, GPM
Total flow rate, lb/h
Solids flow, lb/h
Flyash, lb/h
Byproducts, lb/h
Water flow, lb/h
Solids loading, wt. %
500 MW boiler burning 0.44% sulfur coal
with high calcium flyash
Available flyash alkalinity = 0.40
milliequivalents/gram
Flue gas saturation temperature = 133F
SO2 emissions reduction = 94%
SO2 emissions rate = 0.05 lb/106 Btu
Particulate emissions rate = 0.015 lb/106 Btu
Single Pass System Design
Flue gas stream
SDA Inlet
BH Inlet
ID Fan Inlet
A
B
C
Flow rate, ACFM
Flow rate, lb/h
SO2, ppmv
SO2, lb/h
Particulate, lb/h
Temperature, F
Pressure, in. wg
1,729,848
5,244,973
380
4,381
26,835
275
−16.0
1,594,410
5,424,712
73
880
40,936
177
−19.5
1,632,843
5,478,350
21
263
76
173
−27.0
Solids/slurry streams
Pebble
Lime
Slaking
Water
Lime
Slurry
Recycle
Solids
Process
Water*
Recycle
Slurry
Atomizer
Feed
Byproduct
Solids
1
2
3
4
5
6
7
8
7,535
7,535
83
41,278
0
86
48,813
9,763
100
41,278
0
39,050
20
Stream designation
Stream designation
Total flow rate, GPM
Total flow rate, lb/h
Solids flow, lb/h
Flyash, lb/h
Byproducts, lb/h
Water flow, lb/h
Solids loading, wt. %
0
0
0
183
91,254
0
0
0
0
269
140,067
9,763
91,254
0
0
0
130,304
7
41,467
40,638
26,787
13,851
829
98
*Process water addition to lime slurry for atomizer feed to achieve desired SDA outlet temperature.
as calcium chloride also increase the equilibrium moisture content of the end product. However, since the
use of these additives alters the drying performance
of the system, the operating conditions must be adjusted (generally increasing the approach temperature) to provide for good long-term operability of the
SDA and the ash handling system. Ammonia injection
upstream of a dry scrubber also increases SO2 removal
Steam 41 / Sulfur Dioxide Control
performance. SO2 absorption continues at a slower rate
by reaction with the solids in the downstream particulate collector.
An SDA/baghouse combination also provides efficient control of HCl, HF and SO3 emissions by the summary reactions of:
Ca(OH)2 + 2HC1 → CaC12 + 2H2O
(31)
35-17
The Babcock & Wilcox Company
Typical Power Requirements for 500 MW
SDA/Baghouse System in Table 8
Recycle System Single Pass
Design
System Design
Atomizers and
accessories, kW
Reagent preparation, kW
Baghouse accessories, kW
ID fan power
Total
% of net 500 MW output
1190
230
445
6780
8645
1.73
640
125
445
6880
8090
1.62
Ca(OH)2 + 2HF → CaF2 + 2H2O
(32)
Ca(OH)2 + SO3 → CaSO4 + H2O
(33)
Proper accounting of the reagent consumption must
include these side reactions, in addition to the SO2 removed in the process.
The SDA process can make use of a variety of water sources for preparation of the reagent slurry and
cooling of the flue gas. River water, well water, cooling tower blowdown, municipal waste water treatment
effluent, and seawater have all been used successfully
in SDA applications. In general, lime slaking requires
good quality water with limitations on the sulfite,
sulfate and TDS concentrations being the primary concerns for producing good quality fresh reagent slurry.
Preparation of the recycle solids slurry and humidification of the flue gas to the desired operating temperature can be achieved with lower quality water sources.
Selection of the process operating conditions must also
consider the chloride content of the water sources to
avoid problems with drying the reagent slurry and
potential corrosion.
Sulfur trioxide (SO3)
SO3 and acid mist formation
Sulfur trioxide (SO3) is formed directly in the combustion of sulfur-containing fuels, and indirectly by
the conversion of small quantities of flue gas SO2 to
SO3 in the presence of iron, some ash constituents such
as vanadium, and some selective catalytic reduction
(SCR) catalysts. Under normal operating conditions
in coal-fired boilers without SCR systems, 0.75% of the
SO2 typically is converted to SO3. High vanadium containing ashes can increase this range to 2%. Conversion of SO2 to SO3 by SCR catalysts is dependent upon
SO2 concentration, gas temperature, and catalyst formulation with a typical range of an additional 0.7 to
1.5%. Catalysts have been formulated with relatively
low SO2 to SO3 oxidation potential.
As the flue gas temperature falls below 1000F
(538C), SO3 begins to react with water in the flue gas
to form sulfuric acid vapor, H2SO4. By the time the flue
gas exits the air heater, virtually all of the SO3 has
reacted to form H2SO4.
35-18
Sulfuric acid condenses on metal surfaces beginning
in the temperature range of 200 to 300F (93 to 149C)
and results in corrosion of metal surfaces in flues, air
heaters, dry ESPs and fans. Acid dew point curves are
presented in Fig. 14. In addition, in units with wet
scrubbers, any significant residual sulfuric acid mist
can cause visible plume or opacity problems (blue
plume), visible several miles from the power plant. Wet
scrubbers are not effective in removing acid mists
because the rapid flue gas quenching in the scrubber
produces submicron aerosol mists which are not easily collected (20 to 30%). Dry scrubbers in combination with downstream baghouses are effective in removing H 2 SO 4 (> 95% typical). Finally, in units
equipped with SCR systems, excess ammonia (NH3)
leaving the SCR can react with SO3 to form sticky,
acidic particles of ammonium bisulfate (NH4HSO4)
which can foul air heaters.
Control methods
Sorbent injection The injection of wet or dry alkali
compounds (usually calcium or magnesium oxide compounds), typically in the furnace, after the SCR, or
upstream of the particulate collection device has been
shown to be an effective means of controlling SO3/
H2SO4. Sorbent injection has the advantage of low
capital cost, but has very high reagent cost due to the
high stoichiometric ratio (4 to 8) that is needed to
achieve 80 to 90% SO3/H2SO4 control. Dry ESP performance may be adversely affected by removing the
SO3 from the flue gas (see Chapter 33).
Humidification Cooling the flue gas by humidification upstream of an existing dry ESP will allow the
dry ESP to collect some sulfuric acid. It is possible to
operate a dry ESP at 20F (11C) below the acid dew
point without encountering excessive corrosion. 20 to
40% sulfuric acid removal can be achieved in some instances. This is possible because the acid is absorbed
on the flyash rather than on the metal surfaces of the
dry ESP. Careful attention must be paid to thermal
insulation integrity and in-leakage of seal air streams.
Ammonia injection Ammonia injection upstream of
the dry ESP has been used to control acid mist. However, there can be problems with ash handling, since
the ash tends to be more cohesive. It is also possible
that excess ammonia will react with the SO3 to form
320
(160)
15% H O
300
(149)
Dew Point, F(C)
Table 9
280
(138)
10% H O
5% H O
260
(127)
240
(116)
220
(104)
200
(93) 0
5
10
15
20
25
30
35
40
45
50
H SO Concentration, ppm Wet Volume
Fig. 14 Dew point versus concentration.
Steam 41 / Sulfur Dioxide Control
The Babcock & Wilcox Company
submicron aerosols that are difficult to collect. Capital costs are low, but reagent costs are high.
Wet precipitator To achieve very high removals of
acid mist, a wet ESP can be used. For a utility boiler,
the wet ESP would be used downstream of the wet
FGD system.
Either a stand-alone arrangement or an integrated
close-coupled wet ESP can be used to control SO3; however, the standalone arrangement is typically more
costly than the integrated design and consumes considerable additional space. Fig. 15 shows the integrated design.
The submicron nature of the acid mist can only be
treated in a multi-field unit. Acid mist removal efficiencies of 80 to 90% can be achieved. For example, if
the inlet is 34 ppmdv, less than 5 ppmdv at the stack
can be achieved. Wet ESP can also remove 80 to 90%
of any solid particulate that is present, such as residual flyash from the dry ESP and the small amounts
of gypsum that result from the wet FGD moisture
separator wash system. Even if a wet ESP is not included in a wet FGD project today, careful thought
should be given to future needs. The addition of a wet
ESP to an existing wet FGD system may not be possible if provisions are not made before the initial wet
FGD system installation.
Purge Air / Heater
Supply Skid
Final Moisture
Separator
Casing
Partition
Wall
Wash
Piping
Collecting
Field
(1 of 3
Shown)
Liquid
Collection
Gutters
Purge Air
Piping
High Voltage
Support Insulator
High Voltage
TransformerRectifier Set
Discharge Electrode
Collecting Electrode
Fig. 15 Integrated wet ESP and wet FGD system.
References
1. “United States (U.S.) Environmental Protection Agency
(EPA), National Emissions Inventory Criteria Pollutant
Data: Current Emissions Trends Summary 1970-2002,”
www.epa.gov/ttn/chief/trends/index.html, accessed August
28, 2003.
2. Annual Energy Review 2002, U.S. Department of Energy, Energy Information Agency, Washington, D.C., November, 2003.
3. Plummer, L.N., Wigley, T.M.L., and Parkhurst, D.L.,
“The Kinetics of Calcite Dissolution in CO2-Water Systems
at 5C to 60C and 0.0 to 1.0 atm CO2,” American Journal
of Science, Vol. 278, pp. 179-216, 1978.
4 Master, K., Spray Drying in Practice, SprayDryConsult
International, Denmark, 2002.
Bibliography
Hardman, R., Stacy, R., and Dismukes, E., “Estimating
Sulfuric Acid Aerosol Emissions from Coal-Fired Power
Plants,” Taken from the Conference on Formation, Distribution, Impact and Fate of Sulfur Trioxide in Utility
Flue Gas Streams, United States Department of EnergyFETC, March, 1998.
Steam 41 / Sulfur Dioxide Control
Lesley, S., “Trends in Emissions Standards,” CCC/77 Report, IEA Clean Coal Centre, International Energy Agency,
London, England, United Kingdom, November, 2003.
35-19
The Babcock & Wilcox Company
Wet flue gas desulfurization module at a utility installation.
35-20
Steam 41 / Sulfur Dioxide Control
The Babcock & Wilcox Company
Chapter 36
Environmental Measurement
Environment related measurements at modern power
plants are primarily performed to determine compliance
with government regulations. However, measurements
are also necessary to monitor and optimize process performance, assess guarantees, calibrate continuous emission monitoring systems (CEMS) and verify design information. As discussed in Chapter 32, fossil fuel power
plants emit air, water and solid pollutants.
This chapter focuses on measurements for monitoring air pollution control systems and, in particular,
equipment for controlling sulfur dioxide (SO2), nitrogen oxides (NOx) and particulate emissions. Special
emphasis is placed on measurements associated with
wet SO2 scrubbing systems which involve perhaps the
most complex process.
Post-combustion emissions can be controlled by the
use of one or more of the following systems: 1) particulate – electrostatic precipitators (ESP) or fabric filters
(baghouses), 2) NOx – selective catalytic reduction
(SCR) systems or selective noncatalytic reduction
(SNCR) systems, and 3) SO2 – wet or dry flue gas desulfurization (FGD) scrubbing systems or other forms
of sorbent injection. These systems are discussed in
Chapters 33, 34 and 35. In each case, the flow rate and
composition must be measured for the associated gas,
liquid and solid streams. In addition, the overall stack
emissions are monitored and recorded.
Instrumentation
Primary measurements taken on environmental equipment include pH, liquid level, solids level, solids concentration (density), continuous emission monitoring for regulated pollutants, static and differential pressure, temperature and flow of liquid, flue gas, air and steam.
Chapter 40 discusses the measurement of pressure,
temperature and fluid flow.
pH measurement
The acidic or alkaline nature of a liquid stream is
monitored by measuring pH or the potential of hydrogen which is expressed as the negative log of the hydrogen ion concentration (–log10 [H+]). This is the most
important parameter in controlling wet FGD systems.
pH measurement is also important in water softening,
Steam 41 / Environmental Measurement
acid neutralization, and other auxiliary processes. The
alkalinity, or lack of acidity, is generally proportional
to the reagent use in the FGD system. Solutions with
a pH less than 7 are considered to be acidic; those
having a pH greater than 7 are alkaline.
pH measurements are used to control the feed of
fresh reagent slurry to the wet FGD system. (See
Chapter 35.) A bleed stream of recirculation slurry is
passed through one or two pH sensors. The outputs
are typically combined with signals for boiler load, SO2
level, fresh reagent slurry density and flow to establish the flow of fresh reagent to the FGD absorber module. An increasing pH reduces the fresh reagent feed
flow and a decreasing pH increases the flow.
pH is measured by means of electrodes and a voltmeter. The electrode (Fig. 1) is an electrochemical device comparable to a battery whose voltage changes
with pH. In combination electrodes, one of the halfcells is the measurement electrode or pH sensing bulb
and the other is the reference electrode or reference
junction. Because the measurement electrode reacts
to the pH of the solution, its potential is variable
though repeatable. Theoretical electrode output varies from +414 mV at a pH of 0 to –414 mV at a pH of
14. The actual output is sensitive to the solution concentration at a reference temperature of 77F (25C).
The reference electrode completes the electrical circuit and produces a comparative voltage, so changes
in the overall sensor are only a function of changes
in the measuring electrode. The reference electrode is
comprised of a potassium chloride (KCl) salt solution
with a controlled amount of silver chloride (AgCl) dissolved in it. An Ag/AgCl electrode is placed into this
electrolyte. The reference potential is a function of the
KCl and AgCl concentrations. For example, a 1.0 M
(molar) KCl electrolyte produces an offset (Ex), or voltage difference from theoretical, of –8 mV, while 3.3 M
KCl produces a –45 mV offset (Ex). The difference,
which is consistent across the entire range, is compensated for by standardization or zero adjustment.
The pH sensor is also affected by temperature. The
slope (mV per pH unit) changes 1 mV per 5C (see Fig.
2). Temperature is compensated for by slope or temperature adjustment or by automatic temperature
compensation.
36-1
The Babcock & Wilcox Company
The pH meter is a voltmeter that measures the electrode potential, converts the potential at a given temperature into pH terms, and corrects for nonideal behavior. pH meter operation depends upon proper standardization and calibration. This is best done with
stable pH solutions known as buffers. Four of the best
buffers, measured at 77F (25C), are pH 4.01, 6.87, 9.18
and 12.45 because they are traceable to the National Institute of Science and Technology (NIST).
Standardization (offset or buffer adjustment) is best
done over the pH range anticipated. Standardization
adjusts the offset so the meter reads 0.0 mV at pH 7.0.
Calibration, or slope adjustment, compensates for alterations in an electrode’s response to pH changes. To
perform the calibration, the buffer should span the pH
of the measured solution. For example, if the expected
process pH is 5.4, then a buffer near pH 4 is preferred.
The standardization/calibration procedure is summarized below:
1. standardize using a pH 6.87 buffer,
2 calibrate with a buffer that spans the process pH
using a different adjustment than that used for
standardization (calibration or slope), and
3. use the correct temperature setting, use an automatic temperature compensator or use the same
temperature for the two buffers and the process.
Fig. 1 Combination pH electrode (laboratory version).
The pH electrode used in wet FGD processes may
be subject to fouling and aging. This is compounded
by the slurry’s abrasive or scaling nature which can
cause plugging of the liquid junction. This junction is
the point where the KCl reference solution meets the
solution being measured. The liquid junction can be
a small hole or may be made of fiber, wood, porous ceramic, Teflon or kynar. It holds the electrolyte in the
probe and enables the electrolyte to form a salt bridge
with the measured solution.
There are three types of pH sensors: dip, flowthrough and insertion. The dip sensor is inserted into
the tank and can be removed for maintenance and
calibration. The flow-through sensor is placed in a
flowing stream of process solution. The insertion sensor is a variation of the flow-through sensor, but does
not require sample lines. It is inserted through packing and a valve into the flowing stream. To maintain
or calibrate the insertion sensor, it is retracted through
the valve, which is then closed to isolate the process.
All sensor types have advantages and disadvantages. The dip sensor is easy to maintain but prone to
leakage from scrubber vessels that operate at positive
pressure. Sample lines for flow-through sensors can
plug. Both flow-through and insertion types are subject to high rates of erosion. All types are subject to scaling, although ultrasonic cleaning devices that are designed to remove brittle, insoluble coatings have been
used with some success. Ultrasonic cleaners work best if
used intermittently, but they can cause probe breakage.
36-2
Liquid level
Liquid level measurement is needed in any liquid
storage tank that is not of the overflow design to control flow into and out of the tank. Examples in a wet
FGD system (Chapter 35) include the tanks for absorber slurry recirculation, reagent storage, thickener
underflow and quench recycle. In a typical dry FGD
system, slurry levels in the lime feed slurry tank, recycle slurry tank and atomizer head tank are monitored. Common liquid level measurement devices are
Fig. 2 Typical pH electrode response as a function of temperature.
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
Table 1
Common Liquid Level Measurement Devices for Environmental Control Systems
Sensor Type
Theory of Operation
Environmental Control
System Applications
Comments
Differential
pressure
Measures differential static
pressure with sensors or pressure
taps mounted on the wall of the
vessel. The sensor contacts the fluid.
Slurry tank level. This
Reliable, subject to plugging in
technique is often used with
slurry application. Two types are
a ram valve or a flush system. used flange mounted and
extended diaphragm.
Ultrasonic
Emits ultrasonic pulse to the liquid
surface. The transit time of the
return pulse reflected from surface
is converted to the liquid level.
Open tanks containing most
fluids or slurries.
Sensors do not contact the liquid.
Some problems result from waves,
dust, vapor, foam, etc. Background
noise can often be filtered
electronically.
Electrical
capacitance
Detects level by measuring the
capacitance between the probe and
the tank wall.
High/low level alarm. Discrete
level capacitance probes can
detect liquid surface.
Some problems with solids buildup
or scale.
Float
Float moves up and down with level.
The float is on an arm inserted into
the vessel or within a housing.
Clean water, mill product
tanks (nonscaling): high/low
level alarm or constant tank
volume.
Magnetic float types are available
but are not considered good for
scaling applications.
Radio frequency Detects an electrical signal which
(phase tracking) passes through a sensor and is
reflected back at both the liquid
surface and the bottom of the sensor.
The signal phase shift provides a
continuous indication of level.
Liquid and solids level.
Relatively new, promising
technology. The electric field is
much larger than the conductors.
Optical
Sludge level in thickeners.
For sludge level, the change in
light intensity is measured at a
fixed distance from the surface.
Detects changes in light intensity.
listed in Table 1. In SCR NOx reduction systems, aqueous and anhydrous ammonia storage tank levels are
monitored.
Differential pressure level transmitters are the most
common for absorber recirculation tank level control
because of their proven reliability. However, they are
not the most accurate because of errors due to changes
in slurry density or errors due to flue gas pressure
above the liquid level.
Other liquid level devices have varying degrees of
accuracy due to the tank conditions. For example, most
tanks used in FGD systems contain slurry and are
therefore agitated, causing waves or a vortex on the
surface. The liquid surface level in the absorber tower
recirculation tank is also disrupted by: 1) the very high
spray flow rates impinging on the surface, 2) foaming due to gas released during the reactions or entrained by the spray, and 3) oxidation air sparged into
the tank. Sensors immersed in the slurry also tend to
scale. Some level devices use stilling wells to reduce the
effect of agitation and to shield the level probe from spray.
Solids level
Many types of sensors used for measuring liquid
level are also used for solids level measurement. However, solids level measurement presents some unique
problems due to the often dusty environments, the
uneven level caused by bridging or normal angles of
repose characteristic of the solids, or the changes in
density or properties due to compaction or aeration.
Steam 41 / Environmental Measurement
For environmental equipment, solids level measurement is used mainly for storage silos (ash, lime, limestone, gypsum) but is also used for hoppers on precipitators or fabric filters. Types of silo measurement devices include electrical capacitance, ultrasonic, and radio frequency (phase tracking) sensors. In addition,
load cells or strain gauges that measure the weight
change of the silo as it fills or empties are common.
Another type of solids level device is a cable measurement system in which a weight or float is lowered automatically from the top of the bin or silo. When the
float reaches the solids surface, loss of cable tension is
detected. The device then measures the distance traveled by counting electronic pulses as the float retracts.
The measured level is therefore the silo maximum level
less the distance traveled by the probe. This device
should not be used when the silo is being filled.
A typical device used to determine high hopper level
is a nuclear transmitter and detector. When the ash
level rises above the sensor, the strength of the signal
from the nuclear source to the receiver is decreased.
This signal is converted to a level indication. There
have been objections to the use of this type of device
due to the nuclear material present and licensing requirements.
Another high/low solids level device is the paddle
wheel, which includes a motor that turns a paddle.
When material is present, rotation of the paddle stops.
The increased torque of the motor as it attempts to turn
the stopped paddle triggers a microswitch alarm.
36-3
The Babcock & Wilcox Company
Finally, vibrating probes are sometimes used for
single point solids level detection. The vibration of a
piezoelectric transducer-driven probe inserted into the
vessel is dampened by contact with material. This is
detected as a voltage change, which is electronically
amplified to yield a level indication. The capacitance
probe is a similar device.
Solids concentration (density)
The most commonly used devices for density measurement are nuclear absorption meters (see Fig. 3).
These devices measure the absorption of gamma rays
from a radioactive source, and the degree of absorption is proportional to the solids content. Nuclear density meters do not contact the slurry; instead, they are
installed on the outside of a slurry pipe. Some disadvantages of nuclear density meters are:
1. The signal is not linear with solids content unless a
linearizer is used. If accurate chemical analysis of the
slurry is available, the device can be pre-calibrated.
2. For some models, a nuclear license is required in the
United States (U.S.) and in most other countries.
3. The device does not distinguish between suspended and dissolved solids.
4. Errors can result due to the buildup of solids or
scale in the pipe.
Nuclear density meters are typically low maintenance devices. The inaccuracies mentioned above are
routinely verified by manual sampling and measurement. Low level sources which do not require a site
license have been used successfully in wet and dry
FGD applications.
Other devices used for density measurement include
differential pressure and ultrasonic devices and vibrating reed instruments. The reed instruments electronically convert the slurry dampening effect on electricallydriven coil vibrations to a density measurement.
Pressure, flow and temperature
Pressure, pressure differential, flow and temperature measurements are common in environmental system applications. They indicate process performance,
energy consumption, operational problems and ability to meet design or operating requirements. Theory,
instrumentation and application for these devices are
discussed in detail in Chapter 40. Selected uses in environmental systems are discussed in Chapters 33
through 35. Comments with particular importance in
environmental systems include:
Fig. 3 Nuclear absorption meter for density measurement.
36-4
1. Slurries tend to be highly erosive and potentially
corrosive, and provision must be made for appropriate environments.
2. The presence of solids in liquid or gas flows can
lead to plugging of measuring devices. Continuous purging systems are frequently included to
ensure long-term operation.
3. Temperature monitoring can be particularly important for freeze protection, crystallization prevention, thermal gradient prevention (thickeners
and clarifiers), corrosion prevention (precipitators,
fabric filters, dry FGD systems and flues/ducts)
and general process control. Elastomeric linings
and fiberglass or plastic components must be protected from high temperatures. Unlined steel
stacks must be protected from low temperatures.
Continuous emission monitoring systems
Early power plant emission measurements focused
on providing information for combustion control. The
manual Orsat gas analyzer, which sampled oxygen
(O2), carbon monoxide (CO) and carbon dioxide (CO2)
flue gas concentrations, was used extensively. However, this analyzer is not a continuous monitor and
requires a trained operator.
Power plants are required to continuously monitor
key emissions to maintain compliance with operating
permits. In addition, continuous emission monitoring
systems (CEMS) permit process control of the emissions control equipment and the combustion system.
During the 1980s, CEMS were used primarily to measure particulate (opacity), O2, SO2, NOx and CO2. By the
early 1990s, CEMS to monitor CO, hydrogen chloride
(HCl), ammonia and volatile organic compounds (VOC)
were introduced for commercial combustion applications.
The common methods for continuously measuring
flue gas constituents are described in Table 2 and are
further detailed in Table 3. All of the analyzers are
similar in that they use a measuring cell and a reference cell. They are set to zero with air or a calibration
standard, the span is set with a calibration standard,
and a sample is taken. The result is obtained by comparing the voltages detected across the sample, the
zero standard and span standard.
There are three types of analyzers – extraction,
dilution-extraction, and in situ.
In the extraction method (Fig. 4), a sample of flue
gas is withdrawn from the process stream and directed
to an external analyzer for the constituent concentration determination. This type of analyzer is typically
used where there are short distances between the
sample point and the analyzer. The probe and sample
line are often heated to prevent condensation from
interfering with the measurement. Because the gas
sample is typically drawn by vacuum to the external
analyzer, sample line leaks can compromise the integrity of the sample.
The dilution-extraction method uses a carrier/dilution media, typically instrument quality air, which is
supplied to the extraction probe in the flue gas process stream. Problems associated with dirty, wet and
corrosive flue gases are drastically reduced by the 50
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
Table 2
CEM Technologies
Technology
Operating Characteristics
Infrared radiation (IR)
An infrared beam passes through a measurement filter and is absorbed by the constituent
gas. A light detector creates a signal which is used to monitor concentrations.
Ultraviolet absorption (UV)
A split beam, with optical filters, phototubes and amplifiers, measures the difference in light
beam absorption between the reference and sample.
Chemiluminescence
NOx is measured by first converting any NO2 to NO, then reacting with ozone to convert all
the NO to NO2 and its characteristic light generating effect. Ozone does not react with NO2.
Flame ionization detection
Hydrocarbons are ionized with strong light. The signals are received by the flame ionization
detector.
Transmissometer
Light is passed through the stack where it is reflected by a mirror on the opposite side. The
quantity of light returning is proportional to particulate matter and aerosols in the flue gas.
(See Fig. 5.) Alternatively, the receiver may be placed on the opposite wall.
Electrochemical cells
The voltage measured when a gas sample is injected into a solution with a strong base is
compared to a reference voltage.
Chromatography
A sample, zero and calibration gas are eluted through a column. The output as measured by
flame photometric or thermal conductivity detectors is compared.
to 200 dilution ratio provided by the sample probe. Precise dilution is assured by accurately controlling the
dilution air pressure which yields a constant air flow.
The air flow creates a vacuum on the downstream side
of a critical sample orifice. The gas sample rate, limited by sonic flow through the orifice, is therefore held
constant. Furthermore, because the sample lines from
the probe to the analyzer are under positive pressure,
minor sample line leakage does not affect the integrity
of the sample concentration as it would in a vacuum system. This method has gained wide acceptance in utility
and other systems where long sample lines are required.
In situ analyzers, such as that shown in Fig. 5, provide measurement of flue gas concentrations directly
in the process stream. Several types of detection devices are available, and all are based on absorption
spectroscopy. Since gas stream particulates can reduce
the level of light transmission, ceramic filters are used
to exclude these particles. A single in situ probe can
measure several gas species and opacity. Problems
with in situ analyzers generally occur in the optic or
Fig. 4 Extraction stack/inlet CEM system.
Steam 41 / Environmental Measurement
electronic components. Because a separate analyzer
is required for each sample point, installations that
require multiple sample points frequently find the extractive systems more cost effective.
Continuous analyzers generally require flue gas conditioning. Sample conditioning includes filtration to
remove particulate (see Fig. 6), chilling to remove water, heating to maintain process temperature, and dilution (used with extractive monitor and in situ probe).
The need for conditioning coupled with zero and
span calibration make extractive systems complicated,
Table 3
Continuous Emission Monitoring
(Reference Table 2 for Technologies)
Constituent
CEM Technology
Particulate matter (opacity)
Transmissometer,
beta ray absorption
Sulfur dioxide (SO2)
UV absorption, IR
pulsed fluorescence
Nitrogen oxides (NOx)
Chemiluminescence,
UV spectroscopy, IR
Hydrogen chloride (HCl)
IR with gas filter
Carbon monoxide (CO)
IR
Carbon dioxide (CO2)
IR
Oxygen (O2)
Electrochemical cell
Volatile organic compounds
(VOC)
Flame ionization
detection
Other organic air toxics
Chromatography
Ammonia (NH3)
Same as NOx*
*NH3 is converted to NOx in one of two split streams. Both
streams are analyzed for NOx. NH3 is determined as the
difference.
36-5
The Babcock & Wilcox Company
ment is placed. Many of the problems associated with
CEMS can be traced to dirty conditions, excessive heat
or cold, vibration, humidity, etc.
Monitoring process performance
Fig. 5 In situ transmissometer system.
costly, and vulnerable to plugging, corrosion and leaking. These systems are also slow to respond due to the
time lapse between sampling and analysis. In situ systems use conditioning but do not rely on long sample
lines. These systems have faster response, fewer components and better availability than extractive systems. However, they are prone to interference and
fouling and are less accessible for service. Extractive
systems can be expanded by adding sample points as
shown in Fig. 4. It is important to consider the location and ambient conditions in which CEMS equip-
Environmental control systems involve physical
and chemical processes. Chemical methods are used
to maintain desired removal or emission levels, avoid
operating problems, improve reagent utilization, improve process efficiency, troubleshoot equipment, and
monitor process changes.
In a wet FGD system, the quality of the reagent
and the recirculating slurry stream are monitored.
Analysis is more critical for processes that produce a
usable byproduct such as gypsum. In this case, the
analysis extends into product purity and feed stream
impurities. The quality of the reagent is normally
measured extensively when the reagent source is selected. Later it is evaluated if the source is changed
or process problems occur.
Tables 4 through 7 list the important analyses for
common wet FGD systems. Additional analyses are
required for makeup water streams, sodium-based
FGD systems, dual loop systems, regenerative systems, ex situ oxidation processes, water treatment, and
sulfuric acid or SO2 recovery processes. However, the
major species and methods would be similar to those
presented in Tables 4 through 7; only the concentrations
would vary. The analyses common for spray dry FGD
Table 4
Limestone Quality Analysis (Wet Limestone FGD Systems)
Parameter
Suggested Method*
Suggested Frequency
Use of Data
Reactivity
pH stat test followed by
particle size measurement
Duplicate analysis of candidate
limestones
Compared to reference to determine
acceptability.
Grindability
(Bond Work
Index)
Laboratory ball mill test
Duplicate analysis of candidate
limestones
Limited by specification of wet milling
system design.
Particle size
of limestone
as delivered
Sieve method
Duplicate analysis of candidate
limestones then monitor monthly
Limited by specification of wet milling
system design.
Inerts
Acid dissolution
Duplicate analysis of candidate
limestones then monitor
weekly for gypsum systems
Quality indicator; important for gypsum
systems.
Carbonate
CO2 evolution, Ba(OH)2
absorption, alkalinity
titration
Duplicate analysis of candidate
limestones then monitor
weekly for gypsum systems
Check reagent quality; important for
gypsum systems.
Calcium and
magnesium
AA, IR, EDTA
titration
Duplicate analysis of candidate
limestones then monitor
weekly for gypsum systems
Check reagent quality.
Limestone
slurry solids
content, % by wt
Gravimetric
Daily
Check density meter and indicate
problems in milling circuit.
Limestone
slurry particle
size
Wet sieve
Daily
Troubleshooting problems in milling
circuit or process such as low utilization
or poor gypsum quality.
* Many methods have been standardized through the American Society for Testing and Materials, Philadelphia, Pennsylvania.
36-6
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
Table 5
Lime Quality Analysis (Wet Lime and Spray Dry FGD Systems)
Parameter
Suggested Method*
Suggested Frequency
Use of Data
Slaking rate
ASTM Method C-ll0-76a
Duplicate analysis on
all candidate limes
Temperature rise rate is related to reactivity
and lime quality.
Grit
Acid dissolution
Duplicate analysis on
all candidate limes
High grit levels indicate poor lime quality.
Weight loss
on ignition
Gravimetric
Duplicate analysis on
all candidate limes
Weight loss is an indirect measure of lime
quality via carbonate and hydroxide content.
Available lime
index
Rapid sugar test
Duplicate analysis on
all candidate limes
Lime quality.
Calcium/
magnesium
Atomic absorption (AA)
EDTA titration or Ion
Chromatograph (IC)
Duplicate analysis on
all candidate limes
then as needed to check
reagent quality
Analysis is required for processes producing
a usable byproduct or high magnesium lime
systems.
Lime slurry
solids content,
% by wt
Gravimetric
Daily
Check density meter calibration and indicate
slaker performance.
* Many methods have been standardized through the American Society for Testing and Materials, Philadelphia, Pennsylvania.
systems are presented in Table 8. The lime quality analysis in Table 5 is applicable for wet lime or spray dry FGD
systems. In general, there is significantly less process
chemistry monitoring for a spray dry FGD system.
Performance testing
As with any system, performance tests are conducted on environmental control systems to determine
if the units are operating properly. A typical new environmental control system might include low NOx
burners, SCR, ESP, wet FGD scrubber modules, and
gypsum processing equipment. The ten most common
parameters measured to determine performance for
such a system include:
1.
2.
3.
4.
system pressure drop,
particulate emissions,
stack opacity,
NOx emission concentration,
Fig. 6 Extractive sample probe with dust conditioning.
Steam 41 / Environmental Measurement
5.
6.
7.
8.
9.
10.
SO2 removal efficiency and SO2 emissions,
makeup water requirements,
reagent consumption,
gypsum purity,
mist eliminator carryover, and
electric power consumption.
Other performance parameters that would be measured depend on the type of system. Performance testing is usually extensive and expensive. Multiple performance tests may be completed for a new environmental control system depending on specific contractual requirements. An initial test may be followed by
additional testing after a defined period of operation.
Sample location selection
Selecting the sample locations is the first step in the
performance test and is often incorporated in the design of the environmental control system. Outlet sampling is not difficult if it is done in the stack. However,
the inlet and intermediate samples are more difficult
to obtain. In Fig. 7, the system inlet at the far left is a
section of flue followed by an immediate upward bend.
The dry precipitator outlet is at the induced draft (ID)
fan inlet. Fig. 7 also shows test ports in the downward
flue section after the absorber tower and at the stack
entrance. Test port locations are selected to give the
best flow profile within the plant layout limitations.
The number and location of traverse points are selected using U.S. Environmental Protection Agency
(EPA) Method 1. Application of Method 1 is illustrated
in Fig. 8. The distance downstream from the flow disturbance, which in this case is the stack inlet, is 138
ft (42.1 m). This is more than 8 diameters (138/16 =
8.6). The upstream distance to the stack exit is 5 diameters. Therefore, 12 traverse points are required by
Method 1. For rectangular flues, Method 1 is applied
by first determining an effective or equivalent diameter which is calculated as follows:
36-7
The Babcock & Wilcox Company
Table 6
Recirculation Slurry/Blowdown Analysis (Wet FGD Systems)
Parameter
Suggested Method*
Suggested Frequency
Use of Data
pH
2-buffer method calibration or grab sample
Once per shift by grab sample,
daily by buffer method
Troubleshoot pH meter and maintain
process efficiency.
Slurry suspended
solids content
Gravimetric
Weekly
Calibrate density meter and maintain
process efficiency.
Cations: Ca++ and
Mg++ primary; K+
and Na+ secondary
IC, AA, ICP or wet
chemistry methods
Daily for Ca++ and Mg++ in
calcium-based systems
To calculate stoichiometry and monitor
process chemistry.
Anions: SO3= , CO3= ,
SO4= and Cl− primary; F− and NO3−
secondary
IC or wet chemistry
methods
Daily for SO3= , CO3= , SO4= , Cl−
To calculate stoichiometry, measure chloride concentration, and monitor process
performance and gypsum production.
Dissolved metals:
Fe, Mn, Al, etc.
AA
Infrequently
Process troubleshooting.
Additives: adipic
acid, dibasic acid,
formate, thiosulfate,
scale inhibitors, etc.
IC or wet chemistry
methods
Daily
Determine or correct dosage.
TDS (total
dissolved solids)
Gravimetric
Weekly
Calibrate density meter for suspended
solids; important for mag-lime, high
chloride or suspended solids.
Dissolved
alkalinity
Acid-base titration
Weekly
Measure alkali loss in filter cake of maglime process; important for mag-lime or
sodium systems.
Settling tests
Graduated cylinder
Weekly
Predict thickener performance and assist
process troubleshooting.
Filter leaf test
Filter and weight
During startup
Predict filter cake properties.
Particle size
distribution
Coulter counter or
laser diffraction
During startup
Determine settling or dewatering characteristics; important for gypsum systems.
* Many methods have been standardized through the American Society for Testing and Materials, Philadelphia,
Pennsylvania, and the Electric Power Research Institute, Palo Alto, California.
DC =
2LW
L +W
(1)
where
DC = equivalent diameter
L = length
W = width
Then a matrix layout is used for sample location selection. The cross-section is divided into as many equal
rectangular areas as there are traverse points, and the
sample is taken at the centroid of each area.
Gas-side measurements
For a performance test, a combination of EPA Methods 5 and 8 is the most often used procedure to simultaneously measure particulate, SO2, and SO3 or acid
mist (H2SO4) levels. The Method 5 sampling train,
shown in Fig. 9, is used with Method 8 impingers
shown in this figure. The data obtained from this
traverse also represent EPA Methods 1 through 4. Results include gas velocity by S-type pitot tube (Fig. 10)
36-8
and CO2, O2, moisture, SO2, particulate, and SO3 or
H2SO4 levels. The following calculations are used:
Determination of moisture content in stack gas
Bw =
( MWC )(1.34 )
( DGV )( Pm ) 500
( MWC )(1.34 ) +
( )
T
(2)
m
where
Bw
= moisture fraction
MWC = impinger weight gain, g
DGV = sampled dry gas volume at meter conditions, ft3
Pm
= pressure at meter, in. Hg
Tm
= temperature at meter, R
1.34 = constant for converting grams of H2O to liters of H2O vapor at standard conditions, l/g
500 = conversion of cubic feet at meter conditions
to liters at standard conditions, l R/ft3/in. Hg
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
Fig. 7 Typical test port locations indicating compromises made in measurement due to equipment arrangement.
where
Determination of flue gas molecular
weight – dry basis
( 44 )( % CO2 dry ) + (32 )( % O2 dry )
Md =
× 0.01
+ ( 28 )( % N 2 dry )
(3)
Md
44
32
28
=
=
=
=
molecular weight of gas on dry basis, lb/lb-mole
molecular weight of CO2, lb/lb-mole
molecular weight of O2, lb/lb-mole
molecular weight of N2, lb/lb-mole
Determination of flue gas molecular
weight – wet basis
M w = M d (1 − Bw ) + 18 Bw
(4)
where
Mw
Md
Bw
18
=
=
=
=
molecular weight of gas on wet basis, lb/lb-mole
molecular weight of gas on dry basis, lb/lb-mole
moisture fraction, lb-mole H2O/lb-mole wet gas
molecular weight of H2O, lb/lb-mole
Determination of gas humidity
18 Bw
H =
M d (1 − Bw )
Fig. 8 Stack dimensions and sampling port locations for EPA Method 1.
Steam 41 / Environmental Measurement
(5)
Fig. 9 EPA Method 5 particulates and SO2 emissions sampling train.
36-9
The Babcock & Wilcox Company
Table 7
Dewatering System Analysis (Wet FGD Systems)
Parameter
Suggested Method*
Suggested Frequency
Use of Data
Thickener or hydroclone
underflow solids, %
Gravimetric
Daily
Troubleshoot process and calibrated lime
density meters
Clarified water, water
analysis (anions, cations,
suspended solids)
See Table 6
Weekly
Monitor dewatering system performance
Supernatent, filtrant
solids content, % by wt
Gravimetric
Daily
Monitor filter cloth status
Gypsum Quality Analysis
++
++
+
+
CA , Mg , Na , K ,
Fe2O3, R2O3, SiO2
AA or ICP
Weekly
Product purity and properties
Cl−, SO4=
IC
Daily
Product purity and properties
Iodimetric titration
Daily
Product purity and properties
Moisture content
Gravimetric
Daily
Important for marketable gypsum and
monitoring dewatering system performance
Surface area
BET analysis
(subsieve sizer)
Startup or process
change
N2 gas is condensed on surface and absorbed;
N2 corresponds to surface area
Combined water
Heat to 482F (250C)
Weekly
Gypsum purity
Mean particle size
Coulter counter,
Sedigraph plus
sieve analysis or
laser diffraction
Startup or process
change
Product purity and properties
Aspect ratio
Scanning electron
microscope
Startup or process
change as required
by end users
Product purity and properties
Total water soluble salts
Sum (Na+ + K+ + Mg++ )
As needed
Product purity and properties
Flyash
Determined as acid
insoluble
Daily
Determined as acid insolubles along with
silica (SiO2) and other impurities
pH
Electrode
Daily
Product purity and properties
SO3 , CaSO3 • 1/2
=
H2O
* Many methods have been standardized through the American Society for Testing and Materials, Philadelphia,
Pennsylvania, and the Electric Power Research Institute, Palo Alto, California.
where
H
Bw
Md
18
=
=
=
=
gas humidity, lb H2O/lb dry gas
moisture fraction, lb-mole H2O/lb-mole wet gas
molecular weight of dry gas, lb/lb-mole
molecular weight of H2O, lb/lb-mole
Determination of stack gas velocity
1/2
T ∆P
Vs = 85.49 C p s
Ps M w
(6)
where
85.49 = pitot tube constant in the following units:
ft
s
Fig. 10 S-type pitot tube with sampling probe.
36-10
1/2
( lb / lb-mole )( in. Hg )
( R )( in. H2O )
V s = velocity of the flue gas, ft/s
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
∆P = average differential pressure measured by
S-type pitot tube, in. H2O
T s = average gas temperature in duct, R
Ps = absolute duct pressure, in. Hg
Mw = wet gas molecular weight, lb/lb-mole
Cp = S-type pitot tube correction factor (normally
0.84)
Volumetric flow rate – actual conditions
(7)
Qac = 60 Vs A
where
Qac
Vs
A
60
=
=
=
=
0.001 = conversion of milligrams to grams, g/mg
15.43 = conversion of grams to grains, grains/g
Total particulate, H2SO4, condensible total
particulate and condensible H2SO4
Cs =
Cs
= concentration of specie in the flue gas at
dry conditions, grains/DSCF
Mn
= mass of specie collected, mg
Ts
= average gas temperature in duct, R
Vm
= dry gas volume sampled at meter, DCF
Y
= meter correction factor
Ps
= average gas pressure in duct, in. Hg
0.001 = conversion of milligrams to grams, g/mg
15.43 = conversion of grams to grains, grains/g
29.92 = standard pressure, in. Hg
528 = standard temperature, R
Volumetric flow rate – dry standard conditions
528 Q ac Ps (1 − Bw )
29.92 Ts
(8)
where
Total particulate, H2SO4, NOx and SO2 – lb/h
Qsd
= dry volumetric flow rate at standard conditions, DSCFM
Qac = actual volumetric flow rate, ACFM
Bw
= moisture fraction, lb-mole H2O/lb-mole wet gas
Ts
= average gas temperature in duct, R
Ps
= absolute duct pressure, in. Hg
528 = standard temperature, R
29.92 = standard pressure, in. Hg
(
( 0.001)(15.43 ) M n
Vm
Mn
Vm
(11)
where
Cm
Cs
Qsd
(9)
60
1.428 × 10–4
where
Ca
)
Cm = Cs 1.428 × 10−4 ( 60 )(Qsd )
Total particulate and H2SO4 – grains/ACF
Ca =
(10)
where
actual volumetric flow rate, ACFM
velocity of the flue gas, ft/s
cross-sectional area of the duct, ft2
conversion factor, s/min
Q sd =
( 0.001)(15.43 ) M n (29.92 ) Ts
Vm Y ( 528 ) Ps
= concentration of specie in the flue gas at
duct conditions, grains/ACF
= mass of specie collected, mg
= dry gas volume sampled as measured by
dry gas meter, ACF
= mass flow rate of specie in the flue
gas, × lb/h
= concentration of specie in the flue
gas at dry standard conditions,
grains/DSCF
= dry volumetric flow rate at standard
conditions, DSCFM
= conversion of minutes to hours, min/h
= conversion of grains to pounds, lb/
grain
Total particulate, H2SO4, NOx and SO2
E =
20.9 Cm Fd
60 Qsd ( 20.9 − % O2ds )
(12)
Table 8
Spray Dryer FGD System Process Analysis
Parameter
Suggested Method
Suggested Frequency
Use of Data
Lime slurry solids content
Gravimetric
Once per shift
Confirm process meter
Recycle slurry solids content
Gravimetric
Once per shift
Confirm process meter
Flue gas wet bulb temperature
Manual
Startup, fuel change
Process troubleshooting
Flyash alkalinity
Acid titration
Startup, fuel change
Process troubleshooting
Baghouse ash free moisture
Gravimetric
Startup, process change
Process troubleshooting
Process water TDS (total
dissolved solids)
Gravimetric
Startup, water source change
Confirm operations
Slaking water anions
Wet chemistry
Startup, water source change
Process troubleshooting
Steam 41 / Environmental Measurement
36-11
The Babcock & Wilcox Company
where
where
E
Cm
Fd
Qsd
% O2ds
20.9
60
= emission rate on a dry basis at 0% O2, lb/
106 Btu
= mass flow rate of specie in the flue gas, lb/h
= dry F-factor at 0% O2, determined from
fuel analysis, DSCF/106 Btu (see Equation 17)
= dry volumetric gas flow rate at standard
conditions, DSCFM
= O2 in the gas on a dry basis, %
= O2 in air, used with % O2 in the gas to correct to 0% O2, %
= conversion of minutes to hours, min/h
SO2 – parts per million (ppm) wet
C ppm , w =
(32.03 ) N (V − V ) (V
t
tb
soln
/ Va ) (1 − Bw )
Vd × 2.66
Ceff = collection/removal efficiency, %
Cin = concentration of matter at inlet, lb/106 Btu
Cout = concentration of matter at stack, lb/106 Btu
Percent isokinetic
% I = (Vn / Vs ) × 100
where
Vn =
(13)
Cppm,w = gas SO2 concentration on a wet basis, ppm
wet
N
= barium standard titrant normality, meq/ml
Vt
= volume of barium titrant used for sample,
ml
Vtb
= volume of barium titrant used for blank, ml
Vsoln = total volume of impinger solution, ml
Va
= volume of sample aliquot used, ml
Bw
= gas moisture fraction, g-mole H2O/g-mole
wet gas
Vd
= gas volume sampled at dry standard conditions, DSCF
32.03 = number of milligrams of SO2 per milliequivalents, mg SO2/meq
2.66 = conversion of mg/SCM to parts per million,
mg/SCM / ppm
%I
Vs
= % isokinetic
= average flue gas velocity in duct during
sampling, ft/s
Vn
= average sample gas velocity through the
nozzle during sampling, ft/s
Vd
= dry gas volume sampled at standard conditions, ft3
t
= elapsed sampling time, min
An
= cross-sectional area of nozzles, ft2
Bw
= gas moisture fraction, lb-mole H2O/lb-mole
wet gas
Ts
= flue gas temperature in the duct, R
Ps
= absolute pressure in the duct, in. Hg
60
= conversion from minutes to seconds, min/s
528 = standard temperature, R
29.92 = standard pressure, in. Hg
The % isokinetic value is used as a measure of how
representative the sample is of the actual flue gas.
Generally, if the % isokinetic is between 95 and 105%,
the sample is considered acceptable.
F-factor
SO2 – ppm dry
20.9 C ppm, w
(1 − Bw ) ( 20.9 − % O2ds )
(14)
where
Cppm,d = gas specie (SO2) concentration on a dry
basis, corrected to 0% O2, ppm dry
Cppm,w = gas specie (SO2) concentration on a wet
basis, ppm wet
Bw
= moisture fraction of the gas, lb-mole H2O/
lb-mole wet gas
% O2ds = O2 in the gas on a dry basis, %
20.9 = O2 in air, used with % O2 in the gas to correct to 0% O2, %
NOx – ppm dry and ppm wet
NOx is evaluated directly by monitoring systems as
parts per million, dry basis. It can be converted to ppm
wet if needed by solving Equation 14 for Cppm,w.
Collection/removal efficiency –
total particulate, H2SO4 and SO2
Ceff = (Cin − Cout ) / (Cin ) × 100
36-12
Vd Ts 29.92
60 tAn 528 Ps (1 − Bw )
and where
where
C ppm, d =
(16)
(15)
The F-factor used in making emissions rate calculations was developed from chemical and combustion
analyses of the fuel (reference EPA Method 19). This
factor is the ratio of the theoretical volume of dry gases
at 0% excess air (O2) given off by complete combustion of a known amount of fuel, to the gross caloric
value of the burned fuel. The data generated from the
ultimate analysis of the fuel are used to calculate the
F-factor as follows:
( )
Fd = 106
3.64 ( H ) +1.53(C) + 0.57 (S ) + 0.14 ( N ) − 0.46 ( O )
HHV
(17)
where
Fd
HHV
H
C
S
N
O
=
=
=
=
=
=
=
dry F-factor at 0% O2, DSCF/106 Btu
higher heating value, Btu/lb
hydrogen in the fuel, % by wt
carbon in the fuel, % by wt
sulfur in the fuel, % by wt
nitrogen in the fuel, % by wt
oxygen in the fuel, % by wt
F-factors are constant for a given fuel category
(within ±3%). Standard average values approved by
the EPA are:
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
Fuel
DSCF/106 Btu
Bituminous coal
Oil
Natural gas
Wood bark
Wood chips
Municipal solid waste
9780
9190
8710
9600
9240
9570
The Fd factor is used to convert the measured pollutant concentration to an emissions rate in lb/106 Btu by:
brated weight belt feeder. The measurement is time
averaged. This mass flow method is cumbersome because the initial and final storage tank volumes and
densities must also be measured. This method is best
done over a period of at least 24 hours. The second and
preferred method is chemical analysis. For a wet FGD
system, the reagent consumption is calculated from the
stoichiometric ratio, limestone (or reagent) analysis, and
gas side measurements by the following equation:
lb/106 Btu = Fd Cppm,d K 20.9/(20.9 − % O2,d)
LS =
Where K is the conversion factor from ppmdv to lb/scf.
K NOX = 1.194 × 10–7
K SO2 = 1.660 × 10–7
Particulate and SO2 removal efficiencies
The SO2 and particulate removal efficiencies are
determined by inlet and outlet sampling using Equations 12 and 15.
Stack opacity
Stack opacity is determined by the installed transmissometer or by EPA Method 9 which is a visual
method by a certified observer.
NOx concentration
NOx concentration is determined by EPA Method 7.
This measurement is taken in the stack on a composite sample. NOx concentration may be adjusted to design conditions from actual test conditions.
NH3 concentration
NH3 concentration is determined by EPA Method
CTM-27. This measurement is taken at the SCR outlet on a composite sample before the air heater. NH3
concentration may be adjusted to design conditions
from actual test conditions.
Condensible particulate matter
New regulations limit the amount of total particulate matter finer than 10 microns (PM10) which includes both solids and vapors which may condense in
the atmosphere to form particulates after the flue gas
exits the stack. These condensibles may include H2SO4
and VOCs. EPA Methods 201 and 202 are designed
to measure the condensible fraction of particulate
emissions. There is some concern that Method 202 may
overstate the condensibles by inclusion of SO2 which is
not purged from the impingers before the analysis.
Makeup water requirements
Makeup water requirements are measured at the
appropriate terminal point with a certified flow meter.
Adjustments from test conditions may be necessary
due to variations in gas volume or temperature or
other process deviations from design conditions.
Reagent consumption
There are two common ways to measure reagent
consumption. The first method is to measure the solid
reagent flow (for lime/limestone systems) using a caliSteam 41 / Environmental Measurement
100 ( SR ) ( SO2 )
64 (CaCO3 )
(18)
where
LS
SR
SO2
64
100
CaCO3
=
=
=
=
=
=
limestone consumption, lb/h
stoichiometric ratio (see Chapter 35)
SO2 removed, lb/h
molecular weight of SO2, lb/lb-mole
molecular weight of CaCO3, lb/lb-mole
available CaCO3 in limestone (wt fraction: lb available CaCO3/lb limestone)
Reagent consumption may be adjusted for deviations from SO2 removal rate and mass flow (or concentration) design conditions.
Gypsum purity
A composite sample of gypsum, taken over the test
period, is analyzed as outlined in Table 7. Adjustments
may be necessary for flyash contamination, chloride
concentration, and inerts if the inlet levels to the FGD
system substantially deviate from design.
Other test methods
There are numerous other procedures for measuring system parameters. The example in this chapter
is a formal performance test; other methods could be
used. SO2 can be measured with a CEMS or by other
temporary instrument methods following EPA Method
6. Particulate level can be measured by EPA Method
5 or 17 or alternate methods such as the probe shown
in Fig. 11.
Mercury emissions measurement
Continuous or semi-continuous measurement of
mercury emissions is a developing technology that will
be used to assure compliance with future regulation
of mercury emissions from coal-fired boilers. Various
monitors under development share common features
of sample pre-treatment, adsorption of mercury onto
a gold trap and then periodically purging the mercury
from the trap and quantitatively measuring the mercury using cold vapor atomic spectroscopy (CVASS),
atomic fluorescence spectroscopy (AFS) or Zeemanmodulated atomic spectroscopy (Pavlish, 2003). The
measurement challenges include low concentrations
(typically less than 10µg/Nm3), fouling with particulates, and interference from common flue gas constituents such as SO2, HCl and NOx. An alternative method
accepted by the EPA involves drawing a measured flue
gas sample volume through a carbon trap for a specified time period (1 month for example) and then measuring the mercury in the carbon trap to calculate an
36-13
The Babcock & Wilcox Company
Fig. 11 Probe detail, isokinetic dust sampling.
emission rate in lb/TBtu. ASTM Method D6784-02 is
the validated and accepted stack sampling test method
for measuring mercury speciation and total mercury
in coal-fired flue gas (see Fig. 12).
The future of environmental measurement
Advances in environmental measurement techniques will certainly continue. Technologies such as
fiber optics, video imaging and Fourier transform infrared analysis (FTIR), which have been used successfully in the laboratory, are expected to move into the
field. Measurement will be extended to include other
air and water pollutants, and air toxics monitoring will
become increasingly important.
Fig. 12 Mercury testing at research and development facility.
Bibliography
American Society of Mechanical Engineers (ASME) Performance Test Codes: PTC 1 on General Instructions, 1999;
PTC 2 on Definitions and Values, 1980 (R1985); and PTC
3.2 on Solid Fuels.
ASME PTC Supplements on Instruments and Apparatus:
PTC 19.2 on Pressure Measurement, 1987 (R1998); PTC
19.3 on Temperature Measurement, 1974 (R1998); PTC
19.6 on Electrical Measurements (IEEE Standard 120),
and PTC 19.10 on Flue and Exhaust Gas Analyses, 1981.
United States Code of Federal Regulations, CFR 40, Protection of the Environment, Parts 53 to 80.
United States Code of Federal Regulations, (e-CFR),
Website www.gpoaccess.gov/cfr/index.html, February 7,
2005.
Continuous Emission Monitoring Guidelines: Update,
Report CS-5998, Electric Power Research Institute (EPRI),
Palo Alto, California, September, 1988.
United States Code of Federal Regulations, CFR 40, Part
60 Environmental Protection Agency (EPA), Method 19:
Determination of Sulfur Dioxide Removal Efficiency and
Particulate Matter, Sulfur Dioxide and Nitrogen Oxide
Emission Rates.
36-14
FGD Chemistry and Analytical Methods Handbook, Report CS-3612, Vols. 1 and 2, Electric Power Research Institute (EPRI), Palo Alto, California, July, 1984.
Handbook of Electrode Technology, Orion Research, Cambridge, Massachusetts, 1982.
Liptak, B.G., Ed., Instrument Engineers’ Handbook: Process Measurement and Analysis, Vol. 1, Fourth Ed., CRC
Press, Boca Raton, Florida, June 27, 2003.
Performance Test Code Committee No. 40, Flue Gas
Desulfurization Units, Draft VII, The American Society of
Mechanical Engineers, New York, New York, October, 1989.
Elliot, T.C., “Monitoring Pollution,” Power, pp. 51-56,
September, 1986.
Elliot, T.C., “Level Monitoring,” Power, pp. 41-58, September, 1990.
Gilbert, G., “Three Ways To Measure Flow in Power Plant
Ducts,” Power, pp. 63-72, June, 1987.
Kiser, J.V.L., “Continuous Emissions Monitoring: A
Primer,” Waste Age, pp. 64-68, May, 1988.
Kiser, J.V.L., “More on Continuous Emissions Monitoring,” Waste Age, pp. 119-122, June, 1988.
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
FGD Manual, The McIlvaine Company, Northbrook, Illinois, August, 1989.
Pavlish, J.H., et al., “Status Review of Mercury Control
Options for Coal-Fired Power Plants,” Fuel Processing
Technology, 82: 89-165, pp 98-99, 2003.
Robertson, R.L., “Continuous Emission Monitoring and
Quality Assurance Requirements for New Power Plants,”
appearing in Continuous Emission Monitoring Systems
for Power Plants: The State-of-the-Art, American Society
of Mechanical Engineers (ASME), pp. 13-15, New York,
New York, 1988.
Steam 41 / Environmental Measurement
Rothstein, F., and Fisher, J.E., “pH Measurement: The
Meter,” American Laboratory, September, 1985.
Spriggs, D., “Calibration and Troubleshooting of pH
Loops,” presented to the American Water Works Association Ohio Section Northeast District Meeting, Painesville,
Ohio, July 20, 1989.
36-15
The Babcock & Wilcox Company
Dry flue gas desulfurization system installation in western U.S.
36-16
Steam 41 / Environmental Measurement
The Babcock & Wilcox Company
Section V
Specification, Manufacturing
and Construction
This section begins with an in-depth discussion of the specification, evaluation and procurement process for large capital expense items. This includes
discussions about project scope, terms and conditions, and general bid evaluation. Also discussed are power system economics, and procedures for the evaluation of equipment characteristics in terms of justifiable expenditures. Examples and calculations are included for both utility and industrial units.
This is followed by a discussion of the manufacturing processes for fossil fuelfired equipment. Welding and metal removal techniques, as well as fabrication of the various components and component parts, are covered. Examination and quality control are also discussed. The section ends with a discussion
of various construction techniques, labor requirements, on-site considerations,
safety issues, and post-construction testing prior to unit startup.
Steam 41
The Babcock & Wilcox Company
Chapter 37
Equipment Specification, Economics
and Evaluation
Accurate and complete technical specifications are
critical to the successful development of any new project.
Steam generating and environmental emissions control
systems are complex and typically require the evaluation of many competing factors to select the equipment
and potential options that best meet project needs.
Each application of new or upgraded equipment has
a number of unique factors and requirements that
need to be identified and communicated to the equipment or system designer/supplier. Specifications
should be developed to document these needs. However, the developer of those specifications should also
allow the equipment designers flexibility to adapt their
products to best meet the true requirements of the
project. There are often multiple options or alternative solutions that can be considered. The solution
should be selected after evaluating the initial capital
investment in conjunction with several variables including the relative longer-term operating and maintenance cost benefits, feasibility of obtaining required
regulatory construction and environmental permits,
ability to meet varying operating conditions during the
life of the equipment, and costs associated with the disruption or outage of existing equipment during construction or tie-in.
The following discusses some of the primary factors
that should be considered when developing and planning a project requiring new or upgraded steam generating or environmental control systems. It describes key
technical and commercial criteria that should be developed and communicated to the equipment suppliers.
Project feasibility studies and
technology selection
Before detailed equipment specifications can be
developed, groundwork is required to establish the
basic project needs and evaluate major alternatives.
Some aspects that should be evaluated during the
early feasibility stages include:
1.
2.
3.
4.
steam capacity requirements,
range of plant operating conditions,
steam cycle conditions (pressure/temperature),
fuel type(s),
Steam 41 / Equipment Specification, Economics and Evaluation
5.
6.
7.
8.
9.
10.
combustion technology,
site location and arrangement logistics, including construction feasibility,
stack emissions and air quality control system
technology,
reagent type(s),
solid waste disposal logistics, and
water quality and treatment.
For a utility power plant, the need for new generating capacity is identified from the forecast of both
peak and average long-term electrical demand (load).
The overall power and steam generation plan must
also recognize unit retirements within the system,
spinning reserve, reserve for scheduled and unscheduled outages, and current generating equipment mix.
The specific power plant type selected is based upon
an evaluation of the amount and type of demand, assessment of current boiler types and sizes within the
system, long-term fuel availability and cost, condensing water supply, new equipment types available,
environmental impact and, in many cases, public opinion. Extensive feasibility studies are typically conducted to provide such data.1,2
For an industrial installation, the needs are usually tied to process steam or heating requirements. The
timing of equipment addition, the steam flow rate, and
the frequency of operation are governed by the application. In addition, with the growth of cogeneration and independent power production, steam supply needs have been increasingly influenced by the
demands of electrical power production. In all cases,
the steam flow requirements will determine the type,
size and number of steam generating units. Particular attention should be given to the variety, cost and
availability of fuel sources. Process byproducts, waste
materials and waste heat offer potential low-cost
sources of energy that can be used to displace the use
of higher-cost traditional fuels to meet industrial
steam generation needs.
For projects involving addition of emissions control
systems to existing boilers, many of the design conditions for the system are typically established by the
current boiler operations. However, issues such as
technology selection, reagent type(s), solid waste dis37-1
The Babcock & Wilcox Company
posal, and water treatment requirements should be
considered and evaluated during early stages of project
development. It may also be important to evaluate potential future changes in environmental permitting
requirements and operating conditions, such as the use
of an alternate fuel type, that could affect equipment
sizing or even technology selection.
For repair and retrofit projects, the evaluation is focused on the scope being considered. However, appropriate additional consideration should be given to other
factors potentially being affected by the repair or retrofit. Examples include delivery schedule to meet outage
requirements, changes in emissions rates, and effects on
auxiliaries such as fans and downstream equipment.
During these early stages, it is often helpful to obtain input from the equipment suppliers. On large,
complex projects, some plant owners and project developers have found it valuable to form a strategic
alliance or partnership with a qualified equipment
supplier. As the project develops, such a business
model can help to evolve the design of a unique or
customized new system. This alternative business
structure will be discussed later in this chapter.
The specification should also define how the equipment or system design will be integrated into the
overall project. The following is a list of typical project
definition information that needs to be included in a
specification to an equipment supplier:
1. complete scope of work, including the definition
and location of all terminal and interface points
within the overall plant or existing facilities;
2. site-specific requirements, design conditions, layout/arrangement limitations, delivery logistics,
and access restrictions, among others;
3. plant standardization requirements (if applicable);
4. project schedule, including equipment delivery,
construction and startup/commissioning, consistent with the scope of work definition;
5. commercial contract terms and conditions; and
6. evaluation criteria/factors to be used in assessing
design and operating tradeoffs.
Beyond these items, it is usually appropriate to only
specify material and workmanship quality requirements, allowing potential suppliers to apply their experience and knowledge to propose the most dependable and cost-effective design.
Specifications
Performance – steam generating equipment
Performance specifications, defining the functional
requirements for utility, industrial and environmental equipment, are summarized in the following section. For steam generating equipment, this generally
consists of steam flow, steam temperature and pressure, feedwater temperature and quality, fuel, boiler
system efficiency, emissions requirements, and performance guarantees.
Steam flow Primary performance specifications include the steam flow requirements. For utility and
other units that produce steam for electric power generation, these usually include:
Once the major feasibility issues and alternatives
have been evaluated and established, specifications
need to be developed. These specifications provide a
definition from which the primary equipment or system will be designed and by which that equipment will
be integrated into the overall project.
Specifications can vary in detail but as a minimum,
performance and functional requirements need to be
defined. The basic design is derived from the functional
requirements of the application. The equipment designer needs to know the key characteristics of all major system inputs and all performance output requirements. This information is essential for setting vital
system design parameters such as size, capacity, materials, equipment redundancy level, etc.
The design specification for new or replacement
steam generating equipment should include at least
the following information:
1. steam flow characteristics
2. steam temperature and pressure conditions
3. feedwater supply
4. fuel type(s) and characteristics, including ash
properties
5. boiler efficiency requirements
6. emissions requirements
7. performance guarantees and test conditions
The design specification for new or replacement
environmental control systems should include at least
the following information:
1. conditions and composition of flue gas and flyash
entering the system
2. emissions performance requirements
3. reagent type(s) and characteristics
4. solid byproduct quality requirements
5. wastewater quality limitations
6. makeup water composition
7. performance guarantees and test conditions
37-2
1. maximum continuous rating (MCR),
2. performance load steam flow rate (to match optimal turbine heat rate load),
3. minimum steam flow rate,
4. type of service (base load, cycling or peaking), and
5. expected cycle of operation.
In power station practice, typically one boiler is
matched to an individual turbine-generator set ranging from 25 to 1300 MW. Depending on the load requirements, one or more steam generating units are
purchased. In general, economies of scale dictate the
purchase of the fewest number of units possible to
meet overall load and system requirements.
For some industrial units, specified steam flow requirements include:
1. maximum steam flow capacity,
2. turndown (ratio of maximum to minimum load), and
3. expected steam load pattern variations (daily,
weekly or seasonal).
However, in some industrial applications the primary function of the steam generator is to consume
or process a quantity of fuel. In such cases, the fuel
input is specified and steam capacity is determined
indirectly from the maximum fuel input rating.
Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
Industrial unit operators frequently prefer multiple
smaller boilers rather than a single large unit, giving
them more operating flexibility while maximizing
steam system availability. It is normally critical that
the industrial process be available at all times and not
be limited by the steam generating system. Typically,
the number of steam generating units is established
by assessing the load pattern, load duration, availability requirements, maintenance periods, types of boilers in the system, sources of backup steam or auxiliary power, and possible future expansion plans. Minimum standby requirements are set by the minimum
required steam flow plus an allowance for routine
maintenance and forced outages. Where the load is
seasonal and steam is not a critical process requirement, standby may not be required. Where steam is
required throughout the year, some level of economical excess capacity will be needed (see Table 1).
The number of units to be installed needs to be
evaluated on the basis of total cost, including initial
capital cost, when compared with tradeoffs in thermal
efficiency and the true value of availability or cost
penalty for unavailability. The cost for more, smaller
units will be greater than the cost for fewer, larger
units. However, if the larger units will be operated for
a significant amount of time at reduced load, the effective thermal efficiency will be lower and operating
fuel-related costs will be higher. In addition, installing a number of smaller units over time can defer
capital costs until the additional capacity is required.
Steam temperature and pressure For utility applications, a turbine-generator set is generally specified,
and therefore the turbine cycle selected will determine
the pressure and temperature relationships. As part
of the specifications, the complete turbine heat balance
at various operating conditions such as minimum load,
control load, and full load should be provided to give
the designers more insight into system requirements.
The turbine specifications will typically establish acceptable deviation limits in outlet steam temperature
as well as the maximum rate of change. Constant
pressure operation or variable pressure operation, each
with advantages and disadvantages, may be selected
to meet operator needs. (See Chapter 26.) Constant
pressure versus variable pressure operation also has
a significant impact on supercritical pressure boilers
as referenced in other chapters. When the application
calls for superheat and reheat steam conditions, the
load range and load pattern will help determine the
steam temperature control ranges. The benefits of
higher steam temperatures at lower loads must be
compared to the higher costs of providing an extended
range. The evaluation penalties and allowable variations in steam temperature will also affect the type of
temperature control system included. Allowance must
also be made for pressure and heat loss from piping
between the boiler outlet and the steam use location.
Typically, the heat loss is negligible with today’s insulation products and application techniques. It is normally
left to the supplier to determine the appropriate design
margin necessary to achieve the specified steam pressure and temperature conditions at the terminals.
In industrial applications where there may be some
Steam 41 / Equipment Specification, Economics and Evaluation
flexibility in the selection of steam pressure and temperature, interaction with the steam system supplier
may permit selection of a more economical set of operating conditions.
Feedwater The temperature and chemical analysis
of the feedwater must be specified. The minimum required feedwater temperature is one of the components
that establishes boiler output (firing rate) and the
water chemistry will affect water treatment needs.
Recommended water chemistry specifications are provided in Chapter 42. For small units, a deaerator
treats the feedwater before it enters the boiler. The
resulting feedwater temperature is typically 220 to
240F (104 to 116C). Oxygen in the feedwater must
be minimized to prevent internal boiler corrosion.
In larger high temperature, high pressure boilers,
feedwater heaters are used to improve cycle efficiency
as discussed in Chapter 2. If increased output (MWs)
is desired when feedwater heaters are out of service,
then this design requirement needs to be conveyed
along with the applicable feedwater temperature and
steam flow conditions. If turbine heat balances are
provided for all operating conditions as part of the
specification, feedwater temperature requirements will
inherently be included. In any case, the feedwater
temperature needs to be specified for all boiler conditions over the load range.
Fuel The selected fuel has a major impact on steam
generating equipment design and capital cost due to
the type of combustion equipment, fuel delivery/processing equipment, fouling and erosion characteristics of the flyash, and heat transfer properties of the
flue gas (including moisture content). Refuse fuel, biomass and most byproduct or waste fuels require significantly different combustion systems than pulverized coal, oil or natural gas and can also result in different boiler corrosion characteristics. Boilers designed
to fire multiple fuel types require a compromise between the various fuels, particularly for steam temperature control. They therefore may be more expensive than boilers designed to burn a single fuel type.
Furthermore, boilers designed to accommodate multiple classifications of a fuel type, such as bituminous
and subbituminous coals, will require the application
of some tradeoffs in the design of the boiler, fuel preparation equipment, and combustion system. Designing
for multiple fuel types and classifications is especially
challenging for supercritical boilers by further complicating the design requirements for the circulation
system to accommodate a wider variation in heat
transfer rates through the critical furnace steam/water circuits. Environmental equipment design requireTable 1
Boiler Capacity with Standby Units
Total Number
Number of
of Units
Standby Units
2
3
4
5
1
1
1
1
Per Unit
Total
Capacity, % Capacity, %
100
50
33
25
200
150
133
125
37-3
The Babcock & Wilcox Company
ments can also be significantly different when designed for multiple fuel types and classifications.
Complete analyses should be provided for all fuels
being considered. For each fuel, ultimate analysis,
proximate analysis, heating value and ash analysis
should be provided in accordance with applicable
American Society for Testing and Materials (ASTM)
or equivalent international standard requirements.
The buyer normally provides a range analysis that indicates the extreme values (low and high) for each constituent. However, a fuel analysis derived statistically
from such constituents may represent an erroneous
and unrealistic combination. It is best to provide a set
of actual fuel analyses, which comprise the range, to
enable suppliers to appropriately design and size the
equipment. The analyses should be provided as moisture and ash free, moisture free and/or as-fired. Additional information needed includes as-received solid fuel
sizing, liquid fuel viscosities, and liquid/gaseous fuel
pressures. The effect of the fuel and ash on unit design is discussed in Chapter 21.
Boiler system efficiency Maximizing boiler operating efficiency minimizes fuel usage and reduces costs.
To achieve the highest efficiency, heat traps are used
to extract the last heat from the flue gas. Heat traps
include air heaters and economizers. (See Chapter 20.)
The temperature of the flue gas exiting the final trap
should be low to maximize boiler efficiency. However,
it should normally exceed the acid dew point of the
gas to avoid corrosion and other operating problems
in the last heat trap and in any downstream equipment. In addition, some environmental control equipment such as dry flue gas desulfurization (DFGD)
systems requires the entering gas temperature to be
somewhat higher for proper operation.
Utility applications commonly use both an economizer and an air heater. On other steam generating
applications when a single heat trap is required, an
air heater is usually chosen to aid in combustion of
pulverized coal, wood or biomass. For other fuels, an
economizer is frequently selected because of lower cost,
possible increased efficiency, and reduced nitrogen
oxides (NOx) levels compared to an air heater installation (increased air temperatures can promote NOx
formation in the furnace).
If the boiler supplier is to design the heat traps effectively, the specification should include evaluation
factors such as fuel cost and capitalization period. For
competitive bids, it is also prudent for the buyer to
specify the design exit gas temperature so that the
impact on boiler efficiency between competing designs
is normalized. Minimum exit gas temperature is typically set by corrosion and operating concerns of downstream equipment and should be consistent between
boiler suppliers.
Environmental limits Meeting appropriate environmental emissions limits is essential. Joint discussions between the buyer, equipment suppliers and
regulating agencies are recommended at early phases
of project development to ensure a clear understanding of permissible and achievable emissions limits.
Emissions controlled by the steam generating equipment include NOx, carbon monoxide (CO), and volatile
37-4
organic compounds (VOC). These emissions have a significant impact on design requirements of the combustion system, boiler and NOx control systems and therefore need to be defined. Further, test methods such as
applicable Environmental Protection Agency (EPA) test
methods, test duration, e.g., three-hour test period, and
test conditions, e.g., boiler load range, should be documented to ensure each party has a common understanding of all requirements and conditions. Other
emissions, captured by downstream environmental
equipment, are discussed later in this section.
Performance guarantees Specific guarantees are
normally a function of the scope structure discussed
later in this chapter. They normally include items that
can be controlled by a specific piece of equipment and
items that support the overall plant performance. Ultimately these are capacity, net plant heat rate (NPHR),
stack emissions, reagent use, and other operating factors such as water usage and waste disposal. Specific
guarantees relating to the steam generator scope that
impact NPHR and stack emissions usually include
MCR capacity, boiler efficiency, auxiliary power consumption, water and steam side pressure drop, superheater and reheater steam temperature control range,
spray water quantities, and NOx, CO, and VOC emissions. If the spray water source is downstream of the
feedwater heaters, then heat rate is not impacted by
superheater spray and is therefore not considered. For
subcritical drum type boilers, steam purity is commonly
included.
Performance – environmental control systems
Flue gas conditions and design heat input Environmental control systems are designed to reduce the level
of regulated pollutants such as NOx, sulfur dioxide
(SO2) and particulate matter present in the combustion product gases (flue gas) that leave the steam generator. The size, function and design of these systems
are dependent on the chemical composition, temperature and volume of the entering flue gas. If the environmental control system is to be supplied with the
boiler as an integrated system, the boiler design conditions for steam requirements, feedwater, fuel (including the range of the chemical composition of the fuel
and ash) plus the ambient conditions will provide the
input required to define the range of flue gas operating conditions relevant to integrated system design.
If the environmental control system is to be supplied
separately, the following information for the flue gas
entering the system should be defined in the specification:
1. chemical analysis of the flue gas, including concentration of the pollutant(s) to be controlled,
2. temperature of the flue gas,
3. chemical analysis and type of flyash, and
4. flow rate of the flue gas (on a mass and volumetric flow rate basis).
It is important to provide the design range of each
of these items at maximum and minimum operating
loads to ensure that the system can accommodate
normally expected operating variations. A chemical
analysis of the design fuels and the boiler design heat
Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
input rate are also helpful when correlating the specified flue gas conditions with the expected fuel(s) and
establishing a consistent basis for emissions calculations reported per unit of heat input.
Emissions performance The environmental control system is typically designed to achieve a maximum
allowable outlet emissions rate that is driven by the
project air permits, other environmental regulations
or performance objectives. Alternatively, in some cases,
a minimum percent reduction performance rate may
be required. The specification should define the required performance objective including the guaranteed emission rate at the stack for each controlled pollutant and specific test conditions. The specific test
conditions include the test method to be used, test
duration, measurement frequency and period over
which the measurements will be averaged.
Reagents Many environmental control systems
require a consumable reagent to create the chemical
reactions required to control the target pollutant.
Selective catalytic reduction (SCR) and selective
non-catalytic reduction (SNCR) type NOx control systems use ammonia or urea based reagents. Various
economic, plant logistics and permitting requirements
affect reagent selection. Each type will require different equipment for storage, handling and use. Wet flue
gas desulfurization (WFGD) systems have used a variety of reagent types including limestone, magnesium-enhanced lime and sodium based upon relative
economics and specific performance requirements for
each application. Dry flue gas desulfurization (DFGD)
systems typically use lime.
Other additives and regents can also be used for
various performance enhancements and specialty processes.
The chemical composition of the reagent and the extent that composition is expected to vary should be
specified.
Quality requirements for solid wastes and byproducts
The cost to landfill solid waste materials can vary significantly from project to project. Some projects depend
on producing solid byproduct in a form that can be sold
for commercial application. Coal flyash, for example,
can be sold if the carbon concentration is sufficiently
low. Such a limitation on carbon content may affect
the design of the boiler’s combustion system and/or
coal selection, or may dictate the use of multiple stage
particulate collection to capture most of the flyash prior
to a dry FGD system.
Wet FGD systems can be designed to produce a
grade of gypsum used in wallboard production. The
specific requirements will affect the selection of dewatering equipment and may affect the design of the
purge and wastewater treatment systems. Any requirements on the quality, purity or composition of a
solid waste byproduct should be specified to the equipment supplier.
Process makeup water (FGD systems) Potential
sources of makeup water should be identified and the
analysis and range of contaminants defined. The
analysis can affect the selection of system materials
as well as the ability to achieve a specified byproduct
quality requirement. Various plant wastewater
Steam 41 / Equipment Specification, Economics and Evaluation
streams may be desirable to use as makeup water in
a dry or wet FGD system, but the composition and
quantity of each potential source should be reviewed
and analyzed on a case-by-case basis.
Wastewater requirements Typically, a wet FGD system will require a portion of the filtrate water to be
purged from the system to avoid excessive buildup of
chlorides and/or fines. The purge flow rate is typically
set to control to a maximum chloride concentration in
the recycled slurry system which is also a function of
the chloride concentration in the fuel. Higher design
chloride levels will increase the corrosiveness of the
slurry and more expensive materials will be needed
for the absorber tower and outlet flue.
Performance guarantees Specific guarantees for
environmental control systems are customized to fit
the requirements and objectives of each project. If the
environmental control system is provided as a separate, stand-alone system, performance guarantees
must be tied to flue gas conditions that are specified
at the system inlet.
Typical performance items guaranteed over the operating load range include:
1. emission levels for pollutants being controlled by
the system being installed, and
2. gypsum quality (for wet FGD systems only).
Performance items guaranteed at a specific load
condition include:
1. auxiliary power consumption,
2. reagent flow rate (limestone, lime, ammonia,
other),
3. flue gas pressure drop across the system (if supply of induced draft or booster fans is not within
the supplier’s scope),
4. makeup water consumption rate, and
5. wastewater purge flow rate.
Project requirements
In addition to critical inputs required to size and
select equipment, specifications should provide definition and direction for how the equipment supplier’s
work will integrate into the overall project.
Scope of work
Determining scope structure is a critical decision.
The buyer may specify whether or not bids should be
for a complete turnkey project, in which all components
including erection are within the supplier’s scope.
Other approaches include system island scope and
equipment packages.
Regardless of how the scope is structured, suppliers must understand the scope responsibility to ensure
that the buyer’s needs are met. If the project is executed without addressing ambiguous terminal points,
scope can be missed and the project can face problems
of schedule delay and unexpected costs. Scope definition is an evolutionary process that occurs during
project development. Several types of documents are
needed to define a project and ensure a common understanding of scope. The following should be included
as part of a contract:
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1. equipment listing and/or system descriptions,
2. division of work, including work scope provided by
other parties,
3. terminal points listing,
4. process and instrumentation diagrams (P&IDs),
5. equipment arrangement drawing(s), and
6. definition of the extent of shop fabrication.
Degrees of scope breakdown structure There are a
variety of general breakdown structures which are
used in power plant steam generation and environmental system projects, each with its strengths, weaknesses, costs and risks. Key examples include:
1. Turnkey approach for the material supply and
erection of a complete facility.
2. System island approach focusing on a major subsystem such as the boiler island, turbine island,
and environmental equipment island, each including structural steel, architectural materials, process piping, auxiliary components, etc.
3. Equipment package approach focusing on smaller
scopes such as individual components and related
auxiliaries.
For larger scope approaches, operation and maintenance agreements or equity/financing arrangements may be included.
Considerations for scope breakdown The scope structure is dependent on the buyer’s ability to manage the
project and the selected commercial contracting structure. Different scope structures result in different
impacts to the steam generating system. Listed below
are a few items to consider:
1. If a turnkey project is pursued, some suppliers
may be eliminated because of a lack of experience,
inadequate financial backing to obtain required
project security instruments, or their inability to
support the magnitude of financial risk associated
with large projects. As a result, the buyer may lose
or disqualify potential suppliers who, otherwise,
could provide good technology and services at a
competitive price.
2. In a turnkey project, the selection of sub-suppliers
may be affected by the turnkey contractor’s evaluation process and work experience/relationships.
3. Physical interfaces must be considered to minimize
the risk of missed scope relative to material, engineering, and construction. As the degree of scope
breakdown increases, risks related to physical interfaces increase. Also, some scope is integral to
equipment, such as the structural steel used to
support a baghouse or dry scrubber. Piping and
other equipment terminals need to be coordinated
to properly meet in space (type, size and location)
and so that the system is properly engineered from
a stress analysis and performance perspective.
4. Environmental equipment sizing is dependent on
the inlet gas conditions as well as the effects of potential variations in the operation of upstream systems (boiler, air heater, etc.). Proper margins should
be considered to ensure that emissions limits are
continuously met without adding overlapping lay-
37-6
ers of conservatism. If the equipment is oversized,
a higher cost could be incurred unnecessarily.
Equipment that is too small may under-perform or
fail due to overloading caused by the effects of upstream systems. Purchasing a complete, integrated
system from a single supplier allows the downstream systems to be designed using the supplier’s
experience and knowledge of the operating conditions of the upstream equipment. Purchasing as a
complete package also eliminates the complications
of performance risk responsibility that exist with a
process interface point such as between the boiler
and environmental equipment systems.
5. Performance interface risks also increase as scope
is divided and performance guarantees are required for individual components. This risk can
cause equipment within a particular system to be
over-designed. It may also cause the operation of
the facility to be less efficient because of margin
added by suppliers to manage guarantee risk. For
turnkey projects, overall unit performance, such
as capacity, NPHR and emissions are critical and become contractual obligations. Other performance
elements can be guaranteed separately as scope
becomes further broken down to support the overall
NPHR. The same philosophy could be applied to emissions. Guarantees for a piece of equipment may depend on the performance of other equipment. This can
cause each supplier to assess their individual risk and
apply appropriate margins. As a result, the overall
system may be over-designed with margin applied on
top of margin. Guarantee conditions would be based
on the scope boundary and the more boundaries that
exist, the more measurements are required to prove
individual sub-system performance.
6. When a specification is prepared, consolidation of
construction subcontracts should be considered. It
may be more economical to consolidate electrical,
civil, insulation and lagging, architectural, and
related scope across the entire project rather than
having multiple contractors responsible for the
same work but in different areas. This will reduce
interface risks and bring consistency to the project.
Site conditions and requirements There are numerous requirements specific to each project site and plant
that should be communicated to the equipment supplier. If the supplier’s work includes construction and
extended balance of plant scope, site-specific requirements are especially critical. During a bidding process,
it is often valuable for the equipment supplier and
construction contractor to visit and investigate the site
thoroughly to understand all site logistics.
Equipment arrangement The specification should
clearly describe the site and include dimensioned plot
plans showing the location of existing equipment, the
expected location of new equipment and major locations for tie-in connections to existing plant services,
among other items. The specification should also define any limitations or restrictions to be imposed on
the equipment supplier. The supplier should be encouraged to arrange the equipment within these limitations for optimal overall cost.
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The Babcock & Wilcox Company
Site access Rail, truck, barge and personnel access
to the site should be defined. Sufficient lay down areas adjacent to the site generally reduce handling
costs. However, provisions can often be made for offsite fabrication and extended modularization if space is
limited and there is sufficient delivery access. It is important to state which existing equipment and facilities
will remain operational or on-line during construction.
Site design criteria and applicable codes The specification should also include information on climate conditions and design codes that apply at the site, including:
1.
2.
3.
4.
seismic zone criteria,
wind load criteria,
snow load criteria,
range of ambient conditions for temperature and
relative humidity,
5. soil design conditions, and
6. site altitude.
Also, the specification should identify if the new
equipment will be located in an enclosed building or
outdoors. Even in colder climates, some owners prefer to use as few building enclosures as possible.
Standardization requirements and design criteria It
is important to define any plant standardization requirements that may have been developed to make
operation and maintenance easier and more consistent throughout the plant. Such items could include
common suppliers for valves, instrumentation, motors,
etc. This can be done by providing a list of acceptable
suppliers for certain equipment. However, caution
should be taken not to over-specify equipment requirements. Different technologies can require different criteria and while clear performance expectations
should be outlined, excessive detail may add unnecessary cost.
Project schedule The specification should accurately state project schedule requirements for engineering work and document submittals consistent
with the scope and needs of multiple suppliers, equipment deliveries to site, construction and commissioning, startup and testing. The project schedule needs
to be developed backwards from the required on-line
date, allowing adequate time for equipment to be
checked and commissioned after installation. Equipment deliveries should be scheduled to support the
expected erection sequence, but also need to recognize
lead-times required for engineering, procurement of
raw materials, and fabrication. For projects involving
the modification of or addition to existing equipment,
the project construction schedule may need to be carefully coordinated around normally planned maintenance outages or lower demand periods. If the required outage span is of critical economic importance
to the project, the incremental value should be defined
to the bidders so that added construction costs for multiple shifts and peak labor can be evaluated and optimized. Typically, the value to the plant owner of having the equipment on-line sooner easily justifies the
additional cost required to minimize an outage span.
However, these tradeoffs need to be properly considered.
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Commercial terms and conditions
A bid specification should identify the expected commercial terms that would apply to a resulting contract.
Major clauses that are typically part of a contract include liability terms and limitations thereon, warranty,
force majeure, contract completion dates, title and risk
of loss, changes to the work, proprietary data, choice
of law, cancellation, payment terms, and insurance.
In many instances these are prepared and negotiated
for specific projects to meet both supplier and buyer
needs. In other cases, the United States (U.S.) Uniform Commercial Code, as adopted in the various
states, or other laws, rules or regulations provide protection for the buyer and supplier in the absence of
specific contract provisions.
Payment terms Matching payment terms to a
supplier’s cash flow needs minimizes project cost by
reducing working capital requirements. Milestone
payments provide a payment upon receipt of order, with
additional payments following drawing submittal,
major material orders, and completion of major component fabrication. Progress payments are made at
given dates following project initiation.
Invariably, payment terms must balance two competing interests: the owner’s desire to assure that the
project will be timely completed in accordance with the
contract, and the contractor’s interest in assuring a
positive cash flow. For this reason, many projects provide for some retained amount from each invoice, often 5%, which can be reduced or liquidated once the
contract is completed. The contractor may be allowed
to substitute a letter of credit or bond for the retention once performance guarantees are met.
Evaluation criteria
The design of steam generating units and environmental control systems involves complex tradeoffs
between hardware options and operating costs. For the
supplier to provide the best possible offering to meet
the buyer’s needs, it is important to include the general criteria and quantitative factors the buyer will use
to evaluate competing proposals. The following is a list
of potential key performance items for which quantitative evaluation factors should be provided, depending on project application:
1.
2.
3.
4.
5.
6.
7.
boiler fuel efficiency,
main steam and reheat steam pressure drop,
auxiliary power consumption,
auxiliary steam flow,
reagent flow rate (ammonia, lime/limestone, etc.),
SCR catalyst life, and
flue gas pressure drop.
Other evaluation factors can include ash disposal
costs, revenue from byproduct (e.g., gypsum) sale, and
extended warranties, etc.
General bid evaluation
Once the specification has been prepared and proposals have been submitted, bids are evaluated. A
consulting engineer may be used to help with the
evaluation. Although the best bid is usually competi-
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The Babcock & Wilcox Company
tive, it is not always the lowest price. A thorough review must consider whether the supplier has offered
the intended scope, and any exceptions to the specification must be evaluated. Bid evaluation generally
includes a review of scope, operating ease, maintenance and operating costs, service, design and construction features, hardware, schedule, experience,
commercial terms, and price.
Scope
Scope of supply typically differs between suppliers.
It is important to verify what items are explicitly covered in each bid. Inconsistencies between bids can be
resolved by discussions with the suppliers and by assessing a cost for discrepancies in the bid evaluation.
Operating ease
Design differences will appear among the product
offerings. Seemingly minor design features can significantly alter costs. It can be valuable to have boiler operators evaluate the benefit(s) of such design features.
Maintenance costs
Designs that require minimal maintenance provide
ongoing cost savings. Areas that previously demanded
high maintenance, such as refractory and brickwork,
have generally been eliminated from modern boiler
designs. Current gas-tight water-cooled furnace construction has replaced the tube and tile design. However, some corner seals, hangers, supports and spacers may still be high maintenance items if not properly designed. Pulverizer designs can vary widely resulting in significantly different annual maintenance
costs. These factors can be incorporated into the final
evaluation discussed later.
Operating costs
Annual boiler operating costs can approach the
initial unit investment. Therefore, fuel and auxiliary
power costs should be quantitatively evaluated. Based
on estimated fuel cost, discount rate and the predicted
unit life, present values can be assigned to calculate
annual fuel and power costs. Other operating costs
include reagent usage for emissions control systems,
wastewater flow rate (water treatment system cost),
and solid waste disposal costs, among others.
Service organization
The quality and capability of a supplier’s after-market service department are important. An experienced
staff can troubleshoot problems quickly and minimize
costly downtime. Factors that should be considered
when evaluating supplier alternatives include the
proximity of the supplier’s office or representative to the
plant, the number of available personnel, and the
training and experience of the service personnel.
Design features
A thorough bid evaluation must review the
equipment’s design and construction features and
determine if certain technologies favor one supplier.
Although some designs may present a low initial cost,
accompanying higher maintenance requirements may
quickly offset these savings.
37-8
Areas that should be reviewed include, but are not
limited to:
1. furnace design and arrangement to determine how
the supplier has accommodated the specified fuel
characteristics in the proposed design to ensure
that the effects of slagging, fouling, erosion and
corrosion are minimized, while achieving low NOx,
CO and unburned carbon performance;
2. low NOx burners to determine if they have been
effective on a similar installation;
3. pulverizer design regarding maintenance requirements and degradation between overhauls; and
4. superheater supports.
If special design requirements were specified, the
evaluator needs to ensure that each supplier accommodated the requirement. For example, if very rapid load
change requirements are specified for a supercritical
boiler, additional hardware may be required for the
steam generator to comply.
Construction features
If the scope of work is limited to material supply
only, the degree of shop fabrication and the extent of
design for constructability offered by different bidders
can vary and have a significant effect on the material installation cost. The degree of shop fabrication
can range from supply of many small components to
large prefabricated modules. Even seemingly minor
differences can result in significantly different field
labor requirements that need to be evaluated. The
degree of shop fabrication on a given project is typically driven by transportation logistics and site access
limitations. Plants located with good access to water
transport can benefit from increased shop fabrication
efficiencies, reduced construction risks, and reduced
peak labor requirements at the site.
Schedule
As-bid schedules should be compared to one another
and to the specification. A shorter overall project schedule can reduce project financing costs or increase revenue through early completion and startup. However,
early delivery of some equipment does not necessarily reduce the overall project span if that equipment
does not fall on the project’s critical path. If the scope
being proposed does bring the project economic benefit from a shorter span, then differences can be subject to a quantitative evaluation credit or penalty.
However, if that credit is to be realized, sufficient commercial motivation (such as a bonus for early completion or liquidated damages for late performance)
should be established in the contract to ensure that a
bidder offers a realistic commitment.
Project management and
project team
An equipment supplier’s project manager and key
project personnel can greatly influence project execution performance. It is the responsibility of this project
team to ensure that the specified product is provided
in accordance with the contract schedule and within
project cost constraints. Sub-suppliers and vendors
Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
must be managed effectively, the team needs to respond to buyer changes in scope and design, and communication with the buyer and other project entities
must be maintained. The ability of the supplier’s personnel to manage these critical functions can have a
significant effect on project execution. It is in the
buyer’s best interest to review and evaluate the experience and capability of the personnel that a supplier
will assign to a project, especially if the project is large
in scope, complex, or has extraordinary requirements.
Experience
Demonstrated success in executing projects using
similar equipment with similar scope and complexity
is an important factor to ensuring success of using a
selected supplier. If the technology being selected has
limited commercial experience, the buyer must depend
on the supplier’s experience with similar technologies
and ability to support performance guarantees. The
buyer should contact organizations that have purchased similar units. Visits to operating installations
can provide important insights.
Terms and price
Proposed payment terms and schedule should also
be evaluated carefully. Differences in payment terms
can represent a significant value to the project. However, deferred payments can also be expensive. Commercial terms and conditions essentially define the
level of risk that a supplier will share with the buyer.
The lowest cost can be achieved when the buyer and
supplier share a reasonable amount of the project risk.
Also, performance guarantees rely on a supplier’s
ability to back them up. This ability should be evaluated before awarding a contract.
Commercial structure
Another major decision is the commercial contracting structure. Traditionally, the developer of a capital
equipment project will issue a tender for major equipment packages in which the owner or developer will
manage the risks of integrating these packages.
Some projects such as those financed off-balance
sheet (or project financed) need to have single-point
guarantees of plant performance and construction
schedule to address financial risks. An owner or developer may therefore need to employ a general contractor or possibly a consortium of companies that will
manage the project integration risk and provide overall guarantees.
Another concept is to establish a strategic project
alliance or partnership with one or several major equipment or system suppliers to jointly develop, manage,
and share the risk of project integration and execution.
Traditional commercial structures
A company that is planning a major capital equipment project, such as a new coal-fired power plant,
must work through many of the following development process steps to obtain corporate management
approvals, project financing, local community support
and any required government permits:
Steam 41 / Equipment Specification, Economics and Evaluation
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Define basic needs, objectives and goals.
Explore critical logistics and feasibility.
Identify permitting requirements.
Assess potential alternate approaches or technologies.
Optimize design requirements to meet the goals
and objectives.
Evolve a plan and timetable for development and
implementation.
Secure capital financing.
Identify internal and external resources needed
to develop and execute the project.
Develop specifications for the equipment and system packages that will be purchased.
Evaluate bids and select supplier(s).
Traditionally, the project developer will work
through these steps using in-house resources or by hiring a consulting engineering company to support the
project feasibility and development activities. The
equipment supplier can also be a key resource in a
number of these areas. However, because the traditional procurement philosophy depends on maintaining competitive pressure on the qualified equipment
suppliers, the opportunity to involve an equipment
supplier in the developmental stages can be limited.
Traditional procurement methods require the equipment supplier to bid competitively to a fixed specification after most of these steps have been completed. The
success of this approach depends on the expertise,
oversight, direction and integration capabilities of the
owner and its hired consultant to develop and define
the specific scope and design requirements.
Selection of equipment suppliers is primarily based
on low evaluated bid price. With emphasis on low capital cost and the need to compare technically equivalent offers, long-term value relating to operating costs,
maintenance, and availability can be lost in the process. In addition, a low price may motivate the selected
supplier to work in a manner that may not be in the
interest of the owner during the execution of the contract in an attempt to avoid losses on a project with
low profitability.
An owner also can find that project costs increase
with changes in scope or design that evolve during the
project. Changes are more costly when they occur later
in the process as they will affect work already completed, and may impact the work and scope of other
contractors/suppliers.
Collaborative partnerships/alliances
Recently, collaborative alliance-type business structures have been used to integrate the equipment supplier into the project development process. Such an
approach allows the equipment supplier to contribute
resources and expertise when the project is taking
shape and project direction is still flexible. The equipment supplier can function as a team member or partner, rather than simply a service provider addressing
a fixed specification.
In such an alliance, all parties can contribute to the
final solution and can benefit from the result. This
approach involves the major supplier(s) in the development phase of the project, a time when specific prod37-9
The Babcock & Wilcox Company
uct knowledge can best be applied. This establishes
project design requirements that recognize plant operational needs, establishes appropriate levels of redundancy, and evaluates the layout of equipment to
best facilitate erection and maintenance access. The
ideal time to evaluate and optimize a project is during these early stages.
The commercial framework of an effective alliance
should include a system of risk and reward incentives
that will keep all partners motivated to work towards
the common goals of project cost, project schedule execution, and equipment performance. Partners should
be motivated to earn their profit by performing at or
better than a set of measurable, mutually beneficial
goals established for the project.
Benefits of a project alliance Large complex projects
are well suited for collaborative alliances. Involving
an experienced equipment supplier in the development of the plant design, definition of scope, and estimation of capital costs can bring significant value to
the process and can avoid fatal flaws of assumptions
that can be made during the initial conceptual stages
of a project.
Once an alliance is established, the owner and the
supplier can develop a relationship that capitalizes on
the strengths of each organization as they work
through the issues and move forward to creatively
address challenges of operations, maintenance and
project execution. Some of the benefits that can be
realized from such an alliance program structure include the following:
ent. The equipment supplier needs to be selected at a
much earlier point in the process. Because this selection can not be based on competitively bid prices, other
factors need to be evaluated to determine the relative
degree of confidence that the candidate partner will
contribute. Such factors include:
1. Many aspects of the bid specification development,
proposal development, proposal evaluation, supplier selection and contract negotiation processes
are eliminated, saving time and money.
2. The project team can employ a cooperative approach to focus on optimizing the owner’s true
costs. Decision-making can focus on the best longterm value rather than on the lowest near-term
capital cost.
3. The project specification can be prepared interactively, allowing innovative solutions to be identified, more thorough project planning to be implemented, and false starts to be minimized.
4. The legal and financial framework is typically established at the beginning of the alliance and
usually requires little adjustment during the life
of the alliance.
5. Project resource assignment and loading are
planned to achieve the best utilization of personnel from all participant organizations, eliminating
redundancy and extra costs.
6. Open communication can be used in all aspects of
planning and job tracking, which builds trust and
minimizes conflict.
7. For multiple unit or multiple plant projects, lessons
learned on earlier project phases can benefit later
stages of the project. Implementing lessons learned
is a key factor to achieving economic benefit over
the duration of the alliance.
Power system economics
Factors to consider When considering the alliance
option, the development process is inherently differ37-10
1. experience and success record for the technology
required,
2. experience with other projects performed under an
alliance agreement,
3. experience performing a project of similar scope,
design and complexity,
4. qualifications, experience and capabilities of the
project team that will be assigned to work on the
project,
5. capabilities to manage cost and project risk to competitive levels through a combination of materials
sourcing capability, systems project management
and control, labor charge rates, and markups (overhead and profit) that would be applied against actual costs incurred,
6. degree that the partner will share and limit project
cost overruns relative to a mutually developed
target cost,
7. degree that the partner will share the financial risk
associated with the operating performance of the
equipment and systems to be supplied, and
8. degree that the partner will share the risk of project
schedule performance to meet targeted commercial operation.
The relative economics of the options must be compared as part of the evaluation of alternate power
systems or different product offerings. Unfortunately,
this is not a straightforward, simple task. Large
projects involve a complex series of time dependent
cash flows which usually include an initial near-term
investment in plant and equipment, and a long-term,
uneven series of operating costs, maintenance costs
and revenues from the sale of power or end product.
This is further complicated by the time value of money
and the effects of inflation. Money today is generally
worth more than the same amount of money a year
from now because of: 1) the potential interest which
could be earned during the next year, and 2) the erosion in the future buying power due to inflation. The
following provides a very brief overview of several
methodologies used to place the total evaluated costs
of different projects on the same financial basis so they
can be directly compared. More comprehensive discussions of such evaluations are provided in References
3 to 6. This discussion is broken down into the following subsections:
Constant versus current cost basis
Definitions
System cost evaluation
Evaluation parameters
Methods for evaluating operating costs
Other considerations
Examples
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The Babcock & Wilcox Company
Constant versus current cost basis
Analyses are conducted on either a current or constant cost basis. The current cost basis presents costs
as they would be expected to appear on a company
balance sheet in the future while the constant cost
basis does not include inflation.
The selection of the constant or current cost approach usually does not change the economic choice
between similar projects. For nearer term projects,
such as plant upgrades or the addition of small components, current costs are frequently used because of
near-term impact. For longer term projects such as
new plants, constant costs are frequently used as at
least one of the evaluation tools so that the effect of
inflation does not distort real cost trends. In either
case, it is important to use the same basis for evaluating all alternatives. The examples provided below are
evaluated on a constant cost basis.
Definitions
The following parameters provide the basis for the
economic evaluation:
Discount rate (k) This is the cost of money for a
power system owner and includes the weighted cost
of capital for each class of debt and equity. Establishing the appropriate cost of capital or discount rate is
increasingly complex. References 4 and 7 provide detailed discussion on the sources of funds and the
evaluation of their costs. A simplified discount rate (kc)
estimate can be obtained from the following equation
which takes into account that interest payments on
debt are generally tax deductible expenses:
kc = ( FD ) kd (1 − TR ) + ( FE ) ke
(1)
where
FD
FE
kd
ke
TR
=
=
=
=
=
fraction of capital consisting of debt
fraction of capital consisting of equity
annual debt interest rate
annual stockholder return
fractional income tax rate
The annual debt interest rate and stockholder return reflect the anticipated impact of inflation and are
used in current cost basis analyses. If a constant cost
based analysis is desired, the current cost discount
rate (kc) can be related to the constant cost discount
rate (kf) through the escalation or inflation rate (e) in
the following equation:
kf = (1 + kc ) / (1 + e ) − 1
(2)
The escalation rate may have to be treated as a time
dependent variable if it is expected to change significantly over the period of analysis.
Fixed charges Also referred to as carrying charges,
these are the fixed annual costs associated with the
initial capital investment and are generally incurred
whether or not the plant is operated. The components
include the return on investment, capital recovery (or
depreciation), property taxes and insurance as well as
federal and state taxes. Over the life of a new plant
the annual revenue requirement declines because of
Steam 41 / Equipment Specification, Economics and Evaluation
income tax effects and depreciation of the initial capital investment. However, a weighted average or
levelized value is frequently used for evaluations. To
obtain a levelized value the actual annual fixed
charges are discounted to the present and then
levelized using the equations discussed below. Annual
fixed charge rates vary from 10 to 21% of the initial
total capital investment.
Interest during construction This refers to the cost
of money during construction prior to initial plant
operation. It is not included if all project costs are incurred in a single year.3
Capacity factor This is the total power produced in
a given period (typically one year) divided by the product of the net unit capacity and the given time period.
It accounts for part load operation and outage times.
The capacity factor varies over the plant life, typically
climbing to a maximum in the first few years, remaining relatively constant for a period of several years and
then falling as the unit begins to age.
Load factor This is the fraction of the full load or
maximum continuous rating (MCR) at which the
steam generating system is normally expected to operate for extended periods of time.
Net plant heat rate (NPHR) This is the total fuel
heat input expressed in Btu divided by the net busbar
power leaving the power plant expressed in kWh.
Plant total energy efficiency (E ) can be obtained from
the following relationship:
E =
3412 Btu/kWh
× 100%
NPHR
(3)
The NPHR typically varies with plant load.
Demand and auxiliary power charges These are the
charges placed against the internal use of energy for
auxiliary equipment. Separate rates are established by
electricity and steam usage. The size of the charges
depends upon the cost of fuel and other operating costs.
System cost evaluation
In the economic evaluation of steam generating
systems, it is important to include all appropriate costs
and expenses. Table 2 provides a list of typical capital, variable and fixed operating and maintenance
costs which could be associated with a steam generating system installation. Capital costs basically include
all expenditures for the purchase, installation and
startup of the steam generating system and its auxiliaries. Care must be taken to ensure that different
product offerings contain the same scope of work. To
obtain the total plant investment, interest during construction, initial inventory items (such as fuel) and contingency are added. Variable operating costs include
delivered fuel cost, other consumable material purchases, power and steam demand charges, and waste
disposal or byproduct use.
Fixed operating and maintenance costs cover operating expenses which are likely to be incurred
whether or not the plant is in operation. These change
from year to year and generally increase as the plant
ages. They also tend to vary with the unit load pattern, plant size, and primary fuel.
37-11
The Babcock & Wilcox Company
Table 2
Typical Steam Generating System Cost Items
Capital Costs
Boiler (nominal scope including burner system and air heater)
Fans and drives
Appropriate flues and ducts
Coal crushers
Pulverizers
Pyrite removal (pulverized coal units)
Dust collectors
Ash handling
Steam coil air heaters
Steam piping
Injection water piping
Startup pump and drive
Feedwater heaters and piping (if used)
Feedwater treatment
Selective catalytic reduction (SCR) system
Flue gas desulfurization (FGD) system (dry or wet)
Baghouse or electrostatic precipitator (ESP)
Wet ESP (if required)
Reagent storage and preparation systems
Reagent slurry pumps and piping
Gypsum dewatering system (if wet FGD system is used)
Tanks and sumps
Instrumentation
Controls
Foundations and electrical connections
Structural steel
Building
Platforms
Freight
Sales taxes
Site preparation
Erection/insulation/painting
Startup
Performance tests
Miscellaneous engineering and supervision services
Variable Operating Costs (Credits)
Primary fuel cost
Electrical and steam power demand:
Fan power
Pulverizer power
Recirculating pump power
Boiler feedpump power
Crusher power
Makeup water and chemicals
Wastewater treatment
Steam demand:
Sootblowers
Flue gas reheat
Air heating
Compressed air demand
Ash removal and disposal
Auxiliary fuel for low load stability
Other consumables (ammonia, limestone, etc.)
Credits for any byproduct sales
Fixed Operating and Maintenance Costs
Plant operators
Maintenance labor
Maintenance material
Chemical cleaning
Replacement material
Supervision
Other overhead items
37-12
In the financial evaluations, selected penalties or
operating costs can be associated with superheater,
reheat superheater and economizer pressure drops
(steam-water side and gas side). Depending upon the
buyer’s perspective, these can be explicitly listed as
separate operating costs or they may be indirectly
accounted for as part of the general electrical and
steam power requirements listed above. Reheat superheater steam side pressure loss is of particular interest because of its strong connection with thermal cycle
efficiency.
Evaluation parameters
Present value With an economic life stretching
many decades, power plants experience operating
expenses over extended periods of time. It is necessary
to account for the time value of money in evaluating
projects which have differing initial capital investments and future expenses over several years. This
is usually accomplished by using a present value (P V )
calculation for each annual cash flow. The P V of a future value or payment (F V ) in year n is defined as:
PV = FV (1 + k )
−n
= FV ( PVF )
(4)
where
PVF = (1 + k)−n = present value factor
k
= interest or discount rate
n
= number of years or periods at rate k
An alternate use of the PVF is to evaluate the future
value of a present value:
FV = PV / PVF
(5)
Where a series of equal future annual payments,
A, will be made for n years, the PV is defined as:
(1 + k )n − 1
= A ( SPVF )
PV = A
k (1 + k )n
(6)
where
SPVF = uniform annual series present value factor
(1 + k ) − 1
n
k (1 + k )
n
=
As with the single payment present value factor,
SPVF can be used to convert a PV into a series of future equal payments for n years:
A = PV / SPVF
(7)
For illustration purposes, Table 3 provides values
of PVF and SPVF for a discount rate of 6% from 1 to
30 years.
Levelization In evaluating various power system
options, it is frequently desirable to compare weighted
average annual values of future costs such as fuel
instead of the lumped sum present values. Such a
Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
parameter would be a levelized cost evaluated using
the following equation:
n
Levelized value =
∑ ( FV ) ( PVF )
j
j =1
j
SPVF
(8)
where
PVFj = present value factor for year j and rate k
FVj
= future annual payment in year j
SPVF = uniform annual series present value factor in year n for discount rate k
j
= individual years up to n years
k
= annual discount rate
For the special case where the annual payment
escalates or is inflated from an initial value of S1 with
a constant rate, e, the future value of the annual payment in year j is:
S j = (1 + e ) S1
j
(9)
The resulting levelization equation then becomes:
Levelized value of S
1 − (1 + e ) / (1 + k ) n
= S1
k−e
/ SPVF
(10)
Methods for evaluating operating costs
There are several approaches to the evaluation of
operating costs. The revenue requirements method
and the capitalized cost method are reviewed here and
examples are given. While each method used involves
a large number of inherent assumptions, these are the
dominant methods used to evaluate steam supply and
emissions control equipment. See References 3 to 7 for
more discussion.
Revenue requirements method This method determines the minimum gross receipts which are required
to make each alternative pay its way. The alternative
that requires the lowest receipt of revenues is the economic choice as it will permit profitable operation with
the smallest revenues. This method takes into account
the present value of all future expenditures and costs.
The capital (first cost) expenditure which is justified in order to put two alternatives on an equal basis
is less than the difference in future revenue requirements. The future revenue requirements are converted to current dollars by multiplying each future
expenditure by the PVF for each year in which the
expenditure will occur. By summing the present value
of the future revenue requirements, a total present
value is determined. To convert this sum into a justifiable capital expense, it must be levelized, or converted
to an equivalent equal annual cost. This is done by
dividing the total present value by the uniform annual series present value factor (SPVF) (which is
13.765 for a 30 year period and 6% interest rate, used
in the examples that follow). A tabulation of present
Steam 41 / Equipment Specification, Economics and Evaluation
value factors (PVF) for 6% interest rate is shown in
Table 3. Present value factors for other interest rates
and evaluation periods can be evaluated from Equations 4 and 6. After converting the total into an equal
annual cost, the justifiable capital expenditure is determined by dividing the annual cost by the fixed
charge rate.
Capitalized cost method This method assumes that
the equipment being operated has an infinite lifetime
and that the costs of operating the unit will continue
indefinitely. It is a simpler evaluation procedure to use
than the revenue requirements method described
above, but is not as exact or flexible in accounting for
future changes in such items as fuel and maintenance
costs which will change during the life of the unit.
The amount calculated using this method is the
justifiable capital expense which can be spent to purchase the additional equipment and still give an operating advantage.
For example, if it is found that additional air heater
surface will achieve higher unit efficiency, i.e., fuel
savings over the lifetime of the unit, the additional air
heater surface is justified if its capitalized cost is less
than the cost of the fuel which can be saved over the
remaining unit life net of any tax impact.
Other considerations
Risk All new projects involve some level of risk or
uncertainty. Short-term projects using established
technology typically are considered low risk while
long-term projects using new, untried technology are
generally considered higher risk. A number of approaches are used to account for the risk or uncertainty during project evaluations. One approach is to
establish special guarantee provisions in the specifications and contract. This will typically increase the
price from the suppliers since they assume more of the
risk. A second approach is to increase the buyer’s inTable 3
6% Compound Interest Factors
Single
Payment
Present
Value
Factor
Year
(PVF)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
0.9434
0.8900
0.8396
0.7921
0.7473
0.7050
0.6651
0.6274
0.5919
0.5584
0.5268
0.4970
0.4688
0.4423
0.4173
Uniform
Annual
Series
Present
Value
Factor
(SPVF)
0.943
1.833
2.673
3.465
4.212
4.917
5.582
6.210
6.802
7.360
7.887
8.384
8.853
9.295
9.712
Single
Payment
Present
Value
Factor
Year
(PVF)
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
0.3936
0.3714
0.3503
0.3305
0.3118
0.2942
0.2775
0.2618
0.2470
0.2330
0.2198
0.2074
0.1956
0.1846
0.1741
Uniform
Annual
Series
Present
Value
Factor
(SPVF)
10.106
10.477
10.828
11.158
11.470
11.764
12.042
12.303
12.550
12.783
13.003
13.211
13.406
13.591
13.765
37-13
The Babcock & Wilcox Company
ternal contingency account in the project cost evaluation (see Reference 3). A third approach involves
making adjustments to the discount rate to accommodate the level of risk or uncertainty with higher rates
applied to riskier projects (see Reference 7). One or
more of these options, as well as other approaches, may
be used in the ranking of project options depending
upon the buyer’s internal needs.
Unequal periods When comparing project alternatives of equal life, the various evaluation techniques
generally provide similar rankings. However, when
project lives are significantly different, additional care
must be exercised in performing the analysis and interpreting the results. As an example, the costs of
additional future equipment replacement may need
to be considered when short-term and long-term repairs to a particular equipment problem are considered. In addition, when interpreting the evaluation
results, each financial model uses different assumptions about capital reinvestment which could result in
different project rankings.
Examples
Four examples follow which illustrate the use of the
evaluation methodologies. The first two examples compare the use of the revenue requirement method and
the capitalization method in evaluating the choice
between a subcritical pressure 2400 psi utility steam
cycle and a supercritical pressure 3500 psi utility steam
cycle assuming that a new power plant is needed.
Example 3 provides a comparison between two industrial boiler bids where one bidder has a higher price
but higher boiler efficiency. Example 4 evaluates the
lifetime auxiliary power difference between two industrial boiler bids. All of these examples are evaluated on
a constant U.S. dollar basis, i.e., excluding inflation.
References
1. Aschner, F.S., Planning Fundamentals of Thermal
Power Plants, John Wiley & Sons, New York, New York,
April, 1978.
2. Li, K.W., and Priddy, A.P., Power Plant System Design, Wiley Text Books, New York, New York, March,
1985.
3. Electric Power Research Institute, Technical Assessment Guide (TAG): Electrical Supply, 1989, Vol. 1, Revision 6, Report EPRI P-6587-L, Palo Alto, California, September, 1989.
4. Brigham, E.F., and Ehrhardt, M.C., Financial Management: Theory and Practice, Eleventh Ed., South-Western College Publishing, Mason, Ohio, 2004.
37-14
5. Grant, E.L., and Ireson, W.G., Leavenworth, R.S.,
Principles of Engineering Economy, Eighth Ed., Ronald
Press, New York, New York, February, 1990.
6. Leung, P., and Durning, R.F., “Power system economics: On selection of economic alternatives,” Journal of Engineering for Power, Vol. 100, pp. 333-346, April, 1978.
7. Copeland, T.E., Weston, J.F., and Shastri, K., Financial Theory and Corporate Policy, Fourth Ed., Pearson
Addison-Wesley, Reading, Massachusetts, December 31,
2003.
Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
Example 1
Revenue Requirements Method Evaluation of 2400 psi and 3500 psi Steam Cycles
A) Problem: Determine the economic choice between a 2400 psi
cycle and a 3500 psi cycle with 1000F superheat (SH) and reheat
superheat (RH) temperatures using a constant cost basis.
B) Given:
Unit 1
1. Throttle pressure, psi
2,400
2. Temperature, SH/RH,F
1,000/1,000
3. Plant size, kW
600,000
4. Net plant heat rate (NPHR),
Btu/kWh: 100% Load
9,000
80% Load
9,000
60% Load
9,180
35% Load
10,080
5. Fuel cost, $/million Btu
$2.00
6. Evaluation period, yrs
30
7. Interest rate or discount rate, %
6
8. Maintenance costs
Same
9. Availability
Same
10. Operating costs (excluding fuel)
Same
11. Fixed charge rate, % (Interest,
taxes, insurance, debt return)
14.0
12. Plant capacity factors (Units 1 and 2)
Years
100% Load
80% Load
60% Load
35% Load
10% Load
1 to 10
44%
28%
13%
6%
9%
100%
Average capacity
factor for period
Average capacity
factor for lifetime
76.30%
(a) Years 1 to 10
Unit 2
3,500
1,000/1,000
600,000
9
65.65%
52.85%
9
9
9,000
9,000
9,180
10,080
=
=
=
=
6
36,287 x 10 x $2.00/10 = $72,574,000/yr
x
x
x
x
9,000
9,000
9,180
10,080
=
=
=
=
31,467 x 109 x $2.00/106 = $62,934,000/yr
x
x
x
x
9,000
9,000
9,180
10,080
=
=
=
=
25,650 x 109 x $2.00/106 = $51,300,000/yr
(a) Years 1 to 10
$72,574,000/yr x 7.36 =
(b) Years 11 to 20
$62,934,000/yr x (11.47 − 7.36) =
(c) Years 21 to 30
$51,300,000/yr x (13.76 − 11.47) =
9
10,880 x 109
9
8,704 x 10
9
9,843 x 10
2,040 x 109
31,467 x 109
2,838 x 109
9
8,704 x 10
9
9,843 x 10
9
4,265 x 10
9
25,650 x 10
$258,659,000
$117,477,000
$910,281,000
Steam 41 / Equipment Specification, Economics and Evaluation
x
x
x
x
8,860
8,860
9,040
9,920
=
=
=
=
6
4. PV of fuel costs 3500 psi unit
(a) Years 1 to 10
$71,444,000/yr x 7.36 =
(b) Years 11 to 20
$61,960,000/yr x (11.47 − 7.36) =
(c) Years 21 to 30
$50,506,000/yr (13.76 − 11.47) =
9
$534,145,000
=
=
=
=
25,253 x 10 x $2.00/10 = $50,506,000/yr
20,814 x 10
10,596 x 109
9
3,764 x 10
1,113 x 109
9
36,287 x 10
2. Present value of fuel costs 2400 psi unit
Fuel costs for period x PVF for period
= PV of fuel costs for period
8,860
8,860
9,040
9,920
6
8,760 x 0.06 x 1.00 x 600,000
8,760 x 0.23 x 0.80 x 600,000
8,760 x 0.34 x 0.60 x 600,000
8,760 x 0.23 x 0.35 x 600,000
(c) Years 21 to 30
8,760 x 0.06 x 1.00 x 600,000
8,760 x 0.23 x 0.80 x 600,000
8,760 x 0.34 x 0.60 x 600,000
8,760 x 0.23 x 0.35 x 600,000
20,490 x 109
10,431 x 109
9
3,706 x 10
1,095 x 109
9
35,722 x 10
9
10,711 x 10
9
8,569 x 10
9,693 x 109
2,007 x 109
9
30,980 x 10
(c) Years 21 to 30
(b) Years 11 to 20
8,760 x 0.23 x 1.00 x 600,000
8,760 x 0.23 x 0.80 x 600,000
8,760 x 0.34 x 0.60 x 600,000
8,760 x 0.11 x 0.35 x 600,000
x
x
x
x
30,980 x 10 x $2.00/10 = $61,960,000/yr
Btu/yr
x
x
x
x
=
=
=
=
6
8,760 x 0.23 x 1.00 x 600,000
8,760 x 0.23 x 0.80 x 600,000
8,760 x 0.34 x 0.60 x 600,000
8,760 x 0.11 x 0.35 x 600,000
C) Solution:
1. Cost of fuel consumed per year 2400 psi unit
(h/yr) x capacity factor x kW load x Btu/kWh = Btu/yr
(Btu/yr) x ($/Btu) = $/yr
8,760 x 0.44 x 1.00 x 600,000
8,760 x 0.28 x 0.80 x 600,000
8,760 x 0.13 x 0.60 x 600,000
8,760 x 0.06 x 0.35 x 600,000
8,860
8,860
9,040
9,920
(b) Years 11 to 20
64.93%
(a) Years 1 to 10
x
x
x
x
35,722 x 10 x $2.00/10 = $71,444,000/yr
14.0
21 to 30
6%
23%
34%
23%
14%
100%
Btu/yr
8,760 x 0.44 x 1.00 x 600,000
8,760 x 0.28 x 0.80 x 600,000
8,760 x 0.13 x 0.60 x 600,000
8,760 x 0.06 x 0.35 x 600,000
8,860
8,860
9,040
9,920
$2.00
30
6
Same
Same
Same
11 to 20
23%
23%
34%
11%
9%
100%
3. Cost of fuel consumed per year 3500 psi unit
(h/yr) x capacity factor x kW load x Btu/kWh = Btu/yr
(Btu/yr) x ($/Btu) = $/yr
9
2,794 x 10
9
8,569 x 10
9,693 x 109
4,197 x 109
25,253 x 109
$525,828,000
$254,656,000
$115,659,000
$896,143,000
5. Saving in fuel costs 3500 psi versus 2400 psi
PV of fuel costs
2400 psi unit
$910,281,000
3500 psi unit
$896,143,000
PV of savings
$ 14,138,000
$14,138,000 / 600,000 kW = $23.56/kW
6. Justifiable capital expenditure 3500 psi versus 2400 psi
Justifiable additional expenditure =
PV of fuel cost saving
Fixed charge rate x PVF
PVF for 30 years at 6% interest = 13.76
Fixed charge rate = 14% = 0.14
Justifiable additional expenditure =
$14,138,000
= $7,339,000
0.14 x 13.76
Justifiable expenditure/kW =
$7,339,000 / 600,000 kW = $12.23/kW
D) Result:
1. In terms of today's worth, the 3500 psi cycle will save
$14,138,000 or 23.56/kW in fuel costs over its life as
compared with the 2400 psi cycle.
2. The saving will justify the expenditure of $7,339,000 or
$12.23/kW more for the 3500 psi cycle than for the 2400 psi
cycle, all other factors being equal.
Essentially any auxiliary power usage, difference in boiler
efficiency, or difference in net plant heat rate can be treated in the
same manner as this example. This method basically converts the
differences between designs into fuel costs. The fuel costs, which
account for future load factor, cycle heat rates and future fuel costs,
are converted into present day dollars using present value
mathematics for the projected interest rate over the life of the unit.
The justified capital expenditure can then be calculated.
37-15
The Babcock & Wilcox Company
Example 2
Capitalized Cost Method Evaluation of 2400 psi and 3500 psi Steam Cycles
A) Problem: Compare the economics of a 2400 psi cycle and
a 3500 psi cycle using a constant cost basis.
3. Capitalized value of heat rate difference
Difference = 9,216 − 9,072 = 144 Btu/kWh
Average capacity factor for lifetime = 64.93% = 0.6493
B) Given: Same information as Example 1.
Capitalized value =
C) Solution:
NPHR x kWh generation / yr x Fuel cost
Fixed charge rate
1. Average NPHR 2400 psi cycle Btu/kWh
100% Load:
80% Load:
60% Load:
35% Load:
(0.44 + 0.23 + 0.06)
(0.28 + 0.23 + 0.23)
(0.13 + 0.34 + 0.34)
(0.06 + 0.11 + 0.23)
x 9,000
x 9,000
x 9,180
x 10,080
=
=
=
=
6,570
6,660
7,436
4,032
24,698
kWh generation/yr = Capacity factor x Capacity x h/yr
Capitalized value =
144 x 0.6493 x 600,000 x 8,760 x $2.00 / 106 Btu
0.14
Average NPHR = 24,698/2.68* = 9,216
= $7,020,000
* This is the sum of all capacity factors in Item B12,
Example 1, except the factors for zero load.
$7,020,000 / 600,000 kW = $11.70/kW
D) Result:
For these conditions the expenditure of up to $7,020,000
or $11.70/kW is economically justified for a 3500 psi unit
versus a 2400 psi unit. (Note that this is quite close to
the $12.23/kW answer reached by the revenue
requirements method in Example 1.)
2. Average NPHR 3500 psi cycle Btu/kWh
100% Load:
80% Load:
60% Load:
35% Load:
(0.44 + 0.23 + 0.06)
(0.28 + 0.23 + 0.23)
(0.13 + 0.34 + 0.34)
(0.06 + 0.11 + 0.23)
x
x
x
x
8,860
8,860
9,040
9,920
=
=
=
=
6,468
6,556
7,322
3,968
24,314
The capitalized cost method of evaluation can be
adapted to evaluate auxiliary power, boiler efficiency, or
other operating costs by converting them to fuel cost.
Average NPHR = 24,314/2.68 = 9,072
Example 3
Comparing Industrial Boiler Bids with Differing Boiler Efficiencies and Capital Cost
A) Problem: Determine which of two boiler bids provides
the most economical system offering.
Annual fuel cost = ($5.00/106 Btu) (677.3 x 106 Btu/h)
x (8760 h/yr) (0.9) = $26,701,000/yr
B) Given:
1. Boiler produces 600,000 lb/h superheated steam at
1550 psi and 955F (Hg = 1460 Btu/lb from Mollier
diagram, Chapter 2)
2. Boiler feedwater is 400F (Hf = 375 Btu/lb, Chapter 2)
3. Fuel cost = $5.00/106 Btu (gas)
4. Load factor (average annual fraction of MCR) = 0.9
5. Use factor (fraction of in service time) = 0.9
6. Discount rate = 10%
7. Constant dollar basis
8. Expected unit life = 30 years
9. SPVF = 9.43 (30 years; 10% discount rate)
10. Bid No. 1 guarantees 86.5% efficiency with a price of
$10,400,000
11. Bid No. 2 guarantees 87.5% efficiency with a price of
$11,200,000
12. Income tax rate = 38% (composite)
13. Depreciation tax factor = 0.17
For bid No. 2:
C) Solution:
Equations:
Unit input = (steam flow rate) (∆H) (load factor)/efficiency
Annual fuel cost = (per Btu cost) (annual unit output)
(use factor)
Net PV of fuel savings = ∆ fuel cost x SPVF
Unit input = (600,000 lb/h) (1460 − 375 Btu/lb) (0.9) / 0.875
= 669.6 x 106 Btu/h
Annual fuel cost = ($5.00/106 Btu) (669.6 x 106 Btu/h)
x (8760 h/yr) (0.9) = $26,396,000/yr
Difference between bids (savings before tax) =
$26,701,000 − $26,396,000 = $305,000/yr
Corporate income tax on savings = $305,000 x 0.38
= $115,900/yr
After tax savings = $305,000 − $115,900 = $189,100/yr
Net PV of savings = $189,100/yr x 9.43 = $1,783,200
Difference in price = $11,200,000 − $10,400,000
= $800,000
Tax savings on depreciation = ∆ price x depreciation factor
= $800,000 x 0.17 = $136,000
(dependent upon government depreciation schedule and
discount rate)
Difference in price net of tax savings = $800,000 − $136,000
= $664,000
D) Result:
Because the net present value of the energy savings
($1,783,200) is greater than the net price for the more
efficient unit after depreciation tax savings ($664,000),
bid No. 2 provides the more economical offering.
For bid No. 1:
Unit input = (600,000 lb/h) (1460 − 375 Btu/lb) (0.9) / 0.865
= 677.3 x 106 Btu/h
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Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
Example 4
Evaluating the Cost Impact of Different Auxiliary Power Requirements of Two Industrial Boiler Bids
A) Problem: Determine the economic impact of differing
auxiliary power requirements of two boiler bids.
B) Given:
1. Power cost = $0.025/kWh
2. Load factor = 0.9
3. Use factor = 0.9
4. Auxiliary power requirements
Component
C) Solution:
Total maximum auxiliary power corrected for capacity
and load factors:
Bid No. 1 = (1,123 kW) (0.9) (0.9) = 910 kW
Bid No. 2 = (963 kW) (0.9) (0.9) = 780 kW
Bid No. 1
kW
at MCR
Pulverizer
430
Coal feeder
3
Primary air fans
200
Forced draft fans
450
Auxiliary fans and blowers
30
Regenerative air heater
10
Total maximum auxiliary power 1,123
Bid No. 2
kW
at MCR
320
3
175
425
30
10
963
5. Assume the same discount rate, unit life, and SPVF
as in Example 3.
Steam 41 / Equipment Specification, Economics and Evaluation
Annual power costs:
Bid No. 1 = (910 kW) ($0.025/kWh)
x (8760 h/yr) =
Bid No. 2 = (780 kW) ($0.025/kWh)
x (8760 h/yr) =
Difference =
Tax on difference = $28,470 x 0.38 =
$199,290
$170,820
$28,470
$10,820
Difference net of tax = $28,470 − $10,820 = $17,650
Net PV of difference = $17,650 x 9.43 =
$166,440
D) Result:
The power system supplied as bid No. 1 will cost
approximately $166,440 more to operate than the system
supplied under bid No. 2 on a present value basis.
37-17
The Babcock & Wilcox Company
Many factors are involved in specifying and evaluating the economics of a steam generating or emissions control equipment project.
37-18
Steam 41 / Equipment Specification, Economics and Evaluation
The Babcock & Wilcox Company
Chapter 38
Manufacturing
The installation of a steam generating unit involves
the design and manufacture of the components and
final erection of the unit. The power generation industry has achieved unprecedented levels of quality
and reliability in producing modern steam generating equipment. State-of-the-art design and manufacturing techniques as well as the use of advanced materials are key reasons for these gains.
Component manufacturing involves a variety of
skills and unique manufacturing methods and requires facilities for virtually all welding, metal removal, metal forming and casting processes. Manufacturing operations are continuously evolving to meet
the increased quality and productivity demanded by
today’s markets. These manufacturing and quality
evolutions have enabled the fabrication of large, complex boilers of sizes and technical competence once
thought to be unachievable.
Gaining functionality at low cost is an ever present
goal in the mature fossil power equipment industry.
Achieving high quality levels in manufactured components requires that the manufacturing facility focus on small details. It is, therefore, important for
Manufacturing to participate early in design discussions. The resultant design-for-manufacturability improvements add value to the product. Value engineering, a structured approach that enhances the manufacturing process, is used by The Babcock & Wilcox
Company (B&W) to maintain its leadership position
in the industry.
Once a design approach is determined, communication of the design information to the manufacturing facilities must be accurate and timely. Today’s computers,
integrated systems, and communication technology provide unprecedented capability to handle these tasks.
Traditional techniques as well as innovations implemented by B&W to manufacture steam generating
equipment are described in the following sections. For
information specific to nuclear equipment, see Chapter 50.
Welding
Welding and welding related processes are central
to boiler fabrication. These processes are used in
manufacturing a large percentage of components produced by B&W. In addition, many of today’s basic
welding technologies were pioneered by B&W.
Steam 41 / Manufacturing
A weld can basically be defined as a coalescence of
one or more materials by the application of heat localized in the region of the intended joint. For most
welding processes, the induced heat raises the temperature of the material above the melting point to
create a weld pool. The heat source is then removed,
allowing the pool to solidify and creating a metallurgical bond between the joined surfaces. Depending upon
the application, filler material may be added to the weld
pool to fill a cavity between the parts being joined.
There are many welding processes from which to
select. The choice is primarily based on the best
method of generating and conveying the energy
needed to create the weld. Electric arc welding is by
far the most common group of processes used in fabricating fossil fueled steam generating equipment, although other processes also apply. The most widely
used arc welding processes are gas tungsten arc welding (GTAW), gas metal arc welding (GMAW), submerged arc welding (SAW), shielded metal arc welding (SMAW) and plasma arc welding (PAW). Of the
non-arc welding processes, high frequency resistance
welding (HFRW) and laser beam welding (LBW) are
the most common. Table 1 summarizes the advantages
and disadvantages of each process and provides examples of steam generator applications. The Welding
Handbook and other sources provide specific information on the distinguishing features, attributes and
limitations of each process.1
Selecting a welding process requires consideration
of several factors. The composition of the materials and
the anticipated service conditions dictate the appropriate filler material. Base material composition also affects the use of preheat and post weld heat treatment
to control the resultant hardness of the material and
to minimize the susceptibility of the weld to cracking.
Also, the structural mass of the component and the orientation and design of the weld joints influence the welding processes selected and the process parameters used.
The quality and productivity associated with each welding process must also be factored into the selection.
Welding automation
A given welding process can be performed in a number of ways. Historically, the most common approach was
manual welding, in which the operator moves the welding torch along the joint to be welded and makes the
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The Babcock & Wilcox Company
Table 1
Comparison of Welding Processes
Process
Advantages
Disadvantages
LBW
Very deep penetration
Very high quality
Little distortion
Good mechanical properties
High capital expense
Equipment difficult to maintain
Not portable
Very good fit-up needed
Weld overlay of tubes and panels
GTAW
High quality
Low capital expense
Readily automated
Shallow penetration
High operator skill required
Low productivity
Arc radiation hazard
Tube-to-tube weld root pass
Join superheater and
economizer tube sections
GMAW
Moderate productivity
Moderate quality
Readily automated
Shallow penetration
Contact tip wear requires
periodic stoppages
Arc radiation hazard
Panel wall repair and attachments
Tube-to-tube welds
PAW
Deep penetration
High productivity
High quality
Complex process
Difficult to maintain
High capital expense
Arc radiation hazard
Sootblower tube-to-tube welds
SAW
Very high productivity
High quality
Operator protected
from arc radiation
Limited in welding position
Header fabrication
Water wall fabrication
SMAW
Very low capital expense
Very portable
Can not be automated
High operator skill required
Lower weld quality
Low productivity
Repair
Tube-to-header welds
HFRW
Very high productivity
High quality
High capital expense
Very limited in application
Tube manufacturing
necessary adjustments to the welding equipment. However, automation of welding processes has become very
common because it provides more consistent quality and
lower costs as compared to non-automated processes.
One form of automation is orbital welding, used with
the GTAW process to join superheater and economizer
tube sections. In this process, the welding head is
driven around the outside diameter (OD) of the tube
to produce a weld. A computer coordinates the motion
of the welding head, the weld filler wire feed rate and
the process parameters to maintain high weld quality.
Robotic welding and cutting are also commonly
used. Robots are used in a number of boiler-related
welding applications including seal welding of tangent
tubes in a Cyclone furnace, fabricating coal pulverizer components, applying nonferrous overlay cladding to steam generator tubesheets as well as nozzle
bores, and making complex tube-to-tubesheet welds
inside small diameter bores. The flexibility of robots
also promotes their use in plasma cutting of nozzle
openings in shells and to contour burn nozzle mating
surfaces. A number of robot types, including rectilinear, articulated arm, cylindrical coordinate and gantry style units are used in fabricating boiler components (see Fig. 1).
38-2
Applications
Automated determination of weld joint positions has
also been implemented. Electromechanical devices,
called probes, are used to track the weld groove to
ensure proper placement of the weld head during submerged arc welding. An alternative guidance method,
which has been used with the GMAW process, is
through the arc tracking. This method senses the
welding arc’s electrical characteristics to guide the weld
head. A more recent development for GTAW, GMAW
and PAW is laser-based vision tracking, in which a noncontact sensor determines the torch position within the
groove and adjusts the torch as necessary. This type of
sensor also allows automated adaptive control of the
welding process parameters by real time response to
changes in weld joint topography.
Metal removal
Metal removal is performed either to prepare a component for another manufacturing operation, such as
in machining weld joint preparations, or to produce a
finished shape. Traditional machining processes are
considered to be either chip removal or abrasive removal. The chip removal operations used in steam generation equipment production include turning, millSteam 41 / Manufacturing
The Babcock & Wilcox Company
Fig. 1 Robotic welding.
ing, drilling, boring and broaching, while grinding,
sanding and grit blasting are examples of abrasive
operations. Nontraditional metal removal operations,
such as electro discharge machining (EDM) and arc
gouging, are also used.
B&W’s fabricating shops have a variety of manufacturing equipment ranging in size from small hand
tools to machines with 100 t (91 tm) programmable
rotary tables. Larger pressure vessels require larger
machine tools. For example, the vertical boring mill
shown in Fig. 2 can accommodate a part 16 ft (4.9 m)
in diameter and 10 ft (3.0 m) high, while the horizontal boring mill in Fig. 3 has a rotary table capable of supporting 100 t (91 tm).
As in other manufacturing areas, the most apparent innovation in machining is computer control of the
equipment. Part configurations, programmed off line,
are transmitted by distributed numerical control (DNC)
to many machines on the shop floor. (See Fig. 4.) More
Fig. 3 Horizontal boring mill.
recent user-friendly computer numerical control
equipment also permits sequences to be programmed
by the machine operator. Computer numerical control
(CNC) machining centers with automatic tool changing are common. In addition, multi-spindle computer
numerical control drills are often used to prepare steam
generator tube bundle support plates. (See Chapter 50.)
These and other refinements permit some machine tools
to be accurate within 0.00005 in. (0.00127 mm).
CNC thermal cutting machines, oxy-fuel and
plasma, make use of downloaded computer generated
nesting programs to maximize material use. The addition of a multi-station CNC punch, featuring an
integral plasma burning head, complements the thermal cutting tables.
Electrical discharge machining (EDM) removes
metal by spark erosion between an electrode and the
work piece. In this process, intricate shapes matching
those of the solid carbon electrode can be burned into
the work piece. The solid electrodes are being replaced
in many cases by CNC wire electrode machines.
Automation is increasing as computers often control entire shop sections. Material, automatically
moved into storage buffers, then to CNC machines, is
scheduled and routed using computerized identification systems. Probes are often used to check the final
machined dimensions.
Forming
Fig. 2 Vertical boring mill.
Forming is the permanent plastic deformation of a
work piece accomplished by applying mechanical forces,
through tooling, to the work piece. The primary objective of forming is the production of a desired shape.
Basic forming elements include the material to be
formed, the tooling to change the shape, the lubrica-
Steam 41 / Manufacturing
38-3
The Babcock & Wilcox Company
Fig. 4 Computer numerical control machining.
tion between the tools and the work piece, and the
machine used to hold the tooling and to apply the
forces needed to form the material.
In sheet forming operations, the forces are primarily applied in the plane of the sheet. The thickness is
not constrained between opposing tools but may
change due to in-plane strains. Sheet forming operations also include tube forming processes using an
internal or external tool and sometimes both. Most
sheet forming operations are performed cold.
B&W’s principal forming applications are in the areas of plate and tube bending. Plate is bent to form
large cylindrical shells, while tubes are bent to form
flow loops or offsets. Two methods are used to bend
plate for steam drum fabrication. Press die forming is
used to make half shell courses (two seam welds) while
roll bending is used to form full round shell courses
(one seam weld). (See Chapter 50.)
Tube forming is done primarily on draw benders. The
clamp die, bend die and pressure die are always used
while the wiper die and mandrel are only required for
tight radius bends with thin wall tubing. Forming dimensions are typically expressed relative to the diameter of the tubing being bent. For example, a 1D bend
has a centerline radius equal to the tube diameter.
Tubes with wall thickness greater than 10% of the OD
do not require a mandrel or wiper die for forming.
A variation of draw bending is boost bending. Here
the tube is clamped ahead of the bend die and an axial
force is applied to push the tube into the bend region.
This shifts the neutral axis toward the outside of the
bend to reduce thinning on the outside and increase
thickening on the inside.
The application of computer numerical control to
bending, as shown in Fig. 5, is highly advantageous
for tubes containing multiple bends of the same radius.
The tube is fed into the bender, gripped by the axial
transporter and moved to a reference location. All bends
are then made automatically as programmed. The
transporter rotates the tube for out-of-plane bends and
feeds it axially to the next tangent point.
Castings
Castings are used throughout modern boilers and
steam generating equipment. The choice of castings
over other manufacturing processes, such as fabricated or machined components, is driven by functional
design requirements and by final part configuration.
Geometry often dictates the casting process as the least
costly production method.
Castings are produced from an array of materials,
from simple grades of irons and steels to complex alloys and proprietary metal chemistries and heat treatments. Material choice for particular applications is determined by tradeoffs between the function of the part
Fig. 5 Tube bending by computer numerical control.
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Steam 41 / Manufacturing
The Babcock & Wilcox Company
and the design parameters, compared to the ultimate
cost of the part.
Castings are produced using a multitude of processes including sand casting, permanent mold, die
casting, investment casting, lost foam casting, and
vacuum casting. The process selected is established by
the material being poured, the part configuration and
size, and the required tolerances. The weights of individual castings in modern steam generating equipment can range from a few ounces to many tons.
Process control is critical in producing quality castings. Process is even more important when castings
are subjected to severe operating conditions (e.g., wear
metals in coal pulverizers). Because of this control
requirement, B&W operates its own foundry, producing pulverizer wear metal components from proprietary high chrome irons. (See Fig. 6.)
Fabrication of fossil fuel equipment
Drum fabrication
A large steam drum, complete and ready for shipment, is shown in Fig. 7. The drum consists of multiple cylindrical sections, or courses, and two hemispherical heads. Large stubs and nozzles along its
length serve as flow connections for the steam generating and superheating surfaces of the boiler. The
large nozzles along the bottom and on the hemispherical heads are connections for the downcomers, which
carry water to the various generating system circuits.
Drum fabrication begins by pressing flat plate into
half cylinders or by rolling the plate into full cylindrical shells. When short shell sections must be used
because of material dimensions or heat treatment re-
Fig. 6 Casting process at foundry.
Steam 41 / Manufacturing
Fig. 7 Utility steam drum ready for shipment.
quirements, the plate is rolled into a cylinder. For large
drums, the plate is pressed into half cylinders then
welded longitudinally, forming a course. The drum
length is achieved by circumferentially welding the
required number of shell sections. Longitudinal and
circumferential welds are made using the automatic
submerged arc process.
Drum heads may be hot formed by pressing or spinning flat plate in suitable dies. The heads are attached
to the completed cylinders by circumferential welds.
Automatic welding techniques are often used to join
the various shell courses and heads. Fig. 8 shows a
two wire submerged arc welding machine on a longitudinal seam. Filler wire is continuously fed to the weld
area, which is completely covered by a granular flux
to prevent oxidation and enhance metal properties.
The electrode carriage, moving along the weld joint,
is guided by a seam tracker. Depending on the plate
material, the material thickness and the configuration
of the weld, multiple passes may be required.
For submerged arc circumferential welds, the drum
is rotated while the welding head and flux applying
Fig. 8 Welding longitudinal drum seam with double submerged arc
welding machine.
38-5
The Babcock & Wilcox Company
equipment are stationary. An electromechanical guidance device may also be used to keep the arc tracking
the weld groove.
Prior to and throughout all welding operations, preheat may be applied to minimize stresses and metallurgical transformations. In some cases, heating is
maintained after welding until the vessel has been
stress relieved.
Engineering advances in designs and the use of
high strength, high temperature alloys have required
the development of new weld techniques. This is especially true for stainless steels, Inconel® and other
high nickel alloys. The tungsten inert gas (TIG) process is often specified to attain full root penetration.
These processes also assure a uniform inside surface
contour that does not interfere with fluid flow.
Nozzles and stubs are machined from hot forged
billets, pipe or tubing. Larger connections may be integral with the heads, formed from rolled plate, or
made from heavy wall pipe as shown along the bottom of the drum in Fig. 7. Attachments are manually
welded to the drum with the shielded metal arc process using coated electrodes, by automatic satellite
welding with the submerged arc process, or by semiautomatic welding with the metal inert gas (MIG)
process. Other techniques are being developed that
will significantly contribute to welded joint quality and
increase the deposition rate of weld metal. Narrow weld
grooves in thick plates are used to reduce weld volume in the joint.
Every carbon steel drum in which the material
thickness is greater than 0.75 in. (19.1 mm) must be
subjected to a final post weld heat treatment. In some
cases, several short cycle stress relief operations may
be applied to reduce preheating. For applications requiring high impact strength, formed heavy plate is
water quenched to cool it rapidly . This heat treatment
is followed by a normal stress relief.
All longitudinal and circumferential drum welds and
the adjacent base material must be subjected to radiographic examination. For this purpose extensive radiography (x-ray) equipment is available. (See Fig. 9.)
Ultrasonic evaluations are used where x-ray examinations are difficult or impractical. Surface and subsurface defects may be located using magnetic particle
examination. Liquid penetrant examination also reveals surface flaws.
After all pressure parts have been welded, the vessel is ready for the finishing operations, including the
installation of attachments and internals.
Headers as terminal pressure vessels
Headers are used in steam boilers to connect two
or more tubes to a circuit. Headers can be fabricated
from seamless tubing, pipe or hollow forgings. Access
to their interiors is gained through the use of
handholes. Headers vary in diameter from 3.0 in. to
48 in. (76.23 to 1,219.68 mm.) OD and can reach
lengths in excess of 100 ft (30 m). Fig. 10 shows superheater headers nearing completion. Headers can
be either shop installed to components such as panels
and sections or shipped to the job site for field installation into the boiler.
38-6
Fig. 9 Drum weld testing with linear accelerator.
To fabricate a header, several pipes or hollow
forgings are first joined by submerged arc welding. The
ends of the header stock may have spherical or elliptical forged heads welded in place, or may be machined
to accept a welded-in flat closure plate.
Completion of the header includes drilling and machining the tube and nozzle openings, and fitting and
welding the nozzles and stubs (Figs. 11 and 12). Other
attachments are added by manual or semiautomatic
welding followed by heat treating, cleaning and finishing steps. These operations are conducted following strict quality control procedures.
Tubes as heat transfer surfaces
Tubes, in a variety of arrangements, are the heat absorbing surfaces and flow circuits in today’s steam generating units (see Figs. 14 and 15). Tubes range in size
from 0.875 to 5.0 in. (22.23 to 127.0 mm) OD and may
be plain, finned or studded. Finned and studded tubes
are used to create extended surface in some furnace wall
Fig. 10 Superheater headers nearing completion.
Steam 41 / Manufacturing
The Babcock & Wilcox Company
Fig. 12 Orbital welding.
Fig. 11 Header drilling on vertical boring mill.
panels or sections to aid in heat transfer. Fig. 13 shows
an opening in a wall panel surrounded by studded tubes.
Materials used include carbon steel, chromium molybdenum alloys, composites with a metallurgically bonded
stainless steel, or Inconel cladding over carbon steel.
Tubes can be shipped loose to the job site for field installation, or shop assembled into panels. Fabrication of
a membrane panel begins by placing a metal strip between each row of tubes. This strip is then welded to the
tubes on automatic equipment, which can perform numerous welds simultaneously (Fig. 15). A gas-tight metal
wall surrounding the enclosed volume is created in the
boiler by the membraned wall panels. The membraned
wall panel design eliminates the need for a pressure-tight
casing and reduces field erection costs.
Walls are typically assembled in panels up to 10 ft
(3.0 m) wide and 90 ft (27.4 m) long, although larger
panels have been fabricated. The panels may be
formed into various configurations by using one of two
bending machines (Fig. 16). To further reduce field
erection costs, some panels and sections are
preassembled into modules. Headers are often welded
to these modules to complete the assembly (see Fig. 17).
Convection superheater surface uses continuous
tube sections. A typical horizontal superheater section,
shown in Fig. 18, is made from relatively short lengths
Steam 41 / Manufacturing
of straight tube that are first bent, then welded together to give the proper configuration.
Close return bends are made by first hot upsetting
a section of straight tube to increase the wall thickness
at the bend location. Bending and hot sizing then form
the tube to the desired configuration. The prepared
bends are joined by computer controlled orbital GTAW
to form a section. Upsetting and hot bending operations
are often replaced by CNC booster bending. All other
bends in a section are typically cold formed.
To complete a wall panel or section, support lugs,
brackets and, in the case of panels, wall boxes are
welded into position. Sections are hydro tested at 1.5
times design pressure, as required by the American
Fig. 13 Studded wall panel manufacturing.
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The Babcock & Wilcox Company
Fig. 14 Hopper panel fabrication for a spiral wound universal
pressure boiler.
Society of Mechanical Engineers (ASME) Code. Sections and panels are generally painted prior to shipment. Wall panels are often painted white to reflect
light and thereby enhance worker vision within the
boiler during erection.
Longflow economizers
A longflow economizer is an assembly of finned
tubes and headers installed within a process recovery
boiler (see Chapter 28). The economizer absorbs much
of the residual heat from the low temperature flue
gases to improve boiler efficiency.
Value engineering has been beneficial in redesigning a longflow economizer, reducing manufacturing
costs, lead time and field erection costs. One economizer design change eliminates bending the tube ends
before fitting them into the inlet and outlet headers.
The ends may be swaged to a smaller diameter in an
automated process where the outside diameter and
inside diameter (ID) of the swaged section remain concentric. Fins, formed from cold rolled flat stock and
sheared to size, are automatically submerged arc
welded on both sides to a shot blasted tube. All welds
are then inspected. The tube ends are welded to inlet
and outlet headers in jigs to form platens, which are
furnace stress relieved. Finally the platens are assembled into an economizer module in a fixture. This
fixture, with stiffeners added, is also used as a shipping frame for the unit. The frame is then used at the job
site to lift the economizer module into the boiler (Fig. 19).
Structural steel and casings
As much as 11,000 t (10,000 tm) of structural steel
may be required to support a modern utility boiler. Most
of this steel is available in standard mill shapes, however some members are fabricated from plate material into
T- and H-shaped sections using submerged arc welding.
In modern units, water or steam cooled tubes constitute the basic structure of the boiler enclosure. Most
boilers also contain non-water-cooled or cased enclosures. (See Chapter 23.)
Fuel preparation and burning equipment
B&W manufactures a great variety of burners for
many fuels including oil, gas, coal, refuse, black liquor,
wood bark, combinations of fuels, and specialty fuels
Fig. 15 Wall panel membrane operation.
38-8
Fig. 16 Wall panel bending.
Steam 41 / Manufacturing
The Babcock & Wilcox Company
Fig. 17 Overhead view of wall panel construction.
(see Fig. 20). Because many similar or duplicate burners are built, product standardization and volume
manufacturing techniques have evolved. This includes
the manufacture of CycloneTM furnaces (Fig. 21).
Cyclone barrels, ranging from 5 to 10 ft (1.5 to 3.0
m) in diameter, are fabricated using many duplicate
tubes which are bent to a semicircular shape and joined
to form a cylinder. Jigs, fixtures and power tools are
used for these repetitive operations.
Cyclone furnaces are completely shop assembled in
erection frames which are also used for stress relieving the final product. This permits close quality control to assure that ASME Code and B&W standards
are met. Before shipment, a refractory coating is applied to the studded inside surfaces and the outside is
covered with a protective casing. See Chapter 15 for
further details on Cyclone furnaces.
The B&W coal pulverizer is another product that
benefits from standardization, although some variations are required due to installation configurations.
B&W’s EL pulverizer series, for smaller boiler applications, has been supplemented by the B&W RollWheel™ series. A large B&W Roll Wheel pulverizer
has the capacity to grind 105 t (95 tm) of coal per hour.
(See Chapter 13.)
The top, intermediate and lower pulverizer housings
are fabricated from plate material. Other components
such as tires and grinding ring segments for B&W’s
Roll Wheel pulverizers, and balls and rings for B&W’s
EL pulverizers, are cast from wear resistant parts.
Fig. 18 Superheater sections.
Fig. 19 Longflow economizer prepared for shipment.
Steam 41 / Manufacturing
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The Babcock & Wilcox Company
ERW tubing is typically produced in sizes from 1.0
to 4.5 in. (25 to 114 mm) OD with walls from 0.095 to
0.650 in. (2.413 to 16.51 mm) in carbon, carbon-molybdenum and alloy steel grades. Tubes can be delivered as cold drawn and normalized.
Engineering-manufacturing interface
Fig. 20 Fully assembled pulverized coal burner.
The pulverizer gearbox which is a welded and machined fabrication encloses precision bevel and helical gears. Each pulverizer gearbox assembly is run
tested before being shipped.
Tube manufacturing
Thousands of feet (meters) of tubes made from a
variety of steels and alloys are required for a large
steam generating unit. Tubes are used for heat transfer and steam generating surfaces, including furnace
walls, floors, roofs, and in superheaters, reheaters,
economizers and air heaters.
Two types of tubes are used: seamless and welded.
Each has applications within the boiler based on user
and ASME Code requirements that define diameter,
wall thickness and chemistry. (See Chapter 7.)
Seamless tubes Seamless tubes are pierced from solid
rounds of steel, which are produced in electric arc furnaces. The process is carefully monitored to produce
quality steel consistent with application requirements.
Tubes for boiler application are furnished hot finished or cold drawn, depending on size, tolerance and
finish desired. Metallurgically, the two are similar; the
differences are surface finish and manufacturing tolerances. For certain applications, the surface finish of
the tubes is critical to reduce the pressure drop. To obtain a smooth, even surface and close tolerances, stainless tubing is generally finished by cold drawing. This
process also permits grain size control in final heat
treatment, which is important in high temperature
applications of austenitic stainless steels. The production of seamless tubes requires special tools and careful control of heating and manufacturing procedures.
Electric resistance welded (ERW) tubes The ERW
tube making process begins with a coil of high quality, fully killed steel strip that has been shot blasted
for surface cleanliness. The strip is uncoiled and leveled and its edges are skived to remove defects. Passing through sequential forming rolls, the tube edges
are fused without filler metal by an electrical current
of 450 kHz. An exclusive feature of the process is online electronic weld imaging, which determines weld
integrity. This is typically joined at the welding station by ultrasonic testing.
38-10
Communications between the key areas of manufacturing and engineering are essential in achieving
state-of-the-art manufacturing. As in other manufacturing areas, computers are largely responsible for
many of the improvements. Information such as design data and drawings can be electronically transmitted to the manufacturing facilities thereby reducing total product lead times.
Value engineering, a logical planning tool, has also
streamlined projects from the engineering analysis
through the manufacturing steps. The reduction of
component complexity and improvements in product
quality and delivery are results of this technique.
Equally important as computerization and value engineering is the early participation of manufacturing
personnel in the product design.
B&W’s manufacturing emphasis continues to be on
high quality, competitively priced boiler components
and complete factory-assembled boilers as described
in Chapter 27 (see Fig. 22). State-of-the-art engineering designs, innovative manufacturing processes and
the highest levels of quality control assure that components meet all codes and customer specifications.
Quality assurance and quality control
The quality assurance department establishes procedures and controls to assure that all products conform to product technical requirements. Quality con-
Fig. 21 Cyclone furnace manufacturing.
Steam 41 / Manufacturing
The Babcock & Wilcox Company
Fig. 22 Factory-assembled boilers in various stages of completion.
trol personnel in the manufacturing plants work to
ensure that all products meet applicable codes and
specifications.
The ASME Boiler and Pressure Vessel Code (see
Appendix 2, Codes and Standards Overview) provides
rules for the safe construction of boilers and other
pressure vessels. In the United States, these rules are
also usually part of state laws. The ASME Code is
written by industry members, inspection agencies and
users of boilers and pressure vessels. It strikes an acceptable balance between safety, functionality and
manufacturability.
Section I of the Code, Power Boilers, requires a
boiler manufacturer to have the fabrication procedures, as well as the design and material selection,
monitored by a third party inspector. This authorized
inspector is usually employed by an insurance agency
and is licensed by the National Board of Boiler and
Pressure Vessel Inspectors. In plants that produce a
large volume of boiler components, this inspector may
be a full-time resident. The inspector checks drawings,
reviews material certifications, inspects welds, reviews
radiographs, witnesses hydrostatic tests and monitors
the general workmanship achieved by the fabricator.
At the completion of a job, when the inspector is satisfied that the parts comply with all aspects of the Code,
the inspector signs the ASME Code data sheet.
All welding performed on power boilers and pressure vessels must be done by Code-qualified personnel. The personnel must be trained to use the correct
filler material, welding positions and processes. In
addition, they must be trained to apply any required
preheat and post weld heat treatments. All welding
Steam 41 / Manufacturing
procedures must be qualified to assure consistent, high
quality welds. To maintain the qualifications of the
welding personnel and assure appropriate implementation of procedures, B&W operates welding training
centers and employs trained instructors at its manufacturing facilities.
Nondestructive examination
Nondestructive examination (NDE) provides the
mechanism for quality control of base metals and
weldments. There are four predominant methods of
nondestructive examination that pertain to the pressure vessel industry: radiography (RT), ultrasonics
(UT), magnetic particle inspection (MT), and dye penetrant inspection (PT). Radiography and ultrasonics
are used for volumetric examination, while magnetic
particle and dye penetrant inspection techniques provide for surface examination.
Radiography (RT) Radiography (x-ray) has been a
primary weld quality control technique for many
years. The two types of equipment commonly used are
x-ray machines and gamma ray equipment.
The choice of using x-ray machines or gamma ray
equipment is based on the mobility of the part to be
examined and the availability of an x-ray facility. Xray units can best be used in shops where fixed position equipment is available. Gamma ray equipment
may be used to reduce the time needed to examine a
circumferential weld seam. This examination is done
by locating the isotope, usually cobalt-60, on the
centerline of the unit, wrapping the outside diameter
of the weld seam with x-ray film and exposing the film
through remote control. Gamma ray equipment is
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The Babcock & Wilcox Company
usually preferred for field use or when the component
can not be readily moved.
To assure correct exposure time, a small three hole
penetrometer is placed on the object being x-rayed
which causes an image to form on the film. The penetrometer thickness and hole size are specified in applicable regulatory documents. When properly used,
an image of the holes appears on the film. Flaws of
equal or larger size are expected to appear on the film
as well. The ASME Code specifies acceptance standards
with respect to the size of porosity and slag inclusions.
It also specifies those welds that must be radiographed
in pressure vessels and pressure part fabrications.
Real-time radiography permits viewing the weld seam
on a video screen while the radiographic process is occurring. The results may also be recorded on video tape.
A significant advantage of radiography over other
nondestructive methods is that a permanent film
record is made of each inspection. These records are retained for at least five years or as required by a contract.
Ultrasonics (UT) UT examination has proven to be
a valuable tool in evaluating welds, plate and forgings
of pressure vessels. This examination can be applied
to most sizes and configurations of materials.
In generating the sound for ultrasonic testing, piezoelectric materials are used. When pulsed by an electric current, these materials vibrate and generate a
sound wave. In addition, when the materials receive
sound wave vibrations, they also generate electronic
impulses. These impulses may be viewed on an oscilloscope to locate a defect in the material or weld.
Sound is generated in frequencies typically ranging
from 200 kHz (1 Hz = 1 cycle/s) to 25 MHz.
Electrical pulses are directed from an oscillator to a
transducer that is applied to the material being examined. A liquid couplant is used for good contact between the transducer and the material being examined. The transducer generates high frequency sound
that is directed into the material. If a flaw is encountered,
some of the sound is reflected to the transducer, which
in turn generates an electrical impulse. This impulse is
then displayed on an oscilloscope, showing the size and
location of the defect. With proper manipulation of the
transducer, the entire sample can be examined. Flaw
acceptance standards are given in the ASME Code.
In addition to flaw detection, ultrasonic techniques
are used to measure material thicknesses.
Magnetic particle examination (MT) Magnetic particle examination can only be used on ferrous materials. This nondestructive examination technique will
involve either the dry method, using alternating current (AC) or direct current (DC), or the wet method,
using normal or ultraviolet light for examination. All
procedures involve generating a magnetic field in the
part being examined. A flaw on or near the surface
becomes discernible by the accumulation of magnetic
particles. The method used depends on the size, shape
and surface condition of the material being tested.
Magnetic particle examination provides an inexpensive method of determining the surface and near surface condition of the materials being tested. The process
can be used in the manufacturing facilities or in the field.
38-12
Liquid penetrant examination (PT) In contrast to magnetic particle examination, liquid penetrant examination can be used on ferrous or non-ferrous materials,
however the process only reveals surface flaws. All examinations begin by coating the surface with a red dye.
The bulk of the dye is removed by wiping the surface
with a cloth, leaving dye in any small discontinuities
that exist on the surface of the material being tested.
Dye remaining in surface flaws of the material is made
visible by applying a white developer.
Fabricators use liquid penetrant examination for
welds or base metals of non-ferrous materials, such
as stainless steel or Inconel. This examination can be
performed during manufacturing or in the field. The
equipment is inexpensive and portable and personnel can be easily trained to perform the inspection.
Quality control of fossil fuel equipment
A quality control system must be maintained
throughout all manufacturing operations. The initial
step is the inspection of incoming material to assure
that it conforms to the purchase order requirements
and the appropriate ASME Codes.
In addition to examinations stipulated by the Code,
B&W performs other nondestructive tests as process
quality control measures. Shop butt welds in boiler
wall panels and superheater, reheater and economizer
sections are radiographed. In addition, stub-to-header
welds are examined by magnetic particle examination.
These components may also be hydrostatically tested.
Internal and external cleanliness of pressure parts is
an important part of quality control. Tube IDs are
cleaned with sponges while ODs are shot blasted and
coated with a rust inhibitor. Steel balls are blown through
sections and panels with compressed air to ensure that
the components are free of internal obstructions.
In-process and final inspections, which consist of
checking critical dimensions and verifying that all required nondestructive examinations have been completed, are part of the quality program. A final inspection of truck and rail car loading is made to assure
safe delivery of components to the job site.
Technologies
The development and use of state-of-the-art manufacturing technologies have continued to be important
to B&W. The company maintains an entire group
which is dedicated to manufacturing technology research and development.
Work has been conducted to improve all aspects of
the welding operations, including planning, materials, processes, new applications and automation. In
the area of weld planning, computer based models
have been generated to assist in weld procedure optimization. When commercially available alloys are
found to be lacking in a given operation, new materials which can provide the required mechanical and
corrosion properties are developed.
Improved welding procedures are continuously being developed for the common processes as well as for
the more exotic processes, such as explosion welding,
Steam 41 / Manufacturing
The Babcock & Wilcox Company
laser welding, electron beam welding, plasma MIG and
variable polarity plasma arc welding. In the area of
welding automation, B&W has advanced off-line programming and sensor technologies to improve the flexibility of automated systems.
Dramatic changes in manufacturing are occurring
with the continuous development of advanced computer technologies. Newer machine tools will provide
greater accuracy in motion control, repeatability and
in process measurement. Bends can be made in se-
quence rather than in a batch mode, thereby reducing part inventories. Heat treating has improved with
computer control of furnace temperatures and atmospheres. Inspection is being automated through the
use of computer controlled coordinate measuring
equipment, vision systems and real time radiography.
Furthermore, manufacturing operations are being
integrated with computers on a plant wide basis to
facilitate material flow and to apply statistical process
control tools.
Reference
1. Connor, L.P., Welding Handbook, Vols. 1 and 2, Eighth
Ed., American Welding Society, Miami, Florida, 1987.
Inconel is a trademark of the Special Metals Corporation group of
companies.
Steam 41 / Manufacturing
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The Babcock & Wilcox Company
Wall panel welding.
38-14
Steam 41 / Manufacturing
The Babcock & Wilcox Company
Chapter 39
Construction
Construction plays a major role in the success of any
project. The construction organization must employ
erection techniques that complement the designers’
skill and the fabricators’ craftsmanship. Sound field
assembly is essential for correct functional performance of the completed installation. Efficient and safe
execution of any project requires that components be
on the job site at the right time along with the necessary tools, equipment, labor and supervision. In addition to properly erecting the components, a successful construction organization possesses experience in
estimating, planning, safety, quality control, cost
analysis, labor relations, tool and equipment design,
technical services, and finance and accounting. A competitive marketplace requires continuous improvements in quality, safety and cost, together with reduced
construction schedules, as contractors and owners strive
to minimize project costs and schedules. The most successful projects maintain communication between engineering and manufacturing operations, ensuring that
field erection is a continuation of the shop fabrication
process and not a completely independent event.
During initial project development, the construction
plan and work performance logistics must be evaluated, then incorporated into the overall project design.
Schedule requirements, together with safety and sitespecific conditions, will affect the labor and erection
methods that will be used.
A number of boiler types are small enough to permit shipment completely assembled. However, larger
industrial boilers, central station boilers, and environmental systems are shipped to job sites in various
stages of fabrication and subassembly. A central station boiler with its associated heat transfer equipment
and auxiliaries may weigh more than 12,000 t (10,885
tm), requiring the equivalent of 500 railroad cars to
ship the material to the site over a period of several
months. The modularized construction practices in use
today result in some boiler components weighing 400
to 1000 t (363 to 907 tm). Flue gas desulfurization
(FGD or scrubber) and selective catalytic reduction
(SCR) system modules for environmental retrofit work
may weigh between 50 to 150 tons (45 to 136 tm). In
these cases, overland and barge shipments can become unique operations.
Steam 41 / Construction
The field assembly of power generation facilities and
the associated environmental equipment requires efficient, well engineered, well organized erection methods to permit installation within a reasonable time and
at minimum cost without sacrificing quality and safety.
Modularization of complex components together with
continuous advances in computerized drafting, modeling, scheduling and tracking have become the norm
for these complex or fast track projects. The cost of
erecting a steam generating unit, such as that shown
in Fig. 1 represents a significant part of the total investment in the plant.
Retrofitting an existing plant with environmental
equipment presents a unique set of challenges requiring extensive planning and coordination between
owners, engineers, manufacturers and constructors.
(See Fig. 2.)
Fig. 1 Modern power plant construction includes appropriate
environmental equipment.
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The Babcock & Wilcox Company
local labor productivity, overtime and multiple shift
work inefficiencies, repair difficulty factors, and sitespecific conditions.
Indirect labor and support requirements
Once the direct work hour costs have been developed, indirect labor support requirements can be applied. These are driven by man days and individuals
available for the project timeline. Examples include
the general foreman, laborers, operating engineers,
unloading crews, and any other individuals needed to
support the installation labor activities.
Estimating and cost development
The estimating process begins with a complete understanding of the project work scope and specifications
for performance. The estimator prepares a detailed list
of work activities or tasks for the entire project utilizing specifications and drawings obtained from the
owner and the component supplier’s engineering function. Direct work hours for each labor category are
then assigned to each activity based upon historical
data and general experience. For example, insulation
is estimated based upon the number of hours per unit
area [ft2 (m2)] times the insulated area of the proposed
equipment. The total hours for each craft and for the
total project are then calculated. The totals are frequently corrected for a variety of factors, e.g., local
labor productivity, overtime and site factors. To the
direct labor total, indirect labor such as supervisors,
foremen and housekeeping, etc., are added to produce
a total project estimate.
Scope
Historical performance, accumulated through ongoing experience and applied through an estimating
database, provides the basis for the initial estimate.
The estimating process utilizes a variety of sources to
develop a detailed understanding of a project’s specific
work scope. These sources include product specifications, equipment and layout drawings, site visits, customer interaction, engineering, and internal data developed from experience on similar projects.
Direct costs
The direct costs associated with field construction
are developed and tied to a detailed task list by applying historical work hour rates associated with a specific quantity of material. These quantities may include tonnage, linear feet or square feet (meters).
Installation factors
Following the direct cost estimate, several specific
factors are considered to finalize the direct work hour
requirements for each activity. These factors include
39-2
Schedule and project plan development
The construction schedule is a key input to the integrated project schedules that focus on all of the disciplines needed to complete a given project.
Upon contract award, the construction project team
300
Average Workforce Per Week
Fig. 2 SCR retrofit construction.
Other factors
While detailed estimates are required for specific
projects, total estimates for nominal scope jobs frequently fall into general ranges. For coal-fired utility
boilers of nominal scope, erection work hours usually
range from 1.25 to 2.0 work hours per kilowatt. In
other cases such as retrofit SCRs or FGD systems, the
estimates do not fit such ranges well because of the
dramatically different equipment scopes and configurations possible for a given size unit.
The estimated time required to complete a project
is related to the number of estimated work hours.
There is a limit, however, for any given unit, to the
number of workers that can be efficiently employed.
If more than an optimum number are employed, the
lack of adequate work space results in diminishing
returns and excessive costs. Fig. 3 shows the typical
number of weeks required for various work hour expenditures for a single boiler unit, and the maximum
number of people utilized during peak operations.
Erection time span can also be affected by performing on a multiple shift or overtime basis. With these
alternatives, significant additional costs can be incurred due to the inefficiency resulting from working
longer hours, hours not worked, fatigue, or shift turnover inefficiencies.
250
Craft 3
Craft 2
Craft 1
200
150
100
50
0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 42 45 47
Weeks
Fig. 3 Typical labor requirements for a single boiler unit.
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The Babcock & Wilcox Company
conducts a detailed planning session. Typical participants include the project manager, scheduler/planner,
project superintendent(s), and other contributors as
selected by the project manager. The basis for this
planning session is the scope of work as originally
defined and estimated, and the existing conditions of
the construction site. During the session, missed scope
items or recent customer-initiated changes to the asbid project are evaluated. The primary objective of this
session is to document a detailed construction plan.
The information inputs needed and the outputs from
a successful planning session are shown in Table 1.
Projects are defined by a series of work activities
arranged in a logical sequence. Detailed schedules are
then developed by sequencing all activities according
to their predecessor/successor relationships. These relationships are used to assign activity durations, and
to allocate resources to complete the activity within the
desired time period. Resource allocations typically include labor plus heavy and specialized equipment.
Work activities are arranged into a work breakdown
structure and assigned activity codes. The activity
codes allow the work to be sorted by contract, area of
work, responsibility, component, or other required factors. These activities can then be used to monitor and
track progress throughout the course of the project.
Schedules are established using computer-based
scheduling systems. A broad range of detailed graphic
schedules and reports, including time scale logic diagrams, bar charts, precedence diagrams, labor graphs,
earned value curves and job completion percentages
are derived from such systems. These outputs permit
the overall coordination of several items: the work to
be performed, labor by craft or specialty, erection
equipment assignments, material deliveries, and critical resource requirements. The goal of the planning
session is to initially define the project in enough detail to ensure that subsequent tracking and monitoring activities can effectively control all resources and
job progress, identify positive and negative deviations,
and prescribe necessary corrective actions.
The level of detail developed in the work breakdown
structure is dependent on project complexity. Straightforward, short duration projects may be broken down
into less than fifty activities, whereas more complex,
long-term projects may be defined by hundreds.
Construction project management
The successful completion of a large utility construction project requires a disciplined and proven approach
for executing design, engineering, procurement, expediting, erection, inspection and commissioning. This
approach is required whether the project involves new
boiler erection, significant modifications to an existing unit, or the retrofit of environmental equipment.
Detailed project execution plans are developed to ensure proactive control of scope, safety, quality, cost and
schedule; report progress; identify deviations; forecast
trends; take corrective actions when necessary; promote communications; and coordinate the activities of
all participants. The project team is responsible to
ensure that timely constructability reviews are per-
Steam 41 / Construction
formed to integrate design and construction considerations, assuring a technically complete and
constructable design.
An initial project kickoff period provides a detailed
project definition before any engineering releases are
authorized. This definition period permits all involved
to clarify details and better define owner and engineering requirements. This phase is used to:
1. document owner design, operating and maintenance philosophy,
2. jointly review the specifications,
3. review subcontract vendor specifications,
4. allow the owner to review acceptable vendors,
5. establish procedures for project execution, and
6. firmly establish the project’s schedule.
A project team is utilized to effectively manage and
coordinate the multiple interfaces required for a large
project. This team will establish all procedures and
Table 1
Construction Planning Session
Inputs and Outputs
Session Inputs
Integrated overall project schedule
Contract documents such as commercial terms and
conditions and technical scope
Final estimate including worksheets and specified
material quantities
Subcontract scope and commitments
Material and equipment delivery schedules and
configurations
Prior site reviews
Customer/plant knowledge
Labor agreements and availability
Session Outputs
Detailed construction project management (CPM)
schedule and associated reports
Project safety plan
Manpower loading and leveling
Equipment and critical resource loading and leveling
Identification of subcontract work scope and schedule
requirements
Project work assignments for support disciplines
Site organization chart
Earned value curves (measurement of performance
against a detailed plan to predict final costs and
schedule)*
Financial reporting
Material delivery schedule
Preferred material configuration
Modularization
Field weld locations
Maximum component rigging weight
Maximum component size
Baseline weekly progress report format
* Reference − Fleming, Quentin W. and Koppelman, Joel M.,
Earned Value Project Management, Project Management
Institute, Inc., Pennsylvania, September, 2000.
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The Babcock & Wilcox Company
controls required for the coordination and routing of
documentation, design and engineering information,
technical interfaces, and correspondence.
Once the construction phase of a project begins, the
site organization serves as the primary conduit for
communication. Regular project meetings keep all participants informed.
The key element of the project management approach is the scope-of-work document. Each working
group involved in the project will develop a definition
of objectives, scope of work for their activities, data collection needs, methodology or approach to the work,
end products, responsibilities for all involved, time durations and schedules.
An integrated project schedule and report is developed to cover all activities by involved participants.
Monthly progress reporting and performance measurements are completed using the earned value concept.
Schedule trends/projections are evaluated with action
plans formulated to regain or advance the schedule
targets included in each progress report. Outstanding
or new actions are included. Potential threats to the
project’s goals are identified with alternative suggestions to reduce or eliminate any negative impact.
Design for constructability
The Construction Industry Institute (CII) defines
constructability as a process of optimum integration
of construction knowledge and experience into project
planning, design, procurement, and field operations
to achieve overall project objectives.1 CII recognizes
that maximum benefits are achieved when people
with construction knowledge and experience are involved with the project from its inception, and continue
throughout its duration. The significance of this philosophy is best illustrated by Fig. 4. The ability to influence overall project costs is greatest at the beginning of the project and diminishes asymptotically with
the progression of time.
In the past, the term constructability was generally associated with the quality of the various engineering groups’ approaches to erecting components.
Specifically, it referred to issues or potential assumptions made in association with the designer’s intent
that could preclude a component from being satisfactorily built or inspected (including errors and omissions). Information that lacked clarity was typically
resolved through various means including drawing
revisions, requests for information, engineering memoranda, and nonconformance reports. Resolution almost always increased cost as a result of rework and/
or field delays while awaiting the design engineers’
disposition. Many long-term projects now implement
constructability reviews of these design outputs prior
to the start of construction.
The endorsement of CII’s philosophy and recognition of its inherent benefits provides the foundation
for a successful project. The common goal is to ensure
the timely delivery of quality steam generation and
environmental control equipment that is erected
safely, efficiently, and cost effectively, subject to specific project constraints. This is accomplished when the
39-4
project managers, superintendents, and construction
engineers work hand-in-hand with the engineering
groups early in a project’s development cycle.
Since construction costs for some projects can exceed 50% of a total project, the cost of labor presents
both the greatest opportunity and greatest risk for
almost any project. A design for constructability seeks
to minimize impacts and improve productivity through
the elimination of rework and/or corrective action,
improve material deliveries, and incorporate some type
of modularization.
Implementation
Typical barriers to constructability implementation,
as identified by CII, include lack of disciplined coordination, failure to dedicate an individual administrator, and improper funding for the overall program. For
a constructability program to be effective, these barriers must be recognized and overcome.
Evaluation
To help evaluate constructability efforts, feedback is
needed throughout the project. During construction, it
is important to obtain an objective assessment of the
design documents from contractors and subcontractors.
Coordination and distribution of design drawings
will be monitored and reviewed prior to issuance for
construction. Innovative approaches, erection sequences, and cost saving measures will be reviewed
to assure that the final product exhibits constructionfriendly components. Constructability will also contribute to minimizing interference with existing plant
facilities, thereby minimizing the effects on the operating facility.
The benefits are most evident during the construction phase of a project once engineering and procurement are essentially complete. If flexibility in the
project schedule has already been consumed by engineering and procurement, the cost impact on the
project becomes significant. The cost of a day’s delay
early in a project is minimal, whereas, once construction has started, costs could exceed 100,000 U.S. dollars for each day of delay. Savings and benefits lie in
the reliability and predictability provided to the construction plan through the efficient use of labor and
equipment. Every job will have its share of delays due
to late deliveries, equipment failure, and acts of nature. Therefore, the goal of constructability is to select those attributes of the project that can be controlled
and then exercise maximum influence over those offering the largest payback. The proper utilization of
constructability minimizes project risks such as labor
availability and maximizes opportunities through
productivity improvements.
Integrated design process for retrofits
The integrated design process requires close coordination of design, manufacture, shipping and construction processes. Retrofit projects for complex utility systems are unique and therefore require a significant amount of design integration. Several key steps
are critical when these retrofit projects are considered:
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The Babcock & Wilcox Company
The design/construction team must share a common
and detailed understanding of the defined scope as
early as possible. This scope description and the resulting assignment of responsibilities establish the
direction of the project team.
Project definition for all members of the design and
construction team is not complete until participants
have a clear spatial understanding of new equipment
location within the existing facilities. Interferences are
relatively inexpensive to resolve at the design stage,
but can be devastating to the project budget and
schedule if recognized during the construction process.
Large retrofit projects typically span 15 to 30 months
from award to startup. This span is dependent upon the
number of units to be retrofit, the complexity of the installation, and the unit’s planned outage schedule. These
projects are impacted by numerous site-specific constraints that may lengthen the overall project.
When the total project and schedule integration
process is not followed, project management and engineering will typically initiate the design process and
begin the fabrication of materials well before the involvement of the construction manager and/or superintendent. This approach generally results in project
delays and increased costs after mobilization of the
construction team. Joint planning and an ongoing review of the design by team members from project management, engineering and construction have frequently been shown to result in a high quality, safe,
economical, and on-schedule project.
Integrating the different perspectives, knowledge
and concerns of these three key project disciplines
yields significant benefits. The first joint review only
begins the process. Ongoing reviews generate the
greatest long-term benefits. Significant design and
construction decisions must be made in ways that
balance the scope, schedule, and cost triangle to benefit the overall project.
Some of the key decisions that need to be addressed
by the team are:
1.
2.
3.
4.
5.
6.
7.
8.
9.
the best physical arrangement of the equipment,
supports for the new equipment,
utilization of existing or new steel,
defined and scheduled pre-outage, outage, and
post-outage activities,
planned outage schedule,
definition of the erection sequence,
existing access limitations and additional requirements,
shop or field modularization, and
field labor availability.
A critical period occurs early in a project when scope,
general arrangement, construction approach and
Steam 41 / Construction
High
Conceptual Planning
Ability to Influence Cost
1. Determine the detailed scope early in the process.
2. Define the general arrangement of all components
in concert with existing structures and equipment.
3. Define the construction approach.
4. Perform joint project management, engineering
and construction reviews of the design.
5. Iterate the second, third, and fourth steps to advance and evolve the design.
Design
Procurement
Construction
Startup
Low
Start
Time
Complete
Fig. 4 The ability to influence cost diminishes as a construction
project progresses.
schedule decisions are being defined and key subcontractors are being integrated into the project. Additional resources are needed to focus on technical, commercial and interface issues associated with subcontractors, architect-engineers, structural steel fabricators, and flue and duct fabricators. This support early
in the project provides the necessary attention to effectively address schedule-critical activities during a
time frame when resources are typically overloaded.
Once these specialized functions are executed, these
resources are dismissed and project team members
then consult as required.
Construction technology
The construction of steam and power generation
facilities, and all associated equipment, is a complex
and challenging undertaking. Each project presents
a unique set of objectives, subject to specific constraints and opportunities. Successful projects are the
result of detailed planning and forethought, as well
as the creative application of construction means and
methods to deal with the constraints, and to take advantage of the opportunities. Critical decisions regarding product configuration, constructability, construction equipment selection and labor issues must be
made early and followed throughout the project.
Traditionally, the construction site supervisor has
acquired the necessary skills through experience, and
therefore is well-qualified. Technological advances including computer-aided design, global positioning systems, and more powerful lift cranes have enabled construction engineers and technicians to support supervision by refining the planning process and expediting the work in the field.
Aggressive schedules, improved financial performance, increased scrutiny, and regulations regarding
safety and quality require that projects are executed
with increasingly refined margins for error, both technically and economically. The goals established for
these projects include: 1) reduced field operations costs,
2) a minimal project time span, 3) the construction of
a quality product, and 4) provision for a safe working
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The Babcock & Wilcox Company
environment. The integration of technology into the
construction process increases the opportunity to accomplish these goals through the proper, effective and
innovative application of means, methods, techniques,
tooling and equipment.
A construction technology group normally supports
the field construction program. These engineers provide construction engineering services, construction
logistics, and constructability reviews for each specific
product and configuration. Typical outputs include
recommended shipping sizes and configurations, rigging weight and center of gravity calculations, crane
placement drawings, heavy lift and hauling plans,
and structural analyses of existing facilities for imposed construction loads.
Approaches to construction –
erection methodology
There are three basic approaches that may be used
in a construction project: 1) knocked down, the traditional method, 2) field modularization, and 3) shop
modularization. The knocked down approach is based
on the erection of shop fabricated, standard-sized shipping units that readily fit on a truck/trailer or rail car.
The standard shipping units are erected one piece at
a time in stick fashion. Field modularization combines
these traditional ship units into larger components, or
modules, at the construction site for final installation.
Off-site assembly, shop modularization, or prefabrication combine the traditional ship units into subassemblies at the manufacturer’s plant.
Modularization is an integrated approach to power
plant construction whose concepts must be incorporated at the earliest possible stages of a project’s planning. The most successful projects have continued commitment to this approach by the customer, the equipment supplier, and the erecting contractor.
While modularization may be cost effective, the extent of effective modularization is site specific.
Modularization divides plant materials into subsets,
or modules, that are assembled before being brought
to the construction site. (See Fig. 5.) The degree and
extent of modularization can vary considerably. In its
simplest form, a structural steel beam with shop-attached clip angles is a module. At the opposite end of
the scale, a shop-assembled boiler complete with all
trim piping, instrumentation, and insulation and lagging, or a 50-ton section of ductwork insulated and
lagged is also considered a module.
Boiler components have been modularized for some
time. Fig. 6 depicts furnace wall panels in which loose
boiler tubing and membrane stock are welded to form the
panels. Large modularized scrubber components are
shown in Fig. 7.
A modularized project requires more engineering
and design time than a conventional project. Planning
must consider the water and land routes used for shipping the modules. Construction sites located on navigable waterways have the greatest potential for shipment of large modularized components. (See Fig. 8.)
Module unloading, site movements and erection
procedures must be carefully considered. Special consideration must also be given to foundations, backfill39-6
ing and compacting at the site. Other concurrent site
activities must be evaluated when planning for
modularization.
Construction participation by all involved parties is
required in planning any project to enhance
constructability and identify intended erection methods.
The erection method is influenced by the following factors.
Retrofit versus new plant installation The construction logistics associated with retrofitting, repairing or
altering an existing unit are much different from those
required for constructing a new unit. Logistics for new
plant construction are further diversified, depending
on whether the unit is to be built on an existing plant
site, adjacent to existing units, or on a new site. Retrofit operations are generally performed in a pre-outage/outage/post-outage mode.
In planning retrofit work, an erection method that
permits performing many tasks concurrently is chosen. This optimizes equipment and labor and minimizes outage times. When constructing on an existing plant site, the erection method must maintain a
productive interface between construction activities
and ongoing plant operations. Construction on a new
site offers a contractor the greatest amount of freedom
in selecting the most cost-effective, efficient method for
executing the work; however, potential obstructions include those areas of work occupied by other contractors.
Plant arrangement The overall plant arrangement
plays a key role in establishing the sequence for erecting components and equipment. Plant arrangement
defines the available access routes for material flow
from the laydown and storage areas to the final installation points.
Scope The scope of work directly affects the construction plan and completion of the construction.
Tools and equipment needed for one phase of the
project may also be influenced by the requirements
of other phases.
Parameters Product and component parameters,
including size, weight and shipping configurations,
dictate the type and size of material handling equip-
Fig. 5 Large scrubber modular components on a barge.
Steam 41 / Construction
The Babcock & Wilcox Company
tractors is required to achieve certain location tolerances and to complete the erection.
Schedule The project schedule, including customerspecified start, finish and milestone dates, dictates the
required erection sequence, labor needs and timing for
project completion. The quality and skills of the local
labor force play major roles in the erection plan and
overall sequencing of the work.
Because cost is an important criterion governing
selection of the erection method, the economic advantages and disadvantages of the other selection criteria must also be evaluated. Costs of construction operations versus component shipping configurations are
often arranged in a matrix. The shipping configuration reflecting the lowest total cost is considered to be
the most effective approach and becomes the preferred
choice for erection. Tabulated construction costs are
coupled with corresponding costs for component engineering, shop fabrication and assembly, and shipment to the job site to identify the most effective overall approach for a specific project.
Extent and location of field welds Overall product
quality and constructability are enhanced by minimizing the number of field welds. The required welds must
be readily accessible to allow the use of state-of-theart equipment and processes.
Fig. 6 Raising furnace wall section into position.
ment and the need for special handling procedures,
methods, jigs and fixtures. Material type, thickness,
and required erection tolerances are considered in establishing methods for component alignment, welding, post weld heat treatment, stress relieving, and
nondestructive examination.
Site conditions Existing site conditions and accessibility play major roles in determining the size, weight
and configuration of the components to be shipped.
Water accessibility represents the greatest opportunity
for shipping large shop-assembled modules; otherwise,
rail or truck shipments are required. If multiple transportation modes are used, the size of the component
is limited by the most restrictive shipping method.
Shipping accessibility only partially controls the
extent of material and equipment shipments to the job
site. Upon arrival, the material must be off-loaded and
transported to its storage area or final installation
point. Material off-loading schemes depend upon the
mode of shipment and the site conditions at the offloading area. Transportation of the material is then
limited by the width, overhead clearances and load
limitations of existing roadways.
Contractor interface Interface with other contractors is an important part of a construction project. Once
portions of the project have been completed by individual contractors, effective interfacing between conSteam 41 / Construction
Fig. 7 Modular components for an environmental control installation.
39-7
The Babcock & Wilcox Company
5. temporary structures and construction facilities,
6. civil/site work, and
7. specialized tooling, machining and equipment.
Fig. 8 A barge carrying SCR components is positioned for off-loading.
The scope of work to be performed and the component configuration influence the extent and location
of field welds. The construction engineer must provide
input regarding preferred field weld locations, suggested component configurations for these weld locations, and intended welding processes.
Construction engineering and
rigging design
Background
Babcock & Wilcox Construction Co., Inc. (BWCC)
takes an engineered approach to the execution of
heavy lifts. Specialized tools, equipment, rigs, jigs and
fixtures are provided for each project.
Modern construction includes modularized components that are erected on short timetables. To reduce
construction and shipping costs, the weight of support
steel components has been reduced. As a result, the
calculation of imposed erection loads is critical.
In recent years, customer specifications have required
the submittal of engineered rigging drawings and procedures prior to construction. These submittals often
require the stamp of a licensed professional engineer.
Engineering principles
The construction engineer involved with product
erection must be familiar with the product’s construction details and function as well as responsible for the
engineering, design and specification of all systems,
tools, equipment, devices and mechanisms required for
erection. This requires a command of engineering fundamentals and knowledge of principles taken from
civil, structural, mechanical and electrical engineering disciplines.
Engineered systems
Engineered systems required to support construction operations may generally be identified by:
1. material handling (discussed below),
2. rigs, jigs and fixtures,
3. temporary supports, shoring and reinforcement of
existing structural components,
4. access and protection structures,
39-8
Material handling and setting considerations
Like any phase of a construction project, material
handling operations must be planned and integrated
into the total construction plan. The size, weight and
shipping schedules of material and components to be
received and installed must be known in order to plan
for storage area needs and to schedule crews and equipment. Special handling provisions and special inspection
and storage requirements must be known and accommodated. In addition, the plant structure must be designed to support the loads involved during construction
and the clearances required to get equipment in place.
Material handling plans must reflect actual site conditions including rail and truck access, locations and
condition of haul roads, and availability and location
of laydown areas and warehouses. Although most material shipped to a construction site can be handled
with conventional construction equipment, material
handling plans must identify any special equipment or
fixtures required to handle large or unusual components.
Equipment used for material handling operations
may generally be grouped by function into two categories: 1) transporting, and 2) lifting.
Equipment for transporting material is limited to
that intended for on-site application, and does not include trucks, railroad cars or barges listed for material delivery to the job site.
A wide range of equipment is available for material transport and lifting on the job site. Selection and
use depend on the configuration and weight of the
material to be handled and the relative distance between transport points and available site clearances.
Selected techniques and types of equipment that can
be utilized for material transport and lifting are shown
in Figs. 9 through 11.
While this listing is intended to provide an idea of
the range of tools, methods and equipment available
for material handling, it is not all inclusive. Various
suppliers and manufacturers maintain and supply
their own version of the generic equipment identified.
The selection, specification and use of this equipment
require a thorough construction engineering effort
from the planning phase of the project through the
execution of the work.
Fig. 9 Hydraulic platform trailer.
Steam 41 / Construction
The Babcock & Wilcox Company
Depending on the equipment selected or available,
various operations are involved to get the components
to their final in-place position. These operations, represented in Fig. 12, may be accomplished by use of a
single hydraulic crane or may require a sophisticated
handling system custom designed for the application.
(See Fig. 13.)
Serviceability
The serviceability of a material handling system is
a measure of how well the system performs its intended function subject to conditions produced in its
work environment.
Imposed loads and forces
The weight of the component being handled is a
major consideration in the design and selection of the
material handling system; however, component
weight is not the only load imposed. All systems operate dynamically while simultaneously generating and
being acted upon by forces that include steady-state
and time-varying components. Forces are introduced
by the operating environment, by the work being
done, by the inertia of the masses put into motion, and
by the weights of the load and the system components.2
Imposed loads are generally categorized as gravity
or nongravity. Furthermore, both loadings may be
static or dynamic. While dynamic loading must be
recognized in designing the material handling system,
the magnitude of acceleration/deceleration loads is
small in most cases. As a result, static loading generally governs the system design.
Static gravity loading conditions are categorized as
lifted load, dead load, live load, friction or impact.
The lifted load is the calculated rigging weight of
the component being handled. This calculation must
account for manufacturing variability and normally
includes a safety factor. Shapiro suggests multiplying
the calculated weight by 1.03 for mass produced items
and by 1.07 for singular devices.2
Dead load is defined as the weight of the material
handling system components themselves, independent
of the component being lifted. In calculating this
weight, the same considerations must be made with
regard to potential dimensional variations in components. The suggested weight parameters act as multipliers as they relate to imposed loading or induced
stress and as divisors as they provide stability or uplift resistance. The imposed dead load is the cumulative weight of all other components supported from the
component being designed.
The live load is an allowance that accounts for the
weight of construction personnel, scaffolding, ash (slag
or dust accumulations), and snow or ice accumulations
on the handled component. Because these loads are
frequently unknown when the material handling system is designed, they are applied on the basis of a specified unit weight per surface area or a specified density per volume.
Friction loads are those associated with a body’s
resistance to movement. Friction takes on various
forms depending on the system arrangement and load
handling application.
Steam 41 / Construction
Fig. 10 Hydraulic gantry system.
The coefficients of static, rolling and sliding friction
define friction loads. Depending on the arrangement
of load handling components, friction may become a
significant part of the total design load.
Impact loads are associated with sudden shocks
that occur during a load handling operation. An impact allowance (25% of the handled load) is typically
applied in the direction of load movement. Minimal
impact loading is achieved by moving components at
constant, slow speeds.
Nongravity loading conditions include wind loading, seismic loading and stabilization. Most applicable
codes and specifications have reduced these dynamic
conditions to static load equivalents. For the purpose
of material handling system design, these conditions
are therefore treated as such.
Wind loading, when imposed on material handling
system components, is evaluated and applied in accordance with Uniform Building Code (UBC) or American National Standards Institute (ANSI) guidelines.
Seismic loading is not a major design consideration for
most material handling systems. Nevertheless, seismic forces
may be evaluated with UBC or ANSI specifications.
Stabilization forces are those forces required to
maintain lateral stability of compression and flexural
structural members. This force is arbitrarily consid-
Fig. 11 Manitowoc crane.
39-9
The Babcock & Wilcox Company
maintained throughout the course of load handling
operations. The specific conditions of equilibrium are
stable, unstable, and neutral.
Tower Crane
with Main
Tower
and Boom
Load control
Load control is an assurance that the load will assume a predetermined, expected orientation without
deviation throughout the course of handling operations or at any point in those operations.
Counterbalancing
Crane with Main
Boom and Mast
Crawler Crane
with Main Boom
and Luffing Jib
Ringer Crane
with Mast,
Main Boom
and Fixed Jib
Conventional
Crawler Crane
with
Main Boom
Truck Crane with
Telescoping
Hydraulic Boom
Fig. 12 Configurations of typical lift cranes.
ered to be 2% of the total force developed in the compression zone of the member being stabilized. In the
case of compression members, the compression zone
is the total cross section; for flexural members, this
zone is limited to the compression flange.
Load distribution
Throughout the load handling operation, the component being handled seeks a position of static equilibrium. A lifted load always vertically aligns its center of gravity with the centerline of the lifting hook.
Prudent arrangement and design of the material handling system is based on knowledge of the component’s
center of gravity as well as the magnitude of the resultant loads and forces acting on the system.
Depending on the handling operations involved,
the relative position of a component’s center of gravity with respect to its supports can vary with time. This
variation produces a time-dependent variation in the
magnitude of the support reactions, and thereby, the
load imposed on the material handling system. Consider the steam drum illustrated in Fig. 15. Two separate sets of load blocks and rigging are used for raising the drum to its final position in the boiler support
steel. Throughout the course of the raising operation,
it may be necessary to incline the drum to clear local
interferences with boiler support steel. As the drum is
inclined at some angle θ from the horizontal, the load
imposed on each set of blocks varies in accordance with
the following expressions:
WL1 = 1
Load stability
Load stability is the inherent tendency of a load in
equilibrium, either static or dynamic, to remain in
equilibrium and to minimize any translational or rotational effects produced via the imposition of unforeseen forces and/or moments throughout the course of
load handling operations. A rigging system (see Fig.
14) must be configured to ensure that load stability is
Y
1 + tan θ WL
2
L
(1)
Guy Derrick
W
Stiffleg Derrick
W
W
“Chicago Boom”
W
Monorail
W
Track System
on Rollers
Fig. 13 Site-specific handling system for an environmental control
installation.
39-10
W
Hoist and Load
Blocks
W
Taut Line or Cableway
System
Fig. 14 Typical rigging configurations.
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The Babcock & Wilcox Company
ready access to support the construction effort. Generally, a numbered grid system is used in laydown
yards and warehouses to identify specific storage locations. Fig. 17 shows a typical storage layout.
To support the planned construction activities, material must not only be on site and available, but must
be in good condition. In addition to inspection of the
material upon receipt, the material and the storage
areas are inspected periodically to satisfy specific storage requirements and to ensure proper protection of
the material.
With the amount of material involved in most construction projects, it is essential that an effective documentation system be used. A complete listing of items
to be received is needed to ensure that a complete inventory is maintained. For each item, material receiving and storage records must effectively document
receipt and disbursement status, condition of the material, and current storage location.
Fig. 15 Steam drum lift and support arrangement.
WL 2
Y
= 1 1 − tan θ WL
2
L
(2)
where
WL1
WL2
WL
Y
L
= portion of WL supported by high end blocks
= portion of WL supported by low end blocks
= weight of component being raised
= 2 × (transverse distance between longitudinal centerline of drum and centerline of lifting lugs)
= center-to-center spacing between lifting lugs
Per these expressions, when the drum is horizontal,
i.e., θ = 0 deg:
WL1 = WL 2 =
WL
2
Construction of a fossil fuel unit
The installation of a top-supported steam generating unit is unique in that the heaviest components are
at or near the top and most other major components
are hung from steel rods. Field assembly of the boiler
begins by positioning the major upper components in
a manner that provides a design deflection after completing the boiler installation. While the following discussion is primarily concerned with top-supported
units, many of the basic procedures apply to all units.
Structural supports
The design of the supporting structural steel must
consider the loading and stresses encountered during
the installation of the boiler. The major construction-
(3)
That is, the rigging weight of the drum is shared
equally by each set of load blocks. However, as the
angle θ is increased, the load transferred to the blocks
on the upper end of the drum is increased. Therefore,
each set of load blocks, rigging and drum lifting lugs
are conservatively sized to accommodate the total rigging weight of the drum (Fig. 16).
Design loading
The material handling system design loading is established by identifying the maximum of several critical load combinations and then multiplying this value
by a safety factor of 1.10. Typical combinations include:
lifted load + dead load + live load + impact,
lifted load + dead load + live load + friction, and
lifted load + dead load + live load + impact +
greatest of wind, seismic or stabilization load.
Friction and impact loading are mutually exclusive
events, and therefore are never considered to be a viable combination.
Other site considerations – storage
Storage is also a critical issue. Storage areas must
be laid out and material placed in storage to provide
Steam 41 / Construction
Fig. 16 Typical utility boiler steam drum lift.
39-11
The Babcock & Wilcox Company
Fig. 17 Site laydown area.
imposed loads must be evaluated. Because certain
structural members may be temporarily omitted to
permit access for large subassemblies, the associated
additional structural loads must also be considered.
Before erection is started, all foundations must be
completed and checked for specification compliance.
Because most large units are top-supported, as discussed
in Chapter 26, erection of the structural supporting steel
is the first step in building the unit. This is done by conventional methods, using cranes and derricks. Stairways
and walkways are completed to the fullest possible extent to provide safe access to all parts of the unit.
Because many of the structural members govern
the location of boiler and auxiliary components, supporting steel must be aligned with established building centerlines. After the structure has been aligned
and plumbed, the members are rigidly connected with
high tensile bolts or by welding before supporting any
structural loads.
Assembly of pressure components
The construction schedule and plan include a timely
sequence for installation of boiler components. The
steam drum is usually the first major assembly placed
in the structure. All large or heavy components, superheater modules, top headers, interconnecting pipes
and wall tube panels are positioned, following the plan,
in the boiler cavity while unrestricted space is available to access and hoist them.
39-12
Drums Drums for the largest boilers may weigh
more than 400 t (363 tm); they may be 100 ft (30.5 m)
in length and may be located more than 200 ft (61 m)
above the ground. To clear supporting steel, the drum
may be inclined by as much as 60 deg (1.05 rad) during the lifting operation. Capacity and safety of the
drum rigging are of primary importance in selecting
the equipment and methods.
Fig. 16 shows a typical drum lifting arrangement using lugs that are shop-welded to the drum. Attachment
pieces for the top of tackle blocks are located on temporary steel members above the boiler structure. These
blocks should permit simple linkage connections at the
top support and drum attachments. The capacity of the
hoisting engine and the sizes of tackle blocks and wire
rope are determined with ample safety factors.
When the drum is in its final position, it is supported
from the top structural steel by U-bolts that permit linear movement with temperature variations. Fig. 18
shows a typical drum and support arrangement. The
drum is a major anchor point for other boiler components and, for this reason, accurate location is important. The structural members, platforms and stairways
that were omitted for drum erection are then installed.
Downcomers, headers and large pipes Plant access
consideration is important and the sequential plan
should be carefully followed in the erection of downcomers, loose headers and large pipes. These components are shipped in the longest lengths possible to
avoid costly field welds. Large downcomers are often
placed in the boiler cavity while steel is being erected
and are moved to their final location when convenient.
Without proper integration into the planning sequence, these components must be shipped in shorter
lengths or additional structural steel must be omitted
to provide clearances during erection.
Tube walls To reduce cost and the time required for
field erection, a large percentage of furnace enclosure
tubes are shop-assembled into membrane panels.
B&W’s preference is to furnish wide, long panels. However, as with any modularization approach, shipping
and field conditions determine the panel sizes that can
be provided. The wall panels are erected as-received
from the supplier or, if conditions permit, the construction plan may include on-site assembly into larger wall
sections. Panels may even be ground-assembled into
complete walls with headers, casing, buckstays and
doors attached.
Superheater, reheater and economizer These components can be furnished with loose headers and individual elements or in shop-assembled modules with
or without headers. Again, the design features of the
particular unit and project determine the degree of
field or shop modularization. When large, heavy surface modules are to be erected, the construction plan
normally includes early installation while access and
hoisting clearance are available.
Tube connections Tubes are attached to drums or
headers by welding, expanding, or a combination of
the two (see Fig. 19). Generally, tubes that withstand
pressures greater than 1500 psi (10,342 kPa) are expanded and seal-welded or welded to shop-attached
stubs. Shop-assembled tube-to-header connections, such
Steam 41 / Construction
The Babcock & Wilcox Company
Fig. 19 Expanding tube connections.
Fig. 18 Radiant boiler steam drum in position.
as those in wall panels and superheater modules, are
usually welded directly into the headers. (See Fig. 20.)
Design standards permit expanded tubes for low-pressure boilers. Tube expanding, or rolling, is a process of
cold-working the end of a tube into contact with the metal
of the drum or header tube hole or seat. The end of the
tube is inserted into the hole and then plastically expanded by internal pressure; relieving of the pressure
leaves the tube tightly seated in the drum or header.
A typical roller expander is shown in Fig. 21. This
tool contains rolls set at a slight angle to the body of
the expander, causing the tapered mandrel to feed
inward when it is turned. For conditions of widely fluctuating temperatures and bending loads, the expanded joint must be seal-welded or replaced by a
shop-attached tube stub.
Field welding
The welds that are made in the erection of a steam
generating unit can be divided into two classes – those
for assembly of plate and structural materials to support the unit and those for assembly of tubes, pipes
and other pressure parts making up the steam generating unit. Welding on plate and structural materials is performed in accordance with the Structural
Welding Code AWS D 1.1.
Welding that involves boiler pressure parts must
conform to the requirements of the American Society
of Mechanical Engineers (ASME) Boiler and Pressure
Vessel Code, The fabrication Codes reference ASME
IX for Welding and Brazing Qualification requireSteam 41 / Construction
ments. ASME IX provides the requirements for qualification of procedures and welding personnel.
Various conditions make field welding different in
many respects from welding in the shop (discussed in
Chapter 38). A typical field welding environment includes dust, wind, variable temperature, rain, high
scaffolding, locations remote from supply and maintenance facilities, and a mobile labor force. Under
these conditions, it is important to consider the selection of the welding processes and equipment. Key factors include simplicity, reliability, portability, ease of
maintenance, and availability of spare parts. Equally
important are the skills and availability of the
workforce.
Manual and semiautomatic welding methods are
therefore preferred for field erection of standard boiler
components. While there is a continuing search for and
evaluation of reliable automated welding equipment
for field erection and repair, it is seldom used. For example, use of orbital gas tungsten arc welding (GTAW)
or gas metal arc welding (GMAW) have seen limited
applications due to the precise weld joint fitup requirements, development and tight control of welding parameters and technique, limited space restriction for the
equipment, lack of highly trained operators and the associated cost and maintenance of the welding systems.
Fig. 20 Headers with shop-assembled stubs.
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The Babcock & Wilcox Company
Seal welds Seal welds are used to make mechanical joints fluid-tight. Joint strength is developed by pipe
threads, tubes rolled into drum holes containing
grooves, or header master handholes fitted with specially-designed plugs (see Fig. 22). The maximum size
of seal welds made without post weld heat treatment
is 0.375 in. (9.5 mm).
Special precautions are required to obtain sound
seal welds; welding over pipe threads is not permitted. After seal welding, tubes should be lightly rerolled. Handhole plug seal welds should be thoroughly
cleaned and are preheated to avoid cracking.
Fig. 21 Position of expander and mandrel after tube is expanded and flared.
Processes and equipment
Manual GTAW, shielded metal arc welding (SMAW),
and flux core arc welding (FCAW) are the most common
processes used in the field. (See Chapter 38, Table 1.)
These processes are versatile and can be used on all fieldweld materials utilizing equipment that is simple and
easily maintained. In addition, most field welders are
qualified for the GTAW and SMAW processes.
For welding non-pressure parts or making non-pressure attachments to pressure parts, there is increasing use of semiautomatic welding. Welders trained and
qualified in GMAW or FCAW processes can make
quality welds at significantly higher deposition rates
compared to the GTAW or SMAW process.
As with the GTAW process, adequate precautions
must be taken to protect the weld area from the elements,
especially excessive wind. When a flux core welding electrode that is self-shielded, i.e., does not require external
gas for protection of the molten weld puddle, is used for
erecting boiler casing and other structural components,
excessive wind must still be avoided.
Applications
Pressure welds Welds joining dissimilar metals are
typically made in the shop because they are often difficult to make under field conditions and require special qualification. Field butt welds in tubes and pipes
are made using pre-machined weld joints that have
been covered with a protective cap. Thorough inspection and cleaning are still required before fitup and
welding to avoid weld defects.
Butt welds may be made with an open groove joint
or with a backing ring that is left in place. When an
open groove joint is used, the root pass is typically
made with the GTAW process because of the inherent
better control of the inside weld surface contour. The
groove is completed using the SMAW process.
When the weld joint contains a backing ring, the
entire weld is usually made with the SMAW process.
This method is normally used for the original erection
of riser and downcomer piping. Rings are never used
for furnace walls. However, they may be used for other
pressure boundary tube welds depending upon engineering or customer requirements, and, if permitted,
is the preferred method of fabrication.
39-14
Qualification of welding procedures
and personnel
Welding qualification requirements are contained in
the ASME Code, Section IX. The ASME fabrication
Codes and the National Board Inspection Code (NBIC),
published by the National Board of Boiler and Pressure
Vessel Inspectors, references this Code for qualification
of repairs and alterations to in-service boilers.
A welding procedure qualification test verifies that
required mechanical properties are obtained when
designated materials are welded by following a specific technique. BWCC has established many procedural qualification records based upon the ASME
Code. These procedure qualifications support hundreds of welding procedure specifications.
A welder qualification test is required to verify that
an individual has the skill to deposit sound weld metal
in a given position while following an established
welding procedure. Welders are qualified in accordance
with ASME IX standards either at the job site or at simultaneous testing sites by participating organizations.
Thermal treatment
Preheat Preheating the weld metal is the most effective way of preventing cracks in low alloy steel
welds because it reduces the cooling rate of the weld
and base metal. The required minimum preheat temperature is specified in the field weld schedule and on
BWCC’s welding procedure specifications (WPS). Preheating methods include the use of electric-resistance
blankets and oxy-gas or oxy-fuel torches. Special temperature-indicating crayons are used to assure that
the proper preheat temperature has been attained.
(See also Chapter 38.)
Post weld heat treatment Requirements for post weld
stress relief are also specified in the field weld schedule. Electric resistance heaters are commonly used for
field post weld heat. These heaters offer the advantages
of ease of application and precise temperature control.
Codes, inspections and examinations
The ASME Code requires a valid ASME Certification of Authorization to install power boilers. To obtain an ASME Certificate of Authorization, an organization is required to maintain a Quality Control
System that addresses the Code requirements. A review is performed by ASME to evaluate the Quality
Control System and verify implementation. Once issued, the Certificate of Authorization is renewed triannually by review. A boiler installed in accordance
Steam 41 / Construction
The Babcock & Wilcox Company
with the ASME Code must be inspected by an authorized inspector at various stages of assembly to assure
that all Code requirements are met.
Section I of the ASME Code contains requirements
for the installation of power boilers. ASME B31.1 contains requirements for the installation of boiler and
non-boiler external piping. The state or jurisdictional
authority maintains rules and regulations that govern the installation of boilers and establishes the applicable governing Codes. Section I of the ASME Code
has been adopted by law in most states or jurisdictions.
Whereas ASME governs new construction, the NBIC
governs repairs and alterations to boilers and other
pressure-retaining items. The NBIC requires the repairs
and/or alterations to comply, to the extent possible, with
the original Code of construction. As with the ASME
Code, the NBIC is mandatory only when adopted by a
state or other jurisdictional authority.
Section I of the ASME Code specifies the nondestructive examination (NDE) requirements for new
construction of power boilers. ASME B31.1 specifies
the NDE requirements for boiler and non-boiler external piping. NDE requirements for repairs and alterations are specified in the NBIC. The type and extent of NDE must be considered during the proposal,
planning and scheduling processes. For all construction, the applicable regulations and any additional
NDE requirements exceeding the Code should clearly
be specified in contract documents. The nondestructive technologies are discussed in more depth in Chapters 38 and 45.
Construction of environmental equipment
Regulatory requirements associated with the Clean
Air Act Amendments of 1990 caused many fossil fuelfired electric generating plants in the United States
(U.S.) to install, or plan for the installation of, emission reduction equipment. Many stations installed
sulfur dioxide (SO2) scrubbers in the early 1990s which
were then followed in the early 2000s by the installation of selective catalytic reduction (SCR) systems for
nitrogen oxides (NOx) removal.
While erection of environmental equipment is significantly different from boiler erection, many of the
same principles and attributes of boiler erection apply. A modularized approach generally pays signifi-
Fig. 22 Welded handhole fitting for higher pressure boilers.
Steam 41 / Construction
cant dividends over stick-built construction at the job
site. The project benefits in both labor savings and in
the potential for a reduced site completion schedule
when high-cost field labor is replaced with lower-cost
shop labor.
The construction principles utilized for environmental equipment are the same. However, the method of
construction differs significantly. SCR projects predominantly consist of structural steel and fabricated plate,
while FGD system projects consist of fabricated plate,
structural steel, process equipment and piping. There is
little in the way of operating equipment with the exception of dampers, sonic horns or sootblowers, ammonia
vaporization equipment, and some piping and instrumentation. In these installations, the chemical process
required to support the operation utilizes additional
equipment to handle the lime or limestone reagents and
gypsum removal and drying.
Most SCR projects are designed with the reactor
and flues bottom-supported off structural steel. The
primary component of FGD systems is the absorber
tower which is independently bottom-supported on a
separate foundation. For SCR systems, close coordination is required between steel erection activities and
the installation of the interconnecting flues and reactor. Complicating matters on a retrofit project is the
space available for the SCR. The process temperature
for most SCR systems requires the boiler flue gas to
be taken from an area immediately downstream of the
economizer, and before the air heater inlet. On large
boilers, this tie-in point can be more than one hundred feet (tens of meters) above ground level. Also,
since a reactor can contain nearly a million pounds
(450,000 kg) of catalyst at a significant elevation
above grade, concerns for overturn and uplift forces
may require a complex foundation design.
At many sites constructed decades ago, little consideration was given to future expansion and therefore, current space limitations are a serious concern.
Many projects are faced with a significant rerouting
of the boiler exit gas to a point where space is available for either an SCR or FGD system. The flue gas must
then be routed back to continue its path through the air
heater for SCR applications or to the stack for FGD systems. Each project poses a unique set of circumstances.
Sequencing and modularization
Early in the project, specific information about the
weight of ductwork sections and equipment must be
estimated. Many times the module boundaries are easily identified, due to equipment terminal points or expansion joint locations. Other times, sound judgments
must be made, based on experience. The erector is the
prime contributor to determining splice locations that
are best from a variety of standpoints, including access, crane capacity and geometry.
The resulting erection sequence can then be used
in establishing schedule priorities for detail design,
material procurement and fabrication. To allow maximum flexibility for installation, schedule priorities
should be developed in accordance with erection plans.
Receiving materials far in advance of the time required at the job, or in a sequence that does not sup39-15
The Babcock & Wilcox Company
port planned erection, results in increased handling
costs. Without the proper materials, the constructor is
forced to work on activities that deviate from the intended plan, increasing overall project cost.
The erector should complete a constructability review prior to the issuance of key design outputs. This
review often uncovers missing or incorrect information. Early identification of potential problems can alleviate costly field rework or production delays due to
additional engineering evaluations and the resulting
drawing revisions.
Once modules are identified and an erection sequence is established, the project team interacts with
plate fabricators for delivery options. A modular construction approach provides the project team with the
opportunity to review and approve the manufacturer’s
plan for component fabrication. This process may result in on-site productivity improvements as the constructor advises on alternative shipping configurations
and rigging requirements, and gains valuable information about the material to be received, thus helping to identify the extent of preparatory work that will
be required on site prior to erection.
Fig. 23 is a typical arrangement for an SCR retrofit project. Identified in the figure are module boundaries utilized for design, procurement, planning and
erection activities. The individual modules are installed
in a defined sequence to maximize efficiency and minimize erection time. This sequence, which usually starts
from the lowest to the highest point, builds from the
reactor back to the boiler and involves the erection of
sufficient steel to set the outlet or bypass flues. Once
the initial flues are set, steel progresses again to the
point where additional flue sections can be set and the
reactor built. Ideally, horizontal runs of ductwork are
bottom-supported, and require that the support steel
is first installed beneath the duct. Structural engineers
should be aware of the construction/erection plan so
that the steel erection sequence and requirements
support the equipment’s erection sequence. These activities require close coordination with the design engineers to ensure that the uncompleted steel structure
is adequate to support the initial duct sections as they
are installed. Cover-plating the existing steel is frequently required prior to imposing additional loads
from the new structure and can be a time-consuming
and costly effort. If present, lead-based paint must be
abated from existing steel prior to any welding or
grinding operations. The use of bolt interface connections rather than welded connections could minimize
lead abatement requirements. Close coordination with
plant operations is also required as a result of the
numerous interferences with plant utilities supported
from the columns or beams being modified.
Tie-in to the unit is the last activity phase, accomplished during a planned unit outage. Depending
upon planned unit outages, however, there is flexibility in the erection sequence. Many times a tie-in outage occurs before construction of the SCR is initiated,
especially if the plant has a major outage scheduled
well in advance of the SCR completion. In these instances, a gas bypass flue is installed which allows the
construction of the SCR during unit operation. This re-
39-16
quires dampers and blanking plates to allow the balance of construction to take place subsequent to the tiein. The blanking plates allow safe entry to the flues
during plant operation. However, this approach generally impacts the erection sequence and potentially impacts the total construction cost. A second, shorter outage is then required to make the final tie-in of fluework.
Construction safety
A comprehensive safety program must be implemented at each construction site. The objective is to promote an awareness of safety among personnel and create a safe working environment to prevent injuries.
BWCC has developed a Safety Program Manual in support of a construction site safety program. The manual
has been specifically designed for construction and includes the requirements of 29 CFR 1926 Safety and
Health Regulations for Construction by the Occupational Safety and Health Administration (OSHA). The
contents of the Safety Program Manual include, but are
not limited to, the safety procedures outlined in Table 2.
Internal cleanliness of pressure parts
Manufacturing and shipping
Many problems can develop during operations because of dirt or other foreign matter in the circulating
system of a boiler. During the fabrication of drums,
tubes, headers, pipes or other pressure parts, precautionary measures must be taken to assure internal
cleanliness. For boilers that use welded stub construction, the ends of all tubes and pipes, as well as the
stubs in the drums and headers, are closed with metal
caps and sealed with plastic tape. This usually makes
it unnecessary to clean these components in the field.
Inevitably there are a few closure caps displaced during shipping, unloading and handling. In such instances, the construction crew must examine the components involved, perform any necessary cleaning,
and replace the caps as soon as possible.
Field assembly
Boiler pressure parts should be searched before
handhole and manhole closure fittings are installed.
Reasonably straight tubes between headers or drums
may be probed by passing a ball through them. Bent
tubes that will not clear themselves of foreign material
by gravity may be probed by blowing a tight-fitting
sponge through them. The butt welds in small diameter tubes are examined radiographically for misalignment or obstructions that may cause flow restrictions.
Headers are checked with a light and mirror immediately before the end handhole fittings are installed.
No foreign material may enter the pressure part system during assembly. Closures are left in place until removal for welding or positioning equipment. If shop-installed closures are removed to permit installation, temporary closures are placed over the openings to prevent
debris from entering the equipment. Prior to flushing or
final closing of equipment, a visual inspection is made
and foreign objects are removed from the equipment.
Steam 41 / Construction
The Babcock & Wilcox Company
Expansion Joint
Flue installed before outage
Catalyst
Block
Flue installed during outage
Required temporary support
Tier 2 steel
Catalyst
Block
Sonic
Horn
Tier 3 steel
Tier 4 steel
Catalyst
Block
Expansion
Joint
Catalyst
Block
Damper
Expansion Joint
Damper
Future
Catalyst
Block
Sonic
Horn
Damper
Expansion
Joint
Economizer
Expansion
Joint
Expansion
Joint
Expansion
Joint
Damper
Expansion
Joint
Air Heater
Fig. 23 Typical arrangement for an SCR retrofit project.
Removal of tube sections during repair or alteration
must be performed in a manner that prevents foreign
material from entering the tubes during the cutting
operation. Ends of existing tubes are plugged before
machining new weld preparations.
Post-construction testing
Hydrostatic testing
When all pressure part connections have been completed, the steam generating unit is tested at a pressure specified by the applicable code; this is usually
1.5 times the maximum allowable working pressure
(MAWP). Before the test is applied, a final inspection
is made of all welding. External connections, including
all fittings, are completed within Code requirements.
Connections for flange safety valves are usually blanked.
Welded safety valves are closed with an internal plug.
Hydrostatic testing water must be clean and warm
enough to bring pressure part metal temperatures to
Steam 41 / Construction
at least 70F (21C). Nondrainable superheaters and
reheaters are filled with demineralized water or condensate, if available. As a boiler is being filled, it is
vented at every available connection to allow water
to reach every circuit.
Hydrostatic pressure is applied after the boiler is
filled. If a boiler feed pump or other high capacity
pump is used, precautions must be taken to control the
pressure at all times. While water is being pumped into
the boiler, continuous inspection is made to detect any
leakage. During hydrostatic testing, safety precautions must be observed, and nonessential personnel
must be kept away from the test area.
The test pressure must be held long enough to allow minute leaks to be detected. Following this holding period, pressure is reduced to MAWP and retained
for an inspection period. During final inspection, every area of the pressure system is viewed for leakage
and repaired if necessary.
After inspection, the unit is drained and all
nondrainable parts are protected from freezing, if nec-
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The Babcock & Wilcox Company
essary. The refractory, insulation and casing work are
then completed in areas left open for inspection.
Air testing
Gas-bearing components, such as the boiler, flues
and ducts are field-tested for leakage and tightness.
All boilers are tested by one of two procedures. Boilers designed to operate with a positive pressure,
wherein furnace leaks would emit gases from the
boiler setting, are tested following a pressure-fired
procedure. Units designed for suction or balanced
draft are tested following the balanced draft procedure.
The pressure-fired air test procedure is a pressure
drop test. A test is considered satisfactory when the
pressure is raised to 15 in. wg (3.74 kPa) maximum
and does not drop more than 5 in. wg (1.25 kPa) in
ten minutes. If pressure can not be maintained, leaks
are sought and corrected and the test is rerun until
satisfactory tightness is achieved. On large units, it is
common to install temporary bulkheads in flue and
duct runs for individual tests.
The balanced draft testing procedure is commonly
performed by pressurizing the system with the forced
draft fan while throttling the dampers at the downstream
test terminal. With the system pressurized, all field welds
are inspected by sight and sound to detect leaks.
Assembly of nonpressure parts
and auxiliaries
While pressure parts are being assembled and
tested, work is in progress on nonpressure parts and
auxiliary equipment. These components, including air
heaters, fuel equipment, fans, duct work, refractory,
insulation and casing, require a large portion of the
construction labor. They must be scheduled with consideration for items that must be assembled in a prescribed sequence. For example, air heaters are finished prior to erection of flues and ducts. Pulverizers
are placed early enough for piping, drives and other
auxiliaries to be completed.
Table 2
Selected BWCC Safety Procedures
for Construction
Posting requirements
Medical facilities and
treatment
Safety training
Hazard communication
Accident and personal
injury reporting
Personal protective
equipment
Job safety analysis
Housekeeping
Operator pre-qualification
Lifting equipment
Hand tools
Electrical
Scaffolds and ladders
39-18
Welding, thermal cutting and
compressed gas cylinders
Fire protection
Steel erection
Confined space entry
Lockout/tagout
Excavation and trenching
Radiation protection
Documentation and recordkeeping
Project site safety inspections
Subcontractor safety
Material safety data sheets
Fall protection
Floor, wall openings and
stairways
Refractory materials
The furnace and other wall areas of modern fossil
fuel boilers are made almost entirely of water-cooled
tubes. The increased use of membrane walls has reduced the use of refractory in these areas. However,
castable and plastic refractories may still be used to
seal flat studded areas, wall penetrations, and door
and wall box seals. (See Chapter 23.)
Other than membrane wall construction, when
tubes are tangent or flat studded, several types of plastic refractory materials are applied to the outside of
tubes for insulation or sealing purposes. When an
inner casing is to be applied directly against the tubes,
the refractory serves principally as an inert filler
material for the lanes between tubes. It has a binder
that cements it to the tubes and it is troweled flush
with the surface of the wall.
Smaller boilers may have furnaces constructed of
tubes on wide-spaced centers backed with a layer of
brick or tile. Brickwork of this type is supported by the
pressure parts and held in place by studs. The brick
is insulated and made air-tight by various combinations of plastic refractory, plastic or block insulation
and casing.
High quality workmanship is mandatory in the application of refractory material. Construction details
are clearly outlined on drawings and instructions that
also designate the materials to be used. These materials must be applied to correct contour and thickness
without voids or excessive cracking. Skilled mechanics and close supervision are essential.
Casing
In general, inner or outer boiler casing is used in
areas that are not membraned. Outer casing is applied
outside of insulating materials and has, for the most
part, been replaced by sheet metal lagging. Inner casing is positioned inside of insulation and may be pressure or nonpressure casing.
The primary purpose of pressure inner casing is to
prevent air and gas leakage from a steam generating
unit. The inner casing is seal welded to prevent leakage from the boiler setting and also serves as a base
for the application of insulation and lagging.
In most cases, modern boiler casings feature welded
construction. For pressure casing, it is essential that the
strength of the weld equal the strength of the plate, that
the welds be free of cracks and pinholes, and that they
present a good appearance. For pressure casing, tightness is checked by a pressure drop air test. Nonpressure
casings are given a thorough visual inspection.
Insulation
Selecting the type and thickness of insulation applied
to boiler surfaces is an essential part of the design work.
Specifications are written and drawings are made to indicate the applied materials and the method of attachment.
Typical standards specify insulation blocks or insulation blankets. Some plastic insulation is used for filling voids. The thickness of the insulation for all surfaces is selected to give a specific surface temperature,
e.g., 130F (54C) with 80F (27C) ambient air temperature and 50 ft/s (15.2 m/s) surface velocity. The prime
Steam 41 / Construction
The Babcock & Wilcox Company
requisites for installing boiler insulation are that the
material be tight, free of voids, well anchored, and reinforced where necessary.
Ductwork with heavy stiffeners at frequent intervals presents a difficult insulating job. With the stiffeners outside the flue and duct plate, the insulation
thickness is often increased over minimum requirements to assure adequate coverage of the stiffeners.
If the stiffeners are placed in a manner where standard insulation coverage is too costly, the insulation
may be placed over the stiffeners. As an alternative,
inner lagging may be applied over the stiffeners and
the minimum required insulation is placed over the
lagging. When insulation is applied at an appreciable
distance from a hot surface with a long vertical run,
air may circulate in the void. This increases heat
transfer into the insulation, which is undesirable.
Where vertical runs exceed 10 ft (3 m), horizontal
barriers are installed between the duct and/or tube
wall and insulation.
Sheet metal lagging
Outdoor boilers require the use of a durable waterproof lagging. A light gauge metal lagging (galvanized
steel or aluminum) or outer casing is used on walls,
flues, ducts, air heaters, vestibules, windboxes, downcomers, steam/water lines and other exposed components. The metal covering does not seal against air
infiltration but serves as a barrier to protect the insulation against water and physical damage. The cost
is reasonable and it is extensively used in both indoor
and outdoor installations.
Pre-operational inspection
A final inspection is made after erection work is completed and the unit is ready for operation. This is the
combined responsibility of the erection, service and
operating organizations.
Externally, all components of the unit are checked
for expansion clearances. Obscure corners are examined for any construction blocking or bracing that
might have been left in place. Points reviewed for expansion clearances are platforms and walkways constructed adjacent to external members that move with
the unit.
Of special importance in fossil fuel units is the removal of combustible materials that may present an
explosion hazard during initial firing. Internal cavities are checked to ensure that all debris has been removed. Tubes are given a final inspection for alignment, particularly those that might interfere with
sootblower operations. Movable connections between
tubes are examined for expansion clearances and to
see that all attachments are properly anchored.
On most units, construction schedules do not permit completion of insulation before the unit is fired. It
is important that this work be completed in areas that
will be inaccessible or cause a safety hazard when the
unit is in operation.
References
1. Constructability: A Primer, Publication 3-1, the Construction Industry Institute, Constructability Task Force,
Bureau of Engineering Research, The University of Texas
at Austin, Austin, Texas, Third Printing, April, 1990.
Steam 41 / Construction
2. Shapiro, H.I., Shapiro, J.P., and Shapiro, L.K., Ed.,
Cranes & Derricks, McGraw-Hill Education, November,
1980.
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The Babcock & Wilcox Company
Central station utility steam generating unit under construction.
39-20
Steam 41 / Construction
The Babcock & Wilcox Company
Section VI
Operations
With proper design, manufacture and construction, modern steam generating systems are capable of operating efficiently for long periods of service.
However, successful operation requires adherence to basic operating principles.
These principles begin with the careful monitoring of operating conditions so
that a system functions within design limits. Chapter 40 describes the instrumentation for monitoring pressures, temperatures and flows – the key process
parameters. (Specialized instrumentation for environmental equipment is
covered in Section IV, Chapter 36.) These operating parameters then serve as
the inputs to the control system. The fundamentals of control theory and modern integrated control systems are reviewed in Chapter 41. These systems have
advanced rapidly during the past few decades to provide greater operator knowledge and flexibility to optimize plant performance.
Successful long-term operation of steam producing systems requires careful attention to water treatment and water chemistry control. Chapter 42 provides a discussion of water treatment practices from startup through operation and chemical cleaning. Drum and once-through boilers have different requirements, and each boiler requires individual consideration.
General operating principles and guidelines outlined in Chapter 43 conclude
this section. Each steam generating system is unique and requires specific
operating guides. However, a number of general principles covering initial
operations serve as a basis.
Steam 41
The Babcock & Wilcox Company
Chapter 40
Pressure, Temperature, Quality
and Flow Measurement
Instruments for measuring pressure, temperature,
fluid flow, and the quality and purity of steam are
essential in the operation of a power plant. The measurements obtained permit safe, economical and reliable operation of the steam generating equipment.
Instrumentation may range from a simple indicating
device to a complex automatic measuring device. The
fundamental purpose of the instrument is to convert
some physical property of the material being measured
into useful information. The methods used to obtain
the measurement depend on available technology,
economics, and the purpose for which the information
is being obtained.
Test instrumentation, often portable, may be used
to determine flow, pressures, and temperatures required to satisfy the user and the boiler equipment
supplier that the design operating conditions have
been achieved. Requirements for these instruments
are summarized in the American Society of Mechanical Engineers (ASME) Performance Test Codes. Many
test instruments require skilled technical operators,
careful handling, and frequent calibration. Some instruments and measurement methods may not be
suitable for long-term continuous operation because
of a harsh environment, material limitations, or excessive cost. Instruments used for continuous measurement may require compromises in accuracy for
long-term, dependable, reliable operation.
Fig. 1 Bourdon gauge.
Manometers are considered an accurate means of
pressure or pressure differential measurement. These
instruments, containing a wide variety of fluids depending on the pressure, are capable of high accuracy
with careful use. The fluids used vary from those
lighter than water for low pressures to mercury for
relatively high pressures. Fig. 2 illustrates an inclined
manometer used to measure low pressure differentials
Pressure measurement
The pressure gauge is probably the earliest instrument used in boiler operation. Today, with complex
control systems in operation and more than one hundred thirty years after the first water tube safety
boiler, a pressure gauge is still used to determine steam
drum pressure. The Bourdon tube pressure gauge is
shown in Fig. 1. Although improvements have been
made in construction and accuracy, its basic principle
of operation remains unchanged. A closed end oval
tube in a semicircular shape straightens with internal pressure. The movement of the closed end is converted to an indication (needle position).
Pressure measuring instruments take various forms,
depending on the magnitude of the pressure, the accuracy desired and the application.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Fig. 2 Inclined differential manometer (courtesy of Dwyer Instruments, Inc.).
40-1
The Babcock & Wilcox Company
at low static pressure. Differential diaphragm gauges
with a magnetic linkage are also used for low pressure measurement. Fig. 3 shows a high pressure mercury manometer. For greater precision in measuring
small pressure differentials, such as the measurement
of flow orifice differentials, hook gauges or
micromanometers may be used.
Bourdon tube pressure gauges are available for
measuring a wide range of static pressures in varying degrees of precision and accuracy. Pressure gauges
used as operating guides need not be of high precision and normally have scale subdivisions of about 1%
of the full scale range. For certain tests, such as hydrostatic testing of pressure parts and boiler efficiency,
more precision is required. Gauges with 0.1% full scale
subdivisions are used. For performance calculations,
high precision temperature and pressure measurements are required to accurately determine steam and
water enthalpies. Dead weight gauges or calibrated
pressure transmitters are preferable to Bourdon
gauges for high precision pressure measurement.
Diaphragm type gauges are used for measuring
differential pressures. A slack diaphragm pressure
gauge can be used to measure small differentials
where total pressure does not exceed about 1.0 psig
(6.9 kPa). For high static pressures, opposed bellows
gauges (Fig. 4) read a wide range of differential pressures. They are suitable for measuring differential
pressure across boiler circuits and can be used to measure differentials from 2 to 100 psi (0.01 to 0.69 MPa)
at static pressures up to 6000 psi (41.37 MPa).
Incorporated into many pressure measurement
devices is the capability of producing an output signal proportional to the measurement. The output signal may be transmitted to a central measurement or
control system. Pneumatic transmitted signals are
Fig. 3 High pressure mercury manometer (courtesy of Meriam
Process Technologies).
Fig. 4 Opposed bellows gauge (courtesy of ITT Barton, a unit of ITT Industries, Inc.).
40-2
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
used in control systems, but the more common designs
use electrical circuitry to sense the changing position
of basic mechanical motion and to produce an electrical output signal to be transmitted. These are readily
adaptable to computer based systems. Some transducers use a piezoelectric crystal which changes electrical resistance as the element is deformed under pressure. Other pressure transmitter designs use a diaphragm with strain gauges attached; minor changes
in diaphragm strain are transferred to the strain
gauges, which change resistance. Electrical circuits
recognize the resistance change in the crystal or strain
gauges and produce an indication of pressure. Advanced applications have used an optic glass fiber
embedded in a metal diaphragm, with pressure measurement determined as a change in the light beam
traversing the fiber. Pressure transducers incorporating electrical components have the advantage of fewer
mechanical parts for improved durability. However,
this may restrict the installation location due to temperature limitations of the electrical components. Instruments configured to generate electric signals have
been adapted to incorporate computing capability to
assist in calibration. Pressure transmitters and transducers have been readily adapted for power plant
computer data acquisition and control systems.
Instrument corrections
In recording and reporting pressure readings, corrections may be necessary for water leg and for conversion to absolute pressure by adding atmospheric
pressure. Effective water leg is the added pressure
imposed on the gauge by the leg of water standing
above the gauge. Fig. 5 illustrates a water leg correction to a pressure gauge reading. The density of the
water in the leg may change with ambient temperature and, for precise measurement, the water leg temperature should be monitored. On some gauges it may
be possible to zero the gauge at zero operating pressure with the water leg completely filled to compensate for the water leg static head. Care must be taken
in performing water leg adjustments as this may affect the instrument calibration over the operating
range. Differential pressure measurements require a
water leg correction for both sides of the measuring
instrument. For some liquid level devices, the differential pressure measurements from two water legs of
different elevations are used to provide the indication
of liquid level. Differential pressure measurements
across orifices, nozzles or pitot tubes to measure flow
are described below.
der certain circumstances a through the wall pressure
connection may not be representative. It may be necessary to use a probe incorporating a tip configuration that minimizes the effects of the flowing fluid to
obtain a representative static pressure measurement.
Connecting lines to instruments should be as short
and direct as possible and must be leak-free. For differential pressure readings, it is preferable to use a differential pressure measuring device rather than to calculate the difference between the readings on two instruments. Particular attention should be paid to the placement of the instrument, the potential for condensation
in the impulse lines, and the accumulation of debris or
non-condensable gases in the completed installation.
Temperature measurement
Today, the Fahrenheit and Celsius (formerly centigrade) scales are the most common and firmly established temperature scales.
The Fahrenheit scale is fixed at the freezing point
(32F) and the boiling point (212F) of pure water at
atmospheric pressure, with 180 equal degrees between
the two points. The centigrade scale was originally based
on the same freezing (0C) and boiling (100C) points of
water at standard atmospheric pressure, using the convenient 100 degree interval of the decimal system.
In 1960, the General Conference of Weights and
Measures changed the defining fixed point from the
freezing point to the triple point (0.0C) of water. The
triple point is the condition under which the three
phases of matter (solid, liquid and vapor) coexist in
equilibrium. This point is more easily and accurately
reproduced than the freezing point. At standard atmospheric pressure the interval between the triple
point for water and steam on the centigrade scale
became 99.99C instead of 100C.
In 1990, temperature standards were further refined by the International Temperature Scale 1990
Location of pressure measurement
connections
The criteria for selecting a connection location to the
pressure source for the measuring device are the same
regardless of the magnitude of the pressure, the type
of measuring device or the fluid being measured. Pressure connections, or taps, in piping, flues or ducts
should be located to avoid impacts or eddies; this assures an accurate static pressure measurement. UnSteam 41 / Pressure, Temperature, Quality and Flow Measurement
Fig. 5 Application of water leg correction to pressure gauge reading
(Correction ∆P = gρL/gc).
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The Babcock & Wilcox Company
(ITS-90). These changes, however small, reflect the
continued review of temperature measurement. As
measured by the current standard, water at standard
conditions boils at 211.953F (99.974C).
In thermometer calibrations, the fusion and vaporization of various pure substances have been carefully
determined and are known as fixed points. Two additional scales in scientific work use the absolute zero of
temperature, i.e., –273.16C or –459.69R. The absolute
scale using Celsius degrees as the temperature interval
is called the Kelvin (K) scale; the absolute scale using
Fahrenheit degrees is called the Rankine (R) scale.
Methods of measuring temperature
Heat affected properties of substances, such as thermal expansion, radiation and electrical effects, are
incorporated into commercial temperature measuring
instruments. These instruments vary in their precision depending on the property measured, the substance used and the design of the instrument. The care
taken in selecting the correct instrument largely determines the accuracy of the results. It is the
engineer’s responsibility to make certain that the application is correct and that the results are not affected
by extraneous factors.
Changes of state
Fusion For a pure chemical element or compound
such as mercury or water, fusion, or change of state
from solid to liquid, occurs at a fixed temperature. The
melting points of these materials are suitable fixed
reference points for temperature scales.
The fusion of pyrometric cones is widely used in the
ceramic industry as a method of measuring high temperatures in refractory heating furnaces. These cones,
small pyramids about 2 in. (50.8 mm) high, are made
of oxide and glass mixtures that soften and melt at
established temperatures. The pyrometric cone is suitable for temperatures ranging from 1100 to 3600F
(593 to 1982C). Its use in the power industry is generally limited to the laboratory. An adaptation of this
method of temperature determination is used when
observing ash and slag accumulations soften and flow
in a coal-fired furnace or superheater.
Fusion pyrometers are also made in the form of
crayons, paint and pellets. The crayons and paint,
applied to a metal surface, produce a flat-finish mark.
A change in the finish from flat to glossy indicates that
the surface temperature has reached or exceeded a
selected value. The pellets melt at specified temperatures when in contact with a hot surface and may be
seen more easily than crayon marks.
Vaporization The vapor pressure of a liquid depends
on its temperature. When the liquid is heated to its
boiling temperature, the vapor pressure is equal to the
total pressure above the liquid surface. The boiling
points of various pure chemical elements or compounds
at standard atmospheric pressure [29.92 in. Hg (101.33
kPa)] can be used as thermometric fixed points. If the
liquid and vapor are confined, the increase in vapor
pressure may be used to measure temperature using a
calibrated pressure gauge. (See Fig. 6.)
40-4
Expansion properties
Most substances expand when heated and, for
many materials, the amount of expansion is almost
directly proportional to the change in temperature.
This effect is the basis of various thermometer types
using gases, liquids or solids.
Gases The expansion of gases follows the relationship, in English units:
PvM = RT
(1)
where
P
vM
R
T
=
=
=
=
absolute pressure, lb/ft2
volume, ft3/mole of gas
universal gas constant, 1545 ft lb/mole R
absolute temperature, R = F + 460
At high pressures or near the condensation point, gases
deviate considerably from this relationship. Under
other conditions, however, the deviation is small.
Two types of gas thermometers are based on this relationship. In one, a constant gas volume is maintained
and pressure changes are used to measure changes in
temperature. Very accurate instruments of this type
have been developed for laboratory work. The constant
volume type thermometer is widely used commercially.
Nitrogen is commonly used for the gas-filled thermometer in industrial applications. It is suitable for a
temperature range of –200 to 1000F (–129 to 538C).
The construction is similar to the vapor pressure thermometer with nitrogen gas replacing the liquid and
vapor. Expansion of the heated nitrogen in the bulb
increases the pressure in the system and actuates a
temperature indicator.
Liquids Liquid expansion properties may be incorporated into a thermometer by using a bulb and capillary to confine the liquid. In this thermometer, the
bulb and capillary tube are completely filled with liquid and a calibrated pressure gauge is used to measure temperature. Mercury has been used for a temperature range of –40 to 1000F (–40 to 538C). Instrument readings can be in error if the capillary tubing
is subjected to temperature changes.
The liquid-in-glass thermometer is a simple, direct
Fig. 6 Schematic assembly of vapor pressure thermometer.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
reading, portable instrument. Low precision thermometers are inexpensive and instruments of moderate
precision are available for laboratory use. This thermometer features a reservoir of liquid in a glass bulb
that is connected directly to a glass capillary tube with
graduated markings. Mercury, the most common liquid, is satisfactory from –40F (–40C), just above its freezing point, to about 600F (316C) if the capillary space
above the mercury is evacuated. The upper temperature
limit may be 900F (482C) or higher if this space is filled
with pressurized nitrogen or carbon dioxide (CO2).
The use of unprotected glass thermometers is restricted to laboratory or research applications. For
more severe service there are various designs of industrial thermometers with the bulb and stem protected by a metal casing and usually arranged in a
thermometer well. Response to rapid temperature
changes is slower than with the unprotected laboratory type instrument.
Solids The expansion of solids when heated is recognized in thermometers using a bimetallic strip. Flat
ribbons of two metals with different coefficients of
thermal expansion are joined face to face by riveting
or welding to form a bimetallic strip. When the strip
is heated, the expansion is greater for one metal than
for the other. A flat strip bends, or changes curvature
if it was initially in a spiral form. Bimetallic strips are
seldom used in power plant thermometers but are
widely used in inexpensive thermometers, household
thermostats and other temperature control and regulating equipment. They are particularly useful for
automatic temperature compensation in other instrument mechanisms.
Radiation properties
All solid bodies emit radiation. The amount is very
small at low temperatures and larger at high temperatures. The quantity of radiation may be calculated by
the Stefan-Boltzman formula:
(2)
q/S = σ ε T4
where
q
S
σ
ε
=
=
=
=
radiant energy per unit time, Btu/h
surface area, ft2
Stefan-Boltzman constant, 1.71× 10–9 Btu/h ft2 R4
emissivity of the surface, dimensionless (usually between 0.80 and 0.95 for boiler materials)
T = absolute temperature, R = F + 460
At low temperatures the radiation is primarily in
the invisible infrared range. As the temperature rises,
an increasing proportion of the radiation is in shorter
wavelengths, becoming visible as a dull red glow at
about 1000F (538C) and passing through yellow toward white at higher temperatures. The temperature
of hot metals [above 1000F (538C)] can be estimated by
color. For iron or steel, the approximate color scale is:
dark red
medium cherry red
orange
yellow
white
1000F
1250F
1650F
1850F
2200F
(538C)
(677C)
(899C)
(1010C)
(1204C)
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Within the visible range, two types of temperature
measuring instruments, the optical pyrometer and the
radiation pyrometer, sense the emitted radiation to
indicate temperature.
Optical pyrometers The optical pyrometer visually
compares the brightness of an object to a reference
source of radiation. The typical internal calibration
source is an electrically heated tungsten filament. A
red filter may also be used to restrict this visual comparison to a particular wavelength. This instrument
measures the temperature of surfaces with an emissivity of 1.0, which is equivalent to that of a blackbody. By definition, a blackbody absorbs all radiation
incident upon it, reflecting and transmitting none.
When calibrated and used properly, the pyrometer
yields excellent results above 1500F (816C). Temperature measurement of the interior surface of a uniformly heated enclosure, such as a muffle furnace, is
a typical application. When used to measure the temperature of an object outside a furnace, the optical pyrometer always reads low. The error is small [20F
(11C)] for high emissivity bodies, such as steel ingots,
and large [200 to 300F (111 to 167C)] for unoxidized
liquid steel or iron surfaces.
The optical pyrometer is widely used for measuring
objects in furnaces at steel mills and iron foundries. It
is not applicable for measuring gas temperature because clean gases do not radiate in the visible range.
Radiation pyrometers In one type of radiation pyrometer, all radiation from the hot body, regardless of
wavelength, is absorbed by the instrument. The heat
absorption is measured by the temperature rise of a
delicate thermocouple (TC) within the instrument. The
thermocouple is calibrated to indicate the temperature
of the hot surface at which the pyrometer is sighted,
on the assumption that the surface emissivity equals
1.0. The hot surface must fill the instrument’s entire
field of view.
This type of radiation pyrometer has high sensitivity and precision over a wide range of temperatures.
The instrument gives good results above 1000F (538C)
when used to measure temperatures of high emissivity bodies, such as the interiors of uniformly heated
enclosures. Because operation of the instrument does
not require visual comparison, radiation pyrometers
may be used as remotely operated temperature indicators. Errors in temperature measurements of hot
bodies with emissivities of less than 1.0, especially if
they are in the open, are extremely large.
Radiation pyrometers sensitive to selective wavelengths in the infrared band give good results when
measuring temperatures of bodies or flames. One design uses a system of lenses, a lead sulfide cell and
electronic circuitry to produce a measurement.
An advancement of the single band pyrometer is
the two color pyrometer, which measures the intensities of two selected wave bands of the visible spectrum
emitted by a heated object. This unit computes the total
of the emitted energies and converts it into a temperature indication. As with the optical pyrometer, indications
depend on sighting visible rays and therefore its minimum temperature measurement is 1000F (538C).
40-5
The Babcock & Wilcox Company
Infrared radiation is produced by all matter at temperatures above absolute zero and detectors sensitive
to the infrared band may be used to measure objects
at low temperatures where the radiation is not in the
visible band. The development of metal-silicide detectors permits sensitivities in the 1 to 5 µm band. Metalsilicides are formed by the reaction of metals, such as
platinum or palladium, with p-type silicon. When
coupled with electronic circuitry for producing an image, the detectors are sophisticated devices for low
temperature measurement.1
Infrared thermal imaging equipment is available
for quantitative measurement or qualitative imaging.
The instruments for making quantitative measurements and providing target temperature indications
are called thermographic imagers or imaging radiometers. Qualitative imaging instruments are called thermal viewers. These viewers are mechanically or electronically scanned; the electronically scanned units are
called pyroelectric vidicons or pyrovidicons.2
Infrared temperature measurement is applicable to
surveys of surfaces, such as boiler casings and insulated steam pipes, for locating temperature variations.
These instruments may also assist in determining electrical component temperatures in operating circuits.
Radiation pyrometers are not capable of determining
gas temperatures.
Optical properties
Optical fibers have been used in fixed (end) and
distributed (average temperature along length) temperature measurement. Development is continuing in
the application of this method to temperatures above
450F (232C).3
Electrical properties
Two classes of widely used temperature measuring
instruments, the thermocouple and the electrical resistance thermometer, are based on the relation of
temperature to the electrical properties of metals.
Because of its versatility, convenience and durability, the thermocouple is of particular importance in
power plant temperature measurements. A separate
section later in this chapter is devoted to the thermocouple and its applications.
Resistance thermometer The electrical resistance thermometer, used over a temperature range of –400 to
1800F (–240 to 982C), depends on the increase in electrical resistance of metals with increasing temperature;
this relationship is nearly directly proportional. If the
electrical resistance of a calibrated wire material is measured (by a Wheatstone bridge or other device), the temperature of the wire can be determined.
In the simplest form of the Wheatstone bridge system, shown in Fig. 7a, the reading would be the sum
of the resistances of the calibrated wire and the leads
connecting this wire to the Wheatstone bridge. However, this value would be subject to error from temperature changes in the leads. By using a more refined circuit shown in Fig. 7b, the resistance of the
leads can be eliminated from the instrument reading.
To localize the point of temperature measurement, the
resistance wire may be made in the form of a small
40-6
Fig. 7 Diagrams of electrical circuits for resistance thermometers
(courtesy of Leeds and Northrup Company).
coil. From room temperature to 250F (121C), commercial instruments usually have resistance coils of nickel
or copper. Platinum is used for higher temperatures
and in many high precision laboratory instruments
to cover a wide range of temperatures.
The electrical resistance thermometer can be used
for the remote operations of indicating, recording or
automatic controlling. If proper precautions are taken,
it is stable and accurate, but it is less rugged and less
versatile than a thermocouple.
Acoustic properties
Acoustic properties of gases vary with temperature
and are used as the basis for temperature measuring
instruments. The velocity of sound in a gas varies directly with the square root of its absolute temperature,
as indicated in the following formula:
c =
gc kRT / M
(3)
where
c
gc
k
R
T
M
=
=
=
=
=
=
speed of sound, ft/s
proportionality constant, 32.17 lbm ft/lbf s2
specific heat ratio, dimensionless
universal gas constant, 1545 ft lb/mole R
absolute temperature, R = F + 460
molecular weight, lb/mole
By measuring the time required for sound to traverse
a specific distance, the average gas temperature can
be calculated. This phenomenon has been commercially applied to measuring furnace gas temperatures.
By developing a number of independent temperature
paths a thermal contour may be developed.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Other properties
Other material properties that vary with temperature are also used as the basis for temperature measuring instruments. By flowing gas through two orifices in series, a method has been developed for measuring gas temperatures up to 2000F (1093C) commercially and up to 4500F (2482C) in the laboratory.
Temperatures ranging from absolute zero to 5000F
(2760C) have been accurately determined by using a
laboratory instrument that measures electron motions.
High temperature research has been stimulated by
gas turbine and jet propulsion applications, and further development of new and improved temperature
measuring instruments is expected.
Thermocouples
A thermocouple consists of two electrical conductors
of dissimilar materials joined at the ends to form a circuit. If one of the junctions is maintained at a temperature higher than the other, an electromotive force
(emf) is generated, producing current flow through
the circuit, as shown in Fig. 8.
The magnitude of the net emf depends on the temperature difference between the two junctions and the
materials used for the conductors. No unbalance, or
net emf, is generated if the two junctions are at the
same temperature or if the conductors are of the same
material at different temperatures. If one junction of
a calibrated thermocouple is maintained at a known
temperature, the temperature of the other junction
can be determined by measuring the net emf produced;
this emf is almost directly proportional to the temperature difference of the two junctions. The relationship
between emf and the corresponding temperature difference has been established by laboratory tests
throughout the temperature ranges for common thermocouple materials. These values are plotted in Fig.
9. The thermocouple is a low cost, versatile, durable,
simple device providing fast response for accurate temperature measurement. It also allows convenient centralized reading.
In the potentiometer circuit, copper leads may connect the reference junction terminals to the measuring instrument without affecting the net emf of the
thermocouple. If the instrument is at a uniform temperature, no emf is set up between the copper conductors and slide wire materials within the potentiometer.
However, if temperature differences exist within the
instrument, there will be disturbing emf values in the
circuit and the readings will be affected.
Multiple circuits
If two or more thermocouples are connected in series, the net emf at the outside terminals is equal to
the sum of the emf values developed by the individual
thermocouples. When all of the individual hot and cold
junctions are maintained at the same respective temperatures, as in the device known as the thermopile,
this multiplied emf value makes it possible to detect
and measure extremely small temperature variations.
Two or more thermocouples may be connected in
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Fig. 8 Principle of the thermocouple illustrated.
parallel to obtain a single reading of average temperature. In this case, the resistance of each thermocouple
must be the same. The emf across the terminals of
such a circuit is the average of all the individual emf
values and may be read on a potentiometer normally
used for a single thermocouple.
Practical application and multiple circuits
The limitation of the potentiometer circuitry to
measure small emf values has led to various circuits
of multiple thermocouples connected in series or parallel. These circuits make it possible to measure extremely small temperature variations or average temperatures. Thermocouple circuit considerations of wire
diameter and length, while less important for steady-
Fig. 9 Relation of temperature to electromotive force produced by
several commonly used thermocouples.
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The Babcock & Wilcox Company
state measurement, will affect thermocouple readings
during dynamic temperature conditions. These applications require detailed circuit design investigation.
The application of thermocouples requires attention
to the insulation of the lead wire to prevent erroneous
circuits. Parasitic couples may be introduced by mechanical, soldered, or brazed connections if temperature variations exist within different metals of the connections.
Selection of materials The combinations of metals
and alloys most frequently used for thermocouples are
listed in Table 1 with their general characteristics and
useful temperature ranges. Selection depends largely
on the ability to withstand oxidation attack at the
maximum expected service temperature. Durability
depends on wire size, use or omission of protection
tubes, and nature of the surrounding atmosphere.
All thermocouple materials deteriorate when exposed at the upper portion of their temperature range
to air or flue gases and when in contact with other
materials. Platinum in particular is affected by metallic oxides and by carbon and hydrocarbon gases
when used at temperatures above 1000F (538C) and
is subject to calibration drift. The upper temperature
limits shown in Table 1 are well below the temperatures at which rapid deterioration occurs.
For high temperature duty in a permanent installation or where destructive contact is likely, service life
may be extended, at some sacrifice in response speed,
by using closed-end protection tubes of alloy or ceramic
material. The arrangement should permit removal of
the thermocouple element from the protection tube for
calibration or replacement. Omission of the protection
tube may require frequent calibration and corrections
for calibration drift. For short periods of service within
the useful range of the thermocouple selected, the
correction for calibration change is usually negligible.
Sheathed-type thermocouple Sheathed-type magnesium oxide insulated thermocouples have been in
use for some time. The thermocouple wires are insulated with inert magnesium oxide insulation that protects the wires from the deteriorating effects of the environment. Sheaths can be made of stainless steel and
other resistant materials, ensuring relatively long life
Fig. 10 Sheathed-type thermocouple.
and resistance to oxidizing, reducing, or otherwise
corrosive atmospheres. Sheathed thermocouples are
available as grounded or nongrounded types, as illustrated in Fig. 10. The grounded type has a more rapid
response to temperature change but can not be used
for connection in series or parallel, because it is
grounded to the sheath. For these applications, the
nongrounded type should be used. The grounded type
is susceptible to separation or parting of the thermocouple wire where long leads at high temperatures are
used, whereas the nongrounded type appears satisfactory for this service.
Sheathed thermocouples may be equipped with
pads for welding to tubes, as illustrated in Fig. 11. Padtype thermocouples should not be used when the pad
is exposed to temperatures that are markedly different from that of the body being measured, because this
added metal surface can radiate or absorb heat. Typical applications of pad-type thermocouples are drum,
superheater header, or tube surface temperature
measurements. (See Fig. 12.)
Thermocouple and lead wire There are two classes
of wire for thermocouples, the closely standardized
and matched thermocouple wire and the less accurate
Table 1
Types of Thermocouples in General Use
Type of
Thermocouple (Note 1)
(+) Copper to constantan (−)
(+) Iron to constantan (−)
(+) Chromel to constantan (−)
(+) Chromel to alumel (−)
(+) 90% Pt 10% Rh to
platinum (−)
Useful Temperature
Range, F (C)
−300 to 650
0 to 1400
−300 to 1600
0 to 2300
(−184 to 343)
(−18 to 760)
(−184 to 871)
(−18 to 1260)
900 to 2600
(482 to 1427)
Maximum
Temperature, F (C)
Millivolts at 500F
(260C) (Note 2)
Magnetic
Wire
1100 (593)
1800 (982)
1800 (982)
2500 (1371)
13.24
15.01
17.94
11.24
−
Iron (+)
−
Alumel (−)
3190 (1754) (Note 3)
2.048
−
Notes:
1. Nominal composition: constantan, 55% Cu, 45% Ni; chromel, 90% Ni, 10% Cr; alumel, 95% Ni, 5% Al, Si and Mn
combined.
2. Reference junction 0F (−18.0C).
3. Melting point.
40-8
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Fig. 11 Sheathed thermocouple with pad.
compensating lead wire. For thermocouples of noble
metal, extension leads of copper and copper-nickel
alloy, which have an emf characteristic approximating the noble metal pair, are used to reduce cost. For
thermocouples of base metal, the extension lead wire
is the same composition as the thermocouple wires, but
it is less expensive because the control in manufacture and calibration is less rigorous.
For accuracy, the matched thermocouple wire should
be used at the hot junction and continued through the
zone of greatest temperature gradient to a point close
to room temperature, where a compensating lead wire
may be spliced in for connection to the reference junction. The reference junction is usually located at the
recorder or central observation point. Where a number of thermocouples are used, it may be economical
to establish a zone box (see Fig. 13) from which copper conductors are extended to the measuring instrument.
Splicing of extension lead wires may be done by
twisting the wire ends together, by using screw clamp
connectors, or by fusion welding, soldering or brazing.
Care should be taken to maintain correct polarity
Fig. 12 Application of pad-type thermocouple.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Fig. 13 Thermocouple and lead wire arrangement to measuring
instrument through selector switch.
by joining wires of the same composition. Polarity is
usually identified by color code or tracers in the wire
covering.
Hot junction Wire and pipe-type elements for hot
junctions may be purchased or may be made from stock
thermocouple wire, as shown in Fig. 14. These types
are useful for direct immersion in a gas stream, for
insertion into thermometer wells, or for thermal contact with solid surfaces.
Where the temperature of a metallic surface is to
be measured, a versatile hot junction may be formed
by peening the wires separately into holes drilled in
the surface of the metal. Steps for making this type of
junction are illustrated in Fig. 15.
The peened junction has the advantage of being
completely mechanical, with a tight and remarkably
strong attachment and minimum interference with
the temperature of the object. The temperature indicated is essentially that of the metallic surface, which
is the first point of contact with the conductors. The
depth of the drilled hole has no temperature effect; it
only provides mechanical strength. However, the junc-
Fig. 14 Thermocouple elements and hot junctions.
40-9
The Babcock & Wilcox Company
mocouple, the reference junction temperature is usually automatically compensated for by an internal
resistor circuit. This circuit compensates for deviations
from standard room temperature. The resistor circuit
characteristics are specific to the type of thermocouple
material for which the potentiometer is calibrated.
Some potentiometers provide a selector switch to directly read different types of thermocouples.
Fig. 15 Procedure for installing a peened-junction thermocouple to
measure surface temperature of metal.
tion contact points are subject to thermal conduction
in the wires. Where this type of error is significant,
precautions should be taken to prevent temperature
gradients in the wires. Drilled holes for the wire ends
should allow a snug fit before peening. For installations requiring a significant number of thermocouples,
there are portable spot welding machines available to
join the ends of the wire directly to a steel surface.
Millivolt potentiometer
The temperature-emf relationships of standardized
thermocouple wires, as established and published by
the manufacturer, should be used to convert the potentiometer readings to equivalent temperature values. These tabulated values represent the net emf
impressed in the potentiometer terminals when the
reference junction is at 0F (–18C) and the measuring
junction is at the temperature listed. The millivolt
potentiometer may be used with any type of thermocouple. It is frequently used when several different
thermocouple types are installed.
It is usually impractical to maintain the reference
junction at 0F (–18C) while taking readings. Correction for any reference junction temperature can be
made by adding to each observed emf reading the emf
value corresponding to the reference junction temperature. The temperature of the measuring junction
can then be determined. Most millivolt potentiometers
are equipped with a compensator, which should be
used to correct for the reference junction temperature.
Direct millivolt readings then correspond to the actual
thermocouple temperature.
Direct reading potentiometer
A potentiometer may be graduated to read the hot
junction temperature directly instead of in millivolts.
When calibrated for use with a specific type of ther40-10
Temperature recorders
In temperature recorders, a power operated mechanism automatically adjusts the slide wire of a potentiometer circuit to balance the emf received from the
thermocouple. The action of the slide wire is coordinated with the movement of a recording pen or print
wheel that is drawn over, or impressed on, a moving
temperature graduated chart.
As a result, an essentially continuous record may
be traced for one thermocouple, or a rapid scanning
of many thermocouples may be recorded.
Checking recorder calibration Compared with the
manually operated potentiometer, all recorders are
inherently less accurate because of wear and lost
motion in the actuating mechanism, shrinkage, or
printing inaccuracies of paper and chart scales.
Temperature of fluids inside pipes
The temperature of a fluid (liquid, gas or vapor)
flowing under pressure through a pipe is usually
measured by a glass thermometer, an electrical resistance thermometer, or a thermocouple. Each thermometer is inserted into a well, or thermowell, projecting
into the fluid. The thermowell is preferred but a thermocouple properly attached to the outside of a pipe
wall can provide good results. The thermowell provides
Fig. 16 Thermocouple well installation.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
an average temperature if temperature stratification
exists in the fluid, because thermal conduction along
the well equalizes the temperature.
A metal tube closed at one end, screwed into or
welded to a pipe wall, and projecting into the fluid,
serves as a thermowell (Fig. 16). It must have strength
and rigidity to withstand hydrostatic pressure, resistance to bending and vibration caused by its resistance
to fluid flow, and material compatibility for a welded
attachment. To minimize heat conduction to the surroundings and to give rapid response to temperature
changes, the well should be as small as possible. The
portion outside the pipe should also be small. The
material of the well must resist the erosive or corrosive action of the fluid. Because the temperature may
be locally depressed by acceleration of a compressible
fluid through a constriction in a pipe, the well should
be carefully positioned, taking these factors into account. Care should also be observed when locating the
well for measuring steam temperature downstream of
spray water attemperator injection points, as inadequate mixing of the steam and spray water may result in fluid temperature measurement errors. Projecting parts of the thermowell and the pipe wall should
be thoroughly insulated to prevent heat loss. Substantial error can result from air circulation within the
thermowell and should be minimized by packing with
insulating material.
Thermowell designs vary. If the fluid is a liquid or
a saturated vapor, good heat transfer is assured and
a plain well is satisfactory. If the fluid is a gas or superheated vapor, a finned well is sometimes used. The
method of attachment, a mechanical thread or welded
attachment to the pipe wall, is optional provided safety
code requirements are met (see Fig. 16).
Tube temperature measurement
It is frequently desirable to know the metal temperature of tubes in different classes of service. These
classes include furnace wall or boiler bank tubes that
are cooled by water and steam at saturation temperature, economizer tubes cooled by water below the temperature of saturation, and superheater and reheater
tubes cooled by steam above saturation temperature.
These temperature measurements may be used to
determine the safety of pressure parts, the uniformity
among tubes in parallel flow circuits, or the fluid temperature increase between inlet and outlet conditions.
The peened-type hot junction, illustrated in Fig. 17,
is satisfactory in many cases and is probably the simplest form of thermocouple application. Sheathed-type
thermocouples with pads are generally used to permanently monitor temperatures of tubes not exposed
to external heat. (See Fig. 11.) Properly applied insulation of sufficient thickness in the vicinity of the thermocouple attachment will reduce the effects of thermal conduction along the tube. The thermocouple wire
wrapped around the tube will minimize the conduction along the thermocouple wire. These techniques
are illustrated in Fig. 17. When properly installed the
surface thermocouple may be used to measure both
metal and fluid temperatures.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Fig. 17 Thermocouple wires extending from hot junction disposed
on pipe wall before leading outside.
Furnace wall tubes
In measuring water-cooled furnace wall tube temperatures, special protection for the thermocouple and
its lead wires must be provided because of the destructive high temperature furnace atmosphere and, in
some cases, the accumulation and shedding of ash and
slag deposits. If a simple peened thermocouple is used,
the results may lack accuracy because of errors from
conduction; in most cases, the service life would be
short because of physical damage or wire deterioration from overheating. Cover plates welded to the
tubes have been used to protect the wires, but these
plates interfere with the normal heat transfer and
cause local ash deposits to create abnormal conditions
at the temperature measurement point.
The use of chord-drilled holes through which the
thermocouple wires are laced (Fig. 18) was developed
by The Babcock & Wilcox Company (B&W); this is a
satisfactory temperature measurement method for furnace wall tubes. The tube surface is free of projections,
the wires are protected, and the thermal conduction
effect at the hot junction is minimized because the
wires pass through an essentially isothermal zone
before emerging into cooler surroundings at the rear
of the tube. To minimize the effect on the heat flow pattern within the tube metal, the chord-drilled holes should
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The Babcock & Wilcox Company
time lag between surface and depth thermocouples.
By using the surface and depth dimensions, the
equivalent lengths can be determined and the temperature gradients can be plotted. In practice, the heat
flows through a tube wall in a path of decreasing sectional area and the temperature gradient through the
metal is not linear with respect to thickness. The gradient, however, may be drawn as a straight line if temperatures are plotted against an equivalent length of
flow path (le). This represents an equivalent flat plate
having a uniform flow path with an equivalent but
greater thickness. This is illustrated in Fig. 19.
The equivalent plate thickness is calculated in the
following manner:
le = R n ( R / r )
(4)
where
R = outside radius of tube, in.
r = inside radius of tube, in.
l e = equivalent flat plate thickness, in.
Fig. 18 Chordal thermocouple.
be as small as possible. The effect of these holes on the
strength of the tube is small. This effect is minimal in the
critical direction of hoop stress and is readily tolerated in
the direction of longitudinal stress. The use of chord-drilled
holes in the thicker, high pressure wall tubes is a practical method of obtaining surface metal temperatures.
Gradient thermocouple
Measuring the temperature gradient through a
tube wall is a means of determining the heat flow rate
through the wall and of detecting the accumulation
of certain types of internal deposits.
To obtain the best results, a large temperature gradient through the wall is desirable. However, ideal
conditions may be compromised to permit an arrangement that provides measurable metal temperatures
and is practical to fabricate. Fig. 18 shows a section
through a tube which illustrates the drilling and installation of typical surface and depth thermocouples.
Calibration Sheathed thermocouples are suitable
for this temperature gradient application. For greater
accuracy the thermocouples may be laboratory calibrated. No procedure is available to accurately or economically calibrate the thermocouple tube assembly
in the field. The most satisfactory method is as follows.
Following installation, obtain a series of temperature readings on all thermocouples at two or three
different ratings on the boiler, from a low rate to maximum rate, while the tube is known to be internally
clean; read all temperatures as simultaneously as
possible. Several series of readings should be taken
on the thermocouples at each rating. An average
should be calculated for each thermocouple to correct
for minor differences in temperatures resulting from
heat input variations. This also compensates for the
40-12
In many cases, thermocouple error may represent
a significant portion of the gradient being measured.
Ideally, lines drawn through the surface and depth
temperature (Fig. 20) should intersect the inner surface equivalent thickness line slightly above the fluid
temperature as measured by a thermocouple peened
on the outside surface of the tube opposite the furnace.
The amount above the fluid temperature represents
the temperature drop across the fluid film and this
drop increases with increased heat input. It is difficult to obtain consistently drilled thermocouple holes
that reflect the pattern shown in Fig. 20. If, at low
inputs, the line drawn through the surface and depth
temperature intersects the inner surface equivalent
thickness line at fluid temperature or slightly above,
it may be considered as satisfactory. If it falls below or
well above this point, a correction or calibration may
be made by ignoring the measured equivalent depth
dimension, plotting a line through the outer and inner surface temperatures, then adjusting the equivalent depth to a value represented by the intersection
of the adjusted gradient and depth thermocouple temperature (Fig. 21).
Heat flux measurement Once a series of temperature
plots shows consistent results, heat inputs may be calculated:
q′′ =
k (T1 − T2 )
le
(5)
where
q″
k
T1
T2
le
=
=
=
=
=
heat flux, Btu/h ft2
thermal conductivity, Btu/h ft F
outside surface thermocouple temperature, F
depth thermocouple temperature, F
equivalent plate thickness (surface to depth), ft
(Fig. 19)
Scale detection If the temperature gradients are to
be used as a scale detector, then thermocouples should
be read periodically, plotted, and checked for a change
in the temperature above saturation.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Fig. 19 Thermocouple installation.
To assure a close comparison, the thermocouple temperatures should always be read with the calibrated
equipment and under operating conditions close to
those existing during the original setup. An accumulation of internal deposits in the thermocouple zone is
marked by an increased temperature difference from
inner surface to saturation.
When the average of the surface and depth temperatures approaches the limit for the tube metal, the
boiler should be shut down and the inside tube surfaces inspected. Sufficient allowance should be made
for tube to tube temperature variations.
Fig. 20 Sample plot of temperature gradients for low, medium and
high heat rates.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Limitations of gradient thermocouples The gradient
thermocouple method of measuring heat flow
through tube walls is a guide rather than an absolute measure. Relatively small dimensions and small
differential temperatures exist between surface thermocouple and depth thermocouple locations. Also, any
small error in determining temperatures or in metal
thickness between thermocouples usually represents
a large percentage of this small difference.
The effectiveness of the gradient temperature plot
as an internal scale detector is also dependent on the
nature of the scale. Certain types of scale, such as
carbonate or silica deposits, accumulate uniformly,
while iron oxide deposits can accumulate irregularly.
The location of nonuniform deposits is uncertain and
the gradient thermocouple method is not reliable for
detecting such accumulations.
For a quick determination of internal tube deposit
changes, the difference between surface and depth
temperature readings can be plotted against the difference between surface and fluid temperature readings. With a clean tube, points should fall along a straight
line over a range of inputs. As deposits form, the difference between surface and fluid temperature increases
for an unchanging surface and depth temperature difference. Fig. 22 shows a typical plot of such conditions.
Fig. 21 Adjustment of temperature gradient.
40-13
The Babcock & Wilcox Company
vection transfer from the hot gases in which it is immersed, it is also subject to heat exchange by radiation
to and from the surrounding surfaces and by conduction through the instrument itself. If the temperature
of the surrounding surfaces does not differ from that
of the gas (gas flowing through an insulated duct), the
temperature indicated by the instrument should accurately represent the gas temperature. If the temperature of the surrounding surfaces is higher or lower than
that of the gas, the indicated temperature will be correspondingly higher or lower than the gas temperature.
The variation from the true gas temperature depends on the temperature and velocity of the gas, the
temperature of the surroundings, the size of the temperature measuring element, and the construction of
the element and its supports. To correct for the errors
in temperature measurement caused by the surroundings, it is best to calibrate the instrument to a known
and reliable source.
As an example, consider a 22 gauge (0.7112 mm)
bare thermocouple. When it is used to measure the gas
temperature in boiler, economizer, or air heater cavities with surrounding walls cooler than the gas, the
error in the observed readings may be found from Fig.
23 (line for bare TC).
Fig. 22 Plot of chordal thermocouple temperatures showing effect
of internal deposits.
High velocity thermocouple
The design and operation of steam generating units
depend on the evaluation of gas temperatures in the
furnace and superheater sections of the equipment.
Boiler design to achieve successful thermal performance must take into account the limitations imposed
by the allowable metal temperatures of superheater
Superheater and reheater applications
Chordal surface thermocouples can be used to measure metal temperatures of superheater or reheater
tubes in the gas stream, using the principles previously described. However, special provision must be
made to protect the wires between the point of measurement and the exit from the boiler setting. This can
be done by containing the sheathed thermocouple in
stainless steel tubing that is welded to the superheater
or reheater tube. This maintains the sheath and protection tubing at a temperature which is approximately that of the superheater or reheater tube. Additional cooling of the stainless steel protection tube
is frequently required.
Gas temperature measurement
Temperature measurement of combustion gas at different locations within the boiler is important to the
boiler design engineer and the operating plant engineer. Accurate temperature measurements of gas entering and leaving the heat absorbing components can
confirm design predictions and operating performance.
In all cases of gas temperature measurement, the
temperature sensitive element approaches a temperature that is in equilibrium with the conditions of its
environment. While it receives heat primarily by con-
40-14
Fig. 23 General magnitude of error in observed readings when
measuring temperature in boiler cavities with thermocouples.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
tubes and by the fusing characteristics of ash and slag
from the current or expected fuel. The overall complexity of combustion and heat transfer relationships prevents exact calculation and accurate measurement of
the gas temperatures provides information to confirm
calculation methods.
The optical pyrometer and radiation pyrometer are
not designed to measure gas temperature. Excessive
error is also encountered when gas temperatures in
the furnace and superheater areas are measured with
a bare thermocouple.
The high velocity and multiple-shield high velocity thermocouples (HVT and MHVT), developed to
correct for radiation effects, are the best instruments
available for measuring high gas temperatures in
cooler surroundings or low gas temperatures in hotter surroundings. Cross-sections through single and
multiple-shield high velocity thermocouples developed
for use in boiler testing are shown in Fig. 24.
The surfaces (water-cooled walls, or superheater or
boiler tube banks) surrounding the usual location of
a gas traverse are cooler than the gases. Consequently,
the readings from a bare unshielded thermocouple
indicate lower temperatures than those obtained with
an HVT. For the same reason, an HVT generally indicates lower values than an MHVT. A comparison between bare thermocouple, HVT and MHVT results in
typical boiler furnaces and cavities is given in Fig. 23.
MHVT measurements closely approach true gas
temperatures. In this design, the thermocouple junction is surrounded by multiple shields, all of which
receive heat by convection induced by the high gas
flow rate. In this manner, the heat transfer by radiation is so reduced that there is virtually no heat exchange between the junction and the innermost shield.
Because of the small flow areas that rapidly become
clogged by ash, use of the MHVT is limited to clean gas
conditions. Where traverses are taken in dust- or slagladen gases, it is usually necessary to use the HVT. The
readings are corrected by comparison with results obtained under clean gas conditions from an MHVT.
For temperatures exceeding 2200F (1204C), noble
metal thermocouples are required and it is important
to protect the thermocouple from contamination by the
gases or entrained ash. Various coverings, shown in
Fig. 24, provide some protection for the wires, especially when fouling occurs from molten slag at temperatures above 2400F (1316C). When platinum thermocouples are used in gas above 2600F (1427C), appreciable calibration drift may occur even while taking measurements requiring only several minutes of
exposure time. The thermocouple elements should be
checked before and after use with corrections applied
to the observed readings. When the error (∆T) reaches
40 to 60F (22 to 33C), the contaminated end of the thermocouple should be removed and a new hot junction
should be made using the sound portion of the wire.
Because heat transfer by radiation is proportional
to the surface area, emissivity, and difference of the
source and receiver absolute temperatures, the effects
of radiation increase as the temperature difference
between the thermocouple hot junction and the surrounding surfaces increases. Also, because heat trans-
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
fer to the thermocouple by convection is proportional
to the gas mass velocity and the temperature difference between gas and thermocouple, the junction temperature may be brought closer to the true temperature of the gas by increasing the rate of mass velocity
and convection heat transfer at the thermocouple while
shielding the junction from radiation.
A special high velocity thermocouple probe for measuring high gas temperatures in boilers is illustrated
in Fig. 25. This portable assembly is primarily used
for making test traverses in high duty zones by insertion through inspection doors or other test openings in the setting.
This thermocouple is supported by a water-cooled
probe. The measuring junction is surrounded by a
tubular porcelain radiation shield through which gas
flow is induced at high velocity by an attached aspirator. The gas aspiration rate over the thermocouple
can be checked by an orifice incorporated with the
aspirator and connected to the probe by a flexible hose.
The gas mass velocity (or mass flux) over the thermocouple junction should be at least 15,000 lb/h ft2 (20.34
kg/m2 s). Convection heat transfer to the junction and
shield is simultaneous and both approach the temperature of the gas stream. Radiation transfer at the junction is diminished by the shield. Because the shield is
exposed to the radiation effect of the surroundings, it
may gain or lose heat and its temperature may be
slightly different from the junction temperature.
With the increasing size of steam generators, handling long HVT probes has become more difficult but,
Fig. 24 Shield assemblies for high velocity thermocouple (HVT) and
multiple-shield, high velocity thermocouple (MHVT).
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The Babcock & Wilcox Company
Fig. 25 Rugged, water-cooled, high velocity thermocouple (HVT) for determining high gas temperatures.
to date, no acceptable point by point measurement of
high temperature gases has been fully developed.
Measurement evaluations
Large boilers may have significant variation in actual measurements at a particular measurement
plane. Where significant data variation exists, data
reduction may require mathematical methods to
weight-average individual measured values during
the data reduction process.
Flue gas temperature measurements at the economizer outlet during performance tests are an example
of a large number of data points which require reduction to a single representative temperature.
A weighted average temperature becomes time consuming and the need for such accuracy must be justified. An average of the individual temperature measurements is usually acceptable if a sufficient number of points are obtained. The average gas temperature may be approached by increasing the number of
points or by instrument design to satisfy a particular
requirement. For example, in a heat loss efficiency test,
multiple measuring locations are used to indicate flue
gas exit temperatures for determining dry gas loss. The
number of points required by the ASME Performance
Test Code permits efficiency accuracies within 0.05%.
Under certain circumstances, the maximum, rather
than average, gas temperature may be required for
equipment protection. A moveable probe with one or
two thermocouples may be used to determine the location of this high temperature. For instance, during
boiler pressurization and before steam is flowing
through the superheater or reheater tubes, a bare
thermocouple temporarily installed in the gas stream
immediately before the tubes may be used to indicate
the highest temperature to prevent tube overheating.
These thermocouples are normally removed after
steam flow is adequate for cooling. On units designed
for remote operation, it is possible to remotely retract
40-16
and insert these thermocouples using a sootblower
carriage. The remotely insertable thermocouple is
called a thermoprobe.
Insulation and casing temperature
Outer surfaces
The measurement method should be carefully selected to avoid significant errors in measuring
uncased insulation surface temperature. Portable contact thermocouple instruments designed to be pressed
against a surface are unsatisfactory on insulated surfaces because the instrument cools the surface at the
point of contact, and the low rate of heat transfer
through the insulating material prevents adequate
heat flow from surrounding areas to the contact point.
Thermocouple attachment to the insulation surface
must not appreciably alter the normal rate of heat
transmission through the insulation and from the
surface to the surroundings. Fine wires can be attached and maintained at the surface temperature
more easily than heavy wires. If the insulation is plastic at the time of application, press the thermocouple
junction and several feet of lead wire into the surface
of the insulation; the thermocouple will adhere when
the insulation hardens. If the insulation is hard and
dry, the junction and lead wires may be cemented to
the surface using a minimum of cement. Fastening the
wires to the surface with staples introduces conduction errors. Covering the wires with tape changes the
heat transfer characteristics of the surface and imposes
an undesirable insulation layer between the wire and
the ambient air.
Steel casings
The temperature of steel boiler casings may be accurately measured with portable contact thermocouple
instruments, because lateral heat flow from adjoining
metal areas quickly compensates for the small quan-
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
tity of heat drawn by the instrument at the contact
point. Thermocouple wires may be peened into or
fused onto the metal surface to form the hot junction.
Thermal contact between the lead wires and the surface should be maintained for several feet. The wire
installation should minimize any disturbance of heat
transfer from the surface to the surrounding air. Approximate surface temperatures may be conveniently
measured with fusion paints or crayons.
Thermometers are sometimes fastened to metal
surfaces with putty. This method gives an approximate
surface temperature indication if the metal is massive
and near ambient temperature. It is not recommended
for boiler casing temperature measurement and is
completely unsatisfactory for measuring insulation
surface temperature.
Through-steel components, such as metal ribs imbedded in insulation and studs or door frames extending through insulation, cause considerable local upsets in surface temperatures and their influence may
spread laterally along a metal casing. These effects
must be considered in planning and interpreting surface temperature measurement.
Infrared cameras may be used to measure surface
temperatures. These instruments can minimize the need
for complex thermocouple installations, especially if large
surface areas are to be measured. Improved equipment
permits recording for further review.
Measurement of steam quality
and purity
The most common methods of field testing for steam
quality or purity are:
1. sodium tracer (flame photometry),
2. electrical conductivity (for dissolved solids),
3. throttling calorimeter (for direct determination of
steam quality), and
4. gravimetric (for total solids).
Each of these methods is described in ASME Performance Test Code 19.11, Water and Steam in the
Power Cycle. The throttling calorimeter determines
steam quality directly, whereas the other methods
determine the steam solids content.
Most of the solids content of steam comes from the boiler
water, largely in the carryover of water droplets. (See also
Chapter 5.) It is customary to relate steam quality and
solids content of steam by the following equation:
solids in steam × 100
x = 100 −
solids in boiler water
(6)
where x equals % steam quality in percent by weight
and solids are expressed as equivalent parts per million (ppm) (by weight) of steam or water.
By the use of Equation 6, steam quality can be determined if the solids content is known. This relationship is subject to error resulting from carryover of solids in solution in the steam or in vaporized form. This
effect occurs principally with silica at pressures above
2000 psi (13.79 MPa).
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The four steam quality measurement methods may
be summarized as follows:
1. The sodium tracer method, with continuous recording of total dissolved solids in steam, is used
for the highest accuracy.
2. The conductivity method is useful within certain
limitations but is less accurate.
3. The calorimeter method is not suitable for measuring extremely small quantities of carryover and
at pressures exceeding 600 psi (4.14 MPa).
4. Gravimetric analyses require large samples and
do not detect carryover peaks.
Obtaining the steam sample
If the steam quality results are to be accurate, the
instruments must be supplied with a representative
steam sample. The method of obtaining a steam
sample and the operation of the boiler during testing
are fundamentally the same for each testing method.
The sampling nozzle design should be as recommended by ASME Performance Test Code 19.11. It
should be located after a run of straight pipe equal to
at least ten diameters. Locations in the order of preference are:
1.
2.
3.
4.
vertical pipe, downward flow,
vertical pipe, upward flow,
horizontal pipe, vertical insertion, and
horizontal pipe, horizontal insertion.
The nozzle should be installed in the saturated steam
pipe in the plane of a preceding bend and in a position
that ensures the sampling ports directly face the steam
flow. On boilers with multiple superheater supply tubes,
sampling nozzles should be located in tubes spaced across
the width of the drum. These sampling points should be
at no greater than 5 ft (1.52 m) intervals.
When a calorimeter is used the connection from the
sampling nozzle to the calorimeter must be short and
well insulated to minimize radiation losses. Connections
must be steam-tight so the insulation remains dry.
When steam purity is tested by conductivity or sodium tracer methods, the tubing from the sampling
nozzles to the condenser should be steel (preferably
stainless), with an inside diameter not exceeding 0.25
in. (6.4 mm). It should be of minimal length to reduce
the storage capacity of the line. Multiple connections
can be run to a common line and then to the condenser.
However, these connections should be valved so that
each one can be sampled individually to isolate possible selective carryover. Cooling coils, or condensers,
should be located close to the sampling nozzles to minimize settling of solids in the sample line.
Sodium tracer method
The sodium tracer technique permits measuring
dissolved solids impurities (carryover) in steam condensate to as low as 0.001 ppm.
Sodium is present in all boiler water where chemical treatment is in the form of solids. The ratio of the
total dissolved solids in the steam condensate to the
total dissolved solids in the boiler water is proportional
40-17
The Babcock & Wilcox Company
to the ratio of the sodium in the steam condensate to
the sodium in the boiler water. By determining the
sodium content of the steam condensate and boiler
water and the total dissolved solids in the boiler water, the solids content of the steam and the percent
moisture carryover may be calculated. The sodium
content of steam condensate and water is usually determined by using a flame photometer. The effect of
any change in boiler operating conditions on carryover
is promptly indicated, facilitating problem analysis.
The operation of a flame photometer is illustrated
in Fig. 26. The condensed steam sample is aspirated
through a small tube in the burner into the oxygenhydrogen flame. The flame, at 3000 to 3500F (1649
to 1927C), vaporizes the water and excites the sodium
atoms, which emit a characteristic yellow light having a definite wavelength. The intensity of the emitted
yellow light is a measure of the sodium in the sample.
The intensity of the light is measured with a spectrophotometer equipped with a photomultiplier attachment.
The light from the flame is focused by the condensing mirror and is directed to the diagonal entrance
mirror. The entrance mirror deflects the light through
the entrance slit and into the monochromator to the
plane mirror. Light striking the plane mirror is reflected
to the fiery prism where it is dispersed into its component wavelengths. The desired light wavelength is
obtained by rotating a wavelength selector which
adjusts the position of the prism. The selected wavelength is directed back to the plane mirror where it is
reflected through the adjustable exit slit and lens. The
light impinges on the photomultiplier tube, causing a
current gain which registers on the meter. The amount
of sodium in the sample is obtained by comparing the
emission from the water sample to emissions obtained
from solutions of known sodium concentration.
Conductivity method
Electric conductivity can be used to determine steam
purity in certain boilers. This method is applicable to
units operating with significant solids concentration
in the boiler water and with a total steam solids content in excess of 0.5 ppm.
The conductivity method is based on the fact that
dissolved solids, whether acids, bases or salts, are completely ionized in dilute solution and, therefore, conduct electricity in proportion to the total solids dissolved. On the basis of solids normally present in boiler
water, the solids content in parts per million equals
the electrical conductivity of the sample in micromho
per mm times 0.055.
The condensed sample should ideally be free from
dissolved gases, especially ammonia (NH3) and CO2,
which contribute nothing to the solids content of the
steam but have a significant effect on conductivity.
Fig. 26 Schematic arrangement of flame photometer.
40-18
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Throttling calorimeter
When steam expands adiabatically without doing
work, as through an orifice, the enthalpies of the high
and low pressure steam are equal, provided there is no
net change in steam velocity. Such an expansion is
termed throttling. As can be seen from a Mollier chart
(see Chapter 2), wet steam with an enthalpy exceeding
1150 Btu/lb (2675 kJ/kg) becomes superheated when
throttled to atmospheric pressure. The temperature of
the expanded steam determines the enthalpy, which may
be used with the pressure of the wet steam to determine
the percent moisture in the wet steam sample.
The foregoing principle is used in various forms of
throttling calorimeters. Each incorporates a small orifice for expansion of the steam sample into an exhaust
chamber, where the temperature of the expanded
steam is measured at atmospheric pressure. Velocity
changes in properly designed calorimeters are negligible. The variations in the different designs are chiefly
in the means of shielding the unit from external temperature influences. At pressures below 600 psi (4.14
MPa), the calorimeter shown in Fig. 27 is used. This is
a small, low cost, simple, accurate instrument which
gives good results for steam having appreciable quantities of moisture: up to 4.3% at 100 psi (0.69 MPa), 5.6%
at 200 psi (1.38 MPa) and 7.0% at 400 psi (2.76 MPa).
Fig. 27 shows the calorimeter installed and ready
for use. The connection should be short; the connection and the calorimeter should be well insulated. It
is essential that the calorimeter discharge be completely unobstructed, so no backpressure can build in
the exhaust chamber. The orifices must be clear, full
opening and of the correct diameter: 0.125 in. (3.175
mm) for pressures from atmospheric to 450 psi (3.10
MPa) and 0.0625 in. (1.588 mm) from 451 to 600 psi
(3.11 to 4.14 MPa). The thermometer should be immersed in oil of suitably high flashpoint. The calorimeter is operated by fully opening the shutoff valve and
letting the steam discharge through the unit to the
atmosphere. The calorimeter must be thoroughly
warmed up and in temperature equilibrium before
normal temperature or test readings are taken.
In obtaining calorimeter readings, the temperature
of the expanded and superheated steam is measured
by a thermometer inserted in the thermometer well.
Due to radiation from the calorimeter installation,
thermometer corrections and orifice irregularities, the
observed temperature is generally lower than the actual temperature. To determine a suitable correction,
the as-installed temperature of the calorimeter should
be determined. This can be done by taking readings
when the boiler is known to be delivering dry saturated steam. This is the case when the boiler output
is steady at about 20% of rated capacity with low
water concentration and steady water level. The normal correction is obtained by subtracting the as-installed temperature from the theoretical temperature,
read from the zero moisture curve of Fig. 28. The normal correction should not exceed 5F (2.8C). If it does,
the calorimeter orifice is clogged, the insulation is
faulty, or some other test feature is incorrect. When
the unit is used to determine the quality of a wet steam
sample, the percent moisture can be found from the
curves of Fig. 28 using measured drum pressure and
corrected calorimeter temperature. When properly
installed, insulated and operated, the calorimeter can
give accurate results for steam moisture contents as
low as 0.25% for low pressure boilers. For pressures
above 600 psi (4.14 MPa) and for greater accuracy of
steam purity measurement in the low ppm range,
other methods of measurement should be used.
Fig. 27 Throttling calorimeter showing sampling tube in steam pipe.
Fig. 28 Percent moisture in steam versus calorimeter temperature.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
Gravimetric analysis
Gravimetric analysis is used to determine solids levels, particularly total solids, in a condensed steam
sample. It consists of evaporating a known quantity
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The Babcock & Wilcox Company
Y = compressibility factor, dimensionless, equals
1.0 for most liquids and for gases where the
pressure drop across the device is less than
20% of the initial pressure
A = cross-sectional area of throat, ft2
g c = proportionality constant, 32.17 lbm ft/lbf s2
P1 = upstream static pressure, lb/ft2
P2 = downstream static pressure, lb/ft2
β = ratio of throat diameter to pipe diameter, dimensionless
ρ 1 = density at upstream temperature and pressure, lb/ft3
of condensed steam to complete dryness and weighing the residual. This can be done on a batch basis or
by a continuous sample system.
While a gravimetric analysis provides an accurate
measure of total solids in water, its main disadvantage
is that it requires a relatively large quantity of water
obtained over an extended period of time. It therefore
does not localize carryover peaks when they occur.
Time lag in other methods of steam purity measurement is usually small enough to permit attributing
peaks of carryover to periods of high water level, high
boiler water solids, or other operating upsets.
Flow measurement
Fluid flow includes water, steam, air and gas flow.
While there are many means of measuring flow, the
basic methods for the accuracy required by the ASME
Performance Test Code use the orifice, flow nozzle (flow
tube), or venturi tubes as primary elements. The pressure drop or differential pressure created by these
restrictions can be converted into a flow rate.
The flow of any fluid through an orifice, nozzle or
venturi tube may be determined by the equation:
= Cq YA
m
where
2 gc ρ1 ( P1 − P2 )
1 − β4
(7)
= flow rate, lb/s
m
Cq = coefficient of discharge, dimensionless, dependent on the device used, its dimensions and
installation
Details of primary element sizing, fabrication and
flow calculations can be obtained from the ASME publication Fluid Meters, Their Theory and Application.
Table 2 is extracted from the ASME Performance Test
Code 19.5, Section 4, Flow Measurement, to show the
advantages and disadvantages of the three primary
element types. The throat tap nozzle has the highest
accuracy of the primary flow measuring devices.
The primary elements listed should be fabricated
of erosion and corrosion resistant materials. The orifice and flow nozzles are shown in Fig. 29; the venturi tube is shown in Fig. 30.
Even though these elements can be sized with considerable accuracy by calculation, they should be laboratory calibrated prior to precision testing. Calibration
is usually by weighed water tests using scales. For
commercial use, calculated flow rates or rates based
on prototype testing or calibration are adequate.
Certain important factors of the primary element
installation should be considered for accurate measurement. These include:
Table 2
Advantages and Disadvantages of Various Types of Primary Elements
Advantages
Disadvantages
Orifice
1.
2.
3.
4.
5.
Lowest cost
Easily installed and/or replaced
Well established coefficient of discharge
Will not wiredraw or wear in service during test period
Sharp edge will not foul with scale or other suspended
matter
1. High nonrecoverable head loss
2. Suspended matter may build up at the inlet side of
horizontally installed pipe unless eccentric or
segmental types of orifices are used with the hole
flush with the bottom of the pipe
3. Low capacity
4. Requires pipeline flanges, unless of special
construction
Flow Nozzle
1. Can be used where no pipeline flanges exist
2. Costs less than venturi tubes and capable of handling
same capacities
1. Higher cost than orifice
2. Same head loss as orifice for same capacity
3. Inlet pressure connections and throat taps when used
must be made very carefully
Venturi Tube
1.
2.
3.
4.
5.
6.
40-20
Lowest head loss
Has integral pressure connections
Requires shortest length of straight pipe on inlet side
Will not obstruct flow of suspended matter
Can be used where no pipeline flanges exist
Coefficient of discharge well established
1. Highest cost
2. Greatest weight and largest size for a given size line
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Pipe Wall Tap Flow Nozzle
Fig. 29 Orifice and flow nozzles.
1. location in the piping in relation to bends or
changes in cross-section,
2. possible need for approach straightening vanes,
3. location and type of pressure taps,
4. dimensions and condition of surface or piping before and after the element,
5. position of the element relative to direction of fluid
flow, and
6. type and arrangement of piping from primary element to differential pressure measuring instrument.
Details of these requirements for precision testing are
also covered in the ASME publication Fluid Meters, Their
Theory and Application. These devices produce a differential pressure across the element and a differential pressure gauge should be used for the flow measurement.
Flow measurement of combustion air or flue gas
generally does not require a high degree of precision.
Orifices, flow nozzles, or venturis are also used, but
the rigid requirements of construction and location are
usually not possible because of space limitations. As a
substitute, a component of the steam generator, located
in the flow path, can create a suitable pressure differential, which is used to obtain a flow measurement.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
For example, the draft loss across the gas side of an
air heater may be used as an index of the flue gas flow.
Because pressure differentials vary with a change in
surface cleanliness, these are not highly reliable methods. The use of orifices, flow nozzles, venturi air foils,
or impact suction tubes in areas free of entrained dust
and at relatively stable temperatures prove more satisfactory. Fig. 31 illustrates two types of venturi sections used in air ducts for measuring combustion air
flow. Fig. 32 illustrates an impact suction pitot tube
arrangement for metering primary air flow to a pulverizer. For a dependable determination of air flow,
the primary element should be calibrated at normal
operating pressure and temperature. Test connections,
or sampling points, for this purpose are located at a
zone in the duct or pipe where good flow characteristics are obtainable, and the calibrating flow measurements are made using a hand held pitot tube or
equivalent probe. The pitot tube, when inserted facing the air or gas flow stream, measures velocity pressure, that is, the difference between total and static pressure. The velocity pressure measurement can be converted into a velocity reading for English units only by:
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The Babcock & Wilcox Company
Fig. 30 Dimensional proportions of classical (Herschel) venturi tubes with a rough-cast, convergent inlet cone. (Source: ASME, Fluid Meters,
Their Theory and Application, Sixth Edition, 1971.)
V = 1097
hV
ρ
(8)
where
V = velocity, ft/min
h V = velocity head as indicated by pitot tube differential, in. wg
ρ = density at the temperature of the sampling location, lb/ft3
probe. It also has a coefficient of 1.0 and incorporates
a null balance feature that permits determining when
the probe faces the direction of gas flow. This probe is
illustrated in Fig. 35. In this schematic, the outer holes
in the probe are each at exactly 39.25 deg from the
centerline hole, placing them at a point of zero impact
pressure and providing a reading of true static pres-
A typical pitot tube and measuring manometer are
illustrated in Fig. 33. The pitot tube has a coefficient
of 1.0, which is applied to velocity head readings,
eliminating the need for corrections. Fig. 34 shows a
method of traversing a round duct using a pitot tube.
An additional portable flow measuring device that
can be used for calibration purposes is the Fechheimer
Fig. 31 Venturi sections for air ducts.
40-22
Fig. 32 Averaging pitot tubes.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Fig. 33 Arrangement of pitot tube and manometer.
sure. When the probe faces the gas flow, a manometer connected across the two outer holes shows a zero,
or null, balance. Because the centerline hole receives
full impact or total pressure when facing into the gas
stream, a manometer connected across one outer hole
and the centerline hole gives true velocity pressure,
that is, impact pressure less static pressure.
The impact suction or reversed type pitot tube, illustrated in Fig. 36, produces a differential pressure
greater than one velocity head, which gives a magnified reading. This type of pitot tube measures flow in
either direction. To use the reversed type pitot tube
for flow measurement, calibration is required for the
Reynolds number range as well as for the geometry
of the flow channel and its orientation in the stream.
Permanently installed pitot tubes are used where
relatively high pressure losses due to the primary
measuring element are undesirable. Flow tubes are
also used in these cases. These tubes differ from most
other primary elements in that the flow channel crosssection varies symmetrically in the inlet and exit directions from the contoured throat section.
The throat section is equipped with two sets of pressure taps, one set pointing upstream and one downstream, similar to impact suction pitot tubes. Each set
of taps is interconnected and the two sets in turn are
connected to a differential pressure gauge. The pressure taps are located at cross-sections of equal area so
that the differential developed is a result of impact and
suction pressure differences only and is, therefore, a
function of the velocity head alone.
Many other types of flow measuring devices exist.
The pitot tube grid incorporates an array of pitot tubes
in a flow path. The primary signal is a pressure differential. The array of pitot tubes measures a number of flows and minimizes measurement errors caused
by flow unbalance and upstream conditions. The hot
wire anemometer measures flow using a probe with a
small wire at the tip. Flow over the wire removes heat,
and flow may be measured when the hot wire is in
equilibrium with electrical power input and heat lost.
Doppler phenomena may be applied to flow measureSteam 41 / Pressure, Temperature, Quality and Flow Measurement
Fig. 34 Pitot tube traverse.
Fig. 35 Fechheimer probe.
40-23
The Babcock & Wilcox Company
rapid updates to operating information and provide a
check on measurement errors. Measurements of temperature, pressure and flow that might be in error because of instrument calibration are identified rapidly.
Process control
A computer based control system receives its basic
information from a data acquisition system which accumulates information from the plant instrumentation.
Process control is achieved according to specific mathematical algorithms. The control system, updated by
current data or operator interface, produces output signals to modulate components based on these algorithms.
Fig. 36 Combined-type pitot tube with reversed static tube. (Source:
ASME, Fluid Meters, Their Theory and Application, Sixth Edition, 1971.)
ment with laser or acoustic transmissions. The transmission signal and type of fluid make these methods
very application specific.
Computer application to measurement
The application of computer technology to instrumentation provides the capability to further understand the operating characteristics of many interrelated power plant components and processes at a
much faster rate than was previously possible. Measurements have progressed from readings recorded at
local gauges, strip charts, or manually recorded test
gauges to significant quantities of information acquired in seconds.
The instrument readings are not made directly at
the instrument, but rather transmitted signals from
the instrument are entered into a data acquisition
system and the reading is indicated at a computer. The
computer gathers, stores, interprets and displays the
information. The display appears as an extension of
the instrument. The information gathered may be
further manipulated for process control or equipment
performance computations.
Performance computation
Computer computation permits calculations in near
real time for boiler efficiency and other plant performance indicators. These performance indicators provide
40-24
Data acquisition system
A typical data acquisition system consists of computer hardware and related software. The basic hardware components are the computer, a signal multiplexer and the measuring instrument. The computer
program (software) controls the hardware operation
and data recording. In operation, the program causes
the signal multiplexer to read a specific instrument
analog output signal. The signal is converted from an
analog to a digital signal, which is conveyed to the
computer and stored in memory. The first processing
of the data is the storage of the digitized signal in a
data array. Data acquisition, incorporating many instruments, other computer outputs and manual inputs, requires that each of the signals be assigned a
specific location in the array. The stored signal may
be converted to engineering units and stored in another array. Furthermore, the data may be averaged
over time and then stored. Performance calculations
are generally performed using data converted to engineering units and averaged over time. Portable data
acquisition systems are generally used for specific test
purposes and may use high precision transmitters and
thermocouples.
Signal multiplexer
The signal multiplexer in a data acquisition system
provides an interface between the transmitted instrument signal and the computer. The typical multiplexer
provides signal conditioning, analog to digital signal
conversion and switching capability for multiple inputs.
It produces a digital output signal for computer processing and assignment to a position in the data array. Significant engineering design is required to accommodate
the variety of signals entering the multiplexer.
Data acquisition computer program
The data acquisition software may be program oriented or menu oriented but should readily permit
changes to the quantity of signals, the rate at which
the computer reads each signal and the computations
performed with each signal. Data storage and retrieval are but two of many design considerations for
computer program configurations.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
References
1. Tower, J.R., “Staring PtSi IR cameras: More diversity,
more applications,” Photonics Spectra, (USPS 448870),
Laurin Publishing Company, Pittsfield, Massachusetts,
February, 1991.
2. Kaplan, H., “What’s new in IR thermal imagers,”
Photonics Spectra, (USPS 448870), Laurin Publishing
Company, Pittsfield, Massachusetts, February, 1991.
3. Weiss, J., and Esselman, W., Electric Power Research
Institute and R. Lee Foster-Miller Inc., “Assess fiberoptic
sensors for key power plant measurements,” Power, p. 55,
October, 1990.
Bibliography
1986 Digital Systems Techniques, Instruments and Apparatus, Supplement to ASME Performance Test Codes,
ANSI/ASME PTC 19.22, American National Standards
Institute/American Society of Mechanical Engineers, New
York, New York, 1986.
Manual on the Use of Thermocouples in Temperature
Measurement, ASTM Special Technical Publication 470B,
American Society for Testing and Materials, Philadelphia,
Pennsylvania, 1981.
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The OMEGA Temperature Handbook and Encyclopedia,
Vol. MMV, Fifth Ed., Omega Engineering, Inc., 2004.
Temperature Measurement Designer’s Guide, Thermo
Electric Company Inc., Saddle Brook, New Jersey, 1986.
Also available online at www.thermo-electric-direct.com.
40-25
The Babcock & Wilcox Company
Virtually all areas of a power plant are continually monitored to ensure efficient and reliable daily operation.
40-26
Steam 41 / Pressure, Temperature, Quality and Flow Measurement
The Babcock & Wilcox Company
Chapter 41
Controls for Fossil Fuel-Fired
Steam Generating Plants
Instruments and controls are essential to all steam
generating installations, promoting safe, economic and
reliable operation of the equipment. They range from
the simplest manual devices to complete systems that
automatically control the boiler and all associated
equipment.
Boiler control systems, particularly those applied to
boiler turbine-generator units, are of several types
that perform varied control functions. In the past, the
accepted practice has often been to identify these functions as separate and independent systems, often applied to the boiler by different suppliers. Today, a
power plant control system is most often an integrated
package with demand requirements applied simultaneously to the boiler, turbine and major auxiliary
equipment. This minimizes the number of complex
interactions between subsystems.
Various types of boiler control systems for fossil fuel
boilers include:
1. combustion (fuel and air) control,
2. steam temperature control for superheater and
reheater outlet,
3. drum level and feedwater flow control,
4. burner sequence control and management systems,
5. bypass and startup,
6. systems to integrate all of the above with the turbine and electric generator control,
7. data processing, event recording, trend recording
and display,
8. performance calculation and analysis,
9. alarm annunciation system,
10. management information system, and
11. unit trip system.
An overall integrated control system for a fossil fuelfired drum boiler is described later in this chapter.
Basic control theory
Boiler control is the regulation of the boiler outlet
conditions of steam flow, pressure and temperature to
their desired values. In control terminology, the boiler
outlet steam conditions are called the outputs or controlled variables. The desired values of the outlet conditions are the set points or input demand signals. The
quantities of fuel, air, and water are adjusted to obtain the desired outlet steam conditions and are called
the manipulated or controlled variables.
Disruptive influences on the boiler, both internal
and external, such as fuel heating value variations,
unit load change or change in cycle efficiency, are
called disturbance inputs. The controller or control
system looks at the desired (set points) and actual
(output variables) values of the outlet steam conditions and adjusts the amounts of fuel, air and water
(manipulated variables) to make the outlet conditions
match their desired values. The controller can be
manual, with an operator making the adjustments,
or automatic, with a pneumatic system, electronic
analog computer, or a digital computer making the
adjustments. A block diagram of a conceptual boiler
control system is shown in Fig. 1.
While it is theoretically possible to operate a boiler
with manual control, the operator must maintain a
constant watch for a disturbance. Time is needed for
the boiler to respond to a correction and this can lead
to overcorrection with further upset to the boiler. An
automatic controller, on the other hand, once properly
Fig. 1 Block diagram of conceptual boiler control system.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
41-1
The Babcock & Wilcox Company
tuned will make the proper adjustment quickly to
minimize upsets and will control the system more accurately and reliably.
The various types of automatic control can be illustrated by Fig. 2, which represents the control of one
output variable, steam pressure, in a hypothetical
boiler. The set points for steam pressure and steam flow
will be used as reference values, and the manipulated
variable is the fuel valve position. Disturbance inputs
act on the boiler, which is the system to be controlled.
Open loop control
The simplest control mode is an open loop,
feedforward, or non-feedback control. The manipulated variables of fuel, air and water are adjusted only
from the input demand signals without monitoring the
outlet conditions or output variables. As an example,
Fig. 3 illustrates an open loop control system used to
accomplish the control function illustrated by Fig. 2.
Fig. 3a is a block diagram representing the action to
be taken, which is feedforward only. Fig. 3b is a calibration curve expressing fuel valve position as f(x), a
function of steam flow demand. This curve, established by calibrating or programming the fuel valve
position required to maintain the desired steam flow
with a constant steam pressure, is entered into the controller. The response of this open loop control is fast and
depends only on the accuracy of the calibration curve.
One difficulty with open loop control is that the calibration curve is accurate only as long as the boiler conditions are the same as when the calibration was set.
Another problem is that the output changes as the
load changes on the output signal (the fuel valve in
Fig. 3). For example, a change in friction on the valve
stem will cause a variation in valve position in response to a given input demand signal. This introduces
an error into the performance of the open loop control. Such disadvantages normally outweigh the open
loop advantages of stability and simplicity.
Closed loop control
Usually the process requirements can not be met
by an open loop control, and a closed loop or feedback
control must be used. In closed loop control, the actual output of the system is measured and compared
to the input demand signal with the difference between the two signals (the error signal) used to eliminate this difference.
The open loop system of Fig. 3 could be closed by
having an operator observe the measured steam pres-
Fig. 3 Open loop mode using steam flow demand to vary fuel input.
sure and then manually adjust the fuel valve position
to obtain the fuel flow necessary to maintain the desired steam pressure and flow. To avoid the disadvantages of manual control, an automatic controller can
be provided in a closed loop or feedback system.
Proportional control
The simplest type of closed loop system is proportional control. The manipulated variable or controller
output is proportional to the deviation of the controlled
variable from its desired value. The deviation is called
the error signal. Depending upon controller arrangement, the output signal of a proportional control system will always be either directly or inversely proportional to the controlled variable.
Fig. 4 illustrates the application of proportional control to the control function of Fig. 2. Table 1 explains
symbols in Fig. 4 and subsequent figures. In this system, for every deviation of steam pressure from its set
point, the fuel valve will be moved to a specific position, as shown in Fig. 5, for three values of relative
Fig. 2 Simplified block diagram of a boiler control function.
41-2
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
= Deviation of Controlled
Variable from Set Point
System
K = Proportional Action
Fuel
Valve
Steam
Boiler
Steam
Pressure
Sensor
P
Steam
Pressure
Set Point
Error
Measured Steam Pressure
Fig. 4 Proportional control.
proportional gain. In Fig. 5, the relative proportional
gain could be set so that a pressure error of 10 psi (68
kPa) initiates a 50% change in position of the fuel
valve which in the system calibration would be called
a gain of 1.0. If the control were set to be two or four
times as sensitive, the relative proportional gain would
be said to be 2.0 or 4.0 respectively. In the latter case,
a change of 2.5 psi (17.2 kPa) in steam pressure initiates a 50% change in fuel valve opening.
The response of steam pressure to step increases in
load on the boiler is shown in Fig. 6 for two values of
Table 1
Control Symbols
Fig. 5 Fuel valve opening for various pressure deviations in proportional control system.
proportional gain on the controller. A step increase in
load or steam flow immediately decreases the steam
pressure which, through the proportional controller,
causes the fuel valve to open by a proportional
amount. The additional heat input due to the increased fuel flow causes the steam pressure to return
toward its set point, which in turn reduces the fuel
valve opening.
There may be a certain amount of cycling or searching, depending on the proportional gain of the controller, before the steam pressure stabilizes. It is noted
in Fig. 6 that the steam pressure does not stabilize at
its set point, but is offset to a lower value. A characteristic of proportional only control is that an error or
_ Transmitter / Sensor (PT, LT, FT, etc.)
K
d/dt
T
+
f(x)
f(x)
A
T
A
HS
_
_
_
_
_
_
_
_
_
_
_
Proportional action (gain)
Integral action
Summing action
Difference or subtracting action
Low select auctioneer
High select auctioneer
Derivative (rate)
Averaging
Transfer
Bias action
Operating curves of valves, drives, etc.
_ Final controlling function
_
Manual signal generator
_ Hand / automatic control station
(analog control)
_ Remote hand switch
(digital control)
Fig. 6 Response of steam pressure to step increase of load in a
proportional control system.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
41-3
The Babcock & Wilcox Company
offset is necessary to provide a steady-state fuel valve
opening which will support the desired load, except
for a single load condition.
An increase in the relative proportional gain or sensitivity will reduce the final offset in the steam pressure as shown in Fig. 6. An increase in proportional
gain may increase the time required for the system to
reach a steady-state condition. This offset is always
present with proportional control and, if the gain is
increased even more to reduce the offset, undamped
oscillations will result.
Proportional plus integral control
The offset may be eliminated by adding integral or
reset control to the proportional control system (Fig.
7). The response of the boiler to a step increase in load,
when using a proportional plus integral control system, is shown in Fig. 8. The steam pressure is returned
to its set point without the offset. However, the system may be less stable as it takes a longer period of
time for the steam pressure to stabilize with the offset
completely eliminated.
Integral control, as its name implies, is based on the
repetitive integration of the difference between the
controlled variable and its set point over the time the
deviation occurs. Integral control is also referred to as
reset control because the band of proportional action
is shifted or reset so that the manipulated variable
operates about a new base point.
Proportional plus integral plus derivative control
The stability and response of the system can be improved further by adding a third mode of action called
derivative or rate control. Derivative control action is
a function of the rate of controlled variable change
from its set point, as shown in Fig. 9. The addition of
this control function is shown in Fig. 10. As soon as
the step change is made, the pressure starts to drop
and the proportional mode begins to open the fuel
valve. The derivative mode will also open the fuel
= Deviation of Controlled
Variable from Set Point
System
= Proportional Plus
Integral Action
Fuel
Valve
valve further, as a function of the rate at which the
pressure is changing, anticipating where the valve
should be positioned. When the rate of steam pressure
change decreases, the derivative control has less effect
and the proportional and integral action do the final
valve positioning.
Feedforward/feedback control
In a closed loop system, the controlled variable must
deviate from its set point before the controller initiates
a corrective action. The open loop system therefore has
a faster response because it takes corrective action
before the controlled variable starts to change. When
the open loop or feedforward system is combined with
the closed loop or feedback system, the result is a fast
response system that can compensate for changes in the
calibration curve. Fig. 11 represents a feedforward/feedback control system for the control function of Fig. 2.
As the step change in load occurs, the feedforward
signal immediately positions the fuel valve to meet the
calibration curve requirements. If this curve is exact,
no error develops and the feedback loop has no work
to do. If the calibration curve is in error, the feedback
loop readjusts the fuel valve position to eliminate any
pressure error which may develop due to shifts in the
calibration. However, the response will be faster and
the magnitude of the system upset will be smaller because the feedforward signal moves the valve near its
final steady-state position leaving a smaller range of
action for the feedback loop.
Steam
Boiler
Steam
Pressure
Sensor
Fig. 8 Response of steam pressure to step increase of load in
proportional plus integral control system.
P
Steam
Pressure
Set Point
Error
Measured Steam Pressure
Fig. 7 Proportional plus integral control.
41-4
Fig. 9 Proportional plus integral plus derivative action.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
= Deviation of Controlled
Variable from Set Point
must be done without exceeding the operating limits
of the boiler or turbine-generator.
System
d
dt = Proportional Plus Integral
Plus Derivative Action
Fuel
Valve
Steam
Boiler
Steam
Pressure
Sensor
Steam
Pressure
P
d
dt
Set Point
Error
Measured Steam Pressure
Fig. 10 Proportional plus integral plus derivative control.
Control system design philosophy for a
utility boiler
The effectiveness of a boiler turbine-generator unit,
as a power producing system, depends on how well it
can respond to demands. To achieve optimum response
from the unit while maintaining stable pressure and
temperature, the control system must coordinate the
boiler and turbine. Because the boiler can not produce
rapid changes in steam generation by changes in
throttle pressure, the turbine valves open and close
for initial load response. This initial change permits
the new steam flow requirements to be met at the existing throttle pressure. The control system then acts
to restore the proper amount of stored energy to the
boiler by coordinating the boiler and turbine. This
f(x) = Calibration for
Feedforward Action
Characteristics of different control modes
Boiler-following control This mode of operation is
designed for the boiler response to follow turbine response. Megawatt load control is the responsibility of
the turbine-generator. The boiler is assigned secondary responsibility for throttle pressure control. The
demand for a load change repositions the turbine control valves. Following a load change, the boiler control
modifies the firing rate to reach the new load level and
to restore throttle pressure to its normal operating value.
Load response with this type of system is rapid because the stored energy in the boiler provides the initial change in load. The fast load response is obtained
at the expense of less stable throttle pressure control.
A boiler-following control system is illustrated in Fig. 12.
Turbine-following control In this operating mode,
turbine response follows boiler response. Megawatt
load control is the responsibility of the boiler while the
turbine-generator is assigned secondary responsibility for throttle pressure control. With increased load
demand, the boiler control increases the firing rate
which, in turn, raises throttle pressure. To maintain
a constant throttle pressure, the turbine control valves
open, increasing megawatt output. When a decrease
in load is demanded, this process is reversed. Load
response with this type of system is rather slow because the turbine-generator must wait for the boiler
to change its energy output before repositioning the
turbine control valves to change load. However, this
mode of operation will provide minimal steam pressure
and temperature fluctuation during load change. A
conventional turbine-following control system is
shown in Fig. 13.
Coordinated boiler turbine control While both of the
above systems can provide satisfactory control, each
System
= Summing Action
Fuel
Valve
Steam Flow
Demand
Steam
Pressure
Set Point
Boiler
Steam
Feedforward
f(x)
Steam
Pressure P
Sensor
d
dt
Measured Steam Pressure
Fig. 11 Feedforward/feedback control.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
Fig. 12 Boiler-following control system.
41-5
The Babcock & Wilcox Company
has inherent disadvantages and neither fully exploits
the capabilities of both the boiler and turbine-generator. The turbine-following and boiler-following systems
may be combined into a coordinated control system
giving the advantages of both systems and minimizing the disadvantages. The coordinated boiler turbinegenerator control system is shown in Fig. 14. Megawatt load control and throttle pressure control are the
responsibility of both the boiler and the turbine-generator. One type of a coordinated system assigns the
responsibility of throttle pressure control to the turbinegenerator, taking advantage of the stability of a turbinefollowing system. In addition, the system uses the stored
energy in the boiler, taking advantage of the fast load
response of a boiler-following system.
Because the boiler is not capable of producing rapid
changes in steam generation at constant pressure, the
turbine is used to provide the initial load response.
When a change in load is demanded, the throttle pressure set point is modified using megawatt error (the
difference between the actual load and the load demand), and the turbine control valves respond to the
change in set point to give the new load level quickly.
As the boiler modifies the firing rate to reach the new
load and restore throttle pressure, the throttle pressure set point returns to its normal value. The result
is a fast and efficient production of electric power
through proper coordination of the boiler and turbinegenerator. The response is much faster than the turbine-following system, (Fig. 13). However, it is not as
fast as the boiler-following system because the effect
of megawatt error is limited to maintain a balance
between boiler response and stability. Wider limits
would provide more rapid response while narrower
limits would provide more stability.
A comparison of response characteristics of various
arrangements of a boiler turbine-generator control system
for a large change in load demand is shown in Fig. 15.
Development of the coordinated control system received added impetus when electric power generating
companies introduced the wide area economic load dispatch system. This system requires precise load control. Each controlled unit must produce a specific level
of megawatts and the area load control system adjusts
the turbine control valves until this level is reached.
Even relatively minor interactions between steam flow
and throttle pressure can create a continuous interaction between the boiler, the turbine-generator, and
the area load control. The conventional boiler-following system, which is subject to such interactions between steam flow and throttle pressure, does not lend
itself to area load control because two highly responsive systems would be adversely interacting with each
other.
Wide area economic load dispatch systems require
controlling the boiler and turbine-generator together
in a coordinated system. This achieves automatic control over a wide operating load range.
Integrated boiler turbine-generator control The integrated control system, in its basic form, consists of
ratio controls that monitor pairs of controlled inputs,
including:
Fig. 13 Turbine-following control system.
Fig. 14 Coordinated boiler turbine-generator control system.
41-6
1.
2.
3.
4.
5.
boiler energy input to generator energy output,
superheater spray water flow to feedwater flow,
fuel flow to feedwater flow,
fuel flow to air flow,
recirculated gas to air flow; this, in effect, is a ratio of reheater absorption to absorption in primary
water and steam, and
6. fuel to primary air flow for pulverized coal-fired
units.
Fig. 16 is a simplified diagram showing all system inputs controlled in a parallel relationship by ratio controls.
The integrated control system, shown in Fig. 17,
coordinates the boiler and turbine-generator for fast
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
to variable pressure operation. The system, shown in
Fig. 18, can generate and deliver steam to the turbine
with a wide range of controlled throttle pressure and
temperature to assure the least thermal stress to the
turbine and consequently the most rapid startups.
This system combines the advantages of constant
pressure operation of the boiler with variable pressure
operation of the superheater and turbine. The throttle
pressure is controlled by modulating the superheater
division valves with the drum pressure held at or near
full load pressure. The control strategy and operating
procedure are equivalent to variable throttle pressure
operation with load or steam flow controlled by the
turbine control valves.
Fig. 15 Megawatt load change and throttle pressure deviation.
and efficient response to load demand initiated by the
automatic load dispatch system. See Table 1 for control symbols.
Variable pressure operation
A variable pressure boiler operates with the throttle
pressure varying with load. In its purest form, the
throttle valves on the turbine are left wide open and
throttle pressure varies directly with load. There are
recognized advantages of variable pressure operation
at lower loads. These include minimum change in turbine metal temperature due to the elimination of the
adiabatic throttling effect of turbine valves. Improved
cycle efficiency at reduced loads results from reduced
boiler feed pump power and higher turbine inlet steam
temperatures. However, there are disadvantages including sluggish response to load change demand because of little energy storage during operation. Typically, the load demand change response rate for variable pressure operation is approximately 50% of the
response rate for constant pressure operation.
The Babcock & Wilcox Company (B&W) drum boiler
bypass and startup system adds another dimension
Cycling operation
Most of the fossil fuel-fired drum boilers being installed today will encounter cycling operation. Cycling
involves taking a unit off-line on nights and weekends
and reloading it on weekday mornings.
This analysis of cycling units assumes that the daily
load cycle starts at full load, full temperature operation and passes successively through a load reduction,
an off period and an idle period. This is followed by a
restart and a reloading back to full load, full temperature. The basic difficulty is that steam temperatures
must be controlled to limit cyclic thermal stresses on
the turbine. The boiler lacks capability for temperature control during startup and low load. Therefore,
the turbine requirements and the boiler capability are
not compatible unless an interfacing system is provided. The startup system described above (Fig. 18)
provides this interface.
A more aggressive integrated control strategy is
needed to take full advantage of the boiler turbine system capabilities while recognizing the limitations of each.
The principles applied to such a control system include:
1. The fuel heat content effectively released in the
boiler furnace will establish and maintain the
megawatt output from the unit on a steady-state
basis. Therefore, the only valid boiler load index
for fuel and air input is megawatt demand and/or
generation.
Fig. 16 Simplified diagram of ratio control.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
41-7
The Babcock & Wilcox Company
Maximum and
Minimum Load Limits
Load
Dispatch
System
Megawatt
Load Control
T
A
Maximum Rate
of Change Limit
Unit Load
Master
Unit Frequency
Error
Unit Load Demand
Runbacks
Unit Frequency
Correction
Operational
Limitations
MW Load Demand
Throttle
Pressure
Deviation
Boiler Transient
Correction
MW Error
Boiler Demand
Calibration
T
MW Load Demand
Boiler Master
A
Boiler Demand
Boiler Demand
Anticipating
Signals
Firing Rate
Transient Correction
Air Flow
Demand
Superheated Steam
Temperature Error
Reheat
Temperature
Error
Firing Rate
Demand Calibration
T
Gas
Tempering
Program
Firing Rate Demand
Pressure
Compensated
Drum Level
Feedwater
Flow
Feedwater
Flow
Control
Steam
Feedwater
Flow
Flow Error
Firing Rate
Demand
Limiting
Control
Fuel Flow
Demand
Fuel
Flow
Fuel Flow
Control
Minimum
Air Flow
Air Flow
Demand
Limiting
Control
Temperature
Compensated
Air Flow
Fuel Flow Error
Air Flow
Control
Gas Fan
Ampere Error
f(x)
f(x)
f(x)
Fuel Flow
Control
Forced Draft Fans
Flow Control
Firing Rate Control
Throttle
Pressure
Control
Fuel
Flow
Error
Gas
Recirculation
Flow Control
Air Flow Error
Throttle
Pressure
Set Point
Throttle
Pressure
Total Gas
Recirculation Flow
(Fan Amperes)
Air Flow
Demand
Boiler Feed Pump
Flow Control
Feedwater Flow
(Drum Level) Control
Gas
Recirculation
Program
Oxygen
Error
Air Flow
Demand
Calibration
Boiler
Turbine
Coordination
Control
Minimum
Flow
Minimum
Flow
Firing Rate Demand
Limiting Control
Air
Flow
Error
MW Error
Gas Flow
Distribution
Demand
Calibration
Firing Rate Master
A
Feedwater
Flow Error
Throttle
Pressure
Program
Development
Maximum
Gas Fan
Amperes
f(x)
f(x)
Gas Tempering
Damper
Positioning
Control
Gas Recirculation
Damper
Positioning
Control
f(x)
Throttle
Pressure
Error
T
A
Turbine
Master
f(x)
Gas
Recirculating Fans
Turbine Control
Valves
Gas Flow Distribution Control
Turbine Generator
Control
Fig. 17 Integrated boiler turbine-generator control system.
2. The turbine valve control will control steam flow
and megawatt generation but only on a short term
transient basis.
3. The relationship between steam flow and megawatt generation is not dependent on the turbine
valve position.
Feedwater control systems
Feedwater control regulates the flow of water to a
drum-type boiler to maintain the level in the drum
within the desired limits. The control system will vary
with the type and capacity of the boiler as well as with
load characteristics.
The control strategy of the feedwater control sys41-8
tem can be one of three types. They are classified as
one-, two- or three-element feedwater control systems.
In single element feedwater control (Fig. 19) the
water in the drum is at the desired level when the signal from the level transmitter equals its set point. If a
deviation of water level exists, the controller applies
proportional plus integral action to the difference between the drum level and set point signals to change
the position of the regulating valve. A hand-automatic
station gives the operator complete control over the
valve. A valve positioner can be included in the control valve assembly to match the valve characteristics
to the individual requirements of the system.
Single element control will maintain a constant
drum level for slow changes in load, steam pressure
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
Fig. 18 Superheater bypass and startup system for drum boiler.
or feedwater pressure. However, because the control
signal satisfies the requirements of drum level only,
excessive swell (increase in steam bubble volume due
to an increase in load) or shrink (decrease in steam
bubble volume due to a decrease in load) effects will
result in wider drum level variations and a longer time
for restoring drum level to set points following a load
change with single element control than with two- or
three-element control.
Two-element control comprises a feedforward control loop which utilizes steam-flow measurement to
control feedwater input, with level measurement assuring correct drum level. This control strategy is primarily used in industrial applications and seldom used
in power generating plants.
The most widely used feedwater control system,
especially in the utility industry, is the three-element
feedwater control.
Three-element control is a cascaded-feedforward
control loop which maintains water flow input equal
to feedwater demand. Drum level measurement keeps
the level from changing due to flow meter errors,
blowdown, or other causes.
Fig. 19 Single element feedwater control.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The control applies proportional action to the error
between the drum level signal and its set point. The
sum of the drum level error signal and the steam flow
signal is the feedwater demand signal. This is the output of the summer. The feedwater demand signal is
compared with the water flow input and the difference is the combined output of the controller. Proportional plus integral action is added to provide a
feedwater correction signal for valve regulation or
pump speed control. A hand-automatic station gives
the operator complete control over the valve. In single
boiler turbine units, the turbine first stage shell pressure can be used as a measure of steam flow. The details of this system are illustrated in Fig. 20, using the
symbols given in Table 1.
Three-element feedwater control systems can be
adjusted to restore a predetermined drum level at different loads. In boilers with severely fluctuating loads,
the system can be modified to permit drum water level
to vary with boiler load to compensate for swell and
shrink effects. If the drum level is allowed to vary in
this manner, a nearly constant inventory of water, as
opposed to a constant level, is maintained.
During low load operation (0 to 20%), it is difficult
to obtain steam and water flows accurately because
flow transmitters are usually calibrated for high load
operation. It is advisable to transfer the feedwater control system to single element control. Drum level is the
only variable used in the control scheme. Automatic
transfer as a function of load between three element
and single element control is often provided.
Fig. 20 Three-element cascade feedforward control loop for
feedwater flow control.
41-9
The Babcock & Wilcox Company
Drum water level is one of the most important measurements for safe and reliable boiler operation. If the
level is too high, water can flow into the superheater
with droplets carried into the turbine. This will leave
deposits in the superheater and turbine, and in the
extreme, cause superheater tube failure and turbine
water damage. Consequences of low water level are
even more severe. An insufficient head of water may
cause a reduction in furnace circulation, causing tube
overheating and failure. To provide a more reliable
system B&W recommends the use of three independent drum level transmitters as inputs to an
auctioneered remote level signal system for control,
interlocking, alarming and tripping functions. To provide an additional safeguard, the control logic for
drum level should be independent of the boiler tripping logic. It is also important to install and calibrate
drum level instrumentation with care. Instrumentation to be provided must be in accordance with The
American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code. Minimum drum
water level instrumentation used on utility size power
boilers should be one water gauge glass and two indirect water level indicators with alarm and trip points
clearly marked.
Furnace draft control
The furnace draft control regulates the induced
draft (ID) fans to provide the proper exhausting force
for flue gas flow through the boiler. When the ID fans
are properly balanced with the forced draft (FD) fans,
the furnace pressure will be at the desired operating
level. To improve reliability and meet National Fire
Protection Association NFPA 85 requirements, furnace
pressure is measured with three independent transmitters connected to independent connections. A median select auctioneering system selects the median
or middle of the three transmitter signals for control.
The ID fans are regulated by a feedforward program
based on air flow demand which is then corrected by
any deviation of furnace pressure from its desired set
point. This control strategy must also include furnace
overpressure and implosion protection overrides. The
most common and most dangerous disturbance is furnace implosion.
Furnace implosion is usually the result of a combination of a master fuel trip (flame collapse) and an
equipment malfunction resulting in a vacuum condition in the furnace. The control system must include
two furnace override circuits to minimize any negative pressure excursions. The first is a low furnace
pressure override which will proportionally drive the
inlet dampers or vanes closed when the median furnace pressure signal shows a large negative furnace
pressure excursion. The second is a master fuel trip
(MFT) kicker (or rundown) circuit which will temporarily start driving the ID fan inlet damper or vanes
in the closed direction as soon as a MFT occurs without waiting for a negative furnace excursion to develop. The magnitude of the closing of the ID fan inlet dampers or vanes is dependent on the existing unit
load, as represented by steam flow. These override
circuits are required by NFPA 85 to be downstream of
41-10
the hand/automatic control stations of the ID fans so
that operator action is not permitted. Fig. 21 illustrates
the furnace draft control strategy.
Superheat and reheat temperature control
From the viewpoint of control system designers,
there are inherent advantages to considering boiler
outlet steam temperature control as an independent
temperature control system. A greater understanding
is gained if the temperature control systems are recognized as a system for distributing the boiler heat
input between steam generation, steam superheating
and steam reheating. Starting from that viewpoint,
some of the inherent limitations of boilers to control
temperatures and the difficulties in reaching design
solutions can be identified. For the various methods
of steam temperature control, refer to Chapter 19.
Combustion control systems (air and
fuel flow control)
A combustion control system regulates the fuel and
air input, or firing rate, to the furnace in response to
a load index. The demand for firing rate is, therefore,
a demand for energy input into the system to match
a withdrawal of energy at some point in the cycle. For
boiler operation and control systems, variations in the
boiler outlet steam pressure are often used as an index of an unbalance between fuel-energy input and
energy withdrawal in the output steam.
A great variety of combustion control systems have
been developed over the years to fit the needs of particular applications. Load demands, operating philosophy, plant layout, and types of firing must be considered. The following examples show some of the systems for various types of fuel firing. The control symbols shown in these figures are listed in Table 1.
Oil- and gas-fired boilers Fig. 22 illustrates a system for burning oil and gas, separately or together.
The fuel and air flows are controlled from steam pressure through the boiler master with the fuel readjusted from fuel flow and air flow. The oil or gas header
pressure may be used as an index of fuel flow and the
windbox to furnace differential as an index of air flow
on a per burner basis. Such indices are common for
single burner boilers. For multiple burner boilers, a
pitot tube or other flow measuring instrument is used
to provide more accurate air flow measurement.
Pulverized coal-fired boilers Fig. 23 illustrates a
more sophisticated combustion control that would be
used on larger boilers having several pulverizers.
Each pulverizer supplies a group of burners that are
located in an open or compartmented windbox. Primary and secondary air are admitted and controlled
on a per-pulverizer basis.
To compensate for boiler and pulverizer response
characteristics, a firing rate kicker (derivative action)
is usually required on the pulverizer system. The
boiler firing rate demand is then compared to the total measured fuel flow (summation of all feeders in
service delivering coal) to develop the demand to the
fuel-air master. The fuel-air master demand signal is
then applied in parallel to all operating pulverizers.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
Fig. 21 Furnace draft control.
speed. This overfeed is obtained with present control
systems by the use of kickers on primary air flow and
coal flow developed from a change in pulverizer demand.
Cyclone-fired boilers The CycloneTM boiler (see
Chapter 15) controls shown in Fig. 24 are similar to
those described for pulverized coal-fired units. Although the Cyclone furnace functions as an individual
furnace, the principles of combustion control are the
same.
On multiple Cyclone installations, the feeder drives
are calibrated so that all feeders run at the same speed
for the same master signal. The total air flow is controlled by the velocity damper in each Cyclone furnace
to maintain the proper air/fuel relationship. This air
flow is automatically temperature compensated to
provide the correct amount of air under all boiler loads.
The total air flow to the Cyclone furnace is controlled
by the windbox to furnace differential pressure, which
varies with load to increase or decrease the forced draft
fan output.
Automatic compensation for the number of Cyclone
furnaces in service has been incorporated, along with
an oxygen analyzer. This gas analyzer helps the operator monitor excess air for optimum firing conditions.
Atmospheric pressure fluidized-bed boilers The circulating fluidized bed thermal performance (load,
power consumption, furnace temperature, combustion
efficiency, gaseous emissions) is strongly dependent on
the solids mass or inventory distribution within the system, solids size, and solids flow within and through the
system. (See Chapter 17.) Specific examples of the special role of solids in a circulating fluidized-bed process
include the following:
The individually biased pulverizer demand signal
is then applied in parallel to meet demands for coal
flow, primary air flow, and total pulverizer group air
flow (primary and secondary air flows). When an error develops between demanded and measured primary air flow or total air flow, proportional plus integral action will be applied, adjusting the primary or
secondary air dampers to reduce the error to zero. A
low primary air flow or total air flow cross-limit is applied in the individual pulverizer control. If either
measured primary air flow or total air flow is low relative to coal rate demand, this condition is recognized
in the air flow cross limits in the coal feeder demand
to reduce the demand to that equivalent to the measured air flows. A minimum pulverizer loading limit,
a minimum primary air flow limit, and a minimum
total air flow limit are applied to the respective demands to keep the pulverizers above their minimum
safe operating load. (See Chapter 13.) A minimum load
limit maintains sufficient burner nozzle velocities at
all times, and maintains primary air/fuel and total air/
fuel ratios above prescribed levels.
High capacity vertical shaft pulverizers, such as the
B&W Roll Wheel™ pulverizer (Chapter 13), are being supplied on most large boilers today to achieve the
required steam flow capacities with coal having low
heating values. Pulverizer response can be improved
by overshooting both primary air flow and feeder
Fig. 22 Diagram of combustion control for an oil- and gas-fired boiler.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
41-11
The Babcock & Wilcox Company
Boiler Firing Rate Demand
Feeder Coal
Flow
FT
6. forced draft fan operating point, power consumption
and air flow depend on the furnace solids inventory.
Dynamic
Compensation
From Other
Coal Feeders
Pulverizer
Group Firing
Rate Demand
Total
Fuel Flow
T
Fuel Air
Master
T
Pulverizer
Group
Master
A
To Other
Pulverizer
Groups
A
Secondary Air Flows
FT
Secondary
Air Flow
Demand
Secondary
Air Flow
Control
Air Flow
Cross Limit
FT
Firing Rate
Kicker
Primary
Air Flow
Control system design philosophy for
Universal Pressure (UP ®) once-through boilers
The use of the once-through boiler design in the
United States (U.S.) stems from continuing efforts to
reduce electric power generating costs. The oncethrough boiler can operate at full steam temperature
over a wider load range, and can operate at
supercritical pressures to increase cycle efficiency. The
B&W Universal Pressure UP ® boiler is one type of a
once-through boiler.
The once-through concept can best be visualized as
a single tube as discussed in Chapters 1 and 26. Feed-
FT
Total
Air Flow
Different areas of circulating fluidized-bed process
control are interrelated, with the solids inventory control function playing a central role. The complexity of
process control makes it difficult to analyze and predict system performance for multiple combinations of
the process variables. Additional problems have been
caused by continuous variation of material and energy inputs and widely different speeds of the system
dynamic responses to these variations. Much is to be
learned from operation of commercial and laboratory
circulating fluidized-bed units to define more exactly
the optimal control strategy.
T
A
Bias
To
Secondary
Air Flow Control
Dampers
A
Primary
Air Flow
Demand
Primary
Air Flow
Control
Primary
Air Flow
Cross Limit
FT
Feeder
Control
To
Coal Feeder
Control
Primary
Air Flow
T
A
To
Primary Air
Control Damper
Fig. 23 Diagram of combustion control for a pulverized coal-fired boiler.
1. furnace heat absorption is controlled through
changes in solids inventory,
2. fuel combustion is affected by the solids inventory
distribution in the furnace,
3. solids size strongly affects furnace heat transfer
and inventory distribution, U-beam and multiclone
dust collector efficiencies, solids flow in the system,
and solids losses,
4. carbon conversion efficiency and sorbent consumption depend on amount and distribution of
solid effluents,
5. U-beam collection efficiency depends on the solids level in the particle storage hopper, and
41-12
Fig. 24 Diagram of combustion control for a Cyclone-fired boiler.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
water is pumped into one end, heat is applied along
the length of the tube, and steam flows out of the other
end. The output is a function of the feedwater flow
and the amount of heat supplied. The outlet fluid
enthalpy, or heat content, depends only on the ratio
of heat input to feedwater flow. A valve at the outlet
provides a means of varying the pressure level. When
the pressure level is maintained constant, the outlet
steam temperature is also dependent only on the ratio of heat input to feedwater flow.
At steady-state conditions, feedwater flow equals
steam flow. The pressure level will be influenced by
the valve restriction at the outlet and by the density
of the fluid throughout the system. Therefore, a
change in heat input will influence both pressure and
temperature. It is possible to vary the flow and pressure at the outlet by changing the amount of valve
restriction, or at the inlet by changing both the
feedwater flow and the heat input. It is important to
note that a change in feedwater flow without a corresponding change in the heat input will result in a
change in the outlet steam temperature. During transient conditions, other factions, such as the fluid and
energy storage requirements which change with load,
must be considered because they influence the
feedwater flow and heat inputs.
Combustion guides
With the increase in complexity and automation of
steam generating plants, it is necessary to provide the
operating personnel with information about significant operating events to assist the operator to make
rapid evaluations of the operating situation. The
NPFA 85 Boiler and Combustion Systems Hazards
Code requires that the following information, at a
minimum, be provided to the operating personnel in
a continuous trend display:
1.
2.
3.
4.
5.
6.
7.
8.
Steam flow
Feedwater flow rate
Total fuel flow rate (% of maximum unit load)
Total air flow rate (% of maximum unit load)
Drum level
Final steam temperature
Main steam pressure
Furnace pressure/draft
Excess Air
The level of excess air is one index commonly used
to determine the performance of the unit and to guide
its operation. Excess air is the amount of air supplied
above the theoretical air needed for combustion. (See
Chapter 10.) It is always necessary to supply some excess air to assure complete combustion of the fuel. Any
excess air not used constitutes a loss in boiler efficiency
by exhausting excess heat up the stack.
Steam flow-air flow
The comparison of steam flow to air flow can give
an immediate indication of fuel consumption efficiency.
Because boiler efficiency at a specific load remains
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
essentially constant for a given amount of excess air,
fuel consumption can be determined from steam flow,
which is established by standard flow measuring devices. Steam flow is used as an index of heat absorption. The air flow indication or index can be established by primary elements located on either the air
side or the flue gas side of the unit.
Air flow measurement
From a control standpoint, the preferred location for
air flow measurement is in the clean air duct between
the air heater and the burners. Available air measuring devices are discussed in Chapter 40.
The alternate location for air flow measurement is
on the flue gas side, with connections to measure pressure differences resulting from the flow of combustion
products through a section of the main boiler or air
heater. The products of combustion at a given flue gas
temperature are proportional to the amount of air
supplied; therefore, the flue gas flow can be an index
of air flow.
The measurement of combustion air supplied to a
boiler is made difficult by several factors:
1. The air measuring device is typically of the restrictive type, similar to the primary elements used in
other flow measurements. The resulting
unrestored head loss means added fan power.
2. On large and complicated units it is usually impossible to find one duct through which all of the
combustion air passes. Metering equipment capable of accurately totaling several flows must
then be used.
3. Air density must be considered in both the calibration and operation of any air flow meter. Either
manual or automatic temperature compensation
must be applied to the air flow indication for it to
reflect the mass rate of air flow.
Fuel flow-air flow
The rates of admission of fuel and air flow before
combustion provide an important indication of the fuel
flow to air flow ratio. With reference to NFPA 85, under no circumstances is the air flow demand to be less
than the boiler purge rate and shall not be reduced
below the amount required by the actual fuel inputs.
It is important that the fuel and air flow control subsystem be designed to keep the fuel and air in proper
calibration and enable the operator to adjust the fuelair ratio within a span consistent with the fuel being fired.
Fuel flow measurement
The measurement of gaseous fuels must consider
the physical properties of the gas, particularly temperature, pressure and specific gravity. Where widely
changing properties are encountered, automatic compensation should be used. A primary element installed
in the main header will produce a differential pressure to actuate the recording. On less complex installations, particularly those with single burners, the
pressure at the burner can be used to indicate flow.
With liquid fuels, various types of flow meters can
be installed directly in the supply header to indicate
41-13
The Babcock & Wilcox Company
and record fuel flow. As with gaseous fuels, oil-header
pressure can be used to indicate flow.
The measurement of solid fuel flow can be accomplished through weight scales or feeder speeds. The
use of mass flow, however, is more accurate. The feeder
can be calibrated in units of fuel flow per feeder revolution to produce a continuous flow rate. Gravimetric
feeders (see Chapter 12) provide controlled weight
flow rates to the pulverizers.
Gas analysis
Gas analyzers are used to determine correct fuelair relationships. Representative flue gas samples are
continuously analyzed either chemically or electronically to record the oxygen and combustibles present
in the products of combustion. Because there is direct
correlation between oxygen content in the flue gas
and the quantity of excess air supplied to the combustion zone, the operator receives a continuous and direct reading of combustion efficiency. The indicated or
recorded oxygen signal is used in adjusting the total
air flow.
Comparison of combustion guides
Each combustion guide has its particular merits;
none is infallible. The advantages of one may be used
to overcome the disadvantages of another.
The fuel flow to air flow ratio index will illustrate
how the control system proportions fuel and air continuously during severe load swings. Because coal has
wide variations in fuel heating value and moisture
content, the coal flow as measured by the feeders only
provides an approximation of the fuel flow to the
boiler. When the fuel heating value changes, the calibration of the correct fuel-air relationship also
changes. Therefore, to maintain a given excess air, the
proportions of air and fuel must be corrected. To compensate for this, the energy per unit mass can be calculated using the boiler as a calorimeter.
On major load changes, the steam flow to air flow
is temporarily unbalanced because of the overfiring
and underfiring necessary for responsive load change.
The fuel consumption is normally higher or lower than
indicated by the steam flow load index. This guide is
also affected by changing feedwater or steam temperatures, because a variation of either temperature demands more or less transfer of heat per unit of steam
produced at the specified pressure and temperature.
These deviations are inherently minimized where
megawatt generation is used as the index of heat absorption. It is necessary, when substantial changes
may occur in steam or feedwater temperature, to provide manual or automatic compensation to the steam
flow-air flow circulation.
A gas analyzer gives true excess air determinations.
There is some delay because combustion must be completed before a representative sample can be obtained.
If the sample is taken near the combustion zone, this
delay is not usually significant. Considerable study
may be needed to locate sample points that will give
correct average excess air values. The dirty, hot, and
corrosive conditions of the flue gases at these points
make periodic maintenance necessary for continuous,
41-14
dependable sampling. The gas analyzer is an accurate index for feedback control.
Burner management systems
Burner management systems (BMS) are applied to
all boilers to prevent continued operation during hazardous furnace conditions, and to assist the operator
in starting and stopping burners and fuel equipment.
The most important burner control function is to
prevent furnace or pulverizer explosions which could
threaten the safety of operating personnel and damage the boiler and auxiliary equipment. The control
system must also prevent damage to burners and fuel
equipment from maloperation while avoiding false
trips of fuel equipment when a truly unsafe condition
does not exist.
Other important factors in the design of the burner
management system are the method and location to
be used in the startup, shutdown, operation and control of the fuel equipment. These factors must be understood before purchase, design, or application of a
burner control system. The minimum requirements
for a burner management system are specified in NFPA
85, Boiler and Combustion Systems Hazard Code.
The different categories of burner control are summarized below.
Supervised manual control
Supervised manual control (Fig. 25) is a system in
which a trained operator has primary responsibility
to operate the burner equipment at the burner platform. Checks on the existing conditions are dependent
on observation and evaluation by the local operator.
However, this system must include certain interlocks
for preventing improper operator action, certain safety
trips and flame detection. Good communication between the local operator and the control room is needed
to coordinate the startup and shutdown of burner
equipment. Supervised manual controls may be found
on older boilers but are not permitted by NFPA 85 to
be used on new boilers.
Remote manual sequence control
Illustrated in Fig. 26, this system represents a major improvement over manual control, permitting remote manual operation using instrumentation systems
and position indications in the control room for intelligence. This system requires various burner
permissives (prequalifying conditions), interlocks, and
trips to account for the position of fuel valves and air
registers in addition to main flame detection. With this
system, the operator participates in the operation of
the fuel equipment. Each sequence of the burner operating procedure is controlled from the control room
and no steps are taken except by operator command.
Automatic sequence control
The next logical step (Fig. 27) is to automate the
sequence control to permit startup of burner equipment from a single pushbutton or switch control. Automation, then, replaces the operator in controlling the
operating sequences. Because the operator initiates
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
Main Fuel Valve
Air Register
Main Flame
Detector
Impeller
Main
Flame
Lighter Flame
Detector
Lighter Fuel
Valve
Ignition
Pushbutton and Timer
Air
Fig. 25 Fuel burner supervised manual control.
Fig. 27 Automatic sequence control.
the start command, it is expected that the operator
participates in, or at least monitors each step of the
operating sequence as indicated by signal lights and
instrumentation signals, as the startup process proceeds to completion with the fuel utilization unit in
service on automatic control. This type of system is the
most common system applied to gas, oil, and coal burning systems.
ing flexibility is to allow operator participation at two
or more levels. Increased flexibility is also obtained by
the careful grouping of equipment so that a fault anywhere in the system will affect a limited amount of
equipment. An example of this is the grouping of burners on a pulverizer so that the failure of a piece of hardware on a burner will only affect the failed burner,
and not the pulverizer and its remaining burners.
Fig. 29 illustrates the provision for manual intervention in a fuel management type system. In this figure, functions are detailed at four levels of a pulverizer/burner group control. Manual intervention is provided at level 2 to permit remote manual operation
with interlock protection features.
Fuel management
A degree of fuel system automation can be achieved
that will permit fuel equipment to be placed in service
without operator supervision (Fig. 28). A fuel management system can be applied that will recognize the
level of fuel demand to the boiler. This system will
know the operating range of the fuel equipment in
service, will reach a decision concerning the need for
starting up or shutting down the next increment of
fuel equipment, and will select the next increment
based on the firing pattern of burners in service. Such
demands for the startup or shutdown of fuel preparation and burning equipment can be initiated by the
management system without the immediate knowledge of the operator.
The degree of operating flexibility allowed with a
burner control system is closely related to the degree
of operator participation. A higher level of automation
reduces the flexibility of the operator in handling situations where a piece of equipment fails to perform as
expected. One method used to provide more operat-
Fig. 26 Remote manual sequence control.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
Flame detection
One of the most important items required for a
burner management system is individual burner
flame detection, regardless of fuel.
Ultraviolet (UV) flame detectors have been successfully applied to natural gas-fired burners due to the
abundance of ultraviolet radiation produced by the
combustion of the hydrogen in natural gas. Flicker or
infrared detectors are better suited for coal- or oil-fired
burners. A flicker detector uses the high frequency
dynamic flickering of the primary combustion process.
An infrared detector uses the infrared radiation produced in the primary combustion of the flame.
The proper location of the flame detectors on a
burner is dependent on many factors, including
Fig. 28 Fuel management.
41-15
The Babcock & Wilcox Company
Burner Group
Boiler
Idle Air
Register
Management
To Each
Burner
Group
Level 4
Pulverizer
Burner
Group
Management
Furnace Purge
and Permissive
To Each
Burner
Group
Management
Interface
HS
HS
HS
Level 3
Maintained
Lighters
Start and Stop
Sequences
Idle Air
Registers
Manual
Interface
HS
To Each
Burner
Group
HS
HS
HS
HS
Feeder
Permissive
Coal Valve
Permissive
HS
Impeller
Permissive
Air Register
Permissive
Close
On
Lighter
Permissive
Primary Air Off
Permissive
Pulverizer Off
Permissive
Close
Off
To Boiler
Interlock
HS
Lighter
Trip
Level 2
Lighter
Control
Primary Air
Trip
Primary Air
Control
Pulverizer
Trip
Pulverizer
Control
Feeder
Control
Close
Close
Feeder
Trip
Coal Valve
Control
Burner
Trip
Impeller
Control
Air Register
Control
To Level 1 (Equipment Operators)
Fig. 29 Pulverizer/ burner group control.
burner management system design. It should, therefore, be determined by the boiler manufacturer in conjunction with the BMS manufacturer as an integral
part of the control system design.
Flame monitoring devices in current use are designed for on/off operation based on the presence or
absence of flame. Although the basic detector units
provide a variable analog output signal which can be
read on a meter, there is no direct claim to an established relationship between this relative output signal and the flame quality. Therefore, the analog signals should never be relied upon as flame quality indicators. They should be used only to provide helpful
information for initial setup adjustments and continuous on-line observance.
Some power plants use closed circuit television for
continuous furnace observation by the operator from
the control room.
Classification of lighters/ igniters
The combustion of solid, liquid and gaseous fuels is
hazardous because upset conditions may lead to an
air-fuel mixture that could cause furnace explosion.
These hazardous conditions are especially prevalent
during startup and shutdown of the boiler. Therefore,
it is important to have reliable instrumentation, well
41-16
designed safety interlocks, and clear understanding
of operating sequences by the operator. However, a
reliable and noninterruptible ignition source is probably the single most important factor. The National
Fire Protection Association (NFPA) provides guidelines
on the application of igniters. The following definitions
are extracted from the NFPA 85 Boiler and Combustion Systems Hazards Code.
Class 1 Igniter. An igniter that is applied to ignite
the fuel input through the burner and to support ignition under any burner lightoff or operating conditions. Its location and capacity are such that it will
provide sufficient ignition energy, generally in excess
of 10% of full load burner input, at its associated
burner to raise any credible combination of burner
inputs of both fuel and air above the minimum ignition temperature.
Class 2 Igniter. An igniter that is applied to ignite
the fuel input through the burner under prescribed
lightoff conditions. It is also used to support ignition
under low load or certain adverse operating conditions. The range of capacity of such igniters is generally 4 to 10% of full load burner fuel input.
Class 3 Igniter. A small igniter applied particularly
to gas and oil burners to ignite the fuel input to the
burner under prescribed lightoff conditions. The caSteam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
pacity of such igniters generally does not exceed 4%
of the full load burner fuel input.
Class 3 Special Igniter. A special Class 3 high energy electrical igniter capable of directly igniting the
main burner fuel.
Failure mode analysis
NFPA 85 states that the burner management system must be totally independent of all other control
systems. Therefore, the control system designer must
consider carefully every aspect of the operation and
equipment limitations. A great number of failure
modes must be analyzed and addressed. Due to space
limitation, the following are only a few of the issues:
1. The typical safe way to implement the master fuel
trip (MFT) in the burner management system is
de-energize to trip the equipment. As the description indicates, a circuit should be energized continuously. De-energizing of the circuit represents
an abnormal condition. Therefore, the equipment
must be removed from service. For an energize to
trip system, in the event of specific power failure,
the equipment can not be stopped.
2. Redundancy of control hardware may be necessary or desirable in many areas. However, too
many backups may render the system too cumbersome for practical use.
3. System design must not prevent the operator from
shutting down any equipment desired. The system will function to complement the operator’s action so that he or she will not generate a hazardous operating condition.
Flue gas inlet temperature
Economizer outlet and bypass dampers are modulated to maintain a minimum allowable flue gas temperature at the SCR inlet. This prevents the formation of ammonium bisulfate upstream of the catalyst.
This salt can mask the catalyst pores and cause a loss
of activity. The gas temperature demand is developed
as a function of boiler load. This gas temperature demand signal is compared to a measured SCR system
inlet temperature. The resulting error signal is conditioned by the firing rate demand to generate the demand for the economizer flue gas dampers (Fig. 31).
SO2 emissions control
Various sulfur dioxide (SO2) control strategies and
technologies are discussed in Chapters 32 and 35. The
following focuses on the main control loops associated
with wet and dry scrubbing technologies.
Wet scrubbers
The wet scrubbing process typically includes reagent preparation, absorber area, primary dewatering, and secondary dewatering systems. Sulfur dioxide laden flue gas is contacted with a sorbent liquid which
saturates the flue gas and produces a wet byproduct.
Sulfur dioxide removal is accomplished by a countercurrent spray absorption process within the absorber.
By spraying limestone slurry into the flue gas, the sul-
Post-combustion NOx emissions control
Various nitrogen oxides (NOx) control technologies
are discussed in Chapters 32 and 34. The following
focuses on the control strategy associated with postcombustion selective catalytic reduction (SCR) technology. The B&W SCR NOx removal system is a dry
process in which ammonia (NH3) is used as a reducing agent, and the NOx contained in the flue gas is
reduced to N2 and H2O.
As explained in Chapter 34, ammonia (anhydrous
or aqueous) is injected into the flue gas upstream of
the SCR reactor, through an injection grid. The grid
is designed to ensure an even NH3 distribution and
allow for fine tuning of ammonia distribution. The flue
gas then passes to the reactor and through the catalyst layers. As this occurs the inlet flue gas is constantly
monitored to ensure that the NOx is being reduced to an
acceptable level without overspraying ammonia.
There are two primary control loops for an SCR system: ammonia flow and flue gas inlet temperature.
Ammonia flow control
Ammonia flow demand is calculated based primarily on flue gas flow and the outlet NOx deviation from
set point. This demand signal is limited on anhydrous
systems to ensure that the ammonia to dilution air ratio is always below the hazardous buildup limit of ammonia in the system. If this ratio exceeds the limit, the
ammonia block valve is interlocked to close (Fig. 30).
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
Outlet NOX
Flue Gas Flow
AT
FT
Calculated
Demand
A
NOX
Set Point
Ammonia Flow
FT
T
A
Ammonia / Dilution
Air Ratio
f(x)
Ammonia Flow
Control
Fig. 30 SCR ammonia flow control.
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The Babcock & Wilcox Company
SCR Inlet Temperature
TE
TE
1
2
Unit Load
Demand
TE
FX
...n
f(x)
d
dt
Firing Rate
Demand
X
f(x)
f(x)
T
T
A
A
V
Minimum Position
Rate Limiter
f(x)
f(x)
Economizer Bypass
Damper
Economizer Outlet
Damper
Fig. 31 SCR temperature control.
fur dioxide is converted to hydrates of calcium sulfite
(CaSO3⋅H2O) and calcium sulfate (CaSO4⋅H2O).
As the hot flue gas enters the absorber, the flue gas
is quenched to saturation by the recycle slurry
sprayed from the first absorber spray level, and the
initial removal of sulfur dioxide occurs. The flue gas
then passes upward through the perforated absorber
tray which uniformly distributes the flue gas and recycle slurry from the second and third absorber spray
levels across the absorber cross-sectional area. The
flue gas then passes through the absorber spray zone
above the tray where recycle slurry is sprayed downward, countercurrent to the flue gas flow, from the
second and third absorber spray levels, completing the
SO2 removal process.
The flue gas then flows upward to the first stage
mist eliminator located near the top of the absorber.
The first stage mist eliminator is a three pass vertical
chevron, designed to collect carryover (mist) by inertial
contact. Above and below the mist eliminators are a series of headers with nozzles that spray fresh or blended
water onto the first stage mist eliminators. This removes
any solids that have collected on the upstream and downstream faces of the chevrons. After passing through the
first stage mist eliminator, the flue gas enters the second stage mist eliminator where the process is repeated.
The flue gas then exits the absorber module.
41-18
The recycle slurry and the mist eliminator wash
water pass down through the absorber and are collected in the lower section of the absorber module,
referred to as the absorber reaction tank. Fresh limestone slurry is added to control the pH, and reclaim
water is added to control the recycle slurry density. Side
agitators keep the recycle slurry solids in suspension.
There are three critical control loops associated with
the wet scrubber: pH, density, and reaction tank level.
pH control The recycle slurry pH is controlled by
adding fresh limestone slurry to the absorber. The
amount added is a function of expected boiler load and
SO2 loading as shown in Fig. 32. Due to the large volume of slurry in the reaction tank, a change in flue
gas flow or flue gas SO2 concentration will not show
up as a change in recycle slurry pH until after a relatively long delay. To compensate for this delay,
feedforward signals from flue gas SO2 concentration
and boiler load are used to adjust the demand for fresh
limestone slurry feed (Fig. 32).
Level control Absorber level control compares the
level measurement of the absorber reaction tank to an
operator-adjusted set point. Proportional plus integral
action is applied to any error signal. The resultant demand signal positions the reclaim water control valve
(Fig. 33). A level measurement greater than the set point
will decrease reclaim water flow, while a level measurement less than set point will increase reclaim water flow.
Density control The absorber reaction tank density
Unit Load
Demand
Boiler Exit
Flue Gas SO2
Absorber
Recycle
Slurry pH
No.1
FY
AT
AT
Absorber
Recycle
Slurry pH
No.2
AT
T
A
H L
K
Operator
Select
No.1 or No.2
Deviation
Alarm
T
H L
High Alarm
Low Alarm
Set
Point
K
T
A
f(x)
Absorber Limestone Slurry
Feed Control Valve
Fig. 32 Absorber slurry feed control.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
is affected by the balance between water addition
(fresh limestone slurry, mist eliminator wash, level
control) and water removal (evaporation by the flue
gas, slurry removal during dewatering). The balance
between water removal and water addition, in conjunction with the increase in the density of the solids
(as the fresh limestone reacts with absorbed SO2),
causes the absorber reaction tank density to rise. When
the density reaches a high set point, the density control loop begins the dewatering process (removing solids). Once the density has reached a low set point, the
slurry is recirculated back to the absorber reaction
tank, thus completing the density control cycle.
Dry scrubbers
A dry scrubber is commonly referred to as a spray
dryer absorber (SDA) module. Boiler flue gas exiting
the air heater is directed to the SDA module which
includes a rotary atomizer unit. Atomizer feed slurry,
a mixture of hydrated lime slurry and recycle ash
slurry, is supplied to the atomizer at a controlled rate
and atomized within the SDA module into a cloud of
extremely fine mist. Heat from the flue gas evaporates
the moisture in the slurry cloud while the alkaline
slurry simultaneously absorbs the SO2 contained in
the flue gas. The result is the conversion of the calcium hydroxide slurry component into a fine powder
of calcium/sulfur compounds, and the lowering of flue
gas temperature. The ratio of fresh lime slurry to recycle ash slurry is controlled to maintain the required
alkalinity in the atomizer feed slurry, to achieve the
desired level of SO2 removal. The feed slurry to the
atomizer is controlled to maintain the desired degree
of evaporative cooling in the module. Module outlet
flue gas temperature is regulated by the atomizer feed
slurry control valve to be above the adiabatic satura-
tion temperature (dew point), to ensure the spray-dried
calcium/sulfur product remains dry and free flowing.
SO2 control The reagent preparation system provides a mixture of hydrated lime slurry and recycle
ash slurry to the atomizer head tank to obtain the
desired feed slurry blend for proper SO2 absorption.
The atomizer head tank lime slurry feed flow control
valve regulates the flow of lime slurry to the atomizer
head tank to maintain the required percent SO2 removal and/or stack SO2 concentration. The basic design of this control loop is illustrated in Fig. 34.
Developments in instrumentation
and controls
Power plant automation
Many power plants today are essentially automatic
when operating between one third and full load using the conventional systems discussed earlier in this
chapter. To achieve complete automation of a plant, it
is first necessary to add control subloops for the auxiliaries which were previously considered to be the exclusive responsibility of the operator. All of these
subloops must then be integrated through unit management control to provide complete plant automation.
Fig. 35 shows the arrangement of such a control system.
The basic concept of full automation is to provide
the maximum amount of control and monitoring at the
lowest possible level. The organization of the different levels, as shown in Fig. 36 for a fossil fuel plant,
is summarized as follows:
Slurry Flow to
SDA Atomizer
Head Tank
Stack SO2
FT
SDA Inlet SO2
AT
AT
Absorber
Reaction Tank
Level
SO2
Removal
Set Point
LT
X
H L
A
High Alarm
Low Alarm
Set Point
T
A
A
T
A
f(x)
f(x)
Reclaim Water Feed
to Reaction Tank
Control Valve
Lime Slurry to
Atomizer Head Tank
Control Valve
Fig. 33 Absorber reaction tank level control.
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
Fig. 34 Spray dryer absorber control loop.
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The Babcock & Wilcox Company
Level 1 – equipment hardware being controlled
Level 2 – internal control of the individual equipment items or group of functionally identical items of equipment always operated
in parallel
Level 3 – coordination of the sequence of actions
and interlocking with respect to more
than one equipment group
Level 4 – modulation and sequencing of major cycle
components involving the entire unit
Level 5 – generation of the major load demand signals to coordinate the operation of the
overall plant
Advantages obtained with the hierarchical control
concept include self-regulation of equipment groups.
This allows the equipment group to protect itself
through low level interlocking, which provides greater
reliability and control decentralization and permits
continued plant operation with some portions of the
control system out of service.
Some of the advantages of overall unit automation
are:
1. Improved protection of personnel and equipment
through more complete instrumentation, simplified information display, and more extensive and
thorough supervisory control.
2. Reduced outages, reduced maintenance, and
longer equipment life through more uniform and
complete control procedures of startup, on-line
operation, and shutdown.
3. Better plant efficiency through continuous and
automatic adjustments to the controls to optimize
plant operation.
4. More efficient use of personnel during startup and
on-line operation.
The trend of boiler automation is clear and its future scope can be predicted with considerable confidence. The achievement of some goals will be difficult.
There are operating problems to be solved, traditions
to be overcome, and new philosophies and approaches
to be accepted. Reliable and adequate equipment is
already available and its application, through the cooperation of manufacturers and users, will make the
automatic power plant a reality.
Human factor engineering
Until the 1990s, most control rooms were designed
with only one thing in mind, i.e., how to group the indicators, recorders, and operator stations within reach
and sight of an operator who stands in front of the
panel and operates the unit. With a state-of-the-art
control room, the operators are surrounded by display
screens and keyboards, which make human factor
engineering a very important part of the design. (See
chapter frontispiece.) It will affect the physical well
being of operators as well as his or her ability to operate the unit effectively. The following are just a few
examples of why human factor engineering is important.
1. With microprocessor and computer based distributed control systems, the amount of information
available to the operator has increased dramatically. The system has to be designed so that important information is presented and instantly
understood by the operator. For example, an alarm
list that is not recognized properly will cause a
great deal of confusion. On the other hand, several levels of alarms using different color codes will
help the operator make correct decisions.
2. To be able to read display screens for long periods
of time, lighting in the control room must be designed to avoid eye strain of the operators.
3. Furnishings to accommodate display screens and
keyboards to maximize operator alertness must be
provided.
Smart transmitters
In the past, a transmitter was used to measure pressure, temperature, and flow (differential pressure)
from remote locations. A signal representing the calibrated value of that measurement was sent to the control system located in or near the central control room.
The signal was then conditioned to provide a usable
Fig. 35 Composite of automation components.
41-20
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
Fig. 36 Multi-level approach to power plant operation.
signal to the control system, indicator, or recorder. The
smart transmitters available today can condition the
signal locally – for example, square root extraction to
convert differential pressure to flow and temperature
compensation for flow measurements. The smart
transmitter can also provide remote configuration,
reranging, rezeroing, calibration and diagnostics features to provide direct access to the field device from
the control room, virtually eliminating periodic maintenance visits to the instruments.
Installation and service requirements
It is important to make certain that instrumentation and control equipment are properly installed and
serviced. Supervision of installation and the required
calibration adjustments should be performed by qualified and experienced personnel. Adequate time to tune
the controls should be provided during initial boiler
operation.
Maintenance can be performed by trained plant personnel. The personnel who will be responsible for this
maintenance should be available to observe and assist the control manufacturer’s representatives in the
installation and calibration of the control system. Most
control manufacturers offer training programs to fa-
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
miliarize customer personnel with the control equipment. A planned program of preventive maintenance
should be developed for the control system.
Performance monitoring
The continuing growth in size and complexity of
units has added importance to the frequent analysis
of performance. Many operating companies are analyzing their performance evaluation programs and developing monitoring techniques that make possible the
detection of malfunctions before substantial losses
have occurred.
A number of performance evaluation procedures are
practiced today. In some power companies, the performance of each unit is checked periodically by extensive heat rate tests. Techniques and procedures for
performing such evaluations are covered under the
ASME Performance Test Codes.
The computer is also being used to conduct on-line
performance calculations periodically, hourly and daily
in most systems. This information can be compared
with expected performance data stored in the computer and any deviation recorded for future correction. This could be especially useful for monitoring and
controlling emissions.
41-21
The Babcock & Wilcox Company
Typical utility power plant control console.
41-22
Steam 41 / Controls for Fossil Fuel-Fired Steam Generating Plants
The Babcock & Wilcox Company
Chapter 42
Water and Steam Chemistry,
Deposits and Corrosion
Steam generation and use involve thermal and
physical processes of heat transfer, fluid flow, evaporation, and condensation. However, steam and water
are not chemically inert physical media. Pure water
dissociates to form low concentrations of hydrogen and
hydroxide ions, H + and OH−, and both water and
steam dissolve some amount of each material that they
contact. They also chemically react with materials to
form oxides, hydroxides, hydrates, and hydrogen. As
temperatures and velocities of water and steam vary,
materials may dissolve in some areas and redeposit in
others. Such changes are especially prevalent where
water evaporates to form steam or steam condenses
back to water, but they also occur where the only
change is temperature, pressure, or velocity. In addition, chemical impurities in water and steam can form
harmful deposits and facilitate dissolution (corrosion)
of boiler structural materials. Therefore, to protect
vessels, tubing, and other components used to contain
and control these working fluids, water and steam
chemistry must be controlled.
Water used in boilers must be purified and treated
to inhibit scale formation, corrosion, and impurity contamination of steam. Two general approaches are used
to optimize boiler water chemistry. First, impurities in
the water are minimized by purification of makeup
water, condensate polishing, deaeration and
blowdown. Second, chemicals are added to control pH,
electrochemical potential, and oxygen concentration.
Chemicals may also be added to otherwise inhibit scale
formation and corrosion. Proper water chemistry control improves boiler efficiency and reduces maintenance and component replacement costs. It also improves performance and life of heat exchangers,
pumps, turbines, and piping throughout the steam
generation, use, and condensation cycle.
The primary goals of boiler water chemistry treatment and control are acceptable steam purity and
acceptably low corrosion and deposition rates. In addition to customized boiler-specific guidelines and procedures, qualified operators are essential to achieving
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
these goals, and vigilance is required to detect early
signs of chemistry upsets. Operators responsible for
plant cycle chemistry must understand boiler water
chemistry guidelines and how they are derived and
customized. They must also understand how water
impurities, treatment chemicals, and boiler components
interact. Training must therefore be an integral, ongoing part of operations and should include management,
control room operators, chemists, and laboratory staff.
General water chemistry control limits and guidelines
have been developed and issued by various groups of
boiler owners and operators (e.g., ASME,1,2,3 EPRI4 and
VGB5 ), water treatment specialists6,7,8 utilities and industries. Also, manufacturers provide recommended
chemistry control limits for each boiler and for other
major cycle components. However, optimum water and
steam chemistry limits for specific boilers, turbines, and
other cycle components depend on equipment design
and materials of construction for the combination of
equipment employed. Hence, for each boiler system,
boiler-specific water chemistry limits and treatment
practices must be developed and tailored to changing
conditions by competent specialists familiar with the
specific boiler and its operating environment.
Chemistry-boiler interactions
To understand how water impurities, treatment
chemicals and boiler components interact, one must
first understand boiler circuitry, and steam generation
and separation processes.
Boiler feed pumps provide feedwater pressure and
flow for the boiler. From the pumps, feedwater often
passes through external heaters and then through an
economizer where it is further heated before entering
the boiler. In a natural circulation drum-type unit,
boiling occurs within steel tubes through which a
water-steam mixture rises to a steam drum. Devices
in the drum separate steam from water, and steam
leaves through connections at the top of the drum.
This steam is replaced by feedwater which is supplied
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The Babcock & Wilcox Company
by the feedwater pumps and injected into the drum
just above the downcomers through a feedwater pipe
where it mixes with recirculating boiler water which
has been separated from steam. By way of downcomers, the water then flows back through the furnace
and boiler tubes. Boiler water refers to the concentrated water circulating within the drum and steam
generation circuits. Chapters 1 and 5 provide detailed
descriptions of steam generation and boiler circulation.
Boiler feedwater always contains some dissolved
solids, and evaporation of water leaves these dissolved
impurities behind to concentrate in the steam generation circuits. If the concentration process is not limited, these solids can cause excessive deposition and
corrosion within the boiler and excessive impurity
carryover with the steam. To avoid this, some concentrated boiler water is discarded to drain by way of a
blowdown line. Because the boiler water is concentrated, a little blowdown eliminates a large amount
of the dissolved solids. Since steam carries very little
dissolved solids from the boiler, dissolved and suspended solids entering in the feedwater concentrate
in the boiler water until the solids removed in the
blowdown (boiler water concentration times the
blowdown rate lb/h or kg/s) equal the solids carried in
with the feedwater (lb/h or kg/s).
A small amount of dissolved solids is carried from
the drum by moisture (water) droplets with the steam.
Because moisture separation from steam depends on
the difference between their densities, moisture separation is less efficient at high pressures where there
is less difference between the densities. Therefore, to
attain the same steam purity at a higher pressure, the
dissolved solids concentration in boiler water must
generally be lower.
In a drum boiler, the amount of steam generated is
small compared to the amount of water circulating
through the boiler. However, circulation is also largely
driven by the difference in densities between the two
fluids, so as pressure increases the ratio of water flow
to steam flow decreases. At 200 psi (1379 kPa), water
flow through the boiler must be on the order of 25,000
pph (3 kg/s) to produce just 1000 pounds per hour of
steam. Even at 2700 psi (18.6 MPa), 2500 to 4000 pounds
of water circulates to produce 1000 pounds of steam. By
contrast, most or all of the water entering a once-through
boiler is converted to steam without recirculation.
Some boiler operators have asked why boiler water concentrations change so slowly once a source of
contamination is eliminated and the continuous
blowdown rate is increased. How quickly can excess
chemical be purged from a boiler? How much impurity or additive is needed to upset boiler water chemistry? How quickly do chemical additions circulate
through the boiler? To answer these questions and
explore some other chemistry-boiler interactions, consider for example a typical 450 MW natural circulation boiler, generating 3,000,000 pounds of steam per
hour. It has a room temperature water capacity of
240,000 pounds and an operating water capacity of
115,000 pounds. The furnace wall area is 33,000
square feet, about 5800 of which are in the maximum
heat flux burner zone.
42-2
Impurities purge slowly from the boiler because the
boiler volume is large compared to the blowdown rate.
For example, at maximum steaming capacity with a
blowdown rate 0.3% of the steam flow from the drum,
17 hours may be required to decrease the boiler water concentration of a non-volatile impurity by 50%.
Almost two hours are required to effect a 50% reduction in the boiler water concentration even at a
blowdown rate of 3%. Without blowdown, dissolved
sodium with a fractional carryover factor of 0.1%
would have a half life of 52 hours. While long periods
of time are generally required to purge impurities,
mixing within the boiler is rapid. For the boiler being
used as an example, the internal recycle rate is about
one boiler volume per minute, and steam is generated
at a rate of one boiler volume every 5 minutes.
The rate of steam generation is such that replacement feedwater must be essentially free of hardness
minerals and oxides that deposit in the boiler. For
example, feedwater carrying only 1 ppm of hardness
minerals and oxides could deposit up to 25,000 lb
(11,340 kg) per year of solids in the boiler, so the boiler
might require chemical cleaning as often as 3 or 4 times
per year. Also, small chemical additions have a large
effect on boiler water chemistry. For example, addition of 0.2 lb (0.09 kg) of sodium hydroxide to the
boiler water increases the sodium concentration by 1
ppm, which can significantly affect the boiler water
chemistry. Similarly, a small amount of chemical hideout can have a large effect on boiler water concentration. Hideout or hideout return of only 0.01 gram per
square foot (0.1 g/m2 ) in the burner zone can change
the boiler water concentration by 1 ppm.
Control of deposition, corrosion, and
steam purity
The potential for deposition and corrosion is inherent to boilers and increases with boiler operating pressure and temperature. Evaporation of water concentrates boiler water impurities and solid treatment
chemicals at the heat transfer surfaces. During the
normal nucleate boiling process in boiler tubes, small
bubbles form on tube walls and are immediately swept
away by the upward flow of water. As steam forms,
dissolved solids in the boiler water concentrate along
the tube wall. Additionally, the boundary layer of
water along the wall is slightly superheated, and
many dissolved minerals are less soluble at higher temperatures (common phenomenon referred to as inverse
temperature solubility). Both of these factors favor
deposition of solids left behind by the evolution of
steam in high heat flux areas, as illustrated in Fig. 1.
These deposits in turn provide a sheltered environment which can further increase chemical concentrations and deposition rates. In a relatively clean boiler
tube, concentration of chemicals at the tube surface
is limited by the free exchange of fluid between the
surface and boiler water flowing through the tube.
Wick boiling as illustrated in Fig. 2 generally produces
sufficient flow within the deposits to limit the degree
of concentration. However, as heavy deposits as illus-
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
Fig. 1 Three years of operation resulted in light deposits because of
good water treatment. The upper right figure is the heated side, and
the lower right figure is the unheated side.
trated in Fig. 3 accumulate, they restrict flow to the
surface. Some boiler water chemicals concentrate on
tube walls during periods of high load and then return to the boiler water when the load is reduced. This
is termed hideout and hideout return. This can greatly
complicate efforts to control boiler water chemistry.
Typical boiler deposits are largely hardness precipitates and metal oxides. Hardness, easily precipitated
minerals (mainly calcium and magnesium), enters the
cycle as impurities in makeup water and in cooling
water from condenser leaks. Metal oxides are largely
Fig. 2 Schematic of the wick boiling mechanism (adapted from
Reference 9).
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
from corrosion of pre-boiler cycle components. Scaling
occurs when these minerals and oxides precipitate and
adhere to boiler internal surfaces where they impede
heat transfer. The result can be overheating of tubes,
followed by failure and equipment damage. Deposits
also increase circuitry pressure drop, especially detrimental in once-through boilers. Effective feedwater
and boiler water purification and chemical treatment
minimizes deposition by minimizing feedwater hardness and by minimizing corrosion and associated iron
pickup from the condensate and feedwater systems. Also,
phosphate and other water treatment chemicals are used
in drum boilers to impede the formation of particularly
adherent and low thermal conductivity deposits.
Some chemicals become corrosive as they concentrate. Corrosion can occur even in a clean boiler, but
the likelihood of substantial corrosion is much greater
beneath thick porous deposits that facilitate the concentration process. Concentration at the base of deposits can be more than 1000 times higher than that in
the boiler water and the temperature at the base of these
deposits can substantially exceed the saturation temperature. Hence, as deposits accumulate, control of
boiler water chemistry to avoid the formation of corrosive concentrates becomes increasingly important. Since
chemistry upsets do occur, operation of a boiler with
excessively thick deposits should be avoided.
Because local concentration of boiler water impurities and treatment chemicals is inherent to steam generation, water chemistries must be controlled so the
concentrates are not corrosive. On-line corrosion is
often caused by concentration of sodium hydroxide,
concentration of caustic-forming salts such as sodium
carbonate, or concentration of acid-forming salts such
as magnesium chloride or sulfate.10 Effective feedwater and boiler water treatment minimizes corrosion
by minimizing ingress of these impurities and by add-
Fig. 3 An example of internal deposits resulting from poor boiler
water treatment. These deposits, besides hindering heat transfer,
allowed boiler water salts to concentrate, causing corrosion.
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The Babcock & Wilcox Company
ing treatment chemicals (such as trisodium phosphate)
that buffer against acid or caustic formation. However,
corrosion and excessive precipitation can also be caused
by improper use of buffering agents and other treatment chemicals. For example, underfeeding or overfeeding of treatment chemicals, out-of-specification sodiumto-phosphate ratios, or out-of-specification free-chelant
concentrations can cause corrosion.
Dissolved carbon dioxide and oxygen can also be
corrosive and must be eliminated from feedwater.
Carbon dioxide from air in-leakage and from decomposition of carbonates and organic compounds tends
to acidify feedwater and steam condensate. Oxygen
is especially corrosive because it facilitates oxidation of
iron, copper, and other metals to form soluble metal ions.
At higher temperatures, oxygen is less soluble in water
and the rate of chemical reaction is increased. As boiler
feedwater is heated, oxygen is driven out of solution and
rapidly corrodes heat transfer surfaces. The combination
of oxygen and residual chloride is especially corrosive,
as is the combination of oxygen and free chelant.
Carryover of impurities from boiler water to steam
is also inherent to boiler operation. Though separation
devices remove most water droplets carried by steam,
some residual droplets containing small amounts of dissolved solids always carry through with the steam. Also,
at higher pressures, there is some vaporous carryover.
Excessive impurities can damage superheaters, steam
turbines, or downstream process equipment.
Boiler feedwater
To maintain boiler integrity and performance and
to provide steam of suitable turbine or process purity,
boiler feedwater must be purified and chemically conditioned. The amount and nature of feedwater impurities that can be accommodated depend on boiler operating pressure, boiler design, steam purity requirements, type of boiler water internal treatment,
blowdown rate, and whether the feedwater is used for
steam attemperation. Feedwater chemistry parameters to be controlled include dissolved solids, pH, dissolved oxygen, hardness, suspended solids, total organic carbon (TOC), oil, chlorides, sulfides, alkalinity,
and acid or base forming tendencies.
At a minimum, boiler feedwater must be softened
water for low pressure boilers and demineralized water for high pressure boilers. It must be free of oxygen and essentially free of hardness constituents and
suspended solids. Recommended feedwater limits are
shown in Table 1. Use of high-purity feedwater minimizes blowdown requirements and minimizes the potential for carryover, deposition, and corrosion problems throughout the steam-water cycle.
Operation within these guidelines does not by itself
ensure trouble-free operation. Some feedwater contaminants such as calcium, magnesium, organics, and carbonates can be problematic at concentrations below the
detection limits of analytical methods commonly used
Table 1
Recommended Feedwater Limits
Once-Through
Boilers
Drum Boilers
Oxygen
Pressure,
psig (MPa)
with AVT*
AVT
Treatment
15 to 300
(0.10 to 2.07)
301 to 600
(2.08 to 4.14)
601 to 900
(4.14 to 6.21)
901 to 1000
(6.21 to 6.90)
1001 to 1500
(6.90 to 10.34)
>1500
(>10.34)
All
All
All
pH, all ferrous
heaters
9.3 to 10.0
9.3 to 10.0
9.3 to 10.0
9.3 to 9.6
9.3 to 9.6
9.3 to 9.6
9.3 to 9.6
9.3 to 9.6
8.0 to 8.5
pH, copperbearing heaters
8.8 to 9.2
8.8 to 9.2
8.8 to 9.2
8.8 to 9.2
8.8 to 9.2
8.8 to 9.2
8.8 to 9.2** 8.8 to 9.2
Total hardness,
as ppm CaCO3,
maximum
0.3
0.2
0.1
0.05
0.003
0.003
0.003
0.003
0.001
0.007
0.007
0.007
0.007
0.007
0.007
0.007
0.007
0.030 to 0.150
Iron, ppm
maximum
0.1
0.04
0.02
0.02
0.01
0.01
0.01
0.010
0.005
Copper, ppm
maximum
0.05
0.02
0.01
0.01
0.005
0.002
0.005
0.002
0.001
Organic, ppm
TOC max.
1.0
1.0
0.5
0.2
0.2
0.2
0.2
0.200
0.200
Cation conductivity,
µS/cm max.
0.5
0.2
0.2
0.15
0.15
Oxygen, ppm
maximum***
N/A
* All volatile treatment.
** AVT not recommended for copper-bearing cycles and associated low feedwater pH where the drum pressure is less than 400 psig.
*** By mechanical deaeration before chemical scavenging of residual.
Note:
ppm = mg/kg
42-4
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
for industrial boilers. Also, operators must be sensitive
to changes in feedwater chemistry and boiler operating conditions, and must adapt accordingly.
Makeup water
Boiler feedwater is generally a mix of returned
steam condensate and fresh makeup water. For utility boilers, most of the steam is usually returned as
condensate, and only 1 to 2% makeup is necessary.
However, for some industrial cycles, there is little or
no returned condensate, so as much as 100% makeup
may be necessary.
Chemistry requirements for makeup water depend
on the amount and quality of returned steam condensate. Where a large portion of the feedwater is uncontaminated condensate, makeup water can generally
be of lesser purity so long as the mixture of condensate and makeup meet boiler feedwater requirements.
The feedwater concentration for each chemical species is the weighted average of the feedwater and
makeup water concentrations:
Feedwater concentration = (condensate concentration × flow
(1)
+ makeup concentration × makeup flow) / total feedwater flow
The selection of equipment for purification of
makeup water must consider the water chemistry requirements, raw water composition, and quantity of
makeup required. All natural waters contain dissolved
and suspended matter. The type and amount of impurities vary with the source, such as lake, river, well
or rain, and with the location of the source. Major dissolved chemical species in source water include sodium,
calcium, and magnesium positive ions (cations) as well
as bicarbonate, carbonate, sulfate, chloride, and silicate
negative ions (anions). Organics are also abundant.
The first steps in water purification are coagulation
and filtration of suspended materials. Natural settling
in still water removes relatively coarse suspended solids. Required settling time depends on specific gravity, shape and size of particles, and currents within
the settling basin. Settling and filtration can be expedited by coagulation (use of chemicals to cause agglomeration of small particles to form larger ones that
settle more rapidly). Typical coagulation chemicals are
alum and iron sulfate. Following coagulation and settling, water is normally passed through filters. The
water is chlorinated to kill micro-organisms, then activated charcoal filters may be used to remove the final traces of organics and excess chlorine.
Subsequently, various processes may be used to
remove dissolved scale-forming constituents (hardness
minerals) from the water. For some low pressure boilers, removal of hardness minerals and scale-forming
minerals is adequate. For other boilers, the concentration of all dissolved solids must be reduced or nearly
eliminated. For low pressure boilers, the capital and
operating cost for removal must be weighed against
costs associated with residual dissolved solids and
hardness. These include increased costs for boiler water
treatment, more frequent chemical cleaning of the
boiler, and possibly higher rates of boiler repair. Demineralized water nearly free of all dissolved solids is
recommended for higher pressure boilers and espeSteam 41 / Water and Steam Chemistry, Deposits and Corrosion
cially for all boilers operating at pressures greater than
1000 psi (6.9 MPa).
Sodium cycle softening, often called sodium zeolite
softening, replaces easily precipitated hardness minerals with sodium salts, which remain in solution as
water is heated and concentrated. The major hardness
ions are calcium and magnesium. However, zeolite ionexchange softening also removes dissolved iron, manganese, and other divalent and trivalent cations. Sodium held by a bed of organic resin is exchanged for
calcium and magnesium ions dissolved in the water.
The process continues until the sodium ions in the resin
are depleted and the resin can no longer absorb calcium and magnesium efficiently. The depleted resin
is then regenerated by washing it with a high concentration sodium chloride solution. At the high sodium concentrations of this regeneration solution, the
calcium and magnesium are displaced by sodium.
Variations of the process, in combination with chemical pre-treatments and post-treatments, can substantially reduce hardness concentrations and can often
reduce silica and carbonate concentrations.
For higher pressure boilers, evaporative or more
complete ion-exchange demineralization of makeup
water is recommended. Any of several processes may
be used. Evaporative distillation forms a vapor which
is recondensed as purified water. Ion exchange demineralization replaces cations (sodium, calcium, and
magnesium in solution) with hydrogen ions and replaces anions (bicarbonate, sulfate, chloride, and silicate) with hydroxide ions. For makeup water treatment, two tanks are normally used in series in a cation-anion sequence. The anion resin is usually regenerated with a solution of sodium hydroxide, and the
cation resin is regenerated with hydrochloric or sulfuric acid. Reverse osmosis purifies water by forcing it
through a semi-permeable membrane or a series of
such membranes. It is increasingly used to reduce total
dissolved solids (TDS) in steam cycle makeup water.
Where complete removal of hardness is necessary,
reverse osmosis may be followed by a mixed-bed demineralizer. Mixed-bed demineralization uses simultaneous cation and anion exchange to remove residual
impurities left by reverse osmosis, evaporator, or twobed ion exchange systems. Mixed-bed demineralizers
are also used for polishing (removing impurities from)
returned steam condensate. Before regenerating
mixed-bed demineralizers, the anion and cation resins must be hydraulically separated. Caustic and
acids used for regeneration of demineralizers
and other water purification and treatment
chemicals present serious safety, health, and
environmental concerns. Material Safety Data
Sheets must be obtained for each chemical and
appropriate precautions for handling and use
must be formulated and followed.
Dissolved organic contaminants (carbon-based
molecules) are problematic in that they are often detrimental to boilers but are not necessarily removed by
deionization or evaporative distillation. Organic contamination of feedwater can cause boiler corrosion,
furnace wall tube overheating, drum level instability,
carryover, superheater tube failures, and turbine cor42-5
The Babcock & Wilcox Company
rosion. The degree to which any of these difficulties
occurs depends on the concentration and nature of the
organic contaminant. Removal of organics may require activated carbon filters or other auxiliary purification equipment.
Returned condensate – condensate polishing
For many boilers, a large fraction of the feedwater
is returned condensate. Condensate has been purified
by prior evaporation, so uncontaminated condensate
does not generally require purification. Makeup water can be mixed directly with the condensate to form
boiler feedwater.
In some cases, however, steam condensate is contaminated by corrosion products or by in-leakage of
cooling water. Where returned condensate is contaminated to the extent that it no longer meets feedwater
purity requirements, mixed-bed ion-exchange purification systems are commonly used to remove the dissolved impurities and filter out suspended solids. Such
demineralization is referred to as condensate polishing. This is essential for satisfactory operation of oncethrough utility boilers, for which feedwater purity
requirements are especially stringent. While high
pressure drum boilers can operate satisfactorily without condensate polishing, many utilities recognize the
benefits in high pressure plants. These benefits include
shorter unit startup time, protection from condenser
leakage impurities, and longer intervals between acid
cleanings. Condensate polishing is recommended for
all boilers operating with all volatile treatment (AVT)
and is essential for all boilers operating with all volatile treatment and seawater cooled condensers. Provisions for polishing vary from adequate capacity for
100% polishing of all returned condensate to polishing only a portion of the condensate. However, all must
be adequate to meet feedwater requirements under
all anticipated load and operating conditions.
Most of the pressure vessels that contain ion exchange resins have under-drain systems and downstream traps or strainers to prevent leakage of ion
exchange resins into the cycle water. These resins can
form harmful decomposition products if allowed to
enter the high temperature portions of the cycle. Unfortunately, the under-drain systems and the traps
and strainers are not designed to retain resin fragments that result from resin bead fracture. Also, the
resin traps and strainers can fail, resulting in resin
bursts. Resin intrusion can be minimized by controlling flow transients, reducing the strainer’s screen
size, increasing flow gradually during vessel cut-in,
and returning the polisher vessel effluent to the condenser during the first few minutes of cut-in.
Feedwater pH control
Boiler feedwater pH is monitored at the condensate
pump discharge and at the economizer inlet. When
the pH is below the required minimum value, ammonium hydroxide or an alternate alkalizer is added.
Chemicals for pH control are added either downstream
of the condensate polishers or at the condensate pump
discharge for plants without polishers. For high purity demineralized feedwater, ammonium hydroxide
42-6
injection pumps or alternative feedwater pH control
is achieved using a feedback signal from a specific conductivity monitor. Conductivity provides a good measure of ammonium hydroxide concentration, and automated conductivity measurement is more reliable
than automated pH measurement. Also, the linear
rather than logarithmic relationship of conductivity
to ammonia concentration gives better control. Fig. 4
shows the relationship between ammonium concentration, pH, and conductivity of demineralized water.
While an equilibrium concentration of ammonium
hydroxide remains in the boiler water, much of the
ammonium hydroxide added to feedwater volatilizes
with the steam. Conversely, the solubility of ammonium hydroxide is such that little ammonia is lost by
deaeration. Hence, returned condensate often has a
substantial concentration of ammonium hydroxide
before further addition.
Common alternative pH control agents include neutralizing amines, such as cyclohexylamine and
morpholine. For high pressure utility boilers with superheaters, the more complex amines are thermally
unstable and the decomposition products can be problematic.
Deaeration and chemical oxygen scavengers
Oxygen and carbon dioxide enter the cycle with undeaerated makeup water, with cooling water which
Fig. 4 Approximate relationship between conductivity and pH for
ammonia solutions in demineralized water.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
leaks into the condenser, and as air leaking into the
vacuum portion of the cycle.
For turbine cycles, aeration of the feedwater is initially limited by use of air ejectors to remove air from
the condenser. Utility industry standard practice is to
limit total air in-leakage to less than one standard
cubic foot of air per minute per 100 MW of generating capacity (approximately 0.027 Nm3/100 MW), as
measured at the condenser air ejectors. Final removal
of oxygen and other dissolved gases adequate for boiler
feedwater applications is generally accomplished by
thermal deaeration of the water ahead of the boiler
feed pumps. Thermal deaeration is accomplished by
heating water to reduce gas solubility. Gases are then
carried away by a counter flow of steam. The process
is typically facilitated by the use of nozzles and trays
which disperse water droplets to increase the steamto-water interfacial area. Thermal deaeration can reduce feedwater oxygen concentration to less than 7
parts per billion (ppb). It also essentially eliminates
dissolved carbon dioxide, nitrogen, and argon.
Chemical agents are generally used to scavenge residual oxygen not removed by thermal deaeration. Traditional oxygen scavengers have been sodium sulfite for
low pressure boilers and hydrazine for high pressure
boilers. Sulfite must not be used where the boiler pressure is greater than 900 psig (6.2 MPa). Other oxygen
scavengers (erythorbic acid, diethylhydroxylamine, hydroquinone and carbohydrazide) are also used. Hydrazine has been identified as a carcinogen and this has
increased the use of alternative scavengers. Scavengers
are generally fed at the exit of the condensate polishing
system and/or at the boiler feed pump suction.
Attemperation water
Water spray attemperation is used to control steam
temperature. Attemperation for utility boilers is discussed in the Steam temperature adjustment and control section of Chapter 19, Boilers, Superheaters and
Reheaters. The spray water is feedwater, polished feedwater, or steam condensate. As the spray water evaporates, all chemicals and contaminants in the water
remain in the steam. This addition must not be excessive. It must not form deposits in the attemperator
piping, and it must not excessively contaminate the
steam. If a superheated steam purity limit is imposed,
the steam purity after attemperation must not exceed
this limit. To meet this requirement, the weighted
average of the spray water total solids concentration
and the saturated steam total solids concentration
must not exceed the final steam total solids limit. Additionally, spray water attemperation must not increase the steam total solids concentration by more
than 0.040 ppm. Independent of other considerations,
the spray water solids concentration must never exceed 2.5 ppm. Ideally, the purity of attemperation
water should equal the desired purity of the steam.
Drum boilers and internal boiler water
Boiler water that recirculates in drum and steam
generation circuits has a relatively high concentration
of dissolved solids that have been left behind by wa-
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
ter evaporation. Water chemistry must be carefully
controlled to assure that this concentrate does not
precipitate solids or cause corrosion within the boiler
circuitry. Boiler water chemistry must also be controlled
to prevent excessive carryover of impurities or chemicals with the steam.
Customized chemistry limits and treatment practices must be established for each boiler. These limits
depend on steam purity requirements, feedwater
chemistry, and boiler design. They also depend on
boiler owner/operator preferences regarding economic
tradeoffs between feedwater purification, blowdown
rate, frequency of chemical cleaning, and boiler maintenance and repair. Direct boiler water treatment
(usually referred to as internal treatment) practices
commonly used to control boiler water chemistry include all volatile treatment, coordinated phosphate
treatments, high-alkalinity phosphate treatments,
and high-alkalinity chelant and polymer treatments.
In all cases, when treatment chemicals are mixed, the
identity and purity of chemicals must be verified and
water of hydration in the weight of chemicals must
be taken into account. The specific treatment used
must always be developed and managed by competent water chemistry specialists.
Feedwater is the primary source of solids that concentrate in boiler water, and feedwater purity defines
the practical limit below which the boiler water solids
concentration can not be reduced with an acceptable
blowdown rate. Additionally, hardness and pre-boiler
corrosion products carried by the feedwater play major roles in defining the type of boiler water treatment
that must be employed. Where substantial hardness
is present in feedwater, provision must be made to
ensure that the hardness constituents remain in solution in the boiler water or to otherwise minimize the
formation of adherent deposits. This is often accomplished by use of chelant, polymer, or high-alkalinity
phosphate boiler water treatment. Where substantial
hardness is not present, boiler water treatment can be
optimized to minimize impurity carryover in the steam
and to minimize the potential for boiler tube corrosion.
Because boiler water impurities and treatment
chemicals carry over in the steam, steam purity requirements play a major role in defining boiler water
chemistry limits. Boiler specifications normally include
a list of boiler-specific water chemistry limits that must
be imposed to attain a specified steam purity. Limits
must always be placed on the maximum dissolved
solids concentration. Limits must also be placed on
impurities and conditions that cause foaming at the
steam-water interface in the drum. These include limits on oil and other organic contaminants, suspended
solids, and alkalinity. The carryover factor is the ratio
of an impurity or chemical species in the steam to that
in the boiler water.
Blowdown
The dissolved solids concentration of boiler water
is intermittently or continuously reduced by blowing
down some of the boiler water and replacing it with
feedwater. Blowdown rate is generally expressed as a
percent relative to the steam flow rate from the drum.
42-7
The Babcock & Wilcox Company
Traditional all volatile treatment
For all volatile treatment (AVT), no solid chemicals
are added to the boiler or pre-boiler cycle. Boiler water chemistry control is by boiler feedwater treatment
only. No chemical additions are made directly to the
drum. Feedwater pH is controlled with ammonia or
an alternate amine. Because ammonia carries away
preferentially with the steam, the boiler water pH may
be slightly lower (0.2 to 0.4 pH units) than the feedwater pH. For traditional all volatile treatment, as opposed to oxygen treatment, hydrazine or a suitable
alternate is added to scavenge residual oxygen. Table
1 shows the recommended AVT feedwater control limits. Because all volatile treatment adds no solids to the
boiler water, solids carryover is generally minimized.
All volatile treatment provides no chemical control
for hardness deposition and provides no buffer against
caustic or acid-forming impurities. Hence, feedwater
must contain no hardness minerals from condenser
leakage or other sources. It must be high-purity condensate or polished condensate with mixed-bed quality demineralized makeup water.
All volatile treatment can be, but rarely is, used
below 1000 psig (6.9 MPa). Normally it is used only
for boilers operating at or above 2000 psig (13.8 MPa)
drum pressure. It is not recommended for lower pressure boilers where other options are feasible. While
all volatile treatment is one of several options for drum
boilers, it is the only option for once-through boilers.
Oxygen treatment
Even in the absence of dissolved oxygen, steel surfaces react with water to form some soluble Fe ++ ions
which may deposit in the boiler, superheater, turbine,
or other downstream components. However, in the absence of impurities, oxygen can form an especially protective Fe +++ iron oxide that is less soluble than that
formed under oxygen-free conditions. To take advantage
of this, some copper-free boiler cycles operating with ultra pure feedwater maintain a controlled concentration
of oxygen in the feedwater. Most of these are high pressure once-through utility boilers, but this approach is also
used successfully in some drum boilers.
Oxygen treatment was developed in Europe, largely
by Vereinigung der Grosskesselbetreiber (VGB),11 and
there is also extensive experience in the former So42-8
viet Union (FSU). It can only be used where there is
no copper in the pre-boiler components beyond the
condensate polisher, and where feedwater is consistently of the highest purity, e.g., cation conductivity
< 0.15 µS/cm at 77F (25C). A low concentration of oxygen is added to the condensate. The target oxygen concentration is 0.050 to 0.150 ppm for once-through
boilers and 0.040 ppm for drum boilers. With oxygen
treatment, the feedwater pH can be reduced, e.g.,
down to 8.0 to 8.5. An advantage of oxygen treatment
is decreased chemical cleaning frequencies for the
boiler. In addition, when oxygen treatment is used in
combination with lower pH, the condensate polisher
regeneration frequency is reduced.
Coordinated phosphate treatment
Coordinated phosphate-pH treatment, introduced
by Whirl and Purcell of the Duquesne Light Company,12 controls boiler water alkalinity with mixtures
of disodium and trisodium phosphate added to the
drum through a chemical feed pipe. The objective of
this treatment is largely to keep the pH of boiler water and underdeposit boiler water concentrates within
an acceptable range. Fig. 5 indicates the phosphate
concentration range that is generally necessary and
sufficient for this purpose. Phosphate treatment must
not be used where the drum pressure exceeds 2800
psig (19.3 MPa). All volatile treatment is recommended
at the higher pressures.
In sodium phosphate solutions, an H+ + PO4≡ →
HPO4= balance buffers the pH (i.e., retards H+ ion concentration changes). Solution pH depends on the
phosphate concentration and the molar sodium-tophosphate ratio. The relationship between pH, phosphate concentration, and molar sodium-to-phosphate
ratio is shown in Fig. 6. Where solutions contain other
dissolved salts (e.g., sodium and potassium chloride
and sulfate), sodium phosphate can still be used to control pH, and the curves of Fig. 6 are still applicable.
However, for such solutions, the sodium-to-phosphate
ratio labels on these curves are only apparent values
with reference to pure sodium phosphate solutions.
Measured sodium concentrations can not be used in
calculating sodium-to-phosphate ratios for control of
100
Phosphate, ppm
Blowdown is accomplished through a pressure letdown
valve and flash tank. Heat loss is often minimized by
use of a regenerative heat exchanger.
The ratio of the concentration of a feedwater impurity in the boiler water to its concentration in the
feedwater is the concentration factor, which can be estimated by use of Equation 1. However, a more complex formula must be used where there is substantial
carryover.
If there is no blowdown, solids concentrate until
carryover with the steam is sufficient to carry away
all of the solids that enter the boiler with the feedwater. For example, where the feedwater silica concentration is 0.01 ppm and 10% of the silica in the
boiler water carries over with the steam, the equilibrium boiler water silica concentration is 0.1 ppm.
10
1
1
10
100
1000
10000
Dissolved Solids, ppm
Fig. 5 Phosphate concentrations to control boiler water chemistry
(little or no residual hardness in the feedwater). Indicates phosphate
range at a given dissolved solids concentration.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
11
10.5
pH
Na/PO4 = 3.0 + 1ppm NaOH
Na/PO4 = 3.0
10
Na/PO4 = 2.8
Na/PO4 = 2.6
Na/PO4 = 2.4
9.5
9
1
10
Phosphate, ppm
100
Fig. 6 Estimated pH of sodium phosphate solutions. Note: pH values
can differ by up to 0.2 pH units, depending on the choice of chemical
equilibrium constants used, but more often agree within 0.05 pH units.
boiler water pH because measured sodium concentrations include non-phosphate sodium salts. While dissolved sodium chloride and sulfate do not alter boiler
water pH, ammonia does alter the pH. Hence, the
presence of ammonia must be taken into account
where ammonia concentrations are significant compared to phosphate concentrations.
Historically, the initial goal of coordinated pH-phosphate control was to keep the effective molar sodiumto-phosphate ratio just below 3, to prevent caustic stress
corrosion cracking, acid corrosion, and hydrogen damage. This proved to be an effective method for control
of deposition and corrosion in many boilers. However,
caustic gouging of furnace wall tubes occurred in some
boilers using coordinated pH-phosphate control, and
laboratory tests indicated that solutions with molar
sodium-to-phosphate ratios greater than about 2.85 can
become caustic when highly concentrated. Subsequently, many boilers were operated under congruent
control with a target effective sodium-to-phosphate
ratio of less than 2.85, generally about 2.6, and often
less than 2.6. Again, this proved to be an effective
method of control for many boilers, but some of the
boilers operating with low molar sodium-to-phosphate
ratios experienced acid phosphate corrosion. Instances
of boiler tube corrosion generally occurred in boilers that
experienced substantial phosphate hideout and hideout-return when the boiler load changed.
Phosphate hideout, hideout-return, and associated
corrosion problems are now addressed by equilibrium
phosphate treatment.13 The concentration of phosphate
in the boiler water is kept low enough to avoid hideout and hideout return associated with load changes,
thus it is always in equilibrium with the boiler. The
effective molar sodium-to-phosphate ratio is kept
above 2.8. The free hydroxide, as depicted in Fig. 6,
is not to exceed the equivalent of 1 ppm sodium hydroxide. Concern about caustic gouging at the higher
ratios is largely reduced by experience with this treat-
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
ment regime and by experience with caustic boiler
water treatment.
Tables 2 and 3 show recommended boiler water
chemistry limits. Customized limits for a specific boiler
depend on the steam purity requirements for the
boiler. Boiler and laboratory experience indicate that,
under some conditions, phosphate-magnetite interactions can degrade protective oxide scale and corrode
the underlying metal. To minimize these interactions,
the pH must be greater than that corresponding to the
2.6 sodium-to-phosphate ratio curve of Fig. 6, and
preferably greater than that corresponding to the 2.8
curve. The pH must always be above the 2.8 curve
when the drum pressure is above 2600 psig (17.9
MPa). The maximum pH is that of trisodium phosphate plus 1 ppm sodium hydroxide. Additionally, the
boiler water pH is not to be less than 9 nor greater
than 10. As discussed below, it may be necessary to
reduce the maximum boiler water phosphate concentration to avoid hideout and hideout return, and to
avoid associated control and corrosion problems.
Table 2
Boiler Water Limits
Pressure
Range,
psig (MPa)
Maximum
TDS, ppm
Maximum
Suspended
Solids, ppm
Maximum
Silica, ppm
15 to 50*
(0.10 to 0.35)
1250
15
30
15 to 50**
(0.10 to 0.35)
3500
15
150
51 to 325
(0.35 to 2.24)
3500
10
150
326 to 450
(2.25 to 3.10)
3000
8
90
451 to 600
(3.11 to 4.14)
2500
6
40
601 to 750
(4.14 to 5.17)
2000
4
30
751 to 900
(5.18 to 6.21)
1500
2
20
901 to 1000
(6.21 to 6.90)
1250
1
8
* For natural separation with no diffuser baffles in the
steam drum.
** Where the drum includes baffles that separate water
droplets from steam.
Notes:
1. Operation outside the limits defined in this table is not
recommended. Within these broad limits, more restrictive
limits must be imposed, consistent with the type of boiler
water treatment method chosen to control deposition,
corrosion, and carryover. For example, the boiler water pH
range of 8.5 to 9.0 is only acceptable with all volatile
treatment (AVT).
2. ppm = mg/kg
42-9
The Babcock & Wilcox Company
Table 3
Boiler Water Limits for Coordinated Phosphate Boiler Water Treatment
Pressure, psig (MPa)
15 to 1000
(0.10 to 6.90)
Maximum
TDS, ppm
Maximum
sodium, ppm
Maximum
silica, ppm
Defined by Table 2 or as
necessary to attain required
steam purity, whichever is less
1001 to 1500
(6.90 to 10.34)
1501 to 2600
(10.35 to 17.93)
100 ppm or as necessary to 50 ppm or as necessary to
attain required steam
attain required steam
purity, whichever is less
purity, whichever is less
2601 to 2800
(17.93 to 19.31)
15 ppm or as necessary to
attain required steam
purity, whichever is less
Maximum sodium concentration (if any) as necessary to attain required steam purity
Defined by Table 2 or as
necessary to attain required
steam purity, whichever is less
2 ppm or as necessary to
attain required steam
purity, whichever is less
0.5 ppm or as necessary to
attain required steam
purity, whichever is less
0.1 ppm or as necessary to
attain required steam
purity, whichever is less.
Phosphate as
PO4, ppm
See Fig. 5
"Effective"
Na/PO4
molar ratio
2.6 to 3.0
2.6 to 3.0 + 1 ppm NaOH
2.6 to 3.0 + 1 ppm NaOH
2.8 to 3.0 + 1 ppm NaOH
pH
See Figs. 6 and 7
9.4 to 10.5 and as dictated
by Figs. 6 and 7
9.0 to 10.0 and as dictated
by Figs. 6 and 7
9.0 to 10.0 and as dictated
by Figs. 6 and 7
Maximum
specific conductivity, µS/cm
Twice the maximum TDS (ppm).
Note:
ppm = mg/kg
Phosphate treatment chemicals may hide out during periods of high-load operation, then return to the
boiler water when the load and pressure are reduced.
This type of hideout makes control of boiler water
chemistry difficult and can cause corrosion of furnace
wall tubes. This hideout and return phenomena is
caused by concentration of phosphate at the tube/
water interface in high heat flux areas. In these areas, phosphates accumulate in the concentrated liquid. The concentrated phosphates then precipitate, or
they adsorb on or react with surface deposits and
scale.13,14,15 Where excessive deposits are not present,
this hideout and hideout return associated with load
and pressure changes can be eliminated by decreasing the phosphate concentration in the boiler water
or possibly by increasing the sodium-to-phosphate
ratio. Where hideout and hideout-return are caused
by excessive deposits, the boiler must be chemically
cleaned. The amount of phosphate hideout or return
accompanying load changes must not be more than 5
ppm. Corrective action is necessary if the amount of
phosphate hideout or return accompanying load
changes is more than 5 ppm and/or the boiler water
pH change is more than 0.2 pH units, or where there
are changes in the hideout/hideout-return behavior.
This phenomenon must be distinguished from loss of
phosphate to passive film formation. As the passive oxide film reforms following a chemical cleaning of the
boiler, some phosphate is irreversibly lost from the boiler
water. This is minimized if chemical cleaning is followed
by a phosphate boilout repassivation of the boiler.
Operators should not over-correct for deviations of
42-10
pH and phosphate concentration from target values.
Corrective action must be taken with an understanding of system response times, the amounts of impurities being neutralized, and the amount of treatment
chemicals likely to be required.
Where phosphate treatment is used, pH is an especially critical parameter, so the accuracy of pH measuring devices and temperature corrections must be
assured. The boiler water pH must also be corrected
to discount the pH effect of residual ammonia in the
boiler water. Fig. 7 shows the estimated effect of ammonia on boiler water pH. The figure indicates the
expected pH for solutions with different concentrations
of sodium phosphate and 0.2 ppm ammonia. Where
these species dominate the solution chemistry, such
figures may be used to estimate sodium-to-phosphate
molar ratios.
With high purity feedwater, the recommended boiler
water pH can be attained with appropriate additions
of trisodium phosphate. If the recommended boiler
water pH can not be maintained within the above limits using trisodium phosphate or a mixture of trisodium and disodium phosphate, this is indicative of
alkaline or acid-forming impurities in the feedwater
or excessive hideout, and the root cause must be addressed. An exception is low level equilibrium phosphate treatment, where the small amount of trisodium
phosphate added to the boiler water may at times be
insufficient to achieve the recommended pH. A small
amount of sodium hydroxide may be added to attain
the recommended pH, but the excess sodium hydroxide must not exceed 1.0 ppm.13 Even 1.0 ppm sodium
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
used where waterside deposits are excessively thick,
where there is steam blanketing or critical heat flux
(see Chapter 5), or where there is seepage (e.g.,
through rolled seals or cracks).
Fig. 8 shows phosphate concentration limits for
high-alkalinity phosphate treatment. With some
feedwaters (e.g., high-magnesium low-silica), lower
phosphate concentrations may be advisable. The required pH is attained by adjusting the sodium hydroxide concentration in the chemical feed solution. The
total (M alkalinity in calcium carbonate equivalents)
must not exceed 20% of the actual boiler water solids
concentration.
NH3 PO4 + 1ppm NaOH
Na/PO4 = 3.0
9.8
pH
9.6
Na/PO4 = 2.8
Na/PO4 = 2.6
9.4
9.2
9
8.8
0
1
2
3
4
5
6
7
Phosphate, ppm
Fig. 7 Estimated pH of sodium phosphate solutions containing 0.2
ppm ammonium hydroxide. Note: pH values can differ by up to 0.2 pH
units, depending on the choice of chemical equilibrium constants
used, but more often agree within 0.05 pH units.
hydroxide may be excessive for some units, for example oil-fired boilers with especially high heat fluxes
in some areas of the furnace.
When mixing boiler water treatment chemicals,
operators should verify the identity and purity of the
chemicals and take into account water of hydration
in the weight of the chemicals. Neither phosphoric acid
nor monosodium phosphate should be used for routine boiler water treatment. If monosodium phosphate
is used to counter an isolated incident of alkali contamination of the boiler water, it must be used with
caution, and at reduced load.
High-alkalinity phosphate treatment
(low-pressure boilers only)
Minimal carryover and deposition are achieved
with demineralized makeup water and minimal dissolved solids, but this is not necessarily cost-effective
for all low pressure industrial boilers. Where softened
water with 0.02 to 0.5 ppm residual hardness (as
CaCO3) is used as makeup water for low pressure industrial boilers, high alkalinity or conventional phosphate treatment may be used to control scale formation. This high alkalinity treatment must only be used
for boilers operating below 1000 psig (6.9 MPa). The
pH and phosphate concentrations are attained by
addition of a trisodium phosphate and (if necessary)
sodium hydroxide solution through a chemical feed
line into the drum. With high-alkalinity phosphate
treatment, the boiler water pH is maintained in the
range of 10.8 to 11.4. This high pH precipitates hardness constituents that are less adherent than those
formed at lower pH.
Where high alkalinity boiler water is excessively
concentrated by evaporation, the concentrate can become sufficiently caustic to produce caustic gouging
or stress corrosion cracking of carbon steel. Hence,
high-alkalinity boiler water treatment must not be
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
Dispersants, polymers, and chelants
(low pressure boilers only)
Where substantial hardness (e.g., 0.1 ppm as
CaCO3) is present in feedwater, chelant treatment is
often used to ensure that the hardness constituents
remain in solution in the boiler water, or polymer
treatment is used to keep precipitates in suspension.
Blowdown of the dissolved contaminants and colloids
is more effective than that of noncolloidal hardness
precipitates and metal oxides.
While phosphate treatment precipitates residual
calcium and magnesium in a less detrimental form
than occurs in the absence of phosphate, chelants react with calcium and magnesium to form soluble compounds that remain in solution. Chelants commonly
employed include ethylene-diaminetetraacetic acid
(EDTA) and nitrilotriacetic acid (NTA). Because of concern about thermal stability, the use of chelants and
polymers should be limited to boilers operating at less
than 1000 psi (6.9 MPa).
To be most effective, chelant must mix with the feedwater and form thermally stable calcium and magnesium complexes before there is substantial residence
time at high temperature, where free chelant is not
thermally stable. Because the combination of free
chelant and dissolved oxygen can be corrosive, chelant
must be added only after completion of oxygen removal
and scavenging. Also, there must be no copper-bearing components in the feedwater train beyond the
chelant feed point.
Control limits depend on the feedwater chemistry,
specific treatment chemicals used, and other factors.
However, the boiler feedwater pH is generally be70
60
Phosphate, ppm
10
50
Maximum
40
Optimum
30
Minimum
20
10
0
(0)
200
(1379)
400
(2758)
600
(4137)
800
(5516)
1000
(6895)
Operating Pressure, psig (kPa)
Fig. 8 Phosphate concentration limits for high-alkalinity phosphate
treatment.
42-11
The Babcock & Wilcox Company
tween 9.0 and 9.6 and hardness as calcium carbonate is less than 0.5 ppm. The boiler water pH is generally maintained in the range of 10.0 to 11.4. The
boiler water pH is attained by a combination of alkalinity derived from the chelant feed (e.g., as Na 4
EDTA), evolution of CO2 from softened feedwater, and
addition of sodium hydroxide. Polymeric dispersants
are generally used to impede formation of scale by
residual solids.
Once-through universal pressure boilers
In a subcritical once-through boiler, there is no
steam drum. As water passes through boiler tubing,
it evaporates entirely into steam. Because steam does
not cool the tube as effectively as water, the tube temperature increases beyond this dry-out location. Subcritical once-through boilers are designed so this transition occurs in a lower heat flux region of the boiler
where the temperature increase is not sufficient to
cause a problem. However, because the water evaporates completely, it must be of exceptional purity to
avoid corrosion and rapid deposition, and carryover
of dissolved solids.
Similarly stringent water purity requirements must
be imposed for supercritical boilers. While there is no
distinction between water and steam in a supercritical boiler, the physical and chemical properties of the
fluid change as it is heated, and there is a temperature about which dissolved solids precipitate much as
they do in the dry-out zone of a subcritical oncethrough boiler. This is termed the pseudo transition
zone. (See Chapter 5.)
Satisfactory operation of a once-through boiler and
associated turbine requires that the total feedwater
solids be less than 0.030 ppm total dissolved solids with
cation conductivity less than 0.15 µS/cm. Table 1 lists
recommended limits for other feedwater parameters.
Feedwater purification must include condensate polishing, and water treatment chemicals must all be volatile. Ammonia is typically added to control pH. For traditional all volatile treatment, hydrazine or a suitable
volatile substitute is used for oxygen scavenging. Iron
pickup from pre-boiler components can be minimized
by maintaining a feedwater pH of 9.3 to 9.6. Prior to
plant startup, feedwater must be circulated through the
condensate polishing system to remove dissolved and
suspended solids. Temperatures should not exceed 550F
(288C) at the convection pass outlet until the iron levels are less than 0.1 ppm at the economizer inlet.
Utility once-through boilers with copper-free cycle
metallurgy commonly use oxygen treatment. Table 1
includes recommended limits for other feedwater chemical parameters for oxygen treatment. Startup is with
increased pH and no oxygen feed. Oxygen addition to
feedwater is initiated and pH is reduced only after feedwater cation conductivity is less than 0.15 µS/cm.
System transients and upsets inevitably cause excursions above recommend limits. Increased rates of
deposition and corrosion are likely to be in proportion
to the deviations. Small brief deviations may individually be of little consequence, but the extent, duration,
and frequency of such deviations should be minimized.
42-12
Otherwise, over a period of years the accumulative effects will be significant. Potential effects include increased deposition, pitting, pressure drop, and fatigue
cracking. Particular care is required to minimize the
extent and duration of chemistry deviations for cycling
units where operational transients are frequent.
Steam purity
Purity or chemistry requirements for steam can be
as simple as a specified maximum moisture content,
or they can include maximum concentrations for a
variety of chemical species. Often, for low-pressure
building or process heater steam, only a maximum
moisture content is specified. This may be as high as
0.5% or as low as 0.1%. Conversely, some turbine
manufacturers specify steam condensate maximum
cation conductivity, pH, and maximum concentrations
for total dissolved solids, sodium and potassium, silica,
iron, and copper. Turbine steam must generally have
total dissolved solids less than 0.050 ppm, and in some
cases less than 0.030 ppm. Individual species limits
may be still lower. If steam is to be superheated, a
maximum steam dissolved solids limit must be imposed
to avoid excessive deposition and corrosion of the superheater. This limit is generally 0.100 ppm or less.
Even where steam purity requirements are not imposed by the application, steam dissolved solids concentrations less than 1.0 ppm are recommended at
pressures up to 600 psig (4.1 MPa), dissolved solids
concentrations less than 0.5 ppm are recommended at
600 to 1000 psig (4.1 to 6.9 MPa), and dissolved solids concentrations less than 0.1 ppm are recommended
above 1000 psig (6.9 MPa).
Up to 2000 psig (13.8 MPa), most non-volatile chemicals and impurities in the steam are carried by small
water droplets entrained in the separated steam. Because these droplets contain dissolved solids in the same
concentration as the boiler water, the amount of impurities in steam contributed by this mechanical carryover
is the sum of the boiler water impurities concentration
multiplied by the steam moisture content. Mechanical
carryover is limited by moisture separation devices placed
in the steam path, as described in Chapter 5.
High water levels in the drum and boiler water
chemistries that cause foaming can cause excessive
moisture carryover and therefore excessive steam
impurity concentrations. Foaming is the formation of
foam or excessive spray above the water line in the
drum. Common causes of foaming are excessive solids or alkalinity, and the presence of organic matter
such as oil. To keep dissolved solids below the concentration that causes foaming requires continuous or
periodic blowdown of the boiler. High boiler water alkalinity increases the potential for foaming, particularly in the presence of suspended matter.
Where a chemical species is sufficiently volatile, it
also carries over as a vapor in the steam. Total carryover is the sum of the mechanical and vaporous carryover. Vaporous carryover depends on solubility in
steam and is different for each chemical species. For
most dissolved solids found in boiler water, it is negligible by comparison to mechanical carryover at pres-
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
sures less than 2000 psig (13.8 MPa). An exception is
silica for which vaporous carryover can be substantial at lower pressures. Fig. 9 shows typical vaporous
carryover fractions (distribution ratios) for common
boiler water constituents under typical conditions over
a wide range of boiler pressures. Fig. 10 shows expected total dissolved solids carryover for typical highpressure boilers. Vaporous carryover depends on pressure and on boiler water chemistry. It is not affected
by boiler design. Hence, if vaporous carryover for a
species is excessive, the carryover can only be reduced
by altering the boiler water chemistry. Only mechanical carryover is affected by boiler design. Non-interactive gases such as nitrogen, argon, and oxygen
carry over almost entirely with the steam, having no
relationship to moisture carryover.
Excessive steam impurity concentrations can also
be caused by feedwater and boiler water chemistries
that favor volatile species formation. Carryover of
volatile silica can be problematic at pressures above
1000 psig (6.9 MPa). Fig. 11 shows boiler water silica
concentration limits recommended to obtain steam
silica concentrations less than 0.010 ppm at pressures
up to 2900 psig (20.0 MPa) where the pH may be as
low as 8.8. Vaporous silica carryover at a pH of 10.0
is 88% of that at a pH of 8.8. The vaporous silica carryover at a pH of 11.0 is 74% of that at 8.8. The only effective method for preventing excessive silica or other vaporous carryover is reduction of the boiler water concentrations. Another common source of excessive impurities
in steam is inadequate attemperation spray water purity. All impurities in the spray water enter directly into
the steam. Procedures for measuring steam quality and
purity are discussed in Chapter 40.
Fig. 9 Impurity carryover coefficients of salts and metal oxides in
boiler water (adapted from Reference 16).
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
Fig. 10 Solids in steam versus dissolved solids in boiler water.
Water sampling and analysis
A key element in control of water and steam chemistry is effective sampling to obtain representative
samples, prevent contamination of the samples, and
prevent loss of the species to be measured.17 References
18 and 19 provide detailed procedures. In general,
sample lines should be as short as possible and made
of stainless steel, except where conditions dictate otherwise. Samples should be obtained from a continuously flowing sample stream. The time between sampling and analysis should be as short as possible.
Samples should be cooled quickly to 100F (38C) to
avoid loss of the species of interest. Sample nozzles and
lines should provide for isokinetic sample velocity and
maintain constant high water velocities [minimum of
6 ft/s (1.8 m/s)] to avoid loss of materials. Sample
points should be at least 10 diameters downstream of
the last bend or flow disturbance.
Guidelines and techniques for chemical analysis of
grab samples are listed in Table 4. The detailed methods are readily available from the American Society for
Testing and Materials (ASTM) in Philadelphia, Pennsylvania, U.S. and the American Society of Mechanical Engineers (ASME) in New York, New York, U.S.
Wherever practical, on-line monitoring should be
considered as an alternative to grab samples. This
gives real-time data, enables trends to be followed,
and provides historical data. However, on-line monitors require calibration, maintenance, and checks with
grab samples or on-line synthesized standard samples
to ensure reliability. Table 5 lists important on-line
monitoring measurements and references to specific
methods. In addition to the measurements listed, in-
42-13
The Babcock & Wilcox Company
100
Table 4
Guidelines for Measurements on Grab Samples
Measurement
Maximum Boiler Water Silica, ppm
10
pH
Electrometric
ASTM D 1293
Method A
Conductivity
Dip or flow type conductivity
cells energized with
alternating current at a
constant frequency
(Wheatstone Bridge)
ASTM D 1125
Methods A or B
Dissolved
oxygen
Colorimetric or
titrimetric
ASTM D 888
Methods A, B, C
Suspended
iron oxides
Membrane comparison
charts
ASME PTC 31
Ion exchange
equipment
Iron
Photometric
(bathophenanthroline)
or atomic absorption
(graphite furnace)
ASTM D 1068
Method C, D
Copper
Atomic absorption
(graphite furnace)
ASTM D 1688
Method C
Sodium
Atomic absorption or
flame photometry
ASTM D 4191 or
ASTM D 1428
Silica
Colorimetric or
atomic absorption
ASTM D 859 or
ASTM D 4517
Phosphate
Ion chromatography or
photometric
ASTM D 4327 or
ASTM D 515
Method A
Ammonia
Colorimetric
(nesslerization) or
ion-selective electrode
ASTM D 1426
Method A or B
Hydrazine
Colorimetric
ASTM D 1385
Chloride
Colorimetric,
ion-selective electrode
or ion chromatography
ASTM D 512 or
ASTM D 4327
Sulfate
Turbidimetric or ion
chromatography
ASTM D 516 or
ASTM D 4327
Calcium and
magnesium
Atomic absorption;
gravimetric or
titrimetric
ASTM D 511 or
ASTM D 1126
Fluoride
Ion-selective electrode
or ion chromatography
ASTM D 1179 or
ASTM D 4327
Morpholine
Colorimetric
ASTM D 1942
Alkalinity
Color-change titration
ASTM D 1067
Method B
Hydroxide ion
in water
Titrimetric
ASTM D 514
Total organic
carbon
Instrumental (oxidation
and infrared detection)
ASTM D 4779
1
0.1
0.01
0
(0)
500
(3447)
1000
(6895)
1500
(10,342)
2000
(13,790)
2500
(17,237)
3000
(20,684)
Drum Pressure, psig (kPa)
Fig. 11 Boiler water silica concentration limit, where maximum steam
silica is 0.010 ppm and boiler water pH is greater than 8.8.
strumentation is commercially available to monitor
chloride, dissolved oxygen, dissolved hydrogen, silica,
phosphate, ammonia and hydrazine.
Adequate water chemistry control depends on the
ability of boiler operators to consistently measure the
specified parameters. Hence, formal quality assurance
programs should be used to quantify and track the
precision and bias of measurements. Detailed procedures should be in place to cover laboratory structure,
training, standardization, calibration, sample collection/storage/analysis, reporting, maintenance records,
and corrective action procedures. Further discussion
is provided in Reference 20.
Common fluid-side corrosion problems
Water and steam react with most metals to form
oxides or hydroxides. Formation of a protective oxide
layer such as magnetite (Fe3O4) on the metal surface
causes reaction rates to slow with time. Boiler cycle
water treatment programs are designed to maintain
such protective oxide films on internal surfaces and
thus prevent corrosion in boilers and other cycle components. With adequate control of water and steam
chemistry, internal corrosion of boiler circuitry can be
minimized. Yet, chemistry upsets (transient losses of
control) do occur. Vigilant monitoring of system chemistry permits quick detection of upsets and quick remedial action to prevent boiler damage. Where these
measures fail and corrosion occurs, good monitoring
and documentation of system chemistry can facilitate
identification of the root cause, and identification of the
cause can be an essential step toward avoiding further
corrosion. Where corrosion occurs and the origin is
unknown, the documented water chemistry, location of
42-14
Technique(s)
Reference/
Comment
(Notes 1 and 2)
Notes:
1. ASME PTC refers to Performance Test Codes of the American
Society of Mechanical Engineers, New York, New York.
2. ASTM refers to testing procedures of the American Society for
Testing and Materials, Philadelphia, Pennsylvania.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
Table 5
On-line Monitoring Measurements
Measurement
Technique(s)
Reference
pH
Electrometric
ASTM D 5128
Conductivities
(general, cation
and degassed)
Electrical conductivity
ASTM D 4519
measurement before and
after hydrogen cation
exchanges and at atmospheric boiling water
after acidic gas removal
Sodium
Selective ion electrode
flame photometry
ASTM D 2791
Total organic
carbon
Instrumental (oxidation
and measurement
of carbon dioxide)
ASTM D 5173
the corrosion, appearance of the corrosion, and chemistry of localized deposits and corrosion products often
suggest the cause. Common causes are flow accelerated
corrosion, oxygen pitting, chelant corrosion, caustic
corrosion, acid corrosion, organic corrosion, acid phosphate corrosion, hydrogen damage, and corrosion assisted cracking. Figs. 12 and 13 show typical locations
of common fluid-side corrosion problems. Further dis-
Fig. 13 Boiler convection pass showing typical locations of various
types of water-side corrosion.
Fig. 12 Typical locations of various types of water-side corrosion in
a boiler furnace water circuit.
cussion of corrosion and failure mechanisms is provided
in References 21, 22, 23, and 24. For EPRI members,
Boiler Tube Failures: Theory and Practice25 provides an
especially thorough description of utility boiler corrosion problems, causes, and remedial measures.
One distinguishing feature of corrosion is its appearance. Metal loss may be uniform so the surface
appears smooth. Conversely, the surface may be
gouged, scalloped, or pitted. Other forms of corrosion
are microscopic in breadth, and subsurface, so they
are not initially discernible. Subsurface forms of corrosion include intergranular corrosion, corrosion fatigue,
stress corrosion cracking, and hydrogen damage. Such
corrosion can occur alone or in combination with surface wastage. In the absence of component failure, detection of subsurface corrosion often requires ultrasonic, dye penetrant, or magnetic particle inspection
(Chapter 45). These forms of corrosion are best diagnosed with destructive cross-section metallography.
Another distinguishing feature is the chemical composition of associated surface deposits and corrosion
products. Deposits may contain residual corrosives such
as caustic or acid. Magnesium hydroxide in deposits can
suggest the presence of an acid-forming precipitation
process. Sodium ferrate (Na2FeO4) indicates caustic
conditions. Sodium iron phosphate indicates acid phosphate wastage. Organic deposits suggest corrosion by
organics, and excessive amounts of ferric oxide or hydroxide with pitting suggest oxygen attack.
Flow accelerated corrosion is the localized dissolution of feedwater piping in areas of flow impingement.
It occurs where metal dissolution dominates over protective oxide scale formation. For example, localized
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
42-15
The Babcock & Wilcox Company
conditions are sufficiently oxidizing to form soluble
Fe ++ ions but not sufficiently oxidizing to form Fe +++
ions needed for protective oxide formation. Conditions
known to accelerate thinning include: flow impingement on pipe walls, low pH, excessive oxygen scavenger concentrations, temperatures in the range of
250 to 400F/121 to 204C (although thinning can occur at any feedwater temperature), chemicals (such
as chelants) that increase iron solubility, and thermal
degradation of organic chemicals. Thinned areas often have a scalloped or pitted appearance. Failures,
such as that shown in Fig. 14, can occur unexpectedly and close to work areas and walkways. To assure
continued integrity of boiler feedwater piping, it must
be periodically inspected for internal corrosion and
wall thinning. Any thinned areas must be identified
and replaced before they become a safety hazard. The
affected piping should be replaced with low-alloy chromium-bearing steel piping, and the water chemistry
control should be appropriately altered.
Oxygen pitting and corrosion during boiler operation largely occur in pre-boiler feedwater heaters and
economizers where oxygen from poorly deaerated
feedwater is consumed by corrosion before it reaches
the boiler. A typical area of oxygen pitting is shown in
Fig. 15. Oxygen pitting within boilers occurs when
poorly deaerated water is used for startup or for accelerated cooling of a boiler. It also occurs in feedwater
piping, drums, and downcomers in some low pressure
boilers which have no feedwater heaters or economizer. Because increasing scavenger concentrations
to eliminate residual traces of oxygen can aggravate
flow accelerated corrosion, care must be taken to distinguish between oxygen pitting and flow accelerated
Fig. 14 Rupture of 6 in. (152 mm) feedwater pipe in an area thinned
by internal corrosion.
42-16
corrosion which generally occurs only where all traces
of oxygen have been eliminated.
Chelant corrosion occurs where appropriate feedwater and boiler water chemistries for chelant treatment are not maintained. Potentially corrosive conditions include excessive concentration of free chelant
and low pH. (See prior discussion of boiler water treatment with dispersants, polymers, and chelants.) Especially susceptible surfaces include flow impingement
areas of feedwater piping, riser tubes, and cyclone
steam/water separators. Affected areas are often dark
colored and have the appearance of uniform thinning
or of flow accelerated corrosion.
Corrosion fatigue is cracking well below the yield
strength of a material by the combined action of corrosion and alternating stresses. Cyclic stress may be
of mechanical or thermal origin (Chapter 8). In boilers, corrosion fatigue is most common in water-wetted surfaces where there is a mechanical constraint
on the tubing. For example, corrosion fatigue occurs
in furnace wall tubes adjacent to windbox, buckstay,
and other welded attachments. Failures are thick lipped.
On examination of the internal tube surface, multiple
initiation sites are evident. Cracking is transgranular.
Environmental conditions facilitate fatigue cracking
where it would not otherwise occur in a benign environment. Water chemistry factors that facilitate cracking
include dissolved oxygen and low pH transients associated with, for example, cyclic operation, condenser leaks,
and phosphate hideout and hideout-return.
Acid phosphate corrosion occurs on the inner steamforming side of boiler tubes by reaction of the steel with
phosphate to form maricite (NaFePO4 ). Fig. 16 shows
ribbed tubing that has suffered this type of wastage.
The affected surface has a gouged appearance with
maricite and magnetite deposits. Acid phosphate corrosion occurs where the boiler water effective sodiumto-phosphate ratio is less than 2.8, although ratios as
low as 2.6 may be tolerated at lower pressures.
Though not always apparent, common signs of acid
phosphate corrosion include difficulty maintaining
target phosphate concentrations, phosphate hideout
and pH increase with increasing boiler load or pressure, phosphate hideout return and decreasing pH
with decreasing load or pressure, and periods of high
iron concentration in boiler water. The potential for
acid phosphate corrosion increases with increasing
internal deposit loading, decreasing effective sodiumto-phosphate molar ratio below 2.8, increasing phosphate concentration, inclusion of acid phosphates (disodium and especially monosodium phosphate) in
phosphate feed solution, and increasing boiler pressure. To avoid acid phosphate corrosion, operators
should monitor boiler water conditions closely, assure
accuracy of pH and phosphate measurements, assure
purity and reliability of chemical feed solutions, assure that target boiler water chemistry parameters are
appropriate and are attained in practice, and watch
for aforementioned signs of acid phosphate corrosion.
Under-deposit acid corrosion and hydrogen damage occur where boiler water acidifies as it concentrates
beneath deposits on steam generating surfaces. Hydrogen from acid corrosion diffuses into the steel where
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
Fig. 17 Schematic of hydrogen attack, showing steps that occur
and the final result. Hydrogen attack can occur in both carbon and
low alloy steels in acidic or hydrogen environments.
Fig. 15 Oxygen pitting of economizer feedwater inlet.
it reacts with carbon to form methane as depicted in
Fig. 17. The resultant decarburization and methane
formation weakens the steel and creates microfissures.
Thick lipped failures like that shown in Fig. 18 occur
when the degraded steel no longer has sufficient
strength to hold the internal tube pressure. Signs of
hydrogen damage include under deposit corrosion,
thick lipped failure, and steel decarburization and
microfissures. The corrosion product from acid corrosion is mostly magnetite. Affected tubing, which may
extend far beyond the failure, must be replaced. The
boiler must be chemically cleaned to remove internal
tube deposits, and boiler water chemistry must be altered or better controlled to prevent acid-formation as
the water concentrates. Operators should reduce acidforming impurities by improving makeup water, reducing condenser leakage, or adding condensate polishing. For drum boilers, operators should use phosphate treatment with an effective sodium-to-phosphate
molar ratio of 2.8 or greater.
Fig. 16 Acid phosphate corrosion of ribbed tubing.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
Caustic corrosion, gouging and grooving occur
where boiler water leaves a caustic residue as it evaporates. In vertical furnace wall tubes, this occurs beneath deposits that facilitate a high degree of concentration and the corroded surface has a gouged appearance as shown in Fig. 19. In inclined tubes where the
heat flux is directed through the upper half of the
tube, caustic concentrates by evaporation of boiler
water in the steam space on the upper tube surface.
Resulting corrosion is in the form of a wide smooth
groove with the groove generally free of deposits and
centered on the crown of the tube. Deposits associated
with caustic gouging often include Na2FeO4. To prevent
reoccurrence of caustic gouging, operators should prevent accumulation of excessive deposits and control
water chemistry so boiler water does not form caustic
as it concentrates. The latter can generally be achieved
by assuring appropriate feedwater chemistry with coordinated phosphate boiler water treatment, taking
care to control the effective sodium-to-phosphate molar ratio as appropriate for the specific boiler and the
specific chemical and operating conditions. In some instances, where caustic grooving along the top of a sloped
tube is associated with steam/water separation, such
separation can be avoided by use of ribbed tubes which
cause swirling motion that keeps water on the tube wall.
Caustic cracking can occur where caustic concentrates in contact with steel that is highly stressed, to
or beyond the steel’s yield strength. Caustic cracking
is rare in boilers with all welded connections. This
Fig. 18 Brittle tube failure in hydrogen damaged area.
42-17
The Babcock & Wilcox Company
extent that a tube no longer retains adequate strength
and bulges or ruptures. Internal tube deposits generally cause moderate overheating for extended periods
of time, causing long-term overheat failures. Shortterm overheat failures generally occur only when there
is gross interruption of internal flow to cool the tube,
or grossly excessive heat input.
Out-of-service corrosion is predominantly oxygen
pitting. Pitting attributed to out-of-service corrosion
occurs during outages but also as aerated water is
heated when boilers return to service. Especially common locations include the waterline in steam drums,
areas where water stands along the bottom of horizontal pipe and tube runs, and lower bends of pendant superheaters and reheaters. Pinhole failures are more
common in thinner walled reheater and economizer tubing. Such corrosion can be minimized by following appropriate layup procedures for boiler outages and by improving oxygen control during boiler startups.
Pre-operational cleaning
Fig. 19 Caustic gouging initiated along weld backing ring.
generally occurs in boilers using a high alkalinity
caustic boiler water treatment, and it is normally associated with unwelded rolled joints and welds that
are not stress relieved. On metallographic examination, caustic cracking is intergranular and has the
branched appearance characteristic of stress corrosion
cracking as illustrated in Fig. 20. It can generally be
avoided by use of coordinated phosphate treatment.
Where a high alkalinity caustic phosphate boiler water treatment is used for low pressure boilers, nitrate
is often added to inhibit caustic cracking.
Overheat failures like that shown in Fig. 21 occur
where deposits impede internal heat transfer to the
Fig. 20 Schematic of stress corrosion cracking.
42-18
In general, all new boiler systems receive an alkaline boilout, i.e. hot circulation of an alkaline mixture
with intermittent blowdown and final draining of the
unit. Many systems also receive a pre-operational
chemical cleaning. The superheater and reheater
should receive a conventional steam blow (a period of
high velocity steam flow which carries debris from the
system). Chemical cleaning of superheater and reheat
surfaces is effective in reducing the number of steam
blows to obtain clean surfaces, but is not required to
obtain a clean superheater and reheater.
Alkaline boilout
All new boilers should be flushed and given an alkaline boilout to remove debris, oil, grease and paint.
This can be accomplished with a combination of trisodium phosphate (Na3PO4) and disodium phosphate
(Na2HPO4), with a small amount of surfactant added
as a wetting agent. The use of caustic NaOH and/or
soda ash (Na2CO3) is not recommended. If either is
used, special precautions are required to protect boiler
components.
Chemical cleaning
After boilout and flushing are completed, corrosion
products may remain in the feedwater system and
boiler in the form of iron oxide and mill scale. Chemical cleaning should be delayed until full load operation has carried the loose scale and oxides from the
feedwater system to the boiler. Some exceptions are
units that incorporate a full flow condensate polishing system and boilers whose pre-boiler system has
been chemically cleaned. In general, these units can
be chemically cleaned immediately following pre-operational boilout.
Different solvents and cleaning processes are used
for pre-operational chemical cleaning, usually determined by boiler type, metallic makeup of boiler components, and environmental concerns or restrictions. The
four most frequently used are: 1) inhibited 5% hydrochloric acid with 0.25% ammonium bifluoride, 2) 2%
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
hydroxyacetic/1% formic acids with 0.25% ammonium
bifluoride and a corrosion inhibitor, 3) 3% inhibited
ammonium salts of ethylene-diaminetetraacetic acid
(EDTA), and 4) 3% inhibited ammoniated citric acid.
Steam line blowing
The steam line blow procedure depends on unit
design. Temporary piping to the atmosphere is required with all procedures. This piping must be anchored to resist high nozzle reaction force.
All normal startup precautions should be observed for
steam line blowing. The unit should be filled with treated
demineralized water. Sufficient feedwater pump capacity and condensate storage must be available to replace
the water lost during the blowing period.
Numerous short blows are most effective. The color
of the steam discharged to the atmosphere provides
an indication as to the quantity of debris being removed from the piping. Coupons (targets) of polished
steel attached to the end of the exhaust piping are
typically used as final indicators.
Periodic chemical cleaning
Cleaning frequency
Internal surfaces of boiler water-side components (including supply tubes, headers and drums) accumulate
deposits even though standard water treatment practices are followed. These deposits are generally classified
as hardness-type scales or soft, porous-type deposits.
To determine the need for cleaning, tube samples
containing internal deposits should be removed from
high heat input zones of the furnace and/or areas
where deposition problems have occurred. The deposit
weight is first determined by visually selecting a
heavily deposited section. After sectioning the tube
(hot and cold sides), the water-formed deposit is removed by scraping from a measured area. The weight
of the dry material is reported as weight per unit area:
either grams of deposit per square foot of tube surface
or mg/cm2. Procedures for mechanical and chemical
methods of deposit removal are provided in ASTM
D3483.26 General guidelines for determining when a
boiler should be chemically cleaned are shown in Table
6. The deposit weights shown are based on the mechanical scraping method. This removes the porous
deposit of external origin and most of the dense inner
oxide scale. Values are slightly lower than those obtained from the chemical dissolution method.
Because of the corrosive nature of the fuel and its
combustion products, furnace tubes in Kraft recovery
and refuse-fired boilers are particularly susceptible to
gas-side corrosion which can be aggravated by relatively modest elevated tube metal temperatures. (See
Chapters 28 and 29.) Through-wall failures due to
external metal corrosion can occur in these tubes at
water-side deposit weights much less than 40 g/ft2 (43
mg/cm2 ). In addition, for Kraft recovery boilers there
are significant safety concerns for water leakage in
the lower furnace. (See Chapters 28 and 43.) For these
units, a more conservative cleaning criterion is recommended for all operating pressures.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
Fig. 21 Short-term overheat thin edged failure.
Chordal thermocouples
The chordal thermocouple (see Chapter 40) can be
an effective diagnostic tool for evaluating deposits on
operating boilers. Properly located thermocouples can
indicate a tube metal temperature increase caused by
excess internal deposits, and can alert the operator to
conditions that may cause tube failures. Thermocouples are often located in furnace wall tubes adjacent to the combustion zone where the heat input is
highest and the external tube temperatures are also
high. (See Fig. 22.)
Deposition inside tubes can be detected by instrumenting key furnace tubes with chordal thermocouples. These thermocouples compare the surface
temperature of the tube exposed to the combustion
process with the temperature of saturated water. As
deposits grow, they insulate the tube from the cooling
water and cause tube metal temperature increases.
Beginning with a clean, deposit-free boiler, the instrumented tubes are monitored to establish the temperature differential at two or three boiler ratings; this
establishes a base curve. At maximum load, with clean
tubes, the surface thermocouple typically indicates
metal temperatures 25 to 40F (14 to 22C) above saturation in low duty units and 80 to 100F (44 to 56C) in
high duty units as shown in Fig. 23. The temperature
variation for a typical clean instrumented tube is dependent upon the tube’s location in the furnace, tube
thickness, inside fluid pressure, and the depth of the
Table 6
Guidelines for Chemical Cleaning
Unit Operating
Pressure, psig (MPa)
Water-side
Deposit Weight*
(g/ft2 )
Below 1000 (6.9)
20 to 40
1000 to 2000 (6.9 to 13.8) including all
Kraft recovery and refuse-fired boilers
12 to 20
Above 2000 (13.8)
10 to 12
* Deposit removed from hot or furnace side of tube using
the mechanical scraping method. (1 g/ft2 = 1.07 mg/cm2 )
42-19
The Babcock & Wilcox Company
Clean Tube
500F
(260C)
Chemical Recovery Boiler
583F
(306C)
Saturation Temp
500F (260C) at
665 psi (4.6 MPa)
Heat Input
120,000 Btu/h ft2
(378,550 W/m2)
510F
(266C)
Typical Locations for
Chordal Thermocouples
Outer
Casing
Side
Furnace
Side
Scaled Tube
80 g/ft2
Fossil Fuel-Fired Boiler
877F
(469C)
785F
(418C)
500F
(260C)
500F
(260C)
Typical Locations for
Chordal Thermocouples
Fig. 22 Typical locations of chordal thermocouples.
surface thermocouple. Internal scale buildup is detected by an increase in temperature differential
above the base curve. Chemical cleaning should normally be considered if the temperature differential at
maximum boiler load reaches 100F (56C).
Initially, readings should be taken weekly, preferably using the same equipment and procedure as used
for establishing the base curve. Under upset conditions, when deposits form rapidly, the checking frequency should be increased.
Chemical cleaning procedures and methods
In general, four steps are required in a complete
chemical cleaning process:
1. The internal heating surfaces are washed with a
solvent containing an inhibitor to dissolve or disintegrate the deposits.
2. Clean water is used to flush out loose deposits,
solvent adhering to the surface, and soluble iron
salts. Corrosive or explosive gases that may have
formed in the unit are also displaced.
42-20
3. The unit is treated to neutralize and passivate the
heating surfaces. This treatment produces a passive surface, i.e., it forms a very thin protective film
on freshly cleaned ferrous surfaces.
4. The unit is flushed with clean water to remove any
remaining loose deposits.
The two generally accepted chemical cleaning
methods are: 1) continuous circulation of the solvent
(Fig. 24), and 2) filling the unit with solvent, allowing it to soak, then flushing the unit (Fig. 25).
Circulation cleaning method
In the circulation (dynamic) cleaning method (Fig.
24), after filling the unit with demineralized water,
the water is circulated and heated to the required
cleaning temperature. At this time, the selected solvent is injected into the circulating water and recirculated until the cleaning is completed. Samples of the
return solvent are periodically tested. Cleaning is considered complete when the acid strength and the iron
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
Soaking method
The soaking (static) cleaning method (Fig. 25) involves preheating the unit to a specified temperature,
filling the unit with the hot solvent, then allowing the
unit to soak for a period of time, depending on deposit
conditions. To assure complete deposit removal, the
acid strength of the solvent must be somewhat greater
than that required by the actual conditions; unlike the
circulation method, control testing during the course
of the cleaning is not conclusive, and samples of solvent drawn from convenient locations may not truly
represent conditions in all parts of the unit.
The soaking method is preferable for cleaning units
where definite liquid distribution to all circuits (by the
circulation method) is not possible without the use of
many chemical inlet connections. The soaking method
is also preferred when deposits are extremely heavy,
or if circulation through all circuits at an appreciable
rate can not be assured without an impractically-sized
circulating pump. These conditions may exist in large
natural circulation units that have complex furnace
wall cooling systems.
Advantages of this method are simplicity of piping
connections and assurance that all parts are reached
by a solvent of adequate acid strength.
Solvents
Many acids and alkaline compounds have been
evaluated for removing boiler deposits. Hydrochloric
acid (HCl) is the most practical cleaning solvent when
using the soaking method on natural circulation boilers. Chelates and other acids have also been used.
An organic acid mixture such as hydroxyacetic-formic (HAF) is the safest chemical solvent when applying the circulation cleaning method to once-through
boilers. These acids decompose into gases in the event
of incomplete flushing.
For certain deposits, the solvent may require additional reagents, such as ammonium bifluoride, to promote deposit penetration. Alloy steel pressure parts,
particularly those high in chromium, should generally
not be cleaned with certain acid solvents. A general
guideline for solvent selection can be found in Table 7.
Prior to chemically cleaning, it is strongly recommended that a representative tube section be removed
and subjected to a laboratory cleaning test to determine and verify the proper solvent chemical, and concentrations of that solvent.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
200
With Internal
Deposits
After Operation
T, F
150
Base Curve
Clean Condition
100
50
0
50
0
100
Firing Rate, %
Low Duty Units
200
With Internal
Deposits
After Operation
150
T, F
content of the returned solvent reach equilibrium (Fig.
26), indicating that no further reaction with the deposits is taking place. In the circulation method, additional solvent can be injected if the dissipation of the
solvent concentration drops below the recommended
minimum concentration.
The circulation method is particularly suitable for
cleaning once-through boilers, superheaters, and
economizers with positive liquid flow paths to assure
circulation of the solvent through all parts of the unit.
Complete cleaning can not be assured by this method
unless the solvent reaches and passes through every
circuit of the unit.
100
50
Base Curve
Clean Condition
0
0
50
100
Firing Rate, %
High Duty Units
Fig. 23 Temperature difference between surface and saturation
thermocouples.
Deposits
Scale deposits formed on the internal heating surfaces of a boiler generally come from the water. Most
of the constituents belong to one or more of the following groups: iron oxides, metallic copper, carbonates, phosphates, calcium and magnesium sulfates,
silica, and silicates. The deposits may also contain
various amounts of oil.
Pre-cleaning procedures include analysis of the
deposit and tests to determine solvent strength and
contact time and temperature. The deposit analyses
should include a deposit weight in grams per square
foot (or milligrams per square centimeter) and a spectrographic analysis to detect the individual elements.
X-ray diffraction identifying the major crystalline constituents is also used.
If the deposit analysis indicates the presence of copper (usually from corrosion of pre-boiler equipment,
such as feedwater heaters and condensers), one of
three procedures is commonly used: 1) a copper
complexing agent is added directly to the acid solvent,
2) a separate cleaning step, featuring a copper solvent,
is used followed by an acid solvent, and 3) a chelantbased solvent at high temperature is used to remove
iron, followed by addition of an oxidizing agent at re42-21
The Babcock & Wilcox Company
duced temperature for copper removal. The decision
to use one of these methods depends on the estimated
quantity of copper present in the deposit.
When deposits are dissolved and disintegrated, oil
is removed simultaneously, provided it is present only
in small amounts. For higher percentages of oil contamination, a wetting agent or surfactant may be added to
the solvent to promote deposit penetration. If the deposit is predominantly oil or grease, boiling out with
alkaline compounds must precede the acid cleaning.
Inhibitors
The following equations represent the reactions of
hydrochloric acid with constituents of boiler deposits:
Fe3 O4 + 8HCl → 2FeCl3 + FeCl 2 + 4H2O
(2)
CaCO3 + 2HCl → CaCl 2 + H2O + CO2
(3)
At the same time, however, the acid can also react
with and thin the boiler metal, as represented by the
equation:
Fe + 2HCl → FeCl 2 + H2
Fig. 24 Chemical cleaning by the circulation method – simplified
arrangement of connections for once-through boilers.
Fig. 25 Chemical cleaning by the soaking method – simplified
arrangement of connections for drum-type boilers.
42-22
(4)
unless means are provided to slow this reaction without affecting the deposit removal. A number of excellent commercial inhibitors are available to perform this
function. The aggressiveness of acids toward boiler
deposits and steel increases rapidly with temperature.
However, the inhibitor effectiveness decreases as the
temperature rises and, at a certain temperature, the
inhibitor may decompose. Additionally, all inhibitors
are not effective with all acids.
Determination of solvent conditions
Deposit samples The preferred type of deposit
sample is a small section of tube with the adhering
deposit, though sometimes tube samples are not easily obtained. Selection of the solvent system is made
from the deposit analyses. After selection of the solvent system, it is necessary to determine the strength
of the solvent, the solvent temperature, and the length
of time required for the cleaning process.
Solvent strength The solvent strength should be
proportional to the amount of deposit. Commonly used
formulations are:
1. Natural circulation boilers (soaking method)
(a) pre-operational – inhibited 5% hydrochloric
acid + 0.25% ammonium bifluoride
(b) operational – inhibited 5 to 7.5% hydrochloric
acid and ammonium bifluoride based on deposit analysis
2 Once-through boilers (circulation method)
(a) pre-operational – inhibited 2% hydroxyacetic1% formic acids + 0.25% ammonium bifluoride
(b) operational – inhibited 4% hydroxyacetic-2%
formic acids + ammonium bifluoride based on
deposit analysis
Solvent temperature The temperature of the solvent
should be as high as possible without seriously reducing the effectiveness of the inhibitor. An inhibitor test
should be performed prior to any chemical cleaning
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
to determine the maximum permissible temperature
for a given solvent.
When using hydrochloric acid, commercial inhibitors generally lose their effectiveness above 170F
(77C) and corrosion rate increases rapidly. Therefore,
the temperature of the solvent, as fed to the unit,
should be 160 to 170F (71 to 77C). In using the circulation method with a hydroxyacetic-formic acid mixture, a temperature of 200F (93C) is necessary for
adequate cleaning. Chelate-based solvents are generally applied at higher temperatures (about 275F/
135C). In these cases, the boiler is fired to a specific
temperature. The chelate chemicals are introduced
and the boiler temperature is cycled by alternately
firing and cooling to predetermined limits.
Steam must be supplied from an auxiliary source to
heat the acid as it is fed to the unit. When using the
circulation method, steam is also used to heat the circulating water to the predetermined and desired temperature before injecting the acid solution. Heat should
be added by direct contact or closed cycle heat exchangers. The temperature of the solvent should never be
raised by firing the unit when using an acid solvent.
Cleaning time When cleaning by the circulation
method, process completion is determined by analyzing samples of the return solvent for iron concentration and acid strength. (See Fig. 26.) However, acid circulation for a minimum of six hours is recommended.
In using the soaking method, the cleaning time
should be predetermined but is generally between six
to eight hours in duration.
Preparation for cleaning
Heat transfer equipment All parts not to be cleaned
should be isolated from the rest of the unit. To exclude
acid, appropriate valves should be closed and checked
for leaks. Where arrangements permit, parts of the
unit such as the superheater can be isolated by filling with demineralized water. Temporary piping
should be installed to flush dead legs after cleaning.
In addition to filling the superheater with demineralized water, once-through type units should be pressurized with a pump or nitrogen. The pressure should
exceed the chemical cleaning pump head.
Bronze or brass parts should be removed or temporarily replaced with steel. All valves should be steel or
steel alloy. Galvanized piping or fittings should not be
Table 7
Comparative Cleaning Effectiveness
Makeup of Deposit
Type of
Cleaning
HCl
HAF
EDTA
Citric
Bromate
Iron
Copper
Silica
Hardness
(Ca/Mg)
Good
Good
Good
Good
N/A
Medium
Poor
Medium
Medium
Good
Medium
Medium
Poor
Poor
N/A
Good
Medium/poor
Medium/poor
Poor
N/A
used. Gauge and meter connections should be closed
or removed.
All parts not otherwise protected by blanking off or
by flooding with water will be exposed to the inhibited solvent. Vents to a safe discharge should be provided wherever vapors might accumulate, because
acid vapors from the cleaning solution do not retain
the inhibitor.
Cleaning equipment The cleaning equipment should
be connected as shown in Fig. 24 if the continuous
circulation method is used, or as shown in Fig. 25 if
the soaking method is used. Continuous circulation
requires an inlet connection to assure distribution. It
also requires a return line to the chemical cleaning
pump from the unit. The soaking method does not
require a return line. The pump discharge should be
connected to the lowermost unit inlet.
The filling or circulating pump should not be fitted
with bronze or brass parts; a standby pump is recommended. A filling pump should have the capacity to
deliver a volume of liquid equal to that of the vessel
within two hours at 100 psi (0.7 MPa). A circulating
pump should have sufficient capacity to meet recommended cleaning velocities. With modern oncethrough boilers, a capacity of 3600 GPM (227 l/s) at
300 psi (2.1 MPa) is common. A solvent pump, closed
mixing tank and suitable thermometers, pressure
gauges, and flow meters are required. An adequate
supply of clean water and steam for heating the solvent should be provided. Provision should be made for
adding the inhibited solvent to the suction side of the
filling or recirculating pump.
Cleaning solutions Estimating the content of the
vessel and adding 10% to allow for losses will determine the amount of solvent required. Sufficient commercial acid should then be obtained. An inhibitor
qualified for use with the solvent also needs to be procured and added to the solvent.
Cleaning procedures
The chemical cleaning of steam generating equipment consists of a series of distinct steps which may
include the following:
1.
2.
3.
4.
Fig. 26 Solvent conditions during cleaning by the circulation method.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
isolation of the system to be cleaned,
hydrostatic testing for leaks,
leak detection during each stage of the process,
back flushing of the superheater and forward
flushing of the economizer,
5. preheating of the system and temperature control,
42-23
The Babcock & Wilcox Company
6.
7.
8.
9.
10.
11.
solvent injection/circulation (if circulation is used),
draining and/or displacement of the solvent,
neutralization of residual solvent,
passivation of cleaned surfaces,
flushing and inspection of cleaned surfaces, and
layup of the unit.
Every cleaning should be considered unique, and
sound engineering judgment should be used throughout the process. The most important design and procedural considerations include reducing system leakage,
controlling temperature, maintaining operational flexibility and redundancy, and ensuring personnel safety.
Precautions
Cleaning must not be considered a substitute for
proper water treatment. Intervals between cleanings
should be extended or reduced as conditions dictate.
Every effort should be used to extend the time between chemical cleanings. Hazards related to chemical cleaning of power plant equipment are fairly well
recognized and understood, and appropriate personnel safety steps must be instituted.27
Chemical cleaning of superheater, reheater and
steam piping
In the past, chemical cleaning of superheaters and
reheaters was not performed because it was considered unnecessary and expensive. With the use of
higher steam temperatures, cleaning procedures for
superheaters, reheaters and steam piping have gained
importance and acceptance.
When chemically cleaning surfaces that have experienced severe high-temperature oxide exfoliation
(spalling of hard oxide particles from surfaces), it is
important to first remove a tube sample representing
the worst condition. Oxidation progresses at about the
same rate on the outside of the tubes as on the inside;
exfoliation follows a similar pattern.
The tube sample should be tested in a facility capable of producing a flow rate similar to that used in
the actual cleaning. This allows development of an
appropriate solvent mixture.
To determine the circulating pump size and flows
required, it is usually necessary to contact the boiler
manufacturer.
Figs. 27 and 28 show possible superheater/reheater
chemical cleaning piping schematics for drum boiler and
once-through boiler systems, respectively.
If, in the case of a drum boiler, the unit is to be
cleaned along with the superheater and reheater, it
is usually necessary to orifice the downcomers to obtain the desired velocities through the furnace walls.
A steam blow to purge all air and to completely fill
the system must precede cleaning in all systems containing pendant non-drainable surfaces. Most
drainable systems also benefit from such a steam blow.
Presently, two solvent mixtures are available to
clean superheater, reheater and steam piping. One is
a combination of hydroxyacetic and formic acids containing ammonium bifluoride; the other is an EDTA
(ethylenediaminetetraacetic acid)-based solvent.
42-24
Fig. 27 Typical superheater/reheater chemical cleaning circuit for a
drum-type boiler.
Solvent disposal
General considerations A boiler chemical cleaning
is not complete until the resultant process waste water stream is disposed of. Selection of handling and
disposal methods depends on whether the wastes are
classified as hazardous or non-hazardous. Boiler
chemical cleaning wastes (BCCW) are different in
volume and frequency of generation and have different discharge regulations from other power plant waste
streams. Of all power plant discharges, BCCWs are
most likely to be classified as hazardous. Depending
upon the cleaning process, the resultant BCCW may
become one of the driving forces in solvent selection.
Under National Pollutant Discharge Elimination
System (NPDES) requirements, boiler cleaning wastes
are considered chemical metal cleaning wastes. The
primary parameters of concern are iron, copper, chromium and pH. In all cases, waste management must
be performed in accordance with current regulatory
requirements.
Waste management options Table 8 lists the handling practices for BCCW. In co-ponding, the BCCW
is mixed in an ash pond with other waste streams from
the power plant. Acid wastes are neutralized by the
alkaline ash, and the metals are precipitated as insoluble metal oxides and hydroxides, or absorbed on
ash particles. Co-ponding is the least expensive and
the easiest disposal option.
Incineration of organic-based cleaning wastes by
direct injection into the firebox of the utility boiler is
another common disposal practice. Potential emissions
from the boiler must be carefully monitored to ensure
regulatory compliance.
Large quantities of BCCW are often disposed of in a
secure landfill. Evaporation can reduce waste volume
and, thereby, reduce overall landfill disposal costs.
HCl cleaning wastes can be treated to NPDES standards using lime or caustic precipitation. It is more
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
Removing metal ions and reusing chemical cleaning waste are subjects receiving increased attention.
As the regulatory environment continues to change,
more emphasis will be placed on the treatment and
reuse of BCCW.
Layup
Fig. 28 Typical superheater/reheater chemical cleaning circuit for a
once-through boiler.
difficult to treat the organic cleaning agents (such as
EDTA) by current techniques. Treatment methods with
permanganate, ultraviolet light, and hydrogen peroxide (wet oxidation) have been used with limited
success. Several vendors have proprietary processes
which claim to successfully treat chelated wastes.28,29
Table 8
Boiler Chemical Cleaning Wastes
Practices/Options
Source Reduction
Optimize cleaning frequency
Reduce volume of cleaning solution
Improve boiler water chemistry
Alternate Solutions
Change the cleaning solvent
Disposal
Evaporation
Incineration
Co-ponding
Secured landfill
Treatment
Neutralization
Physical waste treatment
Chemical waste treatment
Recycle and Reuse
Recycle for metal recovery
Reuse acid in alternate applications
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
During periods when boiler operation is interrupted, substantial pitting and general corrosion can
occur within unprotected water-steam circuitry. When
boilers return to operation, corrosion products migrate
to high heat flux areas of the boiler or carryover to
the turbine. Out-of-service corrosion can therefore impede boiler startup and lead to operational problems
such as deposition, under-deposit corrosion, corrosion
fatigue, and cycle efficiency loss.
Preservation methods inhibit out-of-service corrosion by eliminating or controlling moisture, oxygen,
and chemical contaminants that cause corrosion. Table
9 provides a brief summary and comparison of common preservation methods.
These methods are designed to limit corrosion
caused by the normal range of boiler and atmospheric
contaminants. Gross contamination must be avoided
and, if it occurs, the contaminants must be immediately neutralized and removed. Respective vendors
should be contacted for specific recommendations for
balance-of-plant equipment (turbine, condensate,
feedwater, and atmospheric pollution control systems).
Vendor procedures should also be followed for boiler
auxiliary equipment such as pulverizer gearboxes,
sootblowers, fans, and motors.
Boiler shutdown for layup
Appropriate shutdown procedures can facilitate
preservation for subsequent idle periods. Reducing
load dissipates fluid-side salts that concentrate on
tube surfaces in high heat flux areas. As boiler load is
reduced, feedwater and boiler water pH should be
increased to the upper end of the target operating
range, preferably 9.6 or higher. Where an oxygen
scavenger/inhibitor is employed, concentration should
increase to 0.050 ppm hydrazine* or equivalent.
When boiler water is to remain in the boiler for a substantial cold layup period, the oxygen scavenger/inhibitor concentration in the water should be increased
to 20 ppm hydrazine or equivalent after the boiler
pressure has decayed to below 200 psig (1.4 MPa). At
higher pressures and associated temperatures, the
scavenger may rapidly decompose. An oxygen scavenger/inhibitor is not added to boilers that employ oxygen treatment. For boilers on oxygen treatment, the
oxygen feed should be stopped at least an hour be-
*WARNING: HYDRAZINE IS A PROVEN GENERIC
CHEMICAL FOR THIS APPLICATION. HOWEVER,
HYDRAZINE IS A KNOWN CARCINOGEN, AND CAN
BE REPLACED WITH OTHER PRODUCTS THAT
HAVE EQUIVALENT ABILITY TO SCAVENGE OXYGEN
AND INHIBIT CORROSION.
42-25
The Babcock & Wilcox Company
Table 9
Summary and Comparison of Boiler Lay-up Methods
Lay-up Method
Effectiveness
Costs
Safety and
Environmental Concerns
Strengths
Weaknesses
Drained and dry
for erection or
maintenance
Poor
Minimal
Minimal
Allows full access to
internal surfaces
Quick and easy
Not effective
Vaporous
corrosion
inhibitors
Variable,
generally
fair
Chemicals
Chemical application
Chemical removal
and disposal
Handling and disposal
of chemicals
Minimal maintenance
requirements
Remaining inhibitive
capacity is difficult
to monitor
Chemicals must be
replaced periodically
Difficult to distribute
through components
Nitrogen
blanketing
Excellent
Nitrogen distribution
system
Nitrogen
Nitrogen suffocation
Consistently effective
Easy to monitor
Safety concerns
Nitrogen leakage
Hot standby
Good
Heat
Residual temperature
and pressure
Fast restart
Not recommended for
more than 3 days
Cold standby
Poor
Minimal
Minimal
Fast restart
Not recommended for
more than 30 days
Wet, water-filled
Variable,
generally
good
Demineralized water
Chemical treatment
Disposal of treated
water
Handling of
chemicals
Disposal of treated
water
Easily applicable to
non-drainable
components
Facilitates rapid
return to service
Freeze damage
Valve seepage and
associated corrosion
damage
Difficult to monitor
and inspect
May corrode copper
alloys beyond boiler
Dry, dehumidified
air
Excellent
Dehumidifier and
blower unit
Air recirculation
piping
Minimal
Consistently effective
Safe
No disposal problems
Easy to monitor
Boiler must be
totally drained
Initial plumbing
and equipment
requirements
fore shutdown; there can be no oxygen leakage into
the cycle. Where possible, as steam pressure decays
to atmospheric pressure, nitrogen should be introduced
through upper vents to keep the internal pressure
positive and prevent air ingress. Boiler-specific operating instructions should be consulted for other important shutdown procedures and precautions.
Draining for boiler maintenance and inspection
Draining boilers without further preservation is
often necessary for maintenance and inspection, and
the unit should be drained and dried as thoroughly
as possible. Draining the boiler hot (for example, at
20 psig/0.14 MPa) will facilitate drying, but may leave
condensate in non-drainable superheater elements.
Boiler components that need not be open for maintenance should, where possible, be isolated and protected. For example, while the lower furnace is open
for maintenance, the superheater should, if possible,
be protected with an appropriate wet or dry layup
method. All openings should remain covered to prevent ingress of contaminants.
The unpreserved maintenance period should be as
42-26
brief as possible, preferably less than 3 weeks. Where
a long maintenance outage with minimal preservation is necessary, the boiler and open sections of the
pre-boiler system should generally be chemically
cleaned and repassivated to reform a protective oxide
film following the outage.
Hot standby and hot layup
When a boiler returns to operation while steam pressure remains above atmospheric pressure, preservation
requirements are minimal. If the shutdown period is
less than 72 hours and there is no air in-leakage, ammonia and oxygen scavenger/inhibitor concentrations
need only be raised to the high end of the normal operating range with an oxygen scavenger/inhibitor concentration equivalent to about 0.050 ppm hydrazine.
Oxygen scavengers are not used for boilers that employ oxygen treatment. However, a low oxygen concentration must be maintained by effective deaeration, and
water must remain at a high level of purity with cation conductivity less than 0.15 µS/cm.
Extended hot standby is not recommended. Hot
layup can be extended by use of auxiliary heat, but
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
non-corrosive and non-depositing conditions can be
difficult to assure, especially in economizers, superheaters, and reheaters. If temperature is maintained
by injecting blowdown from an adjacent boiler, excessive blowdown solids can accumulate under low-flow
conditions in the standby boiler. When steam is injected from another boiler, deposition and corrosion
problems can arise from temperature and chemistry
differentials. Also, care must be taken to avoid cavitation and to control the chemistry of steam condensate. Water leakage across valves can cause corrosion
in seepage areas, and the corrosion is aggravated by
relatively high material and water temperatures.
Cold standby for up to thirty days
For short periods (not more than a week), boilers
may remain on cold standby status with little or no
chemical additions. Moderate ammonia and oxygen
scavenger/inhibitor additions can extend this period up
to thirty days. Treated demineralized water for shortterm cold standby should have a minimum concentration of 10 ppm ammonia. The concentration of oxygen
scavenger/inhibitor normally used in the boiler should
be increased to the equivalent of 25 ppm of hydrazine.
Nitrogen blanketing (see below) is recommended.
For boilers employing oxygen treatment, no scavenger should be used for short cold standby periods. However, oxygen ingress must be avoided and low oxygen
concentrations must be maintained (for example, by use
of nitrogen blanketing of boiler and deaeration of
makeup water). Throughout the storage period, the pH
must be 9.2 or higher, and cation conductivity throughout the boiler must be less than 0.15 µS/cm.
Boiler storage for more than seven days
Any of several layup practices are acceptable for
storage periods up to six months. Alternatives for fluidside layup include nitrogen blanketing, wet layup with
treated demineralized water, and dry dehumidified
layup. For extended outages, it is important that the
pre-boiler feedwater train, balance of the water-steam
cycle, auxiliary equipment, and fireside of the boiler
are adequately preserved. For idle periods longer than
six months, dry (dehumidified) storage is recommended. For boilers with non-drainable components,
water removal issues must be weighed against the
advantages of dry layup.
Reheaters – all periods
Reheaters are generally stored dry because they
can not easily be isolated from the turbine. Wet storage requires installation of blanks or special valves in
the connecting lines. Drying can be performed by exposing reheaters to condenser vacuum after the fires
have been removed, the unit tripped, and the turbine
seals maintained. With approximately 20 in. (5 kPa)
of vacuum on the condenser, vents or drains on the
reheater inlet should be opened to allow air to pass
through and remove all moisture. Dehumidified dry
storage is recommended where the storage period exceeds 30 days. Alternatively, the evacuated reheater
may be isolated and nitrogen blanketed, or it may be
nitrogen blanketed in conjunction with the turbine.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
Nitrogen blanketing
Even where water is present, corrosion can be prevented by eliminating oxygen from the environment.
Oxygen can be eliminated by sealing and pressurizing the entire boiler, or the space above water level,
with nitrogen to prevent air in-leakage. In the absence
of acids and other oxidants, eliminating air stops corrosion. Nitrogen blanketing is a highly effective
method for preventing corrosion. It is easy to monitor
and alarm, so effective preservation can be assured.
However, the boiler must be well sealed to prevent
excessive leakage.
It is absolutely imperative that working spaces
around nitrogen blanketed equipment be well ventilated. Venting of nitrogen during purging or water
filling operations can release large amounts of nitrogen into surrounding areas. Also, before entry, areas
that have been nitrogen blanketed must be well ventilated and the air tested to confirm that all parts have
adequate oxygen concentrations.
Wet (water-filled) layup
Wet layup in combination with nitrogen blanketing is often the most practical method of protection,
especially for boilers that are not fully or easily
drainable. However, for longer storage periods, advantages of wet layup are offset by accumulative corrosion in areas of valve seepage and by accumulative
cost of replacement water, chemicals, treated water
disposal, nitrogen cover gas, and heat in cold climates.
Consequently, dry layup is generally recommended for
storage periods longer than six months.
Before a boiler is flooded with layup water, provision
must be made to support the additional weight when
drum (if present), superheater, and steam piping are
filled. If the boiler is to be completely filled with layup
water, an expansion tank or surge tank above the highest vent is necessary to accommodate volume changes
that are caused by normal temperature fluctuations.
The expansion space at the top of the boiler (whether
in a drum or in a surge tank) should be nitrogen blanketed to assure that there is no air ingress. Where freezing conditions are expected or possible, provision must
be made for heating water-filled components.
Wet layup generally requires demineralized water
having a specific conductivity less than 1.0 µS/cm before treatment chemicals are added. Use of demineralized water and all volatile treatment chemicals is
essential where boilers include non-drainable or stainless steel components. Use ammonium hydroxide to
raise water pH into the range of 10.0 to 10.4. Use an
oxygen scavenger/inhibitor to further retard corrosion.
Dry (dehumidified) layup
Dry layup requires the removal of all water and the
dehumidification of air to maintain a relative humidity less than 50%, and preferably less than 40%. This
prevents corrosion by hygroscopic salts. Dry-air (dehumidified) storage is highly effective, and its continued effectiveness is easy to monitor. Dry layup allows
easy and safe access for maintenance, with no potential for suffocation and no exposure to toxic chemicals.
42-27
The Babcock & Wilcox Company
It also eliminates the potential for biological activity,
damage from freezing water, and corrosion by leaking water. However, implementation requires that the
boiler be completely drained and dried, and this is a
major problem for boilers with non-drainable superheaters or other non-drainable circuits. Also, mechanical circulation and dehumidification equipment and
piping installation can be costly.
In preparation for dry storage, water must be
drained completely from all boiler circuits, including
feedwater piping, economizer, superheater, and
reheater. All non-drainable boiler tubes and superheater tubes should be blown with pressurized air.
Auxiliary sources of heat are used to dry fluid-side
surfaces. Deposits of sufficient thickness to retain
moisture must also be removed.
The preferred dry layup method is continuous recirculation of dehumidified air. Fans force air through
the dehumidifier, boiler fluid-side circuitry, and back
to the dehumidifier. The system must include instrumentation for measuring relative humidity. Recirculating dehumidification also requires external (usually flexible plastic) piping to complete the path. The
system must be sized to handle the residual moisture
and moist air in-leakage, and must be monitored to
assure that relative humidity remains less than 50%.
An alternative, but inferior, dry layup method is the
use of static desiccant to absorb moisture with no forced
air circulation. This method is effective for boiler components and small (package) boilers, but not generally adequate for large complex boiler circuitry.
Termination of the storage period requires removal
of the recirculation, dehumidification, and monitoring
materials and equipment. Any loose desiccant particles
or dust (which generally contain silica or sulfite
chemicals) must be cleaned from the boiler.
Vaporous corrosion inhibitors (VCI)
Vaporous corrosion inhibitors retard corrosion by
forming a thin protective film over metal surfaces.
Where such chemicals are sealed into a closed space,
they can retard corrosion even in the presence of both
water and oxygen. These inhibitors are not generally
used for completed boilers, where the size and complexity of boiler circuits precludes effective distribution of dry powders. However, they are often used to
inhibit internal corrosion of boiler components, as
supplements to dry storage for small boilers, and as
an alternative treatment for hydrotest water.
References
1. Klein, H.A., and Rice, J.K., “A research study on internal corrosion in high pressure boilers,” Journal of Engineering for Power, Vol. 88, No. 3, pp. 232-242, July, 1966.
2. Cohen, P., Ed., The ASME Handbook on Water Technology in Thermal Power Systems, The American Society of Mechanical Engineers, New York, New York, 1989.
3. “Consensus on Operating Practices for the Control of
Feedwater and Boiler Water Quality in Modern Industrial
Boilers,” The American Society of Mechanical Engineers,
New York, New York, 1994.
4. “Interim consensus guidelines on fossil plant cycle
chemistry,” Report CS-4629, Electric Power Research Institute, Palo Alto, California, June, 1986.
5. “Guideline for Boiler Feedwater, Boiler Water, and
Steam of Steam Generators with a Permissible Operating Pressure > 68 bar,” VGB PowerTech e.V., Essen, Germany, VGB-R 450 Le, (in German), 1988.
6. Betz Handbook of Industrial Water Conditioning,
Ninth Ed., Betz Laboratories, Trevose, Pennsylvania, September, 1991.
7. Drew Principles of Industrial Water Treatment, 11th
Ed., Drew Industrial Division, Ashland Chemical Co.,
Boonton, New Jersey, 1994.
8. Kemmer, F.N., Ed., The Nalco Water Handbook, Second Ed., McGraw-Hill, New York, New York, 1988.
9. Macbeth, R.V., et al., UKAEA Report No. AAEW-R711,
Winfrith, Dorchester, United Kingdom, 1971.
10. Goldstein, P., and Burton, C.L., “A research study on
internal corrosion of high-pressure boilers – final report,”
Journal of Engineering for Power, Vol. 91, pp. 75-101,
April, 1969.
42-28
11. Freier, R.K., “Cover layer formation on steel by oxygen in neutral salt free water,” VGB Speiserwassertagung
1969 Sunderheft, pp. 11-17 (in German), 1969.
12. Whirl, S.F., and Purcell, T.E., “Protection against
caustic embrittlement by coordinated pH control,” Third
Annual Meeting of the Water Conference of the Engineers’
Society of Western Pennsylvania, Pittsburgh, Pennsylvania, 1942.
13. Stodola, J., “Review of boiler water alkalinity control,”
Proceedings of the 47th Annual Meeting of The International Water Conference, Pittsburgh, Pennsylvania, pp.
235-242, October 27-29, 1986.
14. Economy, G., et al., “Sodium phosphate solutions at
boiler conditions: solubility, phase equilibrium and interactions with magnetite,” Proceedings of the International
Water Technology Conference, Pittsburgh, Pennsylvania,
pp. 161-173, 1975.
15. Tremaine, P., et al., “Interactions of sodium phosphate
salts with transitional metal oxides at 360C,” Proceedings
of the International Conference on Interaction of Iron
Based Materials with Water and Steam, Heidelberg, Germany, June 3-5, 1992.
16. Martynova, O.I., “Transport and concentration processes of steam and water impurities in steam generating
systems,” Water and Steam: Their Properties and Current Industrial Applications, J. Staub and K. Scheffler,
Eds., Pergamon Press, Oxford, United Kingdom, pp. 547562, 1980.
17. Nagda, N.L. and Harper, J.P., Monitoring Water in
the 1990s: Meeting New Challenges, STPl102, American
Society for Testing and Materials, Philadelphia, Pennsylvania, 1991.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
18. Annual Book of ASTM Standards, Section 11, Water
and Environmental Technology, Vol. 11.01 (D 1192 Specification for Equipment for Sampling Water and Steam; D
1066 Practice for Sampling Steam; D 3370 Practice for
Sampling Water; and D 4453 Handling of Ultra-pure Water
Samples), American Society for Testing and Materials,
Philadelphia, Pennsylvania, 2004.
19. Steam and Water Sampling, Conditioning, and Analysis in the Power Cycle, ASME Performance Test Code
19.11, The American Society of Mechanical Engineers,
New York, New York, 1997.
20. Rice, J., “Quality assurance for continuous cycle chemistry monitoring,” Proceedings of the International Conference on Fossil Plant Cycle Chemistry, Report TR100195, Electric Power Research Institute, Palo Alto, California, December, 1991.
21. Uhlig, H.H., and Revic, R.W., Corrosion and Corrosion Control, Third Ed., John Wiley & Sons, New York,
New York, 1985.
22. Lamping, G.A., and Arrowood, Jr., R.M., Manual for
Investigation and Correction of Boiler Tube Failures, Report CS-3945, Electric Power Research Institute, Palo Alto,
California, 1985.
23. French, D.N., Metallurgical Failures in Fossil Fired
Boilers, Second Ed., Wiley, New York, New York, 1993.
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
24. Port, R.D., and Herro, H.M., The Nalco Guide to Boiler
Failure Analysis, McGraw-Hill Company, New York, New
York, 1991.
25. Dooley, R.B., and McNaughton, W.P., “Boiler Tube
Failures: Theory and Practice,” Electric Power Research
Institute, Palo Alto, California, 1996. LICENSED MATERIAL available to EPRI members.
26. Annual Book of ASTM Standards, Section 11, Water
and Environmental Technology, Vols. 11.01 and 11.02,
American Society for Testing and Materials, Philadelphia,
Pennsylvania, 2003.
27. Wackenhuth, E.C., et al., “Manual on chemical cleaning of fossil-fuel steam generating equipment,” Report CS3289, Electric Power Research Institute, Palo Alto, California, 1984.
28. Samuelson, M.L., McConnell, S.B., and Hoy, E.F., “An
on-site chemical treatment for removing iron and copper
from chelant cleaning wastes,” Proceedings of the 49th International Water Conference, Pittsburgh, Pennsylvania,
p. 380,1988.
29. “Nalmet heavy metal removal program,” Nalco Chemical Company, Naperville, Illinois, February, 1989.
42-29
The Babcock & Wilcox Company
Degassed conductivity analyzer for water quality analysis.
42-30
Steam 41 / Water and Steam Chemistry, Deposits and Corrosion
The Babcock & Wilcox Company
Chapter 43
Boiler Operations
Effective operation of steam generating equipment
has always been critical to maintaining system efficiency, reliability and availability. With advances in
sensor technology, control software, and steam generator hardware, efficient operation today means balancing equipment performance with safety requirements and emissions mandates. The procedures used
to run steam generating equipment vary widely depending upon the type of system, fuel and application. Systems can range from simple and fully automated requiring a minimum of attention, such as
small gas-fired package boilers, to the very complex
requiring constant operator attention and interaction,
such as a large utility plant. There are, however, a
set of relatively common fundamental operating
guidelines that safeguard personnel and optimize
equipment performance and reliability. When combined with equipment-specific procedures, these
guidelines promote the best possible operations. The
first half of this chapter focuses on general practices
applicable to large multi-burner fossil-fuel fired natural circulation and once-through boilers, though these
practices are also generally applicable to most other
boiler designs. Starting with Operation of Cyclone
furnaces, the remaining sections focus on the unique
practices for several important special cases.
Because of the intimate relationship between equipment design and operation, additional operating guidelines may be found in other chapters of Steam. Selected
areas of particular interest are listed in Table 1.
General boiler operations
Fundamental principles
Although boiler design and power production have
become sophisticated, basic operating principles still
apply. Combustion safety and proper steam/water
cooling of boiler pressure parts are essential.
Combustion safety and steam/water cooling requirements Before firing a furnace, there must be no lin-
gering combustible material inside the unit. Purging,
or removal of this material, assures that the furnace
is ready for firing. A standard operating rule for multiple burner boilers is to purge the unit at no less than
25% of the maximum continuous rating (MCR) mass
air flow for the greater of at least five minutes or five
volume changes.
Steam 41 / Boiler Operations
Once combustion is established, the correct air/fuel
ratio must be maintained. Insufficient air flow may
permit the formation of combustible gas pockets and
provide an explosion potential. Sufficient air flow to
match the combustion requirements of the fuel should
be maintained and a small amount of excess air
should be admitted to cover imperfect mixing and to
promote air and fuel distribution. For emissions reduction, many newer firing systems are staged with
overfire air (OFA) ports installed in the upper combustion zones of the furnace. The controlled introduction of combustion air does not eliminate the need to
provide adequate operating excess air for safety.
In addition to these combustion precautions, it is
important to verify boiler water levels. Combustion
should never be established until adequate cooling
water is in the tubes and steam drum for natural circulation boilers and minimum flow rates are established for once-through boilers.
General safety considerations Pressure part failure
remains a major concern in the boiler industry. The
Table 1
Index to Additional Operating Guidelines
Found in Steam
System or Component
Air heaters
Ash handling equipment
Auxiliary equipment
Burners, coal
Burners, oil and gas
Bypass systems
Chemical cleaning
Chemical recovery units
Cyclone furnaces
Fluidized-bed boilers
Particulate removal equipment
Pulverizers
Scrubbers (flue gas desulfurization)
Selective catalytic reduction systems
Sootblowers
Startup systems
Stokers
Waste-to-energy systems
Water chemistry
Water treatment
Chapter
20
24
25
14
11
19
42
28
15
17
33
13
35
34
24
19
16
29
42
42
43-1
The Babcock & Wilcox Company
American Society of Mechanical Engineers (ASME),
National Board of Boiler and Pressure Vessel Inspectors, and other organizations have issued extensive
codes directed at minimizing these failures. The codes
are continuously updated to support quality pressure
part design. (See Appendix 2.)
Combustion products have also received considerable safety attention. Carbon dioxide (CO2), carbon
monoxide (CO), sulfur oxides and chlorine compounds
must be considered. While CO2 is not poisonous, it reduces oxygen availability in the flue gas. Sulfur oxides
can form acids when breathed into the lungs. Chlorine
compounds can form hydrochloric acids or carcinogens
such as dioxin.
Safety of fuel ash must also be considered. While
few ashes contain hazardous materials, heavy metals and arsenic can be present in dangerous levels. In
addition, residual combustion may continue in ash
collected in hoppers. This is especially true when new
emissions reduction combustion systems are being
installed. Carbon-in-ash characteristics may be altered under the new low nitrogen oxides (NOx) firing
configurations.
Finally, safeguards apply when performing maintenance and other work on out-of-service boilers. A
confined space may have insufficient oxygen for personnel. Good lighting is important for a safe working
environment. In addition, ash accumulations in outof-service boiler areas may still be too hot for maintenance activities.
Initial commissioning operations
Operator requirements
Good operation begins before equipment installation is complete. It includes training of the operators
as well as preparation of the equipment.
Every operator must be trained to understand and
fulfill the responsibility assumed for the successful
performance of the equipment and for the safety of
all personnel involved. To be prepared for all situations that may arise, the operator must have a complete knowledge of all components: their designs, purposes, limitations and relationships to other components. This includes thoroughly inspecting the equipment and studying the drawings and instructions. The
ideal time to become familiar with new equipment is
during the pre-operational phase when the equipment
is being installed.
A distributed control system (DCS) integrates the
individual process controllers of a steam generation
process into a coordinated, interactive system. It enables the operator to manage the process as a complete
system, with control over the interrelationship of various subsystems.
Modern distributed control systems are extendable
to provide operating personnel with advanced simulations of equipment behavior. Simulator training is
typically in real-time, ensuring not only a working
understanding of the various steam generator systems,
but also the reaction time and rate of the equipment.
Combined with simulated equipment failures and
43-2
what-if events, the operating personnel can gain valuable experience prior to initial operation.
Preliminary operation should not be entrusted to
inexperienced personnel who are not familiar with the
equipment and the correct operating procedures. Considerable equipment damage and potential safety
events can result from improper preparation of equipment or its misuse during preliminary checkout.
Operator training takes on special significance during the initial operating period required to prepare the
unit for commercial operation. Knowledgeable and
experienced operators are valuable during this period
when the controls and interlocks are being adjusted,
fuel burning equipment is being regulated, operating
procedures are being perfected and preliminary tests
are being conducted to demonstrate the performance
and capabilities of the unit.
Preparations for startup
A systematic approach is required when a new
boiler is being installed or when any boiler has undergone major repairs or alterations. The procedure
varies with boiler design; however, certain steps are
required for all boilers. The steps may be classified as
inspection, cleaning, hydrostatic testing, pre-calibration of instruments and controls, auxiliary equipment
preparation, refractory conditioning, chemical cleaning, steam line cleaning (blowing), safety valve testing and settings, and initial operations for adjustments and testing.
Inspection An inspection of the boiler and auxiliary
equipment serves two purposes: 1) it familiarizes the
operator with the equipment, and 2) it verifies the
condition of the equipment. The inspection should
begin some time during the construction phase and
continue until all items are completed.
One item frequently overlooked during the inspection is the provision or lack of provision for expansion.
The boiler expands as the temperature and pressure
are increased, as do steam lines, flues and ducts, sootblower piping and drain piping. Before pressure is
raised in the boiler, temporary braces, hangers or ties
used during construction must be removed.
Cleaning Debris and foreign material that accumulate during shipment, storage, erection or repairs must
be removed. Debris on the water side can restrict circulation or plug drain lines. Debris on the gas side can
alter gas or air flows. Combustible material on the gas
side can ignite and burn at uncontrollable rates and
cause considerable damage. Glowing embers can be the
source of ignition at times when ignition is not desired.
Fuel lines, especially oil and gas lines, should be
cleaned to prevent subsequent damage to valves and
the plugging of burner parts. Steam cleaning is recommended for all oil and gas lines. Atomizing steam
and atomizing air lines should be cleaned.
Hydrostatic test After the pressure parts are assembled, but before the refractory and casing are installed, a hydrostatic test at 1.5 times the boiler design
pressure is applied to all new boilers and maintained for
a sufficient time to detect any leaks. Testing is equally
important following pressure part replacements at pressures specified in local code requirements.
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
The hydrostatic test is normally the first time the
new boiler is filled with water; therefore, this is the
time to begin using high quality water for the prevention of internal fouling and corrosion. (See Chapter
42.) Demineralized water or condensate treated with
10 ppm of ammonia for pH control and 500 ppm of
hydrazine for control of oxygen should be used for all
nondrainable superheaters and reheaters. A clear filtered water is suitable for components that will be
drained immediately after the hydrostatic test.
Temperature plays an important part in hydrostatic
testing. The metal temperature and therefore the
water temperature must be at or above applicable
Code restrictions for hydrostatic testing. For example,
these restrictions, as stated in the ASME Code, specify
that the hydrostatic test temperature will not be below 70F (21C) to take advantage of the inherent toughness of carbon steel materials as related to temperature.
The water temperature should be kept low enough so
that the pressure parts can be touched and close inspections can be made. It should not be so high that water
escaping from small leaks evaporates immediately or
flashes to steam. Also, the water temperature should
not be more than 100F (56C) above the metal temperature to avoid excessive metal stress transients.
Finally, no air should be trapped in the unit during the hydrostatic test. As the unit is being filled, each
available vent should be open until water appears.
Instrumentation and controls Every natural circulation boiler has at least two indicating instruments:
a water/steam pressure gauge and a water level gauge
glass. If a superheater is involved, some type of steam
temperature indicator is also used. Once-through type
boilers have steam pressure gauges, flow meters and
temperature indicators. These indicators are important
in that the pressure, temperature levels and flows indicated by them must be controlled within design limits. Therefore, the indicators must be correct. Operation should not be attempted until these instruments
are calibrated, and the calibrations should include corrections for actual operating conditions. Water-leg
correction for the pressure gauge is one example. (See
Chapter 40.)
Most modern boilers are controlled automatically
once they are fully commissioned. However, before
these boilers can be started up, the controls must be
operated on manual until the automatic controls have
been adjusted for site-specific conditions. Automatic
control operations should not be attempted until the
automatic functions have been calibrated and proven
reliable over the load range.
Auxiliary equipment The auxiliary equipment must
also be prepared for operation. This equipment includes fans to supply air for combustion and to transport fuel, feedwater pumps to supply water, fuel equipment to prepare and burn the fuel, and air heaters to
heat the air for combustion. This equipment also includes an economizer to heat the water and cool the
flue gas, ash removal equipment, a drain system to
drain the boiler when required, a functioning
sootblowing system to adequately clean the heat
transfer surfaces, and post-combustion environmental control equipment.
Steam 41 / Boiler Operations
Chemical cleaning Water-side cleanliness is important for all boilers because water-side impurities can
lead to boiler tube failures. They can also lead to carryover of solids in the steam, resulting in superheater
tube failure or turbine blade damage.
The flushing of all loose debris from the feedwater
system and boiler, and the use of high quality water
for the hydrostatic test, must be supplemented by
proper water-side cleaning before startup. To remove
accumulations of oil, grease and paint, the natural
circulation boiler is given a caustic and phosphate
boilout after the feedwater system has been given a
phosphate flush. The once-through boiler and its associated pre-boiler equipment are given a similar flushing. This boiling out and/or flushing should be accomplished before operation.
After boiling out and flushing are completed, products of corrosion still remain in the feedwater system
and boiler in the form of iron oxide and mill scale. It
is recommended that acid cleaning for the removal of
this mill scale and iron oxide be delayed until operations at fairly high capacities have carried loose scale
and oxides from the feedwater system to the boiler.
This results in a cleaner boiler for subsequent operations. Chemical cleaning of internal heating surfaces
is described in Chapter 42.
Steam line blowing Fine mesh strainers are customarily installed in turbine inlet steam lines to protect
turbine blades or valves against damage from scale
or other solid material that may be carried by the initial flow of steam. In addition, many operators use
high velocity steam to clean the superheater and steam
lines of any loose scale or foreign material before coupling the steam line to the turbine. The actual procedure used depends on the design of the unit. Temporary piping for flow bypass to the atmosphere is required
with all procedures. This piping and any noise reduction silencers must be securely anchored to resist the high
nozzle reaction created during the high velocity blowing period.
Several methods are used for blowing steam lines,
including particularly high pressure air and steam
blowing. The recommended method and the one most
used is steam blowing because experience has shown
that temperature shock and high velocities are the
most effective means of removing loose scale. Sufficient shock is obtained with a series of blows where
the steam temperature changes during each blow.
Lower pressure, high velocity steam blowing techniques are also available, including those with high
velocity treated water injection to promote thermal
shocking of the mill scale and debris. Designed and
managed correctly, these techniques provide safe removal of scale and other solid particles detrimental to
turbine components.
There are two basic methods of supplying steam for
steam line blowing with a natural or forced circulation boiler. The first method is to use steam returning
from the flash tank to the superheater on the forced
circulation unit or steam flow from the drum on the
natural circulation unit. The second method is to use
high pressure steam directly from the boiler. The latter method supplies large quantities of steam at higher
43-3
The Babcock & Wilcox Company
pressures. Temporary valving is required to control the
flow rates during the blowing period.
Boiler pressure and temperature can be maintained
during the blowing period by continuous firing. If firing is discontinued during the blowing period, it must
be remembered that any change in boiler pressure
changes the saturation temperature throughout the
system. To avoid excessive thermal shock, changes in
boiler pressure should be limited to those corresponding to 75F (42C) in saturation temperature during the
relatively short blowing periods.
Safety valves Safety valves are essential to the safe
operation of any pressure vessel, allowing adequate
relief of excess pressure during abnormal operating
conditions. The set point of each safety valve is normally immediately checked and adjusted if necessary
after reaching full operating pressure for the first time
with steam. Safety valve seats are susceptible to damage from wet steam or grit. This is an essential reason for cleaning the boiler and blowing out the superheater and steam line before testing safety valves.
Safety valves on drum-type boilers are normally
tested both for set point pressure and for the closing
pressures. This generally requires that the boiler pressure be raised until the valve opens and then reduced
for the valves to close.
The testing of safety valves always requires caution. Safety valve exhaust piping and vent piping
should not exert any excessive forces on the safety
valve. Gags should always be used as a safety measure while making adjustments to the valves.
As an alternate, safety valves can be tested and set
with the boiler pressure below the safety valve design
pressure by supplementing the boiler pressure with a
hydraulic lift, attached to the valve stem, in accordance
with the manufacturer’s instructions. This hydraulic
assist method reduces the risk of damage to the valve
seat from extended steam flow in a conventional test.
Startup Operating procedures vary with boiler design. There are, however, certain objectives that
should be included in the operating procedures of every boiler. These objectives include:
1. protection of pressure parts against corrosion,
overheating and thermal stresses,
2. prevention of furnace explosions,
3. production of steam at the desired temperature,
pressure and purity, and
4. compliance with environmental regulations.
Filling In filling the boiler for startup, certain precautions should be taken to protect the pressure parts.
First, high quality water should be used to minimize
water-side corrosion and deposits. Second, the temperature of the water should be regulated to match
the temperature of the boiler metal to prevent thermal stresses. High temperature differentials can cause
thermal stresses in the pressure parts and, if severe,
will adversely affect the life of the pressure parts. High
temperature differentials can also distort the pressure
parts enough to break studs, lugs and other attachments. Differential temperatures up to 100F (56C) are
generally considered acceptable.
A third precaution taken during the filling opera-
43-4
tion is the use of vents to displace all air with water.
This reduces oxygen corrosion and assures that all
boiler tubes are filled with water.
A fourth precaution on drum-type boilers is to establish the correct water level before firing begins. The
water level rises with temperature. Therefore, only 1
in. (25 mm) of water is typically required in the gauge
glass, except with certain special designs that may
require a higher starting level in order to fill all circulating tubes exposed to the hot flue gases.
Circulation Overheating of boiler tubes is prevented
by the flow of fluid through the tubes. Flow is produced
in the natural circulation-type boiler by the force of
gravity acting on fluids of different densities. Flow
starts when the density of the water in the heated tubes
is less than that in the downcomers. This flow increases
as firing rate is increased. (See Chapter 5.) Some drumtype boilers are designed for forced circulation and depend on a circulating pump to assist this flow.
The once-through type boiler depends on the boiler
feedwater pump to produce the necessary flow. Whenever a once-through boiler is being fired, a minimum
design flow must be maintained through the furnace
circuits. With the use of the bypass system, the fluid
can bypass the superheater and turbine to maintain
this minimum design flow until saturated steam is
available for admission to the superheater and until the
turbine is using sufficient steam to maintain the design minimum furnace circuit flow. (See Chapter 19.)
Purging Considerable attention has been given to
the prevention of furnace explosions, especially on
units burning fuel in suspension. Most furnace explosions occur during startup and low load periods. Whenever the possibility exists for the accumulation of combustible gases or combustible dust in any part of the
unit, no attempt should be made to light the burners
until the unit has been thoroughly purged. The National Fire Protection Association Boiler and Combustion Systems Code (NFPA 85:2004) provides the consensus procedures for purging of various boiler and
combustion systems. For multi-burner boilers, the
purge rate from the forced draft fan through the stack
is at least 25% of the full load mass air flow which
must be maintained for the greater of five minutes or
five volume changes of the boiler enclosure. A maximum of 40% of the full load mass air flow is specified
for coal-fired units only, while no upper limit is set for
oil- or gas-fired units.
Protection of economizer Very little water, if any,
is added to the drum-type boiler during the pressure
raising period; consequently, there is no feedwater
flow through the economizer. Economizers are located
in relatively low temperature zones. Nevertheless,
some economizers generate steam during the pressure
raising period. This steam remains trapped until feedwater is fed through the economizer. It not only makes
the control of steam drum water level difficult; it causes
water hammer. This difficulty is overcome if feedwater
is supplied continuously by venting the economizer of
steam or by recirculating boiler water through the
economizer. If a recirculating line is available, the valve
in this line must remain open until feedwater is being
fed continuously through the economizer to the boiler.
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
Protection of primary, secondary and reheat superheater During normal operation, every superheater
tube must have steam flow sufficient to prevent overheating. During startup and before there is steam flow
through every tube, the combustion gas temperature
entering the superheater section must be controlled
to limit superheater metal temperatures to 900F
(482C) for carbon steel tubes and 950 to 1000F (510
to 538C) for various alloy tubes. While firing rate is
used primarily to control gas temperatures, other
means are useful, e.g., excess air, gas recirculation and
burner selection.
Gas temperature entering the superheater during
startup is typically measured with retractable thermoprobes that are removed as soon as steam flow is established in every superheater tube. (See Chapter 40.)
Other permanent gas temperature monitoring devices
are available, but precautions must be taken so that their
installed locations, usage and maintenance are adequate
for the task of measuring gas temperatures entering the
superheater. These devices are required for the first few
startups to establish acceptable firing rates. They should
always be used on the once-through type boiler.
The two prerequisites for steam flow through every superheater tube are: 1) removal of all water from
each tube, and 2) a total steam flow equal to or greater
than approximately 10% of rated steam flow. Water
is removed from drainable superheaters by simply
opening the header drains and vents. Nondrainable
superheaters are not as simple, because the water
must be boiled away. There will be no steam flow
through a tube partially filled with water, and those
portions of the tube not in contact with water will be
subjected to excessive temperatures unless the gas
temperature is limited.
Thermocouples attached to the outlet legs of
nondrainable superheater tubes, where they pass
into the unheated vestibule, will read saturation temperature at the existing pressure until a flow of steam
is established through the tube. The temperature of
these outlet legs rises sharply to significant increases
above saturation immediately after flow is established.
Superheater tubes adjacent to side walls and division
walls are normally the last to boil clear. These should,
therefore, have thermocouples.
Protection of drums and headers In most installations, the time required to place a boiler in service is
limited to the time necessary for raising pressure and
protecting the superheater and the reheater against
overheating. In some cases, however, the time for both
starting up and shutting down may be determined by
the time required to limit the thermal stresses in the
drums and headers. Protection of drums and headers can
pose significant challenges for operators faced with the
need to cycle the steam generator on/off for load demand.
Various rules, based on thermal stress analysis and
supported by operating experience, have been formulated and accepted as general practice. The rules fall
into three categories: one for drums and headers with
rolled tube joints, a second set for headers with welded
tube joints, and a third set for steam drums with
welded tube joints.
On drums and headers with rolled tube joints, the
Steam 41 / Boiler Operations
relatively thin tubes contract and expand at a much
faster rate than the thicker drum or header walls;
therefore, tube seat leaks are likely to occur if heating and cooling rates are not controlled. Heating and
cooling rates have, therefore, been established at 100F
(56C) change in saturation temperature per hour.
Headers with welded tube connections present no
problem with tube seat leaks or with header distortion because the tubes are welded to the headers and
the headers are normally filled with fluid at a constant
temperature. The concern is mainly with temperature
differentials through the header wall and the resulting
incipient cracking if excessive thermal stresses occur.
Steam drums with welded tube connections are not
subject to tube seat leaks but, because they contain
water in the bottom and steam in the top, the heating
and cooling rates vary between the top and the bottom. This results in temperature differences between
the top and the bottom. Stress analyses show that the
principal criterion for reliable rates of heating and
cooling should be based on the relationship between
the temperature differential through the drum wall
and the temperature differential between the top and
bottom of the drum, both of which are measured in
the same circumferential plane. Analysis also shows
that the allowable temperature differentials are based
on tensile strength, drum diameter, wall thickness and
pressure. Therefore, each steam drum has its own
characteristics.
To determine the temperature differentials during
the periods of startup and shutdown, it is necessary
to continuously and accurately obtain the outside and
inside surface temperatures of the drum shell. Temperatures of the outside of the drum shell are best
determined by thermocouples. At least six outside thermocouples are required: two on each end, one on the
top and bottom (all outside the internal baffle and
scrubber area) and two in the center, one top and one
bottom. Temperatures of the inside of the drum shell
are best determined by placing thermocouples on one
of the riser tubes entering the bottom of the drum, one
on each end, and one in the center.
There are two periods when the steam in the top of
the drum is hotter than the water occupying the lower
half. One period is soon after firing begins on boilers
with large nondrainable superheaters. Steam forms
first in the superheater and flows back to the steam
drum where it heats the top of the drum. A second
period is during cooling when cold air is pumped
through the boiler by the forced draft fans. The boiler
water cools, but the steam in the top of the steam drum
remains at essentially the same temperature.
The temperatures of the top and bottom can be
brought close together by flooding the steam drum
with water. Firing must be stopped and water must
not be allowed to spill over into the superheater. A high
level gauge glass is needed for this operation. However, thermocouples attached to the superheater supply tubes can be used to indicate when the drum is
flooded because there is a sharp change in temperature when water enters these supply tubes. Allowable
temperature differentials for cooling are stringent,
considerably more so than for heating. Fast cooling
43-5
The Babcock & Wilcox Company
should, therefore, be supervised with the use of thermocouples and a high level gauge glass.
Cooling is particularly important when the boiler
is to be drained for short outages. The steam drum
must be cooled to permit filling with the available
water without exceeding the allowable temperature
rate of change. (See Fig. 1.) A wider latitude is permitted if the water used for filling is hotter than the
steam drum.
Before removing the unit from service, a more uniform cooling can be achieved by reducing pressure to
approximately two-thirds of the normal operating
pressure. This reduces the temperature of both the
water and steam in the steam drum.
Rate of Change, F(C)/h
Operating techniques for maximum efficiency
Fuel is a major cost in boiler operation. It is therefore important to minimize fuel consumption and
maximize steam production. Although a boiler’s efficiency is primarily a result of its design, the operator
can maintain or significantly improve efficiency by
controlling heat losses to the stack and losses to the
ash pit.
Stack losses The total heat that exits the stack is
controlled by the quantity and the temperature of the
flue gas. The quantity of gas is dependent on the fuel
being burned, but is also influenced by the amount
of excess air supplied to the burners. While sufficient
air must be provided to complete the combustion process, excessive quantities of air simply carry extra heat
out of the stack.
The temperature of the flue gas is affected by the
cleanliness of the boiler heat transfer surfaces. This
in turn is dependent on sootblower and air heater
operation. Optimal cleanliness of the heat transfer
surfaces is achievable with commercial sensors and
control systems that measure the heat transfer effectiveness of the boiler banks, evaluate against the design duty, and clean only on an as-needed basis. While
high gas exit temperatures waste energy, excessively
low temperatures may also be unacceptable. Corrosion
can occur at the acid dew point of the gas where corrosive constituents condense on the cooler metal surfaces.
Ash plugging of heat transfer surfaces can be aggravated by the presence of condensate. Equipment protec-
400
(222)
Unsafe
300
(167)
Safe
200
(111)
0
0
100
200
300
400
500
(56)
(111)
(167)
(222)
(278)
Total Change of Saturation Temperature, F(C)
600
(333)
Fig. 1 Permissible rate of change for saturation temperature, drum
and furnace.
43-6
tion and performance of backend environmental components [selective catalytic reduction (SCR) system protection, for example] can also be constraints in desirable
steam generator gas temperature.
Pressures and temperatures Most boilers supply
steam to turbines or processes that require heat. These
processes rely on design pressures and temperatures.
Deviations from the set points may result in lower overall efficiency of the power cycle, loss of production, or
damage to the product or process.
In units that produce saturated steam, boiler temperature is directly related to the operating pressure.
For many industrial applications, the process requirements dictate the steam temperature and consequently the operating pressure.
For electric power producing steam systems, steam
temperature has a significant impact on turbine efficiency. Modern controls can typically maintain this
temperature within 10F (6C) of the desired setting.
Each 50F (28C) reduction in steam temperature reduces cycle efficiency by approximately 1% on a supercritical pressure unit.
Variable pressure operation Historically, utility
power boilers in the United States (U.S.) have been
operated at a constant steam pressure and the turbine
load has been controlled by varying the throttle valves
at the turbine inlet. This causes an efficiency loss due
to the temperature drop across the throttle valves.
In variable pressure operation, boiler pressure is
varied to meet turbine requirements. This can significantly improve cycle efficiency when operating at low
loads (15 to 40% of MCR). However, boiler response
to turbine requirements is slower in this mode. When
fast response is needed, pressure increments are used.
At a given pressure, the throttle valves control the
steam to the turbine and provide quick response. As
turbine requirements increase and the valves approach full open position, the boiler pressure is increased to the next increment. This arrangement provides high efficiency while retaining quick response.
Emissions requirements The majority of the steam
generators in operation today were not originally designed for today’s environmental regulations. Hardware changes made to accomplish the emissions reduction are typically accompanied by new operating
philosophies and guidelines for efficiency and equipment protection. To maintain optimal SCR efficiency
and minimal ammonia usage/slip the combustion system is optimized to generate the lowest level of nitrogen oxides (NOx) possible. Staging of combustion air
is frequently used in firing system upgrades. Sufficient care must be taken to ensure that lower furnace
corrosion associated with the reducing atmosphere is
not excessive, especially with high sulfur content fuels. Depending on system design, there may be
tradeoffs between lower NOx generation and increases
in the carbon content in the ash and carbon monoxide (CO) in the flue gas. To maintain ash quality suitable for disposal/sale, operational balance must be
achieved within the combustion process. Furnace combustion is also usually controlled to achieve any specific CO emissions rate.
Combustion optimization A modern DCS is equipped
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
to offer significantly more information and analysis,
assisting the operating personnel in optimizing the
steam generator. Closed loop neural network systems
and other advanced intelligent control systems have
made strides in maintaining optimum operations consistently throughout the operating range. Variants of
these systems use complex databases and algorithms
of unit-specific operating scenarios to guide the controlling parameters during steady state and transient
operation. Extensive parametric testing of the unit is
conducted to define the characteristics and boundaries
of the operating variables. As long as no subsequent
mechanical modifications are added and proper equipment maintenance is available, these advanced control systems are capable of consistently returning the
steam generator to its most optimum operating condition. A significant attribute of these systems is the
ability to target specific results during optimization
and change the targeted parameter as needed. As the
result, NOx can be minimized during selected periods
and heat rate can be minimized the rest of the operating year.
Key operation functions
Burner adjustments The fuel and combustion air
combine and release heat at the burners. To maintain
even heat distribution across the width of the furnace,
air and fuel flows must be evenly supplied to all burners. While individual burner adjustments affect a
particular burner, they also impact adjacent burners.
Most boilers have multiple burners in parallel flow
paths on the front and/or rear furnace walls. Burners must be similar in design and must be adjusted in
the same way to optimize air flow distribution. For a
detailed discussion of burner features refer to Chapters 11 and 14.
Adjustments can typically vary the turbulence and
flow rates in burners. Increased turbulence increases
the air-fuel mixing. It also increases the combustion
intensity, provides faster heat release, reduces unburned carbon (UBC) in the ash, permits operation
with less excess air, and increases boiler efficiency.
However, increased slagging, increased NOx emissions
and higher fan power consumption can also result.
Fuel adjustments on an individual burner basis are
also possible, either through diverter mechanisms in
the fuel preparation system or through flow balancing devices in the coal transport piping. While possible,
the dynamic balancing of fuel flows is difficult. As with
combustion air adjustments, potential impacts to adjacent burners will require reliable feedback on relative flow rates to be effective as a dynamic operational
tool. Advances in flame characterization systems and
sensors for post-combustion constituents are providing more precise feedback targets for on-line fuel balancing, as are in situ coal and combustion air flow
measurement devices.
Overfire air port adjustments Burner systems intended for NOx reduction are typically staged at the
primary combustion elevation and usually operated
with less than theoretical air for complete combustion.
The remaining air needed to complete the burning process is introduced separately, above the highest burner
Steam 41 / Boiler Operations
zone. The overfire air (OFA) flows are typically varied as a function of load, based on parametric testing
performed during commissioning. While normally satisfactory for ensuring complete combustion and emissions compliance, any changes to fuel type, fuel preparation quality, or the fuel/air transport systems will
require close monitoring of OFA system performance.
More advanced dynamic control schemes are available, dependent on measurement feedback of the combustion process in the upper furnace zones.
Excess air The total combustion air flow to a boiler
is generally controlled by adjusting forced and induced
draft fan dampers in relation to the fuel flow. Excess
air is the amount of additional combustion air over that
required to theoretically burn a given amount of fuel.
The benefits of increasing excess air include increased
combustion intensity, reduced carbon loss and/or CO
formation, and reduced slagging conditions. Disadvantages include increased fan power consumption, increased heat loss up the stack, increased tube erosion,
and possibly increased NOx formation.
For most coal ashes, particularly those from eastern U.S. bituminous coals, the solid to liquid phase
changes occur at lower temperatures if free oxygen is
not present (reducing conditions) around the ash particles. As a result, more slagging occurs in a boiler
operating with insufficient excess air where localized
reducing conditions can occur.
Localized tube metal wastage may also occur in
furnace walls under low excess air conditions but the
impact is less clearly defined. The absence of free oxygen (a reducing atmosphere) and the presence of sulfur (from the fuel) are known causes of tube metal
wastage. The sulfur combines with hydrogen from the
fuel to form hydrogen sulfide (H2S). The H2S reacts
with the iron in the tube metal and forms iron sulfide,
which is subsequently swept away with the flue gas.
High chlorine levels can also promote tube wastage.
Although coals and most conventional fuels burned
in the U.S. contain very little chlorine, it is a problem
in refuse-derived fuels. (See Chapter 29.)
Fuel conditions Fuel conditions are temperature,
pressure and, if solid, mean particle size and distribution. Cooler temperatures, lower pressure and
larger particle size contribute to less complete combustion and increased unburned carbon in the ash. Conversely, if the fuel is hotter, finer and at a higher pressure, combustion is improved. Unfortunately NOx emissions and slagging can also increase with these conditions. Current day combustion technologies employ
multi-zone low NOx burners to control the pace of combustion and are more demanding on mean particle size
and distribution for control of NOx and UBC production.
Effects of fuel preparation equipment on boiler performance Fuel preparation equipment readies the fuel
for combustion and can have a significant impact on
pollutant emissions. The preparation equipment may
be the crushers, pulverizers and drying systems on
coal-fired units; fuel oil heaters and pumps on oil-fired
units; refuse handling, mixing or drying equipment
on refuse-fired boilers; or fuel handling, blending, sizing and delivery equipment on stoker-fired units. If
this equipment is not properly operated, the fuel may
43-7
The Babcock & Wilcox Company
not be completely burned, leaving UBC in the ash or
carbon monoxide (CO) in the flue gas.
The operator must monitor the fuel preparation
equipment. Knowledge of the equipment, its maintenance record and operating characteristics is essential.
Feedwater and boiler water conditioning requirements
The main function of a boiler is to transfer heat from
combustion gases through tube walls to heat water and
produce steam. Clean metal tubes are good conductors, but impurities in the water can collect on the
inside surface of the tubes. These deposits reduce heat
transfer, elevate tube temperatures, and can lead to
tube failures. Water conditioning is essential to minimize deposits and maintain unit availability. (See
Chapter 42.)
Sootblower operations As discussed in Chapter 24,
a sootblower is an automated device that uses steam,
compressed air, or high pressure water to remove ash
deposits from tube surfaces. Sootblowing improves heat
transfer by reducing fouling and plugging. However,
excessive sootblowing can result in increased operating cost, tube erosion and increased sootblower maintenance. Conversely, infrequent sootblower operation
can reduce boiler efficiency and capacity. Optimum
sootblowing depends on load conditions, combustion
quality and fuel. With the increased dependency in
the U.S. on Powder River Basin (PRB) coal and the
cost attractiveness of spot market fuels, advanced sootblowing control systems are being increasingly deployed to assist the operators. Unlike manual guidelines, these intelligent systems do not rely on fuel
characteristics to influence cleaning patterns. Rather,
they focus primarily on the heat transfer surfaces and
monitor efficiency. Since cleaning decisions are based
solely on an as-needed basis, the intelligent sootblowing systems are ideally suited for operations dealing
with changing fuel blends. Furnace-based sootblowing
equipment is increasingly being controlled with advanced control schemes that monitor the heat flux in
select zones, supervise blower operation for effectiveness,
and minimize thermal shock to the furnace wall tubes.
Personnel safety Operating instructions usually
deal primarily with the protection of equipment. Rules
and devices for personnel protection are also essential. The items listed here are based on actual operating experience and point out some personnel safety
considerations.
1. When viewing flames or furnace conditions, always wear tinted goggles or a tinted shield to protect the eyes from harmful light intensity and flying ash or slag particles.
2. Do not stand directly in front of open ports or
doors, especially when they are being opened.
Furnace pulsations caused by firing conditions,
sootblower operation, or tube failure can blow hot
furnace gases out of open doors, even on suctionfired units. Aspirating air is used on inspection
doors and ports of pressure-fired units to prevent
the escape of hot furnace gases. The aspirating jets
can become blocked, or the aspirating air supply can
fail. In some cases, the entire observation port or door
can be covered with slag, causing the aspirating air
to blast slag and ash out into the boiler room.
43-8
3. Do not use open-ended pipes for rodding observation ports or slag on furnace walls. Hot gases
can be discharged through the open ended pipe
directly onto its handler. The pipe can also become
excessively hot.
4. When handling any type of rod or probe in the
furnace, especially in coal-fired furnaces, be prepared for falling slag striking the rod or probe.
The fulcrum action can inflict severe injuries.
5. Be prepared for slag leaks. Iron oxides in coal can
be reduced to molten iron or iron sulfides in a
reducing atmosphere in the furnace resulting
from combustion with insufficient air. This molten iron can wash away refractory, seals and
tubes, and leak out onto equipment or personnel.
6. Never enter a vessel, especially a boiler drum,
until all steam and water valves, including drain
and blowdown valves, have been closed and
locked or tagged. It is possible for steam and hot
water to back up through drain and blowdown piping, especially when more than one boiler or vessel
is connected to the same drain or blowdown tank.
7. Be prepared for hot water in drums and headers
when removing manhole plates and handhole covers.
8. Do not enter a confined space until it has been
cooled, purged of combustible and dangerous
gases and properly ventilated with precautions
taken to keep the entrance open. Station a worker
at the entrance and notify the responsible person.
9. Be prepared for falling slag and dust when entering the boiler setting or ash pit.
10. Use low voltage extension cords or cords with
ground fault interrupters. Bulbs on extension
cords and flashlights should be explosion proof.
11. Never step into flyash. It can be cold on the surface yet remain hot and smoldering underneath
for extended periods even after the pressure parts
are cool.
12. Never use toxic or volatile fluids in confined
spaces.
13. Never open or enter rotating equipment until it
has come to a complete stop and its circuit breaker
is locked open and any other drive devices are
immobilized. Some types of rotating equipment
can be set into motion with very little force. These
types should be locked with a brake or other suitable device to prevent rotation.
14. Always secure the drive mechanism of dampers,
gates and doors before passing through them.
15. Do not inspect for tube leak locations until metal
and refractory surfaces are cool, and ash accumulations are removed.
Performance tests Many steam generating units are
operating day after day with efficiencies at or near
design values. Any unit can operate at these efficiencies with the proper instrumentation, a reasonable
equipment and instrument maintenance program,
and proper operating procedures.
Early in the life of the unit when the gas side is
relatively clean, the casing is tight, the insulation is
new, the fuel burning equipment has been adjusted
for optimum performance and the fuel/air ratio has
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
been set correctly, performance tests should be conducted to determine the major controllable heat losses.
These losses are the dry gas to the stack and, on coalfired units, combustible in the ash or slag.
During these tests, accurate data should be taken
to serve as reference points for future operation. Sampling points that give representative indications of
gas temperatures, excess air and combustibles in the
ash should be established and data from these points
recorded. Items related to the major controllable losses
should also be recorded at this time, e.g., draft losses,
air flows, burner settings, steam flow, steam and feedwater temperatures, fuel flow and air temperatures.
Procedures for performance tests are provided in the
American Society of Mechanical Engineers (ASME)
Performance Test Codes, PTC 4, Steam Generating Units;
PTC 4.2, Coal Pulverizers; and PTC 4.3, Air Heaters.
Abnormal operation
Low water If water level in the drum drops below
the minimum required (as determined by the manufacturer), fuel firing should be stopped. Caution
should be exercised when adding water to restore the
drum level due to the potential of temperature shock
from the relatively cooler water coming in contact with
hot drum metal. Thermocouples on the top and bottom of the drum will indicate if the bottom of the drum
is being rapidly cooled by feedwater addition, which
would result in unacceptable top-to-bottom temperature differentials. If water level indicators show there
is still some water remaining in the drum, then feedwater may be slowly added using the thermocouples
as a guide. If the drum is completely empty, then water may only be added periodically with soak times
provided to allow drum temperature to equalize. (See
Protection of drums and headers.)
Tube failures Operating a boiler with a known tube
leak is not recommended. Steam or water escaping
from a small leak can cut other tubes by impingement
and set up a chain reaction of tube failures. By the
loss of water or steam, a tube failure can alter boiler
circulation or flow and result in other circuits being
overheated. This is one reason why furnace risers on
once-through type boilers should be continuously
monitored. A tube failure can also cause loss of ignition and a furnace explosion if re-ignition occurs. As
discussed later in the chapter, process recovery boilers are particularly sensitive to tube leaks because of
the potential for smelt-water reactions, which can lead
to boiler explosions.
Any unusual increase in furnace riser temperature
on the once-through type boiler is an indication of
furnace tube leakage. Small leaks can sometimes be
detected by the loss of water from the system, the loss
of chemicals from a drum-type boiler, or by the noise
made by the leak. If a leak is suspected, the boiler
should be shut down as soon as normal operating procedures permit. After the leak is then located by hydrostatic testing, it should be repaired.
Several items must be considered when a tube failure occurs. In some cases where the steam drum water
level can not be maintained, the operator should shut
off all fuel flow and completely shut off any output of
steam from the boiler. When the fuel has been turned
Steam 41 / Boiler Operations
off, the furnace should be purged of any combustible
gases and feedwater flow to the boiler should be
stopped. The air flow should be reduced to a minimum
as soon as the furnace purge is completed. This procedure reduces the loss of boiler pressure and the corresponding drop in water temperature within the boiler.
The firing rate or the flow of hot gases can not be
stopped immediately on some waste heat boilers or on
certain types of stoker-fired boilers. Several factors are
involved in the decision to continue the flow of feedwater, even though the steam drum water level can
not be maintained. In general, as long as the temperature of the combustion gases is hot enough to damage the unit, the feedwater flow should be continued.
(See later discussion for chemical recovery units.) The
thermal shock resulting from feeding relatively cold
feedwater into an empty steam drum should also be
considered. (See Protection of drums and headers.)
Thermal shock is minimized if the feedwater is hot,
the unit has an economizer, and the feedwater mixes
with the existing boiler water.
After the unit has been cooled, personnel should
make a complete inspection for evidence of overheating and for incipient cracks, especially to headers,
drums, and welded attachments. (See Personnel
safety, especially when the potential of hot materials,
boiler fluids, or combustibles is present.)
An investigation of the tube failure is very important so that the condition(s) causing the tube failure
can be eliminated and future failures prevented. This
investigation should include a careful visual inspection of the failed tube. In some cases, a laboratory
analysis or consideration of background information
leading up to the tube failure is required. This information should include the location of the failure, the
length of time the unit has been in operation, load
conditions, startup and shutdown conditions, feedwater treatment and internal deposits.
Shutdown operations
Boiler shutdown is less complicated than startup.
The emphasis again is on safety and protection of unit
materials. Two shutdown situations may occur: a controlled shutdown, or one required in an emergency.
Under controlled conditions, the firing rate is gradually reduced. Once the combustion equipment is
brought to its minimum capacity, the fuel is shut off
and the boiler is purged with fresh air. If some pressure is to be maintained the fans are shut down and
the dampers are closed. The drum pressure gradually
lowers as heat is lost from the boiler setting; a minimal amount of air drifts out of the stack. If inspection
and maintenance are required, the draft fans remain
on to cool the boiler more quickly. If the unit is
equipped with a regenerative air heater, it is shut
down, allowing the boiler to cool faster. If a tubular
air heater is present, this heat trap can only be bypassed
to help cool the boiler. The cool down rate should not
exceed 100F (56C) per hour of saturation temperature
change to prevent damage due to thermal stress.
In an emergency shutdown, the fuel is immediately
shut off and the boiler is purged of combustible gases.
Additional procedures may apply to the fuel feed equip43-9
The Babcock & Wilcox Company
ment. The boiler may be held at a reduced pressure
or may be completely cooled as described above.
Operation of Cyclone furnaces
The Cyclone component of a Cyclone™ furnace is
a cylindrical chamber designed to burn crushed coal.
The basic design, sizing and general operation of Cyclone furnaces are covered in Chapter 15. The key
feature that affects operations is the collection of most
of the coal ash as a liquid slag in the Cyclone chamber. This slag is continuously tapped into the furnace
through a hole at the discharge end of the Cyclone.
The slag collects on the furnace floor and flows through
a tap into a water filled tank where the chilling effect of
the water leaves the slag in granular form. Unique operational issues center upon maintaining desired furnace
slag tapping without excessive maintenance.
Fuels
A key operating parameter of Cyclone units is the
selection of a proper coal. Fuels acceptable for Cyclone
firing must generally meet the following specifications
subject to site-specific conditions:
Bituminous coals:
1. maximum total moisture – 20%
2. ash content – 6 to 25%, dry basis
3. minimum volatile matter – 15%, dry basis
4. ash (slag) viscosity – refer to Table 2
5. ash iron ratio and sulfur content – See Chapter
15, Fig. 4
Subbituminous coals and lignite:
1a. maximum total moisture for a direct-fired system,
but without a pre-dry system – 30%
1b. maximum total moisture with pre-dry system –
42%
2. minimum high heating value – 6000 Btu/lb
(13,956 kJ/kg), as-fired
3. ash content – 5 to 25%, dry basis
4. ash (slag) viscosity – refer to Table 2
For proper combustion and efficient unit operation,
properly sized crushed coal is required. This is especially important for subbituminous coals, where the
higher moisture content requires a finer coal grind to
maintain Cyclone temperatures and to minimize unburned carbon in the flyash.
Combustion air
All Cyclone furnaces use heated air at a high static
pressure. The air temperature ranges from 500 to 750F
(260 to 399C), depending on the unit design and the
rank of the fuel. The static differential across the
Cyclone ranges from 32 to 50 in. wg (8 to 12.5 kPa).
This high pressure produces the very high velocities
which, in turn, produce the scrubbing action required
for complete combustion of the crushed coal.
A key variable in Cyclone operation is excess air.
For bituminous coals, which are generally high in
sulfur and iron content, 15 to 18% excess air is recommended at full load operation. Operation at lower
excess air can promote an oxygen-deficient reducing
atmosphere, which can significantly increase unit
43-10
maintenance. Operation with molten slag and deficient air can result in iron sulfide attack (wastage) of
the boiler tubes. When operated with insufficient excess air, fuels with high iron content can smelt the iron
from the ash. A pig iron, which forms a strong bond
to the boiler tubing, can form and may result in tube
damage during deposit removal.
Operation with high levels of excess air leads to
lower thermal efficiency and results in Cyclone cooling. This hinders slag tapping. On multiple Cyclone
units, it is important to accurately measure the secondary air and coal flow to each Cyclone to ensure it
is operating with the proper air/fuel ratio.
Because proper excess air is essential, theoretical
air curves should be used to readjust the excess air
levels when one unit of a multiple Cyclone furnace is
removed from service.
Firing subbituminous coals is generally more difficult due to increased fuel moisture which must be
evaporated during combustion. Units designed for
subbituminous coal firing have provisions for higher
air temperature and generally run with 10 to 12%
excess air.
Due to environmental concerns, some bituminous
coal-fired Cyclone furnaces have been converted to
burn low sulfur subbituminous coal or coal blends.
Subbituminous coal has a lower ash content than most
bituminous coals. As a result, less slag is available to
trap the raw coal particles. This, combined with the
depressed flame temperature caused by the increased
moisture content, can result in less coal being entrapped in the slag where the combustion is completed.
Acting on the additional environmental concerns, utilities have installed OFA systems for combustion NOx
control. While furnace wall corrosion remains a concern, worthwhile NOx reductions have been attained
with fuel rich stoichiometry and lower sulfur fuels. These
Cyclone operating techniques have changed the operating practices of these slagging combustors.
When firing higher moisture subbituminous coal,
smaller crushed coal particle size is required and
higher transport air temperature is desired.
Table 2
Ash Viscosity Requirements
Maximum T250*
Coal Rank Ash Viscosity
As-Fired
Total Moisture %
Bituminous
2450F (1343C)
Subbituminous − direct-fired
2300F (1260C)
Subbituminous/lignite**
2300F (1260C)
Lignite***
2300F (1260C)
0 to 20
21 to 30
31 to 35
36 to 42
* T250 is the temperature at which the ash viscosity
is 250 poise.
** For lignite firing, a fuel pre-dry system is required.
*** For high moisture lignite firing, pre-dry and
moisture separator systems are required.
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
As the moisture content reaches the 20% range at
design Cyclone fuel inputs, clinkering and UBC in the
Cyclone and on the furnace floor can increase dramatically. Levels of unburned carbon also increase in
the ash in the economizer, air heater and precipitator
hoppers. Supplemental firing with fuel oil or natural
gas along with design changes may be required if the
unit was not originally designed for this condition.
Several Cyclone units are operating on high moisture North Dakota lignite fuel. This is accomplished
by the use of a pre-dry system, as illustrated in Chapter 15. In this system, hot air [750F (399C)] is introduced to the raw coal stream prior to crushing in a pressurized and heated conditioner. The hot air-coal mixture
then travels to a cyclone separator, where the saturated
air and some coal fines are separated from the coal
stream and are injected into the lower furnace. The dried
coal is then carried by a lift line to the Cyclone burner.
Operation of once-through boilers
Principles
In full once-through operation, high pressure water enters the economizer and high pressure steam
leaves the superheater; there is no recirculation of
steam or water within the unit. The path is through
multiple parallel tube circuits arranged in series. Design and construction details are found in Chapters
19 and 26. This type of boiler can be conceptualized
as a long heated pipe with continuous coolant flowing through it. As the fluid progresses through the
components, heat is absorbed from the combustion
process. The final steam temperature is dependent on
the feedwater inlet temperature and ratio of the fluid
flow to the heat available, which have important implications on unit operation.
Operating practice
The once-through steam generator, referred to by
The Babcock & Wilcox Company (B&W) as the Universal Pressure (UP) boiler, has operating characteristics not seen in drum units. The UP boiler is capable
of operating above the critical pressure point [3200 psi
(22.1 MPa)] and can deliver steam pressure and temperature conditions without a steam-water separation
device after startup. The original UP boilers are typically designed and operated for base load operation.
To address the increasing demand for operational flexibility, the B&W Spiral Wound Universal Pressure
(SWUP) boiler is capable of variable pressure operation and on/off cycling, as well as load cycling and base
load operation. This spiral wound tube geometry UP
boiler, including its startup and bypass systems, minimize the thermal upsets during transients, allowing
rapid load changes.
To start up a UP boiler, a steam/water separation
device (flash tank or vertical steam separator), with
appropriate valving and piping to bypass and return
fluid to the cycle, is supplied. The modern bypass systems are highly automated and very effective in
achieving smooth operation. The bypass system is in
service only during low load operation.
Steam 41 / Boiler Operations
The major control functions for fuel, air, water and
steam flow are highly interactive placing unique constraints on operation. Though today’s integrated control systems manage many operating functions, it is
still important for the operator to fully understand the
relationships between short-term (transient) and longterm (steady-state) energy transfer effects and to carefully monitor and coordinate, as required, all control
actions. Modern control systems are often referred to
as coordinated systems. (See Chapter 41.) The combustion systems are conventional; they are subject to the
normal concerns of fuel utilization, efficiency and safety.
The operator has three main controls for operating
a UP boiler:
1. firing rate,
2. feedwater control, and
3. steam flow/steam pressure.
Firing rate The long-term demand for firing rate is
directly proportional to load. The short-term effects of
firing rate impact steam temperature and pressure.
During increases in firing rate the steam temperature
increases until the feedwater flow is increased to compensate and balance the new firing rate. Steam pressure increases in a similar fashion to that of a drum
boiler. In a supercritical pressure application, there is
no large rise in specific volume during the transition
from liquid to vapor conditions. However, there is still
a large increase in specific volume as a supercritical
fluid is heated. With this expansion, the turbine control valves are opened and flow is increased to maintain pressure. With the many interactions that are a
consequence of firing rate, the operator and automated control system should strive to position firing
rate for the desired electrical load and then manipulate
other variables to control temperature and pressure.
Feedwater flow The outlet steam temperature is
dependent in steady-state conditions on the ratio of
feedwater flow rate to firing rate. Because it is desirable to position firing rate based on electrical demand,
feedwater flow control is based on outlet steam temperature. The short term effect of feedwater flow
changes is to increase or decrease steam pressure and
electrical load. The load change results because energy is placed into or brought out of storage through
cooling or heating of the boiler metals. However, this
load change is transitory. Pressure is a measure of the
balance between steam flow and feedwater flow. The
outlet pressure is constant if they are matched. The
operator can, therefore, use feedwater to assist in recovery from transients and upsets, but ultimately must
position feedwater flow for the appropriate outlet steam
temperature.
Steam flow/steam pressure In steady-state conditions, steam flow is the same as feedwater flow, and
boiler pressure is determined by turbine throttle valve
position. In the short term, a change in steam flow
impacts steam temperature and electrical load. This
is because increasing steam flow at a constant firing
rate affects the balance of the two and the steam temperature drops initially as a consequence to electrical
load increase. This can not be a lasting effect, however, as steam and feedwater flows eventually match
43-11
The Babcock & Wilcox Company
each other at a different pressure. Similarly, load may
be changed by adjusting the turbine throttle valve
which increases or decreases steam flow, but this load
change comes from depleting or building stored energy in the form of pressure. As above, steam flow may
be manipulated to help restore control of steam temperature and load, but it ultimately must be controlled
to achieve the desired operating pressure.
Operating skills
Efficiency The supercritical boiler provides very
high cycle efficiency. This inherent efficiency can be
maintained throughout boiler life with proper instrumentation and maintenance. The operator must be
thoroughly trained to know the optimum operating
parameters. Deviations in these parameters may then
be addressed with instrument maintenance, direct
operator action (such as sootblowing) or an engineering investigation. Performance tests should be conducted on a regular basis. Besides the conventional
need to minimize heat losses, these tests can be used
to confirm control system calibration. Test results
should be reviewed with the operator.
Startup systems Chapter 19 provides a comprehensive overview of the configuration and operation of
state-of-the-art startup and bypass systems for variable and constant furnace pressure once-through
boiler systems. Systems for UP boilers have evolved
as the understanding and experience of the oncethrough concept have increased. A key requirement
for the startup system is to maintain adequate flow
in the furnace walls (30% for most variable pressure
supercritical units, 25% for most constant pressure
supercritical units, and 33% for most subcritical units)
to protect them from overheating during startup and
low load operation. Initial designs (first generation)
simply bypassed any excess flow from the furnace, not
required for the turbine power generation, directly to
the condenser from the high pressure turbine inlet.
Second generation startup systems added a steamwater separation device called a flash tank (including steam-water separation equipment) after the convection pass enclosure circuits, but upstream of the
primary superheater. This permitted the generation
of dry steam for turbine roll and synchronization. The
flash tank was effectively a small drum including
drum internals. (See Fig. 2.)
Subsequent constant pressure third generation designs moved the bypass line plus necessary valves
(200 and 201) downstream of the primary superheater
so that the primary superheater is always in the initial flow circuit. (See Fig. 3 for key elements.)
Steam is produced in the flash tank because the
pressure reducing valve (207 in Fig. 3) drops the pressure from supercritical to approximately 1000 psig
(6.89 MPa) in current designs. For a smooth transition or changeover from startup (flash tank) to oncethrough operation, the enthalpy of the flash tank steam
must be matched with the enthalpy leaving the 201
valve. Because the flash tank generally operates at
1000 psig (6.89 MPa), the throttle pressure to the turbine is only ramped to full pressure after transition
from the flash tank.
43-12
Due to the need for flexibility of the variable furnace pressure SWUP designs, startup and bypass
systems have changed to incorporate features of the
subcritical drum and supercritical once-through
startup systems. As shown in Fig. 4 (key elements
only), the SWUP system has evolved from the second
generation system shown in Fig. 2 with the replacement of the valves and flask tank with vertical steam
separators, a water collection tank and a boiler circulation pump. At startup and low load, the flow passes
through the vertical steam separators where steam is
removed and sent to the superheater and water is
discharged to the water collection tank. Water then
flows through the boiler circulation pump to maintain
the minimum furnace wall circulation. Any excess
water accumulated during startup is sent to the condenser through the 341 valves. When unit operation
reaches the load where the sum of the furnace flow
plus the attemperator spray flows is equal to the main
steam flow rate, once-through operation is achieved,
the 381 valves are closed, and the boiler circulation
pump is shut down.
Limits and precautions The once-through nature of
UP boilers results in special limits and precautions that
must be observed for reliable and dependable operation:
1. Feedwater conductivity – unlike a drum boiler
which can release suspended solids through
blowdown, all hardness and other contaminants
that enter the boiler in the feedwater are deposited on the water side of the heating surface or in
the superheater. Deposition can lead to overheating and tube failures. Boiler firing must be stopped
if conductivity exceeds 2.0 microsiemens for five minutes or if it exceeds 5.0 microsiemens for two minutes. The operator should be trained in water quality control requirements. (See Chapter 42.)
2. Minimum feedwater flow – firing is not permitted
unless the boiler feedwater flow is above the specified minimum. The boiler is to be immediately shut
down if flow falls below 85% of minimum for twenty
seconds or 70% of minimum for one second.
Fig. 2 Second generation UP startup system schematic.
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
Fig. 3 Third generation UP startup system with primary superheater
in initial flow circuit.
3. Feedwater temperature – the heat input required
per unit of water flow is dependent on the difference between the feedwater inlet temperature and
the controlled outlet steam temperature. If feedwater temperature is reduced while the outlet temperature is maintained (by overfiring), the heat
input to the furnace can exceed design levels that
may result in damage to the tube material. For
units that were not designed for a feedwater
heater out of service, removal of a feedwater
heater will require that the final steam temperature be reduced to hold furnace heat input rates
within design limits. Unless specific information
is provided, the general rule is to reduce steam
temperature one degree F for every two degrees
F that the feedwater temperature is low.
TTV
Spray Water
Attemperator
Secondary
Superheater
HP
Reheater
Primary
Superheater
Convection Pass
Vertical
Steam
Separator(s)
L
P
341
Furnace
Economizer
381
Water
Collection
Tank
Boiler
Circulation
Pump
Fig. 4 Startup system for a SWUP boiler (key elements).
Steam 41 / Boiler Operations
IP
Condenser
4. Overfiring – for supercritical units, the fluid in the
furnace has no latent heat of vaporization as in a
subcritical boiler. Consequently, as heat is absorbed,
the fluid temperature is always increasing and the
furnace tube metal temperatures increase. Firing
in excess of design rates can result in excessive tube
metal temperatures in selected furnace locations.
The operator must therefore observe a strict limit
of transient heat input. A maximum of 1.15 times
the steady-state rate is a typical guideline. This rate,
at various load conditions, should be clearly established by combustion tests.
5. Tube leaks – operation with a tube leak is not recommended on any boiler. For once-through units,
the situation is more critical because the leakage
can reduce cooling flow to subsequent tubes or
circuits downstream.
6. Low pressure limit – a constant pressure supercritical
UP boiler must be tripped if the fluid pressure in the
furnace falls below 3200 psig (22.1 MPa) for fifteen
seconds. Failure to do so can result in improper circuit flow, inadequate tube cooling and furnace tube
failures. For the SWUP boilers the units are designed
for specific variable pressure ramps. To avoid possible tube damage, the units must operate along design pressure ramp curves.
Operation of fluidized-bed boilers
Chapter 17 provides a detailed discussion of fluidized-bed combustion systems. The following sections
provide selected remarks on general fluidized-bed
boiler operation, both circulating fluidized-bed (CFB)
systems and bubbling fluidized-bed (BFB) systems.
CFB systems overview
The CFB is constructed and behaves like a conventional drum boiler in many respects. However, thermal performance, combustion efficiency, furnace absorption pattern and sulfur dioxide (SO2) control are
strongly influenced by the mass of solids in the bed
(inventory), the size distribution of the bed material
(bed sizing), and the circulating rate of the bed (flow
rate). Bed density can be described as bulk density
which is a measure of the material weight per unit
volume. There is a higher density and inventory in
the lower furnace, made of coarser particles (average
size 200 to 400 micron), and a lower density and inventory in the upper furnace (also called furnace
shaft) made of finer particles (average size 100 to 200
micron). Fig. 5 shows the density of the bed with respect to furnace height and indicates the effect of load.
To integrate these influences into operating procedures, the CFB is equipped with additional instrumentation which provides operator input for bed management. These inputs are as follows:
1. Primary zone ∆P – The gas-side differential pressure
is measured across the primary furnace zone [from
the air distribution grid to an intermediate elevation
of about 6 ft (1.8 m) above the grid] and is an indication of the coarser bed inventory. This variable is
managed as a function of boiler load and desired furnace shaft ∆P, utilizing the bed drain flow for control.
43-13
The Babcock & Wilcox Company
2. Shaft ∆P – The furnace shaft ∆P, from the intermediate elevation to the furnace roof, indicates the
shaft bed density and is managed to follow boiler
load with corrections for primary zone temperature control. It is influenced by the multi-cyclone
dust collector (MDC) recycle rate, the primary to
secondary air split, and excess air setting.
3. Lower bed (or primary zone) temperature – The
lower bed temperature is set by the operator as a
primary control variable for optimal combustion
and emission performance. The shaft ∆P, primary
to secondary air split, and excess air controls are
used to control this operating parameter.
The variables mentioned above are typically not
available on conventional boilers. However, the overall operation is similar. Fuel feed is set by steam requirements (pressure), total air flow is adjusted to follow fuel flow, and excess air is set to optimize combustion and unit efficiency. Shaft bed density is then
predominantly used to control the lower bed temperature, the most important variable on a CFB boiler. The
lower bed temperature is usually controlled to a fueldependent set temperature [for example 1550F (843C)
for lignite and 1620F (882C) for petroleum coke] which
results in optimal combustion efficiency and SO2 absorption. The optimum bed operating temperature
from combustion and emission standpoints is from 1500
to 1650F (816 to 899C), depending on fuel.
Another variable that is controlled somewhat differently in a CFB is the air admission to the furnace.
The total air flow is divided into primary and secondary flows. Because total air flow is based on fuel flow,
the primary to secondary air split becomes another
important parameter affecting emissions and bed temperature. The split affects the lower bed density, shaft
density, and control of the primary zone temperature.
The optimum air split is determined as a function of
steam flow during commissioning tests. Once the optimum primary to secondary air split (as a function of
steam flow) has been determined for automated control, the operator should not need to independently
manipulate the split.
Solids management is also unique to CFBs. Once
the bed material inventory has been established, bed
inventory is maintained by the fuel ash and sorbentderived solids flows in most cases. Any change in inventory necessary to accommodate load change comes
from the MDC hoppers. In the case of firing low-ash
and low-sulfur fuels, solids input with fuel ash and
sorbent may not be adequate to provide enough bed
material for furnace temperature control. This also
may be the case when firing waste fuels requiring a
high bed drain rate for removing oversized material,
e.g., rocks. If a shortage of solids for maintaining bed
inventory occurs, the first source to add bed material
would be recycling a usable part (properly sized material) from the lower furnace bed drain. If this is not
sufficient, inert bed material fed from an external
source, e.g., sand, would be provided.
With the sometimes complex relationships where
changes in one variable impact several temperatures
and flows, control logics are provided to automatically
control these inter-relating parameters with minimal,
43-14
if any, operator actions needed. However, the operator must be trained to understand these relationships
and to control upsets to establish and maintain stability if necessary.
Fuel sizing and fuel characteristics
Coal firing Fuel sizing is very important to successful boiler operation. It impacts the furnace heat release profile: fine particles tend to burn higher in the
furnace shaft while coarse ones burn predominantly
in the primary zone. For medium and high ash fuels,
fuel sizing also impacts sizing of bed particles and,
correspondingly, bottom ash to flyash split. When fuel
variation occurs, the operator should be thoroughly
trained on the required adjustments in case the variations are outside the range of the programmed control logics.
Biomass firing Biomass fuels provide a particular
challenge in CFB operations because of continuous
variations in size, shape, moisture content, and heating characteristics. To minimize operating problems,
fuel sources should be continuously blended to achieve
as uniform a consistency as possible. Modest inventories are needed – large enough to permit blending for
uniformity of feed but not large enough to result in
excessive inventory storage times. Bed material sizing should be checked on a regular basis to ensure that
the bed material is not deteriorating. Care must be
taken in such sampling procedures because of the high
bed material temperature.
Startup and shutdown considerations Chapter 17
provides general guidelines for the startup of CFBs.
Hot and cold startup conditions are distinguished by
the temperature of the furnace solids inventory, either higher or lower than the auto-ignition temperature of the main fuel established at the end of the
boiler purge sequence. As with any boiler, prior to
startup and after shutdown the unit must be purged
according to the latest applicable NFPA codes. An important part of a cold startup is the warming of the
bed material with auxiliary fuel overbed burners designed for this purpose. During normal operation, a
Fig. 5 Typical bed density profile for a circulating fluidized bed.
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
CFB is loaded with enough bed material to provide a
20 in. wg (50 kPa) pressure differential across the
primary zone. During the warming process, bed materials are introduced to raise the bed pressure drop
from 5 in. wg (1.25 kPa). Auxiliary fuel is used to increase and stabilize the primary zone temperature at
about 1000F/538C (varies somewhat depending on
main fuel) in preparation for main fuel introduction.
Simultaneously, the boiler metal temperatures as indicated by steam pressure (saturation temperature)
must be within the heatup rate allowed for the boiler
pressure parts. Upon ignition of the auxiliary fuel, the
flue gas temperature entering the U-beams and the
steam-cooled surfaces must be monitored and maintained below 950F (510C) until 10% of the MCR
steam flow is established through the steam-cooled
circuits. Once the primary zone temperature is stabilized at the fuel auto-ignition point, the main fuel is
introduced and the bed temperature can be gradually
raised to about 1500F (816C) where the auxiliary
burner may be shut off. Boiler load can be increased
from this low load operation with circulating mode
being established with increasing solids, fuel and air
flow. The rate of increase must be controlled such that
the bed temperature remains stable. Primary air to
total air ratio is further adjusted to improve combustion and reduce emissions.
Overbed burners are used to assist with the burnup
of unburned carbon particles in the primary zone of
the furnace. If the boiler is being shut down for maintenance and personnel entry into the boiler setting is
required, all solids must be completely removed from
the boiler and hoppers, and the boiler temperature
must be below 120F (49C) prior to entry. (See personnel safety discussed earlier.)
BFB systems
Overview As is the case with its CFB counterpart,
bed management of a BFB is important. Bed inventory, bed sizing, makeup and drainage must be integrated into operating procedures from data collected
during commissioning tests. The BFB is also equipped
with additional instrumentation to assist the operator in
developing the unit-specific operating guidelines.
1. Primary zone ∆P – the gas-side differential pressure is used as an indication of bed height. The
primary zone may be compartmented on the air
side for coal firing, and multiple ∆P cells are then
displayed.
2. Bed temperature – the typical bed temperature
range is 1350 to 1650F (732 to 899C) and is a primary control variable. Because control of this variable is critical, multiple thermocouples are installed in the bed.
The operation of a BFB is similar to that of other
combustion technologies in that fuel and air demands
are set by the required steaming conditions. Bed temperature is controlled within the desired range by the
primary/overfire air split for biomass firing and by selected compartment slumping for coal firing (see Chapter 17). If an SO2 sorbent is used, it is usually metered
in proportion to the fuel flow. Various interactions can
Steam 41 / Boiler Operations
occur when manipulating control variables and the
operator must be specifically trained to respond to upsets. These responses include:
1. Fuel flow control – fuel feed is increased or decreased
based on steaming requirement. Changes in fuel
feed have a short-term impact on bed temperature.
2. Bed height – height is controlled by adding material from the makeup system or by removing material through the drain system.
3. Air control – total air is primarily controlled based
on steam flow. Air may be biased by the operator
to change bed conditions. Increasing primary or
bed air at a given load increases bed turbulence
and burnout in the bed, while the secondary air
changes opposite to the bed air change to control
constant total air at a given load. Reducing bed
air at a given load would have the opposite effect.
The operator must, therefore, bias the set point
based on combustion conditions. Fuel sizing variations, moisture content, and higher heating value
are most likely to influence combustion conditions.
4. Bed material flow – material flow to the primary
zone is through makeup and bed drains. Because
these are generally intermittent devices, the operator must observe control variable trends, particularly height, and make appropriate adjustments.
Coal sizing Careful attention to coal sizing (minimum and maximum) is critical to successful unit operation for both under-bed and over-bed feed systems.
Finer particles are elutriated too quickly and coarser
particles tend to take too long to burn completely. In
either case, UBC and SO2 emissions (if being controlled) both increase. An optimum size range exists
for each fluidized-bed system and fuel type. The proper
size range is fine tuned through unit operating practice. In addition, for the over-bed feed system fuel size
interacts with spreader speed, angle of injection and
gas velocity.
Operation of Kraft recovery boilers
Overview
The Kraft recovery boiler has three purposes in
today’s pulp and paper industry:
1. recovery of sodium and sulfur compounds from the
spent pulping liquor in forms suitable for regeneration,
2. efficient heat recovery from burning the liquor to
generate steam for process use, and
3. operation in an environmentally responsible manner, cooling the combustion gases to allow back
end particulate collection and minimizing the discharge of objectionable gases.
Steam flows can exceed 1,000,000 lb/h (126 kg/s) at superheater outlet pressures as high as 1500 psi (10.34
MPa) and final steam temperatures of up to 950F
(510C). These units burn black liquor with solids contents up to 75 to 80% and with heating values decreased to about 5500 to 5600 Btu/lb (12,793 to 13,026
kJ/kg). A detailed review of designs and general op-
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The Babcock & Wilcox Company
erating practice is provided in Chapter 28. Selected
operating issues are highlighted below:
1.
2.
3.
4.
black liquor combustion process and air flow,
auxiliary burners,
operating problems, and
smelt-water reactions.
Black liquor combustion process and air flow
Unlike the firing of conventional fossil fuels, recovery boiler combustion goes through several distinct
stages. Black liquor firing is composed of drying, volatile burning, char burning and smelt coalescence as
discussed in Chapter 28. This has a distinct impact on
unit operation and air addition. All modern B&W recovery boilers are equipped with three levels of combustion air. These are known as the primary, secondary and tertiary air streams in order of increasing elevation in the furnace. A fourth level, called quaternary, can be added for additional NOx and particulate control (see Chapter 28).
Primary air Primary air is in the lowest zone in a
recovery boiler furnace. The air ports are located approximately 3 ft (0.9 m) above the furnace floor. Admitted on all four walls of the unit, the primary air
provides perimeter air around the bed at low velocity
and low penetration, so the boiler does not lose combustion. The primary air is critical to bed stability, bed
temperature and reduction efficiency.
Secondary air High pressure secondary air penetrates the full cross-section of the unit and is admitted at the top of the bed providing the combustion air
for ignition and the heat to dry black liquor droplets
and support pyrolysis. This air also helps control SO2,
total reduced sulfur (TRS) and CO emissions. Finally,
secondary air controls the shape of the top of the bed.
Fig. 6 indicates the proper bed shape with the relative locations of the air ports and liquor nozzles.
Tertiary air Tertiary air is admitted at the upper
elevation, above the liquor guns. Like secondary air,
it is admitted at high pressure to provide penetration
across the width of the furnace to complete the combustion process. This is an oxidizing environment to
control CO and TRS emissions.
To maintain combustion in the proper location, the air
flow splits and pressures must be properly maintained.
Ranges of typical air flow distributions, inlet temperatures
and pressure differentials are summarized in Table 3 for
the two dominant firing systems, stationary and oscillating.
Successful stationary or oscillating firing depends
on the correct liquor droplet size. This size must permit complete in-flight drying before reaching the furnace wall or bed. The variables in black liquor combustion include liquor percent solids, temperature and
pressure at the spray nozzles, spray nozzle sizing and
splash plate angle, and number and position of black
liquor guns in service. Other variables include the
vertical and angular movement of the oscillators or the
off-horizontal angle of the liquor guns for stationary
firing. Other factors on the air side include total excess air; air temperature(s); air splits between the primary, secondary and tertiary ports; and the static air
pressure in each of these air zones.
43-16
Fig. 6 Proper bed shape for a black liquor recovery boiler – three air
level design.
The objective in the manipulation of all of these
variables is to control the steps of the drying and combustion of the liquor, and control bed temperatures.
The result is stability of operation, with minimum
plugging and emissions.
A comprehensive discussion of recovery boiler emissions is provided in Chapter 28.
Auxiliary burners
Recovery boilers are equipped with oil- and/or natural gas-fired auxiliary burners located at the secondary
and tertiary air port elevations. The burners in the secondary windboxes are used for unit startup, as black
liquor can only be fired into a heated furnace with an
auxiliary ignition source. The secondary burners are also
used to stabilize the smelt bed during an upset condition and to burn the bed out of the unit on shutdown.
Operating problems
Two problems unique to recovery boiler operations
are plugging and aggressive tube corrosion.
Plugging of the superheater, boiler bank or economizer is generally caused by two mechanisms. The first
is condensation of the fume or normal gases given off
by the black liquor combustion. The hot combustion
gases that leave the lower furnace contain vaporized
compounds that condense when the gas temperature
is cooled in the upper zones of the boiler, superheater
or boiler bank. This condensation is dependent on gas
temperature. The material condenses on the cooled
heat transfer surfaces such as furnace screen tubes
or primary superheater tubes. It also precipitates out
when the gas temperature falls below approximately
1100F (593C). In either case, this material is a source
of fouling in convection surfaces. Condensation or precipitation depend upon the temperature regime and
chemistry of the fume. The deposit can be in the plastic range and very difficult to remove. On a properly
designed and operated unit, this transition of the fume
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
Table 3
Typical Air Flow Splits and Operating Conditions*
Firing Technique
Stationary
Oscillating
Firing
Firing
Primary air
30 to 40%
300F (149C)
3 to 4 in. wg ∆P
(0.7 to 1 kPa)
40 to 50%
300F (149C)
1 to 3 in. wg ∆P
(0.2 to 0.7 kPa)
Secondary air
40 to 50%
300F (149C)
8 to 18 in. wg ∆P
(2 to 4.5 kPa)
20 to 30%
300F (149C)
6 to 10 in. wg ∆P
(1.5 to 2.5 kPa)
Tertiary air
10 to 20%
80F (27C)
10 to 20 in. wg ∆P
(2.5 to 5 kPa)
20 to 30%
300F (149C)
8 to 12 in. wg ∆P
(2 to 3 kPa)
Economizer outlet conditions
< 2.5% O2
100 to 200 ppm
CO
2.5 to 3% O2
200 to 300 ppm
CO
* Units with four air levels are discussed in Chapter 28.
from a dry gas to a sticky substance takes place in the
upper furnace, wide spaced screen or superheater.
Here the deposits can be controlled by sootblowers. On
an overloaded or improperly operated unit, the gas temperature remains elevated farther back into the closer
side-spaced boiler bank or economizer, where controlling
the plugging with sootblowing equipment becomes difficult. The gas temperature at which the fume turns to
a sticky liquid is also liquor chemistry dependent, with
higher levels of chlorides or potassium compounds being detrimental to unit cleanability.
The second major cause of plugging is mechanical
carryover of smelt, or unburned black liquor, into the
convective heat transfer sections of the boiler. This
Sound an alarm to clear the
area of all unnecessary
personnel.
Immediately stop firing all
fuel-auxiliary fuel and black
liquor. Secure the unit’s
auxiliary fuel system at a
remote location.
material is predominantly made of sodium carbonate
(Na2CO3), sodium sulfate (Na2SO4) and sodium sulfide
(Na2S) compounds. The cause of this carryover is related to operation of the liquor nozzles, oscillators and
various air port settings. As previously noted, the
black liquor firing equipment and air system settings
must produce complete in-flight or wall drying of the
liquor droplets. If this drying occurs too high above
the smelt bed, the less dense droplets are entrained
in the gas stream and carry over into the convection
sections of the boiler. In practice, most recovery boiler
plugging results from a combination of fume condensation and mechanical carryover.
Recovery boilers are also subject to aggressive corrosion compared to conventional fossil fuel-fired units
due to the presence of corrosive sulfur, chloride and
other trace compounds in an elevated temperature
environment. The Kraft recovery boiler also operates
in both an oxidizing and reducing atmosphere due to
the combustion process. Because of these conditions,
the floor and lower furnace walls are constructed using one or a combination of corrosion protection systems: metallic spray coatings or carbon steel tubes,
high-density pin studs with refractory, 304L stainless
steel tubes, Incoloy® alloy 825 and Inconel® alloy 625
composites tubes, and weld overlay of carbon steel tubes.
Smelt-water reactions
One unique and undesirable feature of a Kraft recovery boiler is the possibility of water entering an
operating furnace through a tube leak or external
source, resulting in a smelt-water reaction. A smeltwater reaction occurs when water combines with hot
or molten smelt, and a violent explosion can result.
This concern has resulted in years of study and testing and has prompted enhanced industry standards
on unit design, operation and maintenance. Modern
units are equipped with the provisions for an emergency shutdown procedure. This is initiated if water is
suspected to have entered the furnace of an operating
recovery boiler. Refer to Fig. 7 for procedural overview.
Immediately shut off
feedwater supply and all other
water and steam sources
except smelt shatter steam to
the boiler.
Close primary air dampers and
immediately set other air flows
to essentially stop combustion
and smelting in the bed while
maintaining some level of
purge air. Regulate induced
draft fan flow to maintain
furnace balanced draft.
Drain the boiler as rapidly as
possible to a level 8 ft (2.44
m) above the low point to the
furnace floor. Reduce steam
pressure as rapidly as
possible after the boiler has
been drained to this level.
Fig. 7 Emergency shutdown procedure overview for an operating recovery boiler (adapted from the Black Liquor Recovery Boiler Advisory
Committee, October, 2003).
Inconel and Incoloy are trademarks of the Special Metals Corporation group of companies.
Steam 41 / Boiler Operations
43-17
The Babcock & Wilcox Company
Babcock & Wilcox built and operates this refuse-to-energy plant in the southern U.S.
43-18
Steam 41 / Boiler Operations
The Babcock & Wilcox Company
Section VII
Service and Maintenance
This section describes the last element of a successful steam generating system life cycle plan – service and maintenance.
As owners and operators of steam plants search for optimum performance,
efficiency, and life cycle for all equipment, issues of maintenance and availability have become increasingly important.
The section begins with a discussion of service and maintenance encountered with all plants, both utility and industrial. A well-crafted service and
maintenance program is essential in sustaining the availability of critical steam
generating assets and maximizing overall performance and output. Condition
assessment is then addressed with detailed discussion about examination techniques, assessment of various components, and analysis techniques for determining remaining life. The effects of cycling operation are also addressed.
Steam 41
The Babcock & Wilcox Company
Chapter 44
Maintaining Availability
The design of boiler systems involves the balancing of near-term and long-term capital costs to maximize the availability and useful life of the equipment.
Fossil fuel-fired boilers operate in a very aggressive
environment where: 1) materials and technology are
pushed to their economic limits to optimize efficiency
and availability, and 2) the erosive and corrosive nature of the fuels and combustion products result in
continuous and expected degradation of the boiler and
fuel handling components over time. As a result, the
original boiler design is optimized to balance the initial customer capital requirement and the long-term
expected maintenance, component replacement, and
service costs for a possible operating life of many decades.
When a new power plant is started up, there is a
relatively short learning period when the operators
and maintenance crews learn to work with the new
system and resolve minor issues. This period may be
marked by a high forced outage rate, but this quickly
declines as the system is broken in and operating procedures are refined.
As the plant matures, the personnel adapt to the
new system, and any limitations in the plant design
are either overcome or better understood. During this
phase, the forced outage rate remains low, availability is high, and the operating and maintenance costs
are minimal. The power plant is usually operated near
rated capacity with high availability.
As the plant continues to operate, a number of the
major boiler pressure part components reach the point
where they are expected to be replaced because of erosion, corrosion, creep, and fatigue. Without this
planned replacement, increasingly frequent component failures occur resulting in reduced availability.
In some instances such as waste-to-energy systems,
this period can be as short as one to three years for
superheaters because of the very corrosive flue gas composition. However, for most fossil fuel-fired utility boilers operating on their design fuels, major pressure part
components are economically designed for more than two
decades of operation before economic replacement. Failures of major components such as steam lines, steam
Steam 41 / Maintaining Availability
headers and drums can cause major, prolonged forced
outages. Significant capital expenditures are normally
required to replace such components.
A strategic availability improvement program that
includes capital expenditures to replace or repair this
equipment before major forced outages occur can
smooth out and raise the availability curve. Higher
availabilities usually require higher maintenance,
higher capital expenditures, and better strategic planning. The large expenditures needed for high availability in older plants require a strategic plan to yield
the best balance of expenditures and availability.
Strategic plan for high availability
Mature boilers represent important resources in
meeting energy production needs. A systematic strategic approach is required to assure that these units
remain a viable and productive resource. The more
efficient, but older boilers in the system can be the
backbone of the commercially available power for a
utility.
Emphasis on high availability
Today, the need for high commercial availability is
of prime importance to the financial livelihood of a
power supplier. This means that the low- cost units
in a system must be available for full capacity power
production during critical peak periods, such as hot
summer days. Competition in the electrical supply industry requires that low-cost units be available so that
the system can supply power to the grid at low overall costs. Usually, the large fossil powered units are
the lowest cost units in the system. Lost revenue associated with having a large, low-cost unit out of service for repairs can be in excess of one million U.S.
dollars per day. Owners are attempting to maintain
availability levels of 90% or more on these large workhorses in the system.
The emphasis on maintaining or even improving
availability means that a strategic plan must be put
in place. Times between planned outages have been
44-1
The Babcock & Wilcox Company
increased. Planned outage times have been decreased.
Units are being run continuously for more than a year.
In some instances, units are run up to four years without being shut down. This requires complete system
and component reliability. Problems that were once tolerated can not be permitted to exist.
One example of a change in availability philosophy
is illustrated by the technique used to maintain low
water-side tube deposit levels in the furnace. It was
once common to chemically clean the boiler furnace
every four to seven years. Deposit buildup in the unit
dictated the cleaning cycle. Chemical cleaning normally required extending an outage time by several
days to a week. Today, many units have undergone
extensive changes to the boiler water treatment system. Many high pressure boilers have been converted
to oxygen water treatment (see Chapter 42). Reports
have indicated that oxygen water treatment has drastically reduced the rate at which furnace wall deposits form, and as a result, chemically cleaning the furnace in these high pressure units has been dramatically reduced. The reduced furnace deposits resulting
from oxygen water treatment and the associated reduced need for chemical cleaning are significant factors in improving unit availability. This is a good example of how new technology and a systems approach
to availability can have dramatic effects on overall operating costs.
and equipment condition assessment (see Chapter 45)
to develop an integrated strategic plan for each boiler
and each component in the boiler.
Increased capacity and operability
During the early phases of a boiler’s life cycle, less
maintenance is required to maintain high availability. However, as the unit matures and components
wear, more significant steps become necessary to maintain the desired availability. As the plant matures, the
need for component replacement becomes expected
and routine. Often at this point in the life of a power
plant, system demands, fuels and cost structures have
changed. Units must operate in ways unforeseen
when they were built. They must have greater operability, or the ability to effectively perform their role
in the manner required at the time. A plant that meets
environmental emissions limits by means of system
changes and fuel switching may have introduced capacity problems and operability limits that can become intolerable. Strategic equipment plans must address this
issue of operating under new circumstances.
Boiler changes should be considered that incorporate technology advances to increase unit capability,
operability and availability. This also provides the
opportunity to address current operating issues or
changing operating needs. Design changes might be
incorporated to accommodate new fuel sources or to
more successfully withstand cycling service. The potential for improvement is extensive. However, without a
strategic plan, the replacement and repair of boiler components might be unsystematic, and the results may
not achieve the desired returns on investment.
Key issues to consider when optimizing a unit include understanding how boilers age, identifying the
critical components, and determining the general types
of changes and enhancements possible. These elements are then combined with operating experience
1. increasing plant capacity resulting in absolute
emissions constraints,
2. increasing plant availability and operation (MWh)
resulting in absolute emissions constraints,
3. economic fuel switching, changing absolute emissions and emissions rates,
4. increasingly stringent emissions requirements, reducing plant availability, and
5. reduced plant output due to parasitic load.
44-2
Strategic plans yield high returns
on investment
While the driving force for the availability improvement plan may be to stretch present capacity resources
to meet current demands as well as to improve operability and availability, a well conceived strategic plan
can also achieve an attractive return on investment.
The payback can be realized when the capital improvement results in higher availability, a lower heat
rate, higher capacity, reduced routine maintenance,
or lower forced outage rates. There have been numerous programs that have significantly improved plant
capacity, operability and availability while achieving
a payback in as little as one year.
Impact of environmental regulations
In most developed nations today, regulations at
national and local levels control air emissions from
power plants and other industrial boiler applications
(see Chapter 32). Evolving emissions control limits
and changing plant operating requirements add another dimension to the strategic plan. These interactions typically take the form of:
To take full advantage of the plant capacity as well
as maintenance and upgrade capital expenditures, the
addition of appropriate emissions control technology
becomes an integral part of the strategic plan for all
plants. In fact, combining the addition of emissions control equipment with plant upgrades can result in enhanced power plant economic performance that offsets
part or all of the emissions equipment expenditures.
Thus, the full strategic plan incorporates appropriate
retrofits and upgrades of emissions control equipment.
Maintaining availability
The availability of a boiler is determined by the
combined availability of its various critical components. If critical components become unreliable, boiler
availability declines. These critical components include
the pulverizers and burners, pressure retaining components such as economizers and superheater headers, and the various balance of plant components such
as fans, controls, valves, etc.
The following section discusses the factors that affect the availability of key components of a typical
boiler. The mechanisms that affect component degradation and reliability are revealed. Strategies are outSteam 41 / Maintaining Availability
The Babcock & Wilcox Company
lined in this section for improving availability through
selective replacement upgrades of components that have
become unreliable through normal degradation. Examples of these upgrades are detailed in this section.
Pulverizer availability improvement
strategies – E and EL mills
Reliable pulverizer performance is an important
element of the combustion system, and is essential for
responsive power plant operation with good availability. Other subcomponents of the fuel preparation and
delivery system such as burners, coal feeders, motors,
dampers, coal pipes, combustion controls and combustion air fans must also perform reliably if the combustion system is to ensure good unit availability. See
Chapters 12, 13, 14, 25 and 41 for more information
about these components.
The first vertical air-swept coal pulverizer by The
Babcock & Wilcox Company (B&W) was the E pulverizer introduced in 1937, as shown in Fig. 1a. The EL
pulverizer (Fig. 1b) was developed in the 1950s as an
upgrade to the E pulverizer. However, there are still
a number of E pulverizers in operation today. Both the
E and EL pulverizers are of the ball-and-ring (sometimes referred to as a ball-and-race) design.
Pulverizer degradation mechanisms
As discussed in Chapter 13, the E pulverizer is a
machine that tends to wear from the inside due to the
abrasive action of a continuous stream of fine coal
particles. As the throat of the E pulverizer wears out,
coal begins to fall past seals and into the lower parts
Swing Valve
Assembly
Pulverized
Coal Outlet
(Typical)
of the pulverizer (dribble) causing severe wear to
these parts. To prevent higher coal dribble rates as the
throat wears, operators must increase air flow to maintain adequate velocity through the ever-widening throat
gap. However, as air flow increases, fineness deteriorates,
and erosion wear of other downstream pulverizer components increases. Upgrading the E pulverizer can help
solve this problem and increase pulverizer availability.
Impact loading and thermal stresses may cause the
E pulverizer rings to fail. Under certain operating
conditions, there is considerable vibration generated
and transmitted to the pulverizer components. As a
result, shaft or spring fatigue failures can result which
cause the loss of pulverizer availability.
E and EL type pulverizers can experience operating problems such as cracking of the upper or lower
grinding rings. In addition, as grinding balls attempt
to leave the ball race under the centripetal force of
their rotation around the ring, they put asymmetrical loads on the rings and main shaft. Main shaft
breakage can result.
E and EL upgrades
Since the introduction of the E and EL pulverizers,
a significant number of functional and mechanical
improvements have been made. Some of the major
improvements leading to increased pulverizer availability and reliability are summarized below.
E to EL conversion The preferred improvement to
an E pulverizer is to upgrade it to an EL mill. The EL
pulverizer is much less prone to coal dribble problems
due to improvements to the bottom grinding ring and
Swing Valve
Assembly
Intermediate
Section
Raw
Coal
Inlet
Table
Feeder
Assembly
Pulverized
Coal
Outlet
(Typical)
Discharge
Turret
Raw Coal Inlet
Table
Feeder
Assembly
Spring Bolt
Bracket
Assembly
Rotating
Classifier
Housing
Assembly
Access
Door
Spring
Housing
Assembly
Rejects Cone
Pulverizer
Balls
Top Grinding
Ring
DSVS
Rotating
Classifier
Coal
Chute
Cera-VAM
Ceramic
Lining
Primary Air
Inlet
Relief Gate
Throat
Ring
Bottom Grinding
Ring
Seal Ring
Yoke
Top
Bearing
Plate
Electric
Classifier Drive
Rejects
Cone
Top
Grinding
Ring
Pulverizer
Balls
Bottom
Grinding
Ring
Pyrites Gate
Pyrites
Door
Pyrites
Door
Pyrites
Gate
Main
Shaft
Oil Pump
Assembly
Fig. 1a Babcock & Wilcox E-type pulverizer.
Steam 41 / Maintaining Availability
Pinion Shaft
Assembly
Main
Shaft
Oil Pump
Assembly
Pinion Shaft
Assembly
Fig. 1b Babcock & Wilcox EL-type pulverizer.
44-3
The Babcock & Wilcox Company
throat configuration. A complete E to EL conversion
as shown in Fig. 2 includes new top and bottom grinding rings, springs, classifier, a more wear-resistant
throat, relief gate, and housing units to protect the
inside wall of the pulverizer just above the throat.
Larger pulverizer motors and primary air (PA) fans
may be needed to improve capacity. E to EL conversions have significantly improved the availability,
capacity and reliability of E type pulverizers.
EL grinding zone improvements The B&W OnTrack grinding zone retrofit package incorporates a
number of design improvements that increase EL pulverizer availability and reliability by reducing grinding zone overhauls. Five key design changes are included:
1. Deep dish grinding rings The upper and lower grinding rings include a deeper and improved grinding
track contour that limits radial movement of the
balls as they travel around the grinding track.
(See Fig. 3). This lowers the asymmetric loading
and displacement of the upper ring and lowers the
loading on the lower ring and main shaft, helping to prevent failures of the ring and shaft.
2. Integrally cast metal snubbers Snubbers (or bumpers)
are cast into the upper ring. The snubbers help
reduce the excessive side-to-side movement of the
top grinding rings. Excessive side-to-side movement
causes bending stresses and premature failure of
the main shaft. With snubbers, spring and main
shaft loading is reduced and breakage is less likely.
3. Heavy duty upper ring flutes Heavy duty outer flutes
incorporated in the upper ring resist breaking of
the fluted areas of the rings, enabling the upper
rings to remain in service until they reach the end
of their normal wear cycle. Fig. 4 shows the increased cross section of the heavy duty flutes compared to the narrower standard flutes. These
larger flutes result in smaller gaps between the
flutes and therefore, provide more control over the
grinding balls as they orbit around the pulverizer
track. This helps reduce stresses on the main pulverizer shaft.
4. Larger diameter grinding balls Larger diameter (13.63
in./34.61 cm) grinding balls increase the time be-
E
Top
Ring
EL
Top
Ring
EL
Housing
Unit
Ball
E
Throat
Seal
Ring
Erosion protection for EL pulverizers Pulverizers
experience internal wear from the erosive properties of
coal circulating within the mill. High quantities of silica
and alumina in the coal can reduce the life of most internal components. Fig. 5 shows the areas of an EL pulverizer that typically experience high wear from the
erosive effects of coal. These areas can be protected by
cladding with Cera-VAM high density alumina ceramic.
This ceramic cladding significantly reduces erosion rates
and reduces maintenance work during overhauls. The
application of ceramic lining materials to existing pulverizers must be done with care to minimize the impact
on other operational areas.
Roll wheel pulverizer upgrades
Roll wheel pulverizers are described in detail in
Chapter 13. These pulverizers are installed on many
modern coal-fired boilers. As with the ball and race
mill, wear affects the pulverizer availability. Upgrades
can increase wear resistance.
Improved roll wheel design The typical pulverizer
roll wheel wears in a pattern shown in Fig. 6. When
localized wear reaches a point where the wheel must
be replaced, there is considerable metal left in the remainder of the wheel.
To improve wear life, the standard tires may be
Ball
EL
Throat
E
Bottom Ring
Fig. 2 E to El pulverizer upgrade.
44-4
tween grinding zone overhauls because there is
more wear metal on each ball compared to the
smaller 12.5 in. (31.75 cm) diameter standard
grinding balls. Longer wear cycles associated with
these larger balls improve pulverizer availability
and reduce pulverizer operating costs.
5. Internally reinforced lower ring The lower grinding
ring of the EL pulverizer may experience thermal
stress cracking over time. These cracks may require replacement of the lower ring, affecting mill
availability. Efforts have been made to allow
cracked rings to remain functional in the pulverizer without the need for replacement. One solution to bottom ring cracking is the internally reinforced ring. The grinding ring looks like the standard ring externally, but it is internally reinforced
with steel. The harder, less ductile wear material
of the ring propagates cracks much easier than
tough mild steel. The mild steel reinforcement does
not crack easily and holds the cracked segments
of the ring together so the ring can remain in service.
Seal
Ring
EL
Bottom Ring
Fig. 3 Improved upper grinding ring for an EL pulverizer.
Steam 41 / Maintaining Availability
The Babcock & Wilcox Company
reducing the maintenance costs associated with stationary throat wear. The wear resistance of the throat
segment is increased by applying chromium carbide
weld overlay to the upper area of the vanes. The B&W
rotating throat incorporates a patented air foil vane
design that promotes more uniform air flow within the
port, and has resulted in significant reductions in
pulverizer pressure drop. In addition, the uniform air
flow combined with the carbide weld overlay significantly reduces throat segment wear.
Smaller Gap
to Resist
Ball Motion
Low temperature pressure components
Flute
Increased Length
Fig. 4 Heavy duty flutes for upper grinding ring.
upgraded to an asymmetric design that places more
material in the high wear area. As a further enhancement, the tires may incorporate a low profile. This
lower profile enhances wear life and improves mill
performance in certain circumstances. The upgraded
tires reduce the frequency of mill overhauls and improve mill availability.
Rotating throat The throat area of a roll wheel pulverizer (see Chapter 13, Fig. 3) is critical to the distribution of air through the pulverizer. This area can
experience high erosion rates from the fluidized air/coal
particle mixture, which could lead to premature component failure or increased maintenance. High erosion rates
can also lower component availability. High velocities and
turbulent air flow lead to relatively high pressure drop
through most standard stationary throat designs.
The B&W rotating throat (shown in Fig. 7) is designed to improve mill performance while dramatically
The low temperature pressure components are defined here as those below 900F (482C) metal temperature. These components normally are the economizer,
furnace and convection pass walls, drums and flash
tanks (steam separators), along with their downcomers and connecting piping and headers. These components suffer from corrosion, erosion, fatigue and
overheating. Creep failure of these components only
occurs when local overheating occurs.
Initial Configuration
Turret
Swing Valve
Seat and Plate
Housing
Units
Classifier
Cylinder
Initial Wear
Classifier
Blades
Classifier
Cone
Progressive Wear
Fig. 5 EL pulverizer with Cera-VAM ceramic cladding.
Steam 41 / Maintaining Availability
Fig. 6 Typical roll wheel wear pattern.
44-5
The Babcock & Wilcox Company
Solid Cast VAM® 20
Ledge Cover
Chrome Carbide
Weld Overlay
Cast Steel
Throat Segment
Vane
Fabricated
Outer Wall
Assembly
Support
Clip
Fabricated
Inlet Transition
Cone Assembly
Fig. 7 B&W rotating throat for a roll wheel pulverizer.
Degradation mechanisms
Corrosion Corrosion occurs inside and outside the
tubes, pipes, drums and headers of these lower temperature components. Internal corrosion is usually
associated with the boiler water, contaminants in the
water, and improper chemical cleaning or poor storage procedures (see Chapter 42). External corrosion
can be caused by corrosive combustion products, a reducing atmosphere in the furnace, moisture between
insulation and a component, and acid formed on components in the colder flue gas zones when the temperature reaches the acid dew point. Corrosion results
in wall metal loss. This wall thinning raises the local
stresses of the component and can lead to leaks or
component failure.
Corrosion may also be accelerated by the thermal
fatigue stresses associated with startup and shutdown
cycles. Furnace wall tubes, in areas of high structural
restraint or high heat flux, often contain internal longitudinal or external circumferential or longitudinal
corrosion fatigue cracks in cycled units.
Corrosion fatigue can occur in the steam drum
around rolled tube joints. The residual stresses from
the tube rolling process are additive to the welding and
operating pressure stresses. Corrosion from chemical
cleaning and water chemistry upsets acts on this highly
stressed area to produce cracking around the seal weld
or the tube hole. Extensive cracking can require drum
replacement. Corrosion problems are further discussed
in Chapter 42.
44-6
Erosion Erosion of boiler components is a function
of the percent ash in the fuel, ash composition, and
local gas velocity or sootblower activity. Changing
fuels to a high-ash western United States (U.S.) fuel
may lead to more erosion, slagging and fouling problems. Changing fuels might also require a change in
the lower temperature convection pass elements to accommodate higher fouling and erosion. The tube wall
loss associated with erosion weakens the component and
makes it more likely to fail under normal thermal and
pressure stresses. Erosion is common near sootblowers;
on the leading edges of economizers, superheaters and
reheaters; and where there are vortices or around eddies in the flue gas at changes in gas velocity or direction. Such changes are caused by closely spaced tube
surfaces, slag deposits, or other obstructions including
extended surfaces and staggered tube arrangements.
Fatigue The thermal stresses from temperature differentials that develop between components during
boiler startup and shutdown can lead to fatigue
cracks. These cracks can develop at tube or pipe bends;
at tube-to-header, pipe-to-drum, fitting-to-tube, and
support attachment welds; and at other areas of stress
concentration. Smaller, lower temperature boilers are
less prone to fatigue failures because the thermal differentials are lower and operate over small distances
in these units. As unit size and steam temperature
increase, the potential for thermal stresses and the
resulting fatigue cracking also rises.
Overheating Overheating is generally a problem
that occurs early in the life of the plant and can often
result in tube ruptures. The nature of failures attributable to overheating is discussed in Chapters 7, 42
and 45. These problems may go undetected until a
tube failure occurs. Overheating attributable to operation is generally resolved during the early stages of boiler
life. Other problems regarding overheating may be difficult to ascertain, and specialized boiler performance
testing (see Chapter 40) is generally required to identify the source and determine corrective actions.
In spite of these aging mechanisms, low temperature components are normally expected to be replaced
after more than two decades without major overhauls
unless the unit burns a corrosive fuel, burns fuel in a
reducing atmosphere, or is improperly operated. When
erosion, corrosion, fatigue, or overheating lead to frequent leaking, failures, or the threat of a major safety
related failure, then component repair, redesign, or replacement is appropriate.
Hydrogen damage Boilers operating at pressures
above 1200 psi (8274 kPa) and 900F (482C) final
steam temperature suffer from more complicated aging mechanisms than lower temperature units. These
boilers are generally larger than the low pressure, low
temperature units and this increases the likelihood of
thermal fatigue from boiler cycling. The higher pressures and associated higher furnace wall temperatures make these units more susceptible to water-side
corrosion. The high temperatures in combination with
any furnace wall internal deposits may promote hydrogen damage of the furnace tubing in areas of high
corrosion or heavy internal deposits. Chapter 42 discusses hydrogen damage in more detail. Severe cases
Steam 41 / Maintaining Availability
The Babcock & Wilcox Company
of furnace wall hydrogen damage have forced the retirement of older units.
Furnace wall wastage mechanisms associated with
staged low NOx burners The advent of low NOx (nitrogen oxides) burners with staged combustion for coalfired units has increased the wastage rates of some
boiler furnace walls near the burner zone. Corrosion
rates as high as 0.040 in. (1.02 mm) per year have
been reported for small local regions in furnaces of
units with staged combustion. The pattern of high corrosion rates is not uniform throughout the furnace or
from boiler to boiler. The pattern seems to be unit-specific and rather unpredictable as to its extent and rate.
Normal combustion gases with unstaged combustion
lead to an oxidizing flue gas that is not particularly
corrosive. However, in staged combustion there is incomplete mixing of the air and fuel, and pockets of a reducing gas are formed in the furnace in the burner zone.
The reducing gas is high in H2S, CO and unburned fuel
(carbon and iron pyrites), and is low in O2. This gas mixture together with the sulfur and chlorides in the fuel
does not allow the tubing to form a protective oxide outer
covering. High corrosion rates can occur in areas in contact with the reducing gas and unburned fuel.
The corrosion rate in the high wastage areas of the
boiler furnace is temperature dependant. As a result,
the corrosion rate is higher for high pressure units
with staged combustion than for lower pressure units
with the same burner arrangement. Inside diameter
(ID) deposits in the furnace wall tubing also raise the
metal temperature and increase the outside diameter
(OD) wastage rate. The highest corrosion rates typically occur in localized areas adjacent to and above
the burner elevation up to just below the overfire air
ports, where the reducing gas concentrations are the
highest adjacent to the walls.
Availability improvement strategy examples
Economizer upgrades One example of an availability improvement strategy involves an upgraded bare
tube economizer. A 600 MW coal-fired boiler was designed with a staggered, finned tube economizer. The
economizer, shown in Fig. 8, was equipped with longitudinal fins. In clean condition, these fins increase heat
transfer and reduce the amount of tubing required.
The economizer experienced severe flyash plugging.
As the plugging spread through both banks, system
gas flow resistance more than doubled. The increased
flue gas resistance pushed the boiler fan to its limit
and restricted boiler load. High velocity gas lanes were
created around the plugged areas. Extremely high ash
velocities caused tube erosion and resulted in numerous tube failures. Unit availability and reliability were
greatly reduced.
An engineering evaluation determined that the
existing finned economizer was not appropriate for the
high ash coal used as the main fuel. The staggered
tube pattern only increased the severe flyash plugging. An analysis showed that an in-line bare tube
economizer with equivalent performance could be fitted into the existing space. Fig. 9 illustrates the upgraded in-line economizer design.
The upgraded economizer included the following
features:
1. Vertical spacing between tubes was decreased to
allow installation of more tube rows and to minimize gas-side resistance.
2. An in-line arrangement was used to reduce gasside pressure drop and potential for ash erosion.
3. The economizer tube diameter was increased from
1.75 to 2 in. (44.5 to 50.8 mm) to achieve a higher
flue gas velocity and better convection heat trans-
Fig. 8 Original staggered, finned tube economizer that experienced severe flyash plugging.
Steam 41 / Maintaining Availability
44-7
The Babcock & Wilcox Company
fer without exceeding the allowable velocity limit for
the percent ash and percentage of abrasive silica and
alumina constituents in the fuel. Bare tubes arranged in-line are most conservative in such hostile
environments, are least likely to plug, and have the
lowest gas-side resistance per unit of heat transfer.
The weight of the new economizer did not exceed the
original weight. Also, the new economizer required
no more space than the original design.
4. The tube bends were protected by new erosion barriers on top and bottom of both banks. Properly
designed perforated barriers do not noticeably
reduce the effective heating surface, but they are
very effective in throttling the flue gas flow across
the tube bends along the enclosure walls. Without barriers, the open space between the return
bends and the enclosure walls would be the path
of least resistance, and flue gas would stream
through these gaps at very high velocities. The
effect would be excessive erosion of the bends, reduced overall heat transfer across the banks, and
possible damage to uncooled casing. The existing
inlet and intermediate headers were reused. Access doors and platforms did not have to be relocated or modified.
The upgraded economizer has experienced no
flyash plugging. The recurring tube erosion problem
has also been eliminated. As a result, unit reliability
and availability have been significantly restored. The
boiler operates at full load and has not been limited
by economizer problems.
Furnace wall corrosion reduction Another example
of an availability improvement strategy involved the
reduction in furnace wall corrosion associated with
staged combustion low NOx burners burning higher
sulfur coals. As discussed earlier, staged combustion
can lead to localized corrosion of the furnace wall tubes
in areas where reducing conditions are produced near
the walls. In this example, the corrosion rates in some
regions of the furnace approached 0.040 in. (1.02 mm)
per year. The areas of high corrosion on the furnace
side walls are shown in Fig. 10. The corrosion was
highest on the side walls near the corners of the furnace at the burner elevation.
The high corrosion pattern shown in Fig. 10 was
caused by pockets of high CO, unburned fuel and H2S
formed in areas adjacent to the furnace walls (see Fig.
11). These areas resulted in high corrosion rates that
led to repeated tube leaks and boiler outages. Considerable outage time was required to repair leaks and
replace tube wall panels on a recurring basis. The unit
suffered from low availability due to furnace corrosion.
The current method of combating this high corrosion is to protect the tubing with a cladding that is
more resistant to the corrosive atmosphere. High chromium nickel alloys similar to Inconel alloy 622 (21%
Cr, 13% Mo, 4% Fe, 3% W, and balance Ni) are being
clad over the boiler tube material. Cladding can be applied onto the tubing or furnace panels, or can be
formed as part of the tube during the production process (coextrusion). Other coatings have been tried over
the years, such as high-velocity oxy-fuel (HVOF) spray
coatings. These spray coatings are satisfactory where
low corrosion rates [less than 0.010 in. (0.25 mm) per
year] are involved. However, where more severe corrosion is encountered, the use of weld clad tubing or
coextruded tubing for corrosion protection is most often
chosen. Fig. 12 shows the laser cladding of a furnace wall
panel with Inconel alloy 622. In this example, the panel
was fabricated, laser clad, and then installed in the side
walls to protect the walls from corrosion.
Fig. 13 shows a laser clad sootblower opening. This
opening had experienced rapid corrosion rates due to
Fig. 9 Upgraded bare tube in-line economizer for high ash coal.
44-8
Steam 41 / Maintaining Availability
The Babcock & Wilcox Company
Wastage, Mils Per Year
CO (ppm)
85000
15 or Greater
10-14
65000
45000
25000
5000
Fig. 10 High corrosion pattern on furnace side walls.
Fig. 11 Computer model showing areas of high CO near the side walls.
adjacent reducing conditions and the action of the
sootblowers. Inconel alloy 622 has been shown to dramatically decrease corrosion (as well as erosion) in
areas that have experienced high wastage.
Boilers that are experiencing corrosion from staged
combustion conditions should be carefully monitored.
Wall thickness measurements at suspected high corrosion areas should be taken at frequent intervals
(e.g., yearly or every two years). Maps of the wall
thickness changes (such as shown in Fig. 10) can help
determine which areas to protect with cladded tubing.
With the lower corrosion rates associated with cladded
tubing, the frequency of weld repairs and wall panel
replacements is dramatically reduced. The beneficial
effects on unit availability can be dramatic.
Hopper panel impact protection Many units burning western U.S. coals and to a lesser degree eastern
U.S. coals experience slagging problems. Large accumulated masses of slag can fall onto the hopper slopes
of the lower hopper area of the boiler furnace (see Fig.
14 for a hopper design). Falling slag results in very
high impact loads on the hopper panel tubes and the
supporting structure. Tubes erode, deform, crack, and
eventually leak. Hopper supports deform and lose their
functionality. This situation may lead to unexpected
major outages for lower hopper repairs or replacement.
An innovative hopper design has been patented
(U.S. patent no. 5,692,457) that improves the ability
of the hopper to withstand these massive slag falls.
(See Fig. 14.) The heart of the system is the crush tube
that is designed to absorb the impact load. The crush
tube is replaceable and located under the hopper panel
and is designed to deform preferentially (or crush on
impact loading) compared to the pressure-containing
tube of the hopper panel and the support truss members. In addition, the hopper panel tube is typically
made thicker to improve its ability to withstand falling
slag. The hopper tubes can also be weld clad to resist
erosion and improve longevity in this harsh environment as the ash and slag slide down the hopper.
The combination of a reinforced hopper tube with
the impact absorption capability of the replaceable
crush tube improves the likelihood that the hopper can
withstand a typical slag fall. The crush tubes that
have been deformed are replaced during regular
Steam 41 / Maintaining Availability
Fig. 12 Laser cladding process on a furnace wall panel (courtesy of
Praxair Surface Technologies).
44-9
The Babcock & Wilcox Company
the associated velocities. Table 1 offers guidelines for
applying ceramic linings to coal piping.
Ash composition affects the erosiveness of the coal.
Large percentages of clay, alumina, silica, pyrite and
quartz also increase coal’s abrasiveness. The guidelines given in Table 1 assume a silica composition of
40%. High alumina and silica content increases the
abrasiveness of the coal. Following these guidelines
can help improve unit availability by reducing repair
frequency and the associated replacement time.
Additional availability improvement strategies are
contained in the following chapters:
Chapter 7 discusses various materials that might be
used in upgrades for new components.
Chapter 20 discusses economizer design.
Chapter 42 contains information about proper water
chemistry and layup procedures.
Chapter 45 discusses methods for evaluating the condition of low temperature components.
Hopper
Tubes
Crush
Tube
Support
Beam
Fig. 13 Laser clad sootblower opening.
maintenance outages. Hoppers utilizing this unique
design concept have performed well in service for
many years and have improved unit availability.
Wear resistant materials Most older boiler components do not contain highly wear resistant materials
in high erosion areas. These areas, such as within coal
pulverizers, require frequent and sometimes costly
maintenance. Down time to repair and replace these
eroded components reduces availability.
Advanced materials have been developed specifically for boiler fuel handling applications. Materials
have evolved from basic low carbon steels to ceramic
linings. These linings include high density, high alumina ceramics and silicon carbide ceramics. The alumina ceramics with 96% alpha alumina and a density of about 232 lb/ft3 (3716 kg/m3) are ideal for components exposed to high velocity coal particles. These
alumina linings provide up to ten times the wear resistance of carbon steel. The nitride-bonded silicon
carbide ceramics have good erosion and corrosion properties, and they provide high thermal conductivity
and superior thermal shock resistance. These ceramics are used in the most severe environments.
Typically, ceramic linings are used in coal transport
equipment, pulverizers, piping, exhaust fans and
burner nozzles. The extent of application depends
upon the relative erosive nature of the specific coal and
44-10
VIEW B-B
Hopper
Tube
Crush
Tube
B
DETAIL A
B
DETAIL A
Hopper
Tube
Fig. 14 Impact resistant hopper design.
Steam 41 / Maintaining Availability
The Babcock & Wilcox Company
Recommendations for the Application of High Density
Alumina Ceramic Linings in Coal Piping
Ash Content of Coal
Recommendations
Less than 6%
No ceramic lining required.
6% to 9%
Use ceramic lining from the
pulverizers to the first major
bend plus two pipe diameters
beyond the bend. Line all short
radius bends and two pipe
diameters beyond these bends.
More than 9%
Same as above except, also line
all bends and the pipe two
diameters beyond these bends.
High temperature pressure components
The high temperature pressure components are
defined here as those that operate at or above 900F
(482C) metal temperature. The components normally
at this higher temperature are the superheaters,
reheaters and attemperators with their connecting
tubing and piping. These components operate in a
temperature range high enough where they can experience degradation from oxidation, fuel ash corrosion, carburization, graphitization and creep. These
are the high temperature failure modes. Corrosion,
erosion, fatigue, and overheating are also possible in
a manner similar to that discussed in this chapter on
the lower temperature components. (See Chapter 45
for information on evaluating the condition of these
components and some of their common failure modes.)
High temperature creep rupture and creep fatigue
failure (see Chapters 7 and 45) are the two primary
aging mechanisms for the high temperature components. All components that operate at temperatures
above 900F (482C) are subject to some degree of
creep. Most of the tubes, piping and headers from the
primary superheater to the turbine, including the superheater and reheater, are designed to operate in the
creep regime. As a result, most of these high temperature components have a finite useful life and can fail
by creep or creep fatigue after 20 to 40 years of operation. Replacement and redesign must be considered
in any strategy for operating high temperature, high
pressure boilers.
Chapter 45 discusses methods for predicting creep
ruptures in high temperature superheaters and
reheaters, and for assessing the condition of high temperature piping and headers. Availability of these high
temperature units in the later years of operation generally falls, mainly because of creep ruptures and creep
fatigue failures. It is common to replace a superheater
after 25 years of service due to creep rupture incidents.
Superheater outlet headers have also been replaced
after 25 years due to creep fatigue cracking. Fig. 15
illustrates the typical replacement age for reheaters
in power boilers.
The aging process and rate of component degradation vary from unit to unit. Table 2 presents the comSteam 41 / Maintaining Availability
ponent replacement sequence for a typical high pressure, high temperature unit.
High temperature component degradation
mechanisms
Oxidation The most common degradation mechanism for superheaters and reheaters is tube OD oxidation. At higher temperatures the oxidation rates
from metals increase. Chapter 7 discusses the oxidation limits placed on tube metals to prevent rapid oxidation. Superheater and reheater tubes are designed
with OD metal temperatures below the oxidation limits. However, some oxidation does take place. The rate
of oxidation is typically 0.001 to 0.002 in. (0.025 to
0.051 mm) per year. Failures from oxidation do not
usually occur to tubes unless the oxidation process is
accelerated by overheating or sootblower activity.
When oxidation does occur it appears as wastage
on the upstream side of the tube OD. Flat spots on the
OD or thin spots in the tubing may be obvious where
the wastage has occurred. The wastage is usually
highest on the upstream side of the leading edge tubing near the sootblowers. Wastage from oxidation may
also occur on the tubing OD near the outlets, or near
changes to higher material grades (higher metal temperatures). When oxidation occurs, the ID oxide scale
thickness will also usually be thicker than expected
for the hours of operation. Fuel ash corrosion can accelerate oxidation wastage and is discussed below.
Changes in operating conditions that are associated
with changes in fuel type or changes in burner designs may alter the operating temperature of a tube.
A temperature increase above the oxidation limit can
cause rapid wall loss from oxidation. When this occurs,
tube failures can follow. The tube that is thinned by
oxidation will ultimately fail by a creep mechanism due
to the higher stresses in the thinner wall (see Creep
section below).
Tubes that operate near sootblowers are periodically
cleaned by the sootblower action. This action removes
some of the protective oxide from the tube OD. The
tube regenerates this protective layer, but in doing so,
some wall is lost to form the protective oxide. Over
time this repeated oxidation/cleaning/oxidation cycling
can lead to wall loss that is sufficient for creep fail12
Number of Reheater Projects
Table 1
10
8
6
4
2
0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51
Age of Reheater at Replacement
Fig. 15 Reheater replacement projects by age.
44-11
The Babcock & Wilcox Company
Table 2
Component Replacement Schedule for a Typical
High Temperature, High Pressure Boiler
Typical
Replacement
Period
Component
(Years)
Replaced
20
25
30
35
40
Miscellaneous tubing
Attemperator
Secondary
superheater (SSH)
SH outlet header
Burners and throats
Reheater
Primary superheater
and economizer
Lower furnace
Cause for
Replacement
Corrosion, erosion, overheating
Fatigue
Creep
Creep fatigue
Overheating, corrosion
Creep
Corrosion
Overheating, corrosion
Note: The actual component replacement period is highly
variable depending on the specific design, operation,
maintenance and fuel.
ures to occur. Often, oxidation around the sootblower
area is mistakenly labeled as coal ash corrosion. Coal
ash can cause corrosion failures that appear to be similar to oxidation failures (see section below). Oxidation,
however, does not rely on a corrosive ash.
Fuel ash corrosion Fuel ash corrosion is sometimes
very aggressive, but usually does not occur or becomes
only a minor problem. It is sometimes confused with
oxidation because both occur in the same components
and have similar appearance. Fuel ash corrosion is the
wastage of tubing caused by a chemical reaction with
the fuel ash. Elements in the fuel can react with the
normally protective oxides. Chloride and sulfur are examples of elements that degrade the oxidation resistance of the metal tubing and markedly increase oxidation rates.
Usually, in fuel ash corrosion, the ash forms a liquid
layer on the tubing during unit operation. Complex
alkali metal salts form the liquid corrosive layer in some
coal-fired boilers. Na3Fe(SO4)3 is one member of the
complex sodium or potassium metal (Fe or Al) sulfate
family that forms a corrosive liquid film on superheaters and reheaters in some coal-fired boilers. The liquid
layer is a low melting point mixture of compounds formed
by the ash and it dissolves away the normally protective
oxide scale. In other cases, corrosive liquid deposits can
be formed by vanadium compounds or chlorides in combination with sulfates.
It is difficult to distinguish between oxidation and
fuel ash corrosion. They may be similar in appearance.
One way to distinguish if a superheater or reheater
is suffering from oxidation or fuel ash corrosion is to
analyze the OD scale on the tubing with x-ray diffraction and chemical analysis. Metallographic examination of the tube metal near the OD surface may also
help show the advance of corrosive compounds along
tube grain boundaries. If the tube scale is shown to
have high percentages of elements or compounds
[such as Na3Fe(SO4)3] associated with fuel ash corro44-12
sion, then fuel ash corrosion is present, not just oxidation. Oxidation by itself does not show evidence of
high percentages of these elements or compounds, although low concentrations may be present.
Carburization Although some carburization is often
associated with fuel ash corrosion, carburization of superheaters and reheaters is rare. It has become more
common with the advent of staged combustion for low
NOx burners. Carburization occurs when incomplete
combustion of the coal occurs before the flue gas passes
through the superheater or reheater. Incomplete combustion leads to increased amounts of CO and unburned fuel contacting the superheater tubes.
Metal tubes require an oxidizing atmosphere to
form a protective oxide film on the surface of the tube.
When localized reducing conditions exist around the
tube at an elevated temperature, the tube can not
protect itself from wastage from the sulfur and other
corrosive species. In addition, both the unburned carbon in the fuel, and flue gas CO, react with the dissolved chromium in the tube to form chrome carbides.
Carbon diffuses into the surface of the tube, raises
the carbon level, and forms chrome carbides. If this
occurs, there is so much carbon in the metal that all
of the available chromium reacts to form chromium
carbides. When the chromium is tied up as chromium
carbide it can not strengthen the metal and can not
help form protective chromium-rich oxides. Essentially, the affected portion of the tube near the OD
becomes a weak low-chromium steel material that is
less corrosion-resistant at the elevated temperatures
encountered in superheaters and reheaters.
Graphitization Carbon in both carbon steel and carbon-moly tubes (example: SA209-T1a) is free to diffuse through the metal. Carbon is most stable as
graphite in the metal, so with time, the carbon may
coalesce into graphite flakes. These flakes may line up
in a linear and continuous spiral pattern along the
tube. When they form this pattern, the graphite forms
spiraling planes of weakness in the tube. Under the
influence of operational stresses, cracks can develop
along the spiraling paths of graphite. Sudden tube
failures occur with no warning. Reliability suffers
when this process nears its final phase, as tube failure rates increase.
Graphitization can occur when carbon steel or carbon-moly steel tubes are heated to operational temperatures above about 900F (482C) for long periods
of time. Not all units experience graphitization of the
carbon or carbon-moly tubing. It is currently not clear
why some tubes undergo graphitization and others do
not. When severe graphitization occurs, the tubes fail
with little ductility and the fracture occurs in a spiral
around the tube. Tubes with chromium do not suffer
this problem because the carbon becomes associated
with the chromium as chromium carbides. (See Chapter 7 for more information.)
Creep Chapter 7 discusses creep and creep rupture
of tubing. Superheaters and reheaters will eventually
fail by creep if other failure mechanisms are not
present. Most of the reheaters replaced in Fig. 15 were
replaced due to creep rupture failures. Overheating
due to some form of internal obstruction can lead to creep
Steam 41 / Maintaining Availability
The Babcock & Wilcox Company
failures in short periods of time. Normally, creep rupture
failures take many years to occur. As the frequency of
these failures increases, then component replacement is
required in order to maintain unit availability.
Availability improvement strategy examples
Superheater upgrade to improve fuel ash corrosion
resistance One example of an availability improve-
ment strategy involves an upgraded superheater. This
eastern U.S. utility had recurring tube failures in the
secondary superheater of an oil-fired boiler, and the
boiler suffered from low availability as a result of these
failures. Fuel ash corrosion from the fuel oil caused
failures in the tubes exposed to the higher operating
temperatures. Fig. 16 illustrates the arrangement of
the boiler and shows the problem superheater.
The furnace gas temperature at the leading edge
of the superheater was nearly 2800F (1538C). High
superheater tube temperatures resulted from this
unusually high furnace exit gas temperature (FEGT).
External tube corrosion was accelerated by this high
temperature and by the high vanadium and sodium
contents in the oil. Tube failures occurred so frequently
that the bottom three rows of the horizontal superheater had to be replaced every 18 months.
An upgrade in superheater design usually requires
field testing to define the operating conditions, followed by a detailed engineering study. To correctly
design the upgraded superheater, boiler operating
temperatures were obtained. A computerized boiler
model was used for the performance testing. This system revealed that the actual FEGT was 125F (69C)
higher than the design value. The high FEGT was a
result of furnace design and burner arrangement. Because it was impractical to redesign the furnace or
change to a less corrosive fuel, and the owner did not
wish to lower the unit rating in order to lower the corrosion rate, a design study concentrated on a superheater upgrade.
A new superheater was designed using the actual
FEGT that was obtained from the computer model of
the unit. The new design accommodated the higher
operating metal temperatures and allowed the tubes
to continuously function at the higher temperatures
without producing overheat or corrosion related failures. In the final upgrade arrangement, the three lowest tube rows that had been attacked by corrosion were
replaced with Incoclad 671/800HT, a corrosion resistant coextruded high chromium nickel alloy material. The tubing was made by co-extruding an Inconel
alloy 671 layer 0.070 in. (1.78 mm) thick on the outside of the inner core of Incoloy alloy 800HT. The
outer layer of Inconel alloy 671 provided the high corrosion resistance while the inner core of Incoloy alloy
800HT provided the high strength at the elevated tube
temperatures. The remaining tubes in this bank were
replaced with a stainless steel material to accommodate the higher metal temperatures. A new support
method that allowed greater material expansion at the
elevated operating temperatures was included.
The modified superheater allowed the unit to run
with high availability and at full rated capacity. The
fuel ash corrosion problem was greatly reduced.
Steam 41 / Maintaining Availability
Superheater upgrade to restore full load capability
and improve availability This example of a superheater
and reheater upgrade also involved the upgrade of the
outlet headers to P91 (SA335P91) material. The boiler
was a B&W coal-fired unit with single reheat. The radiant boiler provided 1,600,000 lb/h (201.6 kg/s) main
steam at 1050F (566C) and 2203 psig (15.2 MPa), and
1,263,800 lb/h (159.2 kg/s) reheat steam at 1050F
(566C) and 525 psig (3.6 MPa). The goals of the project
were to restore unit capacity and improve availability.
Steam generator reliability had been high until the
late 1980s, when superheater components began to
suffer from the latter stages of normal aging processes, including outlet header maintenance. The unit
had also lost 10 MW of capacity. Subsequent study suggested that an increase in throttle pressure of 70 psig
(483 kPa) would restore the lost 10 MW. This meant
that the boiler steam-side pressure drop needed to be
reduced by approximately 70 psig (483 kPa).
The project involved an upgraded superheater,
reheater and primary superheater together with the
superheater and reheater outlet headers as shown in
Fig. 17.
Selected features of the redesigned high temperature components include:
Fig. 16 Boiler arrangement showing secondary superheater (SSH)
directly above furnace where gas temperatures reach 2800F (1538C).
44-13
The Babcock & Wilcox Company
Primary Superheater
Inlet
Reheater Inlet
Reheater Outlet
Primary Superheater
Outlet
Secondary Superheater
Outlet
Superheater header upgrades Chapter 45 describes
the mechanisms for reheater and superheater outlet
header failures. The main failure modes are tube-toheader weld failures, ligament cracking and nozzle
cracking. These failures are caused by the combined
effects of thermal cycling and creep, often called creep
fatigue. Advanced design standards for headers have
been developed to help reduce these failures. When an
outlet header must be replaced, a design upgrade should
be considered. An upgraded header can provide longterm, reliable service even under cycling conditions.
Nozzle cracking is associated with the weld in a tee
nozzle or in the internal sharp corners of a forged design. Any header upgrade could include a forged tee to
eliminate the welded connection. The forging would include generous radii to reduce stress concentrations.
Under cycling service, the tube-to-header weld area
may develop cracks due to inadequate tube leg flexibility or due to thermal stresses in the header. Cracking due to inadequate tube leg flexibility can be overcome by providing longer or more flexible tube legs
between the furnace penetration and the header.
However, this modification may require header relocation and/or relocation of the tube penetrations.
Relocating the tube penetrations around the header
may also be necessary to avoid header ligament cracking. Many headers were designed with closely spaced
or non-symmetrical tube penetrations, as shown in
Fig. 18, that are more prone to creep fatigue ligament
Secondary Superheater
Inlet
Fig. 17 Upgraded superheater and reheater sections and headers.
1. Tube material of T91 (SA213T91) was used in the
secondary and reheat outlet banks to provide longer
component life and reduce steam-side pressure drop.
2. Reduced diameter reheat outlet tube legs and
header stubs [2 in. (5.08 cm) OD versus original
2.5 in. (6.35 cm) OD] were used to improve flexibility and reduce stress in an area where tube
failures had been occurring.
3. Secondary superheater outlet header material of
P91 (SA335P91) was used to reduce size and increase component life.
4. The number of parallel steam flow paths in the
primary superheater (PSH) inlet bank, PSH intermediate bank and secondary superheater
(SSH) outlet bank were increased to reduce
steam-side pressure drop. A reduction in steam
drum to SSH steam outlet pressure drop by 70 psig
(483 kPa) was accomplished by increasing the
number of parallel steam flow paths and employing upgraded tube alloys permitting thinner tube
walls. The superheater pressure drop reduction
permitted a corresponding increase in turbine
throttle pressure to regain the original 10 MW
higher generator output.
44-14
Fig. 18 Increased ligament size for longer design life.
Steam 41 / Maintaining Availability
The Babcock & Wilcox Company
cracking. Studies have shown that creep fatigue
cracking can be decreased by using larger ligaments.
Upgraded headers with widely spaced tube penetrations provide larger ligaments and lower ligament temperatures and stresses. As a result, header life is significantly increased.
Redesign of the tube-to-header weld configuration,
as shown in Fig. 19, can also increase the life of a high
temperature header. Chamfering the tube end and
redesigning the weld preparation allows the weld to
be made with a near full penetration tube-to-header
weld. Reduction of the large partial penetration area
at the end of the tube stub reduces the stresses around
the weld joint and reduces the rate of crack propagation from this area of the weld joint.
The tube hole in the header creates a sharp discontinuity at the intersection of the hole and header internal surface. Very high stresses associated with this
sharp corner cause creep fatigue cracks to initiate from
the hole. A redesigned header may also be fabricated
with a chamfer at the tube hole penetration as shown
in Fig. 19. The chamfer lowers the stress around the
hole and reduces creep fatigue cracking.
The most common upgrade for a high temperature
header is an upgrade in material. American Society
of Mechanical Engineers (ASME) SA335P11 headers
may be upgraded to SA335P22 or P91 materials, and
SA335P22 headers may be upgraded to SA335P91.
The material upgrade generally results in a dramatic
increase in header life, and in many cases, it is anticipated that these upgrades may nearly double the life
of certain header components.
Additional availability improvement strategies are
contained in the following chapters:
Chapter 7 discusses various materials that might be
used in upgrades for new components.
Chapter 19 explains boiler, attemperator, superheater
and reheater design.
Chapter 45 discusses methods for evaluating the condition of high temperature components.
Fig. 19 Header upgrade with redesigned tube penetration.
cases is to modify the boiler and/or feedwater system
to prevent the sudden entry of cold water into hot
boiler components.
When a boiler is experiencing cracking due to
subcooling and cold feedwater flow upon startup, an
off-line pump-assisted circulation system may be installed to reduce the thermal transients. The system,
as shown in Fig. 20, consists of an off-line circulation
pump, a thermal sleeved tee connection between the
off-line pump and the feedwater line, a connection line
from the boiler downcomer to the pump, a warming
bypass system, various valves, and a control system.
The off-line pump is only operated when the boiler
is shut down. Its purpose is to provide a small amount
Circulation upgrades
Cycling boiler upgrades
Many older and larger fossil utility boilers were not
designed to accommodate frequent on/off cycles. Design criteria for cycling service boilers are limited due
to the lack of long-term experience with large units.
Cycling service can cause fatigue failures in the economizer tubing and inlet header, lower furnace wall
tubes and headers, structural components such as
buckstays, and some steam drum internals. This fatigue cracking can be caused by the sudden flow of
cold water into hot boiler components. Thermal differentials of 200 to 400F (111 to 222C) can be created.
Furnace subcooling, boiler-forced cooling during a
shutdown, and intermittent cold feedwater flow into
the boiler during startup are three sources of thermal
differentials and cyclic cracking. The thermal stresses
produced within the components may be sufficient to
produce low cycle fatigue cracks. The solution in most
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Fig. 20 Off-line recirculation system to reduce thermal shock.
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The Babcock & Wilcox Company
of circulation within the furnace circuit and through
the economizer to prevent temperature stratification
in the water circuits. The tee connection permits the
introduction of a small amount of hot water from the
furnace into the feedwater stream when feedwater is
intermittently supplied to the boiler and before a
steady feedwater flow is established. The warm furnace water introduced at the tee connection raises the
feedwater temperature enough to prevent thermal
shock to the economizer. The connection contains an
internal thermal sleeve that protects the tee from a
thermal shock when cold feedwater is first fed to the
economizer. A control system monitors the feedwater
temperature and flow and controls the recirculation
pump. When the boiler startup sequence is initiated,
the off-line system is shut down and isolated. Warming lines permit natural circulation through the pump
when it is shut down and the boiler is off-line.
Experience with off-line recirculation systems has
shown that thermal shock differentials can be reduced
to less than 100F (56C) from previous levels of 200 to
400F (111 to 222C). Such a reduction may eliminate
the fatigue cracking that is associated with frequent
unit cycling.
Drum boiler bypass system upgrade
Steam turbine transient stresses associated with on/
off operation or load cycling shorten turbine life. Long
startup times required to minimize these stresses lead
to costly fuel consumption. Drum boilers can be upgraded with a superheater bypass system for improved
cycling capability. The bypass system upgrade can be
installed on a drum boiler to minimize startup time,
provide control of steam temperature to match turbine
metal temperature, and allow dual pressure operation
of the boiler and turbine for better load response.
These features reduce turbine stresses for improved
availability and reduced maintenance costs.
The common means of steam temperature control
in a drum boiler (water attemperation in conjunction
with parallel convection surface, gas recirculation,
excess air, or burner input adjustments) do not permit easy control of turbine temperatures during startup and low loads. This is because there is a large mismatch between flue gas flow and steam flow. The
drum boiler bypass system, shown in Fig. 21, provides
direct control of the steam temperature by saturated
attemperation of the superheat and reheat outlet
steam. This arrangement provides the desired steam
temperature for the turbine without undue restrictions on the startup firing rate.
The drum boiler bypass system substantially reduces cold startup time because it controls the temperature differences of the saturated boiler surface, superheater surface, and turbine. The bypass system consists of a control system with steam piping and valves
and is described in detail in Chapter 19.
The system has a set of superheater stop and bypass control valves downstream of the primary superheater to allow dual pressure operation; the turbine
throttle pressure is controlled separately from drum
pressure. This control system is designed to maintain
constant pressure operation of the drum and boiler
44-16
Fig. 21 Typical superheater bypass system for a drum boiler to
minimize turbine stress.
furnace circuits and variable pressure operation of the
turbine because the turbine throttle valve is open over
most of the load range.
Dual pressure operation minimizes thermal stresses
to the boiler and the turbine. A dual pressure shutdown keeps the boiler near full pressure and the turbine metal near full load temperature in preparation
for a quick restart. In addition, it allows more rapid load
changes than variable boiler pressure operation.
A superheater bypass diverts excess steam from the
boiler to the condenser, thereby separating firing rate
from drum pressure during shutdown and startup. Gas
temperature probes, located near the superheater and
reheater outlet tubes, monitor flue gas temperatures.
The superheater bypass system permits cycling the
unit rapidly and often without accumulating major
fatigue turbine damage.
Circulation improvements
Water circulation upgrades are often required to
overcome operational and maintenance problems.
Symptoms of a circulation problem include localized
tube failures in particular boiler circuits, increases in
water-side and steam-side deposits and pressure drops,
fluctuations in feedwater control, and drum water
level excursions and fluctuations. Occasionally, circulation problems may appear when supply tubes or
headers for the furnace waterwall circuits crack and
distort. Circulation problems can directly affect boiler
performance and, if severe, can reduce capacity and
availability.
Determining causes and solutions for circulation
problems requires boiler performance testing, heat
transfer and circulation computer modeling, and a
thorough knowledge of boiler dynamics. Thorough
discussions of heat transfer and circulation are covered in Chapters 4 and 5.
Consider an example boiler with circulation problems.
This unit was experiencing an abnormally high forced
outage rate due to tube failures in the platen wing walls
as well as extensive failures of the furnace rear wall
arch tubes. Fig. 22a illustrates the upper furnace configuration and arrangement of the wing walls.
The majority of tube failures in this unit were
found in the lower 17 deg (0.3 rad) inclined portion of
the wing walls. Some time later, the rear wall arch
tubes began failing, especially in the lower inclined
area. Poor water chemistry and resultant heavy internal tube deposits were originally blamed for the
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The Babcock & Wilcox Company
tube failures. However, water chemistry was monitored
and found to be acceptable in this case.
A complete engineering study was required to review the plant operating procedures and the original
boiler design. The study goals included:
1. analyzing the overall boiler circulation system,
2. reviewing the platen wing wall design,
3. examining the design and performance of steam
drum internals,
4. investigating the rear wall arch and supply circuit design, and
5. providing operational and hardware modifications
to eliminate the tube failures in the platen wing
walls and rear wall arch tubes.
below the drum centerline, permitted steam to be drawn
into the downcomers. This further reduced the effective water density (pumping head) and mass flow
velocities in the furnace circuits.
The key modifications implemented in the circulation upgrade were as follows (See Fig. 22b):
1. New drum internals. Three rows of highly efficient,
low pressure drop cyclone separators replaced the
existing two rows of high pressure drop turboseparators. (See Fig. 23.) The drum water level
was increased from −10 in. (−254 mm) to the
centerline. These modifications increased the
available head for all circuits.
Field tests were conducted to verify the operating
parameters. A computer simulation focused on the circulation of the steam drum, wing wall and rear wall
arch tube circuits. Mass flow velocities in these tubes
were found to be low. These low velocities contributed
to flow imbalances between circuits as well as film boiling conditions inside the tubes. The steam film acted
as an insulator, producing numerous overheat failures.
The existing drum internals were also found to be
significant contributors to the circulation problem. The
separators in the steam drum generated a high pressure drop, by reducing the pumping head and causing
flow imbalances. The drum water level, 10 in. (254 mm)
2. Redesigned wing walls. The overall length of the
wing walls was increased to raise the heat absorption in these vulnerable circuits, based on the
natural circulation principle of more heat, more
flow. This also lowered the furnace exit gas temperature by about 35F (19C) which reduced the
tendency of slagging beyond the furnace. A third
benefit was a slight reduction in superheat and,
especially, reheat spray, both being excessive on
the existing unit.
The bottom slope was increased from 17 to 40
deg (0.3 to 0.7 rad) and the tube diameter was decreased. Multi-lead ribbed tubes were used instead
of internally smooth tubes in the sloped portion.
Fig. 22a Original upper furnace arrangement.
Fig. 22b Upper furnace arrangement for a circulation upgrade.
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These measures were aimed at eliminating film
boiling and flow instabilities, identified as the root
cause of tube failures in these circuits. Film boiling in these circuits promoted formation of internal deposits and corrosion due to stagnant flow
conditions. The increased flow resistance was more
than offset by the greater pumping head generated by the new design.
3. Redesigned water supply system. The existing
downcomers were lengthened and closed off by
new downcomer bottles. Each bottle was equipped
with eight supply pipes, four feeding each vertical wing wall inlet header.
4. Redesigned rear wall arch. Multi-lead ribbed tubes
were installed in the rear wall arch in the form of
shop-membraned tube panels. This eliminated the
failures in the lower bend area. The original transition from the 2.5 in. (63.5 mm) OD rear wall
tubes to the 3 in. (76.2 mm) arch tubes created a
steam-water jet along the unheated side (inside
of the extrados) of these bends and a corresponding void on the inside of the tube bends. This had
caused the crucial bend sections facing the furnace
heat to fail due to insufficient cooling. For additional margin, the arch tubes were also redesigned
as multi-lead ribbed tubes.
The overall boiler circulation was significantly improved, and a high design margin prevented the recurrence of failures in the wing walls or rear wall tubes.
The circulation upgrade restored 100% load capability
and improved unit reliability and availability.
Strategies for fuel switching while
maintaining high commercial availability
To help reduce sulfur dioxide (SO2) emissions, many
power plants are now burning a Powder River Basin
(PRB) coal blend. The ash of some PRB blends forms
a white deposit in the furnace and elsewhere in the
boiler. The deposit tends to be reflective. This characteristic suppresses heat transfer, especially in the furnace, and leads to flyash plugging of the tightlyspaced convection heating surfaces. The inhibition of
heat transfer raises flue gas temperatures, and often
results in some loss of thermal efficiency.
The elevated gas temperatures can lead to long-term
overheating of the non-cooled mechanical economizer
support hangers, causing premature failure. Under
some conditions, the temperature of the flue gas leaving the economizer can exceed the design temperature
of the casing enclosure and flues between the economizer and the air heater downstream. The high gas
temperature can also elevate economizer water outlet enthalpy, which causes cavitation problems in boiler
circulation pumps in forced circulation boilers.
A boiler’s economizer is, by definition, intended to
reduce operating costs by recovering energy from the
flue gas. This heat energy is transferred to water entering the boiler. Since overall boiler efficiency is increased 1% for every 40F (22C) reduction in flue gas
stack temperature, the design of the economizer and
its interaction with the boiler’s fuel and flue gas are
important concerns to power plant operators.
44-18
Fig. 23 Cyclone steam separator installation.
Many utility boilers were installed with continuous
fin surface (CFS) economizers using a staggered tube
arrangement. This surface used 2.0 in. (5.08 cm) high
and 0.25 in. (0.635 cm) thick fins welded to the top
and bottom of each tube [usually 2 in. (5.08 cm) outside diameter] parallel to the tube axis. CFS economizers originally appealed to many plant designers
because the torturous path created for the flue gas
enhanced heat absorption, and the fins could capture
heat and transfer it to the tubing. This made the CFS
economizer less costly and permitted installation in a
relatively small area.
With the increasing use of western U.S. and lower
quality fuels over the past few decades, however, the
very factor that had been an advantage of the CFS
economizer design became a disadvantage. The spacing proved more susceptible to plugging and flyash
erosion and required more frequent cleaning.
Fuel switching can, therefore, lead to many related
boiler problems that affect efficiency, availability and
capacity. Power plant operators are faced with many
interrelated problems when operating a plant that has
changed from the design fuel to a low cost compliance
fuel such as a PRB coal. Margins for acceptable operation are reduced and the power plant can suffer
from high heat rates (i.e., lower efficiency), high operating costs, and frequent outages to remove ash
buildup. A strategy is needed to deal with these problems so that the new low-cost compliance fuel can be
used without the plant suffering from degradations
in capacity, heat rate, operating cost and availability.
Fuel switching example
In one example of fuel switching, the economizer
experienced ash plugging problems with PRB coal,
making the unit unable to achieve the design main
steam temperature at higher loads. The ash plugging
resulted in periodic shutdowns for cleaning and mainSteam 41 / Maintaining Availability
The Babcock & Wilcox Company
tenance. Because of the economizer’s staggered, finned
tube design, plant operators could not use sootblowers
to restore heat transfer capabilities. At higher loads, the
superheater temperature could not reach design levels, leading to a reduction in boiler efficiency. The resulting low main steam temperature to the turbine is
equivalent to a reduction in cycle efficiency.
The example unit is a 750 MW (gross), pulverized
coal-fired, balanced draft boiler. At maximum continuous rating (MCR), original design conditions were
4,985,000 lb/h (628 kg/s) main steam flow at 2400 psig
(16.5 MPa) throttle pressure and 1007F (542C). The
ash plugging resulted in periodic shutdowns for cleaning and maintenance.
The primary goal of the upgrade project was to replace the worn and increasingly unreliable economizer
with a design that corrected these existing problems,
and while doing so, return the main steam temperature to its original design level. Additional project tasks
included complete boiler modeling, pressure part design and fabrication (including the complete redesign
of the economizer support system), supply of
sootblower equipment and hangers, and the fabrication and supply of steam-cooled wall openings for the
sootblowers and access doors.
The existing economizer was replaced with a bare
tube, in-line design. (See the example of a finned tube
economizer replacement earlier in this chapter.) The
bare tube, in-line economizer design minimized the
erosion and ash trapping problems that are common
to staggered arrangements. The in-line design also
improved the effectiveness of sootblowers and resulted
in the maintenance of adequate heat transfer. Fig. 24
illustrates the upgraded design and its redesigned
economizer, primary superheater and sootblowers.
To maintain the necessary amount of heat transfer surface, the upgrade increased the number of
economizer elements by about 25%. The installation
of a new inlet header and a number of intermediate
headers accommodated the increased number of water flow circuits. Tube shields to protect the tubes in
the sootblower lane were added, in addition to erosion
barriers along the walls of the unit.
To raise the superheat steam temperature, relatively
small horizontal primary superheater loops above the
economizer were added. The existing economizer support tubes were modified to provide water-cooled support
for the small bank of new primary superheater surface.
New sootblowers were also incorporated into the
retrofit design. Limited outboard space prohibited the
installation of full travel, long retract sootblowers.
Extended lance, half-track sootblowers were installed
as part of the upgrade. Gas temperatures entering the
economizer exceeded the traditional maximum temperature for these extended lances, so the lances were manufactured from a high temperature alloy material.
The eight sootblowers were supplied with the Progressive Helix Mechanism feature to reduce the potential for boiler tube erosion (see Chapter 24). This
patented sootblower enhancement reduces tube erosion by shifting the nozzle cleaning path on every
blowing cycle. More than 400 cycles occur before any
nozzle path is repeated.
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The previous economizer design had suffered from
failures of the supports that were of a welded design.
To simplify installation and to provide a support system that did not rely on tension welds, the economizer
support system was designed to accommodate small
banks of elements and to support the banks with pins
and collector plates. Stainless steel and Incoloy alloy
800HT pins and plates were used to ensure high-temperature strength and oxidation resistance without
relying on welds. Fig. 25 shows the collector plates
and pin connections used in this upgrade.
The use of factory-installed pins and plates reduced
on-site installation times. Construction crews removed
the pins as the sections were brought up to elevation,
and then reinstalled the pins after the collector plates
had been mated to the support brackets. Because the
process required no field welding of supports, the entire installation proceeded smoothly. After the sections
had been hung in place, project personnel performed
tube-to-tube welds between banks as time and space
permitted.
The finned tube economizer replacement resulted
in the following unit enhancements:
1. provided a solution to the problem of burning the
PRB fuel blend,
2. eliminated plugging of the finned tube economizer,
3. reduced draft loss,
Stringer
Tubes
Pinned
Collectors
Primary
Outlet
Typical Sootblower Location
Economizer
Outlet
Tube Shields
Economizer
Inlet
Economizer
Inlet Header
Ladder Bar
Supports
Fig. 24 Upgraded economizer and superheater arrangement to
accommodate PRB fuel.
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The Babcock & Wilcox Company
Fig. 25 The use of pins and collectors simplified construction and
improved reliability by eliminating original welded supports.
4. reduced economizer exit gas temperatures to improve unit efficiency,
5. returned main steam temperatures to original design conditions to improve unit efficiency, and
6. improved unit availability through elimination of
fouling problems and restoration of unit capacity
and efficiency.
Capacity upgrades and environmental
regulations
A capacity increase with higher efficiency and
availability (sometimes called uprates), together with
lower emissions, can lead to attractive returns on investment. Increases up to 10% in capacity and improvements in heat rate of 1 to 2% have been demonstrated.
With the current interpretation of the rules for environmental standards relative to capacity increases,
the boiler operator must consider meeting, for example,
U.S. New Source Performance Standards when a capacity upgrade is implemented. The addition of scrubbers and selective catalytic reduction (SCR) systems
for the boiler flue gas must be considered when appropriate. This environmental equipment, combined
with the capacity upgrade, may result in lower total
regulated emissions when the project is properly configured. However, future changes in rules and policies may change the feasibility of this scenario.
Example strategy for capacity upgrade
while maintaining high commercial availability
The typical capacity upgrade starts with an engineering study. To optimize the return on investment
for the capacity increase, the project requires cooperation between the boiler manufacturer and the turbine
vendor. During the engineering study, there is an interaction between the boiler and the turbine equipment suppliers such that the boiler and turbine uprate
designs may be considered simultaneously. A series of
design discussions must be held between the boiler and
turbine designer to develop an upgrade strategy that
can provide the optimum combination of performance
and capital expenditure while considering the limits
44-20
of the existing equipment and the potential design improvements. Often, new technology has been developed for the boiler and turbine generator set since the
commissioning of the power station, and therefore,
there is an opportunity to apply this new technology to
enhance the efficiency and capacity of the unit.
The boiler manufacturer looks at key components
that will be affected by the increased steam and water flow requirements. Operating pressures and heat
transfer are affected by the increased flows. The designer must look at each of the key components versus
the original design and possible design improvements
to develop a plan for the capacity increase. As an example, a furnace circulation analysis must be run to determine if the furnace has the capacity to operate safely
with the higher flows and heat input. Components that
are commonly evaluated are shown in Table 3.
To properly evaluate the unit in the engineering
study, a performance test of the unit under various
conditions is required. This test will calibrate and validate the boiler computer model that is used to evaluate
the boiler upgrade. The boiler model takes into account
changes in boiler surface and fuels that have occurred
since the boiler was first commissioned. The model will
also consider changes to the unit, or operating procedures that were made for any pollution control equipment that may have been added or modified.
The increased firing rate will increase gas velocities
in the convection pass and will increase the possibility
for fouling and slag accumulation. The need for increased
sootblowing and erosion protection is evaluated.
After the engineering study is completed and the
equipment modifications are determined, costs are
evaluated. A typical upgrade might include advanced
turbine components to accommodate the higher steam
flows and to achieve higher efficiency.
Table 3
Key Boiler Components Evaluated in a
Capacity Upgrade Engineering Study
Pressure components
Economizer
Furnace and convection pass
water circuits, including drums
and steam separators
Superheaters and reheaters
Attemperators
Connection piping and headers
Nonpressure boiler components
Fuel preparation equipment
Burners
Air heaters
Ductwork and supports
Balance of plant equipment
Fans
Feed pumps
Pollution control equipment
Controls
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The Babcock & Wilcox Company
Because turbine efficiency is determined by the design of the steam path components such as the nozzles,
bucket profiles, as well as the leakage flows, these components may be upgraded with significant impact on
overall plant performance. Much work has been done to
improve the aerodynamics and reduce losses associated with
buckets and nozzles. Most turbine upgrades involve a reduction in secondary flow losses. Designs have evolved
that improve the resistance to solid particle erosion for
longer efficient design life. There are numerous examples
of the advantages of turbine upgrades. However, the
best strategy is to coordinate the boiler and turbine upgrade to achieve the best return on investment.
Normally, a capacity uprate capital project improves
heat rate and extends times between major turbine
overhaul outages. These benefits are the result of replacing nozzles and final stage buckets with improved
designs and improvements in steam losses together
with higher steam flows.
Typical improvements to the boiler might include
the replacement of the superheater or reheater outlet
bank(s), a new attemperator, new burners, new higher
efficiency separators in the steam drum, and the addition of air quality control equipment. The actual
modifications are very specific to the original unit design, the fuel, and the environmental constraints.
Inconel, Incoclad, Incoloy and 671/800HT are trademarks of the
Special Metals Corporation group of companies.
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The Babcock & Wilcox Company
Upgrade work on lower hopper of once-through Universal Pressure boiler.
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Chapter 45
Condition Assessment
The assessment of accumulated damage, or condition assessment, has a long history in the boiler industry. Whenever a component was found to contain
damage or had failed, engineers asked what caused
the damage and whether other components would fail.
These questions typically pertained to tubing and
headers, which caused the majority of downtime. As
boiler cycling became more common, the need for more
routine condition assessment increased to avoid component failure and unscheduled outages.
Condition assessment includes the use of tools or
methods in the evaluation of specific components and
then the interpretation of the results to identify 1) the
component’s remaining life and 2) areas requiring
immediate attention.
A boiler component’s damage assessment, typically
compared to its design life, is based on accumulated
damage, and can be performed in three phases. In
Phase 1 of the assessment, design and overall operating records are reviewed and interviews are held with
operating personnel. In Phase 2, nondestructive examinations, stress analysis, verification of dimensions,
and operating parameters are undertaken. If required,
the more complex Phase 3 includes finite element
analysis, operational testing and evaluation, and
material properties measurement.1 (See Fig. 1.)
Condition assessment examination
methods
The major boiler components must be examined by
nondestructive and destructive tests.
Nondestructive examinations
Most nondestructive examination (NDE) methods
for fossil fuel-fired plants have been in use for many
years, although new methods are being developed for
major components. Nondestructive testing does not
damage the component.
The NDE methods used in evaluating electric utility power stations and industrial process plants include:
visual, magnetic particle, liquid penetrant, ultrasonic,
eddy current, radiography, nuclear fluorescence, elecSteam 41 / Condition Assessment
Fig. 1 Three phases (levels) of boiler damage assessment (courtesy
of the Electric Power Research Institute).1
tromagnetic acoustics, acoustic emissions, metallographic replication, strain measurement and temperature measurement.
Visual Whether the inspected component is subject
to mechanical wear, chemical attack, or damage from
thermal stress, visual examination can detect and identify some of the damage. Visual inspection is enhanced
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The Babcock & Wilcox Company
by lighting, magnification, mirrors, and optical equipment such as borescopes, fiberscopes and binoculars.
Magnetic particle Magnetic particle testing (MT)
and wet fluorescent magnetic particle testing (WFMT)
detect surface and near surface flaws. Because a magnetic field must be imparted to the test piece, these tests
are only applicable to ferromagnetic materials.2 The
choice between these techniques generally depends on
the geometry of the component and the required sensitivity. For typical power plant applications, one of two
methods is used: 1) the component is indirectly magnetized using an electromagnetic yoke with alternating current (AC), or 2) the part is directly magnetized
by prods driven by AC or direct current (DC).
In magnetic particle testing, any discontinuity disrupts the lines of magnetic force passing through the
test area creating a leakage field. Iron particles applied to the area accumulate along the lines of magnetic force. Any leakage field created by a discontinuity is easily identified by the pattern of the iron particles. Dry magnetic particle testing is performed using a dry medium composed of colored iron particles
that are dusted onto the magnetized area. In areas
where a dry medium is ineffective, such as in testing
overhead components or the inside surfaces of pressure vessels, the wet fluorescent method is more effective. With this method, fluorescent ferromagnetic
particles are suspended in a liquid medium such as
kerosene. The liquid-borne particles adhere to the test
area. Because the particles are fluorescent, they are
highly visible when viewed under an ultraviolet light.
Liquid penetrant Liquid penetrant testing (PT) detects surface cracking in a component. PT is not dependent on the magnetic properties of the material
and is less dependent on component geometry.2 It is
used by The Babcock & Wilcox Company (B&W) in
limited access areas such as tube stub welds on high
temperature headers which are generally closely
spaced. PT detects surface flaws by capillary action of
the liquid dye penetrant and is only effective where
the discontinuity is open to the component surface.
Following proper surface cleaning the liquid dye is
applied. The penetrant is left on the test area for about
ten minutes to allow it to penetrate the discontinuity.
A cleaner is used to remove excess penetrant and the
area is allowed to dry. A developer is then sprayed onto
the surface. Any dye that has been drawn into the surface at a crack bleeds into the developer by reverse
capillary action and becomes highly visible.
Ultrasonic Ultrasonic testing (UT) is the fastest developing technology for nondestructive testing of pressure components. Numerous specialized UT methods
have been developed. A piezoelectric transducer is
placed in contact with the test material, causing disturbances in the interatomic spacings and inducing an
elastic sound wave that moves through the material.3
The ultrasonic wave is reflected by any discontinuity
it encounters as it passes through the material. The
reflected wave is received back at the transducer and
is displayed on an oscilloscope.
Ultrasonic thickness testing Ultrasonic thickness testing (UTT) is the most basic ultrasonic technology. A
common cause of pressure part failure is the loss of
45-2
material due to oxidation, corrosion or erosion. UTT
is relatively fast and is used extensively for measuring wall thicknesses of tubes or piping.
The surface of the component must first be thoroughly cleaned. Because ultrasonic waves do not pass
through air, a couplant such as glycerine, a water
soluble gel, is brushed onto the surface. The transducer is then positioned onto the component surface
within the couplant. A high frequency (2 to 5 MHz)
signal is transmitted by the transducer and passes
through the metal. UTT is performed using a longitudinal wave which travels perpendicular to the contacted surface. Because the travel time for the reflected
wave varies with distance, the metal thickness is determined by the signal displacement, as shown on the
oscilloscope screen (Fig. 2).
Ultrasonic oxide measurement In the mid 1980s, B&W
developed an ultrasonic technique specifically to
evaluate high temperature tubing found in superheaters and reheaters. This NDE method, called the Nondestructive Oxide Thickness Inspection Service
(NOTIS), measures the oxide layer on the internal
surfaces of high temperature tubes. The test is generally applicable to low alloy steels because these materials are commonly used in outlet sections of the superheater and reheater.
Low alloy steels grow an oxide layer on their internal surfaces when exposed to high temperatures for
long time periods (Fig. 3). The NOTIS test is not applicable to stainless steels because they do not develop
a measurable oxide layer.
The technique used for NOTIS testing is similar to
UTT; the major difference between the two is the frequency range of the ultrasonic signal. A much higher
frequency is necessary to differentiate the interface
between the oxide layer and inside diameter (ID) surface of the tube. Using data obtained from this NOTIS
testing, tube remaining creep life can also be calculated as discussed later in Analysis techniques. NOTIS
and UTT are methods in which the transducer is
placed in contact with the tube using a couplant gel.
Because of the high sensitivity of the NOTIS method,
it is less tolerant of rough tube surfaces or poor surface preparation.
Ultrasonic measurement of internal tube damage Several ultrasonic methods have been investigated for
detecting damage within boiler tubes. All techniques
Fig. 2 Typical ultrasonic signal response.4
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The Babcock & Wilcox Company
Fig. 3 Steam-side oxide scale on ID surface.
use contact UT where a transducer is placed on the
outside diameter (OD) or tube surface using a
couplant, and an ultrasonic signal is transmitted
through the material. The techniques can be categorized by type of signal evaluation: backscatter, the
evaluation of UT wave scatter when reflected by damaged material; attenuation, the evaluation of UT signal
loss associated with transmission through damaged
material; and velocity, the measurement and comparison of UT wave velocity through the tube material.4
When a longitudinal wave passes through a tube,
part of the signal is not reflected to the receiver if it
encounters damaged material. The damaged areas
reflect part of the wave at various angles, backscattering the reflected signal. The loss of wave amplitude
that is received back at the transducer is then used to
evaluate the degree of damage.
Damage in the tube can also be assessed by evaluating the loss of signal amplitude (attenuation) as a
shear wave is transmitted through the tube wall. The
technique uses a fixture with two transducers
mounted at angles to each other. One unit transmits
a shear wave into the tube and the second transducer,
the receiver, picks up the signal as the wave is reflected
from the tube ID. A drop in signal amplitude indicates
damage in the tube wall.
This technology is the basis of the B&W patented Furnace wall Hydrogen damage Nondestructive Examination Service (FHyNES)test method (Fig. 4). The velocity test method uses either longitudinal or shear
ultrasonic waves. As a wave passes through a chordal
section of tube with hydrogen damage, there is a
measurable decrease in velocity. Because the signal
is not reflected from the tube inside surface, ultrasonic
velocity measurement is not affected by damage to the
inside of the tube and therefore specifically detects
hydrogen damage.
Steam 41 / Condition Assessment
Immersion ultrasonic testing In immersion ultrasonic
testing, the part is placed in a water bath which acts
as the couplant. B&W uses a form of immersion UT
for tube wall thickness measurements. In two-drum
industrial power boilers, process recovery boilers and
some utility power generation boilers, most of the tubes
in the convective bank between the drums are inaccessible for conventional contact UTT measurements.
For these applications, an ultrasonic test probe was
developed which is inserted into the tubes from the
steam drum; it measures the wall thickness from inside the tubes. As the probe is withdrawn in measured
increments, the transducers measure the tube wall
thicknesses. A limitation of this technique is that the
ID surface of the tubes must be relatively clean.
Shear wave ultrasonic testing This is a contact ultrasonic technique in which a shear wave is directed at
an angle into the test material. Angles of 45 and 60
deg (0.79 and 1.05 rad) are typically used for defect
detection and weld assessment. The entire weld must
be inspected for a quality examination.
Time of flight defraction (TOFD) TOFD is an ultrasonic
technique that relies on the diffraction of ultrasonic
energies from defects in the component being
tested. The primary application is weld inspection on
piping, pressure vessels, and tanks. TOFD is an automated inspection that uses a pitch-catch arrangement with two probes, one on each side of the weld.
The weld material is saturated with angled longitudinal waves to inspect for discontinuities. Because the
time separation of the diffracted waves is directly related to flaw size (height), TOFD can detect both the
flaw and allow estimation of the flaw size.
Eddy current Measuring the effects of induced eddy
currents on the primary or driving electromagnetic
field is the basis of eddy current testing. The electromagnetic induction needed for eddy current testing
is created by using an alternating current. This develops the electromagnetic field necessary to produce
eddy currents in a test piece.
Eddy current testing is applicable to any materials
that conduct electricity and can be performed on magnetic and nonmagnetic materials. The test is therefore
Fig. 4 Shear wave technique for detecting hydrogen damage.
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The Babcock & Wilcox Company
applicable to all metals encountered in power station
condition assessment work.
Parameters affecting eddy current testing include
the resistivity, conductivity, and magnetic permeability of the test material; the frequency of the current
producing the eddy currents; and the geometry and
thickness of the component being tested.
Radiography Radiography testing (RT) is the most
common NDE method used during field erection of a
boiler. Radiography is also valuable in condition assessments of piping. As x-rays and gamma rays pass
through a material, some of the rays are absorbed.
Absorption depends upon material thickness and density. When the rays passing through an object are
exposed to a special film, an image of the object is produced due to the partial absorption of the rays.
In practical terms, a radioactive source is placed on
one side of a component such as a pipe, at a weld, and
a film is placed on the opposite side. If x-rays are directed through the weld and there is a void within the
weld, more rays pass through this void and reach the
film, producing a darker image at that point. By examining the radiographic films, the weld integrity can be
determined. During the field erection of a boiler and
power station, thousands of tube and pipe welds are
made and radiographed. (See also Chapters 38 and 39.)
The major disadvantage of radiography is the harmful effect of excessive exposure to the radioactive rays.
RT is also limited in its ability to provide the orientation and depth of an indication.
Nuclear fluorescence The primary use of this testing in condition assessment is the verification of alloy materials in high temperature piping systems.
When certain elements are exposed to an external
source of x-rays they fluoresce (emit) additional x-rays
that vary in energy level. This fluorescence is characteristic of the key alloys common to high temperature
piping and headers. Chromium and molybdenum are
the key elements measured. The nuclear alloy analyzer is a portable instrument that contains a low level
source of x-rays. A point on the surface of the pipe is
exposed to x-rays emitted from the analyzer. As the
source x-rays interact with the atoms of the metal, the
alloys emit x-rays back to the analyzer. Within the
detector system of the analyzer, the fluoresced x-rays
are separated into discrete energy regions. By measuring the x-ray intensity in each energy region, the
elemental composition is also determined.
Electromagnetic acoustics Electromagnetic acoustics combine two nondestructive testing sciences, ultrasonics (UT) and electromagnetic induction. This
technology uses an electromagnetic acoustic transducer (EMAT) to generate high frequency sound waves
in materials, similar to conventional ultrasonics. Conventional UT transducers used for field testing convert electrical impulses to mechanical pulses by use
of piezoelectric crystals. These crystals must be
coupled to the test piece through a fluid couplant. For
electrically conductive materials, ultrasonic waves can
be produced by electromagnetic acoustic wave generation.5 In contrast to conventional contact UT where a
mechanical pulse is coupled to the material, the acoustic wave is produced by the interaction of two mag-
45-4
netic sources. The first magnetic source modulates a
time-dependent magnetic field by electromagnetic induction as in eddy current testing. A second constant
magnetic field provided by an AC or DC driven electromagnet or a permanent magnet is positioned near
the first field. The interaction of these two fields generates a force, called the Lorentz force, in the direction perpendicular to the two other fields. This Lorentz
force interacts with the material to produce a shock
wave analogous to an ultrasonic pulse, eliminating the
need for a couplant.
Fig. 5 shows the basic principles of EMAT operation.
A strong magnetic field (B) is produced at the surface
of the test piece by either a permanent magnet or electromagnet. Eddy currents (J) are induced in the test
material surface. An alternating eddy flow in the presence of the magnetic field generates a Lorentz force
(F) that produces an ultrasonic wave in the material.
For boiler tubes that are electromagnetically conductive (including alloys such as SA-213T22), the EMAT
technology is ideal.
B&W, working with the Electric Power Research
Institute (EPRI), developed a nondestructive rapid
scan system to inspect boiler tubes using EMAT technology. This EMAT based system is known as the FastScanning Thickness Gage (FST-GAGE ) and was
developed specifically to scan boiler tubes and provide
a continuous measurement of tube wall thickness.
(See Fig. 6.) The system conducts tests at exceptional
speeds, allowing scanning of thousands of feet (m) of
boiler tubing in a single shift. To perform an inspection, the FST-GAGE system is manually scanned
along individual boiler tubes. System sampling rates
greater than 65 samples per second supports rapid
scanning of tubes. During a scan, the system provides
an immediate display of both tube wall thickness and
signal amplitude. At the conclusion of each tube scan,
a complete record of the inspection is electronically
stored and is traceable to each boiler tube and position.
As with conventional UT, the FST-GAGE system can
assess internal tube damage by evaluating the loss of
signal amplitude (attenuation) as a shear wave is transmitted through the tube wall. By monitoring and indicating signal amplitude, the system can also be used to
detect tube damage such as hydrogen damage, similar
to B&W’s patented FHyNES technique. The FST-GAGE
has also demonstrated the ability to detect internal tube
pitting, caustic gouging, and under-deposit corrosion.
Magnet
J (Eddy
Currents)
Conducting
Material
F (Lorentz
Force)
B (Magnetic
Force)
Ultrasonic
Wave
Eddy Current Coil
Fig. 5 Basic principles of EMAT operation.
Steam 41 / Condition Assessment
The Babcock & Wilcox Company
To Scan
Fig. 6 B&W’s Fast-Scanning Thickness Gage (FST-GAGE®) EMAT
based system can provide continuous measurement of tube wall
thickness.
As with any NDE method, surface preparation is
important for effective testing with EMATs. However,
EMAT is not as sensitive to scale as conventional UT
since it produces the ultrasonic wave within the material. Some scales, such as magnetite oxide of uniform
thickness, have no detrimental effect on the signal
generation of the EMAT probe. When the plant burns
a clean fuel such as natural gas, testing may be conducted without any special surface cleaning. To protect the coil from damage, surface preparation will
normally be required for boilers firing oil or solid fuels. Some gas-fired units may require surface cleaning if external buildup or corrosion is present. Grit
blasting or water blasting are effective methods of
cleaning larger areas. Smooth metal is the preferred
surface to ensure rapid testing.
EMAT technology continues to be applied where its
unique properties have advantages over conventional
UT techniques. B&W and EPRI are developing a system for the detection of cracking in boiler tubes associated with corrosion fatigue. Waterside corrosion fatigue is a serious boiler tube failure mechanism. The
failures usually occur close to attachments such as
buckstay welds, windbox attachment welds, or membrane welds. The combination of thermal fatigue
stresses and corrosion leads to ID-initiated cracking
that is oriented along the tube axis. The EMAT system under development for corrosion fatigue has
unique characteristics that enhance its ability to scan
past welds and attachments and scan the full circumference of the boiler tube. The EMAT equipment uses
a tone burst EMAT signal allowing the use of horizontally polarized shear wave (SH waves) to detect cracking adjacent to external tube attachment welds.
B&W has developed an EMAT application to inspect
horizontal banks (i.e., economizer, reheater) of tubing
within the boiler. Horizontal bank tubing may experience tube failures caused by out of service corrosion
pitting forming aligned voids in the tube ID. The purpose of this EMAT test is to detect the internal aligned
Steam 41 / Condition Assessment
pitting at the lower portion of the horizontal tube internal surface. The test is accomplished by scanning
along the outside of the horizontal tube at either the
3 or 9 o’clock positions with an EMAT transducer generating a Lamb wave (ultrasonic waves that travel at
right angles to the tube surface) which is focused at
the 6 o’clock position on the tube.
B&W has also developed a surface wave EMAT
application to show surface indications including axially oriented cracks in boiler tubes. Conventional surface nondestructive test methods were unsatisfactory
because they lacked adequate sensitivity and had slow
production rates for testing on large areas. A tone burst
EMAT technique was developed that uses a bidirectional focused surface wave EMAT that follows the tube
surface circumferentially until the signal is reflected
back from a longitudinally orientated OD crack.
Acoustics Acoustics refers to the use of transmitted
sound waves for nondestructive testing. It is differentiated from ultrasonics and electromagnetic acoustics in that it features low frequency, audible sound.
B&W uses acoustic technology in testing tubular air
heaters. Because the sound waves are low frequency,
they can only be transmitted through air. A pulse of
sound is sent into the air heater tube. As the wave
travels along the tube, it is reflected by holes, blockage or partial obstructions. By evaluating the reflected
wave on an oscilloscope, the type of flaw and its location along the tube can be determined.
Acoustic emissions Acoustic emissions (AE) detect
subsurface crack growth in pressure vessels. When a
structure such as a pipe is pressurized and heated,
the metal experiences mechanical and thermal
stresses. Due to the stress concentration at a defect
such as a crack, a small overall stress in the pipe can
produce localized yield and fracture stresses resulting in plastic deformation. These localized yields release bursts of energy or stress wave emissions that
are commonly called acoustic emissions. AE testing
uses acoustic transducers that are positioned along the
vessel being monitored. AE signals are received at
various transducers on the vessel. By measuring the
time required for the signal to reach each of the transducers, the data can be interpreted to identify the location of the defect.
Metallographic replication Metallographic replication is an in situ test method that enables an image of
the metal grain structure to be nondestructively lifted
from a component. Replication is important in evaluating high temperature headers and piping because
it allows the structure to be examined for creep damage. Prior to the use of replication techniques, it was
necessary to remove samples of the material for laboratory analysis. The replication process involves three
steps: grinding, polishing and etching, and replicating. In the first step, the surface is rough ground then
flapper wheel ground with finer grit paper. In the second step, the surface is polished using increasingly
finer grades of diamond paste while intermittently
applying a mixture of nitric acid and methanol in solution. The acid solution preferentially attacks the
grain boundaries of the metal. In the final step, the
replica, which is a plastic tape, is prepared by coating
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The Babcock & Wilcox Company
one face of the tape with acetone for softening. The
tape is then firmly pressed onto the prepared surface.
Following a suitable drying time, the tape is removed and
mounted onto a glass slide for microscopic examination.
Strain measurement Strain measurements are obtained nondestructively by using strain gauges.
Gauges used for piping measurements are characterized by an electrical resistance that varies as a function of the applied mechanical strain.6 For high temperature components, the gauge is made of an alloy,
such as platinum-tungsten, which can be used at temperatures up to 1200F (649C). The gauge is welded to
the surface of the pipe and the strain is measured as
the pipe ramps through a temperature-pressure cycle
to operating temperature. Strain gauges used for lower
temperature applications such as for analysis of hanger
support rods are made of conventional copper-nickel alloy (constantan). These low temperature gauges are
made of thin foil bonded to a flexible backing and are
attached to the test surface by a special adhesive.
Temperature measurement Most temperature measurements can be obtained with sheathed thermocouples (TC). In special applications where temperature gradients are needed such as detailed stress
analysis of header ligaments, special embedded TCs
are used. The embedded unit is constructed by drilling a small hole into the header. A sheathed TC wire is
then inserted and peened in place. (See Chapter 40.)
Destructive examinations
B&W tries to minimize the use of sample analysis
because it is generally more expensive to perform destructive testing. However, for certain components, complete
evaluation can only be done by removing and analyzing test samples. Destructive testing is described for two
types of specimens, tube samples and boat samples.
Tube samples Tubes are the most common destructively tested components. Tube samples are generally
removed from water- and steam-cooled circuits. A relatively large number of samples may be removed for
visual inspections, from which a smaller number are
selected for complete laboratory analysis. A tube
analysis usually includes the following: 1) as-received
sample photo documentation, 2) complete visual inspection under magnification, 3) dimensional evaluation of a ring section removed from the sample, 4)
material verification by spectrographic analysis, 5) optical metallography, and 6) material hardness measurement. On waterwall tubes removed from the
boiler furnace, the analysis includes a measurement
of the internal deposit loading [g/ft2 (g/m2)] and elemental composition of the deposit. On steam-cooled
superheater and reheater tubes, the thickness of the
high temperature oxide layer is also provided.
Specialized tests are performed as required to provide more in-depth information. Failure analysis is a
common example. When failures occur in which the
root cause is not readily known from standard tests,
fractography is performed. Fractography involves
examination of the fracture surface using a scanning
electron microscope.
Boat samples Boat samples are wedge shaped slices
removed from larger components such as headers,
45-6
piping and drums. The shape of the cut allows the
material to be replaced by welding. Because the repairs
usually require post weld heat treating, the use of boat
samples is expensive. In most instances, replication is
adequate for metallographic examination of these components and boat sample removal is not required.
Condition assessment of boiler
components and auxiliaries
In Phase 1 of a condition assessment program, interviews of plant personnel and review of historical
maintenance records help identify problem components. These components are targeted for a closer onsite examination during Phase 2 of the program. Nondestructive and destructive examination methods can
then be used to evaluate the remaining life of the boiler
components and its major auxiliaries.
Boiler drums
Steam drum The steam drum is the most expensive
boiler component and must be included in any comprehensive condition assessment program. There are
two types of steam drums, the all-welded design used
predominantly in electric utilities where the operating pressures exceed 1800 psi (12.4 MPa), and drums
with rolled tubes. The steam drum operates at saturation temperature [less than 700F (371C)]. Because
of this relatively low operating temperature, the drum
is made of carbon steel and is not subject to significant creep. Creep is defined as increasing strain at a
constant stress over time.
Regardless of drum type, damage is primarily due
to internal metal loss. The causes of metal loss include:
corrosion and oxidation, which can occur during extended outages; acid attack; oxygen pitting; and
chelant attack discussed in Chapter 42. Damage can
also occur from mechanical and thermal stresses on
the drum that concentrate at nozzle and attachment
welds. These stresses, most often associated with boilers that are on/off cycled, can result in crack development. Cyclic operation can lead to drum distortion
(humping) and can result in concentrated stresses at
the major support welds, seam welds, and girth welds.
The feedwater penetration area has the greatest thermal differential because incoming feedwater can be
several hundred degrees below drum temperature.
A problem unique to steam drums with rolled tube
seats is tube seat weepage (slight seeping of water
through the rolled joint). If the leak is not stopped, the
joint, with its high residual stresses from the tube rolling operation, can experience caustic embrittlement.
(See Chapter 42.) In addition, the act of eliminating
the tube seat leak by repeated tube rolling can overstress the drum shell between tube seats and lead to
ligament cracking.
Condition assessment of the steam drum can include visual and fiber optic scope examination, MT,
PT, WFMT, UT and replication.
Lower drum The lower or mud drum is most often
found in industrial boilers. (See Chapter 27.) Part of
the boiler’s water circuit, the lower drum is not sub-
Steam 41 / Condition Assessment
The Babcock & Wilcox Company
ject to large thermal differentials or mechanical
stresses. However, as in steam drums with rolled tubes,
seat weepage and excessive stresses from tube rolling
can occur. In most cases, visual inspection, including
fiber optic probe examination of selected tube penetrations, is sufficient. Kraft recovery boiler lower drums
are subject to corrosion of the tube-drum interface on
the OD. This area of the drum is inaccessible, therefore inspections are conducted from the ID using UTT
and EMATs to check for cracking and wall thinning.
The downcomers carry water from the steam drum
to the mud drum and the various wall circuits. Two
areas on the downcomers that should be inspected are
termination welds for cracks and horizontal runs of
piping for internal corrosion pitting and thinning.
Boiler tubing
Steam-cooled Steam-cooled tubing is found in the
superheater and reheat superheater. Both components have tubes subjected to the effects of metal
creep. Creep is a function of temperature, stress and
operating time. The creep life of the superheater tubes
is reduced by higher than expected operating temperature, thermal cycling, and by other damage
mechanisms, such as erosion and corrosion, causing
tube wall thinning and increased stresses. Excessive
stresses associated with thermal expansion and mechanical loading can also occur, leading to tube cracks
and leaks independent of the predicted creep life.
As discussed in Chapters 19, 21, 29 and 45, superheater tubing can also experience erosion, corrosion,
and interacting combinations of both.
Condition assessment of the superheater tubes includes visual inspection, NOTIS, UTT and tube
sample analysis. Problems due to erosion, corrosion,
expansion, or excessive temperature can generally be
located by visual examination.
Water-cooled Water-cooled tubes include those of
the economizer, boiler (generating) bank and furnace.
The convection pass side wall and screen tubes may
also be water-cooled as discussed in Chapter 19. These
tubes operate at or below saturation temperature and
are not subject to significant creep. Modern boilers in
electric utilities and many industrial plants operate
at high pressures. Because these boilers are not tolerant of waterside deposits, they must be chemically
cleaned periodically, which results in some tube material loss. As discussed in Chapter 42, proper water
chemistry control will limit tube inside surface material loss due to ongoing operations and cleaning.
With the exception of creep deformation, the factors
that reduce steam-cooled tube life can also act upon
water-cooled tubes. Erosion is most likely to occur on
tube outside surfaces in the boiler or economizer bank
from sootblowing or ash particle impingement. Corrosion of the water-cooled tubes is most common on
internal tube surfaces and results from excessive
waterside deposits. Deposit accumulations promote
corrosion, caustic gouging or hydrogen damage.
Risers The riser tubes are generally found in the
penthouse or over the roof of the boiler. They carry
the saturated steam-water mixture exiting the upper
waterwall headers to the steam drum. Condition as-
Steam 41 / Condition Assessment
sessment includes UTT measurements on nondrainable
sections and on the extrados (outside surface) of bends.
When access is available it is advantageous to perform
internal visual inspection with a fiber optic or video probe.
Headers
Headers and their associated problems can be
grouped according to operating temperature. High
temperature steam-carrying headers are a major concern because they have a finite creep life and their
replacement cost is high. Lower temperature waterand steam-cooled headers are not susceptible to creep
but may be damaged by corrosion, erosion, or severe
thermal stresses.
High temperature The high temperature headers
are the superheater and reheater outlets that operate at a bulk temperature of 900F (482C) or higher.
Headers operating at high temperature experience
creep under normal conditions. The mechanics of creep
crack initiation and crack growth are further discussed in the data analysis section of this chapter. Fig.
7 illustrates the locations where cracking is most likely
to occur on high temperature headers. In addition to
material degradation resulting from creep, high temperature headers can experience thermal and mechanical fatigue. Creep stresses in combination with
thermal fatigue stress lead to failure much sooner
than those resulting from creep alone.
There are three factors influencing creep fatigue in
superheater high temperature headers: combustion,
steam flow and boiler load. Heat distribution within
the boiler is not uniform: burner inputs can vary, air
distribution is not uniform, and slagging and fouling
can occur. The net effect of these combustion parameters is variations in heat input to individual superheater and reheater tubes. When combined with
steam flow differences between tubes within a bank,
significant variations in steam temperature entering
the header can occur. (See Fig. 8.) Changes in boiler
load further aggravate the temperature difference
between the individual tube legs and the bulk header.
As boiler load increases, the firing rate must increase
to maintain pressure. During this transient, the boiler
is temporarily over fired to compensate for the increasing steam flow and decreasing pressure. During load
decreases, the firing rate decreases slightly faster than
steam flow in the superheater with a resulting decrease in tube outlet temperature relative to that of
the bulk header (Fig. 9). As a consequence of these
Fig. 7 Header locations susceptible to cracking.
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The Babcock & Wilcox Company
Fig. 9 Superheater tube leg temperatures vary with load.
Fig. 8 Steam temperature variation in a header.
temperature gradients, the header experiences localized stresses much greater than those associated with
steam pressure and can result in large ligament cracks
as shown in Fig. 10.
In addition to the effects of temperature variations,
the external stresses associated with header expansion and piping loads must be evaluated. Header expansion can cause damage on cycling units resulting
in fatigue cracks at support attachments, torque
plates, and tube stub to header welds. Steam piping
flexibility can cause excessive loads to be transmitted
to the header outlet nozzle. These stresses result in
externally initiated cracks at the outlet nozzle to
header saddle weld.
Condition assessment of high temperature headers
should include a combination of NDE techniques that
are targeted at the welds where cracks are most likely
to develop. Creep of the header causes it to swell; the
diameter should be measured at several locations on
the header and the outlet nozzle. All major header
welds, including the outlet nozzle, torque plates, support lugs, support plates and circumferential girth
welds, should be examined by MT or PT. A percentage of the stub to header welds should be examined
by PT. Each section of the header should be examined
by eddy current or acid etching to locate the seam if it
is not readily apparent. The seam weld is examined
for surface indications by MT or PT, and ultrasonic
shear wave testing is performed to locate subsurface
flaws. To examine the header for creep damage, metallographic replication is performed. The last test that
should be performed on any high temperature header
is internal examination of at least two tube bore holes.
45-8
This test is considered the most effective. Ideally, the
evaluation should correspond to the hottest location
along the header.
Low temperature The low temperature headers are
those operating at temperatures below which creep is
a consideration. These include waterwall headers,
economizer inlet and outlet headers, and superheater
inlet and intermediate headers. Any damage to the
low temperature headers is generally caused by corrosion or erosion.
Waterwall headers, found in most electric utility
and industrial power generation boilers, are generally
located outside the hostile environment of the combus-
Fig. 10 Large ligament cracks on header ID.
Steam 41 / Condition Assessment
The Babcock & Wilcox Company
tion zone. One exception is the economizer inlet
header; this may be in the gas stream and is subject
to unique problems associated with cycling. Boilers
that are held overnight in a hot standby condition
without firing can experience severe damage to the
economizer inlet header in a very short time. This
damage is typically caused by thermal shock.
The magnitude of the thermal shock is a function
of the temperature differential between the feedwater
and the inlet header. It is also a function of water flow,
which is usually large because the feedwater piping/
valve train is sized for rated boiler capacity. The thermal shock is worst near the header feedwater inlet and
rapidly decreases as flow passes into the header and
tubes. The primary concern with other low temperature headers is internal and external corrosion during out of service periods. Lower waterwall headers
on stoker-fired boilers that burn coal or refuse may
experience erosion along the side walls adjacent to the
stoker grates.
Attemperators
The attemperator, or desuperheater, is located in
the piping of the superheater and is used for steam
temperature control. (See Chapter 19.) The spray attemperator is the most common type used. (See Fig.
11.) In the spray unit, high quality water is sprayed
directly into the superheated steam flow where it vaporizes to cool the steam. The attemperator is typically located in the piping between the primary superheater outlet header and the secondary superheater inlet header. Steam exiting the primary header
at temperatures of 800 to 900F (427 to 482C) enters
the attemperator, where relatively cool water [approximately 300F (149C)] is sprayed into the steam and reduces the temperature to the inlet of the secondary
superheater. Because of the large temperature difference between the steam and spray water, parts of the
attemperator experience thermal shock each time it
is used. Over a period of years this can lead to thermal fatigue and eventual failure (Fig. 12).
Condition assessment of the attemperator requires
removal of the spray nozzle assembly. The thermal
stresses occurring in the attemperator are most damaging at welds, which act as stress concentrators. The
spray head and welds on the nozzle assembly are examined visually and by PT to ensure there are no
cracks. With the spray head removed, the liner can
be examined with a video or fiber optic probe. For
larger attemperators, it may be necessary to remove
Fig. 11 Typical attemperator assembly.
Steam 41 / Condition Assessment
Fig. 12 Failed attemperator spray head.
radiograph plugs before and after the attemperator
to better view the critical liner welds.
High temperature piping
Damage mechanisms Damage to high temperature
piping systems operating at more than 800F (427C)
arises from creep, cycle fatigue, creep fatigue, and
erosion-corrosion.
Most modern high temperature piping systems are
designed for temperatures ranging from 950 to 1050F
(510 to 566C), or higher. The American Society of Mechanical Engineers (ASME) allowable material
stresses at these temperatures may produce creep
rupture in approximately 30 to 40 years. Systems
designed from 1950 through 1965, that used 1-1/4 Cr1/2 Mo alloy steel, may be underdesigned by today’s
standards because the ASME Code has evolved, lowering the allowable high temperature stress for this
material.
Fatigue damage to a piping system is caused by
repeated cyclic loading, which can be the result of
mechanical loads, thermal expansion and contraction,
and vibration. Most piping systems are designed with
some degree of fatigue resistance. This built-in flexibility comes from hangers and supports.
Creep and fatigue can occur together and interact
to cause more damage than each mechanism by itself;
it is not fully understood which mechanism is the primary cause. This combination of conditions is by far
the most prominent because most power piping systems are highly dynamic.
Erosion-corrosion is not as prominent as the creep
fatigue failure mechanisms. It is defined as wall thinning that is flow induced and occurs on the fluid side
of the piping system. Factors that contribute to erosion-corrosion include bulk fluid velocity, material
composition and fluid percent moisture.
Overall evaluation program When evaluating high
temperature piping, condition assessment is usually
necessary if the following conditions exist: piping operates above 1000F (538C); was manufactured of
SA335-P11 or P22 material, or manufactured of long
seam welded material; has had hanger problems; was
manufactured with specific weld joint types; has a
history of steam leaks; or operates above design conditions. Once a priority list is developed, the evalua45-9
The Babcock & Wilcox Company
tion can begin. This evaluation program should be as
complete as economically possible.
Detailed evaluation program
Phase I To determine where physical testing is required, the following preliminary steps are part of a
Phase I evaluation: plant personnel interviews, plant
history review, walkdowns, stress analysis, and life
fraction analysis.
Plant personnel interviews are conducted to gather
information that is not readily available from plant
records. Significant history may only be found in recollections of experienced personnel.
Operating history reviews complement personnel
interviews. They can provide problem histories and
design or operating solutions.
Piping system walkdowns serve three major functions: to evaluate pipe supports and hangers, to find
major bending or warpage, and to verify changes.
Pipe hangers and supports should be carefully examined. This can be done by creating a baseline inspection record of all supports.
While the data are being taken on the piping
walkdown, the general appearance should also be
noted. In particular, inspections may reveal the following damages: necked-down rods or yokes, spring
coil fractures, deterioration of the hanger can, and
deterioration of tiebacks into building steel.
Many times a walkdown reveals that a modification
was performed. If the entire system was not reviewed
during the modification, other problems may result.
Stress analysis of the piping system can now be
performed. Typically, a computer program is used to
perform the stress calculations based on design and
any abnormal conditions found during the walkdown.
Once a piping system is modeled, the analysis allows
the engineer to pinpoint high stress locations. The
objective is to limit the nondestructive examination
work to these high stress areas.
Life fraction analysis (LFA) of a pipe is done if the
primary failure mode is creep due to operating temperatures above 900F (482C). The LFA is based on the
unit’s operating history and stress levels are calculated using design conditions and minimum wall
thicknesses. This analysis is discussed at length later.
Phase II Phase II of the evaluation includes all
physical testing of the piping system. The majority of
the testing should be nondestructive; however, some
destructive testing may be required. The results from
Phase I testing provide test location priority. Specific
test recommendations are shown in Table 1.
The test data generated from the inspections must
be evaluated to determine the remaining component
life. This is known as the Phase III evaluation and is
covered under Analysis techniques.
Typical failures The most typical steam pipe failure is cracking of attachment welds (support welds or
shear lugs). These cracks are caused by thermal fatigue, improper support, or improper welding.
Radiograph plugs often have cracked seal welds.
Although the plug threads are the pressure bearing
surfaces, they can become disengaged over time due
to corrosion, creep swelling or oxidation.
Steam pipe warping is another serious problem. If
45-10
Table 1
Typical Piping System Tests
Test Area
Circumferential welds
Longitudinal welds
Wye blocks
Hanger shear lugs
Hanger bracket and
supports
Branch connections
RT plugs
Misc. taps and drains
Elbows/bend
A
B
C
D
E
-
Test Type
Optional*
A, B, D, E, F, G, H
A, B, D, E, F, G, H
A, B, E, F, G, H
A, B
C, I, J
C, I, J
C, D, I, J
C, F, G, J
A, B
A, B, D, E, F, G, H
A, B
A, B
A, E, F
C, F, G, J
C, I, J
C, F, G, I
C, I
B, C, G
Visual
Magnetic particle
Liquid penetrant
Ultrasonic shear
Ultrasonic thickness
F
G
H
I
J
-
Replication
Material ID
Dimensional
Radiography
Metallography
* Optional tests should be used to gather more detailed
information.
the pipe has deformed, it has undoubtedly gone
through a severe thermal shock. The high strain between the upper and lower sections of pipe can cause
permanent deformation.
Two final common failure areas are the boiler outlet
headers and turbine stop (throttle) valves. These areas
should always be considered in any piping evaluation.
Low temperature piping
Low temperature piping operating at less than 800F
(427C) is not damaged by creep. These systems typically fail due to fatigue, erosion or corrosion. The
evaluation methods are the same as those for high
temperature piping; however, a finite life is not predicted. Low temperature pipes, if maintained, last
much longer than their high temperature counterparts. Typical systems are reheat inlet steam lines,
extraction lines, feedwater lines and general service
water lines.
Typical failures Many high temperature failure
modes occur in low temperature pipes. Cold reheat
lines experience thermal shock because the reheat
temperature control is typically an in-line attemperator. The attemperator spray can shock the line if the
liner is damaged or the nozzle is broken. Economizer
discharge lines that run from the economizer outlet
header to the boiler drum can be damaged during
startup sequences. If the economizer is steaming and
flow is initiated as a water slug, the line can experience severe shocks. This can cause line distortion and
cracking at the end connections and support brackets. Other low temperature piping can be damaged by
oxygen pitting caused by inadequate water treatment.
Erosion due to flow cavitation around intrusion points
can cause severe wall thinning. If solid particles are
entrained in the fluid, erosion of pipe elbows results.
General corrosion of the inside pipe surface can be caused
by extended outage periods. Proper line draining is recommended unless protective materials are in place.
Steam 41 / Condition Assessment
The Babcock & Wilcox Company
Tubular air heaters
Tubular air heaters are large heat exchangers that
transfer heat from the boiler flue gas to the incoming
combustion air, as discussed in Chapter 20. On large
utility boilers, tubular air heaters can contain up to
90,000 tubes with lengths of 50 ft (15.2 m) each. These
2 in. (50.8 mm) OD tubes are densely grouped with
spacings of 3 to 6 in. (76.2 to 152.4 mm) centers in two
directions. Flue gas flow direction is typically opposite that of the combustion air to maximize thermal
efficiency. Unfortunately, this promotes corrosion on
the gas side cold end.
Condensate formation promotes acid corrosion from
the flue gas which causes wall thinning. If left unchecked for several years the tubes eventually corrode
through, causing air leakage from the air to gas side.
Because access to air heater tubes is limited, eddy
current and acoustic technologies are used to test for
blockage, holes and wall thinning. Eddy current technology is used to measure wall thicknesses of thin
[< 0.065 in. (< 1.65 mm)] nonferrous heat exchanger
tubing. Holes and partial and complete blockage are
located using acoustic technology. When an audible
sound is introduced into a tube it travels the length of
the tube and exits the open end. If a hole exists in the
tube, however, it changes the signal pitch in the same
manner as a flutist changes a note pitch. In a like
manner, partial or total tube blockage yields a pitch
change. B&W uses The Acoustic Ranger inspection
probe for this test. (See Fig. 13.)
The structural members of the boiler must be reviewed during a condition assessment inspection.
Normally these members, along with the support rods
above the boiler and auxiliaries, last the life of the
boiler. However, because nonuniform expansion can
lead to boiler load movement, the support system
should be examined during the boiler outage inspections. Particular attention should be given to header
and drum supports that could be damaged if the vessel is distorted.
Analysis techniques
Once the testing is complete and the data are compiled, the next step in condition assessment is to decide whether to repair, replace or re-inspect certain
components. For high temperature components with
finite lives, this decision is aided by computers that
predict failures by modeling analyses.
Component end of life is defined as the point at
which failures occur frequently, the costs of inspection
and repair exceed replacement cost, or personnel are
at risk. Therefore, remaining life can be considered
as the interval between the present time (tp) with accumulated damage and the time at end of life (te). This
can be written as:
R.L. = te − tp
For waterwall tubing that is eroding at a linear rate,
the remaining life is as follows:
Boiler settings
The boiler components that are not part of the
steam-water pressure boundary are general maintenance items that do not have a significant impact on
remaining life of the unit. The nonpressure components include the penthouse, boiler casing, brickwork
and refractories, and flues and ducts. Deterioration
of these components results from mechanical and thermal fatigue, overheat, erosion and corrosion. In all
cases, condition assessment is done by performing a
detailed visual inspection. For flues, ducts and casing,
it is of value to inspect the in-service boiler to detect
hot spots, air leaks and flue gas leaks that can indicate a failed seal.
Fig. 13 Acoustic Ranger ® schematic.
Steam 41 / Condition Assessment
(1)
R.L. =
(tc − tr )
e.r.
(2)
where
R.L.
tc
tr
e.r.
=
=
=
=
remaining life
current wall thickness, in. (mm)
preset replacement wall thickness, in. (mm)
erosion rate, in./yr (mm/yr)
Remaining life of headers is calculated using modeling software due to the complexity of crack growth.
Steam-cooled tubes
Steam-carrying superheater and reheater tubes
operating at temperatures above 900F (482C) are
subject to failure by creep rupture. The creep life of a
tube can be estimated from tabulated data, provided
the applied (hoop) stress and the operating temperature are known.
When a tube is put in service, the metal contacting
the steam begins to form a layer of oxide scale known
as magnetite (Fe3O4). As the life progresses, the ID
oxide layer grows at a rate that is dependent on temperature. This scale acts as a heat transfer barrier and
causes an increase in the tube metal temperature as
discussed in Chapter 4. The metal temperature, therefore, also gradually increases with time.
Internal oxide thickness measurements are necessary for estimating a tube’s operating temperature and
remaining creep life as well as for assessing the overall condition of the superheater. In the past, these
45-11
The Babcock & Wilcox Company
measurements have been obtained by removing tube
samples for laboratory examination. To avoid destructive tests, B&W developed the NOTIS NDE technique
discussed earlier.
Life prediction methodology The prediction of tube
creep life begins with creep rupture data taken in
short-term laboratory studies. Creep specimens, similar to cylindrical tensile specimens, are machined from
various tube steels. Each specimen is heated to a temperature (T ) and is pulled uniaxially at a stress (S )
until failure occurs; at this point, a time to failure (t)
is measured. A matrix of stress and temperature values has been tested.
The Larson-Miller parameter (LMP) is a function
relating T, S, and t. This parameter is defined as:
LMP = (T + 460 ) ( 20 + log t )
where
T = constant temperature applied to the creep
specimen, F
t = time at temperature T, h
Every tube in service has an associated LMP number that increases with time. These LMP data can be
related to stress, as is illustrated in Fig. 14. This relationship between stress and LMP can then be used to
predict a time to creep rupture for a superheater or
reheater tube. Knowing two of the three factors affecting creep rupture, i.e., hours in service and hoop stress,
the third factor, temperature history, can be estimated.
There are numerous mathematical models relating
steam-side oxide thickness, time, and mean metal temperature for low chromium-molybdenum alloys. The
following relationship is most widely used to calculate
oxide thickness (x) in mils:
log x = 0.00022 (T + 460 ) ( 20 + log t ) − 7.25
From the LMP equation, the expected time to failure (tf ) can be calculated:
LMP = (T + 460 ) ( 20 + log tf )
tf = 150, 000 h
(5)
If this tube has operated for 100,000 hours at these
parameters, the creep life fraction expended is:
fexpended = t / tf =
100, 000
= 0.6667
150, 000
(6)
The creep life fraction remaining is:
fremaining = 1 − texpended = 1 − 0.6667 = 0.3334
tremaining
= fremaining × tf
tremaining
= 0.3334 × 150, 000
tremaining
= 50, 000 h
(7)
Example – Part II
Assume that, after operating at 1050F (566C) for
100,000 hours, tube temperature increases to 1065F
(574C).
Using the same effective LMP, the LMP equation
is used to calculate tf at 1065F (574C) as follows:
LMP = (T + 460 ) ( 20 + log tf )
tf = 85, 000 h
(8)
Therefore, a new tube operating at 1065F would
have an expected life of 85,000 hours. However, from
Part I, this tube has used up two-thirds of its life at
1050F and has a remaining life fraction of 0.33.
(3)
Although this formula works well with 1-1/4 Cr-Mo
alloys, it must be modified for use with higher chromium alloys and carbon steels.
Creep life fraction analysis The life fraction is defined as the ratio of the time a tube withstands a given
stress and temperature (t) to the time for creep rupture conditions (tf).
Robinson’s Rule of life fractions states that if the
applied stress and temperature conditions are varied,
the sum of the life fractions (or damage) associated
with each set of conditions equals 1 at failure. It may
also be written as follows:
(t / t )
f
1
+ (t / tf ) 2 + … + (t / tf ) n = 1
(4)
where subscripts 1 through n indicate unique stress
temperature conditions.
Example – Part I
Assume a tube operates at a hoop stress of 5 ksi
(34,474 kPa) and a temperature of 1050F (566C). What
is the predicted time to failure? Using these parameters and the stress-LMP curve presented in Fig. 14,
the effective LMP at failure is 38,015.
45-12
Fig. 14 Stress versus Larsen-Miller parameter (LMP).
Steam 41 / Condition Assessment
The Babcock & Wilcox Company
Robinson’s Rule can be applied to determine the
higher temperature service life after the tube is exposed to 100,000 hours at 1050F.
Recall Robinson’s Rule – the sum of the life fractions is equal to 1:
(t / t )
f
1050
+ (t / tf ) 1065 = 1
100, 000 / 150, 000 + t / 85, 000 = 1
t = 28, 000 h
(9)
Note that in this example, the total tube life would
be 100,000 + 28,000, or 128,000 hours.
Analysis procedure The following analysis procedure
is used with tube wall oxide thickness measurements
from the NOTIS system.
1. The life of the tube, past and future, is broken into
time intervals, each of length t:
An oxide growth rate is determined knowing the
present oxide thickness and the time in service and
assuming the initial oxide thickness was zero.
Once a mathematical function describing oxide
thickness with respect to time and temperature
is defined, the thickness in each analysis interval
can be calculated. The tube metal temperature in
each interval, taking into account the insulating
property of the oxide, is also calculated.
A linear wall thinning rate is determined for the
tube, knowing the present wall thickness as measured by NOTIS, the original wall thickness, and
the service time of the tube. Once a function describing wall thickness with respect to time is
defined, the wall thickness in each analysis interval can be calculated. The hoop stress is calculated
using the ASME Boiler Code Section I tube formula in each interval.
2. The creep life fraction used up in each interval is
determined:
Given the stress, the LMP value may be found
from the creep rupture database. Given the operating temperature and the LMP, the time a new tube
would last at these conditions (tf) is determined. The
interval creep life fraction used up is then t/ tf.
3. Because the life fractions, summed over the analysis intervals, are equal to 1, the remaining life is
obtained by subtracting the tube service time from
this total life.
Accuracy of creep life prediction analysis Life fraction
analysis is the most accurate and widely accepted
method for estimating tube life. Although this method
is straightforward and well documented, it is not precise.
Result inaccuracies are due to inherent material
property variations. Additionally, during service, short
excursions to higher temperatures lower the remaining life fraction.
Rather than attempting to determine the precise
time of a creep rupture, the evaluation places each
tube into a band of expected remaining lives. These
bands take into account the shortcomings of the life
fraction analysis, as well as the inaccuracy of the operating parameters for the unit being assessed. In
effect, these bands are confidence limits.
Steam 41 / Condition Assessment
Capabilities and limitations At elevated temperatures,
the external and internal surfaces of boiler tubes
slowly oxidize. The external scale is normally removed,
whereas the internal scale usually remains intact.
Typically, the multilaminated scale that is formed on
the inner surface is characterized by an iron-rich inner layer and an oxygen-rich outer layer. The latter
generally contains a large number of pores or voids.
The ultrasonic response with the NOTIS system from
the inner/outer layer interface is small compared to
the signals associated with the metal/oxide and oxide/
air interfaces. Therefore, a tightly adhering porous
oxide does not affect the accuracy of the NOTIS system. However, if the two oxide layers become disbanded due to exfoliation processes, the NOTIS operator may only measure the oxide thickness to the
disbanded area and therefore indicate that the oxide
is exfoliating. Exfoliation is the flaking of scale particles off of the internal oxide layer.
Water-cooled tubes
Water-carrying tubes operate at or below saturation temperature and are not subject to creep damage. Therefore, these tubes have no defined design life
as do high temperature components. However, erosion,
corrosion, thermal expansion and mechanical stresses
act on water carrying tubes. This limits useful practical life.
Outside tube wall thinning Erosion and corrosion
are the most common causes of OD wall thinning. Erosion typically occurs on the tube outside diameter in
the form of wall thickness loss. A tube’s wall thickness
is designed to the ASME Boiler and Pressure Vessel
Code to withstand a given pressure, temperature, and
mechanical load. An example is as follows:
Given: Design pressure (P)
Design temperature (T)
Tube outside diameter (OD)
Tube material
=
=
=
=
2400 psi (16.5 MPa)
700F (371C)
3 in. (76.2 mm)
SA210 A1
From the ASME Code the wall thickness formula is:
t =
PD
+ 0.005 D
2S + P
(10)
where
t
P
D
S
=
=
=
=
minimum wall thickness
design pressure
outside diameter
allowable stress
By knowing the material and temperature, the allowable stress can be found in the ASME Code. In this
case, the allowable stress is 14,400 psi (99,285 kPa).
Solving the equation gives t = 0.245 in. (6.22 mm).
In the case of industrial and utility boilers, the next
higher standard tube thickness would be supplied. In
the case of a chemical recovery boiler used in the pulp
and paper industry a much higher thickness would
be used. This allows for wall thickness reduction when
operated in a reducing atmosphere. (See Chapter 28.)
As a guide, the following are B&W recommendations for utility and industrial boiler tubes:
45-13
The Babcock & Wilcox Company
1. Water-cooled tubes should be repaired to original
wall thickness or replaced if reduced to 70% of
original.
2. Steam-cooled tubes should be repaired to original
wall thickness or replaced if reduced to 85% of
original.
Inside tube wall corrosion Internal corrosion due to
hydrogen damage, caustic gouging and under-deposit
corrosion is more difficult to evaluate for remaining
life because it is not easily quantified.
In addition to wall thickness, other factors, such as
the effect of water quality, microstructure and damaged area size, must also be considered. Internal corrosion data can be mapped similarly to that for ultrasonic wall thickness.
Internal deposits Internal deposits lead to tube failures and provide initiation sites for hydrogen damage
and under-deposit corrosion as discussed in Chapter
42. The type of corrosion depends upon the nature of
the deposit (dense or porous) and the composition of
the chemicals beneath the deposit. Chemical cleaning
of the boiler removes these deposits. The cleaning frequency depends on the type of unit, operating pressure, fuel, and water treatment program. The hours
of operation and data from tube samples also determine the cleaning frequency.
Tube samples should be taken from locations with
the heaviest deposits which are usually located in the
high heat input burner zone areas of the furnace.
The final step is the development of results from
Steps 1 and 2. These results are the remaining life or
crack growth curves that are presented two ways. The
first is a plot of crack versus time. This curve is exponential because the crack grows faster as it becomes
larger. The second curve is the inverse of the first,
plotting size versus remaining life. Remaining life is
based on a critical predetermined through-wall crack
size. Once the crack reaches this value, the remaining life is zero. From the previous equation, this can
be written:
R.L. =
∫
ac
ai
da
bC tm
(12)
where ac is the critical crack depth and ai is the initial
crack depth.
Leak before break analysis (LBBA) When evaluating cracks that are growing at a stable rate, even
though they are through-wall, a condition occurs
where fluid leaks through the crack but does not cause
Step 1
Headers and piping
High temperature headers and piping typically fail
due to creep, fatigue, or a combination of the two. Although a header is more complex in geometry, it is
essentially a pipe with tubes welded to it. Therefore,
many of the remaining life analyses are similar to
those for tubes. However, it must be noted that the
root cause of damage can be different in headers.
On thick walled sections, where thermal and stress
gradients can occur, remaining life is based on crack
initiation and propagation. Calculational methods,
statistics, dimensional measurements, metallographic
methods, and post service creep rupture testing are
considered mainly with crack initiation and the events
preceding it. When dealing with thick sections, these
analytical techniques must be followed by crack
growth analyses. Once a component is cracked, the
pre-crack evaluation methods do not apply.
Crack growth analysis (CGA) There are three steps
used in predicting crack propagation based on time dependent fracture mechanics. (See also Chapter 8.) The
schematic shown in Fig. 15 illustrates the various steps.
Step 1 consists of identifying the creep growth and
deformation behavior of the material. Step 2 consists
of the expressions for the crack tip driving force for
creep, Ct. The basic expression for Ct is:
da
= bC m
t
dt
(11)
where a is crack depth, t is time, and both b and m
are material constants.
45-14
Crack Growth
Specimens
Log
da
dt
Creep
Specimen
Log
da
=bC mt
dt
Log Ct
Crack Growth Behavior
=A
n
Log
Creep Deformation Behavior
Step 2
Step 3
Ct = f(
Cracked
Component
, A, n, a, t)
Life
ai = Initial
Crack Size
ai
Residual Life
Curve
Fig. 15 Three-step methodology for crack growth analysis.
Steam 41 / Condition Assessment
The Babcock & Wilcox Company
a catastrophic rupture. If the flaw is characterized by
depth a and length 2C, then the following expression
applies to leak before break:
R.L. =
∫
ac
ai
da
=
bC tm
∫
Ccr
Ci
dc
bC m
t
(13)
where Ccr and Ci are the critical crack and initial crack
half lengths respectively. Because all variables except
C i are known or determined, the equation can be
solved for Ci. B&W has developed a software code,
Failure Analysis Diagram (PCFAD), that models
many crack scenarios encountered in header and piping systems. The failure assessment procedure uses
a safety/failure plane diagram. The plane is defined
by the stress intensity factor/fracture toughness ratio
( K′r) as the ordinate and the applied stress/net section
plastic collapse stress ratio ( S′r ) as the abscissa. If an
assessment point lies within the curve (Fig. 16), the
structure is safe. The distance from a point to the curve
indicates the margin of safety. Chapter 8 provides
further discussion. These two approaches allow the
engineer to determine 1) how long a flaw will take to
reach a predetermined critical size (crack growth, PC
CREEP), and 2) whether the flaw will cause a leak or
catastrophic failure.
Life fraction analysis Life fraction analyses (LFA)
are performed on piping at temperatures above 900F
(482C) in which the primary failure mode is creep.
Stress levels are calculated using design conditions.
To determine the minimum creep rupture life, published creep rupture data (LMP) are used. The calculation is similar to that for steam-cooled tubes, however piping is not influenced by gas stream heat flux
and, therefore, operates at a fairly consistent temperature. The life fraction expended (LFE) is expressed as:
LFE =
t
tm
(14)
By using Minor’s sum, an expression can be created
to represent the unit’s history of operating at different conditions:
LFE =
∑
z
i =1
ti
tmi
(15)
where
z
i
ti
tmi
=
=
=
=
number of different conditions
ith temperature and stress level
time of operation at given conditions
minimum time to creep rupture (LMP)
When considering only creep rupture stress, a long
remaining life results. However, most piping systems
are also subjected to fatigue stress. Fatigue damage
can be calculated by using standard fatigue curves.
By combining the creep rupture and fatigue components, the expression becomes:
LFE =
∑
z
i =1
ti
+
tmi
Steam 41 / Condition Assessment
∑
x
j =1
cj
Cj
(16)
Fig. 16 Sample PCFAD® failure plant diagram.
where
x
j
cj
Cj
=
=
=
=
number of different stress modes
jth stress level
number of cycles at stress level
number of cycles to failure at stress level
This simple approach requires detailed operating
history. In addition, it only provides a gross estimate
of expected life.
Stress calculation The calculation of stresses for
headers is complex because of tube stub geometry, tube
bank loading, differential tube temperatures, and
piping stresses on the outlet nozzle. Using specially
developed software codes, it is possible to perform a finite element analysis for the entire header. B&W has
performed finite element analysis on the tube stub ligament region and found that this area contains very high
stresses, especially during temperature transients.
The total stress (St) applied to the flaw is equal to
the sum of the primary stresses (axial or hoop) (Sp),
bending stresses (Sb) and pressure stresses on the
crack face (Sc):
St = S p + Sb + Sc
(17)
The primary stress is determined by the orientation of the flaw. If the flaw is located axially along the
length of the component, then the hoop stress is primary. If it is located circumferentially, then the axial
stress is primary. Bending stresses are caused by dead
loads, hanger spacing, thermal differentials and restraints. The pressure stresses applied to the crack face
are only considered when the crack is open to the pressure. When this is the case, the applied stress is equal
to the internal pressure.
BLESS Code analysis BLESS is an acronym for
Boiler Life Evaluation and Simulation System. The
complete BLESS code considers crack initiation and
growth in headers as well as crack growth in pipes.
The BLESS Code can also perform leak before break
analysis (LBBA) of axial cracks in pipes. The Code was
developed for EPRI by B&W as a subcontractor to
General Atomics. The BLESS Code was derived from
B&W’s previous software codes for failure analysis
45-15
The Babcock & Wilcox Company
(PCFAD) and crack growth analysis (PC CREEP).
Because stress calculations in headers and piping require difficult finite analysis due to complex geometries, simplifying assumptions were made in the development of the BLESS Code to allow for analysis.
The BLESS Code greatly facilitates the life assessment of elevated temperature headers and piping by
eliminating the need for finite element thermal and
stress analysis and utilizing developments in nonlinear creep-fatigue crack growth. The evaluation includes both crack initiation and crack growth. The
Code permits the evaluation of the effects of extremely
detailed thermal and mechanical load histories on
headers with very complicated geometric details. The
estimated remaining life is calculated by BLESS either as a single value (when re-run in the deterministic mode) or a statistical distribution. This distribution is obtained when BLESS is run in the probabilistic mode and defines the probability of failure as a
function of time. Such information can be useful in
making run/repair/replace and re-inspection decisions
for aging or cracked headers and piping.
Flaw characterization Flaws found in headers and
piping must be characterized prior to crack growth,
LBBA, or BLESS analysis. This characterization involves accurately determining the flaw’s length and
depth. Through-wall depth is considered the most critical. The most common characterization methods include
standard NDE techniques such as MT, PT, RT and UT.
Destructive samples
Destructive sampling is frequently done when data
from nondestructive evaluations are inconclusive.
Material properties, damage and deposits can be
quantified. Tube samples and boat samples are discussed earlier under Destructive examinations.
Leak detection
Leaks in boilers, piping and feedwater heaters are
major contributors to power plant unavailability and
performance losses. In their early stages, leaks are
often undetected because they are inaudible and/or
concealed by insulation.
In the early 1980s, acoustic monitoring equipment
began to be used for leak detection. By using a piezo-
electric pressure transducer to detect acoustic energy
emitted by a leak, the detection of smaller leaks became possible. Leak noise is transmitted by air and by
the structure. Boiler tube leaks are best detected
through an airborne sensor because of the large boiler
structure volume. Feedwater heaters, headers and
piping leaks are best detected through a structural
sensor. Because these components are small and selfcontained, direct contact monitoring is used.
Leak noise is caused by a fluctuating pressure field
associated with turbulence in the fluid. Turbulence is
a condition of flow instability in which the inertial
effects are highly dominant over the viscous drag effects. Once turbulence is established, the acoustic
energy radiated from a leak increases strongly with
pressure and flow rates.
Acoustic leak detection technology has been demonstrated through laboratory work, field testing and
operational experience. The sensitivity of the sensor
depends on three factors: sound radiated from the
leak, attenuation of sound between the leak and the
sensor, and background noise. Leak noise occurs in a
broad band, ranging from below 1 kHz to above 20 kHz.
Because of the low frequency background noise and
the greater attenuation of high frequencies, most airborne systems operate in the range of 1 to 25 kHz. This
is important because the acoustical signal diminishes
in amplitude as it travels away from the source. Therefore, in designing a system, there is a tradeoff between
sensor spacing and minimum detectable leak.
Table 2 shows typical leak monitor signals for boiler
tubes, feedwater heaters, steam piping, and crack
detection acoustic emissions.7
Boiler leak detection The background noise in a
boiler is primarily due to combustion in the furnace.
Direct measurement of background noise is needed to
determine the spectral characteristics. In addition, the
background noise level must be stable. The magnitudes of background noise from different parts of the
boiler are similar; a large component is due to sootblower operation.
Using background noise and leak characterization
data, full scale tests have been run to optimize sensor
listening distances, sensor orientation, and signal processing equipment. A typical 500 MW utility boiler can
Table 2
Typical Acoustic Monitoring Signals8
Boiler Tubes
Acoustic path
Detection band
Background noise
frequency
Background noise
amplitude*
Total system gain
Number of sensors
Leak Detection
Feedwater Heaters
Steam Lines
Crack Detection
Steam Lines/Headers
Gasborne
0.5 to 25 kHz
Waterborne
5 to 25 kHz
Metalborne
100 to 400 kHz
Metalborne
200 to 500 kHz
Metalborne
100 to 500 kHz
Below 2 kHz
Below 8 kHz
Below 125 kHz
Below 200 kHz
Below 200 kHz
20 to 30 dB
60 dB
12 to 18
40 to 60 dB
50 to 60 dB
1 to 2 per heater
30 to 50 dB
40 to 60 dB
1 per heater
40 to 60 dB
40 dB
Every 20 ft
(6.1 m)
40 to 60 dB
60 to 80 dB
Every 10 to 20 ft
(3 to 6.1 m)
* Reference 1 µbar
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The Babcock & Wilcox Company
be monitored using 16 to 24 sensor channels. Fig. 17
shows a typical airborne sensor and waveguide arrangement.
Waveguides are installed through the boiler enclosure at various locations. A typical sensor has a detection range of approximately 50 ft (15.2 m).
Header and piping leak detection Headers and piping are monitored with structural sensors similar to
those of feedwater heaters. The sensors are placed
approximately 15 to 20 ft (4.6 to 6.1 m) apart.
These sensors can also be used to detect crack
growth. When a crack grows, it emits acoustic energy
that can be detected. The processing of crack growth
signals from leak detection sensors requires different,
more powerful computing hardware than the systems
required for leak detection. With structural leak detection sensors installed, and the proper fitting and
signal processing hardware, periodic monitoring for
crack growth can be performed.
Cycling effects and solutions
In assessing a boiler’s ability to withstand cycling,
those components most vulnerable to cycling are reviewed first. These components are discussed from two
standpoints: the operating methods which minimize
cyclic damage, and design modifications which permit
the component to better withstand cycling conditions.
Cycle definition
Two types of cycling service are usually considered:
load cycling and on/off cycling. The on/off type has also
been called two shifting.
A cycle is considered to start at full load, full temperature steady-state conditions. It goes through a
load change, then returns to the initial conditions. A
typical load cycle is then composed of three phases:
1) load reduction,
2) low load operation, and
3) reloading.
A typical on/off cycle has four phases:
1) load reduction,
2) idle,
3) restart, and
4) reload.
The phase that is often ignored, the idle period, can offer the greatest potential for reducing cyclic damage.
Economizer thermal shock
On boilers that are on/off cycled, economizers often
show more cyclic damage than the other components.
The economizer receives water from the extraction feedwater heater system, and the inner metal surfaces follow the feedwater temperature with practically no time
delay. As a result, high rates of metal temperature
change can occur with resultingly high local stresses.
Fig. 18 shows economizer inlet temperatures during an overnight shutdown cycle. The first two hours
are for load reduction, followed by eight hours of idle
or banked condition. Next, the boiler is fired in preparation for restart. The rates of temperature change
Steam 41 / Condition Assessment
Fig. 17 Typical airborne noise sensors.
during the load decrease and increase are usually not
excessive, but would represent load cycling conditions
for the economizer.
During the banked period, there is some air leakage through the boiler with a resulting decay in boiler
pressure. As this happens, the drum water level decreases. At the same time, the leaking air passing
through the boiler is heated to near saturation temperature, and that air then heats the economizer. An
economizer metal temperature can increase at 30 to
50F/h (17 to 28C/h) during this period and can approach saturation temperatures. When the drum level
drops, the operator usually refills the boiler so that it
is ready for firing. Because there is no extraction steam
available, the feedwater temperature is low. This slug
of cold water quickly chills the economizer, causing thermal shock as indicated by the solid lines in Fig. 18. The
inlet header and tubes receive the greatest shock.
When the boiler is fired in preparation for turbine
restart, rollup, and synchronization, the economizer
heats up rapidly, often nearing saturation temperature. Feedwater is started when the initial load is
applied to the turbine. Because little extraction heating is available, feedwater temperature is low. A severe shock occurs at this point, as the temperature can
increase 300F (167C) in a few minutes.
Typically, early damage consists of cracks initiating in the tube holes of the inlet header which are closest to the feedwater inlet connection (Fig. 19).
Other damage has also been seen from this cyclic
service. Outlet headers have shown damage similar
to inlet headers. Furthermore, some tube bank support systems can not accommodate the high temperature differences between rows.
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The Babcock & Wilcox Company
A second method of reducing thermal shock is to
permit the economizer to reheat during the idle period and then to provide higher temperature feedwater
for restart. This can occur by pressurizing a high pressure heater with steam from an auxiliary source or
from the drum of the unit. The quantity of steam required is low because it only heats the initial low flow
of feedwater.
Fig. 18 Economizer temperatures during overnight shutdown cycles.
Solutions are available to reduce the frequency and
magnitude of thermal shocks. These have taken two forms
and address the out of service and restart conditions.
The first solution is called trickle feed cooling. Very
small quantities of feedwater are frequently introduced during the shutdown and restart periods. This
prevents the inlet header from reheating and reduces
the cooling rate during feedwater introduction. Because feedwater introduction is controlled to limit
economizer temperature rise, some drum blowdown
may be necessary to prevent a high water level.
Fig. 19 Cracking in economizer inlet header occurs first in bore
holes nearest water inlet.
45-18
Furnace subcooling
Several drum boilers that have been subjected to
on/off cycling have developed multiple cracks in lower
furnace wall tubes where the tubes are restrained from
diameter expansion or contraction. Typical cracking
areas have been at the lower windbox attachment where
filler bars or plates are welded to the tubes (Fig. 20).
Investigation of these failures indicated that, during the shutdown or idle period, relatively cold (cooled
below saturation temperature) water settled in the
lowest circuits of the furnace bottom. When circulation was started by initial firing or the circulating
pump, the cold water interface moved upward through
the walls, rapidly cooling the tubes. As the interface
moved, its temperature gradient decreased and the
rate of cooling decreased, therefore reducing damage
higher in the furnace. Experience indicates that if the
subcooling can be limited to 100F (56C), there is a low
probability of damage.
An out-of-service circulating pump system may be
used to limit the subcooling (Fig. 21). This is a low
capacity pump that draws from the bottom of the downcomers and discharges water to the drum, therefore
Fig. 20 Lower windbox attachment cracking due to subcooling.
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The Babcock & Wilcox Company
and variable drum pressures, as shown in Fig. 23. In
this example, for constant drum pressure, the maximum differential occurs at 50% load (hour 1) and is:
1000F − 685F = 315F (538C − 363C = 175C)
The minimum difference is at the end of the idle period (hour 10) and is:
655F − 570F = 85F (346C − 299C = 47C)
This is a stress range proportional to:
315F − 85F = 230F (157C − 29C = 128C)
For variable drum pressure, the maximum difference occurs at 35% load and is:
1000F − 540F = 460F (538C − 282C = 256C)
The minimum temperature difference at the end of the
idle period is:
655F − 400F = 255F (346C − 204C = 142C)
producing a stress range proportional to:
460F − 255F = 205F (238C − 124C = 114C)
preventing the stratification temperatures of water
within the unit.
The variable drum pressure mode of operation is then
slightly less severe for the superheater and reheater
outlets and much less severe for the reheater inlet.
In considering operational changes, it should be
noted that the steam temperature characteristics
shown are the maximum available at a given load.
Tube leg flexibility
The enclosure walls of most boilers are water- or
steam-cooled. The water-cooled circuits carry boiling
water, and the steam-cooled circuits carry steam from
the drum. As a result, they operate near the saturation temperature corresponding to the drum pressure.
Whether the boiler is being fired or shut down, considerable heat absorption or loss is necessary to change
the temperature of the walls. As a result, they change
temperature more slowly than the other components.
The economizer, superheater and reheaters penetrate these walls; the penetrations are designed to be
gas-tight. At the point of penetration the expansion
then follows saturation temperature. However, the
header that forms the inlet or outlet of the other circuits expands with the temperature of the steam or
water that it is handling. Fig. 22 shows the motions
of the header end and the outermost connecting leg
for a superheater or reheater outlet. Note that the
greatest deflection is when the header temperature is
at a maximum.
In the case of economizers and the reheater inlet,
the deflection is in the opposite direction because these
headers operate below saturation temperature. For
these components the greatest temperature difference,
and therefore the greatest deflection, is at low loads.
Regardless of the direction, the greatest temperature difference produces the maximum differential
expansion and the maximum bending stresses in the
connecting legs. The stress range and amplitude dictate component fatigue life.
Consider the superheater outlet and the drum (penetration point) temperature differences at constant
Fig. 22 Superheater tube leg flexibility.
Fig. 21 Out-of-service circulating pump system.
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The Babcock & Wilcox Company
differences develop during pressure reduction, when
little or no steam is being taken from the drum.
If drum pressure is rapidly lost during the idle period, top to bottom differentials develop and the drum
humps. Because most drums have two point supports,
the humping is unrestrained and causes little change
in the drum or support stress levels. However, the
drum acts as a stiff beam, and connected parts move
with it (Fig. 24). If those parts do not have sufficient
flexibility they can experience unacceptably high
stresses.
While most recent units were designed with flexibility in the drum connections, there are some older
units where the front furnace wall tubes are routed
directly to the drum and are supported by the drum.
In such cases, it is difficult to add flexibility by rerouting and the humping must be limited.
Fig. 23 Overnight shutdown temperatures.
Lower temperature differences of 50 to 75F (28 to 42C)
may be obtained in practice.
The first indications of cyclic damage are external
cracks on the tube to header welds or the stub to tube
welds of the outermost header legs. This damage is
relatively easy to inspect and repair. Successive damage is also usually limited to closely adjacent legs because they have experienced similar stress levels. Most
sensitive are high temperature headers which are a
short distance from the penetration seal on wide units.
Drums
It is important to limit the rate of saturation temperature change in a steam drum. When operating
in a variable drum pressure mode, considerable
overfiring or underfiring is necessary to quickly
change the drum pressure. These firing effects on
steam temperature control also prevent rapid drum
pressure changes.
Top to bottom drum temperature differences must
also be limited. Only small differences result when
pressure changes are made under load. The greatest
45-20
Developments
Symptoms of advanced creep and fatigue have been
found in some older superheater and reheater outlet
headers. Diametral swelling has been observed. Interior cracking around the header ID tube holes and
along the length has also been present. To better understand the failure mechanism, finite element stress
analyses have been performed. These analyses consider steady-state temperature differences between
individual tubes and the bulk header and transient
temperature changes of both.
Advances in nondestructive examinations
Innovative techniques are being developed to replace or enhance existing NDE methods. Some are
becoming viable due to advancements in microprocessor technology. Others are relatively new and may
replace current methods. Advanced techniques include: 1) infrared scanning,8 2) automated Phased
Array UT, 3) pipe and wall scanners which automatically cover large areas, and 4) through-insulation radiography. EMAT technology is being refined and
studied for further applications in the NDE field.
Fig. 24 Drum humping.
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The Babcock & Wilcox Company
References
1. “Condition Assessment Guidelines for Fossil Fuel Power
Plant Components,” Report GS-6724, pp. l-l to 1-6, Electric Power Research Institute (EPRI), Palo Alto, California, March, 1990.
2. “Guide for the Nondestructive Inspection of Welds,”
American National Standards/American Welding Society
(ANSI/AWS) B1.10:1999, American Welding Society, Miami, Florida, 1999.
3. Bar-Cohen, Y., and Mal, A.K., “Ultrasonic Inspection,”
Metals Handbook, Ninth Ed., Vol. 17, Nondestructive
Evaluation and Quality Control, pp. 232-233, 254, ASM
International, Metals Park, Ohio, 1989.
4. Alcazar, D.G., et al., “Ultrasonic Detection of Hydrogen Damage,” Materials Evaluation, Vol. 47 (3), March, 1989.
Steam 41 / Condition Assessment
5. Bar-Cohen, Y., and Mal, A.K., “Ultrasonic Inspection,”
Metals Handbook, Ninth Ed., Vol. 17, Nondestructive
Evaluation and Quality Control, pp. 255-256, ASM International, Metals Park, Ohio, 1989.
6. Bar-Cohen, Y., and Mal, A.K., “Strain Measurement for
Stress Analysis,” Metals Handbook, Ninth Ed., Vol. 17,
Nondestructive Evaluation and Quality Control, pp. 448449, ASM International, Metals Park, Ohio, 1989.
7. “Acoustic Leak Detection,” Technical Brief
TB.CCS.32.9.87, Electric Power Research Institute (EPRI),
Palo Alto, California, September, 1987.
8. “Atlantic Electric Demonstrates Infrared Inspection of
Boiler Waterwalls,” First Use, Electric Power Research
Institute (EPRI), Palo Alto, California, December, 1989.
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The Babcock & Wilcox Company
Electromagnetic acoustic transducer (EMAT) technology is one method used to determine remaining life of boiler tubes.
45-22
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The Babcock & Wilcox Company
Section VIII
Steam Generation from
Nuclear Energy
Nuclear power generation provides a critical element in the energy supply
of virtually all developed nations today, and offers the promise to address growing power needs in an environmentally acceptable and safe manner in the future. This section describes the application of steam generation fundamentals
to the design of nuclear steam supply systems (NSSS) in which steam is generated by heat released from nuclear fuels.
This section begins with an overview of nuclear installations, concentrating
on the pressurized water reactor. Principles of nuclear reactions and the nuclear
fuel cycle are then explored in Chapter 47. Chapter 48 is dedicated to nuclear
steam generators. Operating experience indicates that this component is a
particularly challenging and important part of the NSSS. As nuclear power
plants age, the steam generators are increasingly being replaced to optimize
plant performance and extend the operating plant life.
Chapter 49 explores the key service, maintenance and operating characteristic of a nuclear steam system that can optimize life and performance. The
section concludes in Chapter 50 with an overview of the highly specialized
manufacturing requirements and capabilities that are necessary for successful component fabrication.
Steam 41
The Babcock & Wilcox Company
Chapter 46
Steam Generation from
Nuclear Energy
Since the early 1950s, nuclear fission technology
has been explored on a large scale for electric power
generation and has evolved into the modern nuclear
power plants. (See frontispiece and Fig. 1.) Many advantages of nuclear energy are not well understood
by the general public, but this safe, environmentally
benign source of electricity is still likely to play a major role in the future world energy picture. Nuclear
electric power generation is ideally suited to provide
large amounts of power while minimizing the overall
environmental impact.
First generation power plants
The concept of an energy generating plant using
nuclear fission was first considered by nuclear physicists in the 1930s. However, peaceful use of the atom
was delayed until after World War II. The United
States (U.S.) had a head start on nuclear technology
because of its work in the atomic weapons program.
The U.S. Atomic Energy Commission (AEC) took the
lead in research and development for a controlled
chain reaction application to energy generation. Many
concepts were hypothesized and several promising
paths were explored, but the real momentum developed when U.S. Navy Captain Hyman G. Rickover
established a division in the AEC to develop a nuclear
power plant for a submarine. This program, established
in 1949, was to become the forerunner of commercial
generating stations in the U.S. and the world.
Rickover’s design succeeded in 1953. Technology and
materials developed by his team became the cornerstone of future U.S. nuclear plants. Concurrently, the
AEC established a large testing site in Arco, Idaho
where, in 1951, the fast neutron reactor produced the
first electricity (100 kW) generated by controlled fission.
The world’s first civil nuclear power station became
operational in Obninsk in the former Soviet Union
(FSU) in mid-1954, with a generating capability of 5
MW. This was about the same energy level produced
in the U.S. submarine design.
Steam 41 / Steam Generation from Nuclear Energy
In 1953, the Navy canceled Captain Rickover’s
plans to develop a larger nuclear power plant to be
used in an aircraft carrier. However, he subsequently
transformed this project into a design for the first U.S.
civilian power stations. Duquesne Light Company of
Pittsburgh, Pennsylvania agreed to build and operate the conventional portion of the plant and to buy
steam from the nuclear facility to offset its cost of operation. On December 2, 1957, the Shippingport,
Pennsylvania reactor plant was placed in service with
a power output of 60 MW. This event marked the beginning of the first generation U.S. commercial
nuclear plants.
Several basic concepts were being explored, developed and demonstrated throughout the world during
this period. The U.S. submarine and Shippingport
plants were pressurized water reactors (PWR) that
used subcooled water as the fuel coolant and moderator. The FSU developed enriched uranium, graphite-
Fig. 1 Indian Point Station, New York.
46-1
The Babcock & Wilcox Company
moderated, water-cooled designs. British and French
engineers explored natural uranium, graphite-moderated, carbon dioxide-cooled stations. In all these
designs, the coolant (gas, liquid metal or pressurized
water) transferred heat to a heat exchanger, where
secondary water was vaporized to provide steam to
drive a turbine-generator. The other major competing
approach in the U.S. was the boiling water reactor
(BWR). This was similar to the PWR except that the
need for a heat exchanger to transfer heat from the
coolant to the secondary steam cycle was eliminated
by boiling the water in the reactor core and by using
this slightly radioactive steam to drive the turbine. (See
also Chapter 1.)
Two main classes of reactor fuel evolved: enriched
and natural uranium. In the early stage of nuclear
power development, only the two major nuclear powers, the U.S. and the FSU, had sufficient fuel production capacity for civilian power generation using enriched uranium. Therefore, natural uranium was chosen as the principal fuel in the United Kingdom (U.K.),
France, Canada and Sweden. While the enriched uranium-fueled plants could be smaller and therefore required a lower initial investment, higher costs of the
enriched fuel over the life of the plant made its use
economically equivalent to that of natural uranium. All
six countries launched programs to build civil, commercial nuclear power stations. Other countries collaborated
with one of these six for construction technology.
In the U.S., the emerging technology focused on
the enriched uranium light water reactor (LWR) that
used regular water for the coolant and moderator. This
had been the technology selected by the Navy programs and, as a result, the civilian sector gained from
the experience of naval applications. The AEC also financed construction of the nuclear-powered merchant
ship N.S. Savannah, which used this technology in a
PWR designed and constructed by The Babcock &
Wilcox Company (B&W).
In 1955, the AEC began the Power Reactor Demonstration Program to assist private industry. However, by 1963, only one demonstration plant had
started up, and two others had been privately financed. Yankee Rowe in Massachusetts, Indian Point
Unit 1 in New York, and Dresden 1 in Illinois operated successfully and demonstrated the viability of this
technology for larger plants.
Second generation power plants
From these beginnings, the second generation of
nuclear plants began in 1963, when a New Jersey
public utility (Jersey Central Power & Light) invited
bids for a nuclear power station to be built at Oyster
Creek. A comprehensive study showed that it was economically attractive to operate, and the utility was
ready to proceed. This bid was won with a turnkey
proposal to deliver a plant at a fixed price. The suppliers were expected to absorb initial losses in expectation of profitably building a series of similar plants
in the near future. From this study and resulting order came the realization that nuclear power stations
could be competitive with other electricity sources.
46-2
Enthusiasm spread and, in the following years, more
new nuclear generating capacity than conventional
fossil fuel capacity was ordered. By the mid-1970s,
nuclear plants, including new orders, totaled a significant portion of the nation’s electric generating capacity. The second generation nuclear plants were comparable in size or larger than contemporary fossil-fueled plants. While nuclear plant capital costs were
generally higher than those of the current fossil-fueled plants, the lower fuel cost of the nuclear plant
offered a reduction in total generating cost.
The U.S. designs were also attractive for export.
U.S. PWR designs were ordered in Japan, South Korea, the Philippines, Spain, Sweden, Switzerland,
Yugoslavia, Taiwan, Italy, Brazil, Belgium and Germany, while Italy, Mexico, Spain, India, the Netherlands, Switzerland, Taiwan and Japan ordered BWRs
of U.S. design.
In parallel with the rapid U.S. growth in nuclear
electric generation capacity, the rest of the economically developed countries also began development and
construction. In France, early efforts using natural
uranium and gas-cooled reactors could not compete
with oil-fired plants and enriched uranium light water reactors. After France developed uranium enrichment capability, the country’s national utility,
Electricité de France, in conjunction with heavy component designer and manufacturer Framatome, ordered PWR and BWR designs based on U.S. technology. An innovative concept applied by the French was
to build a series of nearly identical plants of each design, thereby achieving economies of scale. Subsequently, the PWR design was selected by the French
for their standardized series of plants. The basic designs developed were also eventually exported to Belgium, South Korea and South Africa.
In the U.K., initial designs for weapons production
reactors were applied to generate commercial power
from natural uranium-fueled, graphite-moderated,
gas-cooled reactors. In the early 1960s, an advanced
gas-cooled reactor (AGR), which used enriched uranium, was designed and subsequently built. Italy and
Japan also built versions of these British designs.
The FSU developed a graphite-moderated, boiling
water-cooled, enriched uranium reactor from its early
Obninsk power station design. A major difference in
this reactor from similar Western designs was that it
did not include a sturdy reactor containment building. The FSU also developed naval propulsion reactors based upon the PWR concept that were then applied to civilian use. This PWR design was exported
to several former Soviet bloc countries and Finland.
The FSU PWR was similar to the U.S. designs except
it generally provided significantly lower electrical output.
The excellent moderator characteristics of deuterium
oxide (heavy water) became the basis for the Canada
Deuterium Uranium (CANDU) reactor systems. These
natural uranium-fueled reactors were first operated
in 1962 (25 MW Nuclear Power Demonstration reactor at Rolphton, Ontario), and subsequent designs
increased output to 800 MW.
In Japan, electric utilities experimented with sev-
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
eral types of imported nuclear generation plant designs.
They ordered gas-cooled reactors from the U.K., and
BWR and PWR designs from the U.S. The Japanese
government also sponsored a breeder reactor design.
Germany was actively involved in designs primarily associated with high temperature gas reactor concepts. In 1969, the formation of Kraftwerk Union introduced German PWR and BWR designs based on
U.S. technology. The intent was to construct a series
of these plants to achieve economies of scale. However,
unlike the French program, few plants were constructed. Several German PWRs were exported to
Brazil, Spain, Switzerland and the Netherlands.
The energy crisis of the mid-1970s caused significant reductions in worldwide electric usage growth
rates, and electric utilities began canceling and delaying new nuclear generating capacity construction.
Cost increases caused by a number of factors also contributed to this construction decline. The delay of
schedules due to slower load growth and/or regulatory
hurdles greatly increased financing costs and drove
unit costs higher. The high inflation of the period further increased construction costs. In addition, continually changing safety regulations increased costs as
changes in design of plants already under construction were required.
PWR installations
By 1978, nine second generation nuclear units designed by B&W were placed into commercial operation, each generating 850 to 900 MW. The first unit
was one of three built at Duke Power Company’s
Oconee Nuclear Station located near Seneca, South
Carolina. The chapter frontispiece shows the three
units of this station. The three vertical, cylindrical
concrete structures are the reactor containment buildings. Although some equipment is shared among
units, each is operationally independent. The rectangular building at the right contains the turbine-generators. The control room, auxiliary systems and fuel
handling facilities for Units 1 and 2 are located in a
structure between reactor buildings 1 and 2. Corresponding equipment for Unit 3 is located separately.
The following general description applies to Oconee
Unit 1, although it is generally applicable to all U.S.
B&W plants; the concepts are applicable to all PWRs.
Containment building
Figs. 2 and 3 show a vertical section and plan of
the reactor containment building. The structure is
post-tensioned, reinforced concrete with a shallow
domed roof and a flat foundation slab. The cylindrical portion is pre-stressed by a post-tensioning system
consisting of horizontal and vertical tendons. The
dome has a three way post-tensioning system. The
foundation slab is conventionally reinforced with high
strength steel. The entire structure is lined with 0.25
in. (6.3 mm) welded steel plate to provide a vapor seal.
The containment building dimensions are: inside
diameter 116 ft (35.4 m); inside height 208 ft (63.4 m);
wall thickness 3.75 ft (1.143 m); dome thickness 3.25
ft (0.99 m); and foundation slab thickness 8.5 ft (2.59
Steam 41 / Steam Generation from Nuclear Energy
Fig. 2 PWR containment building, sectional view.
Fig. 3 Reactor containment building, ground floor plan view.
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The Babcock & Wilcox Company
m). The building encloses the nuclear steam supply
system and portions of the auxiliary and safeguard
systems. The interior arrangement meets the requirements for all anticipated operating conditions and
maintenance, including refueling.
The building is designed to sustain all internal and
external loading conditions that may occur during its
design life. In the event of a major loss-of-coolant accident, the building is designed to sustain the pressure caused by the release of the high-pressure water. To protect against external accidents, extensive
tests and analyses have been conducted to show that
airplane crashes or objects propelled by tornadoes will
not penetrate the wall of the containment.
Nuclear steam supply system (NSSS)
B&W PWR system The major components of the
B&W pressurized water reactor NSSS, shown in Fig.
4, include the reactor vessel, two once-through steam
generators (OTSGs), pressurizer, primary reactor coolant pumps and piping. As shown in the simplified diagram in Fig. 5 (one of two steam generators shown),
the NSSS is comprised of two flow circuits or loops.
The primary flow loop uses pressurized water to
transfer heat from the reactor core to the steam generators. Flow is provided by the reactor coolant pump.
The pressurizer maintains the primary loop pressure
high enough to prevent steam generation in the re-
Fig. 4 B&W nuclear steam supply system.
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tem, there are 380 fuel assemblies traversing the entire
width of the calandria. Heavy-water coolant flows
through the fuel assembly with a full-power flow rate
of 1.98 x 106 lb/h (249.5 kg/s) at an operating pressure
of 1450 psi (10 MPa) and a mean temperature of 553F
(289C). From the calandria, reactor coolant is piped to
four inverted U-tube recirculating steam generators with
design and layout similar to that shown in Fig. 6. In the
CANDU system, each of the fuel assemblies can be isolated from the feedwater system, thereby allowing online refueling at full-power operation.
The balance of the following discussion focuses on
B&W system components as the key concepts are generally applicable to all PWRs.
PWR reactor and fuel
Fig. 5 Simplified schematic of primary and secondary loops.
actor core during normal operation. The steam generators provide the link between the primary coolant
loops and the power producing secondary flow loop.
In the B&W design, subcooled secondary side water
enters the steam generator and emerges as superheated steam, which is sent to the steam turbine to
produce power. The primary side water is cooled as it
flows vertically downward through the straight tubes
and supplies the energy to generate the steam. Table
1 in Chapter 47 of Reference 1 provides a listing of
the important design parameters for the 900 MW
Oconee type NSSS as well as for a larger 1300 MW system. The first 1300 MW design went into operation in
1987 at Muelheim Kaerlich power station in Germany.
Other PWR systems Fig. 6 shows a PWR system using the recirculating steam generator design. The key
components remain the same as the B&W design except that two to four recirculating steam generators
replace the OTSGs in providing the link between the
primary coolant loop and the power producing secondary side flow loop. In the recirculating steam generator (RSG) design (Fig. 7), the primary coolant passes
inside of the U-tubes while the secondary side water
passes over the outside of the tubes where it is partially converted to steam. Steam separation equipment
then removes residual water which is recirculated
back to the bundle for further evaporation. The moisture-free steam is sent to the steam turbine to produce
power.
CANDU The CANDU system uses natural uranium
fuel and heavy water as the reactor coolant and moderator. The calandria (Fig. 8) is a low-pressure, thinwalled vessel containing the moderator and provides
support for the horizontal fuel channel assemblies,
shielding, and control mechanisms. In a CANDU 6 sysSteam 41 / Steam Generation from Nuclear Energy
Reactor vessel and internals
The reactor vessel, which houses the core, is the
central component of the reactor coolant system
(RCS). The vessel has a cylindrical shell with a spherical bottom head and a ring flange at the top. A closure head is bolted to this flange.
The vessel is constructed of low alloy steel with an
internal stainless steel cladding to protect the vessel
from corrosion. The vessel with closure head is almost
41 ft (12.5 m) tall and has an inside diameter of 171
in. (4343 mm). The minimum thicknesses of the shell
wall and inside cladding are 8.4 and 0.125 in. (213
and 3.18 mm), respectively. Reflective metal (mirror)
insulation is installed on the exterior surfaces of the
reactor vessel.
The vessel has six major nozzles for reactor coolant
flow (two outlet hot leg and four inlet cold leg). The
coolant water enters the vessel through the four cold
leg nozzles located above the midpoint of the vessel.
Water flows downward in the annular space between
the reactor vessel and the internal thermal shield, up
Steam Outlet
(to Turbine)
Steam Outlet
(to Turbine)
Steam
Generator
Feedwater Inlet
(from Condenser)
Feedwater
Inlet
(from
Condenser)
Coolant
Pump
Pressurizer
Reactor Vessel
Fig. 6 Four steam generator loop configuration for a pressurized
water reactor with recirculating steam generators.
46-5
The Babcock & Wilcox Company
Steam Outlet
To Turbine
Upper Shell or
Steam Drum
Primary Steam
Separator (Typ.)
Water
Level
Secondary
Steam
Separator
(Typ.)
Recirculated
Separated
Return Water
Feedwater
Inlet Flow
Steam/Water
Mixture
Feedwater
Header
U-Bend Restraints
or Supports (Typ.)
Downcomer
Annulus
Tube Supports
(Typ.)
file leaving the core. The plenum cover is attached to
the top flange of the plenum cylinder. It consists of a
square lattice of parallel flat plates, a perforated top
plate and a flange. The control rod guide tube assemblies are positioned by the upper grid. These assemblies shield the control rods from coolant crossflow and
maintain the alignment of the rods.
Core support assembly The core support assembly
consists of the following components:
1.
2.
3.
4.
5.
6.
7.
8.
core support shield,
core barrel,
lower grid assembly,
flow distributor,
thermal shield,
surveillance specimen holder tubes,
in-core instrument guide tubes, and
internals vent valves.
The core support shield is a flanged cylinder that
mates with the reactor vessel opening. The forged top
flange rests on the circumferential ledge in the reactor vessel top closure flange, while the core barrel is
bolted to the vessel’s lower flange. The cylindrical wall
of the core support shield has two nozzle openings.
These openings form a seal with the reactor vessel out-
U-Tube
(Typ.)
Shut-Off and
Control Rods
Shroud
or Wrapper
Calandria
End Shield
Lower Shell
Tubesheet
Vault
Blowdown Outlet
Primary Head
Reactor Coolant
Outlet
Reactor Coolant
Inlet
Feeder
Pipes
Divider
Plate
Primary Coolant Loop
Secondary Coolant Loop
Fig. 7 Simplified recirculating steam generator (RSG) with water
preheating configuration.
through the core and upper plenum, down around the
inside of the upper portion of the vessel and out
through the two hot leg nozzles. Fig. 9 shows a reactor vessel being installed at a nuclear power plant site.
The core, containing the fuel bundle assemblies, is
the primary component of the reactor vessel. The remaining major components are the plenum and the
core support assemblies (see Figs. 10 and 11).
Plenum assembly The plenum assembly, located
directly above the core, includes the plenum cover,
upper grid, control rod guide tube assemblies, and
flanged plenum cylinder. The plenum cylinder has
multiple openings for reactor coolant outlet flow. These
flow openings are arranged to form the coolant pro-
46-6
Poison
Injection
Calandria
Fuel Channel
Assemblies
Fig. 8 CANDU 6 reactor assembly.
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
Fig. 9 Reactor vessel placed into position between steam generators.
let nozzles by the differential thermal expansion of
stainless and carbon steel. The core support shield also
has eight holes in which the internals vent valves are
mounted.
The core barrel supports the fuel assemblies, lower
grid, flow distributor and in-core instrument guide
tubes. This cylinder is flanged at both ends. The upper
flange is bolted to the core support shield assembly and
the lower flange is bolted to the lower grid assembly. A
series of horizontal spacers is bolted to the inside of the
cylinder and a series of vertical plates is bolted to the
inside surfaces of the horizontal spacers to form walls
enclosing the fuel assemblies. Coolant flows downward
along the outside of the core barrel cylinder and upward through the fuel assemblies. Approximately 90%
of the coolant flow traverses the heat transfer surfaces
of the core fuel assemblies. Of the remaining 10% flow,
some is directed into the gap between the core barrel
and thermal shield primarily to cool the thermal shield.
The remainder of the flow bypasses the core through
various leak paths in the internals.
Core guide lugs are welded to the inside wall of the
reactor vessel. In the event of a major internal component failure, these lugs limit the drop of the core
barrel to 0.5 in. (12.7 mm) and prevent its rotation
about the vertical axis.
The lower grid assembly, consisting of two lattice
structures surrounded by a forged flanged cylinder,
supports the fuel assemblies, thermal shield and flow
distributor. The top flange is bolted to the lower flange
of the core barrel. Pads bolted to the top surface of the
upper lattice structure provide fuel assembly alignment. A perforated plate midway between the lattice
structures aids the uniform distribution of coolant flow
to the core.
The flow distributor is a perforated, dished head that
is bolted to the bottom flange of the lower grid. The
distributor supports the in-core instrument guide
tubes and shapes the inlet flow to the core.
The thermal shield is a stainless steel cylinder located in the annulus between the core barrel and the
reactor vessel. It is supported and positioned by the
Steam 41 / Steam Generation from Nuclear Energy
Fig. 10 Cross-sectional view of reactor vessel internals.
top flange of the lower grid. The thermal shield and
intervening water annuli reduce the radiation exposure and internal heat generation of the reactor vessel wall by attenuating neutron and gamma radiation.
The surveillance specimen holder tubes are installed
on the outer wall of the core support assembly, at approximately mid-height of the core.
The in-core instrument guide tube assemblies guide
the in-core assemblies between the penetrations in the
bottom head of the reactor vessel and the instrument
tubes in the fuel assemblies.
Eight co-planar internals vent valves are installed
on the core support shield; they are 42 in. (1067 mm)
above the centerlines of the reactor vessel inlet and
Fig. 11 Plan view of reactor vessel internals.
46-7
The Babcock & Wilcox Company
Fuel assemblies
In the reactor core, 177 fuel bundle assemblies rest
on a lower grid attached to the core barrel. Each fuel
bundle assembly contains 208 fuel rods (Fig. 12). Each
fuel rod is made up of enriched uranium oxide pellets
contained in zircaloy-4 tubing/cladding (Fig. 13). Fuel
pellets (Fig. 14) are made up primarily from uranium
dioxide (UO2) powder. The powder is pressed and sintered in a dry hydrogen atmosphere to produce the
required pellet size. Final machining of the pellet is
done under water. Within the rods, the fuel pellets are
spring loaded at both ends to ensure contact between
the pellets. The rod is pressurized with dry helium to
improve heat transfer across the gap between the pellets and cladding. End caps are laser welded to seal
the rods and ensure integrity of the fuel/coolant
boundary.
Spacing of the fuel rods in the assembly is maintained with spacer grids at several locations along the
length of the bundle (Fig. 15). These grids are formed
from strips (Inconel for the end spacers and zircaloy for
the intermediate spacers) that are stamped to form the
detailed configurations necessary to ensure adequate
contact points with the fuel rods. The strips are welded
together to form the square-shaped spacer grid that holds
the rods in correct spacing and alignment. Stainless steel
end fittings complete the bundle assembly (Fig. 16).
Each fuel assembly is fitted with an instrumentation tube at the center and with 16 guide tubes, each
accommodating 16 control rods. (See Fig. 17.) Each
group of 16 control rods is coupled together to form a
Fig. 12 Nuclear fuel assembly.
Fig. 13 Typical fuel rod assembly.
outlet nozzles. The valve seats are inclined 5 deg
(0.087 rad) from vertical and the valve discs naturally
hang closed. During normal operation, the valves are
forced closed by the differential pressure, approximately 43 psi (296 kPa), between the outer annulus
of the reactor vessel and the core outlet region. During a severe accident, such as a large break loss of
coolant accident (LBLOCA), however, the differential
pressure reverses and the internals vent valves open,
permitting steam to be vented directly from the core
region to the upper downcomer.
Reactor vessel closure head The closure head is an
integral part of the reactor vessel pressure boundary.
The head provides access for the replacement of spent
fuel, and Alloy 600 penetration nozzles for control rod
drive mechanisms and instrumentation. The closure
head is typically made of low alloy steel and clad with
stainless steel like the rest of the reactor vessel. Recently, many reactor closure heads in existing PWR systems have experienced corrosion damage and are being
replaced (see summary in box on the following page.)
46-8
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
Reactor vessel closure heads
In recent years, discovery of cracked and leaking closure head Alloy 600 penetration nozzles,
mainly the Control Rod Drive Mechanism (CRDM)
nozzles, has raised concerns about the structural
integrity of the closure heads. The CRDM nozzle is
attached to the reactor vessel closure head and provides access to the core for the CRDMs.
Background
The problem was first discovered at the French
Bugey Unit 3 power plant in 1991, when primary
water leakage was observed on the vessel closure
head at the CRDM nozzle region. Investigation of
other French units showed cracking in the CRDM
nozzles and the associated welds, and the cause was
identified as primary water stress corrosion cracking (PWSCC).
This early French experience prompted examination of some PWR nozzle penetrations in the U.S.
Detailed nondestructive examinations showed similar damage. Because the cracks were not throughwall and were within the approved acceptance criteria, the Nuclear Regulatory Commission (NRC)
allowed continued plant operation contingent upon
increased monitoring. However, in 2001, visual inspections of Oconee Unit 3 CRDM nozzles identified boric acid crystals at 9 of the 69 head penetrations, indicating that some primary water leakage
had occurred. Further investigations revealed
PWSCC initiated cracks that propagated from the
weld radially and axially into the nozzle, allowing
primary water leakage.
Evaluation of PWSCC effects has been completed
at many of the PWR plants in the U.S. with subsequent decisions to replace some of the heads. These
decisions to replace, rather than to follow a monitor and repair strategy, are strongly influenced by
the expense of inspection and repair activities,
which are challenging to perform in the hostile radioactive environment. It has proven desirable to
avoid repairs and replace reactor vessel closure
heads in their entirety, as quickly as possible, rather
than bear the cost and schedule implications of difficult inspections and time-consuming repairs. In
2001, B&W received the first replacement head
order in the U.S. to provide heads for Oconee Units
1, 2 and 3.
Closure head replacement requirements
The principal requirement for replacement closure heads is to provide a form, fit and function replacement that is compatible with the original
equipment configuration and that provides enhanced reliability suitable for at least a 40 year
design life. A form, fit and function replacement
design ensures proper and efficient integration of
a new closure head into the existing plant, thereby
simplifying the safety assessments required to show
Steam 41 / Steam Generation from Nuclear Energy
compliance with NRC 10CFR 50.59 regulations.
However, enhanced reliability can only be achieved
by having a sound understanding of the cause of
the degradation, and by optimizing all aspects of
the design that are related to known degradation
mechanisms.
Replacement head features
The conditions that induce PWSCC, and that are
present in the current CRDM-to-head-attachment
region, are:
1. the corrosive environment with primary borated
water,
2. the presence of tensile stresses, and
3. the use of materials susceptible to corrosion.
Accepting the presence of the primary water environment, the major focus of the replacement head design
has been to provide superior materials and to control
the stresses induced at all stages of manufacture.
Materials The material for the CRDM nozzles has
been changed from Alloy 600 to thermally treated
Alloy 690TT. Similarly, the weld consumables for
the CRDM nozzle-to-head weld have been changed
from Alloy 182 to Alloy 52 and/or Alloy 152, both
having material compositions compatible with the
Alloy 690 base material. All of these replacement
materials have demonstrated superior resistance to
PWSCC if they are specified and procured under a
carefully controlled and monitored program.
Fabrication In addition, optimum resistance to
PWSCC requires control of mechanical factors such
as cold work and residual stresses. Materials for fabrication will start in the annealed condition, essentially free of bulk cold work and residual stress.
Some manufacturing steps can reintroduce cold
work and stresses which can negatively affect
PWSCC resistance (both internal and surface conditions are important). Fabrication sequence and
welding methods are important in minimizing internal residual stresses; finishing methods for both
individual parts and completed assemblies are important in controlling surface cold work and related
residual stresses.
Nozzle-to-head welds The original equipment
nozzle-to-head welds were made with a manual
shielded metal arc welding (SMAW) process. The replacement units use an automated gas tungsten arc
welding (GTAW) process which improves weld quality, and minimizes residual as-welded stresses. To address concerns regarding the effect of as-manufactured surface condition on PWSCC resistance, B&W
has employed an electropolishing process for both the
CRDM nozzle prior to installation and the finished
weld after surface conditioning. This process, unlike
abrasive honing or other surface treatments, entirely
removes the cold worked surface layer associated with
machining and grinding.
46-9
The Babcock & Wilcox Company
Fig. 14 Nuclear fuel pellets.
control rod assembly as shown in Fig. 18. At any given
time, 69 of the 177 fuel assemblies contain a control
rod assembly. Because all fuel assemblies are identical and can be used anywhere in the core, the 108 remaining fuel assemblies have their guide tubes partially filled at the top with an orifice rod assembly. This
restricts excessive coolant flow through the unused
control rod guide tubes and equalizes coolant flow
among the fuel assemblies.
The control rod assemblies regulate the reactor reactivity and, therefore, the power output. Each control rod consists of an absorber section made from a
neutron absorbing material such as stainless steel
with silver-indium-cadmium cladding, and an upper
and lower stainless steel end piece. The rods regulate
relatively fast reactivity phenomena such as Doppler,
xenon buildup and decay, and moderator temperature
change effects. The slower reactivity effects, such as
fuel burnup, fission product buildup, and hot-to-cold
moderator reactivity deficit, are controlled by a soluble
Fig. 15 Spacer grid coordinate measuring machine.
46-10
Fig. 16 Final visual inspection of fuel assemblies.
neutron absorbent (usually boron) in the reactor coolant. The concentration of the absorbent is monitored
and adjusted by the plant operators.
Refueling
Most U.S. power reactors operate for a planned
period of between one and two years before the reactivity of the nuclear fuel is reduced and the unit must
be reloaded with fresh fuel. Because only part of the
fuel is replaced during the shutdown, this is referred
to as batch refueling. In some reactors, such as the
CANDU design, a continuous refueling mode that does
not require reactor shutdown is used.
Most PWRs were designed for annual refueling, replacing approximately one-third of the core at each outage. As operating experience has been gained, the trend
has shifted to 18-month refueling cycles. Although fuel
costs are higher, the longer refueling cycle is cost-effec-
Fig. 17 Diagrammatic cross-section of fuel assemblies showing
instrumentation tube and control rod guide tube locations.
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
fuel assemblies are kept in the spent fuel pool at the
reactor site until the radioactive decay and heat generation have declined sufficiently for safe transportation and processing.
Energy transport
Each fission of uranium-235 (U-235) produces approximately 200 MeV, predominantly in the form of
kinetic energy of the fission products. This energy
dissipates to thermal energy of the fuel. The core heat
transfer process involves the fuel, fuel-cladding gap,
cladding and coolant. A typical temperature profile is
shown in Fig. 19. The mode of heat transfer from cladding to coolant is subcooled forced convection. Film
boiling is avoided by maintaining a DNBR above 1.3.
DNBR is the ratio of local heat flux at the departure
from nucleate boiling (DNB) to actual local heat flux.
(See Chapter 5.) The coolant enters the core at approximately 557F (292C) and exits at 607F (319C),
thereby establishing the sink temperature for fuel to
coolant heat transfer. The cladding to coolant convective and cladding conductive heat transfer rates are
relatively high, therefore the fuel temperatures primarily depend on the gap and fuel conductances and the
rate of energy deposition. The heat transfer calculation
methods are described in Chapters 4 and 5. The melting temperature of unirradiated uranium dioxide (UO2)
is 5080F (2804C). This temperature decreases with
burnup at the rate of approximately 58F (32C) per
10,000 MWd/tm U, due to the accumulation of fission
products. A design overpower maximum fuel centerline
temperature of 4700F (2593C) has been selected to
preclude melting at the fuel centerline.
Fig. 18 Control rod assembly.
tive due to reductions in the number of refueling outages, licensing submittals, and replacement power cost.
Furthermore, the burnup capability of the fuel has increased, permitting subsequent batch size reductions.
As nuclear fuel is continually consumed in the reactor, the fuel bundle assemblies are subjected to temperature and irradiation effects that change some of
their characteristics. Dimensional and structural
changes in the assemblies include growth of the fuel
rods, spring relaxation, and fuel rod bow. Some corrosion of the cladding takes place on the coolant side.
This corrosion effect liberates hydrogen from the coolant, some of which is absorbed by the cladding, and
can subsequently decrease cladding mechanical properties. Fission gas release in the fuel rod can cause
high internal pressure. The coolant is continually
monitored during operation to detect any leakage of
these fission gases. While these various effects have
been considered and monitored over the years of reactor operation, they have not been found to limit
operation of the nuclear systems.
Extreme care and detailed handling procedures are
required to remove the spent fuel assemblies for disposition. During their removal from the reactor core
and near-term storage in spent fuel pools, water serves
as both a shielding and as a cooling medium. The spent
Steam 41 / Steam Generation from Nuclear Energy
Fig. 19 Radial temperature profile for a fuel rod at 11 kW/ft.
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The Babcock & Wilcox Company
Instrumentation
The reactor vessel instrumentation consists of the
nuclear instrumentation and in-core monitoring system.
Nuclear instrumentation Neutron flux levels are
monitored using a combination of source, intermediate and power range detectors. Each of these detectors is located at core mid-height, outside the reactor
vessel but inside the primary shield. The distribution
and types of detectors are:
Range
Source
Intermediate
Power
Detector Type
Number
BF3 Proportional
Compensated ion chamber
Uncompensated ion chamber
2
2
4
These measurements are supplied to the reactor operator, safety parameter display system, reactor control portion of the integrated control system and reactor protection system. Additionally, the source and
intermediate range readings are differentiated to provide startup rate, and the outputs of each pair of
power range detectors are differenced to provide top
to bottom flux imbalance.
In-core monitoring system Core performance is monitored using 52 in-core detector assemblies. These assemblies are arranged in a spiral fashion outward from
the center of the core. Each assembly consists of seven
local flux detectors, one background detector and one
thermocouple, arranged as shown in Fig. 20. The
seven local flux detectors, distributed over the axial
core length, indicate the axial flux shape and provide
fuel burnup information. The background detector indicates the integrated axial flux. These flux detectors
are self-powered rhodium-103 instruments. The thermocouple indicates the exit coolant temperature.
Steam generators
Nuclear steam generators are particularly significant components in the NSSS and are discussed in
more detail in Chapters 48 and 50.
The steam generators in PWR systems transfer heat
from the primary coolant loop to the secondary flow
loop, effectively functioning as heat sinks for the reactor core. The decrease of primary coolant temperature through the steam generators is virtually the
same as the increase of primary coolant temperature
through the core. Any difference is attributable to the
fluid energy supplied by the reactor coolant pumps,
less heat losses to ambient.
A variety of steam generator designs have been
used in nuclear reactor systems.2 However, two have
been primarily used on second generation NSSS: the
once-through steam generator (OTSG) and the more
prevalent recirculating steam generator (RSG).
The OTSG is a straight tube counterflow heat exchanger where the primary coolant flows vertically
downward inside the tubes and the secondary side
water flows upward changing from slightly subcooled
liquid to superheated steam at the outlet.
The RSG uses an inverted vertical U-tube bundle
to transfer the energy and generate steam. The primary coolant passes through the U-tubes. The
46-12
Fig. 20 Instrument tube cross-section.
subcooled secondary side water mixes with water from
the steam separators and passes up over the outside
of the U-tube bundle as it is partially converted to
steam. The steam-water mixture passes through multiple levels of steam separation equipment which returns the water to the U-tube bundle for further heating and evaporation and passes the saturated steam
to the power-producing system.
Pressurizer
Description
The pressurizer (Fig. 21) is a tall, cylindrical tank
connected at the bottom to a reactor coolant loop hot
leg through 10 in. (254 mm) diameter surge line piping. Spray is introduced near the top of the pressurizer through a nozzle and 4 in. (102 mm) diameter line
from a cold leg. Three replaceable heater bundles are
installed over the lower portion of the pressurizer.
Pressure relief devices are mounted at the top of the
unit; these include two code safety valves and the
power operated relief valve (PORV).
Function
The pressurizer controls primary system pressure.
During normal operation, the pressurizer volume of
1500 ft3 (42.5 m3) contains equal portions of saturated
liquid and saturated steam. Should the primary system liquid expand, such as through an increase of
coolant temperature due to a load reduction, the excess volume displaces liquid into the surge line, raising the pressurizer level. This evolution is termed an
insurge. The pressurizer steam is compressed, raising
the primary system pressure and causing some of the
steam to be condensed. The specific volume of liquid
is much less than that of steam, therefore the steam
condensation counteracts the ongoing pressure rise.
The opposite occurs during an outsurge, the displacement of pressurizer liquid toward the hot leg through
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
the surge line. In this case, the primary system pressure decreases, saturated pressurizer liquid flashes to
steam and the net increase of specific volume through
the change of phase suppresses the depressurization.
The pressurizer liquid volume is sized to maintain
liquid above the pressurizer heaters and to maintain
pressure above the HPI actuation point during the
outsurge due to a reactor trip. The pressurizer steam
volume is sized to retain a steam bubble during the
insurge due to a turbine trip. Operation without a
pressurizer steam bubble is termed solid plant operation. The pressurizer is sized to avoid this mode in
which pressure control is encumbered.
Heaters
The pressurizer heaters maintain the pressurizer
liquid at the saturation temperature, replacing the
heat losses to ambient. They also raise and/or restore
primary system pressure by elevating the saturation
temperature of the pressurizer fluid. The three
bundles of heaters are divided into five banks. There
are two essential banks and three nonessential banks.
The essential banks are energized automatically, based
on primary system pressure. Essential bank no. 1 is
energized below 2150 psig (14.82 MPa) and is subsequently de-energized above 2160 psig (14.89 MPa); the
corresponding pressures for essential bank no. 2 are
2145 and 2155 psig (14.79 and 14.86 MPa). Nonessential bank no. 3 is sized to maintain the pressurizer fluid
temperature during normal, steady-state operation.
Banks no. 4 and no. 5 provide additional heater capacity
that can be used during system startup or load changes.
Spray
The pressurizer spray system lowers primary system pressure and counters an increasing pressure
transient. The actuation of pressurizer spray introduces 550F (288C) cold leg fluid into the pressurizer
steam space. The resulting condensation decreases the
pressurizer fluid volume, thereby decreasing pressure.
The spray enters the pressurizer through the spray
nozzle. This nozzle imparts rotational motion to the
fluid, generating a downward directed, hollow spray
cone. This pattern enhances steam condensation efficiency while minimizing contact of the cold spray with
the pressurizer vessel walls. Between the pressurizer
wall and the spray nozzle, the spray line makes a bend
in the vertical plane. This loop seal line configuration
is designed to maintain liquid in the spray line,
thereby alleviating the temperature changes experienced by the spray nozzle.
The spray line is attached to the cold leg piping just
downstream of the reactor coolant pump. The spray is
driven by the RCS fluid pressure drop across the reactor vessel, and the full spray flow rate at normal operating conditions is approximately 170 GPM (10.7 l/s).
The spray flow control valve is normally operated in a
modulated rather than on/off mode. When in automatic
mode, the spray flow control valve opens 40% when the
primary system pressure increases to 2200 psig (15.17
MPa) and closes when pressure decreases to 2150 psig
(14.82 MPa). The 40% open setting permits a spray flow
rate of approximately 90 GPM (5.68 l/s).
A continuous flow rate of approximately 1 GPM
(0.063 l/s) is maintained to minimize the thermal transients of the spray nozzle; this is accomplished by a
bypass line around the spray flow control valve. An
auxiliary system provides pressurizer spray when the
reactor coolant pumps are inactive, such as during
decay heat removal cooling of the RCS.
Pressure control devices
Pressure increases are countered by pressurizer
steam condensation through compression and by pressurizer spray actuation. Should pressure continue to
rise, the PORV opens at 2450 psig (16.89 MPa). A pressure actuated solenoid operates the pilot valve, which
actuates the PORV. The PORV discharges into the
pressurizer quench tank and can be isolated by closing the PORV block valve. A hypothetical continuous
rod withdrawal accident from low power would cause
core power generation to greatly exceed steam generator heat removal. The two code safety valves are
sized to prevent RCS pressure from exceeding the 2750
psig (18.96 MPa) limit. These valves open at 2500 psig
(17.24 MPa) and also discharge to the pressurizer
quench tank.
Pumps and piping
Fig. 21 Nuclear steam system pressurizer.
Steam 41 / Steam Generation from Nuclear Energy
Description and function
Coolant is transported from the reactor vessel to the
two steam generators through hot leg piping. The coolant is returned to the reactor vessel from the generators through four cold legs, two per generator. Fluid
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The Babcock & Wilcox Company
circulation is provided by four reactor coolant pumps,
one per cold leg. The arrangement of the piping and
pumps is shown in Figs. 2, 3 and 4.
The hot leg and cold leg piping is fabricated from
carbon steel and is clad on the inside with type 304 or
316 stainless steel. The inside diameters of the hot leg
and cold leg piping are 36 and 28 in. (914 and 711
mm) and their nominal wall thicknesses are 2.75 and
2.5 in. (69.9 and 63.5 mm), respectively. The other
piping attached to the RCS is either fabricated from
stainless steel or clad with stainless steel.
Thermal sleeves are used to minimize the thermal
stresses generated by rapid fluid temperature changes;
they are installed on the four high pressure injection
(HPI) nozzles and two core flood nozzles.
Pump characteristics
The reactor coolant pumps are vertical suction, horizontal discharge, centrifugal units. They are further
characterized as diffused flow, single stage, single
suction, constant speed, vertical centrifugal, controlled
leakage pumps having five-vane impellers. The
pumps are driven by constant speed, vertical squirrel
cage induction motors. Pump sealing is accomplished
using three-stage mechanical seals. The pump and
motor are just over 27 ft (8.2 m) tall (see Fig. 22). The
motor develops approximately 9000 hp (6714 kW) at
cold conditions and 1185 rpm (124 rad/s) using a 6600
volt, three-phase power supply. The locked rotor starting current is approximately 3800 amperes. At normal operating conditions, the motor develops approximately 8300 hp (6192 kW), drawing a current of 685
amperes. Each unit’s rotational moment of inertia is
in excess of 70,000 lbf ft2 (28,928 Nm2). This rotational
inertia is sufficient to sustain rotation for approximately 45 seconds following a power interruption.
Each reactor coolant pump has a nominal capacity of
92,400 GPM (5829 l/s) with a discharge head of 403.5
ft (122.99 m) at operating RCS conditions.
transfer lowers the temperature of the reactor coolant
returning to the core. Core power gradually increases
due to the reactivity gained from the negative temperature coefficient. This means that the increased
reactor coolant density enhances the moderation of
neutrons, thereby increasing the thermal neutrons
available to cause thermal fissions. Also, the control
rods are withdrawn to maintain the average primary
fluid temperature. These primary system interactions
would be reversed as the core and steam generator
stabilized at the new, higher power level. This method
of feedback control has the advantage of immediately
supplying the required electrical load.
An extremely stable but slow method of NSSS control is termed the turbine-following method. The turbine output is varied only as the steam pressure is
adjusted for the revised conditions. Again consider the
response to an increased load demand. The control
rods are withdrawn to increase reactor power and the
feed flow rate is increased to support a higher rate of
steam generation. As the turbine throttle pressure
begins to increase, the throttle valves are gradually
opened, allowing the turbine output to respond to the
increased load demand.
The ICS operates all three systems: turbine, feedwater flow and control rods, to combine the rapid response of the unregulated system with the stability
of the turbine-following system. The key to ICS operation is the turbine header pressure setpoint. The
turbine governor valves maintain turbine speed and
turbine header steam pressure. Because of the thermal inertia of the NSSS, the steam production rate can
not be changed as rapidly as the steam demand varies in response to a turbine load change. This time
delay is handled by temporarily changing the turbine
Integrated control system
Function
The integrated control system (ICS) simultaneously
controls the reactor, steam generators and turbine to
obtain a smooth, rapid response to load changes. The
ICS operates the control rods to regulate core power,
adjusts the feedwater flow to control the rate of steam
production, and operates the turbine throttle valves
to control electrical power output. This control method
combines the advantages of two alternative approaches.
The NSSS responds inherently to load changes
without an ICS, but this response causes undesirable
system variations. Consider the response to an increased load demand without integrated control. The
increased electrical load causes the turbine throttle
valves to open to maintain turbine speed. The increased steam demand lowers steam pressure at the
turbine and within the steam lines and steam generators. Feed flow rate is increased to match the increased
steam flow rate. The increased steam generator heat
46-14
Fig. 22 Reactor coolant pump arrangement.
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
header pressure setpoint. For example, again consider
a load increase. The ICS causes the control rods to be
withdrawn and the feedwater flow rate to be increased. Simultaneously, the ICS temporarily reduces
the turbine header pressure setpoint. The turbine
governor valves open to maintain turbine speed and
to reduce the header steam pressure to the new
setpoint. As core power, primary to secondary heat
transfer and steam flow rate gradually increase, the
turbine header pressure recovers and its set point is
returned to the steady-state value. In this fashion, the
ICS obtains a rapid response and a smooth transition
between turbine loads.
minimizing the activation of the PORV (power operated relief valve). The reactor can also be manually
tripped from the control room.
Limits and controls
The ICS recognizes a variety of limiting conditions,
such as a reactor coolant pump trip, a feed pump trip
or an asymmetric control rod fault. It imposes the
appropriate load and load change limits corresponding to these conditions.
Special ICS signals are imposed below 15% of full
power. During system startup, the reactor and steam
generator power levels are increased to approximately
10% power by steaming through the turbine bypass
valves. The turbine-generator is rolled, synchronized
with the electrical distribution system and gradually
loaded. The turbine control station is placed in automatic mode at approximately 15% turbine load. The
reactor is then controlled to maintain a constant average coolant temperature of 582F (306C) above 15%
power, using the RC subsystem. From 0 to 15% power,
manual control is used to increase the average coolant temperature from 532F to 582F (278 to 306C).
1.
2.
3.
4.
Reactor protection system
Function
The reactor protection system (RPS) trips the reactor when limiting conditions are approached. These
limits prevent boiling of the reactor coolant, limit the
local core power generation rate (the linear heat rate)
and minimize challenges to the PORV.
Multiple independent RPS channels monitor critical reactor trip functions. If any two of these channels detect single or multiple trip functions outside normal parameters, the control rod drive breakers are
opened, tripping the reactor. Depending upon the
NSSS design, the trip functions can include:
1. ARTS (anticipatory reactor trip system) main feedwater pump trip,
2. ARTS turbine trip,
3. overpower trip,
4. high outlet temperature trip,
5. high pressure trip,
6. reactor building high pressure trip,
7. pressure/temperature trip,
8. low pressure trip,
9. power/imbalance/flow trip, and
10. power/reactor coolant pumps trip.
The two ARTS trip functions trip the reactor before
the RCS pressure rises to the reactor set point, thereby
Steam 41 / Steam Generation from Nuclear Energy
Safety features actuation system
The safety features actuation system (SFAS) engages the emergency core cooling system (ECCS) in
the event of a breach of the primary system boundary. The two SFAS signals are low RCS pressure and
high reactor building pressure. A schematic of the
various systems is shown in Fig. 23. The SFAS operates the following systems:
high pressure injection,
low pressure injection,
reactor building cooling, and
reactor building spray.
In addition, the SFAS activates the two emergency
diesel generators.
Each of the three independent measurements of
RCS pressure is fed to a trip bistable. This input is
combined with the output of a reactor building pressure bistable; the trip of either pressure bistable trips
the output. This output signal, combined with those
of the other two pressure logic signals, engages the
SFAS should two out of three trip. Reactor building
spray is also initiated using two out of three logic, but
is based only on reactor building pressure. In addition, the reactor building spray is delayed five minutes from the time of actuation.
Certain features are bypassed when the system is
normally depressurized. These include high pressure
injection, low pressure injection, reactor building isolation and reactor building cooling. Bypass must be
initiated at an RCS pressure of less than 1850 psig
(12.76 MPa); the system is automatically reinstated
when the pressure exceeds 1850 psig (12.76 MPa).
High pressure injection system
The high pressure injection (HPI) system provides
water to the RCS during a loss of coolant accident
(LOCA). It is designed to prevent core uncovery in the
event of a small RCS leak, during which the RCS pressure remains elevated, and to delay core uncovery in
the event of an intermediate size break. The HPI system is activated by the SFAS signal when RCS pressure decreases to 1600 psig (11.03 MPa) or when reactor building pressure increases to 4 psig (27.6 kPa).
The HPI system consists of three pumps, a common
discharge header and four lines that are equipped
with motor operated isolation valves leading to the
four cold legs. One HPI pump operates continuously
to provide water for the reactor coolant pump seals.
Two pumps are always available for automatic safety
injection. The SFAS signals activate both pumps and
their auxiliary equipment. The system also opens the
four isolation valves to preset throttled positions to produce 125 GPM (7.89 l/s) per line using either of the
two HPI pumps.
The HPI system is designed redundantly. Either
pump is sufficient to meet the system requirements.
The pumps are located in separate rooms and draw
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The Babcock & Wilcox Company
Reactor
Building
Core
Flood
Tank
Core
Flood
Tank
Reactor
HPI Pumps
To RCS
Cold Leg Pipe
Makeup
Tank
To RCP Seals
To RCS
Cold Leg Pipe
Reactor
Building
Cavitating Venturis
Decay Heat Coolers
Borated
Water
Storage
LPI Pumps
Reactor
Building
Sump
Fig. 23 Emergency core cooling/injection system.
water from the borated water storage tank (BWST)
through separate lines. The SFAS channels are physically separated. The HPI pump and valve power supply lines are independent, physically separated and
energized from independent power sources. The SFAS
also activates the emergency diesel generators that
provide backup power to the HPI system.
HPI fluid enters each RCS cold leg midway in the
down-sloping piping run at the reactor coolant pump
discharge. The fluid enters horizontally at the side of
the cold leg pipe. The HPI nozzles are equipped with
sleeves to minimize the thermal stress caused by the
cold water injection.
The HPI system can be used during normal operation as part of the makeup and purification system.
Either HPI pump can supply RCS makeup and seal
injection flow to the reactor coolant pumps; these functions are normally performed by the makeup pump.
Low pressure injection system
The low pressure injection (LPI) system provides
water to the core in the event of a large LOCA which
depressurizes the RCS. The two LPI pumps discharge
3000 GPM (189.2 l/s) each at a rated head of 350 ft
(106.7 m). [Shutoff head is 435 ft (132.6 m).] The
borated water storage tank (BWST) supplies the LPI
46-16
pumps. The pumps are actuated independently and automatically by the SFAS signal, as are the four motor
operated isolation valves. They discharge to the reactor
vessel upper downcomer through two core flood nozzles.
The two BWSTs have a capacity of 450,000 gal
(1,703,430 l) each. The boron concentration is maintained above 1800 ppm at 80F (27C). The storage tank
inventory provides at least 30 minutes of operation of
all ECCS pumps. When the BWST inventory is depleted, the LPI pumps are manually transferred to the
reactor building emergency sump, which collects water lost from the RCS. In the event that the HPI pumps
are still required, such as with RCS pressure higher
than the LPI pump shutoff head, the HPI pumps can
be realigned to draw from the discharge of the LPI
pumps. This is referred to as piggy-back operation.
Core flood system
The core flood system provides a passive water supply to the core in the event of a large break loss of coolant accident. The system consists of two tanks, associated piping and valves. Each tank has a volume of
1410 ft3 (39.9 m3). Approximately two-thirds of this
volume, or 7500 gal (28,391 l), is borated water; the
remainder is nitrogen gas pressurized to 600 psig
(4.14 MPa). Should the RCS depressurize to less than
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
600 psig (4.14 MPa) in the event of an LBLOCA, the
nitrogen cover gas forces the core flood tank (CFT) water into the RCS. The boron concentration of the CFT
water is maintained between 2270 and 3490 ppm.
Each CFT discharges through 14 in. (356 mm) lines,
dual check valves and a core flood nozzle into the upper downcomer of the reactor vessel. The two CFTs use
separate piping and nozzles. Each tank is equipped
with a motor operated isolation valve to prevent tank
discharge when the RCS is normally depressurized.
These valves are open when the RCS is pressurized.
Reactor building cooling and spray systems
The reactor building emergency cooling and spray
systems are actuated in the event of a loss of coolant
accident. The spray system also reduces the post accident level of fission products in the reactor building
atmosphere through chemical reaction. The systems
are designed such that either one can offset the heat
released by the escaping reactor coolant.
The systems are activated by the SFAS signals. The
emergency cooling system is actuated within 35 seconds after the RCS pressure decreases to 1600 psig
(10.03 MPa) or the reactor building pressure increases
to 4 psig (27.6 kPa). The emergency spray system is
actuated 5 minutes after the reactor building pressure
reaches 30 psig (206.8 kPa). Both systems can also be
actuated manually.
The reactor building emergency cooling system includes four units, each consisting of an air circulator
and a cooling coil. The 40,000 ft3/min (18.9 m3/s) circulators draw air from a point high within the reactor building dome and discharge downward toward
the cooling units. Two of the four units are equipped
with activated charcoal filters for removing fission
products. The cooling units reject heat to the nuclear
service cooling water system.
The reactor building emergency spray system includes two spray trains, each consisting of a pump,
spray header, spray additive tank and eductor and
associated isolation valves, piping and controls. The
pumps are supplied from the BWST and, later in an
accident, from the reactor building emergency sump.
The 300 hp (224 kW), 1500 GPM (94.6 l/s) spray
pumps discharge through the spray additive eductors,
drawing in sodium hydroxide. The spray additive concentration is sufficient to bring the entire post-accident inventory of reactor building water to a pH of
9.3. The spray discharge is distributed through 100
spray nozzles per header that are arranged to provide
a uniform spray throughout the reactor building,
above the operating floor.
Decay heat removal system
The RCS is periodically cooled and depressurized
for maintenance and refueling. The first portion of the
cooldown is accomplished by circulating the primary
coolant using reactor coolant pumps and by removing heat using the steam generators. This method becomes impractical as the RCS pressure is reduced towards the net positive suction head (NPSH) of the
reactor coolant pumps and as the primary to secondary system temperature difference diminishes.
Steam 41 / Steam Generation from Nuclear Energy
The decay heat removal system (DHRS) is used to
complete the RCS cooldown below 225 psig (1.55 MPa)
and 290F (143C). The DHRS also performs the following functions:
1.
2.
3.
4.
purifies the reactor coolant during cold shutdown,
refills the RCS following maintenance,
cools and adds boron to the spent fuel pool, and
transfers water between the borated water storage
tank and the fuel transfer canal during refueling.
The DHRS also functions as the low pressure injection system during a loss of coolant accident.
The DHRS is activated approximately six hours
after reactor shutdown. It can reduce the RCS temperature from 280F to 140F (138 to 60C) within 14
hours. The DHRS pumps draw reactor coolant from
the hot leg piping, just beyond the reactor vessel,
through a 12 in. (305 mm) decay heat drop line. The
DHRS fluid is discharged through coolers to the reactor vessel upper downcomer through the core flood
nozzles. The injected DHRS fluid then follows the
usual flow path down the reactor vessel downcomer,
up through the core and out the hot leg to the DHRS
inlet, thereby completing the flow circuit. The DHRS
flow rate and rate of RCS cooling are controlled by
bypassing a portion of the DHRS flow around coolers.
The flow rate per cooler is limited to approximately 3000
GPM (189.2 l/s). The heat transferred in the coolers is
removed by the nuclear service cooling water (NSCW)
system, and the temperature difference between the
RCS and the DHRS cooler outlet is maintained at approximately 30F (17C). The decay heat removal suction header temperature is measured to monitor RCS
cooldown and the return header flow rates are also
measured and remotely indicated. The DHRS suction
block valve is interlocked to prevent inadvertent actuation at RCS pressures above 225 psig (1.55 MPa).
A portion of the DHRS flow rate can be diverted to
the makeup and purification system for purifying the
reactor coolant. This flow path is from the discharge
of a DHRS pump; through the letdown filter, purification demineralizers and makeup filters; and back
to a DHRS pump inlet header. The purification demineralizers are limited to a maximum fluid temperature of 135F (57C).
Makeup and purification system
The functions of the makeup and purification system are as follows:
1.
2.
3.
4.
5.
control RCS inventory,
purify and degasify the reactor coolant,
maintain coolant boron concentration,
add chemicals to the reactor coolant for pH control,
supply seal injection flow to the reactor coolant
pumps and handle seal return flow, and
6. add borated water to the core flood tanks.
The makeup and purification system can also function as part of the high pressure injection system.
The makeup and purification system consists of the
letdown, purification and makeup portions. The letdown portion draws reactor coolant from the cold leg
suction through a 2.5 in. (63.5 mm) line. The effluent
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The Babcock & Wilcox Company
is cooled using one of the three letdown coolers. Radioactive nitrogen-16 is allowed to decay in the letdown delay line, a 15 ft (4.6 m) length of 12 in. (305
mm) piping. Depressurization and flow control are
provided by the letdown orifice; the nominal flow rate
of 45 GPM (2.83 l/s) may be increased to 140 GPM
(8.83 l/s) by bypassing the orifice.
The flow rate of 45 GPM (2.83 l/s) processes one RCS
volume daily. Letdown flow rate, temperature and
pressure are measured. Multiple motor operated
valves are used to isolate the system in the event of
SFAS operation.
The purification portion of the system consists primarily of the letdown filters, mixed bed demineralizers and makeup filters. The demineralizers are provided temperature protection by temperature actuated
isolation valves. The purified effluent may be directed
to the makeup tank or diverted to the bleed tanks when
reducing the RCS fluid inventory.
The 4400 gal (16,657 l) makeup tank is central to
the makeup and purification system. It receives purified letdown flow and seal return flow. It also serves as
the point of boron and hydrogen addition to the RCS.
Boron is used for reactivity control, lithium hydroxide
provides pH control and hydrogen or hydrazine is used
for oxygen control. The makeup tank acts as a surge
tank to accommodate temporary changes of RCS inventory and provides water for the makeup pump. Finally,
it can be used to degasify the reactor coolant.
A 4 in. (101.6 mm) line connects the makeup tank
to its pump, with cross connects to the HPI pumps. The
pump discharges are recombined and a 2.5 in. (63.5
mm) diameter flow line is routed back to the seal return coolers to cool the operating pumps. The makeup
flow rate is measured and remotely indicated and is
controlled by the pressurizer level control valve.
Makeup is injected into the RCS through the cold leg
HPI nozzle at the reactor coolant pump discharge,
thereby completing the flow circuit.
During power operation, the makeup and purification system operates continuously to regulate RCS
inventory. The makeup flow control valve is adjusted
automatically to maintain pressurizer level. The flow
rate of the makeup pump is the sum of the makeup
flow rate (to the RCS), the seal injection flow rate to
the reactor coolant pumps and the makeup pump recirculation flow rate. The net makeup system flow rate
to the RCS is the sum of the makeup and the seal injection flow rates, less the seal return flow rate.
Abnormal transient operating guidelines
The abnormal transient operating guidelines
(ATOG) represent a symptom-oriented response to
plant transients. These guidelines provide the operator with a clear and effective method of correcting
abnormal conditions. ATOG involves the identification
and correction of key upset conditions, regardless of
their cause. These actions alone are sufficient to ensure core covery and cooling and to ensure plant
safety.
The three key symptoms of ATOG are loss of
subcooling margin, inadequate heat transfer and excessive heat transfer.
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The subcooling margin refers to the difference between the saturation temperature at RCS pressure and
an RCS temperature. A positive subcooling margin
ensures that the core is covered and therefore cooled. A
loss of subcooling margin, on the other hand, indicates
steam generation within the RCS and may indicate core
uncovery. The operator must take action to restore the
subcooling margin, such as by activating HPI pumps
or a primary system heat removal process.
Subcooling margin is the key ATOG indicator. However, inadequate or excessive heat transfer indications
must also be remedied. Inadequate heat transfer is
countered by restoring primary to secondary system
cooling and/or by initiating HPI-PORV cooling. In the
latter method, core decay heat is removed by actuating full HPI and the PORV. The HPI fluid flows into
the cold leg discharge piping leading to the reactor
vessel. It flows through the core, out the hot leg, into
the pressurizer through the surge line and out the
PORV. Excessive heat transfer is remedied by reducing the rate of primary to secondary system heat transfer. This can be done by throttling the flow of auxiliary feedwater to the steam generators, restoring
steam generator secondary pressure and reducing the
primary to secondary temperature difference.
Exclusive among the events that can give rise to abnormal ATOG symptoms is the steam generator tube
rupture (SGTR) accident. This event is readily identified using radiation indications and alarms and indications of steam generator conditions: pressure, temperature and level. Event oriented operator actions are taken
to minimize radiation release and to ensure core cooling.
NSSS design: today and in the future
There are currently 103 operating, fully licensed
nuclear power reactors in the United States representing 97.5 GW of capacity and generating 780 billion
kWh in 2002, or 20% of the total U.S. generation.2,3
These 103 NSSS units fall into one of three categories:
No.
Pressurized Water Reactor (PWR)
Recirculating Steam Generator (RSG)
62
Once-Through Steam Generator (OTSG)
7
34
Boiling Water Reactor (BWR)
Total
103
MW
59,793
5,915
31,792
97,500
As of May 2004 there were 440 operating nuclear
power systems worldwide with a capacity of 362 GW
producing approximately 16% of global electricity
generation.4,5 More than 30 new plants are under construction.6 As discussed in the introduction to this chapter, commercial NSSS designs outside of the U.S. fall
into one of six general categories:
1. PWR – RSG
2. PWR – OTSG
3. BWR
4. PHWR (pressurized heavy water reactor, including the Canadian CANDU design)
5. GCR (gas-cooled reactor)
6. FBR (fast breeder reactor)
As with the PWRs, the PHWR, GCR and FBR also
include steam generators to provide a heat sink for the
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
primary side reactor coolant system and to generate
steam for the secondary side power cycle. The PHWR
system steam generators are very similar in design to
the PWR recirculating steam generators. (See Chapter 48.) In particular, 33 Canadian CANDU PHWR
systems with 21 GW of capacity are in operation in
Canada, India, Pakistan, China, Argentina, Romania
and South Korea. An additional 18 units (48 GW) in
India are based upon the CANDU technology.
The current (second) generation of nuclear power
plants in the U.S. has demonstrated decades of safe
and reliable performance. Continual improvements
have been made in maintenance and operation. In the
past 20 years, the average capacity factor has increased from about 60% to more than 90%. This significant increase translates into an additional 23,000
MW of power to the grid – the equivalent of 23 new
plants. Production costs (fuel, operations and maintenance) of most plants are less than US$0.02/kWh,
and in the best plants about $0.01/kWh. The proven
reliability has resulted in 25 of the current operating
plants being granted licenses to continue operations for
another 20 years beyond their original license period.
Despite this excellent performance, no new nuclear
plants have been ordered in the U.S. for the past 26
years, although design of a third generation of nuclear
systems, commonly designated Generation III, has proceeded. The key attributes of these new designs are:
1. simple and more rugged making these more resistant to upsets and easier to operate,
2. standardized to reduce cost and schedule,
3. increased availability,
4. extended design life (approximately 60 years),
5. reduced possibility of core meltdown accidents,
6. minimized environmental impact,
7. enhanced fuel burn-up to reduce waste, and
8. extended fuel life.
The most significant change has been the incorporation of passive or inherent safety features which do
not require operator or control system intervention to
avoid accidents if equipment malfunctions. These systems may include gravity assisted flow, natural circulation within and between components, and resistance to deterioration at elevated temperatures. Most
of these NSSS designs (including PWRs, BWRs,
PHWR/PWR hybrid, high temperature GCR) are evolutionary from the existing second generation systems.
These systems are being introduced in other countries
with two in operation by 2003 and others being built
or ordered.
Beyond the Generation III designs, a number of
countries including the U.S. have formulated a general agreement to explore the potential of several more
revolutionary designs, designated Generation IV. Introduction of these new designs may be feasible starting around 2020. In addition to further improving the
key attributes of the Generation III designs, the Generation IV designs will try to offer some radical new
approaches to solve future energy needs and resolve
environmental concerns. The new designs will employ
fast cores and coolants that allow a marked increase
in operating temperatures. The high temperatures
Steam 41 / Steam Generation from Nuclear Energy
can be used for chemical processes, including production of low cost hydrogen. The advanced fuel cycles
can be arranged to extract more energy from the spent
fuel and also to drastically reduce the toxicity of high
level waste.
Nuclear ship propulsion
Nuclear power for propulsion has been applied to
both commercial and naval vessels beginning with the
U.S.S. Nautilus, the world’s first nuclear ship (see Fig.
24). The development of nuclear ship propulsion also
formed the basis for commercial pressurized water reactors (PWR) for land-based electric power generation.
For submarines, nuclear propulsion has proven to be
the greatest single advancement in post-World War II
technology. This dramatic achievement virtually abolished range limitations and enabled the submarine to
become a true submersible, freed from the need to make
regular forays to the surface to recharge batteries.
Nuclear power has also proven extremely valuable
for naval surface ships such as aircraft carriers and
escort vessels. While the advantages are not as readily
apparent as for submarines, the unlimited, sustained
power available with nuclear propulsion allows the
ship commander to devote his full attention toward
effectively executing his mission without the continuous logistical concern for fuel oil supplies.
While any type of reactor system may be used for
ship applications, only the PWR and the sodium-cooled
reactor have been used. Of these, the PWR is the predominant system. A typical PWR schematic arrangement for shipboard application is shown on Fig. 25.
Fig. 24 Launching of the U.S.S. Nautilus, the world’s first nuclear
powered ship.
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The Babcock & Wilcox Company
mercial ships showed promise. However, the public
fear of accidents, especially with ships in harbor, essentially has prevented any further exploration of
commercial ship installations. On the other hand, the
U.S. Navy has maintained an excellent performance
and safety record over the years, and U.S. naval ships
are welcomed in major ports throughout the world.
Commercial nuclear ships
Fig. 25 Pressurized water reactor system – naval type.
In the 1950s, several countries became interested in
applying nuclear power to commercial shipping. These
efforts resulted in the launching of the U.S. ship N. S.
Savannah and the soviet ice-breaker Lenin. Later in the
1970s, Germany launched the N. S. Otto Hahn and
Japan launched the cargo ship N. S. Mutsu. Fig. 26 is a
schematic diagram of a typical marine propulsion plant.
There are important differences between shipboard
reactors and land-based installations. These differences involve weight and space limitations, plant reliability and on-board maintenance, plant safety, and
problems inherent with a moving platform. While the
weight and size of the nuclear reactor itself does not
present a problem, the weight and size of the radiation shielding around the NSSS is significant. These
considerations usually dictate a more compact arrangement of the major components, as compared to
land installations. However, the need to account for
maintenance requirements forces the designer to balance compactness against access needs. Because access to ship units is more limited, reliability of shipboard components assumes even greater importance.
Safety is, of course, a major consideration. Shipboard nuclear plants are more subject to external
hazards than land-based plants, particularly for naval units that may be exposed to extreme battle shock
conditions. In the early stages of development, com-
Nuclear merchant ship Savannah
A nuclear merchant ship was first proposed by President Dwight D. Eisenhower in 1955, as evidence of
the U.S.’s interest in promoting the peaceful use of
atomic energy. After Congress approved the funding in
1956, the President directed the AEC and the Maritime
Administration (MARAD) to design and construct the
vessel that was subsequently named the Savannah.
The program’s major objectives were to demonstrate
the peaceful use of nuclear energy and resolve the problems of commercial marine reactor operation. Plant requirements included a conservative design with a long
core life, use of commercially available materials and
equipment wherever practical, and safety of operation.
The Savannah (Fig. 27) was a single-screw, geared
turbine vessel, 595 ft (181.4 m) long, with a beam of
78 ft (23.8 m), draft of 29.5 ft (9 m), and a displacement of 21,900 t (19,867 tm). The ship had a design
speed of 22 knots (40.7 km/h) at 22,000 shaft hp
(16,412 kW), accommodations for 60 passengers and
652,000 ft3 (18,463 m3) of cargo space.
Fig. 26 Shipboard nuclear propulsion system.
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Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
Fig. 27 N.S. Savannah – first nuclear merchant ship.
B&W supplied the PWR nuclear propulsion plant
and auxiliaries (see Fig. 28) for the Savannah and
trained the operating crew. Pertinent design data for
the power plant are given in Table 1.
The keel of the Savannah was laid in 1958, and the
ship was launched 14 months later. In 1962, the ship
was delivered to the operating agent, and port visitations began. The Savannah’s reactor was fueled by
15,653 lb (7100 kg) of uranium enriched to an average of 4.4% uranium-235. On her first fuel core, the
Savannah traveled approximately 330,000 mi
(531,089 km) and developed 15,000 full power hours
with no shuffling of fuel. By late 1970, the Savannah
had traveled more than 450,000 mi (724,205 km), visited 32 different U.S. ports in 20 states and 45 different foreign ports in 27 countries, and had been visited by more than 1,500,000 people.
The operation of the Savannah provided technology for future development of nuclear ships, and established standards for the design of the ship and
reactor, operating practices and safety. After completing her mission, the Savannah was retired and is now
a museum ship located in Charleston, South Carolina.
Nuclear merchant ship Otto Hahn
After building the N.S. Savannah reactor, B&W
developed an improved nuclear marine plant known
as the Consolidated Nuclear Steam Generator
(CNSG). The CNSG was designed to achieve more
economic nuclear propulsion systems for merchant
ships, and has potential application for small- to medium-sized land-based plants.
The CNSG design incorporates the reactor and oncethrough steam generators within a single pressure
vessel, achieving a compact arrangement and eliminating some of the auxiliary equipment.
The CNSG design was used successfully for the
nuclear plant of the German N.S. Otto Hahn (Fig. 29).
This ship was a single-screw geared turbine ore carrier 565 ft (172.2 m) long, with a beam of 77 ft (23.5
m), a draft of 30 ft (9.1 m), dead weight of about
15,000 t (13,608 tm) and a design speed of 16 knots
(30 km/h) at 10,000 shaft hp (7460 kW).
The nuclear plant for this ship was designed and
Steam 41 / Steam Generation from Nuclear Energy
constructed by the German-Babcock Interatom consortium with the assistance of B&W. A cross-section of
the pressure vessel is shown in Fig. 30. Pertinent design data for the power plant at normal load are given
in Table 2. The Otto Hahn began commercial service
in 1970, and was decommissioned in 1978.
Naval nuclear ships
U.S. naval nuclear propulsion program
Background In 1946, the U.S. Navy’s Bureau of
Ships recognized that atomic energy might ultimately
be developed for ship propulsion. Under the direction
of Captain (later Admiral) Hyman G. Rickover, a team
was established to transform existing theory and concepts into practical engineering designs.
The basic requirements for applying nuclear power
to shipboard propulsion were clear. The reactor would
have to produce sufficient power so that the ship
would have military usefulness, and it would have to
produce that power safely and reliably. The reactor
plant would have to be rugged enough to meet the
stringent requirements of a combatant ship, and be
Fig. 28 N.S. Savannah nuclear steam supply system arrangement.
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The Babcock & Wilcox Company
Table 1
N.S. Savannah
Power plant design data:
Maximum shaft power
Reactor power
Total steam flow
Turbine inlet pressure
Feedwater temperature
Reactor coolant data:
Pressure in reactor
Temperature in core
Flow
22,000 hp (16,412 kW)
70 MW
226,000 lb/h (28.5 kg/s)
430 psi (2.96 MPa)
340 F (171C)
1735 psi (11.96 MPa)
508 F (264C)
9,400,000 lb/h (1184.4 kg/s)
designed for operation by a Navy crew. A suitable reactor would require new corrosion resistant metals that
could sustain prolonged periods of intense radiation,
effective shielding to protect personnel from radiation,
and the development of new components that would
operate safely and reliably for prolonged time periods.
These problems were even more difficult for submarine applications because the reactor and associated
steam plant had to fit within the confines of a small hull,
and be able to withstand extreme battle shock. Although the application of nuclear power to submarines
was a major challenge, success would revolutionize
submarine warfare. No longer limited to submerged
operation on battery power, a true submarine was possible, one that could travel submerged at high speed
for long periods. Because of the immense challenge
posed by this revolutionary approach, the Navy established extremely rigorous guidelines covering design,
fabrication, quality, testing, and training for the suppliers and Navy personnel. These new guidelines demanded significant improvements in performance from
all involved parties and established the design and
engineering philosophy which underlies the basis of the
commercial and Naval nuclear industry today.
Three reactor concepts were initially considered for
naval nuclear propulsion. A study of a gas-cooled reactor showed that this concept was not then suitable.
The pressurized water reactor and liquid metal-cooled
Fig. 30 Reactor vessel cutaway (N.S. Otto Hahn) (courtesy of Gesellschaft fur Kernenergieverwertung in Schiffbau und Schiffahrt mbH).
reactor approaches were found promising and carried
through to full scale prototype plants, and thereafter
to shipboard applications. B&W became actively involved in both designs.
U.S.S. Nautilus
In 1949, the U.S. Navy’s Chief of Naval Operations
issued a formal requirement for the development of a
nuclear powered submarine. The following year, the
U.S. Congress authorized funds for a land-based prototype of the pressurized water reactor that would
power the world’s first nuclear powered ship. B&W was
Table 2
German N.S. Otto Hahn
Fig. 29 N.S. Otto Hahn (courtesy of Gesellschaft fur Kernenergieverwertung in Schiffbau und Schiffahrt mbH).
46-22
Power plant design data:
Shaft power
10,000 hp (7460 kW)
Reactor power
38 MW
Total steam flow
141,000 lb/h (17.8 kg/s)
Superheater outlet press.
440 psi (3.03 MPa)
Superheater outlet temp.
523 F (273C)
Feedwater temp.
365 F (185C)
Reactor coolant data:
Pressure in reactor
918 psi (6.33 MPa)
Temp. in reactor core
523 F (273C)
Flow
5,280,000 lb/h (665.3 kg/s)
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
selected to provide major reactor system components.
Just three years later, the prototype began operation
and for the first time, a reactor produced sufficient
energy to drive power machinery.
On January 17, 1955, the Nautilus (Fig. 31) put
to sea for the first time and radioed her historic message: “underway on nuclear power.” On her shakedown cruise, the Nautilus steamed submerged more
than 1300 mi (2092 km) in 84 hours – a distance that
was 10 times greater than had been traveled continuously by a submerged submarine.
Within months, the Nautilus would break virtually
every submarine speed and endurance record. Her
global odyssey carried her under the seven seas, and
on the first voyage in history across the top of the
world, passing submerged beneath the North Pole.
On her first fuel core the Nautilus steamed more
than 62,500 mi (100,584 km), more than half of which
were totally submerged. During 25 years of service,
she traveled a total of 600,000 mi (965,606 km) on
nuclear energy, making the dream of Jules Verne
come alive. The Nautilus is now a historic museum
ship and is located in New London, Connecticut.
The Nautilus was the first application of a reactor
power plant using pressurized water both as the primary coolant and as the heating fluid for converting
the secondary water into steam. The recirculating steam
generator (Fig. 32) was comprised of a straight tube and
shell heat exchanger with riser and downcomer pipes
connected to a separate steam drum. B&W designed and
fabricated the prototype test steam generator, and the
reactor vessel and pressurizer for the Nautilus.
U.S.S. Seawolf
The U.S.S. Seawolf, the second U.S. nuclear submarine, was launched in 1955, and her liquid metalcooled reactor attained initial criticality in 1956. To
help ensure tube integrity, the Seawolf’s sodiumheated steam generators (Fig. 33) utilized sodium-potassium as a third or monitoring fluid in the annulus
of the double-tube design. Although the ship operated
satisfactorily for almost two years on its sodium-cooled
reactor, overriding technical and safety considerations
(mainly the potential for violent reaction between sodium and water) led to the abandonment of this type
of reactor for propelling U.S. naval ships.
Fig. 31 U.S.S. Nautilus.
Steam 41 / Steam Generation from Nuclear Energy
Fig. 32 U.S.S. Nautilus steam generator.
While liquid sodium is a much more efficient heat
transfer medium than water, it can be very troublesome in service. Two problems are particularly noteworthy: the sodium has to be kept molten at all times
or it will solidify and can damage primary system piping, and the sodium must be kept isolated from water
to prevent a violent reaction.
In 1958, the Seawolf entered a shipyard where her
sodium-cooled plant was replaced with a pressurized
Fig. 33 Sodium-heated steam generator for U.S.S. Seawolf.
46-23
The Babcock & Wilcox Company
water reactor similar to that in the Nautilus. When
her sodium plant was shut down for the last time, the
Seawolf had steamed a total of 71,611 mi (115,247 km)
of which 57,118 mi (91,923 km) were fully submerged.
U.S.S. Skipjack
The U.S.S. Skipjack attack submarine class combined the PWR plant with a streamlined Albacore hull
shape to provide increased speed and reduced flow
noise. In 1956, B&W received a contract for the design and fabrication of steam generators for the Skipjack. These were the first vertical recirculating PWR
steam generators with integral steam separators and
were the forerunner to the recirculating steam generator designs in current commercial PWR (non-B&W)
plants and in CANDU reactor plants.
Technological advancements
Each new naval propulsion plant is a balance between the desire to make technological advances and
a commitment to deliver a reliable fighting ship on
schedule. Each new design can incorporate only a portion of all the potential improvements in technology.
The ultimate success of any power plant design will
depend on how well that balance is achieved.
In developing power plant components for modern
naval vessels, improvements have been made in thermal hydraulic design, materials, structural design, and
fabrication. Significant improvements in the art of
steam-water separation have contributed greatly to
the performance and compactness of naval steam generators.
Significant advances have also been made in reactor fuel technology. Reactor fuel lifetime has been
extended from 2 years for the first Nautilus core, to
more than 15 years for cores delivered in the 1980s.
Efforts have been underway to develop reactor fuel
that will last the life of the ship, making expensive and
time consuming refueling unnecessary.
While much research has been done in the U.S. and
in other countries on alternate forms of submarine
power production, such as magnetohydrodynamics
and fuel cells, nuclear power has proven to be highly
reliable, safe and cost effective, and continues to be
the system of choice for the U.S. Navy and other international fleets for the foreseeable future.
displacement of 26,500 t (24,041 tm). The Soviets’ titanium-hulled Alfa-class attack submarines are reportedly the world’s fastest and deepest diving with a speed
of 45 knots (83 km/h) and an operational depth of 2500
ft (762 m).
Nuclear ship development is proceeding in other
countries. The FSU is continuing development of new
attack and missile submarines. The overall picture is
somewhat unclear due to the economic conditions in
the FSU and also because of continued safety issues,
particularly in the aftermath of the sinking of the
Kursk submarine in 2000. Both issues have led to a
marked downturn in Soviet ship deployment. China has
been developing new attack and ballistic missile nuclear
submarines based on early Soviet designs. India is trying to develop a nuclear ballistic missile submarine.
Future U.S. Navy
The U.S. Navy has the largest nuclear fleet in the
world, comprising 72 submarines and 10 aircraft carriers. In line with the ever changing situation in the
world, the naval strategies and ship requirements are
constantly evolving to meet the perceived global issues. Ship designs and power propulsion systems are
constantly upgraded to meet the navy needs and to
incorporate the newest technological advances.
Submarines
With the demise of the Cold War, the need for a
large contingent of ballistic missile submarines has
greatly diminished and strategy is now more focused
on providing multi-purpose submarines with a broad
range of missions. The U.S.S. Virginia (SSN774) is
the first of a new class of attack submarines intended
as a more cost-effective follow-on to the current
Seawolf class. The ship is capable of both deep ocean
International naval nuclear programs
All of the principal maritime nations have studied
the application of nuclear power to naval ship propulsion. The U.S., Great Britain, France, the People’s
Republic of China, and the FSU have built nuclear
vessels. These nations all have naval nuclear fleets
that rely primarily on pressurized water reactor technology. However, the Soviet Navy reportedly utilizes
liquid metal cooled reactors in at least one attack submarine class for higher power output and greater operational speeds.
The Soviet Typhoon-class ballistic missile submarine (Fig. 34) is the largest submarine type ever built
with a length of 563 ft (171.6 m) and a submerged
46-24
Fig. 34 Soviet Typhoon-class ballistic missile submarine.
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
warfare and shallow water operations of all types.
Missions of the new ship include anti-submarine warfare, covert operations, personnel delivery, intelligence gathering, convert mine warfare, and Battle
Group Support. The Virginia displaces 7800 tons and
is 370 feet long. Fig. 35 shows a Virginia-class submarine under construction.
Aircraft carriers
In 2006, the U.S.S. George W. Bush will be the last
of the Nimitz-class carriers to be built (see Fig. 36).
Construction of a new class of carrier, the CVN 21
with 100,000 ton displacement, will begin at Newport
News Shipbuilding in 2007 for delivery in 2014. The
new ship will incorporate a new design of nuclear
power plant, expanded flight deck, and a new electrical power distribution system. The new power plant
will greatly increase the electrical power supply enabling the deployment of an electromagnetic aircraft
launch system and offering scope for advancements
in new electromagnetic weapons systems. The power
plant and related equipment are designed to reduce
maintenance and provide substantial reduction of personnel required to operate and staff the ship.
Fig. 36 U.S.S. Nimitz and U.S.S. Ronald Reagan are part of the
current Nimitz-class aircraft carrier group.
Fig. 35 Virginia-class submarine nears completion.
References
1. Stultz, S.C., and Kitto, J.B., Eds., Steam/its generation and use, 40th Ed., The Babcock & Wilcox Company,
Barberton, Ohio, 1992.
2. Annual Energy Review 2002, Report DOE/EIA-0384
(2002), Energy Information Agency, U.S. Department of
Energy, Washington, D.C., October, 2003.
3. Annual Energy Outlook 2004, Report DOE/EIA-0383
(2004), Energy Information Agency, U.S. Department of
Energy, Washington, D.C., January, 2004.
4. International Energy Outlook 2004, Report DOE/EIA0484 (2004), Energy Information Agency, U.S. Department
of Energy, Washington, D.C., April, 2004.
5. International Atomic Energy Agency, Power Reactor
Information, Reference Data Series 2, website
www.iaea.org/programmes/a2/, (2004).
6. Nuclear News, Vol. 47, No. 1, American Nuclear Society, LaGrange Park, Illinois, January, 2004.
Inconel is a trademark of the Special Metals Corporation group of
companies.
Steam 41 / Steam Generation from Nuclear Energy
46-25
The Babcock & Wilcox Company
Oconee Nuclear Power Station, Duke Power Company.
46-26
Steam 41 / Steam Generation from Nuclear Energy
The Babcock & Wilcox Company
Chapter 47
Fundamentals of Nuclear Energy
Fundamental particles and structure
of the atom1
In the fifth century B.C. Greek philosophers postulated that all matter is composed of indivisible particles called atoms. Over the next 24 centuries there
were many speculations on the basic structure of
matter but all theories lacked any experimental basis.
It was not until late in the nineteenth and early twentieth centuries that the existence of fundamental particles,
the proton, neutron and electron, was confirmed.
The discovery of nuclear fission, credited to Otto
Hahn, Lise Meitner and Fritz Strassman, was made
possible through an accumulation of knowledge on the
structure of matter beginning with Becquerel’s 1896
detection of radioactivity.
As shown in Fig. 1, the structure of an atom is pictured as a dense, positively charged nucleus surrounded by an array of negatively charged electrons.
Each proton, the equivalent of a hydrogen atom
nucleus, carries an elemental positive charge of electricity. The number of protons determines the type of
chemical element of the atom. Each neutron is an electrically neutral particle with a mass slightly greater
than the proton. Because of their association with the
nucleus of the atom, protons and neutrons are also
referred to as nucleons. Each electron shown orbiting
around the nucleus has an elemental negative charge
and a mass about 1/2000 that of a proton. The nucleus
of an atom with a characteristic number of neutrons
and protons is called a nuclide.
Despite the minute size of the atom, there is a relatively great distance between the nucleus and the orbiting electrons. This distance, approximately 105
times the dimension of the nucleus, accounts for the
ability of various radiations to pass through apparently dense materials.
Fig. 1 also indicates the relationship of the positively
charged protons in the nucleus and the negatively
charged electrons. In the un-ionized state, the number of protons is balanced by an equal number of electrons. An atom becomes ionized by gaining or losing
one or more electrons. A gain of electrons yields negative ions and a loss results in positive ions. An atom in
an ionized state can interact with other elements to
form various compounds.
When an atom has more than two electrons, their
orbits are located in a series of separate and distinct
groupings of energy levels or shells. Each shell is capable of containing a specific number of electrons. In
Steam 41 / Fundamentals of Nuclear Energy
general, an inner shell fills to its maximum number
of electrons before electrons begin to form in the next
shell. An x-ray is a quantum of electromagnetic energy that is emitted when an electron transitions from
an outer shell to an inner shell or between energy
levels within the same shell.
The number of electrons in the outermost shell determines certain chemical properties of the elements.
The properties are similar for elements which have
similar electron distributions in the outer shell regardless of the number of inner shells. This accounts for
the repetition of chemical properties in the Periodic
Table of the Elements. (See Appendix 1.)
Nuclides and isotopes
A nuclide is characterized by its atomic number Z
(number of protons in the nucleus) and the mass number A (total number of protons plus neutrons). When
nuclides are described by chemical symbol, the atomic
Fig. 1 Structure of the atom (Z = atomic number ; A = mass number).
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The Babcock & Wilcox Company
number is the left hand subscript and the mass number the right hand superscript. For example, the α
particle can be represented as α, 2α4, or 2He4. With most
chemical elements there are several types of atoms
having different mass numbers, i.e., different numbers
of neutrons in the nucleus but the same number of
protons. An isotope is one of two or more nuclides of the
same chemical element having different mass numbers.
Two isotopes of hydrogen and two isotopes of oxygen are depicted in Fig. 1. An ordinary hydrogen atom
1
1H , contains one proton and no neutrons. Its atomic
number Z and mass number A are 1. It combines with
oxygen to form H2O or regular or light water. The deuterium atom, 1H2 or 1D2, has one proton and one neutron; Z is 1 and A is 2. It combines with oxygen to form
D2O or heavy water. A third isotope of hydrogen, tritium, 1H3 or 1T3, has one proton and two neutrons.
Heavier nuclides are also identified by chemical
name and mass number. Oxygen-16 and oxygen-17
(Fig. 1) have 16 and 17 nucleons respectively, although
each has eight protons. For example, symbols for the two
isotopes of oxygen described above are 8O16 and 8O17.
Although either the atomic number or the chemical symbol could identify the chemical element, subscripts sometimes are useful in accounting for the total number of charges in an equation.
Mass
It is customary to list the mass of atoms and fundamental particles in atomic mass units (AMU). This is
a relative scale in which the nuclide 6C12 (carbon-12)
is assigned the exact mass of 12 AMU by agreement
at the 1962 International Union of Chemists and
Physicists. One AMU is the equivalent of approximately 1.66 × 10-24 grams, or the reciprocal of the presently accepted Avogadro number, 0.602214 × 1024 atoms per gram-atom. A gram-atom of an element is a
quantity having a mass in grams numerically equal
to the atomic weight of the element.
Table 1 lists the masses of the fundamental particles
and the atoms of hydrogen, deuterium and helium in
atomic mass units.
Mass defect
The mass of the hydrogen atom 1H1 listed in Table
1 is almost but not quite equal to the sum of the masses
of its individual particles, one proton and one electron.
However, the mass of a deuterium atom 1H2 is noticeably less than the sum of its constituents – a proton,
neutron and electron. Measurements show that the
mass of a nuclide is always less than the sum of the
masses of its protons, neutrons and electrons. This
difference, the mass defect (MD), is customarily calculated as:
MD = Zmh + ( A − Z ) mn − me
(1)
where
MD
Z
= mass defect, AMU
= number of protons in the nucleus of the
nuclide
mh
= mass of the hydrogen atom, AMU
A – Z = number of neutrons in the nucleus
47-2
Table 1
Masses of Particles and Light Atoms
Isotope or Particle Mass, AMU
Electron
Proton, 1p1
Neutron, 0n1
Hydrogen, 1H1
Deuterium, 1H2
Helium, 2He4
0.000549
1.007277
1.008665
1.007825
2.01410
4.00260
= mass of neutron, AMU
= mass of the nuclide including its Z electrons, AMU
mn
me
Binding energy
Although most nuclei contain a plurality of protons
with mutually repulsive positive charges, the nucleus
remains tightly bound together, and it takes considerable energy to cause disintegration. This energy,
called binding energy, is equivalent to the mass defect. From the equivalence of mass and energy, as
defined by Einstein’s equation E = mc 2, one AMU
equals 931 million electron volts (MeV ). An electron
volt is the energy gained by a unit electrical charge
when it passes, without resistance, through a potential difference of 1 volt. Therefore,
Binding energy ( MeV )
=
{ Zm + ( A − Z ) m
h
n
− me
} × 931
(2)
This represents the amount of radiant or heat energy released when an atom is formed from neutrons
and hydrogen atoms. It also represents the energy
which must be added to fission an atom into its basic
nucleons, i.e., neutrons and protons.
Dividing Equation 2 by A, the number of nucleons
in the nucleus, yields the binding energy per nucleon.
This in turn can be plotted as a function of A, the mass
number as shown in Fig. 2. The result shows that the
binding energy per nucleon rapidly increases for low
mass numbers, reaches a maximum for mass numbers
in the range of 40 to 80, and then drops off with an
increasing slope. On the rising portion of this curve,
fusion or joining of nucleons to atoms of higher mass
number means that there is an increased binding energy per nucleon and consequently a release of energy.
On the falling portion of this curve, the fission process or
splitting of an atom results in nuclides of lesser mass numbers and greater binding energy per nucleon. Again, energy is released because of the increased mass defect.
Radioactivity and decay
Nuclear radiations
Nuclides that occur in nature are stable in most
cases. However, a few are unstable, especially those
of atomic number 84 and above. The unstable nuclides
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
undergo spontaneous change at specific rates by radioactive disintegration or decay. Many nuclides decay into other unstable nuclides, resulting in a decay
chain that continues until a stable isotope is formed.
There are generally three types of radiation commonly
arising out of the decay of specific nuclides: alpha (α)
particles, beta (β) particles and gamma (γ) rays.
Alpha particle The α particle is equivalent to the
nucleus of a helium atom comprising two neutrons
and two protons. It results from radioactive decay of
an unstable nuclide and, with very few exceptions, is
observed only in the decay of heavy nuclides.
Beta particle The β particle results from radioactive
decay and has the same mass and charge as an electron. It is believed that the nucleus of an atom does
not contain electrons and, in radioactive β decay, the
β radiation arises from conversion of a neutron into a
proton and β particle; therefore:
neutron → proton + β + energy
In some instances a positive β particle (called a
positron) is produced from the conversion of a proton
to a neutron.
Gamma ray Gamma rays are electromagnetic radiation resulting from a nuclear reaction. They can
be treated like particles in many nuclear reactions and
are included among the fundamental particles. Although γ rays have physical characteristics similar to xrays, their energy is greater and wave length shorter.
The only other difference between the two rays is that γ
rays originate from within the nucleus while x-rays originate from within the shell structure of the atom.
Biological effects of radiation
The organs of the human body are composed of tissue which is composed of atoms. When electrons are
knocked out of or added to atoms (ionized), the chemical bonds which bind atoms together to make molecules
are broken. This process is called ionization. The recombination of these broken molecules can result in
changes in the molecular structure of a cell which may
affect the way the cell functions, its growth characteristics and its interaction with other cells. In cases
Fig. 2 Binding energy per nucleon versus mass number.
Steam 41 / Fundamentals of Nuclear Energy
of high radiation exposure, cancer may result. The
term used to describe the effects of radiation on humans is biological damage.
Ionization is a direct result of alpha and beta particles interacting with human tissue. These particles
produce a continuous path of ionization as they travel
throughout the body. Gamma radiation produces ionization indirectly in matter by the photoelectric effect,
the Compton effect and pair production. All three processes yield electrons which in turn produce most of
the ionization which occurs within the body.2
In the photoelectric effect, the γ ray transfers all its
energy to the electron that it strikes. The electron then
causes ionization in the medium. In the Compton effect, only part of the γ ray’s energy is transferred to
the electron as kinetic energy. The remaining energy
gives rise to a lower energy γ ray. Pair production occurs when the γ ray has an energy greater than 1.02
MeV. All of its energy is given up and two particles,
an electron and a positron, are produced. (All three
processes produce electrons which then ionize the
absorbing matter.)
Although ionization causes biological damage, the
seriousness of the damage is determined by many
factors such as the types of cells effected (how radiosensitive they are), the age of the person receiving
the exposure (young cells are more radiosensitive) and
whether the dose is received over a short (acute exposure) or long (chronic exposure) period of time.
Acute exposure is more detrimental because a large
amount of damage is incurred rapidly and the cells
do not have an adequate amount of time to repair
themselves. Under chronic exposure, cells are very
effective in repairing injury. The effects of chronic
exposure and the amount required to produce damage have been extrapolated primarily from known
cases of acute radiation exposure. More recent radiobiology laboratory and other studies have developed
data which assess the effects of chronic exposure. As
the nuclear industry continues, the database for low
level occupational exposure grows and it becomes more
evident that the associated risks are low. The data
available suggest that the body can tolerate low doses
of radiation received over long periods of time with
little risk. This is supported by the exposure and
health history of x-ray technicians, physicians and
radiation workers. In many laboratory and historic
exposure studies, beneficial effects of low level radiation are demonstrated. These studies certainly counter
the argument that no level is low enough and that
allowable levels must be endlessly reduced in the pursuit of safety.
Radiation protection
Alpha particles, due to their large mass and double
positive charge, travel very short distances. Their
range in air is only a few centimeters. Fig. 3 illustrates
the penetration ranges of various types of radiation.
Alpha particles are seldom harmful when the source
is located outside the human body because an α particle of the highest energy will barely penetrate the
outer layer of skin. If emitted inside the body, however, α radiation can be serious. It is important, there47-3
The Babcock & Wilcox Company
fore, to prevent the ingestion or inhalation of α emitting nuclides. Particular care is required to keep the
air in working spaces free of dust containing α emitters. Fabrication of α emitters such as plutonium normally takes place inside gloveboxes that remain under a slight negative pressure. The boxes discharge
air effluent through a filter designed to prevent α
bearing dust from entering the working spaces and
the atmosphere in general. The air is continuously
monitored and analyzed.
Beta particles penetrate up to an inch of wood or
plastic material and travel several yards in air. The
skin and the lenses of the eye are most vulnerable to
external β radiation. However, clothing and safety
glasses provide adequate protection for external exposure to β radiation. The β particle is not as great an
internal hazard as the α particle. The β particle, due
to its smaller mass and lower charge, will travel farther than the α particle through tissue and will deposit less energy in a localized area.
Gamma rays penetrate deeply and deposit their
energy throughout the entire body. They have great
ranges in air and may present a hazard at large distances from the source; however, they do not present
as large an internal hazard as α particles.
Neutrons, like gamma radiation, are an external
hazard and their damage extends throughout the
body. In addition, the effectiveness of neutrons to produce biological damage is 2.5 to 10 times greater than γ
rays. The concrete and water shielding provide the primary protection against neutrons and gamma rays.
Decay rate
The rate at which a radioactive nuclide emits radiation is a characteristic of the nuclide and is unaffected by temperature, pressure or the presence of
other elements that may dilute the radioactive substance. Each nucleus of a specific radioactive nuclide
has the same probability of decaying in a definite
period of time at a rate characterized by its radioactive decay constant. The rate of decay at any time, t,
always remains proportional to the number of radioactive atoms existing at that particular instant. The
decay is calculated by:
Fig. 3 Ranges of various types of radiation in materials.
47-4
N ( t ) = N ( 0 ) e − λt
(3)
where
N(t) = the number of atoms per cm3 at time t
N(0) = the number of atoms per cm3 at time zero
λ
= radioactive decay constant
Half life
Decay is usually expressed in terms of a unit of time
called radioactive half life, T1/2. This represents a measurable period of time, the period it takes for a quantity of radioactive material to decay to one half of its original amount.
The relationship between half life and decay constant can
be determined by substituting (T1/2) for t and N(0)/2 for
N(t) in Equation 3 and solving for λ. The result is:
λ =
0.693
T1 / 2
(4)
Decay constants for radioactivity isotopes are easily obtainable with a listing of measured half lives.3
If N(t) represents the number of radioactive atoms
present at time t, then λN(t) becomes the number of
radioactive nuclei that decay per unit of time at time
t. This is referred to as the radioactivity, or more simply the activity, of the atoms and is expressed in curies. A curie is 3.70 × 1010 disintegrations per second.
N(t) can be converted directly to curies by the relation N(t)/(3.70 × 1010). Fig. 4 shows on a relative scale
how the activity decreases during several half lives.
This curve applies to all radioactive substances.
It is sometimes difficult to distinguish between
stable and radioactive nuclides. All nuclides heavier
than bismuth-209 (Bi-209) are unstable. However, the
specific nuclides thorium-232 (Th-232), uranium-235
(U-235) and U-238 have half lives of 108 to 1010 years
and can be considered stable. In fact, they are generally referred to as the stable isotopes of the heavier
chemical elements. Table 2 shows half lives of some
nuclides of high atomic number.
Induced nuclear reactions
By providing sufficient energy, all of the fundamental particles can be made to react with various nuclei.
In this procedure, the particle strikes or enters an
atomic nucleus causing a transfiguration or change
in structure of the nucleus and the release of a quantity of energy. Particles which activate these reactions include neutrons, deuterons, α, β, protons, electrons and γ.
Many reactions produce artificial radioactive nuclides.
Charged particles such as alphas, betas and protons do not have great penetration power in matter
because the interaction with the existing electrical
field within the atoms either slows or stops them. Collisions between like charged particles require exceedingly high kinetic energy. Electrical fields, however,
can not deflect electrically neutral neutrons; therefore,
they collide with nuclei of the material on a statistical
basis. The neutron is therefore the most effective particle for inducing nuclear reactions including fission.
Reactions of principal interest in the design of
nuclear reactors are those that involve neutrons and
those that involve the interaction of the particles proSteam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
a mass difference. A good statistical probability for the
reaction to occur exists when energy is released as a result
of reaction. The more probable reactions generally can
be initiated by lower energy particles. The less probable
ones, those that require significant energy addition, can
be initiated only by high energy particles. Table 3 gives
some typical induced nuclear reactions.
In a nuclear reactor, many heavy nuclides with
mass numbers greater than 238 are produced by a
series of neutron captures accompanied by β and/or α
decay. These artificially produced nuclides have many
uses – some are readily fissionable, some are fertile
because they absorb a neutron and then transmute
to a fissionable nuclide, some have high energy α decay modes that can be used in neutron sources, and
some are used as sources in medical procedures.
Fig. 4 Exponential decay of radioactive nuclides.
duced by fission and other nuclear processes within
the reactor and surrounding materials.
The expression:
Z1
X A1 ( P1 P2 ) Z 2 X A 2
(5)
is generally used to denote a nuclear reaction and is
the short form for:
Z1
X A1 + P1 → Z X A* →
Z2
X A 2 + P2
The X* notation indicates formation of a compound
nucleus which is generally unstable. Terms P1 and P2
represent incident and resultant particles respectively.
The individual sum of the Zs (atomic numbers) and
the sum of the As (mass numbers) on the left side of
the equation always equals, respectively, the sum of
the Zs and the sum of the As on the right side of the
equation. (See Table 3).
Nuclear reactions always conserve total mass-energy
on the two sides of the equation in accordance with
Einstein’s equation for the equivalence of mass and energy. However, there is usually an energy difference and
Table 2
Half Lives of Heavy Elements
Decay Mode
Naturally occurring nuclides:
Thorium-232
Uranium-238
Uranium-235
α
α
α
Artificial nuclides:
Thorium-233
Protactinium-233
Uranium-233
Uranium-239
Neptunium-239
Plutonium-239
β
β
α
β
β
α
Steam 41 / Fundamentals of Nuclear Energy
Half Life
10
1.39 x 10 yr
4.51 x 109 yr
7.13 x 108 yr
22.1 min
27.4 d
1.62 x 105 yr
23.5 min
2.35 d
2.44 x 104 yr
Probability of nuclear reactions –
cross-sections
The probability of a nuclear reaction between a neutron, or other fundamental particle, and a particular
nuclide is expressed as the cross-section for that reaction. The probability is dependent on the energy of the
interacting particle. Because neutron interactions are
most important in a nuclear reactor, the following discussion is directed toward neutron cross-sections; however, the concepts can be directly applied to all particle interactions.
Two types of nuclear cross-sections are defined:
1. The microscopic cross-section or interaction probability
is an intrinsic characteristic of the nuclei of the material. It has dimensions of an area and is normally expressed in barns where one barn equals 10-24 cm2.
Table 3
Typical Induced Nuclear Reactions
Short Form
Long Form
Alpha:
9
12
4Be (α,n)6C
14
17
N
(α,p)
O
7
8
4
Deuteron:
31
32
15P (d,p)15P
9
10
Be
(d,n)
B
4
5
15
Gamma:
9
8
4Be (γ,n)4Be
2
1
H
(γ,n)
H
1
1
4
Neutron:
10
7
5B (n,α)3Li
113
114
Cd
(n,γ)
48
48Cd
1
2
1H (n,γ)1H
16
16
8O (n,p)7N
Proton:
12
13
6C (p,γ)7N
9
8
Be
(p,d)
Be
4
4
Be9 + 2α4 → 6C12 + 0n1
14
+ 2α4 → 9F18* → 8O17 + 1p1
7N
P31 + 1d2 → 16S33* → 15P32 + 1p1
9
Be
+ 1d2 → 5B11* → 5B10 + 0n1
4
Be9 + 0γ 0 → 4Be8 + 0n1
2
0
2
1
1H + 0 γ → 1 H * → 1 H + 0 n
B10 + 0n1 → 5B11* → 3Li7 + 2α4
113
+ 0n1 → 48Cd114* → 48Cd114 + 0γ 0
48Cd
1
1
2
2
0
1 H + 0 n → 1H * → 1H + 0 γ
16
1
17
16
1
O
+
n
→
O
*
→
N
+
8
0
8
7
1p
5
C12 + 1p1 → 7N13* → 7N13 + 0γ 0
9
1
10
8
2
4Be + 1p → 5B * → 4Be + 1d
6
* Indicates formation of a compound nucleus which is
generally unstable.
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The Babcock & Wilcox Company
2. The macroscopic cross-section is a probability of
interaction per centimeter of neutron path and
takes into account the density of the material. It
has the dimensions cm-1.
The symbol σ represents the microscopic cross-section. In the case of a neutron approaching a fissionable atom it becomes possible to consider a total crosssection σ T in which:
σT = σ c + σ s + σ f = σ a + σ s
(6)
where
σ c = the capture cross-section, a measure of the
probability for absorption without fission
σ s = the scattering cross-section, the probability
that the nucleus will scatter the neutron
σ f = the fission cross-section (present in only a few
of the many nuclei), the probability for a neutron to strike and cause a fission to occur
σ a = the absorption cross-section, the sum of the
probabilities for capture and fission
a corresponding increase in the number of probable
collisions between the nucleus and neutron occurring
at energies in the vicinity of the resonance. Therefore,
an increase in the temperature of the nucleus results
in an apparent broadening of the energy width of the
resonance. This in turn results in a very effective increase in resonance neutron absorption, i.e., capture
and fission. Conversely, a decrease in temperature of
the nucleus results in narrowing the resonance width
and decreasing resonance absorption. The change in
resonance energy width with temperature, known as
the Doppler effect, is important in reactor control.
Fig. 5 illustrates a typical cross-section curve showing the neutron capture cross-section of U-238 as a
function of neutron energy. Below 102 eV the height
of the resonance peaks is about 103 barns. Between
102 and 4 × 103 eV the great number of resonances
makes it impractical to show the cross-section as a
curve, although the resonance parameter data are
available for use on a computer. Between 4 × 103 and
105 eV the curve represents a statistical average of the
measurements which have been made.
The macroscopic cross-section can be obtained from:
Σ = N0 ρ σ / M
(7)
where
Σ = macroscopic cross-section, cm-1
N0 = Avogadro’s number, 0.602214 × 1024 atoms/
gram-atom
ρ = density of the material, grams/cm3
σ = microscopic cross-section, cm2/atom
M = atomic weight, grams/gram-atom
Experimental measurements determine microscopic
cross-sections for each element. Total cross-section
measurements are generally made by transmission
techniques. For example, placing a material of known
density and thickness in front of a neutron source permits measuring the intensity of neutrons at a particular energy on each side of the material. The difference
represents the loss or attenuation of neutrons by the
material. The cross-section required to obtain this attenuation is derived by calculation.
Isotopes of the same element can have very different cross-sections. For example, the isotope xenon-134
(Xe-134) has a microscopic cross-section for neutron
absorption of about 0.2 barn, yet Xe-135 has a microscopic cross-section of 2.7 × 106 barns. U-235 is fissionable at any energy, and U-238 only at high energy.
Cross-sections of some nuclides also contain abrupt
peaks called resonances at certain energy bands (Fig.
5). Because a cross-section is really a function of relative energy of the neutron and the nucleus, an effective change in the cross-section results when the energies of the neutron and the nucleus increase or decrease as a result of temperature changes.
Where the curve of cross-section versus energy is
fairly smooth, the effect of a temperature change of
the target nucleus is relatively small. However, the
effect of a temperature change is large and important
in the vicinity of a resonance. An increase in temperature results in increased vibration of the nucleus with
47-6
The fission process
Nuclear fission is the splitting of a nucleus into two
or more separate nuclei accompanied by release of a
large amount of energy. In the fission of an atom due
to a neutron, the mass of the neutron plus its energy
must be equal to or greater than the mass defect associated with the two fission products. U-235 is the
only naturally occurring nuclide that is capable of undergoing fission by interaction with low energy or slow
neutrons. Some of the artificially produced heavy nuclides are also fissionable with slow neutrons, including plutonium-239 (Pu-239) and U-233. Other nuclides such as U-238 and Pu-242 require higher energy neutrons to cause fission.
This difference in fission capability occurs because
the binding energy of a nucleus is not only determined
by its mass number but also by whether the number
of protons and neutrons is even or odd. A nuclide with
an even number of neutrons and protons, such as U238, has the highest binding energy per nucleon and
requires the most added energy to fission. Fission only
occurs with high energy or fast neutrons (> 1MeV). A
nuclide with an odd number of protons and an even
number of neutrons or an even number of protons and
an odd number of neutrons, such as U-235, Pu-239
and U-233, has a lower binding energy per nucleon.
Nucleons with both an odd number of protons and
neutrons have the lowest binding energy per nucleon
for essentially equivalent mass numbers. U-235 and
Pu-239 are fissionable with slow or thermal neutrons
(~0.025 eV). The term thermal neutron refers to a neutron energy distribution that is in thermal equilibrium
with the temperature of the surrounding materials.
Fission occurs when the fissionable nucleus absorbs
a neutron. In the case of U-235 the reaction is:
U 235 + 0n1 → 92U 236*
92
U 236* →
92
Z1
X A1 +
Y A 2 + 2.43 0n1 + Energy
Z2
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
Fig. 5 Capture cross-section of uranium-238.
As previously noted, the asterisk in 92U236* indicates
an unstable nuclide. The value 2.43 applies to U-235
fission by a thermal neutron and is the statistical average of the number of neutrons produced per reaction. X and Y represent the fission products which are
distributed as shown in Fig. 6.
Energy from fission
Fission also produces γ rays, neutrons, β particles
and other particles. The energy release per fission
amounts to about 204 MeV for U-235 and is distributed as shown in Table 4. Release of approximately
this amount of energy per fission can be predicted by
examination of Fig. 2 for binding energy, considering
that two fission products are formed as shown in Fig.
6. Table 4 also includes data for Pu-239.
Neutrons from fission
The fact that additional neutrons are born or generated by a fission event makes it possible to establish a chain reaction, as depicted in Fig. 7, that can
sustain itself as long as sufficient fissionable material
and neutrons are present. The neutrons produced per
fission event, υ, and the average number of neutrons
produced per neutron absorbed in the fuel, η, vary
with the different fissionable isotopes and with the
energy of the neutron producing the fission. Statistical averages for these quantities are given in Table 5.
There are individual fission reactions that produce only
one neutron, possibly none, or as many as five. Because some of the neutrons are absorbed without producing fission, η becomes a more meaningful quantity in reactor design than υ. The values in the table
are for fission by low energy or thermal neutrons at
room temperature [0.025 eV neutron energy or 7218
ft/s (220 m/s) neutron velocity]. To maintain a chain
reaction, the average number of neutrons per absorption must be significantly greater than 1 because some
of the neutrons will be lost to absorption in the moderator and structural materials, to absorption in control materials, and to leakage from the core. Control
materials such as boron and silver-indium-cadmium
are used to maintain a steady-state chain reaction by
Steam 41 / Fundamentals of Nuclear Energy
absorbing any additional neutrons over that needed
for steady-state operation.
Fission neutron energy distribution
Neutrons released from fission vary in initial energy
over a wide range up to 15 MeV and above. The distribution of neutrons produced by fission as a function of
energy has been determined from several experimental
measurements, and typical results for U-235 and Pu-239
are shown in Fig. 8. Based on these measurements, the
average energy of fission neutrons is about 2 MeV; the
peak of the energy distribution occurs at about 0.8 MeV.
Fig. 6 Mass distribution of fission products from fission of U-235.
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The Babcock & Wilcox Company
Table 4
Energy Produced in Fission (MeV /fission)
U-235
Pu-239
169
8
5
182
175
8
6
189
8
7
8
6
7
22
10
24
204
213
Instantaneous
Kinetic energy of fission products
γ ray energy
Kinetic energy of fission neutrons
Delayed
β particles from fission products
γ rays from fission products
Neutron-capture γs*
Total
* Energy produced depends on reactor composition.
Burnup
As a mass of uranium undergoes fission it produces
energy. The term burnup is used to represent the
amount of energy produced per unit mass of the material. The units of burnup are megawatt days per
metric ton (MWd/tm) of initial heavy metal, i.e., uranium. One megawatt day represents about 2.6 × 1021
fissions. A nuclear fuel assembly is typically discharged
from the reactor when it has achieved a burnup of
about 50,000 MWd/tm. In commercial power reactors
that are fueled with uranium comprising mainly the
isotope U-238, with 4% or less U-235, most of the energy produced comes from the fissioning of U-235. At
burnups of 50,000 MWd/tm only about 5% of the initial uranium content of the fuel assembly has fissioned. Even when the other nuclear reactions that
cause loss of the original uranium atoms are considered,
there is still more than 90% of the initial uranium remaining in the fuel assembly when it is discharged.
Fission products
When a nucleus undergoes fission, experimental
measurements have shown that predominantly two fission products or fragments are generated. The distribution of these fission products for U-235 fissions has also
been measured and is shown in Fig. 6. In fission, as in
any nuclear reaction, there is always conservation of
Fig. 7 Chain reaction.
total mass-energy so that one of the two fission products
will come from each hump of the distribution.
Examination of Fig. 6 reveals that mass number of
the fission products ranges from about 70 to 170 with
two plateaus at approximately 95 and 135. Curves are
shown for fission caused by thermal energy neutrons
and by 14 MeV neutrons. The higher the neutron energy causing fission the more uniform the fission product distribution.
Many fission products interact with neutrons, absorbing them so that they are not available to the
chain reaction. As these fission products build up (see
Fig. 9), they act as absorbers to retard the chain reaction. All long lived fission products except samarium
build up as the core is operated, reaching a maximum
effect at the end of core life.
Table 5
Neutrons from Fission
Fuel
Avg. Neutrons per Avg. Neutrons per
Fission, υ
Absorption in Fuel, η
Uranium-233
Uranium-235
Natural uranium
Plutonium-239
Plutonium-241
47-8
2.51
2.43
2.43
2.90
3.06
2.28
2.07
1.34
2.10
2.24
Fig. 8 Fission neutron energy distribution.
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
After discharge from the reactor and sitting in storage for a few years, most of the fission products will
have decayed due to their relative short half lives.
However, some of the long half life fission products will
contribute significantly to the γ ray source that must
be shielded against in handling the fuel during its ultimate disposal. These isotopes include strontium-90
(Sr-90), ruthenium-106 (Ru-106), cesium-134 (Cs134) and 137 (Cs-137), cerium-144 (Ce-144) and europium-154 (Eu-154). These isotopes will either be
bound in the fuel pellets or on the inside surface of
the cladding. Other isotopes important to fuel handling
are the artificially produced nuclides in the fuel pellet that decay by spontaneously fissioning. These isotopes include Pu-238, americium-241 (Am-241), and
curium-242 (Cm-242) and 244 (Cm-244). In addition,
the γ emitting isotope cobalt-60 (Co-60) is produced in
the structural steels and Inconel® through neutron activation and must be shielded against.
Fission product behavior with time
Certain fission products, specifically Xe-135 and
samarium-149 (Sm-149), both of which have very
high cross-sections for absorption of thermal neutrons,
are not only produced directly from fission but also are
the decay products of other fission products.
Essentially all initial products of fission are highly
radioactive and decay rapidly to less active isotopes
with somewhat longer half lives. There are usually
several isotopes in the chain before a stable end product is reached. The most significant such decay chain
is the following:
β
135
52
Te
→
β
53
< 1.0 min.
I
135
→
β
135
54
6.7 h
Xe
β
135
→ 55Cs
9.2 h
→
56
Ba135
2 × 106 yr
In this chain, tellurium-135 (Te-135) with a one
minute half life decays to iodine-135 (I-135) with a
6.7 hour half life and then to Xe-135. This xenon isotope, which fortunately has only a 9.2 hour half life,
has a macroscopic cross-section for thermal neutron
absorption approximately 100,000 cm-1, as great as all
the long lived fission products together. Unfortunately,
the nuclides of this chain occur abundantly as fission
products – a predictable happening, because the mass
number 135 occurs at a peak in the fission product distribution (Fig. 6). The Xe-135 absorbs an appreciable
Fig. 9 Fission product chain.
Steam 41 / Fundamentals of Nuclear Energy
fraction of available neutrons as long as the reactor is
operating. This changes some of the Xe-135 to Xe-136
(which has negligible neutron absorption). As a result,
when a water reactor operates at constant power level,
the Xe-135 builds up to its equilibrium value in 36 to 48
hours.
When reactor power lessens and, particularly, when
the reactor is shut down, the I-135 formed at the original power level continues for a time to generate Xe135 at a rate corresponding to the original power level.
Therefore, the Xe-135 builds up rapidly after shutdown because fewer neutrons are available for conversion to Xe-136. The buildup reaches a peak 4 to
12 hours after shutdown and then slowly decays. The
time behavior of Xe-135 must be addressed in reactor
control.
Sm-149, the second important fission product in the
reactor core during operation, is generated as follows:
60
Nd149 →
61
Pm149 →
62
Sm149 (stable)
In the chain, neodymium-149 (Nd-149) decays (1.7
hour half life) into promethium-149 (Pm-149), which
in turn decays (47 hour half life) into Sm-149. Although Sm-149 is a stable isotope it is destroyed so
rapidly by neutron absorption that it reaches an equilibrium value when the reactor operates at constant
power. Typically, Sm-149 reaches equilibrium in a
pressurized water reactor after 50 to 100 days.
Buildup after shutdown is slower and less extensive
than for Xe-135.
Decay after shutdown has little consequence for all
other fission fragments because of their long lives and
comparable capture cross-sections between parent and
daughter nuclide.
Nuclear reactor composition
A reactor core is composed of fuel, structural and
control materials, and a moderator and/or coolant.
Typical pressurized water reactor (PWR) fuel assembly and control component designs are shown in Fig.
10. A depiction of the interactions that take place
within a fuel assembly is shown in Fig. 11. Neutrons
react not only with uranium, but also with the nuclei
of most other elements present. Therefore, many materials which have high neutron absorption properties should not be used for structural purposes. Fortunately, a few materials such as aluminum and zirconium have low neutron absorption cross-sections.
Inconel, steel and stainless steel also can be used to a
limited extent.
The choice of coolants includes water, helium and
liquid sodium. Thermal reactor design, where the neutron energy distribution is essentially in thermal equilibrium with its surroundings, requires a moderator
(a material containing atoms of a light element such
as hydrogen, deuterium or carbon) in the core to reduce the kinetic energy of the neutrons. Hydrogen is
the ideal moderator because its nucleus is as light as
a neutron and, therefore, it can absorb the energy of
the neutron in a single direct collision. Hydrogen is
normally present in the form of water. The heavier the
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The Babcock & Wilcox Company
atom the less energy it absorbs per collision, and the
less slowing effect on the neutron. Carbon, in the form
of graphite, is about the heaviest atom that can be
used practically as a moderator. Carbon has the additional advantage of absorbing very few neutrons, even
less than hydrogen. Other low weight atoms can be
used, but they are less practical because of excess
neutron absorption or high material cost. Because the
helium nucleus absorbs essentially no neutrons, it
would be an ideal moderator except that helium is a
gas at reactor operating temperatures. In this state it
would be impossible to provide the core with a sufficient number of atoms to be an effective moderator.
All thermal reactors contain some fast (high energy)
neutrons because only fast neutrons result from fission.
The amount of moderator provided determines the degree of thermalization (energy reduction) or the percentage of thermal neutrons present in the reactor. Perhaps the greatest advantage of the thermal reactor is
its compatibility with the water coolant. Water has
proven to be the most practical and economical coolant.
The low neutrons per fission available with natural uranium makes it difficult to design a natural uranium (0.71% U-235) reactor. However, it can be accomplished if all materials are of especially high purity and if discrete sections of fuel are placed in a heterogeneous array such that the neutrons can slow
down in the moderator and then re-enter the fuel
material as slow neutrons. Under these conditions,
there is a relative high probability of causing fission.
The normal moderators used in natural uranium re-
Fig. 11 PWR neutron moderator/coolant-fuel interactions.
actors are either graphite or deuterium oxide (heavy
water). The absorption cross-section of normal hydrogen makes it less desirable than the other moderators.
Also, minute quantities of any high neutron absorbers can prevent a chain reaction. Nevertheless, all
early reactors used natural uranium and many still
operate, notably the large plutonium producing reactors and the Canadian CANDU pressurized heavy
water reactors. (See Chapter 46.)
Physical description of nuclear
chain reactions4-7
To use fission as a continuous process for power production, it is necessary to initiate and maintain a fission chain reaction at a controlled rate or level which
can be varied with power demand. Obtaining a steadystate chain reaction requires the availability of more
than one neutron for each fission produced because
non-fission reactions absorb some neutrons and others leak from the reactor. For a reactor as a whole, the
neutrons born in each instant of time constitute one
generation of neutrons. The term effective multiplication factor, keff, is defined as the ratio of the number of neutrons in one generation to that in the previous generation. With a multiplication factor of less
than one, the system is a decaying one and will never
be self-sustaining. With a multiplication factor greater
than one, a nuclear system produces more neutrons
than it uses, and power increases. For a steady-state
chain reaction, keff = 1.
The steady-state equation for neutron balance in
a chain reaction can also be written as:
Production = Absorption + Leakage
Fig. 10 Typical PWR fuel assembly and control components.
47-10
(8)
When this condition is obtained, the reactor has
gone critical meaning that the necessary amount of
neutron production has been achieved to balance the
leakage and the absorption of neutrons. The mass of
fissionable material required to achieve this condition
is called the critical mass.
Production, absorption and leakage all depend
heavily on interactions of neutrons with nuclei of the
various materials in the reactor. Production depends
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
primarily on those interactions with U-235 nuclei
which result in fission. Absorption depends on interactions of neutrons with any nuclei in the core that
result in absorption of neutrons with or without fission. Leakage depends on the scattering effect of collisions between neutrons, nuclei and other particles,
which results in transport of neutrons toward the
boundaries of the chain reacting system and ultimate
escape from the system.
Table 5 indicates that each fission of a U-235 atom
by a thermal neutron makes available an average of
2.43 neutrons. However, only 2.07 neutrons are produced per thermal neutron absorbed in U-235 as also
indicated in Table 5. The other 0.36 neutrons are absorbed in non-fission reactions. If natural uranium is
used, the number of neutrons produced per thermal
neutron absorbed is reduced to 1.34 because of the
neutron absorption in U-238. Most of this absorption
results in the ultimate production of fissionable Pu239. However, neutrons used in this manner are no
longer available to help maintain the chain reaction.
A neutron chain reaction is possible because each
fission event on the average produces more than one
neutron. If the process is controlled such that just one
of the neutrons produced from fission causes another
fission reaction then a steady state process is maintained and a constant power level is achieved. To best
understand the process, a general description of the
lifetime of a neutron follows. It must be realized that
for a power reactor the number of neutrons crossing
a 1 cm2 surface (neutron flux) near the center of the
reactor is on the order of 1013 neutrons/cm2/s. The lifetime of a neutron is on the order of 10-9 seconds. Therefore, this description is only representative of what
happens in an instant of time.
As described previously, a neutron produced by the
fission process has an average energy of about 2 MeV
and is termed a fast neutron. At this energy, elastic or
inelastic scattering reaction with the moderator, the
fuel or with the structural materials are most probable. However, about 2% of the fast neutrons cause a
fission in U-238 and produce an even higher number
of neutrons than produced from thermal fission.
In an elastic scattering reaction some of the neutron energy is transferred to the nucleus with which
it collides in the form of kinetic energy; this can cause
the nucleus to be displaced from its normal lattice position in the material. In an inelastic collision a compound nucleus is formed in an excited state and it
reduces its energy by releasing a lower energy neutron and a γ ray. Some of the original neutron’s energy is also deposited as the kinetic energy on the
nucleus. The net impact of the scattering reactions is
to cause the neutron to lose energy or slow down into
the energy range where resonance interactions with
various materials (especially U-238) can take place.
In the resonance range, neutrons will have a high
probability of being captured if their energy coincides
with any of the resonances associated with the uranium fuel or the fission products and will not be available to react with the U-235 to help sustain the chain
reaction. The resonance escape probability is the fraction of neutrons that escape capture while slowing
Steam 41 / Fundamentals of Nuclear Energy
down to the thermal energy range. The term resonance
escape refers particularly to U-238 because in the intermediate range of neutron energy there are several
resonance peaks of absorption cross-section for this isotope. These resonances are useful in the production of
plutonium; however, to maintain criticality in a thermal reactor, sufficient neutrons must escape absorption
in the resonance region.
In contrast, collisions with hydrogen atoms in the
moderator can slow down the neutron very rapidly,
and therefore the resonance escape probability is high
for water moderated systems. Once past the resonance
range the neutron is said to become thermalized and
becomes part of a Maxwellian energy distribution with
an average energy of about 0.2 eV. As the fission crosssections for U-235 and Pu-239 are the highest in the
thermal energy range, most fission reactions take
place in this range.
The probability of having a fission reaction is referred to as the thermal utilization and is the ratio of
the fission cross-section to the absorption cross-section
(capture plus fission) averaged over the moderator
plus the fuel and structural materials.
The other mechanism for loss of neutrons is leakage from the system. This is dependent on the size of
the system and the length of the path neutrons travel
between source and capture. For a thermal reactor this
length is approximately 2.95 in. (75 mm). Today’s
power reactors are on the order of 13.1 ft (4 m) in diameter and therefore only neutrons born in the fuel
assemblies on the periphery of the core have a significant probability of being lost from the system.
Control of the chain reaction
More than 99% of neutrons produced in fission are
prompt neutrons; that is, they are produced almost
instantaneously. About 0.73%, in the case of U-235,
are released by the decay of fission products rather
than directly from fission. The average half life for
these delayed neutrons from fissioning of U-235 is
about 13 seconds. This provides time for the reactor
operator to respond to small changes in either power
demand by the system or reactor system parameters.
The chain reaction can be regulated by placing materials with high neutron absorption capability in the
reactor and providing a means of varying their
amounts. These materials tend to stop the chain reaction and include boron, cadmium-silver-indium, hafnium and gadolinium. One or more of these materials
usually goes into the reactor in the form of control rods
that can be withdrawn to start up the reactor or to increase
power level and reinserted to reduce power or to shut down
the unit. To assure accurate control of power, at least some
of the rods must be capable of fine regulation.
Reactivity
The first step in establishing a chain reaction is to
bring the reactor to critical condition at essentially no
thermal power or zero power level. The reactor power
is gradually increased up to the desired level by the
removal of a control material and maintained there.
The objective in each step of this procedure is to obtain and hold a constant value of keff = 1.0. In view of
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The Babcock & Wilcox Company
the changes that continually occur in a nuclear system, it is never possible to keep keff = 1.0 for more than
a short period of time without adjustments to compensate for variations. Operating a reactor at any constant power level at an effective multiplication factor
of unity corresponds to steering a ship on a compass
course. It takes a continual effort, either automatic or
manual, to hold the ship on the exact course.
If a reactor operates at a specific power level with
keff = 1.0, and if anything changes to increase or decrease the multiplication factor, a reactivity change is
said to have occurred. It may be of positive or negative change depending upon the direction of change
in keff. Reactivity, represented by the symbol ρ, is defined as the ratio:
ρ = ( keff − 1) / keff
(9)
Reactivity has been given units of dollars ($) and
cents (¢) or inhours. It is usually expressed in the
units of pcm (per cent milli) which corresponds to a ρ
of 1 × 10-5. As will be shown, most processes in the reactor, except for control rod insertion, generate reactivities of 1 to 10 pcm which constitute a very small
change from a keff of 1.
Calculation of reactor physics
parameters4-7
The calculation of a chain reaction (or the design
of a nuclear reactor) requires solution of the steadystate equation:
Production = Absorption + Leakage
or its counterpart for nonsteady-state (transient) conditions:
Production − Absorption − Leakage = dn / dt (10)
where dn/dt is the variation of the neutron density
with time.
The production rate is evaluated as:
Production = υ Σ f nv
(11)
where
υ
Σf
n
v
=
=
=
=
neutrons per fission
macroscopic fission cross-sections, cm-1
neutron density, neutrons/cm3
neutron velocity, cm/s
If the neutron flux is defined as the product of the neutron density and neutron velocity, then the production rate can be defined as:
Production = υ Σ f φ
(12)
where
φ = nv = neutron flux
Similarly, the absorption rate is defined as:
Absorption = Σ a φ
47-12
(13)
where
Σa = macroscopic absorption cross-section, cm-1
Leakage is a complicated function of the gradients
in the neutron flux at boundaries of the region under
consideration.
In performing reactor calculations, the core is divided into discrete spatial regions or nodes, and the
continuous neutron energy range is divided into a
number of groups. The above equations then become
a coupled set of partial differential equations that are
solved in both the space and energy domains to find
the neutron flux and reaction rates in each node.
In the design of the early reactors, most calculations
of reactor physics parameters were done by hand using homogeneous models of the core components. Neutron cross-sections were obtained from experimental
plots of total, absorption, scattering and fission crosssections. Critical experiments were performed mocking up the fuel designs and modeling both the fuel and
control rods. From these experiments, modeling adjustments were developed to ensure high accuracy predictions of reactor performance parameters. As with
most other disciplines, the advent of more powerful
computers has permitted the designer to perform detailed calculations in both space and energy. The following sections describe some techniques that have
been used in calculations for commercial PWR fuel
cycle design and licensing.
Cross-sections
Basic neutron and gamma cross-sections are compiled and verified as part of the industry effort to maintain the cross-section libraries. These libraries provide
the basic data needed to calculate the cross-section of
each isotope as a function of incident neutron energy.
Typically two major energy groups, each containing
subgroups, are used by the designer. The first, the fast
and epithermal group, spans energies from 1.85 eV
to 20 MeV and is composed of 40 or more subgroups.
The second, the thermal energy group, covers energies from 0.00001 eV to 1.85 eV and is composed of
50 or more subgroups. In the fast and epithermal energy range, only scattering reactions that decrease
neutron energy are used in the calculations. In the
thermal energy range, the neutron energies are in
thermal equilibrium with the moderator, and energy
can be imparted to the neutron during scattering collisions. Therefore, scattering reactions, which can increase or decrease neutron energy, are permitted in the
calculations for this group.
When designing a reactor core, specific cross-sections are calculated using the total multigroup crosssection set (40 epithermal plus 50 thermal groups) for
each material present. Each cell type in the fuel assembly can then be modeled (Fig. 12). This calculation determines the neutron flux distribution in each
energy group and cell. The resulting neutron flux is
then used to average the cross-sections over the two
major energy groups and over various regions of the
fuel assembly. A full core representation, indicating the
position of fuel assemblies and control components, is
shown in Fig. 13.
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
The important quantities that describe the reactor
core and its performance include critical boron concentration, core power generation distribution, control rod
reactivity worths, and the reactivity coefficients associated with changes in reactor conditions.
Critical boron concentration
There is sufficient U-235 in a commercial power
reactor to power the unit for 12 to 24 months before
refueling. Without additional absorbers present in the
system, the keff would be greater than 1. It is impractical to provide the absorption using control rods.
Therefore, for long-term control keff = 1 is maintained
by soluble boron in the moderator (boron dissolved in
water) and/or burnable absorbers. Burnable absorbers contain a limited concentration of absorber atoms
such that, as neutrons are absorbed, the effectiveness
of absorption decreases and essentially burns out with
time. Burnable absorbers may be in the fuel rods or
in fixed absorber rods that are placed in fuel assembly guide tubes. The boron concentration in the coolant can be near 1800 ppm at the beginning of a fuel
cycle. This concentration can decrease to near zero at
the end of the cycle, when a significant portion of the
Fig. 13 Cross-sectional computer modeling of PWR core.
uranium is depleted and fission products have built
up. The critical boron concentration is the boron level
required to maintain steady-state reactor power levels. The burnable absorber limits the amount of
soluble boron that is used at the beginning of the cycle.
Power distribution
The primary factor governing acceptable reactor
operation is the energy production rate at every point
in each fuel rod. If the rate is too high, the fuel can
melt and cause rod failure. Excessive energy rates can
also cause coolant steaming, which results in poor heat
transfer and can lead to cladding burnout.
The energy production rate, or power, at each fuel
rod location is referred to as the core power distribution. This has typically been calculated by forming a
three-dimensional model of the reactor and representing each fuel assembly as a homogenized region over
an axial interval. A more recent method for power calculations involves reconstructing the power production in each fuel rod based on detailed fuel assembly
calculations. This method is more accurate because it
provides a better fuel assembly model that can include
water, burnable absorbers or guide tube control rods.
With proper fuel assembly placement, the core power
distribution can be optimized to limit power peaks in
fuel rod segments. As part of this primary analysis,
initial enrichments of the fuel and burnable absorbers can be determined, as well as the necessary soluble
boron concentration in the coolant over the cycle.
Fig. 12 Cross-sectional view of fuel assembly.
Steam 41 / Fundamentals of Nuclear Energy
Control rod worths
Control rods are used in a pressurized water reactor to change power levels and to shut down the reactor. Approximately 48 rods, divided into banks of 8,
are commonly used and core reactivity is changed by
sequentially moving the banks. The control rod banks
are grouped into shutdown and control (or regulating) banks. The shutdown banks provide negative reactivity to bring the reactor from hot to cold conditions.
During a shutdown, the core temperature decreases
47-13
The Babcock & Wilcox Company
and its reactivity increases. The shutdown control rod
banks counteract this increase. The controlling banks
are used in conjunction with variations in the soluble
boron concentration to take the reactor from hot zero
power to full power. These banks also provide the reactivity to handle rapid power changes. The negative reactivity caused by the buildup of xenon in the core following a shutdown is offset by a combination of control rod
removal and decreases in the coolant boron concentration.
The reactivity worth of a control rod is a measure
of its ability to reduce core reactivity. Control rod
worths are calculated by first calculating the core with
the control rod inserted to determine its keff. The core
is then similarly calculated with the rod withdrawn.
Control rod worth is defined as:
keff ( i ) − keff ( w )
keff ( w ) keff ( i )
(14)
where
keff(w) = multiplication factor, control rod withdrawn
keff(i) = multiplication factor, control rod inserted
Bank worths are similarly calculated.
Reactivity coefficients
Reactivity coefficients define the rate of core reactivity change associated with the rate of change in
reactor conditions. These coefficients indicate the relative sensitivity of the core operation to changes in operating parameters.
In determining a coefficient, the core is first modeled
with a given power and/or temperature distribution,
and keff is calculated. The reactor is then similarly modeled at a different power or temperature distribution.
The coefficient is defined as the reactivity change per
unit of power or temperature. Fig. 14 shows the impact
of various core parameter changes on core reactivity.
There are three basic reactivity coefficients that are
important to reactor operation: 1) the moderator temperature, 2) Doppler, and 3) power coefficients. The
moderator temperature coefficient is defined as the
change in reactivity associated with a change in moderator temperature. It includes the effects of moderator density changes and the changes in nuclear crosssections. The Doppler coefficient is defined as the
change in reactivity associated with changes in fuel
temperature that occurs primarily because of fuel
nuclides with large resonances. The power coefficient
is defined as the change in reactivity associated with
a change in power level. It is a combination of the
moderator and Doppler coefficients and is based on the
change in temperature as power changes.
When the coolant temperature increases, the associated density reduction normally decreases its moderating capability. A net decline in core reactivity, i.e.,
a negative moderator temperature coefficient, occurs.
Similarly, when the fuel temperature increases, core
reactivity decreases. Both mechanisms provide an inherent safety response for the system. However, if the
soluble boron concentration is too high, a positive
moderator temperature coefficient can occur, and core
47-14
Fig. 14 Core reactivity as a function of operating parameters.
reactivity could increase. For this reason boron concentration is limited to ensure a negative moderator
coefficient at full power.
Neutron detectors
When operating a nuclear chain reaction system,
neutron detectors are used to measure the intensity
of the neutron radiation (flux). This radiation is a direct indication of nuclear reaction intensity. Neutron
detectors can be counters or ionization chambers.
Counters, which detect neutrons by sensing the individual ionizations they produce, are most useful when
the neutron flux is low. Ionization chambers are more
useful at high neutron fluxes. They measure the electrical current that flows when neutrons ionize gas in
a chamber. These two types of detectors, placed on the
exterior of the pressure vessel, only measure neutrons
leaking from the reactor.
Two other types of detectors, a self-powered neutron detector and a miniature fission chamber, can be
used to measure the neutrons inside the instrument
tube of operating fuel assemblies. Self-powered detectors are usually arranged in strings and are positioned
to continuously measure the neutron reactions at up
to seven axial locations in the fuel assembly. The miniature fission chamber contains uranium, and fission
events are detected by the electronics. The fission chamber is moved into and out of the core on a periodic basis, normally monthly, and measures the neutron level
along the entire length of the fuel assembly.
Neutron source
During the start of the chain reaction, it is essential
that the operator monitor nuclear instrumentation that
is counting neutrons and not gamma rays. The mass
of fuel in the core is much greater than the critical mass
required to sustain a chain reaction. Control rods and
soluble boron dissolved in the reactor coolant keep the
core subcritical when no power output is required.
When the core is to be brought to criticality, control
rods are withdrawn to initiate the chain reaction.
However, if the control rods are withdrawn before a
measurable neutron flux is available, a reaction could
be initiated by a stray neutron and build up to a high
power level before the control rods could be reinserted
to maintain the desired core output.
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
To control the rate of buildup of the reaction, it is
necessary to have a neutron source present in the core
for startup. With a neutron source available, it is possible to measure neutron flux before moving control
rods and help ensure a safe reactor startup.
Several types of neutron sources are available. One
is an americium-beryllium-curium source rod. The radioactive isotopes americium and curium emit α particles
which react with the beryllium to produce neutrons.
Fast reactors
It is possible to design for a chain reaction to occur
predominantly with either fast (high energy) neutrons
or slow (thermal energy) neutrons. In fast reactors the
chain reaction is maintained primarily by fast neutrons.
Thermal reactors are those in which the chain reaction
occurs primarily from thermal neutrons. Today’s commercial water reactors are thermal reactors.
Fertile material such as U-238 can be used as a fuel
by first converting it to plutonium in a reactor. Fast
reactors and particularly fast breeder reactors accomplish this conversion most effectively. Liquid sodium,
which has essentially no moderating effect, is the coolant most often considered for fast breeders. Helium is
used as a coolant in high temperature gas-cooled reactor designs.
Conversion and breeding
Most important of the conversion reactions is the
capture of a neutron by a U-238 nucleus, resulting in
a nucleus of fissionable Pu-239:
U 238 + 0n1 → 92U 239 + 0γ 0
92
β
U
92
239
→
β
93
Np
23 min.
239
→
94
Pu239
2.3 d
The U-238 nucleus absorbs a neutron and becomes
U-239, which decays with a half life of 23 minutes,
into neptunium-239 (Np-239). Again this nuclide, with
a half life of 2.3 days, is transmuted to Pu-239 by β
decay. This is the nuclear process by which the most
useful isotope of plutonium is formed.
There are other reactions during operation which
form different isotopes of plutonium. Some of these isotopes, including Pu-241, are fissionable, and others,
including Pu-240, are converted to fissionable isotopes
by neutron absorption. These isotopes can not be separated economically from Pu-239, and therefore must be
taken into account when plutonium is used in a reactor.
The large commercial PWRs in the United States
operate on slightly enriched uranium fuel. These reactors convert U-238 to plutonium and produce about
50% as much plutonium as the U-235 consumed. A reactor is considered to be a converter when the amount
of fissionable material produced, e.g., plutonium, is less
than the amount of fissionable material consumed, e.g.,
U-235. A breeder reactor is one in which more fissionable material is produced than consumed.
By definition, a breeder reactor must have the
value of η (neutrons produced per neutron absorbed
in fissionable fuel, Table 5) greater than 2.0. One
neutron is required to maintain the chain reaction,
one or more for the breeding, and an additional fraction for absorption in nonfuel materials and leakage.
It is not possible to make a breeder reactor with natural uranium fuel, because η is less than 2.0. Table 5
shows that η does not greatly exceed 2.0 with any common fissionable isotopes for fissions produced by thermal neutrons. Consequently, it becomes difficult and
impractical to make a breeder with a thermal reactor.
Fortunately, at high neutron energies, η has a
greater value than at thermal energies, particularly
with Pu-239. For this reason, and because the absorption cross-sections of most materials are less than at
thermal energy, fast reactors breed plutonium more
effectively than thermal reactors. In addition, fast reactors operate best with plutonium fuel.
References
1. Evans, R.D., The Atomic Nucleus, R.E. Krieger Publishing Company, New York, New York, 1982.
2. Moe, H.J., et al., Radiation Safety Training Technician
Training Course, ANL-7291, Rev. 1, Argonne National
Laboratory, Argonne, Illinois, 1972.
3. Firestone, R.B., and Shirley, V.S., Eds., Table of Isotopes, Sixth Ed., Wiley-Interscience, Hobocan, New Jersey, 1998.
4. Lamarsh, J.R., Introduction to Nuclear Reactor
Theory, American Nuclear Society, LaGrange Park, Illinois, 2002.
5. Lamarsh, J.R. and Baratta, A., Introduction to Nuclear
Engineering, Third Ed., Prentice-Hall, Reading, Massachusetts, 2001.
6. Duderstadt, J., and Hamilton, L., Nuclear Reactor
Analysis, Wiley Publishers, Hobocan, New Jersey, 1976.
7. Bell, G., Nuclear Reactor Theory, R.E. Krieger Publishing Company, New York, New York, 1979.
Inconel is a trademark of the Special Metals Corporation group of
companies.
Steam 41 / Fundamentals of Nuclear Energy
47-15
The Babcock & Wilcox Company
Spent fuel storage at a nuclear power plant.
47-16
Steam 41 / Fundamentals of Nuclear Energy
The Babcock & Wilcox Company
Chapter 48
Nuclear Steam Generators
Nuclear steam generators provide the principal isolation barrier between the primary coolant system in
contact with the reactor core and the secondary power
cycle system, as discussed in Chapter 46. Nuclear
steam generators also serve two other functional requirements as they transfer energy from the primary
reactor coolant system to the secondary-side powerproducing system. The first functional requirement is
as the heat sink for the reactor core. The decrease of
primary coolant temperature through the steam generators is virtually the same as the increase of the primary coolant temperature through the reactor core.
Any difference is attributable to the fluid energy supplied by the reactor pumps, less any heat loss to ambient. The second functional requirement is to generate
the flow rate of steam from the feedwater supply at the
temperature, pressure and enthalpy conditions necessary to efficiently drive the steam turbine/electric generating system.
Each commercial pressurized water reactor (PWR)
power system combines two to four steam generators
with a nuclear reactor, pressurizer, and multiple primary coolant pumps to form the nuclear steam supply system (NSSS). The 69 operating PWR systems
in the United States (U.S.) use a total of 209 steam
generators. In addition, the 22 Canada Deuterium
Uranium (CANDU) pressurized heavy water reactor
(PHWR) systems installed in Canada employ a total
of 184 with as many as 12 steam generators per reactor, although 4 is more typical.
There are two fundamental steam generator designs used in commercial power systems in North
America. The Babcock & Wilcox Company (B&W)
once-through steam generator (OTSG) is a vertical
shell counterflow straight-tube heat exchanger design
which directly generates superheated steam as the
feedwater flows through the steam generator in a
Steam 41 / Nuclear Steam Generators
single pass. The other fundamental design used by a
number of suppliers and in the CANDU PHWR is a
recirculating steam generator (RSG) where only part
of the feedwater is converted to steam as the water
passes through the unit. After the steam is separated
from the water, the steam is sent to the turbine for
power generation while the water is returned to the
tube bundle for additional steam generation. These
steam generator designs use a vertical shell and an
inverted U-tube heat exchanger bundle, with steam
separation equipment located inside the top shell of
the RSG. With this design there are significant differences between suppliers and between different
models regarding materials of construction, thermal
hydraulic parameters, manufacturing techniques and
tube supports, all of which can significantly influence
performance.
A few other commercial PWR steam generator designs have been used, primarily in early units. The
first commercial U.S. power reactor at Shippingport,
Pennsylvania, used two different horizontal tube
bundle steam generator designs. NPD (Nuclear Power
Demonstration), the first CANDU power reactor, had
one horizontal U-tube, U-shell steam generator. Current Russian PWR plants use horizontal bundle steam
generators. No horizontal units are in commercial operation today in North America.
A variety of aging issues have been observed in the
existing fleet of PWR steam generators. These factors
have reduced the performance of some steam generators and thus effectively reduced their useful life. Intergranular attack, stress corrosion cracking, tube
denting, tube wall thinning, fretting wear damage,
foreign object damage and other issues have all had
an impact on unit performance because of the need
to plug significant numbers of steam generator tubes.1
In some cases, the degradation has reached a stage
48-1
The Babcock & Wilcox Company
where repair is no longer a viable option and steam
generator replacement is needed. These replacement
steam generators employ new technologies to address
the aging issues and to extend their useful life.
The balance of this chapter focuses on the fundamentals of steam generator design and on the design
improvements that are incorporated into the replacement OTSG and RSG units. Steam generator service
issues are discussed in Chapter 49, Nuclear Services
and Operations. Steam generator manufacturing is
discussed in Chapter 50.
tubes. The steam generator is a once-through design
in that the secondary fluid makes only one pass through
the unit. Because the OTSG produces superheated
steam, it does not require steam separators or dryers.
Referring to Figs. 1 and 3, the feedwater flows
downward within the annular region formed by the
lower shroud and the steam generator inside wall.
Near the bottom of the downcomer the feedwater
passes through the adjustable orifice plate, and then
turns inward toward the bottom of the bundle. The
fluid then flows upward around the tubes, passing
B&W once-through nuclear steam
generator (OTSG)
From Reactor
Reactor
Coolant Inlet
Design configuration and flow
The B&W once-through nuclear steam generator
(see Fig. 1) is a vertical, straight tube and shell,
counterflow heat exchanger, approximately 73 ft
(22.25 m) tall and 13 ft (3.96 m) in diameter, each
weighing approximately 570 tons (517 tm). Each steam
generator produces approximately 5.4 million lb/h
(680.4 kg/s) of steam at 925 psi (6.38 MPa) and 595F
(313C). This provides 60F (33C) of superheat. The
more than 15,000 Inconel 600 tubes in each steam
generator are positioned by broached tube support
plates (see Figs. 1 and 2) which are set within the bundle
shroud, which is in turn positioned to the vessel shell by
shroud pins. These plates are spaced to minimize tube
vibration. The distance between tubesheets is 52.1 ft
(15.9 m).
As shown in Figs. 1 and 3, primary coolant enters
at the top, flows downward through the tubes, and
exits at the bottom through two primary outlets. The
carbon steel shell surfaces exposed to the primary side
coolant are clad with stainless steel to avoid corrosion
in the primary side chemistry environment. The generator functions as a counterflow heat exchanger, i.e.,
the primary coolant flows downward within the tubes
and the secondary fluid flows upward around the
Tube
Support Plates
(Typ.)
Steam Outlet
To
Turbine
Aspirated Steam
to Downcomer
Feedwater Inlet
Header
From
Feedwater
System
Annulus Water
Level
Tube (Typ.)
Downcomer
Annulus
Broached Flow
Passages (3)
Bundle
Shroud
Tube Diameter
0.625 in.
Tubesheet (Typ.)
Tube Support
Lands (3)
Reactor Coolant
Outlet
To Reactor
Coolant Pumps
Primary Coolant Loop
Secondary Coolant Loop
Tube Pitch
0.875 in.
Fig. 2 OTSG broached support plate.
48-2
Fig. 3 Simplified OTSG flow circuits.
Steam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
through broached holes in the 15 tube support plates.
The steam is superheated prior to leaving the top of
the tubed region. It turns outward and downward,
flowing down the upper annular downcomer to the
steam outlet nozzles.
The feedwater is introduced into the annular downcomer through thirty-two 3 in. (76 mm) connections
with attached spray nozzles located 31.9 ft (9.7 m)
above the lower tubesheet. The exit flow from these
nozzles aspirates steam through a gap in the bundle
shroud, thereby allowing the feedwater to reach saturation temperature before entering the tube bundle.
This arrangement was designed to mitigate temperature mismatches between the shell and tube bundle.
Later integral economizer once-through steam generator (IEOTSG) designs introduced feedwater
through two nozzles lower in the shell where it directly
enters an integral economizer section in the lower
portion of the tube bundle region as shown in Fig. 4.
With this design, external feedwater heating is used
at some loads to adjust the feedwater temperature to
approximate tube bundle and shell temperatures,
thereby avoiding excessive temperature differentials
between shell and tube bundle and within the lower
tubesheet. This design is able to achieve more steam
output at a higher pressure to match the output of the
1300 MW 205 fuel bundle core. Most of the discussion
which follows relates to the standard OTSG design.
In the OTSG design, an adjustable orifice is located
near the bottom of the downcomer, just above the ports
into the tubed region. This device consists of a movable plate overlaying a fixed plate; both plates contain 24 identical flow passages. This adjustable orifice allows downcomer flow resistance to be adjusted
to optimize flow stability and downcomer water level.
These factors may change with operation as tube support plate deposits increase riser-side flow resistance.
Key information about the OTSG design is provided
in Table 1.
Modes of secondary-side heat transfer
The secondary-side feed entering an OTSG downcomer annulus is quickly brought to saturation temperature by contact heating between the feedwater
spray and aspirated steam drawn from the riser (in
an IEOTSG it is heated by convective heat transfer
as it begins to pass upward within the tube bundle).
The remaining heat transfer is by nucleate boiling,
film boiling and superheating. Nucleate boiling which
begins at the bundle entrance in the OTSG (and at
the top of the preheater zone in the IEOTSG) involves
the formation of discrete vapor bubbles on the tubes
and the release of these bubbles into the secondary
flow. This combination of phase change and bubble
motion creates very efficient heat transfer, in contrast
to film boiling and superheating which both involve
heat removal from the tube by steam convection and,
consequently, are much less efficient. (See Chapter 5.)
As a result, these latter modes occupy a large part of
the bundle surface to transfer a relatively small portion of the heat load. The ratio of steam mass to total
fluid mass (i.e., steam quality) increases as the secondary fluid flows upward. As the steam quality
Steam 41 / Nuclear Steam Generators
Fig. 4 Integral economizer once-through steam generator (IEOTSG).
48-3
The Babcock & Wilcox Company
Table 1
Once-Through Steam Generator (OTSG) Operating and Design Information
OTSG
Oconee (177)
Plant Information
Power level, MWt
Power level, MWe
No. steam generators
Steam Generator Design Conditions
Primary T (Hot), F (C)
Primary T (Cold) F (C)
Primary flow, lb/h (kg/s)
Primary operating pressure, psia (MPa)
Secondary steam temperature, F (C)
Secondary feedwater temperature, F (C)
Steam flow, lb/h (kg/s)
Secondary operating pressure, psia (MPa)
Steam Generator Design Data
No. tubes per generator
Tube OD, in. (mm)
Tube minimum wall thickness, in. (mm)
Tube material
Surface area, ft2 (m2 )
Tube pitch, in. (mm)
No. support plates
Support plate type
Support plate material
Integral economizer
reaches the high nineties, there is insufficient liquid
to wet the tubes and nucleate boiling gives way to film
boiling. Still farther up the generator where the moisture content of the fluid is depleted and the steam
begins to superheat, heat transfer is by forced convection of vapor. The primary and secondary fluid temperatures and the modes of secondary heat transfer
are indicated in Figs. 5 and 6. The secondary-side temperature remains at saturation through the nucleate
and film boiling regions. The counterflowing primary
fluid gradually cools as it flows through the steam generator. The drop in primary fluid temperature in the
upper areas of the unit is relatively slow due to the
less efficient heat transfer in the film boiling and superheater regions. In the lower regions of the unit, the
primary fluid temperature change is much more rapid
due to more efficient nucleate boiling heat transfer.
Instrumentation
The steam generator thermal performance measurements include fluid pressure, temperature, and
level. Shell temperatures are measured at five equally
spaced locations along the length of the generator.
These measurements are used to determine tube to
shell temperature differentials. A steam generator
downcomer temperature measurement indicates the
temperature of the incoming feed; this temperature
is used in the temperature compensation of level.
There are three ranges of steam generator level measurement: full, operate and startup. The operate range
begins 8.5 ft (2.59 m) above the lower tubesheet. It is
48-4
2568
846
2
604 (317.7)
554 (290.0)
65.66 x 106 (8273.16)
2200 (15.17)
595 (312.8)
460 (237.8)
5.4 x 106 (680.4)
925 (6.38)
15,531
0.625 (15.875)
0.034 (0.864)
Inconel 600
133,000 (12,356)
0.875 (22.225)
15
Broached
Carbon steel
No
graduated in percentage of full (operating) range, from
0% at 102 in. (2.6 m) above the lower tubesheet to 100%
at a height of 394 in. (10.0 m). Whereas the common
upper tap of the startup and operate range levels extends into the tubed region, their lower taps are in the
steam generator lower downcomer. Feed and steam system measurements also indicate steam generator status.
These include steam pressure and the pressure drop
across the feedwater control valves. The flow rate of main
feedwater is indicated in two ranges: startup to 15% of
full flow range, and operating range. The majority of
these steam generator measurements are supplied to the
plant computer and the integrated control system.
Recirculating steam generator (RSG)
Design configuration and flow
Recirculating steam generators are supplied by a
number of manufacturers worldwide as part of PWR
and PHWR (mainly CANDU) systems. Two, three or
four steam generators are supplied for each PWR system and 4 to 12 steam generators are supplied for each
CANDU system. They range in height from approximately 38 to 73 ft (11.6 to 22.3 m) weighing from approximately 50 to 790 tons (45 to 717 tm) each. See
Fig. 7 for selected comparisons of sample units.
Each RSG is a vertical shell, inverted U-tube heat
exchanger with steam-water separation equipment
located above the tube bundle inside the upper shell
(or steam drum). A cylindrical shroud or bundle wrapSteam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
620
(327)
600
(316)
Primary
Water
Temperature, F (C)
580
(304)
560
(293)
Secondary
Fluid
540
(282)
520
(271)
500
(260) 0
Fig. 5 Steam generator heat transfer for an OTSG.
per surrounds the tube bundle separating it from the
lower shell. This creates an annular region which
serves as the downcomer to return the recirculated
water from the steam separators to the tube bundle
inlet at the bottom of the unit. In a feed ring type
RSG, feedwater is introduced by a nozzle and header
to the top of the downcomer, and flows with the separator return flow down and into the tube bundle. In
a preheater type RSG, feed flow enters the steam gen-
Nucleate Boiling
20
Film
Boiling
40
60
Tube Length, % of Total
Weight (tons)
MW t per SG
Heat Transfer Area (ft2)
Number of Tubes
Height
Series 44
316
764
54,000
4,765
62 ft-11 in.
80
100
Fig. 6 Approximate primary and secondary temperature profiles at
full load for an OTSG.
erator through a nozzle and feedwater distribution
box to the baffled section at the cold leg outlet end of the
tube bundle where it is heated to saturation before joining with the hot leg riser flow within the tube bundle. A
typical RSG supplied by B&W to replace an original
equipment manufacture (OEM) unit is shown in Fig. 8.
Replacement Recirculating Steam Generators (RRSG)
CANDU 6
237
547
34,394
3,530
63 ft-5 in.
Superheat
Series 51
343
816
54,500
3,496
67 ft-7 in.
System 67
543
1355
93,707
8,523
62 ft-8 1/2 in.
Model D
398
857.5
79,800
6,633
68 ft-1 in.
CANDU
Darlington
368
660
52,000
4,663
72 ft-10 in.
Fig. 7 Relative sizes of recirculating steam generators (RSG).
Steam 41 / Nuclear Steam Generators
48-5
The Babcock & Wilcox Company
separators in the upper shell to send effectively moisture-free (<0.25% water) steam to the secondary-side
power cycle. Water leaving the steam separators is recirculated down the annulus where it mixes with the
feedwater before being returned to the bundle inlet
for further steam generation.
The natural recirculation within the RSG is driven
by the density difference between the higher density
water column in the downcomer annulus area and the
lower density steam-water mixture in the tube bundle.
The RSG recirculation rate is set by the balance between the pressure drop through the flow path (downcomer, tube bundle and steam separation equipment)
with the driving head created by the density differential (see Chapter 5). To minimize the potential
Steam Outlet
To Turbine
Upper Shell or
Steam Drum
Primary Steam
Separator (Typ.)
Water
Level
Secondary
Steam
Separator
(Typ.)
Recirculated
Separated
Return Water
Feedwater
Inlet Flow
Steam/Water
Mixture
Feedwater
Header
Fig. 8 B&W replacement recirculating steam generator.
A simplified schematic shown in Fig. 9 provides an
overview of the flow configuration and the major design features of a typical feed ring type RSG. The hot
primary coolant enters a portion of the vessel primary
head which is separated into two plenums by a divider
plate. The primary coolant flows through the inside
of the U-tube bundle and exits the steam generator
through the primary head outlet plenum. In most
RSG designs, the U-tubes make a continuous 180
degree bend at the top of the tube bundle; one major
OEM design uses two 90 degree bends separated by
a horizontal section at the top of the tube bundle.
In the configuration shown, secondary-side feedwater enters the upper shell via a feed ring and is
mixed with water returning from the steam-water
separation equipment. The water flows down the
downcomer annulus between the shroud and the shell
to the tubesheet where it enters the tube bundle. The
secondary-side water is heated as it passes up through
the tube bundle generating steam through nucleate
boiling heat transfer, creating a two-phase flow. Steam
of 10 to 40% quality, depending on hot-side or coldside U-tube bundle location, exits the tube bundle and
is distributed to the primary and secondary steam
48-6
U-Bend Restraints
or Supports (Typ.)
Downcomer
Annulus
Tube Supports
(Typ.)
U-Tube
(Typ.)
Shroud
or Wrapper
Lower Shell
Tubesheet
Blowdown Outlet
Primary Head
Reactor Coolant
Outlet
Reactor Coolant
Inlet
Divider
Plate
Primary Coolant Loop
Secondary Coolant Loop
Fig. 9 Simplified recirculating steam generator (RSG) flow circuits.
Steam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
Additional tube supports or restraining systems are
required in the upper bundle U-bend area (see Fig. 14).
These maintain the position of the tubes and prevent
excessive flow-induced vibration as the high velocity
steam-water mixture flows out through the U-bends.
Key information on the various RSG designs is provided in Table 2.
Steam-water separation
High efficiency steam-water separation is a vital
function in all recirculating steam generators, as discussed in Chapter 5. This is particularly true in
nuclear RSGs. Low moisture carryover in the steam
improves turbine efficiency and total power output,
and minimizes the carryover of any contaminants into
the turbine. The traditional limit for nuclear RSG
moisture carryover at full power is less than 0.25%
moisture by weight, while more recent requirements
have been for 0.10% or less.
Low steam carryunder (steam entrainment) within
the downcomer return water maximizes the downcomer annulus driving head, thereby maximizing the
internal circulation rate. Low separator pressure drop
also increases the natural circulation rate through the
bundle by lowering the overall flow resistance.
The B&W steam separation system combines curved
arm primary (CAP) separators (see Chapter 5, Fig. 23)
with cyclone secondary separators (see Fig. 15) to accommodate the necessary steam throughput.2 The actual moisture carryover as measured at steam generator startup has been well below 0.10% moisture by
weight in all B&W replacement RSGs.
Centerline
buildup of any contaminants, a blowdown system is
located in the bottom of the RSG near or as part of
the tubesheet to remove a controlled quantity of water inventory. Blowdown is not very efficient at removal
of many feedwater contaminants but it is the only
way, other than moisture carryover, for feedwater contaminants to be removed from the steam generator during operation. Contaminants remaining in the steam
generator can deposit onto the tubes and to a lesser degree build up on the tubesheet and tube supports.
Preheater (integral economizer) designs are also
used for some RSGs. Here the feedwater is introduced
near the tube bundle cold leg outlet to increase overall thermal efficiency. Several options have been used
for this integral economizer section: counterflow, axial
flow and split flow (cold leg side of the tube bundle).
Simplified schematics are shown in Fig. 10.
Horizontal tube supports (support plates and/or lattice bar grids) are provided at various elevations along
the vertical straight tube bundle section (see Fig. 8).
A variety of supports have been used in the various
original equipment designs (see Fig. 11). The tube supports provide lateral support to the tubes during steam
generator manufacturing, shipment and operation
and protect against seismic loads. They are spaced at
intervals to minimize the likelihood of flow-induced vibration and are designed to provide adequate open
area for the recirculating flow. Many of these designs
were prone to accelerated corrosion, particularly if made
of carbon steel (see Reference 1). B&W’s advanced lattice grid tube supports (Figs. 12 and 13) have addressed
many of these issues.
Shell
Baffles (Typ.)
Feedwater
Inlet
Nozzle
Feedwater
Inlet
Nozzle
Feedwater
Inlet
Nozzle
Tube
Supports
Feedwater
Distribution
Box
Tubesheet
Tubesheet
(a) Baffled Counterflow Type
Tubesheet
(b) Split Flow Type
(c) Axial Counterflow Type
Fig. 10 Integral economizer designs used in RSGs.
Steam 41 / Nuclear Steam Generators
48-7
The Babcock & Wilcox Company
Tube
Low Bars
Tubes
Circulation
Hole
Support
Plate
Plate
Tube
High
Bar
High
Bar
(a) Drilled Hole Design
Tube
Flow
Flow
Low Bars
Fig. 13 B&W lattice grid tube support design details.
(b) Egg Crate Design
(c) Quatrefoil Broached Design
Fig. 11 Original RSG support plate designs by various manufacturers.
Circulation and hydraulic performance
Detailed thermal-hydraulic design analyses are conducted on all RSG designs and include, among others:
1. heat transfer analysis on a local basis,
2. three-dimensional analysis of flow (velocities,
pressures, qualities, etc.),
3. dynamic response of the steam generator to normal and abnormal transients,
4. potential deposit accumulation on the secondary
side of the RSG,
5. recirculation rate within the tube bundle, and
6. flow-induced loadings on internal components.
ticularly important parameter. Higher circulation rates
reduce the overall steam voidage in the tube bundle
and increase the local velocities. Reduced voidage improves the steam drum water stability during transients. A higher circulation ratio also increases the
margin for stability, and increases the margin for tube
surface dryout and for critical heat flux in the tube
support areas. It also reduces low velocity areas, especially near the tubesheet where deposits may accumulate.
Circulation rate is increased by low flow path pressure drop at the tube supports and the steam separators, and by low steam carryunder from the steamwater separators to the downcomer. High circulation
Clamping Bars
Arch Bars
Tubes (Typ.)
Tie Tubes
The circulation ratio (total flow rising through the
tube bundle divided by the exiting steam flow) is a par-
Tube In Plane
Direction
Tube Out of Plane
Direction
Fig. 12 B&W lattice grid tube support assembly.
48-8
Flat Bar
U-Bend
Restraints
Fig. 14 B&W flat bar U-bend restraint system.
Steam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
Table 2
Selected OEM Recirculating Steam Generator Operating and Design Information
(Reference 3, Supplemented)
RSG Series Model or Type
Plant Information
Plant capacity
Plant capacity
No. steam generators
MWt
MWe
System 67
System 80
2,700
865
2
3,817
1,270
2
Steam Generator Operating Conditions (per steam generator)
Primary T (Hot)
F
594.0
621.2
Primary T (Cold)
F
548.0
564.5
Primary flow
106 lb/h
74.00
82.00
Primary operating
pressure
psig
2,235
2,235
Secondary steam temp. F
530.0
554.6
Secondary feed temp. F
435.0
450.0
Steam flow
106 lb/h
5.90
8.59
Secondary operating
pressure
psig
865
1,070
Steam Generator Design Data (per steam generator)
No. tubes
8,519
11,000
Tube OD
in.
0.750
0.750
Tube wall
in.
0.048
0.042
Tube material
Inconel 600 Inconel 600
Surface area (OD)
ft2
90,675
124,800
Tube pitch
in.
1.000
1.000
Tube pitch
Triangular
Triangular
No. of support plates
6
8
Support type
Egg crate
Egg crate
Support material
Carbon
Carbon
steel
steel
Integral economizer
No
Yes
Series 44
Series 51
Model F
Model
D2/D3
2/3/4
2/3/4
3,425
1,150
4
603.9
543.1
32.95
599.1
535.5
34.1
620.0
557.0
37.60
619.0
558.0
35.10
2,235
511.7
425.0
3.30
2,235
513.1
432.0
3.58
2,235
541.0
440.0
3.95
2,235
546.5
740
750
955
1,000
1,520/2,200/3,000 1,650/2,660/3,300
470/700/1,000
560/833/1,100
3,260
0.875
0.050
Inconel 600
44,430
1.234
Square
6
Drilled
Carbon
steel
No
2,800/3,411
930/1,180
3/4
3,388
5,626
4,674
0.875
0.6875
0.750
0.050
0.040
0.043
Inconel 600 Inconel 600 Inconel 600
51,000
55,000
48,300
1.280
0.980
1.0625
Square
Square
Square
7
7
8
Drilled Quatrefoil Quatrefoil
Carbon
Ferritic
Carbon
steel
Stainless
steel
steel
No
No
Yes
Note: SI Conversions: C = (F−32) x 5/9; mm = in. x 25.4; m2 = ft2 x 0.09290; kg/s = lb/h x 0.000126; MPa = psi x 0.006895
ratios (up to 6.0) have been a significant feature in
B&W designs.
Replacement steam generators
Of the 69 operating PWR nuclear power plants in
the U.S., 56 had 163 individual steam generators replaced or awarded by 2005. Additional RSG replacements are anticipated as the remaining installations age.
The previously unanticipated aging issues experienced by nuclear steam generators generally involve
complex interactions between the materials of construction, water chemistry operation and contaminant
ingress, tube support arrangements, fabrication techniques, and local thermal-hydraulic conditions. These
only became apparent with long-term operation of the
equipment. Examples of this damage include:
1. intergranular attack,
2. stress corrosion cracking (SCC),
3. primary- and secondary-side cracking at the
tubesheet expansion transitions,
4. primary-side cracking at the U-bends,
Steam 41 / Nuclear Steam Generators
5. wall thinning/wastage/pitting involving sludge
near the tubesheets,
6. denting or permanent deformation of the tubes at
the carbon steel support plates due to corrosion
product buildup and volume expansion,
7. fretting wear,
8. tube circumferential cracking due to high frequency fatigue,
9. erosion-corrosion in higher velocity regions, and
10. foreign object damage.
In many cases, the affected tubes are plugged when
significant leakage is detected or when degradation
reaches a critical level. However, with time the overall bundle degradation can reach a stage where repair is no longer a viable option and steam generator
replacement is needed. References 1 and 3 explore this
in more depth.
B&W’s advanced series replacement steam generators
are designed with the most current technology available
to overcome the steam generator issues while still meeting or exceeding all of the steam generator functional
requirements. Replacement units must fit within the
48-9
The Babcock & Wilcox Company
Cyclone
Secondary
Separators
Steam
Outlet
Curved Arm
Primary
Separators
Cyclone
Secondary
Separator
Curved
Arm
Primary
Separator
Return
Cylinder
Riser
Primary
Separator
Deck
Recirculating
Water
Return
Steam/Water
Inlet
Fig. 15 Primary and secondary RSG steam separator system.
established plant configuration, and must meet all performance and operational requirements. In addition,
these replacement units must be redesigned to minimize
or eliminate the original problematic degradation.
Replacement steam generators are also designed to
support extension of power plant operating life. In
many cases, the plants with replacement units have
received extended licenses to operate 20 years beyond
the original plant life span and may eventually operate even further. To achieve these objectives, while
combating the causes of component degradation, emphasis is placed on upgrading component materials,
introducing advanced design features and manufacturing methods, and incorporating the latest technical developments.
Replacement recirculating steam
generators (RRSG)
The contract for the first replacement nuclear steam
generator supplied by B&W was awarded in 1988, for
Northeast Utilities’ Millstone Unit 2 nuclear power
plant. Since then and through 2004, B&W has designed and manufactured a total of 6 once-through
and 34 replacement recirculating nuclear steam generator units for the U.S. market.
All of the RSG units are similar but are adapted to
the requirements of the specific power plant. Significant features are shown in Fig. 8. While the basic envelope of each RSG type remained the same as the respective OEM equipment, major changes were made
to the tubing and tube support materials. Design features were included to enhance reliability and facilitate
in-service inspection and maintenance (see Table 3).
Tubing material The majority of critical degradation mechanisms involved the tube bundle and the
tube supports; therefore, the selection and quality of
the tubing are the most important factors in steam generator design. The original equipment tube material
was mill-annealed (MA) Alloy 600 (Inconel: Ni-Cr-Fe
alloy). However, experience has shown this material
to be susceptible to stress corrosion cracking (SCC), especially in areas of cold work such as at the original
tubesheet roll expansion transition regions (see Fig.
16) and in areas of harsh environments such as the
top of the tubesheet. The replacement units feature
Table 3
Replacement Recirculating Steam Generator Design Features
48-10
Features
Original Design
Replacement Design
Improvement
Tube material
Alloy 600MA
Alloy 690TT
Corrosion resistance
Surface area
Nominal
Increase
Accommodates reduced
conductivity and elimination
of preheater
Provides power uprate capacity
and/or steam pressure increase
Tube support plate material
Carbon steel
Type 410S
Corrosion resistance
Tube support plate design
Drilled/broached
Lattice bars
Improves flow area
Minimizes crevices
Divider plate
Floating
All welded
Minimizes bundle bypass
Drum internals
Original
Upgraded by test
and field experience
Improves water inventory and
performance characteristics
Steam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
nal in size, dimensions, and pressure rating. The heat
transfer surface (external surface of the tubing) is
sized to match the function of the original surface and/
or any upgrades required by the plant owner.
In defining the heat transfer surface, certain effects
must be taken into account including:
Tube
Tubesheet
Tube to
Tubesheet
Transition
Fig. 16 Original equipment tube to tubesheet expansion transition.
Alloy 690TT (thermally treated) tubing which has a
high resistance to corrosion. This replacement tubing is
particularly resistant to SCC due to its higher chrome
content and thermal treatment.
Tubing today is manufactured to very stringent
specifications, resulting in a very high quality product. The new metallurgical treatment offers a material grain structure that is much more resistant to
cracking. In addition, these tubes are metallurgically
very clean and have a minimum of defects and inclusions. As a result, these tubes have very low eddy current noise, thus improving the resolution of in-service
eddy current testing (ECT) inspections. Any small,
tight cracks or other defects that may occur will be
found more easily.
General design features The first requirement in the
design of any replacement steam generator is the selection of a general architecture which will, as closely
as possible, match that of the original unit. This is
necessary to comply with Nuclear Regulatory Commission (NRC) requirements and ensure licensing. The
pressure vessel envelope is designed to match the origi-
Steam 41 / Nuclear Steam Generators
1. the net effect of the reduced thermal conductivity
of A690TT relative to A600MA,
2. any tube wall thickness and/or diameter change,
3. preheater deletion if applicable, which requires the
addition of a large amount of surface, and
4. any change of rated performance such as power
increase, steam pressure increase or primary inlet temperature reduction.
Having defined the vessel envelope and heat transfer surface requirements, the design is refined to address other thermal-hydraulic parameters such as
primary-side flow resistance (which must closely
match the original) and the range of secondary-side
thermal-hydraulic issues described above. Finally,
structural and reliability design features are introduced to ensure prolonged and reliable operation.
Tube supports The original equipment incorporated
a variety of tube supports including flat plates with
drilled flow holes, broached plates, and lattice grids
(see Fig. 11). These have been replaced with a refined
lattice grid arrangement made of intersecting flat bars
of Type 410S stainless steel. (See Figs. 12 and 13.)
This design is based on the lattice bar arrangement
used in the later CANDU steam generator designs.
(See also Chapter 50.) These lattice bar tube supports
provide anti-vibration restraint for the straight leg
portions of the tubes and provide lateral support for
the entire bundle. Lateral loads include handling and
shipping loads plus seismic and other accident loads.
Normally the lateral in-service loads from the U-bends
are taken through the uppermost lattice grid tube support; these can be well in excess of handling loads.
The U-bends are supported against flow-induced
vibration (FIV) and mechanical loads by flat bar Ubend supports (see Fig. 14). FIV restraint is provided
by positioning sufficient flat bar supports within the
U-bends to avoid excessive tube response to turbulent
or fluid-elastic instability flow excitation. Support
against mechanical loads, including seismic, is basically provided by coordination and transfer of the Ubend swaying forces to the uppermost lattice, designed
to sustain the lateral load of the overhung U-bends.
The flat bar configurations provide an open flow arrangement and line contact tube support to ensure free
flowing recirculation conditions and to avoid tube-conforming crevices or trapped spaces that may accumulate vapor and deposits, which may encourage corrosion.
The Type 410S material selected for lattice bars and
U-bend supports is a low carbon version of Type 410.
This material has excellent strength in its quenched
and tempered condition, is resistant to tube fretting,
and has good resistance to local and general corrosion.
Unlike carbon steel, any oxide that does form by corrosion has a volume not greater than that of the base
metal. This avoids tube and support plate degradation caused by voluminous rapid linear oxide growth,
48-11
The Babcock & Wilcox Company
usually referred to as denting corrosion, that plagued
many earlier carbon steel support plates.
Welded divider plate All recirculating steam generators feature a flat plate in the primary head to separate the incoming primary flow from the primary outlet flow. In certain original designs, this was essentially a floating design where the divider plate was
located by engaging seat bars that were welded to the
head and tubesheet surfaces. Because of gaps around
the plate, there was some primary flow bypass from
the inlet to the outlet side of the primary head. Replacement steam generators typically have a fully welded
divider plate that is joined around the full perimeter
to the primary head and tubesheet, as shown in Fig.
17. This was not done in some original designs due to
concerns about thermal stresses in the combined head/
plate/tubesheet structure. However, three-dimensional
finite element elastic-plastic analysis now allows a more
accurate assessment of the operational thermal and mechanical loads and shows that the all-welded arrangement
meets all design and pressure vessel code requirements.
Steam drum internals The steam drum internals for
all B&W replacement RSGs incorporate the high effi-
Tubes
Final
Weld
Divider
Plate
Primary
Inlet Nozzle
Fig. 17 Fully welded primary head divider plate.
Fig. 18 Replacement recirculating steam generators can be supplied that use the original upper shell, which remains in containment.
48-12
Steam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
ciency CAP separators and cyclone secondary separators as described earlier. The drum internals have
been replaced for all replacement units whether the
steam drum pressure vessel itself was replaced or retained. In many cases the drum was too large to remove, so new separators were installed into the existing drums within the reactor building. Such replacement RSGs are shipped without the upper shell, or
steam drum (see Fig. 18).
Replacement once-through steam
generators (ROTSG)
The Oconee nuclear plant units in the U.S. were
the original lead units of the B&W PWR program.
Over the years, the once-through steam generators
performed very well, but like the recirculating steam
generators, they eventually showed corrosion problems with their Alloy 600 tubes. Steam generators for
all three Oconee units (two steam generators per unit)
have been replaced.4 (See Fig. 19.)
A major difference between the OTSGs and the recirculating steam generators is that since there is no
steam drum there is no large secondary water inventory in the once-through units. Because of such thermal-hydraulic characteristics and because the straight
tubes and the straight shell are bound together at both
ends, the design of these steam generators is very
tightly integrated. Thermal characteristics of heat-up
and cool-down and the thermal hydraulics of the downcomer flow, feedwater heating, level control, etc. are
highly interdependent with each other and with the
structural and hydraulic configuration of the equipment. The replacement units have been designed to retain, as closely as possible, the thermal and performance
characteristics of the original units so that there is as little
change as possible to this carefully integrated balance.
As with the recirculating design, the tubing material for the ROTSGs has been changed from A600MA
to A690TT. The tube support configuration of the original OTSGs introduced the industry to the broached
plate design. The broached plate design has been retained for the replacement units but with Type 410S
material. In addition to the broaching, the flow passages use a patented hourglass configuration and the
surface finish is enhanced by an electropolishing process. This minimizes deposition and reduces the potential for tube fretting and any support contact surface anomalies.
The original OTSGs were constructed with a radial
open lane through the bundle to allow inspection of
the bundle inner region. Long-term operation has
shown this to be an undesirable feature. Secondaryside flow non-uniformity led to thermal tensile stress,
localized high velocities, and localized corrosive environments, all of which contributed to fatigue in tubes
adjacent to the lane.
In designing the steam generator shell, the original envelope is retained but the material is replaced
with high strength steel to minimize weight, and with
forgings to reduce the number of longitudinal welds.
The original vessel cylindrical support skirt is replaced
with a conical base to improve access for pipe work and
Steam 41 / Nuclear Steam Generators
Fig. 19 Replacement once-through steam generator.
48-13
The Babcock & Wilcox Company
Table 4
Replacement Once-Through Steam Generator Design Features
Features
Original Design
Replacement Design
Improvement
Tube material
Alloy−600MA
Alloy−690TT
Corrosion resistance
Pressure vessel
Carbon steel
High strength steel
Reduces weight
Vessel support skirt
Cylindrical
Conical
Improves maintenance access
Tube support plate
Broached
Broached with added
hour-glassing, enhanced
surface finish, 410S material
Mitigates deposits
Corrosion resistance
Reduces pressure drop
Tube bundle layout
Tube-free lane
Open lane eliminated
Improves flow distribution
for manway access during manufacture, installation
and service (see Fig. 19).
Other design features have been added such as feedwater header configuration improvements, addition of
more inspection ports, and seal welding of infrequently
used inspection ports. A summary of the major changes
to the original design is given in Table 4.
Further development
Research and development (R&D) work defines the
technology needs and establishes internal or external
programs to achieve those objectives. The work includes development of new design configurations and
features; development of manufacturing processes
including specialized welding, cleaning, tube expansion and surface conditioning procedures; development of processes, tooling and robotics for field service
and inspection processes including water lancing, visual inspection, cleaning and tube inspection; thermalhydraulic, stress and flow-induced vibration design
procedures; and design elements including steam
separators and tube support structures. This R&D
work includes the materials, chemistry and corrosion
technology to support component and pressure vessel
design and tube longevity. A summary of B&W’s R&D
activities is shown in Table 5.
Table 5
Major Replacement Recirculating
Steam Generator Development Activities
Materials
Cooperative efforts with
international R&D agencies to
evaluate new materials such as
Alloy 690TT
Weld metals
Corrosion resistance and mechanical
properties of Alloy 52 and Alloy 152
and other materials
Water chemistry
Continued involvement with
industry to establish operating
guidelines
Research on leading issues: tubing
SCC, feedwater additives, and flow
accelerated corrosion of SG internals
Thermal-hydraulic
design
3-D design codes and CFD
analysis
Flow tests of various internal
geometries
Mechanical design
Mechanical tests of tube supports,
gasketed closures, tube-to-tubesheet
joint
Vibration
Cooperation with external labs to
develop tube supports and internal
support structures
Reduced U-bend tube/support
clearance to reduce wear and
fretting
Manufacturing
Development of pressure vessel
welding and tube-to-tubesheet
welding techniques
Steam separation
Testing of primary and secondary
separators to improve overall
performance
Maintenance
services
Testing of new ECT, UT, and video
probes for tube examination
Tube plugging, sleeving, and
waterlancing equipment
development
Tubing
Passivating tube inner surfaces to
reduce primary radiological
activation
References
1. Steam Generator Reference Book, Electric Power Research Institute, Palo Alto, California, 1985.
2. Parkinson, J. R., et al., “Steam Separation Uprate by
Elimination of Capacity-Limiting Mechanisms,” American
Society of Mechanical Engineers (ASME) Winter Annual
Meeting, Miami Beach, Florida, November 17-22, 1985.
3. Cohn, P. Ed., The ASME Handbook on Water in Thermal Power Systems, American Society of Mechanical Engineers, New York, New York, 1989.
4. Klarner, R., Boyd, J.T., and Keck, M., “Once Through
Times Two,” Nuclear Engineering International, April, 2004.
Inconel is a trademark of the Special Metals Corporation group of
companies.
48-14
Steam 41 / Nuclear Steam Generators
The Babcock & Wilcox Company
Bibliography
Kakaç, S., Ed., Boilers, Evaporators and Condensers,
Wiley-Interscience, New York, New York, 1991. See Chapter 9, “Nuclear Steam Generators and Waste Heat Boilers” by Collier, J.G.
Klarner, R., Albert, J., and Schneider, W.G., “SG Replacement, Operation and Support,” PLIM & PLEX 2003 Conference, New Orleans, Louisiana, October 13-14, 2003.
Steam 41 / Nuclear Steam Generators
Klarner, R., Fluit, S., and Schneider, W. G., “Replacement
Steam Generators for Calvert Cliffs, Oconee and Future
Replacement Designs,” Fourth CNS International Steam
Generator Conference, Toronto, Canada, May, 2002.
Schneider, W. G., Klarner, R. and Smith, J., “Replacement
Steam Generators,” Nuclear Engineering International,
January, 2002.
Tong, L. S. and Weisman, J., Thermal Analysis of Pressurized Water Reactors, Third Ed., American Nuclear
Society, La Grange Park, Illinois, 1996.
48-15
The Babcock & Wilcox Company
Fig. 1 B&W nuclear once-through steam generator (OTSG).
48-16
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The Babcock & Wilcox Company
Chapter 49
Nuclear Services and Operations
Nuclear service activity includes all life management planning, inspection, analysis, assessment,
maintenance and repair of equipment as required to
support the plant equipment throughout its operating life. This life management activity must achieve
continued high reliability and high availability for the
entire life of the plant. Because most routine nuclear
plant maintenance is done during scheduled refueling outages and because of the extended time between
such outages (12 to 24 months), successful long range
outage planning is essential. Ultimately, all of this
planning effort is designed to obtain approval from the
appropriate regulating authority to return the plant
to full operation.
In some areas, the routine maintenance for nuclear
plants is similar to that for fossil-fueled plants. This
includes the turbine-generator systems, pumps,
valves, fans, filters, electrical distribution systems, and
some of the instrumentation and control systems.
Nuclear plants, however, have many inspection and
maintenance activities which are different in nature,
precision, extent or available maintenance time period. Also, in parts of the plant subject to radiation exposure there are significant differences due to radiological considerations. Dealing with the radiological
issues imposes unique requirements on plant maintenance, especially in personnel protection, handling
of radioactive materials, disposal of waste items and
the need for remote robotic equipment.
The following sections focus on the maintenance of
the major components and the unique aspects of working in a nuclear facility. Most of the discussion is centered on the key areas of the reactor primary heat transport system as shown in Fig. 1. The reactor shown has
once-through steam generators (OTSGs). Recirculating
steam generators (RSGs) have similar tubing inspection
and repair requirements but also have the steam drum/
upper bundle area which requires periodic inspection.
Maintenance – key issues
Personnel protection
Although stringent precautions are taken, nuclear
plant maintenance workers are exposed to low levels
of radiation. In the United States (U.S.), allowable
technician dose limits are regulated by the Nuclear
Regulatory Commission (NRC). Other countries (e.g.,
Steam 41 / Nuclear Services and Operations
Canada) set their own allowable technician dose limits. Some operating companies curtail exposure even
further.
Workers entering a radioactive area must wear protective clothing. This typically consists of cotton overalls, paper and rubber shoe covers, cotton and rubber
gloves, and a cotton hood or paper hat. Respiratory
protection and/or plastic suits with air supply may also
be required.
Limited accessibility
A major restraint to performing nuclear plant maintenance is the limited accessibility of much of the
equipment. The primary reactor system is not accessible during power operation. As a result, this equipment must be maintained during outages. Repair, replacement or return-to-service of parts must be based
upon maintaining fitness-for-service to the next point
in time when that part will be inspected.
Most of the plant equipment is required by license
to be operable during normal operation. If a safetyrelated system fails, the operator typically has some
limited period of time for its repair and return-to-service, otherwise the entire unit must be shut down. Examples of such critical equipment include the high pressure injection system, low pressure/decay heat removal
system, core flood system, building spray system, reactor protection system, and nuclear instrumentation.
Application of remote technology
Principles known as time, distance and shielding
and ALARA (as low as reasonably achievable) are the
cornerstones of performing maintenance in a radiation-exposure efficient manner. In applying remote
technology, emphasis is placed on the time of personnel exposure as well as the distance between the personnel and the work piece.
When considering whether remote technology is
applicable, the level of radiation, the time required for
the maintenance and the work place environment are
evaluated. Key areas where this technology has been
applied include work in or around the reactor vessel
and its internals and within the steam generators.
Although the reactor vessel is highly radioactive, it is
submerged in water during maintenance. While the
water shields the workers from radiation, remote and/
or fully robotic equipment is necessary for the underwater repairs.
49-1
The Babcock & Wilcox Company
While remote and robotic technology have improved
the extent, quantity and refinement of inspection data
being gathered, the cleaning and repair performed
have increased enormously. The inspection of tens of
thousands of steam generator tubes in a short outage is
not unusual compared to hundreds in prior years. At the
same time, efforts to optimize these activities have led to
shorter outages. As a result of these shorter, more effective outages, the average U.S. reactor availability has
climbed from 60% in the past 20 years to more than 90%.
Although remote technology often encompasses the
use of robots, it can also be an extension of a hand
tool or the development of a flexible probe and manipulator to increase distance from the work piece and
to allow internal access to tight or complicated spaces.
Each maintenance task requires a different degree of
sophistication based on the environment and the complexity of the task. As remote technology advances, the
amount of personnel radiation exposure declines even
as the scope and sophistication of the work increases.
Component maintenance
Plant life management
The objective of plant life management is to ensure
that the plant equipment achieves a continuing state
of high availability throughout its operating life and
the plant reaches at least its desired lifetime. Life
management places emphasis on the assessment of
component condition prior to scheduled outages and
on the scheduling, planning and mobilization of
workforce, equipment and methodology to achieve
timely execution of the outage work. Outages may only
end when all work is successfully completed and documented, and approval is granted by the appropriate
regulatory authority to return to service.
Because experience has shown that much of the
plant availability is dependent on the successful operation of the steam generators, the discussion and
illustration of plant life management methods will
concentrate on these components.
Long range life assessment Prior to development of
a life management plan, a life assessment process is
completed for each major component. This life assessment is necessary to establish the operating history
of the component and to provide a basis for planning
a multi-outage inspection and maintenance program.
For steam generators, the life assessment and other
work should individually address the three major areas of: 1) pressure vessel boundary, 2) the heat transfer tubing and 3) internals such as tube supports,
steam separators and feedwater headers. Breakdown
into these three areas is necessary because the regulatory requirements and the inspection and maintenance
requirements for each are unique.
Pressure vessel boundary The design, manufacture,
in-service inspection, and repair of all component pressure vessel boundaries is regulated by the American
Society of Mechanical Engineers (ASME) Boiler and
Pressure Vessel Code as augmented by other regulatory requirements. During manufacture, the Codedefined volumetric inspections ensure the components
49-2
meet stringent standards and establish a baseline for
in-service evaluations. In-service requirements specify
examination of the pressure vessel boundary, including visual inspection and volumetric nondestructive
examination (NDE) of the welds. An assessment of the
steam generator must determine the condition of the
equipment and any areas of non-compliance with the
requirements and must identify any work needed to
restore the unit to a compliant state.
Tubing The steam generator tubing is the boundary between the primary and the secondary heat
transport systems and is very important to the integrity of the plant. Tube integrity is the primary concern when reviewing the steam generator. In The
Babcock & Wilcox Company (B&W) plants, there are
about 15,000 tubes in each of the two once-through
steam generators (Fig. 1). In plants with recirculating steam generators, there are about 3000 to 11,000
tubes in each of two to four steam generators per plant.
With a typical tube wall thickness of about 0.04 in. (1
mm) or less, the tubing is a vulnerable boundary and
must be carefully maintained. Tube leaks are a major
concern and primary to secondary leakage above certain prescribed limits requires shutdown of the plant.
Experience has shown the tubing to be a major
cause of loss of plant availability, long outages, and
expensive repair and replacement work. Common
problems with steam generator tubing are generally
related to corrosion involving a combination of materials and water chemistry issues. Some of the more
common problems are stress corrosion cracking, pitting, wastage, erosion, fretting at tube supports, and
denting due to corrosion of any carbon steel tube supports. Fretting due to flow-induced vibration and fretting due to foreign object ingress may also exist. In
modern replacement steam generators with highly corrosion resistant tubing and good tube support, foreign
object damage may be the most serious concern regarding tube integrity. Because of the magnitude and frequency of problems over the years, the tubing receives
the majority of attention in the life management plan.
Internals Internals common to all types of steam generators include tube supports, shrouds (bundle wrapper) and feedwater and/or auxiliary water headers.
For recirculating units, additional internals include Ubend tube supports, steam separators and various
supports and baffles internal to the steam drum. In
contrast to the tube bundle that contains many identical elements (tubes), the internals consist of a large
number of parts that are dissimilar in terms of function, configuration and accessibility for service. The internals are subject to a variety of flow forces and flowinduced vibrations. Bundle supports in close contact with
the tubing can cause tube degradation due to fretting,
and tube denting due to corrosion of the supports. The
life assessment process must consider the potential for a
wide variety of potential problems with these internals.
Life management program plan Following the assessment of the component, a long range life management plan can be developed. Table 1 illustrates a small
portion of such a plan for a set of steam generators. It
shows the scope, timing, inspection, cleaning and repair activities for outages 11 through 14 of the total life
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
Table 1
Steam Generator Life Management Program Plan
Unit ABCD/SG 1, 2, 3, 4
Outage No.
Activity
11
October
2003
Pressure vessel NDE program
Tube ECT
Tubesheet waterlancing
Tubesheet FOSAR
Drum and upper
bundle visual inspection
Tube plugging
Planned retrofit of
bundle inspection ports
Chemical cleaning
12
April
2005
SG 2, 4
50% Bobbin
10% TS MRPC
SG 1, 2, 3, 4
SG 1, 2, 3, 4
SG 2
If required
13
October
2006
14
April
2008
SG 1, 3
50% Bobbin
10% TS MRPC
SG 1, 3
If required
SG 1, 3
TSP 6, 8
Assess need
Tube ECT: Eddy current testing, with 50% of bundle using the standard Bobbin and 10% bundle using the MRPC coil.
Tubesheet FOSAR: Foreign object search and retrieval, visual examination.
Drum and upper bundle inspection: Visual/robotic inspection to meet requirements of NRC Generic letter 97-06(1977).
Tube plugging: Based on inspection results.
Planned retrofit of bundle inspection nozzles: See chapter 48.
Tubesheet water lancing: Cleaning sludge deposits on top of tubesheet surface.
Chemical cleaning: chemical dissolution of secondary-side tube deposits.
cycle. A full plan would cover many more outage cycles,
more plant components, and many more activities.
Having identified the necessary inspection and
maintenance tasks, significant effort is then employed
to define work scope, the preparation of detailed plans,
detailed procedures, and to obtain regulatory approvals to proceed. A typical outage would result in a large
volume of tube eddy current testing (ECT), pressure
vessel inspections, and visual and foreign object search
and retrieval (FOSAR) inspections of the secondary and
primary side internals. There would also be cleaning
activities, repairs and possibly some component modifications that had been planned in advance. The assessment of this large database of information, which is done
as soon as the inspection data is available, forms the basis for the next phase to determine fitness-for-service.
Fitness-for-service assessment The fitness-for-service
assessment is a methodology for determining that a
particular plant component is in an acceptable condition at the time of inspection (referred to as condition
monitoring) and confirming that it will be in an acceptable condition at the time of its next planned inspection (operational assessment). The method is illustrated by Fig. 2 which shows the current as-measured
size of a defect in a steam generator tube wall, the estimated growth for a period of operations and the estimated size at the time of its next inspection. Essentially, the initial as-measured size from tube inspection, with an added allowance for measurement error, is plotted at the time of the current inspection. A
projection is made of the growth of this defect to the
Steam 41 / Nuclear Services and Operations
time of the next inspection. If the projected flaw size at
the time of the next inspection is greater than the allowable flaw size, the tube is considered potentially unsafe
and is most likely removed from service by plugging.
The probability of detecting a particular defect in
tubing is dependent on the nature of the defect (pits,
frets, cracks, etc.) and its location relative to other
sources of electronic signals such as tube supports,
tube wall expansion transitions and corrosion deposits. With current technology, pits measuring a small
percentage of the wall thickness can be detected. By
contrast, tight cracks are much more difficult to detect and may sometimes be missed, even at 30% of wall
thickness. Also, allowance for measurement error is
necessary to ensure that a high percentage of the
actual defect sizes are within the bounds of these derived defect sizes.
Steam generator primary side maintenance
Maintenance of a steam generator primary side includes the major activities of:
1. inspection of the tubing,
2. plugging tubes that fail to meet the inspection criteria,
3. repair of tubes to keep them in service and to thus
reduce performance degradation, and
4. stabilizing out-of-service tubes to keep them from
damaging their neighbors.
Steam generator tube inspection Based on prior experience with the steam generators under examination,
some fraction of the tubing will be required to be in49-3
The Babcock & Wilcox Company
Steam Generator Tube Flaw Size (% Through-wall)
Current
Inspection
Next
Inspection
100%
Maximum
Allowable
Flaw Size
Measured
Size
+NDE Error
+Growth
Condition
Monitoring
Operational
Assessment
Projected
Flaw Size
at Next
Inspection
Estimated Flaw Growth
Actual
Flaw Size
at Next
Inspection
Measured
Size
+NDE Error
Measured
Size
Actual Flaw Growth (unknown)
Current Actual Size (unknown)
0%
Operating Time
Fig. 2 Fitness-for-service assessment for a steam generator tube
with defect indication.
spected on a periodic basis. For example, it may be determined that half of the steam generators in the plant
will be inspected at every second outage (as in Table
1). There may also be commitments for specialized inspections or for other tube inspections as a condition
for a return-to-service approval from prior outages.
Eddy current testing (ECT) ECT is the primary inspection method, although ultrasonic testing (UT) is used
in special cases. The ECT is conducted by imposing an
alternating current (AC) magnetic field. This field induces eddy currents in the material that creates a secondary magnetic field. If discontinuities are present,
the eddy currents are altered and the apparent impedance of a detecting coil is changed. The size of the
discontinuity can then be related to this change by
prior calibration.
Tubes are inspected by inserting the probe and
then inspecting the tube while withdrawing the probe
at a controlled rate. RSG and OTSG tubes can be inspected full length except that some smaller radius
RSG tubes may require access from both ends. A typical
robotic positioner for the ECT probes is shown in Fig. 3.
Several different probes are used to characterize the
tubing condition. A bobbin coil ECT probe basically
consists of a bobbin wound with coils of wire. Eddy
currents generated by the coil electromagnetically
couple the probe and the test piece with the eddy currents flowing in a direction parallel to the coil winding. Eddy current signals from a bobbin coil are measured as changes in primary coil electrical impedance
induced by the eddy current magnetic field. Bobbin
coil ECT has been used throughout the industry for
many years, although other probe types are essential
to complement the basic information received. One
limitation is that the signal is integrated 360 deg
around the tube and is therefore unable to differentiate within that range. The bobbin coil is able to size
many types of defects once the nature of such defects
has been determined by laboratory analysis or by other
probe types, but it is not good for exploring unknown
situations such as detecting tight cracks of moderate
size or circumferentially oriented cracks. It can, however, be used to see further in the radial direction than
49-4
other ECT techniques. It is sensitive at low operating
frequencies to conditions (supports, deposits) beyond
the tube outer surface; at high frequencies it has a
shorter range of vision.
Because of these limitations, a number of rotating
and array probes have been developed. MRPC (motorized rotating pancake coil), +Point (plus point)
rotating probes and X-Probe array probes are examples. Rotating probes like MRPC and +Point provide excellent and finely detailed data but have the
disadvantage of very slow probe travel speed. The XProbe offers the speed of the bobbin with the detail of
rotating probes, although with the generation of a very
large amount of data. Fig. 4 shows a typical arrangement of the bobbin coil and X-Probe; the data acquisition and analysis system is shown in Fig. 5.
Ultrasonic testing (UT) UT of tubing is a valuable tool,
particularly in the early investigative phase where a
newly discovered condition must be characterized. The
process requires a rotating surface-riding UT probe
where the signal path must be flooded by a couplant
such as water. Because of the rotation and the
couplant, the process is slow and somewhat awkward,
but it does have excellent resolution. It has the advantage of seeing indications differently than ECT, thereby
providing results to supplement the ECT information.
Destructive examination (DE) DE is a vital part of investigating any newly discovered degradation condition in tubing (or in other component areas). Except
perhaps for phenomena like fretting, it is not possible
to characterize a degradation condition and to determine its root cause without sample removal and laboratory examination. Until newly discovered defects are
characterized in the lab, it is not possible to know with
any certainty the relationship between the defect and
the ECT signal it produced in the field. Because some
Fig. 3 Robotic eddy current inspection shown in a recirculating
steam generator mockup.
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
Push Tube
Wiring Module
Array Coils
Bobbin Coils
Fig. 4 Multi-coil array probe with bobbin coil.
of the more critical defects such as tight cracks are difficult to see at any time, even where they are relatively large, such characterization is vital.
Remote technology In the early years of nuclear
power all of the maintenance work was performed
manually by technicians who entered the steam generator head. As maintenance activities and radiation
levels increased with plant aging, it became increasingly difficult to perform repairs manually. As inspecting ever larger numbers of tubes during refueling
outages became mandatory, this work was a logical
candidate for early remote technology. B&W’s first
manipulator used on OTSGs was positioned manually
on the tubesheet, locked in place, then computer controlled from a remote location. For RSGs, an articulated arm manipulator was used. Although also manually installed, it was not computer controlled. Both manipulators performed well for inspection, but they
could not support the heavy tools required for plugging and other repair operations. In addition, because
of reduced radiation dose limits, the practice of manually installing the manipulators had to be eliminated.
Advanced manipulators Advanced manipulators
have been developed to minimize human exposure,
to perform multiple inspection and repair duties, and
to be computer controlled.
An earlier design of a remote manipulator is shown
in Fig. 6. The unit is installed in the steam generator
head by a series of cables and pulleys as shown in Fig.
7. Although lightweight in construction, it has a load
capacity of 200 lb (91 kg). Once calibrated, it can be
directed to any tube in the steam generator. With the
exception of tool head installations, all operations are
remotely controlled and video equipment is used to
monitor the work. The control center is located outside the containment building.
Fig. 8 shows an advanced manipulator that loads
itself into the channel head while its arm exits the
manway for attachment of tool heads. Being mounted
on the manway opening, it provides unobstructed access to all parts of the tubesheet. It also reduces personnel radiation exposure.
Tube plugging Any tube not meeting the established
criteria for acceptability must be taken out of service
or repaired. While explosive plugs were used in the
Robotic Manipulator
Steam Generator
Primary Head
Probe
Pusher
Power and
Control
Cables
Robotic
Manipulator
Control Cable
Robotic
Manipulator
Controller
LAN
Remote
Data Acquisition
Unit
Control
Cable
Probe
Pusher
Power Supply
LAN
Fixture
Control
Work
Station
PC
Fig. 5 Eddy current data acquisition and analysis system for multicoil array probe.
Steam 41 / Nuclear Services and Operations
Fig. 6 Tubesheet-mounted manipulator inside a recirculating steam
generator primary head.
49-5
The Babcock & Wilcox Company
1970s and 1980s, mechanical plugs are now more common. Fig. 9 shows typical mechanical plugs. Seal
welded plugs are also used. The rolled plug is installed
in one tube end with an air-powered roll expander,
which forces the plug wall outward into the tube wall.
Expansion continues until the plug and tube wall contact the tubesheet bore and the proper torque is
reached by the tool. This process is repeated at the
opposite end of the tube.
Tube repair A limited number of tubes may be
plugged before unit efficiency is impaired. For nuclear
steam generators, this limit is set by thermal performance parameters. One method of repairing damaged
tubes and returning plugged tubes to service is tube
sleeving. In this technique, a short tube (sleeve) is
inserted into the base tube to bridge the degraded
area. Should the defect continue to grow, the sleeve
effectively seals the leak from the secondary side.
However, this technique is generally limited to the
portion of the tubes near the tubesheet. Fig. 10 shows
a typical tube sleeved with roll expanded sleeves.
Fig. 7 Installation sequence for the tubesheet-mounted manipulator
in Fig. 6.
Fig. 8 Manway-mounted manipulator in an RSG head mockup.
49-6
Fig. 9 Steam generator tube mechanical plugs – rolled (left) and
expanding mandrel (right). Note: clearances and expansion transition
profiles are greatly exaggerated radially for illustration.
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
Because of extensive steam generator replacement taking place, the need and practice of sleeving have been
reduced.
Steam generator secondary side maintenance
While control of secondary side water chemistry
helps to minimize repairs in this area, some maintenance is necessary. Two conditions, fouling and sludge
buildup, must be eliminated. Fouling consists of deposition of solids, primarily iron, on the outside of tubes
and at the tube support plates. Support plate deposits
can increase pressure drop resulting in reduced steam
generator performance. Tube bundle deposits can reduce heat transfer capability and also degrade performance. More important, buildup of these deposits can
concentrate contaminants such as chlorides and fluorides
that promote stress corrosion cracking – a problem which
has destroyed tens of thousands of tubes and has led to
the need for extensive steam generator replacement.
Sludge deposit buildup occurs at the lower
tubesheet of the steam generator where solids from
the feedwater are deposited. Again, other contaminants
can concentrate in this sludge, degrading the tubes.
Different techniques are used to remove these
sludge buildups. Chemical cleaning is used for the
tube support plate and tube bundle. A chemical solution is introduced into the secondary side during a
shutdown. Then, following a soaking period, the unit
Fig. 10 Steam generator roller expanded tube sleeves – free span
upper expansion (left) and tubesheet region upper expansion (right).
Steam 41 / Nuclear Services and Operations
is flushed. Sludge piles are removed by water lancing. This process, also known as sludge lancing, uses
high pressure water introduced robotically through a
secondary side opening to loosen deposits. The loose
deposits and water are then suctioned out of the steam
generator and processed through a filter system.
Fig. 11a shows the flexible inter-tube water lancing system used by B&W for steam generator cleaning. The system uses six or eight small-diameter pressure tubes to deliver high pressure water to the very
small nozzles in its end manifold. These end manifolds
direct intense water jets at the tubesheet face and
upward toward the lowermost support. The flexible
lance is fed into the steam generator through a secondary side inspection port just above the tubesheet.
A semi-rigid guide directs the flexible lance along the
steam generator’s central tube-free lane, guides it
through a tight right-angle turn, and projects it into
the individual intertube lanes and ultimately to the
bundle periphery. The jet action dislodges the sludge
deposits from the tubesheet (and/or from tube supports) and permits the deposits to be flushed out of the
bundle and removed by suctioning. This inter-tube system is particularly effective for hard deposits. Fig. 11b
shows the water jet spraying from a flexible lance positioned within a small demonstration tube bundle.
The need for chemical cleaning or sludge lancing
is determined by performance degradation, visual inspections using small fiberscopes and cameras, and by
the removal of tube samples to detect degradation (or
in some cases to directly measure the deposit loading).
Reactor vessel and internals
While the reactor vessel and its internals are static
equipment, they are not free from either degradation
or the need for maintenance. Maintenance ranges
from care for the studs, gaskets and gasket surfaces
during each refueling outage to repairs for various severe and costly degradation mechanisms.
Reactor vessel The vessel closure is the large diameter, high pressure bolted flange with its delicate gasket face which is the joint between vessel and head.
During refueling, the reactor head must be removed
from the vessel to gain access to the core. Each of the
very large studs that retain the head is also removed
from the vessel for cleaning. Special precautions are
taken to contain the contaminated particulate that is
released by stud cleaning equipment. Following cleaning, each stud is lubricated for reinsertion into the
vessel flange. Likewise, each stud hole is cleaned prior
to retensioning the studs.
The primary seal between the reactor vessel flange
and head is a double O-ring configuration. Both mating surfaces must be thoroughly cleaned before installing the O-rings, which are replaced each time the
head is removed. The seals are installed on the head and,
just prior to setting the head, the vessel flange is cleaned
and inspected for scratches that could cause leakage.
Reactor vessel heads worldwide have, of late, been
subject to extensive degradation and some leakage
due to stress corrosion cracking of the weld joints between the control rod drive mechanism (CRDM) guide
tubes and the head. These guide tubes penetrate the
49-7
The Babcock & Wilcox Company
Fig. 11a Flexible inter-tube waterlance system – waterlance and
drive unit mounted to a steam generator mockup.
Fig. 11b Waterlance jet spray pattern in a small demonstration tube
bundle.
head and are welded to the cladding at the inner surface of the head. In at least one case, extensive corrosion of the head itself had occurred before this problem was discovered.
Because these welds are difficult and costly to inspect and repair, many utilities have chosen to replace
the heads with components made with new, more corrosion resistant materials (Alloy 690, 52, 152 versus
the prior Alloy 600, 82, 182 materials).
The small instrument guide tubes in the lower head
of the reactor have also required attention at times but
to a much lesser degree than the head penetrations.
In addition to the above more conventional forms
of degradation, the effect of neutron radiation on reactor vessels must be considered. Neutrons can reduce
the toughness of steels, increasing their susceptibility to brittle fracture. As a result, the welds in the reactor core region are subjected to extensive UT examination. Of particular interest is the surface just under the cladding. Special techniques are used to
achieve maximum coverage and sensitivity.
To gain access to the inside surface of the reactor
vessel, all the fuel and internals must be removed.
Due to its highly irradiated condition, the vessel must
remain filled with water to provide shielding. Each
weld, including those between the nozzles and primary piping, must be examined. This can be accomplished using an automated reactor inspection system,
shown in Fig. 12. A typical vessel inspection can take
from 10 to 20 days, depending on the quantity of welds
and the need for rescanning.
Internals While the reactor vessel internals require
little routine maintenance, there have been various
core barrel integrity problems, mostly related to vibration due to inlet flow buffeting. Because the internals
are highly radioactive, any repairs must be done under water. The bolted joints of the reactor internals
have required the most repair activity. Stress corrosion cracking of high strength steel or Inconel bolts
has been the most common cause for repair. Although
the performance of A-286 stainless and X-750 Inconel
bolts was expected to be good, pure water stress corrosion has been a problem.
In replacing these bolts, standard wrenches, drills
and sockets have been adapted to be operated from
an extension or underwater platform. Underwater
cameras facilitate these remote repairs.
49-8
Control rod drive mechanisms (CRDM)
The CRDMs are mounted to the top of the reactor
vessel head and control the movement of the reactivity control rods in the core. A central shaft known as
either a lead screw or drive shaft attaches to the control rod and is moved by the mechanism. The CRDM
is powered electrically, and position indication (PI)
switches are used to let the reactor operator know the
position of the control rod. During refueling outages,
inspection, tests and routine maintenance are performed on the mechanisms to assure the motors and
PI systems are functioning properly. Motors with unacceptable characteristics are replaced. PIs are also replaced if not functioning properly. Some CRDM designs attach to the reactor vessel head with bolts and
use gaskets to provide the sealing. Occasionally these
joints leak and require replacement of the gaskets and
rework of the flange faces. This work is performed
during the refueling outage while the reactor vessel
head is on its storage stand. Remote tooling and appropriate shielding are used to minimize the radiation dose
to the workers.
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
Reactor head service support structures are designed for several major functions. They provide cooling and lateral support for the CRDMs, support power
and instrumentation cables, facilitate reactor head
lifts, and act as an internal missile shield. On some
reactors the original service structures were not fully
optimized to simplify refueling activities. These original inefficiencies together with increased economic
performance goals have resulted in the replacement
of original service structures independent of or in conjunction with reactor vessel closure head (RVCH) replacement. The primary objective of an enhanced service structure (ESS) is to reduce the disassembly and
reassembly times of the reactor head during refueling outages thereby shortening critical path activities
as well as reducing personnel dose and improving
safety. These objectives can be met by striving for a
redesigned configuration which integrates all functions into a single assembly which can be removed with
a single point pickup after disconnecting instrumentation, CRDM power cables and the head closure studs.
Service structure enhancement can entail integrating
the entire cooling system into the ESS, missile shield
integration and building in a single point pickup tripod arrangement. Improvements to allow quick disconnects for cables and more efficient RVCH stud removal will also improve critical path time. Despite
building more functionality into the ESS, overall access for reactor head inspections can be improved by
providing handholes and by spacing the RVCH insulation away from the head surface, thereby allowing
remote visual inspection of the head with the insulation still in place.
In-core instrumentation
Most pressurized water reactors (PWRs) utilize in-core
instrumentation inserted through the bottom of the reactor vessel. During refueling, these very long, slender rods
are withdrawn from the fuel assemblies. At that time, instruments that are not performing properly are replaced.
Because the instrument (detector) is radioactively hot, the
end that was in the core is pushed back into the reactor vessel
and cut off using underwater remote tooling and is then
disposed. The remainder of the instrument is pulled out the
other end and also disposed. Additional inspections and
maintenance to the sealing system can be performed. New
detectors are inserted for use during the next operating cycle.
Reactor coolant pumps
Depending on the size of the plant, there are from
one to four reactor coolant pumps in the primary system. Because the pumps and motors are constantly
engaged, they require more maintenance than passive components. Pump seals are the items most frequently replaced. Nuclear plant motor maintenance is
similar to that performed in other industries, except that
the motors are very large and must operate with very
little vibration for the sake of the seals and, of course,
they must be maintained within the reactor building.
Pump repair While infrequent, pump repairs, other
than seals, and general overhauls are important in a
comprehensive maintenance program. Overhauls are
conducted to minimize pump failures due to wear.
Steam 41 / Nuclear Services and Operations
Fig. 12 Automated reactor inspection system.
Because of the contaminated environment in which a
pump operates, special tooling is used when making repairs to minimize radiation exposure to technicians.
Mechanical shaft seal maintenance The mechanical
shaft seal is a primary boundary for the reactor coolant. The seals are typically a three stage design, with
each successive stage being subjected to a lower pressure drop. Sealing is provided by rotating and stationary surfaces that contact each other or are separated
by a thin film. The seal faces are typically carbon or
aluminum oxide. Because they must operate continuously in vibrating conditions with exceedingly low
leakage, pump seals need regular attention and sometimes replacement during outage maintenance.
Pressurizer
The pressurizer serves to establish and control the
operating pressure within the primary heat transport
system. This is achieved by electrical heaters that raise
the saturation pressure of the pressurizer’s water and
steam inventory to the appropriate value.
Heaters within the pressurizer are generally the
only components that require maintenance. These
heaters consist of side mounted bundles, used in B&W
designs (Fig. 13), or bottom mounted individual heaters, used in other pressurized water reactors. Heater
maintenance primarily consists of element/bundle replacement, power cable replacement, cable-to-element
connector repair, and element recovery.
Moisture is often the cause of a defective heater element. Element recovery can be done by drawing a
vacuum at the electrical connector and sucking out the
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Channel calibrations are performed routinely to ensure that instrumentation and electrical devices meet
specifications for accuracy and response time. Integrated system tests may also be performed. If a device fails a test, it is replaced or declared inoperable.
The number of such failures permitted before output
reduction or shutdown is very strictly regulated.
Valves and actuators
Valves in a nuclear plant serve two basic functions:
control and isolation. Nevertheless, all valves have
their individual requirements of opening and closing
time, shutoff tightness, monitorability, etc. In addition,
the number of valves of all types in a nuclear plant is
very large – and each valve can change the configuration of the plant.
Therefore, in a nuclear plant, a systematic maintenance plan is mandatory. For example, a plan for motorized isolation valves should address packing and
seat leakage, opening and closing stroke times, actuator output and lubrication, function of control
switches, wear of internal actuator parts, and the reliability of its controller, etc.
Fig. 13 Pressurizer heater bundles – bottom mounted (left) and side
mounted (right).
moisture. If moisture is present in the connector area,
the connector pins may be damaged by arcing and may
break when removing the power cable from the heater.
This damage may be repaired. However, if these intermediate repairs are not successful, the heater element/bundle must be replaced.
Instrumentation and controls (IC)
The critical nature of and general inaccessibility to
nuclear plant IC dictate that they be extremely reliable. This reliability is achieved by stringent qualification and by incorporating multiple channels to measure the same parameters. Such coincident logic reduces the possibility that a single failure will trigger
a safety action.
If a component fails suddenly or gradually degrades,
this must be detectable. Detection is achieved by monitoring parameters with the plant computer and annunciator systems and by alarming abnormal conditions.
Checks are often made by comparing the output
from redundant sensors. On critical components, these
tests are run and documented at specified intervals.
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Piping
Piping is subject to operating pressure and to imposed forces and motions due to its own thermal and
pressure effects and to that of the equipment it serves.
Piping is subject to stress, fatigue, cracking, corrosion
and to flow accelerated corrosion (FAC) which is an
ongoing industry challenge of pipe wall thinning and,
in some cases, failure.
Piping and pipe welds are examined using ultrasonic testing (UT), liquid penetrant (PT) or magnetic
particle testing (MT). Where UT is required, it may
be performed manually or with automated scanners.
Complex shapes, such as nozzle intersections, can be
scanned using robotic manipulators as depicted in Fig.
14. Robots and scanners provide precise positioning
and automatic data analysis with minimal personnel
radiation exposure.
Equipment diagnostics
Loose parts monitoring Loose parts, or foreign objects, such as bolts and small metal pieces caught in
the high velocity flow of the reactor coolant system can
bounce around in the primary system and cause significant damage to areas such as steam generator
tubesheets and seal welds. While loose parts are seldom encountered, the NRC requires a system to detect them. A typical system features acoustic sensors
in the primary system to detect loose parts. These sensors, or accelerometers, detect the noise generated by
impacting loose parts. The system records impact data
and provides an audible alarm for impacts beyond a
prescribed energy level.
Foreign object damage to steam generator tubing
on the secondary side persists; sources include the
windings of upstream valve gaskets which unravel in
service or bits of metal, weld slag and tooling. In new
replacement steam generators with high corrosion resistance, foreign object damage is often the most significant remaining failure risk. Such foreign object
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
change is normally detected by eddy current and/or
visual tube inspection during an outage.
Neutron noise monitoring The internals of the reactor vessel provide support for and alignment of the
core. Maintenance of both is important to assure that
the control rods can be inserted for reactivity control.
The internals are subjected to high velocity reactor
coolant flow, which causes them to vibrate. Although
some vibration is normal, excessive amounts must be
detected. During power operations, neutron flux is
monitored by special instrumentation located outside
the reactor vessel. Certain characteristics of this neutron signal are affected by vibration of the reactor internals. Analysis of this signal can detect abnormal vibration patterns. Measurements are typically made at
the end of a fuel cycle and at the beginning of the next
cycle to verify that the internals are aligned and secure.
Reactor coolant pump monitoring Two principal
pump characteristics are monitored, shaft vibration
and seal performance. Accelerometers and
noncontacting displacement probes located on the
pump provide continuous vibration monitoring. The
displacement probes are mounted radially; the accelerometers are located on and near the pump bearing.
Monitoring equipment in or near the control room
records the sensor data and sounds an alarm if certain limits are exceeded.
Seal performance is also monitored. Parameters such
as seal cavity pressures, seal injection flow and temperature indicate when seal replacement is needed.
Valve monitoring and diagnostics The valve population of a typical nuclear plant is very large and all
valves are critical to plant operation. Nuclear plant
valves control and direct flow, isolate systems and relieve pressure. Motor operated valves (MOVs) and
check valves are especially important because they
provide isolation for critical systems and are often required to operate under severe temperature and pressure conditions. To determine the condition of these
valves, diagnostic systems have been developed.
MOVs provide isolation. They may remain open or
closed during plant operation. The ability of the MOV
to function is directly related to the thrust applied to
the valve stem to overcome differential pressure and
subsequent high friction. However, control switches
limit the thrust of the motor actuator to avoid damaging the valves and internals. Special diagnostic systems determine the available thrust of the actuator
and assure that the switches are properly set. Preventive maintenance programs use the data generated by
these diagnostic systems.
Check valves are passive devices that only permit
flow in one direction. Because the active parts of the
valves are wholly contained in the fluid stream, it has
been difficult to determine functionality without disassembly. However, diagnostic systems that evaluate
in-service check valves have been developed. These
systems use ultrasonics and acoustics to evaluate the
disc position and the impact of the disc on the seat and
back stop. They can detect wear at the hinge pin and
flutter of the disc, which can lead to premature failure. As with MOV diagnostics, data from these systems are used in scheduling maintenance.
Steam 41 / Nuclear Services and Operations
Fig. 14 Automated UT inspection of complex pipe shapes.
Refueling
Major activities
During refueling, approximately one-third of the
fuel assemblies are removed and replaced and the remaining assemblies are usually moved inward within
the core. Scheduled maintenance is performed during
refueling outages. Depending on the extent of maintenance required, either that maintenance or the refueling operation determines the length of the outage.
Fuel movement activities are centered around the
reactor vessel and the spent fuel building. To access
the fuel, the reactor vessel must be opened. The following major steps are involved in this process:
1. remove the missile shields,
2. vent the primary system,
3. uncouple the control rods from their drives,
4. raise and park the drive lead screws,
5. disconnect the power to the control rod drives,
6. install the canal seal plate,
7. detension (loosen) and remove the reactor vessel
studs,
8. install the guide studs,
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9. install the lifting rig, lift the vessel head and place
on a stand,
10. install the internals guide fixture,
11. raise the water level in the refueling canal,
12. install the lift fixture, remove the upper internals
and place on a stand under water, and
13. retract and park in-core instruments (detectors).
The fuel can now be moved.
These operations are shown in Fig. 15. Fuel movement is performed under water with permanently installed equipment. When each fuel assembly is removed, it is transferred to the on-site spent fuel storage area. Here, control rod assembly changes and the
appropriate inspections are made. Fuel that is to be
reused is moved back to the reactor building and
placed in its new core location; new fuel is also installed at this time. Final verification of fuel assemblies is recorded with underwater video equipment.
Fuel handling equipment
Fuel handling equipment can be grouped into three
areas: 1) main fuel handling, 2) fuel transfer, and 3)
spent fuel/new fuel handling. The main fuel handling
system, used to remove and install fuel in the reactor
vessel, consists of a motorized bridge spanning the
canal or cavity and riding on rails. A handling mast,
mounted to and extending below the carriage, is positioned over the fuel assembly to be moved. The
grapple, or gripping device, is then lowered and engages the assembly. Once engaged, the grapple is
raised and the fuel is drawn into the hollow mast.
Sensors indicating load and fuel assembly position
assist the operator. The bridge is then moved to the
fuel transfer area, where the fuel is lowered into a
vertical transfer basket and released from the grapple.
At this point, the basket is lowered to the horizontal
position and is moved through a transfer tube into the
spent fuel area. Finally, the fuel is upended and
moved to storage.
The main fuel handling and transfer systems are
only accessible during a plant shutdown, because they
are located inside the reactor building. As a result,
maintenance on this equipment is scheduled at the
beginning of an outage.
Reactor vessel disassembly and reassembly
To allow access to the fuel, the reactor vessel head
and upper internals must be removed from the reac-
Fig. 15 On-site fuel movement system.
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The Babcock & Wilcox Company
tor vessel. In the B&W nuclear steam supply system
(NSSS), each control rod drive must be disconnected
from its control rod before this operation can begin.
The control rod remains with the fuel. Special tooling
is used to reach down through the top of the drive,
and to attach to and rotate the lead screw and disconnect it from the control rod. The lead screw is then
raised and parked inside the drive assembly. Other
NSSS designs require similar procedures; however,
the sequence and exact techniques may differ.
The tensioned studs and nuts that secure the reactor vessel head to the reactor vessel must be
detensioned and removed before fuel handling can
continue. A typical hydraulic detensioning operation
is shown in Fig. 16. Generally, three detensioners are
used simultaneously and follow a prescribed pattern.
Once the studs are detensioned, they are screwed out
of the threaded holes in the reactor vessel flange and
either removed or parked on the head. A lifting fixture is then attached to the head. The head is then
raised using the reactor building crane and moved
aside to its storage stand inside the reactor building.
The upper internals are lifted in a similar manner;
however, due to their highly contaminated and activated nature, the lifting fixture is attached remotely.
The upper internals are stored on a stand under water in the refueling cavity.
Once the refueling operations are completed, the
upper internals are reinstalled, the head is placed back
on the reactor vessel and the studs are tensioned. In
preparation for these activities the flanges on both the
reactor head and vessel are cleaned and new O-rings
are installed on the head flange. The control rod drives
are recoupled to the control rods, power cables and
cooling water lines are reattached and, at the appropriate time, the system is filled and vented.
Radiation detection and monitoring
Because no human sense can detect nuclear radiations, special instruments and techniques are used for
detecting and measuring radiation. In general, three
types of checks are required as follows:
1. Measurement of beta and gamma radiations by instruments such as the Geiger counter and ionization chamber provide instantaneous indications of
the total level of β and γ. Most instruments are read
as dose rate, usually in Sieverts. All persons in areas where radiation may be encountered normally
wear a film badge or a thermoluminescent dosimeter (TLD). These devices are used for official
records for exposure control. However, one’s exposure can not be determined without evaluating
the device with special processes or instrumentation. These devices measure the amount of β and
γ radiation a person absorbs in terms of the total
dose of radiation for a day, week or month.
2. Protection against neutrons is provided, primarily,
by the concrete and water shielding around
nuclear reactors. When a reactor first goes into
service, neutron counters as well as gamma
counters are used to make a careful survey of the
Steam 41 / Nuclear Services and Operations
Fig. 16 Service technicians operating reactor closure head stud
detensioning equipment during a plant service outage.
surrounding area. Should leakage exist, the
shielding is modified. Thereafter, periodic checks
are made for γ and neutron leakage. In experimental installations, or where neutron surveys indicate
the need for continuous surveillance, special film
badges and neutron dosimeters may also be used.
3. Keeping the concentration of alpha emitters in
working spaces and in outgoing air below prescribed tolerances is sufficient to protect against
α particles. Alpha counters monitor air quality in
working spaces on a regular schedule. Samples of
dust accumulating in various areas of a room are
monitored periodically for alpha radiation. The air
concentrations are then converted into internal
exposures for the worker. Whole body counters
and urinalysis can also help ensure that the workers’ internal exposures are well within the regulatory limits. Portable alpha friskers are also used
to monitor hands, shoes and clothing of personnel leaving risk areas.
When high radioactive air concentrations occur,
other precautions such as respirators, self-contained
breathing air and glove boxes are used to protect the
workers from internal exposures.
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Nuclear operations
Nuclear power plant operations and services described here are generally applicable to light water
moderated and cooled pressurized water reactor
(PWR) systems, as depicted in Fig. 17, and are modeled on plants with reactors designed by B&W. As
design details vary among PWR types, operational
differences are noted.
Major licensing requirements
In the U.S., civilian use of nuclear energy was authorized by the Atomic Energy Act of 1954. The act
also established an Atomic Energy Commission (AEC)
for developing and regulating nuclear energy. A major objective of the AEC was to protect the public health
and safety. The Energy Reorganization Act of 1974
replaced the AEC with the Nuclear Regulatory Commission (NRC), established to regulate the construction and operation of nuclear power plants as well as
research facilities. Public health and safety continue
to be a major goal of the NRC.
The safety of nuclear power plants is based on:
1. Defense in depth This is a feature of PWR reactors based on three barriers between the nuclear
fuel and the environment: 1) the fuel cladding, 2)
the reactor coolant system (RCS) pressure boundary (i.e., the envelope created by reactor vessel,
pumps, piping, pressurizer and the steam generators and their tubing), and 3) the reactor containment building (typically a pre-stressed concrete
structure with an inner steel liner).
2. Design approval This includes NRC review and
approval of the site and the design of safety systems and safety-related equipment.
3. Quality assurance program Construction of the
station and erection of the equipment as well as
maintenance and operation are guided by NRC
approved quality assurance programs.
4. Operating license review Following construction,
the NRC grants the utility (owner) an operating
license. The license and the technical specifications
define the operating bases of the plant.
The nuclear licensing steps, described as follows, are
primarily designed to ensure public safety.
Plant licensing
In addition to licensing by the NRC, approvals for
the plant site, construction and operating licenses
must be obtained from the respective authorities. Additional regulating agencies in the U.S. include the
Federal Energy Regulatory Commission (FERC), the
Environmental Protection Agency (EPA) and the
Corps of Engineers. Public Utilities Commission (PUC),
state environmental control board and local governmental approvals are also often required for nuclear
power plant siting, construction and operation.
NRC power plant licensing takes place in two major steps: the construction permit and the operating
license. Completion of each step entails hearings conducted by an advisory safety licensing board.
In the construction permit stage, certain documen49-14
tation must be prepared for the NRC. The proposed
plant site is characterized, the preliminary design features are outlined, and conformance to the Code of
Federal Regulations standards is presented.
A preliminary safety analysis report, which contains
design and safety information, is prepared by the utility and its contractors, and is submitted to the NRC.
The review includes questions by the NRC and subsequent responses from the plant owner. Along with
the review, these become part of the public record and
licensing process. The NRC staff prepares a safety
evaluation report as a result of their review. This report leads to an Atomic Safety and Licensing Board
hearing, which is open to the public. Upon approval
by the board, a construction permit is issued by the
NRC and plant construction can begin.
As the plant design becomes final and construction
proceeds, the information contained in the review is
revised and expanded. A complete description of the
site characteristics, safety systems, quality assurance
programs and technical specifications is included. This
revised information becomes the final safety analysis
report. This report is also submitted to the NRC for
review and approval. As with the preliminary report,
the review includes NRC questions and owner responses. Following review, the NRC again prepares a
safety evaluation report of the site and plant. This
provides the basis for a second public hearing to approve an operating license for the utility. During construction, on-site NRC inspectors are assigned to assure conformance to the final report.
Upon receipt of the operating license, the utility
performs system pre-operational and hot functional
testing and prepares to load fuel. Approval by the NRC
is required for fuel loading and low power operation
at about 5% of full power. Following successful fuel
loading and low power operation, the NRC grants permission for power escalation.
In 1989, the nuclear power plant approval procedure in the U.S. was revised to allow one-step licensing. The objectives of this simplified procedure are to
streamline the licensing process, to promote standardized vendor designs and to minimize NRC required
design changes during and after construction. It also
provides for combined licensing (construction and
operation) which allows the owner and other stakeholders a much higher level of confidence in the viability of a project.
The simplified rule differs from the original licensing process in that: 1) a whole plant design certification by the NRC is required; 2) following design certification, a combined construction and operating permit may be obtained; and 3) site permits may be obtained prior to design certification.
Technical specifications
The technical specifications for a system or plant
design are, in the broadest sense, the licensed limits
for operation. These specifications are based on the
analyses and evaluations of the final safety analysis
report and include the following.
Safety limits Limits are imposed on important process variables to prevent an uncontrolled release of raSteam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
dioactivity. If any limit is exceeded the reactor must
be shut down, the licensee must notify the commission, review the matter, and record the results of the
review. The review includes the cause of the condition and the corrective action taken to prevent reoccurrence. Operation shall not be resumed until authorized by the commission.
Limiting conditions for operation These conditions
are the lowest permissible equipment performance levels for safe operation of the facility. When a limiting
condition for a nuclear reactor is exceeded, the licensee
shall shut down the reactor or follow any remedial action permitted by the technical specifications until the
condition can be met. In most cases, the licensee must
notify the commission, review the incident, record the
results of the review, and submit corrective actions.
Surveillance requirements Safety-related nuclear
power plant equipment must be tested periodically;
frequency depends on the specific equipment. If safety
equipment fails a surveillance test, corrective action
must be implemented within a specified time. If corrections can not be made within this time period, the
plant must be shut down.
Design features Certain plant design features are
included in the technical specifications. These features,
such as construction materials and layout, would affect plant safety if altered.
Administrative controls Administrative controls are
the provisions relating to organization, management,
procedures, record keeping, review and audit, and reporting that are necessary to assure safe operation of
the facility.
Pre-operational testing
System checkout During nuclear power plant construction, it is desirable to test each system (electrical,
hydraulic, pneumatic, etc.) as soon as possible. Preoperational testing is integrated into the plant erection schedule so that system testing can begin as soon
as support systems are available. Test procedures are
prepared for each component and system. The tests
are performed and witnessed by designated engineers
and reviewers.
Pre-critical testing is performed on all systems and
components. These tests are conducted on the reactor
coolant system, the feedwater system, the steam system, the reactor makeup and purification system, the
emergency feedwater system, and the control and protective systems. In general, pre-critical testing consists
of the following sequence of events:
1. Cleaning and inspection Fluid systems are flushed
to remove construction debris and are inspected
for cleanliness and proper installation of piping
and components.
2. Electrical tests Alternating current (AC) and direct
current (DC) power wiring and distributions are
inspected and tested for proper hookup and circuit
continuity. Rotating and moving equipment, such
as pumps and valves, are given no-load tests to
determine proper direction of motion.
3. Instrumentation tests Instrumentation and control
wiring is inspected and tested for proper hookup
and electrical continuity. The instrumentation
(transmitters, temperature sensors, flow meters
Fig. 17 Pressurized water reactor (PWR) primary and secondary heat transport and electricity generation systems.
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and level indicators) is calibrated and the control
systems are tested. A control simulator is used by
some utilities for cold system testing.
4. Hydrostatic tests All fluid systems and components
except the reactor coolant system (RCS) are cold
tested hydrostatically to greater than design pressure. Because of the relatively high nil ductility temperatures of the reactor vessel welds, the RCS is
hydrotested at a temperature slightly above ambient.
5. Functional tests Functional tests which demonstrate
component performance are conducted. Typically,
system flow rates, pump head capacity relationships,
valve stroke times and controls are tested.
6. Operational tests Additional tests at near normal
operating conditions are performed for low temperature and pressure systems. Instrument air
systems, the spent fuel pool cooling system, component cooling water systems and the decay heat
cooling systems are typical systems tested.
Performance of the high temperature and pressure
systems, such as the RCS, the makeup and letdown
system, the feedwater system, the steam system and
the emergency feedwater system are verified during
hot functional testing.
Water quality Many of the elements of water treatment, water chemistry and corrosion discussed in
Chapter 42 for fossil fuel systems also apply to nuclear
steam systems. Key differences exist between these
treatments, however. In a pressurized water reactor
(PWR) system, two independent flow circuits are used
as discussed earlier: the primary or reactor coolant
system and the secondary or steam generator condensate feedwater system. Additional differences include
more extensive use of high alloy steel, nickel-based
alloys and other non-steel materials. The ultimate
goals of the water treatment system remain to minimize corrosion and deposition. The basic premise of the
nuclear steam supply system chemistry program is
that it is better to prevent contaminants (both ionic
and particulate) from entering the cycle than to attempt to remove them later. This is the basis of the
ALARA (As Low As Reasonably Achievable) chemistry philosophy employed at nuclear plants.
For their primary circuits, PWR plants use chemical shim reactivity control which utilizes a soluble
neutron poison (boric acid) to regulate core reactivity.
In addition, a pH chemical additive, lithium hydroxide, is used to adjust the pH toward the alkaline side.
The industry has developed a set of guidelines for the
proper concentrations of these chemicals, including the
reduction of boric acid concentration as fuel burnup
progresses.1,2
These guidelines attempt to minimize the impact of
water chemistry on the integrity of the primary system
internals, including the pressure boundary and fuel cladding, and to minimize the transport of radioactive corrosion particles throughout the system. In addition to
lithium and boric acid concentration, primary system
chemistry control parameters include chloride, fluoride,
dissolved hydrogen and dissolved oxygen. Hydrogen is
added to maintain reducing conditions in the primary
coolant to minimize primary system corrosion.
For the secondary circuit, the major goals of the
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chemistry program are to minimize both corrosion
product transport and the corrosion of steam generator tubes. Corrosion product transport and corrosion
of the tube material is mainly affected by the water
chemistry related factors of: 1) pH, 2) electrochemical
potential (ECP) and 3) the particular species beyond
those which affect pH (e.g., lead, copper, and sulfur).
Corrosion is also affected by material susceptibility,
tensile stress and operating temperature.
The pH of the secondary circuit is controlled by the
use of volatile amines (e.g., ammonia, morpholine, and
ethanolamine). Reducing conditions are maintained
in the secondary circuit by the use of a volatile oxygen scavenger (e.g., hydrazine). Strict water purity
requirements are imposed to minimize the transport
of contaminants in the system. To achieve maximum
system reliability, the industry has developed a set of
secondary-side water chemistry guidelines for the proper
control of operating chemistry conditions.3
Hot functional testing (HFT) During commissioning
and prior to installation of the fuel and plant operation, a process called hot functional testing is implemented. This serves to check out the operation and
performance of all of the functioning systems. It also
serves to establish a protective oxide layer on all carbon steel and alloy materials in the primary and secondary heat transport systems which, in turn, minimizes corrosion during normal operation.
HFT occurs after all nuclear plant systems have
been erected and have completed pre-operational testing. This testing provides warmup and operation at
zero power operating conditions. The fuel is not loaded
in the core for HFT. In B&W plants, a plate is placed
in the core region to simulate the core pressure drop
for the RCS pump and flow testing.
The HFT begins by establishing water levels in the
RCS as indicated by the pressurizer level in the steam
generators and in the condenser hot well.
The pressurizer heaters (Fig. 13) are energized to
raise the RCS to a pressure that provides a net positive suction head of about 250 psig (1.72 MPa). This
permits operation of the reactor coolant pumps. Upon
reaching this pressure, the reactor coolant (RC) pumps
are energized to heat the reactor coolant and steam
systems at a rate of about 30F/h (17C/h) from about
70 to 530F (21 to 277C).
There are several temperature hold points during
the HFT warmup at which specific tests are performed.
Typical testing includes the pressurizer spray bypass flow
calibration. This bypass has a trickle flow of about 1 GPM
(0.06 l/s), which keeps the pressurizer spray line and the
spray nozzle at a relatively uniform temperature.
At about 600 psig (4.24 MPa), the RCS high pressure
safety injection pumps are tested to demonstrate flow capability and to adjust the safety injection flow distribution.
Following testing at the hold points, system heating continues to the hot zero power (HZP) level. Typically, in pressurized water reactors, the HZP temperature and pressure ranges are:
RC temperature – 500 to 550F (260 to 288C)
RC pressure – 2100 to 2200 psig (14.6 to 15.3 MPa)
Steam temperature – 525 to 570F (274 to 299C)
Steam pressure – 800 to 1200 psig (5.62 to 8.37 MPa)
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Before fuel loading, the reactor protection system
(RPS) and the control systems are calibrated and checked.
In addition, all protective system instrumentation,
including the out-of-core neutron detectors (Fig. 18b),
RCS pressure transmitters and temperature sensors,
nuclear instrumentation and transmitters, RC pump
monitors and the feedwater pump turbine hydraulic
oil pressure switches, are calibrated and tested.
The reactor, coolant system pressure and inventory,
feedwater, steam pressure and electrical generation
are controlled by the integrated control system (ICS)
(Figs. 18a and 18b) and the non-nuclear instrumentation (NNI). The NNI provides most of the instrumentation for the reactor, feed and steam systems, including signal inputs to the ICS, the control console indicators and recorders, and the plant computer as well
as many of the test inputs to the reactimeter. The ICS
is made up of unit load demand controls, integrated
master controls, turbine and turbine bypass system
controls, feedwater controls and reactor control subsystems. The ICS also controls the reactor, feedwater
flow and the turbine-generator output to meet the
electrical power demand.
The NNI also controls the RC system makeup flow,
the pressurizer heaters, the pressurizer power operated
relief valve (PORV) and the reactor coolant pump seal flow.
The feedwater and steam control subsections of the
ICS provide automatic control over the full power
range; manual reactor control is used up to 15% power
and automatic control is available from 15% to full
power. Manual control can be used in each subsection
of the ICS or its actuated components such as control
rods, feedwater valves, feed pump turbine and turbine bypass valves. Alternately, the turbine can be
manually operated from the control room.
Below 15% power, the ICS maintains the steam generator water level at a constant set point and the turbine bypass system similarly controls the steam pressure. The RCS temperature rises with power. The temperature is typically 532F (278C) at zero load and increases to about 580F (304C) at 15% power. As the
load increases to full power, the temperature remains
at about 580F (304C). Above 15% power, the RCS temperature and steam pressure are controlled by the ICS.
PWRs designed and built by other suppliers use
recirculating steam generators (RSG), which have different operating characteristics than the oncethrough steam generators (OTSG). In the RSG plants,
the RCS average temperature rises with the power
level, the steam generator operating pressure drops with
increasing power (Fig. 19), and the steam generator
water level is controlled to a constant RSG secondary
inventory or to a relatively narrow variable RSG band.
An RSG plant’s average RCS temperature is controlled to a variable set point; the feedwater flow is
controlled by a multi-element unit that monitors steam
flow, feedwater flow, steam generator water level and,
for some plants, RC temperature and steam pressure.
The RSG units typically control electrical output by
controlling the turbine to a variable first stage pres-
Fig. 18a Integrated control system.
Fig. 18b Integrated control system – reactor controls.
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Fig. 19 Typical recirculating steam generator plant reactor coolant
system (RCS) average temperature and steam pressure.
sure signal. This control allows the steam pressure to
change with power level.
The duration of an HFT is usually 500 hours for a firstof-a-kind unit and about 250 hours for all other units.
A significant portion of the HFT period is allocated
to operator training because the plant conditions are
near those of normal operation. In performing the hot
tests, the operators gain valuable experience in managing the systems under normal and abnormal conditions. This operating experience constitutes one of
the final stages of operator training prior to the NRC
operator’s license examination.
After completion of the test, the RCS is cooled and depressurized and the reactor vessel head is removed. The
steam, feedwater and fluid safety systems are inspected
and modified as necessary. Following successful HFT,
permission for fuel loading is granted by the NRC.
Operator training U.S. regulations require that the
reactor operators and supervisory personnel be licensed. An individual who has the basic operational
qualifications is called a reactor operator; a senior reactor operator has completed more intensive training.
The utilities develop, manage and conduct NRC approved operator training and requalification programs
to satisfy regulatory requirements and to maintain the
required operating staff. The training programs cover
all facets of nuclear operations, including equipment
malfunctions, design faults and severe transients. An
operator’s license is issued for a period of two years
and is renewable by requalification.
Fuel loading and zero power testing
The nuclear fuel is first loaded into the reactor vessel only after pre-loading tests and practice fuel handling operations are completed. Neutron detectors and
sources placed in the reactor vessel are used to monitor
neutron multiplication during the core loading process.
Fuel loading takes place with the reactor vessel and
the fuel handling pool filled with ambient temperature demineralized water. The borated water is a neutron poison and assures a multiplication factor of 0.95
or less with a fully loaded core.
With the system prepared, fuel loading begins. Neu49-18
tron multiplication measurements, slow fuel assembly
insertion and frequent pauses to relocate sources and
neutron monitors take place until all fuel assemblies
are installed. After loading, the system is closed and
prepared for low power. Testing following fuel loading includes calibrating neutron source range detectors, assuring sufficient source range signal for
warmup to hot zero power, and verification that the
reactor is sufficiently subcritical for the warmup.
Following completion of this testing, safety control
rod groups are withdrawn to provide a subcritical
shutdown margin should a reactor trip be required
during the warmup.
After reaching about 250 psig (1.83 MPa) in the
RCS and with one or more RCS pumps running, the
system high points and control rod drives are vented
to release noncondensable gases. Venting of the drives
is particularly important because gas in the control
drive path can interfere with the hydraulic snubbers
which prevent impact of the rods upon trip.
Upon reaching HZP conditions, excess heat from
the RCS pumps is removed by the turbine bypass system. This maintains constant RCS temperature and
steam pressure conditions.
Initial reactor criticality is achieved in one of two
ways. One method is to dilute the boric acid concentration in the RCS until a subcritical margin is
achieved. Criticality is then achieved by slowly withdrawing the control rods. A second method is preferred
by most B&W plant owners. All control rods are withdrawn while maintaining subcriticality by boric acid
concentration. The concentration is then diluted until
criticality is achieved. After initial criticality is attained,
a series of zero power physics tests are performed:
1. Control rod reactivity worth This verifies that the
individual rod worth, control rod group (banks) rod
worth, and total rod worth are within acceptance
criteria. The tests must show that the control rod
worth is capable of power operation. Performance
of the safety function, which brings the reactor to
a subcritical condition following a trip, is also verified. Typical control rod reactivity worth for each
of seven banks is shown in Table 2.
2. Core reactivity coefficients The reactivity coefficients are the moderator deficit (or coefficient), the
fuel temperature (Doppler) coefficient, the RCS
pressure coefficient and the power (overall) coefficient. This testing verifies that the reactivity coefficients are within acceptance criteria and that
the power coefficient is negative at levels above
about 20% power.
3. Soluble poison (boric acid) reactivity worth Tests
are conducted by exchanging control rod position
with soluble poison concentration to determine
that the reactivity worth of the poison is within
core acceptance criteria. Boric acid dissolved in the
reactor coolant is used to limit the core’s reactivity
throughout the fuel cycle. The boron concentration at HZP is about 1500 ppm. As xenon and other
reactivity poisons build into the fuel and the fuel
is depleted, the boron concentration is reduced to
maintain full power (see Fig. 20).
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
Table 2
Control Rod Group Reactivity Worths
at Hot Zero Power, Beginning of Fuel Cycle
Group
1
2
3
4
5
6
7
Total
Purpose
Reactivity Worth
% ∆ K/K
Safety
Safety
Safety
Safety
Control
Control
Control
0.95
3.05
0.79
1.75
1.15
1.26
1.17
10.12
4. Nuclear instrumentation range and overlap tests
At criticality, the three neutron detector ranges
(startup, intermediate and power) must be on scale
and must have the proper overlap. Testing is conducted at initial criticality to assure proper neutron detection signal strength.
5. Pseudo-control rod ejection tests In addition to the
standard control rod testing, pseudo-control rod
tests are performed. This testing assures that the
control rod with the most reactivity worth does not
exceed the licensed limits.
The zero power physics tests as well as testing of
the protection systems are performed to:
1.
2.
3.
4.
measure operational parameters,
measure performance against design criteria,
provide compliance with NRC requirements, and
obtain data for design improvements and potential power upgrades.
operating performance of the turbine bypass system,
feedwater system, and the feedwater and steam pressure controls is tested for the first time. Initial heat
balances are performed by calculating the primary
heat balances (RCS flow and temperature change
across the reactor) and the secondary heat balances
(feedwater flow and enthalpy rise across the steam
generators).
The heat balances, in addition to RCS flow measurements, permit calibrating the nuclear instrumentation
using the plant thermal power as a baseline. The secondary heat balances also provide an initial cross
check of the RCS flow measurements.
Near the completion of 15% power level testing, a
reactor shutdown from outside the control room is
performed. Reactor control is from a remote panel and
the reactor is brought to and maintained at HZP conditions. This test demonstrates safe control and shutdown of the unit should a fire or toxic gas require the
operators to evacuate the main control room.
The performance at the next power plateau is extrapolated from the previous plateau. For example,
operation at the 45% power plateau is estimated from
the operating experience at the 15% plateau. Following satisfactory operation at 15% power, the system
may be placed in automatic control and the power level
raised to the 45% level. Power escalation, however, is
typically performed with the reactor in manual control and the feedwater and steam systems in automatic
control. As the power is raised above 15%, the turbinegenerator is brought up to speed, loaded and synchronized to the electrical grid. At the 45% power level,
heat balances are again calculated and the neutron
power and RCS flow are calibrated. Control system
Most initial operation parameters are recorded by
special equipment and by the plant computer.
Power ascension tests
After completion of the zero power physics tests and
low power operation (5% or less), the power is raised
in stages. Typically, the power plateaus are 15, 45,
and 75% and full power.
The objectives of power escalation include:
1. determining the plant operating characteristics,
2. familiarizing the operators with the plant,
3. verifying that the plant is capable of operating
safely and within the design and technical specifications,
4. verifying that the operating procedures provide reliable operation, and
5. bringing the unit to rated capacity.
Testing at each stage includes operating the reactor systems and the entire power plant. The test time
at each plateau is sufficient to provide adequate operator familiarization and training.
Operation to the first test plateau is by manual control of the reactor and with the turbine-generator offline. Plant heat removal is by the turbine bypass system, which controls steam flow from the steam generators to the condenser. In this low power range, the
Steam 41 / Nuclear Services and Operations
Fig. 20 Boron concentration in the RCS during a fuel cycle.
49-19
The Babcock & Wilcox Company
tests, consisting of decreasing and increasing power
ramps, are also conducted. At the 45% power level, the
in-core instrumentation (rhodium detectors) is on-line,
and the core performance indicators can be investigated by mapping the core power distribution.
Following successful testing at the 45% power level,
the power is raised to about 75%. During this increase,
the second main feed pump is typically placed in operation at about 45 to 50% power. Heat balances at
75% power are again calculated for the reactor and
the secondary systems, and the neutron detectors and
RCS flow are calibrated.
Testing with three of the four reactor coolant pumps
is conducted at 75% power. This provides the core and
RCS temperature distribution characteristics. It also
verifies proper feedwater flow to the steam generators.
Ramp power changes at rates up to 10% per minute
are also conducted at the 75% power level. This tests
the control system operation and permits control setting changes.
As testing is completed at the 75% power level, the
unit’s performance is reviewed and its full power performance is extrapolated. The reactor is then gradually raised to full power and further testing preparations are made.
At full power, the RCS and the secondary system
heat balances are again performed, the neutron instrumentation is calibrated, and final reactor coolant
flow calibrations are performed.
During steady-state, full power operation, power
maps are obtained from the in-core neutron monitors
and the core neutron flux distribution is evaluated
against the acceptance criteria. Final tests of the reactivity coefficients, control rod worth and boron reactivity worth are also performed and compared with
design values.
Several important safety tests are conducted at the
100% power level, including:
Acceptance testing
After testing at full power is complete, final acceptance testing is performed before turning the unit over
to the utility. Acceptance testing demonstrates that
the steam pressure, flow and temperatures meet specifications and that the electrical output of the turbinegenerator is as designed. Additional tests, such as transient capability, operation with three of four RC
pumps, and load rejection capability are often included
in the acceptance testing.
Typically, steady-state acceptance testing to demonstrate that steam conditions and electric generation
meet the warranties is carried out for about 100 hours.
Parameters such as reactor power, RCS temperatures,
feedwater flow and temperatures, steam temperature
and pressure, and electrical generation are monitored
to maintain a running account of the performance.
Transient tests are scheduled and are typically of
short duration. A typical transient acceptance test is
as follows. Power is reduced from 100 to 60% at the
design rate. Power is held at 60% until peak xenon
poison builds into the core, which is normally six to
eight hours after power reduction. The unit is then
returned to full power at the design rate. This test
demonstrates the transient capability of the control
systems, as well as the boron-handling system’s capability to dilute and then increase the RCS boric acid
concentration.
Certain plant parameters, and those necessary to
demonstrate performance, are recorded. The data are
used for performance evaluation and to demonstrate
that the warranties are met.
Upon satisfactory completion of the acceptance tests,
the plant is turned over to the utility and begins commercial operation.
1. RC flow coast down testing For first-of-a-kind
plants, the RCS pumps are tripped in various combinations to characterize the flow coast down performance and to test the trip functions related to
loss of RCS flow or pumps.
2. Reactor trip testing A reactor trip test is performed
from full power to verify that the control rod insertion rates, the pressurizer performance, and the
control of steam pressure and feedwater flow are
within acceptance criteria.
3. Loss of off-site power Testing of the unit’s response
to separation from the electrical grid is conducted
to verify that performance during the subsequent
reactor trip, startup of the emergency diesel generators, operation of the turbine driven emergency
feedwater pumps, and the natural circulation of
the RCS are within acceptance criteria.
4. Control system tests Steady-state and transient
control systems are tested at full power to verify
their performance.
5. Turbine trip testing The turbine-generator is tripped
at full power to verify that the turbine, the main steam
system, the RCS, and the feedwater system perform as
designed to bring the unit to reduced power.
Most U.S. nuclear power plants are base loaded,
primarily because of associated lower fuel costs. During base load operation, the plant operates at or near
full power, regardless of demand.
49-20
Commercial operation
Electrical power production
The main control room and its adjacent control
equipment, offices and work areas form the center of
nuclear plant operations. The operations personnel,
including the reactor operators, auxiliary operators
and supervisory personnel, perform their functions in
and around the control room. All control stations,
switches, controllers and indicators necessary to start
up, operate and shut down the nuclear units are located here. Operations that maintain safe conditions
after upsets are also coordinated from this central control room. Controls for certain auxiliary systems are
located at remote stations.
The station operator has many duties including
monitoring plant performance and making adjustments as necessary. The operator must periodically
reduce the RCS boron concentration, as indicated in
Fig. 20. This compensates for reactivity loss due to fuel
burnup and maintains full power with the control rods
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
within a specified operating band. The operator must
also maintain a log of operations, review and approve
maintenance activities, and supervise and perform
surveillance tests.
One of the most time consuming functions of the
plant operating staff is scheduling and performing
mandatory surveillance testing of the safety equipment. There are about 400 surveillance tests required
for each nuclear power plant. The emergency diesel
generators, for example, are tested monthly. Most fluid
systems, such as high pressure injection, emergency
feedwater and decay heat removal, are also tested
monthly. Finally, the reactor protection system and related safety systems are tested on a similar schedule.
During power production, the staff conducts maintenance on accessible systems and plans the inspection, maintenance and repair work scope for the next
planned outage. Preventive maintenance and, more
recently, reliability centered maintenance programs
have been instituted and have contributed to improved station reliability.
Nuclear power plant operations are audited periodically by teams from the Institute for Nuclear Power
Operations and the NRC.
References
1. Pressurized Water Reactor Primary Water Chemistry
Guidelines, Vol. 1, Rev. 5, Electrical Power Research Institute (EPRI), 1002884, Palo Alto, California, September,
2003.
2. Pressurized Water Reactor Primary Water Chemistry
Guidelines, Vol. 2, Rev. 5, EPRI, 1002884, Palo Alto,
California, September, 2003.
3. Pressurized Water Reactor Secondary Water Chemistry Guidelines, Rev. 5, TR-102131-R5, EPRI, Palo Alto,
California, 2000.
Inconel is a trademark of the Special Metals Corporation group
of companies.
+Point and X-Probe are trademarks of Zetec, Incorporated.
Steam 41 / Nuclear Services and Operations
49-21
The Babcock & Wilcox Company
Fig. 1 Key areas of service and life extension in a pressurized water reactor (once-through steam generator reactor shown).
49-22
Steam 41 / Nuclear Services and Operations
The Babcock & Wilcox Company
Chapter 50
Nuclear Equipment Manufacture
Many manufacturing operations for nuclear steam
supply system components are similar to those used
for fabricating fossil fueled equipment. However, the
unique requirements and geometry of nuclear components call for special manufacturing methods,
equipment and facilities. Nuclear equipment must
operate reliably with minimal maintenance because
of its operating environment. For this reason there are
rigorous equipment specifications by customers and
regulatory authorities. Quality assurance requirements are stringent and special attention must be
given to cleanliness and material control.
Selecting the manufacturing sequence and methods requires balancing design requirements with
manufacturing capabilities while meeting commercial
obligations. As a result, special equipment and fabrication sequences are usually required.
Typical component description
Commercial nuclear components are typically cylindrical pressure vessels. Some of the components are
large and heavy and require customized shipping and
handling arrangements. Reactor vessels and components for pressurized water reactor (PWR) systems up
to 32 ft (9.75 m) in diameter, 125 ft (38.1 m) long and
weighing 1000 t (907 tm) have been built by The Babcock & Wilcox Company (B&W). Some nuclear components also have close assembly tolerances. This requires
specialized equipment and extraordinary care during
machining and welding operations.
drive mechanism (CRDM) tubes penetrate the hemispherical section and are welded at the inside surface.
Similar tubes for venting and instrumentation may
also be present, and follow the same general arrangement. In recent years, plant owners have replaced
reactor closure heads because of stress corrosion cracking of the weld between the head and the reactor
CRDM tubes, and boric acid wastage of the carbon
steel base material. (See Chapter 46.) The inside of
the reactor vessel includes many attachments for the
fuel support system. (See Chapter 49.) Since there
have been no reactor vessels manufactured recently
by B&W, this section will only focus on reactor vessel
components, such as the reactor closure head.
Fabrication of replacement reactor
vessel closure heads
The closure head has a hemispherical dome with a
bolting ring flange. The closure heads for typical B&W
reactors measure 16.67 ft (5.08 m) outside diameter
(OD), with a dome radius of approximately 7.25 ft
(2.21 m) and a nominal dome thickness of 7 in. (178
mm). The bolting ring flange is 30 in. (762 mm) thick.
Manufacture of reactor vessel components
Different reactor systems have differing reactor vessel designs. B&W has experience in several systems,
including the PWR, which is the focus of this chapter.
Each reactor vessel is made up of a cylindrical main
section and two hemispherically shaped heads. The
reactor closure head is attached by a bolted flange and
has several penetrations for the reactor control rods,
venting and/or instrumentation (Fig. 1). Control rod
Steam 41 / Nuclear Equipment Manufacture
Fig. 1 Reactor vessel closure head.
50-1
The Babcock & Wilcox Company
Typical replacement closure heads are fabricated from
a one-piece forging. This eliminates the periodic inservice inspection required for pressure boundary
welds. Large diameter heads may have their hemispherical portion made from a single forged partial
hemisphere with additional forged rings or segments
that are welded together. The bolting ring is forged
separately and welded to the hemisphere. All reactor
components made of ferritic material have their internal surfaces clad with austenitic stainless steel or
Inconel® to provide resistance to corrosion from the reactor coolant. The cladding can be applied using various
welding methods such as submerged arc welding (SAW)
or gas metal arc welding (GMAW) using wire or strip.
Critical features There are several critical features
on the closure head that must be fabricated to close
tolerances. The gasket surface on the bolting ring
must be flat and have the required surface texture
and lay to ensure a leak-tight joint. The CRDM center lines must be true to the axis of the head and the
CRDM tube diameters must be held within tightly
controlled tolerances to ensure that the operation of
the control rods is not hampered in any way. The weld
between the CRDM tube and the head is designed and
fabricated to avoid residual stress and to maintain the
position of the CRDM tube. It is critical to control residual stresses during the manufacturing process to
avoid stress corrosion cracking of the closure head
during operation. Residual stress is controlled during
manufacture by limiting the cold work and by
electropolishing the CRDM tubes and welds.
Machining The CRDM tube weld preparations (preps)
are machined on a computer numerical control (CNC)
horizontal boring mill. Machining the geometry of the
weld prep requires careful three-dimensional modeling
and programming of the tool path because the geometry
varies depending upon the radial location of the hole on
the head. The stud holes and CRDM penetrations are
drilled using a trepanning cutter (Fig. 2).
Testing and inspection The closure head is tested
and inspected to the requirements of the American
Society of Mechanical Engineers (ASME) Boiler &
Pressure Vessel Code Section III and V. Material testing includes chemistry and mechanical properties and
may include other tests such as ultrasonic, hydrostatic
and surface finish depending on the material form and
application. Fabrication testing includes magnetic particle (MT), dye penetrant (PT), radiographic (RT) and
ultrasonic (UT). Pressure testing includes hydrostatic
testing of the tube material and the closure head assembly. This is done by using a thick circular disc that
is bolted to the head using tooling studs (Fig. 3).
Electropolishing Electropolishing is an electrochemical technique that removes a very thin layer of
material from a work piece. Electropolishing can be
used to smooth a surface or to remove a cold worked
layer of material to reduce residual stress. The work
piece is connected electrically as an anode and, along
with an adjacent cathode, simultaneously brought in
contact with an electrolyte. The amount of material
removed is a function of the electrolyte chemistry and
flow, the electrical current and exposure time.
Electropolishing is applied to CRDM nozzle welds to
50-2
Fig. 2 Horizontal boring mill used to drill holes in reactor pressure
vessel head.
reduce residual stress and is applied to once-through
steam generator (OTSG) tube support plates to
smooth their surface.
Manufacture of steam generators
B&W manufactures once-through steam generators
(OTSG) and recirculating steam generators (RSG) for
PWR and Canada Deuterium Uranium (CANDU) reactor systems. (See Chapter 48.) Both steam generators have many components and manufacturing methods in common. The following sections describe the fabrication of the common components and the manufacture of items that are unique to each design. Fig. 4 shows
a simplified cross section of an RSG, and Fig. 5 shows a
simplified cross section of an OTSG. An RSG consists of
cylindrical and conical shells, hemispherical heads,
nozzles, a tubesheet, U-tubes, lattice grid or broachedhole tube supports, baffle and divider plates, a shroud,
and steam drum internals. A typical RSG is about 75
ft (22.9 m) long, 12 to 15 ft (3.7 to 4.6 m) in diameter
and weighs up to 400 t (363 tm). An OTSG consists of
cylindrical shells, hemispherical heads, nozzles, two
tubesheets, broached-hole tube support plates, straight
Fig. 3 Hydrostatic testing of closure head assembly.
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
Fig. 4 Advanced series recirculating nuclear steam generator.
tubes, a shroud, and feedwater inlet header. A typical
OTSG is about 73 ft (22.3 m) long, 12 ft (3.7 m) in diameter and weighs up to 470 t (426 tm).
Cylindrical shells
The shell courses used in fabricating the cylindrical portion of the steam generators may be made from
forged ring sections or from plate formed by rolls as
shown in Fig. 6. The rolling method depends upon the
size, thickness and material. Cylindrical shells for
steam generators are typically less than 4 in. (101.6
mm) thick and are cold rolled. Some designs require
thicker sections near the tubesheet area or where reinforcement for nozzle openings is required. These
shells are usually hot rolled.
For shells made from rolled plate, the longitudinal
seam of each course is submerged arc welded using
an automatic guidance system. In preparation for
circumferentially welding several courses, each course
edge is machined to improve weld quality. The sections
are then aligned, tack welded and set up on drum rotators. A stationary submerged arc welder, automatically guided, is positioned over the seam and the circumferential welds are made while accurately rotating the drum.
Steam 41 / Nuclear Equipment Manufacture
Fig. 5 Once-through nuclear steam generator.
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The Babcock & Wilcox Company
Steam generator heads
Fig. 6 Cold rolling plate for steam generator cylindrical shell.
The advantage of using forgings for cylindrical shells
is the elimination of the longitudinal seam. This eliminates the cost of making and examining the weld during manufacture, and eliminates the need to conduct
in-service inspection of the weld. Forged cylinders can
usually be made to tighter diameter tolerances.
Tubesheet manufacture
The tubesheet is made from a forging that can weigh
up to 80 t (73 tm). The first major manufacturing operation is cladding the primary side of the tubesheet
with stainless steal or Inconel using GMAW welding
methods, discussed in Chapter 38. The tubesheet is
heated before, during and after welding using large
electric heaters. Usually the welding head is moved
over the stationary tubesheet, however, in some cases
the tubesheet geometry requires it to be rotated under a stationary welding head. In these cases, speed
control of the rotator is critical to maintaining weld
integrity. The clad tubesheet is post weld heat treated
to 1125F (607C). The cladding is then machined and
examined using UT. Cladding thickness after machining is typically 0.3125 in. (7.9 mm).
Drilling the holes through which the tubes are inserted is the most critical operation for tubesheet manufacture. A typical tubesheet is 24 in. (610 mm) thick and
has up to 15,000 holes or more ranging in diameter from
0.5 to 0.875 in. (12.7 to 22 mm), depending upon the
tubing size. These holes must be located accurately, be
precise in diameter, and be straight and perpendicular
to the tubesheet surface. Variations from perpendicularity, often called drill drift, are typically limited to 0.015
in. (0.38 mm) through the thickness of the tubesheet.
Extreme care is therefore given to gundrilling.
Gundrilling is done on a multi-spindle, computercontrolled horizontal drilling machine (Fig. 7).
Gundrills are designed to drill holes with large depthto-diameter ratios. Coolant travels through the center of the drill and removes cutting chips through a
channel along its shank.
Regular dimensional and visual inspections of the
drill tools and the hole diameters and locations are
conducted. After gundrilling, the tubesheet has its circumferential weld preparations machined on a vertical or horizontal boring mill.
50-4
Recirculating steam generators The primary head
of an RSG is typically 10 ft (3.1 m) in diameter, 6 in.
(152.4 mm) thick and weighs up to 35 t (31 tm). Primary heads used in PWR plant steam generators are
clad on the inside surface. Similar ferritic material
primary surfaces on CANDU RSGs do not require
cladding. Two or three nozzles as large as 41 in. (1041
mm) in diameter are attached to the head. The head
is mounted on a large capacity welding positioner so
that it can be properly oriented for submerged arc
welding of nozzles and attachments. Several attachments for internal components, such as the divider
plate seat and manway hinge, are also welded to the
inside surface of the head.
The steam drum head on an RSG is either semi-elliptical or hemispherical, is forged or formed from plate,
and is up to 15 ft (4.6 m) in diameter. It also contains
one large diameter 30 in. (762 mm) steam outlet
nozzle. The nozzle to head weld is performed using
the submerged arc welding process.
Once-through steam generators The primary head
of an OTSG (Fig. 8) is similar in size to an RSG and is
also clad on the inside surface. However, there is no
divider plate in the primary head of an OTSG. The
lower head is set up on a boring mill and the base
support weld prep is machined. The manway gasket
seat and stud holes are drilled and the threads milled.
Fig. 7 Gundrilling a tubesheet.
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
Pressure boundary assembly
Pressure boundary components include the cylindrical shells, heads, the tubesheet, and external and
internal supports.
Alignment, welding, nondestructive examination
(NDE), PWHT and machining are critical operations
when assembling these components. The sequence of
adding nozzles and attachments depends on the accuracy requirements and anticipated weld distortion
during assembly. If there are tight tolerance requirements on the location of nozzles and attachments,
these features are machined after final assembly and
PWHT of the pressure boundary components. However, this adds to the critical path schedule and, where
it can be accommodated, these features are attached
to the individual components and machined prior to
component assembly.
Circumferential weld seams are typically made with
submerged arc welding (SAW) (Fig. 9). The components are aligned and then rotated under a stationary submerged arc weld head. The welds are generally two-sided (first welded on the inside and then on
the outside of the wall thickness) so that the root of
the weld can be ground clear prior to welding the opposite side. If access to the inside is restricted, the
welds are one-sided and are made from the outside.
This requires precise alignment of the mating weld
preps to avoid any defects at the root of the weld. This
area may have restricted access for grinding and examining the surface. The welds receive surface NDE
(MT, PT) and volumetric NDE (UT, RT). The ASME
Code specifies when these examinations shall be made
with respect to the PWHT.
The OTSG pressure boundary assembly has some
unique differences from an RSG, mainly because the
second tubesheet must be installed after the shroud
and tube bundle supports are installed. The lower primary head is installed after the tubes are inserted.
This sequence is explained in more detail later in this
chapter.
Pressure boundary post weld heat treatment PWHT
is an important consideration in planning the assembly of a steam generator. All carbon steel pressure
boundary welds require PWHT. In the assembly sequence, these welds must be accessible for NDE after
PWHT, as specified by the ASME Code (Fig. 10).
PWHT is conducted on as large an assembly as possible to save on the cost of the PWHT furnace operation. Offsetting this are the risk and cost of having to
re-PWHT this large assembly in the event of a major
weld repair. Consequently, an assurance NDE is conducted prior to PWHT. If there are many complex
welds in an assembly, a subassembly of these components may receive its own PWHT and NDE.
Fig. 8 Once-through steam generator primary head.
Fig. 9 Submerged arc welding.
The base support is fitted and set up on a weld
positioner for submerged arc welding. The primary
nozzles are fit and welded using an orbital gas tungsten arc welder (GTAW) that travels around the weld
seam utilizing specialized guidance systems, and video
cameras to provide visibility for the operators. This
equipment is necessary due to the restricted access
around the weld seam created by the base support.
All nozzle welds are backclad to ensure that there is a
continuous corrosion resistant cladding on surfaces in
contact with primary side water. The welds then receive a post weld heat treatment (PWHT) and volumetric examination by ultrasonic testing (UT) or radiographic testing (RT), and surface examination using magnetic particle (MT) or dye penetrant testing
(PT). The head is then set up on a vertical boring mill
and the base support and circumferential seam weld
prep are machined.
Steam 41 / Nuclear Equipment Manufacture
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The Babcock & Wilcox Company
Fig. 10 Radiographic examination of a steam generator weld.
The pressure boundary assembly is prepared for
PWHT by sealing all openings. The tubesheet holes
are cleaned to ensure that all contaminants that might
adhere to the surface during PWHT are removed.
Thermocouples are attached in strategic locations to
monitor and control the heating and cooling operation
and to ensure that the welds achieve their required temperature. The vessel is filled with argon, which is slowly
circulated through the inside of the vessel during PWHT
to eliminate oxidation. The pressure boundary is then
heated in a computer-controlled gas-fired furnace.
PWHT of RSG pressure boundary PWHT can cause
significant temperature differences and thermal stress
in the pressure boundary assembly, especially if its
geometry is complex. Therefore, the pressure boundary is assembled and post weld heat treated prior to
installation of the tube bundle to avoid harmful differential thermal expansion effects. The primary head
is welded to the tubesheet prior to the tube bundle assembly to avoid PWHT effects, although this means
that the tube seal welding must be done in a confined
area. After installing the tube bundle, the final closing seam is welded and locally heat treated. This is
described later in this chapter. The welds are then examined according to ASME Code.
PWHT of OTSG pressure boundary The upper tubesheet and upper primary head of an OTSG are installed after the shroud and bundle supports are installed. These two circumferential seams receive a local PWHT. The straight tubes are inserted through
the lower tubesheet and seal welded at both ends. Then
the lower primary head is installed. The circumferential seam between the lower primary head and lower
tubesheet requires local PWHT after welding. These
operations are described later in this chapter.
Tube bundle components
Tube support assemblies The tube supports of modern RSGs are lattice grids. These grids consist of a ring
assembly and a grid of flat bars that are assembled in
the ring to form the lattice pattern. The flat bars intersecting each other on their edges form a diamond shape
around each tube. This provides good vibration dampening yet allows the steam-water mixture to flow through
the bundle with minimal pressure drop (Fig. 11).
50-6
Lattice grids (see also Chapter 48) must be accurately
manufactured so each diamond is precisely aligned with
the tubesheet drilling pattern. During tube bundle assembly, each tube is inserted through each grid then
through the holes in the tubesheet. The accuracy of the
lattice grids determines the ease with which the tube
bundle is assembled.
The most critical operation in manufacturing lattice grids is cutting slots in the rings and bars where
the bars intersect and fit together. Slotting is done
using a special milling cutter setup driven by a boring mill. It is extremely important for the cutter setup
to be accurate and the work piece to be set up true to
the machine to control slot depth and angle. The mill
must be calibrated to ensure that it is capable of precisely positioning the tool. CNC machines are essential to ensure consistent quality. After final assembly,
the completed grid is inspected to verify that the diamonds are properly located.
OTSGs use broached tube support plates (TSP) to
support the bundle. These TSPs are typically flat
plates made of stainless steel that are drilled to the
tube bundle pattern using a multi-spindle drill. Each
hole is then machined by broaching so that the final
hole shape resembles a trefoil pattern consisting of
three contact areas that support the tube and three
enlarged areas that allow flow through the plate (Fig.
12). Broaching is done on a multi-spindle CNC ma-
Fig. 11 Lattice-grid tube supports.
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
chine that pulls the broaches through the plate vertically downward (Fig. 13). Before broaching, the holes
are tapered on one or both ends depending upon their
location in the bundle to accommodate tube bundle
assembly and to provide improved pressure drop for
secondary side flow. After broaching, each plate is
electropolished by immersing the plate into a tank
containing electrolyte and passing appropriate current between the plate and a nearby cathode.
Electropolishing removes burrs and smooths the surface to avoid damage to the tubes during insertion.
Baffle plates Baffle plates are installed in the
preheater section of RSGs to direct water flow. Baffles
are fabricated from machined plates. The plates are
normally drilled by assembling them into a tightly
clamped stack using bolts and welds and then
gundrilling. Drilling a stack of plates requires the
plates to be ground flat and to uniform thickness to
ensure that the holes in individual plates have accurate perpendicularity to their individual plate surface.
Generally, larger diameter baffle plates are best drilled
individually using a gantry drill because of the difficulty of clamping, handling and accurately drilling a
stack of large diameter plates.
U-bend supports The tube U-bends (Fig. 14) of RSGs
are protected from flow-induced vibration by U-bend
supports. These consist of an assembly of stainless steel
flat bars that are GTAW welded to a collector bar to form
a fan bar assembly. Some types of stainless steel require
that these GTAW welds receive a PWHT in a controlled
atmosphere. The angular separation of the fan bars
depends upon the U-bend size and flow conditions, and
the bars are located to minimize unsupported tube
lengths. The fan bar assemblies are installed between
the tube rows, and the outer ends of the fan bars are
joined after assembly in the bundle with an arch bar.
The U-bend support assembly is not connected to the
shroud, thus allowing the assembly to float with the
tube bundle during operation.
Tube bending Tubes for steam generators are typically 0.5 to 0.875 in. (12.7 to 22 mm) diameter with a
typical nominal wall thickness of 0.045 in. (1.14 mm).
Fig. 12 Broached tube support plate.
Steam 41 / Nuclear Equipment Manufacture
Fig. 13 Multi-spindle CNC broaching machine.
In the OTSG design, the bundle consists of straight
tubes. In the RSG, bundles are composed of U-tubes.
The U-tubes must have accurate bend radii,
straight leg lengths, and must be within a strict ovality
and wall thinning tolerance. These tolerances are required to ensure that tolerance stack-up does not cause
interference in the U-bend region. To achieve these
tolerances, the tubes are purchased to a length tolerance of 0.125 in. (3.18 mm). The tubes are formed on
a draw bender over dies to a radius tolerance of ±0.03
in. (0.8 mm). The dies for the tight radius bends are
Fig. 14 U-bend tube supports.
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The Babcock & Wilcox Company
Tube bundle assembly
The tube bundle is assembled in a clean room (Fig.
15) to ensure that the components are not contaminated. Cleanliness and material control procedures are
carefully monitored. All internal components are
cleaned just prior to enclosing them.
Installation of shroud and bundle supports The shroud
must be installed and aligned to ensure that the tube
bundle supports can be aligned with the tubesheet drilling pattern. The shroud is installed horizontally by
using wheels or bearing rollers bolted onto one end. This
allows the tubesheet end of the shroud to roll into the
shell as a crane supports the other end and provides a
horizontal push. The shroud is then aligned using pins
located around its circumference.
If the RSG design includes an integral preheater,
a secondary divider plate is installed with a powered
cart, which also adjusts the position of the divider
plate. This plate fits into grooves in the shroud. The
preheater baffle plates are then installed by mounting them on the end of a boom that is driven by a floor
mounted power unit. The holes in the baffle plates
must be aligned with those in the tubesheet.
Baffle plates are supported by tie rods machined to
length that ensure parallel placement of the plates to
the tubesheet. The baffle plates must have radial
clearance to allow for thermal expansion. This clearance, however, creates an installation problem because the baffles must support the tube bundle and
remain in alignment with the tubesheet while the
tubes are being installed. This problem is overcome by
installing a special shim that fits into the clearance
between the baffle plates and the shroud. This shim
dissolves during vessel operation, thereby maintaining the proper clearance.
The lattice grids for RSGs are installed by mounting them on a boom (Fig. 16). The grids are aligned
with the tubesheet using optical scopes mounted on
the primary side of the tubesheet. A small target is positioned in selected tube locations on the lattice grids,
and the grid is adjusted using wedges around its circumference until the target aligns with the scope’s line
of sight. Alignment rods that are the same diameter
as the tube are also used to check the alignment of
the lattice grids. The grids are held in place by support blocks welded to the inside of the shroud.
To ensure that the tubes can be installed in an
OTSG without misalignment or damage to their surface, it is critical that the TSPs are aligned with the
hole pattern in the tubesheet and are parallel to the
tubesheet face. The TSPs for OTSGs are connected
together with tie rods. The first set of tie rods is installed into the tubesheet, and the ends are checked
with a coordinate measuring machine to ensure they
provide a flat plane for the first TSP to rest against.
Support blocks are aligned and welded to the shroud,
providing support to the circumferential edge of the
TSP. The first support plate is installed and aligned
using similar optical techniques to that used for aligning lattice grids. Then, wedges and keys are installed
to firmly support the TSP and to keep it in alignment
during rotation of the vessel for subsequent manufacturing operations. This sequence is repeated for each
TSP. After all the TSPs are installed, the top tubesheet
is set up on an alignment fixture in preparation for
installation. Optical alignment scopes are set up, and
the tubesheet is fit to the cylindrical shell. Ceramic
backing bar is installed to the inside diameter of the
circumferential seam along with alignment wedges.
Fig. 15 Nuclear clean room.
Fig. 16 Installation of lattice grid tube bundle support.
designed to contain the tube and to minimize ovality
during bending. After the tubes are bent, they are
dimensionally checked to verify that all tolerances
have been met.
Shrouds The shrouds are fabricated from steel
plates rolled into cylinders and their longitudinal
seams are joined by SAW. The sections of the shroud
near the preheater section of the RSG may have their
inside diameters machined round. This ensures that
baffle plates can slide axially and can expand during
various operating conditions. These shroud sections
for RSGs may also contain manifolds to distribute the
incoming feedwater and recirculating water.
It is critical to ensure that the inside radius of the
shroud is accurate so that the required clearance exists
to allow lattice grids and baffles to be aligned with the
tubesheet pattern. The inside radius of the RSG shroud
is measured by projecting a laser down its centerline and
using a radial micrometer. Alternatively, an optical instrument can be used in a similar setup.
50-8
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
After fitup and alignment have been confirmed, the root
passes of the weld are made while monitoring the alignment. The ceramic backing bar is removed, the optical
instruments are removed, and the remainder of the
weld is completed with SAW. The completed seam then
receives MT, UT (Fig. 17) and RT.
Installation of tubes Tubes are installed with the
vessel in a horizontal position. Each tube hole and
tube are dry-swabbed clean just prior to assembly.
Cleaning operations at this stage are done without
liquids. Any moisture or contaminants trapped between the tube and tube hole can cause tube-totubesheet welding defects.
In an RSG, the U-tubes are fitted with a plastic tube
end pointer and installed in layers from the smallest
bend radius tubes to the largest bend radius tubes
(Fig. 18) starting with the lowest layer. This tubing
sequence simplifies the temporary supports that must
be installed to keep the U-bend supported during tube
installation. As each layer is installed, the appropriate U-bend support fan is installed. The partially completed bundle is temporarily supported to prevent sagging due to the weight of the tubes. Each U-tube is
inserted until it protrudes the specified amount from
the primary face of the tubesheet. This amount of
protrusion depends upon whether the tube-totubesheet weld is a fillet weld or a flush weld. The
installer also checks for proper clearance between each
U-bend. The tubes are tack expanded by inserting an
expander inside the tubes about 0.75 in. (19 mm). The
expander consists of a split collet actuated by a hydraulically driven tapered mandrel. This yields the
tube sufficiently to hold it in place and to close the gap
for welding. This expansion method produces less residual stress in the tube than other methods, such as
roller expansion.
In an OTSG, the straight tubes are fitted with plastic tube end pointers, cleaned, and installed in layers
starting from the top layer and working down. This
tubing sequence avoids any particulate matter that
may be picked up by the tube during insertion from
falling down onto tube ends that have already been
installed. This sequence also simplifies retrieval of a
tube end pointer in the unlikely event that one comes
loose during tube insertion. Tubes are inserted
through the bottom tubesheet, through the TSP assembly, and through the upper tubesheet. The tubes
are inserted so that the correct tube projection is
achieved at the upper tubesheet. The tubes are then
tack expanded using the same tack expansion techniques that are used for RSGs. The tubes in the upper tubesheet are final tack expanded and seal welded.
The tube ends in the lower tubesheet receive an initial expansion to provide some support to the tube
while the tube ends are machined to the proper protrusion at the lower tubesheet. This is followed by a
final tack expansion.
Tube-to-tubesheet welding The tubes and tubesheets are joined with automatic gas tungsten arc
welding (GTAW). The tube-to-tubesheet welding
heads are specially designed units to provide welds of
consistent quality (Fig. 19). At the beginning of each
shift, each operator makes a tube-to-tubesheet weld test
Steam 41 / Nuclear Equipment Manufacture
Fig. 17 Ultrasonic inspection of seam weld.
Fig. 18 Installation of tubing.
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The Babcock & Wilcox Company
block. The block receives a visual and PT inspection, and
is then sectioned for further metallurgical examination.
Each weld is visually compared to a workmanship
sample. All welds not meeting the sample quality are
repaired and then rewelded. This is followed by PT
examination of all tube-to-tubesheet welds. Finally, a
leak test is done by pressurizing the secondary side with
a mixture of air and helium. The primary tubesheet face
is then monitored for helium leaks at the welds.
Tube expansion Each tube is hydraulically expanded into its hole after tube-to-tubesheet welding.
This expansion closes the crevice between the tube and
the hole to avoid a potential corrosion site. The tube
may be expanded near the secondary face of the
tubesheet or it may be expanded full depth or at the
primary face depending on customer specifications.
Hydraulic expansion is the recommended method for
nuclear steam generators because it produces less residual stress in the tube and reduces the potential for
stress corrosion cracking compared to other expansion
methods. Each tube is expanded by inserting a probe
that has a seal positioned at each end of the expansion
zone. Distilled water at approximately 35,000 psi (241.3
MPa) is pumped through the probe, expanding the
tube and sealing it against the tube hole.
The expansion probe must be carefully positioned
with respect to the secondary face of the tubesheet. If
the probe is positioned beyond the face, then unacceptable tube deformation could occur. If the probe is
too far inside the tube hole, an unacceptably long crevice could possibly result. Therefore, the tubesheet
thickness variation is measured and the probe length
is adjusted to ensure proper positioning.
Tubes located near the tubesheet periphery may
require expansion using special probes because the
curvature of the head encroaches on the probe insertion area. A flexible extension is attached to the probe,
which allows it to be inserted in confined areas. In
cases where the tube must be expanded full depth, the
Fig. 19 Tube-to-tubesheet welding.
50-10
expansion is done in two or more steps. Following expansion, each tube is examined with eddy current
testing (ECT) techniques.
Steam drum internals
RSGs require a steam drum and steam separators
to remove moisture from the steam (Fig. 20). OTSGs
provide steam at slightly superheated conditions and
do not require steam separators. The steam separators are similar in design to those used on fossil-fuel
boilers. Generally, the separators in nuclear steam
generators are an axial flow type, although tangential flow separators have been used. There are typically more than 100 separators in a large RSG. Most
designs also have smaller secondary separators located above the primary units.
The fabrication and assembly tolerances of steam
separators are critical. The shape and assembly clearances of internal components have a significant effect
on separator performance. Custom made assembly
jigs and fixtures are used to ensure that the required
tolerances are met. In addition, all internal welds are
carefully ground to avoid discontinuities that affect
separator performance.
The steam separators are installed in a deck structure made of steel plate. This deck support structure
is welded to the inside of the drum, and the supports
are designed to accommodate differential thermal expansion during steam generator operation as well as
loads due to specified accidental pipe break and seismic events. The separator and deck structure is usually of modular construction to simplify installation
into the steam drum.
Final assembly
Closing seam fitting and welding of RSGs The final
assembly operation for RSG fabrication consists of fitting and welding the closing seam, which is usually
one of the circumferential seams on the cone. The
steam drum and the cylindrical shell are positioned
on rotators and the circumferential seam is aligned.
Previous machining of the component mating surfaces
assures good alignment. The weld could be either a
two-sided weld if there is sufficient access to the inside of the vessel, or a one-sided weld. If a one-sided
weld is used, it is generally of a narrow groove design
to limit the volume of weld deposit. The sequence of
making a one-sided weld is described later.
Prior to starting work on the inside of the vessel,
the tube bundle and the steam separator assembly are
sealed off to prevent weld flux and other material from
entering. The drum and cylindrical shell are aligned
and the seam is tack welded to hold the components
in position. The next several weld passes are completed using shielded metal arc welding (SMAW). This
additional welding provides enough structural
strength to allow the assembly to be moved to a submerged arc welding station where the outside of the
weld is finished using SAW. As the vessel is rotated,
the weld is completed.
Due to access limitations at some sites installing
replacement RSGs, fitting and welding of the closing
seam may not occur until after the RSG is inside the
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
face to further control the temperature gradients.
Heat transfer by convection to the secondary side may
be controlled either by drawing a vacuum, or by providing air circulation, depending on the requirements
during heat-up or cool-down.
Fig. 20 Fabrication of steam separator subassembly.
containment building. In these cases, the lower half
of the steam generator is generally assembled to the
refitted upper half of the original steam generator.
Typically, the steam drum and head will be refit with
new separators and steam flow control equipment
before the closing seam is made with the steam generator vertical and in place.
Local PWHT of RSG closing seam The closing circumferential seam requires post weld heat treatment.
Because temperature differences during this procedure
can exceed those experienced during normal operation of the vessel, care must be taken to avoid excessive and harmful differential expansion of internal
components. Temperatures can be controlled using an
electric furnace designed to fit around the closing
seam. Insulation is applied to the outside of the vessel shell and to the attachments in the vicinity of the
seam. The tube bundle U-bend region is also insulated
to reduce radiant heat transfer. Internal heat transfer is further reduced by drawing a vacuum on the
secondary side of the vessel. During PWHT, air may
be blown through the tube bundle primary side to limit
tube temperature. Thermocouples are mounted in
each critical area to monitor and control the process.
The electric furnace has several zones that can be
independently controlled to keep the temperatures
within prescribed limits. A computer is used to control
the furnace and to collect data and provide a record
of temperatures.
Final assembly and local PWHT of OTSG pressure
boundary After the straight tubes are inserted through
the lower tubesheet, seal welded and helium leak
tested, the lower primary head is installed. The circumferential seam between the lower primary head
and lower tubesheet requires local PWHT after welding. This operation is complex because the tube bundle
will be partially heated during the operation. Temperature gradient limits are imposed to limit the
stresses in each component and to limit the loads on
the tubes due to the difference in coefficient of thermal expansion between the tubes and carbon steel
pressure boundary. An electrically heated clamshell
furnace is installed around each circumferential weld
seam. Supplementary electric heaters may be placed
on other components such as the tubesheet primary
Steam 41 / Nuclear Equipment Manufacture
Final inspection and testing
A hydrostatic test is done on the completed vessel;
the primary and secondary sides are tested separately.
The test consists of filling the vessel with treated water that is pressurized to 125% of the design pressure.
The pressure is reduced and held at the design pressure while an inspector examines the vessel for leaks.
The metal temperature must be held above 70F (21C)
to keep it well above its brittle transition temperature.
After hydrostatic testing, the vessel is drained and
dried. A vacuum is drawn on the secondary side to assist drying. Felt plugs are also blown through the
tubes to dry them. All accessible pressure boundary
welds are then examined by the MT method.
Nozzles and integral support surfaces, called terminal points, connect to mating components in the
field and must be within specified tolerances to simplify field installation and minimize stresses caused
by fitup. Special coordinate measuring machines (Fig.
21) are used to set up the tools used to machine the
final terminal point geometry (Fig. 22). It is common
practice to finish machine nozzle weld preps at this
stage to bring them within tolerance.
Just prior to closing the vessel, the insides of the
tubes are cleaned by blowing felt plugs through them.
The secondary side of the steam generator is examined and cleaned, and final drum internal components
are installed. All manway covers are bolted on. The
primary and secondary sides of the vessel are evacuated and backfilled with nitrogen to reduce the formation of oxides. Steam generators are wrapped in
shrink-wrap plastic to protect them during shipment.
Surface conditioning
Some steam generator owners specify that the inside surfaces of the primary side (excluding the tubing) are to be surface conditioned or electropolished.
This process produces a very smooth surface finish,
Fig. 21 Set up of nozzle machining tools using coordinated measuring machine.
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The Babcock & Wilcox Company
cars, the bunks must be designed to allow movement of
the load while negotiating curves. Additional ballast may
be attached to the rail car to lower the center of gravity.
Manufacture of pressurizers
Pressurizers are cylindrical vessels that help stabilize the pressure in the primary heat transport system. (See Chapter 46.) Each unit is fitted with special
penetrations in which electrical heaters are installed.
Fig. 22 Final nozzle end machining.
typically 10 microinches or better. This results in a significant reduction in true surface area of the work
piece which in turn reduces radioactive isotope update
and occupational exposure. Reduced occupational exposure makes these components more easily maintained in the field.
The first step in surface conditioning is to grind the
surface with abrasive flap wheels. Several passes are
required, each one made with progressively finer abrasives until a surface finish of 40 microinches is
achieved. This operation can be done by machine on
an individual component prior to assembly. However,
this is usually impractical because the component
must then be protected from surface damage for the
remainder of the manufacturing operation. Usually,
the grinding is done near the end of the assembly sequence with hand tools. This is a time consuming operation, especially if as-welded surfaces are involved.
The second step in surface conditioning is to impart
further improvements in surface roughness on a microscopic scale by electropolishing. In electropolishing,
an applied electric current flows from the metal surface (anode or work piece) through a conductive electrolytic solution to another conducting surface (cathode). This process smooths the micropeaks formed by
mechanical grinding.
Shipping
Steam generators may be shipped by rail or by special road transport directly to the plant site, or may
travel part of the way by barge or heavy lift ship. For
rail transportation, the load must be centered on the
car for even weight distribution. If the vessel is long,
it can span two railway cars. If it is short, a single
heavy-duty flat car is usually sufficient (Fig. 23). The
vessel is oriented to minimize its width and height and
is loaded onto bunks fastened to the car. Loads up to
16 ft (4.9 m) in diameter can be shipped along most
routes in the United States and Canada. Shipping
larger units requires measurement of bridge clearances
and other potential obstructions. If the vessel spans two
50-12
Pressure boundary assembly
The pressure boundary consists of cylindrical shells
and hemispherical heads. The pressure boundary contains a surge nozzle, spray inlet nozzle, several connections for electric heaters, and various small water level
nozzles. The manufacturing methods and quality assurance requirements for these components are the same
as those described previously for steam generators.
Heater connections and installation The heaters are
the direct immersion type, sheathed in stainless steel
or Inconel and assembled in bundles. In some designs,
the heaters consist of a single straight element. Each
of the elements is field assembled through penetrations
in the vessel wall and is sealed by means of a bolted closure. The closure is sealed by gaskets or patented mechanical seals. An electrical connection is then made to
the end of each heater using a special insulated fitting.
Post weld heat treatment
PWHT of pressurizers is simpler than that of steam
generators because there are no complex geometries
or internals that limit heating and cooling rates.
PWHT is done by putting the completed pressurizer
in a gas furnace and heating to 1125F (607C).
Some patented mechanical seals used for the heater
connections must be installed prior to PWHT because
of their required machined surface finish. This machining can not be done after the component is welded onto
the vessel because of inadequate access for specialized
equipment. As a result, the sealing surface is protected
from the furnace environment by coating it with an
antiscaling compound. Some minor surface dressing of
the sealing surface may be required after PWHT.
Fig. 23 Steam generator awaiting offloading to heavy lift ship.
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
Manufacture of dry shielded canisters1
Dry shielded canisters are part of a system of containers used to store and ship spent nuclear fuel. The
canisters are designed to safely store bundles of spent
fuel at plant sites, and some designs allow transport
to long-term storage sites. The design of the canisters
and internal structures serves as the containment
boundary to confine radioactive spent fuel and provide a leak-tight, inert atmosphere to ensure that the
integrity of the fuel cladding is maintained. A typical
canister consists of an outer cylindrical shell made of
stainless steel, typically 5.5 ft (1.7 m) in diameter by
15.5 ft (4.7 m) in length. The internal assembly consists of an array of guide sleeves that are square in
cross-section. Each one is designed to accept a bundle
of spent fuel. The guide sleeves are made of stainless
steel. The ends of the canisters are capped with shield
plugs that include lead shielding. Although many individualized components are similar to other nuclear
pressure vessels, there are several unique features
that require specialized manufacturing operations.
For example, for some designs, it is necessary to limit the
canister weight due to specific lifting capabilities at the
plant site. Therefore, material thickness must be checked
frequently to allow the manufacturing tolerances to be
worked toward their minimum material condition.
The cylindrical shells are made from stainless steel
plate using manufacturing operations common to
other components described earlier. However, their
outside surface must meet tight tolerances on circularity, diameter and straightness because the cylinder
must fit inside a shielded storage container. The minimum diameter is limited by the requirement to insert
the basket assembly into the cylinder without restriction. The diameter must also provide sufficient allowance for differential expansion of shell and basket
assembly components when the assembly is subject to
elevated temperature during service.
The shield plugs consist of a stainless or carbon steel
circular disk with ribs or stiffeners welded to it. The
entire shield plug assembly is poured full of lead typi-
cally 5 in. (127 mm) thick. A gamma ray scan confirms
the effective thickness of the lead shielding.
The top cover plates are welded to the canister in
the field. Consequently, it is critical to maintain a specific radial gap between the cover plate and the inside diameter (ID) of the cylinder. One way of accomplishing this is by machining and hand working the
OD of the cover plates to suit the as-built ID of the
cylinder. The cover plate must also meet a specific
thickness tolerance to ensure that the maximum
amount of fuel can physically fit into the canister. This
requires flattening operations of the plates during machining and frequent UT thickness checks. There are
similar requirements to custom machine, flatten and
hand work the top shield plug to achieve specified
radial gap.
The guide sleeves are made to form a square crosssection and are sized to suit the dimensions of PWR
and BWR fuel assemblies. The tight tolerances on the
guide sleeves ensure that a spent fuel bundle can be
inserted without binding. The guide sleeves are formed
from stainless steel sheet, and the longitudinal seams
are welded using a welding jig that maintains the
sleeve geometry. The welding equipment utilizes cooling methods and heat input techniques that minimize
distortion due to welding.
During manufacture and assembly of the basket assembly, it is critical to align the spacer discs that support the guide sleeve so the sleeves can be installed
without distortion or binding. The spacer discs are set
up in an alignment jig and welded to the support rods.
The entire assembly must meet exacting geometric
requirements of overall perpendicularity, cylindricity
and height to accommodate thermal expansion during service and to resist potential impact loading during transport.
After the basket assembly is assembled into the cylinder, the final alignment of each guide sleeve is
checked using a plug gauge. The plug gauge, representing the maximum size of fuel to be stored in the
canister, must pass through the guide sleeve within a
specified load limit.
Reference
1. Johnson, E.R., and Saverot, P.M., Eds., Monograph
on Spent Nuclear Fuel Storage Technologies, Institute
of Nuclear Materials Management, Northbrook, Illinois,
1997.
Inconel is a trademark of the Special Metals Corporation group of
companies.
Steam 41 / Nuclear Equipment Manufacture
50-13
The Babcock & Wilcox Company
B&W nuclear steam generator U-bend supports provide close-tolerance fit for improved vibration control.
50-14
Steam 41 / Nuclear Equipment Manufacture
The Babcock & Wilcox Company
Appendices
Steam 41
The Babcock & Wilcox Company
Appendix 1
Conversion Factors, SI Steam
Properties and Useful Tables
This appendix provides tables, charts and figures
that can be useful in evaluating the generation and
use of steam. They supplement the material presented
throughout Steam and are divided into four subsections: selected conversion factors; SI versions of the
Steam Tables and graphical data; useful charts and
figures; and typical operating parameters for a 500
MW pulverized coal-fired power plant.
Fig. 2.2
Fig. 2.3
Pressure-enthalpy diagram for steam –
SI units
Psychrometric chart – SI units
Part 1: Conversion Factors
Table 1.1 Length
Table 1.2 Length, Small Units
Table 1.3 Area
Table 1.4 Volume
Table 1.5 Mass
Table 1.6 Force
Table 1.7 Pressure or Force per Unit Area
Table 1.8 Energy, Work and Heat
Table 1.9 Power or Rate of Doing Work
Table 1.10 Density (Mass/Volume)
Table 1.11 Thermal, Heat Transfer and Flow
Parameters
Table 1.12 Multiplying Prefixes
Table 1.13 Selected Additional Conversion Factors
Part 3: Useful Charts and Tables
Fig. 3.1
Temperature-enthalpy diagram
(MPa = 0.006895 × psi)
Fig. 3.2
Estimates of the weight of air required for
selected fuels and excess air levels
Fig. 3.3
Estimates of the weight of the products
of combustion for selected fuels and excess air levels
Fig. 3.4
Estimates of the percent total air for flue
gas percent oxygen for selected fuels
Fig. 3.5
Estimates of efficiency loss due to unburned combustibles for selected fuels
and ash contents
Fig. 3.6
Estimates of theoretical air required for
the combustion of coal based upon volatile matter content
Table 3.1 SO2, SO3 Estimated Emissions from Boilers Firing Coal or Fuel Oil
Table 3.2 Conversion Formulae for Emission Rates
Table 3.3 Periodic Table of the Elements
Part 2: Systemè International d’Unitès (SI),
Steam Tables Plus Selected Charts and Figures
Table 2.1 SI Properties of Saturated Steam and
Saturated Water (Temperature)
Table 2.2 SI Properties of Saturated Steam and
Saturated Water (Pressure)
Table 2.3 SI Properties of Superheated Steam and
Compressed Water (Temperature and
Pressure)
Fig. 2.1
Mollier diagram (H-s) for steam – SI units
Part 4: Typical 500 MW Pulverized Coal-Fired
Power Plant Parameters
Table 4.1 Coal and Ash Analysis, an Example of a
High Sulfur Bituminous Coal
Table 4.2 Mechanical Equipment – 500 MW PCFired Plant
Table 4.3 Environmental Equipment – 500 MW
PC-Fired Plant
Table 4.4 Plant Performance Summary – 500 MW
PC-Fired Plant
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
T-1
The Babcock & Wilcox Company
Table 1.4
Volume
Table 1.1
Length
Starting
With
Multiply By
To
Obtain
Statute
Mile
Millimeter
Centimeter
Meter
Kilometer
Starting
With
Multiply By
To
Obtain
Fluid
Ounce
Quart
Barrel
(PetroGallon leum)
Cubic
Foot
Cubic
Yard
Cubic
Centimeter
(Milliliter)
Cubic
Meter
Liter
Inch
Foot
Yard
Inch
1
12
36
63.36
X 103
3.937
X 10−2
0.3937
39.37
3.937
X 104
Fluid
Ounce
1
32.00
128.0
5376
957.5
2.585
X 104
3.381
X 10−2
33.82
3.382
X 104
Foot
0.08333
1
3
5280
3.281
X 10−3
3.281
X 10−2
3.281
3281
Quart
0.03125
1
4.000
168.0
29.92
807.9
1.057
X 10−3
1.057
1057
1760
1.094
X 10−3
1.094
X 10−2
1.093
1094
Gallon
7.813
X 10−3
0.2500
1
42.00
7.481
202.0
2.642
X 10−4
0.2642
264.2
6.214
X 10−7
6.214
X 10−6
6.214
X 10−4
0.6214
Barrel
(Petroleum)
1.860
X 10−4
5.952
X 10−3
0.0238
1
0.1781
4.809
6.290
X 10−6
6.290
X 10−3
6.290
1000
1.000
X 106
Cubic
Foot
1.044
−3
X 10
3.342
X 10−2
0.1336
5.615
1
27.00
3.532
X 10−5
3.532
X 10−2
35.32
Cubic
Yard
3.868
X 10−5
1.238
X 10−3
4.951
X 10−3
0.2079
3.704
X 10−2
1
1.308
X 10−6
1.308
X 10−3
1.308
Cubic
Centimeter
(Milliliter)
29.57
946.4
3785
1.590
X 105
2.832
X 104
7.646
X 105
1
1000
1.000
X 106
Liter
2.957
X 10−2
0.9464
3.785
159.0
28.32
764.6
1.000
X 10−3
1
1000
Cubic
Meter
2.957
X 10−5
9.464
X 10−4
3.785
X 10−3
0.1590
2.832
X 10−2
0.7646
1.000
X 10−6
1.000
X 10−3
1
Yard
Statute
Mile
Millimeter
0.02778
0.3333
1
1.578
X 10−5
1.894
X 10−4
5.682
X 10−4
1
914.4
1609
X 106
0.1000
1
100
1.000
X 105
25.40
304.8
1
10.00
Centimeter
2.540
30.48
91.44
1.609
X 105
Meter
0.0254
0.3048
0.9144
1609
1.000
X 10−3
0.010
1
1000
Kilometer
2.540
X 10−5
3.048
X 10−4
9.144
X 10−4
1.609
1.000
X 10−6
1
X 10−5
0.0010
1
Table 1.5
Mass
Table 1.2
Length, Small Units
Starting
With
Multiply By
To
Obtain
Mil
Millimeter
Centimeter
Starting
With
Multiply By
To
Obtain
3.937
X 10−2
39.37
393.7
Pound
3.937
X 10−8
3.937
X 10−5
3.937
X 10−2
0.3937
10.00
1.000
X 104
1.000
X 107
Angstrom
Nanometer
Micron
1000
3.937
X 10−6
3.937
X 10−5
Mil
Inch
1
Pound
Short
Ton
Long
Ton
1
2000
4.464
−4
X 10
0.8929
1
9.842
X 10−7
9.842
−4
X 10
0.9842
1.000
X 107
Gram
453.6
9.072
5
X 10
1.016
6
X 10
1
1000
1.000
X 106
Kilogram
0.4536
907.2
1016
1.000
X 10−3
1
1000
Metric Ton
4.536
−4
X 10
0.9072
1.016
1.000
X 10−6
0.0010
1
1
Nanometer
2.540
X 104
2.540
X 107
0.100
1
1000
1.000
X 106
Micron
25.40
2.540
X 104
1.000
X 10−4
1.000
X 10−3
1
1000
1.000
X 104
Millimeter
2.540
X 10−2
25.40
1.000
X 10−7
1.000
X 10−6
1.000
X 10−3
1
10
Centimeter
2.540
X 10−3
2.54
1.000
X 10−8
1.000
X 10−7
1.000
X 10−4
0.100
1
Table 1.6
Table 1.3
Area
Square
Centimeter
Square
Mile
1296
6.273
X 106
4.014
X 109
0.1550
2.788
X 107
1.076
X 10−3
3.098
X 106
Square
Meter
Square
Kilometer
Starting
With
Multiply By
To
Obtain
Newton
Grams
Kilograms
Pounds
1
9.807
X 10−3
9.807
4.448
Grams (f)
102.0
1
1000
453.6
Kilograms (f)
0.1020
0.001
1
0.4536
0.2248
2.205
−3
X 10
2.205
1
1550
1.550
X 109
Newton
10.764
1.076
X 107
1.196
X 10−4
1.196
1.196
X 106
640
2.471
X 10−8
2.471
X 10−4
247.1
1.563
X 10−3
1
3.861
X 10−11
3.861
X 10−7
0.3861
8361
4.047
X 107
2.590
X 1010
1
1.000
X 104
1.000
X 1010
0.09290
0.8361
4047
2.590
6
X 10
1.000
X 10−4
1
1.000
6
X 10
9.290
X 10−8
8.361
X 10−7
4.047
X 10−3
2.590
1.000
−10
X 10
1.000
X 10−6
1
1
9.000
4.356
X 104
Sqaure
Yard
7.716
X 10−4
0.1111
1
4840
Acre
1.594
X 10−7
2.296
X 10−5
2.066
X 10−4
1
Square
Mile
2.491
X 10−10
3.587
X 10−8
3.228
X 10−7
Square
Centimeter
6.452
929.0
Square
Meter
6.452
X 10−4
Square
Kilometer
6.452
X 10−10
T-2
Force
Acre
1
144.0
1.102
Long Ton
2.540
X 108
6.944
X 10−3
2205
1.102
−3
X 10
1.000
X 108
2.540
X 105
Square
Foot
2.205
1.12
Angstrom
Square
Inch
2.205
X 10−3
1
1
Square
Yard
2240
Short Ton
0.0010
Square
Foot
Metric
Ton
1.102
X 10−6
Inch
Square
Inch
Kilogram
5.000
−4
X 10
3.937
X 10−9
Starting
With
Multiply By
To
Obtain
Gram
Pounds (f)
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
The Babcock & Wilcox Company
Table 1.7
Pressure or Force per Unit Area
Starting
With
Multiply By
To
Obtain
Inch
of
Inch
of
Atmos- Mercury Mercury Water
pheres at 0C at 0C at 4C
Cm of
Table 1.10
Density (Mass/Volume)
Feet
of
Water
at 4C
Kilo- Pounds
grams
per
per
Square
Square Inch
Meter
(abs) Pascal
Bar
Starting
With
Multiply By
To
Obtain
Pounds per
Cubic Foot
Pounds per
Gallon
(U.S. Liquid)
Grams per
Cubic
Centimeter
Kilograms
per
Liter
Kilograms
per
Cubic Meter
1
7.481
62.43
62.43
6.243
X 10−2
1
1.316
X 10−2
3.342
X 10−2
2.458
X 10−3
2.950
X 10−2
9.678
X 10−5
6.804
X 10−2
9.869
X 10−6
0.9869
Pounds per
Cubic Foot
Cm of Mercury at 0C
76.00
1
2.540
0.1868
2.242
7.356
−3
X 10
5.171
7.501
X 10−4
75.01
Pounds per Gallon
(U.S. Liquid)
0.1337
1
8.345
8.345
8.345
X 10−3
Inch of Mercury at 0C
29.92
0.3937
1
7.355
X 10−2
0.8826
2.896
X 10−3
2.036
2.953
X 10−4
29.53
Grams per
Cubic Centimeter
1.602
−2
X 10
0.1198
1
1.000
1.000
X 10−3
Inch of
Water at 4C
406.8
5.354
13.6
1
12
3.937
X 10−2
27.68
4.015
X 10−3
401.9
Kilograms
per Liter
1.602
−2
X 10
0.1198
1.000
1
1.000
X 10−3
Feet of
Water at 4C
33.90
0.4460
1.133
8.333
−2
X 10
1
3.281
X 10−3
2.307
3.345
X 10−4
33.49
Kilograms per
Cubic Meter
16.02
119.8
1000
1000
1
Kilograms
per Square
Meter
Pounds per
Square Inch
(abs)
1.033
X 104
136.0
345.3
25.40
304.8
1
703.1
1.0197 1.0197
X 10−1 X 104
14.70
0.1934 0.4912
3.613
X 10−2
0.4335
1.422
X 10−3
1
1.450
X 10−4
14.50
9.80665
6895
1
1.000
X 105
1
X 10−5
1
Atmospheres
Pascal
Bar
1.01325
1.333
5
X 10
3387.4
249.0
2989
1.333
X 10−2
3.387
X 10−2
2.49
X 10−3
2.989 9.80665 6.895
X 10−2 X 10−5 X 10−2
1.013
PRESSURE is the force per unit area exerted on or by a fluid.
Absolute pressure is the sum of atmospheric and gauge pressure.
Standard atmospheric pressure is 14.696 lbf/in. or 29.92 mm Hg.
British CentiThermal meterUnits
grams
Footpounds
Joules
Wattsecond
Kilowatthours
Kilogram-
meters
Watthours
Volumetric Heat Release Rate
1 Btu/h ft3
3.671
X 107
Heat Transfer Coefficient or Conductance
l Btu/h ft2 F
= 5.6784 W/m2K
1
9.297
X 10−8
1.285
X 10−3
2545
9.480
X 10−4
3413
9.297
X 10−3
Centimetergrams
1.076
X 107
1
1.383
X 104
2.737
X 1010
1.020
X 104
3.671
X 1010
10
Foot-pounds
778
7.233
X 10−5
1
1.98
X 106
0.7376
2.655
X 106
7.233
2655
Horsepowerhours
3.929
X 10−4
3.654
X 10−11
5.050
X 10−7
1
3.725
X 10−7
1.341
3.653
X 10−6
1.341
X 10−3
Joules
Watt-second
1054.8
9.807
X 10−5
1.356
2.684
X 106
1
3.6
X 106
9.807
3600
Kilowatthours
2.93
X 10−4
2.724
X 10−11
3.766
X 10−7
0.7457
2.778
X 10−7
1
2.724
X 10−6
0.001
0.1020
3.671
X 105
1
367.1
2.778
X 10−4
1000
2.724
X 10−3
1
107.6
10−5
0.1383
Watt-hours
0.293
2.724
X 10−8
3.766
X 10−4
745.7
5
Table 1.9
Power or Rate of Doing Work
Starting
With
Multiply By
To
Obtain
Btu per
Minute
Btu
per
Minute
1
Footpounds
per
Second
1.285
X 10−3
7.716
−2
X 10
42.44
Horsepower
Mass Flux
1 lb/h ft2
= 0.001356 kg/m2s
Volumetric Flow Rate
1 ft3/min (ACFM)
1 GPM
= 0.000472 m3/s
= 0.06308 l/s
Table 1.12
1 000 000 000 = 109
Kilowatts
Watts
1 000 000 = 106
56.91
5.691
X 10−2
1 000 = 103
778
1
60
3.3
4
X 10
4.426
4
X 10
44.26
Foot-pounds
per second
12.97
1.667
−2
X 10
1
550
737.6
0.7376
Horsepower
2.357
−2
X 10
3.030
−5
X 10
1.818
−3
X 10
1
1.341
1.341
X 10−3
Kilowatts
1.757
−2
X 10
2.260
−5
X 10
1.356
−3
X 10
0.7457
1
17.5725
2.260
X 10−2
1.356
= 0.000126 kg/s
Multiplying Prefixes
Foot-pounds
per minute
Watts
745.7
= 10.3497 W/m3
Mass Flow Rate
1 lb/h
Multiplication Factors
1 000 000 000 000 = 1012
Footpounds
per
Minute
= 2.326 kJ/kg
= 0.039338 MJ/Nm3
3.413
British
Thermal Units
Kilogrammeters
= l Btu/h ft R
= 12 Btu in./h ft2 F
= 1.7307 W/m K
Heat Flux, or Heat Transfer Rate
1 Btu/h ft2
= 3.1546 W/m2
Horsepowerhours
2.737
X 105
Thermal Conductivity
l Btu/h ft F
Heat Content
1 Btu/lb
1 Btu/Standard cubic foot
Table 1.8
Energy, Work and Heat
Starting
With
Multiply By
To
Obtain
Table 1.11
Thermal, Heat Transfer and Flow Parameters
1000
−3
10
1
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
Prefix
SI Symbol
tera
T
giga
G
mega
M
kilo
k
100 = 102
hecto*
h
10 = 101
deka*
deci*
da
d
0.1 = 10−1
0.01 = 10−2
0.001 = 10−3
0.000 001 = 10−6
0.000 000 001 = 10−9
0.000 000 000 001 = 10−12
0.000 000 000 000 001 = 10−15
0.000 000 000 000 000 001 = 10−18
centi*
c
milli
m
micro
µ
nano
n
pico
p
femto
f
atto
a
* To be avoided where possible.
T-3
The Babcock & Wilcox Company
Table 1.13
Selected Additional Conversion Factors
Length and Area
100 feet (ft)/minute (min) = 0.508 meter (m)/second(s)
= 640 acres
1 square mile (mi2 )
= 259 hectares (ha)
1 m/s
= 196.9 ft/min
1 square kilometer (km2 ) = 100 ha
= 0.3861 mi2
1 ha
= 10,000 m2
= 2.471 acres
1 nautical mile
= 6080 ft
= 1.151 statute mi
= 1.853 km
1 nautical mile/hour (h) = 1 knot
Weight
1 pound (lb)
1 oz
1 grain (gr)
1 lb/ft
1g
1 kg/m
Volume
1 cubic foot (ft3 )
1 cubic inch (in.3 )
1 imperial gallon
1 U.S. gallon (gal)
1 U.S. barrel (bbl)
(petroleum)
1 liter (1)
1 board ft
1 ft3/min
1 m3/h
=
=
=
=
=
=
=
=
=
=
=
=
16 ounces (oz)
7000 grains (gr)
0.454 kilogram (kg)
0.0625 lb
28.35 grams (g)
64.8 milligrams (mg)
0.0023 oz
1.488 kg/m
1000 mg
0.03527 oz
15.43 grains
0.672 lb/ft
1 g/l
Water at 62F (16.7C)
1 ft3
1 lb
1 U.S. gallon
= 62.3 lb
= 0.01604 ft3
= 8.33 lb
Pressure
1 atmosphere (metric)
3
(C x 9/5) + 32
R − 459.67
(F − 32) x 5/9
K − 273.15
1 m3/kg
1 g/m3
0.0624 m3/kg
2.288 g/m3
17.11 g/m3
17.11 mg/l
16.02 ft3/lb
0.437 grain/ft3
0.0584 grain/
U.S. gallon
= 58.4 grain/U.S. gallon
=
=
=
=
=
=
=
Water at 39.2F (4C), maximum density
1 ft3
= 62.4 lb
1 m3
= 1000 kg
1 lb
= 0.01602 ft3
1l
= 1.0 kg
1 kg/m3
= 1 g/l
= 1 part per thousand
1 g/m3
= 1 mg/l
= 1 part per million (ppm)
= 1728 cubic inches (in. )
= 16,390 cubic
millimeters (mm3 )
= 277.4 in.3
= 4.55 liters (l)
= 0.833 imperial gallon
= 3.785 l
= 231 in.3
= 42 U.S. gallons
= 35 imperial gallons
= 106 mm3
= 0.220 imperial gallon
= 0.2642 U.S. gallon
= 61.0 in.3
= 12 in. x 12 in. x 1 in. thick
= 144 in.3
= 1.699 m3/h
= 0.589 ft3/min
Temperature, Measured
F
=
=
C
=
=
Density
1 ft3/lb
1 grain/ft3
1 grain/U.S. gallon
= 98,066.5 pascals (Pa)
= 1 kg force (kgf)/square
centimeter (cm2 )
= 10 m head of water
= 14.22 lb/in.2
1 lb/ft2
= 47.88 Pa
= 0.1924 in. of water
= 4.88 kg/m2
1 ton (t)/in.2
= 13,789 kilopascals (kPa)
= 1.406 kg/mm2
1 in. head of water
= 5.20 lb/ft2
1 m head of water
= 9806 Pa
= 0.1 kg/cm2
1 m head of mercury (Hg) = 133.3 kPa
= 1.360 kg/cm2
= 1333 millibars
1 kg/m2
= 9.806 Pa
= 1 mm head of water
= 0.2048 lb/ft2
1 kg/cm2
= 98.066 kPa
= 735.5 mm Hg
= 0.981 bar
= 14.22 lb/in.2
2
1 kg/mm
= 9.8066 megapascals
(MPa)
= 0.711 t/in2
In these conversions, inches and feet of water are
measured at 62F (16.7C), millimeters and meters of
water at 39.2F (4C), and inches, millimeters, and meters
of mercury at 32F (0C).
T-4
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
The Babcock & Wilcox Company
Note: The following steam tables and Fig. 2.2 have been abstracted from ASME International Steam Tables for Industrial Use
(copyright 2000 by The American Society of Mechanical Engineers), based on the IAPWS industrial formulation 1997 for the
Thermodynamic Properties of Water and Steam (IAPWS-IF97)
Table 2.1
SI Properties of Saturated Steam and Saturated Water (Temperature)1
Volume, m3/kg
Evap
Steam
vfg
vg
Enthalpy, kJ/kg
Water
Evap
Steam
Hf
Hfg
Hg
Entropy, kJ/(kg K)
Water
Evap
Steam
sf
sfg
sg
Temp
K
Temp
K
Press.
MPa
273.16
0.00061166
0.001000
206.0
206.0
0
2500.9
2500.9
0
9.1555
9.1555
273.16
275
280
285
290
295
0.00069845
0.00099182
0.001389
0.001920
0.002621
0.001000
0.001000
0.001001
0.001001
0.001002
181.6
130.2
94.61
69.63
51.87
181.6
130.2
94.61
69.63
51.87
7.8
28.8
49.8
70.7
91.7
2496.5
2484.7
2472.8
2461.0
2449.2
2504.3
2513.5
2522.6
2531.7
2540.8
0.0283
0.1041
0.1784
0.2513
0.3228
9.0783
8.8738
8.6766
8.4862
8.3023
9.1066
8.9779
8.8550
8.7375
8.6251
275
280
285
290
295
300
305
310
315
320
0.003537
0.004719
0.006231
0.008145
0.01055
0.001003
0.001005
0.001007
0.001009
0.001011
39.08
29.77
22.90
17.80
13.95
39.08
29.77
22.91
17.80
13.96
112.6
133.5
154.4
175.3
196.2
2437.3
2425.4
2413.5
2401.6
2389.6
2549.9
2558.9
2567.9
2576.8
2585.7
0.3931
0.4622
0.5302
0.5970
0.6629
8.1244
7.9523
7.7856
7.6241
7.4674
8.5175
8.4145
8.3158
8.2211
8.1303
300
305
310
315
320
325
330
335
340
345
350
355
360
365
0.01353
0.01721
0.02172
0.02719
0.03378
0.04168
0.05108
0.06219
0.07526
0.001013
0.001015
0.001018
0.001021
0.001024
0.001027
0.001030
0.001034
0.001037
11.04
8.805
7.078
5.733
4.677
3.841
3.175
2.641
2.209
11.04
8.806
7.079
5.734
4.678
3.842
3.176
2.642
2.210
217.1
238.0
258.9
279.8
300.8
321.7
342.7
363.7
384.8
2377.5
2365.4
2353.2
2340.9
2328.5
2316.0
2303.4
2290.7
2277.8
2594.6
2603.3
2612.1
2620.7
2629.3
2637.7
2646.1
2654.4
2662.5
0.7277
0.7915
0.8544
0.9164
0.9775
1.0378
1.0973
1.1560
1.2140
7.3154
7.1678
7.0244
6.8849
6.7492
6.6171
6.4884
6.3629
6.2405
8.0431
7.9593
7.8787
7.8013
7.7267
7.6549
7.5857
7.5189
7.4545
325
330
335
340
345
350
355
360
365
370
375
380
385
390
0.09054
0.1083
0.1289
0.1525
0.1796
0.001041
0.001045
0.001049
0.001053
0.001058
1.858
1.571
1.335
1.140
0.9783
1.859
1.572
1.336
1.141
0.9794
405.8
426.9
448.0
469.2
490.4
2264.8
2251.6
2238.2
2224.7
2210.9
2670.6
2678.5
2686.3
2693.9
2701.3
1.2713
1.3279
1.3838
1.4390
1.4937
6.1209
6.0042
5.8900
5.7783
5.6690
7.3922
7.3320
7.2738
7.2174
7.1627
370
375
380
385
390
395
400
405
410
415
0.2106
0.2458
0.2856
0.3304
0.3808
0.001062
0.001067
0.001072
0.001077
0.001082
0.8429
0.7293
0.6334
0.5522
0.4832
0.8440
0.7303
0.6345
0.5533
0.4842
511.7
532.9
554.3
575.7
597.1
2197.0
2182.8
2168.3
2153.6
2138.7
2708.6
2715.7
2722.6
2729.3
2735.8
1.5477
1.6012
1.6542
1.7065
1.7584
5.5619
5.4569
5.3539
5.2528
5.1534
7.1096
7.0581
7.0080
6.9593
6.9119
395
400
405
410
415
420
425
430
435
440
0.4372
0.5002
0.5702
0.6478
0.7335
0.001087
0.001093
0.001098
0.001104
0.001110
0.4242
0.3736
0.3300
0.2924
0.2598
0.4253
0.3747
0.3311
0.2935
0.2609
618.7
640.2
661.9
683.6
705.4
2123.4
2107.9
2092.0
2075.8
2059.3
2742.1
2748.1
2753.9
2759.4
2764.7
1.8098
1.8607
1.9112
1.9612
2.0109
5.0558
4.9597
4.8652
4.7720
4.6802
6.8656
6.8205
6.7764
6.7333
6.6911
420
425
430
435
440
445
450
455
460
465
0.8281
0.9320
1.046
1.171
1.307
0.001117
0.001123
0.001130
0.001137
0.001144
0.2315
0.2067
0.1850
0.1660
0.1493
0.2326
0.2078
0.1862
0.1672
0.1504
727.3
749.3
771.4
793.5
815.8
2042.4
2025.1
2007.4
1989.4
1970.8
2769.7
2774.4
2778.8
2782.9
2786.7
2.0601
2.1089
2.1574
2.2056
2.2534
4.5897
4.5003
4.4120
4.3247
4.2384
6.6498
6.6092
6.5694
6.5303
6.4918
445
450
455
460
465
470
475
480
490
500
1.455
1.616
1.790
2.183
2.639
0.001152
0.001159
0.001167
0.001185
0.001203
0.1345
0.1214
0.1098
0.09021
0.07457
0.1356
0.1226
0.1110
0.09140
0.07577
838.2
860.7
883.4
929.1
975.5
1951.9
1932.4
1912.5
1871.0
1827.1
2790.1
2793.2
2795.9
2800.1
2802.6
2.3010
2.3483
2.3953
2.4886
2.5811
4.1529
4.0683
3.9843
3.8183
3.6543
6.4539
6.4165
6.3796
6.3069
6.2354
470
475
480
490
500
510
520
530
540
550
3.165
3.769
4.457
5.237
6.117
0.001223
0.001245
0.001268
0.001294
0.001323
0.06194
0.05167
0.04324
0.03626
0.03045
0.06317
0.05291
0.04451
0.03756
0.03177
1022.5
1070.4
1119.2
1169.1
1220.3
1780.7
1731.5
1679.1
1623.1
1563.0
2803.3
2801.9
2798.3
2792.2
2783.3
2.6731
2.7646
2.8559
2.9473
3.0391
3.4916
3.3298
3.1680
3.0056
2.8418
6.1647
6.0944
6.0240
5.9530
5.8809
510
520
530
540
550
560
570
580
590
600
7.106
8.213
9.448
10.82
12.34
0.001355
0.001392
0.001433
0.001482
0.001540
0.02557
0.02143
0.01790
0.01485
0.01219
0.02692
0.02282
0.01933
0.01633
0.01373
1272.9
1327.2
1383.7
1442.8
1505.2
1498.3
1428.2
1351.6
1267.1
1172.8
2771.2
2755.4
2735.3
2709.9
2678.0
3.1315
3.2250
3.3201
3.4177
3.5188
2.6755
2.5056
2.3303
2.1477
1.9546
5.8070
5.7305
5.6505
5.5654
5.4734
560
570
580
590
600
14.03
15.90
17.97
20.27
22.064
0.001611
0.001704
0.001837
0.002076
0.003106
0.00984
0.007703
0.005688
0.003561
0
0.01145
0.009407
0.007525
0.005637
0
1572.1
1645.7
1730.7
1842.0
2087.5
1065.1
938.2
780.1
552.4
0
2637.3
2583.9
2510.8
2394.4
2087.5
3.6250
3.7396
3.8697
4.0378
4.4120
1.7461
1.5133
1.2382
0.8632
0
5.3711
5.2528
5.1079
4.9010
4.4120
610
620
630
640
647.0960
Water
vf
610
620
630
640
647.0960
1. U.S. Customary steam tables are provided in Chapter 2, Table 1.
2. In the balance of Steam, enthalpy is denoted by H in place of h to avoid confusion with heat transfer coefficient.
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
T-5
The Babcock & Wilcox Company
Table 2.2
SI Properties of Saturated Steam and Saturated Water (Pressure)
Press.
MPa
Temp
K
0.00080
0.0010
0.0012
0.0014
0.0016
0.0018
0.0020
0.0025
0.0030
0.0040
0.0050
0.0060
0.0080
0.010
0.012
0.014
0.016
0.018
0.020
0.025
0.030
0.040
0.050
0.060
0.080
0.10
0.101325
0.12
0.14
0.16
0.18
0.20
0.25
0.30
0.40
0.50
0.60
0.80
1.0
1.2
1.4
1.6
1.8
2.0
2.5
3.0
4.0
5.0
6.0
7.0
8.0
10
11
12
13
14
16
18
20
22.064
276.911
280.120
282.804
285.119
287.160
288.988
290.645
294.228
297.23
302.11
306.03
309.31
314.66
318.96
322.57
325.70
328.46
330.95
333.21
338.11
342.25
349.01
354.47
359.08
366.64
372.76
373.12
377.93
382.44
386.45
390.06
393.36
400.56
406.68
416.76
424.99
431.98
443.56
453.04
461.11
468.20
474.53
480.27
485.53
497.11
507.01
523.51
537.09
548.74
558.98
568.16
584.15
591.23
597.83
604.01
609.82
620.51
630.14
638.90
647.096
Volume, m3/kg
Water
Evap
Steam
vf
vfg
vg
0.001000
0.001000
0.001000
0.001001
0.001001
0.001001
0.001001
0.001002
0.001003
0.001004
0.001005
0.001006
0.001008
0.001010
0.001012
0.001013
0.001015
0.001016
0.001017
0.001020
0.001022
0.001026
0.001030
0.001033
0.001038
0.001043
0.001043
0.001047
0.001051
0.001054
0.001058
0.001061
0.001067
0.001073
0.001084
0.001093
0.001101
0.001115
0.001127
0.001139
0.001149
0.001159
0.001168
0.001177
0.001197
0.001217
0.001253
0.001286
0.001319
0.001352
0.001385
0.001453
0.001489
0.001526
0.001566
0.001610
0.001710
0.001839
0.002039
0.003106
159.6
159.6
129.2
129.2
108.7
108.7
93.90
93.90
82.75
82.75
74.01
74.01
66.99
66.99
54.24
54.24
45.65
45.66
34.79
34.79
28.19
28.19
23.73
23.73
18.10
18.10
14.67
14.67
12.36
12.36
10.69
10.69
9.430
9.431
8.442
8.443
7.647
7.648
6.202
6.203
5.228
5.229
3.992
3.993
3.239
3.240
2.731
2.732
2.086
2.087
1.693
1.694
1.672
1.673
1.427
1.428
1.236
1.237
1.090
1.091
0.97648
0.97753
0.88467
0.88574
0.71763
0.71870
0.60471
0.60579
0.46131
0.46239
0.37371
0.37480
0.31447
0.31558
0.23921
0.24033
0.19322
0.19435
0.16211
0.16325
0.13962
0.14077
0.12257
0.12373
0.10919
0.11036
0.09840
0.09958
0.07875
0.07995
0.06545
0.06666
0.04852
0.04978
0.03816
0.03945
0.03113
0.03245
0.02603
0.02738
0.02214
0.02353
0.01658
0.01803
0.01451
0.01599
0.01274
0.01427
0.01122
0.01279
0.00988
0.01149
0.00760
0.00931
0.00566
0.00750
0.00382
0.00586
0.0
0.00311
Enthalpy, kJ/kg
Water
Evap
Steam
Hf
Hfg
Hg
Entropy, kJ/(kg K)
Water
Evap
Steam
sf
sfg
sg
15.8
29.3
40.6
50.3
58.8
66.5
73.4
88.4
101.0
121.4
137.8
151.5
173.9
191.8
206.9
220.0
231.6
241.9
251.4
271.9
289.2
317.6
340.5
359.8
391.6
417.4
419.0
439.3
458.4
475.3
490.7
504.7
535.4
561.5
604.7
640.2
670.5
721.0
762.7
798.5
830.1
858.6
884.6
908.6
962.0
1008.4
1087.4
1154.5
1213.7
1267.4
1317.1
1407.9
1450.3
1491.3
1531.4
1570.9
1649.7
1732.0
1827.1
2087.5
0.0575
0.1059
0.1460
0.1802
0.2101
0.2366
0.2606
0.3119
0.3543
0.4224
0.4763
0.5209
0.5925
0.6492
0.6963
0.7366
0.7720
0.8035
0.8320
0.8931
0.9439
1.0259
1.0910
1.1452
1.2328
1.3026
1.3067
1.3608
1.4109
1.4549
1.4944
1.5301
1.6072
1.6718
1.7766
1.8606
1.9311
2.0460
2.1384
2.2163
2.2839
2.3438
2.3978
2.4470
2.5544
2.6456
2.7967
2.9207
3.0274
3.1220
3.2077
3.3603
3.4300
3.4965
3.5606
3.6230
3.7457
3.8717
4.0154
4.4120
2492.0
2484.4
2478.0
2472.5
2467.7
2463.4
2459.5
2451.0
2443.9
2432.3
2423.0
2415.2
2402.4
2392.1
2383.4
2375.8
2369.1
2363.1
2357.5
2345.5
2335.3
2318.5
2304.7
2293.0
2273.5
2257.5
2256.5
2243.8
2231.6
2220.7
2210.7
2201.6
2181.2
2163.4
2133.3
2107.9
2085.6
2047.3
2014.4
1985.3
1958.8
1934.3
1911.4
1889.8
1840.1
1794.9
1713.5
1639.7
1570.8
1505.1
1441.5
1317.6
1256.1
1194.3
1131.5
1067.2
931.1
777.5
584.3
0.0
2507.8
2513.7
2518.6
2522.8
2526.6
2529.9
2532.9
2539.4
2544.9
2553.7
2560.8
2566.7
2576.2
2583.9
2590.3
2595.8
2600.7
2605.0
2608.9
2617.4
2624.6
2636.1
2645.2
2652.9
2665.2
2674.9
2675.5
2683.1
2690.0
2696.0
2701.4
2706.2
2716.5
2724.9
2738.1
2748.1
2756.1
2768.3
2777.1
2783.8
2788.9
2792.9
2796.0
2798.4
2802.0
2803.3
2800.9
2794.2
2784.6
2772.6
2758.6
2725.5
2706.4
2685.6
2662.9
2638.1
2580.8
2509.5
2411.4
2087.5
8.9992
8.8690
8.7624
8.6720
8.5935
8.5242
8.4621
8.3303
8.2222
8.0510
7.9177
7.8083
7.6349
7.4997
7.3887
7.2945
7.2127
7.1403
7.0753
6.9371
6.8235
6.6431
6.5020
6.3859
6.2011
6.0562
6.0477
5.9369
5.8352
5.7464
5.6677
5.5968
5.4452
5.3198
5.1188
4.9600
4.8281
4.6156
4.4465
4.3054
4.1836
4.0762
3.9798
3.8921
3.7015
3.5402
3.2731
3.0530
2.8626
2.6926
2.5372
2.2556
2.1246
1.9977
1.8733
1.7500
1.5006
1.2339
0.9145
0.0
9.0567
8.9749
8.9083
8.8521
8.8036
8.7609
8.7227
8.6422
8.5766
8.4735
8.3939
8.3291
8.2274
8.1489
8.0850
8.0312
7.9847
7.9437
7.9072
7.8302
7.7675
7.6690
7.5930
7.5311
7.4339
7.3588
7.3544
7.2976
7.2460
7.2014
7.1620
7.1269
7.0524
6.9916
6.8954
6.8206
6.7592
6.6615
6.5850
6.5217
6.4675
6.4200
6.3776
6.3392
6.2560
6.1858
6.0697
5.9737
5.8901
5.8146
5.7448
5.6159
5.5545
5.4941
5.4339
5.3730
5.2463
5.1055
4.9299
4.4120
1. See Note 1, Table 2.1
2. See Note 2, Table 2.1
T-6
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
0.001000
7.763
0.0283
0.001000
7.769
0.0283
0.001000
7.779
0.0283
0.001000
7.799
0.0283
0.001000
7.830
0.0283
0.001000
7.861
0.0283
0.001000
7.961
0.0283
0.001000
8.163
0.0283
0.001000
8.364
0.0283
0.001000
8.566
0.0283
0.001000
8.768
0.0283
0.000999
9.272
0.0284
0.000999
9.776
0.0284
0.000999
10.279
0.0284
0.000999
10.782
0.0284
0.000998
11.284
0.0284
0.000998
11.786
0.0284
v,m3/kg
0.004 H,kJ/kg
(302.11) s,kJ/(kg K)
v,m3/kg
0.01 H,kJ/kg
(318.96) s,kJ/(kg K)
v,m3/kg
0.02 H,kJ/kg
(333.21) s,kJ/(kg K)
v,m3/kg
0.04 H,kJ/kg
(349.10) s,kJ/(kg K)
v,m3/kg
0.07 H,kJ/kg
(363.08) s,kJ/(kg K)
v,m3/kg
H,kJ/kg
s,kJ/(kg K)
0.002
(290.65)
v,m3/kg
0.2 H,kJ/kg
(393.36) s,kJ/(kg K)
v,m3/kg
0.4 H,kJ/kg
(416.76) s,kJ/(kg K)
v,m3/kg
0.6 H,kJ/kg
(431.98) s,kJ/(kg K)
v,m3/kg
0.8 H,kJ/kg
(443.56) s,kJ/(kg K)
v,m3/kg
1 H,kJ/kg
(453.04) s,kJ/(kg K)
v,m3/kg
1.5 H,kJ/kg
(471.45) s,kJ/(kg K)
2 v,m3/kg
(485.53) H,kJ/kg
s,kJ/(kg K)
2.5 v,m3/kg
(497.11) H,kJ/kg
s,kJ/(kg K)
3 v,m3/kg
(507.01) H,kJ/kg
s,kJ/(kg K)
3.5 v,m3/kg
(515.71) H,kJ/kg
s,kJ/(kg K)
4 v,m3/kg
(523.51) H,kJ/kg
s,kJ/(kg K)
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
1. See Notes 1 and 2, Table 2.1
0.101325
(373.12)
0.001000
7.761
0.0283
v,m3/kg
H,kJ/kg
s,kJ/(kg K)
0.001
(280.12)
275
0.001000
7.760
0.0283
v,m3/kg
H,kJ/kg
s,kJ/(kg K)
Pressure MPa
(sat. temp.)
0.001002
116.250
0.3920
0.001002
115.791
0.3922
0.001002
115.331
0.3923
0.001002
114.872
0.3924
0.001003
114.412
0.3926
0.001003
113.952
0.3927
0.001003
113.492
0.3928
0.001003
113.308
0.3929
0.001003
113.124
0.3930
0.001003
112.940
0.3930
0.001003
112.756
0.3931
0.001003
112.665
0.3931
0.001003
112.636
0.3931
0.001003
112.609
0.3931
0.001003
112.590
0.3931
0.001003
112.581
0.3931
0.001003
112.575
0.3931
69.16
2550.6
8.7826
138.4
2551.0
9.1037
300
0.001025
324.910
1.0353
0.001025
324.508
1.0356
0.001026
324.107
1.0359
0.001026
323.705
1.0362
0.001026
323.304
1.0366
0.001026
322.903
1.0369
0.001027
322.501
1.0372
0.001027
322.341
1.0373
0.001027
322.180
1.0375
0.001027
322.020
1.0376
0.001027
321.859
1.0377
0.001027
321.780
1.0378
0.001027
321.755
1.0378
4.005
2638.0
7.6747
8.044
2641.6
8.0029
16.121
2643.3
8.3268
40.351
2644.3
8.7520
80.73
2644.7
9.0727
161.5
2644.9
9.3930
0.001065
535.523
1.5977
0.001065
535.179
1.5981
0.001065
534.835
1.5986
0.001065
534.492
1.5991
0.001066
534.149
1.5996
0.001066
533.806
1.6000
0.001066
533.463
1.6005
0.001066
533.326
1.6007
0.001066
533.189
1.6009
0.001067
533.052
1.6011
0.903
2720.5
7.1629
1.802
2730.3
7.4961
2.618
2733.2
7.6726
4.596
2736.0
7.9363
9.211
2737.8
8.2597
18.442
2738.7
8.5814
46.133
2739.2
9.0053
92.29
2739.4
9.3256
184.6
2739.5
9.6456
0.001121
750.890
2.1048
0.001121
750.629
2.1055
0.001121
750.367
2.1062
0.001122
750.107
2.1068
0.001122
749.847
2.1075
0.001123
749.587
2.1082
0.001123
749.328
2.1089
0.2450
2784.7
6.6982
0.3320
2798.8
6.8560
0.5054
2811.9
7.0659
1.025
2824.0
7.4068
2.037
2829.7
7.7303
2.954
2831.4
7.9039
5.179
2833.1
8.1650
10.371
2834.2
8.4868
20.756
2834.7
8.8076
51.909
2835.1
9.2311
103.83
2835.2
9.5512
207.7
2835.2
9.8712
0.001201
975.761
2.5785
0.001202
975.651
2.5794
0.001202
975.542
2.5804
0.080796
2811.705
6.2754
0.104394
2841.382
6.4265
0.143300
2867.592
6.6009
0.220627
2891.277
6.8251
0.2785
2900.1
6.9417
0.3748
2908.7
7.0876
0.5672
2916.9
7.2872
1.144
2924.8
7.6191
2.268
2928.5
7.9386
3.287
2929.7
8.1111
5.760
2930.8
8.3710
11.529
2931.6
8.6920
23.067
2932.0
9.0125
57.681
2932.2
9.4357
115.37
2932.3
9.7557
230.8
2932.3
10.0757
0.0549
2893.1
6.2417
0.0642
2914.0
6.3337
0.0765
2933.7
6.4331
0.0936
2952.2
6.5436
0.1192
2969.7
6.6713
0.1616
2986.2
6.8272
0.2464
3001.9
7.0360
0.3099
3007.9
7.1473
0.4158
3013.9
7.2881
0.6274
3019.6
7.4832
1.262
3025.3
7.8107
2.498
3028.1
8.1283
3.619
3028.9
8.3001
6.339
3029.8
8.5595
12.685
3030.3
8.8802
25.377
3030.6
9.2005
63.453
3030.7
9.6236
126.91
3030.8
9.9436
253.8
3030.8
10.2635
0.0631
3034.3
6.4877
0.0730
3047.8
6.5668
0.0863
3060.9
6.6546
0.1048
3073.5
6.7548
0.1326
3085.7
6.8733
0.1788
3097.5
7.0209
0.2712
3109.0
7.2224
0.3405
3113.5
7.3309
0.4559
3117.9
7.4692
0.6867
3122.3
7.6618
1.379
3126.6
7.9870
2.727
3128.7
8.3035
3.950
3129.4
8.4750
6.917
3130.0
8.7340
13.840
3130.5
9.0545
27.686
3130.7
9.3746
69.223
3130.8
9.7977
138.45
3130.8
10.1176
276.9
3130.9
10.4376
0.0703
3159.1
6.6877
0.0810
3168.9
6.7608
0.0953
3178.5
6.8431
0.1154
3188.0
6.9382
0.1454
3197.2
7.0518
0.1954
3206.3
7.1950
0.2955
3215.2
7.3924
0.3705
3218.7
7.4994
0.4955
3222.2
7.6361
0.7455
3225.6
7.8272
1.495
3229.1
8.1510
2.956
3230.8
8.4668
4.281
3231.3
8.6381
7.495
3231.8
8.8970
14.995
3232.2
9.2172
29.995
3232.3
9.5373
74.994
3232.4
9.9604
149.99
3232.5
10.2803
300.0
3232.5
10.6002
Table 2.3 (Part 1 of 2)
0.0770
3277.3
6.8629
0.0886
3284.9
6.9327
0.1040
3292.5
7.0120
0.1255
3299.9
7.1041
0.1579
3307.2
7.2149
0.2117
3314.5
7.3554
0.3194
3321.6
7.5502
0.4002
3324.5
7.6562
0.5348
3327.3
7.7920
0.8040
3330.1
7.9821
1.612
3332.9
8.3050
3.185
3334.3
8.6203
4.612
3334.8
8.7914
8.073
3335.2
9.0501
16.150
3335.5
9.3703
32.303
3335.6
9.6904
80.763
3335.7
10.1134
161.53
3335.7
10.4333
323.1
3335.7
10.7532
0.0835
3392.8
7.0222
0.0959
3398.9
7.0900
0.1124
3405.0
7.1673
0.1355
3411.1
7.2575
0.1701
3417.1
7.3665
0.2278
3423.0
7.5052
0.3432
3428.9
7.6982
0.4297
3431.3
7.8036
0.5739
3433.6
7.9387
0.8624
3436.0
8.1281
1.728
3438.3
8.4503
3.413
3439.5
8.7653
4.942
3439.8
8.9364
8.651
3440.2
9.1950
17.304
3440.4
9.5151
34.611
3440.5
9.8352
86.533
3440.6
10.2581
173.07
3440.6
10.5780
346.1
3440.6
10.8980
0.0898
3507.3
7.1700
0.1030
3512.4
7.2364
0.1206
3517.4
7.3124
0.1452
3522.5
7.4013
0.1821
3527.5
7.5090
0.2437
3532.5
7.6464
0.3668
3537.4
7.8382
0.4591
3539.4
7.9431
0.6129
3541.4
8.0777
0.9206
3543.3
8.2667
1.844
3545.3
8.5884
3.641
3546.3
8.9032
5.272
3546.6
9.0741
9.228
3546.9
9.3327
18.459
3547.0
9.6528
36.920
3547.1
9.9728
92.303
3547.2
10.3957
184.61
3547.2
10.7156
369.2
3547.2
11.0356
0.0960
3621.7
7.3088
0.1100
3626.0
7.3742
0.1287
3630.3
7.4492
0.1549
3634.5
7.5372
0.1941
3638.8
7.6439
0.2595
3643.0
7.7805
0.3903
3647.2
7.9714
0.4883
3648.9
8.0758
0.6518
3650.6
8.2101
0.9787
3652.2
8.3987
1.959
3653.9
8.7201
3.870
3654.7
9.0347
5.602
3655.0
9.2056
9.805
3655.3
9.4641
19.613
3655.4
9.7842
39.228
3655.5
10.1041
98.072
3655.6
10.5271
196.15
3655.6
10.8470
392.3
3655.6
11.1669
0.1021
3736.7
7.4402
0.1170
3740.3
7.5049
0.1368
3744.0
7.5792
0.1644
3747.6
7.6664
0.2060
3751.3
7.7725
0.2752
3754.9
7.9084
0.4137
3758.5
8.0986
0.5175
3759.9
8.2028
0.6906
3761.4
8.3368
1.0367
3762.8
8.5251
2.075
3764.3
8.8463
4.098
3765.0
9.1607
5.932
3765.2
9.3316
10.383
3765.4
9.5900
20.767
3765.6
9.9101
41.536
3765.6
10.2300
103.842
3765.7
10.6529
207.69
3765.7
10.9729
415.4
3765.7
11.2928
SI Properties of Superheated Steam and Compressed Water (Temperature and Pressure)1
Temperature, K
350
400
450
500
550
600
650
700
750
800
850
900
0.1082
3852.5
7.5654
0.1238
3855.6
7.6296
0.1447
3858.8
7.7033
0.1740
3861.9
7.7900
0.2178
3865.1
7.8956
0.2909
3868.2
8.0309
0.4370
3871.3
8.2206
0.5466
3872.6
8.3246
0.7293
3873.8
8.4584
1.0947
3875.1
8.6465
2.191
3876.3
8.9674
4.326
3876.9
9.2818
6.262
3877.1
9.4526
10.960
3877.3
9.7110
21.921
3877.4
10.0310
43.844
3877.5
10.3510
109.611
3877.5
10.7739
219.22
3877.6
11.0938
438.4
3877.6
11.4137
950
0.1142
3969.3
7.6852
0.1307
3972.1
7.7490
0.1527
3974.8
7.8223
0.1834
3977.6
7.9086
0.2296
3980.3
8.0138
0.3065
3983.0
8.1487
0.4603
3985.8
8.3380
0.5757
3986.9
8.4418
0.7680
3988.0
8.5754
1.1526
3989.0
8.7634
2.306
3990.1
9.0842
4.554
3990.7
9.3984
6.592
3990.8
9.5692
11.537
3991.0
9.8276
23.075
3991.1
10.1476
46.151
3991.2
10.4676
115.380
3991.2
10.8905
230.76
3991.2
11.2104
461.5
3991.2
11.5303
1000
0.1261
4206.7
7.9115
0.1442
4208.9
7.9747
0.1684
4211.0
8.0474
0.2023
4213.2
8.1331
0.2530
4215.3
8.2377
0.3376
4217.5
8.3721
0.5069
4219.6
8.5608
0.6338
4220.4
8.6644
0.8453
4221.3
8.7978
1.2684
4222.2
8.9855
2.538
4223.0
9.3061
5.010
4223.4
9.6202
7.252
4223.6
9.7910
12.691
4223.7
10.0494
25.383
4223.8
10.3693
50.767
4223.8
10.6893
126.919
4223.8
11.1122
253.84
4223.8
11.4321
507.7
4223.9
11.7520
1100
0.1379
4449.7
8.1228
0.1577
4451.4
8.1857
0.1841
4453.1
8.2580
0.2210
4454.8
8.3434
0.2764
4456.6
8.4476
0.3687
4458.3
8.5815
0.5533
4460.0
8.7699
0.6918
4460.7
8.8733
0.9225
4461.3
9.0066
1.3840
4462.0
9.1942
2.769
4462.7
9.5146
5.465
4463.0
9.8287
7.911
4463.2
9.9994
13.845
4463.3
10.2578
27.691
4463.3
10.5777
55.383
4463.4
10.8977
138.457
4463.4
11.3206
276.92
4463.4
11.6405
553.8
4463.4
11.9604
1200
The Babcock & Wilcox Company
T-7
T-8
0.0010
15.79
0.0285
0.0010
17.78
0.0285
0.0010
22.74
0.0285
0.0010
27.67
0.0283
0.0010
29.70
0.0283
0.0010
32.57
0.0281
0.0010
37.43
0.0279
0.0010
42.26
0.0276
0.0010
47.06
0.0271
0.0010
51.83
0.0267
0.0010
56.57
0.0261
0.0010
61.29
0.0256
0.0010
65.98
0.0249
0.0010
70.64
0.0242
0.0010
75.28
0.0234
0.0010
79.90
0.0226
0.0010
84.49
0.0217
0.0010
102.62
0.0178
v,m3/kg
5 H,kJ/kg
(537.09) s,kJ/(kg K)
v,m3/kg
8 H,kJ/kg
(568.16) s,kJ/(kg K)
v,m3/kg
10 H,kJ/kg
(584.15) s,kJ/(kg K)
v,m3/kg
15 H,kJ/kg
(615.31) s,kJ/(kg K)
v,m3/kg
20 H,kJ/kg
(638.9) s,kJ/(kg K)
v,m3/kg
H,kJ/kg
s,kJ/(kg K)
v,m3/kg
25 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
30 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
35 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
40 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
45 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
50 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
55 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
60 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
65 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
70 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
75 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
80 H,kJ/kg
s,kJ/(kg K)
v,m3/kg
H,kJ/kg
s,kJ/(kg K)
1. See Notes 1 and 2, Table 2.1
100
22.064
(647.1)
275
0.0010
12.79
0.0284
Pressure MPa
(sat. temp.)
300
0.0010
201.46
0.3618
0.0010
184.14
0.3686
0.0010
179.78
0.3702
0.0010
175.41
0.3719
0.0010
171.02
0.3735
0.0010
166.61
0.3751
0.0010
162.20
0.3767
0.0010
157.77
0.3783
0.0010
153.32
0.3799
0.0010
148.86
0.3814
0.0010
144.38
0.3830
0.0010
139.89
0.3845
0.0010
135.38
0.3860
0.0010
132.72
0.3868
0.0010
130.85
0.3874
0.0010
126.31
0.3889
0.0010
121.75
0.3903
0.0010
119.92
0.3909
0.0010
117.17
0.391737
0.0010
401.71
0.9791
0.0010
385.78
0.9901
0.0010
381.79
0.9929
0.0010
377.80
0.9958
0.0010
373.80
0.9986
0.0010
369.80
1.0015
0.0010
365.80
1.0044
0.0010
361.80
1.0073
0.0010
357.80
1.0102
0.0010
353.79
1.0132
0.0010
349.78
1.0162
0.0010
345.77
1.0192
0.0010
341.76
1.0222
0.0010
339.41
1.0240
0.0010
337.75
1.0253
0.0010
333.74
1.0284
0.0010
329.73
1.0315
0.0010
328.12
1.0328
0.0010
325.71
1.0347
0.0010
603.78
1.5187
0.0010
589.29
1.5336
0.0010
585.69
1.5374
0.0010
582.09
1.5413
0.0010
578.50
1.5452
0.0010
574.91
1.5492
0.0010
571.34
1.5532
0.0010
567.77
1.5573
0.0010
564.22
1.5614
0.0010
560.67
1.5656
0.0010
557.14
1.5699
0.0011
553.62
1.5742
0.0011
550.11
1.5785
0.0011
548.05
1.5811
0.0011
546.61
1.5830
0.0011
543.13
1.5875
0.0011
539.66
1.5921
0.0011
538.28
1.5939
0.0011
536.21
1.5967
0.0011
807.98
1.9996
0.0011
795.28
2.0187
0.0011
792.15
2.0237
0.0011
789.05
2.0288
0.0011
785.97
2.0339
0.0011
782.91
2.0391
0.0011
779.88
2.0444
0.0011
776.88
2.0498
0.0011
773.90
2.0553
0.0011
770.96
2.0609
0.0011
768.05
2.0666
0.0011
765.17
2.0724
0.0011
762.33
2.0784
0.0011
760.69
2.0819
0.0011
759.54
2.0844
0.0011
756.78
2.0907
0.0011
754.07
2.0970
0.0011
753.00
2.0996
0.0011
751.42
2.1035
0.0011
1015.39
2.4366
0.0011
1005.17
2.4609
0.0011
1002.72
2.4673
0.0011
1000.33
2.4739
0.0011
997.99
2.4805
0.0011
995.70
2.4874
0.0011
993.48
2.4944
0.0012
991.32
2.5015
0.0012
989.23
2.5089
0.0012
987.22
2.5164
0.0012
985.30
2.5242
0.0012
983.5
2.5322
0.0012
981.7
2.5405
0.0012
980.8
2.5455
0.0012
980.1
2.5490
0.0012
978.6
2.5578
0.0012
977.21
2.5670
0.0012
976.70
2.5708
0.0012
975.99
2.5765
0.0012
1227.99
2.8418
0.0012
1221.50
2.8732
0.0012
1220.11
2.8816
0.0012
1218.84
2.8903
0.0012
1217.70
2.8992
0.0012
1216.68
2.9084
0.0012
1215.8
2.9180
0.0012
1215.1
2.9280
0.0012
1214.6
2.9383
0.0013
1214.3
2.9490
0.0013
1214.2
2.9603
0.0013
1214.4
2.9721
0.0013
1214.8
2.9845
0.0013
1215.3
2.9922
0.0013
1215.6
2.9977
0.0013
1216.9
3.0117
0.0013
1218.5
3.0266
0.0013
1219.4
3.0329
0.0418
2846.5
6.0698
0.0013
1448.46
3.2253
0.0013
1448.06
3.2673
0.0013
1448.5
3.2789
0.0013
1449.2
3.2910
0.0013
1450.2
3.3036
0.0013
1451.6
3.3170
0.0013
1453.3
3.3311
0.0014
1455.6
3.3461
0.0014
1458.3
3.3621
0.0014
1461.7
3.3793
0.0014
1466.0
3.3980
0.0014
1471.2
3.4186
0.0015
1477.8
3.4416
0.0015
1482.5
3.4566
0.0015
1486.3
3.4679
0.0015
1497.5
3.4992
0.0201
2819.8
5.7754
0.0276
2905.5
5.9969
0.0490
3005.8
6.3477
0.0014
1679.5
3.5950
0.0014
1689.7
3.6539
0.0014
1693.5
3.6709
0.0015
1698.1
3.6892
0.0015
1703.6
3.7089
0.0015
1710.1
3.7305
0.0015
1718.0
3.7543
0.0016
1727.6
3.7811
0.0016
1739.6
3.8118
0.0017
1755.1
3.8482
0.0017
1776.3
3.8937
0.0018
1808.5
3.9569
0.0020
1876.4
4.0760
0.0054
2418.6
4.9231
0.0079
2624.9
5.2618
0.0140
2868.6
5.7198
0.0247
3022.5
6.1007
0.0324
3072.4
6.2645
0.0552
3138.9
6.5609
Table 2.3 (Part 2 of 2)
0.0015
1924.9
3.9586
0.0016
1954.3
4.0459
0.0017
1965.2
4.0732
0.0017
1978.2
4.1040
0.0018
1994.1
4.1391
0.0018
2014.0
4.1804
0.0019
2039.9
4.2308
0.0020
2075.5
4.2956
0.0022
2129.0
4.3873
0.0026
2222.5
4.5379
0.0036
2402.0
4.8159
0.0054
2631.5
5.1754
0.0080
2817.3
5.4884
0.0099
2906.0
5.6524
0.0116
2961.6
5.7635
0.0173
3078.8
6.0322
0.0283
3177.3
6.3304
0.0365
3212.6
6.4724
0.0608
3261.8
6.7431
0.0018
2188.4
4.3221
0.0020
2251.1
4.4552
0.0021
2275.0
4.5005
0.0022
2304.5
4.5539
0.0023
2341.8
4.6184
0.0025
2390.0
4.6986
0.0028
2453.4
4.8008
0.0032
2536.4
4.9314
0.0039
2639.2
5.0920
0.0048
2754.1
5.2741
0.0061
2868.9
5.4635
0.0079
2976.2
5.6529
0.0103
3074.0
5.8434
0.0122
3127.0
5.9580
0.0139
3162.4
6.0410
0.0198
3242.2
6.2579
0.0314
3314.6
6.5199
0.0401
3341.6
6.6505
0.0662
3380.3
6.9067
0.0021
2466.7
4.6813
0.0025
2567.9
4.8640
0.0026
2605.0
4.9265
0.0029
2648.9
4.9985
0.0031
2700.4
5.0815
0.0035
2759.7
5.1764
0.0040
2826.6
5.2833
0.0046
2898.8
5.4003
0.0054
2973.9
5.5251
0.0064
3049.3
5.6560
0.0077
3123.2
5.7924
0.0095
3194.4
5.9350
0.0120
3262.2
6.0867
0.0140
3300.4
6.1820
0.0158
3326.5
6.2530
0.0220
3386.9
6.4447
0.0344
3443.7
6.6866
0.0436
3465.4
6.8103
0.0713
3497.0
7.0573
0.0025
2743.0
5.0163
0.0031
2864.7
5.2241
0.0033
2904.4
5.2898
0.0036
2948.2
5.3617
0.0040
2995.7
5.4400
0.0044
3046.3
5.5244
0.0050
3099.2
5.6144
0.0057
3153.7
5.7097
0.0065
3208.8
5.8103
0.0076
3263.9
5.9165
0.0090
3318.4
6.0293
0.0109
3371.8
6.1503
0.0135
3423.8
6.2827
0.0156
3453.6
6.3679
0.0175
3474.1
6.4321
0.0240
3522.4
6.6090
0.0371
3568.7
6.8382
0.0470
3586.7
6.9574
0.0764
3613.1
7.1980
0.0029
3000.5
5.3109
0.0037
3120.2
5.5164
0.0040
3155.8
5.5774
0.0043
3193.5
5.6424
0.0048
3232.8
5.7114
0.0053
3273.6
5.7845
0.0058
3315.5
5.8618
0.0066
3358.2
5.9437
0.0075
3401.4
6.0306
0.0086
3444.6
6.1232
0.0101
3487.6
6.2229
0.0121
3530.2
6.3315
0.0148
3572.1
6.4523
0.0171
3596.3
6.5310
0.0190
3613.1
6.5910
0.0259
3653.0
6.7583
0.0398
3691.7
6.9788
0.0502
3706.9
7.0948
0.0814
3729.3
7.3309
SI Properties of Superheated Steam and Compressed Water (Temperature and Pressure)1
Temperature, K
350
400
450
500
550
600
650
700
750
800
850
900
950
0.0033
3231.5
5.5607
0.0043
3340.0
5.7543
0.0046
3370.5
5.8096
0.0050
3402.1
5.8681
0.0054
3434.8
5.9298
0.0060
3468.3
5.9951
0.0066
3502.5
6.0641
0.0074
3537.3
6.1374
0.0083
3572.4
6.2156
0.0095
3607.7
6.2997
0.0111
3643.0
6.3909
0.0132
3678.1
6.4914
0.0161
3712.8
6.6045
0.0184
3733.0
6.6789
0.0205
3747.1
6.7360
0.0278
3780.8
6.8966
0.0424
3813.8
7.1109
0.0534
3826.8
7.2245
0.0863
3846.1
7.4572
0.0038
3440.4
5.7751
0.0048
3535.3
5.9547
0.0051
3561.3
6.0055
0.0056
3588.1
6.0590
0.0060
3615.6
6.1155
0.0066
3643.8
6.1752
0.0073
3672.4
6.2385
0.0081
3701.5
6.3059
0.0091
3730.9
6.3782
0.0104
3760.4
6.4564
0.0120
3790.1
6.5418
0.0142
3819.7
6.6366
0.0173
3849.1
6.7443
0.0197
3866.3
6.8157
0.0219
3878.4
6.8706
0.0296
3907.3
7.0263
0.0450
3935.8
7.2359
0.0565
3947.0
7.3478
0.0911
3963.8
7.5779
1000
0.0500
4180.7
7.4694
0.0626
4189.4
7.5788
0.1007
4202.4
7.8053
1100
0.0548
4429.0
7.6854
0.0687
4435.9
7.7932
0.1102
4446.2
8.0174
1200
The Babcock & Wilcox Company
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
The Babcock & Wilcox Company
Fig. 2.1 Mollier diagram (H-s) for steam – SI units.
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
T-9
The Babcock & Wilcox Company
Fig. 2.2 Pressure-enthalpy diagram for steam – SI units.
T-10
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
The Babcock & Wilcox Company
Fig. 2.3 Psychrometric chart – SI units.
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
T-11
The Babcock & Wilcox Company
Fig. 3.1 Temperature-enthalpy diagram (MPa = 0.006895 × psi).
Fig. 3.2 Estimates of the weight of air required for selected fuels
and excess air levels.
T-12
Fig. 3.3 Estimates of the weight of the products of combustion for
selected fuels and excess air levels.
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
The Babcock & Wilcox Company
Fig. 3.6 Estimates of theoretical air required for the combustion of
coal based on volatile matter contents.
Fig. 3.4 Estimates of the percent total air for flue gas percent
oxygen for selected fuels.
Table 3.1
SO2, SO3 Estimated Emissions from
Boilers Firing Coal or Fuel Oil
SO2:
lb SO2 produced/lb fuel = K
lb SO2 produced/h
= K
% SO2 by weight
=
lb sulfur
lb fuel
64 lb SO2/mole
32 lb sulfur/mole
lb fuel
% sulfur in fuel x 2
h
100
lb SO2/h x 102
lb flue gas/h
ppm SO2 by weight = (% SO2 by weight) x 104
% SO2 by volume
=
100 (% SO2 by weight/64)
(% SO2 by weight) 100−(% SO2 by weight)
+
64
M
ppm SO2 by volume = % SO2 by volume x 104
where K = 0.95 Cyclone furnace firing
0.97 dry bottom PC firing
0.99 oil firing
M = molecular weight of flue gas
30.2 coal firing
29.0 oil firing
Fig. 3.5 Estimates of efficiency loss due to unburned combustibles
for selected fuels and ash contents.
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
SO3:
SO3 quantity
= 1% of SO2 quantity (coal firing)
= 2% of SO2 quantity (oil firing)
T-13
The Babcock & Wilcox Company
Table 3.2
Conversion Formulae for Emission Rates
EPA F-Factor Method
A common method of reporting emissions is in pounds of
pollutant per million Btu of fuel input. An EPA-approved
conversion formula called the dry, oxygen based F-factor
method can be used to convert ppm by dry volume of a
pollutant to lb/106 Btu as follows:
(
2.59 x 10−9 = A constant based on the ideal gas law that
equals 106 moles per DSCF. The ideal gas law, PV=nRT,
says that 1 mole of ideal gas will occupy 385.5 ft3 at 68F
and 14.7 psia. 106 moles would, therefore, occupy 385.5 x 106
ft3 and 106 moles per DSCF = 1/385.5 x 106 = 2.59 x 10−9.
)
lb
20.9
= ppmdv ×
× F × 2.59 × 10−9 × M
106 Btu
( 20.9 - %O2dv ) d
M = the molecular weight of the pollutant being measured
(lb/lb-mole), where
where: Fd = a fuel factor representing the dry standard
cubic feet (DSCF) of flue gas produced by burning a million
Btu of fuel at theoretical air (0% excess air). Standard
conditions are 68F and 14.7 psia. Fd can be calculated from
an ultimate fuel analysis, or a fuel specific default value
may be used as follows:
Fd =
Pollutant
Expressed as
Equivalent
M
NOx
CO
SO2
VOC
SO3
NO2
CO
SO2
CH4
SO3
46.01
28.01
64.06
16.04
80.06
1, 000, 000 3.64 ( % H ) + 1.53 ( % C ) + 0.57 ( % S ) + 0.14 ( % N ) − 0.46 ( % O )
Higher heating value, Btu/lb
Note: The percentage by weight of each constituent in the
above equation is acquired from an ultimate fuel
analysis and must be on the same basis as the
higher heating value (both wet or both dry).
Fuel Type
ppmdv
= the parts per million of pollutant in the
flue gas measured on a dry volume basis.
20.9
factor for the amount of excess
(20.9 − % O2dv ) = aaircorrection
as measured by percent O2 on a dry
Fd Default Values
volume basis in the flue gas.
Refuse (Municipal solid waste)
9,570
Bituminous and subbituminous coal 9,780
Anthracite
10,100
Lignite
9,860
Natural gas
8,710
Fuel oils
9,190
Black liquor
8,800
Wood
9,400
Additional Conversion Methods
Instructions: Multiply the given pollutant value by the factor listed to convert to the units listed in the left-hand column.
Given Value
ppm (dry vol.)
grains/DSCF
ppm (dry vol.)
1
5.504 x 10
(M)
grains/DSCF
1.817 x 10-5 (M)
1
mg/DSCM
4.157 x 10-2 (M)
2.288 x 10
3
mg/Nm3
4.461 x 10 (M)
2.455 x 10
3
(M)(N′)
5.506 x 10 (N′)
(HI)
23.716 (N′)
(HI)
lb/106 Btu
ng/Joule*
-2
6
1 x 10 (HI)
4.308 x 10-4 (M)(N′)
(HI)
mg/DSCM
4
2.321 x 103 (HI)
(M)(N′)
4.074 x 10 -4
18.162 (HI)
(N′)
4.217 x 10-2 (HI)
(N′)
1
0.932
4.156 x 10 (HI)
(N′)
1.073
1
2.406 x 10 (N′)
(HI)
1.037 x 10-2 (N′)
(HI)
-4
-5
6
ng/Joule*
1 x 10 (HI)
(M)(N′)
grains/DSCF = grains per dry standard cubic foot (68F and
29.92 in. Hg)
mg/DSCM = milligrams per dry standard cubic meter
(68F and 29.92 in. Hg)
mg/Nm3 = milligrams per normal cubic meter (0C and
760 mm Hg)
lb/106 Btu = pounds per million Btu, fuel heat input
(HHV basis)
ng/Joule = nanograms per Joule, fuel heat input (HHV
basis)
* Caution: Should not be used for conversion
calculations when ng/Joule is stated as an
electrical output based standard.
T-14
lb/106 Btu
22.417
(M)
24.056
(M)
4.371 x 10
-2
mg/Nm3
4
96.432 (HI)
(N′)
4.458 x 10 (HI)
(N′)
4
1.035 x 10 (HI)
(N′)
2.243 x 10-5 (N′)
(HI)
1
2.321 x 10
9.664 x 10-3 (N′)
(HI)
430.8
1
2
-3
M = molecular weight of pollutant (lb/lb-mole)
N′ = moles of dry flue gas per hour
HI = heat input in fuel, 106 Btu/h (HHV basis)
N′
HI
and its reciprocal occur in many of the
above conversion formulae.
N′
HI
can be calculated using the EPA F-factor
(Fd ) discussed above as follows:
Fd
N′
moles dry flue gas
20.9
=
×
6
HI
385.5 (20.9 − %O2dv)
10 Btu
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
Table 3.3
Periodic Table of the Elements
The Babcock & Wilcox Company
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
T-15
The Babcock & Wilcox Company
Table 4.3
Table 4.1
Environmental Equipment
Nominal 500 MW PC-Fired Drum Boiler Plant
Coal and Ash Analysis, an Example of a
High Sulfur Bituminous Coal
Proximate
Analysis, %
Moisture
VM
FC
Ash
Ultimate
Analysis, %
12.0
35.7
40.3
12.0
Moisture
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
Ash
Chlorine
12.0
60.6
4.1
1.2
4.1
5.9
12.0
0.1
Ash Fusion Temperatures, F
(Reducing Atmosphere)
Initial Deformation
Softening
Hemispherical
Fluid
Sulfur
Forms, %
Pyritic
Organic
Sulfate
2.0
2.0
0.1
4.1
NOx Control
Type:
Si as SiO2
Al as Al2O3
Fe as Fe2O3
Ti as TiO2
Ca as CaO
Mg as MgO
Na as Na2O
K as K2O
S as SO3
P as P2O5
Other
Btu/lb = 10,950 as received
Grindability = 56 HGI
Theoretical air = 7.6 lb/10,000 Btu
SCR, OFA and low NOx
burners
0.07 lb/106 Btu
Emissions:
Ash Analysis, %
1950
2030
2100
2150
Wet Limestone Scrubber (full load)
Limestone usage rate: 30.3 t/h
Gypsum production:
48.4 t/h
SO2 at scrubber inlet:
36,568 lb/h
SO2 at scrubber outlet: 731 lb/h
Required SO2 removal: 98%
45.0
20.0
18.0
1.0
7.0
1.0
0.6
1.9
3.5
0.2
Particulate Control
Type:
Emissions:
Specific collector area:
Table 4.4
Plant Performance Summary
Nominal 500 MW PC-Fired Drum Boiler Plant
Turbine Steam Conditions
Pressure
2400psig
Temperature
1000F
Reheat temperature 1000F
Fuel Input
Table 4.2
Mechanical Equipment
Nominal 500 MW PC-Fired Drum Boiler Plant
Steam Generator
Balanced draft, direct-fired, pulverized coal
Pulverizers
Six, roll wheel mills, 50 t/h each
Main Steam
Flow
3.625 x 106 lb/h
Temp
1005F
Pressure 2415 psi
Reheat Steam
Flow
3.336 x 106 lb/h
Temp
1000F
Pressure 532 psi
Electrostatic precipitator
0.03 lb/106 Btu
350 ft2/1000 SCFM
Coal feed 223 t/h
9
Btu input 4.88 x 10 Btu/h
Ash Flow Rates
t/h
Furnace bottom ash
Economizer ash
Flyash
Total through unit
Mill rejects (pyrites)
5.1
2.2
20.7
28.0
0.5
Heat Rates at Full Load
Steam cycle
Gross
Net
7880 Btu/kWh
8985 Btu/kWh
9871 Btu/kWh
Rated Output
Power Production
Total gross
Total Net
536 MW
494 MW
Thermal
Discharge
6
10 Btu/h
Cooling towers
Stack
Controlled Emissions
lb/h
SO2
NOx as NO2
Particulate
731 *
342 *
146
Efficiencies
Boiler (coal to steam)
Plant (coal to busbar)
Turbine/Generator
Tandem-compound, four-flow, 3600 rpm,
640,000 kVa at 24 kV, 3 phase, 60 Hz.
Untreated Flue Gas Characteristics
Fans
FD: 2 motor-driven, total 4,000,000 lb/h
PA: 2 motor-driven, total 710,000 lb/h
ID: 4 motor-driven, total 5,174,000 lb/h
Nitrogen
Carbon dioxide
Oxygen
Water
Sulfur dioxide
Fan Horsepower Requirements
FD: 2400 HP based on static rise from −0.5 to 14 in. wg
PA: 1700 HP based on static rise from −0.5 to 50 in. wg
ID: 9900 HP based on static rise from −23 to 10 in. wg
Fan data assumes 8% air heater leakage and
87% fan/motor efficiency.
Feedwater Pumps
Main:
2 turbine-driven, 50% capacity,
5000 GPM each, TDH: 7200 ft
Booster:
2 turbine-driven, 50% capacity,
4800 GPM each, TDH: 1280 ft
Condensate: 2 motor-driven, 100% capacity,
1400 hp, 7000 GPM each, TDH: 630 ft
T-16
Volume %
Dry
Wet
Component
81.07
15.28
3.26
−
0.39
100.00
2500
587
88%
35%
Flue Gas Molecular
Weight
73.47
13.84
2.95
9.39
0.35
100.00
30.85 (dry basis)
29.64 (wet basis)
Excess air leaving economizer 17.9%
Mass Flows
lb/10,000 Btu
Actual dry air
Wet gas from fuel
Moisture in air
Wet gas weight
Water from fuel
Water in wet gas
Dry gas weight
8.888
0.800
0.116
9.804
0.444
0.560
9.244
Water in wet gas (as%) 5.711%
Losses
Dry gas loss
Water from fuel
Moisture in air
Unburned
combustibles
Radiation
Unaccounted for
manufacturer's
margin
%
4.659
5.056
0.116
0.500
0.170
1.500
12.001
*Local requirements vary.
Steam 41 / Conversion Factors, SI Steam Properties and Useful Tables
The Babcock & Wilcox Company
Appendix 2
Codes and Standards
There are many codes and specifications which control the design and construction of boilers, steam generators, pressure vessels and piping. Two of the most
important are the American Society of Mechanical
Engineers (ASME) Boiler and Pressure Vessel Code
(BPVC) and the ASME B31 Pressure Piping Code.
Pressure-containing components may be required by
law to meet the requirements of these codes. In the
United States (U.S.) and Canada (and recently in some
other countries), state, city and provincial laws, enforced by local jurisdictions (see Note below), require
new pressure parts to comply with the requirements
of the ASME BPVC. The design and construction of
pressure parts for repair or replacement are established by the local jurisdiction (see note below) and/or
insurance carrier generally following the National
Board Inspection Code (NBIC) in the U.S.
In addition to the BPVC and B31 Pressure Piping
Codes, the ASME Performance Test Code provides
uniform procedures for the testing and performance
evaluation of power plant equipment. This code is frequently used to establish contract compliance of a particular component.
The ASME Boiler and Pressure
Vessel Code
The ASME BPVC establishes rules of safety governing the design, fabrication and inspection during
construction of boilers, pressure vessels and nuclear
power plant components. The objectives of the rules
are to assure reasonably certain protection of life and
property and to provide a margin for deterioration in
service. These rules do not provide criteria for thermal performance, but rather set minimum necessary
guidelines for structural integrity to ensure safe operation during the expected component life. The
BPVC provides a systematic approach to evaluating
Note: Local jurisdiction refers to the municipal, state,
provincial or federal authorities enforcing boiler and pressure vessel laws or regulations.
Steam 41 / Codes and Standards
the stresses and applying material properties in a way
which provides a safe pressure vessel design. The rules
are established through a structured voluntary consensus code writing system and are implemented
through specific contract terms and/or adoption by
various jurisdictions (see Note below).
ASME BPVC history
To understand why the ASME Boiler and Pressure
Vessel Committee was formed and how it operates,
some historical background is necessary.
During the mid 1880s, explosions in fire tube boilers were common. Design knowledge and construction
expertise generally were held by large companies,
such as The Babcock & Wilcox Company (B&W), and
were based essentially on experience.
In 1887, the American Boiler Manufacturers Association (ABMA) was organized to develop general rules
for design and construction of boilers and pressure
vessels. However, participants were reluctant to give
up trade secrets and the effort to develop rules or standards failed. There was, however, some exchange of
technical information such as materials data, riveting
methods, safety factors, head and flange design rules
and hydrostatic testing which helped manufacturers
improve the safety of their products.
From 1898 to 1903, more than 1200 people were
killed in the U.S. in 1900 separate boiler explosions. The
catastrophic explosion of a fire tube boiler in a factory
in Brockton, Massachusetts, in 1905 killed 58 people.
This tragedy led the governor of Massachusetts to request and obtain the first legal set of rules for the design and construction of boilers. The next year a similar set of boiler design and construction rules was issued
by the State of Ohio. Other jurisdictions followed with
their own rules. This wide array of rules and regulations
caused problems for manufacturers and users because
equipment which was acceptable and met the rules in one
state was frequently not acceptable in another.
Colonel E.D. Meier, a founder of the ABMA, campaigned to get acceptance of uniform boiler laws. In
1911, he was elected president of the ASME. Finally,
on February 13, 1915, the first ASME Boiler and Pressure Vessel Code of 147 pages was issued. It was entitled Boiler Construction Code, 1914 Edition.
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ASME BPVC additions
After the 1914 Edition, the following major sections
were issued:
1921 Section III – Boilers for Locomotives. (With the
1962 Edition, this Section was integrated into
Section I and the Section III designation was
later reassigned.)
1922 Section V – Miniature Boilers. (With the 1962
Edition, this Section was integrated into Section I and the Section V designation was later
reassigned.)
1923 Section IV – Low Pressure Heating Boilers.
1924 Section II – Material specifications. (Until 1924,
materials were included as part of Section I.)
1925 Section VIII – Unfired Pressure Vessels. (With
the 1968 Edition, this title was changed to
Rules for Construction of Pressure Vessels,
Division 1 and Division 2 was first issued.)
1926 Section VI – Rules for Inspection (of Power Boilers). (With the 1970 Addenda, this section was
reassigned with a new title.)
1926 Section VII – Suggested Rules for Care of Power
Boilers.
1937 Section IX – Welding Qualifications. (This section was originally a supplement to Section
VIII, but with the 1941 Edition the section was
published separately.)
1963 Section III – Nuclear Vessels. (Now Rules for
Construction of Nuclear Facility Components.)
1968 Section VIII, Division 2 – Alternative Rules for
Pressure Vessels.
1968 Section X – Fiber-Reinforced Plastic Pressure
Vessels.
1970 Section XI – Rules for Inservice Inspection of
Nuclear Power Plant Components.
1970 Section VI – Recommended Rules for Care and
Operation of Heating Boilers.
1971 Section V – Nondestructive Examination.
1975 Section III, Division 2 – Code for Concrete Reactor Vessels and Containments. (Now Concrete Containments.)
1997 Section III, Division 3 – Containment Systems
for Storage and Transport Packagings of Spent
Nuclear Fuel and High Level Radioactive Material and Waste. (Now Containments for
Transportation and Storage.)
1997 Section VIII, Division 3 – Alternative Rules for
Construction of High Pressure Vessels.
2004 Section XII – Rules for Construction and Continued Service of Transport Tanks.
2004 Section II – Metric values of material properties were added as Part D.
As of 2004, the current sections of the BPVC are
summarized in Table 1.
Organization of the ASME Boiler and
Pressure Vessel Committee
The first ASME Boiler and Pressure Vessel Committee in 1911 had seven members. By the early 1990s,
the ASME Boiler and Pressure Vessel Committee had
grown to about 800 people involved at all levels from
working groups to the Boiler and Pressure Vessel Main
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Table 1
ASME Boiler and Pressure Vessel Code Sections, 2004
I Power Boilers
II Materials
III-1 Division 1, Rules for Construction of Nuclear
Facility Components
III-2 Division 2, Code for Concrete Containments
III-3 Containments for Transportation and Storage (of
nuclear spent fuel or high level radioactive waste)
IV Heating Boilers
V Nondestructive Examination
VI Recommended Rules for the Care and Operation
of Heating Boilers
VII Recommended Guidelines for the Care of Power
Boilers
VIII-1 Pressure Vessels, Division 1
VIII-2 Pressure Vessels, Division 2 − Alternative Rules
VIII-3 Alternative Rules for Construction of High
Pressure Vessels
IX Welding and Brazing Qualifications
X Fiber-Reinforced Plastic Pressure Vessels
XI Rules for Inservice Inspection of Nuclear Power
Plant Components
XII Rules for Construction and Continued Service of
Transport Tanks
Committee. The BPVC tries to maintain balance on the
committees with representatives from manufacturers,
users, insurance carriers, jurisdictions and other areas.
However, the representatives from these groups may
maintain their position within the Boiler and Pressure
Vessel Committee even if they change their affiliation.
The administrative structure of the ASME Boiler
and Pressure Vessel Committee consists of the Main
Committee, the Executive Committee, the Conference
Committee and the Headquarters Staff. Subcommittees report to the Main Committee.
In general, there are three different types of subcommittees reporting to the main committee. First,
there are the component or book committees which are
responsible for all the rules of design and construction for a particular type of component and for that
Section of the BPVC in which the rules are given.
Presently, the book subcommittees are:
Section I – Subcommittee on Power Boilers (SC I)
Section III – Subcommittee on Nuclear Power (SC III)
Section IV – Subcommittee on Heating Boilers (SC IV)
Section VIII – Subcommittee on Pressure Vessels
(SC VIII)
Section X – Subcommittee on Reinforced Plastic
Pressure Vessels (SC X)
Section XII – Subcommittee on Transport Tanks (SC
XII)
Second, there are the service book subcommittees.
These subcommittees are responsible for developing
a specific set of rules which may be used by the component committees. Currently, these are:
Section II – Subcommittee on Materials (SC II)
Section V – Subcommittee on Nondestructive Examination (SC V)
Section IX – Subcommittee on Welding (SC IX)
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The Babcock & Wilcox Company
Section XI – Subcommittee on Nuclear Inservice Inspection (SC XI)
Finally, there are the service subcommittees which
are responsible for a specific area of technology or administration of the BPVC that may be applied to the
book sections. These currently are:
Subcommittee on Design (SC D)
Subcommittee on Safety Valve Requirements (SC
SVR)
Subcommittee on Boiler and Pressure Vessel Accreditation (SC BPVA)
Subcommittee on Nuclear Accreditation (SC NA)
Code Editions, Code Addenda and Code Cases
A new edition of the BPVC is issued every three years
(…1998, 2001, 2004…). The code requirements become
mandatory on the date of issue. No items are included
in the new edition of the BPVC which have not been
covered by the previous edition or its three Addenda.
Additions, revisions and deletions to the BPVC are
contained in the Code Addenda, issued every year on
December 31. The Code Addenda becomes mandatory
six months after the date of issue although its contents
are optional and may be used up to that date. This permits a thorough review by the public without having to
comply with mandatory rules. It also gives a transition
period for changing any affected company standards.
Except for Section III, the date of the appropriate
edition and addenda of the BPVC for a particular contract is the date the contract is negotiated or signed.
Most sections indicate that it is the date of the contract, although the actual signing of the contract may
come very much later. Section III permits, for some applications, the use of an edition and addenda which are
not the latest versions. In general, this is used for construction of a component which is used for repair or replacement. The other sections of the BPVC do not control the repair or replacement of components after the
product has been installed; consequently, the decision
of the date of the edition and addenda is the responsibility of the owner, the local jurisdiction and/or the insurance carrier.
Code Cases are contained in two special volumes
independent from the BPVC Sections. Code Cases are
issued four times a year after each Main Committee
meeting and are subject to the same approval procedures as other changes and additions. Code Cases permit the use of a material or construction for which
there are no current BPVC rules. The scope of Code
Cases is purposely kept very specific to limit their usage. Each is reviewed for incorporation into the text
of the appropriate BPVC Section. Code Cases are numbered sequentially, and nuclear Code Cases carry an
N prefix. Code Case use is optional, not mandatory.
When one is chosen, all parts are mandatory and the
Code Case number shall be listed on the
Manufacturer’s Data Report form.
Technical Inquiries
When any user of the BPVC is unable to interpret
a specific rule, a Technical Inquiry may be sent to the
Steam 41 / Codes and Standards
Boiler and Pressure Vessel Committee for an interpretation. Each Section of the BPVC includes an appendix that describes the preparation of Technical Inquiries. It is important that the inquiry meet all of the requirements so that action can be taken without delay. Inquiries are approved by two methods. The first
is consideration by a special group of five people who
must vote unanimously on the answer. If that method
fails, the inquiry must be considered and approved by
the entire subcommittee. Once the inquiry and reply
are approved, a reply is sent to the inquirer. The question and reply are also published in the Interpretations,
issued twice each year to BPVC subscribers.
There are several reasons that an inquiry will not
be handled by the committee:
1. indefinite question – no reference to BPVC paragraph or rule,
2. semi-commercial question – doubt as to whether
question is related to BPVC requirements or is
asking for design approval,
3. approval of specific design – inquirer wants approval of specific design or construction as meeting BPVC requirements, and
4. basis or background of BPVC rules – inquirer
wants rationale or basis of BPVC requirements.
These are not given. Suggested revisions and additions are accepted for consideration.
General design philosophy and safety factors
The basic design philosophy of the BPVC from its
beginning was one in which the primary membrane
stress, or maximum direct stress, does not exceed the
allowable design stress. (See Chapter 8 for an in-depth
discussion of stress analysis and stress categorization,
e.g., primary membrane stress.) The calculated stress
is based on the maximum stress theory. This design
philosophy is still used in Section I; Section VIII, Division 1; and Section IV. In most instances, these sections do not call for a detailed analysis to determine
the local and secondary stresses. Instead, they rely on
a design-by-formula approach.
The BPVC makes a significant distinction between
allowable stress limits and the physical properties of
the material such as ultimate tensile strength. The
published allowable stresses incorporate a safety factor which reduces measured properties to account for:
1) the degree of complexity of the stress evaluation
method, 2) certain levels and types of stress concentration, 3) certain nonuniformity in the materials, and
4) geometric factors. The safety factors are based upon
experience, experimental evidence and theoretical
evaluations. In general, where the BPVC allows a more
detailed exact stress evaluation, a smaller safety factor is permitted in determining the allowable stress. The
BPVC therefore specifies the evaluation procedures and
the applicable allowable stresses (including safety factors) to provide a uniform, safe design procedure.
In the original BPVC in 1914, the allowable stress
limits were based on a safety factor of five applied to
the minimum specified ultimate tensile strength of the
material. However, in December 1931, a joint American Petroleum Institute (API)-ASME Committee on
Unfired Pressure Vessels was formed to develop a speC-3
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cial code for Petroleum Liquids and Gases. The first
edition was issued in September 1934. The API-ASME
Code permitted a safety factor of four with only minor changes in the design equations used for establishing the minimum wall thickness of cylinders and
heads, for reinforced openings, and for other parts. At
that time, the ASME BPVC maintained a safety factor
of five with some special provisions which permitted a
safety factor of four. One of the reasons for the special
provisions was to conserve metal during World War II.
The safety factor of five, except for the special provisions in Section VIII, was used by all sections of the
BPVC through the 1949 Edition. Based upon the satisfactory experience in using a safety factor of four with
the API-ASME Code and the special paragraphs of
Section VIII, the 1950 editions of Section I and Section VIII were issued with a safety factor of four. The
safety factor of Section IV remains at five.
During the 1950s, Admiral Hyman Rickover led the
development of the first nuclear submarine, the Nautilus. Westinghouse’s Bettis Atomic Power Laboratory
was the prime contractor, and B&W designed and built
the reactor vessel, pressurizer and steam generators.
Bettis, General Electric’s Knolls Atomic Power Laboratory and the U.S. Atomic Energy Commission developed and published rules for the stress analysis
and design basis. This was entitled Tentative Structural Design Basis for Reactor Vessels. These rules permitted increased allowable stresses because a thorough
and accurate stress analysis was required.
During the late 1950s, the ASME Code Committee
and the U.S. government began to see the need for
an ASME code which would contain design rules similar to the tentative basis. The first consideration was
to do a major upgrading of Section VIII either by a
supplemental document or major revision of Section
VIII. After much discussion in various committees, it
was decided to develop a new code section.
In 1958, the ASME established a Special Committee to Review Code Stress Basis. This special group met
many times to develop and review all facets of nuclear
vessel requirements – not only design rules, but also
fabrication, inspection, materials and other kinds of
rules. Fatigue analysis methods were introduced for
explicit use for the first time.
In 1963, a public hearing was held in Baltimore,
Maryland. As a result of the meeting, Section III,
Nuclear Vessels, was issued which permitted a safety
factor of three (on minimum specified ultimate tensile
strength). However, in order to use this factor, many
requirements had to be met. A very thorough stress
analysis procedure, called design by analysis based on
the maximum shear stress theory, had to be applied.
Also, more rigid fabrication, examination and testing
procedures were required to allow a reduction in the
safety factor.
While the development of the Nuclear Code was being concluded in late 1961, a task group was formed to
develop an extension of Section VIII. The original title
was Task Group on Code for Industrial Pressure Vessels of Superior Quality. Later, this name was changed
to Alternative Rules for Pressure Vessels and ultimately it
became Section VIII, Division 2.
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In 1968, the new division was issued as an alternative method for constructing pressure vessels, Section VIII, Division 2. It required a much more extensive structural investigation in order to reduce the
safety factor to three.
In 1998, the safety factor for Section I, Section III
Class 2 and 3, and Section VIII, Division 1 was reduced from 4.0 to 3.5 on minimum specified ultimate
tensile strength, based mainly on acceptable experience, and improvements in materials achieved over
the years.
Allowable stress values
The BPVC provides the basis for establishing allowable stress values for Section I, Section VIII, Division
1, and Section III, Division 1, Classes 2 and 3. (See
Chapter 8.) For wrought or cast ferrous and nonferrous materials, the allowable stress values are based
on the following criteria:
1. at temperatures below the creep range, the lowest of the following:
1/3.5 of the specified minimum tensile strength at
room temperature,
(1.1)/3.5 of the tensile strength at temperature,
2/3 of the specified minimum yield strength at room
temperature, and
2/3 of the yield strength at temperature.
In addition, for austenitic stainless steels and certain nonferrous nickel alloys, excluding bolting,
flanges and other strain sensitive usage where
slightly greater deformation is objectionable, the
factor on yield strength at temperature may be
increased from 2/3 to 0.90.
2. at temperatures in the creep range, the lowest of
the following applies:
100% of the average stress to produce a creep rate
of 0.01% in 1000 hours,
80% of the minimum stress to cause rupture at the
end of 100,000 hours, and
67% of the average stress to cause rupture at the
end of 100,000 hours.
Method for development of allowable
stress values
Allowable stress values are developed by the Subcommittee on Materials (SC II) by applying the various safety
factors to data which the committee has obtained from tests
conducted for the committee or various other industrial
sources. The published allowable stress values at any
given temperature are then the lowest stresses evaluated
using the criteria discussed above. (See also Chapter 8.)
The BPVC also provides the basis for establishing
allowable stress values, called design stress intensity
values, for Section VIII, Division 2, and Section III,
Division 1, Class 1. No design stress intensity values
have been established in the creep range for Section
VIII, Division 2. For Section III, Division 1, Class 1
applications in the elevated temperature range, rules
Steam 41 / Codes and Standards
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for some materials are given in Section III, Division
1, NH. For the various materials permitted, except for
bolting materials, the design stress intensity values,
i.e., allowable stress values, are based on the lowest value
of the following criteria:
1/3 of the specified minimum tensile strength at
room temperature,
(1.1)/3 of the tensile strength at temperature,
2/3 of the specified minimum yield strength at room
temperature, and
2/3 of the yield strength at temperature except for most
austenitic stainless steels and certain nonferrous
materials where the factor may reach as high as 90%
of the yield strength at temperature. This may result
in a permanent strain of as much as 0.1%. When this
amount of deformation is not acceptable, the designer
must reduce the allowable stress to obtain an acceptable amount of deformation.
There are tables in Section VIII, Division 2 which
list factors for limiting permanent strain in high alloy
steels and in nickel and high-nickel alloys. In effect,
the criteria permit the designer to choose a factor between 67 and 90% of the yield strength depending on
the tolerable deformation. For example, suppose that
by some limiting clearances the tolerable strain is limited to 0.05% in a shell. The designer can then refer
to the table of limiting permanent strain for 18-8
stainless steel and see that the factor on yield strength
should be limited to 0.80. The designer then goes to
the yield strength values to establish his own allowable stress values.
Bolting materials have their design stress intensity
values, i.e., allowable stresses, established by similar,
but more restrictive, criteria. (See Section II, Part D,
Table 3 and also Appendix 2 of the Standard.)
Strength theories
The three commonly used theories to predict failure are the maximum principal stress theory, the
maximum shear stress theory, and the distortion energy theory as discussed in Chapter 8.
Test results show that for ductile materials, such as
those ferrous and nonferrous materials permitted by
the BPVC, either the maximum shear stress theory
or the distortion energy theory predicts yield and fatigue failure better than the maximum stress theory.
However, the maximum stress theory is easy to apply
in boiler components and pressure vessels where the
circumferential and the longitudinal stresses are calculated using simple formulas with an adequate
safety factor to set the allowable stress values. Where
a more exact analysis is desired and the safety factor
may be less, the BPVC uses the maximum shear stress
theory. Section I, Section IV, Section VIII, Division
1, and Section III, Division 1, Subsections NC, ND and
NE use the maximum stress theory while Section III,
Division 1, Subsection NB and Section VIII, Division
2, use the maximum shear stress theory. The former
use a safety factor of 3.5 or 5 on tensile strength; the
latter use a safety factor of three.
Steam 41 / Codes and Standards
Design criteria
The design criteria for different sections of the BPVC
are related to the theory of failure and safety factors
which are applied to the allowable stress values. For
both Section I, Power Boilers, and Section IV, Heating Boilers, the requirements call for the calculation
of the required minimum wall thickness which will
keep the basic circumferential stress at or below the
allowable stress limit for that section. Additional rules,
equations and charts are given to determine the minimum required thicknesses of components other than
those with circular cross-sections. A more detailed
stress analysis may be required for special designs and
configurations for which there are no rules. Both Section I and Section IV recognize that high local stresses
(discussed below) and secondary stresses may exist
within a component, but those sections have established design rules that keep stresses at a safe level
with a minimum of additional analysis.
Section VIII, Division 1, Pressure Vessels, and Section III, Division 1, Class 2 and 3, Nuclear Facility
Components, have similar design criteria to Sections
I and IV except Sections VIII, Division 1, and III,
Division 1, Class 2 and 3 require the minimum thickness of cylindrical shells to be calculated in both the
circumferential and the longitudinal directions. The
actual minimum required thickness of the cylinder
may be set by stress in either direction. In addition,
Sections VIII, Division 1, and III, Division 1, Class 2
and 3 have rules which permit the combination of
primary membrane stress and primary bending stress
to be as high as 1.5 S where S is the basic allowable
stress value. At elevated temperatures, consideration
must be given to inelastic strain due to creep.
The design criteria for Section VIII, Division 2 provide rules for the more common shell and head geometries for design temperatures that are below the creep
range. A detailed stress analysis is required for most
complex geometries and loadings including internal
pressure loading. For Section III, Division 1, Classes
2 and 3, the requirements are similar to those of Section VIII, Division 2. However, rules are provided requiring detailed analysis and there are fewer formulas.
Both Sections VIII, Division 2, and III, Division 1,
Class 1 have adopted the maximum shear stress criteria. This method requires calculated stresses to be
assigned to various categories and subcategories that
permit different allowable stresses for various combinations of calculated stresses. The various categories
and subcategories of stresses are:
1. primary stresses
a. general primary membrane stress
b. local primary membrane stress
c. primary bending stress
2. secondary stresses
3. peak stresses
Primary stresses are caused by loadings which are
necessary to satisfy the laws of equilibrium with applied pressure and other loads, and they are not selflimiting by deformation and redistribution. Secondary stresses are developed by self-constraint in the
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structure. A basic characteristic of secondary stresses
is that they are self-limiting. That is, rotation, deflection or deformation takes place until the forces and
moments are in balance even though some geometric
change may have occurred. Peak stresses are highly
localized stresses in a structure usually caused by an
abrupt change in the geometry such as a notch or a
nozzle fillet weld. Peak stresses are considered only
during fatigue analysis of cyclic loadings.
Failure modes, stress limits and stress categories are
related. One of the most important aspects of a stress
analysis is to make sure that various stresses are assigned to the proper stress categories. Limits on primary
stress are set to prevent plastic deformation and burst.
Secondary stress limits are set to prevent excessive plastic deformation which may lead to incremental collapse
and to ensure the validity of the use of an elastic analysis for making a fatigue analysis. Peak stress limits are
set to prevent fatigue failure due to excessive cyclic
loadings. For analysis according to Section VIII, Division 2, and Section III, Division 1, Class 1, thermal
stresses are considered only in the secondary and peak
categories.
The ASME Code for Pressure Piping, B31
The ASME Code for Pressure Piping is divided into
many sections relative to different applications. Currently, these sections are:
B31.1
B31.3
B31.4
Power Piping
Process Piping
Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids
B31.5
Refrigeration Piping and Heat Transfer
Components
B31.8
Gas Transmission and Distribution Piping
Systems
B31.9
Building Services Piping
B31.11 Slurry Transportation Piping Systems
The scope of jurisdiction of the ASME BPVC Section I applies to the boiler proper and to the boiler external piping. The boiler external piping is that piping connecting the boiler proper with the nonboiler ex-
ternal piping as defined in PG-58 of Section I. For
boiler external piping, the materials, design, fabrication, installation and testing shall be done according
to ASME B31.1, Power Piping. In addition, most of
the connecting piping outside of the Section I jurisdiction is done according to ASME B31.1.
Editions, Addenda, Cases and Interpretations
With the responsibility of the B31 Pressure Piping
Code Committee resting with ASME, procedures of
releasing editions, addenda, cases and interpretations
are the same for the Piping Code as for the BPVC.
Design philosophy, safety factors and
strength theory
The design philosophy of the Piping Code is one
where the primary membrane stress is not permitted
to exceed the allowable stress. In the Piping Code, the
longitudinal pressure stress is a major consideration
because it combines with longitudinal bending stress
developed from the supporting of dead loads and from
flexibility stress due to the thermal expansion of the
piping system. Although circumferential pressure
stress is calculated and sets the minimum required
thickness for internal pressure, the longitudinal stress
often influences piping arrangement.
Two sections of the ASME B31 Code for Pressure
Piping are primarily used in combination with the
ASME BPVC sections. The two are: ASME B31.1
Power Piping, and ASME B31.3 Process Piping. B31.1
is closely associated with Section I while B31.3 is associated with Section VIII. However, there are no
ASME requirements assigning one or the other. This
is essentially done by the jurisdictions and the laws
they enforce.
Both sections of the Piping Code use the maximum
stress theory for combining and evaluating stresses.
The allowable stress values for Section I and B31.1
are the same as are the safety factors. However, B31.3
is unique because it uses the maximum stress theory
but permits higher allowable stresses which are based
on a safety factor of three on ultimate tensile strength
similar to Section VIII, Division 2 and Section III,
Division 1, Class 1.
Bibliography
Cross, W., The Code: An Authorized History of the ASME
Boiler and Pressure Vessel Code, American Society of
Mechanical Engineers, New York, New York, 1990.
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Greene, A.M., History of the ASME Boiler Code, American Society of Mechnanical Engineers, New York, New
York, 1955.
Steam 41 / Codes and Standards
The Babcock & Wilcox Company
Symbols, Acronyms and Abbreviations
Symbols
Symbols used in Steam are defined within the chapters. The following is a summary of those that are
commonly used. Specialized symbols are not repeated
here. Symbols for chemical elements appear in Appendix 1, Table 3.3. The frequently used units are listed
for each parameter, for illustration purposes. Other
units used are defined in the chapter text.
a
a
a
a, b, c
A
A
An
b
b
B
B
Bw
c
c
cp
cpa
cpg
cv
C
C or c
Ca
crack size, ft or in. (m or mm)
inside radius, ft or in. (m or mm)
major axis of an ellipsoid, ft or in. (m or mm)
general coefficients
area, cross-sectional area or surface area,
ft2 (m2)
mass number (total number of protons
plus neutrons)
cross-sectional area of nozzles, ft2 (m2)
minor axis of an ellipsoid, ft or in. (m or
mm)
outside radius, ft or in. (m or mm)
barometric pressure, in. Hg
ratio of throat diameter to pipe diameter,
dimensionless
moisture fraction, lb/lb (kg/kg)
distance, ft (m)
speed of light
specific heat at constant pressure, Btu/lb
F (J/kg K)
specific heat of air, Btu/lb F (J/kg K)
specific heat of gas, Btu/lb F (J/kg K)
specific heat at constant volume, Btu/lb F
(J/kg K)
crack geometry factor, dimensionless
coefficient
concentration of specie at duct conditions,
lb/lb (kg/kg)
Steam 41 / Symbols, Acronyms and Abbreviations
Ceff
Cf
Ci
Cin
Cm
Cout
Cp
Cppm,d
Cppm,w
Cq
Cs
Ct
Ct
CV
d
da
D
D or d
De or DH
Di
Dsm
DL
e
E
E
E
E
∆E
Eb
collection/removal efficiency,
dimensionless or percent
cleanliness factor, dimensionless
concentration of specie in the impinger, lb/
lb (kg/kg)
concentration at inlet, lb/lb (kg/kg)
mass flow of specie, lb/h (kg/s)
concentration at outlet, lb/lb (kg/kg)
pitot tube correction factor, dimensionless
concentration of specie on a dry basis,
ppm
concentration of specie on a wet basis,
ppm
coefficient of discharge, dimensionless
concentration of specie at standard
conditions, lb/lb (kg/kg)
energy release rate (power) parameter, in.
lb/in.2 h (J/m2 s)
thermal capacitance, Btu/ft3 F (J/m3 K)
valve flow coefficient
diameter, ft or in. (m or mm)
percent reduction in area
diameter, ft or in. (m or mm)
displacement, ft (m)
equivalent or hydraulic diameter = 4A/
Per, ft or in. (m or mm)
internal stack diameter, ft
diameter, Sauter mean
dead load, psi (Pa)
available energy, Btu/lb (J/kg)
emission rate, dry, at 0% O2, lb/h (kg/s)
energy, Btu (J)
weld joint efficiency or ligament efficiency,
dimensionless
Young’s modulus of elasticity, psi (Pa)
change in energy
blackbody emissive power, Btu/h ft2 (W/m2)
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EQ
Eu
seismic loading, psi (Pa)
Euler number = ∆P/ρV 2, dimensionless
f
fx
F
F
friction factor, dimensionless
body force
geometry correction factor, dimensionless
heat exchanger arrangement factor,
dimensionless
peak stresses
radiation configuration factor,
dimensionless
total radiation exchange factor,
dimensionless
crossflow arrangement factor,
dimensionless
allowable axial compressive stress, psi (Pa)
F-factor, dry, at 0% O2, dimensionless
tube bundle depth factor, dimensionless
effectiveness factor, dimensionless
fluid property factor
fluid temperature factor, dimensionless
factor of safety, dimensionless
future value
F
F
F
Fa
FA
Fd
Fd
Fe
Fpp
FT
FS
FV
g
g
gc
G
G
Gmax
Gr
acceleration of gravity, 32.17 ft/s2 (9.8 m/s2)
Gibbs free energy, Btu/lb (J/kg)
proportionality factor, 32.17 lbm ft/lbf s2
(1 kg m/N s2)
incident thermal radiation, Btu/h ft2 (W/m2)
mass flux or mass velocity, lb/h ft2 (kg/m2 s)
critical flow mass flux, lb/h ft2 (kg/m2 s)
g β (Ts − T∞ ) ρ 2 L3
,
Grashof number =
µ2
dimensionless
H
Hf
Hfg
Hfw
Hg
heat transfer coefficient, Btu/h ft2 F (W/m2 K)
thickness, ft or in. (m or mm)
contact coefficient, Btu/h ft2 F (W/m2 K)
crossflow heat transfer coefficient, Btu/h
ft2 F (W/m2 K)
crossflow velocity and geometry factor
longitudinal heat transfer coefficient, Btu/
h ft2 F (W/m2 K)
longitudinal flow velocity and geometry
factor
enthalpy, Btu/lb (J/kg)
enthalpy of saturated water, Btu/lb (J/kg)
enthalpy of vaporization, Btu/lb (J/kg)
enthalpy of feedwater, Btu/lb (J/kg)
enthalpy of saturated steam, Btu/lb (J/kg)
I
I
I
electrical current, amperes
intensity
moment of inertia, in.4 (m4)
J
mechanical equivalent of heat, 778.17 ft
lbf/Btu (1 N m/J)
radiosity, Btu/h ft2 (W/m2)
h
h
hct
hc
hc′
hl
h′
l
J
S-2
JI
JIC
JR
J-integral, in. lb/in.2 (J/m2)
J-integral, critical, in. lb/in.2 (J/m2)
material crack growth resistance, in. lb/
in.2 (J/m2)
k
k
coefficient or parameter
specific heat ratio compressibility factor,
dimensionless
thermal conductivity, Btu/h ft F (W/m K)
insulation thermal conductivity, Btu/h ft F
(W/m K)
isothermal compressibility
discharge coefficient, dimensionless
factor or coefficient
thermal conductance, Btu/h F (W/K)
equilibrium constant, dimensionless
stress intensity factor, ksi in.1/2 (MPa m1/2)
critical stress intensity factor or fracture
toughness, ksi in.1/2 (MPa m1/2)
stress intensity factor/toughness ratio,
dimensionless
mass transfer coefficient, lb/ft2 s (kg/m2 s)
stress intensity range
k
kc
kT
K
K
K
Keg
KI
KIC
Kr
Ky
∆K
l
l⊥
le
L or l
Lh
LMTD
LS
Lt
m
m
ms
mw
M
M
Md
Mo
Mw
n
N
Nu
Nv or N
p
pr
P
P
P
P
Pb
tube centerline spacing parallel to flow, ft (m)
tube centerline spacing transverse to flow,
ft (m)
equivalent plate thickness, ft or in. (m or mm)
length or dimension, ft or in. (m or mm)
fin height, ft or in. (m or mm)
log mean temperature difference, F (C)
limestone consumption, lb/h (kg/s)
fin spacing, ft or in. (m or mm)
mass, lb (kg)
mass flow rate, lb/h (kg/s)
mass of steam, lb (kg)
mass of water, lb (kg)
moisture in steam sample, percent
molecular weight, lb/lb-mole (kg/kg-mole)
molecular weight of gas, dry basis
redundant bending moment, lb ft (N m)
molecular weight of gas, wet basis
parameter, coefficient or number of cycles
coefficient, number of cycles or number of
concentric thermocouple shields
Nusselt number = h L/k, dimensionless
number of velocity heads, dimensionless
particle size, in. (mm)
partial pressure, atm
parameter
pressure or partial pressure, psi (Pa)
primary stress
temperature ratio for surface
arrangement factor, dimensionless
primary bending stress
Steam 41 / Symbols, Acronyms and Abbreviations
The Babcock & Wilcox Company
Pe
Per
PL
PL
Pm
Pm
Pr
Ps
Ptotal
Pv
PV
PVF
∆P
∆Pl
∆PSE
q
q′′
′′
qCHF
q′′′
qrel
qrev
Q or q
Q
Q
Q
Qac
Qsd
r
R
R
R
Peclet number = RePr, dimensionless
perimeter, ft or in. (m or mm)
local primary membrane stress
furnace gas pressure loading, psi (Pa)
pressure at meter, psi (Pa)
general primary membrane stress
cp µ
, dimensionless
Prandtl number =
k
absolute pressure at duct, psi (Pa)
total pressure, lb/ft2 (N/m2)
total vertical design load
present value
present value factor
pressure differential, psi (Pa)
stack flow loss, in. of water
stack effect driving pressure, lb/ft2 (N/m2)
heat flow rate, Btu/h (W)
heat flux, Btu/h ft2 (W/m2)
heat flux at CHF conditions, Btu/h ft2 (W/m2)
volumetric heat generation rate, Btu/h ft3
(W/m3)
heat release rate, Btu/h ft3 (W/m3)
reversible heat input per unit mass, Btu/
lb (J/kg)
heat input, Btu (J), or heat input per unit
mass, Btu/lb (J/kg)
gas flow rate, lb/h (kg/s)
heat absorption or heat added to system,
Btu (J)
secondary stresses
actual volumetric flow rate, ft3/h (m3/s)
dry volumetric flow rate at standard
conditions, ft3/h (m3/s)
Rvs
radius or inside radius, ft or in. (m or mm)
constant or coefficient
forcing function
radius or outside radius, ft or in. (m or
mm)
specific gas constant – R/M, lbf ft/lbm R
(J/kg K)
temperature ratio for surface
arrangement factor, dimensionless
thermal resistance, h ft2 F/Btu (m2 K/W)
universal gas constant, 1545 ft lb/lb-mole
R (8.3143 kJ/kg-mole K)
Rayleigh number = GrPr, dimensionless
ρV L G L
=
,
Reynolds number = µ
µ
dimensionless
fouling index – bituminous ash
slagging index – bituminous ash
slagging index – lignitic ash
slagging index – viscosity
s
specific entropy, Btu/lb F (J/kg K)
R
R
R
R
Ra
Re
Rf
Rs
Rs∗
Steam 41 / Symbols, Acronyms and Abbreviations
sf
sfg
sg
S
S
S
Su
Sy
SPVF
entropy of water, Btu/lb F (J/kg K)
entropy of evaporation, Btu/lb F (J/kg K)
entropy of steam, Btu/lb F (J/kg K)
allowable stress
entropy, Btu/F (J/K)
surface area, or total exposed surface area
for a finned surface, ft2 (m2)
general source term
quantity of entropy, Btu/F (J/K)
steam-water slip ratio, dimensionless
stack effect, in. wg/ft
fin surface area; sides plus peripheral
area, ft2 (m2)
longitudinal (parallel) spacing, ft or in. (m
or mm)
allowable stress intensity, psi (Pa)
applied stress/net section plastic collapse
stress ratio, dimensionless
transverse (side) spacing, ft (m)
Stanton number = Nu/(RePr),
dimensionless
material tensile strength, psi (Pa)
material yield strength, psi (Pa)
series present value factor
t
t
tc
te
tp
T
Tcv
Tsat
Tw
T250
To
To
TD
TS
∆t
∆T
∆TLMTD
∆T sat
thickness, ft or in. (m or mm)
time, h or s
current wall thickness, in. (mm)
time at end of life
present time
temperature, F or R (C or K)
temperature at critical viscosity, F (C)
saturation temperature, F (C)
wall temperature, F (C)
temperature at 250 poise viscosity, F
temperature at initial time, F (C)
sink temperature, F or R (C or K)
terminal temperature difference, F (C)
tensile strength at temperature, psi (Pa)
time interval, h or s
temperature difference, F (C)
log mean temperature difference, F (C)
Tsat – Tw, F (C)
u
u, v, w
υ
va
υf
υfg
υg
internal stored energy, Btu/lb (J/kg)
velocity in x, y, z coordinates respectively,
ft/s (m/s)
overall heat transfer coefficient, Btu/h ft2
F (W/m2 K)
specific volume, ft3/lb (m3/kg)
specific volume, air
specific volume, water
specific volume, evaporation
specific volume, steam
V
V
V
electrical voltage, volts
velocity, ft/s (m/s)
volume, ft3 (m3)
S
S
S
SE
Sf
SL
Sm
Sr
ST
St
U
S-3
The Babcock & Wilcox Company
Vd
Vm
Vn
Vo
Vs
w
wrev
W
W
W1
WL
x
x
xCHF
x, y, z
∆x
X
Y
Y
Yg
Yi
Z or z
Z
Z
dry gas volume, ft3 (m3)
dry gas volume at meter conditions, ft3 (m3)
sample gas velocity through the nozzle,
ft/s (m/s)
redundant shear force, psi (Pa)
velocity of the flue gas, ft/s (m/s)
work per unit mass, ft-lb/lbm (J/kg)
reversible work per unit mass, ft-lb/lbm
(J/kg)
width, ft or in. (m or mm)
work, ft-lb (J)
leakage flow rate, lb/h (kg/s)
wind loading, psi (Pa)
dimension, ft or in. (m or mm)
steam quality, mass fraction steam
steam quality at CHF conditions, mass
fraction steam
dimensions in Cartesian coordinate
system, ft or in. (m or mm)
change in length, ft or in. (m or mm)
weight fraction, dimensionless
compressibility factor, dimensionless
Schmidt fin geometry factor,
dimensionless
concentration in bulk fluid, lb/lb (kg/kg)
concentration at condensate interface,
lb/lb (kg/kg)
elevation or length, ft or in. (m or mm)
atomic number (number of protons in the
nucleus)
Schmidt fin geometry factor,
dimensionless
Greek symbols
α
absorptivity, dimensionless
α
angle, deg (rad)
α
coefficient of thermal expansion, ft/ft (m/m)
α
thermal diffusivity = k/ρcp, ft2/s (m2/s)
α
void fraction, dimensionless
β
deflection or rotation influence coefficients
β
volume coefficient of expansion, 1/R (1/K)
Γ
effective diffusion coefficient
δ
diameter or film thickness, ft or in. (m or mm)
ε
emissivity, dimensionless
ε
roughness, in. (mm)
ε
strain, ft/ft (m/m)
η
efficiency as a fraction or percentage
η
Schmidt fin efficiency, dimensionless
ηnet
net efficiency, dimensionless
ηth
thermal efficiency, dimensionless
θ
angle, deg (rad)
µ
dynamic viscosity, lbm/ft s (kg/m s)
µ
Poisson’s ratio, dimensionless
ν
kinetic viscosity, ft2/s (m2/s)
S-4
π
ρ
ρ
ρd
ρhom
ρ (z)
σ
σ
σ
σ
σa
σr, σt, σz
σt
σy.p.
σ1
σ2
τ
τ
2
φLO
φ
Φ
3.1415926
density, lb/ft3 (kg/m3)
reflectivity, dimensionless
average downcomer density, lb/ft3 (kg/m3)
homogenous density, lb/ft3 (kg/m3)
local density, lb/ft3 (kg/m3)
atomic cross-section, barns
standard deviation
Stefan-Boltzmann constant, 0.1713 x 10-8
Btu/h ft2 R4 (5.669 x 10-8 W/m2 K4)
stress, psi (Pa)
allowable alternating stress, psi (Pa)
radial, tangential and axial stress, psi (Pa)
thermal stress, psi (Pa)
yield point stress, psi (Pa)
longitudinal stress, psi (Pa)
hoop stress, psi (Pa)
shear stress, psi (Pa)
transmissivity, dimensionless
two-phase friction multiplier, all fluid as a
liquid, dimensionless
general dependent variable
two-phase multiplier for a steam-water
separator, dimensionless
Subscripts
1
initial or inlet condition
2
final or outlet condition
a
air
amb
ambient
aux
auxiliary component or system
b
bulk fluid
c
contact or conduction
cg
convection, gas-side
cv
convection
clean
unfouled or clean condition
e
node point east
econ
economizer
eq or e
equivalent
f
fluid, fin or saturated water
g
gas or saturated steam
i
inside or ith parameter or initial condition
in
entering a system
j
jth parameter
l
liquid
max
maximum
min
minimum
o
outside or final condition
out
leaving a system
p
node point under evaluation
P
products
r
radiation
ref
reference
rg
radiation, gas-side
R
reactants
s
steam
sg
surface-to-gas
SE
stack effect
Steam 41 / Symbols, Acronyms and Abbreviations
The Babcock & Wilcox Company
t
w
w
δ
thermal
node point west
wall
liquid film surface (gas liquid interface)
Acronyms and Abbreviations
AA
ABMA
AFS
AFW
AGR
AH
AIB
AIG
AISC
ALARA
amb
AMU
ANSI
API
approx
ARIS
ARTS
ASD
ASME
ASTM
attemp
atm
ATOG
avg
AVT
AZS
atomic absorption
American Boiler Manufacturers
Association
absolute
American Bureau of Shipping
air/cloth
alternating current
actual cubic feet
actual cubic feet per minute
air density separator
acoustic emissions
Atomic Energy Commission, U.S.
Atomic Energy of Canada Limited
atmospheric pressure fluidized-bed
combustion
atomic fluorescence spectroscopy
auxiliary feedwater
advanced gas-cooled reactor
air heater
auxiliary input burner
ammonia injection grid
American Institute of Steel Construction
as low as reasonably achievable
ambient
atomic mass units
American National Standards Institute
American Petroleum Institute
approximate
Automated Reactor Inspection System
Anticipatory Reactor Trip System
allowable stress design
American Society of Mechanical Engineers
American Society for Testing and Materials
attemperator
atmosphere
abnormal transient operating guidelines
average
all-volatile treatment
air zone swirler
B/A
B&W
BAC
BACT
BAT
bbl
BCC
BCCW
BCM
BCT
BCTMP
base-to-acid ratio
The Babcock & Wilcox Company
boiler as calorimeter
best available control technology
best available technology
barrel
body-centered cubic
boiler chemical cleaning waste
boiler condenser mode
body-centered tetragonal
bleached chemical thermomechanical pulp
abs
ABS
A/C
AC
ACF
ACFM
ADS
AE
AEC
AECL
AFBC
Steam 41 / Symbols, Acronyms and Abbreviations
BFB
BFP
BFW
BGC
BH
bit or
bitum
BLESS
bubbling fluidized bed
boiler feed pump
boiler feed water
British Gas Corporation
baghouse
C
CAA
CAD
CANDU
CAP
CBI
CBK
cc
CC
CCZ
CE
CEMS
CFB
CFCC
CFD
cfm
CFR
CGA
CHF
CHP
CII
C.I.S.
cm
CNC
CNCG
CNSG
COE
coef
col
cond
COG
cP
CRDM
CVD
CWA
Celsius or centigrade degrees
Clean Air Act, U.S.
computer-assisted design/drafting
Canada Deuterium Uranium
curved arm primary
curved backward inclined
carbon burnout kinetic
cubic centimeter
combined cycle
Controlled Combustion Zone
collecting electrode
continuous emissions monitoring system
circulating fluidized bed
continuous fiber ceramic composite
computational fluid dynamics
cubic feet per minute
Code of Federal Regulations
crack growth analysis
critical heat flux
combined heat and power
Construction Industry Institute
Confederation of Independent States
centimeter
computer numerical control
concentrated noncondensable gas
consolidated nuclear steam generator
Corps of Engineers, U.S. Army
coefficient
column
condenser
coke oven gas
centipoise
control rod drive mechanism
chemical vapor deposition
Clean Water Act
bituminous
Boiler Life Evaluation and Simulation
System
BLG
black liquor gasification
BLRBAC Black Liquor Recovery Boiler Advisory
Committee
BOF
basic oxygen furnace
BOL
beginning of life
BOOS
burners out of service
BPVC
Boiler and Pressure Vessel Code (ASME)
BRC
below regulatory concern
BSW
bottom sediment and water
Btu
British thermal unit
BWCC Babcock & Wilcox Construction Co., Inc.
BWR
boiling water reactor
BWST
borated water storage tank
S-5
The Babcock & Wilcox Company
d
DAF
dB
DC
DC
DCS
DCS
DE
DE
deg
DESAH
DGV
DHRS
DNB
DNBR
DNC
DNCG
DOD
DOE
DPFAD
day
dry ash-free
decibels
direct current
drain cooler
distributed control system
digital control system
destructive examination
discharge electrode
degree
dual economizer steam air heater
sampled dry gas volume
decay heat removal system
departure from nucleate boiling
DNB ratio
distributed numerical control
dilute noncondensable gas
Department of Defense, U.S.
Department of Energy, U.S.
deformation plasticity failure assessment
diagram
DRB
dual register burner
DRE
destruction and removal efficiency
DSCF(M) dry standard cubic feet (per minute)
DSCM dry standard cubic meter
EAR
EBW
EC
ECCS
ECON
ECP
ECS
ECT
EDC
EDM
EDM
EDTA
eff
EI
EIA
EMAT
emf
EMF
EOR
EPA
EPFM
EPRI
ERW
ESP
ESS
ESW
EU
evap
estimated additional resources
electron beam welding
European Community
emergency core cooling system
economizer
electrochemical potential
environmental control systems
eddy current testing
eddy dissipation concept model
eddy dissipation combustion model
electrical discharge machining
ethylenediaminetetraacetic acid
efficiency
enhanced ignition (burner)
Energy Information Administration
electromagnetic acoustic transducer
electromotive force
electromagnetic filter
enhanced oil recovery
Environmental Protection Agency, U.S.
elastic-plastic fracture mechanics
Electric Power Research Institute
electric resistance welded
electrostatic precipitator
enhanced service structure
electroslag welding
European Union
evaporation
F
FAC
FB
Fahrenheit degrees
flow accelerated corrosion
firebrick
S-6
FBC
FBR
FC
FC
FC/VM
FCAW
FCC
FCC
FD
FEA
FEGT
FERC
FES
FGD
FGR
FHyNES
fluidized-bed combustion
fast breeder reactor
feedwater control subsystem
fixed carbon
fixed carbon/volatile matter ratio
flux core arc welding
face-centered cubic
fluid catalytic cracking
forced draft
finite element analysis
furnace exit gas temperature
Federal Energy Regulatory Commission
finite element system
flue gas desulfurization
flue gas recirculation
furnace hydrogen damage nondestructive
examination system
FIV
flow-induced vibration
FMB
marine package boilers
FMEC
failure mode evaluation chart
FOSAR foreign object search and retrieval
FPS
Fossil Power Systems
FRP
fiberglass reinforced plastic
FS
factor of safety
FSS
flame safety system
FST-GAGE Fast-Scanning Thickness Gage
FSU
former Soviet Union
ft
foot/feet
FT
fluid temperature
FURNIS furnace inspection system
FW
field weld
g
Ga
gal
GCR
gen
GGH
GJ
GMAW
GPM
gr
GR
GT
GTAW
GTCC
gram
gauge
gallon
gas-cooled reactor
generator
gas-to-gas heaters
giga joule
gas metal arc welding
gallons per minute
grains
gas recirculation
gas turbine
gas tungsten arc welding
gas turbine combined cycle
h
HAP
HAZ
HCGE
HFRW
HFT
HGI
HHV
HLW
hp
HP
hour
hazardous air pollutant
heat-affected zone
high capacity gas element
high frequency resistance welding
hot function testing
Hardgrove Grindability Index
higher heating value
high level waste
horsepower
high pressure (turbine)
Steam 41 / Symbols, Acronyms and Abbreviations
The Babcock & Wilcox Company
HPI
HRSG
HT
HTM
HTW
HV
HVOF
HVT
HZP
high pressure injection
heat recovery steam generator
hemispherical temperature
Heat Transfer Manager
high temperature Winkler
high volatile
high-velocity oxy-fuel
high velocity thermocouple
hot zero power
IAPS
International Association for the
Properties of Steam
IAWPS International Association of Wood
Products Societies
IC
Instrument and Controls
IC
ion chromatography
ICPAES inductive coupled plasma atomic emission
spectrometric (analysis)
ICR
Information Collection Request
ICS
integrated control system
ID
induced draft
ID
inside diameter
ID
initial deformation (temperature)
IEOTSG integral economizer once-through steam
generator (nuclear)
IFGR
induced flue gas recirculation
IGA
intergranular attack
IGCC
integrated gasification combined cycle
IGSCC intergranular stress corrosion cracking
IMC
integrated master control subsystem
in.
inch
in. Hg
inches of mercury
in. wg
inches water gauge
INPO
Institute of Nuclear Power Operations
IP
intermediate pressure (turbine)
IPP
independent power producer
IR
infrared radiation
IR-CFB internal recirculation circulating
fluidized-bed
ISO
International Standards Organization
ISP
intermediate size particles
IT
initial deformation temperature
J
joule
K
kcal
kg
kHz
kJ
km
kmole or
kg-mole
kPa
ksi
kV
kW
kWh
Kelvin degrees
kilocalories
kilogram
kilohertz
kilojoule
kilometer
kilogram-mole
kilopascal
1000 pounds per square inch
kilovolt
kilowatt
kilowatt hour
Steam 41 / Symbols, Acronyms and Abbreviations
l
LAER
LAF
lb
LBBA
lbf
LBLOCA
lbm
lb-mole
LBW
LEA
LEFM
LEL
LFA
LFE
L/G
LHV
LLW
LMP
LMTD
LNB
LNCB
LNG
LOCA
LP
LPG
LPI
LPMS
LSD
LVS
LWR
liter
lowest achievable emission rate
laboratory ashing furnace
pound
leak before break analysis
pound force
large break loss of coolant accident
pound mass
pound-mole
laser beam welding
low excess air
linear elastic fracture mechanics
lower explosion limit
life fraction analysis
life fraction expended
liquid to gas ratio (FGD)
lower heating value
low level waste
Larson-Miller parameter
log mean temperature difference
low NOx burner
low NOx cell burner
liquefied natural gas
loss of coolant accident
low pressure (turbine)
liquefied petroleum gas
low pressure injection
loose parts monitoring system
Lagrangian stochastic deterministic (model)
limited vertical sweep
light water reactor
m
MA
MACT
MAF
MARAD
MAWP
max
MCR
MD
MDC
med
MeV
MFR
MFT
mg
MHVT
mi
MIC
MIG
min
MIST
MJ
ml
MLR
mm
MMP
meter
mill-annealed
maximum achievable control technology
moisture and ash free
Maritime Administration, U.S.
maximum allowable working pressure
maximum
maximum continuous rating
mass defect
multi-cyclone dust collector
medium
million electron volts
mass flow rate
master fuel trip
milligram
multiple shield high velocity thermocouple
mile
microbial induced corrosion
metal inert gas
minimum or minute
multiple loop integral systems test
megajoule
milliliter
multi-lead ribbed
millimeter
managed maintenance program
S-7
The Babcock & Wilcox Company
MMT
mol
MOV
mPa
MPa
mph
MRPC
MRS
MSDS
MSW
MT
MTD
mV
MV
MW
MWd
MWt
µS
minimum metal temperature
molecular
motor operated valve
millipascal
megapascal
miles per hour
motorized rotating pancake coil
monitored retrievable storage
material safety data sheets
municipal solid waste
magnetic particle testing
mean temperature difference
millivolt
medium volatile
megawatt, megawatts-electric
megawatt-day
megawatts-thermal
microSiemens
N
N2a
NAAQS
NAPAP
Newton
atmospheric nitrogen
National Ambient Air Quality Standards
National Acid Precipitation Assessment
Program
NBIC
National Board Inspection Code
NC
numerical control
NCG
noncondensable gas
NDE
nondestructive examination
NDTT
nil-ductility transition temperature
NEI
National Emissions Inventory
NFPA
National Fire Protection Association
NIST
National Institute of Science &
Technology
Normal cubic meter
Nm3
NMVOC nonmethane volatile organic compounds
NNI
non-nuclear instrumentation
NOTIS nondestructive oxide thickness inspection
system
NPD
nuclear power demonstration
NPDES National Pollutant Discharge Elimination
System
NPHR
net plant heat rate
NPSH
net positive suction head
NRC
Nuclear Regulatory Commission, U.S.
N.S.
nuclear ship
NSAC
Nuclear Safety Analysis Center
NSCW nuclear service cooling water
NSFO
Navy special fuel oil
NSPS
New Source Performance Standards
NSR
New Source Review
NSSS
nuclear steam supply system
NTU
net transfer unit
NUG
nonutility generator
NWMS nuclear waste management system
NWPA Nuclear Waste Policy Act
O/G
OBW
S-8
oil and gas
oversize bulky waste
OD
ODE
OEM
OFA
OMLR
OPEC
OSHA
OT
OTSG
oz
Pa
PA
PA/PC
PAC
PAW
PAX
PC
PCB
PCDD
PCDF
PCFAD
PDE
PDVSA
PFBC
PFI
PFM
PFT
pH
PHWR
P&ID
PIP
PM
POHC
PORV
ppb
ppm
ppmv
PPS
PR
PRB
press.
pri
prox
PRV
PSD
PSDF
PSH
psi
psia
psig
P/T
PT
PTC
outside diameter
ordinary differential equations
original equipment manufacturer
overfire air
optimized multi-lead ribbed
Organization of Petroleum Exporting
Countries
Occupational Safety & Health
Administration
oxygen treatment
once-through steam generator
ounce
pascal
primary air
primary air and pulverized coal mixture
powdered activated carbon
plasma arc welding
primary air exchange (burner)
pulverized coal
polychlorinated biphenyl
polychlorinated dibenzoparadioxin
polychlorinated dibenzofurans
computer-based failure analysis diagram
partial differential equations
Petroleos de Venezuela South America
pressurized fluidized-bed combustion
Power for Industry (boiler)
Power for Manufacturing (boiler)
Power for Turbine (boiler)
negative log of hydrogen ion
concentration
pressurized heavy water reactor
process and instrumentation diagram
peak impact pressure
particulate matter
principal organic hazardous constituent
power (pilot) operated relief valve
parts per billion (mass)
parts per million (mass)
parts per million by volume
polyphenylene sulfide
process recovery
Powder River Basin
pressure
primary
proximate
pressure reducing valve
prevention of significant deterioration
Power Systems Development Facility
primary superheater
pounds per square inch (absolute or
difference)
pounds per square inch absolute
pounds per square inch gauge
pressure/temperature
penetrant testing (liquid/dye)
Performance Test Code
Steam 41 / Symbols, Acronyms and Abbreviations
The Babcock & Wilcox Company
PUC
pulv
PURPA
PVC
PWHT
PWR
PWSCC
Public Utilities Commission
pulverizer
Public Utility Regulatory Policies Act
polyvinyl chloride
post weld heat treatment
pressurized water reactor
primary water stress corrosion cracking
R
R&D
rad
RAR
RB
RBC
RBE
RBT
RBW
RC
RCM
RCRA
RCS
RDF
recirc
red.
rem
rev
RH
RHAS
RHSH
RH-TRU
RO
ROTSG
rpm
RPS
RRSG
RSG
RT
RVCH
RWP
Rankine degrees
research and development
radian
reasonably assured resources
Radiant boiler
Radiant boiler Carolina-type
Radiant boiler El Paso-type
Radiant boiler Tower-type
Radiant boiler W-type
reactor coolant
reliability centered maintenance
Resource Conservation and Recovery Act
reactor coolant system
refuse-derived fuel
recirculation
reducing atmosphere
roentgen equivalent man
revolutions
reheater
radiant heat absorbing surface
reheat superheater
remote handled transuranic waste
reverse osmosis
replacement once-through steam
generator
revolutions per minute
reactor protection system
replacement recirculating steam generator
recirculating steam generator
radiography testing
reactor vessel closure head
radiation work permit
s
SA
SAE
sat.
SAW
SBLOCA
SBW
SCC
SCC
SCFM
SCR
SD
SDA
SE
sec
SFAS
SFS
second(s)
secondary air
Society of Automotive Engineers
saturated
submerged arc welding
small break loss of coolant accident
steam by weight
stress corrosion cracking
submerged chain conveyor
standard cubic feet per minute
selective catalytic reduction
stack draft
spray dryer absorber
stack effect
second(s)
safety features actuation system
Saybolt Furol Seconds
Steam 41 / Symbols, Acronyms and Abbreviations
SG
SGTR
SH
SI
SIP
SLR
SMAW
SMD
SNAME
steam generator
steam generator tube rupture
superheater
international system of units
state implementation plan
single-lead ribbed
shielded metal arc welding
Sauter mean diameter
Society of Naval Architects and Marine
Engineers
SNCR
selective non-catalytic reduction
SNG
synthetic natural gas
SOG
stripper off gas
SPB
Stirling power boiler
sp gr
specific gravity
SR
stoichiometric ratio
SS
stainless steel
S.S.
steam ship
SSH
secondary superheater
ST
softening temperature
subbitum subbituminous
SUS
Saybolt Universal Seconds
SWUP spiral wound Universal Pressure (boiler)
t
tm
T250
TBS
TC
TD
TDF
TDFM
TDS
TEG
temp
theo
TIG
thk
TLD
TOC
TOFD
TR set
TRC
TRS
TRU
TS
TSC
TSP
TSP
TSS
TSV
TTT
TTV
typ
ton (English units)
metric ton
viscosity at 250 centipoise
turbine bypass system
thermocouple
terminal temperature difference
tire-derived fuel
time dependent fracture mechanics
total dissolved solids
turbine exhaust gas
temperature
theoretical
tungsten inert gas
thick
thermoluminescent dosimeter
total organic carbon
time of flight defraction
transformer rectifier set
total residual chlorine
total reduced sulfur
transuranic
tensile strength
two-stage combustion
total suspended particulate
tube support plates
total suspended solids
turbine stop valve
time-temperature-transformation
turbine throttle valve
typical
UBC
UBC
UBCL
Uniform Building Code
unburned carbon
unburned carbon loss
S-9
The Babcock & Wilcox Company
UCL
UEL
UGA
UIC
U.K.
ULD
UP
UPC
UPC
U.S.
USCG
USD
U.S.S.
UT
UTT
UV
unburned carbon loss
upper explosion limit
undergrate air
uncompensated ion chamber counter
United Kingdom
unit load demand subsystem
Universal Pressure (boiler)
Universal Pressure Carolina-type (boiler)
Universal Pressure coal-fired (boiler)
United States
United States Coast Guard
United States dollar
United States ship
ultrasonic testing
ultrasonic thickness testing
ultraviolet
VM
VOC
vol
vs
VSS
volatile matter
volatile organic compounds
volume
versus
vertical steam separator
W
WCT
WESP
WFGD
wg
WHRB
WPS
WRC
wt
WTE
watt
water collecting tank
wet electrostatic precipitator
wet flue gas desulfurization
water gauge
waste heat recovery boiler
welding procedure specifications
Welding Research Council
weight
waste-to-energy boiler
V
VAC
VIV
volts
volts alternating current
variable inlet vanes
YP
yr
YS
yield point
year
yield strength
S-10
Steam 41 / Symbols, Acronyms and Abbreviations
The Babcock & Wilcox Company
The Babcock & Wilcox Company
Trademarks in Edition: 41
The following is a list of trademarks used in Steam, Edition: 41 that are owned
by The Babcock & Wilcox Company or one of its affiliated companies.
Acoustic Ranger
Auto Spring
B&W
B&W Roll Wheel
B&W-56
B&W-67
B&W-89
B&W-118
Babcock & Wilcox
Cera-VAM
Cyclone
DRB-4Z
DRB-XCL
DSVS
Elverite
FHyNES
FST-GAGE
GenClad
Heat Transfer Manager
Hydrobin
HydroJet
IK-600
LM2100
Multiclone
NOTIS
On-Track
PCFAD
PowerClean
Precision Clean
PrecisionJet
Racer
Stirling
SWUP
Towerpak
UP
VAM
XCL-S
Steam 41 / B&W Trademarks
TM-1
The Babcock & Wilcox Company
Index
Abrasiveness index, 9-9
Absorber (FGD), 35-2
Absorption, 35-5
Absorptivity
definition, 4-3
of gases, 4-12, 4-31
Access doors, 20-6, 23-9
Acid mist, 35-18
Acid rain, 32-4, 34-2, 35-1
Acidity, 36-1
Acoustics
electromagnetic, 45-4
emissions, 45-5
leak detection, 45-16
Adiabatic, 3-4
Adiabatic flame temperature, 2-26,
10-11
Adipic acid, 35-12
Aging (degradation) mechanisms
corrosion, 44-6
erosion, 44-6
fatigue, 44-6
stress, 44-6
Air
combustion, 10-5, 10-16
composition, 10-4
control, 41-10
distributor, fluidized-bed, 17-1, 17-3
enthalpy, 10-19
flow measurement, 40-20, 41-13
infiltration, leakage, 10-16, 10-23,
23-7
moisture, 10-5, 10-6
properties of, 4-11
theoretical, 10-5, 10-7, 10-9, 10-16
Air, quaternary, 28-4
Air flow-steam flow control, 41-13
Air heater, Chapter 20
applications, 20-15
calculations, 22-15
cast iron, 20-8
cold end minimum metal
temperatures, 20-13
Steam 41 / Index
condition assessment of, 45-5, 45-11
corrosion, 20-13
environmental, 20-15
erosion, 20-3, 20-14
fires, 20-14
industrial, 20-15
leakage, 20-12
Ljungström, 20-9
marine, 31-12
operation, 20-13
performance, 20-12
plate, 20-8
plugging, 20-14
recuperative, 20-7
regenerative, 20-9
Rothemühle, 20-10
seal(s), 20-10, 20-11
steam
coil, 20-9, 29-12, 29-21
marine, 31-10
testing, 20-12
tubular, 20-7, 29-21
Air pollution, Chapter 32
air toxics, 32-5, 32-8
carbon dioxide, 32-8
carbon monoxide, 32-2, 32-7
greenhouse gas, 32-8
international regulations, 32-6
mercury, 32-8
nitrogen oxides (NOx), 32-1, 32-4,
32-7 (see also NOx control)
particulate matter, 32-7
(see also Particulate control)
sources, 32-1
sulfur oxides (SOx), 32-1, 32-4,
32-7 (see also SO2 control)
technologies, 32-8
U.S. legislation, 32-1
Air swept spout, 16-7, 29-17
Air testing, 39-18
Albacore hull, 46-24
Alkalinity, 35-1, 36-1
Allowable stress, 7-20, 8-3, C-4
Allowances, 32-4
Alloying elements, 7-5
interstitial, 7-2
substitutional, 7-2
Alpha
emitters, 47-4
particle, 47-3
Alumina ceramics, 13-11, 44-10
Aluminizing, 7-15
American Boiler Manufacturers
Association (ABMA), 23-6, C-1
American Society for Testing and
Materials (ASTM), 9-5, 9-7
American Society of Mechanical
Engineers (ASME), 1-14, 2-1
Boiler and Pressure Vessel Code,
8-1, 19-8, 20-6, C-1
allowable stresses, 7-20, 8-3, C-4
calculations, 8-5
design criteria, 8-2, 8-14
strength theories, 8-2
stress classifications, 8-2,
8-9, 8-10
Performance Test Code, 10-10,
10-18, 10-21, 40-1
Pressure Piping (B31), C-1, C-6
Ammonia, 34-3, 35-2, 35-18
anhydrous, 34-6
aqueous, 34-7
flow control, 34-8, 41-17
injection, 34-6
reagent systems, 34-6
Ammonia sulfates, 20-15, 34-6
Annealing, 7-8
Anticipatory reactor trip system
(ARTS), 46-15
API gravity, fuel oil, 9-14, 10-20
Approach temperature
flue gas desulfurization, 35-14
As-received, coal, 9-5, 9-7
Ash, black liquor, 28-8 (see also
Recovery boiler, Kraft process)
carryover, 28-9
I-1
The Babcock & Wilcox Company
chloride/potassium purging, 28-10,
28-21
fume, 28-9
stickiness, 28-9
Ash, coal, 9-4, 9-8, 21-1 (see also
Slag)
characteristics and composition,
21-3, 21-6
characterization methods, 21-13
classification, 20-13
composition, 9-8
content, 21-1
corrosion, 15-4, 15-10, 21-20
deposition, deposits, slagging and
fouling, 21-3, 44-7
effects of reducing atmosphere,
21-6, 43-7
effects on boiler design, 19-6, 2114, 21-16, 43-7
convection pass design, 21-16
furnace design, 21-14
erosion, 21-17 (see also Erosion)
fusibility, fusion temperature(s),
15-1, 15-3, 21-5
fusion, 9-8
gasifier, Chapter 18
hoppers, 20-4
influence of elements, 21-7
numerical model, 6-12
operating variables, 21-17
particles, 20-3
pulverized coal combustion, 14-4
removal, dry-bottom, wet-bottom,
flyash, 21-2
residue, 10-11, 10-14
sintering strength, 21-19
viscosity, 21-8
measurement, 21-9
temperature relationship, 21-10
Ash, fuel oil, 21-22
characteristics, 21-24
control, 21-25
corrosion, 21-25
high temperature, 21-25
low temperature, 21-25
deposition, 21-23
design considerations, 21-24
operating considerations, 21-24
origin, 21-23
Ash cleaning equipment (see also
Sootblowers)
mechanical rapping system, 29-21
sootblowers, 24-1, 29-21
Ash deposits
emittance, 4-10
thermal conductance, 4-9
Ash handling systems, 24-12,
29-12, 29-18
air heater flyash, 24-12
bottom ash handling systems
clinker grinders, 24-14
dewatering storage bin, 24-14
hydraulic, 24-13
mechanical drag, 24-14
plunger ash extractor, 24-15,
29-12
I-2
slag tank, 24-14
submerged chain conveyor,
24-14, 29-18
water impounded hopper
system, 24-15
dry flyash handling systems,
pneumatic, 24-16
airlock, 24-17
pressure system, 24-17
vacuum system, 24-16
flyash handling system, 24-15,
29-12, 29-19
collector, 24-20
drag chain conveyor, 24-15,
29-12
screw conveyor, 29-12
silo, 24-20
silo unloading, 24-20
mechanical conveying, 24-14
pyrite, 24-15
Aspirator, 3-16
Atom, 47-1
Atomic Energy Act, 49-14
Atomic Energy Commission
(AEC, now NRC), 46-1, 49-14
Atomic number, 47-1, T-15
Atomic Safety and Licensing Board,
49-14
Atomization
oil, 11-11
mechanical, 11-11
steam, 11-12
slurry (FGD)
dual fluid, 35-13
rotary, 35-13
Attemperation, 1-8, 19-14
marine, 31-9
water, 42-7
Attemperator, 19-13, 19-14
arrangement(s), 19-15
condition assessment, 45-9
control, 19-14
spray, 1-8, 19-14
Austenite, 7-3
Austenitic stainless steel, 7-13
Automatic sequence burner
controls, 41-14
Automation
power plant, 41-19
welding, 38-1
Auxiliaries, 39-18
ash handling, Chapter 24
boiler, 1-9, Chapter 25
power requirements, 15-10, 26-6
sootblowers, Chapter 24
Auxiliary power, cost, 37-11, 37-17
Availability
maintaining, Chapter 44
Available energy, 2-17
Babcock,
George Herman, Intro-5,
Intro-6
Baffle(s)
air heater, 20-7
drum, steam, 5-14
economizer, 20-3
marine, 31-12, 31-13
numerical modeling, 6-13
Bagasse, analysis, 9-12
Baghouse, 29-22, Color Plate 7
(see also Fabric filter)
Bainite, 7-5
Balanced draft, 23-4
Ball or ball-and-tube mill, 13-5, 35-6
Banks of tubes
convection heat transfer in, 4-16
crossflow around, 4-16
effect of number of tube rows in,
4-18
longitudinal flow around, 4-18
Bare tube, arrangement
in-line, 20-1
staggered, 20-1
Bark fuel, 27-2, 30-1
Barns, 47-5
Basic oxygen furnace, 27-20
Batch refueling, 46-10
Bernoulli’s equation, 3-4
Best Achievable Control Technology
(BACT), 32-3
Beta particle, 47-3
Bid evaluation, 37-7
Bimetallic materials and tubes,
7-14, 28-11, 29-5
Binding energy, 47-2
Biological effects, radiation, 47-3
Biomass (see also Chapter 30)
as a fuel, 9-18, 30-3
fluidized-bed, 17-1, 17-3, 30-7
Black liquor – see Recovery boiler,
Kraft process
Blackbody
definition of, 4-4
radiation from, 4-4, 4-7
Blast furnace, 27-2, 27-18
gas, 9-10, 27-4, 27-13
Blowdown
steam generator, fossil, 19-14, 42-7
steam generator, nuclear, 48-7
Blowing, steam line, 43-3
Boiler
bank, 1-8, 19-2, 22-11, 27-2, 28-4,
28-17, 29-21
chemistry, 42-1
circulation, general theory, 3-17,
5-17
cleaning, 43-2
codes, 8-5, C-1
configurations, 19-1
control, Chapter 41, 43-3
automatic sequence, 43-3
basic theory, 41-1
coal, pulverized, drum, 41-10
coal, pulverized, Universal
Pressure, 41-12
combustion optimization, 43-6
Cyclone, 41-11
fluidized-bed, 41-11
key operating functions, 43-7
manual, 43-3
oil and gas, 41-10
Steam 41 / Index
The Babcock & Wilcox Company
system design, utility boiler,
41-5
temperature
reheat, 41-10
superheat, 41-10
definition, 1-1, 19-1
design, 1-14, 19-3
ASME Boiler and Pressure
Vessel Code, 19-8, C-1
basic circulation systems, 19-3
calculations, performance, 22-1
combustion effects, 19-5
convection surface, 19-6
criteria, 19-4
critical heat flux, 5-2, 5-4, 19-8
heat absorption, 19-3
heat and chemical recovery
boilers, paper industry,
28-1
heating surface, 19-4, 19-6
pressure parts, 19-8
recovery, chemical and heat,
Chapter 28
safety valves, 19-8
specifications, 19-4
supports, 19-8
thermal gradients, 19-8
design practice, 26-2
development, history of, Intro-1
enclosure, 19-8, 23-1
energy equation, 2-9
expansion, 23-4
historical (see also Steam engine)
Blakey, William, Intro-4
centennial, Intro-5
shell, Intro-2
Stevens, John, Intro-4
straight tube, Intro-7
Trevithick, Richard, Intro-4
waggon, Intro-3
Watt, James, Intro-3
industrial, 27-1
industrial byproduct, 30-2
numerical model, 6-12
pulverized coal, 6-14
recovery, 6-14
waste-to-energy, 6-21
windbox, 6-16
once-through, 1-3, 1-12
operation, 43-1
abnormal, 43-9
operator requirements, 43-2
performance tests, 43-8
personnel safety, 43-8
shutdown, 43-9
startup, 43-2
screen, 19-6
selection, 26-1
setting, 23-1
supports, 19-8
surface, 19-1
types
anthracite combustion (RBW),
19-2, 26-6, 26-15
basic oxygen furnace
(BOF), 27-20
Steam 41 / Index
bent tube, Intro-7
biomass-fired, Chapter 30
blast furnace gas, 27-4
bubbling fluidized-bed (BFB),
17-2, 27-11
carbon monoxide (CO), 27-17
Carolina (RBC), 19-2, 26-12,
Color Plate 2
circulating fluidized-bed (CFB),
17-9, 27-8, Color Plate 5
El Paso (RBE), 19-2, 26-16
electric utility, Chapter 26
Enhanced Oil Recovery (EOR),
27-14
fire tube, Intro-4
FM, 27-12
FMB (marine package boiler),
31-4, 31-5
heat recovery steam generator
(HRSG), 27-15
High Capacity FM (HCFM),
27-12
industrial, Chapter 27, 28-1,
30-1
Integral Furnace, Intro-9, 19-2
fluidized-bed, 17-1
large utility, 19-2, Chapter 26
marine, Intro-6, Chapter 31
(see also Marine boiler)
oxygen converter hood, 27-20
package, Intro-10, 27-12
PFI, 27-13
PFM, 27-12
PFT, 27-13
pressurized fluidized-bed, 17-13
process recovery (PR), 28-1,
Color Plate 4
Radiant, Intro-10, 19-2, 26-11
shop-assembled, Intro-10,
27-12, 38-11
spiral circuitry or spiral
wound, 19-2, 26-7, 26-10
Spiral Wound Universal
Pressure (SWUP), 26-7,
Color Plate 1
Stirling (SPB), Intro-7, 19-2,
27-8, 30-2, Color Plate 3
subcritical, 19-3
supercritical, 19-3
Tomlinson, 28-10
Tower (RBT), 19-2, 26-14
Towerpak, 27-8, 30-8
Universal Pressure (UP),
Intro-10, 19-2, 26-6, 26-9
vertical tube, variable
pressure, 26-10
waste heat, 27-18
water tube, Intro-4, 19-1
wood-fired, Chapter 30
Boiler as a calorimeter (BAC)
calculation method, 10-23
Boiler-following control, 41-5
Boiler support steel, 39-11
Boiling, 1-2, 4-22, 5-1
convective, forced, 5-2, 5-3
departure from nucleate, 5-4,
46-11 (see also Critical heat
flux)
film, 5-2
flow, 5-2, 5-3
heat transfer, 4-22, 5-3
incipient, 5-2
nucleate, 4-22, 5-2
subcooled, 4-23, 5-2
transition, 5-2
Boiling water reactor (BWR), 46-2
Bomb calorimeter, 10-9
Bond work index, 35-7
Boric acid, 49-16, 49-18
Boring mill, 38-3
Bottom ash, 21-2, 24-13, 32-16
Boundary layer, fluid flow, 4-3, 4-14
Bourdon tube pressure gauge, 40-1
Brayton cycle, 2-22
IGCC plants, 18-14
Breeder reactor, 47-15
Broaching, 50-6
Buckstays, 23-2, 23-5
Buffer, 35-12
Bulk fluid temperature, 4-15
Buoyancy effects, 4-3
Burnable absorbers, nuclear, 47-13
Burner
auxiliary, 28-23, 29-21
coal, pulverized, Chapter 14
air-fuel mixing, 14-7
boiler integration, 14-5
burner nozzle, 14-7
cell, 14-9
circular, 14-9
corner-firing system, 14-16
DRB-4Z, 14-13
DRB-XCL, 14-12
dual register, 14-11
enhanced ignition, 14-18
flame safety system, 14-20
flame stability, 14-2, 14-7
impeller, 14-8
low NOx Cell, 14-14
movable, 19-16
numerical model, 6-21
oil or gas firing, 14-20
performance, 14-8
primary air exchange, 14-18
register, 14-7
S-type, 14-9
excess air, 10-15 (see also Excess
air)
flame detection, 41-15
fuel management, 41-15
management system, 41-14
automatic sequence, 41-14
failure mode analysis, 41-17
remote manual sequence, 41-14
supervised manual control, 41-14
oil and gas, Chapter 11
circular, 11-9
corner-firing system, 11-10
gas elements, 11-13
igniters, 11-15
marine, 31-6
mechanical atomizers, 11-11
I-3
The Babcock & Wilcox Company
steam atomizers, 11-12
XCL-S type, 11-9
operation
adjustments, 43-7
emissions 43-6
excess air, 15-2, 43-7
fuel conditions, 43-7
optimization, 43-6
overfire air adjustments 43-7
recovery boiler
limited vertical sweep, 28-20
oscillator, 28-20
selection, effect on steam
temperature, 19-16
Burner management systems, 41-14
Burning profiles, 9-8
Burnup, nuclear, 47-8
Bypass and startup systems
drum boilers, 19-20, 43-4
drum pressure control, 19-21,
44-16
dual pressure 19-20
operation, 19-20
steam pressure control, 19-21
upgrades, 44-16
UP boilers, 19-16, 43-12
constant furnace pressure
startup system, 19-19
flash tank, 19-19
heat recovery, 19-19
minimum required flow, 19-19
overpressure relief, 19-20
steam temperature control,
19-19
variable throttle pressure, 19-19
variable furnace pressure startup
system, 19-17
minimum flow, 19-17
vertical steam separator, 19-17
water collection tank, 19-17
Byproduct fuels, solid, 30-1
Calcination, 17-12
Calcium
carbonate, 35-9
sulfate, 35-9
sulfite, 35-9
Calculations, performance, 22-1
Calorimeter
boiler as (BAC), 10-23
bomb, 10-7
Calorimeter throttling, 40-17
CANDU, 46-2, 46-5, 48-1, 50-2
calandria, 46-6
Capacity
factor, 37-11
increase, 44-2, 44-20
Capitalized cost method, 37-13
Carbon dioxide in flue gas
from fuel analysis, 10-6, 10-21, 32-8
properties, 10-2
Carbon steel, 7-12
Carburization, 44-12
Carnot cycle, 2-12
Carrying charges, 37-11
Carryover, 5-13, 48-7
I-4
Carryover, impurities
mechanical, 42-12
moisture, 5-13
vaporous, 42-12
Carryunder, 5-13, 48-7
Casing, 23-3, 39-18
marine boilers, 31-12
Cast iron, 7-3, 7-14
air heater, 20-8
Cast steel, 7-15
Castings, 38-4
Catalyst – see NOx control, catalyst
Catalytic cracker, 27-13
Cavity
heat transfer, 4-28, 23-6
radiation calculation, 22-13
Celsius, 40-4
Cementite, 7-3
Centigrade temperature scale, 40-3
Centrifuge, 35-8
Ceramic tile, 35-5
Ceramics, 7-15
Ceramics and refractories, 15-10, 29-3
Chain reaction, nuclear, 47-7,
47-10, 47-11
Change of phase, solid, 7-2
Char, 14-3, 18-2
Charpy test, 7-17
Chemical
analyses
dewatering system, 36-10
EPA method, 36-7, 36-8
gypsum quality, 36-10, 36-13
lime quality, 36-7
limestone quality, 36-6
recirculation slurry/blowdown,
36-8
cleaning, fossil – see Chapter 42
advantages, 43-3
alkaline boilout, 42-18
circulation cleaning method,
42-20
cleaning equipment, 42-23
cleaning frequency, 42-19
cleaning time, 42-23
deposit samples, 42-22
deposits, 42-21
inhibitors, 42-22
precautions, 42-24
preoperational, 42-18
preparation, 42-23
procedures, 42-20, 42-23
soaking (cleaning) method, 42-21
solvent strength, 42-22
solvent temperature, 42-22
solvents, 42-21
superheater/reheater, 42-24
cleaning, nuclear, 49-3, 49-7
chemical addition, 49-16
startup, 49-16
cleaning solvent disposal
considerations, 42-24
co-ponding, 42-24
evaporation, 42-24
incineration, 42-24
options, 42-24
recovery process, pulp, 28-1, 43-16
vapor deposition, 7-15
Chemistry, fuel and water, Intro-17
Chimney – see Stack and draft
Chloride, 35-5
Chromizing, 7-15
Circulation, 1-3, 3-17, 5-17, 19-3,
20-4, 48-8
design criteria, 5-19
forced, 1-3, 5-19
improvements, 44-16
marine, 31-12
natural, 1-3, 5-18, 19-3, 43-4
once-through, 5-17, 19-3
startup, 43-4
steam generator, nuclear, 48-8
Circulation or flow circuits
Radiant boiler (RB), 26-13, 26-14
Spiral Wound Universal Pressure
(SWUP) boiler, 26-10
Cladding, 46-5, 46-8, 50-2, 50-4, 50-13
(see also Weld, cladding)
Classifier, coal, 13-2, 13-8
rotating, 13-13
Clean Air Act, U.S., 32-1, 35-1
1990 Amendments, 32-4
acid deposition control, 32-4
air quality control regions, 32-2
air toxics, 32-5
criteria pollutants, 32-2
evolution of legislation, 32-1
Maximum Achievable Control
Technology, 32-5, 32-10
National Ambient Air Quality
Standards, 32-2
New Source Performance
Standards, 32-2
New Source Review, 32-2
NOx SIP Call, 32-5
state implementation plans
(SIPs), 32-2
Clean Air Rules, 32-6
Clean Water Act (CWA), 32-13
Cleaning
air heater, 24-10
back pass/economizer, 24-8
convection pass, 24-5
external, 19-12
furnace, 24-2
internal, 19-12, 43-3 (see also
Chemical, cleaning, fossil)
SCR catalyst, 24-9
sonic horns, 24-9
Cleaning and inspection, nuclear,
49-15
Cleanliness, internal, 39-16
Cleanliness factor, 4-20, 22-4
Climate factor, fossil fuel units, 26-5
CO catalyst, 27-17
Coal
abrasiveness, Chapter 13
testing, 13-8
wear effects, 13-1, 13-4, 13-9
analysis
ash, 15-3
burning profile, 9-8
Steam 41 / Index
The Babcock & Wilcox Company
crushers, 15-6, 15-11
equilibrium moisture, 9-7
grindability, 9-8, 13-8
mineral-matter-free, 9-5, 9-7
moisture, 9-7, 15-3
moisture-free, 9-7
sizing, 15-6
sulfur, 9-4, 9-7, 15-12
angle of repose, 12-14
anthracite, 9-6
bituminous, 9-6
blending, 12-16
breakers, 12-3
bulk density, 12-14
caking, 9-8
char, 9-9
characterization (impurities),
9-7, 12-5
organic sulfur, 12-5
pyritic sulfur, 12-5
sulfate sulfur, 12-5
classification, 9-5
cleaning, 12-4, 32-8
dewatering, 12-8
dry processing, 12-8
flotation, 12-8
gravity concentration, 12-6
tramp metal, 12-3, 12-13
coalification, 9-3, 12-5
crushers, 12-3, 12-12
dry, mineral-matter-free, 9-5
drying, 13-2
dust suppression and collection,
12-17
elemental ash analysis, 9-8
enthalpy, 10-20
erosiveness, 9-9, 13-9
feeders, 12-15, 13-2, 15-7, 44-3
gravimetric, 12-15
volumetric, 12-15
fixed carbon, 9-5
fouling indices, 9-8, 21-13
free swelling index, 9-8
friability, 12-8
frozen coal, 12-17
gasification, 9-11, Chapter 18
(see also Gasification, coal)
grindability, 9-8, 13-8
grinding, 13-2
gross calorific value, 9-8
gross (higher) heating value
(HHV), 9-8
Hardgrove Grindability Index
(HGI), 9-8, 13-8
heating value, 9-8, 10-10
lignite, 9-6
lower (net) heating value
(LHV), 9-8
mining, 12-2
moisture, 9-5, 9-7, 13-10
oxidation, 12-17
preparation, 12-4
processing and handling,
Chapter 12
properties, effect on design, 26-3
proximate analysis, 9-5
Steam 41 / Index
pulverizer – see Pulverizer
pyritic sulfur, 9-4
rank, 9-5
reserves, 9-1
screening, 12-4
size reduction, 12-3
sizing, 12-3
slagging indices, 9-9, 21-13
slagging potentials, 9-9
spontaneous combustion, 12-13
stoker, 16-1, 16-4
storage, 12-10
bunker, 12-14
design, 12-14
downspout design, 12-15
seal height, 12-15
fires, 12-18
flow problems, 12-17
funnel flow, 12-15
mass flow, 12-15
shear cell, 12-15
silo, 12-14
stacker, 12-13
stockpile, 12-13
fires, 12-17
inspection and maintenance, 12-14
reclaim, 12-14
subbituminous, 9-1, 9-6
transportation, 12-8
barge, 12-9
continuous transport, 12-10
rail, 12-9
truck, 12-10
ultimate analysis, 9-8
U.S. availability, 9-2
volatile matter, 9-5
world availability, 9-1
Coalification, 9-3
Coatings, 7-15
Codes, 8-5, C-1
Cogeneration, 1-4, 27-4, 30-1
Coke, 9-6
breeze, 9-9
delayed coke, 9-17
fluid coke, 9-17
oven gas, 9-10
Cold
bending, 7-9
drawing tubes, 38-10
forging, 7-9
rolling, 7-9
work, 7-9
Combined cycle, 1-17, 27-4
Combined heat and power, 30-1
Combustion
biomass fluidized-bed, 17-3, 17-5,
30-7
Btu method, 10-6, 10-23, 10-26
calculation methods, 10-3, 10-23
calculations, 22-3, 22-5 (see also
Chapter 10)
coal, fluidized-bed, 17-1 (see also
Fluidized-bed boiler)
coal, pulverized, 14-1
char oxidation, burnout, 14-3
char reactivity, 14-3
combustion rate, 14-2
devolatilization, 14-3
mineral matter effect, 14-4
moisture effect, 14-3
unburned carbon loss, 14-8,
14-19
volatile matter effect, 14-3 (see
also Volatile matter, coal)
constants, 10-2
control(s), 41-10
corner-firing, 11-10, 14-16
definition, 10-1
Dulong’s formula, 10-10
equilibrium, 2-26
fundamental laws, 10-1
guides, operating, 41-13
heat of, 10-7
mole method, 10-3, 10-6, 10-8, 10-23
numerical model, 6-1 (see also
Numerical modeling)
advanced burner, example, 6-21
combustion reactions
heterogeneous, 6-8
homogeneous, 6-7
mesh generation, 6-19
radiation, 6-8
stoker, example, 6-21
theory, 6-3
oil and gas
efficiency, 11-5
excess air, 11-4
performance requirements, 11-4
pulsation, 11-5
stability, 11-4
turndown, 11-4
pressurized fluidized-bed, 17-13
principles of, Chapter 10
pulverized coal – see Combustion,
coal, pulverized
system, coal
applications for metals and
cement industry, 14-21
compartmented windbox,
14-11
conventional, 14-4
corner-firing, 14-16
downshot firing, 14-5, 14-18
high moisture coal, 14-5
integration with boiler, 14-5
low volatile coal, 14-5
overfire air (OFA) ports,
14-10, 14-18
primary air, 14-2, 14-6
pulverized coal, 14-1
safety, 14-20
secondary air, 14-2, 14-7
research and development,
Intro-14
sorbent, 10-11, 10-27
stoker – see Stoker
three Ts of, 10-1
use of mole, 10-3
Commercial operation, nuclear, 49-20
Commercial structure, 37-9
Compressed water, properties, 2-4, T-7
I-5
The Babcock & Wilcox Company
Compressible, 3-1
Compressor, energy equation, 2-9
Computational fluid dynamics
(CFD), 6-1
Computer numerical control, 38-3
Condensate/condensate polishing, 42-6
Condensation, film, 4-22
Condensing attemperator system,
25-21, 27-7
Condition assessment, Chapter 45
analysis techniques
BLESS code, 45-15
crack growth, 45-14
cycling effects, 45-17
leak before break, 45-14
life fraction, 45-10, 45-12, 45-15
remaining life, 45-11
boiler components
air heater, tubular, 45-11
attemperators, 45-9
drums, 45-6, 45-20
economizer, 45-17
headers
high temperature, 45-7
low temperature, 45-8
settings, 45-11
tubing
steam-cooled, 45-7, 45-11
water-cooled, 45-7, 45-13
Conductance, heat transfer
for conduction, 4-1
for convection, 4-3
in thermal circuit, 4-6
unit-thermal conductance, 4-3
Conduction, heat transfer
cylindrical geometries, 4-6
definition, 4-1
Fourier’s law, 4-1
Conductivity
feedwater limits, 43-12
method, steam purity, 40-17
thermal, refractory and
insulation, 23-6
Conservation
of energy, 3-3, 6-4
of mass, 3-2, 6-4
of momentum, 3-2, 6-4
Consolidated nuclear steam
generator, 46-21
Constructability, 39-4
Construction, Chapter 39
approaches, 39-6
field modularization, 39-6
knocked down, 39-6
shop modularization, 39-6
cost, 39-2
project management, 39-3
safety, 39-16
schedule, 39-2
technology, 39-5
Contact resistance, heat transfer, 4-1
Containment building, 46-3
Continuity equation, 3-2, 6-5
Continuous emission monitoring
(CEM), 34-8, 36-4
Contraction
I-6
pressure loss, 3-11
static pressure, difference, 3-13
Control (and protective systems),
nuclear
in-core instrumentation, 49-9
integrated control system, 46-14,
49-17
neutron detectors, 47-14, 49-17
non-nuclear instrumentation, 49-17
nuclear, 49-17
reactor protection system, 49-17
rod, 49-8, 49-18
assemblies, 46-8
drive mechanisms, 49-8
worth, 47-13, 49-18
room, 49-20
Control system design philosophy
Universal Pressure oncethrough boiler, 41-12
utility drum boiler, 41-5
Control volume
fluid dynamics, 3-2
for energy balance, 4-5, 4-23
for numerical modeling, 6-7
Control(s) and control systems,
Chapter 41
atmospheric fluidized-bed boiler,
41-11
auxiliary boiler (marine), 31-5
basic theory, 41-1
boiler-following, 41-5
burner, 41-14
burner management systems,
41-14
closed loop, 41-2
combustion, 41-10
coordinated boiler-turbine, 41-6
Cyclone-fired boiler, 41-11
during startup, 43-3
feedforward/feedback, 41-4
fluidized-bed, 41-11
furnace draft, 41-10
human factor engineering, 41-20
integrated boiler and turbinegenerator, 41-6
merchant marine boiler, 31-2, 31-3
naval boiler, 31-1
neural networks, 43-7
nuclear plant, 49-10, 49-17
oil- and gas-fired boiler, 41-10
open loop, 41-2
proportional, 41-2
proportional plus integral, 41-4
proportional plus integral plus
derivative, 41-4
pulverized coal-fired boiler, 41-10
pulverizer, 13-2
selective catalytic reduction
systems, 41-17
scrubbers, 41-17
sootblowing, 43-8
steam flow-air flow, 41-13
steam temperature, 19-12, 31-9
(see also Steam, temperature)
turbine-following, 41-5
Universal Pressure boiler, 43-11
Convection, heat transfer, 4-3
boiler surface, 19-6
definition, 4-3
fouling, 4-20
heat flow, rate of heat transfer, 4-3
Convection pass, 1-7, 7-21, 19-1, 20-4
Convective heat-transfer coefficient,
(see also Nusselt number)
in flow over banks of tubes, 4-16,
4-18
in flow through tubes (and ducts)
laminar, 4-15
turbulent, 4-16
in free convection, 4-14
Conversion factors, Appendix 1
Conversion formulae for emission
rates, T-14
Converter reactor, 47-15
Coordinate measuring machine, 50-8,
50-11
Coordinated boiler-turbine control,
41-5
Coordination curves, pulverizer, 13-7
Core – see Reactor
Core reactivity coefficients, 49-18
Corrosion, 23-7, 42-14 (see also Ash,
coal, corrosion and Ash, fuel
oil, corrosion)
acid corrosion, 42-16
acid dew point, 27-16
acid phosphate corrosion, 42-16
air heater, 20-13
caustic corrosion, 42-17
caustic cracking, 42-17
caustic gouging, 42-17
chelant corrosion, 42-16
corrosion fatigue, 42-16
decarburization, 42-17
erosion-corrosion, 45-9 (see also
flow accelerated corrosion)
flow accelerated corrosion, 42-15
fretting, 48-9, 49-2
fuel ash, 7-22, 21-20
general, 42-1
hydrogen damage, 42-16
intergranular, 7-6, 42-15, 42-18,
48-9
locations, 42-15
out-of-service corrosion, 42-18
pitting, 42-16, 48-9, 49-2
protection, process recovery
boiler, 28-11
stress corrosion, 48-9, 49-2, 49-7,
49-8
stress corrosion cracking, 42-18,
48-9
syngas cooler, gasification, 18-11
under-deposit corrosion, 42-16
wastage, 49-2
waste-to-energy system, 29-2
ash cleaning equipment, 29-21
bimetallic tube, 29-5
ceramic tiles, 29-3
chloride, 29-2
flue gas temperature, 29-3, 29-18
hydrochlorides, 29-3
Steam 41 / Index
The Babcock & Wilcox Company
Inconel, 29-4, 29-19
Inconel bimetallic, 29-5, 29-19
lower furnace, 29-3
metal temperature, 29-3
oxidizing atmosphere, 29-3
parallel flow superheater, 29-20
pin stud, 29-3
protection, 29-3
reducing atmosphere, 29-3
refractory, 29-3, 29-8
silicon carbide, 29-3, 29-8
superheater, 29-20
wear zone panel, 29-4
weld overlay, 29-3
Cost(s)
constant, 37-11
current, 37-11
evaluation, 37-11
future value, 37-12
levelization, 37-12
present value, 37-12
Cranes, 39-9
Creep, 7-1, 7-19, 8-12, 44-12
crack growth, 8-12
detection, 45-7
flaw size, 8-10
headers, 45-7
life prediction, 45-12
piping, 45-9
replication, 45-5
rupture, 7-19
Creep-fatigue, 44-14
Criteria Pollutants, 32-2
Critical boron concentration, 47-13
Critical flow, 5-20
Critical heat flux (CHF), 5-2, 5-4,
5-19, 19-8
criteria, 5-6
definition, 5-4
evaluation, 5-6
marine boiler, 31-7
ribbed bore tube, 5-6
Critical mass, 47-10
Critical transformation
temperature, 7-3
lower critical, 7-4
upper critical, 7-4
Cross-section, nuclear, 47-5, 47-12
absorption, 47-6
capture, 47-6
fission, 47-6
macroscopic, 47-6
microscopic, 47-6
resonance, 47-6
scattering, 47-6
Crossflow, friction factor, 3-15
Crushers, 12-3
double roll, 12-3
hammermill, 12-4
rotary breaker, 12-3
single roll, 12-3
Crystal structure, 7-1
body-centered cubic, 7-1
body-centered tetragonal, 7-4
face-centered cubic, 7-1
Curies, 47-4
Steam 41 / Index
Cycle
Brayton, 2-22
Carnot, 2-12
nuclear fuel, 47-12
Rankine, 2-13
for nuclear plant, 2-19
regenerative, 2-14
reheat, 2-15
steam, 2-1, 2-12
Cycling, 27-17, 44-15
definition, 45-17
drum, 45-20
economizer, thermal shock, 45-17
furnace, subcooling, 45-18
operation control, 41-7
superheater, tube leg flexibility,
45-19
Cyclone furnace, Chapter 15, 43-10
advancements, 15-12
advantages, 15-1
air pollution control, 15-12
ash, 15-3
burner, 15-2, 15-4
radial, 15-4
thin door radial, 15-4
scroll, 15-4
vortex, 15-4
capacities, 15-5, 15-9
coal
crushers, 15-6, 15-11
feeders, 15-7
sizing, 15-6, 43-10
suitability, 15-3, 15-5, 43-10
combustion air, 43-10
combustion control, 15-9
controls, 41-11
design features, 15-7
erosion, 15-11
fabrication, 38-9
firing arrangements, 15-5
flyash emission and recovery,
15-3, 15-12
fuels suitable for, 15-3, 15-8, 43-10
igniters, 15-10
oil and gas burners, 15-8
operation and maintenance, 15-10,
43-10
power requirements, 15-10
waste fuels, 15-3, 15-9
D-type boiler (FM), 27-12
Dampers
control, 25-3
guillotine, 25-4
isolation, 25-3
louver, 25-3
round, 25-4
Data acquisition, 40-3, 40-24
Dead weight gauge, 40-2
Decay
radioactive, 47-4
Degradation mechanisms, 44-6, 44-11
Demand charge, 37-11
Density
of flue gas, 4-11
of gases, 4-11
Departure from nucleate boiling,
DNB – see Critical heat flux
Deposits
ash, 21-3, 24-1
scaling, 42-3
slag, 21-11, 24-2
water-side, 42-15, 42-19
Desuperheater (see also Attemperator)
marine, 31-10
Diffusion
atomic, 7-1
thermal, 4-7, 4-22
Dimensional analysis, heat transfer
correlation of data, 4-15
dimensionless numbers or
groups, 4-15
Discount rate, 37-11
Discrete ordinates method, 6-9
Dislocations, 7-2
Dissimilar metal welds, 7-11
Dissolved alkalinity, 35-12
Distillate fuels, 9-12
Distributor grid, 27-17, 34-6
DNB – see Critical heat flux
Doppler
coefficient, nuclear fuel, 47-14,
49-18
effect, 47-6
Dose
equivalent, 49-13
radiation, 47-3
radiation absorbed, 49-13
Downcomer, 48-5
definition, 1-3, 1-9
Draft (see also Stack and draft)
calculations – see Chapter 22
loss, 19-7, 25-6
Draft effect, 3-15
Drainability, economizer, 20-5
Drum, steam, 1-3, 5-13, 39-10
allowable temperature
differential, 43-5
baffle(s), 5-14
capacity, 5-17
condition assessment of, 45-6
cycling, 45-20
fabrication, 38-5
head fabrication, 38-5
lifting, 39-11
marine, 31-11
materials, 7-23
protection, startup and
shutdown, 43-5, 45-20
support, 39-11
U-bolts, 39-12
Dry scrubbers – see SO2 control
controls, 41-19
Dry shielded canister, 50-13
Dryout – see Critical heat flux
Dual economizer steam air heater
(DESAH), 31-11
Dual furnace, 31-9
Duct burner, 27-17
Ductile iron, 7-15
Ductility, 7-17
I-7
The Babcock & Wilcox Company
Duplex alloys, 7-14
Dust collector, 33-12, 35-2
Earthquake
requirements, 26-2
Economic evaluation, 37-1, 37-10
Economizer, 1-8, Chapter 20, 27-2
calculations, 20-4, 22-13
cascading longflow, 28-14
cleanability, 20-2
condition assessment of, 45-7
continuous, 28-14
crossflow, 28-14
cycling, 45-17
drainability, 20-5
erosion, 20-3
fabrication, 38-8
fin, 20-2
gas velocity limits, 20-3
header, 20-6
heat transfer, 20-4
longflow, 20-4, 28-14
marine, 31-11
materials, 7-21
mean temperature, 20-4
plugging, 20-2, 20-14
pressure drop, 20-5
sootblowers, 20-3
startup protection, 43-4
steaming, 20-4
stringer tubes, 20-6
supports, 20-5
tube
baffles, 20-3
diameter, 20-6
tube deflection, 20-5
upgrade, 44-7
vibration, 20-6
wall enclosures, 20-5
Eddies, 3-8
Eddy current testing – see
Nondestructive examination
Edison, Thomas Alva, Intro-6, Intro-8
Efficiency, 44-18
boiler or steam generating unit,
19-4
combustible fuel, 10-17
cycle – see Chapter 2
gasification systems, 18-2, 18-14
heat balance, 10-18
marine boiler, 31-10
operating techniques, 43-6
particulate removal, 36-13
recovery boiler, 28-4
calculations, 28-6
SO2 removal, 35-6, 36-13
Effluents (aqueous), 32-13
Ejector, 3-16
Electric resistance welded (ERW)
tubes, 7-21
Electric utilities
history of, Intro-7
Electromagnetic acoustics, 45-4
Electron, 47-1
Electropolishing, 50-2, 50-11
Electrostatic precipitator, 29-22,
32-10, 33-2, 33-8, 35-2, 35-13
I-8
applications, 33-3, 33-8
Electrostatic precipitator, dry, 33-2
components, 33-4
casing, 33-4
collecting electrodes, 33-5
discharge electrodes, 33-5
enclosure, 33-4
hoppers, 33-4
insulators, 33-5
power supplies and controls, 33-6
rapping systems, 33-5
transformer rectifier, 33-6
particle size distribution, 33-7
particulate control, 33-3
ash removal, 33-3
charging, 33-2
collection, 33-2
rapping, 33-3
performance
Deutsch-Anderson equation,
33-6
enhancement, 33-7
fuel and ash, 33-3
gas flow control, 33-5
sizing factors, 33-6
reentrainment, 33-3
resistivity, 33-3
sectionalization, 33-7
Electrostatic precipitator, wet, 33-8,
35-19
Emergency core cooling system
(ECCS), 46-15
Emergency feedwater system, 49-15
Emissions, air pollution (see also
individual pollutants)
cold gas, 18-2
F-factor, 36-12
gasification plants, 18-12
industrial boilers
carbon monoxides (CO), 27-7
nitrogen oxides (NOx), 27-7
particulate matter (PM), 27-7
sulfur oxides (SOx), 27-7
volatile organic compounds
(VOC), 27-7
oil and gas, 11-5
opacity, 11-9
oxides of nitrogen, 11-5
oxides of sulfur, 11-8
particular matter, 11-8
stokers, 16-10
utility boilers, 1-10, 26-5, 32-2
waste-to-energy system
activated carbon injection, 29-23
baghouse, 29-22
carbon monoxide, 29-23
dry scrubbing system, 29-22
electrostatic precipitator, 29-22,
29-23
hydrochloric acid, 29-22
mercury, 29-22
nitrogen oxides, 29-23
polychlorinated dibenzofurans,
29-6
polychlorinated dibenzoparadioxin, 29-6
selective catalytic reduction,
29-23
selective non-catalytic
reduction, 29-23
sulfur dioxide, 29-22
Emissive power, 4-4
Emissivity (and emittance), 4-4, 4-10
coal-ash deposits, 4-10
gases, 4-12
gray surfaces, 4-4, 4-10
non-gray surfaces, 4-4
of various surfaces, 4-12
Enclosure, Chapter 23 (see also
Setting, boiler)
Energy
applications, 2-9
available, 2-17
consumption, 9-1
equation, 2-7, 2-9, 3-4, 4-5, 4-7
production, 9-1
Enhanced oil recovery, 27-14
Enthalpy, 2-1, 2-7, 5-1
steam and water, 2-1, 2-2, T-5, T-6
Entrainment, 3-16
Entropy, 2-10
increase, 2-12
steam and water, 2-1, 2-2, T-5, T-6
Environmental
gas-side measurements, 36-8
legislation – major U.S., Chapter 32
Clean Air Act, 32-1 (see also
Clean Air Act, U.S.)
Clean Water Act, 32-13
research, development and
evolution of, Intro-14
The Resource Conservation and
Recovery Act (RCRA), 32-15
process monitoring, 36-6
Environmental control, 27-4,
Chapter 32
Environmental equipment,
construction 39-15
Environmental regulations,
Chapter 32, 44-2, 44-20
Equilibrium diagram, 7-3
Equipment diagnostics, nuclear (see
also Nondestructive
examination)
check valves, 49-11
destructive examination, 49-4
eddy current testing, 49-4, 50-10
fitness-for-service assessment, 49-3
foreign object search and retrieval
(FOSAR), 49-3
loose parts monitoring, 49-10
motor operated valves, 49-11
neutron noise monitoring, 49-11
reactor coolant pump monitoring,
49-11
valve monitoring and diagnostics,
49-11
Equipment selection, 26-1
Equipment specification, 37-2
Equivalent
diameter, 3-7, 4-15, 4-18 (see also
Hydraulic diameter)
Steam 41 / Index
The Babcock & Wilcox Company
Erection (see also Construction)
approaches, 39-3
auxiliaries, 39-18
cleanliness, 39-16
cost estimates, 39-2
field welding, 39-13
material handling, 39-8
nonpressure parts, 39-18
procedure, fossil fuel unit, 39-11
structural supports, 39-11
time estimates, 39-2
time span, 39-2
Erection methodology, 39-6
contractor interface, 39-7
new construction, 39-6
plant arrangement, 39-6
product parameters, 39-7
retrofit, 39-6
schedule, 39-2, 39-7
scope, 39-6
site conditions, 39-7
Erosion, 21-17, 23-4
air heater, 20-14
barriers, 44-8
protection, 44-4, 44-20
tube bends, economizer, 20-3
Estimating, construction, 39-2
Euler
equation of motion, 3-3
number, definition, 3-7
Evaluation criteria, 37-7
Evaporation, 4-22, 5-1, 42-2
Evaporator, chemical process recovery
cascade, 28-19
cyclone, 28-19
direct contact, 28-19
multiple effect, 28-19
Examination (see also Condition
assessment)
destructive
boat samples, 45-6
tube samples, 45-6
methodology, 45-1
nondestructive (see also Nondestructive examination)
acoustic emissions, 45-5
eddy current, 45-3
electromagnetic acoustics, 45-4
liquid penetrant, 38-12, 45-2
magnetic particle, 38-12, 45-2
nuclear fluorescence, 45-4
radiography, 38-11, 45-4
replication, 45-5
strain, 45-6
temperature, 45-6
ultrasonic, 38-12, 45-2
visual, 45-1
Excess air, 10-15
effect on Cyclone corrosion, 15-4
effect on Cyclone operation, 43-10
effect on efficiency, 43-1
effect on steam temperature, 19-13
from flue gas analysis, 10-21, 10-23
loss, 43-6
measurement of, 10-21
Expansion, boiler, 23-4
Steam 41 / Index
Expansion joints, 25-5
configurations used in flues and
ducts, 25-5
metallic, 25-5
nonmetallic, 25-5
types, 25-5
Extended surface, 4-20
Extruded tubing, 44-8
Fabric filter (and baghouse), 32-10,
33-8, 35-13, Color Plate 7
air/cloth ratio, 33-10
applications, 33-10
bag materials and supports, 33-11
cleaning, 33-11
configurations, 33-11
hatch style, 33-11
walk-in, 33-11
design parameters, 33-10
drag, 33-10
dustcake, 33-8
enclosure, 33-11
hoppers, 33-11
operating fundamentals, 33-8
tubesheet, 33-8
types, 33-9
pulse jet, 33-10
reverse gas, 33-9
shake deflate, 33-10
shaker, 33-10
Fahrenheit temperature scale, 40-4
Fans
acoustic noise, 25-20
aerodynamic characteristics, 25-20
axial flow, 25-17
centrifugal, 25-15
drives, 25-17
forced draft, 25-13
gas recirculating, 25-14
induced draft, 25-14
laws of performance, 25-11, 25-18
maintenance, 25-14
output control, 25-15
performance, 25-11
power, 25-10
primary air, 13-6, 25-14
specific diameter, 25-12
specific speed, 25-15
stall, 25-19
testing, 25-14
variable speed, 25-15
Fast reactors, 47-15
Fatigue
crack growth, 8-11, 8-13
damage evaluation, 8-6, 45-5
design curve, 8-6
maintaining availability, effect on,
44-6, 44-11, 44-14
Feasibility, project, 37-1
Fechheimer probe, 40-22
Feedwater
control, 41-8
design considerations, 26-5
economizer, 20-6
requirements, Universal Pressure
boiler, 43-11
temperature, effect on final steam
temperature, 19-13
treatment
effect on boiler availability, 43-8
Ferrite, 7-3
Ferritic stainless steels, 7-14
Filling boiler, 43-4
Film condensation, 4-22
Filter
sludge, vacuum, 35-8
Fine grinding, coal, 13-14
Fineness, coal, 13-8
capacity factors, 13-10
testing, 13-10
Finite element analysis (FEA), 8-8
application of, 8-8, 8-9
computer software, 8-9
limitations, 8-9
nonlinear, 8-9
stress analysis, 8-8
Finned tube economizer, 44-7, 44-18
Fins
circumferentially attached, 4-20
economizer, 20-2
efficiency, 4-21
Fire(s) and fire protection
air heater, 20-14
pulverizer, 13-13
Firing rate control, Universal
Pressure boiler, 43-11
Fission, Intro-12, 1-11, 46-1 (see
also Fuel, nuclear)
process, 47-2
product(s), 46-11
Fittings
flow resistance, 3-9
Fixation, 32-16
Fixed charges, 37-11
Flake glass, 35-5
Flame
coal, pulverized, 14-7
detection or scanners, 14-20,
41-15
stability, 14-7
photometer, 40-18
Flat stud tubes, 23-2
Floor design, process recovery boiler,
28-12
decanting, 28-12
sloped, 28-12
Flow
around tubes, 4-16, 4-18
boiling, 5-2
coast down, 49-20
in tubes (and ducts), 4-15, 4-16
instability, 5-11
laminar, 3-8, 4-15
over flat plate, 4-15
patterns, 5-8
turbulent, 3-8, 4-16
two-phase, steam-water, 5-8
Flue gas, 1-5, 1-10
analysis, 10-21
enthalpy, 10-19
excess air determination, 10-21
I-9
The Babcock & Wilcox Company
mass flow, 10-16
moisture, 10-6, 10-17
residue, 10-14
sampling, 10-21
specific heat, 22-9
volumetric combustion chart, 10-22
Flue gas desulfurization (FGD) (see
also SO2 control, scrubber (FGD))
construction, 39-15
dry scrubbing, 32-9, 35-12
sorbent injection, 32-9
wet scrubbing/scrubber, 32-9,
35-2, 36-1
Flue gas sampling
isokinetic, 36-12
location selection, 36-7
Flue gas velocity, 20-3
Fluid
dynamics, Chapter 3
research and development of,
Intro-15
entrainment, 3-16
flow, energy equation, 3-4
flow measurement, 40-20
flow nozzle, 40-20
orifices, 40-20
venturi tube, 40-20
friction, pressure loss, 3-5
pressure loss, two-phase, 5-9
straightening vanes, 40-20
Fluidization, 17-2
Fluidized-bed boiler, Chapter 17,
27-8, Color Plate 5
air staging, 17-8
ash, 17-10, 17-12
attrition, 17-13
bubble caps, 17-2
bubbling bed, 17-1, 17-2, 27-11
calcination, 17-12
circulating bed, 17-1, 17-9, 27-8
control, 41-11
distributor, 17-3
fixed bed, 17-1
fuel feed systems, 17-7
mean diameter, particle, 17-2
minimum fluidization, 17-1
NOx control, 17-8, 17-13
operations, 43-13
bubbling bed, 43-15
fuel sizing, 43-15
operating overview, 43-15
circulating bed, 43-13
biomass firing, 43-14
coal firing, 43-14
fuel sizing and characteristics, 43-14
operating overview, 43-13
operations, 43-13
startup and shutdown, 43-14
overfire air system, 17-6, 17-8
pressurized bed, 17-13
Sauter mean diameter, 17-2
slumped bed, 17-3
solids separation, 17-11
staged combustion, 17-13
superficial bed velocity, 17-3
I-10
temperature control, 17-4, 17-10
turbulent bed, 17-2
U-beams, 17-11
volume-surface mean diameter,
17-2
waste fuels, 17-1
Flyash, 32-1, 32-16 (see also Ash,
coal)
Flyash plugging, 44-7
Forced circulation, 1-3, 5-19 (see
also Circulation)
Forced convection, heat transfer
entrance effects, 4-14
heat transfer coefficient inside
tubes (and ducts), 4-3, 4-15,
4-16
laminar flow, 4-15
turbulent flow, 4-16
Forced outage rate, 44-1
Formic acid, 35-12
Forming, 38-3
Fouling, 4-20, 9-8, 28-9, 44-6 (see
also Ash, coal, deposition)
Fracture mechanics, 8-10
creep
crack growth, 8-12
flaw size, 8-12
elastic-plastic, 8-11
failure assessment
deformation plasticity, 8-11
diagrams, 8-11, 8-12
leak-before-break, 8-12
plastic instability, 8-12
safety margins, 8-12
fatigue crack growth, 8-12
linear elastic, 8-10
time dependent, 8-13
toughness, 7-18
Free convection, heat transfer, 4-14
Free surface, 3-1
Friction factor
crossflow gases, 3-15
flow in pipes and ducts, 3-7, 3-8
Friction loss, 3-5
two-phase flow, steam-water, 5-9
Fuel (see also specific fuel and
Chapter 9)
biomass, 9-18, 16-1, 16-7, 30-1
boiler operations, 43-1
coal, 15-1, 26-3
flow control, 41-10
flow measurement, 41-13
natural gas, 15-8 (see also
Natural gas)
firing application, 26-16
nuclear,
assembly, 46-8, 47-9
burnup, 47-8
fission, 47-6
chamber, 47-14
energy, 47-7
neutrons, 47-7
process, 47-6
products, 47-8
fissionable, 47-5
fusion, 47-2
handling, 49-12
loading, 49-18
refueling, 46-10
oil, 9-12, 11-1, 15-8 (see also
Petroleum)
API gravity, 9-14, 11-2
asphaltene content, 11-2
auxiliary, marine, 31-5
burning equipment, 11-9
burning profile, 11-2
carbon residue, 11-2
combustion calculations,
Chapter 10
distillation, 11-2
enthalpy, 10-20
fire point, 11-2
firing application, 26-16
flash point, 9-14, 11-2
heating value, 11-2
kinematic viscosity, 9-14
merchant marine, 31-3
naval, 31-2
No. 2, 9-12
No. 6, 9-12
Nos. 4 and 5, 9-13
pour point, 9-14, 11-2
preparation, 11-1
properties, 11-2
reserves, 9-12
residual fuel oils, 9-13
Saybolt Furol viscosity, 9-14
Saybolt Universal viscosity, 9-14
specific gravity, 11-2
transportation, storage and
handling, 11-1
ultimate analysis, 11-2
viscosity, 11-2
water and sediment, 9-14, 11-2
Orimulsion, 11-3
other gases, 11-3
purging, 43-1
research and development of,
Intro-14
sludge, 30-4
straw, 30-2
switching, 32-5, 32-8
switching, SO2 control, 35-1, 44-18
wood, 30-2
Fuel ash corrosion, 44-12
Fuel NOx, 34-1
Furnace, 1-7
Controlled Combustion Zone
(CCZ), 16-7, 30-6
design, enclosure, 19-4
dry ash, 19-6
recovery boiler, 28-10
sizing, 19-5, 21-14
slag-tap, 19-6
water-cooled walls, 19-6
wet-bottom, 19-6
divided, 19-16
draft control, 41-10
dutch oven, 30-4
exit gas temperature, calculation,
22-4
heat transfer calculations, 22-3
Steam 41 / Index
The Babcock & Wilcox Company
heat transfer methods
empirical, 4-24
numerical, 4-26
marine, 31-1, 31-2
materials, 7-21
subcooling, 44-15
wall corrosion, 44-8
wall wastage, 44-7
Fused coatings, 7-16
Future value, 37-12
Galvanizing, 7-16
Gamma ray, 47-3, 49-13
Gas (see also Natural gas)
constant, 3-4, 40-4
enthalpy, 10-12, 10-19
equation, 40-4
expansion, 40-4
temperature evaluation, 40-16
temperature measurement,
40-14
flue gas, 10-16
forced convection around
cylinders, 4-15
free convection, 4-14
laminar forced convection in
tubes, 4-15
laws, 3-4, 10-1
physical properties, 3-10, 4-9,
4-11, 10-2
turbulent forced convection in
tubes (and ducts), 4-16
viscosity, 3-11
Gas, flue (see also Flue gas)
analysis, 41-14
biasing effects, 19-15
proportioning damper, 19-15
recirculation, 19-15
tempering, 19-15
Gas disperser, 35-13
Gaseous
fuels from coal, 9-9, 18-1
radiation, 4-4, 4-8, 4-12
state, 3-1
Gasification, black liquor, 28-27
high temperature, 28-28
low temperature, 28-28
Gasification, coal, 9-11, Chapter 18
air-blown, 18-2
crossflow, 18-4
definition, 18-1
developmental issues, 18-11
developments, 18-7
down-flow, 18-4
entrained flow, 18-6
fixed (moving) bed, 18-4
fluidized bed, 18-5
gas compositions, 18-3
gas cooling, 18-11
oxygen blown, 18-2, 18-10
power generation, 18-14
processes, 18-2
product cleanup, 18-12
reactions, 18-1
transport, 18-7
Steam 41 / Index
upflow, 18-3
Geiger counter, 49-13
Generating bank (see also Boiler,
bank)
crossflow, 28-12
longflow, 28-17
Geographical considerations in
boiler design, 26-5
Global warming, 32-8
Grain boundaries, 7-2
Graphitization, 7-4, 7-11, 44-12
Grashof number, definition of, 4-2,
4-14
Grate
air-cooled, 16-6, 16-8
chain, 16-3
moving, 16-2
pinhole, 30-4
stationary, 16-2
traveling, 16-3, 16-5, 16-8, 30-5
vibrating, 16-3, 16-5, 16-9, 30-5
water-cooled, 16-3, 16-10
Gray iron, 7-14
Graybody, thermal radiation, 4-10
Green liquor, 28-25
Greenhouse gases, 32-8
Grid – see Mesh generation
Guarantees
equipment, 26-6
performance, 37-4, 37-5
Gundrilling, 50-4
Gypsum, 32-1, 32-16, 35-8
Half-life, 47-4
heavy elements, 47-5
radioactive, 47-4
Hardening, quenching, 7-9
Hardness, 7-17
Hazardous Air Pollutants (HAPs),
32-4
Hazardous waste, 32-15
Header(s)
analysis techniques, 45-14
condition assessment of, 45-7
creep, 45-7
fabrication, 38-6
leak detection, 45-17
ligament, 44-14
material, 7-23
protection, startup, 43-5
structural analysis – see Chapter 8
tube-to-header weld, 44-15
upgrade, 44-14
Heat
affected zone (HAZ), 7-10
available, 10-11, 10-23
credits, 10-18, 10-23
Dulong’s formula, 10-10
exchanger
air heater(s), 20-7
effectiveness, 4-22
mean temperature difference in,
4-19, 4-21
nuclear, 48-1
types, arrangements, 4-20
losses, 10-15, 10-18, 10-19, 23-5,
43-6
mechanical equivalent, 2-8
of combustion, 10-7
of formation, 28-5
of reaction correction, 28-5
of vaporization, 5-1
rate, 19-9
reduction due to deposits, 43-6
transfer, Chapter 4
applications, 4-28
basic modes, 4-1
boiling, 4-21, 4-27, 5-3
calculations, Chapter 22
cleanliness factor, 4-20
coefficient of, 4-3
condensation, 4-22
conduction, 4-1
contact resistance, 4-1
convection, 4-3, 4-14
discrete ordinates, 6-9
electrical analogy, 4-6, 4-23
extended surface, 4-20
furnaces, 4-24
gas-side, 20-4
gas-to-gas, 20-16
insulation, 4-22, 4-29
Kirchoff’s law, 4-4
modeling of, 6-5
NTU method, 4-21
Ohm’s law, 4-6
porous materials, 4-22
radiation, 4-3, 4-7, 6-8
research and development of,
Intro-15
steam generator, nuclear, 48-3,
48-6
supercritical (pressure water),
5-7
surface, 20-1
waste gases, 27-18
water-side, 20-4
treatment
post weld, 7-11, 50-5, 50-12
welding, 38-6
Heat flux measurement, 40-12
Heat rate, 37-11
Heat recovery steam generator
(HRSG), 27-15
Heat transfer (see Heat, transfer)
Heating surface, regenerative air
heater, 20-11
Heating values, high and low, 9-8,
10-10
Heavy lifting, 39-8
Heavy water, 46-2
Hero’s engine, Intro-1
Hideout, chemical, 42-3
History of steam generation and
use, Intro-1
Hook gauge, 40-2
Hooke’s law, 7-16
Hopper, 23-3
numerical model, 6-21
Hot
functional testing, 49-16
I-11
The Babcock & Wilcox Company
rolling, 7-9
shortness, 7-6
work, 7-9
zero power, 49-18
Human factor engineering, control
systems, 41-20
Hydraulic diameter, 3-5 (see also
Equivalent, diameter)
Hydroclones, 35-8
Hydrogen damage, 42-17, 44-6
detection of, 45-3
Hydrolysis, 34-7
Hydrostatic test, 39-17, 42-23, 43-2,
50-2, 50-11
Ideal gas, 3-4
Igniter, 11-15, 14-20, 15-10
capacity, 15-10
classification of, 41-16
coal burner, 14-20, 15-10
oil and gas, 11-15, 15-10
operation, 15-10
Ignition
stability, flame, 14-7
temperatures, 10-10
Imaging radiometer, 40-6
Impact protection, 44-9
Impact suction pitot tube, 40-21
In-core instrumentation, 49-9
Incineration, 28-23, 29-1
Incompressible, 3-1
Induced nuclear reactions, 47-4
Industrial boiler design, 27-1
Injector, 3-16
Inspection (see also Equipment
diagnostics, nuclear)
pre-operation, 39-19
startup, 43-2
Instability, flow, 5-11
Instrumentation, 40-1
corrections, 40-3
water leg, 40-3
environmental, 36-1
in-core, 49-9
nuclear, 49-10
startup, 43-3
Insulating material
properties of, 4-1, 4-9
thermal conductivity, 23-6
Insulation, 4-22, 4-29, 23-1, 23-5,
23-6, 39-18
ambient air conditions, 4-29
heat loss, 4-29
installation, 23-5
temperature limits and thermal
conductivities, 4-29
Integral Furnace boiler, Intro-9, 19-2
Internal deposits, water-side, 43-9,
44-6
Internal recirculation, CFB, 27-10
International temperature scale, 40-3
Inverse temperature solubility, 42-2
Inviscid, 3-4
Ionization, 47-3
chamber, 47-14, 49-13
I-12
Iron, effects on coal ash, 21-7, 43-10
Irrecoverable, pressure losses, 3-6
Irreversible, 3-5
Isentropic, 3-4
Isolation valves, nuclear, 49-10
Isothermal transformation
diagrams, 7-4
Isotope, 47-1
Jet pump, 3-16
Kelvin temperature scale, 40-4
Kinematic viscosity, 3-10
Kraft process – see Recovery boiler,
Kraft process
Lagging, 23-2, 23-9
Lamellar tearing, 7-11
Laminar flow (see also Flow, laminar)
definition, 4-14
inside tubes (and ducts), 4-15
Larson-Miller parameter
creep life fraction, 45-12
life prediction, 45-12
Laser alignment, 50-8
Laws of thermodynamics, 2-10
Layup, 42-25
dry layup, 42- 27
hot standby, 42- 26
nitrogen blanketing, 42-27
wet layup, 42-27
Leak detection
acoustics, 45-16
headers, 45-17
piping, 45-17
tubes, 45-16
Leak test, 50-10, 50-11
Levelization, cost, 37-12
Licensing, nuclear, 49-14
Life management, nuclear, 49-2
Lighter – see Igniter
Lignite, 9-6
ash fusion temperature, 43-10
Lime, 35-2, 35-15
hydrated, 35-16
pebble, 35-16
Limestone, 35-2 (see also Sorbent)
forced oxidation, 35-6
Linear accelerator, 38-6
Linings, rubber, 35-5
Liquid
forced convection around tubes,
4-16
laminar forced convection in
tubes (and ducts), 4-15
metal coolants, 46-2, 46-22
penetrant examination, 38-12
physical properties, 3-10
state, 3-1
turbulent forced convection in
tubes (and ducts), 4-16
viscosity, 3-11
Ljungström air heater, 20-9
Load, 39-18
blocks, 39-11
dead, 39-9
distribution, 39-10
static equilibrium, 39-10
factor, 37-11
friction, 39-9
impact, 39-9
imposed, 39-9
lifted, 39-9
live, 39-9
seismic, 39-9
stabilization force, 39-9
wind, 39-9
Local heat transfer coefficient
definition, 4-3
in boiling, 5-4
in free convection, 4-14
in laminar flow, 4-15
in turbulent regions, 4-16
Longflow economizer, 20-4, 28-15
Low water, 43-9
Lowest Achievable Emission Rate,
32-4
Machine tools, 38-3
Machining, 38-2
electrical discharge, 38-3
Magnesium oxide, 35-12, 35-18
Magnetic particle examination, 38-12
Maintaining availability, Chapter 44
Maintenance
boiler, Chapter 44
economizer, 20-6
fans, 25-14
nuclear equipment, 49-2
pulverizer, 13-11
remote technology, 49-1, 49-5
stack, 25-10
strategic plan, 44-1
Makeup water and purification
system, 42-5, 49-15
Malleable cast irons, 7-14
Manometer, 40-1
high pressure, 40-2
inclined, 40-1
micromanometer, 40-2
Manpower loading, construction, 39-3
Manufacturing
development, Intro-13, Intro-16
fossil fuel equipment, Chapter 38
methods, 38-1
nuclear equipment, Chapter 50
requirements, 38-1
tubes, 38-10
Marine boiler
circulation, 31-12
codes, 31-6
design, 31-6
development, 31-1
efficiency, 31-10
furnace design, 31-7
nuclear, 46-19
requirements, 31-1
steam separation, 31-12
Steam 41 / Index
The Babcock & Wilcox Company
steam temperature control, 31-9
superheater design, 31-8
tube bends, 31-8
types
coal, 31-3
merchant, 31-2
naval, 31-1
package, 31-4
reheat, 31-3
waste heat, 31-5
Martensite, 7-5
Mass
conservation of, 3-2
defect, 47-2
diffusion and transfer, 4-22
energy equivalence, 47-2
flow rate per unit area, 3-6
flux, 3-6
number, 47-2
transfer coefficients, 4-22
transfer rate, 35-10
velocity, 3-6
Mass burning, refuse, 29-3
air plenums, 29-11
combustion air system, 29-11
excess air, 29-11
fuel feed system, 29-11
overfire air, 29-11
plunger ash extractor, 29-12
rams, 29-11
reciprocating grate, 29-10
steam coil air heaters, 29-12
stoker capacity diagram, 29-10
stoker design, 29-10
undergrate air, 29-11
vibrating conveyor, 29-12
Master fuel trip, 23-5
Material handling and storage
equipment, 39-8
erection, 39-8
plan, 39-8
transportation, 39-8
Materials – see Chapter 7 and
specific materials
Materials, bimetallic, 28-11
Maximum Achievable Control
Technology (MACT), 32-5
Mean film temperature, 4-19
Measurement, instrument and
methods (see also Chapters 36
and 40)
atomic absorption, 42-14
conductivity, 42-14
density, 36-4
flame photometer, 42-14
flow, 36-4, 40-20
gravimetric, 42-14
ion chromatography, 42-14
liquid level, 36-2
mercury emissions, 36-13
on grab samples, 42-14
on-line, 42-13, 42-15
opacity, 36-5, 36-13
pH, 36-1
pressure, 36-4, 40-1
purity, steam, 40-17
Steam 41 / Index
quality, steam, 40-17
solids level, 36-3
temperature, 36-4, 40-3
Mechanical equivalent of heat, 2-8,
3-3, 10-9
Membrane wall, 19-6, 23-1
construction, 39-18
fabrication, 38-7
gasifier design, 18-9
tubes, 23-1, 23-2
Mercury, 32-8
control technologies, 32-10, 32-11,
36-13, 36-14
in U.S. coals, 32-10
regulations, 32-6, 32-10
Mesh generation, 6-9
Metal lagging, 23-2
Metal removal, 38-2
Microalloyed steels, 7-12
Mineral wool, 23-5
Modeling (see also Numerical
modeling)
ash, coal, 6-12
boiler, 6-14
burner, coal, pulverized, 6-21
combustion, 6-1, 6-7
large particle (popcorn) ash (LPA),
6-12
numerical, Chapter 6
recovery boiler, 6-14
stoker, 6-21
turbulent flow, 6-5
windbox, 6-16
Moderator, 46-1
temperature coefficient, 47-14,
49-18
Modular construction, 27-6, 39-6
field, 39-6
shop, 39-6
Moisture
air, 10-5
flue gas, 10-6, 10-17
gypsum, 36-10
in stack gas, 36-8
pulverization, 13-10
pulverized coal combustion, 14-3
Molar quantities
conversion to mass units, 10-4
Molar ratio, NOx control, 34-8
Mole
concept of, 10-1
in combustion calculations, 10-3,
10-6
Mollier diagram
nuclear steam cycle, 2-21
steam, Chapter 2 Frontispiece,
T-9
Momentum
conservation of, 3-2
Mud drum, 1-8
Multi-cyclone (multiclone) dust
collector, 17-11, 27-10
Multi-lead ribbed tubes, 5-5, 26-13,
44-17
Municipal solid waste (MSW), 9-19,
12-18, 27-2, 29-1
National Ambient Air Quality
Standards, 32-2
National Fire Protection Association
(NFPA), 11-1, 13-12, 23-4
National Pollution Discharge
Elimination System, 32-13
Natural circulation, 1-3, 5-18, 26-10,
26-11, 27-1, 27-15, 48-6
Natural gas – see Chapter 11
burner, 11-9
burning equipment, 15-10
consumption, 9-16
firing application, 26-16, 27-4
gas elements, 11-13
igniter, 11-15
preparation, 11-2
production, 9-16
properties, 11-3
reserves, 9-16
transportation, storage and
handling, 11-2
Nautilus, 46-19
Navier-Stokes equation, 3-2
Navy special fuel oil (NSFO), 31-12
Net plant heat rate, 37-11
Neutron, 47-1
absorption, 47-6
delayed, 47-11
detector, 47-14, 49-17
energy distribution from fission,
47-8
flux, 47-11, 49-17
leakage, 47-11
production, 47-10
prompt, 47-11
reactions, 47-5
source, 47-14
thermal, 47-6
New Source Performance Standards
(NSPS), 32-2
New Source Review (NSR), 32-2
Newton’s law of cooling, 4-3
Newtonian fluid, 3-1
Nitrates, 34-2
Nitric acid, 34-2, 35-1
Nitrogen oxides (NOx), 32-7, 34-1,
35-1 (see also NOx and NOx
control)
combustion optimization, 43-6
emissions, 32-7, 34-1
formations, 34-1
nitric oxide (NO), 32-7, 34-1
nitrogen dioxide (NO2), 32-7, 34-1
Non-condensable gases/waste stream,
28-23
Nonattainment Areas, 32-2
Nondestructive examination, 38-11,
45-1 (see also Examination,
nondestructive)
eddy current testing (ECT), 45-3,
49-4, 50-10
probes, 49-4
electromagnetic acoustics, 45-4
leak testing, 50-10
dye penetrant (PT), 50-2
liquid penetrant (PT), 45-2, 49-10
I-13
The Babcock & Wilcox Company
magnetic particle (MT), 45-2,
49-10, 50-2
nuclear fluorescence, 45-4
radiographic (RT), 50-2
ultrasonic testing (UT), 45-2, 49-4,
50-2
Nonpressure parts, materials, 7-24
Nonrecoverable – see Irrecoverable
Normalizing, 7-8
NO x
emissions control, postcombustion, 41-17
ammonia flow control, 41-17
flue gas inlet temperature,
41-17
NOx control, 32-4, 32-9, Chapter 34
analyzer, 34-8
catalyst, 34-3
base metal, 34-5
corrugated fiber configuration,
34-5
honeycomb configuration, 34-5
operating issues, 34-6
parallel plate configuration,
34-5
precious metal, 34-5
sizing, 34-6
zeolite, 34-5
chemical reagents, 34-3
anhydrous ammonia (NH3),
34-3
aqueous ammonia, 34-6
urea, 34-3
coal, and wood/bark stoker, 16-10
coal, Cyclones, 15-13
coal, fluidized-bed, 17-1, 17-8, 17-13
coal, gasification systems, 18-15
coal, pulverized, 14-9
air staging, 14-14
corner-fired, 14-16
wall-fired, 14-15
control by combustion, 14-10
fuel NOx, 14-9
fuel ratio (FC/VM), 14-10, 14-18
fuel staging, 14-10
NOx formation, 14-9
NOx ports, 14-10
thermal NOx, 14-10
combustion, 34-1
oil and gas
burners out-of-service, 11-6
flue gas recirculation, 11-7
low excess air, 11-6
overfire air ports, 11-6
oxides of nitrogen, 11-5
reburning, 11-7
two-stage combustion, 11-6
options, Chapter 34
post-combustion, 34-3
selective catalytic reduction,
Chapter 34
numerical model, 6-18
NOx formation, 34-1
NOx ports, 14-10
Nozzle
energy equations, 2-9
I-14
fabrication, 38-6
spray, FGD, 35-3, 35-4
Nuclear (see also Fuel, nuclear, and
Chapters 46 through 50)
binding energy, 47-2
chain reaction, 47-7
component maintenance, 49-2
cross-section, 47-12
emergency core cooling system
(ECCS), 46-15
fission, 46-1, 47-1
nucleons, 47-1
nucleus, 47-1
nuclide, 47-1
fuel, 46-2, 46-8, 47-7
fuel assembly, 46-8
fuel cycle, 47-12
fundamentals, 47-1
icebreaker, Lenin, 46-20
merchant ship, Otto Hahn, 46-21
merchant ship, Savannah, 46-20
moderator temperature
coefficient, 47-14
multiplication factor, effective,
47-10
operations, 49-14
power, Intro-12, Chapter 46
pumps and piping, 46-13
radiation, 47-2, 49-1
reactions, Chapter 47
reactor, 46-1, 46-5 (see also
Reactor)
resonance, 47-6
safety systems, 1-13
service, Chapter 49
steam generator, 1-12, 46-12 (see
also Steam generator,
nuclear)
once-through, 46-12
recirculating, 46-12
steam supply system (NSSS),
1-11, 46-4
future of, 46-18
integrated control system, 46-14
Nuclear Regulatory Commission
(NRC), 46-9, 49-14
Nuclear ships, 46-19
Nuclides, 47-1
Numerical analysis, 19-7
Numerical modeling, Chapter 6
benefits of, 6-2
carbon burnout kinetic (CBK)
model, 6-8
chemical percolation devolatilization (CPD) model, 6-8
chemical reactions, 6-4, 6-7
combustion, 6-7
eddy dissipation combustion
model (EDM), 6-7
eddy dissipation concept (EDC)
model, 6-7
heterogeneous chemical
reaction, 6-8
homogeneous chemical
reaction, 6-7
computational fluid dynamics, 6-1
conduction heat transfer, 4-23
discrete ordinates, 6-9
discrete phase transport, 6-7
equations
discretization of, 6-8
fluid flow/heat transfer, 6-5
fundamental, 6-5
turbulence, 6-5
Eulerian reference frame, 6-7
examples of, 6-10
advanced burner, 6-21
Kraft recovery boilers, 6-14
popcorn (large particle) ash, 6-12
SCR systems, 6-18
wall-fired pulverized-coal
boiler furnaces, 6-14
waste-to-energy system, 6-21
wet scrubbers, 6-10
windbox, 6-16
finite difference method, 6-9
finite volume approach, 6-9
fluid transport, 6-4
furnace heat transfer, 4-26
history of, 6-2
Lagrangian reference frame, 6-7
limitations of, 6-3
mathematical, 6-1
mesh generation, 6-9
particle, transport, 6-4, 6-7 (see
also Numerical modeling,
discrete phase transport)
process, 6-2
radiation heat transfer, 4-23
radiative heat transfer, 6-4, 6-8
theory of, 6-3
turbulence, 6-5
uses, 6-3
Nusselt number
definition, 4-2, 4-15
in long tubes or conduits, 4-16
O-type FM Boiler, 27-12
Oil – see Fuel, oil
Oil emulsions, 9-18
Once-through
boiler, 1-3, 26-9 (see also Universal
Pressure (UP) boiler)
circulation, 1-3, 5-17
steam generator, nuclear, 1-12,
46-12, 48-2, 48-13, 49-1,
49-17, 50-2, 50-4
Ontario Hydro Method, 32-10
Opacity, 36-13
Openings, pressure vessels
ligaments between, 8-13
reinforcement, 8-13
Operating issues, 34-10
retrofits, 34-10
Operating license, nuclear, 49-14
Operation
fossil fuel-fired boilers, Chapter 43
abnormal, 43-9
combustion safety, 43-1
cooling requirements, 43-1
fundamental principles, 43-1
Steam 41 / Index
The Babcock & Wilcox Company
general, 43-1
general safety considerations,
43-1
low water, 43-9
personnel safety, 43-8
preparations for startup, 43-2
shutdown, 43-9
startup, 43-2, 43-4
tube failures, 43-9
water chemistry and treatment
– see Chapter 42
nuclear steam supply systems,
Chapter 49
acceptance tests, 49-20
operator requirements, 49-18
power ascension testing, 49-19
startup, nuclear, 49-18
zero power tests, 49-18
Operator
requirements, fossil fuel units, 43-2
training, nuclear, 49-18
Optical
fiber, 40-6
pyrometer, 15-3, 40-5
Orifice, 40-19
Orimulsion, 9-18
Orsat analysis, 10-21
Otto Hahn, 46-21
Overfire air (OFA), 11-6, 14-14,
15-13, 16-1, 16-6, 16-9, 17-4, 17-9
Overfire air ports – see NOx ports
Overheat failures, 42-18
Overheating, 44-6
Oxidation, 44-11
FGD, forced, 35-8
resistance, 7-12
Oxygen
analyzer, 10-21
in feedwater, 26-5
required for combustion, 10-5
scavengers, 42-6
treatment, water, 42-8
Ozone, 32-2, 34-2
Package boiler, Intro-10, 27-9, 27-12
Paper industry – see Chapter 28
recovery boiler operation, 43-15
recovery processes and units, 28-1
steam requirements, 28-1
waste fuels, 28-1
Parr formulas, 9-5
Particle(s), atomic
alpha, 47-3
beta, 47-3
fundamental, 47-1
mass, 47-2
Particulate control, 32-9, Chapter 33
coal, gasification systems, 18-12
equipment, 33-2
electrostatic precipitators, 33-2
(see also Electrostatic
precipitator)
fabric filters, 33-8 (see also
Fabric filter)
mechanical collectors, 33-12
Steam 41 / Index
selection, 33-12
venturi scrubbers, 33-12
New Source Performance
Standards, 32-2
opacity, 33-2
Particulate matter
condensable, 36-13
constituents, 33-1
Partnerships, 37-9
Pearlite, 7-4, 7-5
Peat, 9-6
Penthouse, 23-3
Performance
air heater, 20-12
calculations, Chapter 22
economizer, 20-4
environmental system, 37-4
monitoring, 41-21
steam generating system, 37-2
tests
environmental control systems,
36-7
fossil fuel-fired units, 43-8
nuclear units, 49-15
Periodic Table of the Elements, T-15
Personnel safety, rules, 43-8
Petroleum, 9-12 (see also Fuel, oil)
byproducts, 9-17
consumption, 9-14
pitch, 9-17
pH, 36-1
calibration, 36-2
control, 41-18
electrode, 36-1
feedwater, 42-6
for corrosion control, 42-6
fossil, drum, 42-6, 42-8
fossil, once-through, 42-12
sensors, 36-2
standardization, 36-2
Phase diagram, 7-2
iron carbon, 7-2
Phosphate hideout, 42-9
Photochemical smog, 34-2
Physical metallurgy of steel, 7-2
Pinch point, thermal, HRSG, 27-16
Piping
condition assessment of, 45-9, 45-14
creep, 45-9
leak detection, 45-17
materials, 7-23
nuclear, 49-10
Pitot tube, 3-4, 40-21 (see also S-type
pitot tube)
Plant safety, nuclear, 46-15
Plate air heater, 20-8
Plate forming, 38-4
Plutonium, 47-4, 47-15
PM2.5, 32-7
PM10, 32-7
Pneumatic signals, 40-2
Pollution control – see Emissions,
air pollution and individual
pollutants)
Post weld heat treatment, 7-11, 50-5,
50-12
Potentiometer
direct reading, 40-10
millivolt, 40-10
Powder River Basin (PRB) coal, 9-2,
12-15, 21-13, 44-18
Powdered activated carbon (PAC),
32-12
Power
coefficient, nuclear, 47-14
costs, 26-1
cycle diagram
fossil fuel, 2-16, 2-18
nuclear fuel, 2-20
distribution, neutron, 47-7
for auxiliaries, fossil fuel equipment, 15-10, 26-5
Power plant
automation, 41-19
emissions, discharges
aqueous discharges, 32-13
atmospheric emissions, 32-1,
32-7
solid wastes, 32-1, 32-10
Prandtl number, 4-2, 4-14
Precipitation hardened stainless
steels, 7-14
PrecisionJet, 16-9
Present value, present value factor,
37-12
Pressure
component assembly, 38-6, 39-12
difference, contraction and
enlargement, 3-11
drop (or loss)
acceleration loss, 5-10
bend, 3-13
calculation, Chapter 22
contraction, 3-11
enlargement, 3-11
equation, closed channel, 3-7
fittings, 3-9
fluidized-bed, 43-14
friction loss, 3-5, 3-7, 5-10
gas flow across tube banks, 3-15
hydraulic or static loss, 5-10
local loss, 5-10
rectangular duct, 3-13
reheater relationship, 19-11
stack, 3-15
steam-water, 5-9
separator, 5-17
superheater, 19-11
two-phase (steam-water), 3-16,
5-9
valve, 3-9
gauge
dead weight, 40-2
opposed bellows, 40-2
slack diaphragm, 40-2
gradient, 3-1
loss – see Pressure, drop
manometer, 40-1
high pressure, 40-1
measurement
instrument connections, 40-3
part welds, 39-13
I-15
The Babcock & Wilcox Company
stress analysis, 8-3
taps, 40-3
transducer, piezoelectric, 40-3
transmitters, 40-2
vessel design, 8-1
Pressurized casing, marine, 31-12
Pressurized fluidized bed, 17-13
cycle, 17-13
pressure, 17-13
turbine, gas, 17-13
Pressurized water reactor (PWR),
1-12, Chapter 46, 48-1, 49-14
component, manufacturing, 50-1
components, 49-2
coolant pumps, 49-9
fuel handling, 49-11
naval type, 46-20
reactor vessel, 49-7
vessel internals, 49-8
Pressurizer, nuclear steam system,
46-12, 49-9, 50-12
heater, 49-9, 49-16, 50-12
Prevention of Significant
Deterioration, 32-3
Primary air, 13-6
Process steam, 27-5, 27-15
Producer gas, 9-11
Prompt NOx, 34-1
Properties (see also Chapters 2, 3,
4, 7 and 9)
acoustic, 40-6
boiling point, 40-3
coefficients of thermal, 40-5
electrical, 40-6
emissivity, 40-5
expansion, 40-4
freezing point, 40-3
gases, 40-4
liquids, 40-4
optical, 40-6
triple point, 40-3
Proportioning dampers, 19-15, 26-6
Propulsion, nuclear ship, 46-19
Proton, 47-1
Psychrometric chart, T-11
Pulping, 28-1
Pulverized coal (see also
Combustion, coal, pulverized)
firing, application, 26-6, 27-2
introduction of, Intro-9
Pulverizer, Chapter 13
availability improvement, 44-3
ball-and-tube, 13-5
capacity correction factors, 13-11
capacity testing, 13-10
controls, 13-12
fabrication, 38-9
fluid energy, 13-15
high speed, 13-4
loading system, 13-14
maintenance, 13-11
principles of operation, 13-1
roll wheel, 13-1, 44-4
safety systems, 13-13
systems, 13-6
temperatures, 13-8, 13-12
I-16
throat, rotating, 44-5
types E and EL, 13-3, 44-3
upgrades, 44-3, 44-4
Pump, energy equations, 2-9
Pump seals, nuclear, 49-9
Purging, furnace, 43-4
Purification system, 49-15
Pyroelectric vidicons, 40-6
Pyrometer
Cyclone application, 15-3
fusion, 40-4
optical, 40-5
radiation, 40-5
Pyrometric cone, 40-4
Quality assurance, 38-10, 49-14, 50-1
Quality control, Intro-13, 38-10
Quaternary air, 28-21
Radiant boiler – see Boiler, types,
Radiant
bypass systems, 19-20
Radiation, nuclear, 47-1, 49-1
absorbed, 47-3
detector, 47-3, 49-13
dose, 47-3
factor in maintenance, 49-1
protection, 47-3, 49-1
Radiation pyrometer, 40-5
Radiation, thermal, 4-3, 4-7
absorptivity, 4-3
between blackbody surfaces, 4-4
between gray surfaces, 4-4
blackbody, 4-4
carbon dioxide, from, 4-12
cavity, 4-28, 4-32, 20-4, 22-13
discrete ordinates, 6-9
emissive power of, 4-4
emissivity (emittance), 4-4
enclosures for, 4-7
gases, from, 4-8
geometry factor, 4-4
heat loss from setting, 23-6
heat transfer coefficient, 22-7
intertube, 20-4, 22-7
modeling of, 6-8
particles from, 4-8
reflection of, 4-3
reflectivity, 4-3
shield, 4-31
transmissivity, 4-3
water vapor, from, 4-12
Radioactive
decay constant, 47-4
half-life, 47-4
Radioactivity, 47-4
Radiographic examination, 50-2, 50-6
Radiography, 38-11
Rankine cycle, 2-13 (see also Cycle,
Rankine)
in IGCC plants, 18-14
nuclear heat source, 2-19
Rankine temperature scale, 40-4
RDF
processing, 12-18 (see also
Chapter 29)
RDF firing, refuse, 29-5, 29-13
combustion
air-swept distributor spouts,
29-17
Controlled Combustion Zone,
29-18
dump grate stokers, 29-13
fluidized-bed combustion, 29-18
fuel distribution, 29-17
metering feeder, 29-17
overfire air system, 29-18
refuse-derived fuel (RDF), 29-2
technology, 29-13
supplemental firing (co-firing),
29-13
traveling grate stoker, 29-2,
29-17
processing, 29-14
air density separator, 29-15,
29-17
aluminum separator, 29-17
disk screen, 29-15
eddy current separator, 29-17
flail mill, 29-15
magnetic separator, 29-15
oversized bulky waste, 29-17
quality, 29-16
shredder, 29-15
storage, 29-17
system, 29-14
tire shredding, 29-17
trommel, 29-15
yield, 29-15
RDF retrofit, 29-19
Reactivity, 47-11
coefficients, 47-14, 49-18
limestone, 36-6
Reactor
closure head, 46-9, 49-9, 50-1
replacement, 46-9, 50-1
containment building, 46-3
control rod drive mechanism
(CRDM), 50-1
control rods, 46-8, 49-8
coolant pumps and motors, 46-13,
49-9
pump seals, 49-9
coolant system (RCS), 46-5, 49-14
core support, 46-6
decay heat removal system, 46-17
electropolishing, 50-2
emergency core cooling system,
46-15
hydrostatic testing, 50-2
inspection, 50-2
instrumentation, 46-11
machining, 50-2
operator, 49-18
plenum, 46-6
protection system, 46-15
refueling, 46-10
service support structure, 49-9
shielding, 46-5, 46-20
trip testing, 49-20
Steam 41 / Index
The Babcock & Wilcox Company
types
boiling water, 46-2
breeder, 47-15
converter, 47-15
fast, 47-15
pressurized heavy water
(CANDU), 46-2, 46-5
water, Chapter 46, 47-9
naval, 46-20
thermal, 47-15
vessel, 46-5
vessel and internals, 49-7
Reactor vessel, 46-5, 50-1
Reburning, 32-9
Recirculating steam generator,
nuclear, Intro-13, 1-12, 46-12,
48-4, 49-1, 49-17, 50-2, 50-4
Recirculation, gas, 19-15
Recovery boiler
economizer, 20-4
Kraft process, 28-1
black liquor, 28-2, 28-7
elemental analysis, 28-6
evaporation, 28-18
gross heating value, 28-5
limited vertical sweep
burner, 28-20
mix tank, 28-21
oscillator burner, 28-20
oxidation, 28-19
splash plate spray nozzle,
28-20
combustion air system, 28-15
convection surface, 28-17
direct contact evaporator, 28-19
dissolving tank, 28-25
emergency shutdown system,
28-18
emissions, 28-8
evaporator, 28-18
feedwater temperature, 28-18
furnace, 28-3, 28-15
heat balance, 28-5
heat inputs, 28-5
heat losses, 28-5
numerical model, 6-14
operation, 43-15
black liquor combustion
process, 43-16
primary air, 43-16
secondary air, 43-16
tertiary air, 43-16
overview, 43-15
pluggage, 43-16
tube corrosion, 43-16
rated capacity, 28-3
smelt spout system, 28-24
smelt water reactions, 43-17
soda process, 28-25
sootblowers, 28-23
streams entering and leaving,
28-5
sulfite process
magnesium, 28-26
thermal performance, 28-4
vent stack scrubber, 28-25
Steam 41 / Index
wall construction, 28-11
Rectangular ducts, flow, 3-13
Recuperative, air heater, 20-7
Red liquor – see Recovery boiler,
sulfite process, magnesium
Refinery gas, 27-2
Reflooding, 5-4
Refractories, 7-15
Refractory, 23-1
materials, 23-6, 39-18
Refueling, nuclear, 49-11
fuel handling equipment, 49-12
Refuse, 10-14, 29-1 (see also Residue
or Ash, coal)
Refuse-derived duel – see RDF firing
Regenerative
air heater, 20-9
heating surface, 20-11
Rankine cycle, 2-14
Reheat
cycle, 2-15
flue gas, FGD, 35-3
temperature adjustment and
control, 19-15, 19-21
use of, 19-3
Reheater (or reheat superheater), 1-7,
19-11
attemperator, 19-14
cleaning, external, 19-12
cleaning, internal, 19-12
design, 19-11
marine, 31-10
materials, 7-21
Reinjection
stoker, carbon, 16-6
stoker, flyash, 16-9
Relative roughness, 3-9
Remote manual sequence burner
controls, 41-14
Repairs, nuclear equipment, 49-1
Repowering, 26-5
Research and development, Intro-13,
48-14
Residual elements, 7-12
Residual stress, 50-2
Residue, 10-14
Resin fragments, 42-6
Resistance, heat transfer, 4-1
Resource Conservation and
Recovery Act (RCRA), 32-15
Retort, 16-2
Revenue requirements method,
economics, 37-13
Reverse osmosis, 42-5
Reynolds number, 4-2, 4-15
Reynolds number, friction factor
relationship, 3-7
Ribbed tube, 5-5, 26-13, 44-17
Rickover, Admiral Hyman G., 46-1,
46-21
Rigging design, 39-8
Riser (tubes), 1-9
Risk, financial, 37-13
Rothemühle air heater, 20-10
Roughness, effect on friction factor,
3-9
S-type pitot tube, 36-8, 36-10
Safety
burner, coal, 14-20
burner, oil and gas, 11-16
combustion, 14-20, 43-1
construction, 39-16
factors, C-3
nuclear,
analysis report, 49-14
limits, 49-15
pulverizer, 13-13
relief valve, 25-1
valve, 19-8
valve, setting, 43-4
Sampling, water and steam, 42-13
Saturated steam, properties, 2-2,
2-3, T-5, T-6
Saturated water, properties, 2-2,
2-3, T-5, T-6
Savannah, 46-20
Scale, marine, 31-8
Scale detection, fossil fuel boiler, 40-12
Scaling, 35-2
Schedule, construction, 39-2
Scope of supply or work, 37-5
SCR – see Selective catalytic
reduction
Screen
heat transfer and draft loss
calculations, 22-4
Screw feeders, 16-7
Scrubber, dry, Color Plate 7 – see
SO2 control
Scrubber, wet, Color Plate 6 – see
SO2 control
Selective catalytic reduction (SCR),
27-5, 27-7, 29-23, 32-9, 32-12,
34-3, 39-15 (see also NOx
control)
applications, 34-3
arrangements, 34-4
catalyst – see NOx control, catalyst
cold side/low dust, 34-4
distributions, 34-8
ammonia to NOx, 34-9
temperature, 34-9
velocity, 34-8
hot side/high dust, 34-4
mixing, 34-10
retrofits, 34-10
systems, 34-4
Selective non-catalytic reduction
(SNCR), 29-23, 32-9, 34-3, 34-13
(see also NOx control)
Series present value factor,
economics, 37-12
Setting, boiler
appearance, 23-9
cased enclosures and casing, 23-3,
39-18
construction, 23-1
corrosion, 23-7
definition, 23-1
enclosures, 23-1
expansion, 23-4
explosion effect, 23-4
I-17
The Babcock & Wilcox Company
fabrication and assembly, 23-9
heat loss, 23-5
implosion effect, 23-5
inner casing, 23-2
insulation, 23-5, 23-6, 39-18
leakage, 23-7
outer casing, 23-2
penthouse, 23-3
resistance to ash and slag, 23-4
resistance to weather, 23-8
serviceability, 23-9
tube wall, 23-1, 23-2
ventilation, 23-6
vibration, 23-5
windbox, 23-3
Shape or configuration factors,
thermal
definition, 4-4
for radiation, 4-4, 4-7, 4-31
Sheet metal lagging, 23-8, 39-19
Shielding, nuclear, 46-5, 46-20, 47-4,
49-8, 49-13
Shipboard nuclear reactors, 46-20
Shipment and shipping, 39-6, 50-12
Shutdown
fossil fuel-fired units, 43-9
Signal multiplexer, 40-24
Slag, 21-3, 43-7, 43-10
entrained flow gasifier, 18-6
layer, 15-3
removal, 15-3, 15-8, 24-2, 24-13
screen, 19-6
viscosity, 9-8 (see also Ash, coal)
Slagging, 21-3, 44-9 (see also Ash,
coal, deposition)
Slaker, FGD
ball mill, 35-15
detention, 35-15
Slip, ammonia (NH3), 34-6
Slurry, dewatering, FGD, 35-7
Smart transmitters, 41-20
Smelt, Kraft process, 28-2, 43-19
reduction efficiency, 28-8
SO2 control, Chapter 35
fuel switching, 32-5, 32-8, 35-1,
44-18
reagent(s)
lime, 35-2, 35-12, 35-16
limestone, 35-2, 35-6, 35-10
magnesium oxide, 35-12
scrubber (FGD)
chemical analysis, 36-6, 36-8
control, 41-17
density, 41-18
level, 41-18
pH, 41-18
dry, 35-12, Color Plate 7 (see
also Spray dryer absorber
(SDA))
lime, 35-2
limestone, 35-2, 35-6
liquid level, 36-2, 36-3
magnesium oxide, 35-12
numerical model, 6-10
performance testing, 36-7
pH measurement, 36-1
I-18
reagent consumption, 36-13
spray tower, 35-2
stoichiometry, 35-7
tray, 35-3, 35-4
wet, 35-2, Color Plate 6
technologies, 32-8
SO3 control, 35-18
Society of Naval Architects and
Marine Engineers (SNAME),
31-6
Soda process – see Recovery boiler,
Kraft process
Sodium
carbonate, 35-2
cycle softener, 42-5
selective ion electrode, 42-15
tracer method, 40-17
zeolite softener, 42-5
Solid waste
disposal, 32-15
treatment, 32-16
utilization, 32-17
Solids
carryover, 5-13
concentration, 19-14
gasifier discharge, 18-12
gravimetric analysis, 40-17
in boiler water, 5-13
in steam, 5-13, 40-17
Solution annealing, 7-8
Sootblowers, 20-3, 20-14, 24-1, 44-19
application, 24-5, 28-23
cleaning media, 24-1
control(s), 24-4
intelligent controls, 43-8
marine, 31-3
operations, 43-8
RDF boiler, 29-21
recovery boiler, 28-23
terminology, 24-1
type
air puff, 24-12
extended lance, 24-7
fixed position, 24-8
G9B, 24-8
HydroJet, 24-3
IK, 24-5
IR, 24-2
long retractable, 24-5
one way, 24-7
oscillator, 24-7
Precision Clean, 24-7
rake, 24-9
rotary, 24-8
short retractable, 24-2
straight line, 24-10
swing arm, 24-11
waterlance, 24-2
Sorbent (see also SO2 control, reagent)
calcination, 10-14, 10-28
calcium to sulfur molar ratio,
10-11, 10-14, 10-28
combustion calculations, 10-11,
10-28
injection, 35-18
spent sorbent, 10-14
sulfation, 10-14
Specific gravity, 9-14
Specific heat, 2-22, 4-9
ratio, 3-4
Specific volume
water and steam, 2-1, 2-2, T-5, T-6
Specifications, Chapter 37
Spent fuel, nuclear, 46-11, 50-13
Spheroidizing, 7-9
Spout – see Air swept spout
Spray dryer absorber (SDA), 35-12
(see also SO2 control)
approach temperature, 35-14
atomizer, 35-13
gas disperser, 35-13
process, 35-16
reagent, 35-15
recycle, 35-15
single pass, 35-15
spray chamber, 35-13
spraydown, 35-15
stoichiometry, 35-15
Stability, 5-12
Stack and draft, 25-6
barometric pressure, 25-7
draft
balanced, 25-6
forced, 25-6
induced, 25-5
loss, 25-6
natural, 25-6
loss (or resistance), 43-6
friction, 25-8
velocity head, 25-8
specific volume, 25-6
air and flue gas, 25-6
stack
effect, 22-18, 25-6
flow, 3-15
flow loss, 25-8, 43-6
operation and maintenance,
25-10
Staged combustion, 14-11, 15-13,
16-6, 44-8
Startup
fossil fuel-fired units, 43-2, 43-4
State Implementation Plans (SIPs),
32-2
Steady-state
flowing systems, 4-6
heat conduction, 4-5
Steam
air heater, 31-10
as a thermodynamic system, 2-1
capacity, 27-8
coil air heater, 20-9
conditions, 37-2
cycle, 2-14
nuclear plant, 2-19
enthalpy, 2-1, 2-2, T-5, T-6
entropy, 2-1, 2-2, T-5, T-6
flow requirements, 27-2
generating bank, 1-8 (see also
Boiler, bank)
generation fundamentals, 1-2
heat recovery steam generator,
Steam 41 / Index
The Babcock & Wilcox Company
gasification, 18-14
history of generation and use,
Intro-1
impurities, 5-13
line blowing, 43-3
Mollier diagram, Chapter 2
Frontispiece, T-9
natural separation, 5-14
pressure-enthalpy diagram, 2-6,
T-10
process and heating, 27-3
properties, Chapter 2, 4-9, 5-1,
T-5, T-6
purity, 40-17, 42-2, 42-12
measurement, 40-17
quality, 5-1, 40-17
measurement, 40-17
requirements, 26-3, 26-4
samples, 42-13
sampling nozzle, 40-17
installation location, 40-17
scrubber, secondary separator, 5-13
separation, 5-13
separators, 5-13, 31-13, 48-2, 48-7,
50-10
solids removal, washing, 5-16
specific volume, 2-1, 2-7, T-5, T-6
tables, 2-2, T-5
temperature
adjustment, 19-13
control, 1-8, 19-12, 41-10, 43-6
attemperation, 19-14
gas recirculation, 19-15
gas tempering, 19-15
temperature-enthalpy diagram,
T-12
viscosity, 3-1, 3-9, 3-12
Steam engine (see also Boiler,
historical)
aeolipile, Intro-1
beam, Intro-3
Branca, Giovanni, Intro-1
Corliss, Intro-5
Hero’s, Intro-1
Newcomen, Thomas, Intro-3
Savery, Thomas, Intro-3
Steam flow-air flow control, 41-13
Steam generation, Chapter 1
history of, Intro-1
Steam generator
fossil fuel, 1-6 (see also Boiler)
nuclear, Intro-12, 1-12 (see also
Chapter 48)
baffle plate, 50-7
blowdown, 48-7
CANDU, 48-1, 50-2
carryover, 48-7
carryunder, 48-7
circulation, 48-8
clean room, 50-8
cleaning, cleanliness, 50-8
closing seam, 50-10
cracking, 48-9
damage (mechanisms), 48-9
denting, 48-9
divider plate, 48-12, 50-4, 50-8
Steam 41 / Index
downcomer, 48-5
electropolishing, 50-11
erosion-corrosion, 48-9
feedwater, 48-2, 48-6
flow circuits, 48-2, 48-6
foreign object damage, 48-9
fretting, 48-9
heat transfer, 48-3, 48-6
instrumentation, 48-4
integral economizer (preheater),
48-3, 48-7, 50-8
intergranular attack, 48-9
lattice grid (tube support), 48-7,
48-11, 50-6, 50-8
manipulator, 49-5
manufacture, 50-2
natural circulation, 48-6
naval, 46-20
once-through (OTSG), 1-12, 46-4,
46-12, 48-2, 48-13, 49-1,
49-17, 50-2, 50-4
pitting, 48-9
post weld heat treatment, 50-5,
50-11
preheater, 48-7
pressure boundary, 50-5
primary head, 50-4, 50-6, 50-11
primary side maintenance, 49-3
tubing, 49-3
eddy current testing, 49-4
plugging, 49-5
repair, 49-6
recirculating (RSG), 46-5, 46-12,
48-4, 48-10, 49-1, 49-17,
50-2, 50-4
replacement, 48-9
secondary side maintenance,
49-7
chemical cleaning, 49-7
sludge lancing, 49-7
shell (course), 50-3
shroud (wrapper), 48-2, 48-6,
50-8
steam drum, 48-4, 48-12
steam drum head, 50-4
steam drum internals, 50-10
stress corrosion cracking
(SCC), 49-2, 49-7, 48-9, 49-8
support plate, 48-2, 48-7
surface conditioning, 50-11
tack expansion, 50-9
terminal points, 50-11
tie rods, 50-8
tube
bending, 50-7
bundle, 50-6, 50-8
expansion, 50-10
installation, 50-9
ovality, 50-7
plugging, 49-5
repair, 49-6
sleeving, 49-6
support plate (TSP), 50-6, 50-8
tube material, 48-4, 48-10
tube to tubesheet welding, 50-9
tubes, 50-6
tubesheet, 48-2, 48-6, 50-4
U-bend support (restraint) 48-6,
48-8, 50-7
oxygen converter hood, 27-20
Steam line blowing, 42-19
Steam tables (SI) and selected
charts, Appendix 1
Steaming economizers, 20-4
Steel, structural, 8-14, 38-8
Stefan-Boltzmann constant and
law, 4-4, 40-5
Stoichiometry
NOx control, 34-7
SO2 control, 35-16
Stoker, Chapter 16
coal characteristics, 16-4, 16-6
industrial boiler applications, 16-1,
27-1, 29-9, 30-4
marine, 31-4
mass feed, 16-3
numerical model, 6-21
overfeed, 16-1
reciprocating grates, refuse, 29-10
spreader stoker, coal-fired, 16-4
air system, 16-7
ash removal, 16-7
carbon injection, 16-6
feeders, 16-4, 16-7
grates, 16-5
selection/sizing, 16-7
spreader stoker, wood-, bark-,
biomass-fired, 16-7, 30-4
air system, 16-9
ash removal, 16-10
combustion air temperature,
16-10
feeders, distributors, 16-7
grates, 16-8, 30-4
selection/sizing, 16-10
traveling grate, refuse, 29-17
underfeed, 16-2
Storage areas, site, 39-11
Strain gauges, 40-3
Stress
allowable, ASME Code, 7-20, 8-3,
C-4
alternating, 8-6
analysis methods, 8-3
classifications, 8-2, 8-9, 8-10
concentrations, 8-2, 8-6, 8-14
discontinuity, 8-7
drum, 43-5
failure theories, 8-2
hoop, 8-3, 8-4
intensity factor, 8-10
longitudinal, 8-3
peak, 8-3
pressure, 8-3
primary, 8-2
secondary, 8-3
significance, 8-1
steady-state, 8-2
strength theories, 8-2
thermal, 8-5
transient, 8-2
Stress corrosion cracking, 50-1, 50-10
I-19
The Babcock & Wilcox Company
(see also Corrosion, stress
corrosion cracking)
Stress-strain diagrams, 7-16
Stringer tubes, 20-5
Structural analysis, Intro-16,
Chapter 8
Structural support
codes and standards, 8-15
design loads, 8-14
linear type, 8-16
plate type, 8-15
shell type, 8-15
Stud-tube walls
pin stud, recovery furnace, 28-11
sulfite process, 28-26
ammonium-base, 28-27
calcium-base, 28-26
magnesium-base, 28-26
sodium-base, 28-26
Studded surfaces, 15-10, 29-3
Subcooling, 44-15
Subcritical (pressure) drum boilers,
26-11
Sulfation, 17-8, 17-13
Sulfite process – see Recovery boiler,
sulfite process
Sulfur, 9-3
acid gas removal, 18-13
capture, 10-16, 10-31
Claus recovery process, 18-15
coal, gasification systems, 18-13
content – U.S. coals, 9-3, 12-5
forms, 12-5
organic, 12-5
pyritic, 12-5
dioxide (SO2)
control, Chapter 35 (see also
SO2 control)
emissions in flue gas, 35-1
emissions control, FGD, 35-1
hot gas desulfurization, 18-13
in syngas, 18-13
trioxide (SO3), 32-7, 35-18
Sulfuric acid, 35-1
Supercritical (pressure) boilers, 19-2,
20-6, 26-6
Supercritical pressure steam
heat transfer, 5-7
properties, 5-7
Superheat, 19-9 (see also Steam,
temperature)
Superheated steam, properties, 2-4,
T-7
Superheater, 1-7, 19-9
cleaning, external, 19-12
cleaning, internal, 19-12
condition assessment of, 45-7
convection, 19-9
design, 19-10
fabrication, 38-7
heat transfer surface, 19-11
horizontal, 19-12, 19-13
ligament damage, 45-8
marine, 31-8
mass velocity or mass flux, 19-10
materials, 7-21
I-20
pendant, 19-11, 19-13, 26-6, 26-11,
28-17
performance calculations, 22-8
platen, 28-17
radiant, 19-9, 28-17
remaining life, 45-11
separately fired, 19-16
startup protection, 43-5
supports, 19-11
tube metals, 7-21, 19-11
tube sizes, 19-10
tube spacing, 19-7, 19-11
types, 19-9
Supply tubes, 1-9
Supports
boiler, 19-8
reheater, 19-11
superheater, 19-11
Surface tension
water and vapor, 3-1
Surveillance
requirements, 49-15
Syngas compositions, 18-11
Temperature
adiabatic flame, 2-26, 10-11
difference, log mean, 4-19
entropy diagrams, 2-11
exit gas, 19-4
gradient, 40-12
ignition, 10-10
measurement, 40-3
acoustic, 40-6
bimetallic strip, 40-5
casing, 40-16
fluid, 40-10
fusion, 40-4
gas, 40-14
evaluation, 40-16
weighted average, 40-16
gradient, 40-12
infrared, 40-6
insulation, 40-16
methods, 40-4
standards, 40-3
tube, 40-11
recorders, 40-10
scales, 40-3
Tempering
gas, 19-15
gas plenum, 23-3
materials, 7-9
Tensile test, 7-16
Terms and conditions, contract, 37-7
Testing, nuclear, 49-15
acceptance, 49-20
electrical, 49-15
full load, 49-18
functional, 49-16
hot functional, 49-16
hydrostatic, 49-16
instrumentation, 49-16
operational, 49-16
preoperational, 49-15
procedures, 49-15
zero power, 49-18
Thermal
analysis, 8-9
circuit, 4-6, 4-30
conductivity, 4-1, 4-9
of gases, 4-9, 4-11
of insulating materials, 4-9
of liquids, 4-9
of steels and alloys, 4-10
efficiency, Carnot cycle, 2-12
neutron, 47-6
probe, 43-5
resistance, 4-1, 4-6
contact, 4-1
in conduction, 4-3
utilization, 47-11
viewers, 40-6
Thermal conductivity
of insulating materials, 23-6
Thermal NOx, 34-1
Thermocouple, 40-7, 43-5
chordal, 40-12, 42-19
circuit arrangement, 40-7
cold junction, 40-7
correction for, 4-31, 40-8
emf (chart), 40-7
gas temperature error graph, 40-14
gradient, 40-12
limitations, 40-13
scale detection, 40-12
high velocity, 40-14
hot junction, 40-7, 40-9
lead wire, 40-8
material selection, 40-8
multiple circuits, 40-7
multiple-shield high velocity, 40-15
pad type, 40-8
peened, 40-9
principles of, 40-7
sheathed type, 40-8
types, 40-7
Thermodynamics – see Chapter 2
cycles, 2-1, 2-12
definitions, 2-1
first law of, 4-5
laws of, 2-10
process, 2-7
irreversible, 2-11
reversible, 2-10
Thermographic imagers, 40-6
Thermoluminescent dosimeter,
49-13
Thermometer
gas, 40-4
liquid in glass, 40-4
mercury, 40-4
resistance, 40-6
vapor pressure, 40-4
well, 40-10
Thermopile, 40-7
Thermoprobe, 40-16
Thermowell, 40-10
Thorium, 47-4
Throat tap nozzle, 40-20
Throttle pressure control, 43-12
Throttling calorimeter, 40-19
Steam 41 / Index
The Babcock & Wilcox Company
Time-temperature-transformation
(TTT) diagrams, 7-4
Tire shredding, 29-17
Title IV (Acid Deposition Control), 32-4
Total organic carbon (TOC), 42-4
Toughness, 7-17
Trademarks (B&W) appearing in
this edition, TM-1
Transducer, 40-3
Transfer units, 35-10
Transformation diagrams,
isothermal, 7-4
Transient or unsteady-state
conduction, heat transfer, 4-5
Tray, perforated plate, 35-3, 35-6
Trepanning, 50-2
Trim, marine, 31-1
Tube
banks, 19-7 (see also Banks of
tubes)
bending, 38-4, 50-7
cold drawing, 38-10
composite, 28-11
crossflow pressure drop, 3-15
electric resistance welding, 38-10
expansion, 50-10
flat stud, 23-2
forming, 38-4
hole drilling, 38-6
leak detection, 45-16
leg flexibility, 45-19
manufacture, 38-10
membrane, 23-1
plugging, nuclear, 49-5
refractory lining, 23-1
remaining life, 45-11
repair, nuclear, 49-6
seamless, 38-10
sizes, 19-10, 31-2, 31-5
sleeving, 49-6
spacing, 19-7, 19-11
surface, 40-11
tangent, 23-2
temperature, 40-11
upgrades, 23-2
wall enclosures, 23-1
Tube banks, 4-27
arrangement factors, 4-19, 4-20,
4-21
crossflow over, 4-16
longitudinal flow over, 4-18
radiation, 4-28
Tube rolling and expanding, 39-13
Tubular air heater, 20-7
Turbine
combustion in IGCC plants, 18-14
energy equation, 2-9
feed pump, nuclear, 49-17
following control, steam, 41-5
gas, 17-13
nuclear, bypass valve, 49-17
steam, 17-13
trip, testing, 49-20
Turbine-generator control, 43-6
Turbulence fluctuations, 6-5
Turbulence model, 6-5
Steam 41 / Index
Turbulent flow, 4-14, 4-16 (see also
Flow, turbulent)
crossflow around tubes, 4-16
inside tubes, 4-16
longitudinal flow around tubes, 4-18
structure of, 4-16
Turning vanes, flow through, 3-13
Turnkey, 37-5
Two-phase flow, steam-water, 5-8
heat transfer, boiling, 5-3
instability, 5-11
pressure drop or loss, 5-9
separation, 5-13
stability, 5-12
void fraction, 5-9
U-beams, 17-11, 27-10
Ultimate tensile strength, 7-17
Ultrasonic examination, 38-12, 45-2,
49-4, 49-10, 50-2, 50-5
immersion testing, 45-3
oxide measurement, 45-2
shear wave, 45-3
thickness testing, 45-2
time of flight defraction, 45-3
Unburned carbon or unburned
combustible, 10-14, 44-7
pulverized coal, 14-8, 14-19
Undergrate air, 16-1, 16-6, 16-9
Universal gas constant, 3-4, 10-3,
10-9, 40-4
Universal Pressure (UP) boiler,
Intro-10, 19-2, 26-6, 26-9
attemperators, 19-15
bypass and startup systems,
19-16, 19-20
control system philosophy, 41-12
controls, 41-12
operation, 43-11
bypass system, 43-11
control functions, 43-11
limits and precautions, 43-12
practice, 43-11
principles, 43-11
skills, 43-12
startup, 43-12
Upgrades, boiler
bypass system, 44-16
capacity, 44-20
circulation, 44-16
cycling operation, 44-15
economizer, 44-7
headers, 44-14
superheater, 44-13
Uranium, 47-4
Uranium dioxide, 46-8
Urea, 34-3
Useful charts and tables, Appendix 1
U.S. Naval Nuclear Propulsion
Program, 46-21
U.S.S. Kennedy, 31-1
U.S.S. Missouri, 31-1
U.S.S. Nautilus, Intro-12, 46-22
U.S.S. Ronald Reagan, 46-25
U.S.S. Seawolf, 46-23
U.S.S. Skipjack, 46-24
U.S.S. Virginia, 46-24
Utility power plant, Color Plate 8
Vacuum filter, 35-8
Valve
flow, coefficient, 3-12
flow resistance, 3-9
nuclear, 49-10
safety and relief – see Safety,
relief valve
Universal Pressure boiler,
bypass, 43-12
Vapor, superheated, 3-1
Vaporization (ammonia), 34-7
Variable pressure operation, 19-2,
19-17, 19-20, 43-6
operation control, 41-7
Vegetation wastes, 9-19
Velocity
fluidizing, 17-2
head, 3-6
head, mass-velocity relationship
for air, 3-15
head loss for valves and fittings,
3-12
minimum, 17-2
ranges, 3-9
steam generating system, 3-9
Ventilation, boiler room, 23-6
Venturi, 3-4
air foil, 40-21
tube, 40-20
Venturi scrubber, 35-2
Vibration
buckstays, 23-5
casing, 23-5
Viscosity, 3-1
absolute, 9-14
apparent, 3-9
coal ash slag
effect of iron, 15-4
compared with kinematic, 3-10
gases of, 4-11
in common gases, 3-11
in common liquids, 3-11
oxidizing versus reducing
atmosphere, 15-13
requirements for Cyclone
furnaces, 15-4
steam, 3-12
T250, 15-4
Void fraction, 5-9
Volatile matter, coal
ASTM test, 14-3
fuel ratio (FC/VM), 14-10, 14-18
NOx influence, 14-5
Volatile organic compounds (VOCs),
32-7
Warm working, 7-9
Waste, 12-18
energy, 27-4
gas turbine exhaust, 18-14
I-21
The Babcock & Wilcox Company
heat
marine boiler, 31-5
steam generator, 27-15
Waste burning (see also Fuel)
fuel
application, 15-3, 15-9
Water
alkalinity, 42-8
analysis (see also Measurement),
42-13
attemperation, 42-7
boiler, 42-2
chemistry, Chapter 42
quality assurance, 42-14
chloride, 42-4
coil, air heater, 20-9
condensate, 42-6
conductivity, 42-14
demineralizer, 42-5
enthalpy, 2-2, T-5, T-6
entropy, 2-2, T-5, T-6
feedwater, 42-4
foaming, 42-12
for spray attemperators, 42-7
gas-shift reaction, 18-2
gasification system treatment,
18-15
hammer, 20-4
hardness, 42-2, 42-3
hydroxide, 42-1
iron, 42-4
makeup, 42-5
organics, in water, 42-5
oxygen, 42-4
pollution control, 32-13
technologies, 32-15
U.S. legislation, 32-13
quality, 42-5, 49-16
boric acid, 49-16
corrosion product transport,
49-16
pH, 49-16
requirements
fossil fuel boilers, Chapter 42,
43-8
nuclear units, 49-16
seal tanks, 27-18
silica, 42-9, 42-13, 42-14
I-22
sodium, 42-2, 42-5
specific volume, 2-1, 2-2, T-5, T-6
total dissolved solids, 42-9, 42-12
treatment, 32-15, 42-1
all volatile, 42-8
chelants, 42-11
conventional phosphate, 42-11
coordinated phosphate, 42-8
deaeration, 42-6
demineralization, 42-5
dispersants, 42-11
equilibrium phosphate, 42-9
evaporation, 42-2
for drum boilers, 42-7
high alkalinity phosphate, 42-11
hydroxide, 42-1
internal, 42-7
oxygen, 42-8
pH control, 42-6
phosphate, 42-8
polymers, 42-7, 42-11
raw water, 42-5
reverse osmosis, 42-5
softening, 42-5
Universal Pressure boilers,
42-12
waste water, 42-24
Water-cooled furnace
introduction of, Intro-9
Water-cooled walls, 19-6
Water leg correction, 40-3
Weak wash, pulp, 28-3, 28-5
Wear, pulverizer, 13-9
Wear metals
castings, 38-4
Wear resistant materials, 44-10
Weld
cladding, 7-14, 44-8
Welding, 7-10, 38-1
arc, 38-1
automation, 38-1
cladding/overlay, 50-2, 50-4, 50-13
development of, Intro-13
electrodes, 38-6
gas metal arc welding, 38-1, 50-2
gas shielded metal arc, 38-1
gas shielded tungsten arc, 38-1
gas tungsten, 38-1, 50-5, 50-9
heat treatment, 38-1
high frequency resistance, 38-1
laser beam, 38-1
orbital, 38-2, 50-5
plasma arc, 38-1
processes, 38-1
robotic, 38-2
shielded metal arc, 38-1
submerged arc, 38-5, 50-2, 50-5
tube to tubesheet welding, 50-9
Welds
applications, 39-14
codes and inspection, 39-14
field, 39-13
nondestructive examination,
38-11, 49-2
pressure, 39-14
processes and equipment, 39-14
qualification, 39-14
seal, 39-14, 50-6
thermal treatment, 39-14
Wet electrostatic precipitator, 33-8
Wet scrubbers – see SO2 control
Wheatstone bridge, 40-6
White iron, 7-14
White liquor, pulp, 28-2
Wick boiling, 42-2
Wilcox, Stephen, Intro-5, Intro-7
Wind loading, 26-4, 39-9
Wind swept spout – see Air swept
spout
Windbox, 23-3
Wood
as a fuel, 30-2
fuel properties, 9-18
Work breakdown structures, 39-3
Work-hardening, 7-9
Xenon, 47-6, 47-9, 49-20
X-ray, 47-1
machine, 38-6, 38-11
Yancey-Geer Price, 9-9, 13-9
Yield point, 7-17
Yield strength, 7-17
Young’s modulus, 7-16
Steam 41 / Index
Erlet Shaqe