EPA/600/7-90/021 a
November 1990
RETROFIT COSTS FOR S02 AND N0X CONTROL OPTIONS
AT 200 COAL-FIRED PLANTS
VOLUME I - INTRODUCTION AND METHODOLOGY
by
T. Emmel arid M. Maibodi
Radian Corporation
Post Office Box 13000
Research Triangle Park, NC 27709
EPA Contract No. 68-02-4286
Work Assignment 116
Project Officer
Norman Kaplan
U. S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27711
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before con\p!r' ~ ^
1. REPORT NO. 2.
" EPA?600/7-90/021a
PB91-133322 j
4. TITLE AND SUBTITLE
Retrofit Costs for SOg and NOx Control Options at
200 Coal-fired Plants, Volume I - Introduction and
Methodology
5. REPORT OATE
November 1990
6. PERFORMING ORGANIZATION CODE
7. AUTHOfl(S)
Thomas E. Enimel and Mehdi Maibodi
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME ANO AO DRESS
Radian Corporation
P. O. Box 13000
Research Triangle Park, North Carolina 27709
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
88-02-4288, Task 116
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
13. TYPE 0¥ REPORT ANO PERIOD COVERED
Task Final; 1985-1990
14. SPONSORING AGENCY CODE
EPA/600/13
is. supplementary notesAEERL project officer is Norman Kaplan, Mail Drop 62, 919/541-
2556. This=ifs' one of five volumes and three diskettes comprising this report.
io. abstract- tj.)C, report gives results of a study, the objective of which was to signifi-
cantly improve engineering cost estimates currently being used to evaluate the eco-
nomic effects of applying S02 and NOx controls at 200 large S02~emitting coal-fired
utility plants. To accomplish the objective, procedures were developed and used that
account for site-specific retrofit factors. The site-specific information was obtained
from aerial photographs, generally available data bases, and input from utility com-
panies. Cost estimates are presented for six control technologies; lime/limestone
flue gas desulfurization, lime spray drying, coal switching and cleaning, furnace and
duct sorbent injection, low NOx combustion or natural gas reburn, and selective cata-
lytic reduction. Although the cost estimates provide useful site-specific cost infor-
mation on retrofitting acid gas controls, the costs are estimated for a specific time
period and do not reflect future changes in boiler and coal characteristics (e. g. ,
capacity factors and fuel proces) or significant changes in control technology and per-
formance. .
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. cosati Field/Group
Pollution Electric Power Plants
Silfur Dioxide
Nitrogen Oxides
Cost Estimates
Coal
Combustion
Pollution Control
Stationary Sources
Retrofits
13 B 10B
07B
05A.14A
21D
21B
10. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report/
Unclassified
21. NO. OF PAGES
97
20. SECURITY CLASS (This page)
Unclassified
22- PRICE
EPA Form 2220-1 (9-73)
i
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ABSTRACT
This report documents the results of a study conducted under the
National Acid Precipitation Assessment Program by the U.S. Environmental
Protection Agency's Air and Energy Engineering Research Laboratory. The
objective of this research program was to significantly improve engineering
cost estimates currently being used,to evaluate the economic effects of
applying sulfur dioxide and nitrogen oxides controls at ZOO large sulfur
dioxide emitting coal-fired utility plants. To accomplish the objective,
procedures were developed and used that account for site-specific retrofit
factors. The site-specific information was obtained from aerial
photographs, generally available data bases, and input from utility
companies. Cost estimates are presented for the following control
technologies: lime/limestone flue gas desulfurization, lime spray drying,
coal switching and cleaning, furnace and duct sorbent injection, low N0X
combustion or natural gas reburn, and selective catalytic reduction.
Although the cost estimates provide useful site-specific cost information on
retrofitting acid gas controls, the costs are estimated for a specific time
period and do not reflect future changes in boiler and coal characteristics
(e.g., capacity factors and fuel prices) or significant changes in control
technology cost and performance.
NOTICE
This document has been reviewed in accordance with
U.S. Environmental Protection Agency policy and
approved for publication. Mention of trade names
or commercial products does not constitute endorse-
ment or reconimendation for use.
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TABLE OF CONTENTS
VOLUME I - INTRODUCTION AND METHODOLOGY
SECTION PAGE
ABSTRACT - . . ii
LIST OF FIGURES xiv
LIST OF TABLES xv
ABBREVIATIONS AND SYMBOLS xvi
ACKNOWLEDGEMENT xix
METRIC EQUIVALENTS xx
1.0 INTRODUCTION AND SUMMARY . 1-1
1.1 Methodology . 1-4
1.2 Summary of Cost Results 1-7
1.2.1 FGD Cost Estimates 1-7
1.2.2 Coal Switching and Cleaning 1-13
1.2.3 Sorbent Injection Cost and Performance
Estimates . 1-13
1.2.4 Low NO^ Combustion 1-22
1.2.5 Selective Catalytic Reduction
(SCR) Cost Estimates 1-22
1.3 Conclusion 1-27
1.4 References 1-30
2.0 DESCRIPTION OF THE NEW SIMPLIFIED RETROFIT FACTOR AND COST
ESTIMATION PROCEDURES 2-1
2.1 Retrofit Factors and Scope Adder Costs 2-2
2.1.1 Lime/Limestone and Lime Spray Drying Flue Gas
Desulfurization 2-4
2.1.1.1 Description of Simplified Procedures . . 2-4
2.1.1.2 Development and Testing of the Simplified
Procedures 2-7
2.1.1.3 Accuracy of the Simplified Procedures . . 2-12
2.1.2 Sorbent Injection Technologies 2-12
2.1.2.1 Process Selection 2-14
2.1.2.2 Process Area and PM Control Access/
Congestion Factor 2-15
2.1.2.3 Scope Adder Costs . , 2-16
i i i '
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TABLE OF CONTENTS (Continued)
SECTION PAGE
2.1.3 Coal Switching and Cleaning . 2-17
2.1.4 Fluidized Bed Combustion and Coal Gasification . . 2-18
2.1.5 NO Controls 2-20
2.1.5.1 Low NO Combustion Performance Estimating
Procedures . 2-21
2.1.5.2 Natural Gas Reburning .... 2-23
2.1.5.3 Selective Catalytic Reduction . 2-24
2.2 IAPCS Cost Model. ............ 2-27
2.2.1 Flue Gas Desulfurization 2-27
2.2.2 Lime Spray Drying 2-30
2.2.3 Furnace Sorbent Injection ..... 2-30
2.2.4 Physical Coal Cleaning 2-32
2.2.5 Coal Substitution . 2-34
2.2.6 Low NO Combustion 2-34
2.2.7 Natural Gas Reburning 2-34
2.2.8 Selective Catalytic Reduction 2-37
2.2.9 Electrostatic Precipitator 2-37
2.2.10 Fabric Filter 2-39
2.2.11 Waste Disposal 2-40
2.3 Economic and Financial Assumptions 2-40
2.4 References. ... ...... 2-45
VOLUME II - SITE SPECIFIC STUDIES FOR
Alabama, Delaware, Florida, Georgia, Illinois
3.0 ALABAMA 3-1
3.1 Alabama Power Company .............. 3-1
3.1.1 Barry Steam Plant 3-1
3.1.2 Gadsden Steam Plant 3-14
' 3.1.3 Gaston Steam Plant ...... 3-22
3.1.4 Gorgas Steam Plant 3-33.
3.1.5 Greene County Steam Plant . . 3-41
3.1.6 Miller Steam Plant 3-50
3.2 Tennessee Val 1 ey Authority 3-54
3.2.1 Colbert Steam Plant 3-54
3.2.2 Widows Creek Steam Plant 3-54
4.0 DELAWARE 4-1
4.1 Delmarva Power and Light Company ............. 4-1
4.1.1 Indian River Steam Plant ........ 4-1
i v
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TABLE OF CONTENTS (Continued)
SECTION PAGE
5.0 FLORIDA 5-1
5.1 Florida Power Corporation 5-1
5.1.1 Crystal River Steam Plant ............ . 5-1
5.2 Gulf Power Company 5-16
5.2.1 Crist Electric Generating Plant .... 5-16
5.2.2 Lansing Smith Steam Plant .... 5-25
5.3 Seminole Electric Cooperative ............... 5-32
5.3.1 Seminole Steam Plant 5-32
5.4 Tampa Electric Company 5-36
5.4.1 Big Bend Steam Plant 5-36
5.4.2 F. J. Gannon Steam Plant 5-42
6.0 GEORGIA 6-1
6.1 Georgia Power Company 6-1
6.1.1 P. S. Arkwright Steam Plant 6-1
6.1.2 Bowen Steam Plant 6-12
6.1.3 Branch Steam Plant 6-21
6.1.4 Hammond Steam Plant 6-32
6.1.5 Jack McDonough Steam Plant 6-41
6.1.6 Mitchell Steam PI ant 6-52
6.1.7 Robert W. Scherer Steam Plant ..... . 6-60
6.1.8 Wansley Steam Plant 6-66
6.1.9 Yates Steam Plant 6-75
7.0 ILLINOIS ............ 7-1
7.1 Central Illinois Light Company 7-1
7.1.1 E. D. Edwards Steam Plant ............ . 7-1
7.2 Central Illinois Public Service 7-6
7.2.1 Coffeen Steam Plant . . 7-6
7.2.2 Grand Tower Steam Plant 7-20
7.2.3 Hutsonville Steam Plant 7-31
7.2.4 Meredosia Steam Plant 7-43
7.2.5 Newton Steam Plant ..... 7-54
7.3 Commonwealth Edison Company ... 7-68
7.3.1 Joliet 29 Steam Plant ........ 7-68
7.3.2 Kincaid Steam PI ant 7-72
7.3.3 Powerton Steam Plant 7-82
7.3.4 Waukegan Steam Plant 7-91
7.3.1 Will County Steam Plant . 7-99
v
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TABLE OF CONTENTS (Continued)
SECTION PAGE
7.4 Electric Energy Incorporation ...... 7-105
7.4.1 Joppa Steam Plant 7-105
7.5 II1 inois Power Company . 7-122
7.5.1 Baldwin Steam Plant . . 7-122
7.5.2 Hennepin Steam Plant ...... 7-136
7.5.3 Vermilion Steam Plant 7-149
7.5.4 Wood River Steam Plant 7-164
7.6 Southern Illinois Power Company . 7-169
7.6.1 Marion Steam Plant .... ...... 7-169
7.7 Springfield City of Water 7-183
7.7.1 Dal 1 man Steam Plant 7-183
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
8.0 INDIANA 8-1
8.1 Alcoa Generating Corporation and Southern Indiana Gas
and Electric Company ................... 8-1
8.1.1 Warrick Steam Plant 8-1
8.2 Hoosier Energy Rural Electric ........ 8-14
8.2.1 Merom Steam Plant . 8-14
8.2.2 Frank E. Ratts Steam Plant . 8-17
8.3 Indiana - Kentucky Electric Corporation .......... 8-25
8.3.1 Clifty Creek Steam Plant 8-25
8.4 Indiana and Michigan Electric Company . 8-38
8.4.1 Breed Steam Plant 8-38
8.4.2 Rockport Steam Plant 8-42
8.4.3 Tanners Creek Steam Plant ........ 8-49
8.5 Indianapolis Power and Light 8-64
8.5.1 Perry K Steam Plant 8-64
8.5.2 Petersburg Steam Plant . 8-64
8.5.3 E. W. Stout Steam Plant . 8-72
8.6 Northern Indiana Public Service Company .......... 8-86
8.6.1 Bailly Steam Plant ................ 8-86
8.6.2 Michigan City Steam Plant 8-93
8.7 Public Service Company of Indiana ... .... 8-100
8.7.1 Cayuga Steam Plant 8-100
8.7.2 R. A. Gallagher Steam Plant ..... 8-108
vi
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TABLE OF CONTENTS (Continued)
SECTION PAGE
8.7.3 Gibson Steam Plant 8-117
8.7.4 Wabash River Steam Plant 8-125
8.8 Southern Indiana Gas and Electric 8-136
8.8.1 F. B. Culley Steam Plant 8-136
9,0 KENTUCKY ...... ...... 9-1
9.1 Big Rivers Electric Corporation 9-1
9.1.1 Coleman Steam Plant ........ 9-1
9.1.2 R. D. Green Steam Plant 9-17
9.1.3 Robert Reid Steam Plant ..... 9-22
9.2 Cincinnati Gas and Electric 9-28
9.2.1 East Bend Steam Plant 9-28
9.3 East Kentucky Power Corporation 9-31
9.3.1 John Sherman Cooper Steam Plant . 9-31
9.3.2 Hugh L. Spurlock Steam Plant . 9-42
9.4 Henderson Municipal Power and Light ............ 9-56
9.4.1 Henderson Station Two Steam Plant ......... 9-56
9.5 Kentucky Power Company 9-64
9.5.1 Big Sandy Steam Plant . 9-64
9.6 Kentucky Utilities Company ..... 9-64
9.6.1 E. W. Brown Steam Plant 9-64
9.6.2 Ghent Steam Plant ..... 9-64
9.6.3 Green River Steam Plant .... 9-77
9.7 Louisville Gas and Electric 9-84
9.7.1 Mill Creek Steam Plant 9-84
9.8 Owensboro Municipal Utility .... 9-91
9.8.1 Elmer Smith Steam Plant 9-91
9.9 Tennessee Valley Authority . 9-91
9.9.1 Paradise Steam Plant ..... 9-91
9.9.2 Shawnee Steam Plant 9-91
10.0 MASSACHUSETTS 10-1
10.1 Montaup Electric Company 10-1
10.1.1 Somerset Steam Plant 10-1
10.2 New England Power Company ...... 10-11
10.2.1 Brayton Point Steam Plant . 10-11
10.2.2 Salem Harbor Steam Plant ............ 10-25
vi i
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SECTION
TABLE OF CONTENTS (Continued)
PAGE
11.0 MARYLAND H-l
11.1 Baltimore Gas and Electric ll-l
11.1.1 Charles P. Crane Steam Plant .... ll-l
11.2 Potomac Electric Power Company ... ... 11-8
11.2.1 Chalk Point Steam Plant .... 11-8
11.2.2 Dickerson Steam Plant ... 11-18
11.2.3 Morgantown Steam Plant ... 11-26
12.0 MICHIGAN 12-1
12.1 Consumers Power Company 12-1
12.1.1 J. H. Campbell Steam Plant ......12-1
12.1.2 Dan E. Karn Steam Plant 12-8
12.1.3 J. C. Weadock Steam Plant ..... 12-17
12.1.4 J. R. Whiting Steam Plant 12-24
12.2 Detroit Edison Company ... 12-32
12.2.1 Monroe Steam Plant . 12-32
12.2.2 River Rouge Steam Plant 12-42
12.2.3 St. Clair Steam PI ant 12-48
12.2.4 Trenton Channel Steam Plant ........... 12-57
12.3 Upper Peninsula Power Company ..... 12-63
12.3.1 Presque Isle Steam Plant . 12-63
13.0 MINNESOTA .............. 13-1
13.1 Minnesota Power and Light Company .... 13-1
13.1.1 Clay Boswel1 Steam Plant 13-1
13.2 Northern States Power Company ..... 13-10
13.2.1 A. S. King Steam Plant 13-10
13.2.2 Sherburne County Steam PI ant . 13-15
VOLUME IV - SITE SPECIFIC STUDIES FOR
Missouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
14.0 MISSOURI ........ ..... 14-1
14.1 Associated Electric Cooperative System . 14-1
14.1.1 New Madrid Steam Plant . . 14-1
14.1.2 Thomas Hill Steam Plant 14-10
14.2 Empire District Electric Company 14-29
14.2.1 Asbury Steam Plant 14-29
vi i i
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TABLE OF CONTENTS (Continued)
SECTION PAGE
14.3 Kansas City Power and Light . 14-42
14.3.1 Hawthorn Steam Plant 14-42
14.3.2 Iatan Steam Plant . 14-54
14.3.3 La Cygne Steam Plant 14-60
14.3.4 Montrose Steam Plant ....... 14-67
14.4 Missouri Public Service 14-77
14.4.1 Sibley Steam Plant 14-77
14.5 City Utilities of Springfield 14-92
14.5.1 James River Steam Plant ... 14-92
14.6 Union Electric Company 14-109
14.6.1 Labadie Steam Plant 14-109
14.6.2 Meramec Steam Plant 14-124
14.6.3 Rush Island Steam Plant ...... 14-146
14.6.4 Sioux Steam Plant .... . . 14-158
15.0 MISSISSIPPI ...... 15-1
15.1 Mississippi Power Company 15-1
15.1.1 V. J. Daniel, Jr. Steam PI ant 15-1
15.1.2 Jack Watson Steam PI ant . 15-5
16.0 NORTH CAROLINA 16-1
16.1 Carolina Power and Light Company 16-1
16.1.1 Mayo Steam PI ant 16-1
16.1.2 Roxboro Steam Plant ..... 16-4
16.2 Duke Power Company 16-19
16.2.1 Allen Steam Plant . .... 16-19
16.2.2 Belews Creek Steam Plant ... 16-25
16.2.3 CIiffside Steam Plant .... 16-29
16.2.4 Marshall Steam Plant ...... 16-40
17.0 NEW HAMPSHIRE 17-1
17.1 Public Service Company of New Hampshire 17-1
17.1.1 Merrimack Steam Plant .... 17-1
18.0 NEW JERSEY 18-1
18.1 Atlantic City Electric Company 18-1
18.1.1 B. L. England Steam Plant 18-1
18.2 Public Service Electric & Gas Company 18-11
18.2.1 Hudson Steam Plant . 18-11
18.2.2 Mercer Steam Plant ..... 18-15
ix
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TABLE OF CONTENTS (Continued)
SECTION PAGE
19.0 NEW YORK 19-1
19.1 New York State Electric and Gas Corporation 19-1
19.1.1 Goudey Steam Plant 19-1
19.1.2 Greenidge Steam Plant 19-11
19.1.3 Milliken Steam Plant . 19-17
19.2 Niagara Mohawk Power Corporation 19-25
19.2.1 Dunkirk Steam Plant ...... 19-26
19.2.2 C. R. Huntley Steam Plant ............ 19-35
19.3 Rochester Gas and Electric Company ...... 19-46
19.3.1 Rochester 7 Russell Steam Plant ... 19-46
20.0 OHIO 20-1
20.1 Cardinal Operating Company 20-1
20.1.1 Cardinal Steam Plant 20-1
20.2 Cincinnati Gas and Electric Company . 20-19
20.2.1 Walter C. Beckjord Steam Plant . . 20-19
20.2.2 Miami Fort Steam Plant 20-33
20.3 Cleveland Electric Illuminating Company 20-53
20.3.1 Ashtabula Steam Plant .............. 20-53
20.3.2 Avon Lake Steam Plant 20-59
20.3.3 Eastlake Steam Plant . . 20-73
20.4 Columbus and Southern Ohio Electric Company 20-93
20.4.1 Conesville Steam Plant 20-93
20.4.2 Picway Steam Plant ... ..... 20-93
20.4.3 Poston Steam Plant 20-101
20.5 Dayton Power and Light Company 20-118
20.5.1 James M. Stuart Steam Plant ..... 20-118
20.6 Ohio Edison Company 20-118
20.6.1 R. E. Burger Steam Plant .... 20-118
20.6.2 Niles Plant 20-118
20.6.3 W. H. Sammis Steam Plant 20-128
20.6.4 Toronto Plant . . . 20-128
20.7 Ohio Power Company 20-144
20.7.1 General James M. Gavin Steam Plant 20-144
20.7.2 Muskingum River Steam Plant ..... 20-155
x
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TABLE OF CONTENTS (Continued)
SECTION PAGE
20.8 Ohio Valley Electric Corporation .... . 20-156
20.8.1 Kyger Creek Steam Plant 20-156
20.9 Toledo Edison Company ....... 20-170
20.9.1 Bay Shore Steam Plant . 20-170
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
21.0 PENNSYLVANIA ..... 21-1
21.1 Allegheny Power Service Corp. .... ..... 21-1
21.1.1 Armstrong Steam Plant ............... 21-1
21.1.2 Hatfield's Ferry Steam Plant ........... 21-9
21.1.3 Mitchell Steam Plant . 21-17
21.2 Duquesne Light Company 21-21
21.2.1 Cheswick Steam Plant . 21-21
21.3 Metropolitan Edison Company 21-35
21.3.1 Portland Steam Plant 21-35
21.4 Pennsylvania Electric Company 21-49
21.4.1 Conemaugh Steam Plant 21-49
21.4.2 Homer City Steam Plant ...... 21-60
21.4.3 Keystone Steam Plant ... 21-71
21.4.4 Seward Steam Plant . . 21-85
21.4.5 Shawvi11e Steam Plant ....... 21-96
21.5 Pennsylvania Power and Light Company ..... 21-109
21.5.1 Brunner Island Steam Plant 21-109
21.5.2 Martins Creek Steam Plant 21-121
21.5.3 Montour Steam Plant 21-137
21.5.4 Sunbury Steam Plant ............... 21-153
21.6 Pennsylvania Power Company 21-171
21.6.1 Bruce Mansfield Steam Plant ... 21-171
21.6.2 New Castle Steam Plant ... ... 21-173
21.7 Philadelphia Electric Company ... 21-194
21.7.1 Eddystone Steam Plant .... 21-194
22.0 SOUTH CAROLINA ......... 22-1
22.1 South Carol ina Electric and Gas 22-1
22.1.1 Canadys Steam Plant 22-1
22.1.2 Silas C. McMeekin Steam Plant .... 22-8
xi
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TABLE OF CONTENTS (Continued)
SECTION PAGE
22.1.3 Urquhart Steam Plant . . ..... 22-16
22.1.4 Wateree Steam Plant , ..... 22-22
22.2 South Carolina Generating ..... 22-28
22.2.1 Arthur M. Williams Steam Plant 22-28
22.3 South Carolina Public Service . . 22-34
22.3.1 Grainger Steam Plant .............. 22-34
22.3.2 Jefferies Steam Plant . . 22-42
22.3.3 Winyah Steam Plant .... 22-51
23.0 TENNESSEE 23-1
23.1 Tennessee Valley Authority ..... 23-1
23.1.1 Allen Steam Plant ..... 23-1
23.1.2 Bull Run Steam Plant 23-13
23.1.3 Cumberland Steam Plant . . 23-28
23.1.4 Gallatin Steam Plant 23-28
23.1.5 Johnsonville Steam Plant . .... 23-42
23.1.6 Kingston Steam Plant . . 23-46
23.1.7 John Sevier Steam Plant 23-61
24.0 VIRGINIA 24-1
24.1 Appalachian Power Company 24-1
24.1.1 Clinch River 24-1
24.2 Virginia Electric and Power Company ..... 24-6
24.2.1 Chesterfield 24-6
24.2.2 Portsmouth Steam Plant ....... 24-11
24.2.3 Possum Point Steam Plant 24-17
25.0 WISCONSIN 25-1
25.1 Dairyland Power Cooperative t . 25-1
25.1.1 Genoa #3 Steam Plant 25-1
25.2 Wisconsin Electric Power Company 25-9
25.2.1 North Oak Creek Steam Plant ...... 25-9
25.2.2 Pleasant Prairie Steam Plant .... 25-14
25.2.3 Port Washington Steam Plant 25-19
25.2.4 South Oak Creek Steam Plant ........... 25-25
25.2.5 Valley Steam Plant ........ 25-39
25.3 Wisconsin Power and Light 25-45
25.3.1 Columbia Steam Plant 25-45
25.3.2 Edgewater Steam Plant 25-51
25.3.3 Nelson Dewey Steam Plant ..... 25-61
25.3.4 Rock River Steam Plant ....... 25-67
xi i
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/
TABLE OF CONTENTS (Continued)
SECTION PAGE
25.4 Wisconsin Public Service Corporation ..... 25-72
25.4.1 J. P. Pulliam Steam Plant 25-72
25.4.2 Weston Unit 1, 2, 3 Steam Plant 25-82
26.0 WEST VIRGINIA 26-1
26.1 Allegheny Power Service Corp. . . ........ 26-1
26.1.1 Albright 26-1
26.1.2 Fort Martin Steam Plant . 26-11
26.1.3 Harrison Steam Plant 26-21
26.1.4 Pleasants Steam Plant . . . 26-29
26.2 Appalachian Power Company . 26-32
26.2.1 J. E. Amos Steam Plant 26-32
26.2.2 Mountaineer Steam Plant ..... 26-40
26.3 Central Operating Company . 26-48
26.3.1 Philip Sporn Steam Plant . 26-48
26.4 Ohio Power Company ..... ........ 26-60
26.4.1 Kammer Steam Plant .... 26-60
26.4.2 Mitchell Steam Plant 26-69
26.5 Virginia Electric and Power Company ........... 26-80
26.5.1 Mount Storm Steam Plant 26-80
xiii
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LIST OF FIGURES
FIGURE PAGE
1-1 200 Plant Study Technical Approach 1-2
1-2 Site-Specific Cost Estimation Methodology . 1-5
1-3 Summary of Capital Cost Results for Lime/Limestone Flue
Gas Desulfurization 1-8
1-4 Summary of Annual Cost Results for Lime/Limestone Flue
Gas Desulfurization 1-8
1-5 Summary of Cost Per Ton of SO2 Removed Results for Lime/
Limestone Flue Gas Desulfurization ............. 1-9
1-6 Summary of Capital Cost Results for Lime Spray Drying 1-11
1-7 Summary of Annual Cost Results for Lime Spray Drying 1-11
1-8 Summary of Cost Per Ton of SOo Removed Results for
Lime Spray Drying 1-12
1-9 Summary of Capital Cost Results for Coal Switching
and Blending 1-14
1-10 Summary of Annual Cost Results for Coal Switching
and Blending .... 1-14
1-11 Summary of Cost Per Ton of S02 Removed Results for
Coal Switching and Blending 1-15
1-12 Summary of Capital Cost Results for Physical Coal
Cleaning 1-16
1-13 Summary of Annual Cost Results for Physical Coal
Cleaning 1-16
1-14 Summary of Cost Per Ton of SO2 Removed Results for
Physical Coal Cleaning 1-17
1-15 Summary of Capital Cost Results for Duct Spray Drying ..... 1-18
1-16 Summary of Annual Cost Results for Duct Spray Drying 1-18
1-17 Summary of Cost Per Ton of SO2 Removed Results for
Duct Spray Drying 1-19
1-18 Summary of Capital Cost Results for Furnace Sorbent
Injection 1-20
1-19 Summary of Annual Cost Results for Furnace Sorbent
Injection 1-20
1-20 Summary of Cost Per Ton of SO, Removed Results for Furnace
Sorbent Injection 1-21
1-21 Summary of Capital Cost Results for Low NO Combustion .... 1-23
1-22 Summary of Annual Cost Results for NO Combustion 1-23
1-23 Summary of Cost Per Ton of NO Removed Results for Low
N0X Combustion 1-24
1-24 Summary of Capital Cost Results for Selective
Catalytic Reduction 1-25
1-25 Summary of Annual Cost Results for Selective
Catalytic Reduction ..... . 1-25
1-26 Summary of Cost Per Ton of NO Removed Results for
Selective Catalytic Reduction 1-26
xi v
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LIST OF FIGURES
FIGURE PAGE
2-1 Comparison of the Process Area Retrofit Factor Estimated
Using the Detailed EPRI Procedures and the Simplified
Procedures 2-9
2-2 Percent Difference Between the Simplified and Detailed
EPRI Procedure Process Area Retrofit Factors . . 2-9
2-3 Comparison of the Retrofit Factors for the Detailed EPRI
and New Simplified Procedures 2-13
2-4 Possible SCR Configurations . 2-25
LIST OF TABLES
TABLE PAGE
1-1 Emission Control Technologies Selected 1-3
1-2 Economic Bases Used to Develop the Cost Estimates 1-6
1-3 Retrofit Factors Affecting Cost/Performance 1-28
2-1 Retrofit Cost and Performance Inputs to IAPCS Model 2-3
2-2 Summary of the General Facilities Factors and Access/
Congestion Guidelines Used in the EPRI Retrofit
FGD Cost Estimation Guidelines 2-6
2-3 Scope Adjustments and their Contribution to the Overall
Retrofit Factor ...... 2-11
2-4 Trade-offs Associated with Hot Side and Cold Side SCR
Systems for Coal-Fired Utility Boilers ...... 2-26
2-5 Flue Gas Desulfurization Technology Assumptions 2-29
2-6 Spray Drying Technology Assumptions 2-31
2-7 Furnace Sorbent Injection Technology Assumptions 2-33
2-8 Characteristics of Switched Coals ..... 2-35
2-9 Low N0X Combustion Technology Assumptions ..... 2-35
2-10 Natural Gas Reburning Technology Assumptions . 2-36
2-11 Selective Catalytic Reduction Technologies Assumptions .... 2-38
2-12 Financial Factors for Cost Structure ...... 2-41
2-13 Nominal Indirect Cost Schedule 2-42
2-14 Unit Cost Data 2-44
xv
-------
ABBREVIATIONS AND SYMBOLS
ABBREVIATIONS
acfm
--
actual cubic feet per minute
AEERL
--
Air and Energy Engineering Research Laboratory
AEP
--
Associated Electric Cooperative
AFDC
--
allowance for funds during construction
AUSM
--
advanced utility simulation model
-C
constant dollars in cost tables
CG
--
coal gasfication
CG&E
..
Cincinnati Gas and Electric
CS
--
coal switching
CS/B
..
coal switching and blending
DOE
--
Department of Energy
DSD
--
duct spray drying
EIA-767
..
Energy Information Administration Form 767
EPA
--
Environmental Protection Agency
EPRI
Electric Power Research Institute
ESP
--
electrostatic precipitator
FBC
--
fluidized bed combustion
FF
--
fabric filter
FGD
flue gas desulfurization
FPD
fuel price differential
FSI
--
furnace sorbent injection
ft
--
feet
FWF
front, wall-fired
IAPCS
Integrated Air Pollution Control System
-------
ABBREVIATIONS AND SYMBOLS (Continued)
IRS
Internal Revenue Service
KU
Kentucky Utilities
kW
--
kilowatt
kWh
killowatt hour
LC
__
low cost
LIMB
limestone injection multistage burner
L/LS
--
lime/1 imestone
LNB
--
low-NOx burner
LNC
--
low-NOx combustion
LSD
--
lime spray drying
m
--
meter
MM
--
millions
MW
--
megawatt
NAPAP
--
National Acid Precipitation Assessment Program
NGR
..
natural gas reburning
NRDC
--
Natural Resources Defense Council
NSPS
--
new source performance standard
NTIS
--
National Technical Information Service
OEUI
Ohio Electric Utilities
OFA
__
overfire air
OWF
--
opposed, wall-fired
O&M
--
operating and maintenance
PCC
__
physical coal cleaning
PM
--
particulate matter
psia
--
pounds per square inch absolute
/xvii
-------
SCA
SCR
SCR-CS
SCR-HS
sec
SI
sq ft
TAG
TVA
UARG
USGS
S/kW
SYMBOLS
MgO
nh3
N°x
502
503
ABBREVIATIONS AND SYMBOLS (Continued)
2
-- specific collection area (ft /1000 acfm)
-- selective catalytic reduction
-- selective catalytic reduction - cold side
-- selective catalytic reduction - hot side
-- second
-- sorbent injection
-- square feet
-- Technical Assessment Guideline
-- Tennessee Valley Authority
-- Utility Air Regulatory Group
-- U.S. Geological Survey
-- dollars per kilowatt
-- magnesium oxide
-- ammonia
-- nitrogen oxides
-- sulfur dioxide
-- sulfur trioxide
i xviTi :
-------
ACKNOWLEDGEMENT
We would like to thank the following people at Radian Corporation who helped
in the preparation of this report: Robert Page, Susan Squire,
JoAnn Gilbert, Linda Cooper, Sarah Godfrey, Kelly Martin, Karen Oliver, and
Janet Mangum.
xix /
-------
METRIC EQUIVALENTS
Readers more familiar with the metric system may use the following
factors to convert to that system.
Non-metric Times Yields Metric
acfm 0.028317 acms
2
acre 4046.9 m
Btu/lb 0.5556 kg-calories/kg
°F 5/9 (°F-32) °C
ft 0.3048 m
ft2 0.0929 m2
ft3 0.028317 m3
gal. 3.78533 L
Ib/MMBtu 1.8 kg/kg-calorie
psia 0.0703 g/cm2
ton 0.9072 ton
xx
-------
1.0 INTRODUCTION AND SUMMARY
The National Acid Precipitation Assessment Program (NAPAP) is
responsible for developing cost and performance information on various
methods for reducing the emissions of acid rain precursors. Coal-fired
utility boilers are major emitters of sulfur dioxide (SOg) and nitrogen
oxides (N0X). However, estimating the cost and performance of SOg and N0x
controls for coal-fired power plants 1s difficult due to differences in
plant layout and boiler design.
The objective of this study was to significantly improve the accuracy
of engineering cost estimates used to evaluate the economic effects of
applying S02 and NQX controls at 200 large S02-emitting coal-fired utility
plants. This project was conducted in several phases as shown in
Figure 1-1. In Phase I, detailed, site-specific procedures were developed
with input from the technical advisory committee. In Phase II, these
procedures were used to evaluate retrofit costs at 12 plants based on data
collected from site visits. Based on the results of this effort, simplified
procedures were developed to estimate site-specific costs without conducting
site visits. In Phase III, the simplified procedures were verified or
modified based on utility input by visiting six of the 50 plants. The
modified procedures were then used to estimate retrofit costs at the
remaining 138 plants. In Phase IV, utility comments were incorporated into
the final 200-plant study report.
This report presents the cost estimates developed for 631 out of 662
boilers in 200 plants using the simplified procedures. Costs were not
developed for 31 boilers because they were either burning fuels other than
coal or they were new boilers with SO^ and NQX controls already installed.
The commercial and developmental SO2 and N0X control technologies evaluated
in the study are listed in Table 1-1. The detailed cost estimates developed
for 55 boilers in the 12 plants evaluated using the detailed procedures are
presented in another report. (1) The cost results for all the boilers
evaluated in this report are included in a database file for further study
and evaluation.
1-1
-------
Figure 1-1. 200 Plant study technical approach.
1-2
-------
TABLE 1-1. EMISSION CONTROL TECHNOLOGIES SELECTED
Development Status
Ongoing Or
Limited Near
Species Controlled Commercial Commercial
SO^ NO Commercial Experience Demonstration
Lime/limestone (L/LS) flue X
gas desulfurization (FGD)
Additive enhanced L/LS FGD X
Lime spray drying (LSD) FGD8 X
Physical coal cleaning (PCC) X
Coal switching and blending (CS/B) X
Lou-NOx combustion (LNC)
Furnace sorbent injection (FSI) X
with humidification
Duct spray drying (DSD) X
Natural gas reburning (NGR)C X
Selective catalytic reduction (SCR)
Fluidized bed combustion (FBC) ^ X
or coal gasification (CG) retrofit
^Commercial for low sulfur coals, demonstrated at pilot scale for high sulfur coals.
FSI is an equipment designation for limestone injection multistage burners (LIMB).
jFor wet bottom boilers and other boilers uhere LNC is not applicable.
Evaluated qualitatively as combined life extension and SO^/NO control option. No costs were developed.
-------
1.1 METHODOLOGY
For each plant, a boiler profile was completed using sources of public
information, the primary source being the Energy Information Administration
(EIA) Form 767. Additionally, boiler design data were obtained from
Powerplants Database (2) and aerial photographs were obtained from state and
federal agencies. The plant and boiler profile information is used to
develop the input data for the performance and cost models. The performance
and cost results incorporate recommendations from utility companies and a
technical advisory group. The advisory group included utility industry,
flue gas desulfurizatlon (F6D) vendor, and government agency
representatives.
All of the cost estimates were developed using the Integrated Air
Pollution Control System (IAPCS) cost model (3). The IAPCS model was
upgraded to include all of the technologies being evaluated in this program.
All of the cost estimates were developed using the integrated technologies
evaluated in this program. Evaluated qualitatively without cost estimates
were life extension using fluidized bed combustion and coal gasification
combined cycle.
Figure 1-2 presents the methodology used to develop IAPCS inputs to
estimate site-specific costs of retrofitting S02 and N0X controls. The
site-specific information sources were used to develop process area retrofit
multipliers, scope adder costs, and boiler and coal parameters. This
information was input to the IAPCS cost model that generated the capital,
operating and maintenance (O&M), and levelized annual costs of control and
the emission reductions. The use of process area retrofit difficulty
multipliers and scope adder costs to adjust generic cost model outputs to
reflect site-specific retrofit situations was derived from an Electric Power
Research Institute (EPRI) report (4). A more detailed discussion of the
procedures used to develop the cost model inputs is provided in Section 2.
Table 1-2 summarizes the economic bases used to develop the cost
estimates. The following section summarizes the cost model inputs provided
in Section 2.
1-4
-------
Site Specific Information Sources
Aerial
Photographs
Energy Information Administration - Form 767
Boiler/Coal Characteristics
Utility Comments and
Other Data Sources
Retrofit Factors
Access/Congestion
Soil and Underground
Flue Gas Ducting
General Facilities
Regional Cost Factors
Scope Adder Costs
Wet to Dry Ash System
Chimney or Liner
Particulate Matter Controls
Boiler/Coal Parameters
Boiler Characteristics
Coal Characteristics
Capacity Factor
PM Control Type/Size
Flue Gas Temperature
Multiplier
\
Dollars
i
Cost Model Inputs
Direct Inputs
Integrated Air Pollution Control System
Cost Model Outputs
1 f 11
Capital Costs 0 & M Costs Annualized Costs Emission Reduction
Figure 1-2. Site-specific cost estimation methodology.
-------
TABLE 1-2. ECONOMIC BASES USED TO DEVELOP THE COST ESTIMATES
Item
January 1985 Value
&
Operating labor
Water
Lime
Limestone
Land
Waste disposal
Electric power
Catalyst cost
19.7
0.60
65
15
6,500
9.25
0.05
20,290
$/person labor
$/l000 gal
$/ton
$/ton
$/acre
$/ton
$/kWh
$/ton
Levelization factors Current dollars'
Operating and maintenance 1.75
Carrying charges 17.5%
Constant dollars
1.0
10.5%
3 Book life - 30 years; Tax life - 20 years; Depreciation method -
Straight line; and Discount rate - 12.5% based on a 6% escalation
for inflation.
k Book life - 30 years; Tax life - 20 years; Depreciation method -
Straight line; and Discount rate - 6.1%.
Note: It is EPA policy to use metric units. English units are used
in this report because they are familiar to readers. Metric
conversion factors are given on page Ixxii.
1-6
-------
1.2 SUMMARY OF COST RESULTS
This section summarizes the site-specific control cost estimates
developed for each boiler evaluated. The number of boilers varied for each
control technology for reasons discussed under each control technology
summary. For example, low N0X burners were not evaluated on cyclone-fired
boilers because this technology is not being developed for cyclone boilers
(slagging combustors were not addressed under this study). For cyclone
boilers and other wet bottom boilers, natural gas reburning (N6R) was
evaluated for NO control.
X
For each control technology, the following three figures are presented:
Capital costs (dollars/kilowatt), levelized annual costs (mills/kilowatt
hour), and cost per ton of acid gas removed (dollars/ton) each plotted
versus the sum of megawatts. The x-axis (sum of megawatts) is the
cumulative sum of the boiler size sorted in order from the lowest to the
highest cost to control. Also indentified on each curve are the 25, 50, and
75 sum of megawatt percent points for the boilers included in the figure.
Each point on the curve represents a specific boiler cost result. The first
point represents the boiler that had the lowest capital cost and unit cost.
The last point represents the boiler that had the highest cost. The curves
turn up sharply because each curve was developed starting with the boiler
having the lowest control cost and ending with the boiler having the highest
control cost. The cost results do not represent the average or cumulative
cost of control.
Each utility section in this report was sent to the appropriate utility
for review concerning the plant information. Costs developed in this report
are based on the general assumptions outlined in Section 2 and may not
represent a particular utility company's economic guidelines. The cost
results are static (not dynamic) and represent a single year in the
1986-1989 period with regard to capacity factor, coal sulfur, and pollution
control characteristics.
1.2.1 FGD Cost Estimates
Figures 1-3 through 1-5 summarize the cost estimates developed for wet
lime/limestone (L/LS) FGD with adipic acid additive for 449 boilers. Two
1-7
-------
700
000
500
400
300
200
100
0
Figure 1—3. Summary of capital cost results for lime/limestone
flue gas desulfurization.
100
90
80
70
60
50
40
30
20
10
0
Figure 1—4. Summary of annual cost results for lime/limestone
flue gas desulfurization.
1-8
-
¦ WET FGO ¦ NSPS
A LOW COST FGD
{No spars absorbers arid
ccirished boiers.)
1i88 CONSTANT DOLLARS
7S% at Total MW y# I
X X I
2 8% of Total MW \ J
— y
_/^r~ ^ 7S%afTot*IMW
\ 30% el Total MW
29% of Total MW
1 [ 1 1 ' 1 1 1 1 1 1 1 I
0 20.000 40,000 60,000 80.000 100.000 120,000
SUM OF MW
-
¦ WETFQD -NSPS
A LOW COST FGD
(No spare absorbers and
combined boiera.j
1988 CONSTANT DOLLARS
I
78% Of Total MW / „
#0% of Total MW V ft* f
38% of Total MW
28%^of Total MW $0% of Total MW 79% of Total MW
I I I I I I I I I 1 l I
0 20,000 40,000 80,000 80.000 100,000 120,000
SUM OF MW
-------
SUM OF MW
Figure 1-5. Summary of cost per ton of SCb removed results
for lime/limestone flue gas desulfurization.
1-9
-------
FGD configurations were evaluated: a conventional New Source Performance
Standard (NSPS) design having a single system for each boiler, small
absorber size, and one spare absorber; and a low-cost design that does not
have a spare absorber, and combined boiler systems when feasible. The
target SOg removal efficiency was 90 percent.
Cost estimates for FGD were developed only for 449 of 631 boilers
because 46 boilers were already equipped with FGD systems, 130 boilers were
burning low sulfur coals (many are 1971 NSPS units), and 6 boilers were too
small or already retired. The percent increase in capital cost for
retrofitting an FGD system over a typical new plant installation ranged from
19 to over 100 percent, with the average being 45 percent. The levelized
annual cost of control (mills/kilowatt hour) is also strongly influenced by
the system size and design (e.g., percent reduction required or conventional
versus low-cost configuration design), and operation (capacity factor and
sorbent/waste disposal costs).
Figures 1-6 through 1-8 summarize the cost estimates for lime spray
drying (LSD) for all the boilers for which costs were developed. Two
control options were considered for the retrofit of this technology: reuse
of the existing electrostatic precipitator (ESP) or installation of a new
fabric filter (FF). Reuse of the existing ESP was not considered for the
following boiler situations:
• when the specific collection area (SCA) of the existing ESP was
2 3 2
small, <43.3 m /actual m -sec or 220 ft /1000 actual cubic feet
per minute (acfm), and
• when the addition of new plate area was impractical (e.g., roof-
mounted ESPs).
In such cases, a new FF was used for particulate control with the spray
drying system. However, if a unit is burning high sulfur coal, use of a new
FF was not considered. Based on the cited criteria, 168 boilers were
considered with a new FF option, and 195 boilers were considered with reuse
of the existing ESPs. The cost of retrofitting new FFs results in a high
retrofit difficulty factor and a high cost of control.
1-10
-------
'400
X
X
w
N
(A
O
O
J
<
H
£
<
a
20,000 40,000 60,000
SUM OF MW
80,000
100,000
Figure 1—6. Summary of capital cost results for
lime spray drying.
3£
X
W
V)
O
o
<
3
z
z
«
i r
20,000
80,000
40,000 60.000
SUM OF MW
Figure 1—7. Summary of annual cost results for
lime spray drying.
1-11
100,000
-------
SUM OF MW
Figure 1-8. Summary of cost per ton of S02 removed results
for lime spray drying.
1-12
-------
1.2.2 Coal Switching and Cleaning
For coal switching (CS), two fuel price differentials (FPDs) were
evaluated: $5/ton and $15/ton. The $5 to $15/ton FPD was assumed to
represent an estimated range for switching to a low sulfur coal.
Figures 1-9 through 1-11 summarize the costs for 329 boilers in the
200 plants for which costs were developed for CS. The cost estimates for CS
are based on $5 and $15/ton FPD. CS was not considered for some units
because either the units already burn a low sulfur coal or the units have
wet bottom boilers that can burn only coals with special ash fusion
properties. The CS cost estimates are highly dependent upon the FPD. The
impacts of particulate control upgrades and coal handling upgrades are
generally small by comparison.
Figures 1-12 through 1-14 summarize the plant cost of physical coal
cleaning (PCC). Of 631 boilers, only 32 were evaluated for PCC because the
coal already is extensively cleaned or the plant is not located at a mine
mouth.
1-2.3 Sorbent Infection Cost and Performance Estimates
Two sorbent injection technologies in active research and development
were evaluated in this study: furnace sorbent injection (FSI) with
humidification and duct spray drying (DSD). Figures 1-15 through 1-20
summarize the cost estimates developed for these technologies. Some boilers
were not considered good candidates for these technologies for the following
reasons:
• FSI and DSD were not considered practical for boilers having an
ESP SCA < 220 ft2/1000 acfm, and
• DSD was not considered if the duct residence time from the
injection point after the air heater to the ESP inlet was less
than 2 sec (<100 feet of duct length).
Only 321 boilers were considered appropriate for DSD, and 289 were
considered for FSI applications. The costs presented for FSI assume 50 and
70 percent SO^ control with humidification.
1-13
-------
0 20,000 40,000 60,000
SUM OF MW
80,000
100,000
Figure 1-9. Summary of capital cost results for coal
switching and blending.
20,000
40,000 50,000
SUM OF MW
80,000
100,000
Figure 1 — 10. Summary of annual cost results for coal
switching and blending.
1-14
-------
SUM OF MW
Figure 1-11. Summary of cost per ton of SO 2 removed results
for coal switching and blending.
1-15
-------
~i i i I i r
2,000 4.000 6,000 8,000
t r
10,000 12,000 14,000
SUM OF MW
Figure 1-12. Summary of capital cost results for
physical coal cleaning.
1988 CONSTANT DOLLARS
f
7S<* of TotilMW . 1
00% et Total MW X I
2i% el Total MW
/—
1 1 1 1 1 1— i 1 r- —i™ i t i i
0 2.000 4,000 ,6,000 8,000 10,000 12,000 14.000-
SUM OF MW
Figure 1-13.
Summary of annual cost results for
physical coal cleaning.
1-16
-------
a
ui
>
o
2
ui
cc
o'
ei
CM
\
w
H
Cfl
O
O
1,200
,000
800
600
400
200
2,000
4,000
6,000
8,000
1 1 r
'0,000 12,000 14,000
SUM OF MW
Figure 1-14. Summary of cost per ton of SO a removed
results for physical coal cleaning.
1-17
-------
*
X
X
m
V)
O
a
<
i-
E
<
o
20.000
40,000 60,000
SUM OF MW
80,000
100,000
Figure 1-15. Summary of capital cost results for
duct spray drying.
£
*
H
tn
O
O
<
3
z
z
<
20.000
40.000 60.000
SUM OF MW
80.000
100.000
Figure 1-16. Summary of annual cost results for
duct spray drying.
1-18
-------
SUM OF MW
Figure 1-17. Summary of cost per ton of S08 removed results
for duct spray drying.
1-19
-------
1988 CONSTANT DOLLARS
J
79%«fToUIMW jJ
\ rS
90% of Total MW
29% of Total MW
\ —
I I I 1 1 I ¦ 1 T— 1
0 20.000 40.000 60.000 80.000 100,000
SUM OF MW
Figure 1-18. Summary of capital cost results for
furnace sorbent injection.
1988 CONSTANT DOLLARS |
7 9% of Total MW /
90% of Tola! MW ~
3 i% of Total MW j
\
! 1 1 1 1 1 1 1 1
0 20,000 40.000 . 60,000 00,000 100,000
SUM OF MW
Figure 1 — 19. Summary of annual cost results for
furnace sorbent injection.
1-20
-------
SUM OF MW
Figure 1-20. Summary of cost per ton of S02 removed results
for furnace sorbent injection.
1-21
-------
1.2.4 Low NCL Combustion
Figures 1-21 through 1-23 summarize cost estimates for application of
low NO burner (LNB) on dry bottom wall-fired boilers (20-55% NQV
A X
reduction), overfire air (OFA) on tangential-fired boilers (10-35% N0X
reduction), and natural gas reburn (NGR) on cyclone boilers (60% N0X
reduction). The unit costs of LNB and OFA are low (<$300/ton of N0X
removed). However, for boilers where NGR is applied, the unit costs are
much higher ($400 to $1100/ton of N0X removed). This is due to the high
cost of natural gas relative to coal (assumed to be a $2 per million
Btu FPD in 1988 dollars). For this study, 228 boilers were candidates for
LNB, 214 boilers for OFA, and 81 boilers for NGR. Some of the boilers were
not considered for low N0X combustion technologies (LNC) because of the
reservations of plant personnel regarding applicability of these
technologies.
1.2.5 Selective Catalytic Reduction fSCRl Cost Estimates
Figures 1-24 through 1-26 summarize the cost estimates for application
of SCR. For most of the units, cold side, tail-end systems were assumed
(the reactor downstream of particulate control or scrubbers). In some
instances due to space availability limitations or the unit being equipped
with a hot-side ESP, a hot side, high-dust system configuration was used
(the reactor is placed between the economizer and the air heater). Use of
the tail-end system minimizes unit downtime, which reduces the uncertainty
of estimating the cost of replacement power, and maximizes the catalyst
life. However, there is a significant energy penalty associated with flue
gas reheating compared to a high-dust system (equivalent to a 120°F reheat).
This cost was not considered in this study because the current version of
the IAPCS model is unable to estimate it. However, the cold side SCR
requires 60 percent of the hot-side catalyst volume. Based on a one year
catalyst life, the reheat and extra catalyst volume costs off set each
other. For this study, 624 boilers were evaluated for SCR retrofit.
1-22
-------
46
40
35
30
25
20
15
10
~ ye
X OFA
¦ NOR
1968 CONSTANT DOLLARS
J
7 8%jOfToUiMW
/ \ 80% ol Total MW 1
jP2S% of Total MW . _/\ J
/ 3?^—\ • J
/—- \ X >f
20,000 40,000
SUM OF MW
60,000
Figure 1-21. Summary of capital cost results for
low NO x combustion.
20,000 40,000
SUM OF MW
60000
Figure 1—22. Summary of annual cost results for
low NO x combustion.
1-23
-------
1.800
o
Ul
>
o
s
ui
tr
o
z
x
«
H
cfl
O
O
I-
z
20,000
40,000
SUM OP MW
60,000
Figure 1-23. Summary of cost per ton of N0X removed
results for low NOx combustion.
1-24
-------
280
\
»
W
o
Q
<
N
H
<
O
200
® "1 i i i i i i i i i i i i i i i i 1 i i r
0 2CMX>0 00,000 100,000 140.000 180.000
SUM OF MW
Figure 1-24. Summary of capital cost results for
selective catalytic reduction.
M
a
J-
v>
O
O
z
<
-i—i—i—r
0 20,000 60.000
i r—i 1 1 r—r
140,000 180,000
SUM OF MW
Figure 1-25. Summary of annual cost results for
selective catalytic reduction.
1-25
-------
1988 CONSTANT DOLLARS
78% at Total MW
X
¦0% of Total MW
X
28% of Total MW
^
3 YEAH CATALYST LFE
—I 1 1 1 1 1 1 1 1 I 1 1 1 1 1 1 1 1 1—
0 20.000 40.000 60,000 80.000 100.000 120.000 140.000 160.000 180,000 200.000
SUM OF MW
Figure 1-26. Summary of cost per ton of NOx removed results
for selective catalytic reduction.
1-26
-------
1.3 CONCLUSION
For each of the S02 and N0X control technologies evaluated under this
study, different factors affected control cost and performance estimates for
retrofit applications at coal-fired boilers. Table 1-3 identifies those
factors found to have the most significant effects. For the L/LS-FGD
technologies, site access/congestion and flue gas ducting distances were
major factors. For LSD-FGD, the need to add new particulate control was
also a major consideration.
For CS and PCC, the major retrofit factors, excluding FPD, were
particulate control upgrade costs and boiler performance impacts. CS for
wet bottom boilers and switching from a bituminous coal to a subbituminous
coal were not evaluated because boiler performance impacts are likely to be
significant.
For the sorbent injection technologies, FSI and DSD, particulate
control upgrade costs would have the greatest impact. Additionally,
sufficient duct residence time must be available for DSD to guarantee good
droplet drying.
For the LNC and NGR technologies, boiler type and configuration are
important factors. LNB was applied only to dry bottom, wall-fired boilers.
OFA was applied only to tangential-fired units. NGR was applied to wet
bottom boilers and other miscellaneous boiler types. Boiler heat release
rates and residence times in different furnace zones would have significant
effects on N0X removal efficiency for LNC and NGR technologies.
SCR costs would be greatly affected by access and congestion near the
economizer area for hot side applications. For the cold side applications,
access and congestion near the chimney area and flue gas ducting distances
greatly affect costs. For cold side systems, the energy penalty for flue
gas reheat is balanced by increased catalyst life and reduced catalyst
costs. For hot side systems, boiler downtime costs and catalyst life would
be significant cost and performance factors.
The cost and performance information presented is a realistic guide
regarding the degree of retrofit difficulty for each control option
evaluated. However, as noted in Table 1-1, the technologies evaluated in
this study are at various stages of commercial development. There is a
1-27
-------
TABLE 1-3. RETROFIT FACTORS AFFECTING COST/PERFORMANCE
Control
Technology
Access and
Congestion
Ducting
Di stance
Additional
Particulate
Control
Boiler
Type
Boiler
Configuration
Lime/Limestone
Flue Gas
Desulfurization
X
X
Lime Spray
Drying
X
X
X
Coal
Switching/Blending
X
X
Physical Coal
Cleaning
X
X
Furnace Sorbent
Injection
X
Duct Spray
Drying
X
X
Low NO
Combustion
X
sx
Natural Gas
Reburning
X
X
Selective
X
X
X
Catalytic
Reduction
1-28
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higher degree of uncertainty regarding the cost/performance for those
technologies that do not have extensive commercial application in the United
States. Therefore, no attempt has been made in this study to identify a
best option for each plant/boiler.
Additionally, a utility company's decision concerning which retrofit
control to apply to a given boiler is very complex. A list of
considerations used in making such a decision include the following:
• system reduction target and degree of flexibility regarding means
to achieve the target,
• current and future load pattern for each boiler with or without
controls,
¦ cost of purchased power and planned new capacity,
• cost of capital and current/future financial strength, and
• public utility commission and state/regional regulatory agency
attitudes.
The data contained in this report can be used to facilitate selection of
least-cost control options for specific plants/boilers for planning
scenarios that address the above decision criteria.
The cost results for all the technologies presented in this report are
available in three DBase III+ files and can be obtained through the National
Technical Information Service (NTIS). Disks 1 and 2 are high density
diskettes which contain the following: plant name, technology, boiler
number, capacity in megawatts, capacity factor, removal efficiency for both
SOg and NO^, tons of SOg removed per year, tons of N0x removed per year,
capital cost in dollars, annual cost in dollars, dollars per kilowatt, mills
per kilowatt hour, dollars per ton of S02 removed and dollars per ton of NQX
removed. Disk 1 is in current 1988 dollars and disk 2 is in constant 1988
dollars. Disk 3 contains a third DBase file (200.DBF) with general plant,
boiler and company information based on Department of Energy Form 767 data.
It also contains an ASCII file (README.ASC) with a list of abbreviations
used in all three database files. The cost result database can be used to
estimate total costs and emissions for individual or combined control
technologies for the 200 plants presented in this report.
1-29
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1.4 REFERENCES
1. Emmel, T. E., S. D. Piccot, arid B. A. Laseke. Ohio/Kentucky/TVA
Coal-Fired Utility SOg and NOx Control Retrofit Study.
EPA-600/7-88/014 (NTIS PB88-244447/AS), U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, 1988.
2. Elliot, T. C., ed. Powerplants Database, Details of the Equipment and
Systems in Utility and Industrial Powerplants, 1950-1984.
McGraw-Hill, Inc., New York, New York, 1985.
3. Palmisano, P. J., and B. A. Laseke, User's Manual for the Integrated
Air Pollution Control System Design and Cost Estimating Model, Version
II, Volume I. EPA-600/8-86-03la (NTIS PB87-127767), U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina, 1986.
4. Shattuck, D. M., et al. Retrofit FGD Cost Estimating Guidelines. EPRI
Report CS-3696, Electric Power Research Institute (EPRI), Palo Alto,
California, 1984.
1-30
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2.0 DESCRIPTION OF THE NEW SIMPLIFIED RETROFIT FACTOR
AND COST ESTIMATION PROCEDURES
This section describes the simplified procedures used in this study to
estimate the cost and performance of retrofitting S02 and N0X controls on
188 coal-fired power plants. An additional 12 plants were evaluated by
detailed procedures in a previous study (1). The simplified procedures are
a result of streamlining the more detailed procedures used in this previous
study. The procedures adjust the Integrated Air Pollution Control System
(IAPCS) (2) model algorithms for retrofit situations because the model cost
algorithms do not reflect the cost and performance impacts of retrofitting
controls.
To adjust the IAPCS cost estimates, retrofit factors and scope adder
costs were developed for each of the control technologies to reflect
site-specific control costs. Additionally, for the LNC modifications,
performance estimates were developed to account for non-ideal situations
that will occur with the retrofit of these control technologies.
The Electric Power Research Institute (EPRI) "Retrofit FGD
Cost-Estimating Guidelines" report (3) was used to develop retrofit factors
and scope adder costs for L/LS-FGD and LSD-FGD. To the extent possible, the
information and methodology contained in the EPRI guidelines were used for
the other technologies (excluding LNC technologies). Retrofit factors
adjust cost model process area costs to reflect the cost impacts of:
• site access and congestion,
• soil conditions and underground obstructions, and
• distances between process areas.
Scope adder costs adjust cost model estimates by adding additional
equipment costs due to retrofitting the control system that were not
addressed in the cost model algorithms. Typical scope adder costs that are
not included 1n the cost algorithms for new plant control systems or in
retrofit control system base costs include:
• chimney liner or new chimney,
• boiler reinforcement or draft controls,
2-1
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• demolition/relocation of existing facilities,
• additional particulate control facilities,
• conversion of wet ash handling systems to dry systems,
• existing equipment modifications, and
• air heater modifications/replacement.
For many of the technologies, scope adder costs and retrofit factors
were not applicable or had already been included in the cost algorithm
assumptions. The applicability of these retrofit issues for each technology
is briefly discussed for each specific technology. Table 2-1 summarizes the
retrofit factors and scope adder costs that were addressed for each of the
control technologies evaluated under the program. Section 2.1 describes the
procedures used to develop the retrofit difficulty factors, scope adder
costs, and performance estimates for LNC modifications. These values were
then input to the IAPCS cost model.
The retrofit of fluidized bed combustion (FBC) or coal gasification
(CG) with gas turbine and reuse of the existing unit steam turbine was
evaluated qualitatively. No cost estimates were developed because the
application of these technologies is heavily weighted toward the economic
benefits of life extension and heat rate improvements. The evaluation
criteria used to qualitatively assess the potential for each boiler as a
candidate for FBC or CG retrofit are also described in Section 2.1.
Section 2.2 describes the IAPCS model application for each of the
technologies evaluated. Section 2.3 describes the economic and financial
assumptions used to develop the control technology cost estimates.
2.1 RETROFIT FACTORS AND SCOPE ADDER COSTS
This section explains the retrofit factor and scope adder costs
development procedures in more detail. The procedures for all technologies
were based primarily on the EPRI Retrofit FGD Cost Estimating
Guidelines (3). Scope adder costs for conversion of wet ash handling
systems to dry systems and existing equipment modifications (improvements to
rail spurs and coal handling systems) were taken from other references and
2-2
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TABLE 2-1. RETROFIT COST AND PERFORMANCE INPUTS TO IAPCS8 MODEL
Performange
Control Technology Estimates
Retrofit Factors Addressed
Access and.
Congestion
Underground
Obstruct ions
Process
Area
Distance
Scope Adder Costs Addressed
Chimney Demolition Additional Wet to
or and Particulate Dry Ash
Liner Relocation Control Handling
Lime/Limestone Flue
Gas Desulfurization
Lime Spray Drying
Coal Switching
Physical Coal
Cleaning
ro
CO
Furnace Sorbent
Inj ect ion
Duct Spray Drying
Lou NO Combustion
x
Natural Gas
Reburning
Selective Catalytic
Reduction
a
IAPCS = Integrated Air Pollution Control System (2).
b
Made using procedures not included in IAPCS model.
c
For particulate control retrofits.
d K
Additional particulate control may be required in some applications to prevent catalyst poisoning.
-------
are not addressed in the EPRI procedures. Scope adder costs for particulate
control system upgrades, flue gas humidification, and new particulate
controls are based on IAPCS cost algorithms.
Repowering of older boilers for combined life extension and S02/N0x
control is handled qualitatively under this effort. Characteristics that
could make a particular boiler/turbine a good candidate for being replaced
with FBC or CG technologies are briefly discussed. In this study, it was
assumed that the existing steam turbine and most other plant, facilities
would be reused with the retrofit of FBC or CG.
2.1.1 Lime/Limestone and Lime Spray Drying Flue Gas Desulfurization
This section describes the procedures used to estimate L/LS and LSD-FGD
costs using simplified procedures developed from the 12-plant Ohio/Kentucky/
TVA study (1). The 12-plant study used with minor modification the detailed
procedures found in EPRI Retrofit FGD Cost Estimating Guidelines Report (3).
Detailed studies are expensive and time consuming due to the need for site
visits to obtain the data needed to conduct the analysis. Therefore, the
results of the 12-plant study were used to develop simpler procedures which
used publicly available data (aerial photograph and Energy Information
Agency 767 form). The simplified procedures were used to evaluate 50 plants
from which 6 plants were visited and reevaluated using the detailed
procedures. The results from the detailed and simplified procedures were
compared and the differences were analyzed. Only minor adjustments were
found to be required to make the simplified procedures more accurate. The
results of this effort are documented in EPA report Verification of
Simplified Procedures for Site-Specific SO^ and NOx Control Cost
Estimates (4).
2.1.1.1 Description of Simplified Procedures--
The simplified retrofit factor estimating procedure is an eight-step
process. To estimate retrofit factors for L/LS or LSD-FGD using these
procedures, a plot plan and/or aerial photograph of the plant must be
available.
2-4
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A brief description of each of the FGD retrofit estimating procedure
steps follows:
Step 1: Identify on the plot plan or aerial photograph the best location
for the absorbers/spray dryers. Select an access/congestion rank for that
area using the EPRI guidelines summarized in Table 2-2 where
base - 45 ft^/MW, low = 35 ft^/MW, medium = 30 ft^/MW, and high = 25 ft^/MW.
Step 2: Estimate the flue gas ductwork tie-in inlet and outlet length.
Select from one of the following duct-length classifications (in feet):
0 - 100
100 - 300
300 - 600
600 - 1,000
1,000 and greater
Step 3: Assign an access/congestion rank (base, low, medium, or high) to
the inlet and outlet ductwork using EPRI guidelines summarized in Table 2-2.
Step 4: If a new chimney is added, estimate the flue gas ducting, select
the duct length classification, and include the new chimney as a scope adder
cost. If an existing chimney is reused, include the cost of a chimney liner
as a scope adder cost. It is usually less expensive to install a new chimney
if more than 400 feet of duct runs can be saved by not returning to the
existing chimney.
Step 5: If the existing ESP fly ash handling system is a wet sluice system,
include the conversion of the wet system to a dry system as a scope adder
cost. This conversion is necessary to stabilize the FGD sludge for the
conventional l/LS-FGD case and to prevent plugging of the sluice lines in
LSD with reuse of the existing ESP case. This conversion is not necessary
for forced oxidation L/LS-FGD. The cost for converting the wet fly ash
handling system to a dry ash handling system is based on an EPA study
(5) and includes the addition of pneumatic conveying equipment and an ash
silo.
Step 6: For the LSD-FGD case, assign a particulate control access/
congestion factor for reuse of the existing ESP or new baghouse locations as
presented in Table 2-2.
2-5
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TABLE 2-2. SUMMARY OF THE GENERAL FACILITIES FACTORS AND ACCESS/CONGESTION GUIDELINES USED IN THE EPS I RETROFIT
FGD COST ESTIMATION GUIDELINES (3>
Site Accessibility and Congestion
a. BASE CASE • Interferences similar to new plant with adequate crew work spact. Free access for large cranes
and equipment around boiler and stack adequate for standard layout scrubber equipment.
b. LOW CASE - Some above-ground interferences and limited work space. Access for large cranes limited to two
sides; equipment cannot be laid out in standard design. Some equipment must be on elevated slabs or located
remotely.
c. medium CASE - Limited space. Interference with existing structures or equipment that cannot be relocated.
Special designs are necessary. Access for cranes limited to one side; majority of equipment on elevated
slabs or remotely located.
d. high CASE - Severely limited space and access. Crowded working conditions. Access for large cranes blocked
from all sides.
General facilities
a. BASE CASE - Assume one road will have bo be rerouted and necessary drainage will be considered.- The
existing laboratory must be augmented. A warehouse structure must be constructed (use 5 percent).
b. MEDIUM CASE-- A major paved road will have to be built along with the necessary area drainage. A new
laboratory, office building, and a warehouse must be constructed (use 10 percent).
c. HIGH CASE • The utility will need to construct a complex road due to interferences with the FGO equipment.
New laboratories, an office building, warehouse, and machine shops will be needed. The utility has
purchased new land; the fence and roads for that area will need to be developed (use 15 percent).
Engineering and Home Office Fees
a. BASE CASE - do major underground obstructions and adequate load-bearing soils in seismic zone 1 (use 10
percent).
b. HEPIOH CASE - HadiLm underground obstructions or low load-bearing soils in seismic lone 3 (use 12 percent).
c. HIGH CASE - High underground obstructions and low load-bearing soils in seismic zone 3 (use 15 percent).
2-6
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Step 7; Include other scope adder costs such as the costs associated with
rerouting roads, relocation of warehouses and other structures, and the
development of new land (e.g., new roads, drains, and fences) by adjusting
the general facilities factors. Table 2-2 presents the general facility
percentages to use based on the additional scope adder needs.
Step 8: Adjust engineering and home office fees also from 10 to 15 percent
depending on underground obstructions and soil conditions. Table 2-2
summarizes the criteria for selecting the engineering/home office fees.
Using the simplified procedures described above, the following FGD
retrofit factors were developed and used in the IAPCS model for each
control case evaluated:
• Control System Overall Retrofit Factor,
• New Baghouse Retrofit Factor (LSD-FGD only),
• ESP Upgrading Retrofit Factor (LSD-FGD only),
• General Facilities Factor, and
• Engineering and Home Office Fees.
2.1.1.2 Development and Testing of the Simplified Procedures--
The simplified retrofit factor and scope adder cost estimating
procedures resulted from a two-step simplification of the detailed EPRI
procedure guidelines. The first simplification step was to eliminate
developing process factors used in the EPRI procedures. Because the IAPCS
cost model internally accounts for process adjustments (e.g., coal sulfur
content and unit size), such factors were not needed as part of the retrofit
factor process.
In the second step of the simplification process, the major retrofit
factor "drivers" were identified. The overall retrofit factor was divided
into the following two separate components:
• process area retrofit factor (cost multiplier) and
t scope adjustments (scope adder costs).
Each component was evaluated and simplified separately as discussed below.
How the two components are combined to form the overall retrofit factor is
discussed later.
2-7
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Process Area Retrofit Factor
In the detailed EPRI procedures, the process area retrofit factor
reflects the retrofit difficulty associated with installing the five FGD
process areas included in L/LS and LSD-FGD systems: sorbent preparation,
absorbers/spray dryers, flue gas handling systems, waste handling/disposal
facilities, and general support equipment. An evaluation of the cost of
these five process areas Indicates that the absorber and the flue gas
handling areas generally represent over 80 percent of the total FGD system
capital cost for a given boiler. Therefore, only the retrofit difficulties
associated with the absorber and flue gas handling process areas were
estimated. The site access/congestion factors associated with the two areas
(base, low, medium, or high) are weighted according to the approximate
percent of total capital cost represented by each process area. The sum of
the two weighted retrofit difficulties and the duct tie-in distance form the
basis of the process area retrofit factor in the simplified procedure.
For waste handling systems, a low access/congestion factor was assigned
because these subsystems are generally located away from the powerhouse in
areas with relatively good access and little congestion. For the sorbent
preparation and general support equipment areas, the access/congestion rank
assigned to the absorber area (base, low, medium, or high) was assigned to
these two areas as well. This is consistent with the results of the
previous study (1) where the rankings for sorbent preparation and absorbers
were generally the same.
A test of the approach discussed above was conducted to evaluate its
accuracy relative to the detailed EPRI procedure results from the 12-piant
study (1). The results of this comparison appear in Figure 2-1. As shown,
the process area retrofit factors developed using the two different
procedures are in close agreement for most boilers. Figure 2-2 shows that
the percent difference between the two procedures is generally less than
±5 percent.
2-8
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1.6
1.5
-------
Scope Adjustments
The second part of the overall retrofit factor development addresses
scope adjustments or adder costs. These are costs for equipment or other
items not included in IAPCS. The most common scope adjustments include the
following:
• chimney liner (L/LS-FGD only),
• new chimney,
• demolition/relocation (buildings, electrical, ducts, and
plumbing),
• draft controls (to prevent boiler pressure surges),
• wet to dry fly ash handling system conversion, and
• new rails/repair existing rails.
Some of these scope adjustments will frequently be required when
retrofitting FGD systems. The scope adjustments that occur frequently are
shown in Table 2-3 with their estimated impact on capital cost and the
overall retrofit factor. The simplified procedures assume these adder costs
are always required unless specific information for a given site becomes
available that indicates that any one of these items is not necessary.
For L/LS-FGD, a value of 0.09 is added to the retrofit factor to account for
the adder costs listed above (chimney liner, demolition and relocation,
draft control, and new rails). For LSD-FGD, the value added is 0.04 because
chimney liners are not necessary.
The simplified procedures allow the user to select specific additional
scope adjustments (i.e., new chimney or wet to dry ash system) based on the
site-specific needs of the plant under evaluation. Table 2-3 presents the
contribution to the overall retrofit factor for these scope adjustments. If
a new chimney is added, the cost to reline the existing chimney is not
included.
Evaluation of EPRI costs indicates that if 400 feet or more of ductwork
can be eliminated for any boiler examined, a new stack would be added as a
scope adjustment and costs for duct tie-in would be appropriately reduced.
2-10
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TABLE 2-3. SCOPE ADJUSTMENTS AND THEIR CONTRIBUTION
TO THE OVERALL RETROFIT FACTOR
Estimated Estimated
Percentage of Contribution
Adjusted to the
Item Process Area Cost Retrofit Factor
Most Common Adjustments
Chimney Liner (L/LS only)
Demol ition/Re "location
Draft Controls
New Rails
Other Adjustments
Wet to Dry Ash Systems
New Chimney
5 0.05
2 0.02
1 0.01
<1 <0.01
7 0.07
7 0.07
2-11
-------
This would likely be done for many units with roof-mounted chimneys or when
the absorber or new FF area had to be located more than 500 feet away from
the existing chimney,
2.1.1.3 Accuracy of the Simplified Procedures--
The overall retrofit factor is calculated from the process area
retrofit factors and the scope adjustment factors described in the previous
two sections. The same comparison conducted for the process area retrofit
factor discussed earlier was also conducted for overall retrofit factors
estimated using the new simplified and the detailed EPRI procedure results.
The results of this comparison are illustrated in Figure 2-3. As the figure
indicates, overall retrofit factors from the new simplified procedures
compare well with overall retrofit factors using the detailed EPRI
procedures (points on the straight line plotted at 45 degrees represent a
perfect correlation). The average difference between the detailed and
simplified procedures is 3.7 percent.
2.1.2 Sorbent In.iection Technologies
These technologies are in various stages of research and development
and are being developed specifically for retrofit. As such, many costs of
retrofit are built into the costs algorithms. The IAPCS model cost
algorithms for furnace sorbent injection (FSI) with humidification and duct
spray drying (DSD) with calcium-based sorbents were used in this study. The
focus of this study was to identify retrofit modifications and scope adder
costs needed for each specific site. These include major particulate
control upgrades, conversion of wet fly ash handling systems to dry systems,
and demolition/relocation of existing equipment.
Of particular importance to the cost of all the technologies is the
ability to upgrade the existing particulate control device. The IAPCS model
assumes that the benefits of humidification makes most ESPs candidates for
reuse. However, most boilers that have ESPs with specific collection areas
(SCAs) less than the 220 square feet per 1000 actual cubic feet per minute
3
(acfm), (1000 acfm - 28 actual m /min) of flue gas are not good candidates
2-12
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h
o
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2.2
DETAILED RETROFIT FACTOR
Figure 2-3. Comparison of the retrofit factors for the detailed EPRI and
new simplified procedures.
2-13
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for sorbent injection. These ESPs are often old and usually situated in
areas with limited access making plate area addition difficult. Also, many
of these boilers have short duct residence time between the air heater
outlet and the ESP, making the application of humidification or DSD
technically infeasible. Although construction of additional ductwork could
make the application of sorbent injection technologies possible, this was
not considered in this study.
Although access/congestion factors were developed for the sorbent
preparation/receiving areas, these factors were not used except for plants
where a high value was assumed. It was felt that the large project
contingency used for these technologies adequately covered average access/
congestion situations and sorbent conveying distances (500-1500 feet).
Retrofit factors and scope adder costs are based on the EPRI retrofit FGD
cost estimating guidelines for the LSD-FGD technology sorbent
preparation/flue gas handling process areas and building/duct demolition
costs.
The following sections describe the procedures used to identify the
sorbent injection option evaluated and to develop the FSI/DSD process area
and particulate control upgrade retrofit factors and scope adjustments.
Using these procedures, the following data were input to IAPCS: FSI/DSD
process area retrofit factor, particulate matter (PM) control retrofit
factor, and scope adder costs in dollars.
2.1.2.1 Process Selection--
As discussed above, the existing particulate control system type/size
and flue gas ducting configuration are important parameters impacting the
cost/performance of the sorbent injection technologies. The following steps
were used to select the technologies to be evaluated.
Step 1: From the plot plan/aerial photo and data from EIA-767, the existing
particulate control type, size, and flue gas ducting configuration are
determined.
2-14
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Step 2: The sorbent injection technologies were evaluated for units with
over 100 feet of duct distance between the air heater and PM control and SCA
of over 220. When the above criteria are met, cost/performance estimates
are presented for sorbent injection technologies.
2.1.2.2 Process Area and PM Control Access/Congestion Factor--
The following steps were used to develop access/congestion retrofit
difficulty factors for FSI/DSD process areas and PM control area.
Step 1: Using the plot plan or aerial photograph, the sorbent receiving and
preparation area is located. The plot area need is sized using the
following equation;
Area (ft2) = boiler size (MW) * 27
2
The value of 27 ft /MM is based on actual FGD system sorbent preparation
area data.
Step 2. An access/congestion rank for the sorbent preparation area is
selected from Table 2-2 (base, low, medium, or high).
Steo 3. An access/congestion rank is selected for the ESP from Table 2-2,
If ESP plate addition is needed, this factor adjusts the new plate area
capital cost estimated by 1APCS.
The FSI (with no humidification) and DSD technologies have three basic
process areas; the total capital cost contributions for each of these
process areas are as follows:
• reagent preparation, 60 percent,
• duct modifications, 10 percent, and
• recycle/waste disposal, 30 percent.
Because it is clear that the sorbent preparation area has the greatest
impact on cost, the access/congestion factor for the sorbent preparation
area has the most pronounced impact on the FSI and DSD retrofit factor. As
such, this is the only process area where a site-specific access/congestion
factor was selected. Factors for the other two areas were assumed based on
2-15
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the previous study results (1). After selecting the access/congestion rank
for the sorbent preparation area, the factors for each process area were
weighted according to their contribution to the total capital cost shown
above. These weighted factors were then sunned up to yield the overall
process retrofit factor. The access/congestion ranks assigned to the duct
and waste disposal area are summarized below.
• A low access/congestion factor was always assigned to the waste
disposal recycle area because these systems can be located
conveniently at a distance from the ESP/chimney area.
• A medium access/congestion factor was assigned to duct
modifications.
« A low underground obstruction factor was assigned to all
process areas.
2.1.2.3 Scope Adder Costs--
The costs for equipment that are not included in the IAPCS model cost
assumptions for DSD and FSI were added to the model as scope adder costs.
The following scope adder costs were used for DSD and FSI;
t conversion of ESP wet ash-handling system to a dry handling/
storage system,
• additional ductwork, and
• duct demolition.
If necessary, the cost for converting the ESP ash discharge system from a
wet to a dry system was calculated using the following equation:
cost ($) = 0.0151 * (MW)0-8965 * 106
where MW = unit size, in megawatts
This cost is based on an EPA report (5) and includes the cost of
pneumatic conveying equipment and an ash silo. However, dry ash handling
systems are generally less reliable than wet systems and may require more
2-16
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maintenance. For any additional ductwork required, the following equation
from the EPRI Retrofit FGD Cost Estimating Guideline Report (3) was used:
cost (S) - 0.306 * duct length * (MW)0,585 * 1000
The ductwork cost is adjusted for boiler size based on EPRI process factors.
A regression analysis was used to fit the EPRI process factor curve for flue
gas handling cost versus boiler generating capacity (represented by the
final term in the above equation).
For the duct demolition cost, the EPRI procedures were also used to
estimate this cost as follows:
cost {$) = 1800 * demolition length (MW/500)0-75
2.1.3 Coal Switching and Cleaning
In evaluating the cost impacts of CS and cleaning at a plant, more
retrofit issues need to be addressed in addition to fuel cost differentials.
These include the cost of new/upgraded coal receiving, storage, and handling
facilities; boiler operating impacts (capacity, slagging, fouling, erosion,
etc.); and ESP impacts. For all plants, ash analysis, washability data, and
grindability data were not available. As a result, a quantitative analysis
of boiler impacts and coal cleaning cost effectiveness could not be
conducted. As such, only switch coals that were similar to the existing
coals were considered. No boilers firing bituminous coals were switched to
a subbituminous coal or lignite.
ESP performance is affected by reducing the coal sulfur content and
changing ash loading and ash resistivity. The IAPCS model estimates the ESP
plate area needed for particulate control after CS and cleaning and also
estimates the cost of S03 conditioning if any additional plate area is
needed. It is assumed that SO^ conditioning will reduce needed plate area
by 25 percent. If additional plate area is required after application of
SOg conditioning, an ESP access/congestion factor developed using the EPRI
retrofit guidelines is applied to the cost of plate area addition.
2-17
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For boilers that have small ESPs (<250 SCA), adding plate area may be
difficult and unlikely because of limited access and site congestion. For
these situations, common industry practice is to build new ESPs or install
FFs and to abandon old ESPs. This ensures compliance with particulate
emission regulations for the typical range of operating situations
encountered due to variable boiler/operating conditions and coal properties.
2.1.4 Fluidized Bed Combustion and Coal Gasification
Plant life extension combined with significant emission reductions can
be achieved by FBC (atmospheric or pressurized) or CG with a gas turbine.
This can be a cost-effective approach for some utility systems if the
existing turbine and other plant facilities can be reused. A qualitative
evaluation of this emission control strategy was conducted under this study
for some of the plants. A more detailed analysis was not conducted because
extensive boiler/plant/system information is needed to evaluate the cost of
retrofit. The economic justification for these retrofits is critically tied
to life extension and heat rate improvements rather than to emission
reductions. Thus, economic comparison to the other add-on controls
evaluated in this study is difficult without conducting extensive
system-wide economic evaluations.
As defined in this study, repowering with FBC and CG assumes that the
new stand-alone FBC boiler or CG unit with a gas turbine will tie into the
existing steam turbine and with reuse of the other plant facilities, e.g.,
coal receiving/handling/storage, water and wastewater treatment, and solid
waste disposal. With FBC, it is possible to rebuild (retrofit) the existing
boiler as was done at the Northern States Power Black Dog Unit 3 (6).
For each plant, the following criteria were reviewed to determine the
potential for each boiler as a FBC or CG retrofit/repowering candidate:
Boiler Size - Boilers larger than 300 MW were not considered good near-term
candidates for repowering because of the relatively small size of the FBC
and CG units currently being demonstrated and because boilers larger than
300 MW generally do not meet the other criteria that follow.
2-18
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Boiler Heat Rate - Boiler heat rate has a significant economic impact on
retrofit for FBC or CG, as follows: units with a heat rate of <10,000 Btu
per kW/hr would not benefit significantly; units with a heat rate of 10,000-
11,000 Btu per kW/hr would benefit moderately; and units with a heat rate
>11,000 Btu per kW/hr would benefit significantly.
Boiler Capacity Factor - Boilers with capacity factors significantly less
than 50 percent usually are used for meeting peak demands. These boilers
generally have poor heat rates and, as such, are low on the dispatch order.
Retrofit or repowering with FBC or CG generally will require significant
downtime, and the downtime penalty will be less for boilers having low
capacity factors.
Unit Age - Unit age generally is an indicator of boiler size and useful
remaining life. Boilers that came in service before 1950 are small
(<100 MW) and have poor heat rates and low capacity factors. These units
are good candidates for retrofit/repower1ng and would significantly benefit
from heat rate improvement. Additionally, the cost of FGD would be high due
to economies-of-scale, capacity factors, and the short remaining life for
amortization of the capital investment. Units that came in service in the
1950s are generally small to medium in size (100-250 MW) and have moderate
heat rates and low to moderate capacity factors. These units are moderately
good candidates for retrofit/repowering depending on the cost of other
control options. Units that came in service after 1960 are not likely near
term candidates for FBC or CG repowering because of their large size (>250
MW) and remaining life would make other control options more cost effective.
Particulate Control Performance - Because of increasingly stringent
particulate and SOg emission limitations related to state implementation
plans, many boilers have been retrofitted with new particulate controls
capable of meeting particulate emission standards while firing low sulfur
coals (<1 percent sulfur). These boilers may already be firing low sulfur
coals, or the retrofit particulate controls may have been designed for
firing low sulfur coals. As such, these boilers are good candidates for CS
and cleaning, but less likely candidates for repowering with FBC or CG
unless fuel price differentials or stringent SOg/NO emission regulations
eliminate CS and blending as a feasible S02 control option.
2-19
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SO^/NO^ Emission - Many older boilers are high emitters of SO^ and N0X> and
depending on the compliance flexibility that potential acid rain regulation
may allow {regional, state, plant, or boiler) significant emissions
reduction may be required. If these boilers are difficult to retrofit with
conventional and low-cost SOg/NO^ controls, repowering with FBC or CG may
become necessary to extend the life of the boiler and meet SOg/NC^ emission
levels economically. For example, many cyclone boilers made in the 1950s
have high N0X and SOg emission rates with moderate to high capacity factors
and may be difficult,to retrofit for conventional SQ^/NQ^ controls.
2.1.5 NQ^ Controls
Three types of LNC control technologies were evaluated under this
study. LNC was evaluated for all dry bottom boilers with application of LNB
on wall-fired units and OFA on tangential-fired units. For wet bottom
boilers and unconventional firing types, natural gas reburn (NGR) was
evaluated because the application of LNB was not considered feasible and the
application of OFA was not considered to give low enough emission rates.
Selective catalytic reduction (SCR) was evaluated for all boilers and is the
only commercially demonstrated control method for achieving very low NO
/\
emission levels.
For the LNC controls (LNB and OFA), performance estimates were
developed to account for non-ideal situations that will occur with the
retrofit of these technologies. As discussed below, the NO reduction
A
estimates are based on the boiler volumetric heat release rate. No
adjustment to costs were made to reflect site-specific situations. For NGR,
a N0X reduction of 60 percent was assumed for all boilers.
There are two SCR configurations which have wide commercial application
in Europe and Japan: hot side and cold side. Hot side systems have the
catalytic reactor located before the air heater in the temperature zone of
600-700°F. Cold side systems have the catalytic reactor located after the
air heater and must reheat the flue gas up to 600°F. During the course of
this study, very limited data was available on the long,term performance of
hot side SCR systems on coal-fired applications, and no commercial or pilot
scale data was available on hot side systems for U.S. coals. As such, the
2-20
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cold side SCR system was selected due to the greater degree of confidence
regarding catalyst life because cold side systems would be located
downstream of particulate and S0X control systems. This reduces or
eliminates the catalyst poisoning effects of sulfur (SO^), chlorides,
arsenic and alkali metals which are found to higher degree in U.S. coals
than experienced overseas. Additionally, less unit downtime would be
required to tie the system into the existing flue gas flow minimizing
potential unit downtime costs associated with replacement power. The
disadvantage to using cold side SCR systems results from the capital and
economic cost of flue gas reheat. These costs are somewhat offset by lower
catalyst costs. . For boilers where there was not space available for a cold
side SCR system and boilers having hot ESPs, hot side SCR systems were
applied.
2.1.5.1 Low N0x Combustion Performance Estimating Procedures--
This section describes the simplified procedures that were used to
determine the N0X reduction performance due to retrofitting OFA on
tangential-fired boilers and LNB on wall-fired boilers. LNC is not
considered as applicable to wet bottom boilers such as cyclones. These
procedures were developed to reduce the" amount of time needed to evaluate
each of the 200 utility plants in the absence of detailed boiler design and
operating data (e.g., boiler drawings and operating profiles). The
simplified procedures for LNB on wall-fired boilers use available data from
Powerplants Database (7), the EIA-767 forms, and other available sources
to estimate N0X reductions. The simplified procedures for OFA on
tangential-fired boilers rely on established guidelines for utility
boilers (8-9).
Simplified Procedures for Estimating NCL Performance of LNBs Applied to
Wall-Fired Boiler Development and Description
A number of boiler parameters were evaluated as key indicators of N0x
reduction performance for the simplified procedures. However, accurate data
on most of these parameters can not be easily gathered and/or calculated
2-21
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from readily available sources (i.e., Powerplants Database and EIA-767
forms). Additionally, there is very little well documented data on the
performance of LNC retrofit on a wide range of utility boilers. Boiler
volumetric heat release rate was chosen as an indicator of N0X formation
because boiler volume data are available for most boilers in the Powerplants
Database (7). Based on data from four LNB retrofits, a correlation was
developed expressing N0X emission reduction as a function of boiler volume
per megawatt (volumetric heat release rate).
Insufficient data are available for retrofits of OFA on tangential
boilers. Therefore, an even simpler relationship was developed for
estimating N0x reductions as a function of the volumetric heat release rate.
The correlations developed for estimating N0X reduction performance are
discussed below.
Description of the LNB Performance Estimating Procedures
The following equation was developed to predict NO removal efficiency
A
for low N0X burners applied to wall-fired boilers as a function of boiler
volumetric heat release rate (8);
NOxEFF = 68.8 * (V/MW) [A]
where NO EFF = NO removal efficiency (percent)
XX <2
V = Furnace volume (1000 ft )
MW = Boiler rating (megawatts)
Although this equation can yield N0X reduction values less than 30 percent
and greater than 51 percent, 30 and 55 percent were used as lower and upper
limits in this study.
If the furnace volume cannot be estimated or is not known, the
following equations relating furnace volume to boiler rating were used for
boilers constructed before and after the 1971 NSPS (8):
2-22
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For boilers constructed before the 1971 NSPS, V = 0,596 * MW [B]
For boilers constructed after the 1971 NSPS, V - 0.844 * MW [C]
Therefore, substituting either Equation B or C into Equation A for furnace
volume gives roughly a 40 percent N0X removal efficiency for wall-fired
boi1ers constructed before the NSPS was promulgated and roughly a 55 percent
N0X removal efficiency for wall-fired boilers constructed after the NSPS
promulgation.
Simplified Procedures for Estimating NCL Performance of OFA Ports Applied to
Tangential-Fired Boilers
OFA is generally capable of achieving a 15 to 35 percent N0X reduction.
OFA can achieve the 1971 NSPS N0„ emission limit for wall- and tangential-
x 3
fired utility boilers and the 1979 NSPS for N0w emission limit for
x
tangential-fired boilers.
N0X emission reductions for tangential-fired boilers subject to the
NSPS or in service after 1974 are greater than those for older boilers. For
this reason, it is assumed that OFA can reduce uncontrolled N0X emissions by
35 percent for tangential boilers subject to the NSPS or in service after
1974. For boilers in service before 1974, an N0X emission reduction of
25 percent is assumed (9). This value was selected because furnace volume
is about 40 percent less for boilers in service before 1974 than those
subject to the NSPS or in service after 1974, and because the value
is consistent with NO reductions required to meet the 1971 NSPS NO
6
emission limit of 0.6 lb/10 Btu for tangential-fired boilers. For slagging
tangential-fired boilers, N0x emissions reductions stated above should be
reduced by 5 percent (8).
2.1.5.2 Natural Gas Reburning--
NGR, although not as commercially developed as the other N0X combustion
technologies, is included in this analysis. Inclusion of NGR in the study
provides a moderate N0X control level (relative to SCR) for those boilers
2-23
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for which LNBs are inapplicable (e.g., cyclone furnaces). The NOx reduction
performance of NGR would be affected by some of the same factors discussed
previously for INC. However, due to the lack of commercial demonstration
performance data, a single estimate of 60 percent N0X reduction was used in
this study. The Gas Research Institute is hoping to achieve N0X reductions
as high as 75 percent on high N0y emitting boiler types (wet bottom).
To achieve 60 percent N0X reduction, approximately 15 percent of the
boiler heat input would be injected into the upper furnace as natural gas.
Capital costs include the installation of natural gas and OFA injection
ports into the upper furnace, reburn gas supply piping, and controls.
2.1.5.3 Selective Catalytic Reduction--
The major equipment items for an SCR system include the catalyst,
ammonia system, controls, air preheater modifications or flue gas reheater,
ductwork, and fan. The catalyst volume is based on the flue gas flow rate
and the required N0X reduction percentage. The SCR equipment cost estimates
were developed from recent EPRI (10) and EPA (11) studies.
Two SCR system configurations were evaluated and are shown on
Figure 2-4. The hot side system configuration requires that the catalytic
reactor be placed in the flue gas path between the economizer and the air
heater to take advantage of the high flue gas temperature (~600-700°F). The
catalytic reactor for a cold side system would be located in the flue gas
path just before the flue gas enters the chimney. This system requires that
the flue gas be reheated to 600-700°F. Table 2-4 summarizes the pros and
cons of the two configurations. Both types of systems are being used in
Japan and Germany. For most boilers in this study, it was assumed that when
space was available, the cold side configuration would be used. This
configuration minimizes unit downtime and replacement power costs and
maximizes catalyst life. Cold side systems also facilitate combining
smaller units into one system, thereby obtaining economy-of-scale benefits.
Hot side SCR systems were selected for boilers that have hot ESPs.
2-24
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NH.
Retrofit 0(
^Selective
'w—Catalytic
Reduction
System
N«w
FGD
w
V
-*•
_ -J
ESP
¦J
Air Heater
—•""'od
~Q~
Slack
VYYV
Ash
Hot Side System
Figure 2-4. Possible SCR Configurations
2-25
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TABLE 2-4. TRADE-OFFS ASSOCIATED WITH HOT SIDE AND COLD SIDE SCR SYSTEMS
FOR COAL-FIRED UTILITY BOILERS (12)
Item SCR System
Hot Side Cold Side
Boiler downtime (months)
6-12
1-2
Boiler modifications
Yes
No
Economizer bypass
Yes
No
Precipitator reinforcement
Yes
No
SCR flyash removal
Yes
No
SCR system access and congestion
Higher
Lower
Catalyst
Life (hours)
-12,000
. -20,000
Type
Honeycomb or plate
Pellet
Catalyst cost
Larger volume/
Lesser volume
Higher cost
Lower cost
Reheat system
No
Yes
Energy penalties
Reheat
¦v No
Yes
Exchanger pressure drop
No
Yes
Coarse dust preseparator
Yes
No
SCR per boiler
one
one or more
Catalyst cleaning air
Yes
No
NHj usage
Higher
Lower
2-26
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The method used to develop retrofit factors and scope adjustments for
SCR is similar to that used for FGD methods. Scope adder costs considered
are as follows:
• duct and building demolition,
• new duct work,
§ new roads and replacement of demolished facilities, and
• new air heater {hot side) or flue gas reheater (cold side).
The EPRI FGD retrofit guidelines were used to develop costs for the
first three items. New roads and replacement of faci1ities were handled as
increases in general facilities. New air heater and flue gas reheater costs
are based on a vender quote for a 500-MW pi ant and scaled by a 0.6 factor
(11).
Access/congestion and underground obstruction factors were applied to
the catalytic reactor area. The EPRI FGD retrofit guideline factors for the
S02 and flue gas handling area were used. The scope adjustments and
retrofit difficulty factor were input to the IAPCS model to generate the
site-specific retrofit cost estimates.
2.2 IAPCS COST MODEL
Important technical cost assumptions were assigned to the acid gas
removal technologies selected for evaluation. These assumptions are
presented below for the technologies discussed in order of pre-, in situ-,
and post-combustion emission control technologies.
2.2.1 Flue Gas Desulfurization
Two process configurations using lime/limestone FGD with adipic acid
additive were evaluated: 1) common NSPS configuration having a spare
absorber and small absorber size (less than 125 MW each), and 2) a low-cost
configuration that does not have a spare absorber and maximized absorber
size up to 250 MW. Pertinent process design parameters included the use of
2-27
-------
vertical spray tower absorbers, primary and secondary solid dewatering via
thickener and vacuum filter (60 percent solids waste), and waste treatment
and disposal via landfill disposal. The use of reheat was provided by an
in-line steam reheater. An S02 removal efficiency of 90 percent was assumed
for all coal-sulfur levels. However, cost estimates were not generated for
boilers having a coal sulfur level less than 1 percent. Selection of lime
or limestone as the reagent was determined by using the reagent primarily in
use in the State or as directed by the utility company.
The number of operating absorber towers varied with boiler size and one
spare tower was provided for this NSPS option. Standard sparing practice
was followed for all other components. Three types of design strategies
were considered; 1) boilers were equipped with a complete, self-contained
FGD system; 2) when the flue gas from several boilers was already combined,
these boilers were equipped with combined FGD systems in which all process
areas were shared; 3) for the low-cost FGD system, boilers were combined,
spare absorbers were eliminated and absorber module size was maximized to
minimize the number of towers needed. Maximum absorber size was 250 MW. A
summary of the FGD technology assumptions for conventional FGD is presented
in Table 2-5.
Retrofit difficulty factors were developed for two limestone options:
limestone with adipic acid and limestone with forced oxidation. Because the
costs of the L/LS-FGD systems are about the same, only the cost for one
option was presented in the report for each plant. For the plants in states
where lime was predominately used as the reagent, lime FGD cost are
presented. For the states where limestone reagent is predominately used or
where no existing FGD system exist, 1imestone with adipic acid was used.
For a few pi ants, the pi ant personnel specifically requested the use of
1imestone with forced oxidation. Although the retrofit difficulty of
lime/limestone with adipic acid can vary from that of limestone with forced
oxidation, these differences are small and are due to the difference in the
waste handling area retrofit difficulty factors.
2-28
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TABLE 2-5, FLUE GAS DESULFURIZATIQN TECHNOLOGY ASSUMPTIONS
Process
Design configuration:
Absorber type
Reheat
Solids treatment
Design strategy
NSPS
Low Cost
Process design
Nominal stoichiometric ratio
Liquid-to-gas ratio
Number of absorbers
NSPS
Low cost
Number of spare absorbers
NSPS
Low cost
Limestone or Lime with
Organic Acid Additive
Vertical spray tower
In line steam
Dewatered/fixation/1andfil1
Single system per boiler or
Combined system when boiler
flue gas is already combined
Combined system for contiguous
boilers
1.05
60 - 70
<250 = 2 modules + 1 spare
250-499 = 3 modules + 1 spare
500-749 = 4 modules + 1 spare
250 MW Maximum
absorber size
1
0
2-29
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2.2.2 Lime Spray Drying
Two process variations were evaluated: LSD with conventional spray
dryer absorber and DSD. The design and performance assumptions associated
with the spray dryer absorber (LSD-FGD) configuration include both low and
high sulfur coal applications with reuse of the existing ESP or FF. S02
captures were adjusted as follows:
• The maximum SO^ removal for LSD-FGD with an FF in the
configuration was set at 86 percent. With an ESP configuration,
the maximum S02 removal efficiency was set at 70 percent. These
values represent maximum SC^ removals achieved under optimal
conditions. The actual values predicted by the model are a
function of flue gas temperature, SO,, concentration, and ash
alkalinity.
• The maximum SO^ removal for DSD was set at 50 percent across the
entire system for ESP configurations and 68 percent with the FF
configuration because of greater SOg capture across the FF. The
actual values predicted by the model are a function of flue gas
temperature, SO^ concentration, and ash alkalinity.
A summary of the LSD and DSD technology assumptions is presented in
Table 2-6.
2-2.3 Furnace Sorbent Injection
The basic process configuration selected for evaluation involves the
injection of calcitic hydrate into the upper radiant and lower convective
sections of the furnace. Boilers having ESPs with a specific collection
2 3
area of less than 220 ft /10 acfm were assumed not to be upgradable, and
these boilers were not evaluated for FSI. The PM control configurations
evaluated were reuse of the existing ESP or baghouse with additional ash
handling capacity.
The calcitic hydrate is assumed to be delivered to the plant in a
prepared form (i.e., ready for injection). The sorbent is injected at a
2-30
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TABLE 2-6. SPRAY DRYING TECHNOLOGY ASSUMPTIONS
Process Spray Dryer Absorber
Duct Spray Drying
Design configuration LSD-reuse ESP (upgrade)
LSD-new FF
LSD-reuse FF
DSD-reuse ESP (upgrade)
DSD-new FF
DSD-reuse FF
Process design:
Stoichiometric ratio, Ca/S 1.4
Recycle slurry solids, % 35
Lime slurry solids, % 25
Saturation approach, °F 30
Nominal S02 captures, % 70-86 (LSD)
50-68 (DSD)
2-31
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calcium-to-sulfur stoichiometric (Ca/S) ratio of 2.0. This calcium-to-
sulfur ratio was assumed to provide S02 capture of 50 percent arid
70 percent. The ESP operation was upgraded by incorporating spray
humidification as a gas conditioning process and the ESP was tuned up
through the addition of gas distribution vanes, baffles and optimization of
the rapping cycle. Boilers having ESPs with specific collection area of
less than 220 square foot of plate area per 1000 actual cubic feet a minute
of gas were not considered as candidates for FSI. These boilers would most
likely require the addition of a new ESP or FF in order to maintain their
current particulate emission limit at the 50 and 70 percent SC^ reduction
level. For cases where the plate area was not sufficient after
humidification and tune-up, the cost of additional plate area was included.
Boiler modifications and additional soot blowers were provided in every
case, and existing wet fly ash handling systems were converted to dry
systems. A summary of the FSI technology assumptions is presented in
Table 2-7.
2.2.4 Physical Coal Cleaning
The IAPCS AUSM database PCC option was used to estimate the cost of
coal cleaning. For this option, the technical level of coal cleaning was
set at 4 where all coal size fractions are cleaned and the appropriate
characteristics and costs are read from the AUSM database (13). The
database contains heating value, ash content, sulfur content and coal cost.
The model searches the database to find the most similar ROM coal and the
appropriate cleaned coal characteristics and cost based on the technical
level of preparation as mentioned above. "Most similar" is defined by the
following heuristics: (1) a coal with the same rank; (2) a coal with the
same sulfur content; and (3) a coal with the same coal supply region.
Because the PCC equipment costs are assumed to be at the mine (offsite), no
process capital costs are estimated for PCC. Capital costs associated with
fuel cost premium are estimated for preproduction costs and inventory
capital based on EPRI methodology. Annual operating and maintenance costs
comprise only the fuel cost premium and reduced waste disposal costs.
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TABLE 2-7. FURNACE SORBENT INJECTION TECHNOLOGY ASSUMPTIONS
Furnace Sorbent Injection
Prepared off-site
Upper furnace
ESP upgrade, baghouse
Dry
Calcitic hydrate
2:1
700
25 and 35
50 and 70
Spray humidi fication
Tune up then
Plate area addition
if required
All boiler firing types
Process
Design configuration:
Sorbent preparation
Injection point
PM control
Waste handling
Process design;
Sorbent
Ca/S ratio
Boiler quench rate,
Calcium utilization,
S02 capture, %
Gas conditioning
ESP upgrade
F°/sec
%
Process application
2-33
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2.2.5 Coal Substitution
For all boilers, a low sulfur West Virginia bituminous coal was used as
the replacement coal. It was assumed that this coal was the IAPCS coal
number three as presented in Table 2-8.
Two coal fuel price differentials (FDP) were used in this analysis: $5
and $15 per ton. These premiums were used to span the range of fuel cost
increases associated with low-sulfur coal demand under acid rain
legislation. These costs do not include the cost impact of additional coal
receiving/storage/handling facilities, if needed, and the cost impact of
boiler derate due to pulverizer capacity and boiler fouling, slagging, and
erosion. Boiler derate can be significant and can result in sizeable
replacement capacity costs, but was not considered for the simplified
procedure study because detailed unit design and operational information
were needed. The major capital cost for all cases is the cost of inventory
(coal consumption for 60 days at $5 or $15 FPD).
2.2.6 low NO^Combustion
LNC was applied solely to pulverized coal dry bottom boilers. Two
process variations were considered: OFA and LNB. OFA was applied to PC,
tangential-fired boilers (i.e., corner-fired boilers). The estimated low
N0X reduction performance ranged from 20 to 55 percent for LNB and 10 to
35 percent for OFA. The removal efficiencies were adjusted from site to
site to reflect specific design and operating conditions as discussed in
Section 2.1.5. A summary of the LNC technology cost/performance assumptions
is presented in Table 2-9.
2.2.7 Natural Gas Reburnino
Process scope Items include boiler combustion modifications and
six miles of gas pipeline to the plant. Cost elements include a fuel cost
differential (between natural gas and coal) of $2 per million Btus and
credits for savings in coal pulverizer operation, solid waste disposal, and
operating and labor supervision. A summary of the NGR technology
assumptions is presented 1n Table 2-10.
2-34
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TABLE 2-8. CHARACTERISTICS OF SWITCHED COAL
West Virginia
Item Coal
Btu/lb 12,058
Ash, % 16,6
S, % 0.89
H20, % 3.5
TABLE 2-9. LOW N0X COMBUSTION TECHNOLOGY ASSUMPTIONS
Processes
Low N0X Combustion
Boiler application
Process application:
OFA
LNB
Process description*.
OFA
LNB
Boiler modifications
N0X control, percent'
OFA
LNB
Pulverized coal: dry bottom
Tangential-fired
Wall-fired (front or opposed)
One port per row of existing burners
One replacement burner per existing
burner
Boiler tube and windbox
15-35
30-55
Control efficiency was varied as a function of furnace volume per
Equations A, B, and C in Section 2.1.5.1.
See
2-35
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TABLE 2-10. NATURAL GAS REBURNING TECHNOLOGY ASSUMPTIONS
Process Natural Gas Returning
Design Configuration:
Natural gas substitution, %
Injection point
Process application
NOx control, %
S02 control, %
PM control, %
Fuel Price Differential, S/million Btu
Process application
2-36
15
Upper furnace
All wet bottom boilers
60
15
15
2.00
All wet bottom boilers
-------
2-2.8 Selective Catalytic Reduction
SCR was applied to all coal-fired boilers evaluated. A summary of the
SCR technology assumptions is presented in Table 2-11. Two SCR process
variations were evaluated. In the first configuration, the hot side SCR
reactor is between the economizer and air preheater. In the second
configuration, the cold side SCR reactor is placed before the stack and
downstream of other emission control systems. The basic SCR system
comprises four process areas--ammonia preparation, reactors, flue gas
handling, and air heater modifications or flue gas reheater. The target N0X
control efficiency was established at 80 percent based on an ammonia
(NHj)/N0x stoichiometric ratio of 0.87. Catalyst life, which is the primary
cost driver, was set at 3 or 7 years. A 3-year catalyst life is typically
being achieved for hot side systems and a 7-year catalyst life would be
expected for cold side systems in Germany. It should be noted that many
U.S. coals have much higher sulfur, arsenic, and alkali metal contents than
coals in Japan/Germany. These contaminants can significantly reduce
catalyst life and require increased catalyst volume.
The spent catalyst was assumed to be returned to the supplier and the
cost of disposal was assumed to be included in the cost of the catalyst. It
was assumed that installation of cold side reactors or hot side reactors on
boilers with hot ESPs would not incur replacement power costs because
downtime for tie-in could be accomplished during the annual maintenance
outage.
2.2.9 Electrostatic Precipitator
The ESP algorithms contained in IAPCS estimate the performance of new
or existing ESPs. The cost algorithms estimate the cost of a new ESP or
upgrading the existing ESP by gas conditioning, ESP tune-up and plate area
addition, in that order. When flue gas conditions change with the retrofit
of a control technology or coal substitution, the IAPCS model first
estimates the required plate area needed to obtain the current existing
particulate emission rate for the boiler. If the needed plate area is
greater than the existing plate area, then the effect of gas conditioning
2-37
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TABLE 2-11. SELECTIVE CATALYTIC REDUCTION TECHNOLOGY ASSUMPTIONS
Process
Oesign configuration:
Ammonia preparation
Number of Reactors
Flue gas handling
Waste disposal
Process design;
NH3 stoichometric ratio
NHj slip, %
NO control, %
A
Catalyst life, years
Process application
Air heater modification
or
Flue gas reheater
Storage and injection
2 (<500 MW)
3 (750 MW)
4 (>1000 MW)
Ductwork length
Conventional landfill
0.87
2,27
80
3 or 7
Cold-side except where
no space or hot ESP
Corrosive resistant
heater elements and
additional surface area
for hot side systems
Flue gas to flue gas heat
exchange and steam for
cold side systems
2-38
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followed by tune-up, followed by plate area addition are evaluated until the
estimated emissions meet the current emission rate.
Gas conditioning can be used to improve the performance of an ESP.
IAPCS contains two gas conditioning options that can be used in conjunction
with use of the existing ESP: SO^ conditioning is used in this study with
coal switching; and humidification is used in this study with FSI,
Ash resistivity increases significantly when the coal sulfur is
decreased or when calcium sorbents are present. The use of S03 conditioning
reduces ESP plate area requirements by decreasing ash resistivity. The use
of SO^ conditioning was assumed to minimize the incremental plate area
requirements by 25 percent (14). The effect of humidification on plate area
requirements was based on cost and performance relationships developed as
part of the EPA LIMB program. Humidification improves ESP performance
because the moisture on the surface of ash/sorbent particles decreases the
particle resistivity and the gas cooling effect of humidification reduces
the flue gas volume. Flue gas volume reduction increases the effective
specific collection area (plate area per cubic foot of gas) of the ESP.
ESP tune-up included the addition of gas distribution vanes, baffles,
and optimization of the rapping cycle. When plate area addition was
required, an access/congestion retrofit difficulty factor for the ESP area
was used to adjust the cost estimate to account for the increase in cost
associated with space limitations. These factors wfere taken from the EPRI
Retrofit FGD Cost Estimating Guidelines Report (see Table 2-2).
2.2.10 Fabric Filter
An FF was provided as a replacement or alternative PM collection device
for the existing ESP. This option was considered only for DSD and the LSD
systems on boilers burning low sulfur coal. For these processes, the FF
also provided a significant improvement over the ESP in total system S02
removal through the incremental capture of SOg across the filter cake.
2-39
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2.2.11 Waste Disposal
The disposal of solid waste was handled in a consistent manner for all
plants. All solid waste products were disposed of in a landfill 1 mile away
from the plant. Waste treatment was provided for SGD technology in the form
of chemical fixation of the dewatered waste sludge, using lime and fly ash
additives. No chemical treatment was applied to the dry waste producing
processes; all material was collected as is and disposed in landfills.
2.3 ECONOMIC AND FINANCIAL ASSUMPTIONS
At the outset of the National Acid Precipitation Assessment Program
(NAPAP) Task Group I effort in 1985, a decision was made to use economic and
financial data consistent with accepted industry practices at that time.
The accepted standard for the electric utility industry is published in the
EPRI's Technical Assessment Guide (TAG) (15). The EPRI TAG provides the
economic factors and financial data on which the cost estimating procedures
used in the electric utility industry are based. Table 2-12 presents the
TAG values. The reader/user of this report should understand that another
valid set of assumptions based on another point in time (for technology
development) and different economic assumptions may produce results very
different from those reported here.
The following is a brief overview of the economic and financial
assumptions of the EPRI TAG as applied in this stage.
1. Cost-estimating premises adhere to the cost methodology described
in Chapter 3 of 1986 EPRI TAG.
2. The indirect capital cost factors were assigned to each technology
in accordance with the EPRI TAG. These values were varied in
accordance with site-specific conditions and are presented in
Table 2-13.
3. Allowance for funds during construction (AFDC) is estimated by
adjusting the total plant cost by an allowance factor that is a
function of the idealized construction period, the weighted cost
of capital, and the inflation rates.
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TABLE 2-12. FINANCIAL FACTORS FOR COST STRUCTURE a
Current Dollars
Item
Val ue
Cost
Return
Type of security
Debt (Bonds)
50%
11
5.5%
Preferred
15%
11.5
1.7%
Common Stock
35%
15.3
5.3%
Discount rate
12,5%/yr
(weighted cost of capital)
Federal and state income tax rate 38%
Investment tax credit
0%
Property taxes and insurance
2%/yr
Book life
30 yr -
Tax life
20 yr
Current Dollars
Constant Dollars
Inflation rate
6%
0%
Operating and Maintenance Levelization factor
1.75
1.0
Carrying charges, % of Capital
Cost
17.5%
10.5%
aCap1tal structure based on 1984 Edison Electric Institute (EEI) System
Planning Committee Survey.
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TABLE 2-13. NOMINAL INDIRECT COST SCHEDULE
Indirect Component3
LNC
FSI
NGR
SCR
LSD
DSD
ESP
FF
FGt
General facilities, %
5-15
5-15
5-15
5-15
5-15
5-15
5-15
5-15
5-15
Engineering and home
office fees, %
10-11
10-15
10-15
10-15
10-15
10-15
10-15
10-15
10-15
Project contingency, %
30
30
30
30
30
30
30
30
30
Process contingency, %
10
20
20
20
4.3
30
0
0
1.4
Sales tax, %
0
0
O
0
0
0
0
0
0
Royalty allowance, %
0
0
0
0.5
0
0
0
0
0
Preproduction cost
b
b
b
b
b
b
b
b
b
Inventory capital
c
c
c
c
c
c
c
c
c
Initial catalyst
0
0
0
d
0
0
0
0
0
Idealized construction
period, yr
1
1
1
1
3
1
1
1
3
Annual Maintenance cost
factor, % Total Plant Cost 2
4
2
4
6
6
4
4
8
aApplied as a percentage of process capital except as noted,
h
1 month of fixed operating cost; 1 month of variable operating cost; and
2 percent of total plant investment.
c60-day supply of consumables.
^SCR catalyst costs are estimated based on unit size and desired NO removal
efficiency.
eUsed for estimating allowance for funds during construction (AFDC).
2-42
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For annual operating costs, the unit costs for consumables per the
EPRI TAS are summarized in Table 2-14,
Total annual maintenance costs are estimated per the 1986 EPRI
TAGs as a percentage of total plant cost (before addition of AFDC,
preproduction costs, inventory capital, royalty, catalyst, and
land) depending on the nature of the processing conditions and the
type of design. A summary of the factors assigned to the various
technologies is presented in Table 2-13.
The financial factors for capital structure are presented in
Table 2-12.
The financial and economic premises significantly influence the
levelizatlon factors calculated for operating and maintenance
(O&M) and carrying charges. Using the 1986 guidel1nes recommended
by EPRI--12.5 percent discount rate (or weighted cost of capital),
6.0 percent inflation rate (long-term average), 30-year book life
(existing facility), and 20-year tax life (straight-line
depreciation)--the computed O&M levelization factors and capital
carrying charge factors are 1.75 and 0.175 for current dollars and
1.0 and 0.105 for constant dollars, respectively.
All costs are presented in current and constant 1988 dollars.
Capital costs are escalated from a 1982 base year cost in IAPCS
using the Chemical Engineering indices. Current dollar costs
account for inflation; constant dollar costs do not.
2-43
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TABLE 2-14. UNIT COST DATA
Item
January 1985 value
Units
Operating labor3
19.70
S/person hour
Water (river)
0.60
S/1000 gal
Lime
65
$/ton
Limestone
15
$/ton
Land
6,500
$/acre
Catalyst
20,290
$/ton
Waste disposal (wet)c
9.25
$/ton
Waste disposal (dry)c
»
8.0
$/ton
Electric power (in plant)
0.05
$/kWh
aBased on a direct labor charge of $14.6/h plus 35 percent payroll burden,
b
This is a raw water acquisition charge only. Intake structures, treating,
and pumping costs are included in plant capital and operating costs,
cNormally, waste disposal facilities are included in plant capital and
operating costs. The charges shown here are representative of off-site
disposal costs for special cases where on-site disposal is not included.
d
These special values are to be used only in studies of limited scope that
do not internally produce electricity and steam costs. The values are
based on a 2400-psi coal-fired power plant.
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2.4 REFERENCES
1. Emmel, T. E., S. D. Piccot, and B. A. Laseke. Ohio/Kentucky/TVA
Coal-Fired Utility SOg and NOx Control Retrofit Study.
EPA-6QG/7-88/014 (NT1S PB88-244447/AS), U. S. Environmental Protection
Agency, Research Triangle Park, North Carolina, 1988.
2. Palmisano, P. J., and B. A. Laseke. User's Manual for the Integrated
Air Pollution Control System Design and Cost Estimating Model, Version
II, Volume I. EPA-600/8-86-031a (NTIS PB87-127767), U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina, 1986.
3. Shattuck, D. M., et al. Retrofit FGD Cost Estimating Guidelines.
EPRI Report CS-3696, Electric Power Research Institute, Palo Alto,
California, 1984.
K
r
4. Emmel, T. E. and M. Maibodi. Verification of Simplified Procedures for
Site-Specific S02 and NQX Control Cost Estimates. EPA-600/7-90-008
(NTIS PB9Q-187261), U. S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1990.
5. Bahor, M. P., and K. L. Ogle. Economic Analysis of Wet Versus Dry Ash
Disposal Systems. EPA-600/7-81-013 (NTIS PB81-2235Q5), U. S.
Environmental Protection Agency, Research Triangle Park, North
Carolina, 1981.
6. Zilkowski, J. R., et al. Emission Reduction Capacity Increase and
Life Extension through Atmospheric Fluidized Bed Combustion Retrofit--
Black Dog Generating Plant. Paper presented at 1984 Joint Power
Generation Conference, Toronto, Ontario.
7. Elliot, T. C., id. Powerplants Database, Details of the Equipment and
Systems in Utility and Industrial Powerplants, 1950-1984.
McGraw-Hill, Inc., New York, New York, 1985.
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8. Smith, L. L. Energy Technology Consultants, Inc. Personal
communication with T. E. Emmel, Radian Corporation, February 1988.
9. Thompson, R. E., and M. W. McElroy. Guidelines for Retrofit Low N0X
Combustion Control. In Proceedings: 1985 Symposium on Stationary
Combustion N0X Control, Volume 1, EPA-600/9-86-021a (NTIS PB86-225042),
July 1986.
10. Bauer, T. K., and P. G. Spendle. Selective Catalytic Reduction for
Coal-Fired Power Plants: Feasibility and Economics. EPRI CS-3603,
Electric Power Research Institute, Palo Alto, California, 1984.
11. Burke, J. M., and K. L. Johnson. Ammonium Sulfate and Bisulfate
Formation in Air Preheaters. EPA-600/7-82-025a (NTIS PB82-237025),
U. S. Environmental Protection Agency, Research Triangle Park, North
Carolina, 1982.
12. Scharer, B., N. Haug, and H. J. Oels. Cost of Retrofitting
Denitrification. In: Proceedings of Workshop on Emission Control
Costs. Institute for Industrial Production, University of Karlsruhe.
Esslingen am Neckar, West Germany, September 28 - October 1, 1987.
pp. 326-358.
13. Stukel, J. J. Advanced Utility Simulation Model: Program
Documentation, State Level Model (Version 1.0). EPA-600/8-88-071b
(NTIS PB89-166631), U. S. Environmental Protection Agency, Research
Triangle Park, North Carolina, 1989.
14. Bickelhaupt, R. E. Fly Ash Resistivity Prediction Improvement With
Emphasis on Sulfur Trioxide. EPA-600/7-86-010 (NTIS PB86-178126), U.S.
Environmental Protection Agency, Research Triangle Park, North
Carolina, 1986.
15. Electric Power Research Institute. Technical Assessment Guide (TAG),
Volume 1. Electricity Supply--1986. EPRI Report P-4463-SR, Palo Alto,
California, 1986.
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