EPA/600/7—90/021c
November 1990
RETROFIT COSTS FOR S02 AND N0X CONTROL OPTIONS
AT 200 COAL-FIRED PLANTS
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
by
T. Emmel and M. Mai bodi
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 27709
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27711
-------
TECHNICAL REPORT DATA
(Phase read liittrucfians on the reverse before camp!/- ^
1. REPORT NO, 2,
EPA/600/7-96762Tc "
^ PB91--133348 J
4. TITLE AND SUBTITLE
Retrofit Costs for SO2 and NOx Control Options at
200 Coal-fired Plants; Volume III - Site Specific /
Studies for IN, KY, MA. MD, MI. MN
5. REPORT DATE
November 1990
6, PERFORMING ORGANIZATION CODE
7, AUTHORfS)
Thomas E, Erarnel and Mehdi Maibodi
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
P. O. Box 13000
Research Triangle Park, North Carolina 27709
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-4286; 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
r
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 1985-1990
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary notes AEERL project officer is Norman Kaplan, Mail Drop 62, 919/541-
2556. This is one of five volumes and three diskettes that comprise this report. „
16. abstract •j'^g report gives results of a study^jthe objective of which was to signifi-' 5,
cafitly improve engineering cost estimates 'currently being used to evaluate the eco- i
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
pe riod 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.IDENTIFIERS/OPEN ENDED TERMS
c. cosat 1 Fietd/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
18. distribution statement
Release to Public
IB. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
424
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
1
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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 200 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 recommendation for use.
ii
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TABLE OF CONTENTS
VOLUME I - INTRODUCTION AND METHODOLOGY
VOLUME II - SITE SPECIFIC STUDIES FOR
Alabama, Delaware, Florida, Georgia, Illinois
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
SECTION PAGE
ABSTRACT ii
LIST OF FIGURES
LIST OF TABLES ............. vii
ABBREVIATIONS AND SYMBOLS ..... xviii
ACKNOWLEDGEMENT xxi
METRIC EQUIVALENTS ....... xxii
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
-------
TABLE OF CONTENTS (Continued)
SECTION
8.7
8.8
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
PAGE
Public Service Company of Indiana .
8.7.1 Cayuga Steam Plant ....
8.7.2 R. A. Gallagher Steam Plant
8.7.3 Gibson Steam Plant ....
8.7.4 Wabash River Steam Plant .
Southern Indiana Gas and Electric
8.8.1 F. B. Culley Steam Plant
8-100
8-100
8-108
8-117
8-125
8-136
8-136
iv
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TABLE OF CONTENTS (Continued)
SECTION PAGE
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
11.0 MARYLAND . 11-1
11.1 Baltimore Gas and Electric . 11 -1
11.1.1 Charles P. Crane Steam Plant ..... 11-1
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 Plant 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 Boswell 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 Plant 13-15
VOLUME IV - SITE SPECIFIC STUDIES FOR
Missouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
V
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LIST OF FIGURES
FIGURE mkt
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
9.1.1-1 Coleman Plant Plot Plan 9-2
9.3.1-1 Cooper Plant Plot Plan 9-32
9.7.1-1 Mill Creek Plant Plot Plan . 9-85
9.9.2-1 Shawnee Plant Plot Plan 9-92
vi
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LIST OF TABLES
TABLE ' PAGE
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
8.1.1-1 Warrick Power Plant Operational Data . 8-2
8.1.1-2 Summary of Retrofit Factor Data for Warrick Unit 1 or 2 ... . 8-4
8.1,1-3 Summary of Retrofit Factor Data for Warrick Unit 3 8-5
8.1.1-4 Summary of Retrofit Factor Data for Warrick Unit 4 . 8-6
8.1.1-5 Summary of FGD Control Costs for the Warrick Plant
(June 1988 Dollars) 8-7
8.1.1-6 Summary of Coal Switching/Cleaning Costs for the
Warrick Plant (June 1988 Dollars) 8-8
8.1.1-7 Summary of NO Retrofit Results for Warrick .... 8-9
8.1.1-8 NO Control Cost Results for the Warrick Plant
(June 1988 Dollars) 8-10
8.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Warrick Units 1, 2, 3, and 4 ....... 8-12
8.1.1-10 Summary of DSD/FSI Control Costs for the Warrick
Plant (June 1988 Dollars) 8-13
8.2.1-1 Merom Steam Plant Operational Data . 8-14
8.2.1-2 Summary of NO Retrofit Results for Merom 8-15
8.2.1-3 NO„ Control Cost Results for the Merom Plant
(June 1988 Dollars) 8-16
8.2.2-1 Frank E. Ratts Steam Plan Operational Data 8-18
8.2.2-2 Summary of Retrofit Factor Data for F. E. Ratts
Unit 1 or 2 8-19
8.2.2-3 Summary of FGD Control Costs for the Frank E. Ratts
(June 1988 Dollars) 8-20
8.2.2-4 Summary of Coal Switching/Cleaning Costs for the
Frank E. Ratts PI ant (June 1988 Dollars) . 8-21
8.2.2-5 Summary of NO Retrofit Results for F. E. Ratts 8-23
8.2.2-6 NO Control Cost Results for the Frank E. Ratts
Plant (June 1988 Dollars) 8-24
8.3.1-1 Clifty Creek Steam Plant Operational Data . 8-26
8.3.1-2 Summary of Retrofit Factor Data for Clifty Creek Unit 1 ... . 8-28
8.3.1-3 Summary of Retrofit Factor Data for Clifty Creek
Unit 2 or 3 8-29
8.3.1-4 Summary of Retrofit Factor Data for Clifty
Creek Unit 4 or 5 8-30
8-3.1-5 Summary of Retrofit Factor Data for CIifty Creek Unit 6 . . . . 8-31
8.3.1-6 Summary of FGD Control Costs for the CIi fty Creek
Plant (June 1988 Dollars) . 8-32
8.3.1-7 Summary of NO Retrofit Results for Clifty Creek 8-34
8.3.1-8 NO Control Cost Results for the Clifty Creek
PI ant (June 1988 Dollars) 8-35
8.3.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Clifty Creek Units 1, 2, 3, 4, 5 8-36
vii
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LIST OF TABLES (Continued)
TABLES PAGE
8.3.1-10 Summary of DSD/FSI Control Costs for the Clifty
Creek Plant (June 1988 Dollars) . . ....... 8-37
8.4.1-1 Breed Steam Plant Operational Data .... 8-39
8.4.1-2 Summary of Retrofit Factor Data for Breed Unit 1 8-40
8.4.1-3 Summary of FGD Control Costs for the Breed Plant
(June 1988 Dollars) 8-41
8.4.1-4 Summary of N0X Retrofit Results for Breed . 8-43
8.4.1-5 NO Control Cost Results for the Breed Plant
(June 1988 Dollars) 8-44
8.4.2-1 Rockport Steam Plant Operational Data ............. 8-45
8.4.2-2 Summary of Retrofit Factor Data for Rockport Unit 1 or 2 ... 8-46
8.4.2-3 Summary of N0y Retrofit Results for Rockport 8-47
8.4.2-4 N0y Control Cost Results for the Rockport Plant
(June 1988 Dollars) 8-48
8.4.3-1 Tanners Creek Steam Plant Operational Data .......... 8-50
8.4.3-2 Summary of Retrofit Factor Data for Tanner Creek Unit 1 . . . . 8-52
8.4.3-3 Summary of Retrofit Factor Data for Tanners Creek Unit 2 . . . 8-53
8.4.3-4 Summary of Retrofit Factor Data for Tanners Creek Unit 3 . . . 8-54
8.3.3-5 Summary of Retrofit Factor Data for Tanners Creek Unit 4 . . . 8-55
8.3.3-6 Summary of FGD Control Costs for the Tanners Creek Plant
(June 1988 Dollars) ........... 8-56
8.4.3-7 Summary of NO Retrofit Results for Tanners Creek 8-57
8.4.3-8 NO Control Cost Results for the Tanners Creek Plant
(June 1988 Dollars) 8-58
8.4.3-9 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Tanners Creek Unit 1 or 2 8-60
8.4.3-10 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Tanners Creek Unit 3 . 8-61
8.4.3-11 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Tanners Creek Unit 4 8-62
8.4.3-12 Summary of DSD/FSI control Costs for the Tanners Creek Plant
(June 1988 Dollars) . 8-63
8.5.2-1 Petersburg Steam Plant Operational Data . 8-65
8.5.2-2 Summary of Retrofit Factor Data for Petersburg Unit 1 or 2 . . 8-67
8.5.2-3 Summary of FGD Control Costs for the Petersburg Plant
(June 1988 Dollars) 8-68
8.1.2-4 Summary of Coal Switching/Cleaning Costs for the Petersburg
Plant (June 1988 Dollars) 8-69
8.5.2-5 Summary of NO Retrofit Results for Petersburg ........ 8-70
8.5.2-6 NO Control Cost Results for the Petersburg Plant
(June 1988 Dollars) 8-71
8.5.2-7 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Petersburg Unit 1 or 2 8-73
8.5.2-8 Summary of DSD/FSI Control Costs for The Petersburg
Plant (June 1988 Dollars) . 8-74
viii
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LIST OF TABLES (Continued)
TABLES PAGE
8.5.3-1 Stout Steam Plant Operational Data ........ 8-76
8.5.3-2 Summary of Retrofit Factor Data for E. W. Stout Unit
50 or 60 8-77
8.5.3-3 Summary of Retrofit Factor Data for E. W. Stout Unit 70 ... . 8-78
8.5.3-4 Summary of FGD Control Costs for the Stout Plant
(June 1988 Dollars) . 8-79
8.5.3-5 Summary of Coal Switching/Cleaning Costs for the Stout
Plant {June 1988 Dollars) 8-81
8.5.3-6 Summary of NO Retrofit Results for E. W. Stout 8-82
8.5.3-7 NO Control Cost Results for the Stout Plant
(June 1988 Dollars) 8-83
8.5.3-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for E. W. Stout Unit 70 8-84
8.5.3-9 Summary of DSD/FSI Control Costs for the Stout Plant
(June 1988 Dollars) 8-85
8.6.1-1 Bailly Steam Plant Operational Data 8-86
8.6.1-2 Summary of Retrofit Factor Data for Bailly Units 7 and 8 . . . 8-87
8.6.1-3 Summary of FGD Control Costs for the Bailly Plant
(June 1988 Dollars) 8.88
8.6.1-4 Summary of NO Retrofit Results for Bailly ..... 8-89
8.6.1-5 NO Control Cost Results for the Bailly Plant
(June 1988 Dollars) 8-90
8.6.1-6 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Bailly Units 7 and 8 , 8-91
8.6.1-7 Summary of DSD/FSI Control Costs for the Bailly Plant
(June 1988 Dollars) 8-92
8.6.2-1 Michigan City Steam Plant Operational Data .......... 8-93
8.6.2-2 Summary of Retrofit Factor Data for Michigan City
Unit 12 8-94
8.6.2-3 Summary of FGD Control Costs for the Michigan City Plant
(June 1988 Dollars) 8-95
8.6.2-4 Summary of NO Retrofit Results for Michigan City . 8-96
8.6.2-5 NO Control Cost Results for the Michigan City Plant
(June 1988 Dollars) . 8-97
8.6.2-6 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Michigan City Unit 12 8-98
8.6.2-7 Summary of DSD/FSI Control Costs for the Michigan City Plant
(June 1988 Dollars) 8-99
8.7.1-1 Cayuga Steam Plant Operational Data ....... 8-101
8.7.1-2 Summary of Retrofit Factor Data for Cayuga Unit 1 or 2 ... 8-102
8.7.1-3 Summary of FGD Control Costs for the Cayuga Plant
(June 1988 Dollars) 8-103
8.7.1-4 Summary of Coal Switching/Cleaning Costs for the Cayuga
Plant (June 1988 Dollars) 8-105
8.7.1-5 Summary of N0X Retrofit Results for Cayuga 8-106
ix
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LIST OF TABLES (Continued)
TABLES PAGE
8.7.1-6 NO Control Cost Results for the Cayuga
Plant (June 1988 Dollars) 8-107
8.7.2-1 R. A. Gallagher Steam Plant Operational Data ... 8-109
8.7.2-2 Summary of Retrofit Factor Data for R. A. Gallagher
Unit 1 or 2 8-111
8.7.2-3 Summary of Retrofit Factor Data for R. A. Gallagher
Unit 3 or 4 8-112
8.7.2-4 Summary of FGD Control Costs for the R. A. Gallagher Plant
(June 1988 Dollars) 8-113
8.7.2-5 Summary of Coal Switching/Cleaning Costs for the
R. A. Gallagher Plant (June 1988 Dollars) ........ 8-114
8.7.2-6 Summary of N0X Retrofit Results for R. A. Gallagher 8-115
8.7.2-7 NO Control Cost Results for the R. A. Gallagher Plant
(June 1988 Dollars) 8-116
8.7.3-1 Gibson Steam Plant Operational Data 8-118
8.7.3-2 Summary of Retrofit Factor Data for Gibson
Units 1-4 (Each) 8-120
8.7.3-3 Summary of FGD Control Costs for the Gibson Plant
(June 1988 Dollars) ........ ..... 8-121
8.7.3-4 Summary of Coal Switching/Cleaning Costs for the Gibson
Plant (June 1988 Dollars) 8-122
8.7.3-5 Summary of NO Retrofit Results for Gibson 8-123
8.7.3-6 NOy Control Cost Results for the Gibson Plant
(June 1988 Dollars) 8-124
8.7.3-7 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Gibson Units 1-4 (Each) 8-126
8.7.3-8 Summary of DSD-FSI Control Costs for the Gibson Plant
(June 1988 Dollars) 8-127
8.7.4-1 Wabash River Steam Plant Operational Data 8-128
8.7.4-2 Summary of Retrofit Factor Data for Wabash River Units
1-6 (Combined) 8-130
8.7.4-3 Summary of FGD Control Costs for the Wabash River Plant
(June 1988 Dollars) 8-131
8.7.4-4 Summary of Coal Switching/Cleaning Costs for the Wabash River
Plant (June 1988 Dollars) 8-132
8.7.4-5 Summary of NO Retrofit Results for Wabash River . 8-133
8.7.4-6 No„ Control Cost Results for the Wabash River Plant
(June 1988 Dollars) ....... 8-134
8.8.1-1 Culley Steam Plant Operational Data 8-136
8.8.1-2 Summary of Retrofit Factor Data for Culley Units
1 and 2 • 8-137
8.8.1-3 Summary of Retrofit Factor Data for Culley Unit 3 ..... . 8-138
8.8.1-4 Summary of FGD Control Costs for the Culley Plant
(June 1988 Dollars) 8-139
8.8.1-5 Summary of Coal Switching/Cleaning Costs for the Culley Plant
(June 1988 Dollars) 8-140
8.8.1-6 Summary of N0X Retrofit Results for Culley 8-141
x
-------
LIST OF TABLES (Continued)
TABLES £M£
8.8.1-7 NO Control Cost Results for the Culley Plant
(June 1988 Dollars) 8-142
9.1.1-1 Coleman Steam Plant Operational Data , . 9-3
9.1.1-2 Summary of Retrofit Factor Data for Coleman Units 1-2 .... . 9-5
9.1.1-3 Summary of Retrofit Factor Data for Coleman Unit 3 ...... 9-6
9.1.1-4 Summary of F6D Control Costs for the Coleman Plant
(June 1988 Dollars) 9-8
9.1.1-5 Summary of the Coal Switching/Cleaning Control Costs
for the Coleman Plant (June 1988 Dollars) . . . 9-9
9.1.1-6 Summary of NO Retrofit Results for Coleman 9-11
9.1.1-7 NO Control Cost Results for the Coleman Plant
(June 1988 Dollars) 9-12
9.1.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Coleman Units 1-2 9-14
9.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Coleman Unit 3 ..... 9-15
9.1.1-10 Summary of DSD/FSI Control Costs for the Coleman
Plant (June 1988 Dollars) 9-16
9.1.2-1 Green Steam Plant Operational Data . . 9-18
9.1.2-2 Summary of NQX Retrofit Results for Green 9-20
9.1.2-3 NO Control Cost Results for the R. D. Green Plant
(June 1988 Dollars) 9-21
9.1.3-1 Robert Reid Steam Plant Operational Data 9-22
9.1.3-2 Summary of Retrofit Factor Data for Reid Unit 1 ....... . 9-23
9.1.3-3 Summary of FGD Control Costs for the Reid Plant
(June 1988 Dollars) 9-24
9.1.3-4 Summary of Coal Switching/Cleaning Costs for the Reid Plant
(June 1988 Dollars) 9-25
9.1.3-5 Summary of NO Retrofit Results for Henderson 9-26
9.1.3-6 NO Control Cost Results for the Reid Plant
(June 1988 Dollars) 9-27
9.2.1-1 East Bend Steam Plant Operational Data 9-28
9.2.1-2 Summary of NO Retrofit Results for East Bend . 9-29
9.2.1-3 NO Control Cost Results for the East Bend Plant
(June 1988 Dollars) 9-30
9.3.1-1 Cooper Steam Plant Operational Data ..... 9-33
9.3.1-2 Summary of Retrofit Factor Data for Cooper Units 1-2 ..... 9-35
9.3.1-3 Summary of FGD Control Costs for the Cooper Plant
(June 1988 Dollars) 9-36
9.3.1-4 Summary of Coal Switching/Cleaning Costs for the
Cooper Plant (June 1988 Dollars) . 9-38
9.3.1-5 Summary of NO Retrofit Results For Cooper 9-39
9.3.1-6 NO Control Cost Results for the Cooper Plant
(June 1988 Dollars) ............. 9-40
9.3.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Cooper Unit 1 9-43
xi
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TABLES
LIST OF TABLES (Continued)
PAGE
9,3.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Cooper Unit 2 ....... 9-44
9.3.1-9 Summary of DSD/FSI Control Costs for the Cooper
Plant {June 1988 Dollars) ¦ 9-45
9.3.2-1 Spurlock Steam Plant Operational Data 9-46
9,3.2-2 Summary of Retrofit Factor Data for Hugh L. Spurlock Unit 1 . , 9-48
9.3.2-3 Summary of FGD Control Costs for the Hugh L. Spurlock
Plant (June 1988 Dollars) 9-49
9.3.2-4 Summary of Coal Switching/Cleaning Costs for the
Hugh L. Spurlock Plant (June 1988 Dollars) .... 9-50
9.3.2-5 Summary of NO Retrofit Results for Hugh L. Spurlock 9-52
9.3.2-6 NO Control Cost Results for the Hugh L. Spurlock Plant
(June 1988 Dollars) 9-53
9.3.2-7 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Hugh L. Spurlock Unit 1 9-54
9.3.2-8 Summary of DSD/FSI Control Costs for the Hugh L. Spurlock
Plant (June 1988 Dollars) 9-55
9.4.1-1 Henderson Steam Plant Operational Data 9-57
9.4.1-2 Summary of Retrofit Factor Data for Henderson Unit 1 or 2 . . . 9-58
9.4.1-3 Summary of FGD Control Costs for the Henderson Plant
(June 1988 Dollars) 9-59
9.4.1-4 Summary of Coal Switching/Cleaning Costs for the Henderson Plant
(June 1988 Dollars) . 9-61
9.4.1-5 Summary of N0V Retrofit Results for Henderson ... 9-62
9.4.1-6 NO Control Cost Results for the Henderson Plant
(June 1988 Dollars) 9-63
9.6.2-1 Ghent Steam Plant Operational Data . 9-65
9.6.2-2 Summary of Retrofit Factor Data for Ghent Unit 1 9-67
9.6.2-3 Summary of Retrofit Factor Data for Ghent Unit 2 9-68
9.6.2-4 Summary of Retrofit Factor Data for Ghent Unit 3 ....... 9-69
9.6.2-5 Summary of Retrofit Factor Data for Ghent Unit 4 9-70
9.6.2-6 Summary of FGD Control Costs for the Ghent Plant
(June 1988 Dollars) 9-71
9.6.2-7 Summary of Coal Switching/Cleaning Costs for the Ghent
Plant (June 1988 Dollars) . 9-73
9.6.2-8 Summary of NO Retrofit Results for Ghent . 9-74
9.6.2-9 NO Control Cost Results for the Ghent Plant
(June 1988 Dollars) 9-75
9.6.3-1 Green River Steam Plant Operational Data 9-77
9.6.3-2 Summary of Retrofit Factor Data for Green River Unit 4 . . . . 9-78
9.6.3-3 Summary of Retrofit Factor Data for Green River Unit 5 .... 9-79
9.6.3-4 Summary of FGD Control Costs for the Green River Plant
(June 1988 Dollars) 9-80
xii
-------
LIST OF TABLES (Continued)
TABLES PAGE
9.6.3-5 Summary of Coal Switching/Cleaning Costs for the Green
River Plant (June 1988 Dollars) 9-81
9.6.3-6 Summary of NO Retrofit Results for Green River 9-82
9.6.3-7 NO Control Cost Results for the Green River Plant
(June 1988 Dollars) 9-83
9.7.1-1 Mill Creek Steam Plant Operational Data 9-86
9.7.1-2 Summary of N0y Retrofit Results for Mill Creek
Units 1-3 . . 9-87
9.7.1.3 Summary of N0y Retrofit Results for Mill Creek Unit 4 .... . 9-88
9.7.1.4 NO Control Cost Results for the Mill Creek Plant
x(June 1988 Dollars) 9-89
9.9.2-1 Shawnee Steam Plant Operational Data ...... 9-93
9.9.2-2 Summary of Retrofit Factor Data for Shawnee Units 1-5 9-96
9.9.2-3 Summary of Retrofit Factor Data for Shawnee Units 6-10 .... 9-97
9.9.2-4 Summary of FGD Control Costs for the Shawnee Plant
(June 1988 Dollars) 9-98
9.9.2-5 Summary of NO Retrofit Results for Shawnee Units 1-3 ... . 9-100
9.9.2-6 Summary of NO* Retrofit Results for Shawnee Units 4-6 ... . 9-101
9.9.2-7 Summary of NO Retrofit Results for Shawnee Units 7-8 .... 9-102
9.9.2-8 Summary of NO* Retrofit Results for Shawnee Units 9-10 . . . 9-103
9.9.2-9 NO Control Cost Results for the Shawnee Plant
*(June 1988 Dollars) 9-104
9.9.2-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Shawnee Units 1-10 9-107
9.9,2-11 Summary of DSD/FSI Control Costs for the Shawnee Plant
(June 1988 Dollars) 9-108
10.1.1-1 Somerset Steam Plant Operational Data . . 10-1
10.1.1-2 Summary of Retrofit Factor Data for Somerset Unit 7 ..... . 10-2
10.1.1-3 Summary of Retrofit Factor Data for Somerset Unit 8 10-3
10.1.1-4 Summary of FGD Control Costs for the Somerset Plant
(June 1988 Dollars) 10-4
10,1.1-5 Summary of Coal Switching/Cleaning Costs for
the Somerset Plant (June 1988 Dollars) ... 10-5
10.1.1-6 Summary of NO Retrofit Results for Somerset .... 10-6
10.1,1-7 NO Control Cost Results for the Somerset Plant
(June 1988 Dollars) . 10-7
10.1.1-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Somerset Unit 7 10-8
10.1.1-9 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Somerset Unit 8 10-9
10.1.1-10 Summary of DSD/FSI Control Costs for the Somerset Plant
(June 1988 Dollars) 10-10
10.2.1-1 Brayton Point Steam Plant Operational Data 10-12
10.2.1-2 Summary of Retrofit Factor Data for Brayton Point Unit 1 . . 10-14
10.2.1-3 Summary of Retrofit Factor Data for Brayton Point Unit 2 . . 10-15
xiii
-------
TABLES
LIST OF TABLES (Continued)
PAGE
10.2.1-4 Summary of Retrofit Factor Data for Brayton Point Unit 3 . ,. 10-16
10.2.1-5 Summary of FGD Control Costs for the Brayton Point Plant
(June 1988 Dollars) . . 10-17
10.2.1-6 Summary of Coal Switching/Cleaning Costs for the
Brayton Point Plant (June 1988 Dollars) 10-18
10.2.1-7 Summary of NO Retrofit Results for Brayton Point 10-19
10.2.1-8 NCL Control Cost Results for the Brayton Point Plant
(June 1988 Dollars) 10-20
10.2.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Brayton Point Unit 1 or 2 . . . 10-21
10.2.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Brayton Point Unit 3 10-22
10.2.1-11 Summary of DSD/FSI Control Costs for the Brayton Point Plant
(June 1988 Dollars) 10-23
10.2.2-1 Salem Harbor Steam Plant Operational Data 10-25
10.2.2-2 Summary of Retrofit Factor Data for Salem Harbor
Unit 1, 2, or 3 10-26
10.2.2-3 Summary of FGD Control Costs for the Salem Harbor Plant
(June 1988 Dollars) . 10-27
10.2.2-4 Summary of Coal Switching/Cleaning Costs for the
Salem Harbor Plant (June 1988 Dollars) . 10-28
10.2.2-5 Summary of NO Retrofit Results for Salem Harbor ...... 10-29
10.2.2-6 NO Control Cost Results for the Salem Harbor Plant
(June 1988 Dollars) ....... 10-30
10.2.2-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Salem Harbor Unit 1, 2, or 3 10-31
10.2.2-8 Summary of DSD/FSI Control Costs for the Salem Harbor Plant
(June 1988 Dollars) 10-32
11.1.1-1 Charles P. Crane Steam Plant Operational Data 11-1
11.1.1-2 Summary of Retrofit Factor Data for Crane Unit 1 or 2 11-2
11.1.1-3 Summary of FGD Control Costs for the Crane Plant
(June 1988 Dollars) 11-3
11.1.1-4 Summary of NO Retrofit Results for Crane 11-4
11.1.1-5 NO Control Cost Results for the Crane Plant
(June 1988 Dollars) . . 11-5
11.1.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Crane Unit 1 or 2 11-6
11.1.1-7 Summary of DSD/FSI Control Costs for the Crane Plant
(June 1988 Dollars) . 11-7
11.2.1-1 Chalk Point Steam Plant Operational Data ... 11-9
11.2.1-2 Summary of Retrofit Factor Data for Chalk Point Unit 1 or 2 . 11-11
11.2.1-3 Summary of FGD Control Costs for the Chalk Point Plant
(June 1988 Dollars) . 11-12
11.2.1-4 Summary of Coal Switching/Cleaning Costs for the Chalk
Point Plant {June 1988 Dollars) ............. 11-13
xiv
-------
LIST OF TABLES (Continued)
TABLES - PAGE
11.2.1-5 Summary of NO Retrofit Results for Chalk Point ........ 11-14
11.2.1-6 N0V Control Cost Results for the Chalk Point Plant
(June 1988 Dollars) .............. 11-15
11.2.1-7 Ouct Spray Drying and Furnace Sorbent Injection Technologies
for Chalk Point Unit 1 or 2 ............... 11-16
11.2.1-8 Summary of DSD/FSI Control Costs for the Chalk Point Plant
(June 1988 Dollars) ... ........... 11-17
11.2.2-1 Dickerson Steam Plant Operational Data ... ... 11-19
11.2.2-2 Summary of Retrofit Factor Data for Dickerson
Unit 1, 2, or 3 11-21
11.2.2-3 Summary of FGD Control Costs for the Dickerson Plant
(June 1988 Dollars) 11-22
11.2.2-4 Summary of Coal Switching/Cleaning Costs for the
Dickerson Plant (June 1988 Dollars) 11-23
11.2.2-5 Summary of N0„ Retrofit Results for Dickerson ... 11-24
11.2.2-6 NO Control cSst Results for the Dickerson Plant
(June 1988 Dollars) 11-25
11.2.3-1 Morgantown Steam Plant Operational Data ...... 11-27
11.2.3-2 Summary of Retrofit Factor Data for Morgantown Unit 1 or 2 . 11-28
11.2.3-3 Summary of FGD Control Costs for the Morgantown Plant
(June 1988 Dollars) . 11-29
11.2.3-4 Summary of Coal Switching/Cleaning Costs for the
Morgantown Plant (June 1988 Dollars) 11-31
11.2.3-5 Summary of NO Retrofit Results for Morgantown . . 11-32
11.2.3-6 NO Control Cost Results for the Morgantown Plant
(June 1988 Dollars) 11-33
12.1.1-1 J.H. Campbell Steam Plant Operational Data . 12-2
12.1.1-2 Summary of Retrofit Factor Data for J.H. Campbell
Unit 1 or 2 12-4
12.1.1-3 Summary of Retrofit Factor Data for J.H. Campbell Unit 3 . . . 12-5
12.1.1-4 Summary of NO Retrofit Results for J.H. Campbell ....... 12-6
12.1.1-5 NO Control Cost Results for the J.H. Campbell Plant
(June 1988 Dollars) ....... 12-7
12.1.1-6 Duct Spray Drying and Furnace Sorbent Injection Technologies
for J.H. Campbell Unit 1, 2, or 3 12-9
12.1.1-7 Summary of DSD/FSI Control Costs for the J.H. Campbell Plant
(June 1988 Dollars) 12-10
12.1.2-1 Dan E. Karn Steam Plant Operational Data . . ... 12-11
12.1.2-2 Summary of Retrofit Factor Data for Dan E. Karn Unit 1 . . . 12-13
12.1.2-3 Summary of Retrofit Factor Data for Dan E. Karn Unit 2 ... 12-14
12.1.2-4 Summary of NO Retrofit Results for Dan E. Karn ....... 12-15
12.1.2-5 N0V Control Cost Results for the Karn Plant
(June 1988 Dollars) ........... 12-16
xv
-------
LIST OF TABLES (Continued)
TABLES PAGE
12.1.2-6 Duct Spray Drying and Furnace Sorbent Injection Technologies.
for Dan E. Karn Unit 1 or 2 12-18
12.1.2-7 Summary of DSO/FSI Control Costs for the Karn Plant
(June 1988 Dollars) 12-19
12.1.3-1 Weadock Steam Plant Operational Data ............ 12-20
12.1.3-2 Summary of Retrofit Factor Data for Weadock Units 7 or 8 . . 12-21
12.1.3-3 Summary of NO Retrofit Results for Weadock .... 12-22
12.1.3-4 NQy Control Cost Results for the Weadock Plant
(June 1988 Dollars) . 12-23
12.1.4-1 J. R. Whiting Steam Plant Operational Data 12-24
12.1.4-2 Summary of Retrofit Factor Data for J. R. Whiting Unit 1 or 2 12-25
12.1.4-3 Summary of Retrofit Factor Data for J. R. Whiting Unit 3 . . 12-26
12.1.4-4 Summary of NO Retrofit Results for J. R. Whiting ...... 12-27
12.1.4-5 NO Control Cost Results for the Whiting Plant
(June 1988 Dollars) ................... 12-28
12.1.4-6 Duct Spray Drying and Furnace Sorbent Injection Technologies
for J. R. Whiting Unit 1 or 2 12-29
12.1.4-7 Duct Spray Drying and Furnace Sorbent Injection Technologies
for J.R. Whiting Unit 3 12-30
12.1.4-8 Summary of DSD/FSI Control Costs for the Whiting Plant
(June 1988 Dollars) 12-31
12.2.1-1 Monroe Steam Plant Operational Data ....... 12-33
12.2.1-2 Summary of Retrofit Factor Data for Monroe Unit 1 or 2 ... 12-35
12.2.1-3 Summary of Retrofit Factor Data for Monroe Unit 3 or 4 ... 12-36
12.2.1-4 Summary of NO Retrofit Results for Monroe ... . 12-37
12.2.1-5 NO Control Cost Results for the Monroe Plant
(June 1988 Dollars) 12-38
12.2.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Monroe Unit 3 or 4 . 12-40
12.2.1-7 Summary of DSD/FSI Control Costs for the Monroe Plant
(June 1988 Dollars) . 12-41
12.2.2-1 River Rouge Steam Plant Operational Data ..... 12-42
12.2.2-2 Summary of Retrofit Factor Data for River Rouge Unit 2 or 3 . 12-43
12.2.2-3 Summary of NO Retrofit Results for River Rouge ....... 12-44
12.2.2-4 NO Control Cost Results for the River Rouge Plant
(June 1988 Dollars) 12-45
12.2.2-5 Duct Spray Drying and Furnace Sorbent Injection Technologies
for River Rouge Unit 2 or 3 . 12-46
12.2.2-6 Summary of DSD/FSI Control Costs for the River Rouge Plant
(June 1988 Dollars) 12-47
12.2.3-1 St. Clair Steam Plant Operational Data . 12-48
12.2.3-2 Summary of Retrofit Factor Data for St. Clair
Units 1, 2, 3 and 4 12-49
12.2.3-3 Summary of Retrofit Factor Data for St. Clair Unit 6 .... 12-50
xvi
-------
LIST OF TABLES (Continued)
TABLES , PAGE
12.2.3-4 Summary of Retrofit Factor Data for St. Clair Unit 7 .... 12-51
12.2.3-5 Summary of N0y Retrofit Results for St. Clair Units 1-4 . . 12-52
12.2.3-6 Summary of NO Retrofit Results for St. Clair Units 6-7 .. . 12-53
12.2.3-7 NO Control Cost Results for the St. Clair Plant
(June 1988 Dollars) 12-54
12.2.3-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for St. Clair Units 1, 2, 3, 4 and 6 12-55
12.2.3-9 Summary of DSD/FSI Control Costs for the St. Clair Plant
(June 1988 Dollars) 12-56
12.2.4-1 Trenton Steam Plant Operational Data 12-57
12.2.4-2 Summary of Retrofit Factor Data for Trenton Channel
Units 1-4 . 12-58
12.2.4-3 Summary of Retrofit Factor Data for Trenton Channel Unit 5 . 12-59
12.2.4-4 Summary of NO Retrofit Results for Trenton Channel Units 1-3 12-60
12.2.4-5 Summary of NO Retrofit Results for Trenton Channel Units 4-5 12-61
12.2.4-6 NO Control Cost Results for the Trenton Channel Plant
(June 1988 Dollars) ¦ 12-62
12.3.1-1 Presque Isle Steam Plant Operational Data ..... 12-63
12.3.1-2 Summary of Retrofit Factor Data for Presque Isle Unit 1-6 . . 12-65
12.3.1-3 Summary of NO Retrofit Results for Presque Isle ...... 12-66
12.3.1-4 NO Control Cost Results for the Presque Isle Plant
(June 1988 Dollars) 12-67
13.1.1-1 Clay Boswell Steam Plant Operational Data ... ... 13-2
13.1.1-2 Summary of Retrofit Factor Data for Clay Boswell Unit 1 or 2 . 13-4
13.1.1-3 Summary of NO Retrofit Results for Clay Boswell ....... 13-5
13.1.1-4 N0y Control Cost Results for the Clay Boswell Plant
(June 1988 Dollars) 13-6
13.1.1-5 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Clay Boswell Unit 1 or 2 13-8
13.1.1-6 Summary of DSD/FSI Control Costs for the Clay Boswell Plant
(June 1988 Dollars) 13-9
13.2.1-1 A. S. King Steam Plant Operational Data ..... 13-10
13.2.1-2 Summary of Retrofit Factor Data for A. S. King Unit 1 . . . . 13-11
13.2.1-3 Summary of FGD Control Costs for the A. S. King Plant
(June 1988 Dollars) 13-12
13.2.1-4 Summary of NO Retrofit Results for A. S. King ....... 13-13
13.2.1-5 NO Control Cost Results for the A. S. King Plant
(June 1988 Dollars) . 13-14
13.2.2-1 Sherburne County Steam Plant Operational Data ........ 13-16
13.2.2-2 Summary of NO Retrofit Results for Sherburne County .... 13-17
13.2.2-3 NQy Control Cost Results for the Sherburne County Plant
(June 1988 Dollars) 13-18
xvii
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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
FGO
--
flue gas desulfurization
FPD
--
fuel price differential
FSI
__
furnace sorbent injection
ft
--
feet
FWF
--
front, wall-fired
IAPCS
Integrated Air Pollution Control System
xviii
-------
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
--
1ime/1imestone
LNB
__
low-NOx burner
LNC
low-NGx combustion
LSD
--
lime spray drying
m
--
meter
MM
millions
MM
--
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&H
--
operating and maintenance
PCC
physical coal cleaning
PM
--
particulate matter
ps i 3
pounds per square inch absolute
xix
-------
ABBREVIATIONS AND SYMBOLS (Continued)
SCA -- specific collection area (ft^/1000 acfm)
SCR -- selective catalytic reduction
SCR-CS -- selective catalytic reduction - cold side
SCR-HS -- selective catalytic reduction - hot side
sec -- second
SI -- sorbent injection
sq ft -- square feet
TAG -- Technical Assessment Guideline
TVA -- Tennessee Valley Authority
UARG -- Utility Air Regulatory Group
USGS -- U.S. Geological Survey
$/kW -- dollars per kilowatt
SYMBOLS
MgO -- magnesium oxide
NHg -- ammonia
NOx -- nitrogen oxides
SOg -- sulfur dioxide
S03 -- sulfur trioxide
XX
-------
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.
xxi
-------
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
acre 4046.9 m2
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
1b/MMBtu 1.8 kg/kg-calorie
psia 0.0703 g/cm2
ton 0.9072 ton
/'
xxii
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SECTION 8,0 INDIANA
8.1 ALCOA GENERATING CORPORATION AND
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
8.1.1 Warrick Power Plant
The Warrick Power Plant is located on the Ohio River in Warrick County,
Indiana. Units 1 through 3, owned by the ALCOA Generating Corporation
(AGC), are coal-fired boilers with a design gross capacity of 144 MM each.
One half of unit 4, with a design gross capacity of 300 MW, is owned by AGC.
Southern Indiana Gas and Electric Company (SIGECO), a public utility, owns
half of unit 4, and operates all four units for AGC. The output of the
AGC-owned portion of the Warrick Power Plant is dedicated exclusively to the
adjacent ALCOA Warrick Operations to provide power for aluminum smelting and
other plant operations.
Table 8.1.1-1 presents operational data for the existing equipment at
the Warrick plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area west of the plant. PM emissions from
the units are controlled by retrofit ESPs located behind the boilers. Flue
gases from boilers 1, 2, and 3 are directed to two chimneys and flue gases
from unit 4 are directed to a third chimney. All three chimneys are located
behind the ESPs. Fly ash is disposed of in a pond west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1-4 would be located in a relatively open
area south of unit 4. The general facilities factor would be medium
(8 percent) because a road and some storage buildings would have to be
relocated. The site access/congestion factor would be low for all of the
FGD absorber locations. Approximately 200 feet (for unit 4) to 600 feet
(for unit 1) of ductwork would be required to span the distance from the
units to the absorbers. New chimneys would be constructed for units 1-3,
adjacent to their respective absorbers. A high site access/congestion
factor was assigned to flue gas handling for units 1 and 2, medium for
8-1
-------
TABLE 8.1.1-1. WARRICK POWER PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2,3
144
90
1960,64,65
FRONT WALL
85
NO
3 3
10800
10.5
4
300
60
1970
OPPOSED WALL
194
NO
3.3
10800
10.5
WET DISPOSAL
PONDS/ON-SITE
1; 1,2; 2 3
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
ESP
ESP
1973
1983
0.12,.08,.13
0.08
98.5,98.6,98
99.0
2.8-3.8
2.8-3.8
69.1
376.9
689
1385
100
272
710
329
8-2
-------
unit 3, and low for unit 4. The high factor reflects the congestion created
by the demineralizer building situated south of unit 1. The waste generated
would have to be transported to an off-site location due to the space
limitation on-site.
LSD with reuse of the existing ESPs was not considered for units 1-3 at
the Warrick plant because the existing ESPs are hot side. LSD with new FFs
was not considered for units 1-3 because of the high sulfur content of the
coal being burned at the plant. However, the unit 4 ESPs are large enough
to accommodate the additional load and LSD with reuse of the existing ESPs
was evaluated for this unit. The LSD absorbers would be located west of
unit 4 adjacent to its ESPs. A low site access/congestion factor was
assigned to the absorber location. Approximately 400 feet of ductwork would
be required. A medium site access/congestion factor would be assigned to
flue gas handling because of some access difficulty to the upstream of the
ESPs.
Tables 8.1.1-2 through 8.1,1-5 present retrofit factors and cost
estimates for installation of conventional FGD technologies at the Warrick
Power Plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 8.1.1-6 presents the IAPCS cost results for CS at the Warrick
Power Plant. These costs do not include boiler and pulverizer operating
cost changes or any coal handling system modifications that may be
necessary. PCC was not considered for the Warrick Power Plant because it is
not a mine mouth plant.
NOx Control Technologies--
LNBs were considered for NOx emissions control for the four wall-fired
furnaces at the Warrick Power Plant. Tables 8.1,1-7 and 8.1.1-8 present the
N0X reduction and cost estimates for LNB technologies at the plant.
Selective Catalytic Reduction-
Hot side SCR reactors for units 1-3 would be located behind their
chimneys and cold side SCR reactors for unit 4 would be located west of
unit 4 ESPs. A medium general facilities value of 20 percent was assigned
8-3
-------
TABLE 8.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR WARRICK
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE
BAGHOUSE
ESP REUSE NA NA
NEW BAGHOUSE NA NA
NA
NA
NA
NA
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA
ESTIMATED COST (1000$) 1300 NA
NEW CHIMNEY YES NA
ESTIMATED COST (1000$) 1008 0
OTHER NO
NA
NA
NA
0
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.48
NA
NA
NA
NA
NA
NA
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
*
8-4
-------
TABLE 8.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR WARRICK
UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA NA
FLUE GAS HANDLING MEDIUM NA ,
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA NA
ESTIMATED COST (1000$) 1300 NA NA
NEW CHIMNEY YES NA NA
ESTIMATED COST (1000$) 1008 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.44 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 0
8-5
-------
TABLE 8.1.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR WARRICK
UNIT 4
FGO TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE
ESP REUSE NA NA
NEW BAGHOUSE NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA
ESTIMATED COST (1000$) 2682 NA
NEW CHIMNEY NO NA
ESTIMATED COST (1000$) 0 0
OTHER NO
LOW
MEDIUM
NA
300-600
NA
MEDIUM
NA
YES
2682
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.27
NA
NA
NA
NA
NA
1.38
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 8
8-6
-------
Table 3.1,1-5. $urinary of FGO Control Costs for the Warrick Plant (June 1988 Dollars)
Technology
Boller
Main
Boiler Capacity Coal
Capital Capital Annual
Annua I
S02
SQ2
302 Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cast
Removed Removed
Effect.
Difficulty (MU)
(%>
Content
(IMH )
<*/W
($HM)
Cmills/kwh)
(X)
Ctons/yr)
(S/ton)
Factor
.........
.........
......
...........
......
l/S FGO
1
1.48
144
90
3.3
61.8
429.5
30.2
26.6
90.0
30693
984.1
l/S FGO
2
1.48
144
90
3.3
61.8
429.5
30.Z
26.6
90.0
30693
984.1
l/S FGD
3
1.44
144
90
3.3
60.3
419.0
29.7
26.2
90.0
30693
968.2
L/S FGO
4
1.27
300
60
3.3
80.0
266.8
39.2
24.9
90.0
42637
919.4
L/S FGO
1-3
1.47
432
90
3.3
123.0
284.8
65.4
19.2
90.0
92080
710.0
L/S FSD-C
1
1.48
144
90
3.3
61.8
429.5
17.6
15.5
90.0
30693
572.9
L/S FGD-C
2
1.48
144
90
3.3
61.8
429.5
17.6
15.5
90.0
30693
572.9
L/S FGO-C
3
1.44
144
90
3.3
60.3
419.0
17.3
15.2
90.0
30693
563.6
L/S FGD-C
4
1.27
300
60
3.3
80.0
266.8
22.8
14.5
90.0
42637
535.2
L/S FGD-C
1-3
1.47
432
90
3.3
123.0
284.8
38.0
11.2
90.0
92080
412.8
LC FED
1-3
1.47
432
90
3.3
101.9
235.8
58.7
17.2
90.0
92080
637.4
LC FGD
4
1.27
300
60
3.3
64.1
213.5
33.3
21.1
90.0
42630
782.2
LC FGD-C
1-3
1.47
432
90
3.3
101.9
235.8
34.1
10.0
90.0
92080
370.2
LC FGD-C
4
1.27
300
60
3.3
64.1
213.5
19.4
12.3
90.0
42630
454.9
LSD+ISP
4
1.00
300
60
3.3
51.0
169.8
29.4
18.6
74.0
35173
335.8
LSD+ISP-C
4
1.00
300
60
3.3
51.0
169.8
17.1
10.8
74.0
35175
485.4
8-7
-------
Table 8.1.1-6. Summary of Coal Switching/Cleaning Costs for the Warrick Plant (June 1988 Dollars)
Technology' Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost - Cost Removed Removed Effect.
Difficulty (MU> <*) Content !»**) (S/ton)
factor £%)
CS/3*$15
CS/8+J15
1,2,3 1.00
4 1.00
144
300
90
60
7.5
9.8
51.9
32.8
16.9
22.6
14.9
14.3
76.0
76.0
25912
35989
650.9
627.1
CS/3+S15-C
CS/3+I15-C
CS/3+S5
CS/B+$5
CS/B+I5-C
CS/B+I5-C
1,2,3
4
1,2,3
4
1,2,3
4
.00
.00
.00
.00
.00
.00
144
300
144
300
144
300
90
£0
90
60
90
60
3.3
3.3
3.3
3.3
7.5
9.8
6.0
6.7
6.0
6.7
51.9
32.8
41.5
22.4
41.5
22.4
9.7
13.0
7.2
9.0
4.2
5.2
8.5
8.2
6.4
5.7
3.7
3.3
76.0
76.0
76.0
76.0
76.0
76.0
25912
35989
25912
35989
25912
35989
374.2
360.5
279.0
250.1
160.9
144.1
8-8
-------
TABLE 8.1.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR WARRICK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2,3
4
FIRING TYPE
FWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (1000 CU FT)
85
194
BOILER INSTALLATION DATE
1960,64,65
1970
SLAGGING PROBLEM
NO
YES
ESTIMATED NOx REDUCTION (PERCENT)
40
36
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
HIGH,MEDIUM,
LOW
LOW
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
36
62
New Duct Length (Feet)
200
400
New Duct Costs (1000$)
1227
3769
New Heat Exchanger (1000$)
0
3603
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
1262
7434
RETROFIT FACTOR FOR SCR
1.54,1.34,1.16
1.16
GENERAL FACILITIES (PERCENT)
20
13
-------
Table 8,1.1-8. NOx Control Cost Results for the Warrick Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NOX
NOx Cost
Number 1
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW)
e%>
Content
(SUM)
(SNM)
(mills/kwh)
<%>
(tons/yr)
(S/ton)
Factor
(%)
LNC-INB
1.2,3
1.00
144
90
3.3
3.0
20.5
0.6
0.6
40.0
2226
235.5
LNC-tNB
4
1.00
300
60
3.3
4.0
13.2
0.9
0.5
36.0
2783
306.4
LMC-LNB-C
1,2,3
1.00
144
90
3.3
3.0
20.5
0.4
0.3
40.0
2226
169.5
LNC-LNB-C
4
1.00
300
60
3.3
4.0
13.2
0.5
0.3
36.0
2783
181.9
SCR-3
1
1.54
144
90
3.3
27.9
193.9
9.7
8.5
80.0
4453
2167.9
SCR-3
2
1.34
144
90
3.3
25.5
177.1
9.1
8.0
80.0
4453
2034.1
SCR-3
3
1.16
144
90
3.3
23.3
162.1
8.5
7.5
80.0
4453
1913.7
SCR-3
4
1.16
300
60
3.3
43.8
146.0
15.4
9.7
80.0
6184
2483.0
SCR-3-C
- 1
1.54
144
90
3.3
27.9
193.9
5.7
5.0
80.0
4453
1270.2
SCR-3-C
2
1.34
144
90
3.3
25.5
177.1
5.3
4.7
80.0
4453
1191.1
SCR-3-C
3
1.16
144
90
3.3
23.3
162.1
5.0
4.4
80.0
4453
1119.9
SCR-3-C
4
1.16
300
60
3.3
43.8
146.0
9.0
5.7
80.0
6184
1454.4
SCR-7
1
1.54
144
90
3.3
27.9
193.9
8.5
7.4
80.0
4453
1898.0
SCR-7
2
1.34
144
90
3.3
25.5
177.1
7.9
6.9
80.0
4453
1764.2
SCR-7
3
1.16
144
90
3.3
23.3
162.1
7.3
6.4
80.0
4453
1643.8
SCR-7
4
1.16
300
60
3.3
43.8
146.0
12.9
8.2
80.0
6184
2078.1
SCR-7-C
1
1.54
144
90
3.3
27.9
193.9
5.0
4.4
80.0
4453
1115.5
SCR-7-C
2
1.34
144
90
3.3
25.5
177.1
4.6
4.1
80.0
4453
1036.5
SCR-7-C
3
1.16
144
90
3.3
23.3
162.1
4.3
3.8
80,0
4453
965.3
SCR-7-C
4
1.16
300
60
3.3
43.8
146.0
7.6
4.8
80.0
6184
1222.4
sssssasssssss
II
li
ii
it
ii
ll
ii
li
if
II
II
II
II
II
II
ll
:=5ssas:
:=======:
SSSSS==S3
ujj,....
niBimns
=a===s:
===3_--===.
---------
8-10
-------
to the reactor locations for units 1-3 and a low general facilities factor
(13 percent) was assigned to the unit 4 location. A site access/congestion
factor of high, medium, and low were assigned to units 1, 2, and 3-4
respectively. High and medium factors reflect the congestion created by the
newly installed demineralizer building south of unit 1. Approximately 200
to 400 feet of ductwork would be required to span the distance between the
SCR reactors and the chimneys for units 1-3 and 4, respectively.
Tables 8.1.1-7 and 8.1.1-8 summarize the retrofit factors and estimated cost
for installation of SCR at the Warrick Power Plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) with a new baghouse was
considered for units 1-3 and with a reuse of the existing ESPs for unit 4.
FSI and DSD were considered for unit 4 because of sufficient duct residence
time between the boilers and retrofit ESPs and adequate size ESPs.
Tables 8.1.1-9 and 8.1.1-10 present the retrofit factors and cost estimates
for installation of FSI and DSD technologies at the Warrick power plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi1ity--
Units 1-3 would be good candidates for AFBC/CG repowering because of
their small size. However, the high unit capacity factors could result in
high replacement power costs. Unit 4 is not a good candidate due to its
large size and longer remaining life.
8-11
-------
TABLE 8.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR WARRICK UNITS 1,2,3, AND 4
UNIT
1,2,3
4
SITE ACCESS/CONGESTION
REAGENT PREPARATION
BASE
BASE
ESP UPGRADE
NA
MEDIUM
NEW BAGHOUSE
HIGH
NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO
DRY HANDLING
NO
YES
ESTIMATED COST (1000$)
. 2682
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
200
NA
ESTIMATED COST (1000$)
1137
NA
ESP REUSE CASE
NA
NA
ESTIMATED COST (1000$)
NA
NA
DUCT DEMOLITION LENGTH (FT)
50
50
DEMOLITION COST (1000$)
39
72
TOTAL COST (1000$)
ESP UPGRADE CASE
NA
2754
A NEW BAGHOUSE CASE
1176
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.13
1.08
ESP UPGRADE
NA
1.36
NEW BAGHOUSE
1.58
NA
8-12
-------
Table 8.1.1-10. Sutmary of QSD/FSI Control Costs for the Warrick Plant (June 1988 Dollars)
Technology Boiler Main 8oiler Capacity Coat Capital Capital Annual Annual S02 S02 S02 Cost
Nimber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) <%) Content <5MM) <*/kw) (SUN) (mills/kwh) (X) (tons/yr) (S/ton)
Factor i%)
DSD+ESP
4
1.00
300
60
3.3
22,9
76.3
16,4
10.4
48.0
22562 .
726.5
OSO+ESP-C
4
1.00
300
60
3.3
22.9
76.3
9.5
6.0
48.0
22562
420.8
OSD+FF
1,2,3
1.00
144
90
3.3
40.3
279.6
19.7
17.4
71.0
24133
817.9
0S0+FF-C
1,2,3
1.00
144
90
3.3
40.3
279.6
11.5
10.1
71.0
24133
476.1
FS1+ESP-50
4
1.00
300
60
3.3
21.0
69.9
20.5
13.0
50.0
23687
865.7
FSH-ESP-50-C
4
1.00
300
60
3.3
21.0
69.9
11.8
7.5
50.0
23687
500.0
FSI+ESP-70
4
1.00
300
60
3.3
20.a
69.2
20.8
• 13.2
70.0
33162
626.9
FSI+ESP-70-C
4
1.00
300
60
3.3
20.8
69.2
12.0
7.6
70.0
33162
362.0
FSl+FF-50
1,2,3
1.00
144
90
3.3
34.4
239.0
21.1
18.6
50.0
17055
1235.9
FSI+FF-50-C
1,2,3
1.00
144
90
3.3
34.4
239.0
12.2
10.8
50.0
17055
717.1
FSI+FF-70
1,2,3
1.00
144
90
3.3
34.6
240.5
21.4
18.8
70.0
23877
895.8
FS1+FF-70-C
1,2,3
1.00
144
90
3.3
34.6
240.5
12.4
10.9
70.0
23877
519.7
8-13
-------
8.2 HOOSIER ENERGY RURAL ELECTRIC
8.2,1 Merom
Both units at the Merom plant are equipped with Mitsubishi systems;
therefore, additional S02 controls were not considered. SCR was the only
NOx control considered since both boilers are equipped with LNBs.
TABLE 8.2.1-1. MEROM STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE)
FGD SYSTEM INSTALLATION DATE)
1,2
490
40,42
1983,1982
OPPOSED WALL
NA
YES
3.4
10900
10
DRY DISPOSAL
LANDFILL/OFF-SITE
1
RAILROAD
L/LS FGD
1983,1982
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (6F)
ESP
1983,1982
0.05
99.4
3.8
743
1849
402
280
8-14
-------
TABLE 8,2.1-2. SUMMARY OF NOx RETROFIT RESULTS FOR MEROM
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
FIRING TYPE OWF
TYPE OF NOx CONTROL EQUIPPED WITH LNB
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE 1983,1982
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 89
New Duct Length (Feet) 400
New Duct Costs (1000$) 5022
New Heat Exchanger (1000$) 4836
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 9947
COMBINED CASE 15013
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20 '
* Cold side SCR reactors for units 1 and 2 would be located to
the west and east side of their L/LS-FGD systems, respectively.
8-15
-------
Table
8.2.1-3.
NOx Control Cost Results for
the Herom Plant
(June 1988 Dollars)
II
II
It
II
II
II
II
II
!¦
II
11
11
5==5=3=X
IS13SS3SS
¦33311!
asssKaaai
I3S33ISS
s==s:=as
sssaasss:
ssssasss:;;
ssssts
*s=!5!s=:5:s:=:rs
Technology
Soil«r
Main
loiter Capacity Coal
Capital Capital Annual
Annual
NOX
NOX
NOx Cost
Nyrtxr
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW)
<%>
Content
£$HM)
wm
WM)
(mi Ils/kwh}
(X)
(tons/yr)
CS/ton)
.....
Factor
......
.........
m
.......
......
_
sca-3
1
1.16
490
40
3.4
63.5
129.5
22.5
13.1
80.0
6663
3377.5
SCR-3
2
1.16
490
42
3.4
63.5
129.5
22.6
12.5
80.0
6996
3225.8
SCR-3
1-2
1.16
980
41
3.4
116.3
118.6
42.7
12.1
80.0
13659
3128.3
SCR-3-C
1
1.16
490
40
3.4
63.5
129.5
13.2
7.7
80.0
6663
1977.8
SCR-3-C
2
1.16
490
42
3.4
63.5
129.5
13.2
7.3
80.0
6996
1888.8
SCR-3-C
1-2
1.16
930
41
3.4
116.3
118.6
25.0
7.1
80.0
13659
1830.5
SCR*?
1
1.16
490
40
3.4
63.5
129.5
18.4
10.7
80.0
6663
2764.6
sea-/
2
1.16
490
42
3.4
63.5
129.5
18.5
10.3
80.0
6996
2642.0
SCR-7
1-2
1.16
980
41
3.4
116.3
118.6
34.6
9.8
80.0
13659
2530.4
SCR-7-C
1
1.16
490
40
3.4
63.5
129.5
10.8
6.3
80.0
6663
1626.6
SCR-7-C
2
1.16
490
42
3.4
63.5
129.5
10.9
6.3
80.0
6996
1554.4
SCR-7-C
1-2
1.16
980
41
3.4
116.3
118.6
20.3
5.8
80.0
13659
1487.9
8-16
-------
8.2.2 Frank E. Ratts Steam Plant
The Ratts steam plant is located on the White River in Pike County,
Indiana, and is operated by the Hoosier Energy Rural Electric Cooperative.
The Ratts plant contains two coal-fired boilers with a gross generating
capacity of 234 MW.
Table 8.2.2-1 presents operational data for the existing equipment at
the Ratts plant. Coal shipments are received by railroad and transferred to
coal storage and handling areas east and southeast of the plant. PM
emissions from the boilers are controlled by retrofit ESPs located behind
the boilers. Flue gases from the two boilers are directed to separate
chimneys behind the ESPs. Fly ash is disposed of in a pond south of the
plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/IS-FGD absorbers would be located in the open area behind the ESPs.
The site access/congestion factor would be low for the L/LS-FGD absorber
locations. For each unit, approximately 200 feet of ductwork would be
required to span the distance from the chimney to the absorbers and back to
the chimney. A low site access/congestion factor was assigned to flue gas
handling. The general facilities factor would be low (5 percent) because no
demolition/relocation of existing facilities would be required.
LSD-F6D was not considered for the Ratts plant because of the small
sizes of the ESPs. LSD with a new baghouse was not considered because the
medium to high sulfur content of the coal would likely favor application of
L/LS-FGD.
Table 8.2.2-2 summarizes the retrofit factor input to the IAPCS model
and Table 8.2.2-3 presents the estimated cost for installation of L/LS-FGD at
the Ratts plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 8.2.2-4 presents the IAPCS cost results for CS at the Ratts
plant. These costs do not include reduced pulverizer operating costs or any
system modifications that may be necessary for blending coals. PCC was not
evaluated because the Ratts plant is not a mine mouth plant.
8-17
-------
TABLE 8.2.2-1. FRANK E. RATTS STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 117
CAPACITY FACTOR (PERCENT) 60,62
INSTALLATION DATE 1970
FIRING TYPE FRONT WALL
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 2.8
COAL HEATING VALUE (BTU/LB) 11000
COAL ASH CONTENT (PERCENT) 9.2
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/ON-SITE
STACK NUMBER 1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1976
EMISSION (LB/MM BTU) 0.054,0.063
REMOVAL EFFICIENCY 99.9
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.1
SURFACE AREA (1000 SQ FT) 66.6
GAS EXIT RATE (1000 ACFM) 490
SCA (SQ FT/1000 ACFM) 136
OUTLET TEMPERATURE (*F) 310
8-18
-------
TABLE 8.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR F. E. RATTS
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
' LOW
NA
NA
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NA
ESTIMATED COST (1000$)
1079
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
0
8-19
-------
Table 8.2.2-3. Surmary of FED Control Costs for the Frank E. Ratts Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
$02 Cost
Nimber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MU)
<%>
Content
(SMH)
(VkM)
(SUN)
(mi 1 ks/kwh)
<%>
(tons/yr)
Factor
L/S FED
1
1.27
117
60
2.8
45.1
385.2
20.7
33.7
90.0
13815
1499.2
L/S FGD
2
1.27
117
62
2.8
45.1
385.2
20.9
32.9
90.0
14275
1463.0
L/S FGD
1-2
1.27
234
61
2.3
65.3
278.9
31.5
25.2
90.0
28090
1119.8
L/S FGD-C
1
1.27
117
60
2.8
45,1
385.2
12.1
19.6
90.0
13815
873.6
L/S FG0-C
2
1.27
117
62
2.8
45.1
385.2
12.2
19.1
90.0
14275
852.4
L/S FGO-C
1-2
1.27
234
61
2.8
65.3
278.9
18.3
14.6
90.0
28090
652.0
LC FGD
1-2
1.27
234
61
2.8
45.5
194.3
25.2 20.2
90.0
28090
897.4
LC FGD-C
1-2
1.27
234
61
2.8
45.5
194.3
14.6 11.7
90.0
28090
521.4
Sa3SSSSSSSSSIIC3SSSBSBSS8SSS3SaSSSSS8SBSSSBSI3ISSSSSSSSSSSSSSSSaSSSS3SS3311SaS)
8-20
-------
Table 8.2.2-4. Sunuary of Coat Switching/Cleaning Costs for the Frank S. Ratts Plant (June 1983 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nimtoer Retrofit Size factor Sutfur Cost Cost Cost
Difficulty (My) Content <$MH>
Factor (%}
Annual S02 S02 S02 Cost
Cost Removed Removed Effect,
(aills/kwh)
-------
NOx Control Technologies--
- LNBs were considered for N0X control at the Ratts plant because both
units have wall-fired, dry bottom boilers. The boiler volume was not
available and was estimated to be moderate based on boilers of similar size
and age. The LNB performance and cost estimates are presented in
Tables 8.2.2-5 and 8.2.2-6.
Selective Catalytic Reduction-
Cold side SCR reactors for the Ratts plant would be located behind the
chimneys, similar to the wet FGD absorbers. As in the FGD case, a low
general facilities value (13 percent) would be assigned to the locations. A
low site access/congestion factor would also be assigned to the reactor
locations. Approximately 200 feet of ductwork would be required to span the
distance between the SCR reactors and the chimneys. Tables 8.2.2-5 and
8.2.2-6 summarize the retrofit factors and costs for installation of SCR at
the Ratts plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Ratts plant because of the small size of the ESPs and because
insufficient duct residence time between the boilers and the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Both boilers at the Ratts plant would be candidates for retrofit or
repowering technologies solely because of their small boiler size. However,
both boilers have long remaining service life and high capacity factors
which might result in high replacement power costs in the case of extensive
boiler downtime.
8-22
-------
TABLE 8.2.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR F. E. RATTS
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
1-2
FIRING TYPE
FWF
NA
TYPE OF NOx CONTROL
LNB
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1961
NA
SLAGGING PROBLEM
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
40
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
30
51
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1086
1630
New Heat Exchanqer (1000$)
2048
3104
TOTAL SCOPE ADDER COSTS (1000$)
3165
4785
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
8-23
-------
Table 8,2.2-6. MOx Control Cost Results for the Frank E. Ratts Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NO*. NOx Cost
Number Retrofit Size Fictor Sulfur Cost Cost Cast Cost Removed Removed Effect.
Difficulty (X) Content <$MM) (S/kU) (mi I is/icwh) (X) (tons/yr) ($/ton)
Factor (%>
LNC-LNB
1
1.00
117
60
2.8
2.7
23.2
0.6
1.0
40.0
1181
495.3
LNC-IN8
2
1.00
117
62
2.8
2.7
23.2
0.6
0.9
40.0
1220
479.3
LNC-IN8-C
1
1.00
117
60
2.8
2.7
23.2
0.3
0.6
40.0
1181
294.1
LNC-IN3-C
2
1.00
117
62
2.8
2.7
23.2
0.3
0.5
40.0
1220
284.6
SCR-3
t
1.16
117
60
2.8
20.6
176.3
7.0
11.3
80.0
2362
2949.3
SCR-3
2
1.16
117
62
2.8
20.6
176.3
7.0
11.0
80.0
2440
2860.9
SCR-3
1-2
1.16
234
61
2.8
34.3
146.5
12.1
9.7
30.0
4802
2524.6
SCR-3-C
1
1.16
117
60
2.8
20.6
176.3
4.1
6.6
80.0
2362
1728.9
SCR-3-C
2
1.16
117
62
2.8
20.6
176.3
4.1
6.4
80.0
2440
1677.0
SCR-3-C
1-2
1.16
234
61
2.8
34.3
146.5
7.1
5.7
80.0
4802
1478.4
scR-r
1
1.16
117
60
2.8
20.6
176.3
6.0
9.7
80.0
2362
2536.9
SCR-7
2
1.16
117
62
2.8
20.6
176.3
6.0
9.5
80.0
2440
2461.9
SCR-7
1-2
1,16
234
61
2.8
34.3
146.5
10.2
8.1
80.0
4802
2119.0
SCR-7-C
1
1.16
117
60
2.8
20.6
176.3
3.5
5.7
80.0
2362
1492,6
SCR-7-C
2
1.16
117
62
2.8
20.6
176.3
3.5
5.6
80.0
2440
1448.4
SCR-7-C
1-2
1.16
234
61
2.8
34.3
146.5
6.0
4.8
80.0
4802
1246,0
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II
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II
II
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ii
ii
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11
11
II
II
II
II
II
II
II
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II
H
II
II
II
II
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ii
SSSSSSSS8S
II
II
II
II
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8-24
-------
8,3 INDIANA-KENTUCKY ELECTRIC CORPORATION
8.3.1 Clifty Creek Steam Plant
The Clifty Creek steam plant is located on the Ohio River in Jefferson
County, Indiana, and is operated by the Indiana-Kentucky Electric
Corporation. The Clifty Creek plant contains six coal-fired boilers with a
total design gross generating capacity of 1,302 MW.
Table 8.3.1-1 presents operational data for the existing equipment at
the Clifty Creek plant. Coal shipments are received by barge and
transferred to a coal storage and handling area east of the plant. PM
emissions from the boilers are controlled by retrofit ESPs located behind
the boilers. Flue gases from the boilers are directed to two chimneys; one
for units 1-3 and one for units 4-6. The units 1-3 chimney is located
behind the unit 1-3 ESPs and adjacent to the coal pile and the unit 4-6
chimney is located on the north side of the unit 4-6 ESPs. Fly ash is
disposed of in a pond west of the plant. Plant personnel indicated that
they are currently in the initial phases of converting their wet fly ash
system to dry.
Lime/timestw ie and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for all units would be located adjacent to and just
north of unit 6. The general facility factor would be high for this
location because several plant roads and a number of auxiliary facilities
would have to be relocated. The site access/congestion factor would be high
for this location due to space limitation created by units 4-6 ESPs,
chimney, coal storage area, and plant entrance. Approximately 100 to
300 feet of ductwork would be required for installation of the L/LS-FGD
system for units 4-6 and, after building a new chimney at the absorber
location, about 600 feet of ductwork would be required for units 1-3. A
hugh site access/congestion factor was assigned to flue gas handling for all
of the units.
LSD with reuse of the existing ESPs was not considered for unit 6 at
the Clifty Creek plant because unit 6 has hot side ESPs which could not be
reused. LSD with new FFs was not considered because of the high sulfur
8-25
-------
TABLE 8.3.1-1. CLIFTY CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2,3,4,5 6
217 217
89,92,96,85,94 94
1955 1955
FRONT WALL
NA NA
NO NO
3.3 3.3
11510 11510
10.9 10.9
DRY DISPOSAL+
PONDS/ON-SITE
1,1,1,2,2 2
BARGE
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (DF)
ESP ESP
1979(1-4)1978(5) 1977
0.01(1-3),0.02(4-6)
99.9 99.4
0.5-6.0
492.5
925
532
350
* Based on 1988 data.
+ Plant is converting wet fly ash system to dry.
0.3-6.0
483.8
1303
371
760
8-26
-------
content of the coal being burned at the plant. LSD with reuse of the
existing ESPs was evaluated for units 1-5. In order to access the upstream
of the ESPs, LSD absorbers for units 1-3 must be located in a small area on
the south side of the unit 1-3 ESPs. The site access/congestion factor
would be high for this location because of the proximity of the coal
conveyor, coal pile, and river. The general facility factor would be high
for this location because several storage buildings and roads would have to
be relocated. In addition, the river bank might have to be reinforced.
Approximately 300 to 600 feet of ductwork would be required for unit 1 and
600 to 1,000 feet would be required for units 2 and 3. A high site
access/congestion factor was assigned to flue gas handling because of the
congestion caused by the coal conveyor and the existing ductwork between the
boilers and the ESPs. LSD absorbers for units 4 and 5 would be located
similarly to the wet FGD absorbers at the north end of the plant. As in the
wet FGD case, a high site access/congestion factor and a high general
facilities value were assigned to the location. Between 600 and 1,000 feet
of ductwork would be required for installation of the LSD system for units 4
and 5. A high site access/congestion factor was assigned to flue gas
handling for units 4 and 5 because of the obstruction caused by the unit 6
ductwork. A high site access/congestion factor was assigned for upgrading
the existing ESPs.
Tables 8.3.1-2 through 8.3.1-6 present the retrofit factors and the cost
estimates for installation of conventional FGD technologies at the Clifty
Creek plant.
Coal Switching and Physical Coal Cleaning Costs--
Coal switching was not considered for the Clifty Creek plant because
all boilers are wet bottom boilers. Low sulfur bituminous coals having low
ash fusion temperature are not readily available in the east. This is
particularly true for wet bottom boilers.
NO Control Technologies--
A
Because of the boiler design and the fact that they are wet bottom,
LNC and NGR applications were not considered.
8-27
-------
TABLE 8.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CLIFTY CREEK
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1519 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.63 NA
ESP REUSE CASE 1.62
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
8-28
-------
TABLE 8.3,1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CLIFTY CREEK
UNIT 2 OR 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEETJ 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1519 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.63 NA
ESP REUSE CASE 1.76
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
8-29
-------
TABLE 8.3.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR CLIFTY CREEK
UNIT 4 OR 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCE5S/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.53 NA
ESP REUSE CASE 1.76
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) IS 0_ 15
8-30
-------
TABLE 8.3.1-5. SUMMARY OF RETROFIT FACTOR DATA FOR CLIFTY CREEK
UNIT 6
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA NA
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NA
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NA
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.53 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 0_
8-31
-------
Table 8.3.1-6, Suimafy of FGD Control Costs for the Clifty Creek Plant {June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
SOS Cost
Nuifcer
Retrofit
Siie
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
<%)
Content
(SMM)
(S/kU)
(SUM)
(mi IIs/kwh)
CJ»
(tons/yr3
(S/ton)
Factor
m
L/S FGO
1
1.63
217
89
3.3
81.6
375.9
40.4
23.9
90.0
42522
949.4
L/S FGO
2
1.63
217
92
3.3
81.6
376.0
40.8
23.3
90.0
. 43956
928.6
L/S FGO
3
1.63
217
96
3.3
81.6
376.0
. 41.4
22.7
90.0
45867
902.9
L/S FGD
4
1.53
217
85
3.3
77.0
355.1
38.3
23.7
90.0
40611
943.3
L/S FGD
5
1.53
, 217
94
3.3
77.1
355.1
39.6
22.2
90.0
44911
882.8
L/S FGD
6 ¦
1.53
217
94 .
3.3
82.1
378.2
40.4
22.6
90.0
44904
900.1
L/S FGO-C
1
1.63
217
89
3.3
81.6
375.9
23.5
13.9
90.0'
42522
552.6
L/S FGD-C
2
1.63
217
92
3.3
81.6
376.0
23.8
13.6
90.0
43956
540.4
L/S FGD-C
3
1.63
217
96
3-3
81.6
376. D
24.1
13.2
90.0
45867
525.3
L/S FGD-C
4
1.53
217
85
3.3
77.0
355.1
22.3
13.8
90.0
40611
548.9
L/S FGD-C
5
1.53
217
94
3.3
77.1
355.1
23.1
12.9
90.0
44911
513.5
L/S FGD-C
6
1.53
217
94 ¦
3.3
82.1
378.2
23.5
13.2
90.0
44904
523.9
LC FGD
1-3
1.63
651
92
3.3
137.6
211.3
82.7
15.8
90.0
131867
627,2
LC FGD
4-6
1.53
651
92
3.3
130.2
200.0
80.3
15.3
90.0
131867
609.0
LC FGD-C
1-5
1.63
651
92
3.3
137.6
211.3
48.0
9.1
90.0
131867
364.0
LC FGO-C
4-6
1.53
651
92
3.3
130.2
200.0
46.6
8.9
90,0
131867
353.4
LSD+ESP
1
1.62
217
89
3.3
43.7
201.6
23.3
13.7
76.0
36050
.645.0
LSD+ESP
2
1.76
„ 217
92
3.3
47.0
216.4
24.5
14.0
76.0
37265
656.8
LSD+ESP
3
1.76
217
96
3,3
47.0
216.5
24.9
13.6
76.0
38885
639.6
LSD+ESP
4
1.76
217
85
3.3
47.0
216.4
23.8
14.7
76,0
34430
690.9
LSD+ESP
5
1.76
217
94 -
,3.3
47.0
216.5
' 24.7
13.8
76.0
38075
648.0
LSD+ESP-C
1
1.62
217
89
3.3
43.7
201,6
13.5
8.0
76.0
36050
375.0
LSD+ISP-C
2
1.76
217
92
3.3
47.0
216.4
14.2
8.1
76.0
37265
382.0
LSD+ESP-C
3
1.76
217
96
3.3
47.0
216.5
14.5
7.9
76.0
38835
371,9
LSD+ESP-C
4
1.76
217
85
3.3
47.0
216.4
13.8
8.6
76.0
34430
401.9
LSD+ESP-C
S
1.76
217
94
3.3
47.0
216.5
14.3
8.0
76,0
38075
376.8
8-32
-------
Selective Catalytic Reduction--
Cold side SCR reactors for the CIifty Creek plant would be located near
the chimneys, A high general facilities value and a high site access/
congestion factor were assigned to units 1-3 reactor locations because of
the proximity of the coal conveyor, coal pile, and the river. In addition,
this location is close to the river and the soil has low load bearing
capacity. A medium site access/congestion factor was assigned to units 4-6
reactor locations. The general facility factor was medium {20 percent).
Approximately 200 to 300 feet of ductwork would be required to span the
distance between the SCR reactors and the chimney for units 4-6 and about
600 to 700 feet would be required for units 1-3. Tables 8.3.1-7 and 8.3.1-8
present the retrofit factors and cost for installation of SCR at the CIifty
Creek plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Because unit 6 has hot side ESPs, this unit was not considered for
sorbent injection technologies. Units 1-5, however, would be candidates for
FSI and DSD technologies because of the long duct residence times between
the boilers and the ESPs and the large sizes of the ESPs. Tables 8.3.1-9
and 8.3.1-10 present the retrofit factors and cost estimates for
installation of sorbent injection technologies at the CIifty Creek plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All six boilers at the CIifty Creek plant might be candidates for
AFBC/CG repowering because of their size (217 MW) and age. However, the
high capacity factors might result in a high replacement power cost due to
long boiler downtime.
8-33
-------
TABLE 8.3.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR CLIFTY CREEK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2,3
4,5
6
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
NA
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
NA
BOILER INSTALLATION DATE
1955
1955, 1955
1956
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
48
48
48
New Duct Length (Feet)
650
250
250
New Duct Costs (1000$)
5067
1949
1949
New Heat Exchanger (1000$)
2967
2967
0
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
8083
15482
4964
9552
1997
RETROFIT FACTOR FOR SCR
1.52
1.34
1.34
GENERAL FACILITIES (PERCENT)
38
20
20
8-34
-------
Table 8,3.1-8. NOx Control Cost Results for the Clifty Craak Plant (June 1988 Dollars)
SSj;-5{;g2Sgjgg2SIS55S5->SS5"*lllSISSS'*l-l-
(SMM)
(mi I ls/kwh}
(X)
(tons/yr)
<$/ton)
...........
.........
Factor
.......
m
........
SCR-3
1
1.52
217
89
3.3
44.5
205.2
15.0
8.8
80.0
9986
1498.8
SCR-3
2
1.52
217
92
3.3
44.5
205.2
15.0
8.6
80.0
10322
1456.1
SCR-3
3
1.52
217
96
3.3
44.5
205.2
15.1
8.3
80.0
10771
1403.3
SCR-3
4
1.34
217
85
3.3
36.4
167.8
13.1
8.1
80.0
9537
1372.5
SCR-3
S
1.34
217
94
3.3
36.4
167.8
13.3
7.4
80.0
10547
1259.1
SCR-3
6
1.34
217
94
3.3
33.7
155.1
12.8
7.2
80,0
10547
1214.4
SCR-3
1-3
1.52
651
92
3.3
104.7
160.8
. 38.4
7.3
80.0
30966
1238.8
SCR-3
4-6
1.34
651
92
3.3
174.4
267.8
49.7
9.5
80.0
30966
1604.2
SCR-3-C
1
1.52
217
89
3.3
44.5
205.2
6.8
5.2
80.0
9986
878.7
SCR-3-C
2
1.52
217
92
3,3
44.5
205.2
8.8
5.0
80.0
10322
853.6
SCR-3-C
3
1.52
217
96
3.3
44.5
205.2
8.9
4.9
80.0
10771
822.6
SCR-3-C
4
1.34
217
85
3.3
36.4
167.8
7.7
4.7
80.0
9537
803.5
SCR-3-C
S
1.34
217
94
3.3
36.4
167.8
7.8
4.3
80.0
10547
736.9
SCR-3-C
6
1.34
217
94
3.3
33.7
155.1
7.5
4.2
80.0
10547
710.1
SCR-3-C
1-3
1.52
651
92
3,3
104.7
160.8
22.4
4.3
80.0
30966
724.9
SCR-3-C
4-6
1.34
651
' 92
3.3
174.4
267.8
29.2
5.6
80.0
30966
944.4
SCR-7
1
1.52
217
89
3.3
44.5
205.2
13.2
7.8
80.0
9986
1319.1
SCR-7
2
1.52
217
92
3.3
44.5
205.2
13.2
7.6
80.0
10322
1282.3
SCR-7
3
1.52
217
96
3.3
44.5
205.2
13.3
7.3
80.0
10771
1236.8
SCR-7
4
1.34
217
85
3.3
36.4
167.8
11.3
7.0
30.0
9537
1184.4
SCR-7
5
1.34
217
94
3.3
36.4
167.8
11.5
6.4
80.0
10547
1089.0
SCR-7
6
1.34
217
94
3.3
33.7
155.1
11.0
6.2
80.0
10547
1044.3
SCR-7
1-3
1.52
651
92
3.3
104.7
160.8
33.0
6.3
80.0
30966
1Q65.0
SCR-7
4-6
1.34
651
92
3.3
174.4
267.8
44.3
8.4
80.0
30966
1430.4
SCR-7-C
1
1.52
217
89
3.3
44.5
205.2
7.7
4,6
80.0
9986
775.7
SCR-7-C
2
1.52
217
92
3.3
44,5
205.2
7.8
4.5.
80.0
10322
754.0
SCR-7-C '
3
1.52
217
96
3.3
44.5
205.2
7.8
4.3s
80.0
10771
727.1
SCR-7-C
4
1.3*
217
as
3.3
36.4
167.8
6.6
4.1
80.0
9537
695.7
SCR-7-C
5
1.34
217
94
3.3
36.4
167.B
6.7
3.8
80.0
10547
639.4
SCR-7-C
6
1.34
217
94
3.3
33.7
155.1
6.5
3.6
80.0
10547
612.6
SCR-7-C
1-3
1.52
651
92
3.3
104.7
160.8
19.4
3.7
80.0
30966
625.3
SCR-7-C
4-6
1.34
651
92
3.3
174.4
267.8
26.2
5.0
80.0
30966
844.8
SBEnss=--s.
It
H
II
»
II
II
11
II
II
II
II
II
II
II
H
II
H
11
II
SMSSS
11
11
il
II
11
II
II
H
It
II
II
II
II
II
II
II
5SSS33X"
II
II
M
11
N
8-35
-------
TABLE 8.3.1-9, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CLIFTY CREEK UNITS 1,2,3,4,5
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION HIGH
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 53
TOTAL COST (1000$)
ESP UPGRADE CASE 53
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.37
ESP UPGRADE 1.58
NEW BAGHOUSE NA
8-36
-------
Table 8.3.1-10. Sumery of BSD/FS1 Control Costs for the Ciifty Creek Plant (June 1988 Dollars)
Technology
Boiier
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
S02
S02
S02 Cost
Nimber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
(mills/kwh)
(X)
(tcos/yr)
(5/ton)
Factor
DSO+ESP
1
1.00
21?
89
3.3
14.6
67.4
14.5
8.6
49.0
22986
629.4
DSO+ESP
2
1.00
217
92
3.3
14.6
67.4
14.7
8.4
49.0
23761
620.5
DSO+ESP
3
1.00
217
96
3.3
14.6
67.4
15.1
8.3
49,0
24794
609,6
DSO+ISP
4
1.00
217
85
3.3
14.6
67.4
14.1
8.7
49.0
21953
642.2
OSD+ESP
5
1.00
217
94
3.3
14.6
67.4
14.9
8.4
49.0
24277
615.0
OSD+iSP-C
1
1.00
217
89
3.3
14.6
67.4
8.4
4,9
49.0
22986
363.5
OSO+iSP-C
2
1.00
217
92
3.3
14.6
67.4
8.5
4.9
49.0
2376V
358.3
OSD+ESP-C
3
1.00
217
96
3.3
14,6
67.4
8.7
4.8
49.0
24794
351.9
DSD+ESP-C
4
1.00
217
85
3.3
14.6
67.4
8.1
5.0
49.0
21953
370.9
DSO+ESP-C
5
1.00
217
94
3.3
14.6
67.4
8.6
4.8
49.0
24277
355.0
FSI+ESP-50
• 1
1.00
217
89
3.3
13.5
62.2
18.8
11.1
50.0
23624
797.6
FSI+ESP-50
2
1.00
217
92
3.3
13.5
62.2
19.3
11.1
50.D
24420
791.6
FSI+ESP-50
3
1.00
217
96
3.3
13.5
62.2
20.0
10.9
50.0
25482
784.1
FSI+ESP-50
4
1.00
217
85
3.3
13.5
62.2
18.2
11.3
50.0
22562
806.4
FSI+ESP-50
S
1.00
217
94
3.3
13.5
62.2
19,7
11.0
50.0
24951
787.7
FSI+ESP-50-C
1
1.00
217
89
3.1
13.5
62.2
10.9
6.4
50.0
23624
459.6
FSI+ESP-50-C
2
1.00
217
92
3.3
13.5
62.2
11.1
6.4
50.0
24420
456.0
FSI+ESP-50-C
3
1.00
217
96
3.3
13.5
62.2
11.5
6.3
50.0
25482
451.6
FSI+ESP-50-C
4
1.00
217
85
3.3
13.5
62.2
10.5
6.5
50.0
22562
464.7
FSJ+ESP-50-C
5
1.00
217
94
3.3
13.5
62.2
11.3
6.3
50.0
24951
453.7
FSI+ESP-70
1
1.00
217
89
3.3
(3.8
63.4
19.3
11.4
70.0
33073
582.4
FSI+ESP-70
2
1.00
217
92
3.3
13.8
63.4
19.8
11.3
70.0
34188
578.0
FSI+ESP-70
3
1.00
217
96
3.3
13.8
63.4
20.4
11.2
70.0
35675
572.6
FSI+ESP-70
4
1.00
217
85
3.3
13.7
63.4
18.6
11.5
70.0
31587
588.8
FSI+ESP-70
5
1.00
217
94
3.3
13.8
63.4
20.1
11.2
70.0
34932
575.3
FSI+ESP-70-C
1
1.00
217
89
3.3
13.8
63.4
11.1
6.6
70.0
33073
335.6
FSI+ESP-70-C
2
1.00
217
92
3.3
13.8
63.4
11.4
6.5
70.0
34188
333.0
FS1+ESP-70-C
3
1.00
217
96
3.3
13.8
63.4
11.8
6.4
70.0
35675
329.8
FSI+ESP-70-C
4
1.00
217
85
3.3
13.7
63.4
10.7
6.6
70.0
31587
339.3
F5I+ESP-70-C
5
1.00
217
94
3.3
13.8
63.4
11.6
6.5
70.0
34932
331.4
II
II
II
II
II
II
H
U
ii
II
¦1
ssssssssssssassssssaiia
________
issxassas
ssssaass
ssssasas
lassiisss
SSS55SS53SSSS5SSSS3S5SS3S55S
8-37
-------
8.4 INDIANA AND MICHIGAN ELECTRIC COMPANY
8.4.1 Breed Steam Plant
The Breed steam plant is located on the Wabash River in PIainfield
County, Indiana, and is operated by the Indiana and Michigan Electric
Company. The Breed plant contains one coal-fired boiler with a gross
generating capacity of 596 MW.
Table 8.4.1-1 presents operational data for the existing equipment at
the Breed plant. Coal shipments are received by railroad and transferred to
a coal storage and handling area south of the plant. PM emissions from the
boiler are controlled by retrofit ESPs. The ESPs are located on the south
side of the boiler adjacent to the old ESPs. Flue gases from the boiler are
directed to a chimney behind the boiler.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located adjacent to the ESPs east of the
unit. The general facilities factor would be low (5 percent) for the FGD
absorber location as would the site access/congestion factor. Approximately
400 feet of ductwork would be required to span the distance from the chimney
to the absorber and back to the chimney. A low site access/congestion
factor was assigned to flue gas handling.
LSD-FGD with reuse of the existing ESPs was not considered for the
Breed plant because of the marginal size and poor performance of the ESPs.
LSD with a new baghouse was not considered because of the high sulfur
content of the coal being burned.
Tables 8.4.1-2 and 8.4.1-3 present the retrofit factors input to the
IAPCS model and the cost estimates for installation of L/LS-FGD at the Breed
plant.
Coal Switching and Physical Coal Cleaning Costs--
CS was not considered for the Breed plant because low sulfur bituminous
coals having low ash fusion temperatures would be required for this
cyclone-fired boiler; this type of coal is not readily available in the
eastern United States. PCC was not considered for this plant because it is
not a mine mouth plant.
8-38
-------
TABLE 8.4.1-1. BREED STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
1
596
26
1960
CYCLONE
NA
NO
4.2
11000
10.9
DRY
ON-SITE/GIVEN AWAY
1
RAILROAD
ESP
1979
0.24
98.7
0.3
424
2000
212
300
8-39
-------
TABLE 8.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BREED UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NA
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NA
ESTIMATED COST (1000$) 0 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.31 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 0__
8-40
-------
TabU 8.4.1-3. Simmary of FGD Control Costs for the 8r#«d Plant
-------
N0X Control Technologies--
NGR was considered for the cyclone boiler at the Breed plant.
Tables 8.4.1-4 and 8.4.1-5 give a summary of the performance estimate and
costs for N0X control at the Breed plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the boiler at the Breed plant would be
located similarly to the wet FGD absorber. As in the FGD case, a low
general facilities value of 13 percent would be assigned to the location. A
low site access/congestion factor would also be assigned to the reactor
location. Approximately 400 feet of ductwork would be required to span the
distance between the SCR reactors and the chimney. Tables 8.4.1-4 and
8.4.1-5 summarize the retrofit factors and costs for installation of SCR at
the Breed plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the boiler at the Breed pi ant because of the small size of the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi1 i ty- -
The 596 MW boiler at the Breed pi ant is not a good candidate for
AFBC/CG technologies because of its large boiler size.
8-4.2 Rockport Steam Plant
The two boilers at the Rockport pi ant are NSPS boilers burning a low
sulfur coal. Unit 2 will start operation in late 1989 or early 1990.
Retrofit factors were developed for FGD, but due to the low sulfur content
of the coal, costs are not presented. Both boilers are equipped with LNBs,
hence the only N0X control technology considered was SCR. SCR costs for
unit 2 were not presented since the boi1er is not in operation as yet.
Sorbent injection was not evaluated since the boilers are burning such a low
sulfur coal.
8-42
-------
TABLE 8,4.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR BREED
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE CYC
TYPE OF NOx CONTROL NGR
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE 1960
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 103
New Duct Length (Feet) 400
New Duct Costs (1000$) 5631
New Heat Exchanger (1000$) 5439
TOTAL SCOPE ADDER COSTS (1000$) 11174
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
8-43
-------
Table 8.4.1-5. NOx Control Cost Results for the Breed Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coat Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (MU) (%) Content (tM«>
-------
TABLE 8.4.2-1. ROCKPORT STEAM PLANT OPERATIONAL DATA
UNIT NUMBER
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
1, 2
1, 2
1300
55,0
1984,1989
OPPOSED WALL
NA
YES
0.3
8000
5.2
DRY
LANDFILL/OFF-SITE
1
RAILROAD
ESP
1984,1989
O.Ol.NA
99.9.NA
0.6,NA
1097.4,NA
5100,NA
215,NA
289,NA
8-45
-------
TABLE 8.4.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR ROCKPORT UNIT 1 OR 2*
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE LOW
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 100-300
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO
ESTIMATED COST (1000$) NA
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER NO
NA
NA
NA
0
NO
NA
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.20
NA
NA
GENERAL FACILITIES (PERCENT) 5
NA
NA
NA
1.16
NA
1.16
NA
* L/S-FGD and LSD-FGD absorbers for units 1 and 2 would be located
behind the unit 1 chimney.
8-46
-------
TABLE 8,4.2-3. SUMMARY OF NOx RETROFIT RESULTS FOR ROCKPORT
UNIT NUMBER
COMBUSTION MODIFICATION RESULTS
1.2
FIRING TYPE NA
TYPE OF NOx CONTROL NA
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE NA
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 185
New Duct Length (Feet) 200
New Duct Costs (1000$) 4444
New Heat Exchanger (1000$) 8685
TOTAL SCOPE ADDER COSTS (1000$) 13314
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for units 1 or 2 would be located behind
the chimney.
8-47
-------
Table 8,4.2-4. NO* Control Cost Results for the 3 oc It port Plant (June 1988 Dollars)
Technology Boiler Wain Boiler Capacity Coal Capital Capital Annual Annual NO* NOx NQx Cost
Nuifeer Retrofit Size Factor Sulfur cost Cost Cost Cost Removed Removed Effect.
Difficulty (WW) (X) Content (SWO
-------
8.4.3 Tanners Creek Steam Plant
The Tanners Creek steam plant is located on the Ohio River in Dearborn
County, Indiana, and is operated by Indiana and Michigan Electric Company.
The Tanners Creek plant contains four coal-fired boilers with a gross
generating capacity of 1,101 MW.
Table 8.4.3-1 presents operational data for the existing equipment at
the Tanners Creek plant. Coal shipments are received by barge and
transferred to two separate coal piles. The coal pile southwest of the plant
contains low sulfur coal used by units 1-3 and the coal pile northeast of
the plant contains high sulfur coal used by unit 4. PM emissions from the
boilers are controlled by retrofit ESPs. The unit 1-3 ESPs are located
north of the unit 1-3 coal pile and the unit 4 ESPs are located beside the
unit 4 coal pile. Flue gases from boilers 1-3 are directed into a common .
chimney located behind the unit 1-3 ESPs. Unit 4 has a separate chimney
located behind the ESPs for unit 4. Fly ash is disposed of in a pond
southwest of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1-3 would be located behind the unit 3
ESPs. The unit 4 absorbers would be placed beside the unit 4 coal pile,
close to the unit 4 chimney. Both locations would have a low site access/
congestion factor. The general facilities factor would be medium
(8 percent) for units 1-3 because a plant road would have to be relocated.
A medium factor of 10 percent would be assigned to the unit 4 location due
to the relocation of a plant road and storage building. The duct length
needed to span the distance from the chimneys to the absorbers and back to
the chimneys for both locations would be 300 to 600 feet. Low site
access/congestion factors were assigned to flue gas handling.
LSD with reuse of the existing ESPs was considered for all units
because of their adequate ESP sizes. The absorbers for unit 1 would be
located beside the unit 1 ESPs, close to the river and the unit 1-3 coal
pile. Since this location is bounded on all sides, a high site access/
congestion factor was assigned. A duct length of 300 to 600 feet would
be required. A high site access/congestion factor was assigned to flue gas
8-49
-------
TABLE 8,4.3-1. TANNERS CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE ( F)
1,2 3
4
153 215
580
31 31
45
1951,52 1954
1964
ROOF-FIRED
CYCLONE
79.8 139
NA
NO " NO
NO
0.7 0.7
3.0
12300 12300
11100
7.6 7.6
9.7
WET DISPOSAL
PONDS/ON-SITE
1
1
2
BARGE
ESP
ESP
ESP
1977
1977
1977
0.01
0.01
0.04
99.7
99.7
98.3
0.3-6
0.3-6
0.3-6
585
853
1710
640
940
2300
914
907
743
340
340
340
8-50
-------
handling due to the congestion. LSD absorbers for units 2 and 3 would be
placed behind the unit 3 ESPs. A low site access/congestion factor was
assigned to this location. General facilities was assigned 8 percent due to
a road relocation. Unit 2 would require 600 to 1,000 feet of ductwork and
unit 3 would require approximately 400 feet of ductwork. The site access/
congestion factor for flue gas handling was medium for unit 2 and low for
unit 3. The unit 4 LSD absorbers would have the same location as the unit 4
wet FGD absorbers; hence, similar site access/congestion and general
facility factors were assigned to this location. Approximately 1,200 feet
of ductwork would be required. A low site access/congestion factor was
assigned to flue gas handling. ESP upgrading for units 1 and 2 would be
high due to the close proximity of the ESPs to the coal pile. For unit 3,
ESP upgrading would be low. ESP upgrading for unit 4 would be medium since
the unit 4 ESPs are close to the switchyard and the unit 4 coal pile.
However, the ESPs for these units have large SCAs and additional plate area
is not anticipated.
Tables 8.4.3-2 through 8.4.3-5 present the retrofit factor input to the
IAPCS model. Table 8.4.3-6 presents the estimated costs for installation of
L/LS and LSD-FGD technologies at the Tanners Creek plant unit 4. Costs are
not presented for units 1-3 since they are burning a low sulfur coal and
would yield high unit costs.
Coal Switching and Physical Coal Cleaning Costs--
Units 1-3 are currently burning a low sulfur coal and were not
considered for CS. CS was not considered for unit 4 because low ash fusion
temperature, low sulfur coals required for cyclone boilers are not readily
available in the eastern United States.
N0x Control Techno!ogies--
LNBs were considered for units 1-3 at the Tanners Creek plant because
they are roof-fired, dry bottom boilers. NGR was considered for the wet
bottom, cyclone boiler. Tables 8.4.3-7 and 8.4.3-8 present the N0x
performance and cost estimates for N0X control technologies at this plant.
8-51
-------
TABLE 8.4.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR TANNERS CREEK
UNI.T 1
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL
LOW
NA
HIGH
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
1373
NA
1373
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.38
NA
ESP REUSE CASE
1.69
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
10
8-52
-------
TABLE 8.4.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR TANNERS CREEK
UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 1373 NA 1373
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 NA
ESP REUSE CASE 1.45
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
8-53
-------
TABLE 8.4.3-4. SUMMARY OF RETROFIT FACTOR DATA FOR TANNERS CREEK
UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE LOW
RAGHHU^F fASF NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 1862 NA 1862
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 NA
ESP REUSE CASE 1.34
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
8-54
-------
TABLE 8.4.3-5. SUMMARY OF RETROFIT FACTOR DATA FOR TANNERS CREEK
UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE LOW
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 1000 +
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 4533 NA 4533
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 NA
ESP REUSE CASE 1.60
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 0 10
8-55
-------
Table 8,4.3-6. Sunnsry of FGD Control Costs for the Tanners Creek Plant (June 1968 Dollars!
Technology Boiler Main Boiler Capacity CosI Capital Capital Annual Annual S02 SOI $02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed, Effect.
Difficulty (MW> (X) Content (SMO
-------
TABLE 8.4.3-7. SUMMARY OF NOx RETROFIT RESULTS FOR TANNERS CREEK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
4
FIRING TYPE
ROOF-FIRED
CYCLONE
TYPE OF NOx CONTROL
LNB
LNB
NGR
FURNACE VOLUME (1000 CU FT)
79.8
139
NA
BOILER INSTALLATION DATE
1951,52
1954
1964
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
36
44
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
93
101
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
5205
5543
New Heat Exchanger (1000$)
5018
5351
TOTAL SCOPE ADDER COSTS (1000$)
10316
10995
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
8-57
-------
Table 8.4.3-8. NO* Control Cost Results for the Tanners Creek Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nmtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HW) (X) Content (SUM) (i/kW) (MM) (nills/kwh) (X) (tons/yr) (S/ton)
Factor (X)
INC-INB
LNC-LNB
INC-LN8-C
LMC-LN8-C
NGR
NGR-C
SCR-3
SCR *3
SCR-3-C
SCR-3-C
SCR-7
SCR-7
SCR-7-C
SCR-7-C
1,2
3
1,2
3
4
4 .
1-3
4
1-3
4
1-3
4
1-3
4
.00
.00
.00
.00
153
215
153
215
.00 580
.00 580
,16 521
.16 580
.16 S21
.16 580
.16 521
,16 560
.16 521
,16 580
31
31
31
31
45
45
31
45
31
45
31
45
31
45
0.?
0.7
0.7
0.7
3.0
3.0
0.7
3.0
0.7
3.0
0.7
3,0
0.7
3.0
3.0
3.5
19.8
16.1
3.0 19.8
3.5 16.1
8.3
8.3
67.1
74.1
67.1
74.1
67.1
74.1
67.1
74.1
14.3
14.3
28.8
27.8
28.8
27.8
28.8
27.8
28.8
27.8
0.7
0.7
0.4
0.4
12.8
7.4
23.5
27.4
13.8
16.0
19.2
22.6
11.3
13.3
1.6
1.3
0.9
0.8
5.6
3.2
16.6
12.0
9.7
7.0
13.6
9.9
8.0
5.8
36.0
44.0
36.0
44.0
60.0
60.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
30.0
632
1085
632
1085
11482
11482
4779
15310
4779
15310
4779
15310
4779
15310
1031.0
688.0
612.3
408.5
1114.1
641.5
4912.8
1790.6
2877.6
1047.6
4020,3
1475.7
2366.3
867.2
8-58
-------
Selective Catalytic Reduction--
Cold side SCR reactors for units 1-3 combined would be located behind
the unit 3 ESPs. As in the FGD case, a low site access/congestion factor
and a medium general facilities factor of 20 percent would be assigned to
this location. Approximately 400 feet of ductwork would be required. A low
site access/congestion factor was assigned to flue gas handling. Cold side
SCR reactors for unit 4 would be located beside the unit 4 chimney, close to
the coal pile. As in the FGD case, a low site access/congestion factor and
a medium general facilities factor of 20 percent would be assigned to the
unit 4 reactor location. A low site access/congestion factor was assigned
to flue gas handling. Tables 8.4.3-7 and 8,4.3-8 present the retrofit
factors and costs for installation of SCR at the Tanners Creek plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) would be ideal for all of
the boilers at the Tanners Creek plant because of the long duct residence
time and the large size of the ESPs. Tables 8.4.3-9 through 8.4.3-12
present retrofit factors and cost estimates for sorbent injection
technologies.
Atmospheric F1uidized Bed Combustion and Coal Gasification Applicability--
Boilers 1-3 would be candidates for repowering technologies because of
their small boiler size. Unit 4 is large and perhaps has a long remaining
service life; therefore, is not a good candidate for repowering.
8-59
-------
TABLE 8,4.3-9, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR TANNERS CREEK UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1373
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED-COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 41
TOTAL COST (1000$)
ESP UPGRADE CASE 1414
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS '
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
8-60
-------
TABLE 8.4.3-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR TANNERS CREEK UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1862
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 53
TOTAL COST (1000$)
ESP UPGRADE CASE 1915
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSENA
8-61
-------
TABLE 8.4.3-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR TANNERS CREEK UNIT 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 4533
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 112
TOTAL COST (1000$)
ESP UPGRADE CASE 4645
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
8-62
-------
Table 8.4.3-12. Sumiary of OSO/FSi Control Costs for tht Tamers Crwk Plant (June 1988 Dollars)
Technology Boiltr Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 SQ2 Cost
N unbar Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) {%) Content ($MH) (S/kU> (SW) cmf 1 Ls/ktrtiJ (X) (tons/yr)
factor <%)
DSD+ESP
1,2
1,00
153
31
0.7
7.6
49.6
4.8
11.5
49,0
1110
4323.5
OSB+ESP
3
1.00
21S
31
0.7
8.9
41.4
5.4
9.2
49.0
1559
3433.1
DSD+ESP
4
1.00
560
45
3.0
32.2
55.5
20.3
8.9
49.0
29440
689.7
OSD+ESP-C
1.2
1.00
153
31
0.7
7.6
49.6
2.8
6.7
49.0
1110
2507.8
0S0*ESP-C
3
1.00
215
31
0.7
8.9
41.4
3.1
5.3
49.0
1559
1992.5
DS0»ESP-C
4
1.00
580
45
3.0
32.2
55.5
11.8
5.2
49.0
29440
400.0
FS1+ESP-5Q
1,2
1.00
153
31
0.7
8.5
55.5
4.0
9.5
50.0
1140
3472.0
FSI»ESP-50
3
1.00
215
31
0.7
10.1
46.9
4.6
7.9
50.0
1603
2884.2
FSI+ESP-50
4
1.00
580
45
3.0
28.2
48.6
26.0
11.4
50.0
30257
860.0
FSI+ESP-50-C
1,2
1.00
153
31
0.7
8.5
55.5
2.3
5.6
50.0
1140
2022.6
FSt+ESP-50-C
3
1.00
215
31
0.7
10.1
46.9
2.7
4.6
50.0
1603
1680.7
Fsi*esp-50-c
4
1.00
580
45
3.0
28.2
48.6
15.0
6.6
50.0
30257
496.9
FSI~ESP-70
1,2
1.00
153
31
0.7
8.6
56.1
4.0
9.6
70.0
1597
2506.0
FSt+ESP-70
3
1.00
215
31
0.7
10.2
47.3
4.7
a.o
70.0
2244
2080.2
FSI+ESP-70
4
1.00
580
45
3.0
28.7
49.4
26.6
11.6
70.0
42360
627.5
FS1+ESP-70-C
1,2
1.00
153
31
0.7
8.6
56.1
2.3
5.6
70.0
1597
1459.8
FSI+ESP-70-C
3
1.00
215
31
0.7
10.2
47.3
2.7
4.7
70.0
2244
1212.2
FSI*ESP-70-C
4
1.00
580
45
3.0
28.7
49.4
15.4
6.7
70.0
42360
362.6
8-63
-------
8.5 INDIANAPOLIS POWER & LIGHT
8.5.1 Perry K Steam Plant
Retrofit factors and costs for SO2 and N0X control technologies for the
Perry K plant were not developed because of the small size of the boilers.
8.5.2 Petersburg Steam Plant
The Petersburg steam plant is located on the White River in Pike
County, Indiana, and is operated by the Indianapolis Power and Light
Company. The Petersburg plant contains four coal-fired boilers with a total
gross generating capacity of 1,718 MW.
Table 8.5.2-1 presents operational data for the existing equipment at the
Petersburg plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area south of the plant. PM emissions from
unit 1 are controlled by two retrofit ESPs. PM emissions from unit 2 are
controlled by one retrofit and one original ESP. PM emissions from
boilers 3 and 4 are controlled by ESPs installed at the time of
construction. The ESPs for units 1 and 2 are located behind stack 1 and the
ESPs for units 3 and 4 are located behind boilers 3 and 4, respectively.
Flue gases from boilers 1 and 2 are directed to a common chimney and flue
gases from boilers 3 and 4 are directed to a separate chimney for each
boiler. Fly ash from the units is disposed of in a pond to the north of the
plant.
Units 3 and 4 are equipped with new limestone FGD systems and, as such,
would not be considered candidates for additional SOg controls. The lime-
stone storage and handling area for these units is located north of the
plant. In addition, LNBs are used to control N0X emissions from boilers 3
and 4.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS or LSD-FGD absorbers would be located behind the unit 1 and 2
ESPs. The general facilities factor would be high (15 percent) for the FGD
absorber locations because a plant road, fuel tanks, and some underground
8-64
-------
TABLE 8.5.2-1. PETERSBURG STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME {1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE)
FGD SYSTEM (INSTALLATION DATE)
12 3 4
220 430 532 536
77 57 52 52
1967 1969 1977 1986
TANGENTIAL
155 310 517 517
NO NO YES YES
2.5
11000
8.0
WET DISPOSAL
PONDS/STORAGE ON-SITE
112 3
RAILROAD
NA NA LIMESTONE
NA NA 1977 1986
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE
1974
1982
1977
1986
EMISSION (LB/MM BTU)
0.02
0.03
0.02
0.03
REMOVAL EFFICIENCY
98.9
99.5
98.0
99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
2.
0-4.0
SURFACE AREA (1000 SQ FT)
NA
NA
NA
NA
GAS EXIT RATE (1000 ACFM)
900
1950
1900
2250
SCA (SQ FT/1000 ACFM)
NA
NA
NA
NA
OUTLET TEMPERATURE (*F)
300
340
297
300
8-65
-------
pipes have to be relocated. A high site access/congestion factor would be
assigned to the FGD absorber locations because of the congestion created by
water tanks, the river, and the underground obstruction due to the water
intake system. Construction would be blocked from all but one side for
crane access. In the L/LS-FGD case, approximately 350 feet of ductwork
would be required for each of the two units considered. A high site
access/congestion factor was assigned to flue gas handling because of the
congestion caused by the ESPs surrounding the chimney.
LSD with reuse of the existing ESPs was considered for unit 2. It was
assumed that the ESPs with some upgrading would be able to accommodate the
additional load. LSD with a new FF was considered for unit 1. Plant
personnel indicated that the unit 1 ESPs could not handle any additional
load. The LSD absorbers would be located similarly to the wet FGD absorbers
with similar site access/congestion and general facilities factors. For the
LSD case, approximately 400 and 550 feet of ductwork would be required for
units 1 and 2 respectively. A high site access/congestion factor was
assigned to flue gas handling for the LSD-FGD case because of the limited
space between the ESPs.
Tables 8.5.2-2 and 8.5.2-3 present retrofit factors and cost results for
commercial FGD technologies.
Coal Switching and Physical Coal Cleaning Costs-
Table 8.5.2-4 presents the IAPCS cost results for CS at the Petersburg
plant. These costs do not include reduced pulverizer operating cost changes
or any system modifications that may be necessary. PCC was not evaluated
for Petersburg because it is not a mine mouth plant.
Low NOx Combustion--
Boilers 3 and 4 are already fitted with LNBs, therefore, were not
considered for retrofit N0X control technologies. Boilers 1 and 2 at the
Petersburg steam plant are rated at 220 and 430 MW, respectively. The
combustion modification technique applied to these boilers was OFA.
Tables 8.5.2-5 and 8.5,2-6 give a summary of N0X retrofit and cost results.
8-66
-------
TABLE 8,5.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR PETERSBURG
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE (UNIT 2) HIGH
BAGHOUSE CASE (UNIT 1) HIGH
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE 300-600
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA HIGH
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES (UNIT 2)
ESTIMATED COST (1000$) 1901,3466 NA 3466
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1540,3010 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.70 NA
ESP REUSE CASE (UNIT 2) 1.69
BAGHOUSE CASE (UNIT 1) 1.62
ESP UPGRADE (UNIT 2) NA NA 1.58
NEW BAGHOUSE (UNIT 1 NA NA 1.58
GENERAL FACILITIES (PERCENT) 15 0 15_
8-67
-------
Table 8.5.2-3. Seminary of fSD Control Costs for the Petersburg Plant (June 1988 Dollars)
:ss=ss8sansB::;:s::sssss33a=s;::s:ss::ss±ss3sss:::ss=::sssssss3338=sss::s=3S8;s:::ssiss=sss=s=s=2;:;:s=;ss:=s;:
Technology Boiler Wain Boiler Capacity Coal Capital Capital Annual Annual S02 SD2 S02 Cost
Nuifcer
Retrofit Size
Difficulty CHW>
Factor
Factor
<*)
Sulfur
Content
(X)
Cost
(ttW)
Cost
Cost
Cost
-------
Table 8,5.2-4, Summary of Coal Switching/Cleaning Costs for the Petersburg Plant (June 1988 Dollars)
Technology Boiler Main Boiler
Number Retrofit Size
Difficulty (MV)
Factor
Capacity Coal Capital Capital Annual
factor Sulfur Cost Cost Cost
(X) Content {SMI} (S/kW) (tMM)
(X)
Annual SQ2 S02 S02 Cost
Cost Removed Removed Effect,
(mills/kwh) (X) (tons/yr) (S/ton)
CS/l*t15
CS/8*$15
1.00
1.00
220
430
77
57
8.1
16.5
36.8
38.3
21.5
31.8
14.5
14.8
68.0
68.0
2235?
32348
959.5
984.4
CS/B+S15-C
CS/B+S15-C
00
00
220
430
77
57
8.1
16.5
36.8
38.3
12.3
18.3
8.3
8.S
68.0
68.0
22357
32348
551.4
566.3
CS/B+S5
CS/9+J5
oo
00
220
430
77
57
2.5
2.5
5.8
12.0
26.4
27.9
8.8
13.3
5.9
6.2
68.0
68.0
22357
32348
393.4
412.0
CS/B+S5-C
CS/B+S5-C
00
00
220
430
77
57
2.5
2.5
5.8
12.0
26.4
27.9
5.1
7.7
3.4
3.6
68.0
68.0
22357
32348
226.6
237.7
8-69
-------
TABLE 8.5.2-5, SUMMARY OF NOx RETROFIT RESULTS FOR PETERSBURG
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
4
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
NA
NA
FURNACE VOLUME (1000 CU FT)
310
NA
NA
BOILER INSTALLATION DATE
1967,69
NA
NA
SLAGGING PROBLEM
NO
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000S)
49,81
95
95
New Duct Length (Feet)
350
800
400
New Duct Costs (1000$)
2751,4071
10539
5293
New Heat Exchanger (1000$)
2991,4472
5081
5104
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
5791,8624
11024
15715
NA
10492
NA
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
37
37
37
8-70
-------
Tabte 8.5.2-6. NOx Control Cost Results for the Petersburg Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx NOx Cost
Ntmber'Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU> (X) Content CSWO (««)
factor (%)
LNC-OFA
1
1.00
220
77
2.5
, 0.8
3.9
0.2
0.1
25.0
1272
143,6
LNC-OFA
2
1.00
430
57
2.5
1.1
2.6
0.2
0.1
25.0
1840
129.8
INC-OFA-C
1
1,00
220
77
2.5
0.8
3.9
0.1
0.1
25.0
1272
85.3
LNC-QFA-C
2
1.00
430
57
2.5
1.1
2.6
0.1
0.1
25.0
1840
77.0
SCR-3
1
1.52
220
77
2.5
42.1
191.3
13.8 '
9.3
80.0
4070
3400.7
SCR-3
2
1.52
430
57
2.5
69.9
162.5
23.5
10.9
80.0
5889
3991.3
SCR-3 ,
3
1.52
532
52
2.5
89.2
167.6
29.3
12.1
80.0
6647
4413.9
SCR-3
4
1.52
536
52
2.5
84.4
157.6
28.6
11.7
80.0
6697
4272.2
SCR-3
1-
2
1.52
650
64
2.5
99.3
152.8
34.4
9.4
80.0
9996
3442.9
SCR-3-C
1
1.52
220
77
2.5
42.1
191.3
8.1
5.5
80.0
4070
1994.7
SCR-3-C
2
1.52
430
57
2.5
69.9
162.5
13.8
6.4
80.0
5889
2340.0
SCR-3-C
3
1.52
532
52
2.5
89.2
167.6
17.2
7.1
80.0
6647
2589,0
SCR-3-C
4
1.52
536
52
2.5
84.4
157.6
16.8
6.9
80.0
6697
2504.2
SCR-3-C
1-
2
1.52
650
64
2.5
99.3
152.8
20.2
5,5
80.0
99%
2017.1
SCR-7
1
1.52
220
77
2.5
42.1
191.3
12.0
8.1
60.0
4070
2950,8
SCR -7
2
1.52
430
57
2.5
69.9
162.5
19.9
9.3
80.0
5889
3383.6
SCR-7
3
1.52
532
52
2.5
89.2
167.6
24.9
10.3
80.0
6647
3747.7
SCR-7
4
1.52
536
52
2.5
84.4
157.6
24.2
9,9
80.0
6697
3606.0
SCR-7
1-
2
1.52
650
64
2.5
99.3
152.8
29.0
8,0
80.0
9996
2901.7
SCR-7-C
1
1.52
220
77
2.5
42.1
191.3
7.1
4.8
80.0
4070
1737.0
SCR-7-C
2
1.52
430
57
2.5
69.9
162.5
11.7
5.5
80.0
5889
1991.8
SCR-7-C
3
1.52
532
52
2.5
89.2
167.6
14.7
6.1
80.0
6647
2207.4
SCR-7-C
4
1.52
536
52
2.5
B4.4
157.6
14.2
5.8
80.0
6697
2122.5
SCR-7-C
1-
2
1.52
650
64
2.5
99.3
152.8
17.1
4.7
80.0
9996
1707.0
8-71
-------
Selective Catalytic Reduction--
Cold side SCR reactors for units 1-3 would be located adjacent to the
ESPs. A high general facilities value (37 percent) would be assigned to the
location. A high site access/congestion factor would be assigned to the
absorber locations because of the obstruction caused by the water intake
system. About 350 and 800 feet of ductwork would be required for units 1-2
and 3, respectively. Cold side SCR reactors for unit 4 would be located
beside the unit 4 ESPs, north of its chimney. High site access/congestion
and general facility factors were assigned to this location. About 400 feet
of duct length would be required for this unit. Tables 8.5.2-5 and 8.5.2-6
summarize the estimated retrofit factor and cost estimates for retrofitting
SCR at the Petersburg plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for the
Petersburg plant for units 1 and 2. Because of the sufficient duct
residence time between the ESPs and the boilers, the ESPs were reused for
sorbent injection technologies. Upgrading of the existing ESPs would be
required to ensure that the precipitators would be able to handle the
additional load. Tables 8.5.2-7 and 8.5.2-8 present retrofit factors and
cost estimates for FSI and DSD technologies at the Petersburg plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Unit 1 is the only boiler at the Petersburg plant that is small enough
(220 MW) and old enough to be considered a potential candidate for AFBC/CS
repowering at this time. Also this unit has a long remaining life and high
capacity factor reducing the likelihood of near term repowering.
8.5.3 E. M. Stout Steam Plant
The E. W. Stout steam pi ant is 1ocated on the White River in Marion
County, Indiana, and is operated by the Indianapolis Power and Light
Company. The E. W. Stout plant contains a total of thirteen boilers;
eight retried petroleum-fired boilers, two peaking petroleum-fired boilers.
8-72
-------
TABLE 8.S.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR PETERSBURG UNIT 1 OR 2
I TEH
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1901
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 54
TOTAL COST (1000$)
ESP UPGRADE CASE 1955
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
8-73
-------
Table 8.5.2-a. Summary of DS0/F51 Control Casts for the Petarsburg Plant (June 1988 Dollars)
ssassssass
Technology Sailer Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 $02 Cost
Number Retrofit sue Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HU) (X) Content (SUM) (MM) (mills/ki4l) (S)
-------
and three coal-fired boilers (numbered 50, 60, and 70). The total gross
generating capacity of the three coal-fired boilers is 639 MW.
Table 8.5.3-1 presents operational data for the existing equipment at
the E. W. Stout plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area east of the plant. PM
emissions from the three coal-fired boilers are controlled by ESPs; one was
installed at the time of construction and the other two are retrofit. The
ESPs are located behind their respective boilers. Flue gases from the
boilers are directed to chimneys behind the ESPs. Fly ash is disposed of in
ponds to the south of the plant.
lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 50 and 60 would be located behind the
chimneys. L/LS-FGD absorbers for unit 70 would be located to the east of
the boiler. The general facilities factor would be high (15 percent) for
the L/LS-FGD absorber locations of units 50 and 60 due to the relocation of
a road and underground circulating water lines. The site access/congestion
factor would be low for unit 70 L/LS-FGD absorber locations. For units 50
and 60, the absorber location is congested and filling of the river flood
plain would be required to provide adequate land area. As such, a high site
access/congestion factor was assigned to the units 50 and 60 absorber
location. Approximately 300 to 400 feet of ductwork would be required to
span the distance from the chimneys to the absorbers and back to the
chimneys for each of the three units.
LSD with reuse of the existing ESPs was considered for the E. W. Stout
plant. It was assumed that the existing ESPs would be large enough to
accommodate the additional load. The LSD absorbers would be located
similarly to the L/LS-FGD absorbers. Over 400 feet of ductwork would be
required for all units. Site access/congestion factors for flue gas
handling would be high for all of the LSD absorber locations because of the
access difficulties to the upstream of the ESPs.
Tables 8.5,3-2 through 8.5.3-4 present the retrofit factors and cost
estimates for installation of conventional FGD technologies at the
E. W. Stout plant.
8-75
-------
TABLE 8.5.3-1. STOUT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE ( F)
50,50 70
100 439
37,42 39
1958,61 1973
TANGENTIAL
65
310
NO
NO
2.0
11000
8.8
WET
ON-SITE
1,2
3
RAILROAD
ESP
ESP
1969,71
1973
0.12,0.08
0.06
99.0
99.5
2.0-4.0
2.0-4.0
NA
NA
392
147
NA
NA
293
293
8-76
-------
TABLE 8.5.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR E. W. STOUT
UNIT 50 OR 60
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
300-600
ESP REUSE
NA
BAGHOUSE
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
938
NA
938
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.68
NA
ESP REUSE CASE
1.69
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
8-77
-------
TABLE 8.5.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR E. W. STOUT
UNIT 70
FGD TECHNOLOGY
FORCED LIME
L/L5 FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
3531
NA
3531
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.38
NA
ESP REUSE CASE
1.43
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
8-78
-------
Table 8.S.3-4, Saunary of FGD Control Costs for the Stout Plant (June 1988 Collars)
3233ScSISS83S
Technology
(sssasssi
Boiler
II8CISI8]
Main
Bofler Capacity Coal
Capital Capital Annual
MBSMSaaUE
¦ Annual
IEI331!
S02
13513SSICSSI
S02
SQ2 Cost
Nuiter
Retrofit
Si le
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Content
<««)
(S/kW3
<«#»>
(mi Us/kwti)
<%>
(tons/yr)
CS/ton)
........
Factor
........
CX>
.........
........
i .......
L/S FGO
50
1.68
100
37
2.0
54.5
545.3
21.1
65.2
90.0
5201
4065.7
L/S FGD
60
1.68
100
42
2.0
54.5
545.4
21.5
58.4
90.0
5904
3642.3
l/S FGO
70
1.38
439
39
2.0
103.3
235.2
43.4
29.0
90.0
24067
1804.2
L/S FG0-C
50
1.68
100
37
2.0
54.5
545.3
12.4
38.1
90.0
5201
2376.4
L/S FGD-C
60
1.68
100
42
2.0
54.5
545.4
12.6
34.2
90.0
5904
2128.3
L/S FCO-C
70
1.38
439
39
2.0
103.3
235.2
25.3
16.9
90.0
24067
1052.9
LC FGD
50-60
1.68
200
40
2.0
54.3
271.6
23.4
33.4
90.0
11246
2082.7
LC FGD
70
1.38
439
39
2.0
78.6
179.0
35.6
23.8
90.0
24067
1480.4
LC FGD-C
50-60
1.68
200
40
2.0
54.3
271.6
13.7
19.5
90.0
11246
1214.9
LC FGD-C
70
1.38
439
39
2.0
78.6
179.0
20.8
13.8
90.0
24067
. 862.8
lso+esp
SO
1.69
100
37
2.0
22.3
223.1
9.7
30.1
76.0
4409
2209.4
lso+esp
60
1.69
100
, 42
2.0
22.3
223.1
9.9
26.9
76.0
5005
1978.4
LSO+ESP
70
1.43
439
39
2.0
62.1
141.4
25.1
16.7
76.0
20403
1230.4
LSO+ESP-C
50
1.69
100
37
2.0
22.3
223.1
5.7
17.5
76.0
4409
12S8.6
LSO+ESP-C
60
1.69
100
42
2.0
22.3
223.1
5.8
15.7
76.0
5005
1153.5
LSO+ESP-C
70
1.43
439
39
2.0
62.1
141.4
14.7
9.8
76.0
20403
718.6
iinmuim
II
II
il
II
II
II
II
M
ssssssassasssssjss
_______
I5SS3IS35
SSSSSS8S
SSSS3SSS
5S1SSS5
31SSS3SSS3S;
35353S
II
II
II
II
II
II
II
II
8-79
-------
Coal Switching and Physical Coal Cleaning Costs--
Table 8,5.3-5 presents the IAPCS cost results for CS at the E. W. Stout
plant. These costs do not include boiler and pulverizer operating changes
or any system modifications that may be necessary for coal blending. PCC
was not considered for this plant because it is not a mine mouth plant.
N0x Control Techno!ogies--
Units 50, 60, and 70 are dry bottom, tangential-fired boilers;
therefore, OFA was considered for N0x control for the three coal-fired
boilers at the E. W. Stout plant. Performance and cost estimates developed
for the two 100 MW units (50 and 60) and one 439 MW unit (70) are presented
in Tables 8.5.3-6 and 8.5.3-7.
Selective Catalytic Reduction--
Cold side SCR reactors for the E. W. Stout plant would be located close
to the chimney. A medium general facilities value (20 percent) and a low
site access/congestion factor was assigned to the reactor location. A high
factor was assigned to units 50 and 60 reactor location and general
facilities for the same reasons as mentioned in the FGD section.
Approximately 200 feet of ductwork would be required to span the distance
between the SCR reactors and the chimneys for all three units.
Tables 8.5.3-6 and 8.5.3-7 present the retrofit factors and cost estimates
for installation of SCR at the E. W. Stout plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were only considered for
unit 70 at the E. W. Stout pi ant. Units 50 and 60 do not have sufficient
duct residence time and have marginal size ESPs and, as such, were not
considered for sorbent injection technologies. Tables 8.5.3-8 and 8.5.3-9
present the retrofit factors and cost estimates for DSD and FSI for unit 70.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 50 and 60 are good candidates for AFBC/CG repowering because of
their small boiler sizes. However, unit 70 is too large and has a long
remaining,useful life and would not likely be considered anytime in the near
future.
8-80
-------
Table 8.5.3-5. Sunmary of Coal Switching/Cleaning Costs for the Stout Plant (June 1988 Dollars).
¦¦iiiasicsassflssassataati
i*asatassi
K*3a3**BS
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
$02
$02
S02 Cost
Nutter
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cast "
tCBOVI
d Raraved
Effect.
Difficulty (MW)
Content
Factor
<*)
CS/B+S15
50
1.00
100
37
2.0
4.2
42.4
5.4
16.6
60.0
3439
1564.3
CS/B*S15
60
1.00
100
42
2.0
4.2
42.4
6.0
16.2
60.0
3903
1529.8
cs/B+ns
70
1.00
439
39
2.0
14.6
33.3
22.7
15.1
60.0
15911
1427.5
CS/B*S15-C
50
1.00
100
37
2.0
4.2
42.4
3.1
9.6
60.0
3439
901 .a
CS/B»S15-C
60
1.00
100
42
2.0
4.2
42.4
3.4
9,4
60.0
3903
SS1.4
CS/B»$15-C
70
1.00
439
39
2.0
14.6
33.3
13.1
8.7
60.0
15911
022.0
CS/B*$5
SO
1.00
100
37
2.0
3.2
32.0
2.5
7.8
60.0
3439
732.9
CS/B+S5
60
1.00
100
42
2.0
3.2
32.0
2.8
7.5
60.0
3903
704.7
CS/B*S5
70
1.00
439
39
2.0
10.1
22.9
9.5
6.4
60.0
15911
590.8
CS/B+S5-C
50
1.00
100
37
2.0
3.2
32.0
1.5
4.5
60.0
3439
424.1
CS/B+S5-C
60
1.00
100
42
2.0
3.2
32.0
1.6
4.3
60.0
3903
407.4
CS/B+S5-C
70
1.00
439
39
2.0
10.1
22.9
5.5
3.7
60.0
15911
345.9
===========
==========
---------
SSSS33
=========
SS8SSSSS
II
N
II
II
II
II
ll
-===3S=
============
------
II
II
II
II
II
II
II
II
II
II
II
II
H
II
II
II
II
II
8-81
-------
TABLE 8.5.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR E. W. STOUT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
50,60
70
FIRING TYPE
TANG
TANG
TYPE OF NOX CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA,65
310
BOILER INSTALLATION DATE
1958,1961
1973
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
27
82
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
991
2355
New Heat Exchanger (1000$)
1864
4528
TOTAL SCOPE ADDER COSTS (1000$)
2882
6964
RETROFIT FACTOR FOR SCR
1.52
1.16
GENERAL FACILITIES (PERCENT)
38
20
8-82
-------
Table B.I.3-7. NO* Control Cost Results for the Stout Plant
<*>
Content
(SHM)
(S/kU)
<»*)
(tons/yr)
(t/ton)
Factor
m
INC"OF*
50
1.00
100
37
2.0
0.6
6.2
0.1
0.4
25.0
278
479.4
INC-OFA
60
1.00
100
42
2.0
0.6
6.2
0.1
0.4
25.0
315
422.4
INC-QFA
70
1.00
439
39
2.0
1.1
¦ 2.5
0.2
0.2
25.0
1286
187.2
LMC-OFA-C
50
1.00
100
37
2.0
0.6
6.2
0.1
0.2
25.0
278
284.7
LNC-OFA-C
60
1,00
.100
42
2.0
0.6
6.2
' 0.1
0.2
25.0
315
250.8
IMC-OFA-C
70
1.00
439
39
2.0
1.1
2.5
0.1
0.1
25.0
1286
111.2
SCR-3
50
1.52
100
37
2.0
23.6
236.1
7.3
22.4
80.0
889
8180.2
SCR-3
60
1.52
100
42
2.0
23.6
236.1
7.3
19.8
80.0
1009
7232.4
SCR-3
70
1.16
439
39
2.0
55.5
126.5
19.8
13.2
80.0
4114
4807.6
SCR-3-C
50
1.52
100
37
2.0
23.6
236.1
4.3
13.2
80.0
889
4805.8
SCR-3-C
60
1.52
100
42
2.0
23.6
234.1
4.3
11.7
80.0
1009
4248.5
SCR-3-C
70
1.16
439
39
2.0
55.5
126.5
11.6
7.7
80.0
4114
2815.0
SCR-7
50
1.52
100
37
2.0
23.6
236.1
6.4
19.9
80.0
889 .
7243.9
SCR-7
60
1.52
100
42
2.0
23.6
236.1
6.5
17.6
80.0
1009
6407.6
SCR-7
70
1.16
439
39
2.0
55.5
126.5
16.1
10.8
80.0
4114
3919.4
SCR-7-C
50
1.52
100
37
2.0
23.6
236.1
3.8
11.7
80.0
889
4269.3
SCR-7-C
60
1.52
100 ,
42
2.0
23.6
236.1
3.8
10.4
80.0
1009
3776.0
SCR-7-C
70
1.16
439
39
2.0
55.5
126.5
9.5
6.3
80.0
4114
2306.1
S*3SSStStJlSSl3aSSa333SSSSS53833S3S98SSSS811SS8SSSS58SSS3&SS5S3S8SSSS385S93SSSS8SSSS333SfISSX3SSSSSSSSS3SSSSSSSSSS
8-83
-------
TABLE 8.5.3-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR E. W. STOUT UNIT 70
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
LOW
ESP UPGRADE
LOW
NEW BAGHOUSE
NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING
YES
ESTIMATED COST (10005)
3531
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
NA
ESTIMATED COST (1000$)
NA
ESP REUSE CASE
NA
ESTIMATED COST (1000$)
NA
DUCT DEMOLITION LENGTH (FT)
50
DEMOLITION COST (1000$)
91
TOTAL COST (1000$)
ESP UPGRADE CASE
3622
A NEW BAGHOUSE CASE
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.13
ESP UPGRADE
1.16
NEW BAGHOUSE
NA
8-84
-------
Tabic 8.5.3-9. Summery of DS0/FS1 Control Costs for the Stout Plant (June 1988 Dollars}
3S33SS{SS53»!SS!SSS3IC33SS ¦1330SS3338SS3383S 3333S3BSBS3IC3ti2l3S3S33S33S83339SttttS3339tt33383SMSSSSSi8333333333:33S333S8S;X3S3S33SSS
Technology Boiler Wain Boiler Capacity Coal Capital Capital Annual Annual $02 502 S02 Cost
Mutter Retrofit Sice Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW> CX> Content (SMH) (S/kW) (tona/yr) <»/ton)
Factor (X)
DSO+ESP 70
DSO+ESP-C 70
FSI~ESP-50 70
FS1+ESP-S0-C 70
FSl*E$P-70 70
FSI+ESP-70-C 70
1.00 439
1.00 439
1.00 439
1.00 439
1.00 439
1.00 439
39
39
39
39
39
39
2.0
2.0
2.0
2.0
2.0
2.0
26.6 60.6 14.2 9.5
26.6 60.6 8.3 5.5
26.3 59.9 15.8 10.5
26.3 59.9 9.1 6.1
26.3 59.8 15.9 10.6
26.3 59.8 9.2
6.2
49.0 13009
49.0 13009
50.0 13370
50.0 13370
70.0 18718
70,0 18718
1094.2
636.1
1178.1
683.8
851.5
494.2
8-85
-------
8.6 NORTHERN INDIANA PUBLIC SERVICE COMPANY
8.6.1 Baillv Steam Plant
The F6D retrofit factors are based on site visit information.
TABLE 8.6.1-1. BAILLY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY , ^
CAPACITY FACTOR (PERdENt)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
7 8
158 320
70 45
1962 1968
CYCLONE
NA
NO
3.1
11313
13
DRY
•SOLD/PAID
1 1
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
M)
(JF)
ESP
ESP
1980
1981
0.01
0.01
97.3
99.2
3.2
3.2
250.4
500.7
750
1350
334
. 371
305
290
8-86
-------
TABLE 8,6.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BAILLY
UNITS 7 AND 8 *
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
300-600,100-300
ESP REUSE
NA
BAGHOUSE
300-600,100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
NA
0
NA
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.23
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.23
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.1
GENERAL FACILITIES (PERCENT) 5
0
5
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for units 7
and 8 would be located behind the unit 8 ESPs (based on a
detailed site-specific study).
8-87
-------
Table 3.6.1-3. S-stPary of FGD Control Coses for the Bailly Plant (June 1968 Dollars)
II
<1
(I
II
II
II
II
II
II
II
II
=====¦===
X 3 53 3 3 SS S S 2
:s8ssss=i
SSSSSS8SS
saBssass:
!SC8C13B9
"3S3S83SS
isssasss
¦S5SCS3S333 8
S53SSS3SSS!
533Sl32SBS»i8
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
502
S02
S02 Cost
Nurfcer
Setrofi t
Size
Factor
SjIfur
Cast
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
-------
TABLE 8.6.1-4. SUMMARY OF NQx RETROFIT RESULTS FOR BAILLY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
7
8
7-8
FIRING TYPE
CYCLONE
CYCLONE
NA
TYPE OF NOx CONTROL
NGR
NGR
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
NA
BOILER INSTALLATION DATE
1962
1968
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
38
65
88
New Duct Length (Feet)
300
300
300
New Duct Costs (1000$)
1943
2946
3721
New Heat Exchanger (1000$)
2452
3759
4777
TOTAL SCOPE ADDER COSTS (1000$)
4433
6771
8586
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
* Cold side SCR reactors for units 7 and 8 would be located
beside the common chimney or after the FGD.
8-89
-------
Table 8.6.1-5. NOx Control Cost Results for the Bailly Plant (June 1988 Oollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capitat
Capital
Annual
Annual
NOx
NOx
MO* Cost
Nuitoer
Retrofit
Sire
factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MWJ
(X)
Content
CSMM)
(S/kW)
(MM)
(mi IIs/kwh)
(XJ
(tons/yr)
tt/ton)
Factor
(X)
SCR-3 -
7
1.16
158
70
3.1
26.1
165.2
9.5
9,8
80.0
6348
1502.7
SCR-3
6
1.16
320
41
3.1
44.9
140.2
16.4
13.0
80.0
8264
1986.7
SCR-3
7-8
1.16
480
53
3.1
60-. 5
126.0
23.3
10.4
80.0
14601
1594.0
SCi-3-C
7
1.16
158
70
3.1
26.1
165.2
5.6
5.8
80.0
6348
879.4
SCR-3-C
8
1.16
320
45
3.1
44.9
140.2
9.6
7.6
80.0
9264
1162.6
SCR-3-C
7-8
1.16
480
53
3.1
60.5
126.0
13.6
6.1
80.0
14601
931. B
SCR-7
7 •
1.16
158
70
3.1
26.1
165.2
8.2
8.5
80.0
6348
1296.4
SCR-7
8
1.16
320
45
3.1
44.9
140.2
13.8
10.9
80.0
8264
1665.7
SCR-7
7-8
1.16
480
53
3,1
60.5
126.0
19.3
8.7
80.0
14601
1321.5
SCS-'-C
7
1.16
158
70.
3.1
26.1
165.2
4.8
5.0
80.0
6348
761.2
SCR-7-C
8
1.16
320
45
3.1
44.9
140.2
8.1
6.4
80.0
8264
978.7
SCR-7-C
7-8
1.16
480
S3
3.1 ,
60.5
126.0
11.3
5.1
80.0
14601
775.7
:s::sasisis:
asaa==es3:
sssssssssa
:3xs)sassa
! SSSSSSC3SS3SSH
SSSV1SS3SSS33SSS33I31IS33!
3S3XSSSI
8-SO
-------
TABLE 8.6.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BAILLY UNITS 7 AND 8
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000S) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 42,72
TOTAL COST (1000$)
ESP UPGRADE CASE 42,72
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
8-91
-------
. Table 8.6.1-7. Sumnary of DSD/FSI Control Costs'for the Saitly Plant £4une 1988 Dollars)
:::s;s5S8s;s5ssss3S3ssB«;ss5ss3iisii3is5Sss=3s«asiai8B:"=:ss5=S8*c3sss5ss:£s=s»3a»:5s8SEsa»s8iisi::=s;s»sisi
Technology Boiler Hain Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size . Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty C*MM)
-------
8.6.2 Michigan City Steam Plant
CS was not evaluated for unit 12 at the Michigan City plant because it
is a cyclone boiler, and low sulfur bituminous coals having low ash fussion
temperatures are not readily available in the east. FSI was not evaluated
because of the small furnace volume size (cyclone boiler).
TABLE 8.6.2-1. MICHIGAN CITY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 4, 5, 6 12
GENERATING CAPACITY (Mil-each) 47 540
CAPACITY FACTOR (PERCENT) 55
INSTALLATION DATE 1951, 50, 51 1974
FIRING TYPE GAS BURNING CYCLONE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 2.7
COAL HEATING VALUE (BTU/LB) 11000
COAL ASH CONTENT (PERCENT) 9.2
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD PAID/OFF-SITE
STACK NUMBER 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1974
EMISSION (LB/MM BTU) 0.02
REMOVAL EFFICIENCY 94.9
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.1
SURFACE AREA (1000 SQ FT) 586.6
GAS EXIT RATE (1000 ACFM 1810
SCA (SQ FT/1000 ACFM) 324
OUTLET TEMPERATURE (*F) 325
8-93
-------
TABLE 8.6.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MICHIGAN CITY
UNIT 12 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
1.58
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD and LSD-FGD absorbers for unit 12 would be located
behind the unit 12 chimney.
8-94
-------
Table 8,6,2-3. Surinary of FGB Control Costs for the Michigan City Plant (June 1988 Doltars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content CUM) <$/kW)
-------
TABLE 8,6.2-4, SUMMARY OF NOx RETROFIT RESULTS FOR MICHIGAN CITY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
12
CYCLONE
NGR
268
1974
NO
60
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 96
New Duct Length (Feet) 200
New Duct Costs (1000$) 2658
New Heat Exchanger (1000$) 5127
TOTAL SCOPE ADDER COSTS (1000$) 7880
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 20
* Cold side SCR reactors for unit 12 would be located behind
the unit 12 chimney.
FIRING TYPE
TYPE OF NOx CONTROL
FURNACE VOLUME (1000 CU FT)
BOILER INSTALLATION DATE
SLAGGING PROBLEM
ESTIMATED NOx REDUCTION (PERCENT)
8-96
-------
Table 8.6.2-5, NOx Control Cost Results for the Michigan City Plant (Jurse 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NO* NOx NOx Cost
number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
TABLE 8.6.2-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MICHIGAN CITY UNIT 12
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 106
TOTAL COST (1000$)
ESP UPGRADE CASE 106
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
A short duct residence time exists between unit 12 and the
unit 12 ESPs. Little room is available around the ESPs, hence
a high factor was assigned to ESP upgrade.
8-98
-------
Table 8.6.2-7. Summary of 0SD/FS1 Control Costs for the Michigan City Plant (June 1908 Dollars)
335333'3333S3ffS3333333333333333333S3S33333S3S33333333533333333333333333335333333333S3S33Z33S23535535553S33;S:S:£:3;3;;5'2
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 $02 Cost
Nutter Retrofit Site Factor Sulfur Cost Cost Cost Cost Removed'Removed Effect.
Difficulty (S/kW) (SW) (miUs/kwh} (tons/yr) (S/ton)
Factor (X)
DSD+ESP 12 1.00 S40 55 2.7 24.5 45.4 19.0 7.3 49.0 30466 624.3
DSD+ESP-C 12 1.00 540 55 2.7 24.5 45.4 11.0 4.2 49.0 30466 361.3
5*S2"SSSSSS5353SS5SSSSSS5SSSS3SSSS5SS3SSSSSSSSSSSSSSSSSSSSSS5SSSS3SS5SSSSSSSS5SS3SZS5£5333S33"SSSS5SSSSSS:SSSSS:
8-99
-------
8.7 PUBLIC SERVICE COMPANY OF INDIANA
8.7.1 Cayuga Steam Plant
The Cayuga steam plant is located on the Wabash River in Vermin ion
County, Indiana, and is operated by the Public Service Company of Indiana.
The Cayuga plant contains two coal-fired boilers with a gross generating
capacity of 1,062 MW.
Table 8.7.1-1 presents operational data for the existing equipment at
the Cayuga plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area east of the plant. PM emissions from
the boilers are controlled by ESPs installed at the time of construction.
The ESPs are located behind the boilers. Flue gases from the two boilers are
directed to separate chimneys behind the ESPs. Fly ash is disposed of in a
pond south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located behind the ESPs. The general
facilities factor would be medium (8 percent) for the FGD absorber locations
because relocation of a road and part of the steam line would be necessary.
The site access/congestion factor would be low for the L/LS-FGD absorber
locations. Approximately 300 feet of ductwork would be required to span the
distance from the existing chimneys to the absorbers and then to a new
chimney. A low site access/congestion factor was assigned to flue gas
handling.
LSD with reuse of the existing ESPs was not considered for the Cayuga
plant because of the small sizes of the ESPs and the lack of adequate access
upstream of the ESPs. Because of the medium to high sulfur content of the
coal being used, LSD with a new FF was not considered for this plant.
Tables 8.7.1-2 and 8.7.1-3 present the retrofit factor input to the IAPCS
model and the estimated cost for installation of L/LS-FGD at the Cayuga
plant. Retrofit of SOg and/or N0X control technologies would perhaps
require extended outage (base load units) which are not considered and are
outside the scope of this study.
8-100
-------
TABLE 8.7.1-1. CAYUGA STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 531
CAPACITY FACTOR (PERCENT) 60,58
INSTALLATION DATE 1970,72
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) 375,343
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 2.4
COAL HEATING VALUE (BTU/LB) 10400
COAL ASH CONTENT (PERCENT) 12.4
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/ON-SITE
STACK NUMBER 1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1970,72
EMISSION (LB/MM BTU) 0.233
REMOVAL EFFICIENCY 98.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0
SURFACE AREA (1000 SQ FT) 311
GAS EXIT RATE (1000 ACFM 1723
SCA (SQ FT/1000 ACFM) 181
OUTLET TEMPERATURE (*F) 295
8-101
-------
TABLE 8.7.1-2, SUMMARY OF RETROFIT FACTOR DATA FOR CAYUGA
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
100-300 NA
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA NA
NEW BAGHOUSE NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA
ESTIMATED COST (1000S) 4188 NA
NEW CHIMNEY YES NA
ESTIMATED COST (1000$) 3717 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.29 NA
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE NA NA
NEW BAGHOUSE NA NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
8-102
-------
Table 8.7.1-3. Suimary of FGO Control Costs for the Cayuga Plant (June 1988 Dollars)
3SS55SSS83SSSSSSB5SSSI3KSSS3SSS5SSS5S58SSSS£33S5SSB3S55SSS-"S55SS-S5SS'">SSSSSSSSSSSS»3S«52 55r3S523S"»«S35;SS35
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 502 502 S02 Cost
Nwiber Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
l/S FQfi 1 1.29 531 60 2.4 119.0 224.1 58.5 21.0 90.Q 57316 1020.1
l/S FCO 2 1.29 531 58 2.4 119.0 224.1 57.8 21.4 90.0 55406 1043.2
l/S FGC-C 1 1.29 531 60 2.4 119.0 224.1 34.0 12.2 90.0 57316 593.8
l/S FGO-C 2 1.29 531 58 2.4 119.0 224.1 33.6 12.5 90.0 55406 607.3
IC FGD 1-2 1.29 1062 59 2.4 169.5 159.6 91.8 16,7 90.0 112722 814.7
IC FGO-C 1-2 1.29 1062 59 2.4 169.5 159.6 53.4 9.7 90.0 112722 473.5
8-103
-------
Coal Switching and Physical Coal Cleaning Costs--
Table 8.7.1-4 presents the IAPCS cost results for CS at the Cayuga
plant. These costs do not include pulverizer and boiler operating cost
changes or any system modifications to the coal handling system that may be
necessary. Because the Cayuga plant is not a mine mouth plant, PCC was not
considered.
N0X Control Technologies--
OFA was considered for N0X control at the Cayuga plant because both
boilers are tangential-fired. The estimated N0X reduction and costs
developed for the two 531 MW boilers are presented in Tables 8.7.1-5 and
8.7.1-6.
Selective Catalytic Reduction--
Cold side SCR reactors for the Cayuga plant would be located similarly
to the wet FGD absorbers next to the chimney/ESPs. As in the FGD case, a
medium general facilities value of 20 percent would be assigned to the
locations. A low site access/congestion factor would also be assigned to
the reactor locations. Approximately 150 feet of ductwork would be required
to span the distance between the SCR reactors and the chimneys.
Tables 8.7.1-5 and 8.7.1-6 summarize the retrofit factor inputs to the IAPCS
model and the estimated cost for installation of SCR at the Cayuga plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Cayuga plant because of the small sizes of the ESPs and because there is
insufficient duct residence time between the boilers and the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi 1 ity—
The two 131 MW boilers at the Cayuga plant are too large and have too
long a remaining useful life to be considered good candidates for AFBC/CG
repowering.
8-104
-------
Table 8.7.1-4. Suimary of Coal Switthing/Cleaning Costs for th# Cayuga Plant (June 1988 Dollars)
ssssssssssssssssasas
S3asssssssssss:
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 SQ2 $02 Cost
Nirber Retrofit Size Factor Sulfur Cast Cost Cost Cost Removed Removed Effect,
Difficulty (MU> (X) Content (SWO (S/kW) (SW) (mills/kwh) (S) (tons/yr) <$/ton)
Factor (X)
CS/B*S15
CS/B+$15
1.00
1.00
531
531
60
58
2.4
2.4
17.3
17.3
32.5
32.5
39.1
38,0
14.0
14.1
68.0
68.0
43532
42081
898.9
901.9
C5/B+S15-C
CS/B+H5-C
1.00
1.00
531
531
60
58
2.4
2.4
17.3
17.3
32.5
32.5
22.5
21.8
8.1
8.1
68.0
68.0
43532
42081
516.8
518.5
CS/B*$5
CS/B+15
1.00
1.00
531
531
60
58
2.4
2.4
22.1
22.1
15.1
14.7
5.4
5.4
68.0
68.0
43532
42081
347.
349.
CS/8+tS-C
CS/B+S5-C
1.00
1.00
531
531
60'
58
2.4
2.4
11.8
11.8
22.1
22.1
8.7
8.5
3.1
3.1
68.0
68.0
43532
42081
200.1
201.4
SSS3E3XS8S
8-105
-------
TABLE 8,7,1-5, SUMMARY OF NOx RETROFIT RESULTS FOR CAYUGA
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 375,343
BOILER INSTALLATION DATE 1970,1972
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 95
New Duct Length (Feet) 150
New Duct Costs (1000$) 1974
New Heat Exchanger (1000$) 5075
TOTAL SCOPE ADDER COSTS (1000$) 7144
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
8-106
-------
Table 8.7.1-6. NO* Control Cost Results for the Cayuga Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NO* MOx Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMU> (X) Content <$HM> (S/kW) (milU/kwh) {») (tons/yr) (S/tori)
Factor ¦ <%)
LNC-OFA 1
INC-OFA 2
LNC-QFA-C 1
LNC-QFA-C 2
SCR-3 1
5CR-3 2
SCR-3-C 1
SCR-3-C 2
SCR-7 1
SCR-7 2
SCR-7-C 1
SIR-7-C 2
1.00 531 60
1.30 531 58
1.00 531 60
1.00 531 58
1,16 531 60
1.16 531 58
1.16 531 60
1.16 531 58
1.16 531 60
1.16 531 58
1.16 531 60
1.16 531 5B
2.4 1.2 2.3
2.4 1,2 2.3
2.4 1.2 2.3
2.4 1.2 2.3
2.4 64.8 122.1
2.4 64.8 122.1
2.4 64.8 122.1
2.4 64.8 122.1
2.4 64.8 122.1
2.4 64.S 122.1
2.4 64.8 122.1
2.4 64.8 122.1
0.3 0.1 25.0
0.3 0.1 25.0
0.2 0.1 25.0
0.2 0.1 25.0
24.3 8.7 80.0
24.2 9.0 80.0
14.2 5.1 '80.0
14.2 5.2 80.0
19.8 7.1 80.0
19.7 7.3 80.0
11.6 4.2 80.0
11.6 4.3. 80.0
2551 101.7
2466 105.2
2551 60.4
2466 62.5
8165 2971.8
7893 3066.2
8165 1738.2
7893 1793.5
8165 2426.0
7893 2501.5
8165 1425.5
7893 1470.0
8-107
-------
8.7.2 R. A, Gallagher Steam Plant
The R. A. Gallagher steam plant is located on the Ohio River in Floyd
County, Indiana, and is operated by the Public Service Company of Indiana.
The R. A. Gallagher plant contains four coal-fired boilers with a gross
generating capacity of 600 MW.
Table 8.7.2-1 presents operational data for the existing equipment at
the R. A. Gallagher plant. Coal shipments are received by barge and
transferred to a coal storage and handling area south of the plant. PM
emissions from the units are controlled by retrofit ESPs located behind the
boilers. Flue gases from the boilers are directed to two chimneys, one for
units 1 and 2 and one for units 3 and 4. Fly ash is disposed of in ponds to
the north and south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for all of the units would be located north of
unit 4. The general facilities factor would be low (5 percent) for the
L/LS-FGD absorber locations. However, because the absorber sites, north of
unit 4, should be brought up to plant grade, high general facilities
(15 percent) is assigned for excavation. Because ample space is available,
low site access/congestion factors were assigned to the absorber locations.
Approximately 300 feet of ductwork with a new chimney would be required for
installation of the wet FGD system for units 3 and 4 and a low site
access/congestion factor was assigned to flue gas handling for these units.
Plant personnel indicated that a new chimney would be needed because of the
existing chimeny's deteriorating condition. Because the unit 1 and 2
chimney is difficult to access, a new chimney would be built for these
units. The ductwork requirements would be reduced to between 400 and
500 feet for each unit. A high site access/congestion factor was assigned
to flue gas handling for units 1 and 2 because of the congestion around
these units due to the proximity of the chimneys and river.
LSD with reuse of the existing ESPs was not considered for units 1-4 at
the Gallagher plant because of the small sizes of the ESPs. LSD with new
FFs was not considered for the plant because of the high sulfur content of
the coal being used.
8-108
-------
TABLE 8.7.2-1. R. A. GALLAGHER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2,3,4
GENERATING CAPACITY (MW-each) 150
CAPACITY FACTOR (PERCENT) 32,27,31,19
INSTALLATION DATE 1959,58,60,61
FIRING TYPE FRONT WALL
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 3.2
COAL HEATING VALUE (BTU/LB) 11600
COAL ASH CONTENT (PERCENT) 10.0
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/ON-SITE
STACK NUMBER 1,1,2,2
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1969,69,68,68
EMISSION (LB/MM BTU) 0.38
REMOVAL EFFICIENCY 99.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.4
SURFACE AREA (1000 SQ FT) 121
GAS EXIT RATE (1000 ACFM 630
SCA (SQ FT/1000 ACFM) 192
OUTLET TEMPERATURE ( F) 263
8-109
-------
Tables 8.7.2-2 through 8.7.2-4 present retrofit factor inputs to the
IAPCS model and the estimated costs for installation of a L/LS-FGD system at
the Gallagher plant.
Coal Switching and Physical Coal Cleaning Costs--
Table 8.7.2-5 presents the IAPCS cost results for CS at the Gallagher
plant. These costs do not include boiler and pulverizer operating cost
changes or any coal handling system modifications that may be necessary.
PCC was not considered for the Gallagher plant because it is not a mine
mouth plant.
NOx Control Technologies--
LNBs were considered for N0X emissions control for the four front
wall-fired furnaces at the Gallagher plant. The NOx reduction and cost
estimates developed for the four units, rated at 150 MW each, are presented
in Tables 8.7.2-6 and 8.7.2-7.
Selective Catalytic Reduction--
Cold side SCR reactors for units 1 and 2 would be located adjacent to
unit 1 south of the plant and the reactors for units 3 and 4 would be
located adjacent to unit 4 north of the plant. A low general facilities
value of 13 percent was assigned to the reactor locations. A medium site
access/congestion factor was assigned to the unit 1 and 2 absorber locations
because of the proximity of the coal conveyor and the river. A low site
access/congestion factor was assigned to the unit 3 and 4 absorber
locations. Approximately 400 feet of ductwork would be required to span the
distance between the SCR reactors and the chimneys. Tables 8.7.2-6 and
8.7.2-7 summarize the retrofit factor inputs to the IAPCS model and cost
estimates for installation of SCR at the Gallagher plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Gallagher plant because of the small sizes of the existing ESPs and the
short duct residence time between the boilers and ESPs.
8-110
-------
TABLE 8.7.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR R. A. GALLAGHER
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL
LOW
NA
NA
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NA
ESTIMATED COST (1000$)
1348
NA
NA
NEW CHIMNEY
YES
NA
NA
ESTIMATED COST (1000$)
1050
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
0
8-111
-------
TABLE 8.7.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR R. A. GALLAGHER
UNIT 3 OR 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
NA
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA '
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NA
ESTIMATED COST (1000$)
1348
NA
NA
NEW CHIMNEY
YES
NA
NA
ESTIMATED COST (1000$)
1050
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.29
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
0
8-112
-------
Table 8.7.2-4. Sjimary of FGD Control Costs for the R. A. Gallagher Plant (Jwe 1988 Dollars)
x||BassK.3.S2...3-..-;.;...=.;...s.£3|1|...3-:..31I|1|ss|tlttBa|S38...8||SI|safl|t||saf||s||||t||saB3S|||SZ|asB|B
Technology soMer Wain Bailer Capacity Coal Capital Capital Annuat Annual $02 S02 ; $02 Cost
Nurrfcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removad Removed Effect,
Difficulty (MW) (X) Content {SWO CS/kW) {SUM) (mills/kwh) (X) (tons/yr) (f/ton)
Factor <%>
L/S FGD
1
1.48
150
32
3.2
60.5
403.5
23.9
56
a
90.0
10157
2349.8
L/S FGD
2
1.48 •
150
27
3.2
60.5
403.5
23.3
65
7
90.0
8570
2718.8
L/S FCO
3
1.29
150
31
3.2
53.5
356.5
21.5
52
7
90.0
9840
2182.0
US FGD
4
1.29
150
19
3.2
53.5
356.4
20.1
SO
5
90.0
6031
3330.6
L/S FGD
1-2
1.48
300
30
3.2
90.3
301.1
35.7
45
3
90.0
19045
1876.2
L/S FGD
3-4
1.29
300
25
3.2
80.0
266.7
31.3
47
7
90.0
15871
'¦1975.0
L/S FGD-C
1
1.48
150
32
3.2
60.5
403.5
13.9
33
2
90.0
10157
1373.0
L/S FGO-C
2
1.48
150
27
3.2
60.5
403.5
13.6
38
4
90,0
8570
1589.4
L/S FGO-C
3
1.29
150
31
3.2
53.5
356.5
12.5
30
8
90.0
9840
1274.5
L/S FGD-C
4
1.29
150
19
3.2
53.5
356.4
11.7
47
1
90.0
6031
1948.0
L/S FGD-C
1-2
1.48
300
30
3.2
90.3
301.1
20.9
26
5
90.0
19045
1096.2
L/S FGD-C
3-4
1.29
300
25
3.2
ao.o
266.7
18.3
27
9
90.0
15871
1154.1
LC FEB
1-2
1.48
300
30
3.2
68.8
229.4
28.9
36
7
90.0
19045
1518,2
LC FGD
3-4
1.29
300
25
3.2
61.1
203.5
25.4
38
6
90.0
15871
1597.5
LC FGD
1-4
1.39
600
27
3.2
111.2
185.4
46,4
32
7
90.0
34281
1352.4
LC FGO-C
1-2
1.48
300
30
3.2
68.8
229.4
16.9
21
4
90.0
19045
886.0
LC FGD-C
3-4
1.29
300
25
3.2
61.1
203.5
14.8
22
5
90.0
15871
932.5
LC FGD-C
1-4
1.39
600
27
3.2
111.2
185.4
27.1
19
1
90.0
34281
789.4
aasstsssssassss
.........
If
II
II
It
II
II
II
isas=ei
;sniim
II
«
II
II
II
II
II
«
S3SS3IC1
Hssaass:
sass
....
I
I
R
II
«
S
i!
II
!!
sssiaaix
8-113
-------
Table 8.7.2-5. Sunmary of Coal Switehir»g/CIeaning Costs for the R. A. Gallagher Plant {June 1988 Dollars)
SCSSSSSrSSSSB
SIR1III!
KBSHBBSI
-«-> m- 2«S5 3S
sciium
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
502
S02 Cost
Nuitoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Oiffieylty
<%>
Content
(two
(*/kV5
(SMO
(miUs/kMh)
(S)
(tons/yr)
($/ton)
Factor '
<*>
CS/B+115
1
1.00
150
32
3.2
5.9
39.1
6.9
. 16.5
73.0
8250
838.7
CS/B+S15
2
1.00
150
27
3.2
5.9
39.1
6.0
17.0
73.0
6961
868.8
CS/B+*15
3
1.00
150
31
3.2
5.9
39.1
6.7
16.6
73.0
7992
844.0
CS/B*t15
6
1,00
150,
19
3.2
5.9
39.1
4.7
18.6
73.0
4898
949.9
CS/B*I15-C
1
1.00
150
32
3.2
5.9
39.1
4.0
9.5
73.0
8250
483.7
CS/B+S15-C
2
1.00
1S0
27
3.2
5.9
39.1
3.5
9.8
73.0
6961
501.6
CS/B+S15-C
3
1.00
150
31
3.2
5.9
39.1
3.9
9.6
73.0
7992
486.8
CS/B+S15-C
4
1.00
150
19
3.2
5.9
39.1
2.7
10.8
73.0
4898
549.6
CS/B+S5
1
1.00
150
32
3.2
4.3
28.7
3.2
7.5
73.0
8250
384.7
CS/B+>5
2
1.00
150
27
3.2
4.3
28.7
2.8
8.0
73.0
6961
408.7
CS/B+t5
3
1.00
150
31
3.2
4.3
28.7
3.1
7.6
73.0
7992
338.9
CS/B+S5
4
1.00
150
19
3.2
4.3
28.7
2.3
9.3
73.0
4898
473.2
CS/B*S5-C
1
1.00
150
32
3.2
4.3
28.7
1.8
4.4
73.0
8250
222.8
CS/B*$5-C
2
1.00
150
27
3.2
4.3
28.7
1.6
4.6
73.0
6961
236.9
CS/8*$5-C
3
1.00
150
31
3.2
4.3
28.7
1.8
4.4
73.0
7992
225.2
CS/B»t5-C
4
1.00
150
19
3.2
4.3
28.7
1.3
5.4
73.0
4898
275.1
•s5ss33~5?ssss:s:ss::::ssss3:ss:ss5s:ssss3wsssssssssssssss:3sss:sssssssss8s:
8-114
-------
TABLE 8.7.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR R. A. GALLAGHER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3,4
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1959, 1958
1960, 1961
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
40
40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
37
37
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
2513
2513
New Heat Exchanger (1000$)
2377
2377
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
4926
7434
4926
7434
RETROFIT FACTOR FOR SCR
1.34
1.16
GENERAL FACILITIES (PERCENT)
13
13
8-115
-------
Table 6.?.2-7. MOx Control Cost Results for the R. A. Gallagher Plant (Jim 1988 Dollars)
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital
Annual
Annual
MOX
NOX
NO* Cost
Nmfcer Retrofit
Size
Factor
Sulfur
Cost
Cost .
Cost
Cost
Removed Removed
Effect.
Difficulty (m/)
(X)
Content
(two
(i/ku)
(SMH)
(mi IIs/kwh)
(XJ
(tons/yr)
(f/ton)
Factor
LNC-LNB
t -
1.00
150
32
3.2
3.0
20.0
0.6
1.5
40.0
760
850.4
LNC-LNB
2
1.00
. 150
27
3.2
3.0
,20.0
0.6
1.8
40.0
641
1007.9
LNC-LN8
3
1.00
150
31
3.2
3.0
20.0
0.6
1.6
40.0
736
877.9
LNC-LNB
4
1.00
150
19
3.2
3.0
20.0
0.6
2.6
40.0
451
1432.3
LNC-LNB-C
1
1.00
150
32
3.2
3.0
20.0
0.4
0.9
40.0
760
505.0
LNC-LNB-C
2
1.00
150
27
3.2
3.0
20.0
0.4
1.1
40.0
641
598.5
LNC-LNB-C
3
1.00
150
31
3.2
3.0
20.0
0.4
0.9
40.0
736
521.3
LNC-LNB-C
4
1.00
150
19
3.2
3.0
20.0
0.4
1.5
40.0
451
850.5
SCR-3
1
1.34
150
32
3.2
27.7
184.5
8.8
21,0
80.0
1519
5801.3
SCR-3
2
1,34
150
27
3.2
27.7
184.5
8.8
24.7
80.0,
1282
6841.3
SCR-3
3
1.16
150
31
3.2
25.5
170.2
8.3
20.3
80.0
1472
5621.6
SCR-3
4
1.16
150
19
3.2
25.5
170.1
8.2
32.7
80.0
902
9057.2
SCR-3
1-2
1.34
300
30
3.2
46.7
155.8
15.4
19.6
80.0
2849
5417.5
SCR-3
3-4
1.16
300
25
3.2
43.2
144.1
14.5
22.0
80.0
2374
6098.7
SCR-3-C
1
1.34
150
32
3.2
27.7
184.5
5.2
12.3
80.0
1519
3405.4
SCR-3-C
2
1.34
150
27
3.2
27.7
184.5
5.1
14.5
80.0
1282
4016.4
SCR-3-C .
3
1.16
1S0
31
3.2
25.5
170.2
4.9
11.9
80.0
1472
3298.5
SCR-3-C
4
1.16
150
19
3.2
25.5
170.1
4.8
19.2
80.0
902
5316.1
SCR-3-C
1-2
1.34
300
30
3.2
46.7
155.8
9.1
.11.5
80.0
2849
3177.5
SCR-I-C
3-4
1.16
300
25
3.2
43.2
144.1
8.5
12.9
80.0
2374
3575,8
SCR-7
1
1.34
150
32
3.2
27.7
184.5
7.6
18.0
80.0
1519
4986.0
SCR-7
2
1.34
150
27
3.2
27.7
184.5
7.5
21.2
80.0
1282
5874.9
SCR-7
3
1.16
150
31
3.2
25.5
170.2
7.0
17.3
80.0
1472
4779.9
SCR-7
4
1.16
150
19
3.2
25.5
170.1
6.9
27.8
80.0
902
7683.9
SCR-7
1-2
1.34
300
30
3.2
46.7
155.8
13.0
16.4
80.0
2849
4547.8
SCR-7
3-4
1.16
300
25
3.2
43.2
144.1
12.0
18.3
80.0
2374
5054.9
SCB-7-C
1
1.34
. 150
32
3.2
27.7
184.5
4.5
10.6
80.0
1519
2938.3
SCS-7-C
2
1.34
150
27
3.2
27.7
184.5
4.4
12.5
80.0
1282
3462.7
SCR-7-C
3
1.16
150
31
3.2
25.5
170.2
4.1
10.2
80.0
1472
2816.3
SCR-7-C
4
1.16
150
19
3.2
25.5
170.1
4.1
16.4
80.0
902
4529.2
SCR-7-C
1-2
1.34
300
30
3.2
46.7
155.8
7.6
9.7
80.0
2849
2679.1
SCR-7-C
3-4
1.16
300
25
3.2
43.2
144.1
7.1
10.8
80.0
2374
2977.7
ssssssssssss
S Jt®3SSM5S
¦SI!S33S:
II
it
If
II
II
It
it
8-116
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All four boilers at the Gallagher plant would be good candidates for
repowering with AFBC/CG technologies because of their small boiler size and
age.
8.7,3 Gibson Steam Plant
The Gibson steam plant is located on the Wabash River in Gibson County,
Indiana, and is operated by the Public Service Company of Indiana, The
Gibson plant contains five coal-fired boilers with a total gross generating
capacity of 3,340 MW.
Table 8.7.3-1 presents operational data for the existing equipment at
the Gibson plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area southwest of the plant. PM emissions
from boiler 1 are controlled by retrofit ESPs. PM emissions from the other
boilers are controlled by ESPs which were installed at the time of
construction. All five ESPs are located behind the boilers. Flue gases
from boilers 1-4 are directed to two chimneys: one for boilers 1 and 2 and
one for boilers 3 and 4. Flue gas from the fifth boiler is directed to a
third chimney. Fly ash from the units is wet sluiced and disposed of in
large ponds surrounding the plant.
Sulfur emissions from the fifth boiler are controlled by a new FGD
system. The limestone storage and handling area for this unit is located
northwest of the plant.
Lime/limestone and Lime Spray Drying FGD Costs--
L/LS or LSD-FGD absorbers" for units 1-4 would be located behind the
chimneys. The general facilities factor would be low (5 percent) for all
absorber locations. However, a high site access/congestion factor was
assigned to the FGD absorber locations for boilers 2-4 because of the
proximity of the coal conveyor. A low site access/congestion factor would
be assigned to unit 1. In the L/LS-FGD case, approximately 100 feet of
ductwork would be required for each of the four boilers.
LSD with reuse of the existing ESPs was considered for all four units
because of the adequate sizes of their ESPs. For the LSD case,
8-117
-------
TABLE 8.7.3-1. GIBSON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW,EACH)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM
FGD TYPE
FGD INSTALLATION DATE
1,2 3,4,5
-668 668
61,54 58,59,43
1975 1978,79,82
OPPOSED WALL
513
NO YES
2.5
10,700
10.3
WET SLUICE
PONDS/ON-SITE
1 2 3
RAILROAD'
NO YES (UNIT 5)
LIMESTONE
1982
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1976,75
EMISSION (LB/MM BTU) 0.12
REMOVAL EFFICIENCY 99.1
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.1
SURFACE AREA (1000 SQ FT) 562
GAS EXIT RATE (1000 ACFM) 2282
SCA (SQ FT/1000 ACFM) 246
OUTLET TEMPERATURE ( F) 290
ESP
1978,79,82
0.12
99.1
3.1
576,576,900
2282
252,252,394
290
8-118
-------
approximately 600 feet of ductwork would be required for each of the four
boilers. A high site access/congestion factor was assigned to flue gas
handling for the LSD-FGD case because of the close proximity of the ESPs and
difficult access to the ESP inlets.
Table 8.7.3-2 gives a summary of retrofit data for commercial FGD
technologies. Separate retrofit factors have been developed for upgrading
the existing ESPs for units 1-4. FGD costs are presented in Table 8.7.3-3.
The low cost FGD option reduces capital costs due to eliminating the spare
absorber and economy of scale that results when combining process areas and
increasing absorber size.
Coal Switching and Physical Coal Cleaning Costs--
Table 8.7.3-4 presents the IAPCS cost results for CS at the Gibson
plant. These costs do not include boiler and pulverizer operating cost
changes or any system modifications that may be necessary to blend coal.
PCC was not evaluated because this is not a mine mouth plant.
Low N0X Combustion--
Boilers 1-5 at the Gibson steam plant are each rated at 668 MW.
Boilers 3-5 are already equipped with LN8 and will not be considered here.
The combustion modification technique applied to boilers 1-2 was LNBs.
Tables 8.7.3-5 and 8.7.3-6 give a summary of LNB retrofit cost and
performance results.
Selective Catalytic Reduction--
Cold side SCR reactors would be located beside the chimneys. A low
general facilities value was assigned to all units. A low site access/
congestion factor was assigned to all reactor locations. About 200 feet of
ductwork would be required for each unit. Tables 8.7.3-5 and 8.7.3-6
summarize the estimated costs and reactor performances for retrofitting SCR
at the Gibson plant.
Furnace Sorbent Injection and Duct Spray Drying--
Sorbent injection technologies (FSI and DSD) were considered for the
Gibson plant. The duct residence time between the boilers and ESPs is
8-119
-------
TABLE 8.7.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR GIBSON
UNITS 1-4 (EACH)
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL (1,2-4)
LOW,HIGH
NA
LOW,HIGH
FLUE GAS HANDLING (1,2-4)
LOW,HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
5145
NA
5145
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM (1,2-4)
1.27,1.60
NA
ESP REUSE CASE (1,2-4)
1.43,1.69
BAGHOUSE CASE
NA
ESP UPGRADE (1,2-4)
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
5
8-120
-------
Table 8.7.3*3. Simmary of FGO Control Costs for the Gibson Plant (June 1988 Dollars)
SSSBSS3SS
Technology Sailer Main Boiler Capacity Coal Capital Capital Annual
Number Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (MU) <%) Content ($MM) <$/kU) (SMH3
Factor (%)
Annual S02 S02 SQ2 Cost
Cost Removed Removed Effect,
(mills/kwh) <%) (tors/yr) (I/ton)
L/S F3D
L/S FK!
1
1 .27
2,3,4 1.60
668
668
61
58
2.5
2.5
133.2
162.4
199.4
243.1
68.1
76.3
19.1
22.5
90.0
90.0
73903
70273
920.9
1085.4
L/S FG0-C
L/S FGD-C
1
1.27
2,3,4 1.60
668
668
61
58
2.5
2.5
133.2
162.4
199.4
243.1
39.6
44.4
11.1
13.1
90.0
90.0
73908
70273
535.7
632.2
LC FQD
LC FGD
1-2
3-4
1.43 1336
1.60 1336
58
58
2.5
2.5
219.6
241,4
164.4
180.7
116.1
123.2
17.1
18.2
90.0
90.0
140546
140546
826.2.
876.6
LC FG0-C
LC FGD-C
1-2
3-4
1.43 1336
1.60 1336
58
58
2.5
2.5
219.6 164.4
241.4 180.7
67.5
71.7
9.9
10.6
90,
90,
140546
140546
480.4
510.0
LS0+ESP
LSD+ESP
1
1.43
2,3,4 1.69
668
668
61
58
2.5
2.5
88.8
101.8
133.0
152.3
41.5
44.5
11.6
13.1
58,
68.
55931
53180
741.5
836.4
LSD+ESP-C
LSD+ESP-C
1
1.43
2,3,4 1.69
668
668
61
58
2.5
2.5
88.3
101.8
133.0
152.3
24.2
25.9
6.8
7.6
68.0
68.0
55931
53180
431.9
487. a
8-121
-------
Table' 8.7,3-4, Surrmary of Coal Switching/Cleaning Costs fop the Gibson Plant (Jun® 1988 Dollars)
Technology Boiler Main Boiler
Nunber Retrofit Size
Difficulty (MW)
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
(X) Content
CS/8+S15
CS/B+S15
1,2
3,4
1.00
1.00
668
668
60
60
2.5
2.5
20.2
20.2
30.3
30.3
49.4
49.4
14.1
14.1
69.0
69.0
55421
55421
890.6
890.6
CS/B+S15-C
CS/B+S15-C
1,2
3,4
1.00
1.00
668
668
60
60
2.5
2.5
20.
20.
30.3
30.3
28.4
28.4
8.1
8.1
69.0
69.0
55421
55421
511.9
511.9
CS/B+S5
CS/i*$5
1,2
3,4
1.00
1.00
668
668
60
60
2.5
2.5
13.3
13.3
19.9
19.9
19.1
19.1
69.0
69.0
55421
55421
345.'4
345,4
CS/8+S5-C
CS/S+SS-C
1,2
3,4
1.00
1.00
668
668
60
60
2.5
2.5
13.3
13.3
19.9
19.9
11.0
11.0
69.0
69.0
55421
55421
199.0
199.0
8-122
-------
TABLE 8.7.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR GIBSON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3,4,5
FIRING TYPE
OWF
OWF
TYPE OF NOx CONTROL
LNB
EQUIPPED WITH LNI
FURNACE VOLUME (1000 CU FT)
513
513
BOILER INSTALLATION DATE
1975
1978-1982
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
55
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
112
112
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
3010
3010
New Heat Exchanger (1000$)
5825
5825
TOTAL SCOPE ADDER COSTS (1000$)
8947
8947
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
8-123
-------
Table 8.7.3-6, NQx Control Cost Results for the Gibson Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nirtser Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty
-------
insufficient for sorbent injection or humidification. However, the ESPs for
units 1-4 may be sufficient in size such that the first ESP sections can be
modified for sorbent injection or humidification. ESP upgrade and plate
area additions were assigned a high access/congestion factor. Table 8.7.3-7
presents the retrofit scope adders and multipliers. Table 8.7.3-8 presents
the cost for installation of FSI and DSD technologies at the Gibson plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Appl icabi1i ty- -
None of the units would be considered good candidates for repowering or
retrofit because of their large boiler sizes and high capacity factors.
8.7.4 Wabash River Steam Plant
The Wabash River steam plant is located on the Wabash River in Vigo
County, Indiana, and is operated by the Public Service Company of Indiana.
The Wabash River plant contains six coal-fired boilers with a total gross
generating capacity of 920 MW.
Table 8.7.4-1 presents operational data for the existing equipment at
the Wabash River plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area north of the plant. PM
emissions from the boilers are controlled by ESPs; unit 6 ESPs were
installed at the time of construction and the other five are retrofit. The
ESPs are located behind their respective boilers. Flue gases from the
boilers are combined in a common overhead duct and exit through a single
chimney located at the south end of the plant. Fly ash is disposed of in
ponds to the south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for the six units (combined) would be located next
to the common chimney. The general facilities factor would be medium
(8 percent) for the absorber location because several storage buildings
would have to be relocated. The site access/congestion factor would be low
for the absorber location. Approximately 300 feet of ductwork would be
required to span the distance from the chimney to the absorbers and to a new
chimney. Because of the outage time required to reline the existing chimney
8-125
-------
TABLE 8.7.3-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GIBSON UNITS 1-4 (EACH)
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 5145
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 124
TOTAL COST (1000$)
ESP UPGRADE CASE 5269
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
8-126
-------
Tabte 8,7.3-8, Sumwry of OSB/FSI Control Costs for the Gibson Plant (June 1988 Dollars)
Technology loiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 SOZ SC2 Cost
Number Retrofit Site Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (%) Content (MM) (S/ltW) C$#N) Cmills/kwh) <%>
-------
TABLE 8.7.4-1. WABASH RIVER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
1,2
3,4
5 -
6
113
91
125
387
23,10
27,10*
16
20
1953
1954,55
1956
1968
FRONT WALL
TANG
NA
63.0
66.3
225
NO
NO
NO
NO
2.1
2.1
2.1
2.1
10800
10800
10800
10800
10.4
10.4
10.4
10.4
WET DISPOSAL
ON-SITE
1
1
RAILROAD
1
1
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
ESP
ESP
1970
1971,69
1969
1968
0.13
0.13
0.13
0.13
98.5
98.5
98.5
98.0
3.5
3.5
3.5
3.5
65,63
62.6
75.6
165.5
400
400
500
1212
162,157
157
151
137
269
269
289
286
*assumed 10 percent capacity factor for unit 4
8-128
-------
and the small diameter of the existing chimeny, a new chimney would be
constructed adjacent to the absorbers. A low site access/congestion factor
was assigned to flue gas handling.
LSD-FGD with reuse of the existing ESPs was not considered for the
Wabash River plant because of the small sizes of the ESPs. LSD-FGD with new
FFs was not considered for the plant because of the medium to high sulfur
content of the coal being used.
Tables 8.7.4-2 and 8.7.4-3 present the retrofit data and costs for
installation of a L/LS-FGD system at the Wabash River plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 8.7.4-4 presents the IAPCS cost results for CS at the Wabash
River plant. These costs do not include boiler and pulverizer operating
cost changes or any coal handling system modifications that may be
necessary. PCC was not considered for the Wabash River plant because it is
not a mine mouth plant.
N0X Control Technologies--
OFA was considered for NCL control for the unit 6 tangential-fired
x 3
boi1er and LNBs were evaluated for the five front wall-fired boi1ers.
Performance and cost results developed for the six units are presented in
Tables 8.7.4-5 and 8.7.4-6. Furnace volumes were not available for units 1-4
and were estimated based on similar size and age boilers.
Selective Catalytic Reduction--
Cold side SCR reactors (combined) for the Wabash River plant would be
located behind the common chimney. As in the FGD case, a medium general
facilities value of 20 percent would be assigned to the reactor location
due to the necessity of relocating some storage buildings. A low site
access/congestion factor was assigned to the reactor location.
Approximately 300 feet of ductwork would be required to span the.distance
between the SCR reactors and the chimney. Tables 8.7.4-5 and 8.7.4-6 present
the retrofit factors and cost estimates for installation of SCR at the
Wabash River plant.
8-129
-------
TABLE 8.7.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR WABASH RIVER
UNITS 1-6 (COMBINED)
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
YES NA NA
6855 NA NA
YES NA NA
6440 0 0
NO
RETROFIT FACTORS
FGD SYSTEM 1.40 NA
ESP REUSE CASE . • NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 0_
8-130
-------
Table 8.7.4-3. Sumnary of FGD Control Costs for the Wabash Uivcr Plant {June 1988 Dollars)
Technology Boiler Main Boiler
Nurtoer Retrofit Size
Difficulty (MW5
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
«) Content ($MM> (J/kHJ ($MM)
<%>
Annual S02 S02 S02 Cost
Cost Removed Removed Effect.
Ctons/yr)
l/S FGD 1-6
l/S FSD-G 1-6
LC FGD 1-6
LC FGD-C 1-6
1.40 920 18
1.40 920 18
1.40 920 18
1.40 920 18
2.1 180.6 196.3
2.1 180.6 196.3
2.1 151.8 165.0
2.1 151.8 165.0
66.8 46.0 90.0
39.1 26.9 90.0
57.7 39.8 90.0
33.8 23.3 90.0
24963 2675.1
24963 1565.1
24963 2313.4
24963 1352.7
8-131
-------
Table 8,7.4-4. Summary of Coal Switching/Cleaning Costs for the Wabash River Plant {June 1988 Dollars)
============
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II
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II
II
II
S3SSSS331
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satiaia
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issxaais:
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
SQ2 Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
-------
TABLE 8,7.4-5. SUMMARY OF NQx RETROFIT RESULTS FOR WABASH RIVER
BOILER NUMBER
C0M8USTI0N MODIFICATION RESULTS
1,2,3,4
5
6
1-6
FIRING TYPE
FWF
FWF
TANG
NA
TYPE OF NOx CONTROL
LNB
LNB
OFA
NA
FURNACE VOLUME (1000 CU FT) NA,NA,63,63
66.3
225
NA
BOILER INSTALLATION DATE
1953-5
1956
1968
NA
SLAGGING PROBLEM
NO
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
40
36
25
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
NA
NA
NA
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
NA
NA
NA
0
Ductwork Demolition (1000$)
NA
NA
NA
29
New Duct Length (Feet)
NA
NA
NA
300
New Duct Costs (1000$)
NA
NA
NA
1572
New Heat Exchanger (1000$)
NA
NA
NA
1974
TOTAL SCOPE ADDER COSTS (1000$)
NA
NA
NA
3574
RETROFIT FACTOR FOR SCR
NA
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
NA
NA
NA
20
8-133
-------
Table 8.7.4-6. NOx Control Cost Results for the Wabash Rwer Plant (June 1988 Dollars)
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Number Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (l«i)
Content
£$MM>
(S/kW)
(mil Is/Mi)
(X)
(tons/yr)
Factor
(%)
LNC-LNB
1
1.00
113
23
2.1
2.7
23.7
0.6
2.5
40.0
447
1291.7
INC-LNB
2
1.00
113
10
2.1
2.7
23.7
0.6
5.8
40.0
194
2971.0
LNC-LNB
3
1.00
91
27
2.1
2.5
27.0
0.5
2.5
40.0
422
1253.1
LNC-LNB
4
1.00
91
10
2.1
2.5
27.0
0.5
6.6
40.0
156
3383.5
LNC-LNB
5
1.00
125
16
2.1
2.8
22.3
0.6
3.4
36.0
309
1942.4
LNC-LNB-C
1
1.00
113
23
2.1
2.7
23.7
0.3
1.5
40.0
447
766.9
LNC-LNB-C
2
1.00
113
10
2.1
2.7
23.7
0.3
3.5
40.0
194
1763.9
LNC-LNB-C
3
1.00
91
27
2.1
2.5
27.0
0.3
1.S
40.0
422
744.2
LNC-LNB-C
4
1,00
91
to
2.1
2.5
27.0
0.3
3.9
40.0
156
2009.3
LNC-LNB-C
5
1.00
125
16
2.1
2.8
22.3
0.4
2.0
36.0
309
1153.3
LNC-QFA
6
1.00
387
20
2.1
1.1
2.7
0.2
0.3
25.0
594
385.6
LNC-OFA-C
6
1.00
387
20
2.1
1.1
2.7
0.1
0.2
25.0
594
229.0
SCR-J
1-6
1.16
920
18
2.1
98.6
107.2
37.0
25.5
80.0
5689
6512.1
SCR-3-C
1-6
1.16
920
18
2.1
98.6
107.2
21.7
14.9
80.0
5689
3808.8
SCR-7
1-6
1.16
920
18
2.1
98.6
107.2
29.4
20.2
80.0
5689
5162.6
SCR-7-C
1-6
1.16
920
18
2.1
98.6
107.2
17.3
11.9
80.0
5689
3035.5
8-134
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Wabash River plant because of the small sizes of the existing ESPs.
Atmospheric FTuidized Bed Combustion and Coal Gasification Applicability--
Units 1-5 at the Wabash River plant would be good candidates for
AFBC/CG technologies due to their low capacity factors and likely short
remaining useful life. Unit 6 would not be considered a good candidate for
AFBC/CG applications due to its long remaining life.
8-135
-------
8.8 SOUTHERN INDIANA GAS & ELECTRIC
8.8.1 F.B. Cullev Steam Plant
Sorbent injection technologies (FSI and DSD) were not considered for
the boilers at the Culley plant due to the short duct residence time between
the boilers and the ESPs.
TABLE 8.8.1-1. CULLEY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHOD
1 2
3
46 104
265
55 61
68
1955 1956
1973
FRONT WALL
OPPOSED WALL
23 63
176
NO NO
NO
3.1
10800
11.8
WET DISPOSAL
PONDS/ON-SITE
1 2 3
TRUCK
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
ESP
1972
1973
1974
0.25
0.21
0.26
97.6
99.3
97.4
4.1
3.3
3.8
33
85.5
177.7
195
395
833.6
169
217
213
290
300
290
* 1988 data.
8-136
-------
TABLE 8.8.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CULLEY
UNITS 1 AND 2 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA HIGH
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 467, 971 NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 322, 728 0 322, 728
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.70 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.69
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.58
GENERAL FACILITIES (PERCENT) 10 0 10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for units
1 and 2 would be located north of unit 1 beside the coal
conveyor.
8-137
-------
TABLE 8.8.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CULLEY
UNIT 3 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
502 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
2246
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.53
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.44
"ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers, and new FFs for unit 3
would be located south of the unit 3 chimney.
8-138
-------
Table 8.8.1-4. Summary of FGD Control Costs for the Cullty Plant, (June 1988 Dollars)
Iia«ai3is>axi*saii»x3s33»i«ti»aiaii=:iai>atiaiaii=s=:=sssss:s:=ss3sss:3ssssss=sssss:ss:sssss3s:=ss:3r:3ssss==
Technology Boiler Ha in Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 S02 Cost
Hutter Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (SMH) (S/kW) <»«) (n'ills/kwh) (tons/yr) (J/tcn>
Factor (X)
l/S FED
1
1.70
46
55
3.1
39.4
856.8
16.2
73.1
90.0
5630
2879.0
L/S FGD
2
1.70
104
61
3.1
57.5
552.6
24.5
44.2
90.0
14117
1738.2
l/S FGO
1-2
1,70
150
59
3.1
68.9
459.2
29.7
38.4
90.0
19693
1509.8
l/S FGO
3
1.53
26S
68
3.1
87.5
330.1
41.6
26.3
90.0
40098
1036.7
l/S FGD-C
1
1.70
46
55
3.1
39.4
856.8
9.5
42.7
90.0
5630
1680.9
l/S FGO-C
2
1.70
1(54
61
3.1
57.5
552.6
14.3
25.8
90.0
14117
1014.1
l/S FGD-C
1-2
1.70
150
59
3.1
68.9
459.2
17.3
22.4
90.0
19693
880.7
L/S FGD-C
3
1.53
265
68
3.1
87.5
330.1
24.2
15.3
90.0
40098
603.7
LC FGO
1-2
1.70
150
59
3.1
47.7
317.9
23.0
29.7
90.0
19693
1168.3
LC FGO
3
1.53
265 '
68
3.1
66.7
251.8
35.0
22.2
.90.0
40098
872.2
IC FGD-C
1-2
1.70
150
59
3.1
47.7
317.9
13.4
17.3
90.0
19693
680.2
IC FGD-C
3
1.53
265
68
3.1
66.7
251.8
20.3
12.9
90.0
40098
507.2
ISO+FF
1
1.69
46
55
3.1
21.8
473.0
9.2
41.5
78.0
4872
1886.5
LSD+FF
2
1.69
104
61
3.1
37.8
363.4
15.2
27.4
80.0
12472
1219.7
LSD+FF
1-2
1.69
150
59
3.1
49.2
328.2
19.4
25.0
80.0
17398
1112.6
LSD+FF
3
1.44
265
68
3.1
67.3
253.8
27.9
17.7
78.0
34697
803.9
ISD+FF-C
1
1.69
46
55
3.1
21.8
473.0
5.4
24.2
78.0
4872
1100.9
LSO+FF-C
2
1.69
104
61
3.1
37.8
363.4
8.9
16.0
80.0
12472
712.4
ISD+FF-C
1-2
1.69
150
59
3.1
49.2
328.2
11.3
14.6
80.0
17398
650.1
ISD+FF-C
3
1.44
265
68
3.1
67.3
253.8
16.3
10.3
78.0
34697
469.3
8-139
-------
Table 8.8.1-5, Sunnsry of Coal Switching/Cleaning Costs for the Cut ley Plant (Jine 1988 Oollers)
Technology
Boiler Main
Boiltr Capacity Coal
Capital Capital Annual
Annual
S02
S02
502 Cost
Nuitoar Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
Content
CM*)
(«m»
(aills/kwh)
< tons/yr)
(#/ton>
Factor
(*>
CS/B*t15
1
1.00
46
55
3.1
2.3
50.9
3.7
16.7
74.0
4655
794.5
CS/B*t15
2
1.00
104
61
3.1
4.0
38.0
8.3
14.9
74.0
11672
709.7
CS/B+115
3
1.00
26!
68
3.1
8.6
32.5
22.2
14.1
74.0
33155
670.0
CS/B+S15-C
1
1.00
46
55
3.1
2.3
50.9
2.1
9.6
74.0
4655
457.4
CS/B+S15-C
2
1.00
104
61
3.1
4.0
38.0
4.8
8.6
74.0
11672
408.1
CS/B+S15-C
3
1.00
26$
68
3.1
8.6
32.5
12.8
8.1
74.0
33155
385.1
CS/B*«5
1
1.00
46
55
3.1
1.9
40.6
1.8
a.o
74.0
4655
383.3
CS/B*S5
2
1.00
104
61
3.1
2.9
27.7
3.5
6.3
74.0
11672
300.3
CS/B»S5
3
1.00
265
68
3.1
5.9
22.2
3.7
5.5
74.0
33155
262.3
CS/B*$5-C
1
1.00
46
55
3.1
1.9
40.6
1.0
4.6
74.0
4655
221.4
CS/B*S5-C
2
1.00
104
61
3.1
2.9
27.7
2.0
3.6
74.0
11672
173.1
CS/B*i5-C
3 •
1.00
265
68
3.1
5.9
22.2
5.0
3.2
74.0
33155
151.1
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II
II
II
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II
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8-140
-------
TABLE 8,8.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR CULLEY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
.
1
2
3
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
FURNACE VOLUME (1000 CU FT)
23
S3
176
BOILER INSTALLATION DATE
1955
1956
1973
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
34
42
46
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
15
28
56
New Duct Length (Feet)
200
300
300
New Duct Costs (1000$)
629
1521
2629
New Heat Exchanger (1000$)
1170
1908
3345
TOTAL SCOPE ADDER COSTS (1000$)
1814
3457
6029
RETROFIT FACTOR FOR SCR
1.52
1.52
1.34
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors would be located behind the chimney for
each unit.
8-141
-------
Table 8.8.1-7.
HOx Control Cost Results for the Culley Plant
(Jtrw
1988 Dollars J
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Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
NO*
N0X
HOx Cost
Nunfcer
Retrofit
Size
Factor
Sylfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
m
Content
(S*W)
CS/kUJ
(MM)
Cmills/kMhJ m
(tons/yr)
(S/ton)
Factor
<%>
LNC-INS
1
1.00
46
, 55
3.1
1.9
40.7
0.4
1.8
34.0
369
1090.1
LNC-LNB
2
1.00
104
61
3.1
2.6
24.9
0.6
1.0
42.0
1144
487.7
IHC-INB
3
1.00
265
68
3,1
3.8
14,2
0.8
0.5
46.0
3560
227.9
LNC-INB-C
1
1.00
46
55
3.1
1.9
40.7
0.2
1.1
34.0
369
647.2
LNC-LNB-C
2
1.00
104
61
3.1
2.6
24.9
0.3
0.6
42.0
1144
289.5
LNC-LNB-C
3
1.00
265
68
3.1
3.8
14.2
0.5
0.3
46.0
3560
135.3
SCR-3
1
1.52
46
55
3.1
14.6
317.1
4.4
19.9
80.0
869
5082.9
SCS-3
2
1.52
104
61
3.1
23.5
226.1
7.5
13.4
80.0
2130
3426.6
SCR-3
3
! .34
265
68
3.1
42.5
160.3
14.7
9.3
80.0
6191
2377,9
SCR-3-C
1
1.52
46
55
3.1
14.6
317.1
2.6
11.7
80.0
869
2987.4
SC8-3-C
2
1.52
104
61
3.1
23.5
226.1
4.4
7.9
80.0
. 2180
2011.6
SCR-3-C
3
1.34
265
48
3.1
42.5
160.3
8.6
5.5
80.0
6191
1393.1
SCR-7
. 1
1.52
46
55
3.1
14.6
317.1
' 4.0
13.2
80.0
869
4641.1
SCR-7
2
1.52
104
61
3.1
23.5
226.1
6.6
11.9
80.0
2180
3028.4
SCR-7
3
1.34
265
68
3.1
42.5
160.3
12.5
7.9
80.0
6191
2020.7
SCR-7-C
1
1.52
46
55
3.1
14.6
317.1
2.4
10.7
80.0
869
2734.3
SCR-7-C
2
1.52
104
61
3.1
23.5
226.1
3.9
7.0
80.0
2180
1783.5
SCR-7-C
3
1.34
265
68
3.1
42.5
160.3
7.4
4.7
80.0
6191
1188.5
It
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II
II
II
II
11
II
II
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8-142
-------
SECTION 9.0 KENTUCKY
9.1 BIG RIVERS ELECTRIC CORPORATION
9.1.1 Coleman Steam Plant •
The Coleman steam plant is located within Hancock County, Kentucky, as
part of the Big Rivers Electric Corporation. The plant contains three
coal-fired boilers with a total gross generating capacity of 485 MW. The
plant is located west of the Ohio River, with unit 1 residing close to the
river and unit 3 being the furthest away. Figure 9.1.1-1 presents the plant
plot plan showing the location of all boilers and major associated auxiliary
equipment.
Table 9.1.1-1 presents operational data for the existing equipment at
the Coleman plant. The boilers burn medium sulfur coal (2.4 percent
sulfur). Coal shipments are received by barge to a coal storage and
handling area located north of the plant.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit and in front of the chimneys. Fly ash is wet
sluiced to ponds located west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 9.1.1-1 shows the general layout and location of the FGD control
system. Each unit is served by its own chimney. The absorbers for L/LS-FGD
and LSD-FGD for unit 1 would be located northeast of the respective boiler
beside the chimney and adjacent to the oil tank. The unit 2 absorbers would
be located northwest of the respective boiler adjacent to the chimney on one
side and the coal pile on the other (south). For unit 3, the absorber would
be located close to the chimney and coal pile (west). A major paved road
would need to be demolished/relocated to make space for all three absorbers;
therefore, a factor of 8 percent was assigned to general facilities. The
lime and limestone storage/preparation area would be located west of the
coal pile in a relatively open area. The waste handling area would be
located on an existing ash pond west of the storage/preparation area.
9-1
-------
0ft'0 ft,
'ifff
, t08d«
-------
TABLE 9.1.1-1. COLEMAN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-3
GENERATING CAPACITY (MW-each) 160,160,165
CAPACITY FACTOR (PERCENT) 75
INSTALLATION DATE 1969-71
FIRING TYPE FWF
COAL SULFUR CONTENT (PERCENT) 2.4
COAL HEATING VALUE (BTU/LB) 11100
COAL ASH CONTENT (PERCENT) 9.5
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD POND/ON-SITE
STACK NUMBER 1-3
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1969-71
EMISSION (LB/MM BTU) 0.15
REMOVAL EFFICIENCY 97.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.0
SURFACE AREA (1000 SQ FT) 42.8
GAS EXIT RATE (1000 ACFM 498
SCA (SQ FT/1000 ACFM) 86
OUTLET TEMPERATURE (*F) 310
9-3
-------
Retrofit Difficulty and Scope Adder Costs--
The absorbers for each unit would be located in separate areas as
described above.
A medium site access/congestion factor was assigned to the unit 1
absorber location which reflects the congestion created by the boiler, oil
tank, and chimney. The location for the unit 2 absorbers was also assigned
a medium site access/congestion factor due to congestion created by the
respective boiler and coal pile. For unit 3, no major obstacles or
obstructions surround the location of the absorbers; therefore, a low site
access/congestion factor was designated to this location.
For flue gas handling, short duct runs for all units would be required
for L/LS-FGO cases since the absorbers are located close to the chimneys. A
low site access/congestion factor was assigned to the flue gas handling
system due to no major obstacles surrounding the chimneys and the fact that
no significant ductwork would be required.
The major scope adjustment costs and retrofit factors,estimated for the
FGD technologies are presented in Tables 9.1.1-2 and 9.1.1-3. The largest
scope adder cost for the Coleman plant would be the conversion of units
1 to 3 fly ash conveying/disposal system from wet to dry for conventional
L/LS-FGD cases. It was assumed that dry fly ash would be necessary to
stabilize scrubber sludge waste. This conversion is not necessary for
forced oxidation L/LS-FGD. The overall retrofit factors determined for the
L/LS-FGD cases were low to medium (1.19 to 1.36).
The absorbers for LSD-FGD would be located in a similar location close
to the boilers as in L/LS-FGD cases. LSD-FGD with new baghouses was the
only LSD-FGD technology considered for all units because their ESPs are very
small and probably cannot handle the increased load from the LSD absorbers.
For flue gas handling for LSD cases, low to medium duct runs would be
required and a medium site access/congestion factor was assigned to the flue
gas handling system which reflects the difficulty to tie into the upstream
of the ESPs and divert flue gas to the absorbers and back to the ESPs. The
retrofit factors determined for the LSD technology case were low to medium
(1.24 to 1.37} and did not include particulate control costs.
Separate retrofit factors were developed for the new baghouses. A
medium retrofit factor (1.36) was assigned to the new baghouse location for
9-4
-------
TABLE 9.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR COLEMAN UNITS 1-2
F6D TECHNOLOGY
FORCED LIME
L/LS FGO OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS .
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
MEDIUM
LOW
0-100
NA
NA
YES
1429
NO
0
NO
1.36
NA
NA
MEDIUM
LOW
0-100
NA
NA
NO
NA
NO
0
NO
1.31
NA
NA
MEDIUM
NA
MEDIUM
NA
100-300
NA
MEDIUM
NO
NA
NO
0
NO
NA
1.37
NA
1.36
GENERAL FACILITIES (PERCENT) 8
8
9-5
-------
TABLE 9.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR COLEMAN UNIT 3
FED TECHNOLOGY
FORCED LIME
L/LS FGO OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE NA
BAGHOUSE CASE MEDIUM
DUCT WORK DISTANCE (FEET) 0-100 0-100
ESP REUSE NA
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 1469 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.26 . 1.19
ESP REUSE CASE NA
BAGHOUSE CASE 1.24
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 8 8 8
9-6
-------
units 1 arid 2 due to congestion created by the coal pile and chimneys. The
unit 3 baghouse location was assigned a low retrofit factor (1.16) because
of the available space with no major obstacles/obstructions beside the unit
3 chimney. These factors were used in the IAPCS model to estimate new
particulate control costs.
Table 9.1.1-4 presents the costs estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include installing new baghouses to handle the additional
particulate loading for boilers 1-3.
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare
scrubber, optimization of scrubber size, and use of organic acid additives.
Coal Switching Costs--
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined.
The ESP performance impacts were evaluated using the IAPCS model to
estimate the needed plate area. This plate area was compared to the
existing area to determine whether S03 conditioning or additional plate area
was needed. SOj conditioning was assumed to reduce the needed plate area up
to 25 percent.
Costs were generated to show the impact of two different coal fuel cost
differentials. The costs associated with each boiler for the range of fuel
cost differential are shown in Table 9.1.1-5.
N0X Control Technology Costs--
This section presents the performance and costs estimated for NO
A
controls at the Coleman steam'plant. These controls include INC
modification and SCR. The application of NO control technologies is
.At
determined by several site-specific factors which are discussed in
Section 2. The N0X technologies evaluated at the steam plant were:
LNB and SCR.
9-7
-------
Table 9.1.1-4. Surinary of FGD Control Costs for the Coleman Plant (June 1988 Collars)
::3=assss3ssasss3S=sssss5sasss9ssaBiaBS5s«iaias3saiii33siiBiaissiiiasssissBS5a:iBiaa3siiiiiiaifxaisisxiiiiistais
Technology Boiler Hai'n Boiler Capacity Coal Capital Capital Annual Annual SOS S02 $02 Cost
Nunber Retrofit
Siia
Factor
Sulfur
Cost
Cost.
Cost
Cost
Removed Removed
Effect.
Difficulty (MW)
{%)
Content
($MM>
(t/kU)
(WW
(nills/kHh)
(%)
(tons/yr)
<$/tonj
Factor
<*)
•
L/S FGD
1
1.36
160
75
2.4
56.4
352.3
27.2
25.9
90.0
20033
1359.1
L/5 FGD
2
1.36
160
75
2.4
56.4
352.3
27.2
25.9
90.0
20033
1359.1
L/S FGD
3 ,
1.26
165
75
2.4
53.4
323.8
26.5
24.4
90.0
20659
1281.8
L/S FGO-C
1
1.36
160
75
2.4
56.4
352.3
15.9
15.1
90.0
20033
791.3
L/S FGO-C
2
1.36
160
75
2.4
56.4
352.3
15.9
, 15.1
90,0
20033
791,3
L/S FGO-C
3
1.26
165
75
2.4
53.4
323.8
15.4
14.2
90.0
20659
746.0
LC FCO
1-3
1.33
485
75
2.4
88.2
181.8
50.8
15.9
90.0
60723
836.5
LC FCD-C
1-3
1.33
485
75
2.4
88.2
181.8
29.5
9.3
90.0
60723
485.8
LSD+FF
1
1.37
160
75
2.4
42.4
264.9
18.6
17.7
87.0
19253
, 968.0
LSD+FF '
2
1.37
160
75
2.4
42.4
264.9
18.6
17.7
87.0
19253
968.0
LSD+FF
3
1.24
165
75
2.4
38.4
232.6
17.7
16.4
87.0
19855
892.9
LSD+FF-C
1
1.37
160
75
2.4
42.4
264.9
10.9
10,3
87.0
19253
564.4
LSD+FF-C
2
1,37
160
75
2.4
42.4
264.9
10,9
10.3
87.0
19253
564.4
LSD+FF-C
3
1.24
165
75
2.4
38.4
232.6
10.3
9.5
87.0
"19855
520.2
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9-8
-------
Table 9.1,1-5. Suwnary of Coal Switching/Cleaning Costs for the Coleman Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 502 S02 SC2 Cost
Number Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
m
Content
(SKMJ
($WO
(mi IIs/kwh)
(S3
(tons/yr)
(S/ton)
Factor
(X)
CS/B*$15
1
1.00
160
75
2.4
7.7
48.1
15.8
15.0
66.0
14668
1076.7
CS/B*$15
2
1.00
160
75
2.4
7,7
48.1
15.8
15.0
66.0
14668
1076.7
CS/8+S15
3
1.00
165
75
2.4
7.9
47.8
16.3
-I5.0
66.0
15126
1075.1
CS/B+S15-C
1
1.00
160
75
2.4
7.7
48.1
9.1
8.6
66.0
14668
619.2
CS/M15-C
2
1.00
160
75
• 2.4
7.7
48.1
9.1
8.6
66.0
14668
619.2
CS/8*S15-C
3
1.00
165
75
2.4
7.9
47.8
9.4
8.6
66.0
15126
618.3
CS/B+iS
1
1.00
160
75
2.4
6.0
37.7
6.8
6.5
66.0
14668
464.9
CS/B+t5
2
1.00
160
75
2.4
6.0
37.7
6.8
6.5
66.0
14668
464.9
CS/B+tS
3
1.00
165
75
2.4
6.2
37.5
7.0
6.5
66.0
15126
463.4
CS/B*I5-C
1
1.00
160
75
2.4
6.0
37.7
3.9
3.7
66.0
14668
268.2
CS/B*$5-C
2
1.00
160
75
2.4
6.0
37.7
3.9
3.7
66.0
14668
268.2
CS/8*S5-C
3
1.00
165
75
2.4
6.2
37.5
4.0
3.7
66.0
15126
267.3
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9-9
-------
Low N0X Combustion--
Units 1 to 3 are dry bottom, front wall-fired boilers each rated at
160, 160, and 165 MW, respectively. The combustion modification technique
applied for these boilers was LNB. As Table 9.1.1-6 shows, the LNB N0X
reduction performance for each unit was estimated at 43 percent. This
reduction performance level was assessed by examining the effects of heat
release rates and furnace residence time through the use of the simplified
NO^ procedures. Volumetric heat release rates of units 1 and 2 were not
reported in POWER and thus were calculated by dividing the heat input of
unit 3 and the reported furnace volumes for units 1 and 2, respectively. It
was assumed that units 1 and 2 had approximately the same heat inputs as
that of unit 3, since the three units produced approximately the same
electrical outputs. Table 9.1.1-7 presents the cost of retrofitting LNB at
the Coleman boilers.
Selective Catalytic Reduction-
Table 9.1.1-6 presents the SCR retrofit results for units 1 to 3. The
results include process area retrofit factors and scope adder costs. The
scope adders include costs estimated for ductwork demolition, new flue gas
heat exchanger, and new duct runs to divert the flue gas from the ESPs to
the reactor and from the reactor to the chimney.
The SCR reactor for unit 1 would be located east of the respective
boiler beside the chimney and adjacent to the oil tank. The SCR reactor for
unit 2 would be located west of the respective boiler adjacent to the
chimney on one side and the coal pile on the other (south). For unit 3, the
reactor would be located west of the respective boiler close to the chimney.
Since the reactors were located in an open area having easy access with no
major obstacles, the reactors for units 1 to 3 were assigned low access/
congestion factors. All reactors were assumed to be in areas with high
underground obstructions. The ammonia storage system was placed in a remote
area having a low access/congestion factor.
As discussed in Section 2, all NOx control techniques were evaluated
independently from those evaluated for SOg control. If both SOg and N0X
emissions needed to be reduced at this plant, the SCR reactors would have to
be located downstream of the FGD absorbers. In this case, the SCR reactor
9-10
-------
TABLE 9.1.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR COLEMAN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
16.1
16.1
15.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
123.5
123.5
61.6
FURNACE RESIDENCE TIME (SECONDS)
3.4
3.4
3.46
ESTIMATED NOx REDUCTION (PERCENT)
43
43
43
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
38
38
39
New Duct Length (Feet)
120
120
110
New Duct Costs (1000$)
783
783
731
New Heat Exchanger (1000$)
2471
2471
2517
TOTAL SCOPE ADDER COSTS (1000$)
3292
3292
3287
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
9-11
-------
Table 9,1.1-7, NO* Control Cost Results for the Coleman Plant (June 1988 Dollars)
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NO*
NO* Cost
Nuntoer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
-------
for unit 1 would be in a parking lot area east of the powerhouse. The
access/congestion factor would be the same as discussed before (low).
However, a higher general facility will be needed to relocate part of the
parking lot. For unit 2, the SCR reactor would probably be located on the
other side of the respective chimney (east), .A medium access/congestion
factor would be assigned to this reactor since the reactor is in a highly
congested area surrounded by the chimney, coal conveyor, and ESPs of unit 2
but access to this area is relatively easy. For unit 3, the SCR reactor
would probably be located in the same area as discussed above; therefore, a
low access/congestion factor would again be assigned. Table 9.1.1-7 presents
the estimated cost of retrofitting SCR at the Coleman boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SOg control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Ouct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located in a
similar fashion as LSD-FGD. The retrofit of DSD and FSI technologies at the
Coleman steam plant for all units would be very difficult. This is due to
the small size of the ESPs, the major upgrading that would be required, and
insufficient flue gas ducting residence time between the boilers and the
ESPs. Therefore, DSD was considered followed by new baghouses which would
be located beside the chimneys of each unit. An estimated 200 feet of duct
run would be required for each unit"to divert the flue gas from the
absorbers to the new baghouses. Tables 9.1.1-8 and 9.1.1-9 present a
summary of the site access/congestion factors for DSD technology at the
Coleman steam plant. Table 9.1.1-10 presents the costs estimated to
retrofit DSD at the Coleman plant.
9-13
-------
TABLE 9.1.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COLEMAN UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) MEDIUM
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 0
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 200
ESTIMATED COST (1000$) 1209
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 43
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) NA
A NEW BAGHOUSE CASE (DSD) 1252
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) ; UU
9-14
-------
TABLE 9.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COLEMAN UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 0
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 200
ESTIMATED COST (1000$) 1231
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 44
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) NA
A NEW BAGHOUSE CASE (DSD) 1275
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1_J3
9-15
-------
Table 9.1.1-10. Sumary of DSO/FSI Control Costs for the Coleman Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 502 $02 $02 Cost
timber Retrofit
Size
Factor Sulfur
Cost
cost
Cost
Cost
Removed Removed
Effect.
Difficulty
<*5
Content
<«*«>
(S/kW)
(tons/yr)
(S/ton)
Factor
IX)
OSD+FF
1
1.00
160
75
2.4
27.7
172.9
14.1
11.4
71.0
15748
892.8
OSO+FF
2
1.00
160
75
2.4
27.7
172.9
14.1
13.4
71.0
15748
892.3
CSD+FF
3
1.00
165
75
2.4
25.4
154.1
13.6
12.6
71.0
16240
839.7
DS0+FF-C
1
1.00
160
75
2.4
27.7
172.9
8.2
7.8
71.0
15748
519.4
DSO+FF-C
2
- 1.00
160
75
2.4
27.7
172.9
8.2
7.8
71.0
15748
519.-4
0$0*FF-C
3
1.00
165
75
2.4
25.4
154.1
7.9
7.3
71.0
16240
488.1
9-16
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Coleman plant. All of the boilers would be considered
potential candidates for AFBC retrofit due to their small boiler sizes
(<300 MW). The high base load capacity factor (75 percent) for these units
indicates that replacement power costs and heat rate improvement potential
does not favor retrofit/repowering. However, the small ESP size indicates
that switching to low sulfur coals will result in significant costs
associated with particulate control retrofit.
9-1.2 R. D. Green Steam Plant
The R. D. Green steam plant is located on the Green River in Webster
County, Kentucky, and is operated by the Big Rivers Electric Corporation,
The R. D. Green plant contains two coal-fired boilers with a gross
generating capacity of 492 MW.
Table 9.1.2-1 presents operational data for the existing equipment at
the R. D. Green plant. Coal shipments are received by barge and transferred
to a coal storage and handling area north of the plant. PM emissions from
the boilers are controlled by ESPs installed at the time of construction.
The ESPs are located behind the boilers. Flue gases from the boilers are
directed to two separate chimneys. Dry fly ash is disposed of with scrubber
sludge in a landfill south of the plant.
Both 1979 NSPS boilers at the R. D. Green plant are equipped with LSD
absorbers and LNB; therefore, no further S02 control technologies were
investigated for this pi ant.
Selective Catalytic Reduction--
Cold side SCR reactors for units 1 and 2 would be 1ocated on either
side of each chimney. A low site access/congestion factor was assigned to
each reactor location. A medium general facilities factor of 20 percent was
assigned to each location because of road relocations. Approximately
200 feet of ductwork would be required for each unit in order to span the
9-17
-------
TABLE 9.1.2-1. GREEN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 250,242
CAPACITY FACTOR (PERCENT) 79
INSTALLATION DATE 1979,1981
FIRING TYPE OPPOSED WALL
FURNACE VOLUME (1000 CU FT) 271
LOW NOx COMBUSTION YES
COAL SULFUR CONTENT (PERCENT) 3.6
COAL HEATING VALUE (BTU/LB) 10700
COAL ASH CONTENT (PERCENT) 15.0
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL
STACK NUMBER 1,2
COAL DELIVERY METHODS BARGE
FGD SYSTEM (TYPE) LSD
FGD SYSTEM (INSTALLATION DATE) 1979,1981
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1979,1981
EMISSION (LB/MM BTU) 0.06,0.06
REMOVAL EFFICIENCY 99.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 4.0
SURFACE AREA (1000 SQ FT) NA
GAS EXIT RATE (1000 ACFM) NA
SCA (SQ FT/1000 ACFM) 470
OUTLET TEMPERATURE (SF) 300
9-18
-------
distance between the SCR reactors and the chimneys. Both units were assigned
low site access/congestion factors for flue gas handling. Tables 9.1.2-2
and 9.1.2-3 present the retrofit factor inputs to the IAPCS model and the
estimated cost for installation of SCR at the R. D. Green plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The two boilers at the R. D. Green plant have long remaining useful
lives and would not be considered for AFBC/CG repowering.
9-19
-------
TABLE 9,1.2-2, SUMMARY OF NOx RETROFIT RESULTS FOR GREEN
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
NA
NA
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
NA
NA
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
54
52
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1694
1662
New Heat Exchanger (1000$)
3230
3167
TOTAL SCOPE ADDER COSTS (1000$)
4977
4882
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
9-20
-------
Table 9.1.2-3. NO* Control Cost Results for the R. 0. Green plant (June 1988 Dollars)
Technology Boiler Main Bof1«r Capacity Coal Capital Capital Annual
Number Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (MW) (X! Content (SMN)
-------
9.1.3 Robert Reid Steam Plant
No information for the Robert Reid plant was available on the EIA-767
forms. The data presented was taken from an EPA database. In developing
costs, the capacity factor was assumed to be 65%.
TABLE 9.1.3-1. ROBERT REID STEAM PLANT OPERATIONAL DATA*
BOILER NUMBER 1
GENERATING CAPACITY (MW) 70
CAPACITY FACTOR (PERCENT) NA
INSTALLATION DATE 1965
FIRING TYPE FRONT WALL FIRED
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION NA
COAL SULFUR CONTENT (PERCENT) 2.5
COAL HEATING VALUE (BTU/LB) 11800
COAL ASH CONTENT (PERCENT) 8.8
FLY ASH SYSTEM NA
ASH DISPOSAL METHOD NA
STACK NUMBER 1
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE NA
EMISSION (LB/MM BTU) NA
REMOVAL EFFICIENCY NA
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) NA
SURFACE AREA (1000 SQ FT) NA
EXIT GAS FLOW RATE (1000 ACFM) NA
SCA (SQ FT/1000 ACFM) 169
OUTLET TEMPERATURE (°F) NA
* No information was available on the EIA-767 form.
9-22
-------
TABLE 9.1.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR REID
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA ' NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NA
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NA
ESTIMATED COST (1000$) 0 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.20 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 0 0_
* L/S-FGD absorbers were located behind the chimney.
9-23
-------
Table 9,1.3-3. Surinary of FGD Control Costs for the Refd Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nintoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (KW) (X) Content (SMM) (S/kU) (SW) (miUs/kwh) (X)
-------
Table 9.1.3-4. Surinary of Coal Switching/Cleaning Costs for the Reid Plant (June 1988 Dollars)
SSS55S5SS55S5SSSSSSI9IS1I1II54333S3SSSSSSS3SS3SB33S3*SSSSSS3S33SSSSBS1SS33SSS8S3SSBSSSSS3"S3SSSSSS33SS'SSSZ
technology Sailer Main Boiter Capacity Coal Capital Capital Annual Annual SQ2 SQ2 S02 Cost
Nurrtber Retrofit Size Factor Sulfur Cost Cost , Cost Cost Removed Removed Effect.
Difficulty <»0 (X) Content ($MM) (S/kU) (SMM) (mi 1 Is/kwti) <%) (tons/yr) (i/toc)
Factor (%)
CS/B+S15
CS/B+S15-C
CS/B+15
CS/B+iS-C
1.00 70 65 2.5 3.5 49.8 6.4 16.0 , 65.0 5317 1199.0
1.00 70 65 2.5 3.5 49.8 3.7 9.2 65.0 5317 689.9
1.DO 70 65 2.5 2.8 39.4, 3.0 7.4 65.0 5317 556.0
1.00 70 65 2.5 2,8 39.4 1.7 4.3 65.0 5317 320.9
9-25
-------
TABLE 9.1.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR HENDERSON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE FWF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION OATE 196S
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 40
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 21
New Duct Length (Feet) 200
New Duct Costs (1000$) 804
New Heat Exchanger (1000$) 1505
TOTAL SCOPE ADDER COSTS (1000$) 2330
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT! 20
* Cold side SCR reactors would be located behind the chimney.
9-26
-------
Table 9.1,3-6, NOx Control Cost Results for the Reid Plant (June 1998 Dollars}
SSS5SSSSSSSSSSSSSSSSS?SSSS3S8SS5S588S3S3*S3SSSSS3SS3SSSSSSSSSSSSSSSSSSSSSSSSSSSSS^SSSSSSSSSSSSSSSSS555SSX 5
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx NO* Cost
Nuttier Retrofit Sije Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMW> Content (UWj (J/ltW) (tons/yr) (i/ton)
Factor (%)
tNC-LNB
LNC-LNB-C
SCR-3
SCR-3-C
SCR-7
SCR-7-C
1.00 70 65 2,5 2,2 31.6 0.5 1.2 40,0 706 677.1
1.00 70 65 2.5 2.2 31.6 '0.3 0.7 >0.0 706 402.1
1.16 70 65 2.5 15.2 217.3 5.0 12.4 80,0 1412 3508.1
1.16 70 65 2.5 15.2 217.3 2.9 7.3 80.0 1412 2058.2
1.16 70 65 2.5 15.2 217.3 4.4 11.0 30.0 1412 3099,8
1.16 70 65 2.5 15.2 217.3 2.6 6.5 80.0 1412 1824.3
9-27
-------
9.2 CINCINNATI GAS & ELECTRIC
9.2.1 East Bend Steam Plant
Unit 2 at the East Bend plant is equipped with a wet lime FGD system;
therefore, no further SO^ control technologies were evaluated for this unit.
In addition, the boiler has LNBs for NOx control. The only technology
considered for unit 2 was SCR for additional NOx removal.
TABLE 9.2.1-1. EAST BEND STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE)
FGD SYSTEM (INSTALLATION DATE)
650
45
1981
OPPOSED WALL
NA
YES
2.6
11200
11
DRY DISPOSAL
STORAGE/ON-SITE
2
BARGE
LIME FGD
1981
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (SF)
ESP
1981
0.05
99.6
5.2
1290
3738
345
677
9-28
-------
TABLE 9.2,1-2. SUMMARY OF NOx RETROFIT RESULTS FOR EAST BEND
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
2
FIRING TYPE NA
TYPE OF NOx CONTROL NA
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE NA
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 110
New Duct Length (Feet) 400
New Duct Costs (1000$) 5925
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$) 6035
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES fPERCENT) 13
* Hot side SCR reactors for unit 2 would be located west of the
unit 2 ESPs. A medium site access/congestion factor was assigned
to the SCR reactor location because of the difficulty in
accessing the existing chimney.
9-29
-------
Table 9.2.1-3. NOx Control Cost Results for the East Bend Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NO* NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (My) (X) Content (MM) it/kU) (WW), (mills/kwh) (X) (tons/yr) ($/ton)
Factor (X)
SCS-3 2 1.34 650 45 2.6 84.8 130.S 30.7 12.0 80.0 9638 3189.4
SCR-3-C 2 1.34 650 45 2.6 84.8 130.5 18.0 7.0 80.0 9638 1866.8
SCH-7 2 1.34 650 45 2.6 84.8 130.5 25.3 9.9 80.0 9638 2629.6
SCR-7-C 2 1.34 650 45 2.6 84.8 130.5 14.9 5.8 80.0 9638 1546.0
iSS5SSSSSSSSSBSSIB88BS8CSB81S8SSIS8C8SBS8SSISIBS8SSBSS9!83833S5SSS35SSS3S8SSSSSSSS33ISSSSSSS3ala»SSZSSSSSSS3SiS3ZS3S
9-30
-------
9.3 EAST KENTUCKY POWER CORPORATION
9.3.1 John Sherman Cooper Steam Plant
The Cooper steam plant is located within Pulaski County, Kentucky, as
part of the East Kentucky Power Cooperative system. The plant contains two
coal-fired boilers with a total gross generating capacity of 321 MW.
Figure 9.3.1-1 presents the plant plot plan showing the location of all
boilers and major associated auxiliary equipment. The Cooper plant is
located beside the Cumberland River.
Table 9.3.1-1 presents operational data for the existing equipment at
the Cooper plant. The boilers burn medium sulfur coal (1.7 to 2.6 percent
sulfur). Coal shipments are received by barge/truck and transferred to a
coal handling/storage area located east of the powerhouse.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit. Ash from both units is wet sluiced to ponds
located north of the coal pile.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 9.3.1-1 shows the general layout and location of the FGD control
system. Flue gas from both boilers are converged into a common chimney.
The absorbers for L/LS-FGD and LSD-FGD for both units would be located
immediately west of the chimney in a relatively open area. Part of the
employee parking area and a plant road would be relocated to make space
available for the FGD equipment; therefore, a factor of 8 percent was
assigned to general facilities. The lime and limestone storage/preparation
area would be located west of the plant close to the absorbers; the waste
handling area would be located adjacent to it.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for all units would be located west of the chimney/water
intake structure. The absorber locations for all units were assigned a low
site access/congestion factor which reflects no major obstacles or
obstructions around the absorbers.
9-31
-------
Llm«/Um«storw *
Stor«o»/Pw> "ration
ArM
,ESPs
Absortert for
Units 1 & 2
Water Inlat-Qutlat
Structure
Coal
Conwyora^
FGD Waste HarKlling/AtssorDer Area
Ume/Umeetone Storage/Prepafaiion ArM
SCR Reactor*
B*rg«'
Coal Siortaa
and Handling
Arat
Not to scale
Figure 9.3.1-1. Cooper plant plot plan
9-32
-------
TABLE 9,3.1-1. COOPER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (HW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
1 2
100
220.9
70
54
1965
1969
FWF
FWF
1.7
2.6
11826
11830
11.2
11.2
WET SLUICE
POND/ON-SITE
1
BARGE/TRUCK
ESP
ESP
1965
1969
0.25
0.25
98
98
1.9
1.9
84.2
162.2
390
735
216
221
300
300
9-33
-------
For flue gas handling, short to medium duct runs for all units would be
required for L/LS-FGD cases since the absorbers are located close to the
chimney. A medium site access/congestion factor was assigned to the flue
gas handling system because of moderate access difficulty to the chimney
caused by the ESPs and water intake structure.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 9.3.1-2. The largest scope adder
for the Cooper plant is the conversion of units 1 and 2 fly ash conveying/
disposal system from wet to dry for L/LS-FGD and LSD-FGD. It is assumed that
dry fly ash would be necessary to stabilize conventional L/LS-FGD scrubber
sludge waste and to prevent plugging of sluice lines in LSD-FGD systems.
This conversion is not necessary for forced oxidation L/LS-FGD. The overall
retrofit factors determined for the L/LS-FGD cases were low to moderate
(1.28 to 1.35).
The absorbers for LSD-FGD could be located either to the west of the
plant or to the side of the ESPs. LSD-FGD with reused ESPs was the only
LSD-FGD technology considered for both units because of their moderate sizes
(SCAs >215). For flue gas handling for LSD cases, moderate duct runs would
be required and a high site access/congestion factor was assigned to the
flue gas handling system for both units, due to the difficulty in accessing
the upstream of the ESPs and water intake structure. The retrofit factor
determined for the LSD technology case was moderate (1.43) and did not
include particulate control upgrading costs. A separate retrofit factor was
developed for upgrading the ESPs for the units (1.36) and a medium site
access/congestion factor was designated due to the close proximity of the
ESPs to the chimney. The available space around and behind the ESPs could
be used if additional plate area is required. This factor was used in the
IAPCS model to estimate particulate control upgrading costs.
Table 9.3.1-3 presents the cost estimated for L/LS-FGD and LSD-FGD
cases. The LSD-FGD costs include upgrading the ESPs and ash handling
systems for boilers 1 and 2.
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare
scrubber module, and optimization of scrubber size.
9-34
-------
TABLE 9.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR COOPER UNITS 1-2
FGD TECHNOLOGY
FORCED LIME
L/LS FGO OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
100-300
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST (1000$)
938
NA
938
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.35
1.28
ESP REUSE CASE
1.43
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
8
8
9-35
-------
Table 9,3.1-3. Suimary of FCC Control Costs for the Cooper Plant (June 1988 Dollars}
iailSINIIS8SSSlMlHase8S&aaSSSSa8811B9SSBa8IHa8SISSS8S3SS3SSa8S88S3»8SB3SSS3SS9SSSaiSaSS9KSSS3SB8lflISSS3858S
Technology Boiler Hain Boiler Capacity Coal Capital Capital Annual Annual S02 SQ2 S02 Cost
Nunfcer Retrofit
Size
Factor Sulfur
Coat
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW)
(%5
Content
<«*>
(nrills/kwh)
«>
(tons/yr)
(S/tonj
Factor
(X)
US FQD
1
1.35
100
70
1.7
40.6
406.1
18.6
30.3
90.0
7697
2413.1
L/S FGO
2
1.35
221
54
2.6
63.6
287.7
28.8
27.6
90.0
20052
1437.5
l/S FGO
1-2
1.35
321
59
2.3
79.9
248.9
37.3
22.5
90.0
28163
1325.9
l/S FGO-C
1
1.35
100
70
1.7
40.6
406.1
10.8
17.7
90.0
7697
1406.2
L/S FGD-C
2
1.35
221
54
2,6
63.6
287.7
16.8
16.1
90.0
20052
837.8
l/S FGO-C
1-2
1.35
321
59
2.3
79.9
248.9
21.8
13.1
90.0
28163
772.4
tC FGO
1-2
1.35
321
59
2.3
60.6
188.8
31.2
18.8
90.0
28169
1107.5
LC FGO-C
1-2
1.35
321
59
2.3
60.6
188.8
18.1
10.9
90.0
28169
644.2
ISD*ISP
1
1.43
100
7D '
1.7
18.5
185.0
9.5
15.5
76.0
6525
1453.1
LSD*ESP
2 •
1.43
221
54
2.6
36.8
166.6
16.9
16.2
73.0
16269
1041.5
LSO*iSP-C
1
1.43
100
70
1.7
18.5
185.0
5.5
9.0
76.0
6525
845.2
lSO*ESP-C
2
1.43
221
54
2.6
36.8
166.6
9.9
9.4
73.0
16269
606.8
11
It
II
tl
II
II
II
II
II
II
II
II
_________
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S3S8HS
:I353SSS
II3II5SSS
ssiiaasa
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II
U
II
II
II
II
II
N
II
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ssssssss
9-36
-------
Coal Switching Costs--
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined.
The ESP performance impacts were evaluated using the 1APCS model to
estimate the needed plate area. This plate area was compared to the
existing area to determine whether SO^ conditioning or additional plate area
was needed. SO^ conditioning was assumed to reduce the needed plate area up
to 25 percent.
Costs were generated to show the impact of two different coal fuel cost
differentials. The costs associated with each boiler for the range of fuel
cost differential are shown in Table 9.3.1-4.
NOx Control Technology Costs--
This section presents the performance and costs estimated for NO
controls at the Cooper steam plant. These controls include LNC modification
and SCR. The application of NO control technologies is determined by
several site-specific factors which are discussed in Section 2. The N0X
technologies evaluated at the steam plant were: LNB and SCR.
Low N0X Combustion--
Units 1 and 2 are dry bottom, front wall-fired boilers rated at 100 and
221 MW, respectively. The combustion modification technique applied for -
these boilers was LNB. As Table 9-3.1-5 shows, the LNB NO reduction
A
performances for units 1 and 2 were estimated at 30 and 43 percent,
respectively. The reduction performance level of unit 1 was assessed by
examining only the effect of boiler/waterwall heat release rate on N0X
reduction through the use of the simplified N0X procedures; this information
was available for unit 1. For unit 2, the reduction performance level of
unit 2 could be evaluated by examining the effects of heat release rates and
furnace residence time on N0X reduction through the use of the simplified
NO procedures. Table 9.3.1-6 presents the cost of retrofitting LNB at the
A
Cooper boilers.
9-37
-------
Table 9.3.1-4. Summary of Coal Switching/Cleaning Costs for the Cooper Plant (June 1988 Dollars)
Technology Boiler Nain Boiler Capacity Coal Capital Capital Annual Annual 502 S02 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW) (X) Content (MM) (S/kU) (MM) (nllls/kuh) (X) (tona/yr) (S/ton)
Factor (X)
CS/B+S15
CS/B»$15
CS/B+S15-C
CS/B+S1S-C
CS/B-t5
CS/B*S5
CS/B+M-C
CS/8+S5-C
.00
.00
.00
.00
.00
.00
.00
.00
100
221
100
221
100
221
100
221
70
54
70
54
70
54
70
54
1.7
2.6
1.7
2.6
1.7
2.6
1.7
2.6
4.0
7.6
4.0
7.6
3.0
5.3
3.0
5.3
40.0
34.4
40.0
34.4
29,7
24.1
29.7
24.1
9.2
15.3
5.3
~.s
3.9
~.3
2.3
3.6
14.9
14.7
5.6
8.4
6.4
6.0
3.7
3.5
46.0
66.0
4S.0
66.0
iS.D
66.0
48.0
66.0
4124
14735
4124
14735
4124
14735
4124
14735
2221.4
1040.9
1277.1
5%.7
949.4
428.0
547.2
246.8
aaamltllBasSStsa8aHa8BnaBS3s8aaacB8sgaaiaB38aa8|tilaasra8llaaaaa||gaNttanBBB>asaaBaaa|BacllB33!!iataasias8S88
9-38
-------
TABLE 9.3.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR COOPER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
18
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
71.3
81.8
FURNACE RESIDENCE TIME (SECONDS)
NA
2.79
ESTIMATED NOx REDUCTION (PERCENT)
30
43
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
27
49
New Duct Length (Feet)
250
450
New Duct Costs (1000$)
1239
3546
New Heat Exchanger (1000$)
1864
2999
TOTAL SCOPE ADDER COSTS (1000$)
3130
6594
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
9-39
-------
Table 9.3.1-6. NO* Control Cost Results for the Cooper Plant CJi*w 1988 Dollars)
sssaasassaasssssaasssasssasssssssssssssssssssss
Technology Boiler Main Boiler Capacity Coal. Capital Capital Annual Annual NOx NOx NOx Cost
Nuitoer Retrofit Sfia Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (MW) (X) Content (StW) (f/kW) (Sm) (mills/kwh) (X) Ctons/yr) <»/ton)
Factor (X)
LNC-LN8 1 1,00 100 70 1.7 2.6 25.5 .0.6 0.9 30.0 813 678.7
LMC-LN8 2 1.00 221 54 2.6 3.5 15.9 0.8 0.7 43.0 1984 381.5
INC-LNB-C 1 1.00 100 70 1.7 2.6 25.5 0.3 0.5 30.0 813 402.9
INC-LNB-C 2 1.00 221 54 2.6 3.5 15.9 0.4 0.4 43.0 1984 226.5
SCR-3 1 1.16 100 70 1.7 18.7 186.7 6.3 10.2 80.0 2167 2892.9
SCR-3 2 1.16 221 54 2.6 34.4 155.8 11.7 11.2 80.0 3691 3162.8
SCR-3-C 1 1.16 100 70 1.7 18.7 186.7 3.7 6.0 80.0 2167 1696.1
SCH-I-C 2 1.16 221 54 2.6 34.4 155.8 6.8 6.5 80.0 3691 1853.9
SCR-7 1 1.16 100 70 1.7 18.7 186.7 5.4 8.9 80.0 2167 2512.9
SCR-7 2 1.16 221 54 2.6 34.4 155.8 9.9 9.4 80.0 3691 2670.1
SC8-7-C 1 1.16 100 70 1.7 18.7 186.7 3.2 5.2 80.0 2167 1478.4
SCR-7-C 2 1.16 221 54 2.6 34.4 155.8 5.8 5.6 80.0 3691 1571.6
9-40
-------
Selective Catalytic Reduction-
Table 9.3.1-5 presents the SCR retrofit results for units 1 and 2. The
results include process area retrofit factors and scope adder costs. The
scope adders include costs estimated for ductwork demolition, new flue gas
heat exchanger, and new duct runs to divert the flue gas from the ESP to the
reactor and from the reactor to the chimney.
The SCR reactors for units 1 and 2 were located east and west of the
chimney adjacent to the water intake structure. Both reactors are located
in easy access and open areas. No major relocation or demolition would be
required for any of the units. Therefore, the reactors for units 1 and 2
were assigned low access/congestion factors. Both reactors were assumed to
be in areas with high underground obstructions. The ammonia storage system
was placed in a remote area having a low access/congestion factor.
As discussed in Section 2, all N0x control techniques were evaluated
independently from those evaluated for SO^ control. If both SO^ and N0X
emissions needed to be reduced at this plant, the SCR reactors would have to
be located downstream of the FGD absorbers in an area immediately west of
the absorbers. In this case, low access/congestion factors would again be
assigned to both SCR reactors. Table 9.3.1-6 presents the estimated cost of
retrofitting SCR at the Cooper boilers.
Sorbent Injection and Repowering--
•This section presents the cost/performance estimates for SO^ control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located west of
the plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Cooper steam plant for all units has good potential due
to sufficient flue gas ducting residence time between the boilers and the
ESPs. However, the small size of the ESPs (SCA 216-221) could result in the
need for significant ESP upgrades. It was assumed that the ESPs could be
9-41
-------
upgraded and a medium site access/congestion factor (1.34) was assumed.
Additionally, the conversion of the wet ash handling system to dry handling
would be required for reusing ESPs for both FSI and DSD technologies.
Tables 9.3.1-7 AND 9.3.1-8 present a summary of the site access/congestion
factors for DSD and FSI technologies at the Cooper steam plant. Table
9.3.1-9 presents the costs estimated to retrofit DSD and FSI at the Cooper
plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Cooper plant. Both boilers would be considered good
candidates for AFBC retrofit due to their small boiler sizes {<300 MW). The
boilers have moderate to high capacity factors which could result in
significant purchased power penalties due to downtime and indicate marginal
heat rate improvement benefits. However, the small ESP size could result in
significant costs to upgrade the ESPs if coal switching were to be
implemented as the SO,, control strategy.
9.3.2 Huoh L. Sourlock Steam Plant
The Hugh L. Spurlock steam plant is located on the Ohio River in Mason
County, Kentucky, and is operated by the East Kentucky Power Cooperative
Inc. The Spurlock plant contains two coal-fired boilers with a gross
generating capacity of 814 MW.
Table 9.3.2-1 presents operational data for the existing equipment at
the Spurlock plant. Coal shipments are received by railroad or barge and
transferred to a coal storage and handling area west of the plant. PM
emissions from the boilers are controlled by ESPs installed at the time the
boilers were constructed. The ESPs are located behind the boilers. Flue
gases from each boiler are directed to chimneys behind their respective
ESPs. Fly ash is disposed of in a pond east of the plant.
9-42
-------
TABLE 9.3.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COOPER UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) , 938
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 30
TOTAL COST (1000$)
ESP UPGRADE CASE 968
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.34
NEW BAGHOUSE NA
9-43
-------
TABLE 9.3.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COOPER UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
LOW
ESP UPGRADE
MEDIUM
NEW BAGHOUSE
NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING
YES
ESTIMATED COST (1000$)
1908
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
NA
ESTIMATED COST (1000$)
NA
ESP REUSE CASE
NA
ESTIMATED COST (1000$)
NA
DUCT DEMOLITION LENGTH (FT)
50
DEMOLITION COST (1000$)
54
TOTAL COST (1000$)
ESP UPGRADE CASE
1962
A NEW BAGHOUSE CASE
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.13
ESP UPGRADE
1.34
NEW BAGHOUSE
NA
9-44
-------
Table 9,3.1-9. Sunrary of DSO/FS) Control Costs for the Cooper Plant (Jum 1988 Dollars)
Technology Boiler Main Boilar Capacity Coal Capital Capital Annual Annual SG2 S02 S02 Coat
Nuifcer Retrofit Size factor Sulfur Coat Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (SWO (S/lcw) (SW) (nilla/kwh)
-------
TABLE 9.3.2-1. SPURLOCK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1
2
GENERATING CAPACITY (MW-each)
305
508
CAPACITY FACTOR (PERCENT)
68
58
INSTALLATION DATE
1977
1981
FIRING TYPE
OPPOSED WALL TANGENTIAL
FURNACE VOLUME (1000 CU FT)
453
453
LOW NOx COMBUSTION
YES
YES
COAL SULFUR CONTENT (PERCENT)
2.1
0.7
COAL HEATING VALUE (BTU/LB)
11300
11900
COAL ASH CONTENT (PERCENT)
12.7
11.9
FLY ASH SYSTEM
WET
DRY
ASH DISPOSAL METHOD
POND/ON-SITE
STACK NUMBER
1
2
COAL DELIVERY METHODS
BARGE/RAILROAD
FGD SYSTEM (TYPE)
NA
SPRAY TOWEI
SORBENT TYPE
NA
LIME
FGD SYSTEM (INSTALLATION DATE)
NA
1983
PARTICULATE CONTROL
TYPE
ESP
ESP
INSTALLATION DATE
1977
1981
EMISSION (LB/MM BTU)
<1.2
<1.2
REMOVAL EFFICIENCY
99.2
98.8
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
0.0-3.7
0.0-0.7
SURFACE AREA (1000 SQ FT)
285.1
498
GAS EXIT RATE (1000 ACFM)
806
1462
SCA (SQ FT/1000 ACFM)
354
341
OUTLET TEMPERATURE (*F)
300
300
9-46
-------
Lime/Limestone and Lime Spray Drying FGD Costs--
Unit 2 has a new conventional wet lime FGD system installed; therefore,
no SOg control technologies were investigated for this unit. L/LS-FGD
absorbers for unit 1 would be located behind the unit 1 chimney. The
general faci1ities factor assigned was low (5 percent) for this location as
was the site access/congestion factor. Approximately 100 to 300 feet of
ductwork would be required for installation of the L/LS-FGD system and a low
site access/congestion factor was assigned to flue gas handling.
LSD with reuse of the existing ESPs was considered for unit 1. The LSD
absorbers would be located behind the chimney or on the side of the unit
adjacent to the ESPs. The second location is preferred because of the
shorter duct length requirement and easier access to the upstream of the
ESPs. A low site access/congestion factor was assigned to this location. A
road has to be relocated; therefore, 8 percent was assigned to general
facilities. Between 100 and 300 feet of ductwork would be required. A
medium site access/congestion factor was assigned to the flue gas handling
system because of the access difficulties to the existing ESPs.
Tables 9.3.2-2 and 9.3.2-3 present the retrofit factor input to the
IAPCS model and the estimated cost for installation of L/LS and LSD-FGD
technologies for unit 1 at the Spurlock plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 9.3.2-4 summarizes the IAPCS cost results for CS at the Spurlock
plant unit 1. These costs do not include boiler and pulverizer operating
cost changes or any system modifications to the coal handling system. PCC
was not considered for the Spurlock plant because it is not a mine mouth
plant.
N0X Control Techno!ogies--
LNBs are already installed in both furnaces at the Spurlock plant;
therefore, no combustion modification techniques for NOx emissions control
were considered.
9-47
-------
TABLE 9.3.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR HUGH L. SPURLOCK
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW
FLUE GAS HANDLING LOW
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA
NEW BAGHOUSE NA
NA
NA
100-300 NA
NA
NA
LOW
MEDIUM
NA
100-300
NA
MEDIUM
NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA
ESTIMATED COST (1000$) 2549 NA
NEW CHIMNEY NO NA
ESTIMATED COST (1000$) 0 0
OTHER NO
YES
2549
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.27
NA
NA
NA
NA
NA
1.31
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 5
9-48
-------
Table 9.3.2-3. Suimary of FGD Control Costs for the Hugh L. Spurlock Plant (June 1980 Dollars)
•¦)gggigiljj;ESJB335SS^8ISSSSSS38S39993SSBBSSSSSS56333E8SSS8S4SI!SBBSSISn!SS9S3lSSSBSB833&3l&SUllS83SSSS8SSSSSS|!mitSC8IS
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 S02 Cost
Nirtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (Ml) <%) Content (SUN) (S/kU) (MM) (mi I Is/kuh) (X) (tona/yr) (S/ton)
Factor (X)
US fgd
1.27
305
68
2.1
73.4
240. B
36.4
20.0
90.0
29681
1225.0
L/S FGC-C
1.27
305
68
2.1
73.4
240.8
21.2
11.6
90.0
29681
712.9
lc m
1.27
305
68
2.1
55.7
182.6
30.7
16.9
90.0
29681
1034.6
IC FGD-C
1.27
305
68
2.1
55.7
182.6
17.8
9.8
90.0
29681
601.1
ISO+ESP
1.31
305
6S
2.1
39.B
130.4
20.1
11.1
71.0
23269
864.0
LSD+ESP-C
1.31
305
68
2.1
39.8
130.4
11.7
. 6.4
71.0
23269
502.7
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9-49
-------
Table 9.3.2-4. Smmary of Coal Suitchirtg/ClMning Costs for the Hugh L. Spurlock Plant (June 1983 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuifcar Retrofit Size Factor Sulfur Cost Cost Cost Cost ' Removed Removed Effect.
Difficulty (S/ton)
Factor (X)
CS/8+S15 1 1.00 305 68 Z.I 9.7 31.8 21.4 14.0 60.0 19859 1280.0
CS/8*t15*C 1 1.00 305 68 Z.I 9.7 31.8 14.6 8.0 60.0 19859 735.1
CS/B+S5 1 1.00 305 68 Z.I 6.5 21.5 9.9 5.4 60.0 19859 496.5
CS/S*t5-C 1 1.00 305 68 2.1 6.5 21.5 5.7 3.1 60.0 19859 285.9
9-50
-------
Selective Catalytic Reduction-
Hot side or cold side SCR reactors for unit 1 at the Spurlock plant
would be located adjacent to the ESPs east of the plant. A medium general
facilities value of 20 percent was assigned to the location because of a
road relocation. A low site access/congestion factor was assigned to the
reactor location. Approximately 250 feet of ductwork would be required to
span the distance between the SCR reactors and the chimney and a low site
access/congestion factor was assigned to flue gas handling for unit 1. Hot
side or cold side SCR reactors for unit 2 would be located on the west side
of the unit 2 ESPs. Low site access/congestion and general facility values
were assigned to this location. About 250 feet of ductwork would be
required for installation of the SCR system. Tables 9.3.2-5 and 9.3.2-6
present the retrofit factor inputs to the IAPCS model and the estimated cost
for installation of cold side SCR at the Spurlock plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for unit 1
because of the sufficient size ESPs (SCA ¦ 320). Although the duct
residence time between the air heater and ESP is short, the first part of
the ESPs may be modified for sorbent injection (DSD) or humidification (FSI)
application. Tables 9.3.2-7 and 9.3.2-8 present retrofit factor and cost
estimates for sorbent injection technologies.
Atmospheric Fluidized Bed Combustion and Coal Gasification Application--
The 305 and 508 MW boilers at the Spurlock plant are too large and have
too long a" remaining useful life to be considered at this time for AFBC/CG
repowering.
9-51
-------
TABLE 9.3,2-5, SUMMARY OF NOx RETROFIT RESULTS FOR HUGH L. SPURLOCK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
OWF
TANG
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
453
453
BOILER INSTALLATION DATE
1977
1981
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
62
92
New Duct Length (Feet)
250
250
New Duct Costs (1000$)
2379
3207
New Heat Exchanger (1000$)
3640
4944
TOTAL SCOPE ADDER COSTS (1000$)
6082
8242
RETROFIT FACTOR FOR SCR ,
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
13
9-52
-------
Table 9,3.2-6. HOx Control Cost Results for the Hugh L. Spurlock Plant (June 1988 Dollars)
3SSSBSS35533S3S93&283a83SS3S333a3SSw333333S33S3SS33SSSS3S33SS8B3338fl3S3SSl8SS3SS38I388S3333SS3S333333 333ISS33B33
Technology Seller Main Boiler Capacity Coal Capital Capital Annual Annual NOx NO* NOx Cost
Neuter Retrofit Size Factor Sulfur Coat Cost Cost Cost Removed Removed Effect.
Difficulty (NU) <%) Content (SIM) (t/kW) (*N> (niUs/kuh} (X) (tons/yr) CS/tort)
Factor IX)
SCR-3 1 1.16 305 68 2.1 43.4 142.4 IS.6 8.6 80.0 6765 2306.0
SCR-3 2 1.16 508 58 0.7 62.2 122.5 22.9 8.9 80.0 6469 3541.1
SCR-3-C 1 1.16 305 68 2.1 43.4 142.4 9.1 5.0 80.0 6765 1350.0
SCR-3-C 2 1.16 508 58 0.7 62.2 122.5 13.4 5.2 80.0 6469 2071.9
SCR-7 1 1.16 305 68 2.1 43.4 142.4 13.1 7.2 80.0 6765 1932.2
SCR-7 2 1.16 508 58 0.7 62.2 122.5 18.7 7.3 80.0 6469 2895.0
SCR-7-C 1 1.16 305 68 2.1 43.4 142.4 7.7 4.2 80.0 6765 1135.8
SCR-7-C 2 1.16 508 58 0.7 62.2 122.5 11.0 4.3 80.0 6469 1701.8
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9-53
-------
TABLE 9.3.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR HUGH L. SPURLOCK UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2549
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 69
TOTAL COST (1000$)
ESP UPGRADE CASE 2618
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
9-54
-------
Table 9.3.2-8. Summary of dsd/fsi Control Casts for the Hugh L. Spur lock Plant (June 1988 Collars)
K2SflC39SS18SSS3SSSS9833Sl3B9933389l99S3llS3SS98SSSSS%3SS3S9Sl3331ICS3IS33llf ISS33SS93SSSS5SX3SSS SSHtlll 3
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 502 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content (»/kU> (mills/krfo (X) (tona/yr> (S/tonJ
Factor (%}
BSO+ESP 1
1.00
305
68
2.!
17.S
57.4
12.9
7.1
46.0
15097
852.7
DSO+ESP-C 1
1.00
305
68
2.1
17.5
57.4
7.5
4.1
46.0
15097
493.8
FSI+ESP-50 1
1.00
305
68
2.1
16.3
53.6
15.1
8.3
50.0
16489
918.6
FSI*ESP-50-C 1
1.00
305
68
2.1
16.3
53.6
8.8
4.8
50.0
16489
530.7
FSl*ESP-70 1
1.00
30S
68
2.1
16.6
54.3
15.4
8.5
70.0
23085
669.2
FSI*ESP-70-C 1
1.00
305
68
2.1
16.6
54.3
8.9
4.9
70.0
23085
386.6
3831l>3IBlBSS33a33ifl3H»3B3ia3333333B333333B3l38BllB333333338S3lB833aaC311913B3313333g33t3a3333333SSS33£S£SSSS33
9-55
-------
9.4 HENDERSON MUNICIPAL POWER AND LIGHT
9.4.1 Henderson Station Two Steam Plant
The Henderson Station Two steam plant 1s located on Green River in
Henderson County, Kentucky, and is owned by the City of Henderson and
operated by Big Rivers Electric Corporation. The Henderson plant contains
two coal-fired boilers with a gross generating capacity of 337 MW.
Table 9.4.1-1 presents operational data for the existing equipment at
the Henderson plant. Coal shipments are received by barge and transferred
to a coal storage and handling area north of the plant. PM emissions from
the boilers ire controlled by original ESPs located behind each boiler.
Flue gases from the boilers are directed to a common chimney located between
the boilers. Dry fly ash is added to the FGD sludge from other Big Rivers
Electric units and disposed of in a landfill south of the plant or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for both units would be located beside the common
chimney south of the coal pile. A low site access/congestion factor was
assigned, to this location. No relocations/demolitions would be required;
hence, a low general facilities factor of 5 percent was assigned. The duct
length needed to span the distance from the chimney to the absorbers and
back to the chimney would be approximately 200 feet. Due to the easy access
to the chimney, a low site access/congestion factor was assigned to flue gas
handling.
LSD with reuse of the existing ESPs was not considered for the Henderson
plant because of the small sizes of the ESPs (<200). These ESPs would not
be able to handle the extra particulate load created by LSD. LSD with a new
baghouse was not considered because the boilers are burning a medium sulfur
coal (2.3 percent).
Table 9.4.1-2 presents the retrofit factor input to the IAPCS model and
Table 9.4.1-3 presents the cost for installation of L/LS-FGD at the
Henderson plant.
9-56
-------
TABLE 9.4.1-1. HENDERSON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
1.2
165,172
75
1973,1974
FRONT WALL
100
NO
2.3
11500
8 8
DRY DISPOSAL
LANDFILL/SOLD
1
BARGE
ESP
1973,1974
0.15,0.15
98.0
5
100,8
1108
91
300
9-57
-------
TABLE 9.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR HENDERSON
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
NO
NA
NA
NA
NA
NA
NO
NA
NA
0
0
0
NO
RETROFIT FACTORS
FGD SYSTEM 1.20 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 0_
9-58
-------
Table 9,4,1-3. Suwiary of FGO Control Costs for the Henderson Plant (June 1988 Dollars)
S3S3SSSSSSBSSBSSaBSSBSS8BSaBSS8SBSHB»aBBHHSSBSSS5SS3BSSHSasa8SSSSSaSSaSSHM33aSSaSS2S2S2SaHBSaHSSSaSS2saS
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual' Annual S02 S02 S02 Cost
Nintoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty Content (SUM) (J/fcU) (WM) (mills/kwh) (X) (tons/yr)
-------
Coal Switching and Physical Coal Cleaning Costs-
Table 9.4.1-4 presents the IAPCS cost results for CS at the Henderson
plant. These costs do not include pulverizer and boiler operating cost
changes or any system modifications that may be necessary to the coal
handling system. PCC was not evaluated because the Henderson plant is not a
mine mouth plant.
NOx Control Technologies-
The NO control technology considered for the two front wall-fired, dry
A
bottom boilers at the Henderson plant was LNBs. Tables 9.4.1-5 and 9.4.1-6
present the N0X performance and cost estimates for installation of LNB at
the Henderson plant.
Selective Catalytic Reduction--
Cold side SCR reactors for both units would be located behind the
common chimney. As in the wet FGD case, a low site access/congestion factor
was assigned to this location. The general facilities value was a low
13 percent. A duct length of 200 feet would be required and, again, the
site access/congestion factor assigned to flue gas handling was low.
Tables 9.4.1-5 and 9.4.1-6 present the retrofit factors and cost for
installation of SCR at the Henderson plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the boilers at the Henderson plant because of the inadequate sizes of the
ESPs and the short duct residence time between the boilers and ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Although the boilers at the Henderson plant are small, making them
attractive for repowering, the boilers have a long remaining useful life and
would not be considered good candidates for repowering.
9-60
-------
Tabla 9.4.1-4. Suimary of Coat Switching/Cleaning Costs for th« Henderson Plant Content (««) (X) Ctora/yr) CS/ton)
Factor (%)
CS/B*$15
CS/8*S15
1.00
1.00
165
172
75
75
2.3
2.3
7.9
8.2
48.0
47.7
16.4
17.0
15.1
15.1
64.0
64.0
13724
14306
1193.0
1190.7
CS/B*$15*C
CS/B+S15-C
1.00
1.00
165
172
75
75
2.3
2.3
7.9
8.2
48.0
47.7
9.4
9.8
8.7
8.7
64.0
64.0
13724
14306
686.1
684.8
CS/8+15
CS/B+iS
1.00
1.00
165
172
75
75
2.3
2.3
6.2
6.4
37.7
37.4
7.1
7.4
6.6
6.5
64.0
64.0
13724
14306
518.8
516.4
CS/B«*5-C
CS/B+K-C
1.00
1.00
165
172
75
75
2.3
2.3
6.2
6.4
37.7
37.4
4.1
4.3
3.8
3.8
64.0
64.0
13724
14306
299.2
297.9
9-61
-------
TABLE 9.4.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR HENDERSON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
1-2
FIRING TYPE
FWF
FWF
NA
TYPE OF NOx CONTROL
LNB
LNB
NA
FURNACE VOLUME (1000 CU FT)
100
100
NA
BOILER INSTALLATION DATE
1973
1974
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
42
40
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
39
41
67
New Duct Length (Feet)
200
200
200
New Duct Costs (1000$)
1328
1361
2017
New Heat Exchanger (1000$)
2517
2581
3864
TOTAL SCOPE ADDER COSTS (1000$)
3885
3982
5948
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT!
13
13
13
9-62
-------
Table 9.4,1*6. NOx Control Cost Results for the Henderson Plant (Jme 1988 Dollars)
sf|x|BXasstK..s:.:..=;a.;....3...
Technology Boiler Main Boiler Capacity Coal
Number Retrofit Size Factor Sulfur
Difficulty (MV)
Annual NOx NOx NOx Cost
Cost Removed Removed Effect.
-------
9.5 KENTUCKY POWER COMPANY
9.5.1 Bio Sandv Steam Plant
Information for Big Sandy steam plant appears in U.S. EPA report number
EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02 and N0X
Retrofit Study" (NTIS PB88-244447/AS).
9.6 KENTUCKY UTILITIES COMPANY
9.6.1 E. W. Brown Steam Plant
Information for E. W. Brown steam plant appears in U.S. EPA report
number EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02 .
and NOx Retrofit Study" (NTIS PB88-244447/AS).
9.6.2 Ghent Steam Plant
The Ghent steam plant is located on the Ohio River in Carroll County,
Kentucky, and is operated by the Kentucky Utilities Company. The Ghent
pi ant contains four coal-fired boilers with a total gross generating
capacity of 2,224 MW.
Table 9.6.2-1 presents operational data for the existing equipment at
the Ghent plant. Coal shipments are received by barge or railroad and
transferred to a coal storage and handling area northeast of the plant. PM
emissions from the four units are controlled by ESPs Installed at the time
of construction. The ESPs for units 1 and 2 are located behind the unit 1
and 2 boilers and the ESPs for units 3 and 4 are located behind the unit 3
and 4 chimney. Flue gases from the boilers are directed to two chimneys,
one for units 1 and 2 and one for units 3 and 4. Fly ash is disposed in a
pond southeast of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
Although units 2-4 burn low sulfur coal to comply with the 1971 NSPS
emission limits, retrofit factors were developed for all boilers. L/LS-FGD
absorbers for unit 1 would be located at the east end of the unit, the
9-64
-------
TABLE 9.6.2-1. GHENT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
3,4
GENERATING CAPACITY (MW-each)
556
556
CAPACITY FACTOR (PERCENT)
38,36
33,36
INSTALLATION DATE
1973,77
1981,84
FIRING TYPE
TANGENTIAL
OPPOSED WALL
FURNACE VOLUME (1000 CU FT)
421,422
471,432
LOW NOx COMBUSTION
NO
YES
COAL SULFUR CONTENT (PERCENT)
3.0,0.7
0.7
COAL HEATING VALUE (BTU/LB)
11000,12900
12900
COAL ASH CONTENT (PERCENT)
9.1,8.3
8.3
FLY ASH SYSTEM
WET DISPOSAL
ASH DISPOSAL METHOD
PONDS/ON-SITE
STACK NUMBER
1
2 •
COAL DELIVERY METHODS
RAILROAD/BARGE
PARTICULATE CONTROL
TYPE
ESP
ESP
INSTALLATION DATE
1973,77
1981,84
EMISSION (LB/MM BTU)
0.537,0,428
0.171,0.128
REMOVAL EFFICIENCY
98.5,99
99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCERT)
3.2,0.5
0.7
SURFACE AREA (1000 SQ FT)
369,648
581
GAS EXIT RATE (1000 ACFM)
1900,2900
3450
SCA (SQ FT/1000 ACFM)
194,223
168
OUTLET TEMPERATURE (*F)
292,630
775
9-65
-------
unit 2 absorbers would be located between units 2 and 3 and the absorbers
for units 3 and 4 would be located at the west end of the plant. The
general facilities factor is medium (8 percent) for the L/LS-FGD absorber
location for unit 2 because of the necessity for relocation of a road and
high (15 percent) for the absorber location for units 1, 3, and 4 because of
the necessity for the relocation of several large storage buildings and
plant roads. The site access/congestion factor is high for the unit 1
absorber location because of the proximity of the coal conveyor and cooling
towers. The congestion around the unit 2 absorber location, due to the
proximity of the unit 2 and 3 ESPs, coal conveyor, and river, also
necessitates a high site access/congestion factor for this location. After
relocation of the storage buildings, the site access/congestion factor would
be low for the unit 3 and 4 FGD absorber locations. Approximately 300 to
500 feet of ductwork would be required for installation of the wet FGD
system for units 1, 2, and 4 and over 600 feet of ductwork would be required
for unit 3. A medium site access/congestion factor was assigned to flue gas
handling for the L/LS-FGD system at the Ghent plant.
LSD with reuse of the existing ESPs was not considered for any of the
units at the Ghent plant. The unit 1 ESPs are too small to accommodate the
additional load imposed by LSD and the unit 2-4 ESPs are hot side,
therefore, cannot be reused. In addition, the sulfur content of the coal
being burned by unit 1 is high and LSD with new FFs was not evaluated.
However, LSD with new FFs was considered for units 2-4 at the Ghent plant.
The LSD absorbers for units 2-4 would be located similarly to the wet FGD
absorbers with similar general facilities and site access/congestion
factors. About 400 feet of ductwork would be required for unit 2 and a
medium site access/ congestion factor was assigned to flue gas handling for
this unit because of the obstruction caused by the coal conveyor. Over
600 feet of ductwork would be required for unit 3 and about 400 feet would
be needed for unit 4. The site access/congestion factor for flue gas
handling for both of these units is medium.
Tables 9.6.2-2 through 9.6.2-6 give a summary of retrofit factor inputs
to the IAPCS model and estimated cost for installation of conventional FGD
systems at the Ghent plant. Costs were not developed for units 2-4 because
they are burning low sulfur coal which would result in a high unit cost.
9-66
-------
TABLE 9.6.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR GHENT UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA NA
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA NA
ESTIMATED COST (1000$) 4365 NA NA
NEW CHIMNEY NO NA NA
ESTIMATED COST (1000$) 0 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.64 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 0__
9-67
-------
TABLE 9.6,2-3. SUMMARY OF RETROFIT FACTOR DATA FOR GHENT UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE NA
BAGHOUSE CASE MEDIUM
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE NA
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA HIGH
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 4365 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS __ .
FGD SYSTEM 1.64 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.58
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.58
GENERAL FACILITIES (PERCENT) 8 0 8
9-68
-------
TABLE 9.6.2-4. SUMMARY OF RETROFIT FACTOR DATA FOR GHENT UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
600-1000
NA
ESP REUSE
NA
BAGHOUSE
600-1000
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
4365
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.49
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.38
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
15
0
15
9-69
-------
TABLE 9.6.2-5. SUMMARY OF RETROFIT FACTOR DATA FOR GHENT UNIT 4
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
4365
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.42
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.31
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
15
0
15
9-7D
-------
Table 9.6,2-6. Summry of fSD Control Cost# for the Ghent Plant (Juw 1988 Dollars)
sssssaaasasaaaasassasssssassssaaaaaasaaaaasssaaaa
Technology Boiler Main Boiler Capacity Coal Capital Capital AnnuaI Annual S02 S02 S02 Cost
Nuirber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (MO (X) Content (SMM) (*/kW) (nHls/kwh) (X)
Factor
-------
Coal Switching and Physical Coil Cleaning Costs-
Table 9.6.2-7 presents the IAPCS cost results for CS for unit 1 at the
Ghent plant. Units 2-4 were not considered for CS because they are already
burning Tow sulfur coal. PCC has only been considered for mine mouth
plants, therefore, was not considered here.
N0X Control Technologies-
Units 2-4 meet 1971 NSPS N0„ emission and, as such, were not considered
X
for LNC technologies. Unit 1 is a tangential-fired boiler and OFA was
considered for NO emission control for this unit. Tables 9.6.2-8 and
A.
9.6.2-9 present performance and cost results for OFA at unit 1.
Selective Catalytic Reduction-
Hot side SCR reactors for units 2 and 3 at the Ghent plant would be
located between units 2 and 3. Cold side reactors for unit 1 and hot side
reactors for unit 4 would be located at the east and west end of the unit 1
and 4 ESPs, respectively. A low general facilities value of 13 percent was
assigned to the unit 1 and 3 reactor locations. A medium general facilities
value of 20 percent was assigned to the reactor locations for units 2 and 4
because a plant road and several storage buildings would have to be
relocated. A medium site access/congestion factor was assigned to the
unit 1 absorber location because of the proximity of the coal conveyor and
the cooling towers. A medium site access/congestion factor was assigned to
the unit 2 and 3 reactor locations because of the proximity of the coal
conveyor and the river. A low site access/congestion factor was assigned to
the unit 4 reactor location. Approximately 400 feet of ductwork would be
required to span the distance between the SCR reactors and the chimneys for
all of the units. Tables 9.6.2-8 and 9.6.2-9 summarize the retrofit factors
and costs for installation of SCR at the Ghent plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs —
Sorbent injection technologies (FSI and DSD) were not considered for
the Ghent plant. The unit 1 ESPs are too small to handle the additional
load imposed by sorbent injection and the unit 2-4 ESPs are hot side,
therefore, cannot be reused. Installation of new baghouses was not
9-72
-------
Table 9.6.2-7. Sunwry of Coal Snitching/Gleaning Costs for the Ghent Plant !Jum 1988 Dollars)
ssasssisasesasassssasexassssaisaaaassssaassssstaasassasssssasssssssssssssssssaBsassssastsaassassssssssssssassssss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nimber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMW> (%> Content CSHM) ($/kU) (««) (ailU/kwh) (X) Ctons/yr)
Factor (X)
CS/8+115 t 1.00 556 38 3.0 18.3 32.9 28.0 15.1 73.0 36134 TO.8
CS/B+I15-C 1 1.00 556 38 3.0 18.3 32.9 16.1 8.7 73.0 36134 446.2
CS/8+S5 1 1.00 556 38 3.0 12.6 22.6 11.7 6.3 73.0 36134 323.8
CS/B+S5-C 1 1.00 556 38 3.0 12.6 22.6 6.8 3.7 73.0 36134 187.1
¦aaaaaasaaaaaanaaaaaaaaaassaaaasaaaaaasaaaaa'aaaaaasaaaaaa&ssssaaasaaaaasBaatxaaaaaaaBaasssssasssasaassasssaaasssa
9-73
-------
TABLE 9.6.2-8. SUMMARY OF NOx RETROFIT RESULTS FOR GHENT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2,3
4
FIRING TYPE
TANG
TANG»OWF
OWF
TYPE OF NOx CONTROL
OFA
NA
NA
FURNACE VOLUME (1000 CU FT)
421
422,471
432
BOILER INSTALLATION DATE
1973
1977,81
1984
SLAGGING PROBLEM
NA
NA
NA
ESTIMATED NOx REDUCTION (PERCENT) 25
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
98
98
98
New Duct Length (Feet)
400
400
400
New Duct Costs (1000$)
5407
5407
5407
New Heat Exchanger (1000$)
5217
0
0
TOTAL SCOPE ADDER COSTS (1000$)
10722
5505
5505
RETROFIT FACTOR FOR SCR
1.36
1.36
1.16
GENERAL FACILITIES (PERCENT)
13
20,13
20
9-74
-------
Table 9.6.2*9. NOx Control Cost Results for the Ghent Plant (June 1988 Dollars)
3aStlSaiSaSSBBSSSS*S398SS3SS3E8>8a88a3S33a33S389333a8S3SBBSlS>SS3S8aSSaSS3Sa3aS3SSaBSS:8S33SaSSSS3SS:3aSSSSsaSS5
Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOX
NOx Cost
Nuifaer
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Iffeet.
Difficulty OtW)
Content
(«W)
CS/kU)
(»«>
(¦ills/icHh)
(X)
(tora/yr)
<$/ton>
Factor
(X)
LNC-OFA
1
1.00
556
38
3.0
1.2
2.2
0.3
0.1
25.0
1587
167.4
INC-OFA-C
1
1.00
556
38
3.0
1.2
2.2
0.2
0.1
25.0
1587
99.4
SCB-3
1
1.3d
556
38
3.0
76.1
136.3
26.4
14.3
80.0
5077
5208.5
SCR-3
2
1.36
556
36
0.7
74.9
134.3
26.2
14.9
80.0
4006
6538.6
SCR-3
3
1.36
556
33
0.7
74.7
134.3
26.2
16.3
80.0
5141
5092.8
SCR-3
4
1.16
556
36
0.7
69.5
125.0
25.0
14.3
80.0
5608
4456.7
SCR-3-C
1
1.36/
556
38
3.0
76.1
136.8
15.5
8.4
80.0
5077
3051.3
SCR-3-C
2
1.36
556
36
0.7
74.9
134.8
15.3
8.8
80.0
4006
3830.0
SCR-3-C
3
1.36
556
33
0.7
74.7
134.3
15.3
9.5
80.0
5141
2982.9
SCR-3-C
4
1.16
556
36
0.7
69.5
125.0
14.6
8.3
80.0
SMS
2609.0
SCR-7
1
1.36
556
38
3.0
76.1
136.8
21.8
11.8
80.0
5077
4297.0
SCR-7
2
1.36
556
36
0.7
74.9
134.8
21.7
12.4
80.0
4006
5410.1
SCR-7
3
1.36
556
33
0.7
74.7
134.3
21.7
13.5
80.0
5141
4213.5
SCR-7
4
1.16
556
36
0.7
69.5
125.0
20.5
11.7
80.0
5608
3650.8
SCR-7-C
1
1.36
556
38
3.0
76.1
136.8
12.8
6.9
80.0
5077
2529.0
SCR-7-C
2
1.36
556
36
0.7
74.9
134.8
12.8
7.3
80.0
4006
3183.5
SC8-7-C
3
1.36
556
33
0.7
74.7
134.3
12.7
7.9
80.0
5141
2479.2
SCR-7-C
4
1.16
556
36
0.7
69.5
125.0
12.0
6.9
80.0
5608
2147.2
=======3= zi=aiiisiiiiiai3aii:aa=asasBa3=:s3a3s:::a==s:=:==:s=3S3sas:
9-75
-------
considered for sorbent injection technologies because of the additional
costs which would be incurred.
Atmospheric FTuidized Bed Combustion and Coal Gasification Applicability-
None of the boilers were considered for repowering because of their
high capacity factors, large boiler sizes, and long remaining life.
9-76
-------
9.6.3 Green River Steam Plant
Units 1-3 are equipped with a wet lime FGD system; therefore, no
further SO^ control technologies were considered. For N0X control for units
1-3, SCR was the only technology considered since the units are too small
for LNBs. Sorbent injection technologies were not evaluated for units 4 and
5 due to the short duct residence time between the boilers and their
respective ESPs. In addition, unit 5 is equipped with hot side ESPs which
cannot be reused.
TABLE 9.6.3-1. GREEN RIVER STEAM PLANT OPERATIONAL DATA *
BOILER NUMBER
1
2 3
4
5
GENERATING CAPACITY (MW)
25
25 25
75
114
CAPACITY FACTOR (PERCENT)
2
2 2
65
65
INSTALLATION DATE
1950 1950 1950
1954
1959
FIRING TYPE
FRONT WALL
FURNACE VOLUME (1000 CU FT)
NA
NA NA
43.7
52.8
LOW NOx COMBUSTION
NO
NO NO
NO
NO
COAL SULFUR CONTENT (PERCENT)
2.3
COAL HEATING VALUE (BTU/LB)
12000
COAL ASH CONTENT (PERCENT)
8.8
FLY ASH SYSTEM
WET DISPOSAL
ASH DISPOSAL METHOD
PONDS/ON-SITE
STACK NUMBER
I
1 1
2
3
COAL DELIVERY METHODS
TRUCK/RAILROAD
FGD SYSTEM (TYPE)
WET
LIME FGD
NA
NA
FGD SYSTEM (INSTALLATION DATE)
1975
NA
NA
PARTICULATE CONTROL
TYPE
WET
SCRUBBER/
ESP
ESP
MULTIPLE CYCLONE
INSTALLATION DATE
1975
1973
1975
EMISSION (LB/MM BTU)
0.14
0.29
0.14
REMOVAL EFFICIENCY
80
98.5
99
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
4.0-0.0
1.0
0.7
SURFACE AREA (1000 SO FT)
NA
92.16
151.2
EXIT GAS FLOW RATE (1000 ACFM)
360
336
620.9
SCA (SQ FT/1000 ACFM)
NA
274
244
OUTLET TEMPERATURE ("F)
160
325
650
* Some information was obtained from plant personnel.
9-77
-------
TABLE 9.6.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR GREEN RIVER UNIT 4
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
724
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
525
0
525
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.43
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 4
would be located west of unit 5 close to the unit 1-3 chimney.
9-78
-------
TABLE 9.6.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR GREEN RIVER UNIT'S
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
1054
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
798
0
798
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.35
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 5
would be located west of unit 5 close to the unit 1-3 chimney.
9-79
-------
Table 9.6.3-4.- Sutmary of FGD Control Costs for the Green River Plant (June 1938 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
soz .
502 Cost
Nunber Retrofit
Sixe
Factor Sulfur '
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
(X)
Content
CWM)
(t/kU)
(SHM)
(mills/kwh)
m
(tons/yr)
(t/ton>
Factor
m
L/S FGD
4
1.41
75
65
2.3
39.5
527.0
17.4
40.8
90.0
7132
2441.2
L/S FGD
5
1.41
114
6S
2.3
49.1
430.4
21.5
33.1
90.0
10838
1984.8
l/S FGD
4-5
1.41
189
65
2.3
63.5
335.7
28.4
26.4
90.0
17969
1580.4
L/S FGD-C
4
1.41
75
65
2.3
39.5
527.0
10.2
23.8
90.0
7132
1423.5
1/5 FGD-C
5
1.41
114
65
2.3
49.1
430.4
12.5
19.3
90.0
10838
1157.5
US FGD-C
4-5
1.41
189
65
2.3
63.5
335.7
16.6
15.4
90.0
17969
921.3
lc trn
4
1.41
75
65
2.3
27.8
370.6
13.6
32.0
90.0
7132
1913.3
LC FGD
5
1.41
114
65
2.3
34.4
302.2
16.8
25.9
90.0
10838
1552.3
LC FGD-C
4
1.41
75
65
2.3
27.8
370.6
7.9
18.6
90.0
7132
1113.7
LC FGD-C
5
1.41
114
65
-2.3
34.4
302.2
9.8
15.1
90.0
10838
903.6
LSD+FF
4
1.43.
75
65
2.3
23.1
308.6
10.4
24.3
87.0
6854
1514.2
LSO+FF
5
1.35
114
65
2.3
38.3
335.8
15.5
23.9
87.0
10418
1487.7
ISO+FF
4-5
1.38
189
65
2.3
59.8
316.3
23.2
21.5
87.0
17273
1341.7
LSO+FF-C
4
1.43
75
65
2.3
23.1
308.6
6.0
14.2
87.0
6854
882.7
LSD+FF-C
5
1.35
114
65
2.3
38.3
335.8
9.1
13.9
87.0
10418
868.8
LSD*FF-C
4-5
1.38 .
189
65
2.3
59.8
316.3
13.5
12.6
87,0
17273
784.2
.3S.S--S3S.
II
II
II
II
II
II
II
sassas
II
II
1)
ft
II
II
II
II
II
II
11
II
II
II
58saSS3S
saas3«ss
SBS93SS8
g__ag_a_S;,_
55.5SSS
gaw_-._-._-
9-80
-------
Table 9.6.3-5, Summary of Coat Switching/Cleaning Costs for the Green River'Plant (June 1988 Dollars)
Technology
Softer Main Boiler
Number Retrofit Size
Difficulty (MU)
Factor
Capacity Coal
Factor Sulfur
(%} Content
Capital Capital Annual
Cost Cost Cost
<$WQ (S/kW) (SMH)
Annual S02 S02 S02 Cost •
Cost Removed Removed Effect,
(mills/kwh) (X) (tons/yr) (S/ton)
CS/B+S15
CS/B+S15
00
00
75
114
65
65
2.3
2.3
3.4
4.6
45.2
40.6
6.7
9.9
15.
15.
61.0
61.0
4*40
735?
1385.9
1340.7
CS/B+S15-C
CS/i+SIS-C
00
00
75
114
65
65
2.3
2.3
3.4
4.6
45.2
40.6
3.9
5.7
61.0
61.0
4840
7357
797.1
771.0
CS/B*S5
CS/B+S5
00
00
75
114
65
65
2.3
2.3
2.6
3.4
34,9
30.2
3.0
4.3
61.0
61.0
4840
7357
629.0
583.9
CS/B+S5-C
cs/b+ss-c
00
00
75
114
65
65
2.3
2.3
2.6
3.4
34.9
30.2
1.8
2.5
61.0
61.0
4840
7357
362.8
336.6
I8
-------
TABLE 9.6.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR GREEN RIVER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1-3 4 5
FIRING TYPE NA FWF FWF
TYPE OF NOx CONTROL NA LNB LNB
FURNACE VOLUME (1000 CU FT) NA 43.7 52.8
BOILER INSTALLATION DATE NA 19S4 1959
SLAGGING PROBLEM NA NO NO
ESTIMATED NOx REDUCTION (PERCENT) NA 40 32
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH HIGH MODERATE
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0 0
Ductwork Demolition (1000$) 22 22 30
New Duct Length (Feet) 100 100 200
New Duct Costs (1000$) 419 419 1070
New Heat Exchanger (1000$) 1568 1568 0_
TOTAL SCOPE ADDER COSTS (1000$) 2009 2009 1100
RETROFIT FACTOR FOR SCR 1.52 1.52 1.34
GENERAL FACILITIES (PERCENT) 20 20 20
* Cold side SCR reactors for units 1-3 would be located behind
the unit 1-3 chimney. Cold side SCR reactors for unit 4 would
be located beside the unit 4 chimney. Hot side SCR reactors for
unit 5 would be located beside the unit.
9-82
-------
Table 9.6.3-7. NQx Control Cost Results for tha GrMrt River Plant (Jir* 1988 Dollars)
Technology
Bofler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
Nuttoer
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Difficulty
Content
($MH>
wm
(WOO
Citif lls/kwh)
«>
(tons/yr)
Factor
<%>
LNC-INB
4
1
00
75
65
2.3
2.3
30.3
0.5
1.2
40.0
742
LNC-LNB
5
1
00
114
65
2.3
2.7
23.6
0.6
0.9
32.0
902
LMC-IN8-C
4
1
00
75
65
2.3
2.1
30.3
0.3
0.7
40.0
742
LMC-INB-C
5
1
00
114
65
2.3
2.7
23.6
0.3
0.5
32.0
902
SCR-3
1-3
1
52
75
2
2.3
13.2
242.2
5.5
419.6
80.0
46
SCR-3
4
1
52
75
65
2.3
18.4
245.8
5.9
13.7
80.0
1484
SCR-3
5
1
34
114
65
2.3
21.4
187.9
11.2
80.0
2256
SCR-3-C
1-3
1
52
75
2
2.3
18.2
242.2
3.2
246.6
80.0
46
SCR-3-C
4
1
52
73
65
2.3
18.4
245.6
3.4
8.0
30.0
1484
SC8-3-C
5
1
34
114
65
2.3
21.4
187.9
4.3
6.6
80.0
2256
SCR-7
1-3
1
52
75
2
2,3
18.2
242.2
4.9
372.7
80.0
46
sca-7
4
1
52
75
65
2.3
18.4
245.8
5.2
12.3
80.0
1484
SCR-7
5
1
34
114
65
2.3
21.4
187.9
6.3
9.8
80.0
2256
SCR-7-C
1-3
1
52
75
2
2.3
18.2
242.2
2.9
219.7
80.0
46
SCR-7-C
4
1
CM
in
75
65
2.3
18.4
245.8
3.1
7.2
80.0
1484
SCR-7-C
5
1
34
114
65
2.3
21.4
187.9
3.7
5.7
80.0
2256
HOx Cost
Effect.
($/ton)
662.2
643.9
393.1
382.2
120731.a
3944.2
3223.1
70955.2
2315.4
1889.2
107235.4
3529.1
2803.0
63220.5
2077.6
1651.3
33X225 5255525 3S3S3S3C3X
9-83
-------
9.7 LOUISVILLE GAS AND ELECTRIC
9.7.1 Hill Creek Steam Plant
The Mill Creek steam plant is located within Jefferson County,
Kentucky, as part of the Louisville Gas and Electric Company system. The
plant contains four coal-fired boilers with a total gross generating
capacity of 1717 MW. Figure 9.7.1-1 presents the plant plot plan showing
the location of all boilers and major associated auxiliary equipment.
Table 9.7.1-1 presents operational data for the existing equipment at
the Mill Creek plant. The boilers burn high sulfur coal (3.3 percent
sulfur). Coal shipments are received by railroad and barge and conveyed to
a coal storage and handling area located southeast of the powerhouse.
Units 1 and 2 share a common chimney while units 3 and 4 have their
own. All four units have an FGD system (spray towers); units 1 and 2 have
retrofit FGD systems and units 3 and 4 have new FGD systems. Therefore,
application of SOg controls was not considered. The N0X technologies
evaluated at this plant were: OFA - units 1 and 2; LNB - units 3 and 4; and
SCR - all units.
Low NO Combustion--
A
Units 1 and 2 are dry bottom, tangential-fired boilers each rated at
356 MW. The combustion modification technique applied for units 1 and 2 was
OFA, Units 3 and 4 are dry bottom, opposed wall-fired boilers each rated at
463 and 544 MW, respectively. The combustion modification technique applied
for units 3 and 4 was LNB. As Tables 9.7.1-2 and 9.7.1-3 show, the OFA N0X
reduction performance for units 1 and 2 was estimated at 20 percent and LNB
N0X reduction performance for units 3 and 4 was estimated at 50 percent.
The reduction performance levels for units 1 to 4 were assessed by examining
the effects of heat release rates and furnace residence time on NOx
reduction through the use of the-simplified N0x procedures. Table 9.7.1-4
presents the cost of retrofitting OFA and LNB at the Hill Creek boilers.
9-84
-------
¦N
Existing PQD
Waste Handling
Area
f771 FGO Waste MandHno/Absorber Area
VA Lime/Limestone Storage^Praparation Are
NH, storage System
SCR Boxes
Ohio River
Not to scale
Figure 9.7.1-1. Mill Creek plant plot plan
9-85
-------
TABLE 9.7.1-1. MILL CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
3
4
GENERATING CAPACITY (MW-each)
355.5
462.6
543.6
CAPACITY FACTOR (PERCENT)
35, 43
35
49
INSTALLATION DATE
1972-74
1978
1982
FIRING TYPE
TANG
OWF
OWF
COAL SULFUR CONTENT (PERCENT)
3.3
3.3
3.3
COAL HEATING VALUE (BTU/LB)
11139
11137
11140
COAL ASH CONTENT (PERCENT)
11.4
11.4
11.4
FLY ASH SYSTEM
DRY
ASH DISPOSAL METHOD
ON-SITE
STACK NUMBER
1
2
3
COAL DELIVERY METHODS
RAIL/BARGE
FGD SYSTEM
YES
YES
YES
INSTALLATION DATE
1901-80
1978
1982
FGD TYPE
LIME WET SCRUBBER
PARTICULATE CONTROL
TYPE
ESP
ESP
ESP
INSTALLATION DATE
1972
1978
1982
EMMIS ION (LB/MM BTU)
0.1
0.1
0.1
REMOVAL EFFICIENCY
99.4
99.6
99.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
3.2
2.0
2.0
SURFACE AREA (1000 SQ FT)
237.6
315.6
487.2
GAS EXIT RATE (1000 ACFM)
1080
1670
2100
SCA (SQ FT/1000 ACFM)
220
189
232
OUTLET TEMPERATURE (*F)
300, 305
340
300
9-86
-------
TABLE 9.7.1-2. SUMMARY OF NOx RETROFIT RESULTS FOR MILL CREEK UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
TANG
TANG
OWF
TYPE OF NOx CONTROL
OFA
OFA
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.1
14.1
13
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
119.7
119.7
125.5
FURNACE RESIDENCE TIME (SECONDS)
3.59
3.59
3.59
ESTIMATED NOx REDUCTION (PERCENT)
20
20
50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
70
70
85
New Duct Length (Feet)
350
550
1100
New Duct Costs (1000$)
3645
5728
13360
New Heat Exchanger (1000$)
3993
3993
4675
TOTAL SCOPE ADDER COSTS (1000$)
7708
9791
18120
RETROFIT FACTOR FOR SCR
1.16
1.16
1.34
GENERAL FACILITIES (PERCENT)
20
20
13
9-87
-------
TABLE 9.7.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR MILL CREEK UNIT 4
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) 10.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 123.9
FURNACE RESIDENCE TIME (SECONDS) 3.87
ESTIMATED NOx REDUCTION (PERCENT) 50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 96
New Duct Length (Feet) 800
New Duct Costs (1000$) 10677
New Heat Exchanger (1000$) 5150
TOTAL SCOPE ADDER COSTS (1000$) 15923
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 13
9-88
-------
Table 9.7.1-4. NOx Control Cost Results for the Hill Creek Plant (June 19BS Dollars)
maamamamsmmxaaauaaauaaaamaaamMaamnaa^tmmamwMMmaaaaMW^aammMammsamaaamaaama'mMmmaaaammamawBaaammmmmamasmsaaa'amaaawws
Technology Boiler Main Sailer Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
N inter Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (Ml) (X) Content (SMI)
-------
Selective Catalytic Reduction--
Tables 9.7.1-2 and 9.7.1-3 present the SCR retrofit results for each
unit. The results include process area retrofit factors and scope adder
costs. The scope adders include costs estimated for ductwork demolition,
new flue gas heat exchanger, and new duct runs to divert the flue gas from
the PM control device to the reactor and from the reactor to the chimney.
The SCR reactors for units 1 and 2 would be located northeast of the
powerhouse close to the existing FED absorbers in a relatively open area
having easy access. Therefore, the reactors for units 1 and 2 were assigned
low access/congestion factors.
A 20 percent general facilities factor was assigned to both reactors
for relocating the road to the powerhouse and demolition of small equipment
in this area. The SCR reactors for units 3 and 4 would be located south of
the powerhouse in an area surrounded by existing FGD equipment and storage
tanks. Although both reactors are located in a relatively open area, access
to this area would be very difficult. For this reason, a medium access/
congestion factor was assigned to the reactors for units 3 and 4. All
reactors were assumed to be in areas with high underground obstructions.
The ammonia storage system was placed in a remote area having a low access/
congestion factor. Table 9.7.1-4 presents the estimated cost of
retrofitting SCR at the Mill Creek boilers.
9-90
-------
9.8 OWENSBORO MUNICIPAL UTILITY
9.8.1 Elmer Smith Steam Plant
Information on Elmer Smith steam plant appears in U.S. EPA report
number EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02
and N0X Retrofit Study" (NTIS PB88-244447/AS).
9.9 TENNESSEE VALLEY AUTHORITY
9.9.1 Paradise Steam Plant
Information on Paradise steam plant appears in U.S. EPA report number
EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02
and N0X Retrofit Study" (NTIS PB88-244447/AS).
9.9.2 Shawnee Steam Plant
The Shawnee steam plant is located within McCracken County, Kentucky,
as part of the TVA system. The plant contains 10 coal-fired boilers with a
total gross generating capacity of 1,750 MW. Figure 9.9.2-1 presents the
plant plpt plan showing the location of all boilers and major associated
auxiliary equipment.
Table 9.9.2-1 presents operational data for the existing equipment at
the Shawnee steam plant. Boilers 1-9 burn low sulfur coal (0.65 percent
sulfur) while unit 10 burns high sulfur coal. Coal shipments are received
by freight barge and conveyed to a coal storage and handling area located
west of unit 10. Coal can also be received by rail.
Particulate matter emissions from all 10 boilers are controlled with
retrofit baghouses located north of the old ESPs and chimneys. Ash from all
units is wet sluiced to ponds on the far side of the coal storage area
northwest of the plant. On-site waste disposal is limited and TVA is
considering either the purchase of more land adjacent to the plant or dry
disposing of the waste off-site by truck. Currently, TVA plans on
repowering unit 10 with AFBC to demonstrate the commercial ability of this
technology.
9-91
-------
t
LIMESTONE PREPARATION/
STORAGE AREA
LEGEND ¦— * - T
I " SCR
E3 ~FGD
#'s - INDICATE
BOILER NUMBER
Figure 9.9.2-1. Shawnee plant plot plan
9-92
-------
TABLE 9.9.2-1. SHAWNEE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-10
GENERATING CAPACITY (MW-each) 175
CAPACITY FACTOR (PERCENT) 28,33,35,39,23,28,42,38,36,73
INSTALLATION DATE 1953-56
FIRING TYPE FWF
COAL SULFUR CONTENT (PERCENT; 1-9,10) 0.60, 3.5
COAL HEATING VALUE (BTU/LB) 12000
COAL ASH CONTENT (PERCENT) 7.5
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD POND/ON-SITE
STACK NUMBER 1-2
COAL DELIVERY METHODS BARGE or RAIL
PARTICULATE CONTROL
TYPE BAGHOUSE
INSTALLATION DATE 1979-81
EMISSION (LB/MM BTU) 0.03
REMOVAL EFFICIENCY 99.4-99.2
DESIGN SPECIFICATION
GAS EXIT RATE 585
GROSS AIR TO FABRIC RATIO (FT/MIN) 2.23
OUTLET TEMPERATURE (*F) 310
9-93
-------
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 9.9.2-1 shows the general layout and location of the FGD control
system. The major equipment at Shawnee includes 10 boilers and 2 chimneys
which serve 5 units each. The plant is equipped with retrofit baghouses
located between the old ESPs and chimneys, directly behind the boilers
(north). Flue gas from units 1 to 5 is presently ducted to one chimney and
the flue gas from units 6 to 10 is ducted to the other chimney. The
absorbers for units 1 to 5 for the FGD technologies would be located east of
the powerhouse. Part of the employee parking lot (north end) would be used
for the placement of these absorbers. A factor of 7 percent was assigned
to general facilities for units 1 to 5. The absorbers for units 6 to 10
could be located east of the plant but this location would involve the
installation of an extremely long duct run (>1000 feet). The absorbers for
units 6 to 10 would be located directly behind (north) the old ESPs and old
chimneys for these units. This would require that the existing sand filters
be relocated to make space available. A factor of 10 percent was assigned
to general facilities for units 6 to 10. The limestone preparation/storage
area for all units was located adjacent to (north) the absorbers for units 1
to 5 northeast of the unit 1 powerhouse. The waste handling area was
located adjacent (south) to the preparation/storage area.
Retrofit Difficulty and Scope Adder Costs--
The Shawnee plant has already switched to a low-sulfur coal. It is
unlikely that this plant would need scrubbing. However, should this become
necessary, it would be more cost effective to switch to a higher sulfur
content coal, taking into account the fuel cost differential in estimating
cost effectiveness.
Most of the FGD equipment was placed in relatively low access/
congestion areas with no significant underground obstructions. The
absorbers for units 6 to 10, however, were placed in a high access/
congestion area northwest of the powerhouse. This factor reflects the
congestion of the water treatment building (east), coal conveyor (north and
northwest), and river (north) around the absorbers. The poor load bearing
capacity of the soils was also taken into consideration for units 6-10.
There is considerable space available behind the existing chimney for the
9-94
-------
units 1 to 5 L/LS-FGD ductwork and a low access/congestion factor was
assumed for flue gas handling in this area. A low site access/congestion
factor was also assigned to the flue gas handling for units 6 to 10 for
L/LS-FGD. This factor was assigned for the following reasons: 1) all of
the flue gas is presently routed to a common duct and it only needs to be
routed from the baghouses to the absorbers and back to the shared chimney;
2) the location of the absorbers next to the chimney; and 3) the fact that
no significant duct work would be required.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 9.9.2-2 and 9.9.2-3. The
main scope adder cost for the Shawnee plant was the conversion of units 1 to
10 fly ash conveying/disposal system from wet to dry for conventional
L/LS-FGD and LSD-FGD cases. It was assumed that this conversion would be
necessary to stabilize the L/LS-FGD scrubber sludge waste and to prevent
plugging of the sluice lines in LSD-FGD cases. However, this conversion is
not necessary for the application of forced oxidation L/LS-FGD. The overall
retrofit factors determined for the L/LS-FGD technologies were moderate
(1.31 to 1.48).
* The LSD-FGD with reuse baghouse was the only LSD-FGD case considered at
Shawnee. A high access/congestion factor was assigned to LSD-FGD flue gas
handling for several reasons. These included the limited space available
around the retrofit baghouses and the ductwork required to route the flue
gas from upstream to the existing retrofit baghouses, to the absorbers, and
back to the baghouses. The retrofit factors determined for reusing the
baghouses were moderate (1.SO to 1.61).
Table 9,9.2-4 presents the costs estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the baghouses and ash handling systems
for boilers 1-10.
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare
scrubber module, and optimization of scrubber size.
Coal Switching Costs--
The plant has already switched to low sulfur coal.
9-95
-------
TABLE 9.9.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR SHAWNEE UNITS 1-5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING LOW LOW
BAGHOUSE REUSE CASE HIGH
NEW BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
BAGHOUSE REUSE 600-1000
NEW BAGHOUSE NA
BAGHOUSE REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 1548 NA 1548
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 1.31
BAGHOUSE REUSE CASE 1.50
NEW BAGHOUSE CASE NA
BAGHOUSE UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 7 7 7
9-96
-------
TABLE 9.9.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR SHAWNEE UNITS 6-10
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING LOW LOW
BAGHOUSE REUSE CASE HIGH
NEW BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 0-100 0-100
BAGHOUSE REUSE 100-300
NEW BAGHOUSE NA
BAGHOUSE REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 1548 NA 1548
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.48 1.44
BAGHOUSE REUSE CASE 1.61
NEW BAGHOUSE CASE NA
BAGHOUSE UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
9-97
-------
Table 9.9.2-4. Sumary of FGD Control Costs for the Shawnee Plant
L/S FGD 1-5 1.38 875 31 0.7 150.8 172.3 59.5 25.1 90.0 12077 4930.4
US FGD 6-10 1.48 875 43 0.7 162.9 186.2 67.7 20.6 90.0 16752 4043.5
L/S m-c
L/S FGD-C
IC FGD
IC FSG
IC FGD-C
IC FGD-C
L5D*PFF
LSO*PFF
LSO*PFF-C
LSO+PFF-C
1-5
6-10
1-5
6-10
1-5
6-10
1-5
6-10
1-5
6-10
38
48
38
48
50
61
50
61
875
875
875
875
38 875
48 875
875
875
875
875
31
43
31
43
31
43
31
43
31
43
0;7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0,7
150.8
162.9
125.2
135.1
125.2
115.1
89.5
97.3
89.5
97.3
172.3
186.2
34.8
39.5
143.1 51.4
154.4 58.9
143.1 30.0
154.4 34.4
102.2
111.2
102.2
111.2
31.2
34.9
18.3
20.4
14.6
12.0
21.6
17.9
12.6
10.4
13.1
10.6
7.7
6.2
90.0
90,0
90.0
90.0
90.0
90.0
87.0
87.0
87.0
87.0
12077
16752
12077
16752
12077
16752
11607
16100
11607
16100
2880.8
2360.2
4257.8
3516.4
2485.9
2050.8
2689.8
2164.7
1575.7
1267.3
SSaBBB88S8afS«BS3833SSSSSSXBISSSSaS3aS3SSSSSS:=SSSSSS8Sa3SaS8aSS&fi»ISS839aaSa3SSSBSS3IS3aassaS
9-98
-------
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at Shawnee. These controls include LNC
modifications and SCR. The application of NO control technologies is
A
determined by several site-specific factors which are discussed in
Section 2. The N0X technologies evaluated at Shawnee were: LNB and SCR.
Low N0„ Combustion--
x
Units 1 to 10 are dry bottom, front wall-fired boilers each rated at
175 MW. The N0X combustion control considered in this analysis was LNB.
Tables 9.9.2-5 through 9.9.2-8 present the LNB N0X reduction performance
results for units 1 to 10. The N0X reduction performance estimated for each
of the 10 units was 37 percent. The same N0X reduction performance was
estimated for all units because they have the same heat release rates and
furnace residence times. Table 9.9.2-9 presents the costs estimated for LNB
retrofit at the Shawnee boilers.
Selective Catalytic Reduction-
Tables 9.9.2-5 through 9.9.2-8 present the SCR retrofit difficulty
factor and scope adder costs for each unit. For scope adders, costs are
estimated for ductwork demolition, new heat exchanger, and new duct runs to
divert the flue gas from the baghouse outlet to the reactor and from the
reactor to the chimney. The duct costs are the highest for units 5 and 6.
The SCR reactors were located north of the plant immediately behind the
baghouse of each unit in a highly congested area. The road behind the
baghouses would have to be relocated. The ammonia storage system was
located northwest of the plant in a relatively open area.
All reactors, with the exception of those for units 5 and 6, would be
located in a high access/congestion area. Reactors for units 1 to 4 were
located between the baghouses and water treatment plant and those for
units 7 to 10 were located between the baghouses and the sand filter. The
reactors for units 5 and 6 were in a medium congestion area because there
was an open space between the water treatment plant and the sand filter.
All reactors were assumed to be in an area with high underground obstructions.
The ammonia storage system, which supplied ammonia to all 10 reactors, would
9-99
-------
TABLE 9.9.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR SHAWNEE UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
18.6
18.6
18.6
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
63.8
63.8
63.8
FURNACE RESIDENCE TIME (SECONDS)
2.1
2.1
2.1
ESTIMATED NOx REDUCTION (PERCENT)
37
37
37
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
NA
Ductwork Demolition (1000$)
41
41
41
New Duct Length (Feet)
290
370
450
New Duct Costs (1000$)
1994
2543
3093
New Heat Exchanger (1000$)
2608
2608
2608
TOTAL SCOPE ADDER COSTS (1000$) 4642 5192 5742
RETROFIT FACTOR FOR SCR 1.52 1.52 1.52
GENERAL FACILITIES (PERCENT) 13 13 13
9-100
-------
TABLE 9.9.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR SHAWNEE UNITS 4-6
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
6
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
18.6
18.6
18.6
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
63.8
63.8
63.8
FURNACE RESIDENCE TIME (SECONDS)
2.1
2.1
2.1
ESTIMATED NOx REDUCTION (PERCENT)
37
37
37
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demol1tion (1000$)
0
NA
NA
Ductwork Demolition (1000$)
41
41
41
New Duct Length (Feet)
530
660
630
New Duct Costs (1000$)
3643
4537
4331
New Heat Exchanger (1000$)
2608
2608
2608
TOTAL SCOPE ADDER COSTS (1000$)
6292
7186
6979
RETROFIT FACTOR FOR SCR
1.52
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
9-101
-------
TABLE 9.9,2-7. SUMMARY OF NOx RETROFIT RESULTS FOR SHAWNEE UNITS 7-8
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
7
8
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
18.6
18.6
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
63.8
63.8
FURNACE RESIDENCE TIME (SECONDS)
2.1
2.1
ESTIMATED NOx REDUCTION (PERCENT)
37
37
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
Ductwork Demolition (1000$)
41
41
New Duct Length (Feet)
550
480
New Duct Costs (1000$)
3781
3300
New Heat Exchanger (1000$)
2608
2608
TOTAL SCOPE ADDER COSTS (1000$) 6429 S948
RETROFIT FACTOR FOR SCR 1.52 1.52
GENERAL FACILITIES (PERCENT) 13 13
9-102
-------
TABLE 9.9.2-8. SUMMARY OF NQx RETROFIT RESULTS FOR SHAWNEE UNITS 9-10
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
>
9
10
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB .
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
18.6
18.6
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
63.8
63.8
FURNACE RESIDENCE TIME (SECONDS)
2.1
2.1
ESTIMATED NOx REDUCTION (PERCENT)
37
37
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
NA
0
Ductwork Demolition (1000$)
41
41
New Duct Length (Feet)
390
310
New Duct Costs (1000$)
2681
2131
New Heat Exchanger (1000$)
2608
2608
TOTAL SCOPE ADDER COSTS (1000$)
5330
4780
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
13
13
9-103
-------
Table 9,9,2-9. NQx Control Cost Results for the Shawm Plant (Jwe 1988 Dollars)
i»«»Ma:»3B:3:s3E:»iiii3::9snB»:n>ii>u>n»ssss:33s::xis>na»»Ha>uKs»gaan(>ia!f»3=3:«aniz:a:sn
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NQx NOx Cost
Nurtoer Retrofit size Factor Sulfur Cost Cost Cost Cost Removed Renoved Effect.
Difficulty (MW) (X) Content CSW) (S/M) (SMH) (Bills/la*) >nnn»:>>in>n:"n
continued . . •
9-104
-------
Table 9.9.2-9.
NOx Control Coat Results far the Shawnee Plant (June 1988 Dollars) continued .
aBfliAcaasBBais
XBZSSS8
issnm
atimm
e<®rsi 3s> flnKsnn
isacxxsi
iacaigayya»rfflga
'sassss
sssssssssar;
•SSasscss
Technology
Boiler Main
Boiler Capacity Coel
Capital Capital Annual
Annual
Wx
N0x
NOx Cost
Nuifcer Retrofit
Size
Factor Sulfur
Coat
Cost
Coat
Cost
Removed Removed
Effect.
Difficulty (NU)
(X>
Content
(SHU)
(S/klft
(SMK)
(nills/kvh)
(X)
(tons/yr)
(i/ton)
Factor
-------
be located east of the plant in a low access/congestion area with no
significant underground obstructions. Table 9.9.2-9 presents the cost
estimated for retrofitting SCR at the Shawnee boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for S02 control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas for al1 units are
located east of the plant in a relatively open area. The retrofit of DSD
and FSI technologies at the Shawnee steam plant would be relatively easy.
This is due to the long flue gas ducting residence time between the boilers
and the retrofit fabric filters and because no additional particulate
controls would be needed. Additional duct residence time for DSD
application could be made available if the existing ESPs were used for
sorbent injection. The major scope adder cost for DSD and FSI technologies
would be the conversion of wet to dry fly ash handling system for reusing
the baghouses. Table 9.9.2-10 presents a summary of site access/congestion
factors, scope adders, and retrofit factors for DSD and FSI technologies at
the Shawnee steam plant. Table 9.9.2-11 presents the costs estimated for
FSI and DSD retrofit at Shawnee for boilers 1-9.
' Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Using the applicability criteria presented in Section 2 for AFBC
retrofit and AFBC/CG/combined cycle repowering, all boilers at the Shawnee
steam plant would be considered good candidates for AFBC retrofit and AFBC
or CG/Combined Cycle repowering because of their small boiler sizes. The
low capacity factor of the units and the fact that unit 10 has been
repowered with AFBC as a demonstration project also supports this
conclusion.
9-106
-------
TABLE 9.9.2-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SHAWNEE UNITS 1-10
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE NA
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1548
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
BAGHOUSE REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 46
TOTAL COST (1000$)
EXISTING BAGHOUSE CASE 1594
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE NA
NEW BAGHOUSE NA
9-107
-------
Table 9.9.2-11. Sunsary of DSD/FSI Control Costa for th* ShavtM Plant (Jine 1988 Dollars)
aaiHHiiaaaiiasinsiiiBiBiisaaiiamaisasBiisitisnnHiiiaasssiuHaaimausiiiaflasntHisstsisnnsasaasKB
Technology Boiler Hein Boiler Capacity Coal Capital Capital Annual Annual 502 502 S02 Cost
Niafear Retrofit
Size
Factor Sulfur
Coat
Coat
Coat
Coat
Removed f) amoved
Effect.
Difficulty
C"H>
CX)
Content
CSMM)
<*/*«)
CSMH)
(¦Illi/kMh)
C*>
(tans/yr)
(S/ton)
Factor
(X)
OSO+PFF
1
1.00
175
28
0.7
5.9
33.6
4.3
10.0
71.0
1715
2497.9
OSO+PFF
2
1.00
175
33
0.7
5.9
33.6
4.4
8.6
71.0
2021
2164.7
DSD+PFF
3
1.00
175
35
0.7
5.9
33.6
4.4
8.2
71.0
2144
2058.2
DSD+PFF
4
1.00
175
39
0.7
5.9
33.6
4.5
7.5
71.0
2389
1877.7
DSD+PFF
5
1.00
175
23
0.7
5.9
33.6
4.2
11.9
71.0
1409
2976.2
DSO+PFf
6
1.00
175
28
0.7
5.9
33.6
4.3
10.0
71.0
1715
2497.9
DSD+PFF
7
1.00
175
42
0.7
5.9
33.6
4.5
7.1
71.0
2573
1765.0
OSO+PFF
a
1.00
175
38
0.7
5.9
33.6
4.5
7.7
71.0
2328
1919.3
DSD+PFF
9
1.00
175
36
0.7
5.9
33.6
4.4
8.0
71.0
2205
2009.2
D50+PFF-C
i
1.00
175
28
0.7
5.9
33.6
2.5
5.8
71.0
1715
1446.5
DSD+PFF-C
2
1.00
175
33
0.7
5.9
33.6
2.5
5.0
71.0
2021
1253.3
DSO+PFF-C
3
1.00
175
35
0.7
5.9
33.6
2.6
4.8
71.0
2144
1191.5
DSD+PFF-C
4
1.00
175
39
0.7
5.9
33.6
2.6
4.3
71.0
Z389
1086.B
DSO+PFF-C
5
1.00
175
23
0.7
5.9
33.6
2.4
6.9
71.0
1409
1723.8
DSO+PFF-C
6
1.00
175
28
0.7
5.9
33.6
2.5
5.8i
71.0
1715
1446.5
DSO+PFF-C
7
1.00
175
42
0.7
5.9
33.6
2.6
4.1
71.0
2573
1021.4
DSO+PFF-C
8
1.00
175
38
0.7
5.9
33.6
2.6
4.4
71.0
2328
1110.9
DSO+PFF-C
9
1.00
175
36
0.7
5.9
33.6
2.6
4.6
71.0
2205
1163.1
FSI+PFF-50
1
1.00
175
28
0.7
5.3
30.3
3.0
7.0
50.0
1212
2474.5
FSI+PFF-50
2
1.00
175
33
0.7
5.3
30.3
3.1
6.2
50.0
1428
2178.3
FSI+PFF-50
3
1.00
175
35
0.7
5.3
30.3
3.2
5.9
50.0
1515
2083.4
FSI+PFF-50
4
1.00
175
39
0.7
5.3
30.3
3.2
5.4
50.0
1688
1922.9
FSI+PFF-50
5
1.00
175
23
0.7
5.3
30.3
2.9
8.2
50.0
996
2899.3
FSI+PFF-50
6
1.00
175
28
0.7
5.3
30.3
3.0
7.0
50.0
1212
2474.5
FSI+PFF-50
7
1.00
175
42
0.7
5.3
30.3
3.3
5.1
50.0
1818
1822.8
FSI+PFF-50
8
1.00
175
38
0.7
5.3
30.3
3.2
5.5
50.0
1645
1960.0
FSI+PFF-50
9
1.00
175
36
0.7
5.3
30.3
3.2
5.8
50.0
1558
2040.1
FSI+PFF-50-C
1
1.00
175
28
0.7
5.3
30.3
1.7
4.1
50.0
1212
1437.4
FSI+PFF-50-C
2
1.00
175
33
0.7
5.3
30.3
1.8
3.6
50.0
1428
1264.7
FSI+PFF-50-C
3
1.00
175
35
0.7
5.3
30.3
1.S
3.4
50.0
1515 1209.4
nmamaaananiii
continued . . .
9-108
-------
labia 9.9.2-11. Surma ry of DS8/F5I Control Coats for the Shawnee Plant (Ju* 1988 Dollars} continued . . .
K*u*slsi»aaza8SBsaisa>saiBes»ia3as«iHmaan»BSBK»8»siBflswi»Hi»ak«s38tti8nsas3sss»aax3i3Ssa89a3Has9
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nwtoer Retrofit Size Factor Sulfur Coat Coat Coat Cost Removed Removed Effect.
Difficulty (MO CX> Content C»tO ($/kW) {nills/kwh) Ctona/yrJ (S/ton>
Factor (X)
FSI+PFF-50-C 4
1.00
175
39
0.7 ,
5.3
30.3
1.9
3.2
50.0
1688
1115.8
FSI+PFF-50-C 5
1.00
175
23
0.7
5.3
30.3
1.7
4.8
50.0
996
1685.1
FS1+PFF-50-C 6
1.00
175
28
0.7
5.3
30.3
1.7
4.1
50.0
1212
1437.4
FS1+PFF-50-C 7
1.00
175
42
0.7
5.3
30.3
1.9
3.0
50.0
1818
1057.4
FS1+PFF-50-C 8
1.00
175
38
0.7
5.3
30.3
1.9
3.2
50.0
1641
1137.4
FSI+PFF-50-C 9
1.00
175
36
0.7
5.3
30.3
1.8
3.3
50.0
1158
1184.1
F5I+PFF-70 1
1.00
175
28
0.7
5.3
30.3
3.0
7.0
70.0
1697
1769.4
FS1+PFF-70 2
1.00
175
33
0.7
5.3
30.3
3.1
6.2
70.0
2000
1557.8
FSI+PFF-70 3
1.00
175
35
0.7
S.3
30.3
3.2
5.9
70.0
2121
1490.1
FSI+PFF-70 4
1.00
175
39
0.7
5.3
30.3
3.3
5.4
70.0
2363
1375.5
FSI+PFF-70 S
1.00
175
23
0.7
5.3
30.3
2.9
8.2
70.0
1394
2072.9
FSI+PFF-70 6
1.00
175
28
0.7
5.3
30.3
3.0
7.0
ra.o
1697
1769.4
FSI+PFF-70 7
1.00
175
42
0.7
5.3
30.3
3.3
5.2
70.0
2545
1303.8
FSI+PFF-70 8
1.00
175
38
0.7
5.3
30.3
3.2
,5.5
70.0
2303
1401.9
FSI+PFF-70 9
1.00
175
36
0.7
5.3
30.3
3.2
5.8
75.0
2182
1459.2
FSl+PFF-TO-C 1
1.00
175
28
0.7
5.3
30.3
1.7
4.1
70.0
1697
1027.8
FSI+PFF-70-C 2
1.00
175
33
0.7
5.3
30.3
1.8
3.6
70.0
2000
904.4
FSI+PFF-70-C 3
1.00
175
35
0.7
5.3
30.3
1.8
3.4
70.0
2121
864.9
FSI+PFF-70-C 4
1.00
175
39
0.7
5.3
30.3
1.9
3.2
70.0
2363
798.1
FSI+PFF-70-C 5
1.00
175
23
0.7
5.3
30.3
1.7
4.8
70.0
1394
1204.7
FSI+PFF-70-C 6
1.00
175
28
0.7
5.3
30.3
1.7
4.1
70.0
1697
1027.8
FSI+PFF-70-C 7
1.00
175
42
0.7
5.3
30.3
1.9
3.0
70.0
2545
756.4
FSI+PFF-70-C 8
1.00
175
38
0.7
5.3
30,3
1.9
3.2
70.0
2303
813.5
FS1+PFF-70-C 9
1.00
175
36
0.7
5.3
30.3
1.8
3.3
70.Q
2182
846.9
SS8SSa3xaiS8«SS8S3«M
lamaralaaa)ma]llaHUIWSWHIHUSVKnBlsa:anl8Juilat6aiiassa8
9-109
-------
-------
SECTION 10.0 MASSACHUSETTS
10.1 MONTAUP ELECTRIC COMPANY
10.1.1 Somerset Steam Plant
The Somerset Steam Plant is located in Bristol County, Massachusetts,
as part of the Montaup Electric Company system. The plant contains two
coal-fired boilers with a total gross generating capacity of 188 MW.
Tables 10.1.1-1 through 10.1.1-10 summarize the plant operational data and
present the S02 and N0X control cost and performance estimates.
TABLE 10.1.1-1. SOMERSET STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
7 8
71 117
21 21
1951 1959
TANGENTIAL
NA NA
NO NO
1.2
13300
6.8
DRY DISPOSAL
PAID/OFF-SITE
1
BARGE
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
1984
0.03
99.7
0.8-1.2
122.2
300
407
345
ESP
1984
0.02
99.7
0.8-1.2
187.4
465
403
310
10-1
-------
TABLE 10.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR SOMERSET
UNIT 7 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
497
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.4.1
NA
ESP REUSE CASE
1.47
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
* L/LS-FGD and LSD-FGD absorbers for unit 7 would be located
north of unit 8.
10-2
-------
TABLE 10.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR SOMERSET
UNIT 8 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
819
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.34
NA
ESP REUSE CASE
1.36
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
IS
* L/LS-FGD and LSD-FGD absorbers for unit 8 would be located
north of unit 8.
10-3
-------
Table 10.1.1-4. Suimary of FGD Control Costs for tha Somerset Plant Uitm 1988 Dollars)
asaa3aasssssoss33SESsas3a9ss«8S33»ns3as238888as3S3Ssavasasss3£ssssa:ssss3$s9a9$83i33S3;»3$3ssss3asss38;si898S8
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 S02 Cost
N tuber Retrofit Size Factor Sulfur Cost Cost Cost Cost Ramoved Removed Effect.
Difficulty (HW) (X) Content (SMH) (S/kU) (IMN) (ml Ila/kwh) (X) (tons/yr) (S/ton)
Factor <%>
L/S FGD
7
1.41
71
21
1.2
35.6
501.0
13.5
103.1
90.0
1011
13321.2
L/S FGD
8
1.34
117
21
1.2
41.3
352.7
15.7
72.7
90.0
1667
9391.4
L/S FGD-C
7
1.41
71
21
1.2
35.6
501.0
7.9
60.3
90.0
1011
7789.8
L/S FGD-C
B
1.34
117
21
1.2
41.3
352.7
9.2
42.5
90.0
1667
5491.6
LC FGD
r-s
1.37
188
21
1.2
38.0
202.3
15.2
44.0
90.0
UTS
5679.5
LC FGD-C
7-8
1.37
188
21
1.2
38.0
202.3
8.9
25.7
90.0
2678
3317.6
lsc+esp
7
1.47
71
21
1.2
14.1
198.8
6.6
50.5
76.0
857
7697.4
LSO+ESP
8
1.36
117
21
1.2
17.6
150.1
7.7
36.0
76.0
1413
5479.5
LSO+ESP-C
7
1.47
71
21
1.2
14.1
198.8
3.8
29.4
76.0
857
4484.0
LSO+ESP-C
8
1.36
117
21
1.2
17.6
150.1
4.5
21.0
76.0
1413
3195.1
xBssszsaaaBsufltsasssssssssssssssassssxsssassssisssiwvsaMsaaBBSSsassassisissstsassaasssssasaasassssassBMsssssa
10-4
-------
Table 10.1.1-5. Sunary of Coal Switching/Cleaning Costs for the Somerset Plant <$/ton)
CS/B**15
C5/B+S1S
CS/B+S15-C
CS/B+t15-C
CS/B«*5
CS/B+S5
CS/B+S5-C
CS/B*#5-C
00
00
00
00
00
00
00
00
71
117
71
117
71
117
71
117
21
21
21
21
21
21
21
21
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
47.9
41.9
47.9
41.9
37.4
31.5
37.6
31.5
2.7
4.1
1.5
2.4
1.4
2.1
0.8
1.2
20.3
19.0
11.8
11.0
11.1
9.7
6.4
5.7
16.0
16.0
t6.0
16.0
16.0
16.0
16.0
16.0
181
298
181
298
181
298
181
298
14705.7
13730.4
8510.2
mo. 7
8017.4
7042.1
4659.4
4090.3
10-5
-------
TABLE 10,1,1-6, SUMMARY OF NOx RETROFIT RESULTS FOR SOMERSET
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
7
8
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION OATE
1951
1959
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
21
30
New Duct Length (Feet)
600
500
New Duct Costs (1000$)
2433
2717
New Heat Exchanger (1000$)
1518
2048
TOTAL SCOPE ADDER COSTS (1000$)
3972
4795
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
38
38
* Cold side SCR reactors for units 7 and 8 would be located
north of unit 8.
10-6
-------
Table 10.1.1-?. HOx Control Cost Resutts for M» Somerset Plant <4une 1988 Dollars)
3SS53S8SS=aa
saBssaDSSSsasssssBSsssassBsessssaassssassvsassassassasssaasssiaaaassa
Technology Boiler Main Boiler Capacity Coal Capitat Capital Annual
Nuitoer Retrofit Site Factor Sulfur Cost Cost Cost
Difficulty (HU) (X) Content (»«) (S/kU)
Factor (X)
Amual NOx HOx NOx Cost
Cost Removed Removed Effect,
(mills/kwft) (X) (tons/yr) (S/ton)
1.00
1.00
1.00
1.00
1.16
1.16
1.16
1.16
1.16
1.16
1.16
1.16
71
117
71
117
71
117
71
117
71
117
71
117
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
0.5
0.7
0.5
0.7
17.8
23.5
7.6
5.6
7.6
5.6
251.3
200.8
17.8
23.5
251,
200.
0.1
0.1
0.1
0.1
5.3
7.2
17.8 251.3 3.1
23.5 200.8 4.2
4.7
6.3
17.8 251.3 2.8
23.5 200.8 3.7
0.9
0.7
0.5
0.4
40.4
33.6
23.8
19.7
36.0
29.2
21.2
17.2
25.0
25.0
25.0
25.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
90
148
90
148
288
475
288
475
288
475
288
475
1293.9
959.1
768.6
569.5
18315.5
15213.1
10771.1
8938.0
16321.5
13218.6
9628.5
7795.2
sssassstsaaaasBaEasssasaasas
10-7
-------
TABLE 10.1.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SOMERSET UNIT 7
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 23
TOTAL COST (1000$)
ESP UPGRADE CASE
A NEW BAGHOUSE CASE
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
A short duct residence time exists between unit 7 and the unit 7
ESPs. The ESPs are adquate in size for FSI and DSD; however, due
to the congestion around the ESPs a high factor was assigned to
ESP upgrade.
10-8
-------
TABLE 10.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SOMERSET UNIT 8
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 34
TOTAL COST (1000$)
ESP UPGRADE CASE 34
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
Sufficient duct residence time exists between unit 8 and the unit
. 8 ESPs. The ESPs are somewhat congested, hence a medium factor
was assigned to ESP upgrade.
10-9
-------
Table 10.1.1*10. Surmar-y of DSO/FSI Control Costs for the Somerset Plant (June 1988 Dollars}
Technology
Boiler Main Boiler Capacity Coal
timber Retrofit Size Factor Sulfur
Difficulty (NW) (X) Content
Factor (X)
Capital Capital Annual Annual $02 S02 S02 Cost
Cost Cost Cost Cost Removed Removed Effect.
(S/lcU) (SMN) (ni I Is/kwh) (X} (tons/yr) (t/ton)
QS0+ESP
DSO+ESP
OSO+ESP-C
DSO+ESP-C
FSI+ESP-50
FSI*ESP-50
f$i*esp-50-c
FSI*£SP-50-C
FSI+ESP-70
FSI+ESP-70
7
a
7
8
7
a
7
8
7
8
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
71
117
71
117
71
117
71
117
71
117
21
21
21
21
21
21.
21
21
21
21
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
4.6
5.5
4.6
5.5
5.3
6.4
5.3
6.4
5.4
6.5
64.9
47.3
64.9
47.3
75.1
54.4
75.1
54.4
76.3
55.2
3.8
4.2
2.2
2.5
2.9
3.4
1.7
2.0
2.9
3.4
29.4
19.7
17.0
11.4
22.2
15.7
12.9
9-1
22.4
15.9
49.0
49.0
49.0
49.0
50.0
50.0
50,
50.
70.0
70.0
547
901
547
901
562
926
562
926
787
1296
7025.1
4716.0
4062.8
2729.5
5157.4
3657.1
2997.3
2126.1
3722.0
2640.7
FSJ+ESP-70-C
FSI+ESP-70-C
7
8
1.00
1.00
71
117
21
21
1.2
1.2
5.4
6.5
76.3
55.2
1.7
2.0
13.0
9.2
70.0
70.0
787
1296
2163.
1535.
saas|Basjsass
=B=333S98S;33Sa=
10-10
-------
10.2 NEW ENGLAND POWER COMPANY
10.2,1 Bravton Point Steam Plant
The Brayton Point steam plant is located on the Assonet Bay in Bristol
County, Massachusetts, and is operated by the New England Power Company,
The Brayton Point plant contains three coal-fired boilers and one oil-
burning boiler (unit 4) with a gross generating capacity of 1,510 MW.
Table 10.2.1-1 presents operational data for the existing equipment at
the Brayton Point plant. Coal shipments are received by barge and
transferred to a coal storage and handling area southeast of the plant. PM
emissions are controlled by retrofit ESPs which were added to the original
ESPs behind the chimneys. The flue gases from units 1-3 are directed from
the retrofit ESPs to their respective chimneys. Dry fly ash from the units
is stored on-site or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located southeast of
unit 1, close to the coal pile and oil tanks, and the absorbers for unit 3
would be adjacent to the unit 3 retrofit ESPs. The general facilities
factor for the absorber location for units 1 and 2 is medium (10 percent)
because several storage buildings and a plant road would have to be
relocated. No major demolition or relocation would be required for the
unit 3 absorber; therefore, a low general facilities factor (5 percent) was
assigned to unit 3. The site access/congestion factor is low for both
absorber locations. Over 300 feet of ductwork would be required for
installation at the unit 1 absorbers, over 400 feet would be required for
unit 2, and over 600 feet would be required to install the unit 3 absorbers.
A low site access/congestion factor was assigned to unit 1 flue gas handling.
However, a high factor was assigned to unit 2 since the unit 2 chimney is
difficult to access because it is bounded by ESPs and the unit 1 chimney. A
medium site access/congestion factor was assigned to flue gas handling for
unit 3 because of the congestion around the unit 3 chimney.
LSD-FGD with reuse of the existing ESPs was considered for the Brayton
Point plant. The LSD absorbers would be located similarly to the wet FGD
10-11
-------
TABLE 10.2.1-1. BRAYTON POINT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
12 3 4
238 238 597 437
76 88 43 59
19S3 1964 1969 1974
TANGENTIAL OPPOSED OIL
WALL BURNING
131.8 131.8 352
NO NO NO
1.1
13300
6.9
DRY DISPOSAL
STORED ON-SITE/SOLD
1 2 3
BARGE
ESP
1981
0.015 0.017 0.007
99.3 99.7 ,99.9
1.0 ¦
478 478 1150
856 856 2210
558 558 520
350 350 350
10-12
-------
absorbers with similar general facilities, site access/congestion factors,
and ductwork requirements, A low site access/congestion factor was assigned
to the ESP upgrade difficulty for all three units.
Tables 10.2.1-2 through 10.2.1-5 present the retrofit data and estimated
costs for installation of conventional FGD technologies at the Brayton Point
plant.
Coal Switching and Physical Coal Cleaning Costs--
Table 10.2.1-6 presents the estimated costs for CS at the Brayton Point
plant. These costs do not include pulverizer and boiler operating cost
impacts or any coal handling system modifications that may be necessary for
coal blending. PCC was not evaluated because the Brayton Point plant is not
a mine mouth plant.
N0X Control Technologies-
Units 1 and 2 are tangential-fired boilers rated at 238 MW each and
unit 3 is an opposed wall-fired boiler rated at 597 MW. All three boilers
are dry bottom; therefore, the N0X control technologies considered for
units 1-2 and 3 were OFA and LNB, respectively. Tables 10.2.1-7 and 10.2.1-8
present the performance and cost results for the NO control technologies at
A
the Brayton Point plant.
Selective Catalytic Reduction--
Cold side SCR reactors for units 1, 2, and 3 would be located similarly
to the wet FGD absorbers with similar duct length requirements. As in the
FGD case, a medium general facilities value (20 percent) was assigned to
units 1 and 2 and a low general facilities factor (13 percent) to unit 3.
Tables 10.2.1-7 and 10.2.1-8 present the retrofit factors and costs for the
installation of SCR at the Brayton Point plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FS1 and DSD) were considered for
boilers 1, 2, and 3 because there is sufficient duct residence time between
the original and retrofit ESPs and the ESPs are large enough to handle the
additional particulate load. Tables 10.2.1-9 through 10.2.1-11 present the
10-13
-------
TABLE 10.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BRAYTON POINT
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.31
NA
ESP REUSE CASE
1.27
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
10
10-14
-------
TABLE 10.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR BRAYTON POINT
UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.39 NA
ESP REUSE CASE 1.36
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 Q 10
10-15
-------
TABLE 10.2.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR BRAYTON POINT
UNIT 3
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
600-1000
NA
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.42
NA
ESP REUSE CASE
1.38
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
5
10-16
-------
Table 10,2.1-5. sumary of FGD Control Costs for the Brayton Point Plant (June 1988 Dollars)
ssssssasssss
sssassas
assassssas:
asssass
a»sssssaassssssa:
II
II
II
II
II
tt
II
IS3SS83SSSSS3SS:
iaS53S38SSSS
SSS3SS
:*====3=5S3i
:s:3«=333
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
SQ2
$02
S02 Cost
Nurber Retrofit
Sue
factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty CNU)
m
Content
($MH>
(S/ton)
.........
Factor
(%5
........
......
L/S FGO
1
1.31
238
76
1.1
59.5
249.9
28.2
17.8
90.0
11246
2503.2
L/S FGD
2
1.39
238
88
1.1
62.7
263.4
30.4
16.6
90.0
13022
2337.7
L/5 FGD
3-
1.42
597
43
1.1
110.8
185.6
46.5
20.7
90.0
15961
2916.1
L/S FGD-C
1
1.31
238
76
1.1
59.5
249.9
16.4
10.3
90.0
11246
1457.9
L/S FGD-C
2
1.39
238
88
1.1
62.7
263.4
17.7
9.7
90.0
13022
1360.9
L/S FGD-C
3
1.42
597
43
1.1
110.8
185.6
27.2
12.1
90.0
15961
1701.9
LC FGD
1-2
1.35
476
82
1.1
70.2
147.4
39.2
11.5
90.0
24268
1616.6
LC FGD
3
1.42
597
43
1.1
88.5
148.2
39.4
17.5
90.0
15961
2470.1
LC FGD-C
1-2
1.35
476
82
1.1
70.2
147.4
22.8
6.7
90.0
24268
939.2
LC FGD-C
3
1.42
597
43
1.1
88.5
148.2
23.0
10.2
90.0
15961
1440.0
ISD+ESP
1
1.27
238
76
1.1
28.8
120.9
13.4
8.5
76.0
9534
1407.5
LSD+ESP
2
1.36
238
88
1.1
30.5
128.3
14.4
7.8
76.0
11040
1303.7
LSD+ESP
3
1.38
597
43
1.1
63.6
106.6
24.6
10.9
76.0
13531
1817.0
LSD+fSP-C
1
1.27
238
76
1.1
28.8
120.9
7.8
4.9
76.0
9534
819.9
LSD+ESP-C
2
1.36
238
88
1.1
30,5
128.3
8.4
4.6
76.0
11040
759.4
tSD+ESP-C
3
1.38
597
43
1.1
63.6
106.6
14.4
6.4
76.0
13531
1062.1
aaiaaa::
saMstaasvma assjsaa aisassaass.
ssaaeatv
ssaaaiisssa
sssxxssrausa
10-17
-------
Table 10.2.1-6. Simnery of Coal Switching/Cleaning Costs for the Brayton Point Plant (June 1988 Dollars)
ssasuaaiisss
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II
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!SS!S!S=
=========
KssaassssBssasa:
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II
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li
II
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II
II
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II
II
II
II
s==s====
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
SQ2
S02 Cost
Umber Retrofit
Site
factor
Sulfur
Cost
Cost
¦ Cost
Cost
Removed Removed
Effect.
Difficulty (MW>
(X)
Content
(ttW)
(S/kUJ
(MM)
(mills/kwh)
(X)
(tons/yr)
(S/ton>
Factor
(X)
CS/8+S15
1
1.00
238
76
1.1
8.6
36.3
23.1
14.6
8.0
1055
21945.3
CS/8*$15
2
1.00
238
88
1.1
8.6
36.3
26.5
14.4
8.0
1221
21695.1
CS/B*S15
3
1.00
597
43
1.1
19.2
32.2
33;9
15.1
8.0
1497
22649.3
CS/B*S15-C
1
I'.OO
238
76
1.1
8.6
36.3
13.3
8.4
8.0
1055
12610.0
CS/B*S15-C
2
1.00
238
88
1.1
8.6
36.3
15.2
8.3
8.0
1221
12461,7
CS/B*$15-C
3
1.00
597
43
1.1
19.2
32.2
19.5
8.7
8.0
1497
13034.5
CS/B*$5
1
1.00
238
76
1.1
6.2
25.9
9.6
6.1
8.0
'1055
9127.7
cs/a*$5
2
1.00
238
83
1.1
6.2
25.9
10.9
5.9
8.0
1221
8933.4
CS/B*S5
3
1.00
597
43
1.1
13.1
21.9
14.2
6.3
8.0
1497
9517.3
CS/B+S5-C
1
1.00
233
76
1.1
6.2
25.9
5.5
3.5
8.0
1055
5255.8
CS/B+S5-C
2
1.00
238
88
1.1
6.2
25.9
6.3
3.4
8.0
1221
5140.9
CS/8«*5-C
3
1.00
597
43
1.1
13.1
21.9
8.2
3.7
8.0
1497
5492.0
ESS353533!SSS
N
II
II
It
II
iSSSSBSSS
=====¦¦„
S333B83S
========
II
u
It
II
II
II
II
II
It
li
It
II
II
II
II
II
II
It
11
11
It
II
II
11
II
It
It
It
II
It
It
II
10-18
-------
TABLE 10.2.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR BRAYTON POINT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
TANG
TANG
OWF
TYPE OF NOx CONTROL
OFA
OFA
LNB
FURNACE VOLUME (1000 CU FT)
131.8
131.8
352
BOILER INSTALLATION DATE
1963
1964
1969
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
41
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
52
52
103
New Duct Length (Feet)
300
400
600
New Duct Costs (1000$)
2469
3292
8456
New Heat Exchanger (1000$)
3136
3136
5445
TOTAL SCOPE ADDER COSTS (1000$)
5656
6479
14004
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
13
10-19
-------
Table 10.2.1-8. NOx Control Cost Results for the Brayton Point Plant (June 1988 Dollars)
SSSF3BBBSSSSSS
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;s«as3ssi
sssmszsi
ammmssmwt
33=3ias=;
tnssxsn:
aa»*ssSK3=BK:
¦ssssa
sssassssa#;
iSSSSSSBfl
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NOX
NOX Cost
Nuitser Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty
-------
TABLE 10.2.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRAYTON POINT UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 57
TOTAL COST (1000$)
ESP UPGRADE CASE 57
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
10-21
-------
TABLE 30.2.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRAYTON POINT UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT}
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH {FT) 50
DEMOLITION COST (1000$) 114
TOTAL COST (1000$)
ESP UPGRADE CASE 114
A NEW BAGHOUSE CASE - NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE ¦ NA
10-22
-------
Table
10.2.1-11
Suatiary of DSD/FSI Control Costs for the Brayton Point Plant
(June 1988 Dollars)
II
II
II
i!
II
II
II
1!
II
II
II
II
11
11
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
ssssaass
II
II
II
II
II
II
II
N
H
II
II
II
II
II
¦
n
II
II
II
II
II
II
II
II
II
II
n
N
N
N
N
II
II
II
II
II
II
II
II
II
II
11
II
II
II
II
II
li
II
it
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
SQ2
S02
S02 Cost
Nimtoer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
cx>
Content
(SHH)
(S/kW>
(WW)
(mi IIs/kwh) <55}
(tons/yr)
CI/ton>
Factor
(X)
DSO+ESP
1
1.00
238
76
1.1
7.9
33.0
7.2
4.5
49.0
6079
1176.8
DSD+ESP
2
1.00
238
88
1.1
7.9
33.0
7.6
4.1
49.0
7039
1075.7
BSD+ESP
3
1.00
597
43
1.1
14.8
24.9
10.2
4.5
49.0
8628
1183.3
DSD+ESP-C
1
1.00
238
76
1.1
7.9
33.0
4.1
2.6
49.0
6079
680.0
DSD+ESP-C
2
1.00
238
88
1.1
7.9
33.0
4.4
2.4
49.0
7039
621.3
DSD+ESP-C
3
1.00
597
43
1.1
14.8
24.9
5.9
2.6
49.0
8628
685.7
FSI+ESP-50
1
1.00
238
76
1.1
9.2
38.8
7.5
4.8
50.0
6248
1205.3
FSI+ESP-50
2
1.00
238
88
1.1
9.2
38.8
8.2
4.5
50.0
72S4
1129.6
FSI+ESP-50
3
1.00
597
43
1.1
16.S
28.1
11.1
4,9
50.0
8867
1250.9
FSI+ESP-50-C
1
1.00
238
76
1.1
9.2
33.8
4.4
2.7
50.0
6248
697.2
FSI+ESP-50-C
2
1.00
238
88
1.1
9.2
38.8
4.7
2.6
50.0
7234
652.9
FSI+ESP-50-C
3
1.00
597
43
1.1
16.8
28.1
6.4
2.9
50.0
8867
725.2
FSt+ESP-70
1
1.00
238
76
1.1
9.3
39.3
7.6
4.8
70.0
8747
874.5
FSt*ESP*70 '
2
1.00
238
88
1.1
9.3
39.3
8.3
4.5
70,0
10128
820.0
FSI~ESP-70
3
1.00
597
43
1.1
16,9
28.4
11.3
5.0
70.0
12414
907.5
FS1+ESP-70-C
1
1.00
238
76
1.1
9.3
39.3
4.4
2.8
70.0
8747
505.8
FSI+ESP-70-C
2
1.00
238
as
1.1
9.3
39.3
4.8
2.6
70.0
10128
474.0
FS1*ESP*70*C
3
1.00
597
43
1.1
16.9
28.4
6.5
2.9
70.0
12414
526.0
M
11
II
II
H
II
II
II
II
wn&Mstsass
ssxsas
S3X B8333!
isaasaiM
33333333
S9SS&S3SS
SSS3SIII
•333 3 X 3S383E3S!
iSSKSlSI
10-23
-------
retrofit factors and costs for installation of FSI and DSD at the Brayton
Point plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 1 and 2 are small enough to be considered for repowering using
advanced technologies; however, their long remaining, life and high capacity
factors make them unlikely near term candidates. Unit 3, which is a larger
boiler, would be a less likely candidate than units 1 and 2 for the same
reasons.
10-24
-------
10-2-2 Salem Harbor Steam Plant.
The Salem Harbor Steam Plant is located in Essex County, Massachusetts,
as part of the New England Power Company system. The plant contains three
coal-fired boilers with a total gross generating capacity of 330 MW.
Tables 10.2.2-1 through 10.2.2-8 summarize the plant operational data and
present the SO,, and N0X control cost and performance estimates.
TABLE 10.2.2-1. SALEM HARBOR STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON
COAL HEATING VA
COAL ASH CONTEN
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1000 CU FT)
ON
ENT (PERCENT)
UE (BTU/LB)
(PERCENT)
1,2 3 4
82 166 476
80,74 77 58
1951,52 1958 1972
FRONT WALL PETRO.
NA 61.8 BURNING
NO NO
1.2
13000
7.1
DRY DISPOSAL
LANDFILL/OFF-SITE
1
BARGE
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE ('F)
ESP *
NA
NA
NA
NA
NA
NA
NA
NA
* SCA size assumed to be larger than 300 since the ESPs are
1985 retrofit ESPs.
10-25
-------
TABLE 10.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR SALEM HARBOR
UNIT 1, 2, OR 3 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.31
NA
ESP REUSE CASE
1.27
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
* Absorbers for units 1-3 would be located adjacent to the
retrofit ESPs for units 1-3.
10-26
-------
Table 10.2.2*3. Sumary of FGB Control costs for the Sate* Harbor Plant (Jtre 1988 Dollars)
Technology Boiler Main Bailer Capacity Coal Capital Capital Annual Annual SOZ $02 S02 Cost
Nuifcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content
-------
Table 10.2.2*4, Surnmry of Coal Suftching/cieanina Costs for the Salem Harbor Plant (June 1988 Dollars)
aBB8aa33ass333a8Ssaa3B8BB33ass38*s383SB8B3asaa3sa383sa>33a8B8aataa3S33saea3Bsp938SBS3SB383ssasa3S333333333s;5=3s::2S2B
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 S02 Cost
Nintoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (M» (X) Content C«•») C«/MO (tons/yr) (S/con)
Factor (X)
CS\B*#15
1
1.00
62
80
1.2.
3.6
44.2
8.8
15.2
18.0
926
9453.0
CS\B+S15
2
1.08
82
74
1.2
3.6
44.2
8.2
15.3
18.0
856
9528.6
CS\B+»15
3
1.00
166
77
1.2
6.2
37.6
16.3
14.6
18.0
1804
9057.7
CS\8»*15-C
1
1.00
82
80
1.2
3.6
44.2
5.0
8.8
18.0
926
5433.6
CS\B*S15-C
2
1.00
82
74
1.2
3.6
44.2
4.7
8.8
18.0
856
5478.3
CS\8+S15-C
3
1.00
166
77
1.2
6.2
37.6
9.4
8.4
18.0
1804
5205.0
CS\B+t5
1
1.00
82
10
1.2
2,8
33.8
3.9
6.7
18.D
926
4164.5
CS\8*»
2
1.00
82
74
1.2
2.8
33.8
3.6
6.8
18.0
856
4227.1
CS\B+S5
3
1.00
166
77
1.2
4.5
27.2
6.8
6.1
18.0
1804
3762.9
CS\B*S5-C
1
1.00
82
80
1.2
2.8
33.8
2.2
3.9
18.0
926
2399.4
CS\8*f5-C
2
1.00
82
74
1.2
2.8
33.8
2.1
3.9
18.0
856
2436.4
C$\B*t5-C
3
1.00
166
77
1.2 .
4.5
27.2
3.9
3.5
18.0
1804
2167.1
SIBUSIIIBt
IIH*I«13IR
lasBsiiffsa
3838Z
¦asaasaaasaassaa
n
N
H
V
¦
II
II
U
II
nsaaaaiB
Ritiaas
ISNIBaa
aasaaaaasai
Bsaaasass
10-28
-------
TABLE 10.2.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR SALEM HARBOR
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
1-3
FIRING TYPE
FWF
FWF
NA
TYPE OF NOx CONTROL
NGR
NGR
NA
FURNACE VOLUME (1000 CU FT)
NA
61.8
NA
BOILER INSTALLATION DATE
1951,52
1958
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
NA
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
23
40
66
New Duct Length (Feet)
400
400
400
New Duct Costs (1000$)
1765
2666
3985
New Heat Exchanger (1000$)
1655
2526
3815
TOTAL SCOPE ADDER COSTS (1000$)
3443
5232
7866
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for units 1-3 would be located adjacent to
the retrofit ESPs for units 1-3.
10-29
-------
Table to.2.2-6. NOx Control Cost Results for the Salem Harbor Plant (June 1988 Dollars)
nsimHiaaaBauiiiiiissasiaaiissBiiiiiiBassssBKEBssisasaiiasaiiiimHasassiiiiassssssasBsssssssssssssssssss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nunber Retrofit Size
Difficulty CHWJ
Factor
Feetor Sulfur
(X) Content
(X)
Cast
(**<)
Cost
a/m
Cost
(SUM)
Cost
Cmills/kuh)
Removed Removed
(X) (tons/yr)
Effect.
Ci/tonJ
NGR
1
1.00
82
80
1.2
1.9
23.6
3.2
5.6
60.0
2212
1458.5
NCR
2
1 .DO
B2
7*
1.2
1.9
23.6
3.0
5.7
60.0
2046
1470.2
NGR
3
1.00
166
77
1.2
3.2
19.3
6.2
5.5
60.0
4310
1428.6
NSR-C
1
1.00
a2
80
1.2
1.9
23.6
t ,9
3.2
60.0
2212
839.6
NQR-C
2
1.00
82
74
1.2
1.9
23.6
1.7
3.3
60.0
2046
846.6
MGR-C
3
1.00
166
77
1.2
3.2
19.3
3.5
3.2
60.0
4310
821.9
SCR-3
1-3
1.16
330
77
1.2
47.7
144.5
17.4
7.8
80.0
11425
1523.1
SCR-3-C
1-3
1.16
330
77
1.2
47.7
144.5
10.2
4.6
B0.Q
11425
891.3
SCR-7
1-3
1.16
330
77
1.2
47.7
144,5
14.7
6.6
80.0
11425
1288.5
SCR-7-C
1-3
1.16
330
77
1.2
47.7
144.5
S.6
3.9
80.0
. 11425
757.0
:CTsaa«*a«8aaaBBBa:aaaas*aaaaBBSB8B8:ss8aaaaaBBBa8«*Baaa8B*ttSSBaBBs«;»B*aaaa«8aaBB*aBa;B«9aBaasar«BBBaasBsassBsa388ais
10-30
-------
TABLE 10.2.2-7.
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SALEM HARBOR UNIT 1, 2, OR 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 26,26,44
TOTAL COST (1000$)
ESP UPGRADE CASE 26,26,44
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
Units 1, 2, and 3 are good candiates for FSI and DSD due to
the long duct residence time between the boilers and ESPs.
10-31
-------
Table 10.2.2-8. Sunmry of BSO/FSI Control Costs for the Salem Harbor Plant (June 1988 Dollars]
sszissisBiiiiaiiaBBaaBfaiiBisiesaaBaasfssassniaBiiiBsaiiBBSiaiaiiHuaiaiBamHBmaiaBaBaBsiisascsassssssssisss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 SQ2 $02 Cost
Nunber
Retrofit Size
Difficulty (MW>
Factor
Factor Sulfur
(%> Content
IX)
Cost
(SMI)
Cost
(S/kU)
Cost
C«N>
Cost
(mills/kuh)
Removed Removed
(X)
-------
SECTION 11.0 MARYLAND
11.1 BALTIMORE GAS & ELECTRIC
11.1.1 C.P. Crane
CS was not considered for the Crane plant because the boilers are
cyclone, and low ash fusion temperature, low sulfur coals required for
cyclone boilers are not readily available in the eastern United States.
However, plant personnel indicated that burning of low sulfur coal will be
tested on this plant.
TABLE 11.1.1-1. CHARLES P. CRANE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1
200
54
1961
CYCLONE
2
200
48
1963
63.9 60.6
NO NO
2.5 (2.2-2.7)
13400 (12300-14500)
8.2
DRY DISPOSAL
OFF-SITE/STRUCTURAL FIELD USE
1 2
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
AIR TO FABRIC RATIO (CU FT/MIN/SQ FT)
OUTLET TEMPERATURE ('F)
REVERSE GAS BAGHOUSE
1983
0.06
99
3.0
421
835
1.59
300
11-1
-------
TABLE 11.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CRANE
UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE REUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE REUSE
300-600
ESP REUSE
NA
NA
NA
BAGHOUSE REUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.61
NA
ESP REUSE CASE
NA
BAGHOUSE REUSE CASE
1.62
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
* L/LS-FGD and LSD-FGD absorbers for unit 1 would be located
west of the unit 1 baghouse and for unit 2 the absorbers would
be located north of the unit 2 baghouse.
11-2
-------
Table 11.1.1-3, Smmary of FGB Control Costs for the Crane Plant (Jura 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 SQ2 $02 Cost
Nuifcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CHU) Content (SUM) (S/kU) (»*! (tons/yr) <$/ten>
Factor (%)
US FED
L/S FSD
L/S FGO-C
L/S FGD*C
IC FGO
LC FQD-C
LSD*PFF
LSD+PFF
LSOt-PFf-C
LSD+PFF-C
1
2
1
2
1-2
1-2
1
2
1
2
.61
.61
.61
.61
.62
.62
200
200
200
200
.61 400
.61 400
200
200
.62 200
,62 200
54
48
54
48
51
5!
54
48
54
48
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
69.4 347.0 30.0
69.4 346.9 29.3
69.4 147.0 17.5
69.4 346.9 17.1
79.1 197.9 37.5
79.1 197.9 21.8
31.7 158.6 14.2
31.7 158.6 13.9
31.7 158.6
31.7 158.6
8.3
8.1
31.7
34.9
18.5
20.3
21.0
12.2
15.0
16.6
8.8
9.7
90.0
90.0
90.0
90.0
90.0
90.0
87.0
87.0
87.0
87.0
15131
13450
15131
13450
28580
28580
14542
12926
14542.
12926
1982.2
2179.6
1156.2
1271.9
1312.4
764.3
978.7
1077.7
570.5
628.5
ssissraassisssssssasssssssassssaassGSsaxsiisssss
11-3
-------
TABLE 11.1.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR CRANE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
CYCLONE
CYCLONE
TYPE OF NOx CONTROL
NGR
NGR
FURNACE VOLUME (1000 CU FT)
63.9
60.6
BOILER INSTALLATION DATE
1961
1963
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
60
60
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
45
45
New Duct Length (Feet)
300
300
New Duct Costs (1000$)
2230
2230
New Heat Exchanger (1000$)
2825
2825
TOTAL SCOPE ADDER COSTS (1000$)
5100
5100
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
37
37 •
* Cold side SCR reactors for unit 1 would be located west of the
unit 1 baghouse, and cold side SCR reactors for unit 2 would be
located north of the unit 2 baghouse.
11-4
-------
Table 11,1,1-5. KOx Control Cost Results for the Crane Plant (June 1988 Dollars)
Technology Boiler Hain Boiler Capacity Coal Capital Capital Annual Annual nox NOx NO* Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
TABLE 11.1.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CRANE UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE NA
BAGHOUSE UPGRADE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 50
TOTAL COST (1000$)
ESP UPGRADE CASE NA
BAGHOUSE UPGRADE CASE 50
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE NA
BAGHOUSE UPGRADE NA
Long duct residence time exists between units 1 and 2 and their
respective baghouses.
11-6
-------
table 11.1.1-7. Sunmary'of BSD/FS1 Control Costs for the Crarw Plant (Ji*ie 1988 Dollars)
:==::=::s2=:s±ss:ss:=s£:sss=2s:sss3:=ssss:::3ssssss«ss:ss:ss$s:ss=s:ssss==sas=s3;=ss:s£==sss=====sssss=s3;33»ss
Technology Soiler Main • Boiler Capacity Coal Capital Capital Annual Annual S02 S02 $02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (%> Content (SMM) (S/kW) (SUM) (mills/kuh) (55) (tons/yr) (S/ton)
Factor (X)
DSD+PFF
DSD+PFF
OSO+PFF-C
DSD+PFF-C
FSI*PFF-50
FSI+PFF-5Q
FSI+PFF-70
FSI+PFF-70
FSi+PFF-70-C
FSI+PFF-70-C
FS1+PFF-50-C 1
' FS1*PFF-50-C 2
.00
.00
.00
.00
.00
.00
,00
,00
,00
,00
,00
.00
200
200
200
200
200
200
200
200
200
200
200
200
54
48
54
48
54
48
54
48
54
48
54
48
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
7-.1
7.1
7.1
7.1
7.6
7.6
7.6
7.6
7.6
7.6
7.6
7.6
35,6
35.6
35.6
35.6
38.1
38.!
38.1
38.1
38.2
38.2
38.2
38.2
6.9
6.6
4.0
3.8
7.7
7.2
4.4
4.2
7.7
7.2
4.5
4.2
7.3
7.9
4.2
4.6
8.1
8.5
4.7
4.9
71.0
71.0
71.0
71.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
11894
10573
11894
10573
S406
7472
8406
7472
11768
10461
11768
10461
581.5
627.5
335.8
362.6
916.4
961.7
529.1
555.5
656.5
688.8
379.0
397.9
11-7
-------
11.2 POTOMAC ELECTRIC POWER COMPANY
11.2.1 Chalk Point Steam Plant
The Chalk Point steam plant is located on Eagle Harbor in Prince
George's County, Maryland, and is operated by the Potomac Electric Power
Company. The Chalk Point plant contains two coal-fired and two petroleum-
fired boilers. The total gross generating capacity for the two coal-fired
boilers is 728 MW.
Table 11.2.1-1 presents operational data for the existing equipment at
the Chalk Point plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area north of the plant. PM
emissions from the coal-fired boilers are controlled by retrofit ESPs
located behind the old chimneys. Flue gases from the coal-fired boilers are
directed to a common chimney behind the retrofit ESPs. Dry fly ash from the
two units is stored on-site.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located behind the chimney. The general
facilities factor is medium (8 percent) for this location because a plant
road and part of the petroleum pipeline would have to be relocated. The
site access/congestion factor for the site is low. Approximately 100 to
300 feet of ductwork would be required to span the distance from the chimney
to the absorber and back to the chimney. A low site access/congestion
factor was assigned to flue gas handling.
LSD-FGD with reuse of the existing ESPs was considered for the Chalk
Point plant because of the large sizes of the ESPs and the length of the
ductwork between the boilers and the ESPs. The LSD absorbers would be
located similarly to the wet FGD absorbers and would have similar site
access/congestion and general facilities factors. Over 600 feet of ductwork
would be required for installation of the LSD system. The site access/
congestion factor for flue gas handling is medium because of the obstruction
caused by the old chimneys and ash silos.
11-8
-------
TABLE 11,2.1-1. CHALK POINT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3,4
364 659
62,49 16,6
1964,65 1975,81
OPPOSED WALL OIL
187 FIRED
NO
1.6
12500
12.0
DRY DISPOSAL
STORAGE/ON-SITE
1,2;1,2
RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1982
EMISSION (LB/MM BTU) 0.06
REMOVAL EFFICIENCY 99.7,99.3
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.5
SURFACE AREA (1000 SQ FT) 788,988
GAS EXIT RATE (1000 ACFM) 1400
SCA (SQ FT/1000 ACFM) 563,706
OUTLET TEMPERATURE (4F) 244
11-9
-------
Tables 11.2.1-2 and 11.2.1-3 present estimated retrofit factors and costs
for installation of FGD technologies for boilers 1 and 2 at the Chalk Point
plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 11.2.1-4 presents the costs for CS at the Chalk Point plant.
These costs do not include boiler and pulverizer operating cost changes or
any system modifications that may be necessary for coal blending. PCC has
only been considered for mine mouth plants; therefore, it was not evaluated
for the Chalk Point plant.
N0X Control Technologies--
The two coal-fired boilers at the Chalk Point plant are opposed wall-
fired; therefore, LNBs were considered for N0X emission control.
Tables 11.2.1-5 and 11.2.1-6 present the performance and cost estimates for
installation of LNBs for units 1 and 2 at the Chalk Point plant.
Selective Catalytic Reduction--
Cold side SCR reactors for boilers 1 and 2 at the Chalk Point plant
would be located behind the common chimney. As in the FGD case, a medium
general facilities value (20 percent) and a low site access/congestion
factor were assigned to the location. About 200 feet of ductwork would be
required to span the distance between the SCR reactors and the chimney. A
low site access/congestion factor was assignee! to flue gas handling.
Tables 11.2.1-5 and 11.2.1-6 present the retrofit factors and costs for
installation of SCR for units 1 and 2 at the Chalk Point plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) would be particularly well
suited for the Chalk Point plant because of the long duct length between the
boilers and the retrofit ESPs and the large sizes of the ESPs.
Tables 11.2.1-7 and 11.2.1-8 present retrofit factors and cost estimates for
installation of sorbent injection technologies for boilers 1 and 2 at the
Chalk Point plant.
11-10
-------
TABLE 11.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CHALK POINT
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
100-300 NA
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA NA
NEW BAGHOUSE NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA
ESTIMATED COST (1000$) NA NA
NEW CHIMNEY NO NA
ESTIMATED COST (1000$) 0 0
OTHER NO
LOW
MEDIUM
NA
600-1000
NA
MEDIUM
NA
NO
NA
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.20
NA
NA
NA
NA
NA
1.38
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 8
11-11
-------
Table 11.2.1-3. Swmary of FGD Control Costs for the Chalk Point Plant (Jim 1988 Dollars)
¦i«iSBX»Bsassisssssssssis==ss==ssass=aB3sssassasssssi9ssaaBssaBHNaia9Biisflaiasaaaa=ssaas9sss=sssassasssaassss
Technology Boi ler Main Boiler Capacity Coal Capital Capital Annual Amual S02 S02 S02 Cost
Number
Retrofit
size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW>
<%>
Content
($MH)
(S/kV)
CMO
(mills/kuh)
(X)
(tons/yr)
CS/ton)
Factor
(X)
l/S FGD
1
1.20
364
62
1.6
71.9
197.6
35.3
17.9
90.0
21916
1612.9
1/5 FGO
2
1.20
364
49
1.6
71.9
197.5
33.1
21.2
90.0
17321
1908.3
L/S FGO
1-Z
1.20
728
56
1.6
113.2
155.6
56.1
15.7
90.0
39591
1417,4
l/S FGD-C
1
1.20
364
62
1.6
71.9
197.6
20.6
10.4
90.0
21916
938.8
l/S FGD-C
2
1.20
364
49
1.6
71.9
197.5
19.3
12,3
90.0
17321
1112.0
US FGO-C
1-2
1.20
728
56
1.6
113.2
155.6
32.7
9.1
90.0
39591
824.9
LC FGO
1-2
1.20
728
56
1.6
91.1
125.2
49.0
13.7
90.0
39591
1237.4
i.C FGD-C
1-2
1.20
728
56
1.6
91.1
125.2
28.5
8.0
90.0
39591
719.3
LSD+6SP
1
1.38
364
62
1.6
39.8
109.4
18.3
9.3
60.0
14503 '
1262.6
LSD^ESP
2
1.38
364
49
1.6
39.8
109.3
17.4
11.1
60.0
11462
1516.5
LSD+6SP-C
1
1.3B
364
62
1.6
39.8
109.4
10.7
5.4
60.0
14503
735.7
ISD+ESP-C
2
1.38
364
49
1.6
39.8
109.3
10.1
6.5
60.0
11462
884.4
========
II
11
11
11
fl
<1
11
II
II
11
S3ISSS3
BS,laa.
essaaasass
KSaasaas
„r
asssasaa
11-12
-------
Table 11.2,1-4. Summary of Coal Switching/Cleaning Costs for the Chalk Point Plant (June 1988 Dollars)
33SCS53S 3SSSSSSXS
SSSSSSSiSSSBtfS
SSSSSSSSSS
Technology Boiler Main Boiler Capacity. Coal Capital Capital Annual Annual S02 SG2 S02 Cost
Nuifcer Retrofit Sfxe Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (*HH) (S/kW) (SMM) (nUls/kwh) (X) itons/yr) (S/ton)
Factor <%>
CS/B+S1S
CS/B*$15
. 1.00
1.00
364
364
62
49
1.6
1.6
11.7
11.7
32.2
32.2
28.1
22. B
14.2
14.6
41.0
41.0
10Q76
7963
2791.9
2859,4
CS/3+S15-C
CS/S+S15-C
1.00
1.00
364
364
62
49
11.7
11.7
32.2
32.2
16.2
13.1
8,2
8.4
41.0
41.0
10076
7963
1604.B
1644.9
CS/B+15
CS/B+S5
1.00
1.00
364
364
62
49
1.6
1.6
7.9
7,9
21.8
21.8
11.1
9.Z
5.6
5.9
41.0
41.0
10076
7963
1105.6
1155.8
CS/B+15-C
CS/B+S5-C
1.00
1.00
364
364
62
49
1.6
1.6
7.9
7.9
21.8
21.8
6.4
5,3
3.2
3.4
41.0
41.0
10076
7963
637.0
666.7
11-13
-------
TABLE 11.2.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR CHALK POINT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) 187
BOILER INSTALLATION DATE 1964,1965
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT)
SCR RETROFIT RESULTS _
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
Ductwork Demolition (1000$)
New Duct Length (Feet)
New Duct Costs (1000$)
New Heat Exchanger (1000$)
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 622B
COMBINED CASE 9418
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20_
35
LOW
0
71
200
2110
4046
11-14
-------
Table 11.2.1-6. NQx Control Cost Results for the Chalk Point Plant (June 1988 Dollars)
Technology
Soilet
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NQx
NO*
NOx Cost
Nuitoer Retrofit
Size
Factor
Sulfur
Cost
Cost
Coat
Cost
Removed Removed
Effect.
Difficulty CKW)
(X)
Content
(SMM)
(S/kU)
(SUM)
(mills/kwh)
(XJ
(tons/yr)
<$/ton>
........ .
«.
Factor
(X)
.........
......
INC-LNB
1
1.00
364
62
1.6
4.3
11.8
0.9
0.5
35.0
2S6S
324.7
LNC-INB
2
1.00
364
49
1.6
4.3
11.8
0.9
0.6
35.0
2267
410.8
LHC-LH8-C
1
1.00
364
62
1.6
4.3
11.6
0.6
0.3
35.0
2868
192.7
UiC-LNB-C
2.
1.00
364
49
1.6
4.3
11.8
0.6
0.4
35.0
2267
243.8
SCR-3
1
1.16
364
62
1.6
49.0
134.6
17.7
9.0
80.0
6556
2705.7
SCR-3
2
1.16
364
49
1.6
49.0
134.5
17.4
11.2
80.0
5181
3366.6
SCR-3
1-2
1.16
728
56
1.6
85.2
117.0
32.2
9.0
80.0
11843
2720.8
SCR-3-C
1
1.16
364
62
1.6
49.0
134.6
10.4
5.3
80.0
6556
1583.7
SCR-3-C
2
1.16
364
49
1.6
49.0
134.5
10.2
6.5
ao.o
5181
1971.2
SCR-3-C
1-2
1.16
728
56
1.6
85.2
117.0
18.8
5.3
80.0
11843
1591.1
SCR* 7
1
1.16
364
62
1.6
49.0
134.6
14.8
7.5
80.0
6556
2252.2
SCR-7
2
1.16
364
49
1.6
49.0
134.5
14.5
9.3
80.0
" 5181
2792.8
SCR-7
1-2
1.16
728
56
1.6
85.2
117.0
26.3
7.4
80.0
11843
2218.7
SCR-7-C
1
1.16
364
62
1.6
49.0
134.6
8.?
4.4
80.0
6556
1323.9
sca-7-c
2
1.16
364
49
1.6
49.0
134.5
8.5
5.4
80.0
5181
1642.5
SCS-7-C
1-2
1.16
728
56
1.6
35.2
117.0
15.4
4.3
80.0
11843
1303.4
—
ISSSSSSS
M
<1
11
II
It
II
II
II
M
II
II
II
II
II
li
II
II
fl
II
II
II
II
________
:=sasa3s
_________
11-15
-------
TABLE 11.2.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CHALK POINT UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT), 50
DEMOLITION COST (1000$) 79
TOTAL COST (1000$)
ESP UPGRADE CASE 79
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
11-16
-------
Table 11.2.1-8, Swmery of DSO/FSl Control Costs for the Chalk Point Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
timber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU> (X) Content CJMM) (S/kU) (SMM> (mUH/kMh) (X) (tons/yr) (S/ton)
Factor (X)
DSD+ESP 1 1
DSO+ESP . 2 1
DSC+ESP-C 1 1
DSD+ESP-C 2 1
FSI+ISP-50 1 1
FSI+ESP-50 2 1
FSI+ESP-50-C 1 1
FSI+ESP-50-C 2 1
FSI+ESP-70 1 1
FSl+ESP-70 2 1
FSt+ESP-70-C 1 T
PSl»ESP-70-C 2 1
00
00
00
00
00
00
00
00
00
Q0
00
00
366
366
364
366
366
366
366
366
366
366
366
366
62
69
62
49
62
49
62
49
62
49
62
49
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
12.2
12.2
12.2
12.2
13.2
13.2
13.2
13.2
13.4
13.4
13.4
13.4
33.6
33.6
33.6
33.6
36.4
36.4
36.4
36.4
36.9
36.9
36.9
36.9
9.8
9.0
5.7
5.2
12.1
10.5
7.0
6.1
12.3
10.?
7.1
6.2
4.9
5.7
2.9
3.3
6.1
6.7
3.5
3.9
6.2
6.8
3.6
4.0
40.0
40.0
40.0
40.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
9809
7752
9809
7752
12175
9622
12175
9622
17045
13471
17045
13471
997.3
1155.9
577.0
669.3
991.9
1091.8
573.2
631.7
721.7
793.8
417.0
459.2
sssisssxasa«ss3sssesssss83Sss3S«acass33sssssssss8sa:ss8SBsasa38sassassss3S3S3sa=s=s:«ss2S3s:sss:si!Ssa=s:issiis:a=
11-17
-------
Atmospheric F1uidized Bed Combustion and Coal Gasification Applicability--
The two 364 MW boilers at the Chalk Point plant would not be considered
good candidates for AFBC/CB repowering due to the likely long remaining
useful life.
11.2.2 Dickerson Steam Plant
The Dickerson steam plant is located on the Monocacy River in
Montgomery County, Maryland, and is operated by the Potomac Electric Power
Company. The Dickerson plant contains three coal-fired boilers with a gross
generating capacity of 588 MW.
Table 11.2.2-1 presents operational data for the existing equipment at
the Dickerson plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area east of the plant. PM
emissions from the boilers are controlled by retrofit ESPs and wet
scrubbers. The ESPs are located behind the boilers and the wet scrubbers
are located at the south end of the plant. Half of the flue gases from each
boiler is routed to the ESPs and the rest is routed to the wet scrubbers.
All of the flue gas is then directed to a chimney at the southeast corner of
the plant. The other chimneys located behind the unit 2 and 3 ESPs are out
of service. Dry fly ash from the units is stored on-site.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located at the southeast side of the plant
beside the common chimney. The general facilities factor would be medium
(8 percent) for the FGD absorber location because a plant road would have to
be relocated. The site access/congestion factor would be low for this
location. Approximately 100 to 300 feet of ductwork would be required to
span the distance from the chimney to the absorbers and back to the chimney.
A low site access/congestion factor was also assigned to flue gas handling,
LSD with reuse of the existing ESPs was not considered for the
Dickerson plant because of the small sizes of the ESPs. LSD with new FFs
was considered for the plant. The LSD absorbers and baghouses would be
located similarly to the wet FGD system with similar site access/congestion
and general facilities factors. Between 100 and 300 feet of ductwork would
11-18
-------
TABLE 11.2.2-1. DICKERSON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2,3
GENERATING CAPACITY (MW-each) 196
CAPACITY FACTOR (PERCENT) 58,66,59
INSTALLATION DATE 1959,60,62
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) 93.5
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.5
COAL HEATING VALUE (BTU/LB) 12700
COAL ASH CONTENT (PERCENT) 10.7
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD STORAGE/ON-SITE
STACK NUMBER 3
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP,WET SCRUBBER
INSTALLATION DATE 1979
EMISSION (LB/MM BTU) 0.06
REMOVAL EFFICIENCY 97.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.8
SURFACE AREA (1000 SQ FT) 106
GAS EXIT RATE (1000 ACFM) 492
SCA (SQ FT/1000 ACFM) 215
OUTLET TEMPERATURE (eF) 245
11-19
-------
be required and the site access/congestion factor for flue gas handling
would be low.
Tables 11.2.2-2 and 11.2.2-3 present the retrofit factors and the cost
estimates for installation of conventional FGD technologies at the Dickerson
plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 11.2.2-4 summarizes the IAPCS cost results for CS at the
Dickerson plant. These costs do not include boiler and pulverizer operating
cost changes or any coal handling system modifications that may be
necessary. PCC was only considered for mine mouth plants, therefore, was
not evaluated for the Dickerson plant.
N0X Control Technologies--
OFA was evaluated for control of N0X emissions from the three
tangential-fired boilers at the Dickerson plant. Tables 11.2.2-5 and 11.2.2-6
present performance and cost results for installation of N0X emission
control technologies at the Dickerson steam plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the boilers at the Dickerson plant would be
located beside the common chimney. As in the FGD case, a medium general
facilities value (20 percent) and a low site access/congestion factor were
assigned to the location. Approximately 200 feet of ductwork would be
required to span the distance between the SCR reactors and the chimney.
Tables 11.2.2-5 and 11.2.2-6 summarize the retrofit factors and costs for
installation of SCR at the Dickerson plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Dickerson plant because of the marginal size ESPs and short duct
residence time between the boilers and ESPs.
11-20
-------
TABLE 11.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR DICKERSON
UNIT 1,2 OR 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NA
NO
RETROFIT FACTORS
FGD SYSTEM
1.20
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.16
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
11-21
-------
Table It.2.2-3. Summary of F® Control Costs for the Dickerson Plant (June 1988 Dollars)
:»3K=s=£=£:s==s==£sss=Rfi8asssssS8as==H«ssssassssssssaai8SBSl=s»sssss===ss===s=s:SaS8SBS===:=s==8saisttS3SS£s
Technology Boiler .Main, Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Ninter Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (X3 Content (MM) (SAW) (SUN) (milli/knh) <%> (tons/yr) (S/ton)
Factor (X)
L/S F0>
1
1
20
1%
58
1.5
49,9
254.6
23.3
23.4
90.0
10163
2292.5
L/S FCD
2
1
20
196
66
. 1.5
49.9
254.7
24.1
21.3
90.0
11565
2083.8
L/S FGD
3
1
20
196
59
1.5
49.9
254.7
23,4
23.1
90.0
10338
2263.4
L/S FGD
1
¦3
1
20
' 588
61
1.5
98.0
166.6
49.0
15.6
90.0
32066
1527.8
L/S FGD-C
1
.1
20
196
58
1.5
49.9
254.6
13.6
13.6
90.0
• 10163
' 1335.5
L/S FSO-C
2
1
20
196
66
1.5
49.9
254.7
14.0
12.4
90.0
11565:
1213.3
L/S FGD-C
3
1
20
196
59
1.5
49.9
254.7
13.6
13.5
90.0
10338
1318.4
L/S FGD-C
1
3
1
20
588
61
1.5 .
98.0
166.6
28.5
9.1
90.0
32066
. 889.0
LC FG0
1
3
1
20
588
61
1,5
72.9
123.9
40.9
13,0
90.0
32066
1275.1
LC FGD-C
1-
3
1
20
588
61
1.5
72.9
123,9
23.8
7,6
90.0
32066
740.7
LS0*FF
1
1
16
196
58
1.5
36.7
187,3
15.0
15.1
80.0
9024
1661.3
LSD*FF
2
1
16
196
66
1.5
36.7
187,3
15.4
13.6
80,0
10269
1498.2
LSD*FF5
3
1
16
196
59
1.5
36.7
187.3
15.0
14.8
80.0
9180
. 1638.4
LSD*FF-C
1
1
16
196
58 ,
1.5
36,7
187.3
8.8
8.8
80.0
9024
970.0
LSB+FF-C
2
1
16
196
66
1.5
36.7
187.3
9.0
7.9
80.0
10269
874.4
LSD+FF-C
3
1
16
196
59
1.5
36.7
187.3
8.8
8.7
80.0
9180
956.6
3ssssssss=s====ss==::s=s:BB8aas8aas8S8ssaiiauan&8Ba88a9aiiiiiiB8ss8Bssiaaixa33ii38ss3iiBiiiss88ss8aaisss88888s
11-22
-------
Table 11.2.2-4. S urinary of Coal Snitching/Cleaning Costs for the Dickerson Plant (Jirw 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nwber Retrofit Size Factor Sulfur Cost Cost . Cost Cost Removed Removed Effect.
Difficulty (MW> (X) Content (SMM) (S/ktf)
CS/B+S15
1
1.00
196
58
1.5
7.0
35.8
14.7
14.8
36.0
4101
3587.6
CS/B+S15
2
1.00
1%
66
1.5
7.0
35.8
16.5
14.6
36.0
4667
3540.7
CS/B+S15
3
1.00
196
59
1.5
7.0
35.8
14.9
14.7
36.0
4172
3581.1
CS/B-»t15-C
1
1.00
196
SS
1.5
7.0
35.8
8.5
8.5
36.0
4101
2063.2
CS/B+S15-C
2
1.00
196
66
1.5
7.0
35.8
9.5
8.4
36.0
4667
2035.4
CS/B+S15-C
3
1.00
196
59
1.5
7.0
35.8
8.6
8.5
36.0
4172
2059.3
CS/B*S5
1
1.00
196
58
1.5
5.0
25.4
6.1
6.2
36.0
'4101
1495.3
CS/B+J5
2
1.00
196
66
1.5
5.0
25.4
6.0
6.0
36.0
4667
1458.9
CS/B+S5
3
1.00
196
59
1.5
5.0
25.4
6.2
6.1
36.0
4172
1490.2
CS/B+S5-C
1
1.00
196
58
1.5
5.0
25.4
3.5
3.6
36.0
4101
862.1
CS/8+S5-C
2
1.00
1%
66
1.5
5.0
25.4
3.9
3.5
36.0
4667
840.7
CS/8+SS-C
3
1.00
196
59
1.5
5.0
25.4
3.6
3.5
36.0
4172
859.1
11-23
-------
TABLE 11.2.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR DICKERSON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 OR 3
; FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 93.5
BOILER INSTALLATION DATE 1959,60,62
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 45
New Duct Length (Feet) 200
New Duct Costs (1000$) 1469
New Heat Exchanger (1000$) 2791
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 4305
COMBINED CASE 8291
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
11-24
-------
Table 11.2.2-6. NOx Control Cost Results for the Diekerson Plant (Jum 1988 Dollars)
===========
========
I3SS332
8ssas:=s
=========
:ssss=sss
aaasasss
isaseass
ssssa3
II
II
II
II
II
II
II
II
II
SSSSSSSSE
Technology
Boiler Ha in
Boiler Capacity Coal
Capital Capital Annual
Annual
NO*
NQx
N0X COSt
Nunber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (*y>
(X)
Content
<$MM)
CS/kWJ
(WH>
Cmf I Is/kMh)
(X)
(tons/yr)
iS/ton)
Factor
m
UC-OfA
1
1.00
196
SB
1.5
0.8
4.1
0.2
0.2
25.0
724
243.7
INC-OfA
2
1.00
196
66
1.5
0.8
4.1
0.2
0.2
25.0
824
214.2
INC-OFA
3
1.00
196
59
1.5
0.8
4.1
0.2
0.2
25.0
736
239.6
LMC-OFA-C
1
1.00
196
58
1.5
0.8
4.1
0.1
0.1
25.0
724
144.6
UC-OFA-C
2
1.00
196
66
1.5
0.8
4.1
0.1
0.1
25.0
824
127.1
LNC-OFA-C
3
1,00
196
59
1.5
0.8
4.1
0.1
0.1
25.0
736
142.2
SCR-3
1
1.16
1%
58
1.5
29.8
152.0
10.3
10.3
80.0
2316
4437.3
SCR *3
2
1.16
196
66
1.5
29.8
152.0
10.4
9.1
80.0
2636
3931.9
SCR-3
3
1.16
196
59
1.5
29.8
152.0
10.3
10.2
80.0
2356
4366.5
SCR-3
1-3
1.16
568
61
1.5
70.5
120.0
26.3
8.4
80.0
7303
3598.9
SCR-3-C
1
1.16
196
58
1.5
29.8
152.0
6.0
6.0
80.0
2316
2599.9
SCR-3-C
2
1.16
196
66
1.5
29.8
152.0
6.1
5.4
80.0
2636
2303.4
SCR-3-C
3
1.16
196
59
1.5
29.8
152.0
6.0
6.0
80.0
2356
2558.4
SCR-3-C
1-3
1.16
588
61
1.5
70.5
120.0
15.4
4.9
80.0
' 7308
2105.2
SCR-7
1
1.16
196
58 •
1.5
29.8
152.0
8.7
8.7
80.0
2316
3747.8
SCR-7
2
1.16
196
66
1.5
29.8
152.0
8.8
7.7
80.0
2636
3325.9
SC8-7
3
1.16
196
59
1.5
29.8
152.0
8.7
8.6
80.0
2356
3688.7
SCR-7
1-3
1.16
586
61
1.5
70.5
120.0
21.5
6.8
80.0
7308
2943.3
SCR-7-C
1
1.16
196
58
1.5
29.8
152.0
5.1
5.1
80.0
2316
2204.9
SCR-7-C
2
1.16
196
66
1.5
29.8
152.0
5.2
4.6
80.0
2636
1956.2
SCR-7-C
3
1.16
196
59
1.5
29.8
152.0
5.1
5.0
80.0
2356
2170.1
SCR-7-C
1-3
1.16
588
61
1.5
70.5
120.0-
12.6
4.0
80.0
7308
1729.6
S S3SS ¦ U'iB IB SSSSt'SI ¦¦¦¦¦>¦ SSBllHSIIlSBIIlBSlIlBIIIBIIIlllllllllltlllllfllSl |S||gfH8U|| ¦¦USUI ¦¦¦¦¦¦»¦ ¦¦¦HIBMM
11-25
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The three boilers at the Dickerson plant would be good candidates for
AFBC/CG repowering because of their small size (-196 MW) and short remaining
useful life,
11-2.3 Morgantown Steam Plant
The Morgantown steam plant is located on the Potomac River in Charles
County, Maryland, and is operated by the Potomac Electric Power Company.
The Morgantown plant contains two boilers which burn both coal and oil with
a gross generating capacity of 1,252 MW.
Table 11.2.3-1 presents operational data for the existing equipment at
the Morgantown plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area east of the plant. PM
emissions from the boilers are controlled by ESPs which were built at the
same time as the boilers. The ESPs are located behind the boilers and flue
gases are directed to chimneys behind the ESPs. Dry fly ash from the units
is stored on-site.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located at the north and south ends of the
units beside the ESPs. Low general facility and site access/congestion
factors were assigned for the FGD absorber locations. Approximately 100 to
300 feet of ductwork would be required to span the distance from the chimney
to the absorbers and back to the chimney for each unit. Low site access/
congestion factors were assigned to flue gas handling.
LSD-FGD with reuse of the existing ESPs was not considered for the
Morgantown plant because of the small sizes of the ESPs. However, LSD could
be applied if new FFs were installed to accommodate the additional
particulate load. The LSD-FGD absorbers would have the same location as the
L/LS-FGD absorbers. The FFs would be located adjacent to the LSD absorbers
with low site access/congestion factors. Table 11.2.3-2 summarizes the
retrofit factor inputs to the IAPCS model. Table 11.2.3-3 presents the
estimated costs for installation of conventional FGD systems at the
Morgantown plant.
11-26
-------
TABLE 11.2.3-1. MORGANTOWN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 626
CAPACITY FACTOR (PERCENT) 65,60
INSTALLATION DATE . 1970,71
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) 288.8
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.8
COAL HEATING VALUE (BTU/LB) 12500
COAL ASH CONTENT (PERCENT) 11.9
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD STORAGE/ON-SITE
STACK NUMBER 1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1970,71
EMISSION (LB/MM BTU) 0.1
REMOVAL EFFICIENCY 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) NA
SURFACE AREA (1000 SQ FT) 168.5
GAS EXIT RATE (1000 ACFM) 1660
SCA (SQ FT/1000 ACFM) 102
OUTLET TEMPERATURE (8F) 250
11-27
-------
TABLE 11.2.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR MORGANTOWN
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE 100-300
ESP REUSE NA . NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.20 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.16
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 0 5
11-28
-------
Table 11.2.3-3, Summary of FGD Control Costs for the Horgantown Plant (June 1988 Dollars)
Technology
Boiler Main Boiler Capacity Coal Capital Capital Annual
Mutfcer Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (MV) (X) Content ($W) (S/kW)
Factor (X)
Annual $02 SQ2 S02 Cost
Cost Removed Removed Effect,
(mills/kwh) (X) (tons/yr) ($/ton)
L/S FGD
L/S FGD
1.20
1.20
626
626
65
60
1.8
1.8
102.0
101.9
162.9
162.8
53.3
51.8
15.0
15.8
90.0
90.0
44454
41035
1199.7
1263.1
L/S FGD'
L/S FGD'
1.20
1.20
626
626
65
60
1.8
1.8
102.0
101.9
162.9
162.8
31.0
30.2
8.7
9.2
90.0
90.0
44454
41035
697.7
734.8
LC FGD
LC FGD
1.20
1.20
626
626
65
60
1.8
1.8
81.9
81.9
130.9
130.8
46.9
45.4
13.2
13.8
90.0
90.0
44454
41035
1054.9
1106.2
LC FGD-C
LC FGD-C
1.20
1.20
626
626
65
60
1.8
1.8
81.9
81.9
130.9
130.8
27.2
26.4
7.6
8.0
90.0
90.0
44454
41035
612.6
642.7
LSO+FF
ISD+FF
1.16
1.16
626
626
65
60
1.8
1.8
98.7
98.7
157.7
157.7
39.9
39.0
11.2
11.9
78.0
78.0
38392
35439
1038.6
1100.8
L5D*FF-C
LSD+FF-C
1.16
1.16
626
626
65
60
1.8
1.8
98.7
98.7
157.7
157.7
23.3
22.8
6.5
6.9
78.0
78.0
38392
35439
606.6
643.2
=tas:S889S3S3SSasaB983
11-29
-------
Coal Switching and Physical Coal Cleaning Costs-
Table 11.2.3-4 presents the estimated costs for CS at the Morgantown
plant. These costs do not include pulverizer and boiler operating cost
impacts or any coal system modifications that may be necessary. PCC is only
being considered for mine mouth plants. Therefore, it is not applicable to
the Morgantown plant.
N0X Control Technologies--
OFA was considered for N0X emission control for the two tangential -
fired boilers at the Morgantown plant. Tables 11.2.3-5 and 11.2.3-6 summarize
the N0x performance estimates and costs developed for installation of this
technology at the plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the boilers at the Morgantown plant would be
located similarly to the wet FGD absorbers. As in the FGD case, low general
facility values (13 percent) and site access/congestion factors were
assigned. About 200 feet of ductwork would be required. Tables 11.2.3-5
and 11.2.3-6 summarize the retrofit factors and costs for installation of
SCR at the Morgantown plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies {FSI and DSD) were not considered for
the Morgantown plant because the existing ESPs are too small to handle the
additional load imposed by these technologies.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The two 626 MW boilers at the Morgantown plant are too large and have
too long a remaining useful life to be considered for AFBC/CG technologies.
11-30
-------
Table 11.2.3-4. Suimary of Coat Sw i tch ing/CI eani ng Costs for the Morgantown Plant (June 1988 Oollar«)
ssssssssiasssssssssstaass
sasssssrsa
S3 S535 33SSSSS3SSSSSS8WSS£SSCS88SSSBSSSS98S3aSSS3S3C38S8SSa3SSSaiSSS
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nuifcer Retrofit Size Factor Sulfur Coat Cost Cost
Difficulty (NW) (X) Content (JWO (S/kW) <««)
Factor <%>
Annual S02 S02 S02 Cost
Cost Removed Removed Effect.
(miUs/kwh) (X) (tons/yr) (S/ton>
CS/B+S15
CS/B*«15
CS/B+S15-C
CS/B+S15-C
CS/i*®5
CS/B+S5
.00
.00
.00
.00
.00
.00
626
626
626
626
626
626
65
60
63
60
65
60
1.3
1.8
1.8
1.8
1.8
1.8
24.7
24.7
24,
24.
18.2
18.2
39.4
39.4
39.4
39.4
29.1
29.1
51.6
48.1
29.7
27.6
21.0
19.8
14.5
14.6
8.3
8.4
5.9
6.0
48.0
48.0
48.0
48.0
48.0
48.0
23654
21835
23654
21835
23654
21835
2181.7
2201.2
1214.7
1266.2
889.0
904.5
CS/B+*5-C
CS/B+M-C
1.00
1.00
626
626
65
60
1.8
1.8
18.2
18.2
29.1
29.1
12.1
11.4
3.4
3.5
48.0
48.0
23654
21835
512.8
522.0
11-31
-------
TABLE 11.2.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR MORGANTQWN
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
TYPE OF NOx CONTROL
FURNACE VOLUME (1000 CU FT)
BOILER INSTALLATION DATE
SLAGGING PROBLEM
ESTIMATED NOx REDUCTION (PERCENT)
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
Ductwork Demolition (1000$)
New Duct Length (Feet)
New Duct Costs (1000$)
New Heat Exchanger (1000$)
TOTAL SCOPE ADDER COSTS (1000$)
RETROFIT FACTOR FOR SCR
GENERAL FACILITIES (PERCENT)
BOILER NUMBER
1,2
TANG
OFA
288.8
1970, 1971
NO
25
LOW
0
107
200
2898
5602
8607
1.16
13
11-32
-------
Tabic 11.2.3-6. NOx Control Cost Results for the Norgantown Plant (tons/yr) (S/ton)
Factor (X)
LNC-OFA
LHC-OFA
IMC-OFA-C
IMC-OFA-C
SCR-3
SCR-3
SCR-3-C
SCR-3-C
SCR-7
SCR-7
SCR-7-C
SCR-7-C
1
2
1
2
1
2
1
2
1
2
1
2
1.00
1.00
1.00
1.00
1.16
1.16
1.16
1.16
1.16
1.16
1.16
1.16
626
626
626
626
626
626
626
626
626
626
626
626
65
60
65
60
65
60
65
60
65
60
65
60
1.3
1.3
1.3
1.3
2.1
2.1
2.1
2.1
73.2
73.2
73.2
73.2
0.3
0.3
0.2
0.2
73.2 117.0 27.7
73.2 117.0 27.5
117.0
117.0
117.0
117.0
73.2 117.0
73.2 117.0
16.2
16.1
22.6
22.4
13.3
13.2
0.1
0.1
0.0
o.t
7.8
8.4
6.5
4.9
6.3
6.6
3.7
4.0
25.0
25.0
25.0
25.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
2638
2436
2638
2436
8443
7794
8443
7794
8443
7794
8443
7794
106.3
115.1
63.1
68.3
3278.4
3529.6
1917.2
2064.4
2672.8
2873.6
1570.2
1688.5
S:S=SS8S8SS88SS3B3333S3SSSS3S93aa8SS3aiSSSSSS3SSa[SSS8SS35S8C83aa3aS*«a«a8SS8SaB3S83SSBflS33888S3S83aaSSSSSSSS3S8Sa
11-33
-------
Page Intentionally Left Blank
-------
SECTION 12.0 MICHIGAN
12.1 CONSUMERS POWER COMPANY
12.1.1 J. H. Campbell Steam Plant
The J. H. Campbell steam plant is located on Pigeon Lake in Ottawa
County, Michigan, and is operated by the Consumers Power Company. The
Campbell plant contains three coal-fired boilers with a total gross
generating capacity of 1,421 MW.
Table 12.1.1-1 presents operational data for the existing equipment at
the Campbell plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area south of the plant. PM emissions from
the three units are controlled by ESPs installed at the time of
construction with retrofit ESPs augmenting the original precipitators for
units 1 and 2. The original ESPs for units 1 and 2 are located behind the
boilers and the retrofit ESPs are located behind unit 1 and 2 chimney. The
ESPs for unit 3 are located behind the unit 3 boiler. Fly ash is disposed
of in ponds east of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located at the south end
of unit 1 and the unit 3 absorbers would be located at the north end of
unit 3. The FGD absorbers for these units cannot be located directly behind
the chimneys because of the river. Although the retrofit ESPs are already
built out over the river, the duct length would not be prohibitively long
for the location at the south end of the plant. A medium (10 percent)
general facilities factor was assigned for the L/LS-FGD absorber location
for units 1 and 2 because several storage buildings and silos would have to
be relocated. A low (5 percent) general facilities factor was assigned for
the unit 3 absorber location. The site access/congestion factor would be
high for the unit 1 and 2 absorber location because of the proximity of the
coal conveyor and the river. The site access/congestion factor would be low
for the unit 3 absorber location. Approximately 300 to 600 feet of ductwork
12-1
-------
TABLE 12.1.1-1. J. H. CAMPBELL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1 2 3
265 386 770
76 64 88
1962 1967 1980
TANGENTIAL OPPOSED WALL
133 167 751
NO NO NO
0.9 0.9 0.7
12900 12900 12500
11.4 11.4 8.1
WET DISPOSAL
PONDS ON-SITE/SOLD
1 1 2
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
ESP
ESP
ESP
1976
1978
1980
0.031
0.031
0.011
97.0
98.0
99.6
4.6
4.5
4.0
242
746
2177
1177
1492
3400
206
500
640
300
275
305
12-2
-------
would be required for installation of the wet FGD system for units 1 and 2
and approximately 400 feet of ductwork would be required for unit 3. A high
site access/congestion factor was assigned to the units 1 and 2 flue gas
handling system because of the difficultly in accessing the existing
chimney. A low site access/congestion factor was assigned to flue gas
handling for the L/LS-FGD system for unit 3.
LSD-FGD with reuse of the existing ESPs was considered for the Campbell
plant. The LSD absorbers would be located similarly to the wet FGD
absorbers with similar general facilities, site access/congestion factors,
and ductwork requirements. A high factor was assigned to the ESP upgrade
difficulty for units 1 and 2 and a low factor was assigned for unit 3.
Tables 12.1.1-2 and 12.1.1-3 summarize the retrofit factors for all of
the units. Costs were not developed for these units because they fire a low
sulfur content coal to comply with the 1971 NSPS.
Coal Switching and Physical Coal Cleaning Costs--
Units 1-3 are burning low sulfur coal and were not considered in this
evaluation.
N0X Control Technologies-
Unit 1 is a tangential-fired boiler rated 265 MW and unit 2 is an
opposed-wall boiler rated at 386 MW. The combustion modification techniques
for these units are OFA and LNB for units 1 and 2, respectively. Furnace
values were not available for units 1 and 2 and were estimated based on
similar boiler size and age. Tables 12.1.1-4 and 12.1.1-5 present N0x
performance and cost estimates for installation of LNC technologies at the
Campbell plant. Unit 3, built in 19S0, meets the 1971 NSPS NO emission
A
levels and, as such, was not considered for retrofit of LNC technologies.
Selective Catalytic Reduction-
Cold side SCR reactors would be located similarly to the wet FGD
absorbers and would have similar site access/congestion factors, general
facilities factors, and ductwork requirements. Tables 12.1.1-4 and 12.1.1-5
summarize the retrofit factors and costs for installation of SCR at the
Campbell plant.
12-3
-------
TABLE 12.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR J. H. CAMPBELL
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
2246,3147 NA
2246,3147
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.68
NA
ESP REUSE CASE
1.69
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10
12-4
-------
TABLE 12.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR J. H. CAMPBELL
UNIT 3
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW
FLUE GAS HANDLING LOW
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA
NEW BAGHOUSE NA
NA
NA
300-600 NA
NA
NA
LOW
MEDIUM
NA
300-600
NA
LOW
NA
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
YES
5844
NO
0
NO
NA
NA
NA
0
YES
5844
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.38
NA
NA
NA
NA
NA
1.38
NA
1.16
NA
GENERAL FACILITIES (PERCENT) 5
5
12-5
-------
TABLE 12.1.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR J. H. CAMPBELL
BORER NUMBER
COMBUSTION MODIFICATION RESULTS
1 2 3
FIRING TYPE TANG OWF NA
TYPE OF NOx CONTROL OFA LNB NA
FURNACE VOLUME (1000 CU FT) NA NA NA
BOILER INSTALLATION DATE 1962 1967 NA
SLAGGING PROBLEM NA NA NA
ESTIMATED NOx REDUCTION (PERCENT) 25 40 NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH HIGH LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0 0
Ductwork Demolition (1000$) 56 74 125
New Duct Length (Feet) 400 400 400
New Duct Costs (1000$) 3505 4368 6542
New Heat Exchanger (1000$) 3345 4191 6343
TOTAL SCOPE ADDER COSTS (1000$) 6906 8634 13010
RETROFIT FACTOR FOR SCR 1.52 1.52 1.16.
GENERAL FACILITIES (PERCENT) _20 20 ¦ 13
12-6
-------
Table 12.1.1-5. NOx Control Cost Results for the J. H, Campbell Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NOx
NOX COSt
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) would be ideal for the
unit 1 and 2 boilers at the Campbell plant because of the long duct
residence times between the boilers and the larger ESPs. FSI and DSD
technologies were also considered for the unit 3 boiler because of the large
size of the unit 3 ESPs. Even though there is very little duct residence
time between boiler 3 and the ESPs, the ESPs are large and can be modified
for sorbent injection and humidification. Tables 12.1.1-6 and 12.1.1-7
present retrofit data and costs for installation of DSD or FSI technologies
at the Campbell plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Although units 1 and 2 are small enough to be considered for
repowering, using advanced technologies, their long remaining life and
moderate to high capacity factors make them unlikely near term candidates.
Unit 3 is not a candidate for consideration because of its large boiler
size.
12.1.2 Dan E. Karn
The Karn steam plant is located on the Saginaw River delta in Bay
County, Michigan, and is operated by the Consumers Power Company. The Karn
plant contains two coal-fired and two petroleum-fired boilers with a gross
generating capacity of 1,767 MW.
Table 12.1.2-1 presents operational data for the coal-fired boilers at
the Karn plant. Coal shipments are received by railroad and transferred to
a coal storage and handling area west of the plant. PM emissions from the
coal-fired boilers are controlled by ESPs which were installed at the time
of construction and by retrofit ESPs. The retrofit ESP boxes are located on
either side of the two chimneys. Fly ash is disposed of in ponds north and
east of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS and LSD-FGD absorbers for the two coal-fired boilers would be
located north of unit 1 between the coal conveyor and the unit 1 chimney.
12-8
-------
TABLE 12.1.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR J. H. CAMPBELL UNIT 1,2 OR 3
ITEM
1
2
3
SITE ACCESS/CONGESTION
REAGENT PREPARATION
LOW
LOW
LOW
ESP UPGRADE
HIGH
HIGH
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADDER'S
WET TO DRY
YES
YES
YES
ESTIMATED COST (1000$)
2246
3147
5844
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
NA
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
ESP REUSE CASE
NA
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
DUCT DEMOLITION LENGTH (FT)
50
50
50
DEMOLITION COST (1000$)
62
82
138
TOTAL COST (1000$)
ESP UPGRADE CASE
2308
3229
5982
A NEW BAGHOUSE CASE
NA
NA
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.13
1.13
1.13
ESP UPGRADE
1.58
1.58
1.16
NEW BAGHOUSE
NA
NA
NA
12-9
-------
Table 12.1.1-7. Surinary of DSD/FSJ Control Costs for the J. H. CampbelL Plant (Jirw 1988 Dollars)
Technology
iofler
Main
Boiler Capacity Coal
Capital Capital Annuel
Annual
S02
S02
S02 Cost
Nurber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty (MW)
CX)
Content
(SWO
(SMO
{mills/kuh)
C%>
(tons/yr)
(t/ton)
Factor
(%)
0SD*ESP
1
1.00
265
76
0.9
15.1
56.9
9.5
5.4
49.0
5736
1655.6.
DS0+ESP
2
1.00
386
64
0.9
15.4
39.8
10.1
4.7
49.0
7035
1437.2
DS0+ESP
3
1.00
770
88
0.7
22.9
29.7
16.4
2.8
49.0
15561
1052.6
DSO+ESP-C
1
1.00
265
76
0.9
IS. 1
56.9
5.5
3.1
49.0
5736
960.3
OSO+ESP-C
2
1.00
386
64
0.9
15.4
39.8
5.9
2.7
49.0
7035
833.2
DSD+ESP-C
3
1.00
770
88
0.7
22.9
29.7
9.5
1.6
49.0
15561
609.7
FS1+ESP-50
1
1.00
265
76
0.9
17.0
64.2
9.4
5.4
50.0
5B95
1602.0
F51+ESP-50
2
1.00
386
64
0.9
15.2
39.3
9.6
4.4
50.0
7231
1323.4
FSI+iSP-50
3
1.00
770
88
0.7
24.2
31.4
17.6
3.0
50.0
15993
1099.1
FSI+ESP-50-C
1
1.00
265
76
O.f
17.0
64.2
5.5
3.1
50.0
5895
930.8
FSI*£SP-5Q-C
2
1.00
386
64
0.9
15.2
39.3
5.6
2.6
50.0
7231
767.6
FSl*ESP-50-C
3
1.00
770
88
0.7
24.2
31.4
10.2
1.7
50.0
15993
636,5
FSI+ESP-70
1
1.00
265
76
0.9
17.2
64.7
9.6
5.4
70.0
8253
1150.9
FSf+ESP-70 •
2
1.00
386
64
0.9
15.3
39,7
9.7
4.5
70.0
10123
959.8
FSI+ISP-70
3
1.00
770
88
0.7
24.4
31.7
17.9
3.0
70.0
22391
797.4
FSH-ESP-70-C
1
1.00
265
76
0.9
17.2
64.7
5.6
3.1
70.0
8253
673.3
FSI+ESP-70-C
2
1.00
386
64
0.9
15.3
39.7
5.6
2.6
70.0
10123
556.7
FSI+ESP-70-C
3
1.00
770
88
0.7
24.4
31.7
10.3
1.7
70.0
22391
461.8
==sss»sss»s
assisssu
II
II
11
II
II
II
II
II
II
II
II
II
u
II
II
II
u
SSSSSSrSS
SS33C3B*
——t
ssssssss
SSS8SSS3S1S
if
11
II
II
II
II
12-10
-------
TABLE 12.1.2-1. DAN E. KARN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
I,2 3,4
265 605,632
74,75 PETROLEUM
1959,61 BURNING
TANGENTIAL OPPOSED WALL
153,136
NO
0.9
12600
II.6
WET DISPOSAL
POND/ON-SITE/SOLD
1,2
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1977
EMISSION (LB/MM BTU) 0.06,0.05
REMOVAL EFFICIENCY 97
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) NA
SURFACE AREA (1000 SQ FT) 369
GAS EXIT RATE (1000 ACFM 1172
SCA (SQ FT/1000 ACFM) 315
OUTLET TEMPERATURE (*F) 300
12-11
-------
The general facilities factor is high (15 percent) for this location because
the coal conveyor would have to be relocated. After relocation of the coal
conveyor, a low site access/congestion factor could be assigned to the
location. About 200 feet of ductwork would be required to install the
L/LS-FGD system for unit 1 and about 500 feet would be required for unit 2.
Because of the congestion around the chimneys, due to the ESPs, a high site
access/congestion factor was assigned to flue gas handling for both units.
LSD with reuse of the existing ESPs was considered for the two coal
burning units because of the adequate sizes of the ESPs. The ductwork
requirements and flue gas handling site access/congestion factors would be
the same for instal1ation of the LSD-FGD system as for Installation of the
wet FGD system because of the difficulty of accessing the upstream side of
the ESPs.
Tables 12.1.2-2 and 12.1.2-3 present the retrofit factor inputs to the
IAPCS model. Costs are not presented since the Karn plant is burning a low
sulfur coal.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Karn plant because low sulfur
coal is already being burned at the plant.
N0X Control Technologies--
OFA was considered for unit 1 which is a tangential-fired, dry bottom
boiler. LNB was considered for unit 2 which is an opposed wall-fired, dry
bottom boiler. Tables 12.1.2-4 and 12.1.2-5 present the N0X performance and
cost estimates for installation of OFA and LNB at the Karn plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the coal-fired boilers at the Karn, plant
would be located similarly to the FGD absorbers at the north end of the
plant. However, the coal conveyor would not have to be relocated for
installation of the SCR reactors; therefore, a low (13 percent) general
facilities value was assigned to the location. A medium site access/
congestion factor was assigned to the location because of the proximity of
the coal conveyor and the unit 1 ESPs. About 200 feet of ductwork would be
12-12
-------
TABLE 12.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR DAN E. KARN
UNIT 1
FGD TECHNOLOGY
L/LS FGD
FORCED
OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
100-300
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
2246
NA
2246
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.39
NA
ESP REUSE CASE
1.35
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
15
12-13
-------
TABLE 12.1.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR DAN E. KARN
UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION ;
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 2246 NA 2246
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.46 NA
ESP REUSE CASE 1.43
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
12-14
-------
TABLE 12.1.2-4. SUMMARY OF NOx RETROFIT RESULTS FOR DAN E. KARN
BOI1ER NUMBER
COMBUSTION MODIFICATION RESULTS
1 .
2
FIRING TYPE
TANG
OWF
TYPE OF NOx CONTROL
OFA
LNB
FURNACE VOLUME (1000 CU FT)
153
136
BOILER INSTALLATION DATE
1959
1961
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
35
SCR RETROFIT RESULTS
. SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
56
56
New Duct Length (Feet)
200
500
New Duct Costs (1000$)
1753
4381
New Heat Exchanger (1000$)
3345
3345
TOTAL SCOPE ADDER COSTS (1000$)
5153
7782
RETROFIT FACTOR FOR SCR
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
12-15
-------
Table 12.1.2-5. NO* Control Cost Results for the (Cam Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW) (X) Content (SMK) (S/tt) (SMM)
-------
required for installation of the SCR reactors for unit 1 and about 500 feet
would be required for unit 2, Tables 12.1.2-4 and 12.1.2-5 present the
retrofit factor inputs to the IAPCS model and the estimated cost for
installation of cold side SCR at the Karn plant.
Furnace Sorbent Injection and Duct Spray Drying--
Sorbent injection technologies (FSI and DSD) were considered for both
unit 1 and unit 2 because of the large size of the existing ESPs (SCA - 315)
and the sufficient duct residence time between the boilers and the ESPs.
Tables 12.1.2-6 and 12.1.2-7 present retrofit factors and cost estimates for
sorbent injection technologies.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The two 265 MW coal-fired boilers at the Karn plant would be good
candidates for AFBC/CG repowering. However, the high capacity factors for
these units might result in high replacement power costs in the case of
extensive boiler downtime.
12.1.3 J.C. Weadock Steam Plant
Retrofit factors for FGD are presented for the boilers at the Weadock
plant; however, costs were not presented due to the low sulfur content of
the coal. In addition, CS was not evaluated since the boilers already fire
a low sulfur coal. Sorbent injection technologies (FSI and DSD) were not
evaluated due to the short duct residence time between the boilers and the
ESPs and the marginal size of the ESPs.
12-17
-------
TABLE 12.1.2-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR DAN E. KARN UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2246
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 62
TOTAL COST (1000$)
ESP UPGRADE CASE 2308
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
12-18
-------
Table 12.1.2-7. Suimry of DSC/FSI Control Costs for the Kirn Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 SQ2 Cost
Nuiber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (HW) (X) Content (SM) (t/kii) (S»0 (mtlls/kwh) (X) (tons/yr) <$/ton)
Factor <%>
DSO+ESP
DSO+ESP
1.00
1.00
265
265
74
75
0.9
0.9
12.2
12.2
46.2
46.2
8.7
8.7
5.1
5.0
49.0
49.0
5738
5815
1514.7
1501.5
BSD+fSP-C
QS0*ESP-C
1.00
1.00
265
265
74
75
0.9
0.9
12.2
12.2
46.2
46.2
5.0
5.1
2.9
2.9
49.0
49.0
5738
5815
877.4
869.7
FSI*ESP-50
rsi+isp-50
1.00
1.00
265
265
74
75
0.9
0.9
13.5
13.5
50.9
50.9
8.4
8-5
4.9
4.9
50.0
50.0
5897
5976
1425.7
1415.4
FSI+ESP-50-C
FSt+ESP-50-C
1.00
1.00
265
265
74
75
0.9
0.9
13.5
13.5
50.9
50.9
4.9
4.9
2.8
2.8
50.0
50.0
5897
1976
827.1
821.0
FSt+iSP-70
FSI+iSP-70
1.00
1.00
265
265
74
75
0.9
0.9
13.6
13.6
51.2
51.2
8.5
8.6
5.0
4.9
70.0
70.0
8256
8367
1030.7
1023.4
FS1+6SP-70-C
FSl*ESP-70-C
1.00
1.00
265
265
74
75
0.9
0.9
13.6
13.6
51.2
51.2
4.9
5.0
2.9
2.9
70.0
70.0
8256
8367
597.9
593.6
12-19
-------
TABLE 12.1.3-1. WEADOCK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1971
EMISSION (LB/MM BTU) 0.06, 0.285
REMOVAL EFFICIENCY 99.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.0-0.0
SURFACE AREA (1000 SQ FT) 97.92
EXIT GAS FLOW RATE (1000 ACFM) 545
SCA (Sq FT/1000 ACFM) 180
OUTLET TEMPERATURE (*F) 305
7,8
156
75,77
1955, 1958
TANGENTIAL
65.0
NO
0.9
12600
9.1
WET DISPOSAL
POND/ON-SITE
1
RAILROAD
12-20
-------
TABLE 12.1.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR WEADOCK
UNITS 7 OR 8*
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
100-300
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
1397
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
.NO-
RETROFIT FACTORS
FGD SYSTEM
1.37
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.29
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for
units 7 and 8 would be located south of their common chimney.
12-21
-------
TABLE 12,1.3-3. SUMMARY OF NOx RETROFIT RESULTS FOR WEADOCK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
7,8
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 65
BOILER INSTALLATION DATE 1955,1958
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
Ductwork Demolition (1000$) 38
300
New Duct Costs (1000$) 1928
New Heat Exchanger (1000$) 2434
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 4400
COMBINED CASE 6645
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) ^ 20
* Cold side SCR reactors for units 7 and 8 would be located
south of their common chimney.
12-22
-------
Table 12.1,3-4. NOx Control Cost Results for the Weadock Plant (June 1988 Dollars)
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Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx •
NOx Cost
Nimber
Retrofit
Size
Factor
Sulfur
Cost .
Cost
cost
Cost
Removed Removed
Effect.
Difficulty CMW)
(X)
Content
(SMH)
CS/WJ
(SMM3
(mills/kwh)
<*>
Ctons/yr)
(S/ton)
Factor
(%3
LNC-OFA
7
1.00
156
75
0.9
0.7
4.7
0.2
0.2
25.0
752
215.5
INC-OFA
8
1,00
156
77
0.9
0.7
4.7
0.2
0.2
25.0
772
209.9
LNC-OFA-C
7
1.00
156
75
0.9
0.7
4.7
0.1
0.1
25.0
752
127.8
IWC-OFA-C
8
1.00
156
77
0.9
0.7
4.7
0.1
0.1
25.0
772
124.5
SCR-3
7
1.34
156
75
0.9
28.4
181,8
9.5
9.3
80.0
2406
3961.0
SCR-3
a
1.34
156
77
0,9
28.4
181.8
9.5
9.1
80.0
2470
3865.4
SCR-3
7-8
1.34
312
76
0.9
48.2
154.4
16.8
8.1
80.0
4875
3454.6
SCR-3-C
7
¦ 1.34
156
75
0.9
28.4
181.8
5.6
5.5
80.0
2406
2322.2
SCR-3-C
S
1.34
156
77
0.9
28.4
181.8
5.6
5.3
80.0
2470
2266.1
SCR-3-C
7-8
1.34
312
76
0.9
48.2
154.4
9.9
4.7
80.0
4875
2023.6
SCR-7
7
1.34
156
75
0.9
28.4
181.8
8.3
8.1
80.0
2406
' 3431.8
SCR -7
1.34
156
77
0.9
28.4
181.8
8.3
7.9
80.0
2470
3350.0
SCR-7
7-8
1.34
312
76
0.9
48.2
154.4
14.3
6.9
80.0
4875
2932,5
SCR-7-C
1.34
156
75 .
0.9
28.4
181.8
4.9
4,7
80.0
2406
2019.1
SCR-7-C
S
1.34
156
77
0.9
28.4
181.8
4.9
4.6
80.0
2470
1970.8
SCR-7-C
ssssssssssss
7-8
1.34
312
76
ssssss.
0.9
as
48.2
3S5S3S2S3
154.4
8.4
4.0
s
80.0
4875
1724.4
-sssssss:
12-23
-------
12.1.4 J.R, Whitino
Although retrofit factors for FGD were developed for the Whiting plant,
costs are not shown because it is unlikely that the current low sulfur coal
would be used if scrubbing were required.
TABLE 12.1.4-1. J.R. WHITING STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1 2 3
100 125
85»68 86
1952,53 1953
FRONT WALL
52,52 73
NO
0.8
12000
11.0
WET
PONDS/ON-SITE
1,2 3
RAILROAD
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1974 . 1975
EMISSION (LB/MM BTU) 0.05,0.06 0.05
REMOVAL EFFICIENCY 99 99
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.7 0.7
SURFACE AREA (1000 SQFT) 128.96 153.29
EXIT GAS FLOW RATE (1000 ACFM) 400 475
SCA (SQ FT/1000 ACFM) 322 323
OUTLET TEMPERATURE (*F) 285 300
12-24
-------
TABLE 12.1.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR J. R. WHITING
UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET.)
300-600
NA
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000S)
938
NA
938
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
700
o
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
1.54
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE ,
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
10
* Absorbers for units 1 and 2 would be located north of unit 3.
12-25
-------
TABLE 12.1.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR 0. R. WHITING
UNIT 3 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
1145
NA
1145
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
875
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.44
NA
ESP REUSE CASE
1.43
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
10
* Absorbers for unit 3 would be located north of unit 3,
12-26
-------
TABLE 12.1.4-4, SUMMARY OF NOx RETROFIT RESULTS FOR J. R. WHITING
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
FURNACE VOLUME (1000 CU FT)
73
73
NA
BOILER INSTALLATION DATE
1952
1953
1953
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
50
50
40
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
LOW
LOW
SCOPE ADDER PARAMETERS --
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
27
27
32
New Duct Length (Feet)
300
600
300
New Duct Costs (1000$)
1487
2973
1694
New Heat Exchanger (1000$)
1864
1864
2131
TOTAL SCOPE ADDER COSTS (1000$)
3377
4864
3857
RETROFIT FACTOR FOR SCR
1.34
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for unit 1 would be located south of the
unit 1 ESP. Cold side SCR reactors for units 2 and 3 would be
located north of unit 3.
12-27
-------
Table 1Z.1.4-3. MQx Control Coat Result* for the Uhtt1r>g Plant (Jure 1988 Dollars)
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Technology Bolter Main Boiler capacity Coal Capital Capital Amal Amuat MO* MOx Mx Cost
Nuitoer Retrofit Size
Difficulty (HW)
Factor
factor Sulfur
(X) Content
<*>
Cost
(mm
Coat
cs/W)
Coat
(SHH)
Cost
(nills/kwh)
Raaoved
IXJ
Ranoved
(torw/yr J
Effact,
(S/ton)
LNC-LNB
1
1.00
100
58
0.8
2.6
25.5
0.6
1.1
50.0
1104
506.7
LMC-LNB
2
1.00
100
68
0.8
2.6
25.5
0.6
0.9
50.0
1294
432.2
LNC-LNB
3
1.00
125
86
0.8
2.1
22.3
0.6
0.6
40.0
1636
373.7
LNC-LNB-C
1
1.00
100
58
0.8
2,6
25.5
0.3
0.7
50.0
1104
300.7
LNC-LNB-C
2
1.00
100
68
0.8
2.6
25.5
0.3
0.6
50.0
1294
256.5
LNC-LNB-C
3
1.00
12S
16
0.8
2.8
22.3
0.4
0.4
40,0
1636
221.8
SCR-3
1
1.34
too
58
0.8
21.1
210.7
6.9
13.5
80.0
1766
3885.7
SCR-3
2
1.16
100
68
0.8
20.8
208.4
6.7
11.3
80.0
2070
3259.4
SCR *3
3
1.16
125
86
0.8
22.4
179.1
7.8
8.3
80.0
3273
2378.1
SCR-3-C
1
1.34
100
58
0.8
21.1
210.7
4.0
7.9
80.0
1766
2279.8
SCR-3-C
2
1.16
100
68
0.8
20.8
208.4
4.0
6.6
80.0
207B
1912.6
SCR-3-C
3
1.16
125
86
0.8
22.4
179.1
4.6
4.8
80.0
3273
1393,1
SCR-7
1
1.34
100
58
0.8
21.1
210.7
6.0
11.9
80.0
1766
3420.3
SCR-7
2
1.16
100
68
0.8
20.8
208.4
5.9
9.9
80.0
2Q70
2862.4
SGR-7
1
1.16
125
86
0.8
22.4
179.1
6.8
7.2
80.0
3273
2064.2
SCR-7-C
1
1.34
100
58
0.8
21.1
210.7
3.6
7.0
80.0
1766
2013.1
SCR-7-C
2
1.16
100
68
0.8
20.8
208.4
3.5
5.9
80.0
2070
1685.1
SCR-7-C
3
1.16
125
66
0.8
22.4
179.1
4.0
4.2
80.0
3273
1213.4
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12-28
-------
TABLE 12.1.4-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR J. R. WHITING UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 938
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 30
TOTAL COST (1000$)
ESP UPGRADE CASE 968
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
Short duct residence time exists between boilers 1 and 2
and their respective ESPs. A high factor was assigned to
ESP upgrade due to the lack of space around the ESPs.
12-29
-------
TABLE 12.1.4-7, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR J. R. WHITING UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS ¦
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1145
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 35
TOTAL COST (1000$)
ESP UPGRADE CASE 1180
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
Short duct residence time exists between the boiler and the
ESPs. A high factor was assigned to ESP upgrade due to the
lack of space around the ESPs.
12-30
-------
Table 12,1.4-8, Smmary of OSO/FSI Control Costs for the Whiting plant Uine 1988 Oollart)
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
$02
S02
S02 Cost
Nonber
Retrofit
Size
Factor $ulfur
Cost
Cost
Cost
Coat
Removed Removed
Effect.
Difficulty (HW)
m
Content
ts/kw)
.........
........
.......
...........
......
..........
DSB+I5P
1
1,00
100
sa
0.8
6.5
65.4
5.1
10,0
49.0
1595
3199.6
DSD+ISP
2
1.00
100
68
0.8
6.5
65.4
5.3
8.8
49.0
1870
2807.8
DSD+ESP
3
1.00
125
86
0.8
7.6
60.5
6.1
6.5
49.0
2957
2064.8
DSD'ESP-C
1
1.00
100
58
0.8
6.5
65.4
3.0
5.8
49.0
1595
1851.6
DSD*ESP»C
2
1.00
100
68
0.8
6.5
65.4
3.0
5.1
49.0
1870
1624.4
DSD+ESP-C
3
1.00
125
86
0.8
7.6
60.5
1.5
3.8
49.0
2957
1194.5
F5I~ESP-SO
1
1.00
100
58
0.8
7.1
71.1
4.1
8.1
50.0
1640
2510.4
FSI»ESP*50
2
1.00
100
6a
0.8
7.1
71.1
4.3
7.2
50.0
1922
2238.0
FS5*ESP-50
3
1.00
125
86
0.8
8.0
63.9
5.2
5.6
50.0
3039
1725.1
fSl+ESP-SO-C
1
1.00
100
58
0.8
7.1
71.1
2.4
4.7
50.0
1640
1457,8
FSI+ESP-50-C
2
1.00
100
68
0,8
7.1
71.1
2.5
4.2
50.0
1922
1298.8
FS1+ESP-50-C
3
1,00
125
86
0.8
8.0
63.9
3.0
3.2
50.0
3039
1000.2
FS1+ESP-70
1
1.00
100
58
0.8
7.2
71.9
4.2
8.2
70.0
2295
1812.0
FSI*ESP-70
2
1.00
100
68
0.8
7.2
71.9
4.3
7.3
70.0
2691
1616.2
FSl*ESP-70
3
1,00
125
66.
0.8
8.0
64.3
5.3
5.6
70.0
4254
1245.3
FSS-eSP-70-C
1
1.00
100
58
0.8
7.2
71.9
2.4
4.8
70.0
2295
1052.2
?SI*ESP-70-C
2
1.00
100
68
0.8
7.2
71.9
2.5
4.2
70.0
2691
938.0
fSiȣSP-?0-C
3
1.00
125
86
0.8
8.0
64.3
3.1
3.3
70.0
4254
722.0
-sss^ssssssssssssssssasssssaissmsssasaBaaraassaaiaraaKMKaiaiavKaiKttssaixcsssaaKaiaKvaaaaavKBaKKaiMMaaiJiMaiaiasaMJiaraixswaBssaiaBK
12-31
-------
12.2 DETROIT EDISON COMPANY
12.2.1 Monroe Steam Plant
The Monroe steam plant is located on the Raisin River in Monroe County,
Michigan, and is part of the Detroit Edison Company. The Monroe plant
contains four coal-fired boilers with a gross generating capacity of
3,000 MW.
Table 12.2.1-1 presents operational data for the existing equipment at
the Monroe plant. Coal shipments are received by railroad and transferred to
a coal storage and handling area east of the plant. PM emissions from the
boilers are controlled by ESPs installed at the time of construction. All
four ESPs are located behind the boilers. Flue gas from boilers 1 and 2 is
directed to one chimney and the flue gas from boilers 3 and 4 is directed to
another chimney. Fly ash from the units is disposed of in an ash pond south
of the plant or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for all the units would be 1ocated behind the
chimneys. The general facilities factor would be high (15 percent) due to
the necessity for relocation of some storage buildings, sluice lines, and
roads. A medium site access/congestion factor was assigned to the FGD
absorber locations for units 1 and 2 because of the constraints created by
the office building and oil tanks. After demolition, a low site access/
congestion factor was assigned to the FGD absorber locations for units 3 and
4. Approximately 400 feet of ductwork would be required for all of the
units. A low site access/congestion factor was assigned to flue gas
handling. Cost includes a new chimney liner.
LSD with reuse of the existing ESPs was considered for units 3 and 4
because of the adequate sizes of their ESPs. Because units 1 and 2 have
smal1 ESPs, LSD with a new baghouse was considered for these two units. The
LSD absorbers would be placed in the same location as the L/LS-FGD
absorbers. Approximately 400 feet of ductwork would be required for units 1
and 2 and about 500 feet would be required for units 3 and 4. Because the
ESPs are close to the boilers, a medium site access/congestion factor was
12-32
-------
TABLE 12.2.1-1. MONROE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)*
REMOVAL EFFICIENCY*
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
lr—1"A'S"'P—A ~4L
* 1988 data.
1,2,3,4
750
58,75,68,80
1971,73,73,74
OPPOSED WALL
469
NO
0.95
12900
7.4
WET DISPOSAL
ON-SITE/PONDS/SOLD
1,1,2,2
RAILROAD/VESSEL
ESP
1971,73,73,74
0.03,0.03,0.019,0.019
98.9,98.9,99.3,99.3
3 5
449,449,674,674
2360
170,170,257,257
265
12-33
-------
assigned to flue gas handling for units 3 and 4. A low site access/
congestion factor was assigned to flue gas handling for units 1 and 2,
Tables 12.2.1-2 and 12.2.1-3 present the retrofit factor inputs to the
IAPCS model for the FGD technologies. Because all boilers are burning low
sulfur coal, costs are not presented here. Estimating FGD costs for low
sulfur coals would result in high unit costs and low levelized annual costs
relative to high sulfur coal application.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC was not considered at the Monroe plant because of the low
sulfur content of the coal already being used.
N0X Control Technologies--
The boilers at the Monroe steam plant are rated at 750 MW. The
combustion modification technique applied to these opposed wall-fired (cell
type) boilers was LNBs. Tables 12.2.1-4 and 12.2,1-5 present a summary of
N0X removal and cost results. It should be mentioned that LNBs on cell type
burners are not yet fully demonstrated on utility boilers.
Selective Catalytic Reduction--
Cold side SCR reactors would be located behind the chimney for each
unit. As in the FGD case, storage buildings and roads would have to be
relocated to provide room for the reactors and a high general facilities
value of 38 percent was assigned to the locations. After demolition, the
SCR reactors would be located in an area with a low site access/congestion
factor. About 400 feet of ductwork would be required for all units.
Tables 12.2.1-4 and 12.2.1-1 present the retrofit factors and cost for
retrofiting SCR at the Monroe plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for
units 3 and 4 at the Monroe plant, despite the short distance between the
boilers and the ESP units, because of the adequate sizes of the ESPs. The
existing ESPs and inlet ductors would have to be modified to provide
adequate duct residence time for slurry injection or humidification.
12-34
-------
TABLE 12.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR MONROE
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
5708
NA
0
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.27
ESP UPGRADE
NA
NA
, NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
15
0
15
12-35
-------
TABLE 12.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR MONROE
UNIT 3 OR 4
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
5708
NA
5708
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.38
NA
ESP REUSE CASE
1.38
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
12-36
-------
TABLE 12.2.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR MONROE
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3,4
FIRING TYPE
OWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (1000 CU FT)
469
469
BOILER INSTALLATION DATE
1971,
73 1973,74
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
43
43
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
123
123
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
6442
6442
New Heat Exchanger (1000$)
6244
6244
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
12808
19333
12808
19333
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
38
38
12-37
-------
Table 12.2.1-5. NOx Control Cost Results for the Monroe Plant (June 1988 Dollars}
ssssssssaass
¦ssssssa
ESS98SBSB
sssasmsaiB
¦ssssssas
5S3SSSBS
sstistaii
Eassassaa
IBSSBSSS
sssssszssarsa
sssaass
BSSSSSSSS
S8SSSSS3S
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capi tal
Annual
Annual
NO*
NOx
NO* Cost
NiMber
Retrofit
Size
factor
Sulfur
Cost
Cost
Cost
Cost
Removec
Removed
Effect,
Difficulty (KV>
Content
(SfflD
!S/kW)
(SUM)
£m(1Is/kwh >
m
(tons/yr)
<$/ton)
Factor
m
-
LNC-INB
1
1.00
750
58
1.0
5'. 7
7.6
1.3
0.3
43.0
6551
194.8
LNC-LMB
2
J.00
730
75
1.0
1.7
7.6
1.3
0.3
43.0
8471
150.7
LNC-LNS
3
1.00
750
68
1.0. '
5.7
7.6
1.3
0.3
43.0
7681
166.2
LNC-LNB
4
1.00
750
80
1.0
5.7
7.6
1,3
0.2
43.0
9036
141,2
LNC-LNB-C
1
1,00
750
58
1.0
5.7
7.6
0.8
0.2
43.0
6551
115.5
LNC-LNB-C
2
1.00
750
75
1.0
5.7
7.6
0.8
0.2
43.0
8471
89.3
LNC-LNB-C
3
1.00
750
68
1.0
5.7
7.6
0.8
0.2
43.0
7681
98.5
LHC-LN8-C
4
1.00
750
80
1.0
5.7
7.6
0.8
0.1
43.0
9036
63.8
SCR-3
1
1.16
750
58
1.0
95.4
127.2
35.6
9.3
80,0
12188
2919.7
SCR-3
2
1.16
750
75
1.0
¦95.4
127,2
36,4
7.4
80.0
15760
2309.5
SCR-3
3
1.16
750
68
1.0
95.4
127.2
36.1
8.1
80,0
14289
2523.3
SCR-3
4
1.16
750
80
1.0
95.4
127.2
36.6
7.0
80.0
16811
2180.0
SCR-3
1-2
1.16
1500
67
1.0
173.0
118.6
69.0
7.8
80.0
28159
2449.3
SCR-3
3-4
1.16
1500
74
1.0
178,0
118.7
69.6
7.2
80.0
31100
2239.4
SCR-3-C
1
1.16
750
58
1.0
95.4
127.2
20.8
5.5
80.0
12188
1707.9
SCR-3-C
2
1.16
750
75
1.0
95.4
127,2.
21.3
4.3
80.0
15760
1350.3
SCR-3-C
3
1.16
750
68
1.0
95.4
127.2
21.1
4,7
80.0
14289
1475.6
SCR-3-C
4
1.16
750
80
1.0
95.4
. 127.2
21.4
4.1
80.0
16811
1274.5
SCR-3-C
1-2
1.16
1500
67
1.0
178.0
118.6
40.3
4.6
80.0
28159
1431.6
SCR-3-C
3-4
1.16
1500
74
1,0
178.0
118.7
40.7
4.2
80.0
31100
1308.7
SCR-7
1
1.16
750
58
1.0
95.4
127.2
29.5
7.7
80.0
12188
2419.5
SCR-7
2
1.16
750
75
1.0
95.4
127.2
30.3
6.1
80.0
5 15760
1922,6
SCR-7
3
1.16
750
68
1.0
95,4
127.2
30.0
6,7
80.0
14289
2096.6
SCR-7
4
1.16
750
80
1.0
95,4
127.2
30.6
5.8
80.0
16811
1817.4
scs-7
1-2
1.16
1500
67
1.0
178.0
118.6
56.8
6.4
80.0
28159
2016,2
SCR-7
3-4
1.16
1500
74
1.0
178.0
118.7
57.5
5,9
80.0
31100
1847.3
SCR-7-C
1
1,16
750
58
1,0
95.4
127.2
17,3
4.5
80.0
12188
1421.3
SCR-7-C
2
1,16
750
75
1.0
95.4
127.2
17.8
3.6
80.0
15760
1128,7
SCR-7-C
3
1.16
750
68
1.0
95,4
127.2
17.6
3.9
80.0
14289
1231.2
SCR-7-C
4
1.16
750
80
1.0
95.4
127.2
17,9
3.4
80.0
16811
1066.7
SCR-7-C
1-2
1.16
1500
67
1.0
178.0
118.6
33.3
3.8
80.0
28159
1183.5
SCR-7-C
3-4
1.16
1500
74
1.0
178.0
118.7
33.7
3.5
80.0
31100
1084.1
ss::S3s:ssss8s:ss83s«ssess;:z::s8s:s5:sscssssss6:sa::3:ssss:s:ss3s:s::s9tssassss8=si;ssat3iaisESsaiaaasssitafiai
12-38
-------
Units 1 and 2 were not considered for sorbent injection technologies due to
their small ESPs and short duct residence time. Table 12.2.1-6 gives a
summary of retrofit factors for FSI and DSD technologies at the Monroe
plant. Separate retrofit factors have been developed for upgrading the ESPs
to accommodate FSI and DSD technologies. Table 12.2.1-7 presents the cost
for installation of FSI and DSD at the Monroe plant.
Atmospheric F1uidized Bed Combustion and Coal Gasification Applicabi1ity--
The 750 MM boilers at the Monroe plant are too large and too new to be
considered for AFBC/CG technologies.
12-39
-------
TABLE 12.2.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MONROE UNIT 3 OR 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 5708
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 136
TOTAL COST (1000$)
ESP UPGRADE CASE 5844
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
12-40
-------
Table 12.2.1-7. Sutmary of DSD/FSt Control Costs for the Monroe Plant {June 1988 Collars)
Technology Boiler Main Boiler Capacity Coat Capital Capital Arvuial Annual S02 S02 S02 Cost
Ntmber Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMU) <*> Content (MM) (I/kW) (MM) (mills/kwh) (%} (tons/yr) (S/ton)
Factor . (%)
0SD+ESP
DSD*SSP
0SDȣSP*C
OSD+ESP-C ¦
FS!*ESP-50
FSHESP-50
fsi+esp-so-c
FS1+ESP-50-C
00
00
00
00
00
CO
00
0Q
750
750
750
750
750
750
750
750
63
80
68
80
68
80
68
80
1.0
1.0
25.3
25.3
25.3
25.3
31.1
31.1
31.1
31.1
33.7
33.7
33.7
33.7
41.4
41.4
41.4
41.4
16.6
17.9
9.6
10.4
19.9
21.8
11.6
12,6
3.7
3.4
49.0 .
49.0
49.
49.
50.
50.
50.
SO.
16138
18986
16138
18986
16586
19513
16586
19513-
1030.0
942.1
597.2
545.7
1201.3
1118.6
696.7
648.0
FSi~ESP-70
FSI+ESP-70
1.00
1.00
750
750
63
80
31.2
31.2
41.6
41.6
20.2
22.2
4.5
4.2
70.0
70.0'
23220
27318
870.2
810.9
FS1+ESP-70-C
FSI+£SP"70-C
1.00
1.00
750
750
68
SO
31.2
31.2
41.6
41.6
11.7
12.8
2.6
2.4
70.0
70.0
23220
27318
504.6
469.7
12-41
-------
12.2.2 River Rouge Steam Plant
Both of the coal-fired boilers at the River Rouge plant are currently
burning a low sulfur coal; therefore, CS was not evaluated. Although
retrofit factors for FGD were developed for these boilers, costs are not
shown because the low sulfur coal would yield high unit costs per ton of S02
removed.
TABLE 12.2.2-1. RIVER ROUGE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1
GENERATING CAPACITY (MW) 283
CAPACITY FACTOR (PERCENT)* PETROLEUM
INSTALLATION DATE BURNING
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER 1
COAL DELIVERY METHODS
2
239
56
1957
3
267
45
1958
TANGENTIAL FRONT WALL
147 188
NO NO
0.8
12000
10.5
DRY DISPOSAL
PAID DISPOSAL/SOLD
2 3
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)*
REMOVAL EFFICIENCY*
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
1978
0.001
99.99
0.5
1027
1168
880
325
ESP
1978
0.002
99.99
0.5
1211
1328
912
320
* 1988 data.
12-42
-------
TABLE 12.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR RIVER ROUGE
UNITS 2 OR 3*
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
0
NA
0
NEW CHIMNEY+
YES
NA
NO
ESTIMATED COST (1000$)
2760,3084 0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.56
NA
ESP REUSE CASE
1.62
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
10
* Absorbers for units 2 and 3 would be located west of the
unit 3 ESPs.
+ Chimney cost for a 660-foot stack was included.
12-43
-------
TABLE 12,2.2-3. SUMMARY OF NOx RETROFIT RESULTS FOR RIVER ROUGE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
2
3
FIRING TYPE
TANG
FWF
TYPE OF NOx CONTROL
OFA
LNB
FURNACE VOLUME (1000 CU FT)
147
188
BOILER INSTALLATION DATE
1957
1958
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
48
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
52
56
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
3300
3521
New Heat Exchanger (1000$)
3144
3360
TOTAL SCOPE ADDER COSTS (1000$)
6495
6937
RETROFIT FACTOR FOR SCR
1.52
1.34
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for unit 2 would be located east of the
unit 2 ESPs, and the reactors for unit 3 would be located beside
(west of) the unit 3 ESPs.
12-44
-------
Table 12.2.2-4. NOx Control Cost Results for the River Rouge Plant (June 1988 Collars)
Technology Soiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nurtoer Retrofit Size Factor Sulfur Cast Cost Cost Cost Removed Removed Effect.
Difficulty CHU) «) Content (*HN) (S/kU) ($MM5 (mitIs/kwh> (X) (tons/yr! CVton)
Factor (S)
LNC-LN8 3 1.00 267 45 0.8 3.3 14.2 0.8 0.8 48.0 2195 384.7
LNC-LN8-C 3 1.00 267 '45 0.8 3.8 14.Z 0.5 0.5 48.0 2195 228.1
LNC-0FA 2 ' 1.00 239 56 0.8 0.9 3.7 0.2 0.2 25.0 910 215.5
INC-OFA-C 2 1.00 239 56 0.8 0.9 3.7 0.1 0.1 25.0 910 127.8
SCR-3 2 1.52 239 56 0.8 43.1 180.5 14.4 12.3 80.0 2910 4963.4
SCR-3 3 1.34 267 45 0.8 43.6 163.4 14.9 14.2 80.0 3658 4075.7
SCR-3-C 2 1.52 239 56 0.8 43.1 180.5 8.5 7.2 80.0 2910 2910.2
SCR-3-C 3 1.34 267 45 0.8 43.6 163.4 8.7 8.3 80.0 3658 2388.6
SCR-7 2 1.52 239 56 0.8 43.1 180.5 12.5 10.6 80.0 2910 4288.6
SCR-7 3 1.34 267 45 0.8 43.6 163.4 12.7 12.1 80.0 3658 3475.9
SCR-7-C 2 1.52 239 . 56 0.8 43.1 180.5 7.3' 6.3 80.0 2910 2523.5
SCR-7-C 3 1.34 267 45 0.8 43.6 163.4 7.5 7.1 80,0 36S8 2044.9
12-45
-------
TABLE 12.2.2-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR RIVER ROUGE UNIT 2 OR 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 0
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 57,62
TOTAL COST (1000$)
ESP UPGRADE CASE 57,62
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
The duct residence time is medium for unit 2 arid long for
unit 3. ESP upgrade for both units would be difficult due
to the lack of available space around the ESPs.
12-46
-------
Table 12.2.2-6. Swirary of BSD/FSI Control Costs for the River Rouge Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 . SQ2 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (KM) (X) Content <$MM> (S/kV) (SHM) (mi ILsAwh) <%)i (tcns/yr)
Factor <%5
OSD+ESP
DSO-ESP
1.00
1.00
239
267
56
45
0.8
0.8
9.2
9.7
38.4
36.5
7.4
7.4
6.3
7.0
49.0
49.0
3681
3305
2007.9
2226.9
DSD+ESP-C
DSD+E5P-C
1.00
1.00
239
267
56
45
o.a
0.8
9.2
9.7
38.4
36.5
4.3
4.3
3.6
4.0
49.0
49.0
3681
3305
1161.6
1289.1
FSI-iSP-50
FSI+ESP-5Q
1,00
1.00
239
267
56
45
0.8
0.8
9.5
10.1
39.6
37.8
6.4
6.3
5,4
6.0
50.0
50.0
3783
3396
1688.2
1856.5
FSI+ESP-50-C,
FSJ+6SP-50-C
1.00
1,00
239
267
56
45
0.8
0.8
9.5
10.1
39.6
37.8
3.7
3.7
3.2
3.5
50.0
50.0
3783
3396
978.5
1077.0
FSr+ESP-70
FSi+ESP-70
1.00
1.00
239
267
56
45
0.8
0.8
9.6
10.2
40.1
38.3
6.5
6.4
5.5
6.1
70.0
70.0
5297
4755
1222.7
1343.9
FSJf|SP-70*C
FSI+ESP-70-C
1.00
1.00
239
267
56
45
0.8
0.8
9.6
10.2
40.1
38.3
3.8
3.7
3.2
3.5
'70.0
70.0
5297
4755
708.6
779.6
12-47
-------
12.2.3 St. Clair Steam Plant
Retrofit factors were developed for the boilers at the St. Clair plant;
however, costs are not presented since the boilers fire a low sulfur coal.
In addition, CS was not evaluated since the boilers currently fire a low
sulfur coal. Sorbent injection technologies (FSI and DSD) were not
evaluated for unit 7 due to the short duct resdence time between the boiler
and the ESPs and due to the inadequate size of the ESPs.
TABLE 12.2.3-1. ST. CLAIR STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
1000 CU FT)
ON
ENT (PERCENT)
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTFM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3,4 5
163,152 163,164 358
52,64 63,66
1953 1954 1959
FRONT WALL CYCLONE
75.3 75.3 112
6 7
294 -435
60 37
1961 1969
TANGENTIAL
204 270.4
PETROLEUM NO
BURNING
NO NO
0.5
9500
4 5
DRY DISPOSAL
PAID DISPOSAL/SOLD
1 1 2 3
VESSEL/RAILROAD
NO
0.7
9800
5.2
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE
EMISSION (LB/MM BTU)* 0.015
REMOVAL EFFICIENCY* 99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
1976,77 1977
0.015
99.4
.6
538.1 538.1
751 751
717 717
330 330
ESP ESP
1982 1969
0.00 0.040
99.99 98.5
964.3 270.4
1320 1466.5
730
292
184
307
1988 data,
12-48
-------
TABLE 12.2.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR ST. CLAIR
UNITS 1, 2, 3, AND 4 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH .
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE
100-300
, ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
' HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
-
FGD SYSTEM
1.61
. NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.54
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58,
GENERAL FACILITIES (PERCENT)
15
0
15
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for units 1,
2, 3 and 4 would be located beside their common chimney.
12-49
-------
TABLE 12.2.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR ST. CLAIR
UNIT 6*
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
¦ NA
HIGH '
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY+
YES
NA
YES
ESTIMATED COST (1000$)
3696
0
3696
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.67
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.73
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58 ,
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 6
would be located northeast of unit, 7.
+ Chimney cost for a 660-foot stack was included.
12-50
-------
TABLE 12.2.3-4. SUMMARY OF RETROFIT FACTOR DATA FOR ST. CLAIR
UNIT 7 *
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD
OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
,FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.53
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.54
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 7
would be located north of unit 7.
12-51
-------
TABLE 12.2.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR ST. CLAIR UNITS 1-4
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1. 3
2
4
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
FURNACE VOLUME (1000 CU FT)
75.3
75.3
75.3
BOILER INSTALLATION DATE
1953,54
1953
1954
SLAGSING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
32
32
32
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS-
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
39
39
39
New Duct Length (Feet)
200
200
200
New Duct Costs (1000$)
1319,
1314
1324
New Heat Exchanger (1000$)
2499
2490
2508
TOTAL SCOPE ADDER COSTS (1000$)
3857
3842
3871
RETROFIT FACTOR FOR SCR
1.34
1.34
1.34
GENERAL FACILITIES (PERCENT)
38
38
38
* Cold side SCR reactors for units I, 2, 3 and 4 would be
behind their common chimney.
12-52
-------
TABLE 12.2.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR ST. CLAIR UNITS 6-7
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1-4 6 7
FIRING TYPE NA TANG TANG
TYPE OF NOx CONTROL NA OFA OFA
FURNACE VOLUME (1000 CU FT) NA 204 270.4
BOILER INSTALLATION DATE NA 1961 1969
SLAGGING PROBLEM NA NO NO
ESTIMATED NOx REDUCTION (PERCENT) NA 25 25
SCR RETROFIT RESULTS *
- SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM HIGH MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0 0
Ductwork Demolition (1000$) 110 61 81
New Duct Length (Feet) 200 200 200
New Duct Costs (1000$) 2968 1862 2342
New Heat Exchanger (1000$) 5741 3560 4503
TOTAL SCOPE ADDER COSTS (1000$) 8819 5483 6926
RETROFIT FACTOR FOR SCR 1.34 1.72 1.34
GENERAL FACILITIES (PERCENT) 38 38 20
* Cold side SCR reactors for units 6 and 7 would be located
behind their respective chimneys,
12-53
-------
Table 12.2.3-?. NOx Control Cost Results for the St. Clair Plant {June 1988 Dollars)
Technology
Boi t er
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NO*
NOx
NOx Cost
Number
Retrofit
Size
factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
(%!
Content
C*MM)
(SMM)
{mi Its/kwh)
(%>
(tons/yr)
(S/ton)
factor
(S)
IMC-LNB
1
1.00
163
52
0.5
3.1
19.1
0.7
0.9
32.0
1350
513.6
INC-INB
2
1.00
162
64
0.5
3.1
19.1
0.7
0.8
32.0
1651
418,9
LNC-LNB
3
1.00
163
63
0.5
3.1
19.1
0.7
0.8
32.0
1635
423.9
lNC-i.NI
4
1.00
164
66
0.5
3.1
19.0
0.7
0.7
32.0
1724
403.1
INC-LNi-C
1
1.00
163
52
0.5
3.1
19.1
0.4
0,6
32.0
1350
. 304.6
LNC-LMB-C
2
1.00
162
64
0.5
3.1
19.1
0.4
0.5
32.0
1651
248.4
LNC-INB-C
3
1.00
163
63
0.5
3.1
19.1
0.4
0.5
32.0
1635
251.4
LNC-INB-C
4
1.00
164
66
0.5
3.1
19.0
0.4
0.4
32.0
1724
239.1
LNC-OFA
6
1.00
294'
60
0.7
1.0
3.2
0.2
0.1
25.0
1512
140.7
INC-QFA
7
1.00
435
37
0.7
1.1
2.6
0.2
0.2
25.0
1380
180.4
LNC-OFA-C
6
1.00
294
60
0.7
1.0
3.2
0.1
.0.1
25.0
1512
83.4
INC-OFA-C
7
1.00
435
37
0.7
1.1
2.6
0.1
0.1
25.0
1380
107.0
SCR-3
1
1.34
163
52
0.5
¦ 30.6
188.0
10.5
14.2
SO.O
3374
3119.0
SCR-3
2
1.34
162
64
0.5
30.4
187.5
10.6
11.7
80.0
4127
2565.8
SCR-3
3
1.34
163
63
0.5
30.6
188.0
10.7
11.9
80.0
4088
2607.8
SCR-3
4
1.34
164
66
0.5
30.8
187.6
10.7
11.3
80.0
4309
2493.7
SCS-3
6
1.72
294
60
0.7
56.0
190.4
' 19.0
12.3
80.0
4840
3928.7
SCS-3
7
1.34
435
37
0.7
60.5
139.0
21.7
15.4
80.0
4416
4912.2
SCS-3
1-4
1.34
652
53
0.5
90.8
139.2
33.9
11.2
80.0
13756
2463,2
SCR-3-C ¦
1.
1.34
163
' 52
0.5
30.6
188.0
6.2
8.3
80.0
3374
1827.7
SCR-3-C
2
. 1.34
162
64
0.5
30.4
187.5
6.2
6.8
80.0
4127
1503.0
SC8-3-C
3
1.34
163
63
0.5
30.6
188.0
6.2
6.9
80.0
4088
1527.7
SCR-3-C
4
1.34
164
66
0.5
30.8
187.6
6.3
6.6
80.0
4309
1460,7
SCR-3-C
6
1.72
294
60
0.7-
56.0
190.4
. 11.1
7.2
80.0
4840
2302.7
SCR-3-C
7
1.34
435
37
0.7
60.5
139.0
12.7
9.0
80.0
4416
2875.8
SCR-3-C
1-4
1.34
652
53
0.5
90.3
139.2
19.8
6.5
80.0
13756
1440.8
SC»-7
1
1.34
163
52
0.5
30.6
188.0
9.1
12.3
80.0
3374
2708.0
SCR-7
2
1.34
162
64
0.5
30.4
187.5
9.2
10.1
80.0
4127
2231.9
s:r-7
3
1.34
163
63
0.5
30.6
138.0
9.3
10.3
80.0
4088
2268.6
SCR-7
4
1.34
164
66
0.5
30.8
187.6
9.3
9.9
80.0
4309
2169.9
SCR-7
6
1.72
294
60
0.7
56.0
190.4
16.5
10.7
80.0
4840
3414.3
SCR-7
7
1.34
435
37
0.7
60.5
139.0
. 18.0
12.8
SO.O
4416
4078.1
SCR-7
1-4
1.34
652
53
0.5
90.8
139.2
28.3
9.4
80.0
13756
2060.0
SCR-7-C
1
1.34
163
52
0.5
30.6
188.0
5.4
7.2
80.0
3374
1592.2
SCR-7-C
2
1.34
162
64
0.5
30.4
187.5
5.4
6.0
80.0
4127
1311.7
SCR-7-C
3
1.34
163
63
0.5
30.6
188.0
5.5
6.1
80.0
4088
1333.4
SCR-7-C
4
1.34
164
66
0.5
30.8
187.6
5.5
5.8
80.0
4309
1275.2
SCR-7-C
6 "
1.72
294
60
0.7
56.0
190.4
9.7
6.3
80.0
4840
2008.0
SCR-7-C
7
1.34
435
37
0.7
60.5
139.0
10.6
7.5
80.0
4416
2397.9
SCR-7-C
1-4
1.34
652
53
0.5
90.8
139.2
16.6
5.5
80.0
13756
1209.8
12-54
-------
TABLE 12.2.3-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ST. CLAIR UNITS 1, 2, 3, 4 AND 6
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST,(1000$) 43,43,43,43,67
TOTAL COST (1000$)
ESP UPGRADE CASE 43,43,43,43,67
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS __
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE • NA
Long duct residence time exists between the units and their
respective ESPs. A high factor was assigned to ESP upgrade
since little space is available.
12-55
-------
Tabte 12.2.3-9. $ unitary of DSD/PSI Control Costs for the St. Clair Plant (June 1988 Dollars)
Technology
Bo i t er
Main
Boiler Zapacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nunber
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect,
Difficulty (MU)
«>
Content
(SMH)
(*/W)
<»H)
(mills/kwhj
(%}
(tons/yr)
($/ton)
Factor
(%>
DS0+ESP
1
1.00
163
52
0.5
6.1
37.4
5.5
7.4
49.0
1905
2876.5
DSD-E5P
2
1.00
162
64
0.5
6.1
37.5
5,7
6.3
49.0
2331
2438,5
DSD+ESP
3
1.00
163
63
0.5 .
6.1
37.4
5.7
6.3
49.0
2308
2459.5
DSD-ESP
4
1.00
164
66
0.5
6.1
37.3
5.7
6.1
49.0
2433
2361.0
cso-esp
6
1.00
294
60
0.7
9.5
32.3
7.9
5.1-
49.0
5357
1480.8
DSD+ESP-C
1 '
1.00
163
52
0.5
6.1
37.4
3.2
4.3
49.0
1905
1662.4
DSO+ESP-C
2
1.00
162
64
0.5
6.1
37.5
3.3
3.6
49.0
2331
1408.8
DSD+tSP-C
3
1.00
163
63
0.5
6.1
37.4
3.3
3.6
49.0
2308
1421.0
CS3»ESP-C
4
1.00
164
66
0.5 ' ¦
6.1
37.3
3.3
3.5
49.0
2433
1364.0
OSDfESP-C
6
1.00
294
60
0.7
9.5
32.3
4.6
3.0
49.0
5357
856.4
•S1+ESP-5G
1
1.00
163
52
0.5
7.3
45.1
4.7
6.3
50.0
1958
2389.6
FSI+ESP-50
2
1.00
162
64
0.5
7.3
45.2
5.0
' 5.5
50.0
2395
2073.4
FSI~ESP-50
3
1.00
163
63
0.5
7.4
45.1
5.0
5.5
50.0
2372
2089.5
FSI'ESP-50
4
1.00
164
66
0.5
7.4
45.0
5.0
5.3
50.0
2501
2019.5
-FSI+ESP-50
6
1.00
294
60
0.7
10.8
36.6
7.8
5.0
50.0
5505
1417.5
FSI+ESP-50-C
1
1.00
163
52
0.5
7.3
45.1
2.7
3.7
50.0
1958
1385.9
F5I~ESP-SO-C
2
1.00
162
64
0.5
7.3
45.2
2.9
3.2
50.0
2395
1201.6
FSI+ESP-50-C
3
1.00
163
63
0.5
7.4
45.1
2.9
3.2
50.0
2372
1211.1
FSI+SSP-50-C
4
1.00
. 164
66
0.5
7,4
45.0
2.9
3.1
50.0 '
2501
1170.3
fSl+ESP-50-C
6
1.00
294
60
0.7
10.8
36.6
4.5
2.9
50.0
5505
320.9
FSI+ESP-70
1
1.00
163
52
0.5
7.4
45.7
4.7
6.4
70,0
2741
1727.1
FSI*ESP-70
2
1.00
162
64
0.5
7.4
45.8
5.0
5.5
70.0
3353
1499.5
FSl*ESP-70
' 3
1.00
163
63
0.5
7.5
45.7
5.0
5.6
70.0
3321
1511,1
FS1+ESP-70
u
1.00
164
66
0.5
7.5
45.6
5.1
5,4
70.0
3501
1460.7
FSI+E5P-7C
6
1.00
294
60
0.7
10.9
37.1
7.9
5.1
70.0
7707
1028.0
FSl*ESP*70*C
1.
1.00
163
52
0,5
7.4
45.7
2.7
3.7
70.0
2741
1001.7
FSI-ESP-70-C
2
1.00
162
64
0.5
7.4
45.8
2.9
3.2
70.0
3353
869.0
PSI+ESP-70-C
3
1.00
163
63
0.5
7.5
45.7
2.9
3.2
70.0
3321
875.8
FSl*ESP-70-C
4
1.00
164
66
0.5
7.5
45.6
3.0
3.1
70.0
3501
846.5
FSHESP-70-C
6
1.00
294
60
0.7
10.9
• 37.1
4.6
3.0
70.0
SSS3SSS
7707
SS32SSSSS:
595.3
12-56
-------
12.2.4 Trenton Channel Steam Plant
All units at the Trenton Channel plant fire a low sulfur coal.
Although retrofit factors for FGD were developed, costs are not presented
because it is unlikely that the current low sulfur coal would be used if
scrubbing were required. Sorbent injection technologies (FSI and DSD) were
not considered due to the small size of the existing ESPs.
TABLE 12.2.4-1. TRENTON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3,4 5
60 60 500
34 20 62
1949 1949 1968
TANGENTIAL
45 45 270
NO NO NO
0.8
12800
8.4
DRY DISPOSAL
PAID DISPOSAL/SOLD
1 1 2
RAILROAD/VESSEL
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)*
REMOVAL EFFICIENCY*
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
ESP
ESP
ESP
1965
1965
1968
0.015
0.015
0.068
99.5
99.5
97.8
1.0
1.0
1.0
79.9
79.9
270.4
580
580
1530
138
138
177
270
270
270
1988 data.
12-57
-------
TABLE 12.2.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR TRENTON CHANNEL
UNITS 1-4*
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD
OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
100-300
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY+
NO
NA
YES
ESTIMATED COST (1000$)
0
0
693
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.53
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.65
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
15
0
15
* Absorbers and new FFs for units 1-4 would be located north of
the units 1-4 chimney.
+ Chimney cost for a 660-foot stack was included.
12-58
-------
TABLE 12.2,4-3. SUMMARY OF RETROFIT FACTOR DATA FOR TRENTON CHANNEL
UNIT 5 *
F6D TECHNOLOGY
FORCED
LIME
L/LS FGD
OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.73
NA
ESP REUSE CASE
1.74
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
15
* Absorbers and new FFs for unit 5 would be located behing the
unit 5 chimney.
12-59
-------
TABLE 12.2.4-4. SUMMARY OF NOx RETROFIT RESULTS FOR TRENTON CHANNEL UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
45
45
45
BOILER INSTALLATION DATE
1949
1949
1949
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
Ductwork Demolition (1000$)
New Duct Length (Feet)
New Duct Costs (1000$)
New Heat Exchanger (1000$)
TOTAL SCOPE ADDER COSTS (1000$)
2125
2860
3595
RETROFIT FACTOR FOR SCR
1.72
1.72
1.72
GENERAL FACILITIES (PERCENT)
38
38
38
* Cold side SCR reactors for units 1 -3 would located north of
unit 1.
HIGH
HIGH
HIGH
0
0
0
18
18'
18
200
400
600
735
1470
2205
1372
1372
1372
12-60
-------
TABLE 12.2.4-5. SUMMARY OF NOx RETROFIT RESULTS FOR TRENTON CHANNEL UNITS 4-5
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
1-4
5
FIRING TYPE
TANG
NA
TANG
TYPE OF NOx CONTROL
OFA
NA
OFA
FURNACE VOLUME (1000 CU FT)
45
NA
270
BOILER INSTALLATION DATE
1949
NA
1968
SLAGGING PROBLEM
NO
NA
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
NA
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
18
52
90
New Duct Length (Feet)
800
800
200
New Duct Costs (1000$)
2940
6615
2541
New Heat Exchanger (1000$)
1372
3152
4895
TOTAL SCOPE ADDER COSTS (1000$)
4330
9819
7527
RETROFIT FACTOR FOR SCR
1.72
1.72
1.72
GENERAL FACILITIES (PERCENT)
38
38
38
* Cold side SCR reactors for unit 4 and units 1-4 would be located
north of unit 1. Cold side SCR reactors for unit 5 would be
located behind the unit I chimney.
12-61
-------
Table 12.2.4-6. NOx Control Cost Results for the Trenton Channel Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
'Effect.
Oiffieulty (HW)
(X)
Content
(SHH)
(S/kW)
(two
(miILs/kwh)
<%)
(toris/yr)
{$/teri5
............
.........
Factor
.........
(xy
.........
.........
........
............
.......
..........
.........
LNC-QFA
1
1.00
60
34
a.a
0.5
8.4
0.1
0.6
25.0 .
129
875.5
LNC-QFA
2 ¦
'1.00
60
34
o.a
0.5
8.4
0.1
0.6
25.0
129
875.5
LNC-OFA
3
1.00
' 60
20
0.8
0.5
8.4
0.1
1.1
25.0
76
1488.3
INC-OFA
4
1.00
60
20
0.8
0.5
8,4
0,1
1.1
25.0
76
1488.3
LNC-CFA
5 .
1.00
500
62
0.8'
1.2
2.4
0.3
0.1
25.0
1956
134.4
INC-OFA-C
1
1.00
60
34
0.8
0.5
8.4
0.1
0.4
25.0
129
518.9
INC-OFA-C
2
1.00
60
34
0.8
0.5
8.4
0.1
0.4
¦ 25.0
129
518.9
INC-OFA-C
3
1.00
60
20
0.8
0.5
8.4
0.1
0.6
25.0
76
882.2
LNC-OFA-C
4
1.00
60
20
0.8 ,
0.5
8.4
0,1
' 0.6
25.0
76
882.2
L-NC-QFA-C
5
1.00
¦ 500
62
0.8
1.2
2,4
0.2
0,1
25.0
1956
79.7
SCR-3
1
1.72
60
34
0.8
19.3
321.6
5.9
33.1
¦80.0
412
14375.8
SCR *3
• 2 ¦
1.72
60
34
0.8
20.0
334.1
6.1
33.9
80.0
412
14694.8
SCR-3
3
1.72
60
20
0.8
20.8
346.6
6.1
58.5
80.0
242
25366,1
SCR-3
4
1.72
60
20
0.8
21.5
359.1
6.3
59.7
80.0
242
25908.8
SCR-3
1-4
1.72
240
27
0.8
52.1
217.0
16.2
28.5
80.0
1309
12344,6
SCR-3
5
1.72
• 500
. 62
0.8
83.2
166.5
29.0
10.7
80.0
6260
4628.6
SCR-3-C
1
1.72
60
34
0.8
19.3
321.6
3.5
19.5
80.0
412
8446.4
SCR-3-C
2
1.72
60
3'
0.8
20.0
334.1
3.6
19.9
80.0
412
8637.4
SCR-3-C
3
1.72
60'
20
0.8
20.8
346.6
3.6
34.4
80.0
242
14917.6
SCR-3-C
4
1.72
60
20
0,8
21.5
359.1
3.7
35.1
80.0
242
15242.4
SCR-3-C
1 -4
1.72
240
27
0,8
52.1
217.0
9.5
16.7
80.0
1309
7251.2
SCR-3-C
5
1.72
500
62
0.8
83.2
166.5
17.0
6.3
80.0
6260
2711.5
SCR-7
. 1
1.72
60
34
0.8
19.3
321.6
5.4
30.4
80.0
412
13190.6
SCR-7
2
1.72
60
34
0.8
20.0
334.1
5.6
31.1
80.0
412
13509.6
SCR-7
3
1.72
60
20
0.8 '
20.8
346.6
5.7
53.8
80.0
242
23351.4
SCR-7
4
1.72
60s
20
0.8
¦ 21.5
359.1
5.8
55.1
80.0
242
23893.6
SCR-7
1-4
1.72
240
27
0.8
52.1
217.0
14.2
25.0
80.0
1309
10851.7
SCR-7
5
1.72
500
62
0.8
83.2
166.5
24.9
9.2
80.0
6260
3978,5
SCR-7-C
1
1.72
60
34
o.a
19.3
321.6
3.2
17,9
80.0
412
7767.4
SCR-7-C
2
1.72-.
60
34
0.8
20.0
334.1
3.3
18.3
80.0
412
7958.4
SCR-7-C
3
1.72
60
20
0.8
20.8
346.6
3.3
31.7
80.0
242
13763.3
SCR.-7-C
4
1.72
60
20
0,8
21.5
359.1
3.4
32,5
80.0 .
242
14088.1
SCR-7-C
" 1-4
1.72
240
27
0,8
12.1
217.0
8.4
14.7
80.0
1309
6395.7
SCR-7-C
,5
1.72
500
62
0.8
83.2
166.5
14.6
5.4
80.0
6260
2339.0
SSSS3II1SIBSS1ItlBSllllSSSSSSS
........
ISSSSSSS
HHBas
3SIIIIISSSK
¦353911911
!s£s:s:ss
12-62
-------
12.3 UPPER PENINSULA POWER COMPANY
Presaue Isle Steam Plant
All units at the Presque Isle plant fire a low sulfur coal, hence CS
was not evaluated. Although retrofit factors for FGD were developed, costs
are not shown because the low sulfur coal would result in high unit costs.
Retrofit factors and costs were not developed for sorbent injection because
of the small ESPs and short duct residence time between the boilers and
ESPs.
TABLE 12.3.1-1 PRESQUE ISLE STEAM PLANT OPERATIONAL DATA3
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT]
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
1
2
3
4
25
37
56
57
8*
13*
43
46
1955
1962
1964
1966
WALL
TANGENTIAL
15.0
NA
NA
28.8
NO
NO
NO
NO
0.8
12400
8.9
DRY DISPOSAL
LANDFILL/ON-SITE
1
1
1
1
SHIP
ESP
ESP
ESP
ESP
1973
1973
1973
1973
<0.27
<0.24
<0.24
<0.24
97.5
98.2
98.2
93.4
<1.0
<1.0
<1.0
<1.0
23.8
32.8
38.9
38 ¦ 9
126.5
176.8
217
217
188
186
179
179
370
386
330
330
(Continued]"
12-63
-------
TABLE 12.3.1-1 PRESQUE ISLE STEAM PLANT OPERATIONAL DATA
(CONTINUED...)
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
5,6 7,8 9
84,85 81,83 84
53,61 67,70 66
1974,75 1978 1979
FRONT WALL OPPOSED WALL
46.8 NA
NO YES
0.8 0.5
12400 8900
8.9 6.7
DRY DISPOSAL
LANDFILL/ON-SITE
1 2
SHIP
NA
YES
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE
(°F)
ESP
ESP
ESP
1973
1973
1973
<0.20
0.03
0.03
99.6,99.5
99.5,99.6
99.6
<1.0
<1.0
<1.0
84.2
84.2
84.2
286.5
313.3
313.3
294
269
269
290
730
730
a Some information was obtained from plant personnel
* Units 1 and 2 are operated when required.
12-64
-------
TABLE 12,3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR PRESQUE ISLE
UNITS 1-6 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
600-1000
NA
ESP REUSE
NA
BAGHOUSE
600-1000
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
2485
0
2485
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.76
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.83
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
15
0
15
* Absorbers and new FFs for units 1-6 would be located north of
unit 9. Units 7-9 were not evaluated because they are NSPS units.
12-65
-------
TABLE 12,3.1-3, SUMMARY OF NOx RETROFIT RESULTS FOR PRESQUE ISLE *
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
2,3,4
5,6
7-9
FIRING TYPE
TANG
FWF
NA
TYPE OF NOx CONTROL
OFA
LNB
NA
FURNACE VOLUME {1000 CU FT)
NA,NA,
28.8
46.8
NA
BOILER INSTALLATION DATE
1962,64,66
1974,75
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
36
NA
SCR RETROFIT RESULTS
BOILER NUMBER
1-6
7-9
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
70
57
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
2079
1772
New Heat Exchanger (1000$)
3986
0
TOTAL SCOPE ADDER COSTS (1000$)
6135
1829
RETROFIT FACTOR FOR SCR
1.72
1.72
GENERAL FACILITIES (PERCENT)
38
38
* Unit 1 is too small to be evaluated for LNBs. Cold side SCR
reactors for units 1-6 would be located behind the unit 1-6
chimney. Hot side SCR reactors for units 7-9 would be located
behind the unit 7-9 chimney.
12-66
-------
Table 12.3.1-4. NOx Control Cost Results for the Prasqu* 1st* Plant (Jim. 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nurter Retrofit Size Factor Sulfur Cost Cost Cost- Cost Removed Removed Effect.
Difficulty (miUs/kwhJ (X)
-------
SECTION 13.0 MINNESOTA
13.1 MINNESOTA POWER AND LIGHT COMPANY
13.1.1 Clay Boswell Steam Plant
The Clay Boswell steam plant is located on Blackwater Lake in Itasca
County, Minnesota, and is operated by the Minnesota Power and Light Company
The Boswell plant contains four coal-fired boilers with a gross generating
capacity of 969 MW.
Table 13.1.1-1 presents operational data for the existing equipment at
the Boswell plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area south of the plant. PM emissions from
the boilers are controlled by retrofit FFs for units 1 and 2 and by wet
scrubbers for units 3 and 4. Unit 4 also has a hot side ESP system. Flue
gases from boilers 1, 2, and 3 are directed to a chimney located south of
unit 3 and the chimney for unit 4 is located behind unit 4. Fly ash from
the units is disposed of in ponds west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS or LSD-FGD technologies were not considered for units 3 and 4
because these units already have LSD-FGD systems installed. L/LS-FGD
absorbers for units 1 and 2 would be located south of the unit 1 FF.
Because no significant demolition or relocation would be required, the
general facilities factor is low (5 percent) for this location. However,
the site access/ congestion factor is medium for this location because of
the proximity of the water pond, chimney, and the unit 3 sludge dewatering
area. About 300 to 500 feet of ductwork would be required for installation
of the L/LS-FGD system and a low site access/congestion factor was assigned
to flue gas handling.
LSD with reuse of the existing baghouses was considered for units
1 and 2. The LSD-FGD absorbers would also be located on the south side of
the unit 1 FF similar to the L/LS-FGD absorbers. About 400 to 600 feet of
duct-work would be required and a high site access/congestion factor was
13-1
-------
TABLE 13.1.1-1. CLAY BOSWELL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FT)
1000 CU
ON
ENT (PERCENT)
UE (BTU/LB)
(PERCENT)
FURNACE VOLUME
LOW NOx combust:
COAL SULFUR CON!
COAL HEATING VA
COAL ASH CONTENT
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE)
FGD SYSTEM INSTALLATION DATE)
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
AIR TO FABRIC RATIO (CU FT/MIN/SQ FT)
OUTLET TEMPERATURE (eF)
1,2 3 4
64 334 507
29 40 61
1958,60 1973 1980
FRONT WALL TANGENTIAL
39 234 543
NO NO YES
0.8 0.8 0.8
8600 8600 8600
8.6 8.6 8.6
WET DISPOSAL
PONDS/ON-SITE
1 1 2
RAILROAD
NA
LSD
LSD
NA
1973
1980
FABRIC
WET
SCRUBBER
FILTER
HS ESP
1978
1973
1980
0.04
0.13
0.09
99.7
96
99.8
1.0
1.0
1.0
NA
NA
78.6
348
1197
200
NA
NA
393
1.9:1.0
NA
NA
365
128
865
13-2
-------
assigned to flue gas handling because of the difficulty accessing upstream
of the FFs. .
Table 13.1.1-2 presents retrofit factor estimates for installation of
conventional FGD technologies for units 1 and 2 at the Clay Boswell plant.
Costs were not developed for these two units because it is unlikely that the
current low sulfur coal would be used if scrubbing were required.
Coal Switching and Physical Coal Cleaning Costs--
The Boswell plant is already burning low sulfur coal; therefore, CS and
PCC were not considered for the plant.
N0X Control Technologies--
LNBs were considered for control of NO emissions from units 1 and 2
A
which have front wall-fired boilers. OFA was considered for unit 3 which is
a tangential-fired boiler. Unit 4 already has LNC; therefore, no additional
N0x emission control technologies were considered for this unit.
Tables 13.1,1-3 and 13.1.1-4 present a summary of retrofit factors and
costs, respectively, for NOx control technologies at the Clay Boswell plant.
Selective Catalytic Reduction-
Cold side SCR reactors for units 1-2, 3, and 4 would be located on the
south side of the unit 1 FF, close to unit 3 chimney, and north of unit 4,
respectively. A low general facilities value (13 percent) was assigned to
the reactor locations. Approximately 400 feet of ductwork would be required
to span the distance between the SCR reactors and the chimney for units 1
and 2, about 200 feet would be required for unit 3, and 200 feet for.unit 4,
Medium, high, and low site access/congestion factors were assigned to the
SCR reactor locations for units 1-2, 3, and 4, respectively. The high site
access/congestion factor for unit 3 is due to the space congestion created
by the close proximity of the unit 3 chimney and the lake. Tables 13.1.1-3
and 13.1.1-4 present the retrofit factors and costs for installation of SCR
at the Boswell plant.
13-3
-------
TABLE 13.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CLAY BOSWELL
UNIT 1 OR 2
FGD TECHNOLOGY
Fnorpn
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
LOW
NA
BAGHOUSE REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
BAGHOUSE REUSE
300-600
BAGHOUSE
NA
BAGHOUSE REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
628
NA
628
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
BAGHOUSE REUSE CASE
1.56
BAGHOUSE CASE
NA
BAGHOUSE UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
5
13-4
-------
TABLE 13.1.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR CLAY BOSWELL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
4
FIRING TYPE
FWF
TANG
NA
TYPE OF NOx CONTROL
LNB
OFA
NA
FURNACE VOLUME (1000 CU FT)
39
234
NA
BOILER INSTALLATION DATE
1958,1960
1973
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
42
69
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
o
Ductwork Demolition (1000$)
19-
91
91
New Duct Length (Feet)
400
200
200
New Duct Costs (1000$)
1527
2562
2562
New Heat Exchanger (1000$)
1426
4936
4936
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
2972
4484
7589
NA
7589
NA
RETROFIT FACTOR FOR SCR
1.34
1.52
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
13-5
-------
Table 13.1.1-4. no* Control Cost Results for the Clay ioswell Plant (June 1988 Dollars)
ssaaasiasssssssssssssassssssssssssssssasssssssaasssaasaaasaasKcssssssaKSsaassflaaaaaasaassssaaasaaaassssaas&Essa^
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nuitoer Retrofit Size Factor Sulfur Cast Cost .Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (StVO (S/kU) (SHH3 (mi IIs/kuh) (X) (tons/yr) <»/ton)
Factor (%>
LNC-LN8
1,2
1
00
64
29
o.a
2.1
33.4
0.5
2.8
42.0
435
1059.0
LNC-LNB-C
1,2
1
00
64
29
0.8
2.1
33.4
0.3
1.7
42.0
435
628.7
LNC-OFA
3
1
00
334
40
0.8
1.0
3.0
0.2
0.2
69.0
3673
58.9
LNC-CFA-C
3
1
00
334
40
0.8
1.0
3.0
0.1
0.1
69.0
3673
35.0
SCR-3
1,2
1
34
64
29
0.8
16.6
259.0
5.1
31.1
80.0
828
6101.3
SCR-3
1-2
1
34
128
29
0.8
25.4
198.3
8.1
24.8
80.0
1657
4877.0
SCR-3
3
1
52
334
40
0.8
53.8
161.0
18.1
15.5
80.0
4259
4246.3
SCR-3
4
1
16
507
65
0.8
67.6
133.4
25.1
8.7
80.0
10505
2385.9
SCR-3-C
1,2
1
34
64
29
0.8
16.6
259.0
3.0
18.3
80.0
828
3585.4
SCR-3-C
1-2
1
34
128
29
0.8
25.4
198.3
4-7
14.6
80.0
1657
2862.9
SCR-3-C
3
1
52
334
40
0.8
53.8
161.0
10.6
9.1
80.0
4259
2489.5
SCR-3-C
4
1
16
507
65
0.8
67.6
133.4
14.7
5.1
80.0
10505
1395.8
SCR-7
1,2
1
34
64
29
0.8
16.6
259.0
4.5
27.7
80.0
828
5434.4
SCR-7
.1-2
1
34
128
29
0.8
25.4
198.3
7.0
21.4
80.0
1657
4210.1
SCR-7
3
1
52
334
40
0.8
53.8
161.0
15.2
13.0
80.0
4259
3569.3
SCR-7
4
1
16
507
65
0,8
67.6
133.4
20.7
7.2
80.0
10505
1969.2
SCR-7-C
1,2
1
34
64
29
0.8
16.6
259.0
2.7
16.3
ao.o
828
3203.3
SCR-7-C
1-2
1
34
128
29
0.8
25.4
198.3
4.1
12.6
80.0
1657
2480.8
SCR-7-C
3
1
52
334
40
0.8
53.8
161.0
8.9
7.6
80.0
4259
2101.6
SCR-7-C
4
1
16
507
65
0.8
67.6
133.4
12.2
4.2
80.0
10505
1157.1
aas:
isasc
3S299SS3
ssasaas
9SSS33
K=3333S=33M
isxssaiaxs
sssasasa
-sssssasss
SSISS3S3S
asaass&sss
13-6
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for
units 1 and 2 because the existing baghouse could be modified to handle the
added particulate load and there is sufficient duct residence time between
the boilers and the baghouse. FSI and DSD were not considered for units 3
and 4 because these units already have LSD-FGD systems. Tables 13.1.1-5 and
13.1.1-6 present retrofit data and costs for installation of FSI and DSD
technologies at the Boswell plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 1 and 2 at the Boswell plant are good candidates for repowering
technologies because of their small boiler sizes and potentially short
remaining useful lifetimes. Units 3 and 4 are too large to be considered
for repowering technologies.
13-7
-------
TABLE 13.1.1-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CLAY BOSWELL UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE NA
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 628
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$). NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 21
TOTAL COST (1000$)
BAGHOUSE UPGRADE CASE 649
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
BAGHOUSE UPGRADE NA
NEW BAGHOUSE NA
13-8
-------
Table 13.1.1-6. Sunmry of DSD/FSI Control Costs for the Clay BosttelI Plant (June 1988 Dollars)
iSs:a83aBBiB3asBsssaaB:ss3ssss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (WH) CmitIs/lwhJ (X) (tons/yr) (l/ton>
Factor (X)
DSD+PFF 1,2 1.00 64 29 0.8
DSO+PFF-C 1,2 1.00 64 29 0.8
FSI+PFF-50 1,2 1.00 64 29 0.8
FSI+PFF-5Q-C 1,2 1.00 64 29 0.8
FSI»PFF-70 1,2 1.00 64 29 0.8
F5I+PFF-70-C 1,2 1.00 64 29 0.8
3.5 55.4 3.5 21.3 71.0 1088 3249.B
3.5 55.4 2.0 12.6 71.0 10S8 1876.6
3.3 50.8 2.3 14.1 50.0 769 2985.9
3.3 50.8 I.J 8.2 50.0 769 1729.6
3.3 50.8 2.3 14.1 70.0 1077 2134.6
3.3 50.B 1.3 8.2 70.0 1077 1236.6
sstBssaasssssssBcsssssass
SS3SSS5SSSSSS33S3SSS
13-9
-------
13.2 NORTHERN STATES POWER COMPANY
13.2.1 A.S. King Steam Plant
Sorbent injection technologies (FSI and DSD) were not considered for
the King plant due to the inadequate size of the ESPs. CS was also not
considered because the boiler is cyclone and low ash fusion temperature and
low sulfur coals required for cyclone boilers are not readily available in
the eastern United States.
TABLE 13.2.1-1. A. S. KING STEAM PLANT OPERATIONAL DATA .
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1
598
50
1968
CYCLONE
279
NO
1.1
8900
9.0
DRY DISPOSAL
LANDFILL/ON-SITE
1
BARGE
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE ("F)
ESP
1968
0.07
98.6
3.2
288
1700
169
330
13-10
-------
TABLE 13.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR A. S. KING
UNIT 1 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (10005)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.20
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.16
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 5
0
5
* L/LS-FGD absorbers, LSD-FGD absorbers, and new FFs for unit 1
would be located south of the unit 1 chimney.
13-11
-------
Table 13.2.1-3. Sutmary of FGD Control Costs for the A. S. King Plant (Jme 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW) Content CSWO <*/kW) (SMM) (mills/kwh) (X) 2SSSSSSSS5ZSS3SSSS™ S22S3&S BSSSSfSSS SSSSSBUSS® JB3S'S5SHIS3lS33tS3!SS«S!SS®3S5S53S5SS3S3®3SS333S2®aSSBB3SS3S!SSS SS;aS2S
13-12
-------
TABLE 13.2.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR A. S. KING
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE CYCLONE
TYPE OF NOx CONTROL NCR
FURNACE VOLUME (1000 CU FT) 279
BOILER INSTALLATION DATE 1968
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 60
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 103
New Duct Length (Feet) 200
New Duct Costs (1000$) 2821
New Heat Exchanger (1000$) 5450
TOTAL SCOPE ADDER COSTS (1000$) 8375
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for unit 1 would be located south of the
unit 1 chimney.
13-13
-------
Table 13.2,1-5, NQx Control Cost Results for the A. S. Kir® Plant (June 1988 Dollars)
:s:ssss:
SSSSSSSSSSSSSSSSSS8
ssssssssssass
SSS333SS3S
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NQx NQx NOx Cost
Nutfeer Retrofit Sii# Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (MW) (X) Content (MM) («/kU> (IHM> (mills/kwh) (*> (tons/yr) ($/ton)
Factor (%)
NCR
NGR-C
SCR-3
SCR-3-C
sea-7
SCR-7-C
1.00 S9B
1.00 59S
1.16 598
1.16 598
1.16 598
1.16 598
50
50
50
50
50
50
1,1 8.6 14.3 14.8 5.7
1.1 8.6 14.3 8.5 3.3
1 72.6 121.5 28.7 10.9
1 72.6 121.5 16.7 6.4
1 ' 72.6 121.5 23.5 9.0
1 72.6 121.5 13.8 5.3
60.0 16952
60.0 16952
80.0 22602
80.0 22602
80.0 22602
80.0 22602
874.9
S03.5
1268.3
741.0
1041.0
610.9
13-14
-------
13.2.2 Sherburne County Steam Plant
The Sherburne County steam plant is located close to the Mississippi
River in Sherburne County, Minnesota, and is operated by the Northern States
Power Company. The Sherburne plant contains three coal-fired boilers with a
gross generating capacity of 2,250 MW.
Table 13.2.2-1 presents operational data for the existing equipment at
the Sherburne County plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area north of the plant. PM
emissions from units 1 and 2 are controlled by wet scrubbers and emissions
from unit 3 are controlled by reverse air FF. Flue gases from boilers 1 and
2 are directed to a common chimney located behind the units. Flue gases
from unit 3 are directed to another chimney. Wet fly ash from the units is
disposed of in ponds south of the plant. Because the Sherburne County plant
already has FGD technologies Installed or under construction, SC., removal
technologies were not considered for this plant.
NOx Control Technologies--
N0X control technologies were not considered for the Sherburne County
plant because the plant already has LNBs installed.
Selective Catalytic Reduction--
Cold side SCR reactors for the boilers at the Sherburne County plant
would be located beside the chimneys. Low general facility values
(13 percent) and site access/congestion factors were assigned to all of the
reactor locations. Approximately 300 feet of ductwork would be required to
span the distance between the SCR reactors and the chimneys for all units.
A low site access/congestion factor was assigned to flue gas handling.
Tables 13.2.2-2 and 13.2.2-3 present the retrofit factors and costs for
installation of SCR at the Sherburne County plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
A11 three boilers at the Sherburne County plant are large and have long
remaining useful lives; therefore, are not considered good candidates for
repowering technologies.
13-15
-------
TABLE 13.2.2-1. SHERBURNE COUNTY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
1000 CU FT)
ON
ENT (PERCENT)
FURNACE VOLUME
LOW NOx COMBUST!
COAL SULFUR C0N1
COAL HEATING VALUE f0TU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE)
FGD SYSTEM (INSTALLATION DATE)
1,2 3
720 810
61,54 65(ASSUMED)
1976,77 1987
TANGENTIAL FRONT WALL
540 934
YES YES
0.6 0.6
8500 8500
8.5 8.5
WET DISPOSAL
PONDS/ONSITE
1 2
RAILROAD
L/LS LSD
1976,77 1987
PARTICULATE CONTROL
TYPE WET REVERSE AIR
SCRUBBER BAGHOUSE
INSTALLATION DATE 1976,77 1978
EMISSION (LB/MM BTU) 0.09 0.03
REMOVAL EFFICIENCY 99.1 99.8
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) <1.0 0.9
SURFACE AREA (1000 SQ FT) NA NA
GAS EXIT RATE (1000 ACFM . NA NA
SCA (SQ FT/1000 ACFM) NA NA
AIR TO FABRIC RATIO (CU FT/MIN/SQ FT) NA 1.9
OUTLET TEMPERATURE (*F). NA 155
13-16
-------
TABLE 13.2,2-2. SUMMARY OF NOx RETROFIT RESULTS FOR SHERBURNE COUNTY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
FIRING TYPE
NA
NA
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
NA
NA
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
119
130
New Duct Length (Feet)
300
300
New Duct Costs (1000$)
4717
S054
New Heat Exchanger (1000$)
6093
6539
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
10929
16511
11723
NA
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13-17
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Table '3.2.2-3. NOx Control Cost Results for the Sherburne County Plant (Jltm 1988 Dollars)
sssdSSSSS3ssss=s==33a==ss3S3ssaS3S9a9saS3aaBXHaaB»±£ei3aaBSfCS3»sss3SS9aasjll3£aaa3s=zs3S33S5===z=»==a5ss3Ssa
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Site Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HW) (X) Content <«M) (»/kw> (mi IIs/kwh) IX) (tons/yr) (J/ton)
Factor <%}
SCR-3
1
1.16
720
61
0.6
86.5
120.1
33.0
8.6
80.0
14190
2327.3
SCR-3
2
1.16
720
54
0.6
86.5
120.1
32.7
9.6
80.0
12561
2601.a
SCR-3
1-2
1.16
1440
58
0.6
161.9
112.5
63.2
8.6
80.0
26983
2342.7
SCR-3
3
1.16
810
65
0.6
94.1
116.1
37.4
8.1
80.0
23814
1569.0
SCR-3-C
1
1.16
720
61
0.6
86.5
120.1
19.3
5.0
80.0
14190
1360.7
SCR-3-C
2
1.16
720
54
0.6
86.5
120.1
19.1
5.6
80.0
12561
1521.5
SCR-3-C
1-2
1.16
1440
58
0.6
161.9
112.5
36.9
5.0
80.0
26983
1369.1
SCR-3-C
3
1.16
810
65
0.6
94.1
116.1
21.8
4.7
80.0
23814
916.6
scr-7
1
1.16
720
61
0.6
86.5
120.1
26. B
7.0
80.0
14190
1888.5
SCt-7
2
1.16
720
54
0.6
86.5
120.1
26.5
7.8
80.0
12561
2106.1
SCR-7
1-2
1.16
1440
58
0.6
161.9
112.5
50.8
6.9
80.0
26983
1881.2
SCR-7
3
1.16
810
65
0.6
94.1
116.1
30.4
6.6
80.0
23814
1274.8
SCR-7-C
1
1.16
720
61
0.6
86.5
120.1
15.7
4.1
80.0
14190
1109.3
SCR-7-C
2
1.16
720
54
0.6
86.5
120.1
15.5
4.6
80.0
12561
1237.5
SCR-7-C
1-2
1.16
1440
58
0.6
161.9
112.5
29.8
4.1
80.0
26983
1104.7
SCR-7-C
3
1.16
810
65
0.6
94.1
116.1
17.8
3.9
80.0
23814
748.1
SSSS=:SS=SSS33SS3SSS&«:3S8SSS==SaS3S33aaSSS3a>Kta9fl>S3aS3B8SaSSHlSSSSBB83S3S88S3SSSBS8aaaBSlIII88B8a8SSa8a»aiSl
13-18
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