EPA/600/7-90/021b
November 1990
RETROFIT COSTS FOR SOg AND N0X CONTROL OPTIONS
AT 200 COAL-FIRED PLANTS
VOLUME II - SITE SPECIFIC STUDIES FOR
Alabama, Delaware, Florida, Georgia, Illinois
by
T. Emmel and M. Maibodi
Radian Corporation
Post Office Box 13000
Research Triangle Park, NC 27709
EPA Contract No. 68-02-4286
Work Assignment 116
Project Officer
Norman Kaplan
U. S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27711
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TECHNICAL REPORT DATA
(I'Scnsc rend I/nt/jrclwns on the reverse before complr " ' '
i/FteronTNo. a- •
EPA/600/7-90/021b
: PB.91-133330
A. TITLE AND SUBTITLE
.Retrofit Costs for SO2 and NOx Control Options at
200 Coal-fired Plants; Volume II - Site Specific
'• Studies for AL, DE, FL, GA, IL
5, REPORT DATE
November 1990
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Thomas E, Emmel and Mehdi Maibodi'
8. PERFORMING ORGANIZATION REPORT NO,
9. PERFORMING ORGANIZATION NAME AND,ADDRESS
Radian Corporation
P. 0. Box 13000
Research Triangle Park, North Carolina 27709
10. PROGRAM ELEMENT NO.
1 1, 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
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 comprising this report.
i6. abstract rep0rt gives results of e-study^*Jthe objective of which was to signifi-
cantly improve engineering cost estimates currently being used to evaluate the eco- ?•
nomic effects of applying S02 and NOx controls at 200 large S02~ emitting coal-fired <
utility plants. To accomplish the objective, procedures were developed and used that
account for site-specific retrofit factors. The site-specific information was obtained
from aerial photographs, generally available data bases, and input from utility com-
panies. Cost estimates are presented for six control technologies; lime/limestone
flue gas desulfurization, lime spray drying, coal switching and cleaning, furnace and
duct sorbent injection, low NOx combustion or natural gas reburn, and selective cata-
lytic reduction. Although the cost estimates provide useful site-specific cost infor-
mation on retrofitting acid gas controls, the costs are estimated for a specific time
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. COSATI Field/Group
Pollution Electric Power Plants
Silfur Dioxide
Nitrogen Oxides
Cost Estimates
Coal
Combustion
Pollution Control
Stationary Sources
Retrofits
13B 10 B
07 B
05A, 14A
21D
21B
IB. DISTRIBUTION-STATEMENT
Release to Public
19, SECURITY CLASS (This Report}
Unclassified "
21, NO. OF PAGES
446
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 <9-73)
i
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ABSTRACT
This report documents the results of a study conducted under the
National Acid Precipitation Assessment Program by the U.S. Environmental
Protection Agency's Air and Energy Engineering Research Laboratory. The
objective of this research program was to significantly improve engineering
cost estimates currently being used to evaluate the economic effects of
applying sulfur dioxide and nitrogen oxides controls at 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
SECTION ' PAGE
ABSTRACT . ...... . . ii
LIST OF FIGURES ............................. v
LIST OF TABLES ...... vi
ABBREVIATIONS AND SYMBOLS ... .... . . . . . - ... xvii
ACKNOWLEDGEMENT ........... ....... . . xx
METRIC EQUIVALENTS . xx
3.0 ALABAMA .... . ... ................ 3-1
3.1 Alabama Power Company 3-1
3.1.1 Barry Steam Plant ................. 3-1.
3.1.2 Gadsden Steam Plant ............ 3-14
3.1.3 Gaston Steam Plant . . . .... . . . . ... . . . 3-22
3.1.4 Gorgas Steam Plant ................ . 3-33
3.1.5 Greene County Steam Plant . . . . . 3-41
3.1.6 Miller Steam Plant 3-50
3.2 Tennessee Valley Authority ................ 3-54
3.2.1 Colbert Steam Plant . 3-54
3.2.2 Widows Creek Steam Plant . 3-54
4.0 DELAWARE ............................. 4-1
4.1 Delmarva Power and Light Company ....... 4-1
4.1.1 Indian River Steam Plant . 4-1
5.0 FLORIDA . . . ...... . 5-1
5.1 Florida Power Corporation 5-1
5.1.1 Crystal River Steam Plant ...... 5-1
5.2 Gulf Power Company 5-16
5.2.1 Crist Electric Generating Plant . . . . . . . . . . 5-16
5.2.2 Lansing Smith Steam Plant . . ... ......... 5-26
5.3 Seminole Electric Cooperative , 5-32
5.3.1 Seminole Steam Plant ........ .5-32
iii
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TABLE OF CONTENTS (Continued)
PAGF
SECTION ' . •
5.4 Tampa Electric Company . : . . ........ 5-36
5.4.1 Big Bend Steam Plant 5-36
5.4.2 F. J. Gannon Steam Plant 5-42
6.0 GEORGIA. 6-1
6.1 Georgia Power Company ........... . . . 6-1
6.1.1 P. S. Arkwright Steam Plant .... 6-1
6.1.2 Bowen Steam Plant ..... 6-12
6.1.3 Branch Steam Plant 6-21
6.1.4 Hammond Steam Plant ................ 6-32
6.1.5 Jack McDonough Steam Plant . 6-41
6.1.6 Mitchell Steam Plant • . . 6-52
6.1.7 Robert W. Scherer Steam Plant 6-60
6.1.8 Wansley Steam Plant ... 6-66
6.1.9 Yates Steam Plant 6-75
7.0 ILLINOIS ................ ....... 7-1
7.1 Central 'Illinois Light Company ^ 7-1
7.1.1 E. D. Edwards Steam Plant ....... 7-1
7.2 Central Illinois Public Service ..... 7-6
7.2.1 Coffeen Steam Plant .... ...... 7-6
7.2.2 Grand Tower Steam Plant 7-20
7.2.3 Hutsonvil1e Steam Plant . . . . . . ... 7-31
7.2.4 Meredosia Steam Plant ¦ 7-43
7.2.5 Newton Steam Plant .7-54
7.3 Commonwealth Edison Company 7-68
7.3.1 Joliet 29 Steam Plant ...... . ... 7-68
7.3.2 Kincaid Steam Plant . . 7-72
7.3.3 Powerton Steam Plant ............... 7-82
7.3.4 Waukegan Steam Plant 7-91
7.3.5 Will County Steam Plant 7-99
7.4 Electric Energy Incorporation . . . . . ... . . . . . . 7-105
7.4.1 Joppa Steam Plant ... 7-105
7.5 Illinois Power Company . . . 7-122
7.5.1 Baldwin Steam Plant . 7-122
7.5.2 Hennepin Steam Plant 7-136
7.5.3 Vermilion Steam Plant ......... 7-149
7.5.4 Wood River Steam Plant . 7-164
7.6 Southern Illinois Power Company . 7-169
7.6.1 Marion Steam Plant ............... 7-169
7.7 Springfield City of Water ...... 7-183
7.7.1 Dallman Steam PI ant 7-183
iv
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TABLE OF CONTENTS (Continued)
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
VOLUME IV - SITE SPECIFIC STUOIES 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
LIST OF FIGURES
FIGURE PAGE
VOLUME II - SITE SPECIFIC STUDIES FOR
Alabama, Delaware, Florida, Georgia, Illinois
3.2.2-1 Widows Creek Plant Plot Plan .......... , 3-55
7.2.1-1 Coffeen Plant Plot Plan " 7-7
7.2.2-1 Grand Tower Plant Plot Plan . . 7-21
7.2.5-1 Newton Plant Plot Plan ... .......... 7-56
7.3.2-1 Kincaid Plant Plot Plan 7-73
7.4.1-4 Joppa Plant Plot Plan .......... 7-106
7.5.1-1 Baldwin Plant Plot Plan 7-123
7.5.3-1 Vermilion Plant Plot Plan . 7-150
7.6.1-1 Marion Plant Plot Plan . . . . 7-170
7.7.1-1 Dal 1man Plant Plot Plan 7-184
v
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LIST OF TABLES
TABLE • ¦££££
VOLUME II - SITE SPECIFIC METHODOLOGY FOR
Alabama, Delaware, Florida, Georgia, Illinois
3.1.1-1 Barry Steam Plant Operational Data ..... . . 3-2
3.1.1-2 Summary of Retrofit Factor Data for Barry Units 1, 2, or 3 . . 3-4
3.1.1-3 Summary of Retrofit Factor Data for Barry Unit 4 . 3-5
3.1.1-4 Summary of Retrofit Factor Data for Barry Unit 5 ....... 3-6
3.1.1-5 Summary of NO Retrofit Results for Barry .... 3-8
3.1.1-6 NO Control Cost Results for the Barry Plant
(June 1988 Dollars) . . . . 3-9
3.1.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Barry Unit 4 3-11
3.1.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Barry Unit 5 . . . . 3-12
3.1.1-9 Summary of DSD/FSI Control Costs for the Barry Plant
(June 1988 Dollars) 3-13
3.1.2-1 Gadsden Steam Plant Operational Data . . . . . . . . ... - .3-14
3.1.2-2 Summary of Retrofit Factor Data for Gadsden Units 1 or 2 ... 3-15
3.1.2-3 Summary of FGD Control Costs for the Gadsden Plant
(June 1988 Dollars) . . 3-16
3.1.2-4 Summary of Coal Switching/Cleaning Costs for the
Gadsden Plant (June 1988 Dollars) . . 3-17
3.1.2-5 Summary of NO Retrofit Results for Gadsden . 3-18
3.1.2-6 NO Control Cost Results for the Gadsden Plant
{June 1988 Dollars) 3-19
3.1.2-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Gadsden Units 1 or 2 ...... 3-20
3.1.2-8 Summary of DSD/FSI Control Costs for the Gadsden
Plant (June 1988 Dollars) 3-21
3.1.3-1 Gaston Steam Plant Operational Data .............. 3-23
3.1.3-2 Summary of Retrofit Factor Data for Gaston
Units 1, 2» 3, or 4 .............. . ... . . . 3-25
3.1.3-3 Summary of Retrofit Factor Data for Gaston Unit 5 3-26
3.1.3-4 Summary of FGD Control Costs for the Gaston Plant
(June 1988 Dollars) . . . . . . . . . . • • • • • • 3-27
3.1.3-5 Summary of Coal Switching/Cleaning Costs for
the Gaston Plant (June 1988 Dollars) ............ 3-28
3.1.3-6 Summary of NO Retrofit Results for Gaston ... . . . . . . . 3-30
3.1.3-7 NO Control Costs Results for the Gaston
Plant (June 1988 Dollars) ................. 3-31
3.1.4-1 Gorgas Steam Plant Operational Data ...... 3-33
3.1.4.2 Summary of Retrofit Factor Data for Gorgas -
Units 5, 6, and 7 ........ ........ 3-34
3.1.4-3 Summary of Retrofit Factor Data for Gorgas
Units 8, 9, and 10 . . . 3-35
3.1.4-4 Summary of FGD Control Costs for the Gorgas
PI ant (June 1988 Dollars) 3-36
vi
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LIST OF TABLES (Continued)
TABLES
3.1.4-5
3.1.4-6
3.1.4-7
3.1.4-8
3.1.5-1
3.1.5-2
3.1.5-3
3.1.5-4
3.1.5-5
3.1.5-6
3.1.6-1
3.1.6-2
3.1.6-3
3.1.6-4
3.2.2-1
3.2.2-2
3.2.2-3
3.2.2-4
3.2.2-5
3.2.2-6
3.2.2-7
3.2.2-8
3.2.2-9
3.2.2-10
4.1.1-1
4.1.1-2
4.1.1-3
PAGE
Summary of Coal Switching/Cleaning Costs for
the Gorgas Plant (June 1988 Dollars) .......
Summary of NO Retrofit Results for Gorgas Units 5-7
Summary of NO for Gorgas Units 8-10
NO Control Cost Results for the Gorgas
Plant (June 1988 Dollars)
Greene County Steam Plant Operational Data . .
Summary of Retrofit Factor Data for Greene
County Unit 1 or 2
Summary of FGD Control Costs for the Greene
County Plant (June 1988 Dollars)
Summary of Coal Switching/Cleaning Costs for the
Greene County Plant (June 1988 Dollars) . -
Summary of NO Retrofit Results for Greene County
NO Control Cost Results for the Greene
County Plant (June 1988 Dollars) . .
Miller Steam Plant Operational Data
Summary of Retrofit Factor Data for Miller Unit 1 or 2
Summary of NO Retrofit Results for Miller
NO Control Cost Results for the Miller Plant
(June 1988 dollars)
Widows Creek Steam Plant Operational Data . .
Summary of Retrofit Factor Data for Widows Creek
Units 1-3 . .
Summary of Retrofit Factor Data for Widows Creek
Units 4-6
Summary of FGD Control Costs for the Widows Creek Plant
(June 1988 Dollars)
Summary of NO
Retrofit Results for Widows Creek
Units 1-3
Summary of N0}
Units 4-6
Summary of NO
Units 7-8 .
NO Control Cost Results for the Widows Creek P1ant
(June 1988 Dollars)
Retrofit Results for Widows Creek
Retrofit Results for Widows Creek
Duct Spray Drying and Furnace Sorbent Injection
Technologies for Widows Creek Units 1-6
Summary of DSD/FSI Control Costs for the Widows Creek
Plant (June 1988 Dollars) .......
Indian River Steam Plant Operational Data
Summary of Retrofit Factor Data for Indian
River Units 1-3
Summary of Retrofit Factor Data for Indian River Unit 4
3-37
3-38
3-39
3-40
3-42
3-44
3-45
3-46
3-47
3-48
3-50
3-51
3-52
3-53
3-56
3-58
3-59
3-61
3 — 6 3
3-64
3-65
3-66
3-69
3-70
4-2
4-4
4-5
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LIST OF TABLES (Continued)
TABLES PAGE
4.1.1-4 Summary of FGD Control Costs for the Indian
River Plant (June 1988 Dollars) .............. 4-6
4.1.1-5 Summary of Coal Switching/Cleaning Costs for
the Indian River Plant (June 1988 Dollars) .... 4-7
4.1,1-6 Summary of NO Retrofit Results for Indian River 4-9
4.1.1-7 NO Control Cost Results for the Indian River Plant
Plant (June 1988 Dollars) . . 4-10
4.1.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Indian River Units 1-3 .......... 4-12
4.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Indian River Unit 4 4-13
4.1.1-10 Summary of DSD/FSI Control Costs for the Indian River
Plant (June 1988 Dollars) 4-14
5.1.1-1 Crystal River Steam Plant Operational Data 5-2
5.1.1-2 Summary of Retrofit Factor Data for Crystal River Unit 1 ... 5-5
5.1.1-3 Summary of Retrofit Factor Data for Crystal River Unit 2 ... 5-6
5.1.1-4 Summary of Retrofit Factor Data for Crystal
River Units 4 or 5 ¦ 5-7
5.1.1-5 Summary of NO Retrofit Results for Crystal River ....... 5-8
5.1.1-6 NO Control Cost Results for the Crystal River
Plant (June 1988 Dollars) 5-9
5.1.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Crystal River Unit 1 5-11
5.1.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Crystal River Unit 2 5-12
5.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Crystal River Unit 4 or 5 5-13
5.1.1-10 Summary of DSD/FSI Control Costs for the Crystal
River Plant (June 1988 Dollars) 5-14
5.2.1-1 Crist Power Corrpany Operational Data 5-17
5.2.1-2 Summary of Retrofit Factor Data for Crist Unit 4 or 5 . . ... 5-19
5.2.1-3 Summary of Retrofit Factor Data for Crist Unit 6 or 7 5-20
5.2.1-4 Summary of FGD Control Costs for the Crist Plant
(June 1988 Dollars) 5-21
5.2.1-5 Summary of Coal Switching/Cleaning Costs for the
Crist Plant (June 1988 Dollars) 5-22
5.2.1-6 Summary of NO Retrofit Results for Crist . 5-23
5.2.1-7 NO Control Cost Results for the Crist Plant
(June 1988 Dollars) . 5-24
5.2.2-1 Lansing Smith Steam Plant Operational Data 5-26
5.2.2-2 Summary of Retrofit Factor Data for Lansing Smith
Units 1 or 2 . 5-27
5.2.2-3 Summary of FGD Control Costs for the Lansing Smith
Plant (June 1988 Dollars) 5-28
viii
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LIST OF TABLES (Continued)
TABLES PAGE
5,2.2-4 Summary of Coal Switching/Cleaning Costs for the
Lansing Smith Plant (June 1988 Dollars) 1-29
5.2.2-5 Summary of NO Retrofit Results for Lansing Smith . . 5-30
5.2.2-6 NOy Control Cost Results for the Lansing Smith Plant
(June 1988 Dollars) 5-31
5.3.1-1 Seminole Steam Plant Operational Data ... 5-33
5.3.1-2 Summary of N0X Retrofit Results for Seminole 5-34
5.3.1-3 NO Control Cost Results for the Seminole Plant
(June 1988 Dollars) 5-35
5.4.1-1 Big Bend Steam Plant Operational Data ..... 5-37
5.4.1-2 Summary of Retrofit Factor Data for Big Bend
Units 1, 2 and 3 ........ 5-39
5.4.1-3 Summary of FGD Control Costs for the Big
Bend Plant (June 1988 Dollars) 5-40
5.4.1-4 Summary of Coal Switching/Cleaning Costs for the Big
Bend Plant (June 1988 Dollars) 5-41
5.4.1-5 Summary of N0X Retrofit Results for Big Bend 5-43
5.4.1-6 NO Control Cost Results for the Big Bend Plant
(June 1988 Dollars) 5-44
5.4.2-1 F. J. Gannon Stean Plant Operational Data . 5-45
5.4.2-2 Summary of Retrofit Factor Data for F. J. Gannon
Units 1 or 2 5-47
5.4.2-3 Summary of Retrofit Factor Data for F.J. Gannon
Units 3 or 4 ... 5-48
5.4.2-4 Summary of Retrofit Factor Data for J. J. Gannon Unit 5 . . . . 5-48
5.4.2-5 Summary of Retrofit Factor Data for F. J. Gannon Unit 6 . . . . 5-50
5.4.2-6 Summary of FGD Control Costs for the Gannon Plant
(June 1988 Dollars) 5-51
5.4.2-7 Summary of Coal Switching/Cleaning Costs for the
Gannon Plant ( June 1988 Dollars) 5-53
5.4.2-8 Summary of NO Retrofit Results for F. J. Gannon, Units 1-3 . 5-54
5.4.2-9 Summary of NO* Retrofit Results for F. J. Gannon, Units 4-6 . . 5-55
5.4.2-10 NO Control Cost Results for the Gannon Plant
(June 1988 Dollars) • 5-56
5.4.2-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for F. J. Gannon Units 1 or 2 5-57
5.4.2-12 Duct Spray Drying and Furnace Sorbent Injection
Technologies for F. J. Gannon Units 3, 4, 5, or 6 5-58
5.4.2-13 Summary of DSD/FSI Control Costs for the Gannon
Plant (June 1988 Dollars) 5-59
6.1.1-1 P. S. Arkwright Steam Plant Operational Data .... 6-2
6.1.1-2 Summary of Retrofit Factor Data for P. S.
Arkwright Units 1-4 6-4
6.1.1-3 Summary of FGD Control Costs for the Arkwright
Plant (June 1988 Dollars) ..... 6-5
ix
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LIST OF TABLES (Continued)
TABLES PAGE
6.1.1-4 Summary of Coal Switching/Cleaning Costs for the
Arkwright Plant (June 1988 Dollars) .... 6-6
6.1.1-5 Summary of NO Retrofit Results for P. S. Arkwright 6-7
6.1.1-6 NO Control Cost Results for the Arkwright
Plant {June 1988 Dollars) 6-8
6.1.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for P. S. Arkwright Units 1-4 6-10
6.1.1-8 Summary of DSD/FSI Control Costs for the
Arkwright Plant (June 1988 Dollars) ....... 6-11
6.1.2-1 Bowen Steati Plant Operational Data 6-12
6.1.2-2 Summary of Retrofit Factor Data for Bowen Unit 1 or 2 .... . 6-13
6.1.2-3 Summary of Retrofit Factor Data for Bowen Unit 3 or 4 .... . 6-14
6.1.2-4 Summary of FGD Control Costs for the Bowen
Plant (June 1988 Dollars) 6-15
6.1.2-5 Summary of Coal Switching/Cleaning Costs for the
Bowen Plant (June 1988 Dollars) 6-16
6.1.2-6 Summary of .N0X Retrofit Results for Bowen 6-17
6.1.2-7 NO Control Cost Results for the Bowen Plant
(June 1988 Dollars) 6-18
6.1.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Bowen Unit 1 or 2 6-19
6.1.2-9 Summary of DSD/FSI Control Costs for the Bowen
Plant (June 1988 Dollars) 6-20
6.1.3-1 Branch Steam Plant Operational Data 6-21
6.1.3-2 Summary of Retrofit Factor Data for Branch Units 1 and 2 . . . 6-22
6.1.3-3 Summary of Retrofit Factor Data for Branch Units 3 and 4 ... 6-23
6.1.3-4 Summary of FGD Control Costs for the Branch Plant
(June 1988 Dollars) 6-24
6.1.3-5 Summary of Coal Switching/Cleaning Costs for
the Branch Plant (June 1988 Dollars) 6-25
6.1.3-6 Summary of NO Retrofit Results for Branch Units 1-2 6-26
6.1.3-7 Summary of NO* Retrofit Results for Branch Units 3-4 ..... 6-27
6.1.3-8 NO Control Cost Results for the Branch Plant
(June 1988 Dollars) 6-28
6.1.3-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Branch Units 1 and 2 6-29
6.1.3-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Branch Units 3 and 4 6-30
6.1.3-11 Summary of DSD/FSI Control Costs for the
Branch Plant (June 1988 Dollars) ..... 6-31
6.1.4-1 Hammond Steam Plant Operational Data ..... ... 6-33
6.1.4-2 Summary of Retrofit Factor Data for Hammond Units 1-3 6-34
6.1.4-3 Summary of Retrofit Factor Data for Hammond Unit 4 6-35
6.1.4-4 Summary of FGD Control Costs for the Hammond Plant
(June 1988 Dollars) .6-36
x
-------
LIST OF TABLES (Continued)
TABLES PAGE
6.1.4-5 Summary of Coal Switching/Cleaning Costs for the
Hammond Plant (June 1988 Dollars) , 6-38
6.1.4-6 Summary of NO Retrofit Results for Hammond 6-39
6.1.4-7 NO Control Cost Results for the Hammond Plant
(June 1988 Dollars) 6-40
6.1.5-1 Jack McDonougb Steam Plant Operational Data .... 6-42
6.1.5-2 Summary of Retrofit Factor Data for Jack
McDonough Unit 1 or 2 6-44
6.1.5-3 Summary of FGD Control Costs for the Jack McDonough
Plant (June 1988 Dollars) 6-45
6.1.5-4 Summary of Coal Switching/Cleaning Costs for the
Jack McDonough Plant (June 1988 Dollars) .... 6-46
6.1.5-5 Summary of NQX Retrofit Results for Jack McDonough 6-47
6.1.5-6 NO Control Cost Results for the Jack McDonough Plant
(June 1988 Dollars) 6-48
6.1.5-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Jack McDonough Unit 1 or 2 ... 6-50
6.1.5-8 Summary of DSD/FSI Control Costs for the
Jack McDonough Plant (June 1988 Dollars) ... 6-51
6.1.6-1 Mitchell Steam Plant Operational Data 6-52
6.1.6-2 Summary of Retrofit Factor Data for Mitchell Units 1-3 .... 6-53
6.1.6-3 Summary of FGD Control Costs for the Mitchell
Plant (June 1988 Dollars) 6-54
6.1.6-4 Summary of Coal Switching/Cleaning Costs for the
Mitchell Plant (June 1988 Dollars) ... 6-55
6.1.6-5 Summary of NO Retrofit Results for Mitchell 6-56
6.1.6-6 NO Control Cost Results for the Mitchell
Plant (June 1988 Dollars) 6-57
6.1.6-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Mitchell Unit 1 or 2 ...... 6-58
6.1.6-8 Summary of DSD/FSI Control costs for the Mitchell
Plant (June 1988 Dollars) 6-59
6.1.7-1 Scherer Steam Plant Operational Data 6-61
6.1.7-2 Summary of Retrofit Factor Data for Scherer Unit 1 or 2 ... . 6-63
6.1.7-3 Summary of N0¥ Retrofit Results for Scherer 6-64
6.1.7-4 NO,, Control Cost Results for the Scherer Plant
(June 1988 Dollars) ........ 6-65
6.1.8-1 Wansley Steam Plant Operational Data .... 6-67
6.1.8-2 Summary of Retrofit Factor Data for Wansley Units 1 or 2 ... 6-69
6.1.8-3 Summary of FGD Control Costs for the Wansley
Plant (June 1988 Dollars) 6-70
6.1.8-4 Summary of Coal Switching/Cleaning Costs for the
Wansley Plant (June 1988 Dollars) 6-71
6.1.8-5 Summary of N0X Retrofit Results for Wansley ..... 6-72
xi
-------
LIST OF TABLES (Continued)
TABLES PAGE
6.1.8-6 NOv Control Cost Results for the Wansley Plant
(June 1988 Dollars) • 6-73
6.1.9-1 Yates Steam Plant Operational Data .... 6-76
6.1.9-2 Summary of Retrofit Factor Data for Yates
Units 1-5 (Each) 6-78
6.1.9-3 Summary of Retrofit Factor Data for Yates
Unit 6-7 (Each) • • 6-79
6.1.9-4 Summary of FGD Control Costs for the Yates Plant
(June 1988 Dollars) 6-80
6.1.9-5 Summary of Coal Switching/Cleaning Costs for the Yates
Plant (June 1988 Dollars) 6-81
6.1.9-6 Summary of NO Retrofit Results for Yates ..... 6-83
6.1.9-7 NO Control Cost Results for the Yates Plant
(June 1988 Dollars) 6-84
6.1.9-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Yates Unit 6-7 (Each) 6-86
6.1.9-9 Summary of DSD/FSI Control Costs for the Yates
Plant (June 1988 Dollars) 6-87
7.1.1-1 E. D. Edwards Steam Plant Operational Data 7-1
7.1.1-2 Summary of Retrofit Factor Data for Edwards Unit 1 or 2 ... . 7-2
7.1.1-3 Summary of Retrofit Factor Data for Edwards Unit 3 7-3
7.1.1-4 Summary of NO Retrofit Results for Edwards . . 7-4
7.1.1-5 NO Control Cost Results for the Edwards Plant
(June 1988 Dollars) 7-5
7.2.1-1 Coffeen Steam Plant Operational Data 7-8
7.2.1-2 Summary of Retrofit Factor Data for Coffeen Units 1-2 7-10
7.2.1-3 Summary of FGD Control Costs for the Coffeen Plant
(June 1988 Dollars) ....... 7-11
7.2.1-4 Summary of Coal Switching/Cleaning Costs for the
Coffeen Plant (June 1988 Dollars) . 7-13
7.2.1-5 Summary of NO Retrofit Results for Coffeen 7-14
7.2.1-6 NO Control Cost Results for the Coffeen Plant
(June 1988 Dollars) 7-15
7.2.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Coffeen Unit 1 7-17
7.2.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Coffeen Unit 2 ..... 7-18
7.2.1-9 Summary of DSD/FSI Control costs for the Coffeen
Plant (June 1988 Dollars) . 7-19
7.2.2-1 Grand Tower Steam Plant Operational Data 7-22
7.2.2-2 Summary of Retrofit Factor Data for Grand Tower
Units 7-9 7-24
7.2.2-3 Summary of FGD Control Costs for the Grand Tower
Plant (June 1988 Dollars) 7-25
xii
-------
LIST OF TABLES (Continued)
TABLES PAGE
7.2.2-4 Summary of the Coal Switching/Cleaning Costs for
the Grand Tower Plant (June 1988 Dollars) . 7-27
7.2.2-5 Summary of NO Retrofit Results for Grand Tower 7-28
7.2.2-6 NCL Control Cost Results for the Grand Tower Plant
(June 1988 Dollars) 7-29
7.2.2-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Grand Tower Units 7-8 . 7-32
7.2.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Grand Tower Unit 9 ..... 7-33
7.2.2-9 Summary of DSD/FSI Control Costs for the Grand
Tower Plant (June 1988 Dollars) 7-34
7.2.3-1 Hutsonville Steam Plant Operational Data ..... 7-35
7.2.3-2 Summary of Retrofit Factor Data for Hutsonville
Unit 5 or 6 7-37
7.2.3-3 Summary of FGD Control Costs for the Hutsonville
Plant (June 1988 Dollars) ....... .... 7-38 .
7.2.3-4 Summary of Coal Switching/Cleaning Costs for the
Hutsonville Plant (June 1988 Dollars) 7-40
7.2.3-5 Summary of NO Retrofit Results for Hutsonville . 7-41
7.2.3-6 N0y Control Cost Results for the Hutsonville Plant
(June 1988 Dollars) 7-42
7.2.4-1 Heredosia Steam Plant Operational Data . 7-44
7.2.4-2 Summary of Retrofit Factor Data for Heredosia
Unit 1, 2, 3 or 4 . 7-46
7.2.4-3 Summary of Retrofit Factor Data for Meredosia Unit 5 7-47
7.2.4-4 Summary of FGD Control Costs for Heredosia Plant
(June 1988 Dollars) 7-48
7.2.4-5 Sunnary of Coal Switching/Cleaning Costs for the
Meredosia Plant (June 1988 Dollars) ............ 7-50
7.2.4-6 Summary of NO Retrofit Results for Meredosia 7-51
7.2.4-7 NO Control Cost Results for the Meredosia
xPlant (June 1988 Dollars) 7-52
7.2.4-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Meredosia Unit 1, 2, 3 or 4 7-53
7.2.4-9 Summary of DSD/FSI Control Costs for the Meredosia
Plant (June 1988 Dollars) 7-55
7.2.5-1 Newton Steam Plant Operational Data 7-57
7.2.5-2 Summary of Retrofit Factor Data for Newton Unit 2 7-59
7.2.5-3 Summary of FGD Control Costs for the Newton Plant
(June 1988 Dollars) 7-60
7.2.5-4 Summary of NO Retrofit Results for Newton .......... 7-62
7.2.5-5 NO Control Cost Results for the Newton Plant
(June 1988 Dollars) 7-63
7.2.5-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Newton Unit 2 7-65
xiiL
-------
LIST OF TABLES (Continued)
TABLES £ME
7.2.5-7 Summary ofDSD/FSI Control Costs for the Newton
Plant (June 1988 Dollars) . 7-66
7.3.1-1 Joliet 29 Steam Plant Operational Data 7-68
7.3.1-2 Summary of Retrofit Data for Joliet 29 Unit 7 or 8 7-69
7.3.1-3 Summary of NO Retrofit Results for Joliet 29 7-70
7.3.1-4 NOy Control Cost Results for the Joliet Plant
(June 1988 Dollars) 7-71
7.3.2-1 Kincaid Steam Plant Operational Data .......
7.3.2-2 Summary of Retrofit Factor Data for Kincaid Units 1
7.3.2-3 Summary of FGD Control Costs for the Kincaid Plant
(June 1988 Dollars) - •
7.3.2-4 Summary of the Coal Switching/Cleaning Costs for
the Kincaid Plant (June 1988 Dollars)
7.3.2-5 Summary of NO Retrofit Results for Kincaid . . . .
7.3.2-6 N0y Control Cost Results for the Kincaid Plant
(June 1988 Dollars) 7-81
7.3.2-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Kincaid Units 1-2 7-83
7.3.2-8 Summary of DSD/FSI Control Costs for the Kincaid
Plant (June 1988 Dollars) 7-84
7.3.3-1 Powerton Steam Plant Operational Data . 7-86
7.3.3-2 Summary of Retrofit Factor Data for Powerton
Boilers 51, 52, 61 or 62 7-88
7.3.3-3 Summary of NO Retrofit Results for Powerton 7-89
7.3.3-4 N0y Control Cost Results for the Powerton Plant
(June 1988 Dollars) 7-90
7.3.3-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Powerton Boilers 51, 52, 61, 62 ..... . 7-92
7.3.3-6 Summary of DSD/FSI Control Costs for the Powerton
Plant (June 1988 Dollars) 7-93
7.3.4-1 Waukegan Steam Plant Operational Data . . 7-94
7.3.4-2 Summary of Retrofit Factor Data for Waukegan Unit 6 7-95
7.3.4-3 Summary of Retrofit Factor Data for Waukegan Unit 7 or 8 ... 7-96
7.3.4-4 Summary of NO Retrofit Results for Waukegan . 7-97
7.3.4-5 NGV Control Cost Results for the Waukegan Plant
(June 1988 Dollars) 7-98
7.3.5-1 Will County Steam Plant Operational Data 7-99
7.3.5-2 Summary of Retrofit Factor Data for Will County Unit 1 ... 7-100
7.3.5-3 Summary of Retrofit Factor Data for Will County
Unit 2 or 3 ¦ 7-101
7.3.5-4 Summary of Retrofit Factor Data for Will County Unit 4 . . . 7-102
7.3.5-5 Summary of N0X Retrofit Results for Will County 7-103
xiv
7-74
-2 7-76
...... 7-77
7-79
...... 7-80
-------
LIST OF TABLES (Continued)
TABLES PAGE
7.3.5-6 NO Control Cost Results for the Will County Plant
(June 1988 Dollars) ........ 7-104
7.4.1-1 Joppa Steam Plant Operational Data .... 7-107
7.4.1-2 Summary of Retrofit Factor Data for Joppa
Units 1, 2, 5, 6 7-109
7.4.1-3 Summary of Retrofit Factor Data for Joppa Units 3-4 7-110
7.4.1-4 Summary of FGD Control Costs for the Joppa Plant
(June 1988 Dollars) 7-112
7.4.1-5 Summary of the Coal Switching/Cleaning Costs for
the Joppa Plant (June 1988 Dollars) 7-113
7.4.1-6 Summary of NO Retrofit Results for Joppa Units 1-3 .... . 7-115
7.4.1-7 Summary of NO Retrofit Results for Joppa Units 4-6 7-116
7.4.1-8 NO Control Cost Results for the Joppa Plant
(June 1988 Dollars) 7-117
7.4.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Joppa Units 1, 2, 5, 6 . 7-119
7.4.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Joppa Units 3-4 • • 7-120
7.4.1-11 Summary of DSD/FSI Control Costs for the Joppa
Plant (June 1988 Dollars) 7-121
7.5.1-1 Baldwin Steam Plant Operational Data 7-124
7.5.1-2 Summary of Retrofit Factor Data for Baldwin Unit 1 7-126
7.5.1-3 Summary of Retrofit Factor Data for Baldwin Unit 2 7-127
7.5.1-4 Summary of Retrofit Factor Data for Baldwin Unit 3 7-128
7.5.1-5 Summary of FGD Control Costs for the Baldwin Plant
(June 1988 Dollars) 7-130
7.5.1-6 Summary of the Coal Switching/Cleaning Costs for
the Baldwin Plant (June 1988 Dollars) 7-131
7.5.1-7 Summary of NO Retrofit Results for Baldwin 7-133
7.5.1-8 NO Control Cost Results for the Baldwin Plant
(June 1988 Dollars) 7-134
7.5.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Baldwin Unit 1 7-137
7.5.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Baldwin Unit 2 7-138
7.5.1-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Baldwin Unit 3 7-139
7.5.1-12 Summary of DSD/FSI Control Costs for the Baldwin
Plant (June 1988 Dollars) 7-140
7.5.2-1 Hennepin Steam Plant Operational Data ... 7-141
7.5.2-2 Summary of Retrofit Factor Data for Hennepin Units 1 or 2 . . 7-143
7.5.2-3 Summary of FGD Control Costs for the Hennepin Plant
(June 1988 Dollars) ......... 7-144
7.5.2-4 Summary of Coal Switching/Cleaning Costs for the
Hennepin Plant (June 1988 Dollars) . . 7-145
xv
-------
LIST OF TABLES (Continued)
TABLES £ME
7.5.2-5 Summary of NO Retrofit Results for Hennepin 7-146
7.5.2-6 NO Control Cost Results for the Hennepin Plant
(June 1988 Dollars) .............. 7-147
7.5.3-1 Vermilion Steam Plant Operational Oata . . 7-151
7.5.3-2 Summary of Retrofit Factor Data for
Vermilion Units 1-2 ..... 7-153
7.5.3-3 Summary of FGD Control Costs for the Vermi1 ion
Plant (June 1988 Dollars) .......... 7-154
7.5.3-4 Summary of the Coal Switching/Cleaning Costs for the
Vermilion Plant (June 1988 Dollars) ..... 7-156
7.5.3-5 Summary of NO Retrofit Results for Vermilion 7-157
7.5.3-6 N0y Control Cost Results for the Vermilion Plant
(June 1988 Dollars) 7-158
7.5.3-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Vermilion Unit 1 7-161
7.5.3-8 Duct Spray Drying and furnace Sorbent Injection
Technologies for Vermilion Unit 2 ....... 7-162
7.5.3-9 Summary of DSD/FSI Control Costs for the Vermilion
Plant (June 1988 Dollars) 7-163
7.5.4-1 Wood River Stear Plant Operational Data ..... 7-164
7.5.4-2 Summary of'Retrofit Factor Data for Wood River Unit 4 . . , . 7-165
7.5.4-3 Summary of Retrofit Factor Data for Wood River Unit 5 . . . . 7-166
7.5.4-4 Summary of NO Retrofit Results for Wood River 7-167
7.5.4-5 NO Control Cost Results for the Wood River Plant
x(June 1988 Dollars) - 7-168
7.6.1-1 Marion Steam Plant Operational Data 7-171
7.6.1-2 Summary of Retrofit Factor Data for Marion Unit 1 7-173
7.6.1-3 Summary of Retrofit Factor Data for Marion Units 2-3 .... 7-174
7.6.1-4 Summary of FGD Control Costs for the Marion Plant
(June 1988 Dollars) 7"175
7.6.1-5 Summary of N0y Retrofit Results for Marion .... 7-177
7.6.1-6 NO Control Cost Results for the Marion Plant
(June 1988 Dollars) ................... 7-178
7.6.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Marion Units 1, 2 or 3 7-180
7.6.1-8 Summary of DSD/FSI Control Costs for the Marion
Plant (June 1988 Dollars) 7-182
7.7.1-1 Dallman Steam Plant Operational Data ¦ 7-185
7.7.1-2 Summary of Retrofit Factor Data for Dallman Units 1-2 .... 7-187
7.7.1-3 Summary of FGD Control Costs' for the Dallman Plant
(June 1988 Dollars) ........... 7-188
7.7.1-4 Summary of NO Retrofit Results for Dallman 7-190
7.7.1-5 N0V Control Cost Results for the Dallman Plant
(June 1988 Dollars) 7-191
7.7.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Dallman Units 1-2 7-194
7.7.1-7 Summary of DSD/FSI Control Costs for the Dallman
Plant (June 1988 Dollars) 7-195
xvi
-------
ABBREVIATIONS AND SYMBOLS
ABBREVIATIONS
acfm -- actual cubic feet per minute
AEERL --Air and Energy Engineering Research Laboratory
AEP -- Associated Electric Cooperative
AFDC -- allowance for funds during construction
AUSM -- advanced utility simulation model
-C -- constant dollars in cost tables
CG -- coal gasfication
CG&E -- Cincinnati Gas and Electric
CS -- coal switching
CS/B -- coal switching and blending
DOE -- Department of Energy
DSD -- duct spray drying
EIA-767 -- Energy Information Administration Form 767
EPA -- Environmental Protection Agency
EPRI -- Electric Power Research Institute
ESP -- electrostatic precipitator
FBC -- fluidized bed combustion
FF -- fabric filter
FGD -- flue gas desulfurization
FPD -- fuel price differential
FSI -- furnace sorbent injection
ft -- feet
FVIF -- front, wall-fired
IAPCS -- Integrated Air Pollution Control System
xvii
-------
, ABBREVIATIONS AND SYMBOLS (Continued)
IRS -- Internal Revenue Service
KU -- Kentucky Utilities
kW . kilowatt
kWh -- kilTowatt hour
LC --low cost
LIMB -- limestone Injection multistage burner
L/LS -- lime/limestone
LNB -- low-NOx burner
LNC -- low-NOx combustion
LSD -- lime spray drying
m -- meter
MM -- millions
MW -- megawatt
NAPAP -- National Acid Precipitation Assessment Program
NGR -- natural gas reburning
NRDC -- Natural Resources Defense Council
NSPS -- new source performance standard
NTIS -- National Technical Information Service
OEUI -- Ohio Electric Utilities
OFA -- overflre air
OWF -- opposed, wall-fired
O&M -- operating and maintenance
PCC -- physical coal cleaning
PM -- particulate matter
psia -- pounds per square inch absolute
xviii
-------
ABBREVIATIONS AND SYMBOLS (Continued)
2
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
S/kW -- dollars per kilowatt
SYMBOLS
MgO -- magnesium oxide
NH^ -- ammonia
NOx -- nitrogen oxides
SOg -- sulfur dioxide
SO3 -- sulfur trioxide
xix
-------
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.
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
_2
m
Btu/lb
0.5556
kg-calories/kg
°F
5/9 (°F-32)
°C ,
ft
0.3048
in
ft2
0.0929
ft3
0.028317
m3
gal.
3.78533
L
Ib/MMBtu
1.8
kg/kg-calorie
psia
0.0703
g/cm2
ton
0.9072
ton
xx
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SECTION 3.0 ALABAMA
3.1 ALABAMA POWER COMPANY
3.1.1 Barrv Steam Plant
The Barry steam plant is located within Mobile County, Alabama, as part
of the Alabama Power Company system. The plant is located adjacent to the
Mobile River and contains five coal-fired boilers with a total gross
generating capacity of 1,525 MW,
Table 3.1.1-1 presents operational data for the existing equipment at
the Barry plant. The boilers burn low sulfur coal. Coal shipments are
received by barge and unloaded through a water channel to a coal storage and
handling area west of the plant and close to the river.
PM emissions for the boilers are controlled with retrofit ESPs located
behind old ESPs. Units 1-3 have hot side ESPs. The plant has a wet fly ash
handling system and ash is disposed of in an ash pond southeast of the
plant. Units 1-3 are ducted to a common retrofit chimney and units 4 and 5
have separate chimneys. Two old chimneys behind units 1-3 are left intact
along with the old ESPs. The following evaluation is based on a 1980 aerial
photograph of the plant. Any additions to the plant layout since that time
should be taken into consideration.
Lime/Limestone and Lime Spray Drying F6D Costs--
The five boilers are located beside each other adjacent to the river.
The absorbers for units 1-3 would be located close to unit 1 between the
common chimney and the coal pile and adjacent to the employee parking area.
The absorbers for units 4 and 5 would be located on the other side of the
plant {to the east) and adjacent to the unit 5 chimney. The limestone
preparation, storage, and handling area would be located behind the unit 1-3
absorbers. A plant road and part of the employee parking area would have to
be relocated for unit 1-3 absorbers; therefore, a factor of 10 percent was
assigned to general facilities. For unit 4-5 absorbers, some storage
buildings and oil tanks would have to be demolished and relocated; as such,
3-1
-------
TABLE 3.1.1-1. BARRY 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)
LUC (BTU/LB)
(PERCENT)
1, 2 3 4 5
125 225 350 700
65,67 74 57 76
1954 , 1959 1969 1971
TANGENTIAL
93 147 NA 334
NO
0.8
12,000
13.0
WET SLUICE
PONDS/ON-SITE
1 12 3
BARGE
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU) 0.05
REMOVAL EFFICIENCY NA
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.7 to
SURFACE AREA (1000 SQ FT) 183.6
GAS EXIT RATE (1000 ACFM) 714
SCA (SQ FT/1000 ACFM) 257
OUTLET TEMPERATURE (*F) 655
ESP
1976
0.04 0.01 NA
99.9 99.9 99.9
5.0 0.5 to 3.0
316.6 451.2 635.0
1274 1367 2427
249 330 262
721 269 266
3-2
-------
a factor of 10 percent was assigned to general facilities for these
absorbers. A low site access/congestion factor was assigned to all of the
FGD absorber locations reflecting the easy accessibility to the absorber
locations and the low congestion.
For units 1-3 and 5, short duct runs would be required for L/LS-FGD
cases (about 100 to 300 feet) and a low site access/congestion factor was
also assigned to the flue gas handling system because of no major
obstacles/obstructions in the surrounding areas. Absorbers for unit 4 would
be placed beside unit 5 ESPs resulting in a duct length of S00 feet and a
new chimney for this unit. A high site access/congestion factor was
assigned to the unit 4 flue gas handling system because the unit 4 chimney
and unit 5 ESP makes access difficult. The major scope adjustment costs and
retrofit factors estimated for the FGD technologies are presented in
Tables 3.1.1-2 through 3.1.1-4.
LSD with reuse of the existing ESPs was not considered for units 1-4.
Units 1, 2, and 3 have hot side ESPs and for unit 4 reuse of the existing
ESPs would be very difficult. Therefore, LSD with a new baghouse was
considered for units 1-4. LSD with reuse of the existing ESPs was
considered for unit 5. The.absorbers and new baghouses for all units would
be located in similar locations as the absorbers in the L/LS-FGD case. For
all units, moderate flue gas handling duct lengths were required. For all
units, the locations of the baghouses would be close to the absorbers and,
as such, a low site access/congestion factor was assigned to these
locations.
FGD cost estimates for the Barry plant are not presented because it is
unlikely that the current low sulfur coal would be used if scrubbing were
required. FGD cost estimates based on the current coal would result in low
estimates of capital/operating costs and high cost effectiveness values.
Coal Switching and Physical Coal Cleaning Costs--
Because the Barry plant 1s already using low sulfur coal, CS and PCC
were not considered in this study.
3-3
-------
TABLE 3.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BARRY
UNITS 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 NA
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000S) 1145,1940 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE NA
BAGHOUSE CASE ; ' 1.16
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 10 0 10
3-4
-------
TABLE 3.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR. BARRY UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
2882
NA
NA
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
2450
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA '
ESP REUSE CASE
NA
BAGHOUSE CASE
1.36
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 10
0
10
3-5
-------
TABLE 3.1.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR BARRY UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
'.NA
YES
ESTIMATED COST (1000$)
5365
NA
5365
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
1.43
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10
3-6
-------
Low N0X Combustion--
Units 1-5 are dry bottom, tangential-fired boilers. The combustion
modification technique applied to all boilers was OFA. Table 3.1.1-5 shows
the OFA NOx reduction performance for each unit. Table 3.1.1-6 presents the
NOx cost results of retrofitting OFA at the Barry plant.
Selective Catalytic Reduction-
Hot side SCR reactors for units 1-3 would be located beside unit 1 in a
low site access/congestion area. The cold side SCR reactor for unit 4 would
be placed behind unit 5 ESPs adjacent to unit 4 ESPs/chimney. A high site
access/congestion factor would be assigned to this location due to the
limited space available behind unit 5. The cold side SCR reactor for unit 5
would be located adjacent to unit 5 in a low site access/congestion area.
For flue gas handling, a duct length of 250 feet would be required for all
units. Because units 1-3 have high temperature ESPs, flue gas preheat for
the SCR unit is not required. The ammonia storage system was placed close
to the sorbent storage preparation area west of the plant. A factor of
20 percent was assigned to general facilities for all units due to the need
to relocate plant roads and storage buildings.
Table 3.1.1-5 presents the SCR process area retrofit factors and scope
adder costs. Table 3.1.1-6 presents the estimated cost of retrofitting SCR
at the Barry boilers.
Duct Spray Drying and Furnace Sorbent Injection-
DSD and FSI with ESP reuse were not evaluated for units 1-3 because
these units have hot side ESPs. For unit 4, it appears that sufficient duct
residence time is available between the boilers and the retrofit ESPs or the
old ESPs could be used for sorbent injection or humldification. By contrast,
for unit 5, there does not appear to be sufficient duct residence time
between the boiler and the ESPs. However, sorbent injection was evaluated
because the first ESP section could be modified for sorbent injection or
humidification and additional plate area could be added downstream of the
ESPs. A high site access/congestion factor was assigned for upgrading the
ESPs for unit 4 because of the access difficulty to the existing ESPs. A
3-7
-------
TABLE 3.1.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR BARRY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 3 4 5
FIRING TYPE TANG TANG TANG TANG
TYPE OF NOx CONTROL OFA OFA OFA OFA
FURNACE VOLUME {IOOO CU FT) 93 147 NA 334
BOILER INSTALLATION DATE 1954 1959 1969 1971,
SLAGGING PROBLEM NO NO NO NO
ESTIMATED NOx REDUCTION (PERCENT) 25 25 25 25
SCR RETROFIT RESULTS :
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW LOW HIGH LOW
SCOPE ADDER PARAMETERS--
New Chimney (1000$) 0 0 0 0
Ductwork Demolition (1000$) 32 50 69 116
New Duct Length (Feet) 250 250 250 250
New Duct Costs (1000$) 1411 1991 2578 3867
New Heat Exchanger (1000$) 0 0 3952 5991
TOTAL SCOPE ADDER COSTS (1000$) 1443 2041 6599 9974
RETROFIT FACTOR FOR SCR 1.16 1.16 1.52 1.16
GENERAL FACILITIES (PERCENT) 20 20 20 20
3-8
-------
Table 3.1.1-6. NO* Control Cost Results for the Barry Plant (Jim 1988 Collars)
ssis3asss=3Sss:3:3s::s3S3S33Sssssssssasiisaasssa3aBSSa883S3s:ssssssa8esaasBSsaaM8i8asa&oaa3S8S8sasass35:ssssass:
Technology Bofler Main Boiler Capacity Coal Capital Capital Annual Annual ' MOx NOx NOx Cost
Number Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW>
(X>
Content
(SMM>
(S/kU)
(SMM)
(nilU/kHh)
(X)
(tons/yr)
($/ton)
Factor
(X)
LNC-OFA
1
1.00
12S
65
0.8 -
0.7
5.4
0.1
0.2
25.0
552
259.2
LNC-QFA
' 2
1.00
125
67
0.8
0.7
5.4
0.1
0.2
25.0
569
251.4
INC-QFA
3
1.00
225
74
0.8
0.9
3.8
0.2
0.1
25.0
1131
- 160.1
LNC-OFA
4
1.00
350
57
0.8
1.0
2.9
0.2
0.1
25.0
1356
159.3
tMC-OFA
5
1.00
700
76
0.8
.1.3
1.9
0.3
0.1
25.0
3615
78.8
tNC-OFA-C
1
1.00
125
65
0.B
0.7
5.4
0.1
0.1
25.0
552
154.0
LNC-OFA-C
2
1.00
125
67
o.a
0.7
5.4
' 0.1
0.1
25.0
56?
149.4
LNC-OFA-C
3
1.00
225
74
o.a
0.9
3.S
0.1
0.1
25.0
1131
95.1
LNC-OFA-C
1.00
350
57
o.a
1.0
2.9
0.1
"0.1
25.0
1356
94.6
INC-OFA-C
1.00
TOO
76.
0.8
1.3
1.9
0.2
0.0
25.0
3615
46.8
SCR-3
1
1.16
125
65
0.8
20.9
167.5
7.1
9.9
80.0
1767
4002.7
SCR-3
1.16
125
67
0.8
20.9
167.6
7.1
9.7
80.0
1821
3891.2
SCR-3
1.16
225
74
0.8
31.4
139.4
11.2
7.7
80.0
3621
3100.1
SCR-3
4
1.52
350
57
0.8
56.4
161.1
18.6
10.7
80.0
4338
4295.2
SCR-3
5
1.16
700
76
0.8
83.4
119.2
31.2
6.7
80.0
11568
2694.6
SCR-J-C
1
1.16
125
651
0.8
20.9
167.5
4.1
5.8
80.0
1767
2346.5
SCR-3-C
1.16
125
67
0.8
20.9
167.6
4.2
5.7
80.0
1821
2281.0
SCR-3-C ¦
3
1.16
225
74
0.8
31.4
139.4
6.6
4.5
80.0
3621
1815.0
SCR-3-C
4
1.52
350
57
0.8
56.4
161.1
10.9
6.3
80.0
4338
2519.1
SCR-3-C
5
1.16
700
76
0.8
83.4
119.2
18.2
3.9
80.0
11568
1576.2
SCR-7
1
1.16
125
65
0.8
20.9
167.5
6.0
8.5
80.0
1T67
3421.5
SCR-7
2
1.16
125
67
0.8
20.9
167.6
6.1
8.3
80.0
1821
3327.3
SCR-7
3
1.16
225
74
0.8
31.4
139.4
9.4
6.4
80.0
3621
2589,5
SCR-7
4
1.52
350
57
0.8
56.4
161.1
15.8
9.0
80.0
4338
3632.3
SCR-7
1.16
700
76
0.8
83.4
119.2
25.4
5.5
80.0
11568;
2197.4
SCR-7-C
1
1.16
125
65
0.8
20.9
167.5
3.6
5.0
80.0
1767
2013.5
SCR-7-C
2
1.16
125
67
0.8
20,9
167.6
3.6
4.9
80.0
1821 '
1957.9
SCR-7-C
3
1.16
225
74
0.8
31.4
139.4
5.5
3.8
80.0
3621
1522.4
SCR-7-C
4
1.52
350
57
0.8
56.4
161.1
9.3
5.3
80.0
4338
2139.3
SCR-7-C
5
1.16
700
76
0.8
83.4
119.2
14.9
3.2
80.0
11568
1291.3
s*:ss3*M»»c**B**a^:«ra3»aa«3:3*as«4MraHm»at«a^*»**»*aara^am«ai*:auma^»auMt«B(aMt*»»M*M
3-9
-------
moderate access/congestion difficulty factor was assigned for upgrading the
unit 5 ESP.
Tables 3.1.1-7 and 3.1.1-8 present a summary of the site access/
congestion factors for FSI and DSD technologies at the Barry steam plant.
Table 3.1.1-9 presents the costs estimated to retrofit sorbent injection
technologies at the Barry boilers. Because the plant is burning low sulfur
coal, the estimated unit costs are high.
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 Barry plant. Units 1-3 would be considered good
candidates for repowering/retrofit because of their small boiler sizes.
Units 4 and 5 would not be considered good candidates because they are more
than 300 MW units. All units have high capacity factors making the cost of
repowering less attractive due to downtime cost (replacement power).
3-10
-------
TABLE 3.1.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BARRY UNIT 4
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$) 2882
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$ 77
TOTAL COST (1000$)
ESP UPGRADE CASE 2959
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE , " NA
3-11
-------
TABLE 3.1.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BARRY UNIT 5
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 5365
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$) 129
TOTAL COST (1000$)
ESP UPGRADE CASE 5494
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE • NA
3-12
-------
Title 3.1,1-9. Sumiary of DSO/fSl Control Cost# for the Barry Plant (June 1988 Dollars)
SS8a3S3CI3S3SaS33S»t»«
^sasasftxsassssssxssssssasssaaaas
33333sssss;;;sszss:=3
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Muter Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty SI*iSP-70
FS1+ESP-70
FS!*ESP-70-C
fS]*ESP-70-C
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00'
1.00
1.00
350
700
350
700
350
700
350
700
350
700
350
700
57
76
57
76
57
76
57
76
57
76
57
76
0.3
Q.8
0.8
0.8
0.8
0.8
0,8
0.8
0.8 .
0.8
0.B
O.B
14.7
26.3
14.7
26.3
15.4
29.7
15.4
29.7
15.5
29.9
15.5
29.9
42.0
37.6
42.0
37.6
44.0
42.4
44.0
42.4
44.3
42.7
44.3
42.7
8.6
16.3
5.0
9.4
8.2
17.8
4.8
10.3
S.4
18.1
4.9
10.5
4.9
3.5
2.9
2.0
4.7
3.B
2.7
2.2
4.8
3.9
2.8
2.2
46.0
46.0
46.0
46.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
5234
13764
5234
13764
5640
15039
5640
15039
7895
21054
7895
21054
1646.2
, .1183.1
955.7
686.4
1462.0
1183.0
849.8
666.6
1057.8
857.6:
614.9
497.7
55S3S1S33
33S33SS833833
3SrS33333S313
3-13
-------
3,1,2 Gadsden Steam Plant
The Gadsden Steam Plant is located in Etowah County, Alabama, as part
of the Alabama Power Company system. The plant contains two coal-fired
boilers with a total gross generating capacity of 120 MW. Tables 3.1.2-1
through 3.1.2-8 summarize the plant operational data and present the SO^ and
N0X control cost and performance estimates.
TABLE 3.1.2-1. GADSDEN 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
60
48, 75
1949
TANGENTIAL
NA
NO
I.5
12500
II.3
WET DISPOSAL
POND/ON-SITE
1
TRUCK/RAILROAD
PARTICULATE CONTROL
TYPE ESP*
INSTALLATION DATE 1975
EMISSION (LB/MM BTU) 0.05, 0.02
REMOVAL EFFICIENCY 99.95
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) NA
. SURFACE AREA (1000 SQ FT) NA
EXIT GAS FLOW RATE (1000 ACFM) 300
SCA (SQ FT/1000 ACFM) NA
OUTLET TEMPERATURE ( F) 315
* An SCA size of 300 was assumed for both units.
3-14
-------
TABLE 3.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR GADSDEN
UNITS 1 OR 2 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA HIGH
FLUE GAS HANDLING LOW 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 MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 593 NA 593
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE 1.61
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.37
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
* L/S-FGD absorbers for units 1 and 2 would be located south
of the common chimney for units 1 and 2. LSD-FGD absorbers
would be located beside the unit ESPs.
3-15
-------
Table 3,1.2-3. Summary of FGB Control Costs for the Gadsden Plant. (Juw 1988 Dollars).
Technology Boiler Hain Boiler Capacity Coal Capital Capital Annual Annual
S02
S02
Nurtoer Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Difficulty (HW3
(X)
Content
(SUM)
L/S FGD
1
1.27
60
48
1.5
29.1
484.5
¦ 11.8
46.6
90.0
2622
L/S FGD
2
1.27
60
75
1.5
29.1
484.8
12.8
32.4
90.0
4097
L/S FG5
1-2
1.27
120
62
1.5
41.0
341,5
17.5
26.9
90.0
6773
l/S FC0-C
1
1.27
60
48
1.5 '
29.1
484.5
6,9
' 27.2'
90.0
- 2622
L/S FGD-C
2
1.27
60
75
1.5
29.1
484.8'
7.4
18.9
90.0
4097
L/S FGD-C
1-2
1.27
120
62
. 1.5
41.0
341.5,
10.2
15.7
90.0
6773
IC FGD
1-2
1.27
120
62
1.5
28.6
238.1
13.8
21.1
90.0
6773
LC FGD-C
1-2
1.27
120
62
1.5
28.6
238.1
8.0
12.3
90.0
6773
LSO+ESP
. 1 .
1.61
60
48
1.5
13.6
225.9
6.4
25.5 '
76.0
2223
ISD+ESP
2
1.61
60
75
1.5
13.6
225.9
6.8
17.3
76.0
3473
LS0+ESP-C
1
1.61
60
48
1.5
13.6
225.9
3.8
-14.9
76.0
2223
S02 Cost
Effect.
(S/ton)
LSD*ESP-C
1.61
60
1.5
13.6 225.9 4,0
10.1
76.0
3473
4488.4
3117.5
2588.2
2621.3
1818.0
1510.0
2032.6
1183.5
2897.7
1967.1
1687.5
1144.5
3-16
-------
* Table 3.1,2-4, Suimary of Coat Switching/Cleaning Coses for the.Gadsden Plant (June 1988 Dollars)
s^-sssssSSSSSSllSSSSSSSSSSIStHSSSSSSSlSSSXBf SfSS5StSS93BSIllllSSSSSSS33311HI3IBSISlIIHISlSlllSSSS
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual £02 $02 $02 Cost
Ntmber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MV) {mills/kwh) (X) (tons/yr) (S/ton)
Factor .
CS/S«*15
1
1.00
60
48
1.5
2.8
46.5
4.2
16.5
' 37.0 ¦
1092
3812.1
CS/B*t15
2
1.00
60
75
1.5
2.8
46.5
6.1
15.6
,37.0
1706
3594.7
CS/B*$15-C
1
1.00
60
48
1.5
2.8
46.5
2.4
9.5
37.0
1092
2195.5
CS/B+S15-C
2
1.00
60
73
1.5 •
2.8
46.5
3.5
8.9
37.0
1706
2066.9
CS/B+S5
1
1.00
60
48
1.5
2.2
36.1
2.0
7.8
37.0
1092
1803.2
CS/B+J5
2
1.00
60
75
1.5
2.2,
36.1
2.8
7.0
37.0
1706
1621.9
CS/B*$5-C
1
1.00
60
48
1.5
2.2
36,1
1.1
4.5
37.0
1092
1042.0
CS/B+S5-C
2
1.00
60
75
1.5
2.2
36.1
1.6
4.0
37.0
1706
934.9
—T
::s3S3s:
IIHIBfl
S M Si 91M StS ¦!
tWi ¦¦¦¦¦¦!
3-17
-------
TABLE 3.1.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR GADSDEN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
FIRING TYPE " TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE 1949
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 18
New Duct Length (Feet) 200
New Duct Costs (1000$) 735
New Heat Exchanger (1000$) 1372
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 2125
COMBINED CASE 3213
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
* Cold side SCR reactors for units 1 and 2 would be located
south of the common chimney for units 1 and 2.
3 - IB
-------
'Table- 3.
,1.2-6,
NO* Control Cost Results for the Gadsden Plant
(June
1988 Dollars)
Technology
Botier
Main
ssmsmmsssmmmmsssmsmmmma%
Boiler Capacity Coal
¦iiiiiiisiasiiiiauiifai
Capital Capital Annual
1SB81CSB
Annual
SI1XMMRS
KOx
lllBBISSZBi
NOx
NOx Cost
Nimber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
-------
TABLE 3.1.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GADSDEN UNITS 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 YES
ESTIMATED COST (1000S) 593
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$) 20
TOTAL COST (1000$)
ESP UPGRADE CASE 613
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
Medium duct residence time exists between the boilers and
their respective ESPs. A medium factor was assigned to ESP
upgrade since there is some congestion among the ESPs.
3-20
-------
Table 3.1.2-8. Summary of DSO/FSI Control Costs for the Gadsden Plant (June 1988 Dollars)
Technology
Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 SO2 S02 Cost
ttunber Retrofit Six* Factor Sulfur Cost - Cost Cost Cost Removed Removed, Effect,
Difficulty (MM) (X) Content (SUM) (S/lcW) (SUM) (mills/kwh) (X) (tons/yr) (i/ton)
Factor (X)
DSD+ESP
DSO+ESP '
DSD+ESP-C
DSO+ESP-C
FSt+fSP-50
FS!*ESP-50
FSUESP-50-C
FSI+ESP-50-C
FSI+ESP-70
FSI+ESP-70
FSl*ESP-70-C
FSI+ESP-70-C
1.
2
1.
2
1
2
1
2
1
2
1
2
.00
.00
.00
.00
.00
.00
.00
,00
,00 ¦
.00
.00
.00
60
60
60
60
'60
60
60
60
60
60
60
60
48
75
48
75
48
75
48
75
48
75
48
75
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1;5
1.5
1.5
1.5
5.3
5.3
5.3
5.3
5.9
5.9
5,9
5.9
5.9
5.9
5.9
5.9
88.4
88.4
88.4
88.4
98.2
98.2
98.2
98.2
99.0
99.0
99,0
99.0
4.0
4.4
2.3
2.5
3.4
3.9
2.0
2.3
3.4
3.9
2.0
2.3
16.0
11.1
9.3
6.4
13.4
9.9
7.8
5.7
13.5
10.0
7.8
5.8
49.0
49.0
49.0
49.0
50,
50,
50.
50,
70.0
70.0
70.0
70.0
1417
2215
1417
2215
1457
2276
1457
2276
2039
3186
2039
3186
2852.0
1984.3
1650.8
1147.6
2313.0
1710.0
1343.4
991.4
1667.8
1235.2
968.6
716,1
3-21
-------
3.1;3 Gaston Steam Plant
The Gaston steam plant is located within Shelby County, Alabama, as
part of the Alabama Power Company system. The plant is located on the west
bank of the Goosa River and contains five coal-fired boilers with a total
gross generating capacity of 1,880 MW.
Table 3.1.3-1 presents operational data for the existing equipment at
the Gaston plant. The boilers burn medium sulfur coal. Coal shipments are
received by railroad and transferred to a coal storage and handling area
south of the plant and adjacent to the river.
PM emissions for all boilers are controlled with retrofit ESPs located
behind each unit and close to the river. The plant has a dry fly ash
handling system. Fly ash is disposed of in a landfill adjacent to the coal
pile. Part of the fly ash is sold. Units 1 through 4 are served by a
common chimney located adjacent to unit 1 north of the plant. Unit 5 has
its own chimney south of the plant. Four old chimneys, which were serving
units 1-4, are left intact behind the units. A coal conveyor stretches from
the poal pile to unit 1 runs behind the old chimneys and retrofit ESPs to
each unit. The following evaluation is based on a 1981 aerial photograph,
and any alterations made to the plant layout since this time should be taken
into consideration.
lime/Limestone and Lime Spray Drying FGD Costs--
The five boilers are located beside each other and parallel to the
river. The absorbers for units .1-4 would be located beside the unit 1-4
common chimney to the north of the plant. The absorbers for unit S would be
located adjacent to its chimney south of the pi ant. The limestone
preparation, storage, and handling area would be located west of the plant
and close to the cooling towers. For unit 1-4 absorber locations, part of
the employee parking area has to be relocated and, as such, a base factor of
8 percent was assigned to general facilities. For the unit 5 absorber
location, some of the oil storage tanks have to be relocated resulting in a
10 percent general facilities.
3-22
-------
TABLE 3.1.3-1. GASTON 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)
1,2,3,4
5
250
880
72,70,60,70
68
1960,60,61,62
1974
OPPOSED WALL
TANG
NA
400
NO
NO
1.4
1.4
12,300
12,300
12.0
12.0
DRY DISPOSAL
ON-SITE/SELL
1
2
RAILROAD
ESP
ESP
1974-76
1974
0.05-0.07
0.12
99.1-98.7
98.4
NA NA
342,363,342,342 1175
1250 4100
274,290,274,274 287
650 630
3-23
-------
A medium site access/congestion factor was assigned to all of the FGD
absorber locations. For units 1-4 absorbers, this was due to being located
close to the water channel and water intake structure (underground
obstructions). The medium site access/congestion factor for unit 5 absorber
location is due to the coal conveyor and oil storage tanks.
For flue gas handling, short duct runs would be required for the
L/LS-FGD cases (about 200 feet) because the absorbers are placed immediately
behind the chimneys. Low site access/congestion factors were also assigned
to the flue gas handling system because of the easy accessibility to the
existing chimneys.
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs operate at temperatures greater than 600°F. This
eliminates the benefits of gas cooling/humidification on ESP performance.
Additionally, access to the ESPs is extremely difficult and might result in
a long boiler downtime. Therefore, LSD with a new baghouse was considered
for the Gaston plant. LSD absorbers would be located close to the chimneys
and the baghouses would be located adjacent to the absorbers. A medium site
access/congestion factor was also assigned to the absorber/baghouse
locations.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 3.1.3-2 and 3.1.3-3. Table 3.1,3-4
presents the capital and operating costs for commercial FGD technologies.
The low cost FGD option reduces costs for units 1-4 due to the elimination
of spare absorber modules and economy of scale that occurs when combining
process areas and maximizing absorber size. For unit 5, the low cost option
reduces cost due to the elimination of the spare absorbers and increased
absorber size.
Coal Switching and Physical Coal Cleaning Costs-
Table 3.1.3-5 presents the IAPCS cost results for CS at the Gaston
plant. These costs do not include boiler and pulverizer operating cost
changes or any system modifications that may be necessary to blend coal.
Coal switching for a fuel price differential of $15 per ton is higher than
that of $5 per ton because of inventory capital and preproduction costs,
3-24
-------
TABLE 3.1.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR GASTON UNITS 1
2, 3, OR 4 .
FGD TECHNOLOGY '
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA ,
BAGHOUSE CASE
LOW ..
DUCT WORK DISTANCE (FEET)
•100-300
NA
ESP REUSE
. BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA .
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.30
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.40
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.37
GENERAL FACILITIES (PERCENT) 8
0
8
3-25
-------
TABLE 3.1.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR GASTON UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW. BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY ..
NO
NA
NO-
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
¦ 0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.30
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1,40
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.37
GENERAL FACILITIES (PERCENT) 10
0
10
-------
table 3.1.3-4. Suwnary of FGD Control Costs for the Gaston Plant (June 1938 Dollars)
SBB9sssssssssas&;:asss:
Technology Boil#r Main Boiler Capacity Coal , Capital CapitaL Annual . Annual S02 S02 S02 Cost
Hunter'-Retrofit Size factor Sulfur Cost Cost' Cost " Cost Removed Removed Effect.
Difficulty (My) (X) Content (few) (S/kU) (SMM) (nills/kwh) CX) (tons/yr) (S/tonJ
Factor (X)
l/S FGD
1
1.30
• 250
72
1.4
65.8
263.3
28.8
18.3
90.0
15578
1851.0
US FGD
2
. -1,30
250
TO
1.4
65.8
263.3
28.6'
18.7
90.0
15145
1889.5
L/S FGD
3
1.30
250
60 '
1.4
65.8
263.2
27.5
20.9
90.0
12982
2120.4
L/S FGD
4
1.30
250
70
1.4
65.8
263.3
28.6
18.7
90.0
15145
1889.5
US FGO
5
1.30
880
68
'¦*
150.3
170.8
69.5
13.2
.90.0
-51789
1341.1
L/S FGO-C
1
1,30
250'
72
1.4
65.8
263.3
16.8
10.7
90.0
15578
1079.4
L/S FGD-C
2
1.30
250
70
1.4
65.8
263.3•
16.7
10.9
90.0
15145 •
1102.0
L/S FGD-C
- 3
1.30
250
60
1.4
65.8
263.2'
16.1
12.2 '
90.0
12982
1237.6
L/S FGD-C
4
1.30
250
70
1.4
65.8
263.3
16.7
10.9
90.0
15145
1102.0
L/S FGD-C
5
1.30
. 880
68
1.4
150.3
170.8
40.5
7.7
90.0
51789
781.4
LC FGO
1-4
1.30
1000
68
1.4
142.6
142.6
69.9
11.7
90.0
58851
1188.2
LC FGO
5
1.30
880 .
68
1.4
125.7
142.9
62.1
11.8
90.0
51789
1198.4
LC FGO-C
1-4
1.30
1000
68
1.4
142.6
142.6
40.7
6.8
90.0
58851
691.6
LC FGD-C
5
1.30
880
68
1,4
125.7
142.9
36.1
6.9
90.0
51789
697.5
LSD+FF .
1
1.40
250
72
1.4
74.1
296.4
26.8
17.0
87.0
14974
1791,6
LSO+FF
2
1.40
250
70
1.4
74.1
296.4
26.7
17.4
87.0
14558
1831.0
LSD+FP
3
1.40
250
60
1.4
74.1
296.4
25.8
19.6
87.0
12479
2068.2
LSC+FF
4
1.40
250
70
1.4
74.1
296.4
26.7
17.4
87.0
14558
1831.0
LSD*FF
5
1.40
880
68
1.4
237.1
269.4
81.7
15,6
87.0
49782
1641.5
iSO+FF-C
¦ 1
1.40
250
72
1.4
74.1
296.4
15.7
10.0
87.0
14974
1048.7
LSD+FF-C
2
1.40
250
70
1.4
74.1
296.4
15.6
10.2
87.0
14558
1071.9
LSD+FF-C
3
! .40
250
60
1.4
74.1
296,4
15.1
11.5
87.0
12479
1211.5
LSD+FF-C
4
1.40
250
70
1.4
74.1
296.4
15.6
10.2
87.0
14558
1071.9
LSD+FF-C
5
1,40
880
68
1.4
237.1
269.4
47.9
9.1
87.0
49782
961.8
SS8388KSS
s=;;ssas:ss:
:as3s=3sa
xaesnssa
S8S3S3SSS
ssaaessss
23S299233S9l3SSrX5
sssssasa
83»3SSS
SSS&S3S3S5"
3-27
-------
Table 3.1.3-5. Summary of Ceal_ Snitch)rig/Clearn"rig Costs for the Gaston Plant {Juri« 1988 Dollars)
Biaoxs«sssssB88SKSSKBllSBXB«a»s3M9!SS»8SSxass)»Ba8ixsssaBBas8a»s3s:sssssjlxs8SSss3S?a3Eas=s::i::::::::asssar£s=: '
Technology ~ Boiler Main Bel Iar Capacity Coal Capital Capitat Annual Annual/ S02 S02 . S02 Cost
Nunber Retrofit Size Factor Sulfur ! Cost Cost' -Cost "Cost Removed Removed _ Effect.
Difficulty (MH) (niiUs/kuh) (%} (tons/yr> CS/ton)
Factor (%5
CS/8*$15
1.00
2S0
72
1.4 '
8.4 •
33.7
22.4
14.2
34.0
5926
3772.1
CS/B*$15
1.00
ISO
70'
1.4
8.4
33.7
21.8
14.2
34.0 .
5761
3781.1
CS/8+S15 ¦
¦1.00
•' 250
60
1.4
8.4
33.7
18.9
14.4
34.0
4938
3834.9
CS/I*$!5
1.00
250
. 70
1.4
8.4
33,7
21.8
14.2
34.0
5761
3781.1
CS/B+S15
1.00
880
68
1.4
26.2
29.7
72.7
13.9
34.0
19701•
3691.1
CS/B*S15-C
1.00
250
72
1.4
8.4
33.7
12.8
B.I
34.0
5926
2167.6
CS/S+S15-C
1.00
250
70
1.4
8.4
33.7
12.5
8.2
34.0
5761
2172.9
CS/B+S15-C
1.00
250
60
1.4
8.4
33.7.
10.9
8.3
34.0
4938
2204.8
CS/8*S15-C
' 1.00
2S0
70
1.4
' 8.4
33.7
12.5
8.2
34.0
5761
2172.9
CS/B+S15-C
1.00
880
68
1.4
26.2
29.7
41.8
8.0
34.0
19701
2120.7
CS/8+S5
1.00
250
72
1.4
5.6
23.3
8.9
5.6
34.0
5926
1497.8
CS/8*$S
1.00'
250
70
'«*.
5.8
23.3
8.7
5.7 •
34.0
5761
1504.6
CS/B*$5
1.00
250
60
1.4
5.8
23.3
7.6
5.8
34.0
4938
• 1545.2
CS/S+S5
1.00 .
250
70
1.4
5.8
23.3
8.7
5.7
34.0
5761
1504.6
CS/B+S5
1.00
880
68
1.4
17.1
19.4
27.8
5.3
34.0
19701
1412.2
CS/B+S5-C
1.00
250
72
1.4
5.8
23.3
5.1
3.2
34.0
5926
862.6
CS/B*$5-C
1.00
250
70
1.4
5.8
23.3
5,0
3.3
34.0
5761
866.6
CS/B+I5-C
1.00
250
60
1.4
5.8
23.3
4.4
3.3
34.0
4938
890.6
CS/B+I5-C
1.00
250
70
1.4
5.8
23.3
5.0
3.3
34.0
5761
866.6
CS/B+15-C
1.00
860
£8
1.4
17.1
19.4
16.0
3.1
34.0
19701
813.0
caaasssssssassss
mmmmanKmmmmmwa
525313 331S
S3SH88S3
sesEsssa
SSB3S3SSS
31 SI S3 SI 35
SBBSasa
ssaassassa
SS3SS3S
C338SSSSS
SSS84ESKS8
3-28
-------
which are a function of variable costs (e.g. fuel costs). PCC was not
evaluated because this is not amine mouth plant.
Low NO Combustion--
A
Units 1-4 are dry bottom, opposed wall-fired boilers rated at 250 MW
each and unit 5 is a dry bottom, tangential-fired boiler rated at 880 MW.
The combustion modification technique applied to boilers 1-4 was LNB and for
unit S was OFA. Tables 3.1.3-6 and 3.1.3-7 present the N0x performance and
cost results of retrofitting LNB and OFA at the Gaston plant. Although
boiler volumetric data was not available for units 1-4, a moderate N0X
.reduction was assumed to be typical for these boilers.
Selective Catalytic Reduction--
Hot side SCR reactors for all units would be located immediately behind
the chimneys in low site access/congestion areas. This is due to the
smaller space needed for the SCR reactors compared to the FGD absorbers. A
duct length of 250 feet was estimated for the flue gas handling system. The
ammonia storage system was placed close to the sorbent storage area adjacent
to the air cooling towers. Some plant roads have to be relocated;
therefore, a factor of 15 percent was assigned to general facilities.
Table 3.1.3-6 presents the SCR process area retrofit factors and scope
adder costs. Table 3.1.3-7 presents the estimated cost of retrofitting SCR
at the Gaston boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the Gaston steam plant is
not feasible. This is due to the inadequate duct residence time between the
boilers and the retrofit ESPs for either humidification (for FSI
application) or sorbent droplet evaporation (for DSD application). Also,
because the ESP temperatures are high (>600°F), gas cooling/humidification
would not significantly improve ESP performance and would hurt air heater
heat recovery.
3-29
-------
TABLE 3.1.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR GASTON
BOILER NUMBER :
COMBUSTION MODIFICATION RESULTS
1,2,3,4 5
FIRING TYPE OWF TANG
TYPE OF NOx CONTROL LNB OFA
FURNACE VOLUME {1000 CU FT) NA 400
BOILER INSTALLATION DATE 1960 1974
SLAGGING PROBLEM NO NO
ESTIMATED NOx REDUCTION (PERCENT) 40 35
SCR RETROFIT RESULTS (EACH UNIT)
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0
Ductwork Demolition (1000$) 54 138
New Duct Length (Feet) 250 250
New Duct Costs (1000$) 2117 4421
New Heat Exchanger (1000$) 0 0
TOTAL SCOPE ADDER COSTS (1000$) 2171 4559
RETROFIT FACTOR FOR SCR 1.16 1.16
GENERAL FACILITIES (PERCENT) . 15 15
3-30
-------
Table 3.1.3-7. KOx Control Cost Results for the Gaston Plant (June 1988 Dollars)
i»8sis3asnuisiaismssaa383iiiBH3S£BasssS9iasaBiiiKiBH3siiiBESSSaSKsasss5scaiiiiiisaaa9BnBiiBissssssaass:
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx" NOx NOx Cost
Nuifeer Retrofit Size Factor Sulfur Cost Cost Coat Cost Removed Removed Effect."
Difficulty (HW) (X) Content (SMI) (S/kV) (MM) (1/ton)
Factor CX3
INC-LNB 1 1.00 250 72 1.4 3.7 14.7 0.8 0.5 40.0 2663 292.2
LNC-LNi 2 1.00 250 70 1.4 3.7 14.7 0.8 0.5 40.0 2589 300.6
LNC-INB 3 1.00 250 60 1.4 3.7 14.7 0.8 0.6 40.0 2219 350.7
LMC-LNB 4, 1.00 250 70 1,4 3.7 14.7 0.8 0.S 40.0 2589 300.6
LNC-LNB-C 1 1.00 250 72 1.4 3.7 14.7 0.5 0.3 40.0 2663 173.6
INC-LM8-C 2 1.00 250 70 1.4 3.7 14.7 0.5 0.3 40.0 2589 178.6
LMC-LMB-C 3 1.00 250 60 1.4 3.7 14.7 0.5 0.4 40.0 2219 208.3
LNC-LNB-C 4 1.00 250 70 1.4 3.7 14.7 0.5 0.3 40.0 2589 178.6
LNC-OFA 5 1.00 880 68 1.4 1.5 1.7 0.3* 0.1 35.0 5534 56.4
LNC-0M-C 5 1.00 880 68 1.4 1.5 1.7 0.2 0.0 35.0 5534 33.5
SCR-3 1 1.16 250 72 1.4 33.3 133.1 12.2 7.7 80.0 5327 2289.6
SCR-3 2 1.16 250 70 1.4 33.3 133.1 12.2 7.9 BO.O 5179 2348.5
SCR-3 3 1.16 250 60 1.4 33.3 133.1 12.0 9.1 BO.O 4439 2703.0
SCR-3 4 1.16 250 70 1.4 33.3 133.1 12.2 7.9 80.0 5179 2348.5
SCR-3 5 1.16 880 68 1.4 99.1 112.6 37.7 7.2 80.0 12649 2977.0
SCR-3-C 1 1.16 250 72 1.4 33.3 133.1 7.1 4.5 80.0 5327 1339.8
SCR-3-C 2 1.16 250 70 1.4 33.3 133.1 7.1 4.6 80.0 5179 1374.3
SCI-3-C 3 1.16 250 60 1.4 33.3 133.1 7.0 5.3 80.0 4439 1582.2
SCR-3-C 4 1.16 250 70 1.4 33.3 133.1 7.1 4.6 80.0 5179 1374.3
SCR-3-C 5 1.16 880 68 1.4 99.1 112.6 22.0 4.2 80.0 12649 1740.7
SCR-7 1 1.16 250 72 . 1.4 33.3 133.1 10.1 6.4 8O.0 5327 1905.3
SCR-7 2 1.16 250 70 1.4 33.3 133.1 10.1 6.6 80.0 5179 1953.2
SCR-7 3 1.16 250 60 1.4 33.3 133.1 10.0 . 7.6 80.0 4439 2241.9
SCR-7 4 1.16 250 70 1.4 33.3 133.1 10.1 6.6 80.0 5179 1953.2
SCR-7 5 1.16 880 68 1.4 99.1 112.6 30.5 5.8 80.0 12649 2407.4
SCR-7-C 1 1.16 250 72 1.4 33.3 133.1 6.0 3.8 80.0 5327 1119.6
SC8-7-C 2 1.16 250 70 1.4 33.3 133.1 5.9 3.9 80.0 5179 1147.9
SCR-7-C 3 1.16 250 60 1.4 33.3 133.1 5.9 4.5 80.0 4439 1318.1
SCR-7-C 4 1.16 250 70 1.4 33.3 133.1 5.9 3.9 80.0 5179 1147.9
SCR-7-C 5 1.16 880 68 1.4 99.1 112.6 17.9 3.4 80.0 12649 1414,4
3-31
-------
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 Gaston plant. Units 1-4 would be considered good
candidates for repowering or retrofit because of their small boiler sizes.
However, the long remaining boiler life and high capacity factors reduce the
applicability of these technologies. Unit 5 is even less likely a candidate
for repowering/retrofit because of the large boiler size, long remaining
life, and high capacity factor.
3-32
-------
3.1.4 Sorqas Steam Plant
Sorbent Injection technologies (FSI and DSD) were not considered for
the boilers at the Gorgas plant due to the short duct residence time between
the boilers and the ESPs and the lack of ESP information.
TABLE 3.1.4-1. GORGAS 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) ,
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
S 6,7 8,9 , 10
60 100 156,161 700
41 42,48 63,55 79
1944 1951,52 1956,58 1972
TANG FRONT WALL TANGENTIAL
NA NA,58.9 NA 334
NO
1.5
12500
11
WET DISPOSAL
POND/ON-SITE
1 12
RAILROAD/TRUCK
ESP ESP ESP
NA NA NA
NA NA NA
NA NA NA
NA NA NA
NA NA NA
NA NA NA
NA NA NA
NA NA NA
ESP
1972
0.06
99.4
NA
NA
320
NA
NA
3-33'
-------
TABLE 3.1.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR GORGAS
UNITS 5, 6 AND 7 *
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
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$)
593,938
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
' NO
RETROFIT FACTORS
FGD SYSTEM
1.38
NA ,
ESP REUSE CASE
NA
BAGHOUSE CASE
1.27
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 units 5,
6 and 7 would be located east of their common chimney.
3-34
-------
TABLE 3.1.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR GORGAS
UNITS 8, 9 AND 10 *
FGD TECHNOLOGY
FflHf FD I IMF
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
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$) 1397-5365
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.68
NA
ESP REUSE CASE
NA '
BAGHOUSE CASE
1.62
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 8,
9 and 10 would be located north of their common chimney.
3-35
-------
Table 3.1.4-4. Suirnery of FGD Control Costs for the Gorgas Plant (June 19&8 Dollars)
• BBBBSBl
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.Technology
Boiler
Main
Boiler Capacity Coat
Capital Capital Annual
Annual
so2
S02
S02 Cost
Number Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (NU)
a>
Content
($MO
(S/kW
-------
Table 3.1.4*5. Sunmary of Coal Snitching/Cleaning Costs for the Gorges Plant (Jwe 1988 Dollars)
it
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW>
tx>
Content,
($HH>
<$/W>
(MN)
(milIs/kwh)
IX)
(tons/yr)
($/tonJ
- Factor '
(X)
CS/S+S15
5
1.00
60
41
. " 1.5
2.8
46.8
3.7
17.0
37.0
, 932
3923.2
C5/B+$15
6
1.00
. 100
42
1.5
4.1
40.7
5.9
16,0
37.0
1592
3696.3
CS/B+S15
7
1.00
100
48
1.5
4.1
40.7
6.6
15.7
37.0
1819
3623.4
CS/B+J15
8
1.00
156
63
1.3 >
5.3
37.0
12.7
14.7
37.0
3725
3403.2
CS/B*I1S
9
1.00
165
55
1.5
6.0
36.6
11.8
14.9 ¦
37.0
3440
3442.7
CS/B+S15
to
1.00
700
79
1.5
21.4
30.6
67.0
13.8
37.0
' 20960-
3198.3
CS/B+t15-C
5
1.00
60
41
1.5
2.8
46.8
2.1
9.8
37.0
932
2261.3
CS/S+S15-C
6
1.00
100
42
1.5
4.1
40.7
3.4
9.2
37.0
1592
2129.2
CS/B*$15-C
7
1.00
100
48
1.5
4.1
40.7
3.8
9.0
37.0
1819
2086.0
CS/B*$1S-C
8
1.00
156
63
1.5
5.8
37.0
7.3
8.5
37.0
3725
1956.8
CS/B*$15-C
9
1.00
165
55
1.5
6.0
36.6
6.8
8.6
37.0
3440
' 1980.3
CS/B+S15-C
10
1.00
700
79
1.5
21.4
30.6
38.5
7-9
37.0
20960
1837.0
CS/B+15
5
1.00
60
41
¦ 1.5
2.2
36.4
1.8
8.2
37.0
932
1897.5
CS/B*t5
6
1.00
100
. 42
1.3
3.0
30.3
" 2.7
7.2
37.0
1592
'1673.3
CS/B-»$5
7
1.00
100
48
1.5
3.0
30.3
2.9
7.0
37.0
1819
1614.6
CS/B+J5
8
1.00
156
63
1.5
4.2
26.6
5.3
6-1
37.0
3725
1418.2
CS/B+S5
9
1.00
165
55
1.5
4.3
" 26.3
5.0
6.3
37.0
3440
1446.6
CS/B-S5
to
1.00
700
79
1.3
14.1
20.2
25.8
5.3
37.0
20960
-1228.7
CS/B+S5-C
5 .
1.00
60
41
1.5
2.2
36.4
1.0
4.7
37.0
932
1097.6
CS/8+t5-C
6
1.00
100
42
1.5
3.0
30.3
1.5
4.2
37.0
1592
967.2
CS/B+S5-C
7
. 1.00
100
48
1.5
3.0
30.3
1.7
4.0
37.0
1819
932.6
CS/B*t5-C
8
1.00
156
63
1.5
4.2
26.6
3.0
3.5
37.0
3725
817.6
CS/B+$5-C
9
1.00
165
55
1.5
4.3
26.3
2.9
3.6
37.0
3440
834.5
C5/B»$5-C
10
1.00
700
79
1.5
14,1
20.2
14.8
3.1
37.0
20960 .
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II
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3-37
-------
TABLE 3.1.4-6. SUMMARY OF NOx RETROFIT RESULTS FOR GORGAS UNITS 5-7
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
5
6, 7
5-7
FIRING TYPE
TANG
FWF
NA
TYPE OF NOx CONTROL
OFA
LNB
NA
FURNACE VOLUME (1000 CU FT)
NA
NA, 58.9
NA
BOILER INSTALLATION DATE .
1944
1951, 52
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
: 40
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
18
27
55
New Duct Length (Feet)
200
200
- 200
New Duct Costs (1000$)
735
991
1733
New Heat Exchanger (1000$)
1372
1864
3307
TOTAL SCOPE ADDER COSTS (1000$)
2125
2882
5095
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for units 5
east of their common chimney.
, 6 and
7 would be
located
3-38
-------
TABLE 3.1.4-7. SUMMARY OF NOx RETROFIT RESULTS FOR GORGAS UNITS 8-10
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
8
9
10
8-10
FIRING TYPE
TANG
TANG
TANG
NA
TYPE OF NOx CONTROL
OFA
OFA
OFA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
334
NA
BOILER INSTALLATION DATE
1956
1958
1972
NA
SLAGGING PROBLEM
NO
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT) 25
25
25
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH HIGH HIGH HIGH
SCOPE ADDER PARAMETERS-
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
38
39
116
154
New Duct Length (Feet)
300
300
300
300
New Duct Costs (1000$)
1928
1992
4640
5787
New Heat Exchanger (1000$)
2434
2517
5991
7513
TOTAL SCOPE ADDER COSTS (1000S) 4400 4549 10747 13454
RETROFIT FACTOR FOR SCR 1.52 1.52 1.52 1.52
GENERAL FACILITIES (PERCENT) _38 38 38 38
* Cold side SCR reactors for units 8, 9 and 10 would be located
north of their common chimney.
3-39
-------
Table 3.1.4-8. NOx Control Cost Results for the Gorges Plant (June 1983 Dollars)
Technology Boiler Main Sailer Capacity Coat CapitBl Capital Annual Annual NOx ' NQx NOx Cost
Nunber Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (%) Content <$W> <$/kU) CSW) (mills/kwh) <%) (tons/yr) ($/ton)
Factor (X)
LNC-LNB
6
. 1.00
too
42
1.5
2.6
25.5
0.5
1.5
40.0
610
884; 4
LNC-LNB
7
1.00
100
48
1.5
2.6
25.5
0.5
1.3
40.0
697
773.8
LHC-LM8-C
6
1.00
100
42
1.5
2.6
25.5
0.3
0.9
. 40.0
610
525.4
LNC-LNB-C
7
1.00
100
48
1.5
2.6
25.5
0.3
0.8
40.0
697
459.7
LtiC-OFA
" 5
1.00
60
41
1.5
0.5
8.4
0.1
0.5
. 25.0
. 160
668.9
LNC-OFA
8
1.00
156
63
1.5
0.7
4.7
0.2
0.2
25.0
637
. 245.1
i-HC-OFA
9
1.00
165
55
1-5
0.8
4.6
0.2
0.2
25.0
566
271.6
WC-OFA
10
1.00
700
79
1.5
1.3
1.9
0.3
0.1
25.0
3586
79.5
LMC-OFA-C
5
1 -00
60
41
1.5
0.5
8.4
0.1
0.3
: 25.0
160
397.5
UC-OFA-C
8
1.00
156
63
1.5
0.7
4.7
0.1
0.1
25.0
637
145.6
LMC-OFA-C
9
1.00
165
55
1.5 -
0.8
4.6
0.1
0.1
25.0
588
161.4
INC-OFA-C
id
1.00
700
79
1.5
1.3
1.9
0.2
0.0
25.0
3586
47.2
SCR-3
,5
1.16
60
41
1.5
13.9
232.1
4.3
19.7
80.0
510
8331.2
SCR-3
, 6-
1.16
100
42
1.5
18.8
187.8
6.0
16.3
80.0
1220
4905.0
SCR-J
7
1.16
100
48
1.5
18.8
187.9
6.0
14.3
80.0
1394
4317.7
SCR-3
8
1.52
156
63
1.5
32.3
207.0
10.1
11.7
80.0 .
2039
4939.5
SCR-3
9
1.52
165
55
1.5
33.6
203.5
10.4
13.1
80.0
1883
• 5545.3
SCR-3
10
1.S2
700
,79 '
1,5
104.7
149.6
36.3
7.5
80.0
11475
3160.9
SCR-3 ¦
5-7
1.16
260
44
1.5
37.6
144.6
12.7
12.7
80.0
3323
3833.6
SCR-3
8-10
1.52
1021
66
1.5
146.6
143.6
50.8
8.6
BO.O
13982
¦ 3634.3
SCR-3-C
5
1.16
60
41
' 1.5
13.9
232.1
2.5
11.6
80.0
510
4895.6
SCR-3-C
6
1.16
100
42
1.5
18.8
187.8
3.5
9.5
80.0
1220
2879.3
SCR-3-C
7
1.16
100
48
1.5
18.8
187.9
3.5
8.4
80.0
1394
2534,2
SCR-3-C
8
1.52
156
63
1.5
32.3
207.0
5.9
6.9
80.0
2039
2901.0
SCR-3-C
9
. 1.52
165
55
1.5
33.6
203.5
6.1
7.7
80.0
1883
3257.0
SCR-3-C
10
1.52
700
79
1.5
104.7
149.6
21.2
4.4
80.0
11475 '
1851.9
SCR-3-C
5-7 ¦ :
1.16
260
44
1.5
37.6
144.6
7.5
7.5
80.0
3323
2247,1
SCR-3-C
8-10
1.52
1021
66
1-5
146.6
143.6
29.8
5.0
80.0
13982
2129.2
SCR-7
5
1.16
60
41
1.5
13.9
232.1
3.8
17.5
80.0
510
7371.3
SCR-7
6
1.16
100
42
1.5
IB.8
187.8
5.2
14.0
80.0
1220
4235.5
SCR-7
7 ¦ '
1.16
100
48
1.5
18.8
187.9
5.2
12.4
80.0
1394
3731.9
SCR-7
a
1.52
156
63
1.5
32.3
207,0
8.8
10.2
80.0
2039
4314.7
SCR-7
9
1.52
165
55
1.5
33.6
203.5
9.1
11.4
80.0
1883
4829.6
SCR-7 .¦
10
1.52
700
79
1.5
104.7
149.6
30.6
6.3
80.0
11475
2662.6
SCR-7
. 5-7 -
1.16
260
44
1.5
37.6
144.6
10.6
10.6
80.0
3323
3194.6
SCR-7
8-10
1.52
1021
66 '
1.5
146.6
143.6
42.5
7.2
80.0
13982
3037.9
SCR-7-C
5
1.16
60
41
1.5
13.9
232.1
2.2
10.3
80.0
510
4345.7
SCR-7-C
6
1.16
100
42
1.5
18.8
187.8
3.0
8.3
80.0
1220 '
2495.7
SCR-7-C
7
1.16
100
48
1.5
18.8
187.9
3.1
7.3
80.0
1394
219B.5
SCR-7-C
8
1.52
156
63
1.5
32.3
207.0
5.2
6.0
80.0
2039
2543.0
SCR-7-C
9
1.52
165
55
1.5
33.6
203.5
5.4
6.7
80.0
1883
2847.0
SCR-7-C
10
1.52
TOO
79
1.5
104.7
149.6
18.0
3.7
80.0
11475
1566.4
SCR-7-C
5-7
1.16
. 260
44
1.5
37.6
144.6
6.3
6.2
BO.O
- 3323
1881.0
SCR-7-C
8-10
1.52
1021
66
1.5
146.6
143.6
25.0
4.2
80.0
13982
1787.5
:SaaSSSS3aSB«SSSSS8=S«lSSSSSSSKS=:=3SS=SSSSSSS88SSS'
3-40
-------
3.1.5 Greene County Steam Plant
The Greene County steam plant is located within Greene County, Alabama,
and is part of the Alabama Power Company. The plant houses two coal-fired
boilers with a gross generating capacity of 506 MW. The plant is adjacent to
the Black Warrier River with a water channel extending from the south loop of
the river to the east side of the coal pile.
Table 3.1.5-1 presents, the operational data for the Greene County plant.
Both boilers burn moderate sulfur coal. Coal shipments are received by barge
or railroad and conveyed to a coal storage and handling area south of the
plant. The coal is crushed and then conveyed to the boilers.
PM emissions for both boilers are controlled with retrofit hot side
ESPs. The ESPs are located behind each boiler. The units are ducted to a
common retrofit chimney built southwest of unit 2. The two original chimneys
are left intact and are located directly behind the retrofit ESPs. Ash from
the units is wet sluiced to ponds located to the south of the coal pile. The
following evaluation is based on a 1981 aerial photograph, and any
alterations made to the plant since that time should be taken into
consideration.
lime/Limestone and Lime Spray Drying FGD Costs--
For L/LS-FGD system, the absorbers would be placed in a low site access/
congestion area south of and close to the common chimney. A short duct run
(100-300 feet) having a low access/congestion retrofit difficulty would be
required. The lime/limestone preparation and waste handling area would be
located close to the absorbers and north of the coal pile. A storage
building would have to be relocated for the placement of the absorbers.
Therefore, a factor of 8 percent was assigned to general facilities,
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs are hot side and access to them 1s difficult. LSD with a
new baghouse was considered with the baghouses being located adjacent to
their respective absorbers which would be placed in a similar fashion as the
L/LS-FGD absorbers.
3-41
-------
TABLE 3,1.5-1. GREENE COUNTY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
1000 CU FT)
ON
ENT (PERCENT)
UE (BTU/LB)
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON
COAL HEATING VA
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1 2
250 256
70 59
1965 1966
OPPOSED WALL
124 124
NO NO
I.4 1.4
12,500 12,500
II.0 11.0
WET DISPOSAL
PONDS/ON-SITE
1 1
BARGE/RAILROAD
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1975 1975
EMISSION (LB/MM 0.06 0.06
REMOVAL EFFICIENCY 99.7 99.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.7 to 5.0
SURFACE AREA (1000 SQ FT) 394.0 394,
GAS EXIT RATE (1000 ACFM 1400 1400
SCA (SQ FT/1000 ACFM) 281.4 281.4
OUTLET TEMPERATURE (4F) 715 715
3-42
-------
A moderate duct run (300-600 feet) would be required for the application
of LSD technology, A low ductwork site access/congestion factor was assigned
to both LSD and installation of ducting to the baghouse.
The major scope adjustment costs and-estimated retrofit factors for the
FGD technologies are presented in Table 3.1.5-2. Table 3.1.5-3 presents the
process retrofit factors and capital and operating costs for commercial FGD
technologies. The low cost FGD case shows the impact of eliminating spare
absorbers and maximizing absorber size.
Coal Switching and Physical Coal Cleaning Costs-
Table 3.1.5-4 presents the IAPCS results for OS at the Greene County
plant. These costs do not include changes in boiler and pulverizer operating
costs. Coal switching for a fuel price differential of $15 per ton is higher
than that of $5 per ton because of inventory capital and preproduction costs,
which are a function of variable costs (e.g. fuel costs). PCC was not
evaluated because the coal sulfur level is relatively low and this is not a
mine mouth plant.
Low NO Combustion--
A
Units 1 and 2 are opposed wall-fired boilers rated at 250 and 256 MW,
respectively. The combustion modification technique applied to unit 2 was
LNB. LNBs were not considered for unit 1 since unit 1 has all burners, and
LNBs are not yet satisfactorily demonstrated nor commercially available for
all burner units. As Table 3.1.5-5 shows, the LNB N0X reduction performance
for unit 2 was assessed based on volumetric heat release rate (MW per furnace
volume). Table 3.1.5-6 presents the cost of retrofitting LNB at the Greene
County plant. '
Selective Catalytic Reduction-
Two SCR configurations are possible at the Greene County plant. Because
the units have hot ESPs, the SCR reactors could be located adjacent to the
old chimneys and would have a high access/congestion factor. Cold side SCR
reactors for units 1 and 2 would be located south of the common chimney and
would have a low access/congestion factor and the need for flue gas reheat.
Both cases were evaluated. The ammonia storage is placed south of the
3-43
-------
TABLE 3.1.5-2. SUMMARY OF RETROFIT FACTOR DATA FOR GREENE COUNTY
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW r
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
2132
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
NA .
BAGHOUSE CASE
1.27
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
3-44
-------
Table 3.1.5-3. Senna ry of FGO Control Costs for the Greene County Plant (June 1988 Dollars)
j- SSS5SSISSBS53S&5SSSS5S3SS3S3S8SSB&ZSI3SI1£S5SSS55SSS&SSSSSS&3SS85SS3S8II4SSS5SSBSSIBSI33IICISS&SBSS81185S3ISSSII
Technology Boiler Wain Boiler Capacity Coal Capital Capital Annual Annual S02 S02 SQ2 Cost
Minber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HW)
{X}
Content
(SMM)
(S/kU) -
(SMH)
(mi I LsAuh)
m
(cons/yr)
($/tonJ
Factor -
.......
.........
(X)
........
........
.......
..........
.........
l/S FGO '
1
1.27
250
76
1.4
64.6
258.3
28.6
17.3
90.0
16142
1781.5
L/S FGO
2
, 1.27
256
59
1.4
65.5
255.9
27.3
20.7
90.0
12832
2130.2
l/S FGO
' 1-2
1.27
506
65
1.4
99.9
197.4
44.2
15.3
90.0
27942
1581.7
L/S FGD-C
1
1.27
250
76
1.4
64.6
258.3
16.8
10.1
90.0
16142
.1038.6
L/S FGD-C'
2
1.27
256
59
1.4
65.5
255.9
16.0
12.1
90.0
12832
1243.4
L/S FGD-C
1-2
1.27
506
65
1.4
99.9
197.4
25.8
8.9
90.0
27942
922.2
LC FGD
1-2
1.27
506
65
1.4
SO.2
1S8.5
38.3
13.3
90.0
27942
1369.1
LC FGD-C '
1-2
1,27
506
65
1.4
80.2
158.5
22.3
7.7
90,0
27942
797.3
ISD+FF
1-2
1.27
506
65
1.4
132.3
261.4
46.2
16.0
87.0
26860
1721.4
LSO+FF-C '
1-2
1.27
506
65
1.4
132.3
261.4
27,1
9,4
87.0
26860
1008.3
3-45
-------
Table 3,1.5-4. Swinary of Coal Snitching/Cleaning Costs for the Sreene County Plant (June 1988 Dollars)
SS33Z3SSSSSSSSSI*SI8S=
ISSSSSS3SSSS
Technology Boiler' Main Boiler Capacity Coal Capital Capital Annual- Annual SQ2 S02 S02 Cost
Nunber Retrofit Site Factor Sulfur Cost ' Cost Cost Cost' Removed Removed Effect.
Difficulty CMW> «) Content (SUM) £$/kW) (WW) (mills/kwh) (X5 (tons/yr) <$/ton)
Factor IX)
CS/B+S15
CS/B+S15
1.00
1.00
250
256
70
59
1.4
1.4
a. 6
a.7
34.2
34.1
21.9
19.2
14.3
14.5
33.0
33.0
5453
4706
4024.3
4085.6
CS/B+$15-C
CS/B+I15-C
1.00
1.00
250
256
70
59
1.4
1.4
a.6
8.7
34.2
34.1
12.6
11.1
8.2
8.4
33,0
33.0
5453
4706
2312.7
2349.1
CS/B+tS
CS/B+*S
1.00
1.00
250
256
70
59
•1.4
1.4
6.0
6.1
23.8
23.7
8.8
7.8
5.3
5.9
33.0s
33.0
5453
4706
1618.9
1664.7
CS/B+J5-C
CS/B+S5-C
1.00
1.00
250
256
70
59
1.4
1.4
6.0
6.1
23.8
23.7
5.1
4.5
3.3
3.4
33.0
33.0
5453
4706
932.5
959.6
3-46
-------
TABLE 3.1.5-5, SUMMARY OF NOx RETROFIT RESULTS FOR GREENE COUNTY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
NA
OWF
TYPE OF NOx CONTROL
NA
LNB
FURNACE VOLUME (1000 CU FT)
NA
124
BOILER INSTALLATION DATE-
NA
1965
SLAGGING PROBLEM
NA
NO
ESTIMATED NOx REDUCTION (PERCENT)
NA
34
SCR RETROFIT RESULTS
COLD SIDE
HOT SIDE
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
o
Ductwork Demolition (1000$)
54
200
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
2541
1694
New Heat Exchanger (1000$)
4895
0 ,
TOTAL SCOPE ADDER COSTS (1000$)
7527
1894
RETROFIT FACTOR FOR SCR
1.16
1.52
GENERAL FACILITIES (PERCENT)
13
13
3-47
-------
Table 3.1.5-6. MOx Control Cast Results for the Greene County Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Amual Annual NOx NOx NOx Cost
Nimber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (SMt> (S/kW) (Sftt) (mills/kwh) (X) (toos/yr) («/ton)
Factor (X)
LNC-LNB
LNC-LNB'C
1.00
1.00
256
256
59
59
1.4
1.4
3.7 14.5
1.7 14.5
0.8
0,5
0.6
0.4
34.0
34.0
1865
1865
421.3
250.3
SCfl-3 (CS)
SCR-3 (CS)
1.16 250 70 1.4 38.7 154.7 13.1 8.5 80.0 5084 2574.0
1.16 256 59 1.4 39.3 153.6 13.2 9.9 80.0 4388 2998.6
SCR-3 (NS)
SCR-3
-------
reactors and is assigned a low access/congestion factor. For both cases,
200 feet of duct is required to span the distance between the reactors and
the existing duct work; no major demolition/relocation is required and the
base value of 13 percent was assigned to general facilities.
Table 3.1.5-5 presents the SCR process area retrofit factors and scope
adder costs. Table 3.1.5-6 presents the estimated cost of retrofitting SCR
at the Greene County plant.
Furnace Sorbent Injection and Duct Spray Drying--
Because of the short duct residence time between the boilers and the
ESPs, the marginal size of the ESPs, the congestion around the ESPs area, and
the hot side ESPs (715°F), FSI and DSD were not considered here.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering appl icabi 1 ity criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Greene County plant. Both units would be considered
candidates for repowering or retrofit because they are less than 300 MW.
However, the high capacity factors could result in high costs associated with
downtime (replacement power costs) and the moderate unit age makes these
units unlikely repowering candidates in the near future. Space availability
adjacent to both units enhances the potential for equipment reuse and reduces
construction costs and downtime.
3-49
-------
3.1.6 Miller Steam Plant
Both units at the Miller plant are currently burning a low sulfur coal\
therefore, FGD costs were not presented since the low sulfur coal would yield
high unit costs and CS was not considered for the plant. The only technology
considered for control of N0X emissions was SCR since both units are equipped
with LNBs. Sorbent injection technologies (FSI and DSD) were not evaluated
for this plant because the boilers are equipped with hot side ESPs which can
not be reused.
TABLE 3.1.6-1. MILLER 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
I,2
660
38,39
iQ7fi as
OPPOSED WALL
526
YES
0.6
12500
II.2
WET DISPOSAL
POND/ON-SITE
1
RAILROAD/TRUCK
3,4
660
1989,91
PLANNED
FOR
CONSTRUCTION
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)
...
PF)
ESP
1978,85
0.02,0.03
99.1
0.5
1037
3888
267
679
3-50
-------
TABLE 3.1.6-2.
SUMMARY OF RETROFIT FACTOR DATA FOR MILLER
UNIT 1 OR 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
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA .
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
5090,9475 NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.27
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* Absorbers and new FFs for units 1 and 2 would be located behind
the common chimney for units 1 and 2.
3-51
-------
TABLE 3.1.6-3. SUMMARY OF NQx RETROFIT RESULTS FOR MILLER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE OWF
TYPE OF NOx CONTROL EQUIPPED WITH LNBs
FURNACE VOLUME (1000 CU FT) 526,NA
BOILER INSTALLATION DATE 1978,85
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$) 0
• Ductwork Demolition (1000$) 111
New Duct Length (Feet) 250
New Duct Costs (1000$) 3736
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 3847
COMBINED CASE 5792
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
* Hot side SCR reactors for units 1 and 2 would be located behind
the common chimney for units 1 and 2.
3-52
-------
Table 3.1.6-4. NOx Control Cost Results for the Hi Her Plant (June 1988 Dollars)
==:=£SSSSassaBSS;;£s;5S;5SSS55S«sas3a8SSa»ISSSS;£»BaBBaB»RSiaSSBSSSB8n»SBKSlX8ElSn»KRMRlffCaBHllBSjiaSRB8l«S
Technology Boiler Main Boi ler Capacity Coal Capital Capital Annual Annual HOx NO* NOx Cost
Nimfetr Retrofit Size Factor Sulfur Cost ' Cost Cost Cost • Removed Removed Ifftet.
Difficulty CNW3 <%} Content (MM) (S/ton)
'Factor ' (X)
SCR-3
1 . .
1.16
660
38 •
0.6
77.9
118.0
28.3
12.9
80.0
7286
3886.5
SCR-3
2
1.16
660
39
0.6
77.9
118.0
28.4
12.6
80.0-
7477
3791.9
SCR-3
.1-2
1.16
1320
39
0.6
147.9
112.0
54.7
12.1
80.0
14955
• 3660.9
SCR-3-C
,1
1.16
660
38
0,6
77.9
118.0
16.6
7.5
80,0
7286
2274.6
SCR-3-C 1
2
1.16
660
39
0.6
77.9
118.0
16.6
7.4
80.0
7477
2219.2
SCS-3-C
1-2
1.16
1320
39
' 0.6 -
147.9
112.0
32.0
7.1
80.0
14955
2141.8
SCR *7
1
1.16
660
38
0.6
77.9
118-0
22.9
10.4
80.0
7286
3146.6
SCR-7
2
¦1.16
660
39
0.6
77.9
118.0
23.0
10.2
80.0
7477
3071.0
SCR-7
1-2
1.16
1320
39
0.6
147.9
112.0
44.0
9.7
80.0
14955
2940.0
SCR-7-C
1
1.16
660
38
0.6
77.9
118.0
13.5
6.1
80.0
7284
1850.7
SCR-7-C
2'
1.16
660
39
0.6
77.9
118.0
13.5
6.0
80.0
7477
1806.2
SCR-7-C
1-2
1.16
1320
39
0.6
147.9
1'12.0
25.9
5.7
80.0
14955
1728.7
============SS======================S===SSS=======a===S==3SSS=3SSB=C3=3S=3S2=Sefi=====a2Sr===a===========sz======
3-53
-------
3.2 TENNESSEE VALLEY AUTHORITY
3.2.1 Colbert Steam Plant
Information for Colbert steam plant appears in U.S. EPA report number
EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility SO., and NOx
Retrofit Study" (NTIS PB88-244447/AS).
3.2.2 Widows Creek Steam Plant
The Widows Creek steam plant is located within Jackson County, Alabama,
as part of the TVA system. The plant contains eight boilers with a total
gross generating capacity of 1,965 MW. Figure 3.2.2-1 presents the plant plot
plan showing the location of all boilers and major associated auxiliary
equipment.
Table 3.2.2-1 presents operational data for the existing equipment at the
Widows Creek steam plant. Boilers 1 to 6 burn low sulfur coal (0.8 percent
sulfur). Half of the coal shipments are received by freight barge and the
other half is received by rail and conveyed to a coal storage and handling
area located west of the plant.
Particulate matter emissions for boilers 1-6 are controlled with
retrofit ESPs located behind the old ESP boxes. 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 two
options: the purchase of more land adjacent to the plant or dry disposing
the waste off-site.
Boilers 7 and 8 bum high sulfur coal (3.5 percent) and have limestone
flue gas scrubbing units. As such, cost estimates for SOg controls for
units 7 and 8 are not presented.
Lime/L1mestone and Lime Spray Drying FGD Costs--
Figure 3.2.2-1 shows the general layout and location of the FGD control
system. Absorbers for L/LS-FGD and LSD-FGD for units 1 to 6 would be
located in a relatively small area southeast of unit 1. They were not
located in the space available west of unit 6 due to the location of the
preparation area for units 1 to 6. The preparation area is located to the
3-54
-------
LEGEND £
. . . ¦ . . ¦ . " Sf
- SCR >'
¦ X
• 0 100 200
- FGD
H's - INDICATE
BOILER NUMBER
Figure 3.2.2-1. Widows Creek plant plot plan
3-55
-------
TABLE 3.2.2-1. WIDOWS CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-6 7 8
GENERATING CAPACITY (MW-each) 140 575 550
CAPACITY FACTOR (PERCENT) 29,26,37,35,29,35 24 38
INSTALLATION DATE 1952-54 1961 1965
FIRING TYPE FWF TANG TANG
COAL SULFUR CONTENT (PERCENT) 0.8-1.1 3.4 3.6
COAL HEATING VALUE (BTU/LB) 12000 12000 12000
COAL ASH CONTENT (PERCENT) 10 11 11
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD POND/ON-SITE
STACK NUMBER 1 2 3
COAL DELIVERY METHODS BARGE/RAIL
FGD (TYPE) NA LIMESTONE
PARTICULATE CONTROL
TYPE ESP ESP ESP
INSTALLATION DATE 1977 1981 1978
EMISION (LB/MM BTU) 0.05 0.06 0.07
REMOVAL EFFICIENCY 99.2 99.2 99.2
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.7 4.0 4.5
SURFACE AREA (1000 SQ FT) 322.6 217.7 217.7
GAS EXIT RATE (1000 ACFM) 575 ; 1624 1473
SCA (SQ FT/1000 ACFM) 561 134 134
OUTLET TEMPERATURE (CF) 310 175 175
3-56
-------
east of unit 1 on the other side of the water channel, which would make it
difficult to reach the other side of unit 6 if the absorbers were located to
the west. In addition, flue gas from units 4-6 are converged into a common
duct. An easier approach, which would require a shorter breaching duct,
would be the diversion of this flue gas to the southeast of unit 1 for the
L/LS-FGD absorbers. The coal conveyor running to units 7 and 8 would be
relocated to make more space available for the FGD equipment; therefore, a
factor of 10 percent was assigned to general facilities for units 1-6. The
limestone preparation/storage area for units 1 to 6 was placed by the corner
(southwest) of the powerhouse and the waste handling area was placed
adjacent to the limestone preparation and storage area for units 7 and 8
east of the plant.
Retrofit Difficulty and Scope Adder Costs--
Units 1-6 already have switched to low sulfur coal. It is unlikely
that scrubbing would be needed. If this becomes needed, however, it is more
cost effective to switch to a high sulfur coal taking into account the fuel
cost differential for estimation of cost effectiveness. Costs presented in
this section, it must be noted, are dependent upon acid rain legislation and
the type of coal chosen for use.
The FGD scrubbing equipment for units 1 to 6 was assumed to be located
in a high access/congestion area east of unit 1. This area is bounded by
the cooling water intake channel to the east, the Tennessee River to the
south, the coal conveyor to the north, and a powerhouse to the west. A high
underground obstruction factor was assumed due to the underground discharge
tunnels.
Boilers 1 to 3 and 4 to 6 presently converge into two separate duct
runs before going to a common chimney. As a result, a modest duct run would
be required for boilers 1 to 6.
For L/LS-FGD, a low ductwork access/congestion factor was assigned to
units 1 to 3 because sufficient layout space was available. A medium
ductwork access/congestion factor was assigned to units 4 to 6 because it
would be necessary to route the ductwork around the existing chimney.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 3.2.2-2 and 3.2.2-3. The
3-57
-------
TABLE 3.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR WIDOWS.CREEK UNITS 1-3
FGD TECHNOLOGY
'' / FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION ,
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY ' YES NO YES
ESTIMATED COST {1000$) 1268 NA 1268
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.59 1.56
ESP REUSE CASE 1.73
BAGHOUSE CASE NA
ESP UPGRADE. NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
3-58
-------
TABLE 3.2.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR WIDOWS CREEK UNITS 4-6
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING MEDIUM MEDIUM
ESP REUSE CASE - HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 1000 +
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 1268 NA 1268
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.64 1.60
ESP REUSE CASE 2.03
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
3-59
-------
largest scope adder for Widows Creek would be the conversion of units 1 to.6
fly ash conveying/disposal system from wet to dry for conventional L/LS-FGD
and LSD-FGD cases. It was assumed that dry fly ash would be necessary to
stabilize L/LS-FGD scrubber sludge waste and to prevent plugging of sluice
lines in LSD-FGD cases. However, this conversion would not be necessary for
the forced oxidation case. The overall retrofit factors determined for the
L/LS-FGD cases were moderate to high for units 1 to 6 (1.56 to 1.64).
The LSD with reused ESP was evaluated for units 1-6. For LSD-FGD, a
medium ductwork access/congestion factor was assigned to units 1 to 3, while
a high factor was assigned to units 4 to 6. The ESPs at units 1 to 6 have
1arge SCAs (>500) and, as such, it is 1ikely that 1ittle or no ESP plate
area addition would be required for spray drying at these units. The
process area retrofit difficulty factors ranged from moderate to extreme for
units 1 to 6 (1.73 to 2.03). A separate retrofit factor (1.58) was
developed for the upgrade of the ESPs for units 1 to 6 and was used in the
IAPCS model to estimate the particulate control costs if additional plate
area was required.
Table 3.2.2-4 presents the costs estimated for L/LS-FGD and LSD-FGD
cases. The LSD-FGD costs include upgrading the ESPs and ash handling
systems for boilers 1-6.
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—
Because units 1-6 have already switched to low sulfur coal and
units 7-8 have 1imestone FGD units, coal switching was not evaluated.
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at the Widows Creek steam plant. These controls
include LNC modifications and SCR. The application of N0X control
technologies is determined by several site-specific factors which are
3-60
-------
Table 3.2.2-4, Sunmary of FGD Control Costs for the Widows Creek Plant (June 1988 Dollars*
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual . S02 S02 SQ2 Cost
Number Retrofit Size Factor Sulfur Cost Cost ' Cost Cost Removed Removed Effect.
Difficulty (MW) (Xj Content ($MH) (S/kWJ ($MN) (mitls/kMh) (X) ctc*w/yr) <$/ton)
Factor (X)
L/S FGD
1"3
1.59
421
31
0.8
102.6
243.7
37.5
32.8
90.0
6641
5644.9
l/S FGD
4-6
1.64
421
33 •
1.1
106.6
253.2
39.4
32.4
90.0
9720
4054.7
L/S FGO-C
1-3
1.59
421
31
0.8
102.6
243.7
21.9
19.2
90.0
6641
• 3303.4
L/S FGO-C
4-6
1.64
421'
33
1.1
106.6
253.2
23.1
18.9
90.0
9720
2372.2
IC FGD
1-3
1.59
421
31
0.8
76.8
182.5
29.7
26.0
90.0
6641
4468.9
LC FGO
4-6
1.64
' 421
33
1.1
79.7
189.2
31.2
25.6.
90.0
9637
3237.5
LC FGO-C
1-3
1.59
421
31
0.8
76.8
182.5
17.3
15.2
90.0
6641
2612.3
LC FGD-C
4-6
1.64
421
33
1.1
79.7
189,2
18.2
15.0
90.0
9637
1892.0
LSD+ESP
1
1.73
: 140' '
29
0.8
• 24.1
172,5
9.3
26.2
'' 76.0 '
1751 '
5317.0
LSD+ESP
2
1.73
140
26
0.8
24.2
172,6
9.2
29.0
76.0
1570
. 5890.7
LSD+ESP
3
1.73
140
37
0.8
24.2
172.7
9.5
21.0
76.0
2235
4254.4
LSD+ESP
4
2.03
140
35
0.8
27.7
198.1
10.4
24.3
76.0
2114
4938.5
LSD+ESP
5
2.03
140
29
0.9
28.1
200.7
10.5
29.4
76.0.
1970
5306.2
LSD+ESP
6
2.03
140
35
1.1
28.7
205.0
10.9
25.4
76.0
2906
3743.9
LSD+ESP-C -
1
1.73
140
29
0.8
24.1
172.5
5.4
15.3
76.0
1751
3108.1
LSD+ESP-C
2
1.73
140
26
0.8
24.2
172.6
5.4
17.0
76.0
1570
3444.0
LSD+ESP-C
3
1.73
140
37
0.8
24.2
172.7
5.6
12.2
76.0
2235
2486.0
LSD+ESP*C
4
2.03
140
35
0.8
27,7
198.1
6.1
14.2
76.0
2114
2888.3
LSD+6SP-C -
5
2.03
140
29
Qi9
28.1
200.7
6.1
17.2
76.0
1970
•3104.1
LSD+ISP-C
6
2.03
140
35
1.1
28.7
205.0
6.4
14.8
76.0
2906
2189.3
aHI8BasaSISSSS83IIIII8SSSBailiaSS8StllIS3IBSllllia8SSHIS8&8«S&88S85SS9SC983SS8SSS3388SSSSSSSS:S8SSSS:3$SS3S:S
3-61
-------
discussed in Section 2. The NQX technologies evaluated at the steam plant
were; LNB - units 1 to 6, OFA - units 7 to 8, and SCR for all units.
Low N0X Combustion--
Units 1 to 6 are dry bottom, front wall-fired boilers rated at 140 MW
each. Units 7 to 8 are dry bottom, tangential-fired boilers rated at 575 MW
and 550 MW, respectively. Thus, the N0X combustion control considered for
units 1 to 6 was LNB and the N0X combustion control considered for units 7
and 8 was OFA. Tables 3.2,2-5 through 3.2.2-7 present the NOy reduction
"performance results for units 1 to 8. The N0X reduction performance
estimated for units 1 to 6 (equipped with LNBs) would be 30 percent while the
N0X reduction performance results for units 7 and 8 (equipped with OFA) would
be 25 and 20 percent, respectively. The N0X reduction performances were
determined by examining the effects of heat release rates and furnace
residence time orv NQX reduction through the use of the simplified procedure.
Table 3.2.2-8 presents the estimated cost of retrofitting LNB and OFA ports
on the Widows Creek boilers.
Selective Catalytic Reduction--
Tables 3.2.2-5 through 3,2.2-7 present the SCR retrofit results for each
unit. The results include process area retrofit difficulty factors and scope
adder costs. For scope adders, costs were estimated for ductwork demolition,
new flue gas heat exchanger, and new duct runs to divert the flue gas from
the ESP to the reactor arid from the reactor to the chimney.
The SCR reactor for unit 1 was located east of the unit's ESPs, the
reactors for units 2 and 3 were located behind their respective ESPs, and
the reactors for units 4 to 6 were located west of the unit 6 ESPs. The
reactor for unit 7 is located at the southwest corner of the boiler house in
a highly congested area adjacent to the ESP while the reactors for unit 8
were located northeast of the boiler in an uncongested area.
Medium access/congestion factors were assigned to the reactors for
units 1 to 6. These reactors were located in the relatively low access/
congestion areas but general access to these areas is poor. The reactor for
unit 7 was given a high access/congestion factor because the reactor would
be blocked by the service bay, the ESPs, and the electrical power yard. The
3-62
-------
TABLE 3.2.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR WIDOWS CREEK UNITS 1-3
COMBUSTION MODIFICATION RESULTS
BOILER NUMBER
1
2
3
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB, ¦
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
21.5
21.5
21.5
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
64.2
64.2
64.2
FURNACE RESIDENCE TIME (SECONDS)
1.73
1.73
1.73
ESTIMATED NOx REDUCTION (PERCENT)
30
30
30
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
NA
Ductwork Demolition (1000$)
35
35
35
New Duct Length (Feet)
350
283
217
New Duct Costs (1000$)
2120
1714
1315
New Heat Exchanger (1000$)
2291
2291
2291
TOTAL SCOPE ADDER COSTS (1000$)
4446
4040
3640
RETROFIT FACTOR FOR SCR
1.34
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
3-63
-------
TABLE 3.2.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR WIDOWS CREEK 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)
21.5
21.4
21.4
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
64.2
67.5
67.5
FURNACE RESIDENCE TIME (SECONDS)
1,73
.1.66
1.66
ESTIMATED NOx REDUCTION (PERCENT)
30
30
30
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
NA
Ductwork Demolition (1000$)
35
35
35
New Duct Length (Feet)
650
650
684
New Duct Costs (1000$)
3938
3938
4144
New Heat Exchanger (1000$)
2291
2291
2291
TOTAL SCOPE ADDER COSTS (1000$)
6263
6263
6469
RETROFIT FACTOR FOR SCR
1.34
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
3-64
-------
TABLE 3.2.2-7. SUMMARY OF NQx RETROFIT RESULTS FOR WIDOWS CREEK UNITS 7-8
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
'
7
8
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
11.2
11.7
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
. (1000 BTU/SQ FT-HR)
88.7
103.1
FURNACE RESIDENCE TIME (SECONDS)
3.84
2.83
ESTIMATED NOx REDUCTION (PERCENT)
25
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
Ductwork Demolition (1000$)
100
97
New Duct Length (Feet)
367
333
New Duct Costs (1000$)
5060
4473
New Heat Exchanger (1000$)
5324
5184
(PERCENT)
3-65
-------
Table 3.2.2-8. NOx Control Cost Results for the Widows Creek Plant (Jim 1933 Dollars)
sssssssssssa;
ii
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II
II
II
It
II
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ISSISIISBI
BSS*ASBBS
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SSESa SSSBESSSES
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Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
NOx
NOx
NOx Cost'
Nuitoer
Retrofit
Size
Factor Sulfur
Cost
Cost.
Cost
Cost
Removed Ramoved
Iffeet.-
Difficulty (HU5
cx>
Content
CSMM)
(t/ItU)
factor
<%>
LNC-LNB
1
1.00
140
29
0.8
2.9
20.9
0.6
1.7
30.0
464
1331.4
IMC-IMB
2
1.00'
140.
26
0.8
2.9
20.9
0.6
1.9
30.0
416
1485.0
LNC-LNB
. 3 ¦
.1.00
140'
17
0.B
2.9
20.9
0.6
1.4
30.0
591
1043,5
LHC-INB
4
.1.00
140
¦ 35,
' 0.8
2.9
20.9
0.6
1.4
30,0
55?
1103.2
LNC-LNB
5
1.00
140
29
0.9
2.9
20.9
0.6
1.7
30.0
464
1331.4
LNC-LN8
6
1.00
140
35
1.1
2.9
20.9
0.6
1.4
30.0
559
1103.2
LKC-LNB-C
1
1.00
140
29
o.a
2.9
20.9
0.4
1.0
30.0
464
791.0
LHC-LKB-C
2
1.00
140
26
o.a
2.9
20.9
0,4
1.1
30.0
416
882.2
INC-LNB-C
3
1.00
140
37
0.8
2.9
20.9
0.4
0.8
30.0
591
619.9
LNC-INB-C
4
1.00
140
35
0.8
2.9
20.9
0.4
0.9
30.0
559
655.4
LNC-LNB-C
5
1.00
140
29
0.9
2.9
20,9
0.4
1.0
30.0
464 •
791.0
LKC-LNB-C
6
1.00
140
35
1.1
2.9
20.9
0.4
0.9
30.0
559
655.4
INC-Of*
7
1.00
575
24
3.4
1.2
2.2
0.3
0.2
25.0
938
281.0
INC-OFA
8 •
1.00
550
38
3.6
1.2
2.2
0.3
0.1
20.0
1136
227.7
LNC-OFA-C
7
1.00
575
24
3.4
1.2
2.2
0.2
0.1
25.0
938
167.0
LNC-OFA-C
8
1.00
550
38
3.6
1.2
2.2
0.2
0.1
20.0
1136
135.3
SCR "3
1
1.34
140
29
• 0.8
26.2
187.5
8.2
23.0
80.0
1236
"6609.5
SCR-3
2-
1.34
140
26
0.8
25.8
184.5
8.1
25.3
80.0
1108
7285.2.
SCR-3
3
1.34
140
,37
0.3
25.4
181.6
8.1
17.8
80.0
1577
5130.4
SCR-3
4
1.34'
140
35
0.8
28.1
200.7
.8.5
. 19.9
80.0
1492
5727.1
SCR-3
5
1.34
140
29
0.9
28.1
200.7
8.5
23.9
80.0
1236
6872.5
SCR-3
6
1.34
140
35
1.1
28.3
202.2
8.6
20.0
30.0
1492
5751.8
SCR-3
7
1.52
¦ 575
24
3.4
81.6
141.8
27.1
22.4
80.0
3001
9026.4
SCR-3
a
1.16
550
38
3.6
66.6
121.0
23.6
12.9
80.0
4545
5183.5
SCR-3-C
1
1.34
140
29
0.8
26.2
187.5
4.8
13.5
80.0
1236
3882.0
SCR-3-C
2
1.34
140
26
0.8
25.8
184.5
4.7
14.9
80.0
1108
4278.4
SCR-3-C
I .
1.34
140
37
0.8
25.4
181.6
4.7
10.5
80,0
1577
3011.7
SCR-3-C
4
1.34
140
35
o.a
28.1
200.7
5.0
11,7
SSS3 SHS3SSSSZ
80.0
aBSCX,
1492
3365.7
SSI 3SBSSS
•continued . . .
3-66
-------
Table 3.2.2-8, NOx Control Cost Results for the widows Creek Plant (June 1988 Dollars) continued ...
85i»BBEiKsss5sss5saiii!SS8uianss8sasasiis3S8S9B8SS33sssiaiais9B£asaasas:3ssss3ssassasfisassassssssasss:sssss&S3
Technology Boiler Main Boflar Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cast
Number Retrofit
Size
Factor
Sulfur
Coat
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (KW)
(X)
Content
(SMM)
(S/kU)
(SUM)
(¦ills/kwh)
(%)
(tons/yr)
($/ton)
Factor
CX5
SCR-3-C
5
1.34
140
29
0.9
, 28.1
200.7
5.0
14,0
80.P
1236
4039.4
SCR-3-C
6
1.34
140
. ' 35'
1.1
28.3
202.2
O
in
11.7
80.0
1492
3380.5
SCR-3-C
7
1.52
575
24
3.4
81.6
141.8
15.9
13.1
80.0
3001
5293.4
SCR-3-C
- 8
1.16
550
38
3.6
66.6
121.0
13.8
7.5
80.0
4545
3035.5
SCR -7
1
1,34
140
29
0.8
26.2
187.5
7.0
19.7
80.0
1236
- 5678.8
SCR-7
2
1.34
140
26
0.8
25.8
184.5
6.9
21.7
80.0
1108
6246.9
SCR-7
3
1.34
140
37
0.8
25.4
181.6
6.9
15.3
80.0
1577
4401.0
SCR-7
4
1.34
140
35
0.8
28.1
200.7
7.4
17.2
80.0
1492
4955.9
SCR-7
5
1.34
140
29
0.9
28.1
200.7
8.5
23.9
80.0
1236
6872.5
SCR-7
6
1.34
140
35
1.1
28.3
202.2
7.4
17.3
80.0
1492
4980.7
SCR-7
1.52
575
. 24
3.4
81.6
141.8
22.4
18.5
80.0
3001
7451.8
SCR-7
8
1.16
550
38
3.6
66.6
121.1
19.0
10.4
80.0
4545
4190.7
SCR-7-C
1
1.34
140
29
0.8
26.2
187.5
4.1
11.6
80.0
1236
3348,8
SCR-7-C
2
1.34
140
26
0.8
25.8
184.5
4.1
12.8
80.0
1108
3683.6
SCR-7-C
3
1.34
140
37
0.8
25.4
181.6
4.1
9.0
80.0
1577
2593.7
SCR-7-C
4
1.34
140
35
0.8
28.1
200.7
4.4
10.2
80.0
1492
2923.9
SCR-7-C
5
1.34
140
29
0.9
28.1
200.7
5.0
14.0
80.0
1236 ,
4039.4
SCR-7-C
6
1.34
140
35
1.1
28.3
202.2
4.4
10.2
80.0
1492
2938.7
SCR-7-C
7
1.52
575
24
3.4
31.6
141.8
13.2
10.9
80.0
3001
4391.2
SCR-7-C
8
1.16
5*0
38
3.6
66.6
121.1
11.2
6.1
80.0
4545
2466.7
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3-67
-------
reactor for unit 8 was assigned a low access/congestion factor due to its
easy accessibility. ATI reactors were assumed to be in areas with high
underground obstructions. Table 3.2.2-8 presents the estimated cost of
retrofitting SCR at the Widows Creek 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.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas for units 1 through 6
were located east of boiler 1. The retrofit of DSD and FSI technologies at
the Widows Creek'steam plant for units 1 to 6 would be relatively easy.
This is due to the large ESPs (SCA >500) long flue gas duct runs and the
subsequent long residence time between the boilers and the retrofit ESPs. If
ESP upgrading was required, a high site access/congestion factor was assigned
to the ESPs upgrade (1.55) because of the close proximity of the ESF\-. The
conversion of wet to dry fly ash handling system would also be required for
reusing the ESPs. Table 3.2.2-9 presents a summary of site access/congestion
factors, scope adders, and retrofit factors for DSD and FSI technologies at
the Widows Creek steam plant. Table 3.2.2-10 presents the costs estimated
for FSI and DSD retrofit at Widows Creek for boilers 1-6.
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, boilers 1 to 6 at Widows
Creek would be considered good candidates for AFBC retrofit and AFBC or
CG/combined cycle repowering because of their small boiler sizes and low
capacity factors. Boilers 7 and 8 would not be considered candidates for
this retrofit technology because both boilers are equipped with retrofit FGD
units.
3-68
-------
TABLE 3.2.2-9,
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR WIDOWS CREEK UNITS 1-6
ITEM __
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1268
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 38
TOTAL COST (1000$)
ESP UPGRADE CASE 1306
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.55
NEW BAGHOUSE NA
3-69
-------
Table 3.2.2-10
, Suimary of OSO/FSI Control Costs far the Widows Creek Plant
(June 1988 Dollars)
II33SSBS
raS£33Sa
siss:sssBs::sssss333s:sS8s3ss:a:
=sassrs=s=
==..*===;=*
«=======¦
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
$02
S02
502 COSt
Nunber
Retrofit
Size
Factor
Sulfur
Cost Cost
cost
Cost
Bmwiuw4 ffwmviwf
KCTWtWJ RCiIW»cU
Effect.
-Difficulty
m
Content
(JHH) Jl/kW)
(Km;
(mi IIs/kwh) (X)
(tons/yr)
(S/ton)
factor
CX>
DSD+ESP
1
1.00
140
29
0.8
7.9 56.4
4.6
13.0
49.0
, 1117
,4142.8
DSD+ESP
2
1.00
140
26
0.8
7.9 56.5
4.6
14.3
49.0
1001
4566.1
DSD+ESP
3
1.00
140
37
0.8
7.9 56.6
4.8
10.6
49.0
1425
3366.8
DSO+ESP
4
1.00
140
35
O.S
7.9 56.3
4.7
11.0
49.0
1348
3517.3
dsd+esp
5
1.00
140
29
0.9
8.1 58.0
4.7
13.3
49.0
1256
3770.7
DSO+ESP
6
1.00
140
35 .
1.1
8.5 60.8
5.1
11.8
49.0
' 1853
2743.2
DSD+ESP-C
1
1.00
140
29
0.8
7.9
56.4
2.7
7.6
49.0
1117
2405.3
DSD+ESP-C
2
1.00
140
26
0.8
7.9
56.5
2.7
S3
49.0
1001
2651.5
DSD+ESP-C
3
1.00
140
37
0.8
7.9
56.6
2.8
6.1
49.0
1425
1953.9
DSD+ESP-C
4
1.00
140
35
0.8
7.9
56.3
2.8
6.4
49.0
1348
2041.4
DSD+ESP-C
5
1.00
140
29
0.9
8.1
58.0
2.8
7.7
49.0
1256
2189.3
DSD+ESP-C
6
1.00
140
¦35
1.1
8.5
60.8
3.0
6.9
49.0
1853
1592.3
FSi+€SP-50
1
1.00
140
29
0.8
8.1
58.0
3.7
10.4
50.0 .
1148
3221.3
FSI+ESP-50
2
1.00
140
26
0.8
8.1
58.0
3.6
11.4
50.0
1029
3518.7
FSI+ESP-50
3
1.00
140
37
0.8
8.1
58.0
3.9
8.6
50.0
1464
2664.2
FSI+ESP-50
4
1.00
140
35
0.8
8.1
58.0
3.9
9.0
50.0
1385
2779.5
FSI+ESP-50
5
1.00
140
29
0.9
8.3
59.0
3.8
10.7
50.0
1291
2953.9
FSJ+ESP-50
6
1.00
' 140
35
1-1
„ 8.5
60.8
4.3
9.9
50.0
1905
2231.5
FSI+ESP-50-C
1
1.00
140
29
0.8
8.1
58.0
2.2
6.1
50.0
1148
1877.3
FSI+ESP-50-C
2
1.00
140
26
0.8
8.1
58.0
2.1
6.6
50.0
1029
2051.4
FSI+ESP-50-C
3
1.00
140
37
0.8
8.1
58.0
2.3
5.0
50.0
1464
1551.3
FSS+ESP-50-C
4
1.00
140
35
0.8
8.1
58.0
2.2
5.2
50.0
1385
1618.8
FSI+ESP-50-C
5
1.00
140
29
0.9
8.3
59.0
2.2
6.2
50.0
1291
1721.0
fSI+ISP-50-C
6 • "
1.00
140
35
1.1
8.5
60.8
2.5
5.8
50.0
1905
1298.6
FSI+ESP-70
1
1.00
140
29
0.8
8.2
58.7
3.7
10.5
70.0
1607
2326.2
FSI+ESP-70
2
1.00
140
26
0.B
8.2
58.7
3.7
11.5
70.0
1441
. 2540.4
FSI+ESP-70
3
1,00
140
37
0.8
8.2
58.7
3.9
8.7
70.0
2050
1925.0
FSJ+ISP-70
4
1.00
140
35
o.a
8.2
58.7
3.9
9.1
70.0
1939
2008.0
FSI+ESP-70
5
1.00
140
29
0.9
8.4
59.7
3.9
10.8
70.0
1808
2134.2
FSI+ESP-70
6
1.00
. 140
35
1.1
8.6
61,6
4.3
10.0
70.0
2666
1614.7
FSI+ESP-70-C
1
1.00
140
29
0.8
8.2
58,7
2.2
6.1
70.0
1607
1355.7
FSI+ESP-70-C
2
1.00
140
26
0.8
8.2
58.7
2.1
6.7
70.0
1441
1481.1
fSl+ESP-70-C
3
1.00
140
¦37
0.8
8.2
58.7
2.3
5.1
70.0
2050
1120.9
FSI+ESP-70-C
4
1.00
140
35
0.8
8.2
58.7
2.3
5.3'
70.0
1939
1169.5
FSI+ESP-70-C
5
1.00
140
29
0.9
8.4
59.7
2.2
6.3
70.0
1308
1243.5
FSI+ESP-70-C,
6
1.00
140
35
1.1
8.6
61.6
2.5
5.8
70.0
2666
939.6
1!
II
If
If
II
II
II
II
II
II
II
II
II
II
II
II
V
II
II
II
II
sssavsass
SSSKSg
33333532SS33
ssssaasasa
ssaaiBsss
334UIB St
esa»»«ag«»aga«Ma»»in
uumaassaisam
3-70
-------
SECTION 4.0 DELAWARE
4.1 DELMARVA POWER AND LIGHT COMPANY
4.1.1 Indian River "Steam Plant
The Indian River steam plant is located within Sussex County, Delaware,
as part of the Delmarva Power and Light Company system. Adjacent to the
Indian River, the plant contains four coal-fired boilers and has a total
gross generating capacity of 780 MW.
Table 4.1.1-1 presents operational data for the existing equipment at
the Indian River plant. Boilers 1-3 burn 1.4 percent sulfur coal and unit 4
burns 0.75 percent sulfur coal (1971 NSPS unit). Coal shipments are
received by railroad and transferred to a coal storage and handling area
east of the plant and beside the Indian River.
PM emissions for the boilers are controlled with ESPs located behind
each unit. The plant has a dry fly ash handling system. Fly ash is
disposed of in an ash pond east of the coal pile. Units 1 through 4 are
served by their own chimneys located behind the ESPs.
Lime/Limestone and Lime Spray Drying FGD Costs--
The four boilers are located beside each other with boiler 1 being
close to the Indian River and boiler 4 being, away from the river. The
absorbers for units 1 through 4 would be located behind the unit 4 chimney
and close to the coal pile. Unit 4 is currently burning low sulfur coal
and, as such, scrubbing would not be required. Although retrofit factors
were developed for this unit, capital and operating costs were not. The
limestone preparation, storage, and handling area would be located south and
east of the coal pile. Some of the plant roads, coal storage area, and a
coal conveyor, would have to be relocated to make space available for the FGD
absorbers. Therefore, a factor of IS percent was assigned to general
facilities.
The Indian River plant Is surrounded by water and very limited space is
available for locating FGD absorbers. FGD absorbers for units 1-3 were not
4-1
-------
TABLE 4.1.1-1. INDIAN RIVER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2 3 4
GENERATING CAPACITY (MW-each) 81 176 442
CAPACITY FACTOR (PERCENT) 73 64 54
INSTALLATION DATE 1957,19 1970 1980
FIRING TYPE FRONT FRONT OPPOSED
WALL WALL WALL
FURNACE VOLUME (1000 CU FT) 47.6,36.5 91.4 NA
LOW NOX COMBUSTION NO NO NO
COAL SULFUR CONTENT (PERCENT) 1.4 1.4 0 .75
COAL HEATING VALUE (BTU/LB) 12700 12700 13200
COAL ASH CONTENT (PERCENT) 10.5 10.5 7.5
FLY ASH SYSTEM DRY HANDLING
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1,2 3 4
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP ESP . ESP
INSTALLATION DATE 1977,78 1981 1980
EMISSION (LB/MM BTU) 0.18,0.11 0.07 0.04
REMOVAL EFFICIENCY 99.5 99.5 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.8 1.8 0.9
SURFACE AREA (1000 SQ FT) 99.4 207.4 1210
GAS EXIT RATE (1000 ACFM) 298 525 1956
SCA (SQ FT/1000 ACFM) 333 395 618
OUTLET TEMPERATURE ( F) 270 285 300
4-2
-------
located behind their respective chimneys due to major demolition/relocation
that would be necessary. Therefore, the site behind unit 4 was selected for
all units. This location has a high site access/congestion factor due to
the access/congestion difficulties created by the coal pile and coal
conveyors.
For flue gas handling, long duct runs (over 1000 feet) would be
required for units 1-3 if chimneys are reused. Therefore, a new chimney was
assumed to reduce the need for long return duct runs. Short duct runs were
assigned to the unit 4 flue gas handling system because its absorbers cart be
placed immediately behind the unit 4 chimney. A high site access/congestion
factor was assigned to the flue gas handling systems due to the access/
congestion difficulties of this location.
LSD with reuse of the existing ESPs was not considered for units 1-3.
Even though the ESPs are large (SCA >300) and would probably handle the
increased load from LSD application, access to the inlet of the ESPs is
extremely difficult. This could result in long boiler downtimes for tie-in.
LSD with a new baghouse was not considered for units 1-3 because of a
limited space available to locate both the absorbers, baghouses, a new
chimney, and the long duct run requirements. For unit 4, ESPs may be
accessed from the north side and absorbers would be located behind the
chimney. A high site access/congestion factor was assumed for the absorber
locations and the flue gas handling system. No major ESP upgrade would be
anticipated because the ESPs are large (SCA >600).
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 4.1.1-2 and 4.1.1-3. Table 4.1,1-4
presents the capital and operating costs for commercial FGD technologies.
Costs for unit 4 are not presented because the unit is burning low sulfur
coal. The low cost FGD system for units 1-3 reduces capital costs because
of the economies of scale obtained by combining the FGD systems and using
large absorber sizes and eliminating spare absorber modules.
Coal Switching and Physical Coal Cleaning Costs-
Table 4.1.1-5 presents the IAPCS cost results for CS at the Indian
River boilers 1-3. These costs do not include boiler and pulverizer
4-3
-------
TABLE 4.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR INDIAN RIVER UNITS 1-3
(EACH)
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) 600-1000 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 YES NA NA
ESTIMATED COST (1000$) .567 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.76 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 0
4-4
-------
TABLE 4.1.1-3.
SUMMARY OF RETROFIT, FACTOR DATA FOR INDIAN RIVER UNIT 4
FGD TECHNOLOGY
L/LS FGD
FORCED
OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
. NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
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) 15
0
8
4-5
-------
Table 4.1.1-4. Surmary of Fffl Control Costs for the Indian River "Plant {June 1988 Dollars)
Technology Boiler Main Boiler Capacity Ceal Capital Capital Annual Annual. 502 S02 S02 Cost
Nuttier Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MM) Content (SHX) (S/kW) (SWf).-(mUls/kuh) (X) aesaa3=s3amsaas33sa9sasssssssss
4-6
-------
Table 4.1.1-5. Swmary of Coal Switching/Cleaning Costs for the Indian River Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 502 Cost
Nuifcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X)- Content (SUM) Ct/kW) (SW) (¦( Ua/kuh) (X) (tons/yr) (J/tor.)
Factor <%)
CS/B*»15
CS/8+S15
CS/S*$15-C
CS/B*»15-C
CS/B+tS
CS/B+S5
2
3
t, 2
3
1, 2
3
00
00
00
00
00
00
81
176
81
176
81
176
73
64
73
64
73
64
1.4
1.4
1.4
1.4
1.4
1.4
3.S
6.4
3.5
6.4
2.7
4.6
43.5
36.6
43.5
36.6
33.1
26.2
7.9
14.5
4.6
8.4
3.5
6.1
15.3
14.7
8.8
8.5
6.8
6.2
32.0
32.0
32.0
32.0
32.0
32.0
1742
3318
1742
3318
1742
3318
4556.3
4382.7
2619.5
2519.7
2015.5
1829.9
CS/B*$5-C
CS/B*$5-C
1, 2
3
1.00
1.00
81
176
73
64
1.4
1.4
2.7
4.6
33.1
26.2
2.0
3.5
3.9
3.1
32.0
32.0
1742
3318
1161.6
1054.6
4-7
-------
operating cost changes or any system modifications that may be necessary to
blend coal. PCC was not evaluated because this 1s not a mine mouth plant.
Low N0X Combustion
Units 1-3 are dry bottom, wall-fired boilers. The combustion
modification technique applied to these boilers was LNB. Tables 4.1.1-6 and
4.1.1-7 present the performance and cost results of retrofitting LNB at the
Indian River plant. Unit 4 was assumed to already have LNBs as an NSPS
unit.
Selective Catalytic Reduction
Cold side SCR reactors for units 1-3 would be located in the small
space available between the coal pile and units 1 and 2. The SCR reactor
for unit 4 would be located immediately behind the unit 4 chimney. Reactors
for units 1-3 are located in high site access/congestion areas. The space
between units 1-2 and the coal pile is very congested because of the ash
silos, coal conveyors, and ESPs. Two of the ash silos have to be relocated
to open up more space for units 1-3 reactors; therefore, a factor of
35 percent was assigned to general facilities. Access to unit 4 reactor
area is difficult because of the coal conveyor. However, sufficient space
is available behind the chimney and a medium site access/congestion factor
was assigned to the unit 4 reactor location. All reactors were assumed to
be in areas with high underground obstructions. The ammonia storage system
was placed close to the coal pile in a similar layout as the sorbent storage/
preparation area for the case of wet FGD. Duct lengths of 250 feet were
estimated for the flue gas handling systems.
Table 4.1.1-6 presents the SCR process area retrofit factors and scope
adder costs. Table 4.1.1-7 presents the estimated cost of retrofitting SCR
at the Indian River boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of sorbent injection technologies at the Indian River
steam plant for all units would be difficult because the short duct
residence time between the boilers and the ESPs would not be sufficient for
either humidification (FSI application) or sorbent evaporation (DSD
4-8
-------
TABLE 4.1.1-6. . SUMMARY OF NOx RETROFIT RESULTS FOR INDIAN RIVER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 ,
3
. 1-3
4
FIRING TYPE
FWF
FWF
,NA
. OWF
TYPE OF NOx CONTROL
LNB
LNB
NA
LNB
FURNACE VOLUME (1000 CU FT)
47.6
91.4
NA
NA
BOILER INSTALLATION DATE
1959
1970
NA
1980
SLAGGING PROBLEM
NO
NO
NA
NO
ESTIMATED NOx REDUCTION (PERCENT)
40
.36
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
23
41
67
82
New Duct Length (Feet)
250
250
250
,250
New Duct Costs (1000$)
1095
1724
2526
2955
New Heat Exchanger (1000$)
1642
2616
3870
4546
TOTAL SCOPE ADDER COSTS (1000$) 2761 4382 6464 7584
RETROFIT FACTOR FOR SCR 1.52 1.52 1.52 1.34
GENERAL FACILITIES (PERCENT) 35 35 35 13
4-9
-------
Table 4.1.1-7. NOx Control Cost Results for the Indian River Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
N wiser Retrofit Siie Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content ($MM) (S/kW) (SUM) (mills/kwh) (X) (tons/yr)
INC-1KB
1, 2
1.00
at
73
1.4
• 2.3
29.0
0.5.
1.0
40.0
843 .
610.4
INC-1MB
3
1.00
176
64
•1.4 '
3.2
18.2
0.7
0.7
. 36.0'
.1446 '
485.7
LNC-LNB-C
1. 2
1.00
81
73
1.4
2.3
29.0
0.3
0.6
40.0
843
362.2
LNC-LNB-C
3
1.00
176
' 64
1.4
3.2
18.2
0.4
0.4
36.0
1446
288.2
SCR-3
1, 2
1.52
81
73
1.4
20.8
256.4
6.6
•12.8 '
80.0
1687
3924.7
SCR-3
3
1.52
176
64
1.4
34.5
.196.1
11.4
11.6
80.0
3213
3555.5
SCR-3
4
1.34
442
54
0.8 •
59.9
135.6
21.5
10.3
80.0
6513
3295,6
SCR-3
1-3'
1.52
338
68
1.4
57.3
169.5
19.7
9.8
80.0
6556
3000.8
SCR-3-C
1. 2
1.52
81
73
1.4
20.8
256.4
3.9
7.5
80.0
1687
2303.8
SCR-3-C
3
1.52
176
- 64
¦ 1.4
• 34.5
196.1
6.7
6.8
80.0
3213
2085.2
SCR-3-C
4
1.34
442
54
. 0.8
59.9
135.6
12.6
6.0
80.0
6513
1929.4
SCR-3-C '
1-3
1.52
338
68
, 1.4
57.3
169.5
11.5
5.7
80.0
6556
1758.4
SCR-7
1, 2
1.52
81
73
1.4 '
20.8
256.4
.6.0
11.5
80.0
. 1687
3533.3
SCR-7
3
1.52
176
64
1.4
34.5
196.1
10.0
10.1
80.0
3213
3109.1
SCR-7
4
1.34
442
54
0.8
59.9
135.6
17.9
8.6
80.0
6513
2745,7
SCR-7
1-3
1.52
338
68
1.4
57.3
169.5
16.9
8.4 '
80.0
6556
2580,7
SCR-7-C
1, 2
1.52
81
73
1.4
20.8
256.4
3.5
6.8
; so.o '
1687
2079.6
SCR-7-C
3
1.52
176
64
1.4
34.5
196.1
5.9
6.0
80.0
3213
1829.4
SCR-7-C
4
1.34
442
54
0.8
59.9
135.6
10.5
5.0
80.0
6513
1614.4
SCR-7-C
1-3
1.52
338
68
1.4
57.3
169.5
10.0
4.9
80.0
6556
1517.7
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4-10
-------
application). However, both technologies were considered for this plant
because the ESPs are large enough to modify, the first ESP sections for
humidification and sorbent injection. The sorbent receiving/storage/
preparation areas were located behind the unit 4 chimney.
Tables 4.1.1-8 and 4.1.1-9 present a summary of the site access/
congestion factors for sorbent injection technologies at the Indian River
steam plant. Table 4.1.1-10 presents the costs estimated to retrofit FSI
and DSD at the Indian River boilers.
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 Indian River plant. Units 1-2 would be considered good
candidates for repowering or retrofit because of their small boiler sizes.
Units 3-4 would not be considered because of their age and/or size.
4-11
-------
TABLE 4.1,1-8.
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR INDIAN RIVER UNITS 1-3 (EACH)
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
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$) 26
TOTAL COST (1000$)
ESP UPGRADE CASE 26
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM .ONLY) 1.25
ESP UPGRADE 1.58
NEW BAGHOUSE - NA
4-12
-------
TABLE 4.1.1-9. DUCt SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR INDIAN RIVER UNIT 4
ITEM -
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 91
TOTAL COST (1000$)
ESP UPGRADE CASE 91
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.58
NEW BAGHOUSE NA
4-13
-------
Table 4,1.1-10. Surinary of DSO/FSt Control Costs for the Indian River Plant (June 1983 Dollars)
=E=S====a*S3=
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nuitoer Retrofit
Size
Factor-
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MHJ
<*>
Content
CSMH5
<$/kU)
($MM)
(mills/kwh)
<%>
(tons/yr)
<$/$on)
factor
(%>
DSD+ESP
1,
2
1.00
81
73
1.4
5.5
66.3
5.3
10.2
49.0
2667
1972.7
DSO+ESP
3
1.00
176
64
1.4
3.4
47.7
7-1
7.2
49.0
5080
1401.0
CSD+ESP
4
1.00
442
54
0.8
11.4
25.7
8.6
4.1.
49.0
5885
1460.2
DSQ*ESP-C
1.
2
1.00
81
73
1.4
5.5
68.3
3.0
5.9
49.0
2667
1139.5
DSD*fSP-C
3
1.00
176
64
1.4
8.4
47,7
4.1
4.2
49.0
5080
810.1
DSD+ESP-C '
4
1.00
442
54
0.8
11.4
25.7
5.0
2.4
49.0
¦ 5885
845.2
FSJ*E$P-50
•1.
2
1.00
81
73
1.4
5.9
73.3
4.6
8.8
50.0
2741 .
1661.4
F5I+ESP-50
3
1.00
176
64
1.4
8.5
48.4
6,8
6.8
50.0
5221
1292.8
FSHESP-50
4
1.00
442
54
0.8
12.9
29.2
8.6
4.1
50.0
6048
' 1420.1
FSI*ESP-50-C
1.
2
'1.00
81
73
1.4
5.9
73.3
2.6
5.1
50.0
2741
961.6
FSI+ESP-50-C
3
1.00
176
64
8.5
48.4
3.9
4.0
50.0
5221
748.0
FSI+ESP-SO-C
4
1.00
442
54
0.8
12.9
29.2
5.0
2.4
50.0
6048
823.2
FSl+ESP-70
1,
2
1.00
81
73
1.4
6.0
74.6
4.6
8.9
70.0
3837
1203.9
FSI+ESP-70
3
1.00
176
64
1.4
8.6
49.1
6.9
7.0
70.0
7310
938.8
FSI+ESP-70
4
1.00
442
54
0.8
13.1
29.5
8.7
4.2
70.0
8467
1029.7
FSI+ESP-70C
1,
2
1.00
81
73
1.4
6.0
74.6
2.7
5.2
70.0
3837
696.8
FSI+ESP-70-C
• 3
1.00
176
64
. 1-4
8.6
49.1
4.0
4.0
70.0
7310
543.2
FS1+ESP-70-C
4
1.00
442
54
0.8
13.1
29.5
5.1
2.4
70.0
S467
596.9
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4-14
-------
SECTION 5.0 FLORIDA
5,1 FLORIDA POWER CORPORATION ¦ '
* 5.1.1 Crystal River Steam Plant
The Crystal River steam plant is located within Citrus County, Florida,
as part of the Florida Power Corporation system. The plant is located near
Crystal River City and adjacent to Crystal River Bay on the Gulf of Mexico.
The plant contains four coal-fired and one nuclear boiler with a total gross
generating capacity of 3,116 MW. • - .
Table 5.1.1-1 presents operational data for the existing equipment at
the Crystal River plant. The boilers burn low sulfur coal (0.7 to
1.0 percent). Coal shipments are received by barge/railroad and are
transferred to the units 1-2 coal storage and handling area. Part of the
coal is then transferred by a coal conveyor to a second coal pile east of
units 4-5. Units 4-5 comply with the 1971 NSPS emission limit of <1.2 lbs
SOg per MM Btu.
PM emissions for the boilers are controlled with new or retrofit ESPs
located behind each unit. The plant has a dry fly ash handling system.
Almost half of the fly ash is sold while the rest of it is disposed of
on-site. In addition, the plant has the capability to sluice the fly ash in
case of an emergency. All units have separate chimneys located behind each
unit. .
Lime/Limestone and Lime Spray Drying FGD Costs-
Units 1-2 are located beside each other and between the water channel
and the water intake channel. Unit 3 (nuclear) is located east of unit 1.
The absorbers for units 1-2 for both conventional and LSD-FGD cases would be
located west of unit 2 in an open space between the unit 2 retrofit ESPs and
the oil tanks. Space is also available east of unit 1. However, unit 1 is
located very close to the nuclear unit and might cause some interferences.
Therefore, this location was not considered in this study.
5-1
-------
TABLE 5.1.1-1. CRYSTAL 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
r 2
420 476
63 63
1966 1969
TANGENTIAL
228.5
NO
1.0
12300
NA
NA
NO
1.0
12300
NA
4,5^
665
80
1982,
FRONT
WALL
734
YES
0.7
12500
NA
DRY HANDLING
ON-SITE/SOLD
2
BARGE/RAILROAD
1
3-4
84
3
890
31
1977
NUCLEAR
POWER
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PEi
SURFACE AREA (1000 SQ FT
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
ESP
1979
1979
1982,
84
0,05
0.02
0.02-
¦0.01
99.5
99.5
99.8
) 1.3
1.3
0.8
432 •
1351
1582
1415
1930
2348
305
700
674
292
300
282,
287
5-2
-------
The absorbers for units 4-5 would be located behind the chimneys on
either side of the coal conveyor for conventional FGD cases and on the side
of each unit for the LSD case. No major demolition or relocation would be
necessary for any of the units except units 4-5 in the LSD case. Because
the absorbers for units 4-5' in the LSD-FGD case are located on the side of
each unit, some of the storage areas and one of the ash silos would have to
be relocated. Therefore, general facilities factors of 5 and 10 percent
were assigned to the FGO costs accordingly. Sorbent storage and handling ,
areas would be located south of the coal pile serving units 4-5 and close to
the railroad tracks so that the existing tracks can be used for sorbent
transfer.
A medium site access/congestion factor was assigned to the FGD absorber
locations serving units 1-2 due to some access difficulties to this area
created by the water channel, oil tanks, and units 1-2. For units 4-5, a
low site access/congestion factor was assigned for the conventional FGD
absorber locations. For flue gas handling, a long duct length with a high
site access/congestion factor would be required for unit 1 because the
chimney serving unit 1 is located away from the absorbers and access to this
chimney is difficult. Because over 1,000 feet of duct would be needed to
reuse the existing chimney, a new chimney would be located adjacent to the
absorbers for unit 1. For units 2 and 4-5, a low site access/congestion
factor was assigned due to relatively short duct runs and because of the
open space available around the existing chimneys.
LSD with a new baghouse was considered for unit 1 because plant
personnel indicated that on occasion SO^ conditioning is necessary to meet
the emission levels. Because of this problem and the location of the ESPs
(away from the absorber location), the ESPs for unit 1 were not reused for
the LSD-FGD case. A new baghouse and chimney were located close to the LSD
absorbers which were located in a similar layout to the conventional wet
FGD. A medium site access/congestion factor was also assigned to the new
baghouse location. Reuse of the existing ESPs was considered for the other
three units. For unit 2, a low site access/congestion factor was assigned
to the flue gas handling system with a short to moderate duct run being
required. For units 4-5, LSD absorbers would be located on either side of
the units. However, access to the existing ESPs would be difficult due to
5-3
-------
the limited space available between the ESPs and the boilers. A high site
access/congestion factor was assigned to the flue gas handling system.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 5.1.1-2 through 5.1.1-4. Because all
boilers currently burn low sulfur coal, an FGD system would only be.
considered at the plant if SO,, emission levels were very low (<1.2 lbs per
MM Btu) or the price differential between low and high sulfur coal made
scrubbing economical. As such, FGD cost estimates are not presented for the
currently used coal.
Coal Switching and Physical Coal Cleaning Costs--
Because the Crystal River plant already burns a low sulfur coal, costs
were not developed for CS or PCC.
Low NOx Combustion--
Units 1-2 are dry bottom, tangential-fired boilers rated at 420 and
476 MW, respectively. The combustion modification technique applied to
these boilers was OFA. . As Table 5.1.1-5 shows, the OFA NO reduction
X
performance level was based on the low volumetric heat release rate.
Units 4-5 are already equipped with LNB and are not considered as LNC
candidates. Table 5.1.1-6 presents the cost of retrofitting OFA at the
Crystal River plant.
Selective Catalytic Reduction--
Cold side SCR reactors for all units would be located behind the
chimney or to the side of the unit. A low site access/congestion factor was
assigned to all reactor locations. Approximately 200 feet of duct would be
required for all units. No major demolition/relocation would be required
for placement of the SCR reactors; therefore, a base factor of 13 percent
was assigned to general facilities. The ammonia storage system was piaced
near the railroad tracks and close to the coal pile serving units 4-5.
Table 5.1.1-5 presents the SCR retrofit factors and scope adder costs.
The scope adders include costs estimated for ductwork demolition, flue gas
heat exchangers, and new duct runs to divert the flue gas from the ESPs to
the reactor and from the reactor to the chimney. Table 5.1.1-6 presents the
5-4
-------
TABLE 5.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CRYSTAL RIVER
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITEACCESS/CONGESTION
S02 REMOVAL MEDIUM - NA MEDIUM
FLUE GAS HANDLING HIGH NA .
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 600-1000 NA
ESP REUSE
BAGHOUSE 600-1000
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 2940 ,0 2940
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.65 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.69
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.36
GENERAL FACILITIES (PERCENT) 5 0 5
-------
TABLE 5.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CRYSTAL RIVER
UNIT 2
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
.
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600 .
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$)
NA
NA
NA
• NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
1.40
BAGHOUSE CASE
NA
ESP UPGRADE
NA-
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
5
-------
TABLE 5.1.1-4. SUMMARY OF
RETROFIT FACTOR DATA FOR CRYSTAL RIVER
UNIT 4 OR 5
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE 300-600
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 1.20 NA
ESP REUSE CASE 1.36
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1..I6
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 10
5-7
-------
TABLE 5.1.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR CRYSTAL RIVER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1 2 4,5
FIRING TYPE ¦ TANG TANG FWF
TYPE OF NOx CONTROL 0FA OFA LNB
FURNACE VOLUME (1000 CU FT) 228.5 NA 734
BOILER INSTALLATION DATE 1966 1969 1982
SLAGGING PROBLEM _N0 NO NO
ESTIMATED NOx REDUCTION (PERCENT) 25 25 NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION :
FOR SCR REACTOR LOW LOW LOW
SCOPE ADDER PARAMETERS--
New Chimney (1000$) 0 0 0
Ductwork Demolition (1000$) 79 87 112
New Duct Length (Feet) 200 200 200
New Duct Costs (1000$) 2294 2469 3002
New Heat. Exchanger (1000$) 4409 4753 5809
TOTAL SCOPE ADDER COSTS' (1000$) 6782 7309 8923
RETROFIT FACTOR FOR SCR 1.16 1.16 1.16
GENERAL FACILITIES (PERCENT) 13 13 13
5-8
-------
Table 5.1.1-6. NOx Control Cost Results for the Crystal River Plant (June 1988 Dollars)
sasssssassss
ssisssss:
ssassssssssssssss
11
11
II
II
II
II
II
II
II
II
II
II
II
It
II
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II
II
11
II
8
II
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II
II
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i
IBIlSSBtSSX
aasstsss
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IBSISSBS 3
Technology -
Boiler
Main
Soiler Capacity Coal
Capital Capital Annual
¦ Annual
NOx
NOx
NO* Cost
Nusber
Retrofit
! Size
factor
Sulfur
Cost ,
Cost
Cost'
Cost
Removed
Removed
Effect.
Difficulty (MW)
<%)
Content'
<$HH)
ts/kvrj
(niUs/kwh)
<%>
(tsris/yr)
($/ton)
Factor
(S)
UC-OFA
1
1.00
420
63
1.0
1.1
2.6
0.2
0.1
25.0
1748
133.2
INC-OFA
2
1.00
476
63
1.0
1.2
2.4
0.2
0.1
25.0
1981
123.5
INC-OFA-C
1 .
' 1.00 .
420
63 '
1.0
1.1
2.6
0.1
0.1
25.0
1748
79.1
LNC-OFA-C
2
• 1.00
476
. 63 ¦
1.0
1.2
2.4
0.1
0.1
25.0
1981
73.4-
SCR-3
1
1.16
420
63
1.0
' '52.1
124.1
18.8
8.1
80.0 .
5593
3364.6
SCR-3
2
1.16
476
63
1.0
58.1
122.2
21.1
8.0
80.0
6339
1328.3
SCR-3
4,5
1.16
665
so
0.7
77.5
116.6
29.8
6.4
80.0
15454
1929.5
SCR-3-C
1
1.16
420
63
1.0
52.1
124.1
11.0
4.8
80.0 ¦
5593
1969.5
SCR-3-C
2'
1.16
476
63
1.0
se.i
122.2
12.3
4.7
80.0
6339
1948.0
SCR-3-C
4,5
1.16
665
80 .
0.7
77.5
116.6
17.4
3.7
80.0
15454
1128.0
SCR -7
. 1
1.16
420
63
1.0
52.1
124.1
15.4
6.6
80.0
5593
2749.8
SCR-7
2
1.16
476
63
1.0
58.1
122.2
17.2
6.5
80.0
6339
2713.5
SCR-7
. 4,5
1.16
665
SO
0.7
77.5
116.6
24.4
5.2
80.0
15454
- 1578.0
SCR-7-C
1
1.16
420
63
1.0
52.1
124.1
9.0
3.9
80.0
5593
1617.2
SCR-7-C
' 2
1.16
476
63 ¦
1.0
58.1
122.2
10.1
3.9
80.0
6339
1595.8
SCR-7-C
4,5
1.16
665
SO
0.7
77.5
116.6
14.3
3.1
80.0
15454
926.6
s=__________
_________
S5S3SSS
=========
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II
II
II
II
il
il
a
II
II
II
II
II
II
SSSSS3S
sssssssssss
II
II
II
N
II
II
II
«
5-9
-------
estimated cost of retrofitting SCR at the Crystal River boilers. Retrofit
of hot side SCR system would result in a unit downtime penalty. The
replacement cost could be significant for these large baseload units.
Duct Spray Drying and Furnace Sorbent Injection--
i The retrofit of FSI and DSD technologies at the Crystal River steam
plant would be difficult for unit 1 for two major reasons: 1) the retrofit
ESPs might not be able to handle the increased PM and would require major
ESP upgrades and additional plate area; and 2) the short duct residence time
between the boilers and ESPs would not be sufficient for either
humidification (FSI application) or for sorbent evaporation (DSD
application). By contrast, retrofit of FSI and DSD technologies on unit 2
would be easy. This is due to the long duct run between the boiler and
retrofit ESP and to the fact that this ESP is oversized for its current
load. For these reasons, unit 2 is a good candidate for DSD or FSI
technologies. For units 4-5, the application of these two technologies
would also be difficult for the latter reason. However, FSI and DSD
technology was considered for these units because the ESPs could be modified
for humidification and additional plate area could be added downstream of
the ESPs.
A high site access/congestion factor was assigned for upgrading the
unit 1 ESP because of access difficulty and some congestion that is created
by the office building, ash silos, and chimney. For units 4-5, a low site
access/congestion factor was assigned for the ESP upgrades because of the
space availability behind the ESPs. The, sorbent receiving/storage/
preparation areas would be located west of unit 2 for units 1-2 and east of
unit 4 for units 4-5.
Tables 5.1.1-7 through 5.1.1-9 present a summary of the site access/
congestion factors for FSI and DSD technologies at the Crystal River steam
plant. Table 5.1.1-10 presents the costs estimated to retrofit FSI and DSD
at the Crystal River boilers. The high unit costs are a result of units
burning low sulfur coal.
5-10
-------
TABLE 5.1.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CRYSTAL RIVER UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
ESP UPGRADE
NEW BAGHOUSE
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$) 88
TOTAL COST (1000$)
ESP UPGRADE CASE 88
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE ,1.58
NEW BAGHOUSE ' NA
MEDIUM
HIGH
NA
5-11
-------
TABLE 5.1.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CRYSTAL RIVER UNIT 2
ITEM
; SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 96
TOTAL COST (1000$)
ESP UPGRADE CASE 96
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.16
NEW BAGHOUSE _
5-12
-------
TABLE 5.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CRYSTAL RIVER UNITS 4 OR 5
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$) 124
TOTAL COST (1000$)
ESP UPGRADE CASE 124
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
5-13
-------
Table 5.1.1-10. Sumtary of OSD/FSl Control Costs for the Crystal. River Plant (June 1988 Dollars)
3SSSSSSSSSSSSS3S8SS3SSSS3SSaa3Sa33C38SSS8S3935S3!aBBKBVSaSS3l3S!taSSS>S9S99ISSlliBSSSSSSSS8SB8tt9SSCS33SSSSS;SSSSSSSSSS
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) (X) Content (SUM) (S/kVO (WW) (mills/kxh) (tons/yr) ($/ton)
Factor (X)
DSD+ESP
1
1.00
420
63
1.0
13.2
31.5
9.8
4.2
49.0
8843
1107.9
DSD+ESP
2
1.00
476
63
1.0
13.5
28.3
10.4
4.0
49.0
10022
1042.7
DSD+ESP
4,5
1.00
665
SO
0.7
15.4
23.1
12.8
2.8
49.0
12218
1051.5
DSO+ESP-C
1
1.00
420
63
1.0
13.2
31.5
5.7
2.4
49.0
8843
641.5
DSD+ESP-C
2
1.00
476
63
1.0
13.5
28.3
6.0
2.3
49.0
10022
603.4
SSD+ESP-C
4,5
1.00
665
80
0.7
15.4
23.1
7.4
1.6
49.0
12218
608.1
FSS+ESP-50
1
1.00
420
63
1.0
15.7
37.3
10.7
4.6
50.0
9089
1180.5
FSJ+ESP-50
2
1.00
476
63
1.0
13.7
28.8
11.0
4.2
50.0
10300
1063.9
FSI+ESP-50
4,5
1.00
665
80
0.7
16.0
24.1
13.2
2.8
50.0
12557
1050.3
F5I+ESP-50-C
1
1.00
420
63
1.0
15.7
37.3
6.2
2.7
50.0
9089
684.1
FS1+CSP-50-C
2
1.00
476
63
1.0
13.7
28.8
6.3
2.4
50.0
10300
615.5
FS1+ESP-50-G
4,5
1.00
665
80
0.7
16.0
24.1
7.6
1.6
50.0
12557
607,5
FSS+ESP-70
1
1.00
420
63
1.0
15.8
37.6
10.9
4.7
70.0
12724
856.0
FS1+ESP-70
2
1.00
476
63
1.0
13.9
29.1
11.1
4.2
70.0
14420
772.9
FSI+ESP-70
4,5
1.00
665
80
0.7
16.3
24.5
13.4
2.9
70.0
17579
764.4
FSI+ESP-70-C
1
1.00
420
63
1.0
15.8
37.6
6.3
2.7
70.0
12724
496.0
FSI+ISP*70-C
2
1.00
476
63
1.0
13.9
29.1
6.4
2.5
70.0
14420
447.1
FSI+ESP-70-C
4,5
1.00
665
80
0.7
16.3
24.5
7.8
1.7
70.0
17579
442.1
==============
======
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5-14
-------
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 Crystal River plant. None of the boilers would be
considered good candidates for repowering and retrofit because of their
large size, short service life, and high capacity factor.
5-15
-------
5.2 GULF POWER COMPANY
5.2.1 Crist Electric Generating Plant
The Crist Electric Generating Plant is located near the mouth of the
Escambia River in Escambia County near Pensacola, Florida, and is owned and
operated by the Gulf Power Company. The Crist plant contains four
coal-fired and three oil and gas-fired boilers with a total gross generating
capacity of 1107 MW. The generating capacity of the four coal-fired boilers
is 1022 MW,
Table 5.2.1-1 presents operational data for the existing equipment at
the Crist plant. Shipments of coal are received by barge and transferred to
a coal storage and handling area adjacent to the plant. PM emissions from
two of the coal-fired boilers (6 and 7) are controlled by ESPs installed at
the time of construction. PM emissions from the other two coal-fired
boilers are controlled by retrofit ESPs in series with original ESPs. ESPs
for all four, units are located behind the boilers. Flue gases from boilers
1-5 are ducted to one chimney while the flue gas from boilers 6-7 is ducted
to another chimney. Flyash from the coal-fired generating units is
collected, dried, and pneumatically conveyed to storage tanks on the west
side of the property. This ash is sold, when possible, otherwise it is
transported by truck to a state permitted landfill on the west edge of the
property.
Lime/Limestone and Lime Spray Drying FGD Costs--
Because the coal pile is located directly behind units 4-7, the
absorbers for units 4-1 would be located east of unit 1 after relocating
demineralizer/condensate storage tanks and No. 2 oil storage tanks adjacent
to unit 1. These tanks would be relocated to a new location further south.
For units 6-7, absorbers would be located west of unit 5 adjacent to the
cooling towers, west of the office and general repair building. Additional
ductwork would be required to go around the existing dry ash handling
bridge.
A high site access/congestion factor would be assigned to the FGD
absorber locations because of the space limitation created by the proximity
5-16
-------
TABLE 5.2.1-1. CRIST POWER COMPANY 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
1-3
28, 28, 38
2,3
1945,52
GAS
FIRED
4-5
88,89
46
1958,61
TANG
42.4
6
327
44
1970
FRONT
WALL
158
NO
2.4
12100
9.4
WET
ON-SITE/SOLD
2
BARGE
7
519
27
1973
OPPOSED
WALL
282
rARTICULATE 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 (lF)
ESP
ESP
ESP
IT SIDE)
NA
NA
NA
0.02
0.04
0.08
99.0
98.5
98.5
0.5-3.5
0.6-3.5
0.6-3.5
184
69.1
1582
515
505
2348
357
137
158
650
283
285
5-17
-------
of the river, the channels, and auxiliary equipment. In the L/LS-F6D case,
medium to long duct runs would be required. A high site access/congestion
factor was assigned to the flue gas handling system because of the
difficulties accessing the downstream of the ESPs. For units 6-7, a new
chimney would need to be installed close to the absorbers to reduce the duct
length- and congestion. Plant personnel indicated that construction of a new
chimney may be difficult due to the close proximity of the Municipal
airport.
LSD with reuse of the existing ESPs was not considered for units 4-5
because the units are equipped with an arrangement of cold and hot side ESPs
which are not easy to reuse. For units 6-7, the access to the ESPs is
difficult; therefore, reuse of the existing ESPs was not considered. LSD
with a new baghouse was not considered for units 6-7 because the boilers are
burning medium to high sulfur coal. (Gulf Power, under contract to EPRI,
has been operating a high sulfur coal baghouse test facility at its Scholz
steam plant.)
Tables 5.2.1-2 and 5.2.1-3 give a summary of retrofit data for
commercial FGD technologies. Table 5.2.1-4 presents the FGD capital and
operating cost results. The low cost FGD cases show the benefits of
combinino FGD systems to obtain economy of scale, eliminating spare absorber
modules, and maximizing absorber size. Limited space is available on site
for waste disposal. Plant personnel indicated that the wet sludge has to be
transported by truck to a disposal site approximately ten miles away (this
value was used in this study).
Coal Switching and Physical Coal Cleaning Costs-
Table 5.2.1-5 presents the IAPCS cost results for CS at the Crist
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 NO Combustion--
A
Boilers 4-7 at the Crist steam plant are rated at 88, 89, 327, and
519 MW, respectively. The combustion modification techniques applied to
5-18
-------
TABLE 5.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CRIST
UNIT 4 OR 5
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) 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$) 887 NA NA
NEW CHIMNEY NO NA NA.
ESTIMATED COST (1000$) 0 0 0
OTHER YES NO
RETROFIT FACTORS
FGD SYSTEM 1.88 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 0_
5-19
-------
TABLE 5.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CRIST
UNIT 6 OR 7
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA NA
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 600-1000 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA NA
ESTIMATED COST (1000$) 4519 NA NA
NEW CHIMNEY YES NA NA
ESTIMATED COST (1000$) 4046 0 0
OTHER YES NO
RETROFIT FACTORS
FGD SYSTEM 2.00 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 0_
5-20
-------
Table 5
.2.1-4.
Surinary of FGD
Control
Costs for the Crist Plant (June
1988 Dollars)
ItSSSSailBBI
Technology
¦ SSHSSBi
Bailer
¦SHB9BH
Main
¦ inimnifiuisBmil
Boiler Capacity Coal
IB3ai391»SIIII33IB33113I
Capital Capital Annual
ISS3B3S3I!
Annual
isiiasisi
S02
!5S5SS»*»Sa
S02
tassissaa
SQ2 Cost
Nirater
Retrofit
Size
Factor
Sulfur
Cos t
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Factor
........
(XI
.w. .......
.........
.......
..........
.........
............
.........
L/S FGD
4,5
1.88
88
46
2.4
66.9
760.4
24.3
68.5
90.0
6120
3967.4
L/S FGD
4-5
1.88
177
46
2.4
89.9
508.0
33.2
46.6
90.0
12309
2701.0
US FGD
6
2.00
327
44
2.4
127.9
391.0
48.4
38.4
90.0
21755
2222.7
L/S FGD
7
2.00
51?
27
2.4
168.6
324.9
60.2
49.0
90.0
21188
2839.0
L/S FGD
6-7
2.00
846
34
2.4
237.4
280.6
88.6
35.2
90.0
43492
2037.7
L/S FGD-C
4,5
1.88
88
46
2.4
66.9
760.4
14.2
40.1
90.0
6120
2322.1
L/S FGD-C
4-5
1.88
177
46
2.4
89.9
508.0
19.5
27.3
90.0
12309
1580.2
L/S FGD-C
6
2.00
327
44
2.4
127.9
391.0
28.3
22.4
90.0
21755
1299.8
L/S FGD-C
7
2.00
519
27
2.4
168.6
324.9
35.2
28.7
90.0
21188
1662.2
L/S FGD-C
6-7
2.00
846
34
2.4
237.4
280.6
51.8
20.6
90.0
43492
1191.9
LC FGD
4-5
1.38
177
46
2.4
64.4
363.7
25.4
35.7
90.0
12309
2066.8
LC FGD
6-7
2.00
846
34
2.4
200.3
236.8
77.3
30.7
90.0
43492
1777.3
LC FGD-C
4-5
1.88
177
46
2.4
64.4
363.7
14.9
20.8
90.0
12309
1207.6
LC FGD-C
6-7
2.00
846
34
2.4
200.3
236.8
45.2
17.9
90.a
43492
1038.9
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5-21
-------
Table
5.2.1
*5
S urinary of Coal Switching/Cleaning Costs for the Crist Plant
(June 1988 Dollars)
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annust
Annual
S02
302
S02 Cost
Nimter
Retrofit
Size
Factor Sulfur
Cast
Cost
Cost
Cost
Removed Removed
effect.
Difficulty £MM)
(X)
Content
-------
TABLE 5.2.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR CRIST
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4, 5
6
7
FIRING TYPE
TANG
FWF
OWF
TYPE OF NOx CONTROL
OFA
LNB
LNB
FURNACE VOLUME (1000 CU FT)
42.4
158
282
BOILER INSTALLATION DATE
1959
1970
1973
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
29
34
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$)
26
72
101
New Duct Length (Feet)
500
250
250
New Duct Costs (1000$)
2389
2663
3457
New Heat Exchanger (1000$)
0
4086
5340
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
2415
3628
6821
8898
11950
RETROFIT FACTOR FOR SCR
1.72
1.72
1.72
GENERAL FACILITIES (PERCENT)
38
38
38
5-23
-------
Table 5.2.1-7. NOx Control Cost Results far the Crist Plant (June 1988 Dollars)
acaasaaaasaaasasaaasassaaaasaaaaaaaiaaaaBBassssasasssasaaaaaisaaaaaaaaitfaaaaaaaBss&aassasBsaaasaBaaau^s^aiaasSBBassa
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nwtoar Retrofit
Si I*
Factor Sulfur
Cost
coat
Coat
Cost
Removed Removed
Effect.
Difficulty (mi)
C%)
Content
(M*>
C»/W>
(SMI)
(itiills/kwh)
iiiiiiiniHinnHa»innn»»namiiiiiuniiHniniini»nnininitmnmn»
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%
5-24
-------
these boilers are OFA for units 4-5 and LNB for units 6-7. Tables 5.2.1-6
and 5.2.1-7 give a summary of N0X retrofit performance and cost results.
Selective Catalytic Reduction-
Hot side SCR reactors for units 4 and 5 would be located east of
unit 1.. Cold side SCR reactors for units 6 and 7 would be located beside
the common chimney for units 6 and 7. High general facility factors were
assigned to both locations. High site access/congestion factors were
assigned to both locations due to the limited space available.
Tables 5.2.1-6 and 5.2.1-7 summarize the estimated retrofit factors arid
costs of retrofitting SCR at the Crist plant.
Furnace Sorbent Injection and Duct Spray Drying--
Sorbent injection technologies (FSI and DSD) were not evaluated for
units 4-5 because the units are equipped with hot side ESPs which are not
feasible to reuse. Units 6-7 have inadequate size ESPs and were not
evaluated for the sorbent injection technologies.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering ^plicability criteria
presented in Section 2 were used to determine the applicability'of these
technologies at the Crist plant. Units 4-5 would be considered good
candidates for repowering or retrofit because of their small boiler sizes
and low capacity factors. Units 6-7 are large and have high capacity
factors and would not be good candidates.
5-25
-------
5.2.2 Lansing Smith Steam Plant ,
Both units are equipped with retrofit hot-side ESPs and were not considered
for LSD or furnace sorbent injection technologies.
TABLE 5.2.2-1. LANSING SMITH STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1
2
GENERATING CAPACITY (MW)
150
190
CAPACITY FACTOR (PERCENT)
73
75
INSTALLATION DATE
1965
1967
FIRING TYPE
TANGENTIAL
FURNACE VOLUME (1000 CU FT)
92
NA
LOW NOx COMBUSTION
NO
NO
COAL SULFUR CONTENT (PERCENT)
2.4
COAL HEATING VALUE (BTU/LB)
12100
COAL ASH CONTENT (PERCENT)
9.4
FLY ASH SYSTEM
WET DISPOSAL
ASH DISPOSAL METHOD
POND/ON-SITE
STACK NUMBER
1
1
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL*
TYPE
ESP
ESP
INSTALLATION DATE
NA
NA
EMISSION (LB/MM BTU)
0.04
0.02
REMOVAL EFFICIENCY
99
99
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
0.5-3.5
0.6-3.5
SURFACE AREA (1000 SQ FT)
303.3
379
EXIT GAS FLOW RATE (1000 ACFM)
1313
1640
SCA (SQ FT/1000 ACFM)
231
231
OUTLET TEMPERATURE (*F)
260
260
* Both units are retrofitted with hot side ESPs.
5-26
-------
TABLE 5,2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR LANSING SMITH
UNITS 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
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
YES ' NA
1348,1667 NA
YES NA
1050,1330 0
NO
NA
NA
NA
NA
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.48
NA
NA
GENERAL FACILITIES (PERCENT) 15
NA
NA
NA
NA
NA
NA
NA
NA
* L/S-FGD and LSD-FGD absorbers for units 1 and 2 would be located
east of the unit 2 retrofit ESPs.
5-27
-------
Table S.2,2-3, Summary of FGD Control Costs for the Lansing Smith Plant (June 1988 Oollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Amual S02 S02 so2 Cost
Nurfcer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
-------
7able 5.2.2-4. Summary of Coat Suit eh irtg/C leaning Coses for the Lansing Smith Plant (Jure 1988 Dollars)
— — — — X— ¦•SS£<«bSSk>»SS» «¦ «¦> wSS•»<•»SSt— SS££•>»»St2>5S2J — SE3B• >SS«Sa *SS»S tfvaS5« oSSSSSSiSS&S ;S2S3C5SB15S55SS;SSS "1III1I3
Technology Boiler Main- Boiler Capacity Coal Capital Capital Annual Annual S02 502 502 Cast
Number Setrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MM) <%) Content (***) (S/lcW> (mills/kwh) <%) (tons/yr) c$/teri5
factor (X)
CS/B+S15
cs/a*$is
CS/8+S15-C
C5/8»$15-C
CS/8*S5
CS/B+S5
CS/B+S5-C
CS/B+S5-C
.00
.00
.00
,00
.00
.00
.00,
.00
150
190
150
190
150
190
150
190
73
75
73
75
73
75
73
75
2.4
2.4
2.4
2.4
2.4
2.4
5.7
6.9
5.7
6.9
4.1
4.9
4.1
4.9
37.9
36.3
37.9
36.3
27.6
25.9
27.6
25.9
14.1
18.0
8.1
10.4
5.9
7.4
3.4
4.3
14.7
14.5
8.4
8.3
6.1
5.9
3.5
3.4
62.0
62.0
62.0
62.0
62.0
62.0
62.0
62.0
11470
14927
11470
1492?
11470
14927
11470
14927
1225.6
1209.1
704.4
694.8
511.1
495.2
294.5
285.2
5-29
-------
TABLE 5.2.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR LANSING SMITH
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
92
NA
BOILER INSTALLATION DATE
1965
1967
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
37
44
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
2513
2885
New Heat Exchanger (1000$)
2377
2739
TOTAL SCOPE ADDER COSTS (1000$)
4926
5668
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
38
38
* Cold side SCR reactors for units 1
east of the unit 2 retrofit ESPs,
and 2 would be located
5-30
-------
Table 5.2,2-6. NOx Control Cost Results for the Lansing Smith Plant (Juris 1988 Dollars)
KaaXa3KSaaX5X=£__S=.-.=SaB===£BBB==SaXXX3„S__=ss==SS=SKSKBSSaKX2BaKaaVX2XBS=Ss=S±saBSS_=ss3S££ssS.=.==£==_=s=S=3
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 iffeet.
Difficulty Content (SMM) (S/kU) («MM> (mi I Is/kwh) {%> (toris/yr) (t/ton)
Factor
LNC-OFA 1 1.00 150 73 2.4 0.? 4.9 ¦ 0.2 ' 0.2 25.0 737 209.1
INC-OfA 2 1.00 190 75 2.4 0.8 4.2 0.2 0.1 25.0 959 176.6
INC-OFA-C 1 1.00 150 73 2.4 0.7 4,9 0.1 0.1 25.0 737 124.1
INC-OFA-C 2 1.00 190 75 2.4 0.8 4.2 0.1 0.1 25.0 959 105.0
SCR-3 1 1.16 150 73 2.4 27.2 181.3 8.8 9.2 80.0 2359 3747.9
SCR-3 2 1.16 190 75 2.4 32.2 169.2 10.7 8.5 80.0 3069 3470.3
SCR-3-C 1 1.16 150 73 2.4 27.2 181.3 5.2 5.4 80.0 2359 2199.0
SCR-3-C 2 1.16 190 75 2.4 32.2 169.2 6.2 5.0 80.0 3069 2035.2
SCR-7 1 1.16 150 73 2.4 27.2 181.3 7.6 7.9 80.0 2359 3225.9
SCR-7 2 1.16 190 75 2.4 32.2 169.2 9.1 7.3 80.0 3069 2962.3
SCR-7-C 1 1.16 150 73 2.4 27.2 181.3 4.5 4.7 80.0 2359 1899.9
SCR-7-C 2 1.16 190 75 2.4 32.2 169.2 5.4 4.3 80.0 3069 1744.2
5-31
-------
5.3 SEMINOLE ELECTRIC COOPERATIVE
5.3.1 Seminole Steam Plant
The Seminole steam plant is located within Putnam County, Florida, as
part of the Seminole Electric Cooperative system. The plant is located west
of the St. Johns River and contains two coal-fired boilers with a total
gross generating capacity of 1,430 MM.
Table 5.3.1-1 presents the operational data for the existing equipment
at the Seminole plant. The boilers burn 2.8 percent sulfur coal. Coal
shipments are received by railroad and transferred to a coal storage and
handling area west of the plant.
PM emissions for the boilers are controlled with ESPs located behind
each unit. The plant has a dry fly ash handling system. Part of the fly
ash and almost all the bottom ash are sold and the rest is disposed of
on-site. Units 1 and 2 are served by separate flues within a common
chimney.
Although both boilers are equipped with new FGD control systems, the
Seminole plant is included in the Top 200 SO,, emitting power plants;
therefore, it was considered in this study. However, additional S02
controls were not considered. Because both units are equipped with LNB,
only SCR was evaluated for this plant.
Selective Catalytic Reduction-
Cold side SCR reactors for both units would be located behind the
common stack downstream of the existing FGD units. Both reactors would be
located in a low site access/congestion area. For flue gas handling, duct
lengths of 200 feet were estimated for units 1-2. The ammonia storage
system would be placed beside the reactors. A storage building and a paved
road would need to be relocated and a factor of 20 percent was assigned to
general facilities. Table 5.3.1-2 presents the SCR retrofit results for all
units. Table 5.3.1-3 presents the estimated cost of retrofitting SCR at the
Seminole boilers.
5-32
-------
TABLE 5.3.1-1. SEMINOLE 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
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)
60, 49
1984-85
OPPOSED WALL
513
NO
2.8
12000
8.7
DRY HANDLING
ON-SITE/SOLD
1, 2 (INSIDE COMMON CHIMNEY)
RAILROAD
YES
SPRAY TOWER
1984, 85
ESP
1984, 85
0.02
99.8
3.0
462.0
2,132
217
300
5-33
-------
TABLE 5.3.1-2, SUMMARY OF NOx RETROFIT RESULTS FOR SEMINOLE
BOILER 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$) 0
Ductwork Demolition (1000$) 118
New Duct Length (Feet) 200
New Duct Costs (1000$) 3132
New Heat Exchanger (1000$) 6067
TOTAL SCOPE ADDER COSTS (1000$) 9318
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
5-34
-------
Table S.3.1-3. NOx Control Cost Results for the Seminole Plant (June 1988 Dollars)'
Technology Boiler Main Boiler Capacity Coal . Capital Capital Annual Annual NOx NOx NOx Cost
Ntmber Retrofit Size Factor Sulfur Cost Cost Coat Cost Removed Removed Effect.
Difficulty (MW) <%> Content (SWO (S/lcU> (»«>
-------
5.4 TAMPA ELECTRIC COMPANY
5.4.1 Bio Bend Steam Plant
The Big Bend steam plant is located at the eastern entrance of
Hillsborough Bay in Hillsborough County, Florida, and is part of the Tampa
Electric Company. It is bounded on the north and south by water channels.
The Big Bend plant contains four coal-fired boilers with a total gross name
plate generating capacity of 1,821 MM.
Table 5.4.1-1 presents operational data for the existing equipment at
the Big Bend plant. Shipments of medium sulfur coal are received by barge
and conveyed to a coal storage and handling area west of the plant, PM
emissions from the boilers are controlled by ESPs installed at the time of
construction and one additional ESP added to unit 1. All ESPs are located
behind the boilers. Flue gas from boilers 1 and 2 is ducted to a common
chimney while the flue gas from boilers 3 and 4 is ducted to a separate
chimney for each boiler. Dry fly ash from the plant is sold. Unit 4 was
built with a forced oxidation limestone FGD system designed to remove 90
percent of the sulfur dioxide compounds from the flue gas. In addition,
unit 4 has LNC controls.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS or LSD-FGD absorbers would be located behind the chimneys for
units 1-3. Because units 1-2 share a chimney, a new chimney would be built
to avoid a prolonged downtime for units 1-2. The silos located behind the
chimneys would not be destroyed. The general facilities factor would be
high (15 percent) due to the necessity for relocation of some storage
buildings and roads. A high site access/congestion factor was assigned to
the FGD absorber locations because of the proximity of the channel. In
addition, there is considerable underground obstruction at the proposed FGD
absorber location {two water discharge structures) and poor soil bearing
capacity which affects the cost of earthwork, foundation design and
construction. For the L/LS-FGD case, approximately 300 feet of ductwork
would be required for units 1-2 and 500 feet for unit 3. A medium site
5-36
-------
TABLE 5,4.1-1. BIG BEND 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
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)
*Given by plant personnel.
1,2 3
445.5 445.5
58,50 50
1970,73 1976
TURBO-FURNACE
222 243
NO YES
2.8 2.0
11400 11850
9.4 8.8
WET/DRY HANDLING
ON-SITE/SOLD
1 2 3
BARGE
NO NO YES
LIMESTONE
1985
ESP
ESP
ESP
1970,73
1976
1985
0.06
0.02
0.01
99.8
99.8
99.8
3.8
3.8
3.2
498,467
458
440/550
1020,1408
1420
2200
488,331
323
400/500
298,301
351
340
4
486
49
1985
TANGENTIAL
383
YES
2.8
10850
9.6
5-37
-------
access/ congestion factor was assigned to flue gas handling because of the
congestion around the boilers.
LSD with reuse of the existing ESPs was not considered although the .
ESPs are large. This is a result of the plant personnel stating that the
ESPs would not be able to handle any increased load. Additionally, access
to the ESPs is difficult, making reuse of the ESPs costly because of
replacement power costs. All units are burning medium sulfur coal;
therefore, LSD with a new baghouse was not considered as an option.
Tables 5.4.1-2 and 5.4.1-3 give a summary of retrofit data and costs
for L/LS-FGD technologies. Because unit 4 is already equipped with an FGD
absorber (meeting 1979 NSPS), S02 control technologies,were not considered
for this unit.
Coal Switching and Physical Coal Cleaning Costs-
Table 5.4.1-4 presents the IAPCS cost results for CS at units 1-3.
These costs do not include boiler or pulverizer operating cost changes or
system modifications that may be necessary to blend coal. Because of the
distance from the plant's coal sources, transportation costs might be $20
per ton. Therefore, in addition to $5 and $15 per ton of fuel price
differential, $20 per ton was also considered. PCC was not evaluated
because this is not a mine mouth plant.
Low NOx Combustion--
Units 1-3 are Riley Stoker turbo-fired wet bottom boilers. Presently,
there is no commercial technology available for reducing N0X through LNC
technologies, however, NGR was considered perhaps applicable for these
boilers. A natural gas pipeline is not available in the surrounding area;
therefore, NGR is not feasible. Unit 4 is already meeting 1979 NSPS and
would not be considered.
Selective Catalytic Reduction--
Cold side SCR reactors would be located behind the chimneys for all
units. As in the FGD case, storage buildings and roads would have to be
relocated to provide room for the reactors and a medium general facilities
value of 20 percent would be assigned to the location. After demolition,
5-38
-------
TABLE 5.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BIG BEND
UNITS 1,2,3
FGD TECHNOLOGY
LIME
L/LS FGD SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL < HIGH NA
FLUE GAS HANDLING MEDIUM
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA
NEW BAGHOUSE NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA
ESTIMATED COST (1000$) NA NA
NEW CHIMNEY (1-2,3) YES, NO NA
ESTIMATED COST (1000$) 6000, 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM (1-2,3) 1.65, 1.60
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA
NEW BAGHOUSE NA NA
GENERAL FACILITIES (PERCENT) 15 0
5-39
-------
Table 5,4.1-3, Summary of FGD Control Costs for the Big Bend Plant (Jurw 1988 Dollars)
lllSISIIflSSSSSSKIIllSlllHBSSflSllHlSll33S33S89SSKS9IISllllllll8BI ¦¦1S1IISI1I1 MWttSttMWlMMMMM ¦¦¦¦¦¦ II1IIIIIBBII1II
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
N inter
Retrofit
Silt
factor
Sulfur
cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW)
(X)
Content
-------
Table 5.4.1-4. Sutmary of Coal Snitching/Claming Costs for the Big Bend Plant (June 1988 Dollars)
:3a3£ss3sas3ss£sssxa3ssa3assfi333as>8asassBSSS8S3aas3:s:ssss3a3aasBa3as3a33Bss3;:aeaasx3aaas333S=5aiBisasa3sss:=3
Technology
Soller
Main
Boiler Capacity Coal
Capital Capital Annual
AnnuaI
¦ 502
S02
S02 Cost
Number
Retrofit
5ize
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Sffect.
Difficulty
Content
(mi IIs/kwh)
(X)
(tons/yr)
(I/tor,)
Factor "
m
CS/B+S15
1
1.00
445
58
2.8
14.0
31.5
32.1
14.2
70.0
37843
848.9
CS/B*S15
2
1,00
445
50
2.8
14.0
31.5
28.1
14.4
70.0
32624
861.8
CS/B+S15
3
1.00
445
50
2.0
14.1
31.7
23.2
14.5
58.0
19282
1462,7
CS/B+S15-C
1
1.00
445
SB
2.a
14.0
31.5
' 18.5
8.2
70.0
37843
488.1
CS/B*S15-C
¦ 2
1.00
445
50
2.8
14.0
31.5
16.2
8.3
70.0
32624
495.7
C5/B+S15-C
3
1.00
445
50
2.0
14.1
31.7
16.2
8.3
58.0
19282
841.3
CS/3*$20
1
1.00
445
58
2.8
16.3
36.7
41.9
18.5
70.0
37843
1106.4
CS/B+S2Q
2
1.00
445
50
2.8
16.3
36.7
36.6
18.8
70.0
32624
1120.9
CS/B+J20
3
1.00
445
50
2.0
16.4
36.9
36.7
18.8
58.0
19282
1901.1
CS/B+S20-C
1
1.00
445
58
2.8
16.3
36.7
24.1
10.6
70.0
37843
635.8
CS/B+S20-C
2
1.00
445
50
2.8
16.3
36.7
21.0
10.8
70.0
32624
644.5
CS/B+I20-C
3
1.00
445
50
2.0
16.4
36.9
21.1
10.8
58.0
19282
1093.0
CS/8+15
1
1.00
445
58
2.8
9.4
21.2
12.6
5.6
70.0
37843
334.1
CS/B+S5
2
1.00
445
50
2.8
9.4
21.2
11.2
5.8
70.0
32624
343.6
CS/B*$5
3 , >
1.00
445
50
2.0
9.5
21.3
11.3
5.8
58.0
19282
585.9
CS/B+S5-C
1
1.00
445
58
2.8
9.4
21.2
7.3
3.2
70.0
37843
192.5
CS/B*$5-C
2
1.00
445
50
2.8
9.4
21.2
6.5
3.3
70.0
32624
198.1
CS/B+S5-C
3
1.00
445
50
2.0
9.5
21.3
6.5
3.3
58.0
19282
337.9
8sssa88s&a8ansss8ss8sssssssssas=a:393saBaass8saasE=s=sssaxsaiaanstis>asa3SS=:8as==a383s=s3xeasss«assss:3sss»3
5-41
-------
the SCR reactors would be located in an area with significant underground
obstructions and, as such, a medium site access/congestion factor was
assigned to the SCR reactor locations. About 350 feet of ductwork would be
required for units 1-2, 500 feet for unit 3, and 250 feet for unit 4.
Tables 5.4.1-5 and 5.4.1-6 present the retrofit factor and cost estimates
for retrofitting SCR at the Big Bend plant.
Furnace Sorbent Injection and Duct Spray Drying--
Sorbent injection technologies were not considered for the Big Bend
plant because of the short duct residence time between the boilers and the
ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi1ity--
None of the boilers would be considered good candidates for repowering
because of their large size and short service life.
5.4.2 F. J. Gannon Steam Plant
The F. 0. Gannon steam plant is located on Hillsborough Bay in
Hillsborough County, Florida, and is part of the Tampa Electric Company.
The plant contains six coal-fired boilers with a total gross generating
capacity of 1,271 MM.
Table 5.4.2-1 presents operational data for the existing equipment at
the Gannon plant. Coal shipments are received by barge and rail and
conveyed to a coal storage and handling area west of the plant. The south
side of the Gannon plant abuts a county road alongside property belonging to
a phosphate manufacturing plant. A railroad line runs on the property. PM
emissions from the boilers are controlled by ESPs. Boilers 1-3 and 5-6 each
have a separate stack. Boiler 4 has two chimneys. The ESPs were installed
behind their respective stacks. The Gannon plant has a dry fly ash handling
system.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS or LSD-FGD absorbers for units 1 and 2 would be located behind the
unit 1 and 2 ESPs and the unit 3-6 absorbers would be located at the east
5-42
-------
TABLE 5,4.1-5, SUMMARY OF NOx RETROFIT RESULTS FOR BIG BEND
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
4
FIRING TYPE
TURBO-FURNACE
TANG
TYPE OF NOx CONTROL
NA
NA
NA
FURNACE VOLUME (1000 CU FT)
222
243
383
BOILER INSTALLATION DATE
1970,73
1976
1985
SLAGGING PROBLEM
YES
YES
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
NA
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$)
83
83
88
New Duct Length (Feet)
350
500
250
New Duct Costs (1000$)
5250
7500
3124
New Heat Exchanger (1000$)
4571
4571
4813
TOTAL SCOPE ADDER COSTS (1000$)
9904
12154
8025
RETROFIT FACTOR FOR SCR
1.34
1.34
1.34
GENERAL FACILITIES (PERCENT)
20
20
20
5-43
-------
Table 5
.4.1-6.
NOk Control Cost Results for the Big Bend Plant CJine 1988 Dollars)
3X33S32S32SS
sssssssssssssssasj
;SSSS3SS3S53SaS32=a=5S3S222333a5
33SSS3SS
II
II
II
II
!!
H
II
II
II
II
II
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II
II
If
1!
II
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II
II
It
Technology
Soiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NO*
M0x
NOx Cost
Nimber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW)
(X)
Content
(SWO
es/kvj
(SHH)
(mi Us/kwh)
m
(tons/yr>
CS/ton)
factor
(X)
SCR-3
1
1.34
445
58
2.8
64.0
143.9
22.7
10.0
80.0
13493
1683.2
SCR-3
2
1.34
445
50
2.8
64.5
145.0
22.5
11.5
80.0
11632
1934.7
SCR-S
3
1.34
445
50
2.0
66.8
150.0
22.2
11.4
80.0
5132
4321.3
SCt-3
4
1.34
486
49
2.8
67.2
138.2
23.9
11.5
80.0
12449
1920.9
SGR-3-C
1
1.34
445
58
2.8
64.0
143.9
13.3
5.9
80.0
13493
985.7
SCR-3-C
2
1.34
445
50
2.8
64.5
145.0
13.2
6.8
80.0
11632
1133.3
SCR-3-C
3
1.34
445
50
2.0
66.8
150.0
13.0
6.7
80.0
5132
2534.1
SCR-3-C
4
1.34
426
49
2.8
67.2
138.2
14.0
6.7
80.0
12449
1124.7
SCR-7
1
1.34
445
58
2.8
64.0
143.9
19.0
8.4
80.0
13493
1410.2
scr-7
2
1.34
as
50
2.8
64.5
'145.0
18.8
9.7
80.0
11632
1618.0
scr-7
5
1.34
445
50
2.0
66.8
150.0
18.5
9.5
80.0
5132
3603.3
SCR-7
4
1.34
486
49
2.8
67.2
138.2
19.9
9.1
80.0
12449
1597.7
SCR-7-C
1
1.34
445
58
2.8
64.0
143.9
11.2
4.9
80.0
13493
829.2
SCR-7-C
2
1.34
445
50
2.8
64.5
145.0
11.1
5.7
80.0
11632
951.9
SCR-7-C
3
1.34
445
50
2.0
66.8
150.0
10.9
5.6
80.0
5132
2122.7
SCR-7-C
4
1-34
m
49
2.8
67.2
138.2
11.7
5.6
80.0
12449
939.5
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5-44
-------
TABLE 5.4.2-1. F. J. GANNON 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
125
180
188
239
414
37,35
44
44
59
46
1957
1960
1963
1965
1967
CYCLONE
! BOILER
TURBO-
FURNACE
NA
66.6
NA
129.1
219.4
NO
NO
NO'
NO
NO
1.1
1.1
1.1
1.1
1.1
12500
12500
12500
12500
12500
7.3
7.3
7.3
7.3
7.3
DRY HANDLING
ON-SITE/SOLD
1,2 3 4 I
BARGE/RAIL
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
ESP
ESP
1985
1984
1983
1973
1973
0.04
0.02
0.01
0.05
0.03
99.1
99.1
99.1
99.8
99.8
1.25
1.25
1.25
2.8
2.8
603
600
596
440
327
440
574
631
820
1350
265
345
376
361
442
300
300
300
290
290
5-45
-------
end of unit 5. The general facilities factor is low (5 percent) for the
unit 1 and 2 locations. However, the general facilities factor is very high
(15 percent) for the units 3-6 absorber locations because of the necessity
for relocating the water treatment facility. An additional 30 percent has
been added to the retrofit factor for installation of FGD technologies to
account for the extraordinary cost of relocating the water treatment
facility. The site access/congestion factor is high for the units 1 and 2
FGD absorber locations because of the proximity of the railroad tracks,
roadways, ash handling silos, wastewater facilities, and property line. The
site access/congestion factor is high for the units 3-6 absorber locations
because of the high congestion and underground obstructions beneath the
water treatment facility site.
More than 300 feet of ductwork would be required for the installation
of wet FGD absorbers for units 1 and 2. Approximately 300 feet of ductwork
would be required for unit 6, 700 feet for unit 5, and greater than
1,000 feet for units 3 and 4. To reduce the duct lengths, a new chimney
would be constructed behind the absorbers for units 3 and 4 and, as such,
about 600 to 800 feet of duct length would be required. The flue gas
handling site access/congestion factor is high for all of the units because
of the close proximity of the ESPs and boilers to the chimneys and property
line. It might not be possible to retrofit all the units with FGD systems
because of this space limitation.
Because of the adequate sizes of the ESPs, LSD with reuse of the
existing ESPs was considered for all of the units. The LSD absorbers would
be located similarly to the wet FGD absorbers and were assigned the same
general facilities percentages and site access/congestion factors. The
ductwork for units 3,4,5, and 6 would be long in the LSD-FGD case.
Tables 5.4.2-2 through 5.4.2-5 give a summary of retrofit data for the
FGD technologies. Table 5.4.2-6 presents the FGD costs.
Coal Switching and Physical Coal Cleaning Costs--
CS was not considered for units 1-4 because they are cyclone boilers
requiring low sulfur bituminous coals having low ash fusion temperatures
which are not readily available in the east. Plant personnel indicated that
some degree of fuel switching is possible on these units with fluxing to
5-46
-------
TABLE 5.4.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR F. J. GANNON
UNITS 1 OR 2
FGD TECHNOLOGY
LIME
L/LS FGD SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH
FLUE GAS HANDLING HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA HIGH
NEW BAGHOUSE NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NO
ESTIMATED COST (1000$) NA NA
NEW CHIMNEY YES NO
ESTIMATED COST (1000$) 6000 0
OTHER YES YES
RETROFIT FACTORS
FGD SYSTEM 1.80
ESP REUSE CASE 1.72
BAGHOUSE CASE NA
ESP UPGRADE NA 1.58
NEW BAGHOUSE NA NA
GENERAL FACILITIES (PERCENT) 5 5
5-47
-------
TABLE 5.4.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR F. J. GANNON
UNITS 3 OR 4
FGD TECHNOLOGY
LIME
L/LS FGD SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL
HIGH
HIGH
FLUE GAS HANDLING
HIGH
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
600-1000
ESP REUSE
1000+
BAGHOUSE
NA
ESP REUSE
NA
HIGH
NEW BAGHOUSE
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
ESTIMATED COST (1000$)
NA
NA
NEW CHIMNEY
YES
NO
ESTIMATED COST (1000$)
6000
0
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.91
ESP REUSE CASE
2.26
BAGHOUSE CASE
NA
ESP UPGRADE
NA
1.58
NEW BAGHOUSE
NA
NA
GENERAL FACILITIES (PERCENT)
15
15
5-48
-------
TABLE 5.4.2-4. SUMMARY OF RETROFIT FACTOR DATA FOR F. J. GANNON
UNIT 5
FGD TECHNOLOGY
LIME
L/LS FGD SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
HIGH
FLUE GAS HANDLING
HIGH
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
600-1000
ESP REUSE
1000+
BAGHOUSE
NA
ESP REUSE
NA
HIGH
NEW BAGHOUSE
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
ESTIMATED COST (1000$)
NA
NA
NEW CHIMNEY
YES
NO
ESTIMATED COST (1000$)
6000
0
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.91
ESP REUSE CASE
2.06
BAGHOUSE CASE
NA ,
ESP UPGRADE
NA
1.58
NEW BAGHOUSE
NA
NA
GENERAL FACILITIES (PERCENT)
15
15
5-49
-------
TABLE 5.4.2-5. SUMMARY OF RETROFIT FACTOR DATA FOR F. J. GANNON
UNIT 6
FGD TECHNOLOGY
LIME
L/LS FGD SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
HIGH
FLUE GAS HANDLING.
HIGH
ESP REUSE CASE
,
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
HIGH
NEW BAGHOUSE
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
ESTIMATED COST (1000$)
NA
NA
NEW CHIMNEY
YES
NO
ESTIMATED COST (1000$)
6000
0
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.80
ESP REUSE CASE
1.86
BAGHOUSE CASE
NA
ESP UPGRADE
NA
1.58
NEW BAGHOUSE
NA
NA
GENERAL FACILITIES (PERCENT)
15
15
5-50
-------
Table 5.4.2-6. Sumary of FGD Control Costs for the Gannon Plant (Jivve 1988 Dollars)
ajgssjgisscsgssssSSSSSSSSSSSSSaS S5SS9S3SSS333SSSSSSS833S SSSS3H3S9S9SSSS!9S>8SBSS83S3I93SSS3I3393S3SSSBS3SSSS 53SS333333533Z33SS5
Technology ' Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 S02 Cost
Number
Retrofit
Size'
Factor
Sulfur
Coat
Cost
Cast
Cost
Removed Removed
Effect.
Difficulty (MW)
(%)
Content
(tons/yr>
(S/ton)
Factor
(%)
l/S FGD
t, 2
1.80
125
37
55.0
440.1
20.3
50.2
90.0
3088
6586.8
L/S FGD
3
1.91
180
44
1.1
76.4
424.5
28.4
40.9
90.0
52S8
1364.9
L/S FGD
4
1.91
188
44
78.0
414.9
29.0
40.0
90.0
5523
5251.8
l/S FGO
5
1.91
239
59
1.1
88.9
371.8
34.9
28.3
90.0
9414
3707.0
L/S FGO
6
1.80
414
46
116.9
282.3
45.1
27.0
90.0
12714
3544.1
L/S FGO
1-2
1.80
250
36
83.8
335.2
30.9
39.1
90.0
6009
5134.3
L/S FGD
3-6
1.86
1021
48
1.1
240.0
235.1
94.1
21.9
90.0
32719
2877.4
L/S FGD-C
1, 2
1.80
125
37
55.0
440.1
11.9
29,4
90.0
3088
3853.7
L/S FGO-C
3
1.91
180
44
1.1
76; 4
424.5
16.6
23.9
90.0
5288
3138.5
L/S FGO-C
4
1.91
188
44
1.1
78.0
414.9
17.0
23.4
90.0
5523
3072.3
L/S FGD-C
5
1.91
239
59
1.1
88.9
371.8
20.4
16.5
90.0
9414
2166.2
L/S FGO-C
6
1.80
414
46
116.9
282.3
26.3
15.8
90.0
12714
2071.7
L/S FGD-C
1-2
1.80
250
36
83.8
335.2
18.1
22.9
90.0
6009
3004.2
L/S FGO-C
3-6
1.86
1021
48
240.0
235.1
55.0
12.8
90.0
32719
1681.4
LC FGO
1-6
1.85
1271
46
1.1
225.0
177.0
92,9
18.1
90.0
39034
2379.1
LC. FGD-C
1-6
1.85
1271
46
1.1
225.0
177.0
54.2
10.6
90.0
39034
1388.9
LSD+ESP
1, 2
1.72
125
37
1.1
21.1
168.4
8.5
20.9
76.0
2618
3235.5
LSD-»ESP
3
2.26
180
44
1.1
35.4
196.6
12.9
18.5
76.0
4483
2870.0
LSD+ESP
4
2.26
188
44
1.1
36.4
193.6
13.2
18.2
76.0
4682
2817.4
LSD+ESP
5
2.06
239
59
1.1
44.5
186.1
16.6
13.4
76.0
7981
2073.8
LSD+ESP
6
1-86
414
46
1.1
62.4
150,8
22.3
13.4
76.0
10779
2067.9
LSD+ESP-C
1. 2
1.72
125
37
1.1
21.1
168.4
4.9
12.2
76.0
2618
1889.8
LSD'ESP-C
3
2.26
180
44
1.1
35.4
196.6
7.5
10.9
76.0
4483
1679.7
LSD+ESP-C
4
2.26
188
44
1.1
36.4
193.6
7.7
10.7
76.0
4682
1649.0
LSO*ESP-C
5
2.06
239
59
'.1.1
44.5
186.1
9.7
7.8
76.0
7981
1213.2
LSO+ESP-C
6
1.86
414
46
1.1
62.4
150.8
13.1
7.8
76.0
10779
1210.7
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ss=a===:
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II
II
II
II
II
tl
susssssssas:
SSS3H33S3I
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II
II
II
II
II
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II
II
11
II
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II
II
II
II
II
II
II
II
II
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II
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5-51
-------
lower ash fusion temperatures. However, this was beyond the scope of this
work and was not considered. Costs were developed for units 5 and 6 and are
presented in Table 5.4.2-7, PCC was not evaluated because this is not a
mine mouth plant.
Low NO Combustion--
A
The combustion modification technique applicable to the boilers at the
Gannon plant would be N6R; however, a natural gas pipeline is not available
in the surrounding area; therefore, NGR application would not be feasible.
Selective Catalytic Reduction--
For units 1-5, cold side SCR reactors would be located south of the
unit ESFs and for unit 6 east of its ESPs. The general facilities factor is
low for this location. However, the site access/congestion factor is high
because of the proximity of the railroad track and property boundary. About
250 feet of ductwork would be required for units 1 and 2, 300 feet for
unit 3, 500 feet for unit 4, 600 feet for unit 5, and 700 feet for unit 6.
Tables 5.4.2-8 through 5.4.2-10 present retrofit factor and cost estimates
for retrofitting SCR at the Gannon plant.
Furnace Sorbent Injection and Duct Spray Drying--
Sorbent injection technologies (FSI and DSD) were considered for the
Gannon plant because of the large size ESPs. The front section of the
existing ESPs could be modified for sorbent injection or humidification.
Tables 5.4.2-11 and 5.4.2-12 give a summary of retrofit factors for FSI and
DSD technologies at the Gannon plant. Table 5.4.2-13 presents the costs for
FSI and DSD.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 1-5 would be considered good candidates for repowering or
retrofit because of the small boiler size and likely short remaining life.
However, the high capacity factors could result in high replacement power
costs for extended, downtime. Unit 6 is large and would not be considered
for repowering.
5-52
-------
TabE* 5.4.2-7, Surma ry of Coal Switching/Cleaning Costs for the Cannon Plant (June 1938 Dollars)
Technology Bolter Main Boiler Capacity Coal Capital Capital Annual Annual S02 SQ2 SQ2 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NU)
-------
TABLE 5.4.2-8. SUMMARY OF NOx RETROFIT RESULTS FOR F. J. GANNON UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
CYC
CYC
CYC
TYPE OF NOx CONTROL
NA
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
66.6
BOILER INSTALLATION DATE
1957
1958
1960
SLAGGING PROBLEM
NA
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
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 (1000$)
32
32
42
New Duct Length (Feet)
250
250
300
New Duct Costs (1000$)
3750
3750
4500
New Heat Exchanger (1000$)
2131
2131
2652
TOTAL SCOPE ADDER COSTS (1000$)
5913
5913
7194
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
13
13
13
5-54
-------
TABLE 1.4.2-9. SUMMARY OF NOx RETROFIT RESULTS FOR F. J. GANNON UNITS 4-6
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
6
FIRING TYPE
CYC
TURSO-
FURNACE
TYPE OF NOx CONTROL
NA
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
129.1
219.4
BOILER INSTALLATION DATE
1963
1965
1967
SLAGGING PROBLEM
NA
YES
YES
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
o
0
Ductwork Demolition (1000$)
43
52
78
New Duct Length (Feet)
500
600
700
New Duct Costs (1000$)
7500
9000
10500
New Heat Exchanger (1000$)
2722
3144
4371
TOTAL SCOPE ADDER COSTS (1000$)
10266
12196
14950
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
13
13
13
5-55
-------
Table 5.4.2-10, MO* Control Cost Results for the Cannon Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MQx NOx NOx Cost
Nuifcer
Retrofit
Size
Factor Sulfur
Coat
Cost
Cost
Cost
Removed Removed
Iffact.
Difficulty (My)
IX)
Content
(SMN)
(f/ky>
(SMN)
(mi 1li/kuh)
(X)
(tons/yr)
<$/ton>
.........
..........
„ „ ,
Factor
......
.......
(%>
._•••....
........
............
......
...........
........
SCR-3
1,
2
1.52
125
37
1.1
27.9
223.3
8.4
20.8
80.0
2367
3561.1
SCR-3
3
1.52
180
44
1.1
35.8
198.8
11.2
16.1
80.0
4054
2719.8
SCR-3
4
1.52
188
44
1.1
40.0
212.7
12.1
16.7
80.0
4234
2862.1
SCR-3
5
1.52
239
59
1.1
48.0
200.7
15.0
12.1
80.0
6632
2255.9
SCR-3
6
1.52
414
46
1.1
69.2
167.2
22.4
13.5
80.0
8957
2506.4
SCR-3-C
1,
2
1.52
125
37
1.1
27.9
223.3
5.0
12.2
80.0
2367
2093.2
SCR-3-C
3
1.52
180
44
1.1
35.8
198.8
6.6
9.5
80.0
4054
1620.7
SCR-3-C
4
¦ 1.52
188
44
1.1
40.0
212.7
7.1
9.8
80.0
4234
1682.1
SCR-3-C •
5
1.52
,239
59
1.1
48.0
200.7
8.8
7.1
80.0
6632
1324.9
SCR-3-C
6
1.52
414
46
1.1
69.2
167.2
13.2
7.9
80.0
8957
1470.7
SCR -7
1,
2
1.52
125
37
1.1
27.9
223.3
7.4
18.3
80.0
2367
3129.9
SCR-7
3
1.52
180
44
1.1
35.8
198.8"
9.7
14.0
80.0
4054
2397.1
SCR-7
4
1.52
188
44
1.1
40.0
212.7
10.6
14.6
80.0
4234
2499.4
SCR-7
5
1.52
239
59
1.1
48.0
200.7
13.0
10.3
80.0
6632
1961.6
SCR-7
6
1.52
414
46
1.1
69.2
167.2
19.1
11.4
80.0
8957
2128.9
SCR-7-C
1,
2
1.52
125
37
1.1
27.9
223.3
4.4
10.8
80.0
2367
1846.1
SCR-7-C
3
1.52
180
44
1.1
35.8
198.8
5.7
8.3
80.0
4054
1412.9
SCR-7-C
4
1.52
188
44
1.1
40.0
212.7
6.2
8.6
80.0
4234
1474.3
SCR-7-C
5
1.52
239
59
1.1
48.0
200.7
7.7
6.2
80.0
6632
1156.3
SCR-7-C
6
1.52
414
46
1.1
69.2
167.2
11.2
6.7
80.0
8957
1254.4
II
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5-56
-------
TABLE 5.4.2-11, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR F. J. GANNON UNITS 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 NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 35
TOTAL COST (1000$)
ESP UPGRADE CASE 35
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
5-57
-------
TABLE 5.4.2-12. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR F. J. GANNON UNITS 3,4,5,OR 6
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$) 46, 46, 57, 87
TOTAL COST (1000$)
ESP UPGRADE CASE 46, 46, 57, 87
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
5-58
-------
Table 5.4.2-13. Surinary of DSO/FSI Control Costs for the Gannon Plant (June 1988 Dollars)
________-as==
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
' S02
$02 Cost
Hunter Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
(milU/kutO
<%>
(tora/yr)
tt/ton)
Factor
(X)
DSD+ESP
1, 2
1.00
125
3?
1.1
5.5
44.2
4.2
10.3
49.0
1669
2490.3
DSO+ESP
3
1.00
ISO
44
1.1
6.3
35.1
4.8
6.9
49.0
2858
1674.5
OSD+ESP
4
1.0)
188
44
1.1
6.5
34.3
4.9
6.7
49.0
2985
1630.2
DSO+ESP
1
1.00
239
59
1.1
8.6
36.0
6.5
5.2
49.0
5089
1267.6
DSD+ESP
6
1.00
414
46
1.1
11.9
28.7
8.0
4.8
49.0
6873
1171.1
DSO+ESP-C
1, 2
1.00
125
37
1.1
5.5
44.2
2.4
5.9
49.0
1669
1441.6
DSO+ESP-C
3
1.00
iao
44
1.1
6.3
35.1
2.8
4.0
49.0
2858
969.3
DSO+ESP-C
4
1.00
188
44
1.1
6.5
34.3
2.8
3.9
49.0
2985
943.7
OSD+ESP-C
5
1.00
239
59
1.1
B.6
36.0
3.7
3.0
49.0
5089
733.8
DSO+ESP-C
6
1.00
414
46
1.1
11.9
28.7
4.7
2.8
49.0
6873
678.7
FSl+ESP-50
1, 2
1.00
125
37
1.1
8.3
66.3
4.2
10.4
50.0
1715
2452.6
FSI+ESP-50
3
1.00
180
44
1.1
B.7
48.1
5.0
7.3
50.0
2938
1718.1
FSI+ESP-50
4
1.00
188
44
1.1
8.7
46.2
5.1
7.1
50.0
3068
1673.2
FSI+ESP-50
5
.1.00
239
59
1.1
9.8
40.8
6.B
5.5
50.0
5230
1291.1
FSI+ESP-50
6
1.00
414
46
1.1
13.4
32.3
8.8
5.3
50.0
7063
1244.8
FSI+ESP-50-C
1, 2
1.00
125
37
1.1
8.3
66.3
2.4
6.0
50.0
1715
1426.8
FS1+ESP-50-C
3
1.00
180
44
1.1
8.7
48.1
2.9
4.2
50.0
2938
997.6
FS1+ESP-50-C
4
1.00
18S
44
1.1
8.7
46.2
3.0
4.1
50.0
3068
971.3
FSI+iSP-SO-C
5
1.00
239
59
1.1
9.8
40.8
3.9
3.2.
50.0
5220
748.1
FSI+ESP-50-C
6
1.00
414
46
1.1
13.4
32.3
5.1
3.1',
50.0
7063
721.7
FSI+ESP-70
1. 2
1.00
12S
37
1.1
8.4
67.2
4.3
10.5
70.0
2402
1772.8
FSI+ESP-70-
3
1.00
180
44
1.1
8.8
48.8
5.1
7.4
70.0
4113
1244.9
FSI+ESP-70
4
1.00
188
44
1.1
8.8
47.0
5.2
7.2
70.0
4295
1214.0
FSt+£$P-70
5
1.00
239
59
1.1
9.9
41.5
6.9
5.6
70.0
7322
937.6
FSI+£SP-70
6
1.00
414
46
1.1
13.6
32.8
8.9
5.4
70.0
9889
904.3
FSI+ESP-70-C
1. 2
1.00
125
37
1.1
8.4
67.2
2.5
6.1
70.0
2402
1031.4
FSI+E5P-70-C
3
1.00
180
44
1.1
8.8
48.8
3.0
4.3
70.0
4113
722.8
FSI-SSP-70-C
4
1.00
188
44
1.1
8.3
47.0
3.0
4.2
70.0
4295
704.8
FSI+ESP-70-C
5
1.00
239
59
1.1
9,9
41.5
4.0
3.2
70.0
7322
543.3
FSJ+ESP-70-C
6
1.00
414
46
1.1
13.6
32.8
5.2
3.1
70.0
9889
524.3
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5-59
-------
SECTION 6.0 GEORGIA
6.1 GEORGIA POWER COMPANY
6.1.1 P. S. Arkwriqht Steam Plant
The P. S. Arkwright steam plant is located within Bibb County, Georgia,
as part of the Georgia Power Company system. The plant is located just
north of the city of Macon along the Ocmulgee River and contains four
coal-fired boilers with a total gross generating capacity of 160 MW.
Table 6.1.1-1 presents operational data for the existing equipment at
the Arkwright plant. The boilers burn medium sulfur coal. Coal shipments
are received by railroad and transferred to the coal storage and handling
area which is north of the boilers between the river and the railroad
tracks.
PM emissions for the boilers are controlled with retrofit ESPs located
behind each unit. The fly ash is wet sluiced to an on-site ash pond located
one-half mile west of the plant. Units 1-4 are served by a common chimney
located behind the retrofit ESPs and situated between units 2 and 3.
Lime/Limestone and Lime Spray Drying FGD Costs--
The four boilers are located beside each other, parallel to the river,
with the switchyard being located between the boilers and the river. The
absorbers for units 1-4 would be located in an open area directly behind the
chimney which is between the ESPs and the railroad tracks with the coal pile
lying to the north. The limestone preparation, storage and handling area
would be south of the coal pile, adjacent to the water treatment area, and
next to the railroad tracks so that the limestone can be unloaded into the
area. No major demolition or relocation of equipment or buildings would be
necessary; hence, a base factor of 5 percent was assigned to general
facilitles.
A low site access/congestion factor was assigned to the FGD absorber
locations. For flue gas handling, short duct runs of less than 300 feet
would be required for the L/LS-FGO case because the absorbers would be
6-1
-------
TABLE 6.1.1-1. P.S. ARKWRIGHT 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
40
53,70
1941, 1942
TANGENTIAL
NA
NO
1.9
12,700
9 8
WET DISPOSAL
ON-SITE
1
RAILROAD
3, 4
40
67,62
1943, 1948
FRONT WALL
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
1978
0.02
85.0
2.0
39.3
180
222
400
6-2
-------
placed Immediately behind the chimney. The existing chimney can be accessed
easily; therefore, a low site access/congestion factor was assigned to the
flue gas handling system.
LSD with reuse of the existing ESPs was considered for all units at the
Arkwright plant. The ESPs are small (SCA=222); however, sufficient room
exists behind the units for upgrading with additional plate area. For the
flue gas handling systems, a moderate duct length of 500 feet was required
for these units. Although there is plenty of open area for the absorbers,
access to the ESPs is difficult due to the close proximity of the ESPs to
each other. For this reason, a medium site access/congestion factor was
assigned to the flue gas handling system. A medium access/congestion factor
was assigned for upgrades to the existing ESPs.
The major scope adjustment costs and retrofit factors estimated for the
F6D technologies are presented in Table 6.1.1-2. Table 6.1.1-3 presents the
capital and operating costs for commercial FGD technologies. The.low cost
option reduces costs due to economies of scale and elimination of a spare
absorber modules.
Coal Switching and Physical Coal Cleaning Costs-
Table 6.1.1-4 presents the IAPCS results for CS at the Arkwright 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-
Units 1-2 are tangential-fired boilers rated at 40 MW each, while
units 3-4, also rated at 40 MW, are front wall-fired. The combustion
modification technique applied to boilers 1 and 2 was OFA, and to units 3
and 4 was LNB.
Tables 6.1.1-5 and 6.1.1-6 present the N0X performance and cost results
of retrofitting OFA and LNB at the Arkwright plant. Although furnace
volumes were not available for any of the boilers, values were estimated
based on boiler size and age.
6-3
-------
TABLE 6.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR P.S. ARKWRIGHT
UNITS 1-4 (EACH)
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) 100-300 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 412 NA 412
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE 1.38
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5
6-4
-------
Table 6.1.1-3. Swinery of FGD Control Costs for the Arkwright Plant (Jute 19BB Dollars)
II
II
II
II
II
II
II
II
II
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
502 Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (NWS
m
Content
(SWO
(1/m
(SW)
(im'lls/kwh)
<%>
(tons/yr)
(S/ton)
Factor
(X)
L/S FGD
1
1.27
40
53
1.9
24.3
607.1
10.1
54.4
90.0
2401
4210.7
L/S FGD
2
1.27
40
70
1.9
24.3
607.4
10.6
43.2
90.0
3171
3344.1
L/S FGD
3
1.27
40
67
1.9
24.3
607.3
10.5
44.8
90.0
3035
3465.6
L/S FGD
4
1.27
40
62
1.9
24.3
607.2
10.4
47.7
90.0
2808
3693.7
L/S FGD
1-4
1.27
160
63
1.9
48.1
300.5
21.1
23.8
90.0
11414
1844.7
L/S FGD-C
1
1.27
40
53
1.9
24.3
607.1
5.9
31.8
90.0
2401
2457.8
L/S FGO-C
2
1.27
40
70
1.9
24.3
607.4
6.2
25.2
90.0
3171
1950.3
L/S FGO-C
3
1.27
40
67
1.9
24.3
607.3
6.1
26.1-
90.0
3035
2021.5
L/S FGD-C
4
1.27
40
62
1.9
24.3
607.2
6.1
27.9
90.0
2808
2155.0
L/S FGO-C
1-4
1.27
160
63
1.9
48.1
300.5
12.3
13.9
90.0
11414
1075.8
LC FGD
1-4
1.27
160
63
1.9
33.2
207.3
16.5
18.7
90.0
11414
1447,5
LC FGD-C
1-4
1.27
160
63
1.9
33.2
207.3
9.6
10.9
90.0
11414
842.4
LSO+ESP
1
1.32
40
53
1.9
10.1
252.9
5.4
29.2
76. Q
2035
2662.9
LSO+ESP
2
1.3a
40
70
1.9
10.1
252.9
5.6
22.9
76.0
2688
2087.4
LSl+ESP
3
1.38
40
67
1.9
10.1
252.9
5.6
23.8
76.0
2573
2167.6
LS0»ESP
4
1.38
40
62
1.9
10.1
252.9
5.5
25.4
76.0
2381
2318.8
LSD+ESP-C
1
' 1.38
40
53
1.9
10.1
252.9
3.2
17.0
76.0
2035
1548.0
LSD+ESP-C
2
1.38
40
70
1.9
10.1
252.9
3.3
13.3
76.0
2688
1212.8
ISD+ESP-C
3
1.38
40
67
1.9
10.1
252.9
3.2
13.8
76.0
2573
1259.5
LSO+ESP-C
4
1.38
40 '
62
1.9
10.1
252.9
3.2
14.8
76.0
2381
1347.6
6-5
-------
Table 6.1.1-4. Sumvary of Coal Switchins/Cteaning Costs for the Arkwright Plant , CJurie 1988 Dollars)
II
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Technology
Boiler
Main
Bailer Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nuitoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removec
Removed
iffect.
Difficulty (HW)
(%)
Content
cswo
(S/ku>
(WOO
(mills/kwh)
m
CS/ton)
Factor
(X)
........
........
a ... a.*
_______
________
CS/3+S15
1
1.00
40
53
1.9
2.4
59.5
3.3
17.7
50.0
1326
2478.2
CS/B+S15
2
1.00
40
70
1.9
2.4
59.5
4.2
16.9
50.0
1752
2371.7
CS/8*$15
3
1.00
40
67
1.9
2.4
59.5
4.0
17.0
50.0
1677
2386.6
CS/B+S15
4
1.00
40
62
1.9
2.4
59.5
3.7
17.2
50.0
1552
2414.4
CS/8+S15-C
1
1.00
40
S3 .
1.9
2.4
59.5
1.9
10.2
50.0
1326
1428.0
CS/S+S15-C
2
1.00
40
70
1.9
2.4
59.5
2.4
9.7
50.0
1752
1364.9
CS/S+S15-C
3
1,00
40
67
1.9
2.4
59.5
¦ 2.3
9.8
50.0
1677
1373.1
CS/B*$15-C
4
1.00
40
62
1.9
2.4
59.5
2.2
9.9
50.0
1552
1390.3
CS/B+SS
1
1.00
40
53
1.9
2.0
49.1
1.7
9.0
50.0
1326
1267.1
CS/B+S5
2
1.00
40
70
1.9
2.0
49.1
2.1
8.4
50.0
1752
1173.7
CS/8+S5
3
1.00
40
67
1.9
2.0
49.1
2.0
8.5
50.0
. 1677
1186.8
CS/B+S5
4
1.00
40
62
1.9
2.0
49.1
1.9
8.7
50.0
1552
1211.2
CS/B+S5-C
1
1,00
40
53
1.9
2.0
49.1
1.0
5.2
50.0
1326
732.6
CS/B*S5-C '
2
1.00
40
70
1.9
2.0
49.1
1.2
4.8
50.0
1752
677.5
CS/B*S5-C
. 3 !
1.00
40
67
1.9
2.0
49.1
1.1
4.9
50.0
1677
685.3
CS/B+S5-C
4
1.00
40
62
1.9
2.0
49.1
1.1
5.0
50.0
1552
699.6
5S5SS8SSS
11
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II
II
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II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
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SSS3CSS Si 35 325
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II
II
II
II
II
II
II
6-6
-------
TABLE 6,1,1-5, SUMMARY OF NOx RETROFIT RESULTS FOR P.S. ARKWRIGHT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
3, 4
1-4
FIRING TYPE
TANG
FWF
NA
TYPE OF NOx CONTROL
OFA
LNB
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
NA
BOILER INSTALLATION DATE
1941,42
1943,48
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
40
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000S)
14
14
38
New Duct Length (Feet)
ZOO
200
200
New Duct Costs (1000$)
580
580
1305
New Heat Exchanger (1000$)
1076
1076
2471
TOTAL SCOPE ADDER COSTS (1000$)
1669
1669
3814
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
6-7
-------
Table 6,1.1-6. NOx Control Cost Results for the Arkwrijht Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nutfcer Retrofit Size Factor Sulfur Cost Coat Coat Coat Removed Removed Effect.
Difficulty (MU) (X) Content (SMM) (S/kU) (SW) (mi I Is/kuh) (%> (tons/y) <»/ton>
Factor (X)
I.NC-LNB
3
1.00
40
67
1.9
i.a
44.2
0.4
1.6
40.0
382
960.3
LNC-LNB
4
1.00
40
62
1.9
i.a
44.2
0.4
1.7
40.0
' 354
1059.3
LKC-LNB-C
3
1.00
40
67
1.9
1.8
44.2
0.2
0.9
40.0
382
582.4
LHC-LN8-C
4
1.00
40
62
1.9
1.8
44.2
0.2
1,0
40.0
354
629.3
LNC-OFA
1
1.00
40
53
1.9
0.4
10.7
0.1
0.5
25.0
135
674.1
INC-OFA
2
1.00
40
70
1.9
0.4
10.7
0.1
0.4
25.0
178
510.4
LNC-OFA-C
1
1.00
40
53
1.9
0.4
10.7
art
0.3
25.0
135
400,0
i-MC-OFA-C
2
1.00
40
70
1.9
0.4
10.7
0.1
0.2
25.0
178
102.9
SCR-3
1
1.16
40
53
1.9
11.1
277.9
3.4
18.1
80.0
432
7761.3
SCR-3
2
1.16
40
70
1.9
11.1
277.9
3.4
13.8
80.0
571
5942.8
SCR-3
3
1.16
40
67
1.9
11.1
278.1
3.4
14.5
80.0
765
4459.1
SCR-3
6
1.16
40
62
1.9
11.1
278.0
3.4
15.6
80.0
707
4800.2
SCR-3
1-4
1.16
40
67
1.9
13.3
332.8
3.8
16.2
80.0
765
4961.0
SCR-3-C
1
1.16
40
53
1.9
11.1
277.9
2.0
10.6
80.0
432
4562.1
SCR-3-C
2
1.16
40
70
1.9
11.1
277.9
2.0
8.1
80.0
571
3492.2
SCR-3-C
3
1.16
. 40
67
1.9
11.1
278.1
2.0
8.5
80.0
765
2620.!
SCR-3-C
4
1.16
40
62
1.9
11.1
278.0
2.0
9.2
80.0
707
2820.7
SCR-3-C
1-4
1.16
40
67
1.9
13.3
332.8
2.2
9.5
80.0
765
2920.4
SCR-7
1
1.16
40
53
1.9
11.1
277.9
3.0
16.3
80.0
432
7007.0
SCR-7
2
1.16
40
70
1.9
11.1
277.9
3.1
12.5
80.0
571
5371.7
SCR-7
3
1.16
40
67
1.9
. 11.1
278.1
3.1
13.1
80.0
765
4033.0
SCR-7
4
1.16.
40
62
1.9
11.1
278.0
3.1
14.1
80.0
707
4339.5
SCR-7
1-4
1.16
40
67
1.9
12.0
299.8
3.2
13.8
80.0
765
4232.7
SCR-7-C
1
1.16
40
53
1.9
11.1
277.9
1.8
9.6
80.0
432
4129.8
SCR-7-C
2
1.16
40
70
1.9
11.1
277.9
1.8
7.4
80.0
571
3164.9
SCR-7-C
3
1.16
40
67
1.9
11.1
278.1
1.8
7.7
80.0
765
2375.9
SCR-7-C
4
1.16
40
62
1.9
11.1
278.0
1.8
8.3
80.0
707
2556.7
SCR-7-C
1-4
1.16
40
67
1.9
12.0
299.8
1.9
8.1
80.0
765
2495.4
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6-8
-------
Selective Catalytic Reduction--
Cold side SCR reactors for all units would be located immediately
behind the chimneys as were the FGD absorbers. All four reactors would be
located in a low site/congestion area with 200 feet of ducting required.
The ammonia storage system was placed close to the reactors, west of the
plant. No major demolition/relocation would be necessary and, as such, a
base factor of 13 percent was assigned to general facilities.
Table 6.1.1-5 presents the SCR process area retrofit factors and scope
adder costs. Table 6.1.1-6 presents the estimated cost of retrofitting SCR
at the Arkwright boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI- and DSD technologies at the Arkwright steam plant
was considered for all units. Although the ESPs have marginal SCAs (222),
there appears to be room available behind the ESPs for additional plate area
and sufficient duct residence time is available between the boilers and the
ESPs. A medium site access/congestion factor was assigned for upgrading the
ESPs because of the space limitation around the ESPs. The sorbent receiving/
storage/preparation area was located in the same area as that described for
L/LS-F6D.
Table 6.1.1-7 presents a summary of the site access/congestion factors
for FSI and DSD technologies at the Arkwright steam plant. Table 6.1.1-8
presents the costs estimated to retrofit sorbent injection technologies at
Arkwright.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All units would be considered good candidates for repowering or
retrofit because of the small boiler size and likely short remaining life.
Although the capacity factors are high, the small unit sizes would minimize
system impacts due to extended downtimes.
6-9
-------
TABLE 6.1.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR P.S. ARKWRIGHT UNITS 1-4 (EACH)
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$) 412
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$ 15
TOTAL COST (1000$)
ESP UPGRADE CASE 427
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
6-10
-------
Table 6,1,1-8. Sutmary of DSO/FSI Control Costs for the Arkwright Plant {June 1938 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Mu*er
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HV)
<%)
Content
(MM)
(I/kU)
mm
(mi Us/icwh)
(%)
-------
6.1.2 Bowen Steam Plant
The ESPs for units 3 and 4 would be difficult to upgrade due to the
configuration of the boilers and the ESPs; therefore, FSI and DSD were not
evaluated for the Bowen- Plant. In addition, the duct residence time between
the boilers and the ESPs for these units is short.
TABLE 6.1.2-1. BOWEN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON
COAL HEATING VALUE (BTU/LB)
1000 CU FT)
ON
ENT (PERCENT)
COAL ASH CONTEN
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
(PERCENT)
1,2 3,4
700 880
70,74 77,83
1971,72 1974,75
TANGENTIAL
334 607
NO NO
1.8
12200
10.5
WET DISPOSAL
ON-SITE/SOLD
1 2
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (4F)
ESP
1981
0.02
NA
2.0
476.6
2017.9
236
NA
ESP
1981
0.02
NA
2.0
622
2930
212
NA
6-12
-------
TABLE 6.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR BOWEN
UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
MET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
S365
NA
5365
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.68
NA
ESP REUSE CASE
1.69
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
15
* L/LS-FGD and LSD-FGD absorbers for units 1 and 2 would be
located behind the common chimney for units 1 and 2.
6-13
-------
TABLE 6.1.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR BOWEN
UNIT 3 OR 4 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
6587
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1*55
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.53
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
15
0
15
* L/LS-FGD absorbers, LSD-FGD absorbers, and new FFs for units 3
and 4 would be located behind the common chimney for units 3
and 4.
6-14
-------
Table 6.1,2-4. Surnary of FOO Control Casts for the iow«n Plant (June 1988 Dollars)
Technology
ioiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
502 Cost
Ntmber Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Rwioved
Effect.
Difficulty (MU)
(X)
Content
(SUN)
(SMO
(mills/kuh)
(tons/yr)
CS/ton)
Factor
...........
.......
m
.......
...........
......
..........
........
l/S FGD
1
1.66
TOO
-70
1.8
160.2
228.9
73.0
17.0
90.0
55045
1326.7
L/S FGD
2
1.6a
700
74
1.8
160.2
228.9
74.4
16.4
90.0
58190
1278.1
L/S FGD
3
1.55
880
77
1.8
181.1
205.8
87.9
U.8
90.0
76119
1154.6
L/S FGD
4
1.55
880
83
1.3
181.1
205.8
90.4
14.1
90.0
' 82050'
1101.9
L/S FGD
1-2
1.68
1400
72
1.8
280.5
200.3
132.4
15.0
90.0
113235
1169,0
L/S FGD
5-4
1.55
1760
80
1.8
307.6
174.8
158.2
12.8
90.0
158170
1000.2
L/S FGD-C
1
1,68
700
70
1.8
160.2
228.9
42.6
9.9
90.0
55045
773.2
L/S FGD-C
2
1.68
700
74
1.8
160.2
228.9
43.3
9.5
90.0
58190
744.6
L/S FGD-C
3
1.55
880
77
1.8
181.1
205.8
51.2
8.6
90.0
76119
672.2
L/S FGD-C
4
1.55
880
83
1.8.
181 .-1.
. 205.8
52.6
8.2
90.0
82050
641.2
L/S FGD-C
1-2
1.68
1400
72
1.8
280.5
200.3
77.1
8.7
90.0
113235
680.9
L/S FGD-C
3-4
1.55
1760
80
1.8
307.6
174.8
92.0
7.5
90.0
158170
581.8
LC FGD
1-2
1.68
1400
72
1.8
241.1
172.2
120.4
13.6
90.0
113235
1063.0
LC FGD
3-4
1.55
1760
80
1.8
273.4
155.3
147.8
12,0
90.0
158170
934.4
LC FGD-C
1-2
1.68
1400
72
1.8
241.1
172.2
70.0
7.9
90.0
113235
618.6
LC FGD-C
3-4
1.55
1760
80
1.8
273.4
155.3
85.9
7.0
90.0
158170
543.1
ISO+ESP
1
1.69
700
70
1.8
104.7
149.6
43.8
10,2
76.0
46665
939.5
LS0*£SF>
2
1.69
700
74
1.8
104.7
149.6
44.6
9.8
76.0
49332
904.3
LSD+ISP-C
1
1.69
700
70
1.8
104.7
149.6
25.6
6.0
76.0
46665
548.3
LSO+ESP-C
2
1.69
700
74
1.8
104.7
149.6
26.0
5.7
76.0
49332
527.6
LSD+FF
3
1.53
880
77
1.8
198.8
226.0
75.2
12.7
87.0
73158
1028.1
LSD"fF
4
1.53
880
83
1.8
198.9
226.0
77.0
12.0
87.0
78859
976.6
LSD+FF-C
3
1.53
880
77
1.8
198.8
226.0
44.0
7.4
87.0
73158
601.2
LSD*FF»C
4
1.53
860
83
1.8
198.9
226.fi
45.0
7.0
87.0
78859
570.8
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6-15
-------
Table 6.1.2-5. Summary of Coal Switching/Cleaning Costs for the Bower) Plant (June 1980 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Amual
Annual
SSS8SB8
S02
S02
$02 Cost
lluibar Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW)
(%>
Content
(SMH}
wm
(SMH)
(mi IIs/kuh)
m
(tons/yr)
CS/ton)
Factor
(X)
CS/8+S15
1
1.00
700
70
1.8.
21.4
30.6
60.0
14.0
49.0
30167
1988.4
CS/B»$!5
2
1.00
700
74
1.8
21.4
30.6
63.2
13.9 ,
49.0
31890
1980.4
CS/B*S15
3
1.00
880
77
1.8
26.6
30.2
82.2
13.8
49.0
41716
1969.8
CS/B+S15
4
1.00
880
83
1.8
26.6
30.2
88.1
13.8
49.0
44967
1960.2
CS/B+S15-C
1
1.00
700
70
1.8
21.4
30.6
34.5
8.0
49.0
30167
1142.4
CS/8*t15-C
2
1.00
700
74
1.8
21.4
30.6
36-3
8.0
49.0
31890
1137.6
CS/B*$15-C
3
1.00
680
77
1.8
26.6
30.2
47.2
8.0
49.0
41716
1131.4
CS/S+S15-C
4
1.00
880
83
1.8
26.6
30.2
50.6
7.9
49.0
44967
1125.7
CS/B+S5
. 1
1.00
700
70
1.8
14.2
20.3
23.3
5.4
49.0
30167
771.0
CS/8+S5
2
1.00'
700
74
1.8
14.2
20.3
24.4
5.4
49.0
31890
765.2
CS/B*$5
3
1.00
880
77
1.8
17.5
19.8
31.5
5.3
49.0
41716
756.3
CS/B*$5
4
1.00
880
83
1.8
17.S
19.8
33.7
5.3
49.0
44967
749.5
CS/B*$5-C
1
1.00
700
70
1.8
14.2
20.3
13.4
3.1
49.0
30167
443.9
CS/B*$5-C
2
1.00
700
74
1.8
14.2
20.3
14.0
3.1
49.0
31890
440.4
CS/B+S5-C
3
1.00
88Q
77
1.8
17,5
19.8
18.2
3.1
49.0
41716
435.2
CS/B+S5-C
4
1.00
880
83
1.8
17.5
19.8
19.4
3.0
49.0
44967
431.1
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6-16
-------
TABLE 6.1.2-6, SUMMARY OF NOx RETROFIT RESULTS FOR BOWEN
. BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2 3, 4
FIRING TYPE TANG TANG
TYPE OF NOx CONTROL OFA . OFA
FURNACE VOLUME (1000 CU FT) 334 607
BOILER INSTALLATION DATE 1971, 1972 1974, 1975
SLAGGING PROBLEM _N0 NO
ESTIMATED NOx REDUCTION (PERCENT) 25 25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0
Ductwork Demolition (1000$) 116, 196 138, 232
New Duct Length (Feet) 500 300
New Duct Costs (1000$) 7734, 11601 5305, 7968
New Heat Exchanger (1000$) 5991, 9080 6872, 10416
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 13841 12315
COMBINED CASE 20877 18606
RETROFIT FACTOR FOR SCR 1.52 1.52
GENERAL FACILITIES (PERCENT) 38 38
* Cold side SCR reactors for units 1-2 and 3-4 would be located
north of the unit 1-2 chimney and north of the unit 3-4 chimney,
respectively.
6-17
-------
Table 6.1.2-7. NOx Control Cose Results for the Bowen Plant (June 1988 Dollars)
ISS55SSSSSB1!
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(Btaas:
isiiiaaas:
itiamsi
laiuaaassiaasss:
imsssssssss
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5SSI85SSSS;
:sss»aas
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nuiiser
Retrofit
Size
Factor
sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW)
m
Content
<**)
(S/ttO
(srn
(mi ILs/kwh)
(S/too)
.........
Factor
.......
..........
«}
.........
........
......
...........
.........
INC-QFA
1
1.00
700
70
1.8
1.3
1.9
0.3
0.1
25.0
3267
87.3
tNC-OFA
2
1.00
700
74
1.8
1.3
1.9
0.3
0.1 .
25.0
3454
82.6
LNG-QFA
3
1.00
880
77
1.8
1.5
1.7
0.3
0.1
25.0
4518
69.3
INC-OF*
4
1.00
880
83
1.8
1.5
1.7
0.3
0.0
25.0
4870
64.3
LNC-OFA-C
1
1.00
700
70
1.8
1.3
1.9
0.2
0.0
25.0
3267
51.9
INC-OFA-C
2 !
1.00
700
74
1.8
1.3
1.9
0.2
0.0
25.0
3454
49.1
tNC-OFA-C
3
1.00
880
77
1.8
1.5
1.7
0.2
0.0
25.0
4518
41.1
LNC-OFA-C
4
1.00
8B0
83
1.8
1.5
1.7
0.2
0.0
25.0
4870
38.2
SCR-3
1
1.52
700
70
1.8
107.9
154.2
36.6
8.5
80.0
10455
3500.6
SCR-3
2
1.52
700
74
1.8
107.9
154.2
36.8
8.1
80.0
11052
3326.0
SCR-3
3
1.52
880
77
1.8
128.4
145.9
44.9
. 7.6
80.0
14457
3103.0
SCR-3
4
1.52
880
83
1.8
128.4
145.9
45.2
7.1
80,0
15584
2899,0
SCR-3
1-2
1.52
1400
72
1.8
200.7
143.4
70.0
7.9
80.0
21507
3253,8
SCR-3
3-4
1.52
1760
80
1.8
242.5
137.8
86.8
7.0
80.0
30041
2889,9
SCR-3-C
1
1.52
700
70 ,
1.8
107.9
154.2
21.5
5.0
80.0
10455
2051.9
SCR-3-C
2
1.52
700
W ..
1.8
107.9
154.2
21.5
4.7
80.0
11052
1949.4
SCR-3-C
3
1.52
880
77
1.8
128.4
145.9
26.3
4.4
80.0
14457
1817.6
SCR-3-C
4
1.52
880
83
1.8
128.4
145.9
26.5
4.1
80.0
15584
1697.9
SCR-3-C
1-2
1.52
1400
72
1.8
200.7
143.4
41.0
4.6
80.0
21507
1906.0
SCR-3-C
3-4
1.52
1760
80
1.8
242.5
137.8
50.8
4.1
80.0
30041
1691.9
SCR-7
1
1.52
700
70
1.8
107.9
154.2
30.9
7.2
80.0
10455
2951.7
SCR-7
2
, 1.52
700
74
1.8
107.9
154.2
31.0
6.8
80.0
11052
2806.9
SCR-7
3
1.52
880
77
1.8
128.4
145.9
37.6
6.3
80.0
14457
2604.0
SCR *7
4
1.52
880
83
1.8
128.4
145.9
38.0
5.9
80.0
15584
2436.2
SCR-7
1-2
1.52
1400
72
1.8
200.7
143.4
58.5
6.6
80.0
21507
2720.2
SCR-7
3-4
1.52
1760
80
1.8
242.5
137.8
72.4
5.9
80.0
30041
2409.7
SCR-7-C
1
1.52
700
70
1.8
107.9
154.2
18.2
4.2
80.0
10455
1737.4
SCR-7-C .
2
1.52
700
74
1.8
107.9
154.2
18.3
4.0
80.0
11052
1651.9
SCR-7-C
3
1.52
ma
77
1.8
128.4
145.9
22.1
5.7
80.0
14457
1531.7
SCR-7-C
4
1.52
880
83
1.8
128.4
145.9
22.3
3,5
80.0
15584
1432.7
SCR-7-C
1-2
1.52
1400
n
1.8
200.7
143.4
34.4
3.9
80.0
21507
1600.3
SCR-7-C
3-4
1.52
1760
80
1.8
242.5
137.8
42.6
3.S
80.0
30041
1416.8
sassssssssssi
1!
II
II
tt
(i
it
It
it
ssssaass:
iSSMltX
ssassassss
iSS898233ssaasiti
isaaanta
ftasnss
ssuassaeat
asasis:
ssHmassassa
iitamst
6-18
-------
TABLE 6.1.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BOWEN 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$) 5365
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 129
TOTAL COST (1000$)
ESP UPGRADE CASE 5494
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 between units 1 and 2 and their
respective ESPs is sufficient for FSI and DSD. A high factor
was assigned to ESP upgrade.
6-19
-------
Table 6.1.2-9. Sutmary of DSO/FSI Control Coats for the Bowen Plant (Jir* 1W6 Dollars)
lasssssstssssssesssass
sssstssssassssasss
sas3333«s=;s8>Ba33t3S3=easss3:s:s388ss=:ss==s
Technology Boiler Main BoiLer Capacity Coal Capital Capital Annual Annual S02 $02 S02 Cost
Muitoer Retrofit Site Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (tons/yrj <»/too>
Factor (X)
0SD*ESP
DSD*E5P
DSD+ISP-C
DSO*ESP-C
FSl+ESP-50
FSI+ESP-50
FSHESP-70
FSt+ESP-TO
FSI+ESP-50-C 1
FSl*ESP-50-C 2
FSl+ESP-TO-C 1
FSI+ESP-70-C 2
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
,00
.00
700
TOO
700
700
TOO
TOO
700
700
TOO
700
700
TOO
70
74
70
74
70
74
TO
74
TO
74
70
74
1.8
1.B
35.9
35.9
35.9
35.9
38.7
36.7
36.
38,
38.9
38.9
38.9
38.9
51.3
51.3
51.3
51.3
55.2
55.2
55.2
55.2
55.6
55.6
55.6
55.6
23.2.
23.9
13.5
13.9
29.2
30.3
16.9
17.6
29.7
30.9
17.2
17.9
5.4
5.3
3.1
3.1
6.8
6.7
3.9
3.9
6.9
6.8
4.0
3.9
49.0
49.0
49.0
49.0
50.0
50.0
50.0
50.0
TO.O
70.0
70.0
70.0
29754
31455
29754
31455
30580
32328
30580
32328
42812
45259
42812
45259
781.0
761.1
452.9
441.2
915.9
938.2
553.3
542.9
694.8
682.1
402.1
394.6
6-20
-------
6.1.3 Branch Steam Plant
The Branch Steam Plant is located in Putnam County, Georgi a, as part of
the Georgia Power Company system. The plant contains four coal-fired
boilers with a total gross generating capacity of 1,540 MW. Tables 6.1.3-1
through 6.1.3-11 summarize the plant operational data and present the S02
and HO control cost and performance estimates,
x
TABLE 6.1.3-1. BRANCH 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
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
250
319
481
490
89
77
69
65
1965
1967
1968
1969
OPPOSED WALL
NA
162.2
NA
NA
NO
NO
NO
NO
1.3
12400
10.6
WET DISPOSAL
PONDS/ON-SITE
5
5
5
5
RAILROAD
ESP
ESP
ESP
ESP
1978
1978
1981
1982
0.08
NA
0.02
0.02
98.0
98.0
98.0
98.0
1.0
1.0
0.6
1.0
335.2
417.4
999.0
453.1
1386
1679
1963.8
1963.8
242
249
509
231
300
240
300
300
6-21
-------
TABLE 6.1.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR BRANCH
UNITS 1 AND 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
NA
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
2132,2652
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.16
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for units 1
and 2 would be located southwest of the common chimney.
6-22
-------
TABLE 6.1.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR BRANCH
UNITS 3 AND 4 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING'
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
3833,3897
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.16
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD and LSD-FGD absorbers for units 3 and 4 would be
located southwest of the common chimney. ESP reuse was not
considered due to the access/congestion problems near the
ESPs.
6-23
-------
Tabl* 6,
.1.3-4.
Sunnsry of FG0 Control costs for the Branch Plant (June
1988 Dollars)
If
If
ii
II
II
II
II
it
ii
ii
ii
»
ii
ii
ii
»
It
11
II
11
It
!!
II
II
11
II
II
II
II
II
II
II
II
II
II
II
s::ss;:ss
Technology
Boi ter
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
$02
S02
S02 Cost
Nunber
Retrofit
Size
Factor
Sulfur '
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
(X)
Content
c»#o
ti/m
(«W)
(mills/kwh) (X)
Ctons/yr)
CS/torO
Factor
<%>
LC FGD
1-4
1.27
1540
73
1.3
190.5
123.7
104.2
10.6
90.0
89522
1163.9
LC FGO-C
1-4
1.27
1540
73
1.3
190.5
123.7
60.5
6.1
90.0
89522
676.4
If <2
1
1.27
250
89
1.3
63.0
252.0
30.6
15.7
90.0
17718
1729,8
lfgd
2
1.27
319
77
1.3
71.2
223.1
34.1
15.9
90.0
19561
1745.2
if as
3
1.27
481
69
1.3
91.0
189.1
43.1
14.8
90.0
26429
1630.5
LFSD
4
1.27
490
65
1.3
91.9
187.6
42.8
15.3
90.0
25363
1686.4
LFGD
1-4
1.27
1540
73
1.3
222.0
144.2
113.7
11.5
90.0
89522
1270.5
IFGB-C
1
1.27
250
89
1.3
63.0
252.0
17.8
9.2
90.0
17718
1007.0
tFGD-C
2
1,27
319
77
1.3
71.2
223.1
19.9
9.2
90.0
19561
1016.2
LFGD-C
3
1.27
481
69
1.3
91.0
189.1
25.1
B.6
90.0
26429
949.6
LFGD-C
4
1.27
490
65
1.3
91.9
187.6
24.9
8.9
90.0
25363
982.5
LFGD-C
1-4
1.27
1540
73
1.3
222.0
144.2
66.2
6.7
90.0
89522
739.0
ISD+FF
1
1.16
250
89
1.3
49.9
199.8
20.8
10.7
87.0
17029
1222.9
LSD+FF
2
1.16
319
77
1.3
55.8
175.0
21.9
10.2
79.0
17200
1275.9
LSC+FF
3
1.16
481
69
1.3
82.7
172.0
32.1
11.0
87.0
25401
1263.7
LSO*FF
4
1.16
490
65
1.3
83.9
171.2
32.0
11.5
87.0
24376
1313.6
LSO*FF
1-4
1.16
1540
73
1.3
246.6
160.1
94.9
9.6
37.0
86040
1103.5
LSO+FF-C
1
1.16
250
89
1.3
49.9
199.8
12.2
6.2
87.0
17029
713.8
ISP+FF-C
2
1.16
319
77
1.3
55.8
175.0
12.8
6.0
79,0
17200
745.5
ISDtFF-C
3
1.16
481
69
1.3
82.7
172.0
18.8
6.5
87.0
25401
738.6
LSO+FF-C
4
1.16
490
65
1.3
83.9
171.2
18.7
6.7
87,0
24376
768.1
LSD*FF-C
1-4
1.16
1540
73
1.3
246.6
160.1
55.5
5.6
87.0
86040
645.1
333SS85S3SSSS
II
II
II
II
II
II
II
fl
SSS8SBSS:
II
II
II
II
II
(1
::
11
Ii
II
II
II
11
11
=========
=======
==========
=__s_.=.
6-24
-------
Table 6.1.3-5. Summary of Coal Switching/Cltaning Costs for the Branch Plant (June 1988 Dollars)
S1IS11C1BC811
MIIUI
*¦¦¦¦¦¦¦
atssmt
¦vaaaavsi
SB ¦¦¦JIB J
llfSCSHCK
3£iaillls.....l...
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
NLnb«r Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HW)
<%>
Content
-------
TABLE 6.1.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR BRANCH +
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
OWF
OWF
OWF
TYPE OF NOx CONTROL
NA
LNB
NA
FURNACE VOLUME (1000 CU FT)
NA
162.2
NA
BOILER INSTALLATION DATE
1965
1967
1968
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
NA
35
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (10005)
0
0
0
Ductwork Demolition (1000$)
54
65
88
New Duct Length (Feet)
200
200
200
New Duct Costs (1000$)
1694
1953
2484
New Heat Exchanger (1000$)
3230
3738
4783
TOTAL SCOPE ADDER COSTS (1000$)
4977
5756
7355
RETROFIT FACTOR FOR SCR
1.16
1.16
1,16
GENERAL FACILITIES (PERCENT)
20
- 20
20
+ Units 1 and 3 have cell burners, therefore LNBs were not
evaluated for these units.
* Cold side SCR reactors for all units would be located
southwest of the common chimney.
6-26
-------
TABLE 6,1.3-7. SUMMARY OF NOx RETROFIT RESULTS FOR BRANCH +
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
1-4
FIRING TYPE
OWF
NA
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1969
NA
SLAGGING PROBLEM
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
89
210
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
2511
490/
New Heat Exchanger (1000$)
4836
9614
TOTAL SCOPE ADDER COSTS (1000$)
7436
14731
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
+ Unit 4 has cell burners and was not
* Cold side SCR reactors for all units
southwest of the common chimney.
evaluated
would be
for LNBs.
located
6-27
-------
Tab It 6.1.3-6. NOx Control Cost Results for the Branch Plant Nun 1988 Dol lara)
taiiatntaafssisgMasBanaasscsssaiflisaaxisisaviatsas'sastiitststattiflBBasaaiissnaaataaasaimsaiatssssaasaaissss
Technotogy Boiler Main SoEltf Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit
Slit
Factor
Sulfur
Cost
Coat
Coat
Coat
Removed Removed
Effect.
Difficulty (HUJ
CX)
Content
(SMI)
(SAW)
Cl/ton)
............
Factor
tx>
mwmmmmm.
IMC-IN1
2
1.00
319
77
1.3
4.1
12.7
0.9
0.4
35.0
3151
272.9
LNC-LNB-C
2
1.00
319
77
1.3
4.1
12.7
0.5
0.2
35.0
3151
162.1
SCR-3
1
1.16
250
89
1.3
36.4
145.5
13.1
6.7
80.0
6523
2002.5
SCR-3
2
1.16
319
77
1.3
43.8
137.4
15.8
7.3
80.0
7202
2190.7
SCR-3
3
1.16
481
69
1.3
59.8
124.4
22.0
7.6
80.0
9731
2264.6
SCR-3
6
1.16
490
65
1.3
60.9
124.3
22.3
8.0
80.0
9338
2389.4
SCR-3
1-4
1.16
1540
73
1.3
169.9
110.4
66.2
6.7
80.0
32960
2008.0
SCR-3-C
1
1.16
250
69
1.3
36.4
145.5
7.6
3.9
80.0
6523
1172.3
SCR-3-C
2
1.16
319
¦IT
1.3
43.8
137.4
9.2
4.3
80.0
7202
1282.4
SCR-3-C
3
1.16
4A1
69
1.3
59.6
124.4
12.9
4.4
80.0
9731
1325.0
SCR-3-C
4
1.16
490
65
1.3
60.9
124.3
13.1
4.7
80.0
9338
1398.2
SCR-3-C
1-4
1.16
1540
73
1.3
169.9
110.4
38.7
3.9
80.0
32960
1173.5
scu-r
1
1.16
250
89
1.3
36.4
145.5
11.0
5.7
80.0
6523
1689.)
SCR-7
2
1.16
319
77
1.3
43.8
137.4
13.2
6.1
80.0
7202
1828.4
SCR-7
3
1.16
481
69
1.3
59.8
124.4
18.1
6.2
80.0
9731
1860.4
SCR-7
4
1.16
490
65
1.3
60.9
124.3
18.3
6.6
80.0
9338
1960.3
SCR-7
1-4
1.16
1540
73
1.3
169.9
110.4
53.6
5.4
80.0
32960
1625.9
SCR-7-C
1
1.16
250
89
1.3 .
36.4
141.5
6.5
3.3
80.0
6523
992.8
SCR-7-C
2
1.16
319
77
1.3
43.8
137.4
7.7
3.6
80.0
7202
1074.8
SCR-7-C
3
1.16
481
69
1.3
59.8
124.4
10.6
3.7
80.0
9731
1093.4
SCR-7-C
4
1.16
490
65
1.3
60.9
124.3
10.8
3.9
80.0
9338
1152.4
SCR-7-C
1-4
1.16
1540
71
1.3
169.9
110.4
31.5
3.2
80.0
32960
954.6
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6-28
-------
TABLE 6.1.3-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRANCH UNITS 1 AND 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$) 2132, 2652
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 59, 71
TOTAL COST (1000$)
ESP UPGRADE CASE 2191, 2723
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
Units 1 and 2 have a long duct residence time. A high factor
was assigned to ESP upgrade because of the congestion around
the ESPs for these units.
6-29
-------
TABLE 6.1.3-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRANCH UNITS 3 AND 4
ITEM •
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS 1
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 3833,3897
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$) 97,97
TOTAL COST (1000$)
ESP UPGRADE CASE 3930,3995
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
Units 3 and 4 have a long duct residence time. Room is
available for ESP upgrade, hence a low factor was assigned.
6-30
-------
Table 6,1.3-11, Summary of OSP/FSi Control Costs for the Branch Plant (June 1988 Collars)
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Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
502
SC2 Cost
Nunber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.,
Difficulty (MW)
(X>
Content
(#WO
(mitls/kwh)
C%)
(tons/yr)
(S/tonJ
Factor
£%J
DSD~ESP
1
1.00
250
89
1.3
14.2
56.7
9.9
5.1
49.0
9578
1035.7
DSD+ESP
2
1.00
319
77
1.3
15.4
48.2
9.8
4.5
42.0
9170
1066.8
OSD+ESP
3
t.oo
481
69
1.3
19.6
40.6
13.3
4,6
49.0
14286
930.2
DSD+ESP
4
1.00
490
65
1.3
22.6
46.0
13.9
5.0
49.0
13710
1010.8
DSD+ESP-C
1
1.00
250
89
1.3
14,2
56.7
5.7
2.9
49.0
9578
600.0
DSD+ESP-C
2
1.00
319
77
1.3
15.4
48.2
5.7
2.6
42.0
9170
618.7
DSD+ESP-C
3
1.00
481
69
1.3
19.6
40.6
7.7
2.6
49.0
14286
539.1
DSD+ESP-C
4
1.00
490
65
1.3
22.6
46.0
8.0
2.9
49.0
13710
586.5
FSI+ESP-50
1
1.00
250
89
1.3
16.1
64.2
11.1
5,7
50.0
9843
1131.1
FSI+ESP-50
2
1.00
319
77
1.3
18.6
58.4
12.3
5.7
50,0
10867
1131.9
FSI+ESP-50
3
1.00
481
69
1.3
18.6
38.6
14.5
5.0
50.0
14683
987.6
FSI+ESP-50
4
1.00
490
65
1.3
24.2
49.4
15.7
5.6
50.0
14090
1113.9
FS1+ESP-50-C
1
. 1.00
250
89
1.3
16.1
64.2
6.5
3.3
50.0
9843
655.4
FS1+ESP-50-C
2
1.00
319
77
1.3
18.6
58.4
7.1
3.3
50.0
10867
656.2
FS1+ESP-50-C
3
1.00
481
69
1.3
18.6
38.6
8.4
2.9
50,0
14683
571.5
FS1+ESP-50-C
4
1.00
490
65
1.3
24.2
49.4
9.1
3.3
50.0
14090
645.9
FSI+ESP-70
1
1.00
250
89
'1.3
16.2
64.9
11.3
5.8
70.0
13781
821.3
FSI+ESP-70
2
1.00
319
77
1.3
18.8
58.8
12.5
5.8'
70.0
15213
821.2
FSI+ESP-70
3
1.00
481
69
1.3
18.7
39.0
14.8
5.1
70.0
20556
718.1
FSI+ESP-70
4
1.00
490
65
1.3
24.4
49.7
15.9
5.7
70.0
19726
808.4
FS1+ESP-70-C
1
1.00
250
89
1,3
16.2
64.9
6.6
3.4
70.0
13781
475.8
FS1+ESP-70-C
2
1.00
319
77
1.3
18.8
58.8
' 7.2
3.4
70.0
15213
476.0
FSI+ESP-70-C
3
1,00
481
69
1.3
18.7
39,0
8.5
2.9
70.0
20556
415.5
FSI+ESP-70-C
4
1.00
490
65
1.3
24.4
49.7
9.2
3.3
70.0
19726
468.7
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6-31
-------
6.1.4 Hammond Steam Plant
The Hammond steam plant is located on the Coosa River in Floyd County,
Georgia, and is part of the Georgia Power Company. The plant contains
four coal-fired boilers with a total gross generating capacity of 800 MW.
Table 6.1.4-1 presents operational data for the existing equipment at
the Hammond plant. Coal shipments are received by railroad and conveyed to
a coal storage and handling area west of the plant and adjacent to the
river. PM emissions from boilers 1-3 are controlled by retrofit ESPs.
Emissions from boiler 4 are controlled by an ESP installed at the time of
construction. All four ESPs are located behind the boilers and flue gas is
directed to two flues inside a common chimney. Three old chimneys are
retired and left intact behind the units. Ash from the units is disposed of
in ash ponds to the east and west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS or LSD-FGD absorbers would be located behind the common chimney.
The general facilities factor would be high (15 percent) because of the need
to relocate storage buildings and roads. A low site access/congestion
factor can then be assigned to the FGD absorber locations. Land across the
road can be acquired for the storage and preparation areas. In the L/LS-FGD
case, approximately 250 feet of ductwork would be required. For the LSD
case, approximately 350 feet of ductwork would be required. In both FGD
cases, a low site access/congestion factor would be assigned to flue gas
handling because of the easy access to the common stack.
Because of the small size of the existing ESPs, LSD was only considered
in conjunction with the use of new FFs. FFs would be located adjacent to
the absorbers and similar site access/congestion factors would be assigned
to their locations.
Tables 6.1.4-2 and 6.1.4-3 give a summary of retrofit data for
commercial FGD technologies. Table 6.1.4-4 presents the process area
retrofit factors and capital/operating costs for commercial FGD
technologies. The low cost option reduces capital/operating costs due to
economy of scale and elimination of a spare absorber module.
6-32
-------
TABLE 6.1.4-1. HAMMOND 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
100
500
64,84,70
70
1954,54,55
1970
FRONT WALL
OPPOSED WALL
47.5
276.6
NO
NO
1.7
1.7
12500
12500
9.7
9.7
WET DISPOSAL
PONDS/ON-SITE
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)
(H)
ESP
1971,69,69
NA
98
0.7
69.1
420
165
320
1970
NA
98.4
0.7
129.6
803
161
320
6-33
-------
TABLE 6.1.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR HAMMOND
UNITS 1-3 (EACH)
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
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
.
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
938
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
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
6-34
-------
TABLE 6.1.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR HAMMOND 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 NA
BAGHOUSE CASE LOW
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$) 3968 NA 0
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 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
6-35
-------
Table 6.1.4-4. Sunnary of FGD Control Costs for the Hammond Plant (June 1988 Dotl«rs>
Technology Boiler Kain Soiler Capacity Coal Capital Capital Annual Annual S02 S02 SQ2 Cost
Number Retrofit Siie Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (S/kw) ($MM) (mi IIs/kwh) {X} (tons/yr) (S/ton)
Factor (X)
l/S FGD
1
1.27
100
64
1.7
39.2
392.3
16.8
30.0
90.0
6603
2544.0
l/S FGD
2
1.27
100
84
1.7
39.2
392.5
17.9
24.4
' 90.0
8667
2069.1
l/S FGD
3
1.27
100
70
1.7
39.2
392.4
17.1
28.0
90.0
7222
2373.3
L/S FGD
4
1.27
500
70
1.7
100.2
200.5
47.8
15.6
90.0
36112
1322.3
L/S FED
1-3
1.27
300
73 .
' 1.7
72.4
241.2
33.7
17.6 .
90.0
22596
1492.7
L/S FGD-C
1
1.27
100
64
1.7
39.2
392.3
9.8
17.5
90.0
6603
1484.2
L/S FGD-C
2
1.27
100
84
1.7
39.2
392.5
10.5
14.2
90.0
8667
1205.8
L/S FGD-C
3
1.27
100
. 70
1.7
39.2
392.4
10.0
16.3
90.0
7222
5384.1
L/S FGD-C
4
1.27
500
70,
1.7
100.2
200.5
27.8
9.1
90.0
36112
,770.0
L/S FGD-C
1-3
1.27
300
73'*
1.7
72.4
241.2
19.6
10.2
90.0
22596
869.6
LC FGD
1-4
1.27
800
71
1.7
108.7
135.9
59.5
12.0
90.0
58605
1015.6
LC FGD-C
1-4
1.27
800
71
1.7
108.7'
135.9
34.6
7.0
90.0
58605
590.2
LSD+FF
1
1.27
100
64
1.7
26.1
260.7
10.7
19.1
87.0
6347
1690.S
LSD+FF
2
1.27
100
84
1.7
26.1
260.8
11.4
15.4
87.0
8330
1364.3
LSD+FF
3 '
1.27
100
70
1.7
26.1
260.7
10.9
17.8
87.0
6942
1572.9
LSD+FF
4
1.27
500
70
1.7
93.7
187.5
36.7
12.0
87.0
34708
1058.6
LSO+FF
1-3
1.27
300
73
1.7
63.4
211.4
24.9
13.0
87.0
21717
1148.4
LSD+FF-C
1
1.27
100
64
1.7
26.1
260.7
6.3
11.2
87.0
6347
987.1
LSD+FF-C '
2
1.27
100
84
1.7
26.1
260.8
6.6
9.0
87.0
8330
795.7
LSD+FF-C
3
1.27
100
70
1.7
26.1
260.7
6.4
10.4
87.0
6942
. 918.0
LSD+FF-C
4
1.27
500
70
1.7
93.7
187.5
21.5
7.0
87.0
34708
618.6
LSD+FF-C
1-3
1.27
300
73
1.7
63.4
211.4
14.6
7.6
87.0
21717
, 671.0
6-36
-------
Coal Switching and Physical Coal Cleaning Costs-
Table 6,1.4-5 presents the IAPCS cost results for CS at the Hammond
plant. These costs do not include boiler and pulverizer operation 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 —
The four boilers at the Hammond steam plant are wall-fired boilers
rated at 100, 100, 100, and 500 MW, respectively. The combustion
modification technique applied to all four boilers was LNB. Tables 6.1.4-6
and 6.1.4-7 present the NQX performance and cost results of retrofitting LNB
at the Hammond plant.
Selective Catalytic Reduction--
Cold side SCR reactors would be located similarly behind the; ESPs and
chimneys. 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 30 percent would be assigned to the location. However, after
demolition, the SCR reactors would be located in an area with a low site
access/congestion factor. About 250 feet of ductwork would be required.
Tables 6.1.4-6 and 6.1.4-7 summarize the retrofit factors scope adders and
estimated costs for retrofitting SCR at the Hammond plant.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the Hammond plant was not
considered for any of the units. All the units have small SCAs (<170) and
would not be able to handle additional particulate loading.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 1-3 would be considered good candidates for repowering or
retrofit because of the small boiler size and likely short remaining life.
However, the capacity factors are high which might result in high
replacement power cost for an extended downtime. Unit 4 is not a good
candidate for repowering because of its large boiler size, high capacity
factor, and longer remaining life.
6-37
-------
Table 6.1.4-5. Suimary of Coal Switching/Cleaning Costs for the Hammond Plant (June 1988 Sollars)
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Technology
Boilar 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 (MW)
<*>
Content
(SHM>
CS/kW>
(tm)
Factor
(X)
CS/B+S13
1
1.00 ¦
100
64
1.7
4.7
46.7
8.7
15.5
45.0
3289
2644.7
CS/i+115
2
1.00
100
84
1.7
4.7
46.7
ll.l
15.1
45.0
4317
2566.5
CS/8+S15
3
1.00
100
70
1.7
4.7
46.7
9.4
15.3
45.0
3597
2616.5
CS/B+S15
4
1.00
500
?0
1.7
18.7
37.4
44.1
14.4
45.0
17986
2454.1
CS/I*S15"C
1s
1.00
100
64
1.7
4.7
46.7
5.0
8.9
45.0
3289
1521.6
CS/B+S15-C
2
1.00
' 100
84
1.7
4.7
46.7
6.4
8.7
45.0
4317
1475.3
CS/B+S15-C
• 3
1.00
100
70
1.7
4.7
46.7
5.4
8.8
45.0
3597
1504.9
CS/B+S15-C
4
1.00
500
70
1.7
18.7
37.4
25.4
8.3
45.0
17986
1410.7
CS/B+S5
1
1.00
100
64
1.7
3.6
36.4
3.9
6.9
45.0
3289
1181.5
CS/B+S5
2
1.00
100
84
1.7
3.6
36.4
4.8
6.5
45.0
4317
1116.5
CS/B+S5
3
1.00
100
70
1.7
3.6
36.4
4.2
6.8
45.0
3597
1158.1
CS/B*$5
4
1.00
500
70
J.7
13.5
27.0
17.9
5.8
45.0
17986
995.7
CS/B+S5-C
1
1.00
100
64
1.7
3.6
36.4
2.2
4.0
45.0
3289
681.9
CS/B+S5-C
2
1.00
100
84
1.7
3.6
36.4
2.8
3.8
45.0
4317
643.4
CS/B*tt-C
3
1.00
100
70
1.7
3.6
36.4
2.4
3.9
45.0
3597
• 668.0
CS/B+S5-C
4
1.00
500 ¦
70
1.7
13.5
27.0
10.3
3.4
45.0
17986
573.8
6-38
-------
TABLE 6.1,4-6, SUMMARY OF NOx RETROFIT RESULTS FOR HAMMOND
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2,3
4
1-3
FIRING TYPE
FWF
FWF
NA
TYPE OF NOx CONTROL
LNB
LNB
NA
FURNACE VOLUME (1000 CU FT)
47.5
276.6
NA
BOILER INSTALLATION DATE
1954
1970
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
33
38
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
27
90
62
New Duct Length (Feet)
250
250
250
New Duct Costs (1000$)
1239
3176
2356
New Heat Exchanger (1000$)
1864
4895
3603
TOTAL SCOPE ADDER COSTS (1000$)
3130
8161
6021
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
30
30
30
6-39
-------
Table 6.1.4-7. HO* Control Cost Results for the Hammond 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
Content
CSHM)
(%/m
{S«H)
(itnlls/kwhj
<%5
(tons/yr)
CJ/tonJ
Factor
<«
LNC-LN8
1
1.00
100
64
1.7
2.6
25.5
0.5
1.0
33.0
767
704.9
LNC-INB
2
1.00
100
84
1.7
2.6
25.5
0.5
0.7
33.0
1007
537.1
INC-LMS
3
1.00
100
70
. 1.7
2.6
25.5
0.5
0.9
33.0
839
644.5
LNC-LNB
4
1.00
500
70
1.7
4.9
9.7
1.0
0.3
38.0
4830
213.0
LNC-LHB-C
1
1.00
100
64
1.7
2.6
25.5
0.3
0.6
33.0
767
418.7
U
-------
6.1.5 Jack McDonough Steam Plant
The Jack McDonough plant is located within Cobb County, Georgia, as
part of the Georgia Power Company system. The plant, located directly south
of the oil burning Atkinson power plant and west of the Chattahoochee River,
contains two coal-fired boilers and has a total gross generating capacity of
490 MW.
Table 6.1.5-1 presents operational data for the existing equipment at
the Jack McDonough plant. Both boilers burn medium sulfur coal which is
received by railroad and transferred to a coal storage and handling area
northeast of the plant away from the river.
PM emissions for the boilers are controlled with retrofit ESPs located
behind each unit and stacked on top of each other. The plant has a wet fly
ash handling system. Part of the fly ash; is temporarily disposed of in an
ash pond beside the coal pile while the rest 1s sold. Both units are served
by a common chimney located behind the ESPs.
Lime/Limestone and Lime Spray Drying FGD Costs-
Absorbers for both units would be located east of the chimney beside
the river. The limestone preparation, storage, and handling area would be
located south of the coal pile and close to the railroad tracks. This would
most likely enable the plant to receive the sorbent via existing railroad
tracks. Some of the roads and a major part of the storage building beside
the chimney would be relocated; therefore, a factor of 15 percent was
assigned to general facilities. The temporary waste handling area would be
located close to the ash pond site. However, because of the limited space
available, waste generated by the FGD absorbers would have to be deposited
off-site 1n the same manner as the fly ash.
The site beside the common chimney is surrounded by the river to the
east, chimney to the west, storage building to the north, and office
building and ESPs to the south. As such, a high site access/congestion
factor was assigned to the FGD absorber locations. In addition to general
facilities, 10 percent was added to the retrofit factor due to major
demolitions and relocations which would be necessary. Short duct runs of
6-41
-------
TABLE 6.1.5-1. JACK McDONOUGH 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
245
71,77
1963,64
TANG
154.5
NO
2.5
11800
9.6
WET DISPOSAL
ON-SITE PONDS/SELL
1
RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1972
EMISSION (LB/MM BTU) 0.04
REMOVAL EFFICIENCY 99.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0
SURFACE AREA (1000 SQ FT) 209.3
GAS EXIT RATE (1000 ACFM 1000
SCA (SQ FT/1000 ACFM) 209
OUTLET TEMPERATURE (*F) 300
6-42
-------
150 feet would be required for L/LS-FGD cases because absorbers were placed
immediately behind the chimneys.
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs are small and are located in a very high site/access
congestion area. The ESPs would probably require major upgrades and plate
area additions to handle the increased PMs generated from the LSD
application. LSD with a new baghouse was not considered because the boilers
are not burning low sulfur coal.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 6.1.5-2. Table 6.1.5-3 presents the
capital and operating cost estimates for commercial FGD technologies. The
low cost FGD case shows the effect of a combined system (economy of scale),
no spare absorber modules and large absorber modules.
Coal Switching and Physical Coal Cleaning Costs-
Table 6.1.5-4 presents the IAPCS cost results for CS at the Jack
McDonough plant. These costs do not include boiler and pulverizer operating
cost change 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 Combust ion-
Units 1 through 2 are dry bottom, tangential-fired boilers rated at
245 MW each. The combustion modification technique applied to both boilers
was OFA. Tables 6.1.5-5 and 6.1.5-6 present the N0X performance and cost
results of retrofitting OFA at the Jack McDonough plant. A high N0X
reduction performance was estimated based on the relatively low volumetric
heat release rate.
Selective Catalytic Reduction-
Cold side SCR reactors would be located immediately beside the common
chimney in an area having high site congestion and high underground
obstruction factors. The SCR reactors were located close to the chimney
and, as such, a short duct run of 200 feet was required. Some of the plant
roads and storage buildings would be relocated; therefore, a factor of
30 percent was assigned to general facilities.
6-43
-------
TABLE 6.1.5-2. SUMMARY OF RETROFIT FACTOR DATA FOR JACK McDONOUGH
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
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
YES
NA
NA
ESTIMATED COST (1000$)
2093
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
YES
RETROFIT FACTORS
FGD SYSTEM
1.70
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
0
6-44
-------
Table 6.1.5-3. Surinary of FGD Control Costs for the Jack NcDonough Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual , Annual S02 S02 S02 Cose
Nutfcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (WW) (%} Content (WW) (t/kW) (WH) (ai I Is/kwM (X) (tons/yr) (S/ton)
Factor (X)
L/S FGD 1,2 1.70 245 74 2.5 86.5 -353.2 38.4 24.2 90.0 29390 1306.0
US FGD 1-2 1.70 490 74 2.5 133.5 272.4 62.2 19.6 90.0 58780 1058.0
L/S FGD-C 1,2 1.70 245 74 2.5 86.5 353.2 22.4 14.1 90.0 29390 761.5
L/S FGD-C 1-2 1.70 490 74 2.5 133.5 272.4 36.2 11.4 90.0 58780 616.4
LC FGD 1-2 1.70 490 74 2.5 101.6 207.3 52.5 16.5 90.0 58780 892.4
LC FGD-C 1-2 1.70 490 74 2.5 101.6 207.3 30.S 9.6 90.0 58780 519.0
6-45
-------
Table 6.1.5-4. Surmary of Coal Switching/Cleaning Costs for the Jack MeDonough Plant (Juris 198S Dollars)
Technology Boiler Main Boiler
Nunber Retrofit Size
Difficulty (KW)
Factor
Capacity Coal Capital Capital AnnuaI
Factor Sulfur Cost Cost Cost
(X) Content CSMM3 (S/kU) (SUM)
m
Annual S02 S02 S02 Cost
Cost Ranoved Removed Effect,
(mills/kwh) (X) (tons/yr) ($/ton)
CS/B+115
CS/B+S15
00
00
245
245
71
77
2.5
2.5
8.6
8.6
35.0
35.0
21.9
23.6
14.4
14.3
65.0
65.0
20329
22047
1076.4
1069.2
CS/S+S15-C
CS/B*115-C
00
00
245
245
71
77
8.6
8.6
35.0
35.0
12.6
13.5
3.3
8.2
65.0
65.0
20329
22047
618.6
614.4
CS/8+S5
CS/B+J5
00
00
245
245
71
77
6.0
6.0
24.6
24.6
8.9
9.5
5.8
5.7
65.0
65.0
20329
22047
435.4
429.9
CS/B+f5¦
CS/B+S5-
00
00
245
245
71
77
6.0
6.0
24.6
24.6
5.1
5.5
3.3
3.3
65.0
65.0
20329
22047
250.8
247.6
6-46
-------
TABLE 6.1.5-5. SUMMARY OF NOx RETROFIT RESULTS FOR JACK McDONOUGH
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1. 2
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 154.5
BOILER INSTALLATION DATE 1963
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH
SCOPE ADDER PARAMETERS-- .
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 89
New Duct Length (Feet) 200
New Duct Costs (1000$) 2511
New Heat Exchanger (1000$) 4836
TOTAL SCOPE ADDER COSTS (1000$)
COMBINED 7436
INDIVIDUAL 4918
RETROFIT FACTOR FOR SCR 1.52
GENERAL FACILITIES (PERCENT) 30
6-47
-------
Table 6.1.5-6, NQx Control Cost Results for the Jack MeOonough Plant (June 1988 Dollars]
85S3SSS5S SSSSSS8SS8SSS88S9SSBS99S3SSSSSSd!SSSSZZ
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Muifeer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MUJ (X) Content <$KH} (S/kU>
-------
Table 6.1.5-5 presents the SCR retrofit results which include process
area retrofit factors and scope adder costs. Table 6.1.5-6 presents the
estimated cost of retrofitting SCR at the Jack McOonough boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the Jack McDonough steam
plant for both units would be difficult because ESPs have small SCAs (<210)
and probably would not be able to handle the increased PM without a major
ESP upgrade and/or plate area addition. However, long duct residence time
between the boilers and ESPs would be sufficient for humidification (FSI
application) or sorbent evaporation (DSD application). As a result, FSI and
DSD technologies were considered for this plant. A high site access/
congestion factor was assigned for upgrading the ESPs and adding plate area
due to space limitation around the ESPs.
Table 6.1.5-7 presents a summary of the site access/congestion factors
for FSI and DSD technologies at the Jack McDonough steam plant.
Table 6.1.5-8 presents the costs estimated to retrofit sorbent injection
technologies at the Jack McDonough plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Jack McDonough plant. Both units would be considered
good candidates for repowering or retrofit because of their small boiler
sizes. However, the high unit capacity factors could result in significant
replacement power costs.
6-49
-------
TABLE 6.1.5-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JACK McDONOUGH UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS .
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2093
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$ 59
TOTAL COST (1000$)
ESP UPGRADE CASE 2152
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.58
NEW BAGHOUSE:NA
6-50
-------
Table 6.1.5-8. Summary of DSD/FSJ Control Costs for ih# Jack MeDenough Plant (June 1988 Dollars)
Technology Boiler Main Boil«r Capacity Coal Capital Capital Amual
Nimbtr Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty
Factor (%5
Annual S02 S02 $02 Cost
Cost Removed Semovw Effect,
(mi lls/kuh) (X) (tons/yr) t$/ton)
BS0+ESP
BS0+ESP
DSD*ESP-C
DSD+ESP-C
FSI+ESP-50
FSI+ESP-50
FSI+ESP-50-C
FSI+ESP-50-C
FSI+ESP-70
FSI+ESP-70
FSI+ESP-70-C
FSI+ESP-70-C
1.00
1.00,
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
245
245
245
245
245
245
245
245
245
245
245
245
71
77
71
77
71
77
71
77
71
77
71
77
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
2.5
18
18
18
18
19
19
19
19
19
19
19
19
76
76
76
76
78
78
78
78
79
79
79
79
12.6
13.1
7.3
7.6
15.3
16.1
8.8
9.3
15.5"
16.4
9.0
9.5
8.3
7.9
4.8
4.6
10.0
9.7
5.8
5.6
10.2
9.9
5.9
5.7
49.0
49.0
49.0
49.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
15243
16531
15243
16531
15666
16990
15666
16990
21932
23785
21932
23785
825.1
790.4
478.2
458.0
974.3
946.7
563.7
547.5
708.7
688.8
410.0
398.3
S=5S=5=«
6-51
-------
6.1.6 Mitchell Steam Plant
The Mitchell Steam Plant is located in Dougherty County, Georgia, as
part of the Georgia Power Company system. The plant contains three
coal-fired boilers with a total gross generating capacity of 202 MW.
Tables 6.1.6-1 through 6.1.6-8 summarize the plant operational data and
present the SOg and N0x control cost and performance estimates.
TABLE 6.1.6-1. MITCHELL 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
23
20
1948,49
FRONT WALL
NA
NO
3
156
68
1964
TANGENTIAL
91.8
NO
1.3
12300
9 5
WET DiSPOSAL
POND/ON-SITE
1
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)
* Some information was obtained from plant personnel.
ESP
ESP
1975
1964
0.01
0.01
99.5
99.5
1.0
1.0
28.5
103.7
128.4
NA
222
NA
299
299
6-52
-------
TABLE 6.1.6-2. SUMMARY OF RETROFIT FACTOR DATA FOR MITCHELL
UNITS 1-3 *
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 NA
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 1761 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 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
* Absorbers and new FFs for units 1-3 combined would be
located east of the common chimney.
6-53
-------
Table 6.1.6*3. Surinary of FGO Control Costs for the Nitcheil Plant (June 1988 Dollars)
— ....SSSZISSi;—-SS5»55S5S5ii2£iSi*Sg5SS555SS5SSi£SSSSi8SS5SS5BSS5S5S8S58i»S3SSSS85S8MHllIlIlllSIlII11855SSllll
Technology Boiler Main Beiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nurtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (%} Content (SWO
-------
Table 6.1.6-4, Summary of Coat Switching/Cleaning Costs for the HitehelI Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 S02 Cost
Number Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty {%> Content (»H) (SAW) ($MH) (mills/kwh) (X) (tons/yr) (*/ton)
factor (%}
CS/B+S15
C5/B+S15
CS/B+S15-C
CS/8+115-C
CS/B*$5
CS/B+S5
CS/B+S5-C
CS/6+S5-C
1,2
3
1,2
3
1,2
3
1,2
3
.00
.00
.00
.00
,00
,00
,00
,00
23
156
23
156
23
156
23
156
20
68
20
68
20
68
20
68
1.3
1.3
1.3
1.3
1.3
1.3
1.3
1.3
1.6
6.1
1.6
6.1
1.3
4.4
1.3
4.4
68.8
38.8
68.8
38.8
58.4
28.4
SB.4
28.4
1.0
13.7
0.6
7.9
0.7
5.8
0.4
3.3
25.7
14.8
14.9
8.5
16.4
6.2
9.5
3.6
29.0
29.0
29.0
29.0
29.0
29.0
29.0
29.0
120
2764
120
2764
120
2764
120
2764
8633.9
4971.3
5005.8
2858.0
5508.1
2091.6
3205.9
1205.5
xiss«tiixisi33asiisissiiiiiitaiiaiissssisi3s3saisiiissssxi»iiis«siisasssissi»3£
6-55
-------
a
TABLE 6.1.6-5. SUMMARY OF NOx RETROFIT RESULTS FOR MITCHELL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
1-3
FIRING TYPE
TANG
NA
TYPE OF NOx CONTROL
OFA
NA
FURNACE VOLUME (1000 CU FT)
91.8
NA
BOILER INSTALLATION DATE
1964
NA
SLAGGING PROBLEM
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
NA
LOW
SCOPE ADDER PARAMETERS--
-
Building Demolition (1000$)
NA
0
Ductwork Demolition (1000$)
NA
46
New Duct Length (Feet)
NA
200
New Duct Costs (1000$)
NA
1495
New Heat Exchanger (1000$)
NA
2842
TOTAL SCOPE ADDER COSTS (1000$)
NA
4383
RETROFIT FACTOR FOR SCR
NA
1.16
GENERAL FACILITIES (PERCENT)
NA
20
a Units 1 and 2 were considered to
* Cold side SCR reactors for units
east of the common chimney.
be too small for LNBs.
1-3 combined would be located
6-56
-------
Table 6.1.6-6. NO* Control Cost Results for-the Mitchell Plant (June 1988 Dollars)
;;;;;;;2S;CSll2ISS;;;2aiIHIlSHMIIISS"SSSSIIIIIIIiriSl 22*2IIIIHXSSSSS&SX1I3SS8S8SSS:SS8SBSSSSS&SSSS«5BS*S5SCS
Technology Boiler Main Boiler Capacity Coal ' Capital Capital Annual Annual NOx MOx NQx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MV) (X) Content ($MM> (S/kv) (SUM) (mi IIs/tcwh)
-------
TABLE 6.1.6-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MITCHELL UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 251
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$) 10
TOTAL COST (1000$)
ESP UPGRADE CASE 261
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 boilers 1 and 2 and
their retrofit ESPs. A high factor was assigned to ESP
upgrade. Unit 3 was not a candidate for FSI or DSD because
of the inadequate size of the unit 3 ESPs.
6-58
-------
Table 6.1.6-8. Summary of OSO/FS! Control Costs for the Mitchell Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 $02 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
difficulty (HU) EX) Content (SMM) (mills/kuh) (X) (tons/yr> <»/ton)
Factor (X)
CSO'ESP
DSO+ESP-C
f si+esp-so
f$l*ESP-5Q-C 1
FSi+ESP-70
FSI+ESP-70-C 1
2 1.00 23 20 1.3 3.6 155.9 3.1 77.0 49.0 200 15521.7
2 1.00 23 20 1.3 3.6 155.9 1.8 44.5 49.0 200 8973.5
2 1.00 23 20 1.3 4.4 192.9 2.3 56.2 50.0 205 11026.2
2 1.00 23 20 1.3 4.4 192.9 1.3 32.7 50.0 205 . 6414.3
2 1.00 23 20 1.3 4.5 195.4 2.3 56.6 70.0 238 7935.3
2 1.00 23 20 1.3 4.5 195.4 1.3 32.9 70.0 288 4616.4
;S3SSS£2S&S£
6-S9
-------
6.1.7 Robert W. Scherer Steam Plant
The Robert W. Scherer steam plant is located on Lake Juliette in Monroe
County, Georgia, and is operated by the Georgia Power Company. The Scherer
plant has four coal-fired boilers with a gross generating capacity of
3,564 MW. Unit 3 is operating under test conditions and unit 4 is planned
for start-up in 1989. A 1982 aerial photograph was used in evaluating this
plant and units 3 and 4 were absent. However, in this report units 3 and 4
will be included under the assumption that the units are situated north of
unit 2 in a similar layout as units 1 and 2.
Table 6.1.7-1 presents the operational data for the existing equipment
at the Scherer 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 the
boilers were constructed. Units 1 and 2 have hot side ESPs, while units 3
and 4 have cold side ESPs. The ESPs are located behind the boilers. Flue
gases from units 1 and 2 are directed to separate stacks within a common
chimney, located behind the ESPs for those units. Units 3 and 4 have their
own chimney located behind their respective ESPs. Since units 3 and 4 are
1979 NSPS boilers, it was assumed that both boilers are equipped with FGD
systems and are not considered for further SO^ scrubbing.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located behind their
common chimney. The site access/congestion factor for both locations would
be low. No major relocations/demolitions would be required for installation
of the absorbers; therefore, all locations were assigned a low 5 percent to
general facilities. Ductwork of 100 to 300 feet would be required for both
units. The site access/congestion factor assigned to flue gas handling was
low.
Since units 1 and 2 have hot side ESPs, LSD with reuse of the existing
ESPs was not possible. Therefore, LSD with a new baghouse was considered
for units 1 and 2. The LSD absorbers would have a similar location as the
wet FGD absorbers, behind the common chimney, with a low site access/
congestion factor and a low general facility value of 5 percent. The new
6-60
-------
TABLE 6.1.7-1. SCHERER 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
891
24,35,65,65 *
1982,84,87,89
TANGENTIAL
NA
NO
0.6
12700
8 9
WET DISPOSAL
PONDS/ON-SITE
1,2,3,4 (1,2 WITHIN
ONE CHIMNEY)
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 (8F)
ESP
1982,84,87,89
0.03,0.02,0.01,NA
99.6,99.6,99.9,NA
0.6
1804,1804,1361,1361
5924,5924,3253,3253
305,305,418,418
824,824,247,247
* Capacity factors for units 3 and 4 are assumed as 65 percent
6-61
-------
FFs would be located adjacent to the LSD absorbers. A duct length of 100 to
300 feet would be required. A low site access/congestion factor was
assigned to flue gas handling.
Tables 6.1.7-2 presents the retrofit factor input to the IAPCS model.
However, the costs are not presented since the Scherer plant is burning a
low sulfur compliance coal.
Coal Switching and Physical Coal Cleaning Costs--
The boilers at the Scherer plant are currently burning a low sulfur
coal; therefore, CS and PCC were not considered for this plant.
N0X Control Technologies--
The boilers at the Scherer plant are already meeting 1979 NSPS N0x
emissions and were not considered.
Selective Catalytic Reduction-
Hot side SCR reactors would be located behind the common chimney for
units 1 and 2 and cold side reactors would be located behind the respective
chimney for units 3 and 4. As in the FGD case, low site access/congestion
factors and low general facility values (13 percent) were assigned to the
reactor locations. For each unit, approximately 250 feet.of duct would be
required to span the distance between the SCR reactors and the chimney. The
site access/congestion factor for flue gas handling was low for all units.
Tables 6.1.7-3 and 6.1.7-4 present the NGX performance and cost estimates
for installation of SCR at the Scherer plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
unit 1 and 2 since they are equipped with hot side ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All boilers at the Scherer plant are too large and have a long remaining
useful life; therefore, should not be considered for AFBC/CG technologies.
6-62
-------
TABLE 6.1.7-2. SUMMARY OF RETROFIT FACTOR DATA FOR SCHERER
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
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 YES NA NO
ESTIMATED COST (1000$) 6661 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 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
6-63
-------
TABLE 6.1.7-3, SUMMARY OF NOx RETROFIT RESULTS FOR SCHERER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3,4
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1982,84
1987,89
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 (1000S)
0
0
Ductwork Demolition (1000$)
139
139
New Duct Length (Feet)
250
250
New Duct Costs (1000$)
4453
4453
New Heat Exchanger (1000$)
0
6924
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
4592
6915
11516
17409
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES {PERCENT)
13
13
6-64
-------
Table 6
,1.7-4.
NOx Control Cost Results for the Seherer Plant
{Jtne
1988 Dollars)
S 3 S 9 28 S SS S Si IBS S St
Technology
;s;=sb«8
Boiler
tsasssss:
Main
"SSS8SSS2SS38SSSS5S53&
Boiler Capacity Coal
!31SSSS59SSI1IIISBSSS&3"
Capital Capital Annual
HBtaill
Annual
NOx
NOX
:eaas8S88
NOx Cost
Nurber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect,
Difficulty CMW)
(X)
Content
<$MH}
<***}
(milts/lcMh} (X)
(toos/yr)
(S/ton)
Factor
(X)
SCR-3
1
1.16
891
24
0.6
102.2
114.7
36.6
19.5
80.0
4357
8389.7
SCR-3
2
1.16
891
. 35
0.6
102.3
114.8
37.0
13.5
80.0
6354
5822.8
SCR-3
3
1.16
891
65
0.6
100.8
113.1
37.7
7.4
80.0
11800
3191.3
SCR-3
4
1.16
891
65
0.6 •
100.8
113.1
37.7
7.4
80.0
11800
3191.3
SCR-3
1-2
1.16
1712
30
0.6
196.6
110.3
71.6
15.3
80.0
10893
6177.7
SCR-3
3-4
1.16
1782
65
0.6
190.1
106.7
72.8
7.2
80.0
23601
3082.6
SCR-3-C
1
1.16
891
24
0.6
102.2
114.7
21.4
11.4
80.0
4357
4911.9
SC8-3-C
2
1.16
891
35
0.6
102.3
114.8
21.7
7.9
80.0
6354
3408.3
SCR-3-C
3
1.16
891
65
0.6
100.8
113.1
22.0
4.3
80.0
11800
1866.7
SC8-3-C
4
1.16
891
65
0.6
100.8
113.1
22.3
4.3
80.0
11800
1866.7
SCR-3-C
1-2
1.16
1782
30
0.6
196.6
110.3
41.9
9.0
80.0
10893
3849.5
SCR-3-C
3-4
1.16
1782
65
0.6
190.1
106.7
42.5
4.2
80.0
23601
1802.3
scR-r
1
1.16
891
24
0.6
102.2
114.7
29.3
15.6
80.0
4357
6723.2
SCR-7
2
1.16
891
35
0.6
102.3
114.8
29.7
10.9
80.0
6354
4680.2
SCR-7
3
1.16
891
65
0.6
100.8
113.1
30.4
6.0
80.0
11800
2576.0
SCR-7
4
1.16
891
65
0.6
100.8
113.1
30.4
6.0
80.0
11800
2576.0
SCR-7
1-2
1.16
1782
30
0.6
196.6
110.3
57.1
12.2
80.0
10893
5244.6
SCR-7
3-4
1.16
1782
65
0.6
190.1
106.7
58.2
5.7
80.0
23601
2467.4
SCR-7-C
1
1.16
891
24
0.6
102.2
114.7
17.2
9.2
80.0
4357
3957.2
SCR-7-C
2
1.16
891
35 '
0.6
102.3
114.8
17.5
6.4
60.0
6354
2753.6
SCR-7-C
3
1.16
891
65
0.6
100.8
113.1
17.9
3.5
80.0
11800
1514.2
SCR-7-C
4
1.16
891
65
0.6
100.8
113.1
17.9
3.5
80.0
11800
1514.2
SCR-7-C
1-2
1.16
1782
30
0.6
196.6
110.3
33.6
7.2
80.0
10893
3085.7
SCR-7-C
3-4
1.16
1782
65
0.6
190.1
106.7
34.2
3.4
80.0
23601
1449.8
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6-65
-------
6,1.8 Wanslev Steam Plant
The Wansley steam plant 1s located within Heard County, Georgia, and is
a part of the Georgia Power Company system. Situated in the western central
part of the state, approximately 40 miles to the southeast of Atlanta, the
plant site is located alongside the Chattahoochie River. To the northwest ,
of the plant site is a man-made lake. The plant contains two coal-fired
boilers with a total gross generating capacity of 1,730 MW.
Table 6.1.8-1 presents the operational data for the existing equipment
at the Wansley plant. The boilers burn a medium sulfur coal. Coal
shipments are received by railroad and transferred to a coal storage and
handling area located to the northwest of the plant site between the
powerhouse and the man-made lake.
PM emissions for the boilers are control led with ESPs located behind
each unit. The plant has a wet fly ash handling system. Approximately
one-third of the fly ash is removed from the plant site through paid
disposal. The remaining fly ash is conveyed through sluice lines to a
disposal site located beside the man-made lake to the northwest. Units 1
and 2 are served by separate flues within a common chimney. The following
evaluation is based on a 1981 aerial photograph, and any alterations made to
the plant layout since this time should be taken into consideration.
Lime/Limestone and Lime Spray Drying FGD Costs--
The two boilers are located beside each other with the chimney located
midway between the units and behind the ESPs. Limited space exists between
the two coal conveyors for placement of the FGD absorbers. The area to the
east of the plant contains oil tanks, storage structures, and office build-
ings which also would not be a suitable location for the retrofit control
equipment. The FGD system was assumed to be located on the southwestern
side of the pi ant where ample open space exists for control equipment and
absorber placement. Although this area would no longer be available for
future units, locating the FGD absorber behind the units between the two
coal conveyors would result in a high site access/ congestion factor. The
L/LS preparation area would be located adjacent to the absorbers. No major
6-56
-------
TABLE 6.1.8-1. WANSLEY 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
865
79,68
1976, 1978
TANGENTIAL
603
. NO
2.5
II,400
8 6
WET SLUICE
ON-SITE POND/PAID DISPOSAL
1 - ENCLOSING 2 CHIMNEYS
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
1976, 1978
0.06
98.6
2.5
656.6
3,070
214
268
6-67
-------
demolition would be necessary and, for this reason, a factor of 5 percent
was assigned to general facilities for absorber placement.
For the flue gas handling system, a duct run of approximately 700 feet
per unit would be needed. Because ductwork passes beneath the existing coal
conveyor, a medium site access/congestion factor was assigned to the flue
gas handling system.
LSD with reuse of existing ESPs was not considered for this plant
because the ESPs are small (SCA=214) and are located in a high site access/
congestion area with coal conveyors on either side and with the common
chimney placed midway between the ESPs. The LSD with a new baghouse option
was also not considered since the Wansley pi ant is burning a medium-to-high
sulfur coal.
The major scope adjustment items and retrofit factor estimates for the
FGD technologies are presented in Table 6.1.8-2. Table 6.1.8-3 presents the
capital and operating cost estimates for commercial FGD technologies. The
low cost FGD cases show the effect of no absorber sparing and large absorber
sizes.
Coal Switching and Physical Coal Cleaning Costs--
Table 6.1.8-4 presents the IAPCS cost results for CS at the Wansley
plant. These costs do not include boiler and pulverizer operating cost
changes or any system modifications that may be necessary to blend coal.
Coal switching for a fuel price differential of $15 per ton is higher than
that of $5 per ton because of inventory capital and preproduction costs,
which are a function of variable costs (e.g. fuel costs). PCC was not
evaluated because this is not a mine mouth plant.
Low N0xCombustion--
Both Wansley units are dry bottom, tangential-fired boilers rated at
865 MW each. The combustion modification technique applied to both boilers
is OFA. Tables 6.1.8-5 and 6.1.8-6 present the performance and cost results
of retrofitting OFA at the Wansley plant.
6-68
-------
TABLE 6.1.8-2. SUMMARY OF RETROFIT FACTOR DATA FOR WANSLEY UNITS 1 OR 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
NA
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
600-1000
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NA
ESTIMATED COST (1000$)
6055
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.49
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
0
6-69
-------
Table 6.1.8-3. Sumtary of FGO Control Costs for the Mans ley Plant < June 1988 Dollars)
Technology Softer Hain Boiler Capacity Coal Capital Capital Annual
Nuifcer Retrofit Silt Factor Sulfur Cost Cost Cost
Difficulty (My) CX> Content
L/S FGD
l/S FGD
1.49
1.49
865
865
79
68
2.5
2.5
177.4
177.4
205.1
205.1¦
94.5
as.9
15.8
17.2
90.0
90.0
115250
99202
819.9
895.8
L/S FOO-C
L/S FGD-C
' 1.49
1.49
865
865
79
68
2.5
2.5
177.4
177.4
205.1
205.1
54.9
51.7
9.2
10.0
90.0
90.0
115250
99202
476.7
521.2
LC FGD
LC FGD
1.49
1.49
865
865
79
68
2.5
2.5
149.6
149.6
172.9
172.9
86.1.
80.4
14.4
15.6
90.0
90.0
115250
99202
746.7
810.7
LC FGD-C
LC'FGD-C
1.49
1.49
865
865
79
68
2.5
2.5
149.6
149.6
172.9
172.9
50.0
46.8
8.3
9.1
90.0
90.0
115250
99202
433.6
471.3
SSS3ISSSS
ssssjsbsscsss
6-70
-------
Table 6.1.8-4, Surinary of Coal Switching/Cleaning Costs for the Wansley Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SC2 S02 SO2 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMW) CSMH) (mills/kwh) (tens/yr) (t/ton>
Factor <%>
CS/B+S15 1
CS/B+S15 2
CS/B+$15-C 1
CS/B+S15-C 2
CS/B+S5 1
CS/B*$5 2
CS/B*$5-C 1
CS/B+J5-C 2
1.00 865 79
1.00 865 68
1.00 865 79
1.00 865 68
1.00 865 79
1.00 865 68
1.00 865 79
1.00 865 68
2.5 26.3 30.5
2.5 26.3 30.5
2.5 26.3 30.5
2.5 26.3 30.5
2.5 17.4 20.1
2.5 17.4 20.1
2.5 17.4 20.1
2.5 17.4 20.1
53.3 13.9 66.0
72.4 14.1 66.0
47.8 8.0 66.0
41.6 8.1 66.0
32.3 5.4 66.0
28.3 5.5 66.0
18.6 3.1 66.0
16.3 3.2 66.0
84829 981.6
73017 992.0
84829 563.8
73017 570.0
84829 380,2
73017 387.7
84829 218.8
73017 223.2
6-71
-------
TABLE 6.1.8-5. SUMMARY OF NOx RETROFIT RESULTS FOR WANSLEY
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
603
603
BOILER INSTALLATION DATE
1976
1978
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
35
35
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
136
136
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
3501
3501
New Heat Exchanger (1000$)
6802
6802
TOTAL SCOPE ADDER COSTS (1000$)
10439
10439
RETROFIT FACTOR FOR SCR
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
6-72
-------
Table 6.1.8-6. NOx Control Cost Results for the Wansley Plant I June 1981 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx NOx Cost
Nmtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty £HW5 (X) Content CSHH) (S/kU) (SUM) (mills/kwh) (%3 (tons/yr> ($/tan)
Factor (X)
tNC-OFA 1 1.0(3 865 79 2.5 1.5 1.7 0.3 0.1 35.0 6895 45.1
LNC-OFA 2 1.00 865 68 2.5 1.5 1.7 0.3 ' 0.1 35.0 5935 52.4
INC-OFA-C 1 1,00 865 79 2.5 1.5 1.7 0.2 0.0 35.0 6895 26.8
INC-OFA-C 2 1.00 865 68 2.5 1.5 1.7 0.2 0.0 35.0 5935 31.1
SCR-3 1 1.34 865 79 2.5 106.9 123.5 39.9 6.7 80.0 15760 2529.3
SCR-3 2 1.34 865 68 2.5 106.8 123.5 39.3 7.6 80.0 13566 2895.9
SC8-3-C 1 . 1.34 865 79 2.5 , 106.9' 123.5 23.3 . 3.9- 80.0 15760 1479.5
SCR-3-C 2 1.34 865 68 2.5 106.8 123.5 23.0 4.5 60.0 13566 1694.5
SCR-7 1 1.34 865 79 2.5 106.9 123.5 32.7 5.5 80.0 15760 2074.9
SCR-7 2 1.34 865 68 2.5 106.8 123.5 32.1 6.2 80.0 13566 2368.0
SCR-7-C 1 1.34 865 79 2.5 106.9 123.5 19.2 3.2 80.0 15760 1219.1
SCR-7-C 2 1.34 865 68 2.5 106.8 123.5 18.9 3.7 80.0 13566 1392,0
6-73
-------
Selective Catalytic Reduction-
Cold side SCR reactors can be located on the northern side of the plant
in an open area adjacent to the chimney and ESPs between the two coal
conveyors. Due to the congestion created by the coal conveyors and ESPs, a
medium site access/congestion factor was assigned to the SCR reactor
locations. Since the SCR reactors are located beside the chimney, a short
duct length of less than 200 feet would be required. No major demolition/
relocation would be required and, as such, a low factor of 13 percent was
assigned to general facilities.
Evaluation of SCR controls was done separately from FGD. Both
technologies need to be considered if the SCR reactors could be located
downstream from the FGD absorbers. For this scenario, site access/
congestion factors would be similar to those for the FGD absorber placement
location which are low.
Table 6.1.8-5 presents the SCR retrofit results for both units.
Table 6.1.8-6 presents the estimated cost of retrofitting SCR at the Wansley
plant.
Duct Spray Drying and Furnace Sorbent Injection-
DSD and FSI were not considered at the Wansley Plant for the following
reasons.
o Short duct residence time between the boilers and the ESPs is
not sufficient for humidi ficat ion (FSI) and sorbent injection
(DSD) applications.
o ESPs are small and the addition of plate area would be difficult
because of the coal conveyors on either side of the ESPs and the
chimney behind the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabili ty- -
The repowering applicability criteria presented in Section 2 was used
to determine the applicability of these technologies at the Wansley plant.
Neither of these units would be considered good candidates for repowering or
retrofit because of their large boiler sizes, high capacity factors, and
long remaining life.
6-74
-------
6.1.9 Yates Steam Plant
The Yates steam plant is located within Coweta County, Georgia, as part
of the Georgia Power Company system. The plant is located adjacent to the
Chattahoochie River and contains seven coal-fired boilers with a total gross
generating capacity of 1,465 MW.
Table 6.1.9-1 presents operational data for the existing equipment at
the Yates plant. The boilers burn medium sulfur coal. Coal shipments are
received by railroad and transferred to the coal storage and handling area
north of units 1-5, east of units 6-7, and close to the Chattahoochie River.
PN emissions for boilers 1-5 are controlled with retrofit ESPs, while
boilers 6-7 have original ESPs, which in each case are located behind the
respective unit. The plant has a dry fly ash handling system. Part of the
waste ash is disposed of in a landfill southwest of the plant while some is
sold or paid disposed of off-site. Units 1-5 are served by a common chimney
and units 6-7 are served also by a separate common chimney. Each chimney
contains multiple flues. The following evaluation is based on a 1981 aerial
photograph, and any alterations made to the plant layout since that time
should be taken into consideration.
Lime/Limestone and Lime Spray Drying FGD Costs-
Units 1-5 are located, beside each other in an area that is adjacent to
the river and close to the coal pile. Unit 1 is closest to the river and
units 6-7 are situated a few thousand feet east of the coal pile. The
absorbers for units 1-5 would be located east of the boilers and south of
the coal pile. The absorbers for units 5-6 would be located directly behind
the chimney in an open area. The limestone preparation and storage/handling
area would be located in an open area between the absorbers for units 6-7
and units 1-5. No major demolition or relocation would be necessary for any
of the 7 absorber areas. Consequently, a base factor of 5 percent was
assigned to general facilities.
A low site access/congestion factor was assigned to all of the FGD
absorber locations. For units 1-5, a flue gas handling duct length of
400-500 feet would be required since the absorbers are located to the side
of boiler 5. Units 6-7 would require less than 300 feet of ducting because
6-75
-------
TABLE 6.1.9-1. YATES 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, 7
115 156 404
42,48,45 47,48 51,54
1950,50,52 1957,58 1974
TANGENTIAL
74 94 222
NO NO NO
2.4
11,600
10.4
DRY
LANDFILL/SELL
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
1971,68,69
0.09
98.4,98.1,98.0
103.3,75.6,75.6
490,420,420
211,180,180
300
ESP
1970,68
0.09
98.5
0.7
ESP
1974
0.05,0.06
99.9
103.3 NA
685,550 NA
151,188 324
310 320
6-76
-------
the absorbers are located directly behind the chimney. A low site access/
congestion factor was also assigned to the flue gas handling systems because
the chimneys are relatively easy to access in all cases.
LSD with reuse of the existing ESPs was considered for units 6-7 but
not for units 1-5. ESPs for units 6 and 7 have large SCAs (-630) and would
be able to accommodate the extra particulate load from LSD. On the other
hand, the SCAs for units 1-5 are inadequate, ranging from 151 to 211, and
would not be able to handle the excess load. Installation of baghouses for
these units was not considered because the boilers are not burning low
sulfur coal. The absorbers for units 6-7 would be located in the same
locations as in the L/LS-FGD case. Moderate duct lengths of less than
600 feet would be required for these units. A high site access/congestion
factor was assigned to the flue gas handling system because it is difficult
to access the flue gas ducting between the ESPs and boilers. A medium site
access/congestion factor was assigned for ESP upgrades which would not
likely be required.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 6.1.9-2 and 6.1.9-3.
Table 6.1.9-4 presents the capital and operating costs for commercial FGD
technologies. The low cost FGD cases show the effect of combined FGD
systems, no spare scrubber modules, and large absorber sizes.
Coal Switching and Physical Coal Cleaning Costs-
Table 6.1.9-5 presents the IAPCS results for CS at the Yates plant.
These costs do not include boiler and pulverizer operating cost changes or
system modifications that may be necessary to blend coal. Coal switching
for a fuel price differential of $15 per ton is higher than that of $5 per
ton because of the inventory capital and preproduction costs, which are a
function of variable costs (e.g. fuel costs). PCC was not evaluated
because this is not a mine mouth plant.
6-77
-------
TABLE 6.1,9-2. SUMMARY OF RETROFIT FACTOR DATA FOR YATES UNITS 1-5
(EACH)
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
NA
FLUE GAS HANDLING
LOW
NA
-
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.31
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
0
6-78
-------
TABLE 6.1,9-3. SUMMARY OF RETROFIT FACTOR DATA FOR YATES UNIT 6-7
(EACH)
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.20 NA
ESP REUSE CASE 1.36
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5'
6-79
-------
Table 6.1.9-4. Suimary of FGD Control Costs for the fates Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coat Capital Capital Annual Annual $02 S02 $02 Cost
Nunber !
Retrofit
Size
Factor Sulfur ,
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty (HU)
m
Content
(»«)
(S/kW)
(SW)
CffliUs/kwti)
CX>
(tons/yr)
(S/ton)
Factor
CS>
L/S FGO
1,2,3
. 1.31
115
45
2.4
43.8
381.1
17.9
39.5
90.0
8213-
2m.6
l/S FGO
4,5
1.31
156
48
2.4
51.3
328.7
21.4
32.7
90.0
11884
1803.2
l/S FGO
1-3
1.31
345
45
2.4
81.1
235.0
34.6
25.4
90.0
24639
1403.7
l/S FGO
4-5
1.31
312
48
2.4
76.8
246.1
33.0
25.2
90.0
23768
1390.2
L/$ FGD
6
1.20
404
51
2.4
82.9
205.2
37.8
20.9
90.0
32700
1154.9
L/S FGD
7
1.20
404
54
2.4
82.9
2Q5.3
38.5
20.1
90.0
34623
1110.8
L/S FGD-C
1,2,3
1.31
115
45
2.4
43.8
381.1
10.4
23.0
90.0
8213
1272.1
l/S FGD-C
4,5
1.31
156
48
2.4
51.3
328.7
12.5
19.1
90.0
11884
1052.4
l/S FG0~C
1-3
1.31
345
45
2.4
81.1
235.0
20.2
14.8
90.0
24639
819.0
L/S FGD-C
4-5
1.31
312
48
2,4
76.8
246.1
19.3
14.7
90.0
2376S
811.0
L/S FGO-C
6
1.20
404
51
2.4
82.9
205.2
22.0
12.2
90.0
32700
673.0
L/S FGD-C
7
1.20
404
54
2.4
82.9
205.3
22.4
11.7
90.0
34623
647.2
IE FGD
1-5
1.31
657
46
2.4
103.3
157.3
49.1
18.4
90.0
48381
1014.3
IC FGO
6-7
1.20
808
53
2.4
116.6
144.3
59.2
15.9
90.0
67322
879.4
IC FGD-C
1-5
1.31
657
46
2.4
103.3
157.3
28.6
10.7
90.0
48381
590.7
IC FGD-C
6-7
1.20
SOS
53
2.4
116.6
144.3
34.4
9.3
90.0
67322
511.6
LSD+ESP
6
1.36
404
51
2.4
54.0
133.7
24.0
13.3
76.0
27722
867.3
l$D*E$P
7
1.36
404
54
2.4
54.0
133.7
24.5
12.8
76.0
29353
333.7
ISD+ESP-C
6
1.36
404
51
2.4
54.0
133.7
14.0
7.8
76,0
27722
SOS. 6
ISO+ESP-C
7
1.36
404
54
2.4
54.0
133.7
14.3
7.5
76.0
29353
485.9
============
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_______=
6-80
-------
Table 6,1,9-5, Sunmry of Coal SuitcMtif/C leant rig Costs for the lfates Plant (Ji*m 1988 Dollars)
SISSSSBSB 8S;jBSX8|
1!
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11
II
11
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SSSS3SSSS1
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SS3BS333
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Technology
Boiler
Mtirt
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
SC2
SQ2 Cost
Nuntoer
Retrofit
Size
factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU>
(X>
Content
(SMM)
CSMM)
(mills/kwft)
m
(tons/yr)
(S/too)
Factor
(%>
CS/B+S15
1
1.00
115
42
2.4
4,5
39.4
6.7
15.8
64.0
5462
1223.3
CS/S+S15
2
1.00
115
48
2.4
4.8
42.0
7.6
15.7
64.0
6242
1213.3
CS/B+S15
S
1.00
115
45
2.4
4.8
42.0
7.2
15.8
64.0
5852
1225.0
CS/B+S1S
4
1.00
156
47
2.4
6.6
42.2
10.0
15.6
64.0
8291
1206.0
CS/B*t15
5
1.00
156
48
2.4
6.1
39.0
10.0
15.3
64.0
8468
1185.8
CS/B+S15
6
1.00
404
51
2.4
13.0
32.1
26.1
14.5
64.0
23300
1122.3
CS/B+S15
7
1.00
404
54
2.4
13.0
32.1
27.5
14.4
64.0
24671
1115.7
CS/8*S15-C
1
1.00
115.
42
2.4
4.5
39.4
3.8
9.1
64.0
5462
704.6
CS/B+S15-C
2
1.00
115
48
2.4
4.8
42.0
4.4
9.0
64.0
6242
698.6
CS/B+$15-C
3
1.00
115
45
2.4
4.8
42.0
4.1
9.1
64.0
5852
TO,6
CS/B+J15-C
4
1.00
156
47
2.4
6.6
42.2
5.8
9.0
64.0
8291
694.5
CS/B*S15-C
5
1.00
156
48
2.4
6.1
39.0
5.8
8.8
64,0
8468
682.6
CS/B+S15-C
6
1.00
404
51
2.4
13.0
32.1
15.0
8.3
64.0
23300
645.5
CS/B*515-C
7
1.00
404
54
2.4
13.0
32.1
15.8
8.3
64.0
24671
641.6
CS/S+$5
1
1.00
115
42
2.4
3.3
29.0
3.0
7.0
64.0
5462
545.2
CS/8+J5
2
1.00
115
48
2.4
3.6
31.7
3.4
7.0
64.0
6242
540.0
CS/I+S5
S
1.00
115
45
2.4
3.6
31.7
3.2
7.1
64.0
5852
549.5
CS/B»$5
4
1.00
156
47
2.4
5.0
31.9
4.4
6.9
64.0
8291
532.0
CS/B*$5
5
1.00
156
48
2.4
4.5
28.6
4.3
6.6
64.0
8468
512.6
CS/B+S5
6
1.00
404
51
2.4
8.8
21.7
10.5
5.8
64.0
23300
451.0
CS/B+S5
7
1.00
404
54
2.4
8.8
21.7
11.0
5.8
64.0
24671
446.2
CS/B+S5-C
1
1.00
115
42
2.4
3.3
29.0
1.7
4.1
64.0
5462
315.1
CS^B+$5-C
2
1.00
115
48
2.4
3.6
31.7
1.9
4.0
64.0
6242
312.0
CS/B+S5-C
3
1.00
115
45
2.4
3.6
31.7
1.9
4.1
64.0
5852
317.6
CS/B*$5-C
4
1.00
156
47
2.4
5.0
31.9
2.5
4.0
64.0
8291
307.5
CS/B+tS-C
5
1.00
156
48
2.4
4.5
28.6
2.5
3.8
64.0
8468
296.0
CS/B+S5-C .
6
1.00
404
51
2.4
8.8
21.7
6.1
3.4
64.0
23300
260.1
CS/B+tS-C
7
1.00
404
54
2.4
8.6
21.7
6.3
3.3
64.0
24671
257.2
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6-81
-------
Low NO Combustion--
A
Units 1-7 are dry bottom, tangential-fired boilers. The combustion
modification technique applied to all boilers was OFA. Tables 6.1.9-6 and
6.1.9-7 present the N0X performance and cost results of retrofitting OFA at
the Yates plant.
Selective Catalytic Reduction-
Cold side SCR reactors for units 1-3 would be located west of unit 1,
close to the coal conveyor. For units 4-5, reactors would be located east
of the common chimney. For units 6-7, reactors would be placed behind
their common chimney. All seven reactors would be located in low
site/congestion areas. The ammonia storage system was placed in an open
area between the absorbers for units 1-5 and units 6-7. An additional
350-450 feet of ducting would be required for units 1-3 and 4-5,
respectively, with 200 feet needed for units 6-7. More ducting would be
needed for units 1-5 since the absorbers are placed at the side of the
boilerhouse; whereas, unit 6-7 absorbers would be placed directly behind the
chimneys.
Table 6.1.9-6 presents the SCR retrofit factors and scope adder costs.
Table 6.1.9-7 presents the estimated cost of retrofitting SCR at the Yates
boilers.
Duct Spray Drying and Furnace Sorbent Injection--
For units 6-7, it appears that sufficient duct residence time could be
made available between the boilers and the ESPs by modifying the first ESP
section for sorbent injection or humidification. For units 6-7, a medium
site access/congestion factor would be assigned for upgrading or modifying
the ESPs. By contrast, units 1-5 do not have sufficient duct residence time
between the boiler and ESPs and the ESPs are too small to use the first part
for sorbent injection or humidification. As such, the sorbent injection
technologies were not evaluated for units 1-5. The sorbent receiving/
storage/preparation areas would be located between the two boilerhouse
sites.
6-82
-------
TABLE 6,1.9-6. SUMMARY OF NOx RETROFIT RESULTS FOR YATES
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2, 3
4, 5
6,' 7
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
74
94
222
BOILER INSTALLATION DATE
1950-52
1957-58
1974
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
35
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
1
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
68
63
77
New Duct Length (Feet)
350
300
200
New Duct Costs (1000$)
3579
2892
2243
New Heat Exchanger (1000$)
3918
3689
4308
TOTAL SCOPE ADDER COSTS (1000$)
COMBINED
INDIVIDUAL
7566
3939
6645
3670
NA
6628
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
6-83
-------
T«bte 6,1.9-7. HO* Control Cost Results for the Yates Plant (Jwe 1988 Dollars)
::ss:uh:ii
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Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nunber
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Coat
Removed
Removed
Effect.
Difficulty (MU)
Content
(SIM)
(S/kW)
Ctons/yr)
(f/ton)
Factor
(%>
LNC-OFA
1
1.00
115
42
2.4
0.7
5.7
0.1
0.3
25.0
341
406.5
LNC-OFA
2
1.00
115
4fl
2.4
0.7
5.7
0.1
0.3
25.0
390
355.7
LNC-OFA
3
1.00
115
45
2.4
0.7
5.7
0.1
0.3
25.0
366
379.4
LNC-OFA
4
1.00
156
47
2.4
0.7
4.7
0.2
0.2
25.0
518
302.3
LNC-OFA
5
1.00
156
4«
2.4
0.7
4.7
0.2
0.2
25.0
529
296.0
LNC-OFA
6
1.00
404
51
2.4
1.1
2.7
0.2
0.1
15.0
2038
112.4
LNC-OFA
7
1.00
404
54
2.4
1.1
2.7
0.2
0.1
35.0
2158
106.2
LNC-OFA-C
1
1.00
115
42
2.4
0.7
5.7
0.1
0.2
25.0
341
241.5
LMC-OFA-C
2
1.00
115
48
2.4
0.7
5.7
0.1
0.2
25.0
390
211.3
LNC-OFA-C
3
1.00
115
45
2.4
0.7
5.7
0.1
0.2
25.0
366
225.4
LNC-OFA-C
4
1.00
156
47
2.4
0.7
4.7
0.1
0.1
25.0
518
179.5
LNC-OFA-C
5
1.00
156
46
2.4
0.7
4.7
0.1
0.1
25.0
529
175.8
LNC-OFA-C
6
1.00
404
51
2.4
1.1
2.7
0.1
0.1
35.0
2038
66.8
LNC-OFA-C
7
1.00
404
54
2.4
1.1
2.7
0.1
0.1
35.0
2158
63.1
SCR-3
1,2,3
1.16
115
45
2.4
21.0
183.0
6.7
14.8
80.0
1170
5716.0
SCR-3
4,5
1.16
156
48
2.4
24.9
159.4
8.3
12.6
80.0
1693
4875.5
SCR-3
1-3
1.16
345
45
2.4
<6.2
134.0
15.9
11.7
80.0
3510
4533.3
SCR-3
4-5
1.16
312
.48
2.4
43.8
140.5
14.9
11.4
80.0
3386
4411.2
SCR-3
6
1.16
404
51
2.4
51.0
126.3
18.1
10.0
80.0
4658
3890.8
SCR-3
7
1.16
404
54
2.4
51.0
126.3
18.2
9.5
80.0
4932
3687.9
SCR-3-C
1,2.3
1.16
115
45
2.4
21.0
183,0
3.9
8.7
80.0
1170
3355.6
SCR-3-C
4,5
1.16
156
48
2.4
24.9
159.4
4.8
7.4
80.0
1693
2859.3
SCR-3-C '
1-3
1.16
345
45
2.4
46.2
134.0
9.3
6.9
80.0
3510
2656.3
SCR-3-C
4-5
1.16
312
48
2.4
43.8
140.5
8.B
6.7
80.0
3386
2585.3
SCR-3-C
6
1.16
404
51
2.4
51.0
126.3
10.6
5.9
80.0
4658
2278.2
SCR-3-C
7
1.16
404
54
.2.4
51.0
126.3
10.6
5.6
80.0
4932
2159.3
SCR-7
1,2,3
1.16
115
45
2.4
21.0
183.0
5.7
12.7
80.0
1170
4904.3
SCR-7
4,5
1.16
156
48
2.4
24.9
159.4
7.0
10.6
80.0
1693
4114.5
scr-7
1-3
1.16
345
45
2.4
46.2
134.0
13.1
9.6
80.0
3510
3721.6
SCR-7
4-5
1.16
312
48
2.4
43.8
140.5
12.4
9.4
80.0
3386
3650.1
SCR-7
6
1.16
404
51
2.4
51.0
126.3
14.8
8.2
80.0
4658
3174.5
SCR-7
7
1.16
404
54
2.4
51.0
126.3
14.9
7.8
80.0
4932
3011.5
SCR-7-C
1,2,3
1.16
115
45
2.4 '
21.0
183.0
3.4
7.5
80.0
1170
2890.5
SCR-7-C
4,5
1.16
156
48
2.4
24.9
159.4
4.1
6.3
80.0
1693
2423.2
SCR-7-C
1-3
1.16
345
45
2.4
46.2
134.0
7.7
5.7
80.0
3510
2191.3
SCR-7-C
4-5
1.16
312
48
2.4
43.8
140.5
7.3
5.5
80.0
3386
2149.3
SCR-7-C
6
1.16
404
51
2.4
51.0
126.3
8.7
4.8
80.0
4658
1867.9
SCR-7-C
7
1.16
404
54
2.4
51.0
126.3
8.7
4.6
80.0
_ 4932
1771.7
iMBMM—Mwsaiffwfww—m f*"?*if *—»iammmmmimmmmm'H9wwwwwlMin9witT¥9¥wmaiiPmmmr^wmiitvHa's:vtirsriBzii!
6-84
-------
Table 6.1.9-8 presents a summary of the site access/congestion factor
for FSI and DSD technologies at the Yates steam plant. Table 6.1.9-9
presents the costs estimated to retrofit FSI and DSD at Yates.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 was used to determine the applicability of these
technologies at the Yates plant. Units 1-5 would be considered good
candidates for repowering and retrofit because of their small boiler sizes.
However, units 6-7 would not be considered because they are more than
300 MW. All units have moderate to high capacity factors which could result
in high replacement power cost for extensive downtimes. Units 2-4 would be
difficult to access for rebuilds or reuse of the furnace, pulverizers, and
heat recovery sections.
6-85
-------
TABLE 6.1.9-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR YATES UNIT 6-7 (EACH)
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 85
TOTAL COST (1000$)
ESP UPGRADE CASE 85
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
6-86
-------
Table 6.1.9*9, Summary of DSO/FSi Control Costs for the Tales Plant (J1988 Dollars)
sssssss::
Technology Boiler Main Boiler Capacity Coal
Ninfcer Retrofit Slie Factor Sulfur
Difficulty (MM) <%) Content
Factor (X)
Capital Capital Annual
Cost Cost Cost
(SUM) (1/kU) (MM)
Amual $02 $02 $02 Cost
Cost Removed Ramoved Effect,
(ml IIs/kuh) (X) (tons/yr) (S/ton)
DSD*ESP
DSD+ESP
00
00
404
404
51
54
2.4
2.4
19.7
19.7
48.8
48.8
14.1
14.5
?.a
7.6
49.0
49.0
17676
18716
798.2
775.1
DS0+ISP-C
0SD+iSP-C
1.00
1.00
404
404
51
54
2.4
2.4
19.7
19.7
48.8
48.8
8.2
8.4
4.5
4.4
49.0
49.0
17676
18716
462.3
448.8
FSMSP-50
FSI*ESP-5Q
1.00
1.00
404
404
51
54
2.4
2.4
17.6
17.6
43.5
43.5
16.4
17.0
9.1
8.9
50.0
50.0
18166
19235
902.4
886.3
FSI+ESP-50-C 6 1.00 404 51 2.4 17.6 43.5 9.5 5.2 50.0 18166 521.3
FSI+ESP-50-C 7 1.00 404 54 2.4 17.6 43.5 9.8 5.2 50.0 19235 511.9
FSI+ESP-70
FSI»ESP-7Q
.00
.00
404
404
51
54
17.4
17.4
43.1
43.1
16.6
17.3
9.2
9.0
70.
70.
25433
26929
653.
642.
FSt+ESP-70-C
FSI+ESP-70-C
00
00
404
404
51
54
17.4
17.4
43.1
43.1
9.6
10.0
5.3
5.2
70.0
70.0
25433
26929
377.4
370.?
sssssssssssss
SII3S9ISSSI32S3IBI&IIIEaSIBSSIBBia
¦aiiKiaias
D&B3IB3SIB3S3IS
6-87
-------
Page Intentionally Left Blank
-------
SECTION 7,0 ILLINOIS
7.1 CENTRAL ILLINOIS LIGHT COMPANY
7.1.1 E- D. Edwards Steam Plant
L/S-FGD arid LSD-FGD retrofit factors were developed for the boilers at
the Edwards plant; however, costs are not presented since the low sulfur coal
being used by the plant would yield low capital/operating costs and high
cost per ton of S02 removed. The boilers currently fire a low sulfur coal
hence CS was not considered. Since 1984 CILCO has been implementing a coal
blending program to comply with the 1.8 mmBTU standard. Sorbent injection
technologies were not evaluated because of the inadeguate size of the ESPs.
TABLE 7.1.1-1. E. D. EDWARDS 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
125
272
376
34
39
63
1960
1968
1972
FRONT WALL
73.5
155.6
187.5
NO
NO
NO
0.9
13000
6.0
WET DISPOSAL
POND/ON-SITE
1
1
2
RAILROAD/BARGE/TRUCK
ESP
ESP
ESP
1960
1968 .
1972
0.20
0.15
0.10
96.3
98.6
98.9
NA
NA
NA
63.4
138.2
215
462
815
1210
137
170
178
300
300
300
7-1
-------
TABLE 7.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR EDWARDS
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
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
1145,2299 NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.64
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.58
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
.NA
1.36
GENERAL FACILITIES (PERCENT) 15
0
15
* L/LS-FGD absorbers, LSD-FGD absorbers, and new FFs for units 1
and 2 would be located south of the common chimney for units 1
and 2.
7-2
-------
TABLE 7.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR EDWARDS UNIT 3 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
3073
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.38
. NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.27
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
* L/S-FGD absorbers, LSD-FGD absorbers, and new FFs for unit 3
would be located north of the unit 3 chimney.
7-3
-------
TABLE 7.1.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR EDWARDS
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
1-2
3
FIRING TYPE
FWF
FWF
NA
FWF
TYPE OF NOx CONTROL
LNB
LNB
NA
LNB
FURNACE VOLUME (1000 CU FT)
73.5
155.6
NA
187.5
BOILER INSTALLATION DATE
1960
1968
NA
1972
SLAGGING PROBLEM
NO
NO
NA
NO
ESTIMATED NOx REDUCTION (PERCENT)
40
39
NA
34
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
32
57
76
73
New Duct Length (Feet)
400
400
400
400
New Duct Costs (1000$)
2258
3559
4440
4301
New Heat Exchanger (1000$)
2131
3397
4263
4126
TOTAL SCOPE ADDER COSTS (1000$)
4421
7014
8779
850.0
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
1.16
GENERAL FACILITIES (PERCENT)
38
38
38
20
* Cold side SCR reactors for units 1 arid 2 would be located south
of the common chimney for units 1 and 2. Cold side SCR reactors
for unit 3 would be located north of the unit 3 chimney.
7-4
-------
Table 7.1.1-5. NO* Control Cost Results for the Edwards Plant CJurte 1988 Dollars)
ixsiBBiisiiiiBiuaBasissaisiiaaHMiMMSssiaiassiaiiissiiiuiiaHimassaaissusmiscfHMBSisiiitiBisxxastasst
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annuel NO* NO* fcQx Cost
Mimber Retrofit
Size
Factor Sulfur
cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MO
m
Content
(S/ttO
(SMM)
(milts/knh)
(%>
(tons/yr)
<$/ton>
Factor
«>
INC-INB
1
1.00
125
34
0.9
2.8
22.3
0.6
1.6
40.0
590
1034.2
LNC-LNB
2
1.00
272
39
0.9
3.8
14.0
0.8
0.9
39.0
1436
580.1
tNC-LNB
3
1.00
376
63
0.9
4.3
11.5
0.9
0.5
34.0
2796
339,1
LMC-INB-C
1
1.00
125
34
0.9
2.8
22.3
0.4
1.0
40.0
590
613.8
IMC-LNB-C
2
1.00
272
39
0.9
3.8
14.0
0.5
0.5
39.0
1436
344,2
INC-INB-C
3
1.00
376
63
0.9
4.3
11.5
0.6
0.3
34.0
2796
201.2
SCR-3
1
1.52
125
34
0.9
28.3
226.7
8.8
23.6
80.0
1180
7447.4
SCR-J
2
1.52
272
39
0.9
49.9
183.5
16.2
17.4
80.0
2946
5482.6
SCR-3
3
1.16
376
63
0.9
50.7
134.9
18.3
8.8
80.0
6578
2774.9
SCR-3
1-2
1.52
397
37 .
0.9
65.5
165.0
21.7
16.9
80.0
4079
5323.9
SCR-3-C
1
1.52
125
34
0.9
28.3
226.7
5.2
13.9
80.0
1180
4374.6
SCR-3-C
2
1.52
272
39
0.9
49.9
183.5
9.5
10.2
80.0
2946
3217.1
SCR-3-C
3
1.16
376
63
0.9
50.7
134.9
10.7
5.1
80.0
6578
1624.4
SCR-3-C
1-2
1.52
397
37
0.9
65.5
165.0
12.7
9.9
80.0
4079
3122.2
SCR-7
1
1.52
125
34
0.9
28.3
226.7
7.8
20.9
80.0
1180
6587.5
SCR-7
2
1.52
272
39
0.9
49.9
183.5
13.9
15.0
80.0
2946
4732.8
SCR-7
3
1.16
376
63
0.9
50.7
134.9
15.2
7.3
80.0
6578
2310.8
SCR-7
1-2
1.52
397
37
0.9
65.5
165.0
18.5
14.4
80.0
4079
4533.6
SCR-7-C
1
1.52
125
34
0.9
28.3
226.7
4.6
12,3
80.0
1180
3881.9
SCR-7-C
2
1.52
272
39
0,9
49.9
183.5
8.2
8.8
80.0
2946
2787.5
SCR-7-C
3
1.16
376
63
0.9
50.7
134.9
8.9
4.3
80.0
6578
1358.5
SCR-7-C
1-2
, 1.52
397
37
0.9
65.5
165.0
10.9
8.5
80.0
4079
2669.4
SSSSSS3==S*
N
11
li
11
|
11
£SSSSSS3»9S
8SSSSS
i%sss»Bassssasssss
ssssasas
xsssssss
.=aa«*ss
:saaasassaaa
saasasa:
saaasssaas
sacaastsa
7-5
-------
7.2 CENTRAL ILLINOIS PUBLIC SERVICE
7.2.1 Coffeen Steam Plant
The Coffeen steam plant is located within Montgomery County, Illinois,
and is part of the Central Illinois Public Service Company system. The plant
contains two coal-fired boilers with a total gross generating capacity of
1,006 MW. Figure 7.2.1-1 presents the plant plot plan showing the location,
of the boilers and major associated auxiliary equipment.
Table 7.2.1-1 presents operational data for the existing equipment at
the Coffeen steam plant. Both boilers burn high sulfur coal (3.7 percent
sulfur). The plant is located next to the Hillsboro coal mine and the coal
is conveyed from the mine to a coal storage area located south of the plant.
Particulate matter emissions for both boilers are controlled with
retrofit ESPs located behind each unit. Fly ash from all units is sold to
the County Road Commission for their use. On-site landfills are available
northeast of the plant for bottom ash from the boilers.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 7.2.1-1 shows the general layout and location of the FGD control
system. The absorbers for both units and all FGD technologies were located
south of the boilers in a relatively small area. A storage area building and
part of the plant road would be relocated to make more space available for
the FGD absorbers. Therefore, a factor of 7 percent was assigned to general
facilities. The limestone preparation/storage area was placed directly east
of the absorbers with the waste handling area being located east of the
preparation/storage area in the ash pond #1 site.
Retrofit Difficulty and Scope Adder Costs--
The Coffeen plant is equipped with two boilers, one chimney, and two
retrofit ESPs. The boilers sit east to west, side by side. The ESPs are
located directly behind (south) the units with the chimney centered behind.
The FGD absorbers were placed south of the chimney where they would be
bounded on three sides. The absorbers would be bounded to the west by the
coal conveyor, to the north by the chimney, and to the south by the coal
7-6
-------
N
Switchyard
Boilers
1 S. 2
Absorbers
NH, Storage
System
Asfi Pond #2
Lime/Linn eetone
Storage/Preparation Waste
Area Handling Area
Coal Storage
Area
Coal Mine
Area
(771 FGD Waste Handling/Absorber Area
Yfa time/Umeatone Storage/Preparation Area
¦ NN, Storage System
SCR Boxes
Not to seals
Figure 7.2.1-1. Coffeen plant plot plan
7-7
-------
TABLE 7.2.1-1. COFFEEN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1
2
GENERATING CAPACITY (MM)
389
617
CAPACITY FACTOR (PERCENT)
29
52
INSTALLATION DATE
1965
1972
FIRING TYPE
CYC
CYC
COAL SULFUR CONTENT (PERCENT)
3.7
3.7
COAL HEATING VALUE (BTU/LB)
10400
10400
COAL ASH CONTENT (PERCENT)
10.0
10.0
FLY ASH SYSTEM
DRY
ASH DISPOSAL METHOD
OFF-SITE
STACK NUMBER
1
COAL DELIVERY METHODS
CONVEYOR
COAL MINE
NEXT
TO THE PLANT
PARTICULATE CONTROL
TYPE
ESP
ESP
INSTALLATION DATE
1973
1982
EMMISION (LB/MM BTU)
0.05
0.05
REMOVAL EFFICIENCY
98.5
97.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
4.5
4.5
SURFACE AREA (1000 SQ FT)
308.9
397.4
GAS FLOW (1000 ACFM)
1422.7
2217
SCA (SQ FT/1000 ACFM)
217
179
OUTLET TEMPERATURE (*F)
310
310
7-8
-------
storage/handling area. A high site access/congestion factor was assigned to
the absorbers to reflect this congestion. No obstructions exist in the area
where the tie-in ductwork would be located and short to medium duct runs for
all units would be required since the absorbers are close to the chimney. As
a result, a low site access/congestion factor was assigned to flue gas
handling for all units and all FGD technologies.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Table 7.2.1-2. There are no
significant scope adders for the retrofit of FGD control technologies at the
Coffeen steam plant. The overall retrofit factors estimated for the L/LS-FGD
cases were moderate (1.44 to 1.48).
The only LSD-FGD case considered was LSD with a new baghouse. The
existing ESPs are located in a high site access/congestion area and the SCAs
are small (179-220). Also, it is likely that a considerable plate area
increase would be required to upgrade the existing ESPs. The retrofit factor
determined for the LSD technology was moderate (1.45) and did not include
particulate control costs. A separate factor of 1.58 was estimated for new
particulate controls. This high factor is a result of the high site
access/congestion associated with the intended location of the absorbers and
baghouses.
Table 7.2.1-3 presents the cost estimates for L/LS and LSD-FGD cases. The
LSD-FGD costs include installing new baghouses to handle the additional
particulate loading 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, and optimization of scrubber size.
Coal Switching and Physical Coal Cleaning 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. This is particularly true for cyclone boilers; therefore, coal
switching was not evaluated for the Coffeen plant.
7-9
-------
TABLE 7.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR COFFEEN UNITS 1-2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE NA
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA HIGH
SCOPE ADJUSTMENTS
WET TO DRY NO NO NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.44 1.48
ESP REUSE CASE NA
BAGHOUSE CASE 1.45
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.58
GENERAL FACILITIES (PERCENT) 7
7-10
-------
Table 7.2.1-3. Surrary of FGD Control Costs for the Coffeen Plant- (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coat Capital Capital Annual Annual S02 SQ2 S02 Cost.
Number Setrofit Size . Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) {%} Content ($MM> (t/ky) (SMM) (mills/kwhj (X) (tons/yr) ($/ton)
Factor (X)
L/S FGD 1 1.44 389 29 3.7 111.3 286.1 46.3 46.9 90.0 31287 1480.3
L/S FGD 2 1.44 617 52 3.7 152.0 246.3 75.1 26.7 90.0 88983 843.8
L/S FGD-C 1 ¦ 1.44 389 . 29 3.7 111.3 286.1 27.0 27.4 90.0 31287 864.0
l/S FGD-C 2 1.44 617 52 3.7 152.0 246.3 43.7 15.5 90.0 88983 491.1
LC FGD
IX FGD-
IS0+FF
LS0+FF
1-2 1.44 1006 41 3.7 192.4 191.3 94.1 26.0
1-2 1.44 1006 41 3.7 192.4 191.3 54.8 15.2
1 1.45 389 29 3.7 103.4 265.9 37.0 37.5
2 1.45 617 52 3.7 156.2 -253.1 63.0 22.4
90.0 114393
90.0 114393
84.0
84.0
29063
82657
822.6
478.9
1274.2
761.6
LSD+FF-C 1 1.45 389 29 3.7 103.4 265.9 21.7 21.9 84.0 29063 746.0
LSD+FF-C 2 1.45 617 52 3.7 156.2 253.1 36.8 13.1 84.0 82657 , 444.8
=3S58S8SS3SS8SSSSSR3SSSSS8SSC18S3SSaSISSS35B9S53583BSS88S33SSSSB8SBSSS333S
7-11
-------
Table 7.2.1-4 presents the IAPCS results for physical coal cleaning at
the Coffeen plant. These costs do not include reduced pulverizer operating
costs or system modifications that may be necessary to handle deep cleaned
coal.
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at Coffeen. These controls include LNC and SCR.
The application of NQX control technologies is affected by several
site-specific factors which are discussed in Section 2. The N0x control
technologies evaluated at Coffeen were: NGR and SCR.
Low N0X Combustion--
Units 1 and 2 are wet bottom, cyclone-fired boilers rated at 389 and
617 MM, respectively. The combustion modification technique applied was NGR.
The N0X reduction performance estimated for both units was 60 percent.
Table 7.2.1-5 presents the results for all boilers evaluated for N0X control
applicability at the Coffeen plant. Table 7.2.1-6 presents the cost of
retrofitting NGR at the Coffeen plant.
Selective Catalytic Reduction--
Table 7.2.1-5 presents the SCR retrofit factors for each unit. The
table includes process area retrofit difficulty factors and scope adder
costs. The scope adders include costs estimated for ductwork demolition, new
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 reactors for units 1 and 2 were located south of the powerhouse,
behind the ESPs, and north of the crusher house. The reactor for unit 1
would be bounded on three sides,by the coal conveyor belt, the chimney, and
the crusher house. Meanwhile, the reactor for unit 2 would be bounded on two
sides by the chimney and the coal conveyor.
The reactors for units 1 and 2 were assigned medium site access/
congestion factors. The ammonia storage system, which would supply ammonia
to both reactors, would be located in an open area. The reactors were placed
in an area with high underground obstructions and the ammonia system was
7-12
-------
' Table 7.2,1-4. Sunrary of Coal Snitching/Cleaning Costs for the Caffeen Plant {June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removes Effect,
Difficulty CMW) C»J Content (SUM) s:s:=="s:s:sssss:sssssssssss:sss==:sssssssfss:sssssssssssss;::s:ss"s="ssss==sss::=sss
7-13
-------
TABLE 7.2.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR COFFEEN
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
CY
CY
TYPE OF NOx CONTROL
' NGR
NGR
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
75
106
New Duct Length (Feet)
150
150
New Duct Costs (1000$)
1,503
1,968
New Heat Exchanger (1000$)
4,198
5,554
TOTAL SCOPE ADDER COSTS (1000$)
5,776
7,628
RETROFIT FACTOR FOR SCR
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
7-14
-------
Table 7,2.1-6, h'Ox Control Cost Resutts for the Coffeen Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 1 KOx NO* NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost " Removed Removed Effect,
Difficulty
-------
placed in an area with no significant underground obstructions.
Table 7.2.1-6 presents the estimated cost of retrofitting SCR at the Coffeen
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 both units would be
located south of the plant in a relatively small area. The retrofit of DSD
and FSI technologies at the Coffeen steam plant would be difficult because of
the small SCA (<220), although there is more than 2 seconds of flue gas
ducting residence time between the boilers and the ESPs. Significant
particulate control upgrading would likely be needed to handle the increased
solids loading resulting from the DSD and FSI retrofit. As a result, DSD
followed by new fabric filters installed behind the chimney was evaluated;
Tables 7.2.1-7 and 7.2.1-8 present a summary of site access/congestion
factors, scope adders, and retrofit factors for DSD and FSI technologies at
the Coffeen steam plant. Table 7.2.1-9 presents the costs estimated to
retrofit DSD at the Coffeen 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 appl icability of these
technologies at the Coffeen plant. The boilers at Coffeen would not be
considered good candidates for AFBC retrofit and AFBC or CG/combined cycle
repowering because of their large boiler sizes (>300 MW). However, the
capacity factor on boiler 1 is low and NO^SOg emissions are high suggesting
that this boiler may be a good candidate if size is not a technology limiting
constraint.
7-16
-------
TABLE 7.2.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COFFEEN UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE NA
NEW BAGHOUSE HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 3,051
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 83
TOTAL COST (1000$)
ESP UPGRADE CASE NA
A NEW BAGHOUSE CASE 3,134
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE NA
NEW BAGHOUSE 1.55
7-17
-------
TABLE 7.2.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COFFEEN UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
HIGH
ESP UPGRADE
NA
NEW BAGHOUSE
HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING
NO
ESTIMATED COST (1000$)
NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
300
ESTIMATED COST (1000$)
3,996
ESP REUSE CASE
NA
ESTIMATED COST (1000$)
NA
DUCT DEMOLITION LENGTH (FT)
50
DEMOLITION COST (1000$)
117
TOTAL COST (1000$)
ESP UPGRADE CASE
NA
A NEW BAGHOUSE CASE
4,113
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.25
ESP UPGRADE
NA
NEW BAGHOUSE
1.55
7-18
-------
Table 7.2.1-9. Surinary of DSD/FSI Control Costs for the Coffttn Plant (June 198S Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 S02 Cost
Nimber Retrofit Size . Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMU> «} Content <«H> (t/k«) (SHH) (mills/kwh} (%>
-------
7.2.2 Grand Tower Steam Plant
The Grand Tower steam plant is located in Jackson County, Illinois, as
part of the Central Illinois Public Service Company system. The plant
contains three coal-fired boilers with a gross generating capacity of 286 MW.
Figure 7,2.2-1 presents the plot plan showing the location of all boilers and
major associated auxiliary equipment.
Table 7.2.2-1 presents operational data for the existing equipment for
the boilers at Grand Tower. The boilers burn medium sulfur coal (2.7 percent
sulfur). Coal is received by truck and taken to the coal storage/handling
area located next to boilers/powerhouse (north).
Particulate emissions are controlled with retrofit ESPs located behind
the units. The ash from all units is wet sluiced to the ash ponds which are
located on the far side of the powerhouse (south).
Lime/Limestone and Lime Spray Drying FGD Costs--
Figure 7.2.2-1 shows the general layout and location of the FGD control
system. The FGD absorbers for all FGD technologies were located in an open
area south of the chimney in an uncongested area. The only demolition and
relocation required for this placement of the FGD absorbers would be a plant
road; therefore, a factor of 5 percent was assigned to general facilities.
The lime and limestone preparation/storage area and waste handling area were
located south of the absorbers in close proximity to the ash ponds in a low .
access/congestion area.
Retrofit Difficulty and Scope Adder Costs--
The Grand Tower plant has 3 units, numbered 7, 8, and 9. No information
was available for units 1 to 6 in the EIA-767 forms or other data reviewed
and, as a result, it was assumed that these units have been retired and are
no longer in service. The plant 1s bounded on the west side by the
Mississippi River and on the remaining.sides by rolling hills. All boilers
sit side by side, parallel to the river. The coal storage/handling area is
located to the north of the powerhouse while the ash ponds are located to the
south of the powerhouse. The L/LS and LSD-FGD absorbers were located between
the powerhouse and the ash ponds. A low site access/congestion factor was
7-20
-------
Q.
Q.
vs
to scale
Coat
Conveyor
9
8
0
7
S'uice
Urte
NH, Storage
System
•rSSSSr.
H»ndlii
Waste
0 Area
r,u» Waa,» Wm w \
SCR8°x*tSm*m
Fm
re
Grand
Tower
Phnt
Plot
PTsri
7-21
-------
TABLE 7.2.2-1. GRAND TOWER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (HW-each)
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
7,8
85, 81
10
1951
FWF
2,7
11500
10.3
114
40
1958
FWF
2.7
11500
10.7
WET SLUICE
POND/ON-SITE
1
TRUCK
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
1969
1970
0.13
0.16
98.4
97.9
2.1
2.1
19.9
54
149.5
377
133
143
310
310
7-22
-------
assigned to the location of the absorbers because there is no plant facility
surrounding this location. The access/congestion factor assigned to the flue
gas handling was medium as a result of the ductwork congestion created by the
closeness of the chimneys to the boilers and the railroad track. Also, a
long duct run would be required for all F6D retrofit cases at the Grand Tower
plant.
The major scope adjustment costs and estimated retrofit factors for the
F6D technologies are presented in Table 7.2.2-2. The largest scope adders
for the Grand Tower plant would be construction of a new chimney and the
conversion from wet to dry ash handling/disposal system for the L/IS-FGD
cases evaluated. It was assumed that the dry fly ash would be necessary to
stabilize the scrubber sludge waste for these cases. This conversion is not
required for the application of forced oxidation FED. Reuse of the existing
chimney was difficult due to the location of the chimney between the existing
ESPs. The cost of a new chimney was added to the scope-adders. The overall
retrofit factors determined for the L/LS-F6D cases were moderate (1.44 to
1.49).
The LSD-FGD case evaluated at Grand Tower was LSD with a new baghouse.
This case was evaluated for the primary reason that the SCAs at these units
are small (<145). The overall retrofit factor estimated for the LSD
technology was moderate (1.45). A separate factor was developed for the new
particulate controls and used by the IAPCS model to determine any additional
cost which might be required. This factor was low (1.16) and is a result of
the location chosen for the new particulate control on the side of the boiler
between the powerhouse and the ash ponds.
Table 7.2.2-3 presents the process area retrofit factors and cost
estimates for L/LS and LSD-FGD cases. The LSD-FGD costs include installing
new baghouses to handle the additional particulate loading for boilers 7-9.
Two combined FGD cases for units 7-9 were considered. The first case
uses conventional forced oxidation technology for an NSPS type system and
demonstrates the economies of scale. The second case represents the low cost
control case. The additional reduction in costs is primarily due to the
elimination of spare scrubber module, the optimization of scrubber module
size, and the use of adipic acid.
7-23
-------
TABLE 7,2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR GRAND TOWER UNITS 7-9
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
600-1000
600-1000
ESP REUSE
NA
BAGHOUSE
600-1000
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
NO
ESTIMATED COST (1000$)
819
NA
NA
NEW CHIMNEY
YES
YES
YES
ESTIMATED COST (1000$)
2,075
2,075
2,075
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.49
1.44
ESP REUSE CASE
NA
BAGHOUSE CASE
1.45
ESP UPGRADE
NA
NA
NA
NEW,BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 5
5
5
7-24
-------
Table 7.2.
2-3, Swmary of
FGD Control Costs for the Grand
Tower Plant (Jon#
1988 Dollars)
SSBXXSSSSSB.
Technology
:S8E3SSSSS
8oiter
Ba»»=a8iii
Main
8B882S———ww«A8SBCS235S£S
Boiler Capacity Coal
Capital Capital Annual
mssssss s:a.
Annual
assess:
S02
S02
S02 Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost :
Removed
Removed
Effect.
Difficulty (MV)
{%}
Content
(SMM>
CS/kU)
($HM)
(mills/kuh)
(X)
(tons/yr)
CS/ton)
Factor
'<%)
L/S FGO
7
1.49
85
10
2,7
43.6
513.3
16.2
217.1
90.0
1533
10544.0
US FGD
' 8
1.49
81
10
2.7
42.7
526.7
15.8
223.0
90.0
1461
10833.7
L/S FGD
9
1.49
114
40
2.7
49.8
436.6
21.0
52.6
90.0
8223
2554;0
L/S FOO-C
' 7
1.49
85
10
2.7
43.6
513.3
9.5
127.0
90.0
1533
6168.7
L/S FGD-C
8
1.49
81
10
2.7
42.7
526.7
9.3
130.5
90.0
¦ 1461
6338.0
L/S FQD-C
9
1.49
114
40
2.7
49.8
436.6
12.3
30.7
90.0
8223
1490.4
LC FGD
7-9
1.49
280
22
2.7
. 62.5
223.0
25.5
47.3
90.0
11108
2298.9
LC FCO-C
7-9
1.49
230
22 .
2.7
62.5
223.0
14.9
27.6
90.0
11108
1342.3
LSD+FF
7
1.45
85
10
2.7
25.8
303.6
10.0
134.0
87.0
1473
6773.3
LSD+FF
8
1.45
81
10
2.7
24.7
305.2
9.7
136.2
87.0
1404
6882.4
LSD+FF
9
1.45
114
40
2.7
31.7
278.4
13.2
33.1
86.0
7869
1678.2
LSD+FF-C
7
1.45
85
10
2.7
25.8
303.6
5.8
78.3
87.0
1473
3959.2
LSD*-FF-C
8
1.45
81
10
2.7
24.7
305.2
5.6
79.6
87.0
1404
4022.1
LSD+FF-C
9
1.45
114
40
2.7
31.7
278.4
7.7
19.3
86.0
7869
979,6
7-25
-------
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. SQj 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 7.2.2-4.
N0X Control Technology Costs
This section presents the performance and costs estimated for N0X
controls at the Grand Tower steam plant. These controls include INC
modification and SCR. The application of N0X 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 7 to 9 are dry bottom, front wall-fired boilers rated at 85, 81,
and 114 MW, respectively. The combustion modification technique applied for
these boilers was LNB. As Table 7.2.2-5 shows, the LNB NO reduction
A
performances for units 7 and 8 could not be estimated using the simplified
procedures. No boiler information could be found for units 7 and 8 in POWER
to assess their N0X reduction performances. Since these boilers are
relatively old, it is estimated that a N0X reduction of 20 to 30 percent can
be achieved by these boilers retrofitted with LNB. For unit 9, the LNB N0X
reduction performance was estimated at 50 percent using the simplified
procedures. Table 7.2.2-6 presents the cost of retrofitting LNB at the Grand
Tower boilers, assuming a N0X reduction performance of 25 percent for units 7
and 8.
7-26
-------
Table 7.2.2-4. Surmary of Coal Snitching/Cleaning Costs for the Grand Tower Plant (June 1968 Dollars)
N
N
II
H
II
11
II
II
11
II
II
82SS33SSI
IBS3SBSS8S
IS888S82
tSSSISSB!
8SS82B2S9ISSS
iixaasss:
iSSSCSS3S385
SSS8S8
¦SSSSS5SSS!
IBSSflSSS
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nmfcer
Retrofit
Si ze
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
¦
CS/S+S15
7
1,00
85
10
2.7
4.2
49.2
2.0
27.3
68.0
1165
1746.3
CS/B*$15
a
1.00
81
10
2.7
4.0
49.7
2.0
27.6
68.0
1111
1761.1
CS/B+S15
9
1.00
. 114
40
2.7
5.1
45.1
6.6
16.5
68.0
6252
1052.2
CS/8+S15-C
7
1.00
85
10
2.7
4.2
49.2
1.2
15.9
68.0
1165
1016.6
CS/B*$15-C
8
1.00
81
10
2.7
4.0
49.7
1.1
16.0
68.0
1111
1025.2
CS/B+S15-C
9
1.00
114
40
2.7
5.1
45.1
3.8
9.5
68.0
6252
606.5
CS/B*$5
7
1.00
85
10
2.7
3.3
38.8
1.3
17.0
68.0
1165
1086.1
CS/B+S5
8 ,
1.00
81
10
2.7
3.2
39,3
1.2
17.2
68.0
1111
1100.7
CS/B-S5
9
1.00
114
40
2.7
4.0
34,8
3.1
7.7
68.0
6252
491.4
CS/B+S5-C
7
1.00
85
10
2.7
3.3
38.8
0.7
9.9
68.0
1165
635.0
CS/B+SS-C
8
1.00
81
10
2.7
3,2
39.3
0.7
10.1
68.0
1111
643.5
CS/B+S5-C
9
1.00
114
40
2.7
4.0
34.8
1.8
4.5
68.0
6252
284.4
7-27
-------
TABLE 7.2.2-5 SUMMARY OF NOx RETROFIT RESULTS FOR GRAND TOWER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
7
8
9
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
17.9
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
53.7
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
2.39
ESTIMATED NOx REDUCTION (PERCENT]
i 25
25
10
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
New Chimney (1000$)
2,075
2,075
2,075
Ductwork Demolition (1000$)
24
24
30
New Duct Length (Feet)
600
600
700
New Duct Costs (1000$)
2,722
2,722
3,745
New Heat Exchanger (1000$)
1,703
1,703
2,016
TOTAL SCOPE ADDER COSTS (1000$)
6,524
6,524
7,866
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
7-28
-------
Table 7.2,2-6. NOx Control Cost Results for the Grand Tower Plant (June 1988 Dollars)
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
MQX
NOX
NOx Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Content
($MO
($MO
(mi 1ls/kwh)
<%>
Ctoris/yr)
(S/ton)
Factor
<%)
LNC-INB
7
1.00
85
10
2.7
2.4
28.2
0.5
7.0
25.0
85
6160.6
INC-tNB
8
1.00
81
10
2,7
2.3
29.0
0.5
7.2
25.0
81
6340.0
LNC-LNB
9
1.00
1U
40
2.7
2.7
23.6
0.6
1.5
50.0
911
645.5
LNC-INB-C
7
1.00
85
10
2.7
2.4
28,2
0.3
4.2
25.0
85
3656.8
LNC-INB-C
8
1.00
81
10
2.7
2.3
29.0
0.3
4.3
25.0
81
3762.0
LNC-LNB-C
9
1.00
114
40
2,7
2.7
23.6
0.3
0.9
50.0
911
383.1
SCR-3
7
1.16
85
10
2.7
20.7
243.1
6.0
81.0
ao.o
272
22186.8
SCR-3
S
1.16
81
10
2.7
20.2
249.1
5.9
82.5
80.0
259
22617.4
SCR-3
9
1.16
114
40
2.7
25.0
219.3
7.6
19.0
80.0
1458
5205,2
SCR-3-C
7
1.16
as
10
2.7
20.7
243.1
3,5
47.6
80.0
272
13052.6
SCR-3-C
a
1.16
81
10
2.7
20.2
249.1
3.4
48.6
80.0
259
13307.5
SCR-3-C
9
1.16
114
40
2.7
25.0
219.3
4.5
11.2
80,0
1458
3059.1
scr-7
7
1.16
85
10
2.7
20.7
243.1
5.3
71,5
80.0
272
19599,6
SCR-7
a
1.16
81
10
2.7
20.2
249.1
5.2
73.1
BO.O
259
20029.8
SCR-?
9
1.16
114
40
2,7
25.0
219.3
6.6
16,6
80.0
1458
4558.6
SCR-7-C
7
1.16
85
10
2.7
20.7
243.1
3.1
42.2
30.0
272
11570.2
SCS-7-C
S
1.16
81
10
2.7
20.2
249.1
3.1
43.2
80.0
259
11825.3
SCR-7-C
9
1.16
114
40
2.7
25.0
219.3
3.9
, 9-8
80.0
1458
2688.7
II
II
II
II
II
II
II
II
II
II
II
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II
II
II
II
II
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II
II
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II
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II
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11
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.___.__.__s
7-29
-------
Selective Catalytic Reduction-
Table 7.2.2-5 presents 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 ESPs to the
reactor and from the reactor to the chimney.
The SCR reactors for units 7 to 9 would be located s1de-by-side in a
relatively open area close to the powerhouse between it and the ash ponds.
Since the reactors were located in an open area having easy access with no
major obstacles, the reactors for units 7 to 9 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 NQX control techniques were evaluated
independently from those techniques evaluated for SO^ control. Using this
scheme, both the SCR reactors and the FGD absorbers were located in the same
area. If both S02 and N0X emissions were reduced at this plant, the SCR
reactors would have to be located downstream of the FGD absorbers in a
relatively open area further south from the SCR reactors' original locations.
In this case, low access and congestion factors would be assigned to all SCR
reactors. Table 7.2.2-6 presents the estimated cost of retrofitting SCR at
the Grand Tower 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 all units were
placed in a layout similar to that for LSD-FGD. The retrofit of DSD and FSI
would be difficult and costly because the SCAs are small (<150) and, for DSD
retrofit, there is insufficient duct residence time (1 second). Therefore, a
7-30
-------
new particulate control (new baghouse) would be needed to handle the
increased particulate load resulting from DSD or FSI application. For DSD
with a new fabric filter, the baghouse would be located south of the plant
between the powerhouse and ash ponds and the retrofit factors for the new
controls would be low (1.13). It was assumed that the ESPs could not be
upgraded for FSI due to a high access/congestion factor for modifying the
existing ESPs. Additionally, the conversion of the wet to dry ash handling
system would be required when reusing the ESPs for FSI. Tables 7.2.2-7 and
7.2.2-8 present a summary of the site access/congestion factors for DSD and
FSI technologies at the Grand Tower plant. Table 7.2.2-9 presents the
estimated cost to retrofit DSD with fabric filter at the Grand Tower plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC or CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Grand Tower plant. The boilers at the Grand Tower are
small, they were built prior to 1960 and have low capacity factors. As such,
they would be considered good candidates for retrofit/repowering using AFBC
or CG. Additionally, application of coal switching and sorbent injection
would be costly due to the need to add new particulate control devices.
7.2.3 Hutsonville Steam Plant .
The Hutsonville steam plant is located within Crawford County,
Illinois, as part of the Central Illinois Public Service Company system.
The plant is located beside the Wabash River which separates Illinois and
Indiana. The plant contains four retired oil burning boilers and two
operating coal-fired boilers. Both coal burning boilers have a combined
total gross generating capacity of 150 MW.
Table 7.2.3-1 presents operational data for the existing equipment at
the Hutsonville plant. The boilers burn medium sulfur coal. Coal shipments
are received by trucks and transferred to a coal storage and handling area
south of the plant.
PH emissions for both boilers are controlled with retrofit ESPs located
behind each unit. The plant has a wet fly ash handling system. Fly ash is
7-31
-------
TABLE 7.2.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GRAND TOWER UNITS 7-8
item
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 819
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 600
ESTIMATED COST (1000$) 2523
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 27
TOTAL COST (1000$) .
ESP UPGRADE CASE (FSI) 846
A NEW BAGHOUSE CASE (DSD) 2550
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1.13
7-32
-------
TABLE 7.2.2-8,
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GRAND TOWER UNIT 9
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1054
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 600
ESTIMATED COST (1000$) 2976
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 33
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 1087
A NEW BAGHOUSE CASE (DSD) 3009
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) K13
7-33
-------
Table 7.2.2-9. Sunmary of DSD/FSl Control Costs for the Grand Tower Plant (June 1988 Dollars)
======S==r"=====S£===£=S=S=====3KXXXaa===2====S«aBaS3SSSaSSS*a===S==BaS3XSSSSSSSS3SC5*BSSSaXS3S3SS=S===S======3
Technology Boiler Main Boiler Capacity Coil Capital Capital'Annual Annual S02 S02 S02 Cost
Number Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
TABLE 7.2.3-1. HUTSONVILLE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 5, 6
GENERATING CAPACITY (MW-each) 75
CAPACITY FACTOR (PERCENT) 78
INSTALLATION DATE 1953-54
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) 49.2
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 2.4
COAL HEATING VALUE (BTU/LB) 11000
COAL ASH CONTENT (PERCENT) 9.5
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1-2
COAL DELIVERY METHODS TRUCK
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1971
EMISSION (LB/MM BTU) 0.13
REMOVAL EFFICIENCY 97.9-99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0
SURFACE AREA (1000 SQ FT) 47.9
GAS EXIT RATE (1000 ACFM) 300
SCA (SQ FT/1000 ACFM) 159
OUTLET TEMPERATURE (SF) 300
7-35
-------
disposed of in a new ash pond site (built in 1986) southwest of the coal
pile. There are four roof mounted chimneys. The first two were used for
the oil burning units and are retired while the other two serve units 5 and
6 (the coal burning units).
Lime/Limestone and Lime Spray Drying FGO Costs--
The six boilers are located beside each other with boiler 1 being the
closest to the coal pile and boiler 6 the furthest. The retrofit ESPs for
boilers 5 and 6 are located behind each unit between the boilers and the
switchyard. The water intake and discharge structure is located on the
other side of the boiler toward the river.
The absorbers for units 5 and 6 would be located beside the retrofit
ESPs for unit 6 to the north of the plant. The sorbent preparation,
storage, and handling area would be located behind the absorbers. There are
no major obstacles/obstructions in the surrounding area and, as such, a base
factor of 5 percent was assigned to general facilities. The existing ash
pond site would be used for the FGD sludge disposal.
A low site access/congestion factor was assigned to the FGD absorber
locations due to the easy accessibility and space availability north of
unit 6. Because the chimneys are roof mounted and access to them is
difficult, a new chimney would be constructed beside the absorbers. Over
300 feet of duct would be required to divert the flue gases from each of the
units (5 and 6) to the absorbers and new chimney. A medium site access/
congestion factor was assigned to the flue gas handling system because of
the access difficulties to the boilers created by the close proximity of the
units to each other and their respective ESPs.
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs are small (SCA =159) and would require major upgrading and
additional plate area to handle the increased PM generated from the LSD
application. LSD with a new baghouse was not considered because the boilers
are not burning low sulfur coal.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 7.2.3-2. Table 7.2.3-3 presents the
process area retrofit factors and capital/operating costs for commercial FGD
technologies. The low cost FGD option reduces costs due to eliminating
7-36
-------
TABLE 7.2.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR HUTSONVILLE
UNIT 5 OR 6
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$) 724 NA NA
NEW CHIMNEY YES NA NA
ESTIMATED COST (1000$) 525 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) 5 0 0__
7-37
-------
Table 7,2,3-3. Sunniary of FG3 Control Costs for the HutsonvilU Plant (June 1988 Dollars)
Technology Boiler Main Boiler Cspacity Coal Capital Capital Annual Annual S02 $02 S02 Cost
Number Retrofit Size Factor Sulfur cost Cost Cost Cost Removed Removed Effect.
Difficulty (MY) (X) Content (MM) (»/kW)
-------
spare absorber modules and economies of scale associated with combining
process areas.
Coal Switching and Physical Coal Cleaning--
Table 7.2.3-4 presents the IAPCS results for CS at the Hutsonville
plant. These costs do not include cost impacts for changes in boiler and
pulverizer operation. PCC was not evaluated because this is not a mine
mouth plant.
Low N0X Combustion--
Units S and 6 are dry bottom tangential-fired boilers rated at 75 MW
each. The combustion modification technique applied to all boilers was
OFA. Tables 7.2.3-5 and 7.2.1-6 present the performance and cost results of
retrofitting OFA at Hutsonville. The high NGX removal performance is based
on the low volumetric heat release rate for these boilers.
Selective Catalytic Reduction-
Cold side SCR reactors for units 5 and 6 would be located beside the
unit 5 and 6 ESP boxes. Both reactors are located in medium site access/
congestion areas. All reactors were assumed to be in areas with high
underground obstructions. Duct length of 350 and 300 feet would be required
for units 5 and 6, respectively. The ammonia storage system was placed
close to the reactors north of the plant, No major demolition/relocation
would be required for the SCR reactor location and, as such, a base factor
of 13 percent was assigned to general facilities.
Table 7.2.3-5 presents the SCR process area retrofit factors and scope
adder costs. Table 7.2.3-6 presents the estimated cost of retrofitting SCR
at the Hutsonville plant.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the Hutsonville steam plant
for both units would be very difficult and were not considered for two major
reasons: 1) the ESPs have small SCAs (<160); therefore, they would not be
able to handle the increased PM and would require major upgrading and
additional plate area; and 2) there is a short duct residence time between
7-39
-------
Table 7.2.3-4. Sirroary of Coal Snitching/Cleaning Costs for the Hutsonville Plant (June 1988 Dollars)
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 CMU) (X) Content <$MM) (S/lcW) C$MM) (miUs/kwh) (%} (tons/yO (S/too)
Factor
-------
TABLE 7.2.3-5, SUMMARY OF NOx RETROFIT RESULTS FOR HUTSONVILLE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
5
6
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
49.2
49.2
BOILER INSTALLATION DATE
1953
1954
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
NEW CHIMNEY (1000$)
0
0
DUCTWORK DEMOLITION (1000$)
22
22
NEW DUCT LENGTH (Feet)
350
300
NEW DUCT COSTS (1000$)
1466
1256
NEW HEAT EXCHANGER (1000$)
1568
1568
TOTAL SCOPE ADDER COSTS (1000$) .
3056
2846
RETROFIT FACTOR FOR SCR
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
7-41
-------
Table 7.2.3-6. NQx Control, Cost Results far the HutsenviUe Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NQx NQx MOx Cost
number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CHW) (X) Content (SWO (S/kW) (SHH) (mills/kwh) <%5 (tons/yr) CJ/tsn)
Factor (X!
LNC-QFA 5, 6 1.00 75 78 2.4 0.6 7.4 0.1 0.2 25.0 439 274.8
LNC-QFA-C 5, 6 1.00 75 78 2.4 0.6 7.4 0.1 0.1 25.0 439 163.0
SCR-3 5 1.34 75 78 2.4 ' 17.6 235.0 5.7 11.1 80.0 1406 4043.5
SCR-3 6 1.34 75 78 2.4 17.4 232.2 5.6 11.0 80,0 1406 4016.7
SCR-3-C 5 1.34 75 78 2.4 17.6 235.0 3.3 6,5 80.0 1406 2372.8
SCR-3-C 6 1.34 75 78 2.4 17.4 232.2 3.3 6.5 80.0 1406 2356.8
SCR-7 5 1.34 75 78 2.4 17.6 235.0 5.1 9,9 80.0 1406 3599.4
SCR-7 6 1.34 75 78 2.4 17.4 • 232.2 5.0 9.8 80.0 1406 3572.7
SCR-7-C 5 1.34 75 78 2.4 17.6 235.0 3.0 5.8 80.0 1406 2118.4
SCR-7-C 6 1.34 75 78 2.4 17.4 232.2 3.0 5.8 80.0 1406 2102.4
7-42
-------
the boilers and ESPs making humidificatlon (FSI application) and sorbent
evaporation (DSD application) infeasible. In addition, ESPs are located
close to the switchyard and in a highly congested area and adding plate area
would be very difficult.
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 Hutsonville plant. Both units would be considered good
candidates for retrofit/repowering because of their small boiler sizes.
7.2.4 Meredosia Steam Plant
The Meredosia steam plant is located in Morgan County, Illinois, as
part of the Central Illinois Public Service Company system. The plant
contains six boilers; five are coal-fired and one primarily fires oil.
Units 1 to 5 have a net generating capacity of 354 MW. Unit 6 was not
considered for F6D retrofit.
Table 7.2.4-1 presents operational data for the existing equipment at
the Meredosia steam plant. Boilers 1-5 burn medium sulfur coal. Coal is
delivered by truck from a local mine. Barge unloading facilities are also
available on-site but no longer are used. The coal is stored in an area
southeast of the plant.
PM emissions for units 1-5 are controlled with retrofit ESPs located
behind each unit. Ash from the units is wet sluiced to ponds located south
of the plant beside the coal pile. Units 1-4 are served by a common chimney
located southeast of unit 1. Units 5 and 6 each have separate chimneys.
Lime/Limestone and Lime Spray Drying FGD Costs--
The switchyard is located behind the unit 1-4 ESPs making it impossible
to place FGD absorbers behind these units. Therefore, the unit 1-4
absorbers were located south of the chimney, close to the coal pile. This
location blocks the entrance to the plant; as such, a major plant road has
to be relocated to make it possible to access the plant. Absorbers for
7-43
-------
TABLE 7.2.4-1. MEREDOSIA STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW,COMBINED)
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)
1-4
5
6
115
239
210
18-10
55
1948
1960
1975
TANG
TANG
NA
128.5
NO
NO
2.6
2.6
OIL
11000
11000
BURNING
8.0
8.0
UNIT
WET
SLUICE
POND/ON-SITE
1
2
3
TRUCK ¦
ESP
ESP
NA
1972
1970
0.07
0.11
98.0
97.0
2.9
2.9
54.7
116.6
145
750
377
155
390
289
7-44
-------
unit 5 were placed behind the unit to the north of the switchyard and the
storage building. The limestone preparation/storage area and waste handling
area were placed in an area remote from the absorbers east of the plant. A
10 percent general facilities was assigned to units 1-4 because of the
entrance road relocation and 8 percent was assigned to unit 5 for general
facilities due to relocation of a plant road.
Absorbers for units 1-4 were located close to the units in a high
access/congestion area surrounded by a chimney, the coal pile, the coal
conveyor, and the switchyard. Unit 5 absorbers were located in an open
space to the north side of the switchyard with few access/congestion
problems.
Because the absorbers for units 1-4 are located close to the chimney,
short duct lengths would be required (less than 300 feet). Absorbers for
unit 5 were located away from the chimney and north of the switchyard.
Because the chimney is between the boiler and the ESPs, a duct length of
about 500 feet was required with a high site access/congestion factor.
The LSD-FGD technology considered was LSD with reuse of the existing
ESPs for units 1-4. Because the unit 5 ESPs are small (SCA -155) reuse of
the existing ESPs would not be possible. Unit 5 burns a high sulfur coal;
as such, LSD with a new baghouse option was not considered. LSD absorbers
for units 1-4 would be located in the same location as conventional FED
absorbers and would have similar site access/congestion factors. Less than
600 feet and about 700 feet of duct lengths would be required for units 1-2
and 3-4, respectively, to be able to reuse the ESPs. A high access/
congestion factor was assigned for ESP upgrades and for flue gas handling
due to space limitation around the ESPs created by the chimney and
switchyard.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 7.2.4-2 and 7.2.4-3.
Table 7.2.4-4 presents the capital and operating costs for commercial FGD
technologies. The low cost FGD option shows the reduced capital cost that
occurs when eliminating spare absorbers and maximizing absorber size.
7-45
-------
TABLE 7.2.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR MEREDOSIA
UNIT 1,2,3 OR 4
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE (1-2)
300-600
ESP REUSE 3-4)
600-1000
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST
(1000$)
299
NA
299
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST
(10,00$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.55
NA
ESP REUSE CASE (1,2; 3,4)
1.69,1.83
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10
7-46
-------
TABLE 7.2.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR MEREDOSIA
UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 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$)
2047
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.46
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
0
7-47
-------
Table 7.2.4-4. Summary of FSD Control Costa for the Meredosia Plant ' {June 1988 Dollars)
ixastB»H8isasississsiassuisiB3BBasiasasBsss:ssssss35ssssssssssss5xss:ss:~~«s=Bs;ssss£3ss;ssxaB88as:ss»s«2si
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annuel 502 $02 S02 Cost
Ntmber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Dffficulty (MW> (X) Content (SMM) (J/kU) (SKH) (mUls/kuh) (X) (tons/yr) (S/tcn)
Factor (X)
t/S FGD
L/S FSD
1*4
5
1.55
1,46
115
239
15
' 55
2.6
2.6
55.7
76.0
484.1
317.8
20.8
35.1
137.6
30.5
.90.0
90.0
3152
24021
6598.2
1461.4
L/S FGD-C
l/S FG0-C
1-4
5
1.55
1.46
115
239
15
55
2.6
2.6
55.7 484.1
76.0 317.8
12.2 -
20.5
80.5
17.8
90.0
90.0
3152
24021
3859.5
851.5
IC FED
LC FG0
1-4
5
1.55
1.46
115
239
15
55
2.6
2.6
38.9
59.0
338.1
247.0
15.3
29.6
100.9
25.7
90.0
90.0
3152
24021
4839.2
1230.2
LC FGD-C
LC FG0-C
1-4
5
1.55
1.46
115
239
15
55
2.6
2.6
38.9
59.0
338.1
247.0
8.9
17.2
59.0
14.9
90.0
90.0
3152
24021
2827.9
715.8
LSD+ESP
ISD*ESP
1. 2
3, 4
1.69
1.83
29
29
18
10
2.6
2.6
10.7 367.9
11.4 392.0
5.8 126.4
5.9 232.2
76.0
76.0
809
449
7149.0
13128.9
LSD+ESP-C
LSD+ESP-C
1, 2
3, 4
1.69
1.83
29
29
18
10
2.6
2.6
10.
11.
367.9
392.0
3.4
3.4
73.5
135.0
76.0
76.0
809
449
4155.0
7635.5
7-48
-------
Coal Switching and Blending--
Table 7.2.4-5 presents the IAPCS results for CS at the Meredosia plant.
These costs do not include reduced pulverizer operating costs or system
modifications that may be necessary to handle deep cleaned coal. PCC was
assumed to occur at the nine and was not evaluated here.
Low N0X Combustion--
Units 1-5 are dry bottom, tangential-fired boilers. The combustion
modification technique applied to boilers 1-5 was OFA. Tables 7.2.4-6 and
7.2.4-7 present the performance and cost results of retrofitting OFA at the
Meredosia plant.
Selective Catalytic Reduction--
For units 1-4, the cold side reactors were located beside the chimney
in an area of low access/congestion and 150 feet of duct length was
estimated for the flue gas handling system. For unit 5, about 500 feet of
duct length was required. All reactors were assumed to be in areas with
high underground obstructions. Part of the parking area and a road beside
the unit 1-4 chimney would be relocated for placement of the SCR reactors;
as such, a factor of 20 percent was assigned to general facilities. For
- unit 5, a plant road must be relocated; therefore, 15 percent was assigned
to general facilities. The ammonia storage system was placed northeast of
the switchyard beside the sorbent preparation area.
Table 7.2.4-6 presents the SCR retrofit results for all units.
Table 7.2.4-7 presents the cost results for retrofitting SCR at this plant.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of DSD and FSI technologies at Meredosia plant would be
possible for units 1-4 if the first ESP section could be modified to provide
sufficient duct residence time for humidification or sorbent injection.
Retrofit of DSD and FSI with reuse of the existing ESPs would not be
possible for unit 5 because of the small SCA (<20Q) and insufficient duct
residence time.
Table 7.2.4-8 presents a summary of site access/congestion factors,
scope adders, and plant retrofit factors for DSD and FSI technologies at the
7-49
-------
Table
7.2.4-5
Summary of Coal
Switching/Cleaning Costs
for the Meredosia Plant
(June 1988 Dollars)
Technology
Boiler
'¦¦S 331ES mm
Miiri
IfSlllIXIlSSlIllllllllK
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
SQ2
S02 Cost
Munber Retrofit
size
Factor
Sulfur-
cost
Cost
Cost
Cost
Removec
Removed
Effect.
Difficulty (MU)
TO
Content
(SMH)
(S/kW)
(SMM)
(mi Lls/kuh)
m
(tons/y)
(S/ton)
. .
.......
. . .
Factor
.......
m
........
........
.......
.....
...«•»•
........
CS/I+S15
1,
2
1.00
29
18
2.6
1.8
62.9
1.2
25.7
69.0
730
1611.9
CS/B+S15
3,
4
1.00
29
10
2.6
1.8
62.9
0.9
34.2
69.0
405
2141.4
CS/8+S15
5
1.00
239
55
2.6
9.6
40.1
17.5
15.2
69.0
18375
949.8
CS/B+S1S-C
1,
2
1.00
29
18
2.6
1.8
62.9
0.7
14.9
69.0
730'
934.6
CS/B+S15-C
3,
4
1,00
29
10!
2.6
1.8
62.9
' 0.5
19.9
69.0
405
1247.0
CS/8+S15-C
5
1.00
239
55
2.6
9.6
40.1,
10.0
8.7
69.0
18375
546.5
CS/B*$5
1,
2
1.00
29
18
2.6
1.5
52.5
0.7
16.3
69.0
730
1022.1
CSfS*K
3,
4
1.00
29
10
2.6
1.5
52.5
0.6
23.8
69.0
405
1493.6
CS/B+S5
5
1.00
239
55
2.6
7.1
29.8
7.5
6.5
69.0
18375
408.6
CS/B+S5-C
1,
2
1.00
29
18
2.6
1.5
52.5
0,4
9.5
69.0
730
594.9
CS/B*J5-C
3,
4
1.00
29
10
2.6
1.5
52.5
0.4
13.9
69.0
405
872.5
CS/B+S5-C
5
1.00
239
55
2.6
7.1
29.8
4.3
3.8
69.0
18375
235.8
ssss-xasxx.
________
sssism:
_________
________
==*====
SSSSSS3BSS3
5SSSSSS
7-50
-------
TABLE 7.2,4-6. SUMMARY OF NOx RETROFIT RESULTS FOR MEREDOSIA
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1-4
5
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA
128.5
BOILER INSTALLATION DATE
1948
1960
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
30
. 52
New Duct Length (Feet)
150
500
New Duct Costs (1000$)
807
4125
New Heat Exchanger (1000$)
2027
3144
TOTAL SCOPE ADDER COSTS (1000$)
2863
7320
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
15
7-51
-------
Table 7.2,4-7. NOx Control Cost Results for the Meredosia Plant • tJme 1938 Dollars)
ssB3S555ssssss»sss3SSsaitsis»aiii8iBSfi889Biissis»iiasiiaasaESSSSSSSsassassssiBiS8iaa8SS8sas8sS3sss==:=;=::::s
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx MQx Cost
Nuttier
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficylty (HW)
m
Content
(SUM)
(S/kW
(SUM)
(mills/kwh)
«>
Factor
cx>
LNC-OFA
1,2
1.00
29
18
2.6
0.4
13.0
0.1
1.8
25.0
39
2102.2
LNC-OFA
3,4
1.00
29
10 .
2.6
0.4
13.0
0.1
3.2
25.0
22
3784.0
LNC-OFA
5
1,00
239
55
2.6
0.9
3.7
0.2
0.2
25.0
987
194.3
INC-OFA-C
1,2
1.00
29
18
2.6
0.4
13.0
0.0
1.1
25.0
39
1247.6
LNC-OFA-C.
3,4
1.00
29
10
2.6
0.4
13.0
0.0
1.9
25.0
22
2245.6
LNC-OFA-C
5
1.00
239
55
2.6
0.9
3.7
0.1
0.1
25.0
987
115.3
SCR-3
1-4
1.16
115
15
2.6
2D.7
180.0
.6.7
44.6
80.0
415
16250.8
SCR-3
5
1.16
239
55
2.6
37.9
158.6
12.8
11.1
80.0
3159
4063.8
SCR-3-C
1-4
1.16
115
15
2.6
20.7
180.0
4.0
26.2
80.0
415
9534.4
sca-3-c
5
1.16
239
55
2.6
37.9
158.6
7.5
6.5
80.0
3159
2382.1
SCR-7
1-4
1.16
115
15
2.6
20.7
180.0
5.8
38.2
80.0
415
13941.2
SCR-7
5
1.16
239
55
2.6
37.9
158.6
10.8
9.4
80.0
3159
3434.0
SCR-7-C
1-4
1.16
115
" 15
2.6
20.7
180.0
3.4
22.5
80.0
415
8211.3
SCR-7-C
5
1.16
239
55
2.6
37.9
158.6
6.4
5.5
80.0
3159
2021.2
7-52
-------
TABLE 7.2.4-8.
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MEREDOSIA UNIT 1, 2, 3 OR 4
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$) 299
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST ,(1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 12
TOTAL COST (1000$)
ESP UPGRADE CASE 311
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
7 - 53
-------
Meredosia steam plant. Table 7.2.4-9 presents the cost estimated to retrofit
DSD and FSI at the Meredosia plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Boilers 1-5 at Meredosia would be considered good candidates for
repowering or retrofit because of their small sizes. However, the
congestion at this site will increase the cost of any major construction
effort.
7.2.5 Newton Steam Plant
The Newton steam plant is located within Jasper County, Illinois, as
part of the Central Illinois Public Service Company system. The plant
contains two coal-fired boilers with a total gross generating capacity of
1,165 MW. Figure 7.2.5-1 presents the plant plot plan showing the location
of all boilers and major associated auxiliary equipment.
Table 7.2.5-1 presents operational data for the existing equipment at
the Newton plant. Unit 1 is equipped with an FGD unit and unit 2 burns a 1ow
sulfur NSPS compliance coal. Coal shipments are received by railroad and
conveyed to a coal storage and handling area located west of the plant.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit. The fly ash handling system is dry.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 7.2.5-1 shows the general layout and location of the FGD control
system. Unit 1 has an FGD system and the process is dual-alkali built by
General Electric Environmental Services. The absorbers for L/LS-FGD and
LSD-FGD for unit 2 would be located between the powerhouse and chimney in a
large open area. No demo!ition/relocation would be required; therefore, a
factor of 5 percent was assigned to general facilities. The existing
limestone storage/handling area and waste handling area for unit 1 would be
expanded and used for unit 2 also.
7-54
-------
Table 7.2.4-9. Summary of DSD/FSI Control Costs for the Heredosia Plant (June 1988 Dollars)
Technology Boitsr Main loiter Capacity Coal
Number Retrofit Size- factor Sulfur
Difficulty (MW) (%) Content
Factor (X)
Capital Capital Annual
Cost Cost Cost
(SMM) (S/kU) (SW4)
Annual SQ2 S02 S02 Cost
Cost Removed Removed Effect,
(mi IIs/kwh) (%) (tons/yr) (l/ton)
D5D+ESP
DSD+ESP
DSD+ESP-C
OSD+ESP-C
FSI+ESP-50
FSi+ESP-50
FSl+ESP-70
F5I+ESP-7Q
FSI+ESP-70-C
FS1+ESP-70-C
1, 2
3, 4
1, 2
3, 4
1, 2
3, 4
FSt+ESP-50-C 1, 2
FSI+ESP-5Q-C 3, 4
1, 2
3, 4
1, 2
3, 4
00
QD
00
00
00
0Q
00
00
.00
.00
.00
.00
29
29
29
29
29
29
29
29
29
29
29
29
18
10
18
10
18
10
18
10
18
10
18
10
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
2.6
4.3
4.6
4.3
4.6
5.1
5.1
148.7
158.8
148.7
158.8
5.1 174.3
5.1 174.3
174.3
174.3
5.1 177.4
5.1 177.4
5.1
5.1
177.4
177.4
3.9
3.9
2.2
2.2
2.9
2.7
1.7
1.6
2.9
2.7
1.7
1.6
85.0
151.7
49.1
87.7
62.5
106.8
36.3
62.1
63.2
107.9
36.7
62.7
49.0
49.0
49.0
49.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
516
287
516
287
530
294
530
294
742
412
742
412
7538.8
13450.8
4356.8
7778.8
5394.1
9215.1
3133.2
5356.5
3894.0
6647.5
2262.1
3864.6
7-55
-------
Not to scale
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NHj Storage System
SCR Boxes
Figure 7.2.5-1. Newton plant plot plan
7-56
-------
TABLE 7.2.5-1. NEWTON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
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
FGD SYSTEM
INSTALLATION DATE
FGD TYPE
590
50
1977
TANG
2.4
11618
10.8
575
29
1982
TANG
0.6
1130
6.3
DRY DISPOSAL
ON-SITE LANDFILL
1 2
RAILROAD
YES NO
1979
DUAL ALKALI -
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMMISION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS FLOW (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
1977
1982
0.05
0.07
99.2
99.8
4.0
4.0
642.6
783.4
2290
2771.4
280
282
310
310
7-57
-------
Retrofit Difficulty and Scope Adder Costs--
A low site access/congestion factor was assigned to the absorber
locations due to the absorbers being located in an open area close to the
chimney with no major obstacles or obstructions.
For flue gas handling, a short to moderate duct run for the unit would
be required for L/LS-FGD cases to divert the flue gas from the boiler to the
absorbers and back to the chimney. A low site access/congestion factor was
assigned to the flue gas handling system due to no major obstacles or
obstructions in the surrounding area.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 7.2.5-2. No large scope adder cost
is required for the Newton plant. The overall retrofit factor determined for
the L/LS-FGD cases was low (1.24).
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. The technology evaluated at Newton was LSD with ESP reuse.
This technology was selected because of the moderate SCA size (>280). For
flue gas handling for LSD cases, a moderate duct run would be required to
divert flue gas from the upstream of the ESPs to the absorbers and back to
the ESPs. A low site access/congestion factor was assigned to the LSD-FGD
flue gas handling system. The retrofit factor determined for the LSD
technology case was low (1.27) and did not include particulate control
upgrading costs. A separate retrofit factor was developed for upgrading the
ESPs and was low (1.16) due to the available space around the ESPs. This
factor was used in the IAPCS model to estimate particulate control costs.
Table 7.2.5-3 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boiler 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, and optimization
of scrubber size..
It is unlikely that unit 2 would remain firing a low sulfur coal if
retrofit of FGD was desired. If the unit was switched to burning the coal
fired at unit 1, the annual cost would increase by 18 percent and the SO^
cost effectiveness would decrease by 70 percent.
7-58
-------
TABLE 7,2.5-2. SUMMARY OF RETROFIT FACTOR DATA FOR NEWTON UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
LOW
LOW
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
100-300
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.24
1.24
ESP REUSE CASE
1.27
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
5
5
7-59
-------
Table 7.2.5-3. Sumwry of F6D Control Costs for the Newton Plant (June 1988 Dollars)'
3S-SSSSSS18SRS38SSSS3SSSSSH«8S3S383ISS»!S8SSS8HSS8SSHS8SSRaSHaS888SSSS-Kasa&ISSaSS8SaSS8SSa8HBS»:SSSa8S8&aSSa88=S
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annuai SOS S02 S02 Cost
Nimtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (MW) <%> Content <$*M) C$/kU) (MM) (tans/yr) (S/ton)
Factor (%)
L/S FGD 2 1,24 575 29 0.6 100.4 174.6 40.6 27.8 90.0 ¦ 6604 6151.5
L/S FGD-C 2 1.24 57* ' 29 0.6 100.4 174.6 23.7 16.2 90.0 6604 3592.6
IC FGD 2 1,24 575 29 0.6 79.7 138.7 33.9 23.2 90.0 6604 5133.3
IC FGC-C 2 1.24 575 29 0.6 . 79.7 138.7 19.8 13.5 90.0 6604 2995.2
ISD+ESP 2 1.27 575 29 0.6 56.5 98.3 21.5 14.7 76.0 S599 3841.7
LSD+ESP-C 2 1.27 575 29 0.6 56.5 98.3 12.6 8.6 76.0 5599 2246.3
¦ tasSS=S===-==-S:3SS3SS3S3S55?S;=SSSSSSS;;SSS-SS&SSS3SSSS:S
7-60
-------
Coal Switching Costs--
Newton plant unit 1 has an FGD system and unit 2 has already switched to
a low sulfur coal and, as such, they would not be considered in this study.
NO Control Technology Costs--
This section presents the performance and costs estimated for
N0X controls at the Newton steam plant. These controls include LNC
modification and SCR. The application of N0X control technologies is
determined by several site-specific factors which are discussed in Section 2.
The N0X technologies evaluated at the steam plant were: OFA and SCR.
Low N0X Combustion--
Units 1 and 2 are dry bottom, tangential-fired boilers rated at 590 and
575 MW, respectively. The combustion modification technique applied for this
evaluation was OFA. As Table 7.2.5-4 shows, the OFA N0X reduction
performance for each unit was estimated to be 25 percent. This reduction
performance level was assessed by examining the effects of heat release rates
ad furnace residence time on N0x reduction through the use of the simplified
N0X procedures. Table 7.2.5-5 presents the cost of retrofitting OFA at the
Newton boilers.
Selective Catalytic Reduction-
Table 7.2.5-4 presents 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 FGD
absorbers for unit 1 and from the ESPs for unit 2 to each reactor and from
each reactor to the chimney.
The SCR reactor for unit 1 would be located to the west of the FGD
absorbers for unit 1 in an open area with no major obstacles; whereas, the
SCR reactor for unit 2 would be located between the powerhouse and the
chimney in a large open area. Because both reactors are in relatively open
areas with no major obstructions, the reactors for units 1 and 2 were
assigned low access/congestion factors. A general facility factor of
17 percent was assigned to the reactor for unit 1 because a road would need
7-61
-------
TABLE 7.2.5-4. SUMMARY OF NOx RETROFIT RESULTS FOR NEWTON
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
10.7
10.7
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
72.8
72.8
FURNACE RESIDENCE TIME (SECONDS)
3.94
3.7
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$)
102
100
New Duct Length (Feet)
300
300
New Duct Costs (1000$)
4199
4136
New Heat Exchanger (1000$)
5407
5324
TOTAL SCOPE ADDER COSTS (1000$)
9708
9560
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
17
13
7-62
-------
Table 7.2.5-5. MO* Control Cost Results for the Newton Plant (June 1968 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx MQx Cost
Nimcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed , Effect.
Difficulty (MU) (X) Content (MM) (SAW) <$HH) (mills/kuh) (tons/yr) (S/ton)
Factor <%)
INC-OFA
LNC-OFA
1.00
1.00
590
575
50
29
1.3
1.2
2.1
2.2
0.3
0.3
0.1
0.2
25.0
25.0
2080
1176
132.2
231.6
UC-QFA-C
LNC-OFA-C
1.00
1.00
590
575
50
29
2.4
0.6
1.3
1.2
2.1
2.2
0.2
0.2
0.1
0.1
25.0
25.0
2080
1176
78.5
137.4
SCR-3
SCR-3
SCR-3-
SCR-3-
SCR-7
SCR-7
SCR-7-C
SCR-7-C
1.16
1.16
1.16
1.16
1.16
1.16
1.16
1.16
590
575
590
575
590
575
590
575
50
29
50
29
50
29
50
29
2.4
0.6
2.4
0.6
2.4
0.6
2.4
0.6
72.5
70.1
72.5
70.1
72.5
70.1
72.5
70.1
22.9
22.0
22.9
22,0
22.9
22.0
22.9
22.0
26.6
25.2
15.6
14.8
21.8
20.5
12.8
12.0
10.3
17.3
6.0
10.1
8.4
14,0
5.0
8.2
80.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
6657
3763
6657
3763
6657
3763
6657
3763
4001.5
6702.3
2341.4
3923.5
3269.3
5440.7
1922.2
3200.7
¦I1ISIVSISIS
SB SSS S3 ~ S3 S
7-63
-------
to be relocated. 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. For unit 1, the results
for SCR presented in Table 7.2.5-4 would remain unchanged since N0X is the
only pollutant needed to be controlled, for unit 2, the FGD absorbers,were
located in the same area as the SCR reactors. If both SQ„ and NO emissions
L X
needed to be reduced for this unit, the SCR reactor would have to be located
downstream of the FGD absorbers (i.e., south of the chimney for unit 2) in
an area having little obstructions and easy access. A low access/congestion
factor again would be assigned to this SCR reactor. Table 7.2.5-5 presents
the estimated cost of retrofitting SCR at the Newton 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 were located in a
similar fashion as LSD-FGD. The retrofit of FSI technology at the Newton
steam plant for unit 2 would be easy. The ESPs are located in a low site
access/congestion area and the upgraded ESPs could handle the increased load
from FSI. A low retrofit factor (1.13) was assigned to the upgraded ESPs
location for FSI. However, a combined particulate and SOj removal concept
provides an alternative and low cost method to the new baghouse option. The
ESPs can be used not only to collect particulate matter but to remove SO^ as
well (E-S0X technology). Table 7.2.5-6 presents a summary of the site
access/congestion factors for DSD and FSI technologies at the Newton steam
plant. Table 7.2.5-7 presents the cost estimated to retrofit DSD and FSI at
the Newton plant.
7-64
-------
TABLE 7,2.5-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NEWTON UNIT 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$) 111
TOTAL COST (1000$)
ESP UPGRADE CASE 111
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
7-65
-------
Table 7.2.5-7, Surmary of DSC/FSI Control Costs for tht Newton Plant !Jure 1988 Dollars)
Kicssss:s:s:s:3ssss=ss:::sss::ss=iiKiaf:ss3siiiii»as3iiiiiiisii::ss:ssaaiaaisiiiiiziiis3iiiiisisHiiii=s=s3Esss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annuel Annual $02 SOS SQ2 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) <%) Content (SUM) (S/kU) CSMM) (raills/kuh) (*)
-------
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 Newton plant. The unit 2 boiler would not be considered
a good candidate for AFBC retrofit because of its large size (575 MW).
7-67
-------
7.3 COMMONWEALTH EDISON COMPANY
7.3.1 Joliet 29 Steam Plant
Although retrofit factors were developed for units 7 and 8 at the Joliet
29 plant, costs are not presented since the low sulfur coal being fired would
result in low captial/operating costs and high cost per ton of S02 removed.
CS was not evaluated because the plant is currently burning a low sulfur
coal. Sorbent injection technologies (FSI and DSD) were not considered for
any boilers at the Joliet 29 plant due to the short duct residence time
between the boilers and their respective ESPs and the small sizes of the
ESPs.
TABLE 7.3.1-1. JOLIET 29 STEAM PLANT OPERATIONAL DATA *
UNIT NUMBER
7
8
BOILER NUMBER
71,72
81,82
GENERATING CAPACITY (MW/UNIT)
550
550
CAPACITY FACTOR (PERCENT)
30
29
INSTALLATION DATE
1965
1966
FIRING TYPE
TANGENTIAL
FURNACE VOLUME (1000 CU FT)
510
510
LOW NOx COMBUSTION
NO
NO
COAL SULFUR CONTENT (PERCENT)
0.44
0.45
COAL HEATING VALUE (BTU/LB)
9500
9500
COAL ASH CONTENT (PERCENT)
6.7
6.7
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
PAID/OFF-
•SITE
STACK NUMBER
1
2
COAL DELIVERY METHODS
TRAIN
PARTICULATE CONTROL
.TYPE
ESP
ESP
INSTALLATION DATE
1965
1966
EMISSION (LB/MM BTU)
0.03
0.04
REMOVAL EFFICIENCY
99.2
98.87
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
NA
NA
SURFACE AREA (1000 SQ FT)
139.4
139.4
EXIT GAS FLOW RATE (1000 ACFM)
856.3
856.3
SCA (SQ FT/1000 ACFM)
163
163
OUTLET TEMPERATURE (*F)
287
287
* Some information was obtained from plant personnel.
7-68
-------
TABLE 7.3,1-2. SUMMARY OF RETROFIT FACTOR DATA FOR JOLIET 29
UNIT 7 OR 8 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 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
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
3850
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.44
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT) 10
0
10
L/S-F6D absorbers, LSD-FGD absorbers, and new FFs would be
located northeast of the unit 7 chimney for unit 7 and
southwest of the unit 8 chimney for unit 8.
7-69
-------
TABLE 7.3,1-3. SUMMARY OF NOx RETROFIT RESULTS FOR JOLIET 29
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
71,72,81,82
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 510
BOILER INSTALLATION DATE 1965
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS *
UNIT NUMBER 7 OR 8
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000S) 0
Ductwork Demolition (1000$) 97
New Duct Length (Feet) 200
New Duct Costs (1000$) 2687
New Heat Exchanger (1000$) 5184
TOTAL SCOPE ADDER COSTS (1000$) 7967
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 38
* Cold side SCR reactors for unit 7 would be located behind the
unit 7 chimney, and the reactors for unit 8 would be located
behind the unit 8 chimney.
7-70
-------
Table 7.3.1-4, NCx Control Cost Results for the Joliet 29 Plmt (Jurs# 1988 Dollars)
Technology Bofler Main Soiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost . Cost Removed Removed Effect.
Difficulty im (X) Content (IMH) (S/kU) CWN) {mills/kyh) <%) Ctons/yr) (i/tonj
Factor (%}
INC-OFA
LNC-DFA
71,72 1.00
81,82 1.00
225
225
30
29
0.4
0.4
0.9
0.9
3.3
3.8
0.2
0.2
0.3
0.3
25.0
25.0
600
580
308.6
319.3
LNC-OFA-C
INC-OFA-C
71,72
81,82
.00
.00
225
225
30
29
0.9
0.9
3.S
3.8
0.2
0.2
25.0
25.0
600
580
183.2
189.6
SCR-3
SCR-3
1.34
1.34
550
550
30
29
77.7
77.7
141.3
141,3
27.0
27.0
16.7
19.3
80.0
80.0
4692
4535
5765.7
5957.8
SCR-3-
SCR-3-
1.34
1.34
550
550
30
29
77.7
77.7
141.3
141.3
15.8
15.8
11.0
11.3
80.0
80.0
4692
4535
3377.6
3490.2
SCR-7
SCR-7
1.34
1.34
550
550
30
29
0.4
0.4
77.7
77.7
141.3 22.4
141.3 22.3
15.5
16.0
80.0
80,0
4692
4535
4768.5
4926.2
SCR
SCR
1.34
1.34
550
550
30
29
0.4
0.4
77.7
77.7
141
141
13.2
13,1
9.1
9,4
80.0
80.0
4692
4535
2806.3
2899.2
7-71
-------
7.3.2 Kirtcaid Steam Plant
The Kincaid steam plant is located within Christian County, Illinois, as
part of the Commonwealth Edison Company system. The plant contains two
coal-fired boilers with a total gross generating capacity of 1,182 MW
(originally designed for 1,320 MW). Figure 7.3.2-1 presents the plot plan
used in the evaluation.
Table 7.3.2-1 presents operational data for the existing equipment at
the plant. Both boilers burn high sulfur coal (3.3 percent sulfur). Coal is
conveyed from a nearby mine to the storage/handling area located west of the
plant.
Particulate matter emissions for the boilers at Kincaid are controlled
with retrofit ESPs located behind (south) the old ESPs/chimneys. Fly ash
from the boilers is handled dry and disposed of in an adjacent mine (coal
source).
Lime/Limestone and Lime Spray Drying F6D Costs-
Figure 7.3.2-1 shows the general layout and location of the FGD control
system. The absorbers for the boilers were located south of the powerhouse
and adjacent to the existing retrofit ESPs for both I/IS and LSD-FGD
technologies. The limestone preparation/storage area was placed to the east
of the absorber for unit 2, west of the run-off storage basin and standby
pond. The waste handling area was temporarily located to the west of the
unit 1 absorber. Since the employee parking area would be relocated in order
to make more space available for the location of the absorbers in the
location discussed above, a factor of 10 percent was assigned to general
facilities.
Retrofit Difficulty and Scope Adder Costs--
At the Kincaid plant the boilers are located west to east, side by side,
and the retrofit ESPs sit directly behind (south) the old chimneys for each
unit. A recently built chimney is shared by both units.
The absorbers were located in a general area south of the plant. They
were located, more specifically, on both sides (west and east) of the
retrofit ESPs. In addition, the absorber for unit 1 was located west of
7-72"
-------
Crusher House
Discharge
£23
NM, Storage ume'Limestone .
System StoraQe/Preparation
Area
FGO Was!# Handling/A&sorBer Area
Lime/Limestone Storage/Preparation Area
nm, Storage System
SCR Soxes
Not to scale
Figure 7.3.2-1. Kincaid plant plot plan
7-73
-------
TABLE 7.3.2-1. KINCAID 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
591
46, 39
1967,68
CYCLONE
436
NO
3.3
10300
9.9
PAID DRY DISPOSAL
OFF-SITE
1
CONVEYOR
NEARBY COAL MINE
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1967,1982
EMISSION (LB/MM BTU) 0.05
REMOVAL EFFICIENCY 98.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 4.0
SURFACE AREA (1000 SQ FT) 851.6
GAS EXIT RATE (1000 ACFM) 2400
SCA (SQ FT/1000 ACFM) 355
OUTLET TEMPERATURE (eF) 310
7-74
-------
the unit ESPs and the absorber for unit 2 was located to the east of its
respective ESPs. Neither absorber would be congested by any major
equipment, plant roads, etc.
Low site access/congestion factors were assigned to both absorber areas
for all FGD technologies because no significant obstacles would surround the
absorbers and no underground obstructions appear to exist in the designated
location. Also, low site access/congestion factors were assigned to flue gas
handling for both boilers for all FGD technologies because adequate space is
available around the retrofit ESPs and chimney. A medium ductwork tie-in
distance would be necessary for the retrofit of FGD technologies at the
plant.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Table 7.3.2-2. There are no
significant scope adjustments and related costs required for the retrofit of
FGD control technologies at Kincaid. The overall retrofit factors determined
for the L/LS-FGD cases were low to moderate (1.31).
The LSD with ESP reuse was the only LSD-FGD case evaluated because the
SCAs are large (468). The overall retrofit factor determined for the LSD-FGD
cases was also low (1.27) excluding particulate control costs. The
particulate control upgrade factor was low (1.16), reflecting the space
available around the existing ESPs. This factor would be used in the IAPCS
model if any additional plate area increase is required.
Table 7.3.2-3 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs 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, and optimization of scrubber size. However, there might be higher
operating risks associated with this approach.
Coal Switching and Physical Coal Cleaning Costs--
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, tube
erosion, and coal rate. However, without an ash analysis for the
existing and switch coals, boiler derate or capacity increase cannot be
7-75
-------
TABLE 7.3.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR KINCAID UNITS 1-2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE LOW
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NO NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER (WASTE DISPOSAL) YES NO YES
RETROFIT FACTORS
FGD SYSTEM 1.41 1.31
ESP REUSE CASE 1,37
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 IP
7-76
-------
Table 7.3,2-3. Sunnry of FGO Control Costs for the Kfncaid Plant (June 1988 Dollars)
¦¦sasass9iais3s83sssaaa3issaaaaasisa9assssss3ss33ss:s3ssssss3s«;sisssssss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual tanual S02 SOI S02 Cost
Nuitier Retrofit Size Factor Sulfur Cost Cost Coat Cost Removed Removed Effect.
Difficulty
-------
determined. This is particularly true for cyclone boilers; therefore, coal
switching was not evaluated for the Kincaid plant.
Table 7.3.2-4 presents the IAPCS results for physical coal cleaning at
the Kincaid plant. These costs do no include reduced pulverizer operating
costs or system modifications that may be necessary to handle deep cleaned
coal.
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at Kincaid. These controls include LNC and SCR.
The application of N0X control technologies is affected by several
site-specific factors which are discussed in Section 2. The NQX technologies
evaluated for the Kincaid station were: NGR and SCR.
Low N0X Combustion--
Units 1 and 2 are wet bottom, cyclone-fired boilers rated at 591 MW
each. The combustion modification technique applied to these units was NGR.
Neither OFA nor LNB are applicable as N0X combustion controls for cyclone
boilers. As Table 7.3.2-5 shows, the NGR N0X reduction performance for each
unit was assumed to be 60 percent. Table 7.3.2-6 presents the cost of
retrofitting NGR at the Kincaid plant.
Selective Catalytic Reduction-
Table 7.3.2-5 presents the SCR retrofit results for each unit. The
results include process area retrofit difficulty factors and scope adder
costs. The data includes scope adder costs estimated for ductwork
demolition, new 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 reactors for units 1 and 2 were located south of the powerhouse
behind the unit ESPs in a parking lot. This is a low access/congestion area
with no significant underground obstructions. A general facilities factor of
25 percent was applied to both units, reflecting the need to replace part of
the employee parking used to install the SCR reactors. The ammonia storage
system, which would supply ammonia to the reactors to both units, was located
southeast of the powerhouse in a relatively open area with no significant
7-78
-------
Table 7,3.2-4. Surinary of Coal Switching/Cleaning Costs for the Klncald Plant (Juna 1988 Dollars)
58ss8xs:ss3ssss383as3sss5ss3ssssss3393s8ssss:s53s3s33sssss«ssasa:sa3sas3ass3::as3sass3:9sss8ssssssssss:s5sssssss
Technology Sofltr Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 SQ2 cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (t/kW) (mills/kwh) (X) (tona/yr) ($/ton>
Factor (X)
PCC 1 1.00 591 4* 3.3 39.4 66.6 17.4 7.3 23.0 17723 984.3
FCC 2 1.00 591 39 3.3 39.4 66.6 16.3 8.1 23.0 15026 1086.1
PCC-C 1 1.00 591 46 3.3 39.4 66.6 10.2 4.3 23.0 17723 573.9
PCC-C 2 1.00 591 39 3.3 39.4 66.6 9.5 4.7 23.0 15026 634.0
3is3s===33sas=33=3aas3»ss=333333as33ss33aitaasas89aesax
7-79
-------
TABLE 7,3,2-5. SUMMARY OF NOx RETROFIT RESULTS FOR KINCAID
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
FIRING TYPE CYCLONE
TYPE OF NOx CONTROL NGR
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) NA
FURNACE RESIDENCE TIME (SECONDS) NA
ESTIMATED NOx REDUCTION (PERCENT) 60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 102
New Duct Length (Feet) 450
New Duct Costs (1000$) 6304
New Heat Exchanger (1000$) 5412
TOTAL SCOPE ADDER COSTS (1000$) 11819
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 25
7-80
-------
Table 7.3.2-6. NOx Control Cost Results for the icfneaid plant (June 1988 Dollars)
sssssssssssssssssssssasssBsrassssssassssssssssssss&asassssssssasaasaaaasEsaBsaassssasssssssssssssssszsssssssssss
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
NCR
1
1.00
591
46
8.5
14.3
13.5
5.7
60.0
11976
1130.5
NGR
2
1,00
591
39
8.5
14.3
11.6
5.8
60.0
10153
1146.8
NGR-C
1
1.00
59!
46
3.3
8.5
14.3
7.8
3.3
60.0
11976
650.9
NGR-C
2
1.00
591
39
3.3
8.5
14.3
6.7
3.3
60.0
10153
660.8
SCR-3
1
1.16
591
46
3.3
77.0
130.4
28.7
12.1
80.0
15966
1800.2
SCR-3
2
1.16
591
39
3.3
77.0
130.3
28.4
14.0
80.0
13538
2095.0
SCR-3-C
1
1.16
591
46
1.3
77.0
130.4
16.8
7.1
80.0
15968
1053.0
SCR-3-C
'2
1.16
591
39
3.3
77.0
130.3
16.6
8.2
80.0
13538
1225.8
SCR-7
1
1.16
591
46
3.3
77.0
130.4
23.8
10.0
80.0
15968
1489.1
SCR-?-
2
1.16
591
39
3.3
77.0
130.3
23.4
11.6
80.0
13538
1728.1
SCR-7-C
1
1.16
591
46
3.3
77.0
130.4
14.0
5.9
80.0
15968
874.8
SCR-7-C
2
1.16
591
39
3.3
77.0
130.3
13.7
6.8
80.0
13538
1015.6
aasassBssssisss
S883!
3S8&BB8S83
ssasaasi
88IIS8S88388S888
SSBB88S3
SB3=aaa
Banusassua
S33S3SS»»
7-81
-------
underground obstructions. Table 7.3.2-6 presents the estimated cost of
retrofitting SCR at the Kincaid 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 both units were
located south of the plant in a relatively open area in a similar fashion as
LSD-FGD. The retrofit of DSD and FSI technologies at the Kincaid steam plant
would be relatively easy because the ESP SCAs are large (>400) and there is
400 feet of flue gas ducting between the boilers and the retrofit ESPs.
Additionally, the old ESP boxes could be used for the humidification or
sorbent injection. If ESP plate area was required, the ESP upgrade
access/congestion factor would be low (1.13). Table 7.3.2-7 presents a
summary of site access/congestion factors, scope adders, and retrofit factors
for DSD and FSI technologies at the Kincaid steam plant. Table 7,3.2-8
presents the costs estimated to retrofit DSD and FSI at the Kincaid 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 Kincaid plant. The boilers at the Kincaid plant would
not be considered good candidates for AFBC retrofit and AFBC/CG/combined
cycle repowering because of their large size (660 MW).
7-3.3 Powerton Steam Plant
The Powerton steam plant is located within Tazewell County, Illinois, as
part of the Commonwealth Edison Company system. The plant is located
7-82
-------
TABLE 7.3.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR KINCAID UNITS 1-2
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$ 113
TOTAL COST (1000$)
ESP UPGRADE CASE 113
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
7-83
-------
Table 7.3.2-8. Sumary of DSO/FSI Control Costs for the Kincaid Plant (June 1988 Dollars)
Technology. Boilar Main Boilar Capacity Coal Capital Capital Annual
Nuitoer Retrofit Sfie Factor Sulfur Cost Cost Cut
Difficulty (MU) (X) Content (Smm> (t/kW) ISm)
Factor (X)
Annual S02 S02 S02 Cost
Cost Removed Removed Effect.
<¦1lls/kwh) (X) (tora/yr) (S/ton)
DSD*ESP
DSD+ESP •
DSO+ISP-C
DSD*6SP-C
FS1*ESP-5Q
FS1+ESP-50
FS1+ESP-50-C
FSK-ESP-50-C
FSI+ESP-70
FSl+ESP-70
FS1+ESP-70-C
FSI+ESP-70-C
00
00
00
00
00
00
00
00
00
00
00
00
591
591
591
591
591
591
591
591
591
591
591
591
46
39
66
39
46
39
46
39
46
39
46
39
69.9
69.9
69.9
69.9
53.2
53.2
53.2
53.2
53.6
53.6
53.6
53.6
118.2
118.2
118.2
118.2
90.1
90.1
90.1
90.1
90.7
90.7
90.7
90.7
35.0
32.9
20.3
19.2
39.5
35.7
22.9
20.7
40.1
36.2
23.2
21.0
14.7
16.3
a.s
9.5
16.6
17.7
9.6
10.2
16.8
17.9
9.8
10.4
48.0
48.0
48.0
48.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
36000
30522
36000
30522
37776
32028
37776
32028
52887
44839
52887
44839
971.1
1077.4
565.1
627.6
1044.9
1114.0
605.0
645.7
758.4
808.1
439.1
468.3
=3S38S3S=5SSS=SS3!«8888SSaSS3S
:S33XSS3SaXSS8aSSSS3S3SSS33=:at3XS5
7-84
-------
adjacent to a pond beside the Illinois River and contains two steam turbine
units (5,6) powered by four coal-fired boilers with a total gross generating
capacity of 1,784 MW.
Table 7.3.3-1 presents operational data for the existing equipment at
the Powerton plant. The boilers burn low sulfur coal received by railroad
and transferred to a coal storage and handling area northwest of the units
and adjacent to the pond.
PM emissions for the boilers are controlled with ESPs 1ocated behind
each unit. The plant has a dry fly ash handling system. Fly ash is
disposed of off-site. Flue gas from all boilers is ducted to a common
chimney. A retrofit FGD scrubber unit with a new chimney for boiler 51 of
unit 5 is no longer in operation.
Lime/Limestone and Lime Spray Drying FGD Costs--
The four boilers are located beside each other adjacent to the water
channel. The absorbers for all boilers would be located behind and east of
the chimney. The limestone preparation, storage, and handling area would be
located behind the absorbers. Some of the roads have to be relocated;
therefore, a factor of 10 percent was assigned to general facilities. A
temporary waste handling area would be located approximately three quarters
of a mile southwest of the plant. However, because of the limited space
available, waste generated by the FGD absorbers must be transferred off-site
in the same manner as the fly ash.
A low site access/congestion factor was assigned to the FGD absorber
locations due to the accessibility and space availability behind the
chimney. For flue gas handling, because absorbers are placed immediately
behind the chimneys, short duct runs would be required for the L/LS-FGD case
(less than 300 feet). A low site access/congestion factor was assigned to
the flue gas handling system due to easy access to the existing chimney.
LSD with reuse of the existing ESPs was considered for this plant
because the ESPs are adequate (SCA >207) and were assumed not to require
major upgrading to handle the increased PM generated from the LSD
application. The LSD absorbers would be located behind the common chimney.
To route the flue gas from upstream of the existing ESPs to the absorbers
and back to the ESPs, over 700 feet of duct length would be required. A
7-85
-------
TABLE 7.3.3-1. POWERTON STEAM PLANT OPERATIONAL DATA
UNIT NUMBER
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)
5
6
51,52
61,62
446
446
37
42
1972
1975
CYCLONE
CYCLONE
285.4, 271
238, NA
NO
NO
0.6
0.6
9400
9400
4.8
4.8
DRY HANDLING
OFF-SITE
. RAILROAD
1
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 (SF)
ESP
ESP
1972
1975
0.10
0.10
98.6
99.3
0.7
0.7
332
650
1605
1639
207
397
300
300
7-86
-------
high site access/congestion factor was assigned to the flue gas handling
system in the case of LSD-FGD because of the congestion created by the ash
silos, chimney, and close proximity of the ESPs to each other and to the
boiler house.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 7,3,3-2. FGD cost estimates are not
presented because it is unlikely that the current low sulfur coal would be
used if scrubbing was required. FGD cost estimates based on the current
coal would result in low estimates of capital/operating costs and high
cost-effectiveness values. Additionally, it is unlikely that LSD-FGD with
ESP reuse would be applied due to the very high access/congestion associated
with the flue gas ducting and possible long boiler downtime.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for this plant because the plant is
already using a low sulfur coal.
Low N0X Combustion-
All four boilers are cyclone-fired and are rated at 446 MW each. The
combustion modification technique applied to all boilers was NGR. As
Table 7.3.3-3 shows, the NGR N0X reduction performance for each unit was
assumed to be 60 percent. Table 7.3.3-4 presents the cost of retrofitting
NGR at the Powerton plant.
Selective Catalytic Reduction-
Cold side SCR reactors for all boilers would be located immediately
behind the chimney in low access/congestion areas. About 250 feet of duct
length was estimated for the flue gas handling system. The ammonia storage
system was placed close to the reactors east of the plant. No major
equipment relocation would be needed and a base factor of 13 percent was
assigned to general facilities.
Table 7.3,3-3 presents the SCR process area retrofit factors and scope
adder costs. Table 7.3.3-4 presents the estimated cost of retrofitting SCR
at the Powerton boilers.
7-87
-------
TABLE 7.3.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR POWERTON
BOILERS 51,52,61,OR 62
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
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$)
0
0
0
OTHER (WASTE DISPOSAL)
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.30
NA
ESP REUSE CASE
1.57
BAGHOUSE CASE
NA.
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
8
* Chimney liner cost is included
in the
FGD retrofit
evaluation.
7-88
-------
TABLE 7.3.3-3. SUMMARY OF NOx RETROFIT RESULTS FOR POMERTON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
51,52,61,62
FIRING TYPE CYC
TYPE OF NOx CONTROL NGR
FURNACE VOLUME (1000 CU FT) 285.4,271,238,NA
BOILER INSTALLATION DATE 1972-1975
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) 60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 83
New Duct Length (Feet) 250
New Duct Costs (1000$) 2971
New Heat Exchanger (1000$) 4571
TOTAL SCOPE ADDER COSTS (1000$) 7625
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13__
7-89
-------
Table 7,3.3-4. NO* Control Cost Results for the Powerton Plant (June 1968 Dollars)
Technology Bailer Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nurtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU> (X) Content
NGR
NGR
NGR-C
NGR-C
SCR-3
SCR-3
SCR-3-C
SCR-3-C
SCR-
SCR-
51,52 1
61,62 1
51,52 1
61,62 1
51,52 1
61,62 1
51,52 1
61,62 1
51,52
61,62
SCR-7-C
SCR-7-C
51,52 1
61,62 1
00
00
00
00
16
16
16
16
16
16
16
16
446
446
446
446
446
446
446
446
446
446
446
446
37
42
37
42
37
42
37
42
37
42
37
42
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
6.8
6.8
6.8
6.8
56.6
56.6
56.6
56.6
56.6
56.6
56.6
56.6
15.3
'15.3
15.3
15.3
126.9
126.9
126.9
126.9
126.9
126.9
126.9
126.9
8.5
9.6
4.9
5.5
21.2
21.4
12.4
12.5
17.4
17.6
10.2
10.3
5.9
5.8
3.4
3.4
14.6
13.0
8.6
7.6
12.0
10.7
7.1
6.3
60.0
60.0
60.0
60.0
80.0
80.0
80.0
80.0
80
80
80.0
80.0
8074
9165
8074
9165
10765
12220
10765
12220
10765
12220
10765
12220
1055.6
1042.1
608.6
600.4
1965.3
1749.5
1149.5
1023.1
1612.3
1438.5
947.3
844,9
7-90
-------
Duct Spray Drying and Furnace Sorbent lnjection--
The retrofit of FSI and DSD technologies at the Powerton steam plant
would be difficult. This is caused by inadequate duct residence time
between the boilers and the retrofit ESPs for either humidification (FSI
application) or sorbent droplet evaporation (DSD application). However, the
ESPs may be large enough to modify the first ESP section to be used for
humidification or sorbent injection. A high site access/congestion factor
was assigned to the ESP locations if additional plate area or upgrading/
modification of the existing ESPs is required. The sorbent receiving/
storage/preparation area was located east of the plant.
Table 7.3.3-5 presents a summary of the site access/congestion factors
for FSI and DSD technologies at the Powerton plant. Table 7.3.3-6 presents
the costs estimated to retrofit FSI and DSD at the Powerton plant. The
estimated unit costs for all boilers are high because of the low sulfur
content of the coal.
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 Powerton plant. Neither of units would be considered
good candidates for repowering/retrofit because of their large boiler sizes.
7.3.4 Waukegan Steam Plant
L/S-FGD and LSD-FGD retrofit factors were evaluated for boilers 6, 7,
and 8 at the Waukegan plant; however, costs are not presented because the low
sulfur coal currently being fired would yield low capital/operating costs and
high cost per ton of SO^ removed. A new baghouse was used in conjunction
with LSD instead of reusing the existing ESPs, since the ESPs for these
boilers are congested and any upgrading would be difficult. CS was not
evaluated because the plant is using a low sulfur coal. FSI and DSD were not
considered for units 6 and 8 due to the short duct residence time between the
boilers and their respective ESPs and due to the inadequate size of the ESPs.
The unit 7 ESPs appear large enough for the application FSI and DSD, however,
access to these are difficult and were not considered for sorbent injection
technologies.
7-91
-------
TABLE 7.3.3-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR POWERTON BOILERS 51,52,61,62
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 92
TOTAL COST (1000$)
ESP UPGRADE CASE 92
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS "
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
7-92
-------
TabU 7,3.1-6. Suimary of DSO/FSJ Control Costs for the Pewerton Plant (June 1988 Dollars)
ssssssas:::
Technology
Boiler Main Boiler Capacity Coal Capital Capital Annual
Number Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty <*> Content (»«) (1/KU) («H)
Factor (%)
Annual S02 SQ2 SQ2 Cost
Cost Removed Removed Effect,
mi lls/kMh) (X) (tons/yr) (S/ton)
DSO+fSP
BSO+fSP
BSD+ESP-C
DSD+ESP-C
FSl+fSP-50
FSl»ISP-50
FSI*ISP-50-C
FSi*ISP-50-C
FSI+iSP-70
FSt+ESP-70
FSl+fSP-70-C
FSI+ISP-70-C
51,52 1
61,62 1
51,52 1
61,62 1
51,52 1
61,62 1
51,52 1
61,62 1
51,52 1
61,62 1
51,52 1
61,62 1
CM)
00
00
00
00
00
00
00
00
00
00
00
446
466
446
446
446
446
446
446
446
446
446
446
37
42
37
42
37
42
37
42
37
42
37
42
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
16.5
11.3
16.5
11.3
18.2
13.4
18,2
13.4
18.0
13.5
18.0
13.5
37.0
25.3
37.0
25.3
40.8
30.0
40.8
30.0
40.4
30.4
40.4
30.4
9.1
7.9
5.3
4.6
9.1
8.1
5.3
4.7
9.1
8.3
5.3
4.8
49.0
49,0
49.0
49.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
4506
5115
4506
5115
4631
5256
4631
5256
6483
7359
6483
7359
2014.4
1547,9
1570.6
896.7
1957.2
1548.2
1138.9
898.4
1400,4
1122.4
814.8
651.3
7-93
-------
TABLE 7.3.4-1. WAUKEGAN STEAM PLANT OPERATIONAL DATA *
BOILER NUMBER 1-5
GENERATING CAPACITY (MW) RETIRED
CAPACITY FACTOR (PERCENT)
INSTALLATION OATE
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)
6
7
8
112
353
317
7
44
18
1952
1958
1962
CYCLONE TANGENTIAL
43
510
506
NO
NO
NO
0.47
0.4
0.42
9300
9500
9500
5.04
7.4
7.4
DRY DISPOSAL
PAID/OFF-SITE
1
2
3
RAILROAD
ESP
ESP
ESP
1971
1976
1962
0.04
0.024
0.02!
96.88
99.57
99.5
0.5
0.5
0.5
62.5
512.3
151.
430
1700
1051
136
439
134
295
700
284
Some information was obtained from plant personnel
7-94
-------
TABLE 7.3.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR WAUKEGAN UNIT 6
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)
300-600
NA
ESP REUSE
BAGHOUSE
300-600
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
. YES
NA
YES
ESTIMATED COST (1000$)
784
0
784
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.43
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* L/LS-FGD absorbers, LSD-FGD absorbers, and new FFs for unit 6
would be located east of the retired chimney for units 1-5.
7-95
-------
TABLE 7,3.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR WAUKEGAN
UNIT 7 OR 8 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
600-1000
NA
ESP REUSE
BAGHOUSE
600-1000
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
2471,2219
0
2471,2219
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.53
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.54
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers, and new FFs for units 7
and 8 would be located east of the retired chimney for units 1-1.
7-96
-------
TABLE 7.3.4-4, SUMMARY OF NOx RETROFIT RESULTS FOR WAUKEGAN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
6
7
8
FIRING TYPE
CYCLONE
TANG
TANG
TYPE OF NOx CONTROL
NGR
OFA
OFA
FURNACE VOLUME {1000 CU FT)
NA
252
254
BOILER INSTALLATION DATE
1952
1958
1962
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
60
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
29
70
64
New Duct Length (Feet)
400
300
500
New Duct Costs (1000$)
2118
3109
4866,
New Heat Exchanger (1000$)
1995
0
3724
TOTAL SCOPE ADDER COSTS (1000$)
4142
3178
8654
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
38
38
38
* Cold side SCR reactors for unit 6 would be located behind the
unit 6 chimney. Hot side SCR reactors for unit 7 and cold side
SCR reactors for unit 8 would be located behind the unit 7 chimney.
7-97
-------
Table 7.3,4-5. NOx Control Cost Results for the yaukegars Plant (June 1988 Dollars)
ssbss==s=s=
Technology
:s:ss3s=5
3oiler
Main
Boiler Capacity Coal
Capital Capital Annual
:bs«3s::s;s3
Annual
NOx
s==:s;;=ii
NOx
SSSBSSSSS
NOX Cost
Number
Retrofft
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
(S3
Content
(WW)
<$/kU>
(SUM)
-------
7.3.5 Mill County Steam Plant
L/S-FGD and LSD-FGD retrofit factors were developed for the boilers at
the Will County plant; however, costs are not presented since the low sulfur
content of the coal being fired would result in low capital/operating costs
and high cost per ton of SC>2 removed. The boilers already are firing a low
sulfur coal hence CS was not considered. Sorbent injection technologies (FSI
and DSD) were not evaluated due to the short duct residence time between the
boilers and their respective ESPs and due to the difficulty involved in
upgrading the existing ESPs.
TABLE 7.3.5-1. HILL COUNTY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1
2
3
4
GENERATING CAPACITY (MW-each)
167
167
278
542
CAPACITY FACTOR (PERCENT)
9
13
18
34
INSTALLATION DATE
1955
1955
1957
1963
FIRING TYPE
CYCLONE
TANGENTIAL
FURNACE VOLUME (1000 CU FT)
40.6
40.6
200
470
LOW NOx COMBUSTION
NO
NO
NO
NO
COAL SULFUR CONTENT (PERCENT)
0.46
0.46
0.43
0.42
COAL HEATING VALUE (BTU/LB)
9300
9300
9400
9400
COAL ASH CONTENT (PERCENT)
5.2
5.1
7.8
7.8
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
PAID/OFF-SITE
STACK NUMBER
1
2
3 *
4
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL
TYPE
ESP
ESP
ESP
ESP
INSTALLATION DATE
1984
1973
1973
1963
EMISSION (LB/MM BTU)
0.004
0.006
0.02
0.03
REMOVAL EFFICIENCY
99.7
99.6
99.7
98.9
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
0.5
0.5
0.5
0.5
SURFACE AREA (1000 SQ FT)
227.5
248.2
331.2
199.:
GAS EXIT RATE (1000 ACFM)
650
770
1425
1533
SCA (SQ FT/1000 ACFM)
365
322
330
130
OUTLET TEMPERATURE (*F)
320
355
675
286
7-99
-------
TABLE 7.3.5-2. SUMMARY OF RETROFIT FACTOR DATA FOR WILL COUNTY UNIT 1*
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
1169
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.52
NA
ESP REUSE CASE
1.49
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
* L/S-FGD and LSD-FGD absorbers for unit 1 would be located north
of unit I,
7-100
-------
TABLE 7.3.5-3. SUMMARY OF RETROFIT FACTOR DATA FOR WILL COUNTY
UNIT 2 OR 3*
FGD TECHNOLOGY
FORCED LIME
L/LS FGO OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
HIGH ,
NA
ESP REUSE CASE (Unit 2)
HIGH
BAGHOUSE CASE (Unit 3)
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE (Unit 2)
600-1000
BAGHOUSE (Unit 3)
300-600
ESP REUSE (Unit 2)
NA
NA
HIGH
NEW BAGHOUSE (Unit 3)
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
YES (Unit 3)
ESTIMATED COST (1000$)
1169,1946
0
1946
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.52
NA
ESP REUSE CASE (Unit 2)
1.62
BAGHOUSE CASE (Unit 3)
1.56
ESP UPGRADE (Unit 2)
NA
NA
1.58
NEW BAGHOUSE (Unit 3)
NA
NA
1.36
GENERAL FACILITIES (PERCENT) 15
0
15
* L/S-FGD and LSD-FGD absorbers for unit 2 would be located north
of unit 1 and the absorbers for unit 3 would be located south
of unit 4.
7-101
-------
TABLE 7.3.5-4. SUMMARY OF RETROFIT FACTOR DATA FOR WILL COUNTY UNIT 4*
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
3794
0
3794
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.52
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
IS
0
15
* L/S-FGD absorbers, LSD-FGD absorbers, and new FFs for unit. 4
would be located south of unit 4.
7-102
-------
TABLE 7,3.5-5. SUMMARY OF NOx RETROFIT RESULTS FOR WILL COUNTY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
4
FIRING TYPE
CYC
CYC
TANG
TANG
TYPE OF NOx CONTROL
NGR
NGR
OFA
OFA
FURNACE VOLUME (1000 CU FT)
40.6
40.6
200
470
BOILER INSTALLATION DATE
1955
1955
1957
1963
SLAGGING PROBLEM
NO
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
60
60
25
25
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR .
HIGH
HIGH
HIGH
MEDIUI
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
40
40
58
96
New Duct Length (Feet)
200
200
200
300
New Duct Costs (1000$)
1338
1338
1802
3995
New Heat Exchanger (1000$)
2535
2535
0
5138
TOTAL SCOPE ADDER COSTS (1000$)
3913
3913
1861
9230
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
1.34
GENERAL FACILITIES (PERCENT)
38
38
38
38
* Cold side SCR reactors for units 1 and 2 would be located behind
their respective chimnies. Hot side SCR reactors for unit 3 would
be located behind the unit 3 chimney. Cold side SCR reactors for
unit 4 would be located south of unit 4.
7-103
-------
Table 7.3.5-6. NOx Control Cost Results for the yiU County Plant (June 1988 Dollars)
Technology Bofter Main Boiler Capacity Coal Capital Capital Annual Annual NO* NOx NO* Cost
Nuioer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MV) (X) Content (SMO (S/kU) t$*M)
Factor
LNC-OFA
3
1.00
278
18
0.4
0.9
3.4
0.2
0.5
25.0
450
452.8
INC-OFA
4
. 1.00
542
34
0.4
1.2
2.2
0.3
0.2
25.0
1657
160.6
inc-ofa-c
3
1.00
278
18
0.4 ¦
0.9'
3.4
0.1
0.3
25.0
450
268.6
LNC-QFA-C
4
1.00
542
34
0.4
1.2
2.2
0.2
0.1
. 25.0
1657
95.3
NCR
1
¦ 1.00
167
9
0.5
3.3
19.5
1.2
9.0
60.0
810
1468.5
NCI!
2
1.00
167
13
0.5
3.3
19.5
1.5
7.9
60.0
1170
1280.2
NCS-C
1
1.00
; 167
9
0.5
3,3
19.5
0.7
5.3
60.0
810
859.5
NGR-C
2
1.00
167
13
0.5
3.3
19.5
0.9
4.6
60,0
1170
745.9
SCR-3
1
. 1.52
167
9
0.5
33.8
1 202.2
10.7
81.6
80.0,
1080
9940.8
SCR-3
2
1.52
167
13
0.5
34.0
203.8
10.9
57.1
80.0
1560
6963.7
SCR-3
3
1.52
278
18
0.4
46.3
166.5
15.6
35.6
80.0
1440
10822.7
SCR-3
4
, 1.34
542
34
0.4
78.0
143.9
27.3
16.9
80.0
5304
5148.4
SCR-3-C
1
1.52
167
9
0.5
33.8
202.2
6.3
47,9
80,0
1080
5835.5
SCR-3-C
2
1,52
167
13
' 0.5
34.0
203.8
6.4
33.5
80.0
1560
4087.5
SCR-3-C
3
1.52
278
18
' 0.4
46.3
166.5
9.1
20.8
, 80.0
1440
6344.8
SCR-3-C
' 4
1.34
542
34
0.4
78,0
143.9
16.0
9.9
80,0
5304
3015.6
SCR-7
T
1.52
167
9
- 0.5
33,8
202.2
9.3
70.7
80.0
1080
8621.3
SCR -7
• 2
1.52
167
13
0.5
34.0
203.8
9.4
49.6
80.0
1560
6050.1
SCR-7
3
1.52
278
18
0.4
46.3
166.5
13.2
30.2
80.0
1440
9178.2
SCR-7
4
1.34
542
34
0.4
78,0
143.8
22.7
14.1
80.0
5304
4277.8
SCR-7-C
' 1
1.52
167
9
0.5
33.8
202.2
5.5
41.7
80.0
1080
5079.6
SCR-7-C
2
1.52
167
13
0.5
34.0
203.8
5.6
29.2
80.0
1560
3564.1
SCR-7-C
3
1.52
278
18
0.4
46.3
166.5
7.8
17.7
80.0
1440
5402,5
SCR-7-C
4
1.34
542
34
0.4
78.0
143.8
13.3
8.3
80.0
5304
2516.8
7-104
-------
7,4 ELECTRIC ENERGY INCORPORATION
7.4.1 Joppa Steam Plant
The Joppa steam plant is located within Massac County, Illinois, as part
of the Electric Energy system. The plant contains six coal-fired boilers
with a total gross generating capacity of 1,098 MW. Figure 7.4.1-1 presents
the plant plot plan showing the location of the boilers and major associated
auxiliary equipment. An aerial photograph was available for review in the
evaluation.
Table 7.4.1-1 presents the operational data for the existing equipment
at the Joppa plant. All boilers burn medium sulfur coal (2.0 percent
sulfur). Coal shipments are received by freight barge and rail and then
conveyed to a coal storage/handling area located east of the units.
Particulate matter emissions for all six boilers are controlled with
ESPs located behind each unit. Ash from all units is wet sluiced to ponds on
the far side (north) of the coal storage area. Small amounts of the fly ash
go to a nearby cement plant for their use as a raw material. Limited space
is available for future waste disposal; thus, future waste would be disposed
off-site.
Lime/Limestone and Lime Spray Drying FGD Costs--
The Joppa plant includes three chimneys, each shared by two units
located between the existing ESPs. The FGO absorbers were placed between the
existing ESPs and chimneys and the coal storage/handling area. This location
is presently occupied by warehouses. The relocation of the warehouses and
plant roads would be required in order to place the absorbers in this
location. The limestone preparation/storage area was located to the north of
the powerhouses and the waste handling area was placed adjacent to the
preparation/storage area.
Retrofit Difficulty and Scope Adder Costs--
The FGD absorbers for units 1, 2, 5 and 6 were assumed to be in areas of
medium site access/congestion and units 3 and 4 were assumed to be in high
site access/congestion areas. The medium site access/congestion factors
7-105
-------
FGD Waste Handling/Absorber Area
Lime/limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 7.4.1-1. Joppa plant plot plan
7-106
-------
TABLE 7.4.1-1. JOPPA STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-6
GENERATING CAPACITY (MW-each) 183
CAPACITY FACTOR (PERCENT) 13, 15
FIRING TYPE TANG
INSTALLATION DATE 1953-55
COAL SULFUR CONTENT (PERCENT) 2.0
COAL HEATING VALUE (BTU/LB) 11700
COAL ASH CONTENT (PERCENT) 9.0
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1-3
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1971-72
EMISSION (LB/MM BTU) 0.08-0.09
REMOVAL EFFICIENCY 98.8-98.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0
SURFACE AREA (1000 SQ FT) 121
GAS EXIT RATE (1000 ACFM) 673
SCA (SQ FT/1000 ACFM) 180
OUTLET TEMPERATURE (*F) 310
7-107
-------
reflect the access difficulty for units 1, 2, 5, and 6 because of the coal
conveyor and the existing ESPs and chimneys. Units 3 and 4 are highly
congested because the coal conveyors are both north and south and the
existing ESPs and the chimney are to the west. A high underground
obstruction factor was assigned to the placement of all absorbers because of
the drain water switch lines and the ash disposal lines. The access/
congestion factor assigned to the flue gas handling was low for units 1, 2,
5, and 6 and all FGD technologies because of the location of the absorbers
and their accessibility to the chimneys and the fact that no significant duct
work would be required. By contrast, due to access difficulties created by
the coal conveyors to the unit 3 and 4 chimneys, high access/congestion
factors were assigned to the flue gas handling system. Short ductwork would
be required for the retrofit of L/LS-FGD technology at the plant. Finally, a
10 percent general facilities factor was assigned for all units and all FGD
technologies because of the demolition and relocation of the storage
warehouses and plant road required for the placement of the absorbers
discussed above.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 7.4.1-2 and 7.4.1-3. The
largest scope adder for the Joppa plant would be the conversion of wet to dry
ash handling system for all units considered for conventional L/LS-FGD
retrofit. It was assumed that dry fly ash would be necessary to stabilize
the L/LS-FGD scrubber sludge waste. Dry ash handling is not necessary for
forced oxidation L/LS-FGD and was not considered a scope adder for these
cases. The overall retrofit factors determined for the L/LS-FGD cases were
moderate (1.36 to 1.60).
A considerable ESP plate area addition would be required to upgrade the
ESPs because of the SCA size (<200) and the ESPs location {high site
access/congestion). As a result, the LSD-FGD case evaluated was LSD with a
new baghouse. A medium duct run would be necessary for the new baghouse in
LSD-FGD cases to divert the flue gas from the absorbers to the new baghouses
and back to the existing chimneys. The estimated retrofit factors for this
case were moderate (1.40 to 1.62) and did not include particulate control
costs. Separate factors were estimated for new particulate controls. The
same site access/congestion factors used for the absorbers were also assumed
7-108
-------
TABLE 7.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR JOPPA UNITS 1,2,5,6
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM MEDIUM MEDIUM
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE NA
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 1612 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.41 1.36
ESP REUSE CASE NA
BAGHOUSE CASE 1.40
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.36
GENERAL FACILITIES (PERCENT) 10 10 10
7-109
-------
TABLE 7.4.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR OOPPA UNITS 3-4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE NA
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA HIGH
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 1612 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.60 1.56
ESP REUSE CASE NA
BAGHOUSE CASE 1.62
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.58
GENERAL FACILITIES (PERCENT) 10 10 10
7-110
-------
for ESP upgrade, resulting in overall moderate to high retrofit factors (1.36
to 1,58). - The factors determined for new particulate controls were used in
the IAPCS model to estimate the particulate control costs.
Table 7.4.1-4 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boilers 1-6.
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, and optimization of scrubber size.
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 SO^ conditioning or additional plate area was
. needed. S03 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 7.4.1-5.
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for NO controls at the Joppa steam plant. These controls include
A
LNC and selective catalytic reduction. The application of NQx control
technologies is determined by several site-specific factors which are
discussed in Section 2. The N0X technologies evaluated at the steam plant
were: OFA and SCR.
7-111
-------
Table 7.4,1-4. Suimary of FGD Control Costs fop the Joppa Plant (June 1953 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
502 Cost
Nusbcr
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MU)
(%)
Content'
(SUM)
a/m
($HM)
(Bills/kHh)
<30
itons/yr)
($/ton)
Factor
(%>
L/S FGO
1.
5
1.41
183
15
2.0
60.7
331.4
22.7
94.6
90.0
3595
6325.3
US FGD
2,
6
1.41
163
13
2.0
60.6
331.4
22.5
107.9
90.0
3116
7218.1
l/S FGD
3,
4
1.60
183
15
2.0
68.0
371.4
25.2
104.8 '
90.D
3595
7011.2
L/S FGD-C
1,
5
1,41
183
15
2.0
60.7
331.4
13.3
55.3
90.0
3595
3699.6
L/S FGD-C
2,
6
1.41
183
13
2.0
60.6
331.4
13.2
63.1
90.0
3116 •
4222.8
L/S FGD-C
3,
4
1.60
183
15
2.0
68.0
371.4
14.7
61.3
90.0
3595
4101.7
LC FGD 1-6 1.50 1100 ¦ 14 2.0 183,1 , 166.4 68.2 50.6 90.0 20168 3382.6
LC FGD-C 1-6 1.50 1100 14 2.0 183.1 166.4 39.9 , 29.6 90.0 20168 1978.7
ISD+FF
1,5
1.40
183
15 •
2.0
45.9
250.8
15.9
66.3
87.0
3455
4612.1
LSD+-FF
2,6
1.40
183
13
2.0
45.9
250.8
15.8
75.9
87.0
2994
5280.9
ISD+FF
3,4
1.62
183
15
2.0
52.8
288.7
17.9
74.2
87.0
3455
5167.3
LSD+-FF-C
1,5 '
1.40
183
15
2.0
45.9
250.8
9.3
38.8
87.0
3455
2702.0
LSD+FF-C
2,6
1.40
183
13
2.0
45.9
250.8
9.3
44.5
87.0
2994
3094.3
ISD+FF-C
3,4
1.62
183
15
2.0
52.8
288.7
10.5
43.5
87.0
3455
3029.1'
7-112
-------
Table 7.4.1-5. Summary of Coat Snitching/Cleaning Costs for the Joppa Plant (June *982 Ooltars)
Technology Boiler Main Boiler
Nunber Retrofit Size
Difficulty (MW)
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
{%} ' Content (SMM) (J/kU) (SM«>
Annual S02 502 • S02 Cost
Cost Removed Removed Effect,
(miIIs/kwh) (%> Ctans/yr) (I/tor)
CS/B+I15 1,3,4 1,00 183 15 2.0 7.2 39.5 4.9 20.2 57.0 2258 2156.3
CS/3-S15 2,6 ' 1.00 183 13 2.0 7.2 39.5 4,4 21,3 57.0 1957 2270,5
CS/B+S15-C 1,3,4 1.00 183' 15 2.0 7.2 39.5 2.8 11.7 57,0 2258 1249.7
CS/8*S15-C 2,6 1.00 183 13 2.0 7.2 39.5 2.6 12.4 57.0 1957 1317.4
CS/B+S5 1,3,4 1.00 183 15 2.0 5.3 29.1 2.6 10.6 57.0 2258 1129.4
CS/B+S5 2,6 1.00 183 13 2.0 5.3 29.1 2.4 11.5 57.0 1957 1221.0
CS/8+S5-C 1,3,4 1.00 183 15 2.0 5.3 29.1 1.5 6.2 57.0 2258 657.6
CS/B+IS-C 2,6 1.00 183 13 2.0 5.3 29.1 1.4 6.7 57.0 1957 711.8
7-113
-------
Low N0X Combustion-
Units 1 to 6 are dry bottom, tangential-fired boilers rated at 183 MW
each, The combustion modification technique applied for this evaluation was
OFA. As Tables 7.4.1-6 and 7.4.1-7 show, the OFA N0X reduction performance
for units 1 to 6 was estimated to be 20 percent for all units. This
reduction performance level was assessed by examining the effects of heat
release rates and furnace residence time through the use of the simplified
NOx procedures. Table 7.4.1-8 presents the cost of retrofitting OFA at the
Joppa plant.
Selective Catalytic Reduction-
Tables 7.4.1-6 and 7.4.1-7 present the SCR retrofit results for each
unit. The results include process area retrofit difficulty factors and scope
adder costs. For scope adders, costs were estimated for building and
ductwork demolition, new heat exchanger, and new duct runs to divert the flue
gas from the ESPs to the SCR reactor and from the reactor to the chimney.
The estimate of the reactor sizes was based on an examination of the aerial
photograph of the plant.
It was assumed that the reactors for units 1 to 6 would be located
behind or beside respective chimneys. Some demolition and relocation would
be involved with the placement of the reactors for units 1 to 6. A
25 percent general facilities factor was assigned to units 1 to 6 to account
for road and building relocations.
The reactors for units 1, 2, 5 and 6 were assigned a low access/
congestion factor and units 3 and 4 were assigned a high factor because the
reactors for units 3 and 4 would be surrounded by the chimneys and the coal
conveyors. The ammonia storage system was placed in a remote area near the
inlet channel (low access/congestion). The reactors were assumed to be in
areas with high underground obstructions while the ammonia system was not.
Table 7.4.1-8 presents the estimated cost of retrofitting SCR at the Joppa
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
7-114
-------
TABLE 7.4,1-6. SUMMARY OF NOx RETROFIT RESULTS FOR JOPPA UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.5
14.5
14.5
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
31.6
31.6
31.6
FURNACE RESIDENCE TIME (SECONDS)
3.06
3.06
3.06
ESTIMATED NOx REDUCTION (PERCENT)
20
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
163
163
Ductwork Demolition (1000$)
43
43
43
New Duct Length (Feet)
130
130
130
New Duct Costs (1000$)
917
917
917
New Heat Exchanger (1000$)
2,678
2,678
2,678
TOTAL SCOPE ADDER COSTS (1000$)
3,638
3,801
3,801
RETROFIT FACTOR FOR SCR
1.16
1.16
1.52
GENERAL FACILITIES (PERCENT)
25
25
25
7-115
-------
TABLE 7.4.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR JOPPA UNITS 4-6
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
6
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.5
14.5
14.5
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
31,6
31.6
31.6
FURNACE RESIDENCE TIME (SECONDS)
3.06
3.06
3.06
ESTIMATED NOx REDUCTION (PERCENT)
20
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
81
163
0
Ductwork Demolition (1000$)
43
43
43
New Duct Length (Feet)
130
130
130
New Duct Costs (1000$)
917
917
917
New Heat Exchanger (1000$)
2,678
2,678
2,678
TOTAL SCOPE ADDER COSTS (1000$)
3,719
3,801
3,638
RETROFIT FACTOR FOR SCR
1.52
1.16
1.16
GENERAL FACILITIES (PERCENT)
25
25
25
7-116
-------
Table 7.4,1-8. HQx Control Cast Results for the Joppa Plant {June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NO* NOx NOx Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CHU) (X) Content ($/kW> (SMN) (mi IIs/kwh) (%) (tons/yr! (S/ton)
Factor (%)
IMC-OFA
1,3,4
1.00
183
15
2.0
0.8
4.3
0.2
0.7
20.0
154
1122.9
LMC-OfA
2,6
1.00
183
13
2.0
0.8
4.3
0.2
0.8
20.0
133
1295.6
INC-OFA-C
1,3,4
1.00
183
15
2.0
0.8
4.3
0.1
0.4
20.0 .
154
666.6
INC-QFA-C
2,6
1.00
183
13
2.0
0.8
4.3
0.1
0.5
20.0
133
769.1
SCR-3
1
1.16
183
15
2.0
28.7
156.9
9.6
39.8
80.0
615
15575.5
SCR-3
2
¦ 1.16
183
13
2.0
28.9
157.8
.9.6
46.0
80.0
533
17996.5
SCR-3
3
1.52
183
15
2.0
34.1
186.2
10.9
45.4
80.0
615
17766.9
SCR-3
4
1.52
183
15
2.0
34.0
185.8
10.9
45.3
80.0
615
17743.0
SCR-3
5
1.16
183 .
15
2.0
28.9
157.8
9.6
39.9
80.0
615
15622.8
SCR-3
6
1.16
' 183
13
2.0
28.7
156.9
9.6
45.8
80.0
533
17941.7
SCR-3-C
1
1.16
183
15
2.0
28.7
156.9
5.6
23.3
80.0
615
9133.2
SCR-3-C
2
1.16
183
13
2.0
28.9
157.8
5.6
27.0
80.0
533
10553.9
SCR-3-C
3
1.52
183
15
2.0
34.1
186.2
6.4
26.6
SO.O
615
10427.8
SCR-3-C
4
1.52
183
15
2.0
34.0
185.8
6.4
26.6
80.0
615
10413.7
SCR-3-C
5
1.16
183
15
2.0
28.9
157.8
5.6
23.4
80.0
615
9161.6
SCR-3-C
6
1.16
183
13
2.0
28.7
156.9
5.6
26.9
80.0
533
10521.1
SCR-7
1
1.16
183
15
2.0
28.7
156.9
8.1
33.5
80.0
615
13119.3
SCR-7
2
1.16
133
13
2.0
28.9
157.8
8.1
38.7
80.0
533
15162.5
SCR-7
3
1.52
183
15
2.0
34.1
186.2
9.4
39.1
80.0
615
15310.7
SCR-7
4
1.52
183
15
2.0
34.0
185.8
9.4
39.1
80.0
615
15286.8
SCR-7
5
1.16
183
15
2,0
28.9
157.8
8.1
33.6
80.0
615
13166.7
SCR-7
6
1.16
183
' 13
2.0
28.7
156.9
8.0
38.6
80.0
533
15107.6
SCR-7-C
1
1.16
183
15
2.0
28.7
156.9
4.7
19.7
80.0
615
7725.9
SCR-7-C
2
1.16
133
13
2.0
28.9
157.8
4.8
22.8
SO.O
533
8930.1
SCR-7-C
3
1.52
183
15
2.0
34.1
186.2
5.5
23.1
80.0
615
9020.6
SCR-7-C
4
1.52
183
15
2.0
34.0
185.8
5.5
23.0
80.0
615
9006.3
SCR-7-C
5
1.16
183
15
2.0
28.9
157.8
4.8
19.8
80.0
615
7754.4
SCR-7-C
6
1.16
183
13
2.0
28.7
156.9
4.7
22.7
80,0 '
533
8897,4
::s>33S3i:
I1135II
It
II
II
II
II
II
II
SSSSSSSS9
S S 3S* S 2 XS
SB&SBiiSaSSSBSSKSSJSS S
sssasssss:
sssssasss:
7-117
-------
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 all units would be
located between the powerhouse and the coal storage/handling area in a layout
similar to that for LSD-FGD. The retrofit of DSD at Joppa would be difficult
for several reasons. The ESP SCAs are small (121) and there is little duct
residence time (<1 second) between the boilers and the ESPs. A new baghouse
would be required for DSD retrofit and would be located in the congested area
behind the ESPs, close to the chimneys. Finally, a 30 foot duct run would be
required to reroute the flue gas from the existing ESPs to the new baghouse
and then back to the chimney. It was assumed that the existing ESPs could
not be cost effectively upgraded for FSI with additional plate area due to
the high site access/congestion caused by the close proximity of the ESPs to
each other and the chimneys. Table 7.4.1-9 and 7.4.1-10 present a summary of
the site access/congestion factors, scope adders, and retrofit factors for
DSD and FSI at the Joppa steam plant. Only costs for DSD with new fabric
filters are presented in Table 7.4.1-11.
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 Joppa plant. The boilers at Joppa would be considered
good candidates for AFIC retrofit and AFBC or CG/combined cycle repowering
because of their small boiler sizes {<200) and their age (pre-1960
installation date). These boilers also have low capacity factors indicating
that replacement power costs for extended boiler outage would be minimal.
Additionally, the low capacity factor would indicate that these boilers have
high heat rates and a significant improvement in unit heat rate could result
from retrofit or repowering of these boilers.
7-118
-------
TABLE 7.4.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JOPPA UNITS 1,2,5,6
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) MEDIUM
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1,612
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 1,963
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 47
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 1,659
A NEW BAGHOUSE CASE (DSD) 2,010
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1.34
7-119
-------
TABLE 7.4.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JOPPA UNITS 3-4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1612
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 1,963
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 47
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 1,659
A NEW BAGHOUSE CASE (DSD) 2,010
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) . 1.55
7-120
-------
Table 7.4,1-11. Surma ry of DSD/FSI Control Costs for the Joppa Plant (June 1988 Dollars)
3sai3sis«sssBBsa8«aB«i88SBSssss3Bssssiss==:::s::s:s£SSS35:53ss538=s=::ssss:::ss:=:sssss5s:ss:=:sssssz=sss:;=sss
Technology
BoiUr
Mtin
Boiler Capacity Coal
Capital Capital Annual
Annual
502
S02
S02 Cost
Nurtser
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
(X)
Content
($MM)
<$MK!
(mills/kwh)
(%>
-------
7.5 ILLINOIS POWER COMPANY
7.5.1 Baldwin Steam Plant
The Baldwin plant is located within Randolph County, Illinois, as part
of the Illinois Power Company system. The plant contains three coal-fired
boilers with a net generating capacity of 1,680 HW. Figure 7.5.1-1 presents
the plant plot plan showing the location of all the boilers and major
associated auxiliary equipment.
Table 7.5.1-1 presents operational data for the existing equipment at
the Baldwin steam plant. All boilers burn high sulfur coal (2.8 percent
sulfur). Coal shipments are received by rail and conveyed to a coal storage
and handling area located northeast of unit 1.
Particulate matter emissions for all three boilers are controlled with
ESPs located behind each unit. Ash from all units is wet sluiced to ponds
located southwest of the plant. Limited space is available for waste
disposal and excess furnace waste may need to be dry disposed of off-site.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 7.5.1-1 shows the general layout and location of the FGD control
system. The ESPs for each unit are directly behind the boilers, followed by
the chimneys (one for each boiler), in front of the cooling water reservoir.
The absorber for unit 1 was located north of the unit 1 chimney beside the
water treatment area. There is limited space between units 2-3 and the
cooling water reservoir to locate the absorbers for these units; therefore,
the absorbers would be located in an area to the south of unit 3. Plant
roads and an employee parking area would need to be relocated to accommodate
the placement of the FGD absorbers. Finally, the limestone preparation/
storage and waste handling areas were placed directly south of the unit 2 and
3 absorbers. Because of the relocation of the employee parking area and
plant roads for unit 1, a factor of 10 percent was assigned to general
facilities. No major demolition/relocation would be required for units 2 and
3 FGD system and a factor of 5 percent was assigned to general facilities.
7-122
-------
Electrical
Warehouse
Coal Storage/
Handling Area
N
Visitor
Parking Area
Absorbers
for Unit 1
Water
Treatment Area
Sorbent Storage/
Handling Area
Waste
Handling Area
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Railroad
Tracks
Not to scale
Ash
Storage Area
Figure 7.5.1-1. Baldwin plant plot plan
7-123
-------
TABLE 7.5.1-1. BALDWIN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
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 LIMIT (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
560
560
560
62.3
63.7
68.3
1970
1973
1975
CYC
CYC
TANG
2.8
2.8
2.8
10700
10700
10700
10.5
10.5
10.5
WET SLUICE
POND/ON-SITE
1 ¦ ••
2
3
RAILROAD
ESP
ESP
ESP
1970
1973
1975
0.20
0.20
0.10
90.3
94.7
99.5
4.5
4.5
4.0
311
311
542
1730
1730
2190
ISO
180
247
310
310
310
7-124
-------
Retrofit Difficulty and Scope Adder Costs--
The absorber locations for all units were assigned low site
access/congestion factors. The absorbers for unit 1 would be located north
of the respective unit in an area with no major obstacles/obstructions. The
absorbers for units 2 and 3 were located in an area slightly remote from the
chimneys south of unit 3. A medium flue gas handling factor was assigned to
unit 1, due to the congestion created by the water treatment area. A high
site access/congestion factor was assigned to unit 2 flue gas handling system
because of the access difficulty caused by the unit 3 chimney/ESP. A
moderate site congestion factor was assigned to unit 3 flue gas handling
system because of the limited space availability around the chimney. A
moderate duct length was required for unit 3, while long duct runs would be
needed for units 1 and 2.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 7.5.1-2 through 7.5.1-4.
The largest scope adder for the Baldwin plant would be the conversion of
units 1 through 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 used
to stabilize part of the conventional L/LS-FGD scrubber sludge waste. The
overall retrofit factors determined for the L/LS-FGD cases were moderate
. (1.35 to 1.53). The conversion of wet to dry ash handling is not required
for L/LS forced oxidation application.
For the LSD-FGD reuse ESP case, a large plate area addition would be
required to upgrade the ESPs for units 1 and 2 due to the small SCAs {<200).
Because the existing ESPs are located in a highly congested area, LSD with a
new baghouse was the only LSD-FGD case evaluated for units 1 and 2. However,
unit 3 ESPs are moderate in size (>240) and LSD reuse ESP was the only case
considered for unit 3. The retrofit factors determined for the LSD
technology were moderate (1.38 to 1.43) and did not include particulate
control costs. Separate retrofit factors were estimated for upgrading ESPs
(1.58) and the new baghouses (1.16) to reflect the access/congestion
associated with their locations. These factors were used in the IAPCS model
to estimate the new particulate control costs.
7-125
-------
TABLE 7.5.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BALDWIN UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING MEDIUM MEDIUM
ESP REUSE CASE NA
BAGHOUSE CASE MEDIUM
DUCT WORK DISTANCE (FEET) 600-1000 600-1000
ESP REUSE NA
BAGHOUSE 600-1000
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 4393 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.49 1.42
ESP REUSE CASE NA
BAGHOUSE CASE 1.38
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 10 10 10
7-126
-------
TABLE 7.5.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR BALDWIN UNIT 2
FGO TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 600-1000 600-1000
ESP REUSE NA
BAGHOUSE 600-1000
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 4393 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.58 1.50
ESP REUSE CASE NA
BAGHOUSE CASE 1.47
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 5 5
7-127
-------
TABLE 7.5,1-4. SUMMARY OF RETROFIT FACTOR DATA FOR BALDWIN UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING MEDIUM MEDIUM
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 4393 NA 4393
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.42 1.35
ESP REUSE CASE 1.38
BAGHOUSE CASE . NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
7-128
-------
FGD Retrofit Costs-
Table 7.5,1-5 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include installing new baghouses to handle the additional
particulate loading for boilers 1 and 2 and upgrading the ESPs and ash
handling systems for boiler 3.
The low cost control case was evaluated separately for unit 1 and
combined for units 2 and 3. For unit 1, the significant reduction in costs
is primarily due to the elimination of spare scrubber module and optimization
of scrubber size. For units 2 and 3, an additional reduction in cost occurs
due to the benefit of economies-of-scale when combining process areas.
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. This is particularly true for cyclone boilers. As such, coal
switching was not evaluated for units 1 and 2. The transportation cost
differential might be substantial resulting in a higher fuel price
differential as assumed in this report.
Unit 3 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. S03 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 7.5.1-6.
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at the Baldwin plant. These controls include LNC
and SCR. The application of N0X control technologies is determined by
several site-specific factors which are discussed in Section 2. The N0X
technologies evaluated at the Baldwin plant were: NGR - units 1 and 2, OFA -
unit 3, and SCR - all units.
7-129
-------
Table 7.5.1«5. . Summary of FGD Control Costs for the Baldwin Plant (Jun« 1986 Dollars)
Technology Boi
:ss£::sa«x8s3ss=3ssssss::ssssss3s:
ler Main Boiler Capacity Coal
Capital Capital Annual Annual
502
S02
Munb«r
• Retrofit
Six*
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Difficulty
Content
(ttm)
<$/kU>
cswo
(mi 1ls/kwh)
<%>
(tons/yr)
Factor
L/S FGD
1
1.49
560
62
2.8
142.1
253.7
70.5
23.1'
90.0
70872
L/S FGD
2
1.58
560
64
2.8
145.3
259.5
72.1
' 23.1
90.0
72464
L/S FGD
3
1.42
560
68
2.8 ¦
132.5
236.5
69.5
20.7
90.0
77697
l/s fgd-c
1
1.49
560
62
2.8
142.1
253.7
41.0
13.4
90.0
70872
L/S FGD"C
2
1.58
560
64
2.8
145.3
259.5
42.0
13.4
90.0
72464
L/S FGD-C
3
1.42
560
6S
2.8
132.5
236.5
40.4
12.1
90.0
. 77697
LC FS0
1
1.49
560
62
2.8
115.4
206.1
61.8
20.2
90.0
70872
LC FGD
2-3
1.50
1120
66
2.8
198.2
176.9
112.2
17.3
90.0
150162
LC FGD-C
1
1.49
560
62
2.8
115.4
206.1
35.9
11.7
90.0
70872
LC FGD-C
2-3
1.50
1120
66
2.8
198.2
176.9
65.2
• 10.1
90.0
150162
LSD+ESP
3
1.38
560
68
2.8
79.8
142.5
41.2
12.3
72.0
61973
LSS+ESP-C
3
1.38
560
68
2.8
79.8
142.5
23.9
7.1
72.0
61973 '
LSD*FF
1
1.38
560
62
2.8
115.4
206.0
48.5
15.9
87.0
68115
LS0+FF
2
1.47
560
64
2.8
117.5
209.8
49.5
15.8
87.0
69646
LS0+FF-C
1
1.38
560
62
2.8
115.4
206.0
28.3
9.3
87.0
68115
LSD+FF-C
2
1.47
560
64
2.8
117.5
209.8
28.9
9.2
87.0
69646
S02 Cost
Effect.
($/ton)
995.0
995.3
894.4
579.0
579.2
520.1
871.5
747.3
506.6
434.1
664.2
386.3
712.2
710.1
415.6
414.4
SSZ8S81
SSSS3S3S
7-130
-------
Table 7.5.1-6. sanitary of Coat Switching/Cleaning Costs for the Baldwin Plant (June 1988 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 502 S02 Cost
Nonber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HV) (X) Content <$MM) (S/kU)
-------
Low N0x Combustion--
Units 1 and 2 are wet bottom, cyclone-fired boilers rated at 560 MW
each. The combustion modification technique applied to both boilers was NGR.
Unit 3 is a dry bottom, tangential-fired boiler rated at 635 MW. The
combustion modification technique applied for this unit was OFA. The NQX
reduction performance estimated for unit 3 was 25 percent. Table 7.5.1-7
presents the results for all boilers evaluated for N0X control applicability
at the Baldwin plant. Table 7.5.1-8 presents the cost of retrofitting NGR
and OFA at the Baldwin plant. For this study it was assumed that the plant
has access to a natural gas pipeline. However, plant personnel indicated
that 18 miles of pipeline and interconnection is expected to add at least 10
million dollars to the capital cost. This additional cost was added as a
scope adder to the NGR capital cost.
Selective Catalytic Reduction-
Table 7.5.1-7 presents the SCR retrofit results for each unit. The
results include process area retrofit difficulty factors and scope adder
costs. The scope adders include costs estimated for ductwork demolition,
new heat exchanger, and new duct runs to divert the flue gas from the ESPs to
the reactor and from the reactor to the chimney. A 25 percent general
. facilities factor was assigned to unit 1. Part of the visitor parking area
and the roadway would have to be relocated.
The reactor for unit 1 was located north of the unit 1 chimney beside
the water treatment area. Because the location of the reactor is in an open
area with no major obstructions, this reactor was assigned a low access/
congestion factor. The SCR reactors for units 2 and 3 would be located south
of unit 3 in an open area with no major obstructions where the fourth unit
would be built. Access to this area is relatively easy. For this reason,
both reactors were assigned low access/congestion factors. All reactors were
located in areas with high underground obstructions. Finally, the ammonia
storage system, which would supply ammonia to the reactors for all three
units, would be located southeast of the reactors for units 2 and 3 in an
area with low access/congestion and no significant underground obstructions.
As discussed in Section 2, all N0X control techniques were evaluated
independently from those techniques evaluated for SOg control. In this case,
7-132
-------
TABLE 7.5.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR BALDWIN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
CY
CY
TANG
TYPE OF NOx CONTROL
NGR
NGR
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
10.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
72.4
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
4.17
ESTIMATED NOx REDUCTION (PERCENT)
60
60
25
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$)
98
98
98
New Duct Length (Feet)
800
1000
650
New Duct Costs (1000$)
10860
13575
8824
New Heat Exchanger (1000$)
5240
5240
5240
TOTAL SCOPE ADDER COSTS (1000$) 16198 18913 14162
RETROFIT FACTOR FOR SCR 1.16 1.15 1.16
GENERAL FACILITIES (PERCENT) 25 13 13
7-133
-------
Table 7.5.1-8. NOx Control Cost Results for the Baldwin Plant (June 1988 Dollars)
ssss::::=:::;s:ss3ss:
£<38333833BSX3S£SS
Technology Boiler Main Boiler Capacity Coal Capital' Capital Annual Annual NOx MOx NOx Cost
N uitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (SMM) (S/kU) <$#N) (S/ton)
Factor (X)
LNC-OFA
3
1.00
560
68
2.8
1.2
2.2
¦ 0.3
0.1
25.0
2965
91.0
INC-OFA-C
3
1.00
560
68
2.8
1.2
2.2
0.2
0.0
25.0
2965
54.0
nsr
1
1.00
560
62
2.8
8.1
14.4
16.7
5.5
60.0
16009
1043.6
HSR
2
1.00
560
64
2.8
8.1
14.4
17.1
5.1
60.0
16369
1042.2
NGR-C
1
1.00
560
62
2.8
8.1
14.4
9.6
3.1
60.0'
16CQ9
600.2
NGR-C
2
1.00
560
64
2.8
8.1
14.4
9.8
3.1
60.0
16369
599.3
SCR-3 .
1
1.16
560
62
2.8
78.3
139.9
29.1
9.5
80.0
21345
1364,7
SCR-3
2
1.16
560
64
2.8
78.8
140.8
29.1
9.3
80.0
21825
' 1333.6
SCR-3
3
1.16
560
6a
2.8
73.7
131.6
26.9
8.0
80.0
9487
2835.0
SCR-3-C
1
1.16
560
62
2.8
78.3
139.9
17.0
5.6
80.0
21345
798.3
SCR-3-C
2
1.16
560
64
2.8
78.8
140.8
17.0
5.4
80.0
2182S
780.2
SCR-3-C
3
1.16
560
68
2.8
73.7
131.6
15.7
4.7
80.0
9487
1659.1
SCR-?
1
1.16
560
62
2.8
78.3
139.9
24.4
8.0
80.0
21345
1145.4
SCR-7
2
1.16
560
64
2.8
78.8
140.8
24.4
7.8
80.0
21825
1119.1
SCR-7
3
1.16
560
68
2.8
73.7
131.6
22.2
6.6
80.0
9487
2341.7
SCR-7-C
1
1.16
560
62
2.8
78.3
139.9
14.4
4.7
80.0
21345
672.7
SCR-7-C
2
1.16
560
64
2.8
78.8
140.8
14.3
4.6
80.Q
21825
657.4
SCR-7-C
3
1.16
560
68
2.8
73.7
131.6
13.1
3.9
80.0
9487
1376.4
7-134
-------
the three SCR reactors are located in the same areas as the FGD absorbers.
If both SO2 and N0X emissions needed to be reduced at this plant, the SCR
reactors would have to be located downstream of the FGD absorbers using this
scheme. The SCR reactor for unit 1 would be located east of the FGD
absorbers for unit 1; whereas, the SCR reactors for units 2 and 3 would be
located immediately south of the FGD absorbers for units 2 and 3, The new
locations of the reactors are generally in open areas having easy access.
Therefore, low access/congestion factors again would be assigned to these
reactors. Table 7.5.1-8 presents the estimated cost of retrofitting SCR at
the Baldwin boilers. SCR application on cyclone boilers burning high sulfur
coal would have a high degree of uncertainty because of the lack of
commercial experience.
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.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas for all units were
located south of the plant. The layout and location would be similar to that
for LSD-FGD. The retrofit of DSD at Baldwin would be difficult. The SCAs
for units 1 and 2 are small (<20Q) for DSD application. Even though the SCA
for unit 3 is moderate in size and might be sufficient to handle the
increased particulate load resulting from sorbent injection application,
there is short duct residence time between the boiler and the ESP in addition
to the location of the ESP in a high access/congestion area. Therefore, it
was assumed that new particulate controls would be needed for the DSD
technology. Over 400 feet of duct runs would be required to divert the flue
gas from the boilers to the baghouses and back to the existing chimneys.
It was assumed that the ESPs could be upgraded for FSI for unit 3 but not for
units 1 and 2 which would require additional plate area. As such, FSI costs
for units 1 and 2 were not reported. The conversion of wet to dry ash
7-135
-------
handling system would be required for reusing the ESPs for FSI technology.
Tables 7.5.1-9 through 7.5.1-11 present a summary of site access/congestion
factors, scope adders, and retrofit factors for DSD and FSI technologies at
the Baldwin steam plant. The costs are shown on a dollar ($) per boiler
basis. Table 7.5.1-12 presents the costs estimated to retrofit DSD with new
fabric filter and FSI on unit 3 for the Baldwin 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 Baldwin plant. The boilers at Baldwin would not be
considered candidates for AFBC retrofit and AFBC/CG/combined cycle repowering
because all boilers are large (MW >600) and were built after 1970.
7.5.2 Hennepin Steam Plant
The Hennepin steam plant is located within Putnam County, Illinois, as
part of the Illinois Power Company system. The plant is located beside the
Illinois River and contains two coal-fired boilers with a total gross
generating capacity of 280 MW.
Table 7.5.2-1 presents operational data for the existing equipment at
the Hennepin plant. The boilers burn high sulfur coal. Coal shipments are
received by barge and transferred to a coal storage and handling area west
of the plant and adjacent to the river.
PH emissions for the boilers are controlled with retrofit ESPs located
behind each unit. The plant has a wet fly ash handling system. Fly ash is
disposed of on-site in an ash pond located east of the plant. Both units
are ducted to a common chimney located beside the river.
Lime/Limestone and Lime Spray Drying FGD Costs--
Boilers 1 and 2 are located beside each other, parallel to the river,
with the water intake and discharge structure located directly behind the
chimney. The FGD absorbers would be placed east of unit 2 which will
require relocating some railroad tracks to make sufficient space available
7-136
-------
TABLE 7.5.1-9.
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BALDWIN UNIT 1
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$) 0
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 600
ESTIMATED COST (1000$) 7551
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 109
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 0
A NEW BAGHOUSE CASE (DSD) 7660
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1.16
7-137
-------
TABLE 7.5.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BALDWIN UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS '
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 0
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 900
ESTIMATED COST (1000$) 11,326
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 109
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 0
A NEW BAGHOUSE CASE (DSD) 11,435
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1.16
7-138
-------
TABLE 7.5.1-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BALDWIN UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS '
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 4,393
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 600
ESTIMATED COST (1000$) 7,551
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 109
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 4,502
A NEW BAGHOUSE CASE (DSD) 7,660
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.58
NEW BAGHOUSE (DSD) 1.16
7-1J9
-------
Table 7.5.1-12. Suimary of DS0/FS1 Control Costs for the Baldwin Plant (June 198fi Dollars)
II
II
II
II
II
II
II
II
II
(1
II
II
II
II
II
II
II
If
II
II
II
II
II
II
II
II
(1
II
II
¦ ;;a 8JBSS.
II
II
It
II
II
II
ii
li
if
ii
ll
il
li
it
ii
Si
ii
ii
ii
ii
ii
ii
::s:sss3i
:SSSSSS9S
iss sssssssssissssss—
asssssssss:
aasssssss
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
SQ2
S02
S02 Cost
Number Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty (MW)
(X)
Content
($MK)
<$AU>
<$wo
(mi 1 Is/kuti)
(X)
(tons/yr)
(S/ton)
Factor
(X)
DSO+FF
1
1.00
560
62
2.8
72.6
129.6
34.6
11.3
71.0
55713
'621.4
DSO+FF
2
1.00
560
64
2.8
76.5
136.7
35.6
11.4
71.0
56965
625.5
DSD+FF
3
1.00
560
68
2.8
76.6
136.8
38.7
11.5
69.0
59968
644.6
DSD+FF-C -
1
1.00
560
62
2.8
72.6
129.6
20.2
6.6
71,0
55713
361.8
DSD+FF-C
2
1.00
560
64
2.8
76.5
136.7
20-8
6.6
71.0
56965
364.4
DSD+FF-C
• 3
1.00
560
. 60
2.8
76.6
136.8
22.5
6.7
69.0
59968
375.1
FSI+ESP-50
3
1.00
560
68
2.8
33.6
59.9
31.7
10.7
50.0
43165
827.2
FSI+ESP-50-C
3
1.00
560
68
2.8
33.6
59.9
20.6
6.2
50.0
43165
477.4
FSI+ESP-70
3
1.00
560
68
2.8
33.2
59.3
36.2
10.8
70.0
60431
599.7
FSI+ESP-70-C
3
1.00
560
68
2.8
33.2
59.3
20.9
6.2
70.0
60431
346.0
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7-140
-------
TABLE 7.5.2-1. HENNEPIN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1 2
GENERATING CAPACITY (MW) 70 210
CAPACITY FACTOR {PERCENT} 42.6 64.6
INSTALLATION DATE 1953 1959
FIRING TYPE TANGENTIAL TANGENTIAL
FURNACE VOLUME (1000 CU FT) 49.8 128.5
LOW NOx COMBUSTION NO NO
COAL SULFUR CONTENT (PERCENT) 2.67 2.67
COAL HEATING VALUE (BTU/LB) 10800 10800
COAL ASH CONTENT (PERCENT) 10.5 10.5
FLY ASH SYSTEM WET HANDLING
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1974 1972
EMISSION (LB/MM BTU) 0.06 0.12
REMOVAL EFFICIENCY 98.7 97.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.8 2.8
SURFACE AREA (1000 SQ FT) 64.8 147
GAS EXIT RATE (1000 ACFM) 290 750
SCA (SQ FT/1000 ACFM) 223 196
OUTLET TEMPERATURE (°F) 305 335
7-141
-------
for the absorbers. A low site access/congestion factor was assigned to the
FED absorber locations. The sorbent preparation, storage, and handling area
would be located beside the absorbers. Because railroad tracks have to be
relocated, a factor of 10 percent was assigned to general facilities. A
temporary waste handling area would be located close to the storage area.
However, because of the limited space available, waste generated by the FGD
application has to be transferred off-site.
It was assumed that a new chimney would be constructed beside the
absorbers to reduce the required flue gas duct length to approximately
500 feet of duct. A high site access/congestion factor was assigned to the
flue gas handling system reflecting the congestion around the units.
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs are small (SCAs <225) and would require major upgrading and
additional plate area to handle the increased PM generated from the LSD
application. In addition, access to the upstream of the ESPs is very
difficult. LSD with a new baghouse was not considered because the boilers
are not burning low sulfur coal.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 7.5.2-2. Table 7.5.2-3 presents the
process area retrofit factors and capital/operating costs for commercial
L/LS-FGD technologies. The low cost FGD case shows the reduction in cost
associated with eliminating spare absorbers and maximizing absorber size.
Coal Switching and Physical Coal Cleaning Costs-
Table 7.5.2-4 presents the IAPCS results for CS at the Hennepin plant.
These costs do not include impacts due to changes in boiler and pulverizer
operating costs; however, does include ESP upgrade costs. PCC was not
evaluated because this is not a mine mouth plant.
Low NQX Combustion--
Units 1 and 2 are dry bottom tangential-fired boilers rated at 70 and
210 MW, The combustion modification technique applied to both boilers was
0FA. Tables 7.5.2-5 and 7.5.2-6 present the NO reduction performance and
A
cost results of retrofitting OFA at Hennepin. Although furnace volume data
7-142
-------
TABLE 7.5.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR HENNEPIN
UNITS 1 OR 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 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$}
681,
1823 NA
NA
NEW CHIMNEY
YES
NA
NA
ESTIMATED COST (1000$)
490,
1470 0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
0
7-143
-------
Table 7.5.2-3. Sunnary of fGD Control Costs for the Hennepin Plant (June 1988 Dollars}
II
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Technology
Boiler Nain
Boiler Capacity Coal
Capital Capital Annual
Annual
502
S02
S02 Cost
Nunber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
(XJ
Content
(WW)
wm
(««)
(mills/kwh)
«}
(tons/yr)
($/ton)
Factor
(X)
L/S FGD
1
1.48
70
43
2.7
42.3
604.4
17.8
68.1
90.0
5779
3078.6
L/S FGD
2
1.48
210
65
2.7
72.4
344.7
34.4
29.0
90.0
26291
1109.3
l/s. m
1-2
1.48
280
59
2.7
87.7
313.1
41.1
28.3
90.0
32071
1281.1
L/S F50-C
1
1.48
70
43
2.7
42.3
604.4
10.4
39.7
90.0
5779
1796.6
L/S FGO-C
2
1.48
210
65
2.7
72.4
344.7
20.0
t6.9
90.0
26291
762.5
L/S FGO-C
1-2
1.48
280
59
2.7
87.7
313.1
23.9
16.5
90.0
32071
746.2
LC F60
1-2
1.48
280
59
2.7
66.6
237.8
34.2
23.6
90.0
32071
1065.0
LC FGO-C
1-2
1.48
2S0
59
2.7
66.6
237.8
19.9
13.7
90.0
32071
619.5
8SS'19SIBSSSSSSSSSS88SlSS8SBSSSSESS3B88S988SSS33S3SSSS8SBSSSSSSSlS3SSiSS8SSSS33388SISVBIS9SSSSSSS3SSSSS3SSSSSSSSSS
7-144
-------
Table 7.5,2-4. Summary of Coal Snitching/Cleaning Costs for the Hennepin Plant (June 1988 Dollars)
¦aiiis«ai>iasiiiiaisiii«»SHasiiamKiii»t»>isiaiifia»iiiaaiiiisaiatniBiiiiiiiiiisBiiaBa>3s:sss:sBiBiisaii
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Ccst
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (SMH) (S/kW) (mills/kwh) (X) (tons/yr) <$/ton)
Factor {X}
CS/B+S15
CS/B*$15
00
00
70
210
43
65
2.7
2.7
3.0
8.5
43.4
40.4
4,3
17.5
16.5
14.7
71.0 4535
71.0 20632
950.9
848.8
CS/B+i15-C
CS/B+S15-G
.00
.00
70
210
43
65
2.7
2.7
3.0
8.5
43.4
40.4
2.5
10.1
9.5
8.5
71.0
71.0
4535
20632
547.8
488.1
CS/B*S5
CS/B+S5
.00
.00
70
210
43
65
2.7
2.7
2.3
6.3
33.1
30.0
2.0
7.3
7.8
6.2
71.0
71.0
4535
20632
447.1
354.6
CS/B+S5-C
CS/B+S5-C
.00
.00
70
210
43
65
2.7
2.7
2.3
6.3
33.1
30.0
1.2
4.2
4.5
3.6
71.0 4535
71.0 20632
258.5
204.5
SSS3SS5SSSSSS3S
7-145
-------
TABLE 7.5.2-5. SUMMARY OF NQx RETROFIT RESULTS FOR HENNEPIN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
¦
1
2
1-2
FIRING TYPE
TANG
TANG
NA
TYPE OF NOx CONTROL
OFA
OFA
NA
FURNACE VOLUME (1000 CU FT)
49.8
128.5
NA
BOILER INSTALLATION OATE
1953
1959
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
25
NA
SCR RETROFIT RESULTS (COMBINED)
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
New Chimney (1000$)
NO
NO
NO
Ductwork Demolition (1000$)
21
47
59
New Duct Length {Feet}
500
, 500
500
New Duct Costs (1000$)
2011
3824
4525
New Heat Exchanger (1000$)
1505
2909
3457
TOTAL SCOPE ADDER COSTS (1000$)
3536
6780
8040
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES.(PERCENT)
13
13
13
7-146
-------
Table 7.5.2-6. HO* Control Cost Results for the Hennepin Plant (June 1988 Dollars)
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Technology
Boiler
Nain
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
MOx
NGx Cost
Nunber
Retrofit
Size
Factor Sulfur
cost
cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
(S/tonJ
Factor
m
LNC-OFA
1
1.00
70
43
2.7
0.5
7.7
0.1
0.4
25.0
229
512.1
LHC-0FA
2
1.00
210
65
2.7
0.8
4.0
0.2
0.2
25.0
1040
175.1
INC-OFA-C
1
1.00
70
43
2.7
0.5
7.7
0.1
0.3
25.0
229
303.9
LNC-OFA-C
2
1.00
210
65
2.7
0.8
4.0
0.1
0.1
25.0
1040
103.9
SCR-3 •
t
1.16
70
43
2.7
16.2
231.B
5.1
19.4
80.0
732
6922.6
SCR-3
2
1.16
210
65
2.7
33.8
160.7
11.5
9.7
80.0
3329
3463.7
SCR-3
1-2
1.16
280
59
2.7
42.3
151.0
14.6
10.1
80.0
4061
3593.0
SCR-3-C
t
1.16
70
43
2.7
16.2
231.8
3.0
11.4
80,0
732
4065.6
SCR-3-C
2
1.16
210
65
2.7
33.8
160.7
6.8
5.7
80.0
3329
2029.9
SCR-3-C
1-2
1.16
280
59
2.7
42.3
151.0
8.5
5.9
SO.O
4061
2105.2
SCR-7
1
1.16
70
43
2.7
16.2
231.1
4.5
17.2
80.0
732
6124.2
SCR-?
2
1.16
210
65
2.7
33.8
160.7
9.8
8.2
80.0
3329
2937.2
SCR-7
1-2
1.16
2B0
59
2.7
42.3
151.0
12.3
8.5
80.0
4061
3017.5
SCR-7-C
1
1.16
70
43
2.7
16.2
231.8
2.6
10.1
80.0
732
3608.2
SCR-7-C
2
1.16
210
65
2.7
33.8
160.7
5.8
4.8
SO.O
3329
1728.3
SCR-7-C
1-2
1.16
280
59
2.7
42.3
151.0
7.2
5.0
80.0
4061
1775.5
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7-147
-------
was not available for unit 1, it was assumed to have a low volumetric heat
release rate typical of the 1950's boiler design.
Selective Catalytic Reduction--
Cold side SCR reactors for both units would be located west of unit 1.
Both reactors are located in a low access/congestion area requiring about
500 feet of flue gas ducting and flue gas reheater. A base factor of
13 percent was assigned to general facilities. The ammonia storage system
was placed close to the reactors, east of the plant.
Table 7.5.2-5 presents the SCR factors and scope adder costs.
Table 7.5.2-6 presents the estimated cost of retrofitting SCR at the Hennepin
boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI or DSD technologies at the Hennepin plant for
both units would be very difficult for two major reasons; 1) the ESPs have
small SCAs (<225); hence, they probably would not be able to handle the
increased PM and would require major upgrading and additional plate area; 2}
the short duct residence time between the boilers and ESPs would not be
sufficient for humidi fication (FSI application) or sorbent evaporation (DSD
application). In addition, the ESPs are located in a high congestion area
making it difficult to add plate area. Therefore, sorbent injection
technologies were not considered for this 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 Hennepin. Both units would be considered potential
candidates for retrofit/repowering because of their small boiler sizes.
However, the high capacity factors could result in significant replacement
power cost. ,
7-148
-------
7,5.3 Vermi11 on Steam PI ant
The Vermilion steam plant is located within Vermilion County, Illinois,
as part of the Illinois Power Company system.. The plant contains two
coal-fired boilers with a total gross generating capacity of 165 MW.
Figure 7.5.3-1 presents the plant plot plan showing the location of all
boilers and major associated auxiliary equipment.
Table 7.5.3-1 presents operational data for the existing equipment at
the Vermilion plant. The boilers burn medium sulfur coal (2.4 percent
sulfur). Coal shipments are received by truck and conveyed to a coal storage
and handling area located east of the powerhouse.
Particulate matter emissions for the boilers are controlled with
retrofit ESPs. Fly ash is wet sluiced to ponds located west of the plant.
Lime/limestone and Lime Spray Drying FGD Costs-
Figure 7.5.3-1 shows the general layout and location of the FGD control
system. The boilers share a common chimney. The absorbers for L/LS-FGD and
LSD-FGD for both units would be located north of the chimney on the other
side of the railroad track. No demolition/relocation would be required;
therefore, a factor of 5 percent was assigned to general facilities.
However, a small amount of demolition/
relocation would be needed for the fire pump house and well water storage
tank. The limestone storage/handling area and waste handling area would be
located to the north of the absorbers.
Retrofit Difficulty and Scope Adder Costs--
A low site access/congestion factor was assigned to the absorber
locations. Because the absorbers would be located on the other side of the
railroad, the railroad would not need to be relocated.
For flue gas. handling, however, moderate duct runs for the units would
be required for L/LS-FGD cases to divert the flue gas from the downstream of
the ESP outlets to the absorbers and back to the chimney. A low site
access/congestion factor was assigned to the flue gas handling system due to
no major obstacles or obstructions in the surrounding area.
7-149
-------
Waste
Handling Area
Lime/Limestone
Storage/Prep arat ion
Area
NHj Storage
System
Not to scale.
FGD Waste Handling/Absorber Area
Lima/limestone Storage/Preparatiori Area
NH, Storage System
SCR Boxes
Figure 7.5.3-1. Vermilion plant plot plan
7-150
-------
TABLE 7.5.3-1. VERMILION STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
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
I
70
53.4
1955
TANG
2.4
10775
11.2
95
66.1
1956
TANG
2.4
10775
11.2
WET SLUICE
POND/ON-SITE
1
TRUCK
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION LIMIT (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
1973
1974
0.118
0.10
99.0
99.7
2.8
2.8
55.1
97.2
254
425
217
229
310
310
7-151
-------
The major scope adjustment costs and retrofit factors estimated for the
F6D technologies are presented in Table 7.5.3-2. The largest scope adder
for the Vermilion plant would be the conversion of units 1-2 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 (1.31 to 1.38).
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. Because the sizes are marginal and the ESPs are
roof-mounted, upgrading would be difficult. The LSD-FGD technology with a
new baghouse was the only case considered. For flue gas handling for LSD
cases, moderate duct runs would be required the same as for L/LS-FGD cases.
The retrofit factor determined for the LSD technology case was low (1.27)
and did not include the new baghouse costs. A separate retrofit factor was
developed for the new baghouses for the units. The baghouse locations would
be adjacent to the absorbers with a low site access/congestion factor;
therefore, a retrofit factor (1.16) was designated to the baghouse
locations. This factor was used in the IAPCS model to estimate particulate
control costs.
Table 7.5.3-3 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include installing new baghouses to handle the additional
particulate loading 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, optimization of scrubber module
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.
7-152
-------
TABLE 7.5.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR VERMILION UNITS 1 OR 2
F6D TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE NA
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 1300 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 1.31
ESP REUSE CASE NA
BAGHOUSE CASE 1.27
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 5 5
7-153
-------
Table 7.5,3-3. Suimary of FGD Control Costs for the Vermilion Plant (June 1988 Dollar*)
IltlttlSllS
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Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cast
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
-------
The ESF 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 SOj 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 di fferent coal fuel cost
differentials. The costs associated with each boiler for the range of fuel
cost differential are shown in Table 7.5.3-4.
Currently the plant receives coal by truck. To be able to switch to a
low sulfur coal, the existing railroad facilities would have to be upgraded.
This upgrading of the existing railroad track was added as a scope adder to
the capital cost.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0x
controls at the Vermilion plant. These controls include INC modification and
SCR. The application of N0X control technologies is determined by several
site-specific factors which are discussed in Section 2. The N0X technologies
evaluated at the steam plant were: OFA and SCR.
Low N0X Combustion--
Units 1 and 2 are dry bottom, tangential-fired boilers rated at 70 and
95 MW, respectively. The combustion modification technique applied for this
evaluation was OFA. As Table 7.5.3-5 shows, the OFA N0X reduction
performances for units 1 and 2 were estimated to be 25 and 30 percent,
respectively. Both reduction performance levels were assessed by examining
the effects of heat release rates and furnace residence time on N0X
reduction through the use of the simplified N0X procedures. Table 7.5.3-6
presents the cost of retrofitting OFA at the Vermilion boilers.
Selective Catalytic Reduction-
Table 7.5.3-5 presents 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
7-155
-------
Table 7.5,3-4. Summary of Coal Switching/Cleaning Costs tor the Vermilion Plant (Jum 1988 Dollars)
Technology , Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 502 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW>
-------
TABLE 7.5.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR VERMILION
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
1-2
FIRING TYPE
TANG
TANG
NA
TYPE OF NOx CONTROL
OFA
OFA
NA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.3
13.2
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
21.6
44.9
NA
FURNACE RESIDENCE TIME (SECONDS)
3.44
3.23
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
30
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Buildlng Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
21
26
39
New Duct Length (Feet)
300
300
300
New Duct Costs (1000$)
1207
1443
1992
New Heat Exchanger (1000$)
1505
1807
2517
TOTAL SCOPE ADDER COSTS (1000$)
2732
3276
4549
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
7-157
-------
Table 7.5.3-6. MO* Control Cost Results for the Vermilion Plant (June 1988 Dollars)
S£S5SSS5S3SSSSS55555SS5SSS33SSS£SSSSSr3S3SS£33S3S5S3S3SBSSS93SS3S3S3SX333SSS3SSSSSS*SnS3 S3 3» 3 «!•»•!• 3tSSS3555SSS3I3;'3 3;S3S35S5
Technology loiter Main Boiler Capacity Coat Capital Capital Annual Annual NOx NOx NOx Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty t*W> (X) Content (WO (S/kW) (WW) (mills/kwh) (X> (tons/yr) <$/ton>
Factor {%)
IHC-OFA
1
1.00
70
53
2.4
0.5
7.7
0.1
0.4
25.0
287
407.4
INC-OFA
2
1.00
95
66
2.4
0.6
6.4
0.1
0.2
30.0
579
228.9
INC-OFA-C
1
1.00
70
53
2.4
0.5
7.7
0.1
0.2
25.0
287
241.8
LNC-OFA-C
2
1.00
95
66
2.4
0.6
6.4
0.1
0.1
30.0
579
135.8
SCR-3
1
1.16
70
53
2.4
15.4
219.5
5.0
•15.1
80.0
920
5388.9
SCR-3
-2
1.16
95
66
2.4
18.5
194.2
6.1
11.2
80.0
1545
3975.0
SCS-3
'1-2
1.16
165
61
2.4
26.9
162.9
9.2
10.5
80.0
2464
3743.6
SCR-3-C
1
1.16
70
53
2.4
15.4
219.5
2.9
8.9
80.0
920
3162.4
SCR-3-C
2
1.16
95
66
2.4
18.5
194.2
3.6
6.5
80.0
1545
¦ 2331.0
SCS-3-C
1-2
1.16
165
61
2.4
26.9
162.9
5.4
6.2
80.0
2464
2193.7
SCR-7
1
1.16
70
53
2.4
15.4
219.5
4.4
13.4
80.0
920
4753.5
SCR-7 •
2
1.16
95
66
2.4
18.5
194.2
5.3
9.7
80.0
1545
3461.7
SCR-7
1-2
1.16
165
61
2.4
26,9
162.9
7.8
8.9
80.0
2464
3184.6
SCR-7-C
1
1.16
70
S3
2.4
15.4
219.5
2.6
7.9
80.0
920
2798.4
SCR-7-C
2
1.16
95
66
2.4
18.5
194.2
3.1
5.7
80.0
1545
2036.9
SCR-7-C
1-2
1.16
165
61
2.4
26.9
162.9
4.6
5.3
80.0
2464
1873.4
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II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
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7-158
-------
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 reactors for both units would be located north of the chimney
on the other side of the railroad track in a relatively open area having
easy access. For this reason, 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 NQX control techniques were evaluated
independently from those evaluated for SO^ control. If both SO^ and NOx
emissions have to be reduced at this plant, the results presented for SCR in
Table 7.5.3-5 would not change since the reactors would be located
downstream of the FGD absorbers in same area as discussed before.
Table 7.5.3-6 presents the estimated cost of retrofitting SCR at the
Vermilion 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 were located north of
the plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Vermilion steam plant for the units would be very
difficult. The ESPs are marginal in size, resulting in insufficient duct
residence time between the boilers and the ESPs for DSD application.
Therefore, new baghouses were assumed for the DSD cases which would be
located north of the plant in a similar fashion as LSD-FGD cases. The new
baghouses would require 400 feet of duct run to divert the flue gas from the
boilers to the baghouses and back to the chimney. For FSI, upgrading the
ESPs or plate area addition would be very difficult because the ESPs are
squeezed between the boiler building and the chimney. As such, the retrofit
7-159
-------
factor estimated for upgrading the ESPs for FSI was high (1.58). Also, the
conversion of wet to dry fly ash would be needed for reusing the ESPs to
prevent plugging of sluice lines. Therefore, FSI costs were not developed
for this plant. Tables 7.5.3-7 and 7.5.3-8 present a summary of the site
access/congestion factors for DSD and FSI technologies at the Vermilion steam
plant. Table 7.5.3-9 presents the costs estimated to retrofit DSD at the
Vermilion 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 Vermilion plant. Both boilers would be considered good
candidates for AFBC retrofit because of their small sizes (<110 MW).
However, the high capacity factors for these units could result in
significant replacement power costs for extended downtime.
7-160
-------
TABLE 7.5.3-7.
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR VERMILION UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1300
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 400
ESTIMATED COST (1000$) 1491
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 23
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 1323
A NEW BAGHOUSE CASE (DSD) 1514
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.58
NEW BAGHOUSE (DSD) ; 1.16
7-161
-------
TABLE 7.5.3-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR VERMILION UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS ¦
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1300
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 400
ESTIMATED COST (1000$) 1783
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 29
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 1329
A NEW BAGHOUSE CASE (DSD) 1812
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.58
NEW BAGHOUSE (DSD) 1.16
7-162
-------
Table 7.5.3-9. Surmary of DS0/F5I Control Costs (or the Vermilion Plant (June 1968 dollars)
Technology Boiler Main Boiler Capacity Coal , Capital Capital Annual Annual S02 SG2 SOZ Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW> (X) content (MM)
-------
7.5.4 Wood River Steam Plant
Both coal burning boilers at the Wood River plant are firing a low
sulfur coal; therefore, CS was not evaluated. In addition, FGD costs are not
presented since the low sulfur coal would result In low capital/operating
costs and high cost per ton of SC^ removed. Sorbent injection technologies
were not considered because of the short duct residence time between the
boilers and ESPs, the small size of the ESPs, and the difficulty in accessing
the ESPs.
TABLE 7.5.4-1. WOOD 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
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 5
46 92 340
? ? M 7 42 A
1949,49,50 1954 1964
PETROLEUM TANGENTIAL
BURNING NA 182.9
NO NO
1.0
12100
5.0
WET DISPOSAL
POND/ON-SITE
2 3
RAILROAD/TRUCK
ESP & CYCLONE ESP
1967 1970
0.07 0.06
98.3 97.2
4.1-0.0 4.1-0.0
NA 200.3
410.9 1205
NA 166
335 291
7-164
-------
TABLE 7.5.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR WOOD RIVER
UNIT 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)
600-1000
NA
ESP REUSE
BAGHOUSE
600-1000
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO ORY
YES
NA
NO
ESTIMATED COST (1000$)
870
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
644
0
644
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.84
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
* L/LS-FGD and LSD-FGD absorbers for unit 4 would be located
east of unit 5.
7-165
-------
TABLE 7.5.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR WOOD RIVER
UNIT 5 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
$02 REMOVAL
HIGH
NA
HIGH ,
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
2808
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
2380
0
2380
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.70
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.69
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT) 15
0
15-
* L/LS-FGD and LSD-FGD absorbers for unit 5 would be located
east of unit 5.
7-166
-------
TABLE 7.5.4-4. SUMMARY OF NOx RETROFIT RESULTS FOR WOOD RIVER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
FIRING TYPE
TYPE OF NOx CONTROL
TANG
OFA
TANG/TWIN FURNACE
DESIGN
NA
FURNACE VOLUME (1000 CU FT)
NA
182.9
BOILER INSTALLATION DATE
1954
1964
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
25
68
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
944
2028
New Heat Exchanger (1000$)
1773
3884
TOTAL SCOPE ADDER COSTS (1000$)
2742
5979
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
38
38
* Cold side SCR reactors for units 4 and 5 would be located
behind their respective chimneys.
7-167
-------
TabU 7.5.4-5. MOx Control Cost Results for the Wood River Plant (June 1988 Dollars)
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Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NO* NO* NOx Cost
Nunber Retrofit Size Factor Sulfur Coat Coat Coat Cost Removed Removed Effect,
Difficulty (MW) (X) Content (SMO (S/M) (SM) (aills/kwii; (tors/yr) {*/ton>
Factor (X)
1.00
1.00
92
92
25
15
1.0
1.0
0.6
0.6
6.5 0.1
6.5 Q.I
0.6
0.4
25.0
25.0
155
155
844.9
501.9
1.52 92 25 1.0 22.6 245.2 7.0 34.5 80.0 495 14030.8
1.52 340 42 1.0 57.7 169.6 19.2 15.3 80.0 3076 6229.6
1.52 92 25 1.0 22.6 245.2 4,1 20.3 80.0 495 8242.8
1.52 340 42 1.0 57.7 169.6 11.2 9.0 80.0. 3076 3653.2
1.52 92 25 1.0 22.6 245.2 6.2 30.8 80.0 495 12506.5
1.52 340 42 1.0 57.7 169.6 16.4 13.1 80.0 J076 5322.3
1.52 92 25 1.0 22.6 245.2 3.7 18.1 80.0 495 7369.6
1.52 340 42 1.0 57.7 169.6 9.6 7.7 80.0 3076 3133.4
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7-168
-------
7.6 SOUTHERN ILLINOIS POWER COMPANY
7.6.1 Marlon Steam Plant
The Marion steam plant is located within Williamson County, Illinois,
as part of the Southern Illinois Power Cooperative system. The plant
contains four coal-fired boilers with a total gross generating capacity of
272 MW. Figure 7.6.1-1 presents the plant plot pi an showi ng the location of
all boilers and major associated auxiliary equipment.
Table 7.6.1-1 presents operational data for the existing equipment at
the Marion plant. The boilers burn high sulfur coal (3.0-4.0 percent
sulfur). Coal shipments are received by truck and conveyed to a coal storage
and handling area located west of the plant.
Particulate matter emissions for the boilers are controlled with
retrofit ESPs located behind each unit. Fly ash for units 1-3 is wet
sluiced to ponds located north of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 7.6.1-1 shows the general layout and location of the FGD control
system. The plant is located on a large site northwest of Lake Egypt. Units
1-2 share one chimney. Unit 4 has a new FGD system (Venturi scrubber)
installed in 1978, using limestone as sorbent and built by Babcock and
Wilcox. Therefore, unit 4 will not be considered in this study. The
absorbers for L/LS-FGD and LSD-FGD for units 1-3 would be located east of the
powerhouse and unit 1, toward Lake Egypt. Part of the parking area, a
warehouse, and some auxiliary equipment close to the powerhouse would need
to be demolished and relocated; therefore, a factor of 15 percent was
assigned to general facilities. The limestone storage/handling area and
waste handling area for unit 4 would be expanded and also used for units 1-3.
Retrofit Difficulty and Scope Adder Costs--
A high site congestion factor was assigned to the absorber locations
because of congestion created by conveyors on two sides, the powerhouse, and
an assumed high underground obstruction. This assumption is based on the
absorber locations being close to a water intake structure.
7-169
-------
Lima/Limestone
Storage/Preparation
Area ana Waste
Handling Area Reactors
Lake Eygapt
wattr Intak*
Structure
FGD Waste Handling/Absorber Area
LimelLimeston* Storage/Preparation
SCR Reactors
Not to scale
Figure 7.6.1-1. Marion plant plot plan
7-170
-------
TABLE 7.6.1-1. MARION STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-3 4
GENERATING CAPACITY (MW-each) 33 173
CAPACITY FACTOR (PERCENT) 28 67
INSTALLATION DATE 1963 1978
FIRING TYPE CYC CYC
COAL SULFUR CONTENT (PERCENT) 3.0-4.0 3.0-4.0
COAL HEATING VALUE (BTU/LB) . 10210 10210
COAL ASH CONTENT (PERCENT) 16.3 16.3
FLY ASH SYSTEM DRY/WET SLUICE
ASH DISPOSAL METHOD POND/ON-SITE
STACK NUMBER 1,1,2 3
COAL DELIVERY METHODS TRUCK
FGD UNIT NO YES
INSTALLATION DATE - 1979
FGD TYPE - LIMESTONE
WET SCRUBBER
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1972 1978
EMISSION (LB/MM BTU) 0.2 0.1
REMOVAL EFFICIENCY 99.2-99.0 99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 4.0 4.0
SURFACE AREA (1000 SQ FT) 34.6 203,8
EXIT GAS FLOW RATE (1000 ACFM) 121.6 605
SCA (SQ FT/1000 ACFM) 285 337
OUTLET TEMPERATURE ( F) 300-310 300
7-171
-------
For flue gas handling, a short duct run for the unit 1 absorbers would
be required for L/LS-F6D cases. A medium site access/congestion factor was
assigned to the flue gas handling system for unit 1 due to the chimney
location close to the powerhouse in a high site access/congestion area.
Units 2-3 would require moderate duct runs because the absorbers are located
away from the units. A high site access/congestion factor was assigned to
the flue gas handling system for units 2-3 because the units are located in
a congested area between units 1 and 4.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 7.6.1-2 and 7.6.1-3. It was assumed
that dry fly ash would be necessary to stabilize scrubber sludge waste and to
prevent the plugging of sluice lines. This conversion is not necessary for
forced oxidation L/LS-FGD. The overall retrofit factors determined for the
L/LS-FGD cases were medium to high.
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. Reused ESPs was the only LSD-FGD technology case considered
for the units because of their moderate size (SCA >200). For flue gas
handling for LSD cases, a short duct run would be required for unit 1; a
high site access/congestion factor was assigned due to the difficulty to tie
into the upstream of the ESPs to divert flue gas from the boilers to the
absorbers and back to the ESPs. Units 2-3 would require a medium duct run
with a high site access/congestion factor for the same reasons as stated
above for unit 1. The retrofit factors determined for the LSD technology
case were moderate to high (1.61 to 1.69) and did not include particulate
control upgrading costs. Separate retrofit factors were developed for the
upgrading of ESPs. The ESPs units 1-3 were designated a high retrofit factor
because of their close proximity to each other and the powerhouse/chimneys.
These factors were used in the IAPCS model to estimate particulate control
upgrading costs.
Table 7.6.1-4 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boilers 1-3. The low cost control case reduces capital and annual operating
costs significantly due to the benefits of economies-of-scale when combining
process areas, elimination of spare scrubber modules, and optimization of
scrubber module size.
7-172
-------
TABLE 7.6.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR MARION UNIT 1
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
$02 REMOVAL
HIGH
HIGH
HIGH
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
100-300
ESP REUSE
100-300
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
NO
ESTIMATED COST (1000$)
0
NA
0
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
1.52
ESP REUSE CASE
1.54
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
15
15
7-173
-------
TABLE 7.6.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR MARION UNITS 2 OR 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING . HIGH HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NO NO
ESTIMATED COST (1000$) 0 NA 0
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.61 1.64
ESP REUSE CASE 1.62
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 15 15
7-174
-------
Table 7.6.1*4. Sunmary of FGD Control Costs for the Marion Plant (June 1988 Dollars*
Technology
Boiler
Main
as3a33sssss:s:ss:ssssss:
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nunber
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
BmwivwI fiMnuod
" Mw ' VU rvQlMVCU
Effect.
Difficulty (MW>
{%>
Content
(SUN)
(S/kU)
(SUM)
(milLs/lcwh)
(tons/yr)
(J/ton)
Factor
SS)
L/S FGD
t
1.48
33
28
3.0
30.0
909.0
12.2
150.7
90.0
2122
5745.9
L/S FED
2
1.61
33
28
3.0
32.5
984.6
13.0
161.0
90.0
2122
6141.2
L/S FGO
3
1.61
33
28
3.0
32.5
984.6
13.0
161.0
90.0
2122
6141.2
L/S FQD-C
1
1.48
33
28
3.0
30.0
909.0
7.1
88.0
90.0
2122
3355.4
L/S FGD-C
2
1.61
33
28
3.0
32.5
984.6
7.6
94.1
90.0
2122
3587.2
L/S FG0-C
3
1.61
33
28
3.0
32.5
984.6
7.6
94.1
90.0
2122
3587.2
LC FGD
1-3
1.57
99
28
3.0
38.4
387.8
16.2
66.8
90.0
6367
2549.0
LC FGD-C
1-3
1.57
99
28
3.0
•38.4
387.8
9.5
39.0 '
90.0
6367
1487.5
LSD+ESP
1
1.54
33
28
3.0
10.8
326.6
6.0
74.1
76.0
1799
3333.1
LSD+ESP
2
1.62
33
28
3.0
11.3
341.5
6.1
75.9
76.0
1799
3414.7
LSO+ESP
3
1.62
33
28
3.0
11.3
341.5
6.1
75.9
76.0
1799
3414.7
LSD+ESP-C
1
1.54
33
28
3.0
10.8
326.6
3.5
43.0
76.0
1799
1936.5
LSD+ESP-C
2
1.62
33
28
3.0
11.3
341.5
3.6
44.1
76.0
1799
1984.5
LSD+ESP-C
3
1.62
33
28
3.0
11.3
341.5
3.6
tazzaaza
44.1
76.0
1799
1984.5
7-175
-------
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. This is particularly true for cyclone boilers; as such, coal
switching was not evaluated for the Marion plant.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Marion steam plant. These controls include LNC modification
and SCR. The application of N0X control technologies is determined by
several site-specific factors which are discussed in Section 2. The NO„
X
technologies evaluated at the steam plant were: NGR and SCR.
Low N0x Combustion--
Units 1 to 4 are wet bottom, cyclone-fired boilers; units 1 to 3 are
each rated at 33 MW and unit 4 is rated at 173 MW. The combustion
modification technique applied to all boilers was NGR. As Table 7.6.1-5
shows, the NGR N0x reduction performance for each unit was estimated to be
60 percent. Table 7.6.1-6 presents the cost of retrofitting NGR at the
Marion plant.
Selective Catalytic Reduction-
Table 7.6.1-5 presents the SCR retrofit results for units 1 to 4. 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 reactors for units 1 to 3 would be located east of the
powerhouse and unit 1, toward Lake Egypt in a relatively high congested area
having easy access. Medium access/congestion factors were assigned to these
reactors because of congestion created by the sludge conveyors and the
powerhouse. A 25 percent general facility factor was also assigned to each
reactor because part of a warehouse and some auxiliary equipment close to the
7-176
-------
TABLE 7.6.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR MARION
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2, 3
4
FIRING TYPE
CY
CY
CY
TYPE OF NOx CONTROL
NGR
NGR
NGR
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
60
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$)
12
12
41
New Duct Length (Feet)
250
450
170
New Duct Costs (1000$)
648
1166
1195
New Heat Exchanger (1000$)
958
958
2590
TOTAL SCOPE ADDER COSTS (1000$)
1618
2136
3825
RETROFIT FACTOR FOR SCR
1.34
1.34
1.16
GENERAL FACILITIES (PERCENT)
25
25
13
7-177
-------
Table 7.6,1-6. NO* Control Cost Results for the Marion Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx NOx Cost
Nuifeer
Retrofit
Size
factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
(S/kU)
(two
(ni1Is/kwh)
(X)
(tons/yr)
........
........
...
...
...
NCR
1
1.00
33
28
3.0
1.0
31.2
0.6
7.3
60.0
447
1327,8
NGR
2
1.00
33
28
3.0
1.0
31.2
0.6
7.3
60
.0
447
1327,8
NCR
3'
1.00
33
28
3.0
1.0
31.2
0.6
7.3
60.0
447
1327.8
NOR
4
1.00
173
67
3.0
3,3
19.1
5.7
5.6
60.0
5613
1008.2
NGR-C
1
1.00
33
23
3.0
1.0
31.2
0.3
4.3
60
0
447
771.1
NGR-C
2
1.00
33
28
3.0
1.0
31.2
0.3
4.3
60
0
447
771.1
NGR-C
3
1.00
33
28
3.0
1.0
31.2
0.3
4.3
60
0
447
771.1
NGR-C
4
1.00
173
67
3.0
3.3.
19.1
3.3
3.2
60
0
5613
580.3
SCR-J
1
1.34
33
28
3.0
11.9
360.4
3.6
44.6
80
0
597
6054.6
SCR-3
2
1.34
33
28
3.0
12.4
376.7
3.7
45.8 ,
80
0
597 •
6214.1
SCR-3
3
1.34
33
28
3.0
12.4
376.7
3.7
45.8
80
0
597
. 6214.1
SCR-3
4
1.16
173
67
3.0
27.1
156.7
10.1
9.9
80
0
7484
1344.2
SCR-3-C
1
1.34
33
28
3.0
11.9
360.4
2.1
26.2
80
0
597
3558.3
SCR-3-C
2
1.34 .
33
28
3.0
12.4
376.7
2.2
26.9
80
0
597
3653.7
SCR-3-C
• 3
1.34
33
28
3.0
12.4
376.7
2.2
26.9
80
0
597
3653.7
SCR-3-C
4
1.16
173
67
3.0
27.1
156.7
5.9
5.8
80
0
7484'
716.4
SCR-7
1
1.34
33
28
3.0
11.9
360.4
3.3
41.2
80
0
597
5589.1
SCR-7
2
1.34
33
28
3.0
12.4
376.7
3.4
42.4
80
0
597
5748,6
SCR-7
3
' 1.34
33
28
3.0
12.4
376.7
3.4
42.4
80
0
597
5748.6
SCR-7
4
1.16
173
67
3.0
27.1
156.7
8.6
8.5
80
0
7484
1149.7
SCR-7-C
1
1.34
33
28
3.0
11.9
360.4
2.0
24.3
80
0
597
3291.6
SCR-7-C
2
1.34
33
28
3.0
12.4
376.7
2.0
25.0
80
0
597
3387.0
SCR-7-C
3
1.34
33
28
3.0
12.4
376.7
2.0
25.0
SO
0
597
3387.0
SCR-7-C
4
1.16
173
67
3.0
27.1
156.7
5.1
5.0
80
0
7484
674.9
7-171
-------
powerhouse would have to be demolished or relocated. The SCR reactor for
unit 4 would be located in a relatively open area south of both the existing
FGD unit and chimney for unit 4. A low access/congestion factor was assigned
to this reactor. 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 NQX control techniques were evaluated
independently from those evaluated for S02 control. If both S02 and N0X
emissions were needed to be reduced at this plant for units 1 to 3, the SCR
reactors would have to be located downstream of the FGD absorbers (north) in
relatively the same area as discussed above. Therefore, the results listed
above for retrofitting SCR to this boiler would be applied in this case.
For unit 4, N0x is the only pollutant to be controlled since S02 emissions
are already controlled by an FGD system. Therefore, the results in
Table 7.6.1-5 would remain unchanged for this reactor. Table 7.6.1-6
presents the estimated cost of retrofitting SCR at the Marion 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 were located east of the
plant in a similar fashion as LSD-FGD. Sufficient duct residence time
could be made available for DSD if the old ESPs were used to provide duct
residence time between the boilers and retrofit ESPs. It was assumed that
the ESPs could be upgraded to handle the increased load from DSD and FSI.
To upgrade the ESPs, a high site access/congestion factor was assigned to
units 1-3. To reuse the ESPs, the conversion of wet to dry fly ash would be
needed to prevent plugging of sluice lines. Table 7.6.1-7 presents a summary
of the site access/congestion factors for DSD and FSI technologies at the
7-179
-------
TABLE 7.6.1-7, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MARION UNITS 1,2 OR 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 13
TOTAL COST (1000$)
ESP UPGRADE CASE 13
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.55
NEW BAGHOUSE NA
7-180
-------
Marion steam plant. Table 7.6.1-8 presents the costs estimated to retrofit
DSD and FSI at the Marion plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi1ity--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Marion plant. Boilers 1 through 3 would be considered
good candidates for AFBC retrofit because they are small, old, and have low
capacity factors. However, boiler 4 would not be considered since it has an
existing FGD unit.
7-181
-------
Table 7.6
1-8. Summary of OSO/FSI
Control
Costs for the Marion Plant (June
1988 Dollars)
====*==
u.„.u>
........
,.«===:
.........
Technology
Boiter
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Kurtoer
Retrofit
Size
Factor
Sylfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
(X)
Content
-------
7.7 SPRINGFIELD CITY OF WATER
7.7.1 Dallman Steam Plant
The Dallman steam plant is located within Sangamon County, Illinois, as
part of the Springfield City Water, Light, and Power Company system. The
plant contains three coal-fired boilers with a total gross generating
capacity of 352 MW. Figure 7.7.1-1 presents the plant plot plan showing the
location of all boilers and major associated auxiliary equipment.
Table 7.7.1-1 presents operational data for the existing equipment at
the Dallman plant. The boilers burn medium to high sulfur coal (2.9 percent
sulfur). Coal shipments are received by railroad and conveyed to a coal
storage and handling area located east of the plant.
Particulate matter emissions for the boilers are control led with ESPs
located in front of each unit. Fly ash from all units is wet sluiced.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 7.7.1-1 shows the general layout and location of the FGD control
system. Although there are three coal-fired boilers at the Dallman plant,
only units 1 and 2 were considered for FGD retrofit in this study. Unit 3 is
equipped with recently installed (1980) scrubber modules that presently
operate with a removal efficiency of 85 percent at full load. The absorbers
for units 1 and 2 were located north of the respective units, west of the
coal pile, and close to the coal conveyors. Some plant roads and auxiliary
equipment would need to be demolished/relocated; therefore, a factor of
10 percent was assigned to general facilities. The limestone storage/
handling and waste handling areas would be located to the south of the
units 1 and 2, close to the coal storage and handling area.
Retrofit Difficulty and Scope Adder Costs--
The plant is bounded by Springfield Lake on three sides and a major
highway on the other. Units 1 and 2 are located close to each other on the
edge of a small peninsula north of Springfield Lake.
7-183
-------
Springfield Lake
SCR Reactor
for Unit 3
Waste
Handling Area
Not to scale
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 7.7.1-1. Dallman plant plot plan
7-184
-------
TABLE 7.7.1-1. DALLMAN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
FIRING TYPE
INSTALLATION DATE
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
INSTALLATION DATE
FGD TYPE
PARTICULATE CONTROL
1
2
3
80
80
192
23
25
54
CYC
CYC
TANG
1968
1972
1978
2.9
2.9
2.9
10351
10351
10351
9.2
9.2
WET SLUICE
POND/ON-SITE
9.2
1
2
RAILROAD
3
NO
NO
YES
-
-
1980
LIMESTONE
WET SCRUBBER
TYPE
ESP
ESP
ESP
INSTALLATION DATE
1972
1972
1978
EMISSION (LB/MM BTU)
0.24
REMOVAL EFFICIENCY
67.4
60.7
97.2
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
3.9 -
3.9
3.9
SURFACE AREA (1000 SQ FT)
35.3
39.5
244
GAS EXIT RATE (1000 ACFM)
325
325
775
SCA (SQ FT/1000 ACFM)
109
118
315
OUTLET TEMPERATURE (*F)
300
200
140
7-185
-------
A high site access/congestion factor was assigned to the absorber
locations because they are bounded by the coal conveyors on two sides, the
coal storage/handling area, and the powerhouse.
For flue gas handling, moderate duct runs for the units would be
required for L/LS-FGD cases to divert the flue gas from the absorbers to the
chimneys. A medium site access/congestion factor was assigned to the flue
gas handling system due to some major obstacles and obstructions in the
surrounding area.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 7.7.1-2. The largest scope adder for
the Dal 1 man plant would be the conversion of units 1-2 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 medium
{1.60 to 1.64).
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. A considerable ESP plate area addition would be required to
upgrade the ESPs on units 1-2 due to the small SCA size (<120). Therefore,
LSD with new baghouses was the only LSD-FGD technology considered for the
units. For flue gas handling for LSD cases, moderate duct runs would be
required, the same as for L/LS-FGD cases. The retrofit factor determined for
the LSD technology case was medium (1.58) and did not include the new
baghouse costs. A separate retrofit factor was developed for the new
baghouses for the units and was high (1.58), This reflects the congestion
around the baghouses created by the coal conveyors, coal pile, chimneys, and
powerhouse. This factor was used in the IAPCS model to estimate particulate
control costs.
Table 7.7.1-3 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include installing new baghouses to handle the additional
particulate loading for boilers 1 and 2. The low cost control case reduces
capital and annual operating costs due to the benefits of economies-of-scale
when combining process areas, elimination of spare scrubber modules, and
optimization of scrubber module size.
7-186
-------
TABLE 7.7.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR DALLMAN UNITS 1-2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
HIGH
HIGH
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
NA
BAGHOUSE CASE
MEDIUM
DUCT WORK DISTANCE (FEET)
300-600
300-600
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
NO
ESTIMATED COST (1000$)
768
NA
NA
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.64
1.60
ESP REUSE CASE
NA
BAGHOUSE CASE
1.58
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
10
10
10
7-1B7
-------
Table 7.7.1-3. Suimary of FGD Control Costs for the Dallman Plant (June 1988 Dollars)
SS38S5iaiS3S8SSSSSI5S118SSIlBSaSSISSailCSSS8C38S»SSBS:BSXSSS*B3SaiBSSSSBBI3IS«BlBS13CISBS3SII8
Technology Soiler Main Boiler Capacity Coal Capital Capital Annual
Nuifcer Retrofit Siie factor Sulfur Cost Cost Cost
Difficulty (X) Content
-------
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. This is particularly true with cyclone boilers and, as a result,
coal switching was not evaluated for the Dal 1 man power plant.
N0x Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Dallman steam plant. These controls include INC modification
and SCR. The application of N0X control technologies is determined by
several site-specific factors which are discussed in Section 2. The N0X
technologies evaluated at the steam pi ant were: NCR - units 1 and 2;
OFA - unit 3; and SCR - all units. Unit 3 was considered in the study, even
though it should meet the 1972 NSPS for N0X emissions.
Low N0X Combustion--
Units 1 and 2 are wet bottom, cyclone-fired boilers each rated at 80 MW.
The combustion modification technique applied to both boilers was NGR.
Unit 3 is dry bottom, tangential wall-fired boiler rated at 192 MW. The
combustion modification technique applied for this unit was OFA. As
Table 7.7.1-4 shows, the NGR NQX reduction performance for units 1 and 2 was
estimated to be 60 percent. No boiler information was available in POWER to
assess the OFA N0X reduction performance for unit 3. However, since this
boiler was recently installed (1978), it is estimated that a 20 to 30 percent
N0X reduction can be achieved for this boiler retrofitted with OFA. If
unit 3 already uses OFA to meet the NSPS, further N0x reductions may be
possible but would likely be much less than 20 to 30 percent. Table 7.7.1-5
presents the cost of retrofitting NGR and OFA at the Dallman plant. A
25 percent N0x reduction was assumed for unit 3 using OFA.
Selective Catalytic Reduction-
Table 7.7.1-4 presents the SCR retrofit results for units 1 to 3. The
results include process area retrofit factors and scope adder costs. The
7-189
-------
TABLE 7.7.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR DALLMAN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
CY
CY
TANG
TYPE OF NOx CONTROL
NGR
NGR
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
NA
ESTIMATED NOx REDUCTION (PERCENT) 60
60
25
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$)
23
23
44
New Duct Length (Feet)
300
500
200
New Duct Costs (1000$)
1305 ,
2174
1451
New Heat Exchanger (1000$)
1630
1630
2757
TOTAL SCOPE ADDER COSTS (1000$)
2958
3827
4252
RETROFIT FACTOR FOR SCR
1.52
1.52
1.16
GENERAL FACILITIES (PERCENT)
25
25
20
7-190
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Table 7.7.1-5. NOx Control Cost Results for the DalI man Plant (June 1988 Dollars}
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NOx
NOx Cost
Member
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HU)
(%)
Content
C*MH)
(S/ttO
(Sffl)
(mills/knh)
(X)
(tons/yr)
(t/ton)
Factor
(Si
LNC-OFA
' 3
1.00
192
54
2.9
0.8
4.2
0.2
0.2
25.0
835
210.5
IMC-OFA-C
3
1.00
192
54
2.9
0.8
4.2
0.1
0.1
25.0
835
124.9
MGR
1
1.00
80
23
2.9
1.9
23.9
1.1
7.1
60.0
806
1421.7
NCR
2
1.00
SO
25
2.9
1.9
23.9
1.2
7.0
60.0
876
1390.6
NGR-C
1
1.00
80
23
2.9
1.9
23.9
0.7
4.1
60.0
806
825.1
NGR-C
2
1.00
80
25
2.9
1.9
23.9
0.7
4.0
60.0
876
806.5
SER-3
1
1.52
80
23
2.9
20.3
253.9
6.3
39.0
80.0
1075
5854.7
SCR-3
2
1.52
80
25
2.9
21.1
264.0
6.4
36,8
80.0
1168
5516.3
SCR-3
3
1,16
192
54
2.9
29.2
152.0
10.6
11.7
80.0
6055
1749.9
SCR-3-C
1
1.52
80
23
2.9
20.3
253.9
3.7
22.9
80.0
1075
3439.1
SCR-3-C
2
1.52
80
25
2.9
21.1
264.0
3.8
21.6
80.0
1168
3241.6
SCR-3-C
3
1.16
192
54
2.9
29.2
152.0
6.2
6.8
80.0
6055
1024.2
SCR-7
1
1.52
80
23
2.9
20.3
253.9
5,6
34.9
80.0
1075
5229.4
SCR-7
2
1,52
B0
25
2.9
21.1
264.0
5.8
32.9
80.0
1168
4941,0
SCR-7
3
1.16
192
54
2.9
29.2
152.0
9.0
9.9
80.0
6055
1483.6
SCR-7-C
1
1.52
B0
23
2.9
20.3
253.9
3.3
20.5
80.0
1075
3080.8
SCR-7-C
2
1.52
SO
25
2.9
21.1
264.0
3.4
19.4
80.0
1168
2911.9
SCR-7-C
3
1.16
192
54
2.9
29.2
152.0
5.3
5.8
80.0
6055
871.6
7-m
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scope adders include costs estimated for ductwork demolition, new flue gas
heat exchanger, new duct runs to divert the flue gas of units 1 and 2 from
the ESPs to the reactors and from the reactors to their respective chimneys,
and new duct runs to divert the flue gas of unit 3 from the FED absorbers to
the reactors and from the reactor to the chimney.
The SCR reactors for units 1 and 2 would be located north of the
respective units, west of the coal pile, and close to the coal conveyors.
Access to this area is difficult because of the proximity of the coal
storage and handling area; therefore, high access/congestion factors were
assigned to both reactors. A 25 percent general facility factor was assigned
to each reactor because some plant roads and auxiliary equipment would have
to be demolished or relocated. For unit 3, the SCR reactor would be located
north of the chimney in an relatively open area. Therefore, a low access/
congestion factor was assigned to this reactor. A 20 percent general
facilities factor was assigned to this reactor because a plant road would
have to be relocated. 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 NQX control techniques were evaluated
independently from those evaluated for SO2 control. However, if S02 and NOx
emissions both were to be controlled for units 1 and 2, the SCR reactors
would have to be located downstream (north) of the FGD absorbers in a highly
congested area between the coal conveyors. Therefore, high access/congestion
factors would be assigned for both reactors in this case instead of assigning
medium access/congestion factors. For unit 3, N0x is the only pollutant to
be controlled since this unit is equipped with an FGD system. Hence, the
results in Table 7.7.1-4 would remain unchanged for this unit. Table 7.7.1-5
presents the estimated cost of retrofitting SCR at the Dal 1 man boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for S0^ 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.
7-192
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Duct Spray Drying arid Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located north of
the plant. The retrofit of DSD and FSI technologies at the Dallman steam
plant for the units would be difficult. There is not sufficient duct
residence time between the boilers and the ESPs, as well as the ESPs are
very small (SCA <120). Therefore, only DSD with new fabric filters was
considered with the baghouses being located north of units 1 and 2 in a
similar fashion as LSD-FGD cases. The new baghouses would require 400 feet
of duct run to divert the flue gas from the boilers to the baghouses and
back to the chimneys. A high retrofit factor was designated for the
baghouses for DSD for the same reasons as stated above in LSD-FGD cases. The
FSI was assumed not to be applicable because the ESPs would not be good
candidates for upgrade by adding plate area because the retrofit factor for
upgrading the ESPs is high (l.SS). Also, the conversion of wet to dry fly
ash would be needed for reusing the ESPs to prevent plugging of sluice lines.
Table 7.7.1-6 presents a summary of the site access/congestion factors for
DSD and FSI technologies at the Dallman steam plant. Table 7.7.1-7 presents
the costs estimated to retrofit DSD at the Dallman 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 Dal lman plant. Both boilers would be considered good
candidates for AFBC retrofit because of their small sizes (<300 MW).
7-193
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TABLE 7.7,1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR DALLMAN UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 768
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 400
ESTIMATED COST (1000$) 1613
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 25
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 793
A NEW BAGHOUSE CASE (DSD) 1638
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1.55
7-1S4
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Table 7.7.1-7. Sunwy of DSD/fSl Control Costs for the Daltman Plant (June I960 Dollars)
8SSBSX8&SS?SS<
Technology Boiler Main Boiler Capacity Coal
Nimber Retrofit Size Factor Sutfur
Difficulty (MM) (%) Content
Factor (%!
Capital Capital Annual
Cost Cost Cost
c$mm; (s/ku) (sm)
Annual S02 S02 S02 Cost
Cost Removed Removed Effect,
(mills/kuh) (X) Ctons/yr)
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