EPA/600/7-90/021 e
November 1990
RETROFIT COSTS FOR S02 AND NOj CONTROL OPTIONS
AT 200 COAL-FIRED PLANTS
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
by
T. Eiranel and M. Mai bodi
Radian Corporation
Post Office Box 13000
Research Triangle Park, NC 27709
EPA Contract No. 68-02-4286
Work Assignment 116
Project Officer
Norman Kaplan
U. S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina ,27711
,--AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH A1JD DEVELOPMENT
.U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27 711
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TECHNICAL REPORT DATA
(Please read fiislntcfioHS on the rc.vetsc. before comply~' ——
1 ..REPORT NO, 2.
EPA/600/7-90/021e
1 PB91-133363 !
1. J
4. TITLE AND SUBTITLE
Retrofit Costs for SOg and N0X Control Options at
200 Coal-fired Plants; Volume ¥ - Site Specific
Studies for PA, SC. TN, V.A, WI, WV
5, REPORT OATH
November 1990
6- PERFORMING ORGANIZATION CODE
7. AUTHORISI
Thomas E. Emmel and Mehdi Maibodi
8. PERFORMING ORGANIZATION REPORT NO.
9, PEflFORMINQ ORGANIZATION NAME AND ADDRESS
Radian Corporation
P. O. Box 13000
Research Triangle Park, North Carolina 27709
10, PROGRAM ELEMENT NO.
11. contract/grant NO.
68-02-4286, Task 116
»2. SPONSORING AGENCY NAME AND AOORESS
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
is.supplementary notes AEERL project officer is Norman Kaplan, Mail Drop 62, 919/541-
2556, This is one of five volumes and three diskeUes.conj_prj^ing Uiis^ repo.rt.._^_
6 ' 1
' / " J
16- ^JS^S^The report gives results of a study;5the objective of which was to signifi- Anjif
cantly improve engineering cost estimates currently being used to evaluate the eco- W;
nomic effects of applying S02 and NOx controls at 200 large S02-emitting coal-fired":'1
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-"
parties. Cost estimates are presented for six control technologies: lime/limestone
flue gas desulfurization, lime spray drying, coal switching and cleaning, furnace and
duct sorbent injection, low NOx combustion or natural gas reburn, and selective cata-
lytic reduction. Although the cost estimates provide useful site-specific cost infor-
mation on retrofitting acid gas controls, the costs are estimated for a specific time
period and do not reflect future changes in boiler and coal characteristics (e. g. ,
capacity factors and fuel proces) or significant changes in control technology and per-
formance.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. cosati Field/Group
Pollution Electric Power Plants
Si If u r Dioxide
Nitrogen Oxides
Cost Estimates
Coal
Combustion
Pollution Control
Stationary Sources
Retrofits
13B 1013
07 B
05A, 14 A
21D
21B
IB. DISTRIBUTION STATEMENT
Release to Public
IS, SECURITY CLASS (This Report}'
Unclassified
21. NO. OP PAGES
568
20. SECURITY CLASS (Thispage}
Unclassified
22, PRICE
EPA Farm 2220-1 (9-73)
1
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ABSTRACT
This report documents the results of a study conducted under the
National Acid Precipitation Assessment Program by the U.S. Environmental
Protection Agency's Air and Energy Engineering Research Laboratory, The
objective of this research program was to significantly improve engineering
cost estimates currently being used to evaluate the economic effects of
applying sulfur dioxide and nitrogen oxides controls at 200 large sulfur
dioxide emitting coal-fired utility plants. To accomplish the objective,
procedures were developed and used that account for site-specific retrofit
factors. The site-specific information was obtained from aerial
photographs, generally available data bases, and input from utility
companies. Cost estimates are presented for the following control
technologies: lime/limestone flue gas desulfurization, lime spray drying,
coal switching and cleaning, furnace and duct sorbent injection, low N0^
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 performances
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.
u
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!
Page Intentionally Left Blank
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TABLE OF CONTENTS
VOLUME 1 - INTRODUCTION AND METHODOLOGY
VOLUME II - SITE SPECIFIC STUDIES FOR
Alabama, Delaware, Florida, Georgia, Illinois
VOLUME III- SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
VOLUME IV - SITE SPECIFIC STUDIES FOR
Missouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
SECTION PAGE
ABSTRACT U
LIST OF FIGURES vi
LIST OF TABLES vii
ABBREVIATIONS AND SYMBOLS ....... ... xxii
ACKNOWLEDGEMENT xxv
METRIC EQUIVALENTS ...... xxvi
21.0 PENNSYLVANIA 21-1
21.1 Allegheny Power Service Corp 21-1
21.1.1 Armstrong Steam Plant .... 21-1
21.1.2 Hatfield's Ferry Steam Plant 21-9
21.1.3 Mitchell Steam Plant . 21-17
21.2 Ququesne Light Company . 21-21
21.2.1 Cheswick Steam Plant 21-21
21.3 Metropolitan Edison Company 21-35
21.3.1 Portland Steam Plant . . . 21-35
21.4 Pennsylvania Electric Company ...... 21-49
21.4.1 Conemaugh Steam Plant , 21-49
21.4.2 Homer City Steam Plant ..... 21-60
21.4.3 Keystone Steam Plant 21-71
21.4.4 Seward Steam Plant ..... 21-85
21.4.5 Shawville Steam Plant . . 21-96
iii
-------
TABLE OF CONTENTS (Continued)
PAGF
SECTION
21.5 Pennsylvania Power and Light Company 21-109
21.5.1 Brunner Island Steam Plant ..... 21-109
21.5.2 Martins Creek Steam Plant 21-121
21.5.3 Montour Steam Plant 21-137
21.5.4 Sunbury Steam Plant ... . 21-153
21.6 Pennsylvania Power Company 21-171
21.6.1 Bruce Mansfield Steam Plant . . 21-171
21.6.2 New Castle Steam Plant 21-173
21.7 Philadelphia Electric Company . . 21-194
21.7.1 Eddystone Steam Plant 21-194
22.0 SOUTH CAROLINA 22-1
22.1 South Carolina Electric and Gas .............. 22-1
22.1.1 Canadys Steam Plant . . 22-1
22.1.2 Silas C. McMeekin Steam PI ant 22-8
22.1.3 Urquhart Steam Plant . . . 22-16
22.1.4 Wateree Steam Plant ....... 22-22
22.2 South Carolina Generating . 22-28
22.2.1 Arthur M. Williams Steam Plant ... 22-28
22.3 South Carolina Public Service ... 22-34
22.3.1 Grainger Steam Plant . . 22-34
22.3.2 Jefferies Steam Plant 22-42
22.3.3 Winyah Steam Plant . 22-51
23.0 TENNESSEE ......... 23-1
23.1 Tennessee Valley Authority ........... 23-1
23.1.1 Allen Steam Plant ..... 23-1
23.1.2 Bull Run Steam Plant .............. 23-13
23.1.3 Cumberland Steam Plant ... 23-28
23.1.4 Gallatin Steam Plant 23-28
23.1.5 Johnsonvilie Steam Plant . . 23-42
23.1.6 Kingston Steam Plant 23-46
23.1.7 John Sevier Steam Plant ..... 23-61
24.0 VIRGINIA 24-1
24.1 Appalachian Power Company .24-1
24.1.1 Clinch River .... 24-1
24.2 Virginia Electric and Power Company 24-6
24.2.1 Chesterfield .... 24-6
24.2.2 Portsmouth Steam Plant . 24-11
24.2.3 Possum Point Steam Plant , 24-17
iv
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TABLE OF CONTENTS (Continued)
SECTION PAGE
25.0 WISCONSIN 25-1
25.1 Dairyland Power Cooperative . 25-1
25.1.1 Genoa #3 Steam Plant ....... 25-1
25.2 Wisconsin Electric Power Company ...... 25-9
25.2.1 North Oak Creek Steam Plant 25-9
25.2.2 Pleasant Prairie Steam Plant 25-14
25.2.3 Port Washington Steam Plant .... 25-19
25.2.4 South Oak Creek Steam Plant ...... 25-25
25.2.5 Valley Steam Plant . 25-39
25.3 Wisconsin Power and Light 25-45
25.3.1 Columbia Steam Plant 25-45
25.3.2 Edgewater Steam Plant 25-51
25.3.3 Nelson Dewey Steam Plant 25 61
25.3.4 Rock River Steam Plant 25-67
25.4 Wisconsin Public Service Corporation . 25-72
25.4.1 J. P. Pulliam Steam Plant * 25-72
25.4.2 Weston Unit 1, 2, 3 Steam Plant ! ! ] 25-82
26.0 WEST VIRGINIA
26.1 Allegheny Power Service Corp. . . 26-1
26.1.1 Albright * jg.j
26.1.2 Fort Martin Steam Plant 26-11
26.1.3 Harrison Steam Plant 26-21
26.1.4 Pleasants Steam Plant ..... 26-29
26.2 Appalachian Power Company . 26-32
26.2.1 J. E. Amos Steam Plant 26-32
26.2.2 Mountaineer Steam Plant 26-40
26.3 Central Operating Company 26-48
26.3.1 Philip Sporn Steam Plant 26-48
26.4 Ohio Power Company ...... 26-60
26.4.1 Kammer Steam Plant !.!!!! 26-60
26.4.2 Mitchell Steam Plant * 26-69
26.5 Virginia Electric and Power Company 26-80
,26.5.1 Mount Storm Steam Plant 26-80
v
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
LIST OF FIGURES
PAGE
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennlsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
Cheswick Plant Plot Plan . 21-22
Portland Plant Plot Plan . 21-36
Conemaugh Plant Plot Plan 21-50
Horner City Plant Plot Plan 21-61
Keystone Plant Plot Plan 21-74
Seward Plant Plot Plan 21-86
Brunner Island Plot Plan 21-110
Martins Creek Plan Plot Plan ........... 21-126
Montour Plant Plot Plan ..... 21-141
Sunbury Plant Plot Plan . . . : 21-154
New Castle Plant Plot Plan 21-176
Eddystone Plant Plot Plan 21-195
Allen Plant Plot Plan .... 23-2
Bull Run Plant Plot Plan 23-18
Gallatin Plant Plot Plan 23-30
Kingston Plant Plot Plan 23-47
John Sevier Plant Plot Plan 23-65
vi
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LIST OF TABLES
TABLES PAGE
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
21.1.1-1 Armstrong Steam Plant Operational Data ........... 21-1
21.1.1-2 Summary of Retrofit Factor Data for Armstrong Units 1 or 2 . 21-2
21.1.1-3 Summary of FGD Control Costs for the Armstrong
Plant (June 1988 Dollars) 21-3
21.1.1-4 Summary of Coal Switching/Cleaning Costs
for the Armstrong Plant (June 1988 Dollars) ....... 21-4
21.1.1-5 Summary of NO Retrofit Results for Armstrong . . 21-5
21.1.1-6 NO Control Cost Results for the Armstrong Plant
(June 1988 Dollars) 21-6
21.1.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Armstrong Units 1 and 2 21-7
21.1.1-8 Summary of DSD/FSI Control Costs for the Armstrong
Plant (June 1988 Dollars) 21-8
21.1.2-1 Hatfield Ferry Steam Plant Operational Data . 21-10
21.1.2-2 Summary of Retrofit Factor Data for Hatfield
Ferry Unit 1, 2, or 3 21-12
21.1.2-3 Summary of FGD Control Costs for the Hatfield
Plant (June 1988 Dollars) 21-13
21.1.2-4 Summary of Coal Switching/Cleaning Costs
for the Hatfield Plant (June 1988 Dollars) 21-14
21.1.2-5 Summary of NO Retrofit Results for Hatfield Ferry 21-15
21.1.2-6 NO Control Cost Results for the Hatfield Plant
(June 1988 Dollars) 21-16
21.1.3-1 Mitchell Steam Plant Operational Data 21-18
21.1.3-2 Summary of NO Retrofit Results for Mitchell 21-19
21.1.3-3 NO.. Control Cost Results for the Mitchell Plant
(June 1988 Dollars) 21-20
21.2.1-1 Cheswick Steam Plant Operational Data . 21-23
21.2.1-2 Summary of Retrofit Factor Data for Cheswick Unit 1 21-25
21.2.1-3 Summary of FGD Control Costs for the Cheswick
Plant (June 1988 Dollars) . 21-26
21.2.1-4 Summary of Coal Switching/Cleaning Costs for the
Cheswick Plant (June 1988 Dollars) ... ... 21-28
21.2.1-5 Summary of NO Retrofit Results for Cheswick 21-29
21.2.1-6 NO Control Cost Results for the Cheswick Plant
(June 1988 Dollars) 21-30
21.2.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Cheswick Unit 1 21-33
21.2.1-8 Summary of DSD/FSI Control Costs for the Cheswick
Plant (June 1988 Dollars) 21-34
21.3.1-1 Portland Steam Plant Operational Data . 21-37
vii
-------
LIST OF TABLES (Continued)
TABLES
21.3.1 -2
21.3.1-3
21.3.1-4
21.3.1-5
21.3.1-6
21.3.1-7
21.3.1-8
21.3.1-9
21.4.1-1
21.4.1-2
21.4.1-3
21.4.1-4
21.4.1-5
21.4.1-6
21.4.2-1
21.4.2-2
21.4.2-3
21.4.2-4
21.4.2-5
21.4.2-6
21.4.2-7
21.4.2-8
21.4.3-1
21.4.3-2
21.4.3-3
21.4.3-4
21.4.3-5
PAGE
Summary of REtrofit Factor Data for Portland Units 1 or 2 . . 21-39
Summary of FGD Control Costs for the Portland Plant
(June 1988 Dollars) 21-40
Summary of the Coal Switching/Cleaning Costs for the
Portland Plant (June 1988 Dollars) . 21-41
Summary of NO Retrofit Results for Portland Plant
(June 1988 Dollars) • 21-43
NO Control Cost Results for the Portland Plant
(June 1988 Dollars) 21-44
Duct Spray Drying and Furnace Sorbent Injection
Technologies for Portland Unit 1 21-46
Duct Spray Drying and Furnace Sorbent Injection
Technologies for Portland Unit 2 21-47
Summary of DSD/FSI Control Costs for the Portland
Plant (June 1988 Dollars) - 21-48
Conemaugh Steam Plant Operational Data 21-51
Summary of Retrofit Factor Data for Conemaugh Units 1 or 2 . 21-53
Summary of FGD Control Costs for the Conemaugh Plant
(June 1988 Dollars) 21-54
Summary of the Coal Switching/Cleaning Costs for the
Conemaugh Plant (June 1988 Dollars) 21-56
Summary of NO Retrofit Results for Conemaugh 21-57
N0V Control Cost Results for the Conemaugh Plant
(June 1988 Dollars) 21-58
Homer City Steam Plant Operational Data 21-62
Summary of Retrofit Factor Data for Homer City
Units 1, 2, or 3 - ¦ 21-64
Summary of FGD Control Costs for the Homer City
Plant (June 1988 Dollars) . 21-65
Summary of the Coal Switching/Cleaning Costs for the
Homer City Plant (June 1988 Dollars) 21-57
Summary of NO Retrofit Results for Homer City 21-68
NO Control Cost Results for the Homer City Plan
X(June 1988 Dollars) 21-69
Duct Spray Drying and Furnace Sorbent Injection
Technologies for Homer City Unit 3 21-72
Summary of DSD/FSI Control Costs for the Homer City
Plant (June 1988 Dollars) 21-73
Keystone Steam Plant Operational Data 21-75
Summary of Retrofit Factor Data for Keystone Unit 1 .... . 21-77
Summary of Retrofit Factor Data for Keystone Unit 2 .... . 21-78
Summary of FGD Control Costs for the Keystone Plant
(June 1988 Dollars) 21-80
Summary of the Coal Switching/Cleaning Costs for the
Keystone Plant (June 1988 Dollars} 21-81
viii
-------
LIST OF TABLES (Continued)
TABLES ^
21.4.3-6 Summary of NO Retrofit Results for Keystone . , 21-83
21.4.3-7 NO Control Cost Results for the Keystone Plant
(June 1988 Dollars) 21-84
21.4.4-1 Seward Steam Plant Operational Data 21-87
21.4.4-2 Summary of Retrofit Factor Data for Seward Units 4 or 5 . . . 21-89
21,4.4-3 Summary of FGD Control Costs for the Seward Plant
(June 1988 Dollars) 21-91
21.4.4-4 Summary of the Coal Switching/Cleaning Costs for the
Seward Plant (June 1988 Dollars) 21-92
21.4.4-5 Summary of NO Retrofit Results for Seward Units 4-5 .... 21-93
21.4.4-6 NO Control Cost Results for the Seward Plant
(June 1988 Dollars) . 21-95
21.4.5-1 Shawville Steam Plant Operational Data ... 21-97
21.4.5-2 Summary of Retrofit Factor Data for Shawville Unit 1 or 2 . . 21-99
21.4.5-3 Summary of Retrofit Factor Data for Shawville Unit 3 or 4 . . 21-100
21.4.5-4 Summary of FGD Control Costs for the Shawville Plant
(June 1988 Dollars) 21-101
21.4.5-5 Summary of the Coal Switching/Cleaning Costs for the
Shawville Plant (June 1988 Dollars) 21-103
21.4.5-6 Summary of N0X Retrofit Results for Shawville . 21-104
21.4.5-7 NO Control Cost Results for the Shawville Plant
(June 1988 Dollars) 21-105
21.4.5-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Shawville Unit 3 or 4 21-106
21.4.5-9 Summary of DSD/FSI Control Costs for the Shawville Plant
(June 1988 Dollars) 21-107
21.5.1-1 Brunner Island Steam Plant Operational Data 21-111
21.5.1-2 Summary of Retrofit Factor Data for Brunner Island
Unit 1 or 2 21-113
21.5.1-3 Summary of Retrofit Factor Data for Brunner Island
Unit 2 21-114
21.5.1-4 Summary of FGD Control Costs for the Brunner Island
Plant (June 1988 Dollars) 21-115
21.5.1-5 Summary of Coal Switching/Cleaning Costs for the
Brunner Island Plant (June 1988 Dollars) ......... 21-117
21.5.1-6 Summary of NO Retrofit Results for Brunner Island . . . . . 21-118
21.5.1-7 NO Control Cost Results for the Brunner Island Plant
x(June 1988 Dollars) 21-119
21,5.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Brunner Island Unit 1 ..... 21-122
21.5.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Brunner Island Unit 2 21-123
21.5.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Brunner Island Unit 3 21-124
ix
-------
LIST OF TABLES (Continued)
TABLES PAGE
21.5.1-11 Summary of DSD/FSI Control Costs for the Brunner
Island Plant (June 1988 Dollars) 21-125
21.5.2-1 Martins Creek Steam Plant Operational Data 21-127
21.5.2-2 Summary of Retrofit Factor Data for Martins Creek Unit 1 . . 21-129
21.5.2-3 Summary of Retrofit Factor Data for Martins Creek Unit 2 . . 21-130
21.5.2-4 Summary of FGD Control Costs for the Martins Creek Plant
(June 1988 Dollars) 21-132
21.5.2-5 Summary of the Coal Switching/Cleaning Costs for the
Martins Creek Plant (June 1988 Dollars) . . 21-133
21.5.2-6 Summary of N0„ Retrofit Results for Martins Creek Plant
(June 1988 Dollars) 21-135
21.5.2-7 N0V Control Cost Results for the Martins Creek Plant
(June 1988 Dollars) 21-136
21.5.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Martins Creek Unit 1 21-138
21.5.2-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Martins Creek Unit 2 .... 21-139
21.5.2-10 Summary of DSD/FSI Control Costs for the Martins
Creek Plant (June 1988 Dollars) 21-140
21.5.3-1 Montour Steam Plant Operational Data 21-143
21.5.3-2 Summary of Retrofit Factor Data for Montour Unit 1 21-144
21.5.3-3 Summary of Retrofit Factor Data for Montour Unit 2 21-145
21.5.3-4 Summary of FGD Control Costs for the Montour Pi ant
(June 1988 Dollars) . 21-147
21.5.3-5 Summary of the Coal Switching/Cleaning Costs for
the Montour Plant (June 1988 Dollars) 21-148
21.5.3-5 Summary of NO Retrofit Results for Montour 21-150
21.5.3-7 NO Control Costs Results for the Montour Plant
(June 1988 Dollars) 21-151
21.5.4-1 Sunbury Steam Plant Operational Data 21-155
21.5.4-2 Summary of Retrofit Factor Data for Sunbury Units 1-2 ... . 21-157
21.5.4-3 Summary of Retrofit Factor Data for Sunbury Units 3-4 ... . 21-158
21.5.4-4 Summary of FGD Control Costs for the Sunbury Plant
(June 1988 Dollars) . ".21-159
21.5.4-5 Summary of the Coal Switching/Cleaning Costs for
the Sunbury Plant (June 1988 Dollars) 21-161
21.5.4-5 Summary of N0X Retrofit Results for Sunbury Units 1-2 ... . 21-162
21.5.4-7 Summary of NO Retrofit Results for Sunbury Units 3-4 .... 21-163
21.5.4-8 NO Control Cost Results for the Sunbury Plant
(June 1988 Dollars) ..... 21-165
21.5.4-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Sunbury Units 1 or 2 21-167
21.5.4-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Sunbury Unit 3 21-168
21.5.4-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Sunbury Unit 4 21-169
21.5.4-12 Summary of DSD/FSI Control Costs for the Sunbury
Plant (June 1988 Dollars) 21-170
X
-------
LIST OF TABLES (Continued)
TABLES MGE
21.6.1-1 Bruce Mansfield Steam Plant Operational Data 21-172
21.6.1-2 Summary of NO Retrofit Results for Bruce Mansfield 21-174
21.6.1-3 NO Control Cost Results for the Bruce Mansfield Plant
(June 1988 Dollars) 21-175
21.6.2-1 New Castle Steam Plant Operational Data 21-177
21.6.2-2 Summary of Retrofit Factor Data for New Castle Units 1-5 . . 21-179
21.6.2-3 Summary of FGD Control Costs for the New Castle Plant
(June 1988 Dollars) ...... 21-180
21.6.2-4 Summary of the Coal Switching/Cleaning Costs for
the New Castle Plant (June 1988 Dollars) 21-182
21.6.2-5 Summary of NO Retrofit Results for New Castle Units .... 21-183
21.6.2-6 Summary of NO Retrofit Results for New Castle Units 1-5 . . 21-184
21.6.2-7 NO Control Cost Results for the New Castle Plant
(June 1988 Dollars) 21-186
21.6.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for New Castle Unit 1 21-188
21.6.2-9 Duct Spray Drying and Furnace Injection
Technologies for New Castle Unit 2 . 21-189
21.6.2-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for New Castle Unit 3 ..... . 21-190
21.6.2-11 Duct Spray Drying and Furnace Injection
Technologies for New Castle Unit 4 . . . 21-191
21.6.2-12 Duct Spray Drying and Furnace Injection
Technologies for New Castle Unit 5 21-192
21.6.2-13 Summary of DSD/FSI Control Costs for the New Castle
Plant (June 1988 Dollars) 21-193
21.7.1-1 Eddystone Steam Plant Operational Data 21-196
21.7.1-2 Summary of NO Retrofit Results for Eddystone 21-198
21.7.1-3 NO Control Cost Results for the Eddystone Plant
(June 1988 Dollars) 21-199
22.1.1-1 Canadys Steam Plant Operational Data 22-1
22.1.1-2 Summary of Retrofit Factor Data for Canadys Unit 1 or 2 ... . 22-2
22.1.1-3 Summary of Retrofit Factor Data for Canadys Unit 3 22-3
22.1.1-4 Summary of FGD Control Costs for the Canadys Plant
(June 1988 Dollars) 22-4
22.1.1-5 Summary of Coal Switching/Cleaning Costs for the Canadys
Plant (June 1988 Dollars) 22-5
22.1.1-6 Summary of NO Retrofit Results for Canadys 22-5
22.1.1-7 NOy Control Cost Results for the Canadys Plant
(June 1988 Dollars) 22-7
22.1.2-1 Silas C. McMeekin Steam Plant Operational Data 22-9
22.1.2-2 Summary of Retrofit Factor Data for McMeekin Unit 1 or 2 . . 22-10
22.1.2-3 Summary of FGD Control Costs for the McMeekin Plant
(June 1988 Dollars) 22-11
22.1.2-4 Summary of Coal Switching/Cleaning Costs for the McMeekin
Plant (June 1988 Dollars) 22-13
22.1.2-5 Summary of NO Retrofit Results for McMeekin 22-14
22.1.2-6 NOv Control Cost Results for the McMeekin Plant
(June 1988 Dollars) 22-15
XI
-------
LIST OF TABLES (Continued)
TABLES page
22.1.3-1 Urquhart Steam Plant Operational Data 22-16
22.1.3-2 Summary of Retrofit Factor Data for Urquhart Unit 1, 2, or 3 22-17
22.1.3-3 Summary of FGD Control Costs for the Urquhart Plant
(June 1988 Dollars) ........ 22-18
22,1.34 Summary of Coal Switching/Cleaning Costs for the
Urquhart Plant (June 1988 Dollars) 22-19
22.1.3-5 Summary of N0X Retrofit Results for Urquhart 22-20
22.1.3-6 NO Control Cost for the Urquhart Plant
(June 1988 Dollars) 22-21
22.1.4-1 Wateree Steam Plant Operational Data 22-22
22.1.4-2 Summary of Retrofit Factor Data for Wateree Unit 1 or 2 . . . 22-23
22.1.4-3 Summary of FGD Control Costs for the Wateree Plant
(June 1988 Dollars) 22-24
22.1,4-4 Summary of Coal Switching/Cleaning Costs for the Wateree
Plant (June 1988 Dollars) 22-25
22.1.4-5 Summary of NO Retrofit Results for Wateree . 22-26
22.1.4-6 NO Control Cost Results for the Wateree Plant
(June 1988 Dollars) . . _ 22-27
22.2.1-1 Arthur M. Williams Steam Plant Operational Data ....... 22-28
22.2.1-2 Summary of Retrofit Factor Data for Williams Unit 1 22-29
22.2.1-3 Summary of NO Retrofit Results for Williams ........ 22-30
22.2.1-4 N0y Control Cost Results for the Williams Plant
(June 1988 Dollars) 22-31
22.2.1-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Arthur M. Williams Unit 1 22-32
22.2.1-6 Summary of DSD/FS1 Control Costs for the Williams Plant
(June 1988 Dollars) 22-33
22.3.1-1 Grainger Steam Plant Operational Data ... 22-34
22.3.1-2 Summary of Retrofit Factor Data for Grainger Unit 1 or 2 . . 22-35
22.3.1-3 Summary of FGD Control Costs for the Grainger Plant
(June 1988 Dollars) 22-36
22.3.1-4 Summary of Coal Switching/Cleaning Costs for the Grainger Plant
(June 1988 Dollars) 22-37
22.3.1-5 Summary of NO Retrofit Results for Grainger 22-38
22.3.1-6 NO Control Cost Results for the Grainger Plant
(June 1988 Dollars) . 22-39
22.3.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Grainger Unit 1 or 2 22-40
22.3.1-8 Summary of DSD/FS1 Control Costs for the Grainger Plant
(June 1988 Dollars) ............ 22-41
22.3.2-1 Jefferies Steam Plant Operational Data 22-42
22.3.2-2 Summary of Retrofit Factor Data for Jefferies Unit 3 .... 22-43
22.3.2-3 Summary of Retrofit Factor Data for Jefferies Unit 4 .... 22-44
22.3.2-4 Summary of FGD Control Costs for the Jefferies Plant
(June 1988 Dollars) . 22-45
22.3.2-5 Summary of Coal Switching/Cleaning Costs for the
Jefferies Plant (June 1988 Dollars) ..... 22-46
xii
-------
LIST OF TABLES (Continued)
TABLES PAGE
22.3.2-6 Summary of NO Retrofit Results for Jefferies 22-47
22.3.2-7 NO Control Cost Results for the Jefferies Plant
(June 1988 Dollars) 22-48
22.3.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Jefferies Unit 3 or 4 22-49
22.3.2-9 Summary of DSD/FSI Control Costs for the Jefferies Plant
(June 1988 Dollars) 22-50
22.3.3-1 Winyah Steam Plant Operational Data 22-51
22.3,3-2 Summary of Retrofit Factor Data for Winyah Unit 1 . 22-52
22.3.3-3 Summary of FGD Control Costs for the Winyah Plant
(June 1988 Dollars) 22-53
22.3.3-4 Summary of Coal Switching/Cleaning Costs for the Winyah Plant
(June 1988 Dollars) 22-54
22,3.3-5 Summary of NO Retrofit Results for Winyah 22-55
22.3.3-6 N0y Control Cost Results for the Winyah Plant
(June 1988 Dollars) 22-56
22.3.3-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Winyah Unit 1 ............. . 22-57
22.3.3-8 Summary of DSD/FSI Control Costs for the Winyah Plant
(June 1988 Dollars) 22-58
23.1.1-1 Allen Steam Plant Operational Data 23-3
23.1.1-2 Summary of Retrofit Factor Data for Allen Unit 1 23-5
23.1.1-3 Summary of Retrofit Factor Data for Allen Unit 2 23-6
23.1.1-4 Summary of Retrofit Factor Data for Allen Unit 3 23-7
23.1.1-5 Summary of FGD Control Costs for the Allen Plant
(June 1988 Dollars) 23-8
23.1.1-6 Summary of NO Retrofit Results for Allen 23-10
23.1.1-7 NOy Control Cost Results for the Allen Plant
(June 1988 Dollars) 23-11
23.1.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Allen Unit 1 23-14
23.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Allen Unit 2 23-15
23.1.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Allen Unit 3 23-16
23.1.1-11 Summary of DSD/FSI Control Costs for the Allen Plant
(June 1988 Dollars) 23-17
23.1.2-1 Bull Run Steam Plant Operational Data ............ 23-19
23.1.2-2 Summary of Retrofit Factor Data for Bull Run Unit 1 23-21
23.1.2-3 Summary of FGD Control Costs for the Bull Run Plant
(June 1988 Dollars) 23-23
23.1.2-4 Summary of NO Retrofit Results for Bull Run 23-24
23.1.2-5 N0„ Control Cost Results for the Bull Run Plant
(June 1988 Dollars) 23-26
23.1.2-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Bull Run Unit 1 23-27
23.1.2-7 Summary of DSD/FSI Control Costs for the Bull Run
Plant (June 1988 Dollars) 23-29
23.1.4-1 Gallatin Steam Plant Operational Data 23-31
xiii
-------
LIST OF TABLES (Continued)
TABLES PAGE
23,1.4-2 Summary of Retrofit Factor Data for Gallatin Units 1-2 ... 23-33
23.1.4-3 Summary of Retrofit Factor Data for Gallatin Units 3-4 . . . 23-34
23.1.4-4 Summary of FGD Control Costs for the Gallatin Plant
(June 1988 Dollars) 23-36
23.1.4-5 Summary of Coal Switching/Cleaning Costs for the
Gallatin Plant (June 1988 Dollars) .... 23-37
23.1.4-6 Summary of NO Retrofit Results for Gallatin Units 1-3 ... 23-39
23.1.4-7 Summary of NO Retrofit Results for Gallatin Unit 4 .... . 23-40
23.1.4-8 NO Control Cost Results for the Gallatin Plant
(June 1988 Dollars) 23-41
23.1.4-9 Ouct Spray Drying and Furnace Sorbent Injection
Technologies for Gallatin Units 1-2 23-43
23.1.4-10 Duct Spray Drying and furnace Sorbent Injection
Technologies for Gallatin Units 3-4 23-44
23.1.4-11 Summary of DSD/FSI Control Costs for the Gallatin Plant
(June 1988 Dollars) 23-45
23.1.6-1 Kingston Steam Plant Operational Data ..... 23-48
23.1.6-2 Summary of Retrofit Factor Data for Kingston Units 1-4 ... 23-50
23.1.6-3 Summary of Retrofit Factor Data for Kingston Units 5 9 . . . 23-51
23.1.6-4 Summary of FGD Control Costs for the Kingston Plant
(June 1988 Dollars) 23-53
23.1.6-5 Summary of NO Retrofit Results for Kingston Units 1-3 ... 23-54
23.1.6-6 Summary of NO Retrofit Results for Kingston Units 4-6 ... 23-55
23.1.6-7 Summary of NO Retrofit Results for Kingston Units 7-9 ... 23-56
23.1.6-8 NO Control Cost Results for the Kingston Plant
(June 1988 Dollars) 23-57
23.1.6-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Kingston Units 1-4 ...... 23-60
23.1.6-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Kingston Units 5-9 ...... 23-62
23.1.6-11 Summary of DSD/FSI control Costs for the Kingston Plant
(June 1988 Dollars) 23-63
23.1.7-1 John Sevier Steam Plant Operational Data .......... 23-66
23.1.7-2 Summary of Retrofit Factor Data for John Sevier Units 1-4 . . 23-68
23.1.7-3 Summary of FGD Control Costs for the John Sevier Plant
(June 1988 Dollars) 23-69
23.1.7-4 Summary of the Coal Switching/Cleaning Cost for the
John Sevier Plant (June 1988 Dollars) ..... 23-71
23.1.7-5 Summary of NO Retrofit Results for Sevier Units 1-2 .... 23-72
23.1.7-6 Summary of NO* Retrofit Results for Sevier Units 3-4 .... 23-73
23.1.7-7 NO Control Cost Results for the John Sevier Plant
(June 1988 Dollars) 23-75
23.1.7-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for John Sevier Units 1-4 ... . . 23-77
23.1.7-9 Summary of DSD/FSI Control Costs for the John Sevier Plant
(June 1988 Dollars) ................... 23-78
24.1.1-1 Clinch River Steam Plant Operational Data 24-2
24-.1.1-2 Summary of Retrofit Factor Data for Clinch River
Unit 1, 2, or 3 24-3
xiv
-------
LIST OF TABLES (Continued)
TABLES PAGE
24.1.1-3 Summary of NO Retrofit Results for Clinch River 24-4
24.1.1-4 NO„ Control Cost Results for the Clinch River Plant
(June 1988 Dollars) 24-5
24.2.1-1 Chesterfield Steam Plant Operational Data 24-6
24.2.1-2 Summary of Retrofit Factor Data for Chesterfield
Unit 3, 4, or 5 24-7
24.2.1-3 Summary of Retrofit Factor Data for Chesterfield Unit 6 . . . . 24-8
24.2.1-4 Summary of NO Retrofit Results for Chesterfield 24-9
24,2-1-5 NO Control Cost Results for the Chesterfield Plant
(June 1988 Dollars) . 24-10
24.2.2-1 Portsmouth Steam Plant Operational Data .... 24-11
24.2.2-2 Summary of Retrofit Factor Data for Portsmouth
Units 3 and 4 . 24-12
24.2.2-3 Summary of NO Retrofit Results for Portsmouth ....... 24-13
24.2.2-4 NO Control Cost Results for the Portsmouth Plant
(June 1988 Dollars) 24-14
24.2.2-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Portsmouth Units 3 and 4 24-15
24.2.2-6 Summary of DSD/FSI Control Costs for the Portsmouth Plant
(June 1988 Dollars) 24-16
24.2.3-1 Possum Point Steam Plant Operational Data . . 24-17
24.2.3-2 Summary of Retrofit Factor Data for Possum Point Unit 3 . . . 24-18
24.2.3-3 Summary of Retrofit Factor Data for Possum Point Unit 4 . , . 24-19
24.2.3-4 Summary of N0„ Retrofit Results for Possum Point ...... 24-20
24.2.3-5 NOy Control Cost Results for the Possum Point Plant
(June 1988 Dollars) 24-21
24.2,3-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Possum Point Unit 4 24-22
24.2.3-7 Summary of DSD/FSI Control Costs for the Possum Point Plant
(June 1988 Dollars) 24-23
25.1.1-1 Genoa #3 Steam Plant Operational Data ... 25-2
25.1,1-2 Summary of Retrofit Factor Data for Genoa #3 Unit 1 25-3
25.1.1-3 Summary of FGD Control Costs for the Genoa Plan
(June 1988 Dollars) 25-4
25.1.1-4 Summary of Coal Switching/Cleaning Costs for the Genoa Plant
(June 1988 Dollars) 25-6
25.1.1-5 Summary of NO Retrofit Results for Genoa #3 ......... 25-7
25.1,1-6 NO Control Costs Results for the Genoa Plant
(June 1988 Dollars) ....... 25-8
25.2.1-1 North Oak Creek Steam Plant Operational Data 25-10
25.2.1-2 Summary of Retrofit Factor Data for North Oak Creek
Unit 1 or 2 25-12
25.2.1-3 Summary of N0X Retrofit Results for North Oak Creek ..... 25-13
j xv
-------
LIST OF TABLES (Continued)
TABLES PAGE
25.2.2-1 Pleasant Prairie Steal Plant Operational Data 25-14
25.2.2-2 Summary of Retrofit Factor Data for Pleasant Prairie Unit 1 . 25-15
25,2.2-3 Summary of Retrofit Factor Data for Pleasant Prairie Unit 2 . 25-16
25.2.2-4 Summary of NO Retrofit Results for Pleasant Prairie .... 25-17
25.2.2-5 N0y Control Cost Results for the Pleasant Prairie Plant
(June 1988 Dollars) 25-18
25.2.3-1 Port Washington Steam Plant Operational Data 25-20
25,2,3-2 Summary of Retrofit Factor Data for Port Washington
Units 1-5 (Each) 25-22
25.2.3-3 Summary of FGO Control Costs for the Port Washington Plant
(June 1998 Dollars) ................... 25-23
25.2.3-4 Summary of Coal Switching/Cleaning Costs for the Port Washington
Plant (June 1988 Dollars) ~ 25-24
25.2.3-5 Summary of N0X Retrofit Results for Port Washington ..... 25-26
25.2.3-5 NO Control Cost Results for the Port Washington Plant
(June 1938 Dollars) 25-27
25.2.4-1 South Oak Creek Steam Plant Operational Data 25-28
25.2.4-2 Summary of Retrofit Factor Data for South Oak Creek
Unit 5 or 6 . 25-30
25.2.4-3 Summary of Retrofit Factor Data for South Oak Creek
Unit 7 or 8 . 25-31
25.2.4-4 Summary of FGD Control Costs for the South Oak Creek Plant
(June 1988 Dollars) ....... 25-32
25.2.4-5 Summary of Coal Switching/Cleaning Costs for the South Oak Creek
Plant (June 1988 Dollars) 25-33
25.2,4-6 Summary of NO Retrofit Results for South Oak Creek ..... 25-35
25.2.4-7 NO Control Cost Results for the South Oak Creek Plant
(June 1988 Dollars) 25-36
25.2.4-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for South Oak Creek Unit 5 or 6 25-37
25.2.4-9 Summary of DSD/FSI Control Costs for the South Oak Creek Plant
(June 1988 Dollars) 25-38
25.2.5-1 Valley Steam Plant Operational Data . . 25-39
25.2.5-2 Summary of Retrofit Factor Data for Valley
Units 1-2 or 3-4 25-40
25.2.5-3 Summary of FGD Control Costs for the Valley Plant
(June 1988 Dollars) ........ 25-41
25.2.5-4 Summary of Coal Switching/Cleaning Costs for the Valley Plant
(June 1988 Dollars) ....... ...... 25-42
25.2.5-5 Summary of NO,. Retrofit Results for Valley 25-43
25.2.5-6 NO Control Cost Results for the Valley Plant
(June 1988 Dollars) 25-44
25.3.1-1 Columbia Steam Plant Operational Data ............ 25-46
25.3.1-2 Summary of Retrofit Factor Data for Columbia Unit 1 or 2 . . 25-48
i xvi j
-------
LIST OF TABLES (Continued)
TABLES PAGE
25.3.1-3 Summary of NO Retrofit Results for Columbia 25-49
25.3.1-4 NOv Control Cost Results for the Columbia Plant
(June 1988 Dollars) 25-50
25.3.1-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Columbia Unit 2 . . . 25-52
25.3.1-6 Summary of DSD/FSI Control Costs for the Columbia Plant
(June 1988 Dollars) . 25-53
25.3.2-1 Edgewater Steam Plant Operational Data 25-54
25.3.2-2 Summary of Retrofit Factor Data For Edgewater Unit 3 or 4 . . 25-56
25.3.2-3 Summary of Retrofit Factor Data for Edgewater Unit 5 .... 25-57
25.3.2-4 Summary of FGD Control Costs for the Edgewater Plant
(June 1988 Dollars) 25-58
25.3.2-5 Summary of NO Retrofit Results for Edgewater . . . 25-59
25.3.2-6 NO Control Cost Results for the Edgewater Plant
(June 1988 Dollars) 25-60
25.3.3-1 Nelson Dewey Steam Plant Operational Data . 25-62
25.3.3-2 Summary of Retrofit Factor Data for Nelson Dewey Unit 1 or 2 25-63
25.3.3-3 Summary of FGD Control Costs for the Nelson Dewey Plant
(June 1988 Dollars) 25-64
25.3.3-4 Summary of NO Retrofit Results for Nelson Dewey 25-65
25.3.3-5 NO Control Cost Results for the Nelson Dewey Plant
(June 1988 Dollars) 25-66
25.3.4-1 Rock River Steam Plant Operational Data 25-67
25.3.4-2 Summary of Retrofit Factor Data for Rock River Unit 1 or 2 . 25-68
25.3.4-3 Summary of FGD Control Costs for the Rock River Plant
(June 1988 Dollars) 25-69
25.3.4-4 Summary of NO Retrofit Results for Rock River 25-70
25.3.4-5 N0V Control Cost Results for the Rock River Plant
(June 1988 Dollars) 25-71
25.4.1-1 Pulliam Steam Plant Operational Data 25-73
25.4.1-2 Summary of Retrofit Factor Data for J. P. Pulliam
Unit 3, 4, 5, or 6 25-75
25.4.1-3 Summary of Retrofit Factor Data for J. P. Pulliam
Unit 7 or 8 25-76
25.4.1-4 Summary of FGD Control Costs for the Pulliam Plant
(June 1988 Dollars) 25-77
25.4.1-5 Summary of Coal Switching/Cleaning Costs for the Pulliam
Plant (June 1988 Dollars) 25-78
25.4.1-6 Summary of NO Retrofit Results for J. P. Pulliam ...... 25-79
25.4.1-7 NO Control Cost Results for the Pulliam Plant
(June 1988 Dollars) 25-80
25.4.2-1 Weston Unit 1, 2, 3 Steam Plant Operational Data 25-82
25,4.2-2 Summary of Retrofit Factor Data for Weston Unit 1 or 2 ... 25-83
xvi'i " /
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LIST OF TABLES (Continued)
TABLES PAGE
25.4.2-3 Summary of Retrofit Factor Data for Weston Unit 3 25-84
25.4.2-4 Summary of FGD Control Costs for the Weston Plant
(June 1988 Dollars) 25-85
25.4.2-5 Summary of Coal Switching/Cleaning Costs for the Weston
Plant (June 1988 Dollars) 28-86
25.4.2-6 Summary of NO Retrofit Results for Weston . 25-87
25.4.2-7 NO Control Cost Results for the Weston Plant
(June 1988 Dollars) 25-88
25.4.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Weston Unit 3 25-89
25.4.2-9 Summary of DSD/FSI Control Costs for the Weston
Plant (June 1988 Dollars) 25-90
26.1.1-1 Albright Steam Plant Operational Data . 26-1
26.1.1-2 Summary of Retrofit Factor Data for Albright
Unit 1 or 2 26-2
26.1.1-3 Summary of Retrofit Factor Data for Albright Unit 3 26-3
26.1.1-4 Summary of FGD Control Costs for the Albright Plant
(June 1988 Dollars) 26-4
26.1.1-5 Summary of Coal Switching/Cleaning Costs for the
Albright Plant (June 1988 Dollars) 26-5
26.1.1-6 Summary of NO Retrofit Results for Albright 26-6
26.1.1-7 N0„ Control Cost Results for the Albright Plant
(June 1988 Dollars) 26-7
26.1.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Albright Unit 1 or 2 26-8
26.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Albright Unit 3 26-9
26.1.1-10 Summary of DSD/FSI Control Costs for the Albright Plant
(June 1988 Dollars) 26-10
26.1.2-1 Fort Martin Steam Plant Operational Data ... 26-12
26.1.2-2 Summary of Retrofit Factor Data for Fort Martin
Unit 1 or 2 26-13
26.1.2-3 Summary of FSD Control Costs for the Fort Martin
Plant (June 1988 Dollars) 26-14
26.1.2-4 Summary of Coal Switching/Cleaning Costs for the Fort
Martin Plant (June 1988 Dollars) 26-16
26.1.2-5 Summary of NO Retrofit Results for Fort Martin 26-17
26.1.2-6 NO Control Costs Results for the Fort Martin Plant
(June 1988 Dollars) 26-18
26.1.2-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Fort Martin Unit 1 or 2 26-19
26.1.2-8 Summary of DSD/FSI Control Costs for the Fort Martin
Plant (June 1988 Dollars) ........ 26-20
:xviii
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LIST OF TABLES (Continued)
TABLES PAGE
26.1.3-1 Harrison Steam Plant Operational Data ...... 26-22
26.1.3-2 Summary of Retrofit Factor Data for Harrison
Unit 1, 2 or 3 . 26-24
26.1.3-3 Summary of FGD Control Costs for the Harrison
Plant (June 1988 Dollars) . . 26-25
26.1.3-4 Summary of Coal Switching/Cleaning Costs for the
Harrison Plant (June 1988 Dollars) ..... 26-26
26.1.3-5 Summary of NO Retrofit Results for Harrison ........ 26-27
26.1.3-6 N0y Control Cost Results for the Harrison Plant
(June 1988 Dollars) 26-28
26.1.4-1 Pleasants Steam Plant Operational Data ..... . 26-29
26.1.4-2 Summary of NO Retrofit Results for Pleasants ... 26-30
26.1.4-3 N0y Control Cost Results for the Pleasants Plant
Plant (June 1988 Dollars) ......... 26-31
26.2.1-1 Amos Steam Plant Operational Data ....... 26-32
26.2.1-2 Summary of Retrofit Factor Data for Amos Units 1 and 2 ... 26-33
26.2.1-3 Summary of Retrofit Factor Data for Amos Unit 3 ...... . 26-34
26.2.1-4 Summary of NO Retrofit Results for Amos 26-35
26.2.1-5 NO Control Cost Results for the Amos Plant
(June 1988 Dollars) 26-36
26.2.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Amos Units 1 and 2 26-37
26.2.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Amos Unit 3 . . . 26-38
26.2.1-8 Summary of DSD/FSI Control Costs for the Amos Plant
(June 1988 Dollars) 26-39
26.2.2-1 Mountaineer Steam Plant Operational Data .......... 26-41
26.2.2-2 Summary of Retrofit Factor Oata for Mountaineer Unit 1 . . . 26-42
26.2.2-3 Summary of N0X Retrofit Results for Mountaineer 26-44
26.2.2-4 NO Control Cost Results for the Mountaineer Plant
(June 1988 Dollars) 26-45
26,2.2-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Mountaineer Unit 1 26-46
26.2.2-6 Summary of DSD/FSI Control Costs for the Mountaineer
Plant (June 1988 Dollars) ................ 26-47
26.3.1-1 Philip Sporn Steam Plant Operational Data 26-49
26.3.1-2 Summary of Retrofit Factor Data for Philip Sporn
Unit 1, 3 or 4 • 26-51
26.3.1-3 Summary of Retrofit Factor Data for Philip Sporn Unit 2 . . . 26-52
26.3.1-4 Summary of Retrofit Factor Data for Philip Sporn Unit 5 . . . 26-53
26.3.1-5 Summary of FGD Control Costs for the Sporn Plant
(June 1988 Dollars) 26-54
xix
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LIST OF TABLES (Continued)
TABLES PAGE
26.3.1-6 Summary of NO„ Retrofit Results for Philip Sporn 26-55
2S.3.1-7 NO Control Cost Results for the Sporn Plant
(June 1988 Dollars) .......... .... 26-56
26,3.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Philip Sporn Units 1, 2, 3 or 4 .... . 26-58
26.3.1-9 Summary of DSD/FSI Control Costs for the Sporn Plant
(June 1988 Dollars) 26-59
26.4.1-1 Kammer Steam Plant Operational Data ... ..... 26-61
26.4.1-2 Summary of Retrofit Factor Data for Kammer
Unit 1, 2 or 3 ..................... . 26-62
26.4.1-3 Summary of FGD Control Costs for the Kammer Plant
(June 1988 Dollars) ........... 26-63
26.4.1-4 Summary of NO„ Retrofit Results for Kammer 26-65
26.1.1-5 NO Control Cost Results for the Kammer Plant
(June 1988 Dollars) 26-66
26.4.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Kammer Unit 1, 2 or 3 ......... . 26-67
26.4.1-7 Summary of DSD/FSI Control Costs for the Kammer Plant
(June 1988 Dollars) ... .......... 26-68
26.4.2-1 Mitchell Steam Plant Operational Data 26-70
26.4.2-2 Summary of Retrofit Factor Data for Mitchell Unit 1 26-71
26.4.2-3 Summary of Retrofit Factor Data for Mitchell Unit 2 .... . 26-72
26.4.2-4 Summary of FGD Control Costs for the Mitchell Plant
(June 1988 Dollars) 26-73
26.4.2-5 Summary of Coal Switching/Cleaning Costs for the Mitchell
Plant (June 1988 Dollars) ...... 26-75
26.4.2-6 Summary of NO Retrofit Results for Mitchell . 26-76
26.4.2-7 NO Control Cost Results for the Mitchell Plant
(June 1988 Dollars) 26-77
26.4.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Mitchell Unit 1 or 2 26-78
26.4.2-9 Summary of DSD/FSI Control Costs for the Mitchell Plant
(June 1988 Dollars) 26-79
26.5.1-1 Mount Storm Steam Plant Operational Data 26-81
26.5.1-2 Summary of Retrofit Factor Data for Mount Storm Unit 1 ... 26-83
26.5.1-3 Summary of Retrofit Factor Data for Mount Storm Unit 2 . . . 26-84
26.5.1-4 Summary of Retrofit Factor Data for Mount Storm Unit 3 ... 26-85
26.5.1-5 Summary of FGD Control Costs for the Mount Storm Plant
(June 1988 Dollars) 26-86
26.5.1-6 Summary of Coal Switching/Cleaning Costs for the Mount Storm
Plant (June 1988 Dollars) 26-87
26.5.1-7 Summary of N0y Retrofit Results for Mount Storm . 26-88
26.5.1-8 NO Control Cost Results for the Mount Storm Plant
(June 1988 Dollars) 26-89
-------
LIST OF TABLES (Continued)
TABLES PAGE
26.5.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Mount Storm Unit 1, 2 or 3 26-91
26.5.1-10 Summary of DSO/FSI Control Costs for the Mount Storm
Plant (June 1988 Dollars) 26-92
rxxi" "i
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ABBREVIATIONS AND SYMBOLS
ABBREVIATIONS
acfm
..
actual cubic feet per minute
AEERL
__
Air and Energy Engineering Research Laboratory
AEP
Associated Electric Cooperative
AFQC
--
allowance for funds during construction
AUSM
--
advanced utility simulation model
-C
--
constant dollars in cost tables
CG
--
coal gasficat ion
CG&E
Cincinnati Gas and Electric
CS
--
coal switching
CS/I
..
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
F8C
--
fluidized bed combustion
FF
--
fabric filter
FGD
..
flue gas desulfurization
FPD
--
fuel price differential
FSI
--
furnace sorbent injection
ft
--
feet
FWF
front, wall-fired
IAPCS
Integrated Air Pollution Control System
\ xxii I
-------
ABBREVIATIONS AND SYMBOLS (Continued)
IRS
--
Internal Revenue Service
KU
Kentucky Utilities
kW
--
kilowatt
kWh
--
killowatt hour
LC
--
low cost
LIMB
--
limestone injection multistage burner
L/LS
--
1ime/1imestone
LNB
--
1qw-N() burner
X
LNC
--
low-NOx combustion
LSD
--
lime spray drying
m
--
meter
MM
--
mill ions
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 Ut11ities
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
jxxiii
-------
SCA
SCR
SCR-CS
SCR-HS
sec
SI
sq ft
TAG
TVA
UARG
USGS
$/kW
SYMBOLS
MgO
NH3
NOx
so2
so3
ABBREVIATIONS AND SYMBOLS (Continued)
-- specific collection area (ft^/1000 acfm)
-- selective catalytic reduction
-- selective catalytic reduction - cold side
-- selective catalytic reduction - hot side
-- second
-- sorbent injection
-- square feet
-- Technical Assessment Guideline
-- Tennessee Valley Authority
-- Utility Air Regulatory Group
-- U.S. Geological Survey
-- dollars per kilowatt
-- magnesium oxide
-- ammonia
-- nitrogen oxides
-- sulfur dioxide
-- sulfur trioxide
) xxiv
-------
ACKNOWLEDGEMENT
We would like to thank the following people at Radian Corporation who helped
in the preparation of this report; Robert Page, Susan Squire,
OoAnn Gilbert, Linda Cooper, Sarah Godfrey, Kelly Martin, Karen Oliver, and
Janet Mangum.
XXV
-------
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 m
Btu/lb 0.5556 kg-calor1es/kg
°F 5/9 (°F-32) °C
ft 0.3048 m
ft2 0.0929 m2
ft3 0.028317 m3
gal. 3.78533 L
lb/MMBtu 1.8 kg/kg-calorie
psia 0.0703 g/cm2
ton 0.9072 ton
1 xxv'i >
-------
SECTION 21.0 PENNSYLVANIA
21.1 ALLEGHENY POWER SERVICE CORP.
21.1.1 Armstrong Steam Plant
The Armstrong Steam Plant is located In Armstrong County, Pennsylvania,
as part of the Allegheny Power Service Corp. system. The plant contains two
coal-fired boilers with a total gross generating capacity of 352 MW.
Tables 21.1.1-1 through 21.1.1-8 summarize the plant operational data and
present the SO, and NO control cost and performance estimates.
L X
TABLE 21.1.1-1. ARMSTRONG STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-EACH) 176
CAPACITY FACTOR (PERCENT) 75
INSTALLATION DATE 1958,59
FIRING TYPE FRONT WALL
FURNACE VOLUME (1000 CU FT) 112
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.9
COAL HEATING VALUE (BTU/LB) 12500
COAL ASH CONTENT (PERCENT) 11
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL/SOLD
STACK NUMBER 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP*
INSTALLATION DATE 1975
EMISSION (LB/MM BTU) 0.02
REMOVAL EFFICIENCY 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0-2.4
SURFACE AREA (1000 SQ FT) 138.2
EXIT GAS FLOW RATE (1000 ACFM) 800
SCA (SQ FT/1000 ACFM) NA
OUTLET TEMPERATURE (°F) 305
* Each boiler has 2 ESPs in series; the original and retrofit
ESPs. An SCA size of 300 was assumed.
21-1
-------
TABLE 21.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ARMSTRONG
UNITS 1 OR 2 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
MEDIUM,
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
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
1.55,l.i
BAGHOUSE CASE
"NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers for units 1 and 2 would be located north
of the common chimney for units 1 and 2. LSD-FGD absorbers
would be beside each unit's existing ESPs.
21-2
-------
fable 21.1.1-3. Surinary of FGD Control Costs for the Armstrong plant (June, 1983 Dollars)
Technology Boiler Main Bailer Capacity Coal Capital Capital Annual Annual SQ2 S02 SQ2 Cost
Nunber Retrofit Size Factor Sulfur Cost Coat Cost Cost Removed Removed Effect.
Difficulty (MV) (X) Content (SHM)
-------
Table 21.1.1-4. Sutmary of Coil Suftching/Cleaning Costs for the Armstrong Plant (SUM) <*ii I Is/kwh) (%) (tans/yrj (S/ton)
factor (%)
CS/B+115
CS/B+$15-C
CS/B+S5
CS/B*tS-C
1,2
1,2
1,2
1,2
1.00 176
1.00 176
1.00 176
1.00 176
75
75
75
75
1.9
1.9
1.9
1.9
7.0 39.6 16.9 14.6 51.0 8564 1971.6
7.0 39.6 9.7 8.4 51.0 8564 1133.2
5.2 29.3 7.0 6.1 51.0 8564 819.0
5.2 29.3 4.0 3.5 51.0 8564 471.9
21-4
-------
TABLE 21.1.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR ARMSTRONG
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
FIRING TYPE FVIF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) 112
INSTALLATION DATE 1958,1959
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 47
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 41
New Duct Length (Feet) 200
New Duct Costs (1000$) 1379
New Heat Exchanger (1000$) 2616
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 4037
COMBINED CASE 6104
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
* Cold side SCR reactors for units 1 and 2 would be located
north of the common chimney for units 1 and 2.
21-5
-------
Table 21.1.1-6. MQx Control Cast Results for the Armstrong Plant (June 1985 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nirtoer Retrofit Size Factor Sulfur Cost Cost Cast Cost Removed Removed Effect.
Difficulty (NW) (X) Content CJWO CS/kV) <$MH) (mil Is/kkrh) m (tons/yr) (l/ton)
Factor (X)
INC-LNS 1,2 1.00 176 • 75 1.9 3.2 18.2 0.7. 0.6 47.0 2253 ¦ 303.5
IMC-IN8-C 1,2 1.00 176 75 1.9 3.2 18.2 0.4 0.4 47.0 2253 193.1
SCR-3 ' 1,2 1.16 176 75 1.9 27.9 15B.4 9.8 8.5 80.0 3835 2555.3
SCR *3 1-2 1.16 352 75 1.9 46.2 131.2 17.2 7.4 80.0 7669 2237.2
SCR-3-C 1,2 1.16 1 76 75 1.9 27.9 158.4 5.7 5.0 80.0 3835 1496.6
SCR-3-C 1-2 1.16 352 75 1.9 46.2 131.2 10.0 4.3 80.0 7669 1308.8
SCR-7 1,2 1.16 176 75 1.9 27.9 153.4 8.4 7.2 80.0 3835 2180.3
SCR-7 1-2 1.16 352 75 1.9 46.2 131.2 14.3 6.2 80.0 7669 1362,4
SCR-7-C 1,2 1.16 176 75 1.9 27.9 158.4 4.9 4.3 80.D 3835 1281.8
SCR-7-C 1-2 1.16 352 75 1.9 46.2 131.2 8.4 3.6 80.0 7669 1094.0
21-6
-------
TABLE 21.1.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ARMSTRONG UNITS 1 AND 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION " LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$) 46
TOTAL COST (1000$)
ESP UPGRADE CASE 46
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
21-7
-------
Table 21,t,1-8. Suimary of DSD/FSi Control Costs for the Armstrong Plant {June 1988 Dollars!
Technology Boiler Hairi Boiler Capacity Coal Capital Capital Amual Annual S02 S02 S02 Cost
Wurtser Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed . Effect,
Difficulty (MO (X5 Content (tMM) <«AW) <*•<) (X) Ctons/y-) (f/ton)
Factor C%1
DSD+ESP 1,2
BS0+ESP-C 1,2
FSI»ESP-50 1,2
FSI+ISP-50-C 1,2
FSI+ESP-70 1,2
FSI+ESP-70-C 1,2
1.00 176 75 1.9 8.6 49.0 8.1 7.0 49.0 8228 990.4
1.00 176 75 1.9 8.6 49.0 4.7 4.1 49.0 8228 572.1
1.00 176 73 1.9 9.4 53.7 8.9 7.7 50.0 8457 1047.9
1.00 176 75 1.9 ,9.4 53.7 5.1 4.4 50.0 8457 605.4
1.00 176 75 1.9. 9.6 ' 54.3 9.0 7.8 70.0 11839 761.2
1.00 176 75 1.9 9.6 54.3 5.2 4.5 70.0 11839 439.7
21-8
-------
21.1.2 Hatfield's Ferry Steam Plant
The Hatfield Ferry steam plant is located within Greene County,
Pennsylvania, as part of the Allegheny Power Service system and operated by
the West Penn Power Company. The plant is located west of the Honongahela
River and contains three coal-fired boilers with a total gross generating
capacity of 1,660 My,
Table 21.1.2-1 presents operational data for the existing equipment at
the Hatfield Ferry plant. The boilers burn medium sulfur coal. Coal
shipments are received by barge and transferred to a coal storage and
handling area north of the plant and adjacent to the river.
PM emissions for the boilers are controlled with ESPs located behind
each unit. The plant has a dry fly ash handl ing system. Almost all the fly
ash is paid disposal. Units 1 through 3 are served by two chimneys.
Chimney 1 serves unit 1 and half of the flue gas from unit 2 while chimney 2
serves the other half and unit 3.
Lime/Limestone and Lime Spray Drying FGD Costs--
The three boilers are located beside each other and parallel to the
river. Boiler houses are close to the river while the chimneys and
switchyard are away from the river. The absorbers for units 1 through 3
would be located behind the chimneys and ash removal equipment. The
limestone preparation, storage, and handling area would be located on a open
space south of the plant. To locate the absorbers behind the chimneys a
storage building, training classroom building, and the wastewater impoundment
tank has to be relocated; therefore, a factor of 15 percent was assigned to
general facilities. In addition, extensive on-site building relocation would
be necessary to locate sludge fixation facilities.
A medium site access/congestion factor was assigned to the FGD absorber
locations because of the close proximity of electric power lines and
excavation of the hillside. For flue gas handling, medium duct runs would be
required for the L/LS-FGD case (over 300 feet). A medium site access/conges-
tion factor was assigned to the flue gas handling system because of the
obstruction caused by ash removal equipment and wastewater treatment facility
around the existing chimney.
21-9
-------
TABLE 21.1.2-1. HATFIELD FERRY 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
555,555,550
51,68,59
1969,70,71
OPPOSED WALL
335.5
NO
2.4
12800
10
DRY HANDLING
PAID DISPOSAL/SOLD
1-2
BARGE
ESP
1969,70,71
0.04
NA
2.0-3.9
311.2
1,733
178
300
21-10
-------
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs are small (SCA =178) 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 also 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 21.1.2-2. Table 21.1.2-3 presents
the process area retrofit factors and capital/operating costs for commercial
FGD technologies. The low cost FGD option reduces capital costs due to
eliminating spare absorber modules and economy of scale when combining FGD
systems and using large absorber modules.
Coal Switching and Physical Coal Cleaning Costs--
Table 21.1.2-4 presents the IAPCS results for CS at the Hatfield Ferry
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 NQX Combustion--
Units 1 through 3 are dry bottom boilers rated at 555, 555, and 550 MW
respectively. The combustion modification technique applied to all boilers
was LNI. The N0X performance estimate was based on the boiler volumetric
heat release rate. Tables 21.1.2-5 and 21.1.2-6 present the NO reduction
A
performance and cost results of retrofitting LNI at the Hatfield Ferry plant.
Selective Catalytic Reduction-
Cold side SCR reactors for all units would be located immediately
behind the chimneys located in medium site access/congestion area, due to the
close proximity of the electric power lines. For flue gas handling, a short
duct length of about 200 feet would be required for each of the units. The
ammonia storage system was placed south of the plant close to the sorbent
preparation area. Although space is available behind the chimneys for SCR
reactors, a road has to be relocated and, as such, a factor of 18 percent was
assigned to general facilities.
21-11
-------
TABLE 21.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR HATFIELD FERRY
UNIT 1,2 OR 3
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM 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 NO
ESTIMATED COST (1000$) NA
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER NO
NA
NA
NA
0
NA
NA
NA
0
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.45
NA
NA
NA
NA
NA
NA
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
21-12
-------
Table 21.1.2-3. Stannary of FGD Control Coses for the Hatfield Plant (June 1983 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital'Annual
Annual
S02
S02
$02 Cost
Nuttier
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
<$MH>
(mills/kwh)
(X)
LC FGO
1-5
1.46
1660
59
2.4
231.7
139.6
131.6
• 15.3
90.0
139539
943.2
LC FGD-C
1-3
1.46
1660
59
2.4
231.7
139.6
76.4
6.9
90.0
139539
547.8
LFGD
1
1.46
555
51
2.4
117.9
212.4
56.2
22.7
90,0
40123
1401.9
LFGD
2
1.46
555
68
2.4
117.9
212.4
62.0
18.a
90.0
53498
1159.2
irsD
3
1.46
550
59
2.4
1.17.3
213.2
58.6
20.6
90.0
45999
1273.8
LFSD-C
1
1.46
555
51
2.4
117.9
212.4
32.8
13. Z
90.0
40123
816.3
IFQD-C
2
1.46
555
65
2.4
117.9
212.4
36.1
10.9
90.0
53498
674.0
IFGD-C
3
; 1.46
550
59
2.4
117.3
213.2
34.1
12.0
90.0
45999
741.3
il
M
I!
1!
II
II
11
II
II
II
II
II
II
II
II
II
II
II
11
II
===¦¦
II
II
II
H
II
U
11
II
It
II
Ik
II
il
11
il
¦..OKun
======
II
H
If
II
II
II
II
II
II
II
II
II
II
II
II
It
II
II
21-13
-------
Table 21.1.2-4, Sunnary of Coal Switching/Cleaning Costs for the Hatfield Plant (June 1988 Dollars)
:SSS3=SS3SS3SSaSSS=SSSS3:=SS8S5SSSS8SS=S8388S::SS3SSrS8SSSSS:SSS83aE3BS8SSS=BSSSSS==SSSSS==Sa3SSS==S8SS=S:23aS=S
Technology
Boiler
Heiri
Boiler Capacity Coal
Capital Capital Annual
Annual
502
S02
S02 Cost
fcunber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (NWJ
(X)
Content
(sm>
CVkW)
CWH)
(nflls/kuh)
E%>
(tans/yr)
CS/ton)
Factor
<*>
CS/B+S15
1
1.00
555
51
2.4
19.2
34.5
36.5
14.7
60.0
26677
1369.9
CS/B+S15
2
1.00
55 S
68
2.4
19.2
34.5
47.3
14.3
60.0
35570
1330.5
CS/B+515
3
1.00
550
59
2.4
19.0
34.5
41.3
14.5
60.0
30584
1348.8
CS/B+$15-C
1
1,00
555
51
2.4
19.2
34.5
21.0
8.5
60.0
26677
738.1
CS/B+S15-C
2
1.00
5S5
£8
2.4
19.2
34.5
27.2
8.2
60.0
35570
764.7
CS/B+f15-C
3
1.00
550
59
2.4
19.0
34.5
23.7
8.3
60.0
30584
775.6
CS/B*$5
I
1.00
555
51
2.4
13.4
24.2
15.1
6.1
60.0
26677
564.5
CS/B+S5
2
1.00
555
<58
2.4
13.4
24.2
19.0
5.8
60.0
35570
534.5
CS/B+IS
3
1.00
550
59
2.4
13.3
24.2
16.8
5.9
60,0
30584
548,4
CS/B+S5-C
1
1.00
555
51
2.4
13,4
24.2
8.7
3.5
60.0
26677
325.7
CS/B+S5-C
2
1.00
555
68
2.4
13.4
24.2
11.0
3.3
60.0
35570
307.9
CS/B+15-C
¦ 3
1.00
550
59
2.4
13.3
24.2
9.?
3.4
60.0
30584
316.2
21-14
-------
TABLE 21.1,2-5. SUMMARY OF NQx RETROFIT RESULTS FOR HATFIELD FERRY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
TYPE OF NOx CONTROL
FURNACE VOLUME (1000 CU FT)
BOILER INSTALLATION DATE
SLAGGING PROBLEM
ESTIMATED NOx REDUCTION (PERCENT)
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 98
New Duct Length (Feet) 200
New Duct Costs (1000$) 2701
New Heat Exchanger (1000$) 5212
TOTAL SCOPE ADDER COSTS (1000$) 8010
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 18
1, 2, 3
OWF
LNB
335.3
1969, 1970, 1971
NO
40
21-15
-------
Table 21.1.2-6. NOx Control Cost Results for the Hatfield Plant (June 1988 Dollars)
Technology
Boiler
Hair>
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nunber Retrofit
¦Siie
Factor
Sulfur
Cost
cost
cost
cost
Removed
Removed
Effect.
Difficulty
Content
CtMM)
C$/kW)
(WW)
(flilUs/kMh)
C%>
Ctons/yr)
It/ton)
Factor
(%)
LNC-LNS
1
1.00
555
51
2.4
5.1
9.1
1.1
0.4
40.0
4001 '
275.0
uMC-LNB
2
1.00
5SS
6a
2.4
5.1
9.1
1,1
0.3
40.0
5335
206.2
IHC-LN3
3
1.00
550
59
2.4
5.1
9.2
1.1
0.4
40.0
4587
239.0
tNC-LNB-C
1
1.00
555
51
2.4
5.1
9.1
0.7
0.3
40.0
4001
163.2
LNC-LMB-C
2
1.00
555
68
2.4
5.1
9.1
0.7
0.2
40.0
5335
122.4
IKC-IMB-C
3
1.00
550
59
2.4
5.1
9.2
0.7
0.2
40.0
4587
141.8
SCR-3
1
1.34
555
51
2.4
73.1
131.8
26.4
10.6
80.0
8002
3297.1
SCR-3
2
1.34
555
68
2.4
73.2
131.8
27.0
8.2
ao.o
10669
2527.9
SCR-3
3
1.34
550
59
2.4
72.7
132.2
26.5
9.3
80,0
9174
2834.2
SCR-3-C
1
1.34
555
51
2.4
73.1
131.8
15.4
6.2
80.0
8002
1930.0
SCR-3-C
2
1.34
555
68
2.4
73.2
131.8
15.8
4.8
ao.o
10669
1479.0
SCR-3-C
3
1.34
550
59
2.4
72.7
132.2
15.5
5.4
80.0
9174
1688.0
SCR-7
1
1.34
555
51
2.4
73.1
131.8
21.9
a.8
80.0
8002
2732.5
SCR-7
Z
1.34
555
63
2.4
73.2
131.8
22.5
6.8
80.0
10669
2104.5
SCR-7
3
1.34
550
59
2.4
72.7
132.2
22.0
7.7
80.0
9174
2396.2
SCR-7-C
1
1.34
555
51
2.4
73.1
131.8
12.9
5.2
80.0
8002
1606.5
SCR-7-C
2
1.34
555
68
2.4
73.2
131.8
13.2
4.0
80.0
'10669
1236.5
SCR-7-C
3
1.34
550
59
2.4
72.7
132.2
12.9
4.5
80.0
9174
1408.4
21-16
-------
Table 21.1.2-5 presents the SCR retrofit factors and scope adder costs.
Table 21.1.2-6 presents the estimated cost of retrofitting SCR at the
Hatfield Ferry boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the Hatfield Ferry steam
plant for all units would be difficult for two major reasons. The ESPs have
small SCAs (<200) and probably would not be able to handle the increased PM.
Therefore, they would require major ESP upgrading and additional plate area.
There is also a short duct residence time between the boilers and ESPs
making the duct runs Inadequate for humidification '(FSI application) and
sorbent evaporation (DSD application). Therefore, the sorbent injection
technologies were not considered for this plant.
Atmospheric F1uidized 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 Hatfield Ferry plant. None of the units would be
considered good candidates for repowering or retrofit because of their large
boiler sizes and high capacity factors.
21.1.3 Mitchell Steam Plant
Boiler 33 at the Mitchell plant is equipped with a Lime-FGD system;
therefore, no further SO,, control technologies were considered for this unit.
Boilers 1-3 were not evaluated because they are not coal-fired. For N0X
control., both SCR and OFA were evaluated for boiler 33.
21-17
-------
TABLE 21.1.3-1, MITCHELL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-3* 33
GENERATING CAPACITY (MM) ' 150 299
CAPACITY FACTOR (PERCENT) OUT OF SERVICE 30
INSTALLATION DATE 1948 1949 1949 1963
FIRING TYPE PETROLEUM TANGENTIAL
FURNACE VOLUME (1000 CU FT) BURNING NA
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 2.6
COAL HEATING VALUE (BTU/LB) 12200.
COAL ASH CONTENT (PERCENT) 12
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD STORAGE/ON-SITE
STACK NUMBER 4
COAL DELIVERY METHODS BARGE/RAILROAD
FGD SYSTEM (TYPE) LIME FGD
FGD SYSTEM INSTALLATION DATE) 19B2
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1973
EMISSION (LB/MM BTU) .0.02
REMOVAL EFFICIENCY 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0-3.0
SURFACE AREA (1000 SQ FT) 125.4
EXIT GAS FLOW RATE (1000 ACFM) 1100
SCA (SQ FT/1000 ACFM) 114
OUTLET TEMPERATURE ( F) 300
* Boiler Nos. 1, 2 and 3 are associated with generating
Unit Nos, 1 and 2 which are rated at 75 MW each.
21-18
-------
TABLE 21.1.3-2, SUMMARY OF NOx RETROFIT RESULTS FOR MITCHELL
. . BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
33
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE 1963
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 Demol111 on (1000$) 61
New Duct Length (Feet) 200
New Duct Costs (1000$) 1881
New Heat Exchanger (1000$) 3596
TOTAL SCOPE ADDER COSTS (1000$) 5538
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for unit 33 would be located beside
the unit 33 chimney.
21-19
-------
Table 21.1.3-3. NOx Control Cose Results for the Mitchell Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual .Annual NOx NOx NOx Cost
Nunber Retrofit Size Factor Sulfur Cost Cost - Cost Cost Removed Rejiwved Effect.
Difficulty (KW3 (%3 Content (»«} (t/kW) <$HH) (miUs/kwh) <%) (tons/yr) ($/ton)
Factor «>
LMC-OFA 33 1.00 299 30 2.6 1.0 3.2 0.Z 0.3 25.0 598 348.4
LNC-OFA-C 33 1.00 299 30 2.6 1.0 3.2 0.1 0.2 25.0 598 206.8
SCR-3 33 1.16 299 30 2.6 41.3 138.0 14.2 18.0 80.0 1914 7407,2
SCR-3-C 33 1.16 299 30 2.6 41.3 133.0 8.3 10.6 80.0 1914 4340.6
SCR-7 33 1.16 299 30 2.6 41.3 t33.0 11.7 14,9 80.0 1914 6126.6
SCR-7-C 33 1.16 299 30 2.6 41.3 138.0 6,9 8.8 80.0 1914 3606.9
21-20
-------
21.2 DUQUESNE LIGHT COMPANY
21.2.1 Cheswick Steam Plant
The Cheswick steam plant is located in a somewhat congested residential,
commercial, and industrial area about 16 miles northeast of Pittsburgh, PA at
Springdale, PA, within Allegheny County, Pennsylvania, as part of the
Duquesne Light Company system. The plant contains one coal-fired boiler with
a total gross generating capacity of 600 MW (net generating capacity of 570
MW). Figure 21.2.1-1 presents the plant plot plan showing the location of
the boiler and major associated auxiliary equipment.
Table 21.2.1-1 presents operational data for the existing equipment at
the Cheswick plant. The boiler burns medium sulfur coal (1.6 percent
sulfur). Coal shipments are received primarily by truck (barge secondary)
and conveyed to a coal storage and handling area located north of the plant.
Particulate matter emissions for the boilers are controlled with ESPs
located behind the unit. The plant has a dry fly ash handling system and is
disposed in a landfill located five miles away from the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.2.1-1 shows the general layout and location of the FGD control
system. The plant is located on a small site surrounded by residential
housing on three sides and the Allegheny River to the south. The absorbers
for L/LS-FGD and LSD-FGD for the unit would be located in available space
west of the powerhouse between the chimney and coal storage and handling
area. Some relocation or demolition of the existing equipment, as well as
the coal pile, would be required; therefore, a factor of 15 percent was
assigned to general facilities. The lime storage/preparation area would be
located south of the plant close to the river with the waste handling area
located adjacent to it.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for L/LS-FGD and LSD-FGD technologies for the unit would
be located adjacent to the chimney, close to the coal storage and handling
21-21
-------
Co^St°raga;
ln9 Area
Coa'Con^eyc,
A'bSQrber
£mp)0yee
Parking Arga
«nostone
H' Storage
System
Urra/r®** Hm
-------
TABLE 21.2.1-1. CHESWICK 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 (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)
600
57
1970
TANG
1.6
12283
12.1
DRY DISPOSAL
OFF-SITE (5 MILES)
1
TRUCK, BARGE
ESP
1970
0.08
98.9
1.8
444
1982
200
310
21-23
-------
area. Another possible location for absorbers would be southwest of the
chimney between the coal conveyor and the river.
A high site access/congestion factor was assigned to the absorbers
location which reflects the congestion created by the surrounding coal
conveyors, powerhouse, coal storage and handling area, sump drainage lines,
towers and underground fuel lines. For flue gas handling, a short duct run
would be required for L/LS-FGD cases since the absorbers are located directly
behind the chimney.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 21.2.1-2. There are no large scope
adder costs for the Cheswick plant. The overall retrofit factors determined
for the L/LS-FGD cases were medium.
The absorbers for LSD-FGD would be located in the same location as
L/LS-FGD cases. LSD-FGD with a new baghouse was the only LSD-FGD technology
considered for the unit because of the difficulty to tie into the upstream of
the ESPs. In addition, the ESPs are marginal in size and might not be able
to handle the additional particulate load generated by applying LSD. The
retrofit factor determined for the LSD technology case was moderate and did
not include particulate control upgrading costs. A separate retrofit
factor was developed for the new baghouse for the unit (1.58) and a high site
access/congestion factor was designated which reflects the difficulty in
locating the new baghouse. This factor was used in the IAPCS model to
estimate particulate control costs.
Table 21.2.1-3 presents the estimated costs for L/LS-FGD and LSD-FGD
cases. 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 module, and optimization of scrubber size.
Plant personnel indicated that the disposal costs are S26/ton, and as such,
this value was used by the Cheswick plant.
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.
21-24
-------
TABLE 21.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CHESWICK UNIT 1
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)
0-100
0-100
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
1.47
1.50
ESP REUSE CASE
NA
BAGHOUSE CASE
1.54
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
15
15
15
~Chimney liner cost is included for relining of the existing
chimney.
21-25
-------
Table 21.2.1-1. Surmary of FGD Control Costa for the Chesuick Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW) (X) Content <$MM) (S/kU) (SMU (%) (tons/yr) (S/:cn>
Factor <%>
LC FGD 1 1.47 600 57 1,6 98.9 164.fi 53,7 17.9 90.0 33885 1565.3
IC FC0-C 1 1.47 600 57 1.6 98,9 164.8 31.2 10.4 90.0 33885 921.4
LFGD 1 1.47 600 57 1.6 123.7 206.2 61,8 20.6 90.0 33885 1822.6
IFGO-C 1 1.47 600 57 1.6 123.7 206.2 35.9 12.0 90.0 33885 1060.6
LSO-FF 1 1.54 600 57 1.6 142.0 236.4 58.4 19.5 87.0 32567 1793.6
ISO+FF-C 1 1.54 600 57 1.6 142.0 236.6 34.1 11.4 87.0 32567 1047.2
5 35 55 SB 286 S5—25S5 *
21-26
-------
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 SOj conditioning or additional plate area was
needed. SOj conditioning was assumed to reduce the needed plate area up to
25 percent. Costs were generated to show the impact of two different coal
fuel cost differentials. The costs associated with each boiler for the range
of fuel cost differential are shown in Table 21.2.1-4.
N0x Control Technology Costs--
This section presents the performance and costs estimated for NO
A
controls at the Cheswick steam plant. These controls include LNC modifica-
tion and SCR. The application of N0X control technologies is determined by
several site-specific factors which are discussed in Section 2. The NO^
technologies evaluated at the steam plant were: -OFA and SCR.
Low N0X Combustion--
Unit 1 is a dry bottom, tangential-fired boiler rated at 565 MW. The
combustion modification technique applied for this evaluation was OFA. As
Table 21.2.1-5 shows, the OFA NO reduction performance for this unit was
X
estimated at 15 percent. This reduction performance level was assessed by
examining the effects of heat release rates and furnace residence time
through the use of the simplified N0X procedures. Table 21.2.1-6 presents the
cost of retrofitting OFA at the Cheswick boiler.
Selective Catalytic Reduction-
Table 21.2.1-5 presents the SCR retrofit results for unit 1. The
results include process area retrofit factors and scope adder costs. The
scope adders include costs estimated for ductwork demolition, new flue gas
heat exchanger, and new duct runs to divert the flue gas from the ESPs to the
reactor and from the reactor to the chimney.
The SCR reactor for unit 1 would be located adjacent to the chimney,
close to the coal storage and handling area in a relatively small area.
Access to this area would be difficult. For this reason, the reactor was
assigned a high access/congestion factor. The reactor was assumed to be in
21-27
-------
Table 21.2,1-4. Sunwry of Coal SwItcMng/Clearrlng Costs for the Cheswick Plant (June 1988 Doltarsi
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annuat 502 502 502 Cast
Murfcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (S/kU) {»«) (miUs/kwfi) (X} (tons/yr) (l/ton)
Factor (X)
CS/B+S15
CS/B+S15-C
cs/a*$5
CS/8«S5-C
1.00 600
1.00 600
1.30 600
1.00 600
57 1.6 19.5 32.5 44.5 14.9
S7 1.6 19.5 32.5 25.6 8.5
57 1.6 13.3 22.1 18.7 6.2
57 1.6 13.3 22.1 10.8 3.6
43.0 16018
43.0 16018
43.0 16018
43.0 16018
2780.4
1598.5
1167.6
672.7
21-28
-------
TABLE 21.2,1-5, SUMMARY OF NOx RETROFIT RESULTS FOR CHESWICK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) 16
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 90.2
FURNACE RESIDENCE TIME (SECONDS) 2.74
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 104
New Duct Length (Feet) 150
New Duct Costs (1000$) 2120
New Heat Exchanger (1000$) 5461
TOTAL SCOPE ADDER COSTS (1000$) 7685
RETROFIT FACTOR FOR SCR 1.52
GENERAL FACILITIES (PERCENT) 17
21-29
-------
Table 21.2.1-6, HOx Control Cost Results for Che CheaMtck Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx MOx NOx Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost . Removed Removed Effect.
Difficulty Content <«•»> (t/kU) (tMH) (mills/kuh) <%> Ctons/rD (S/ton)
Factor (X)
IMC-OFA 1 1.00 600 57 1.6' 1.3 2.1 0.3 ' 0.1 25.0 2263 121.5
LMC-OFA-C 1 1.00 600 57 1.6 1.3 2.1 0.2 0.1 25.0 2263 72.2
SCR-3 1 1.52 600 ' 57 1.6 03.9 139.8 29.8 9.9 . 80.0 .7240 4111.7
SCR-3-C 1 1.52 600 17 1,6 83-9 139.8 17.4 5.8 80.0 7340 24D7.6
SCR-7 1 1.52 600 57 1.6 83.9 ,139.8 24,9 8.3 80.0 7240 3432.5
SCR-7-C 1 1.52 600 57 1.6 83.9 139.8 14.6 4.9 80.0 7240 2018.6
21-30
-------
an area with high underground obstructions. The ammonia storage system was
placed in a remote area having a low access/congestion factor.
In this study, all NOx control techniques were evaluated independently
from those evaluated for SC^ control. As a result, for this plant the FGD
absorbers were located in the same area as the SCR reactor. If both SOg
and N0X emissions have to be reduced at this plant, the SCR reactor would
have to be located downstream of the FGD absorbers (i.e., west of the
chimney) in an area surrounded by the coal conveyors. Once again, a high
access/congestion factor would be assigned to this SCR reactor.
Table 21.2.1-6 presents the estimated cost of retrofitting SCR at the
Cheswick boiler. Plant personnel indicated that fly ash coming out of the
precipitator contain highly corrosive elements which might reduce the
catalyst life. In addition, because of the close proximity of residential
and commercial areas to the plant and possibility of ammonia slip, SCR may
not be feasible at this plant.
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 were located west of the
plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Cheswick steam plant for the unit would be very
difficult because the upgrading of the ESPs would be difficult. Also, there
is not sufficient flue gas ducting residence time between the boiler and the
ESPs. Therefore, a new baghouse was considered for DSD, located in a high
site access/congestion area between the chimney and the coal storage/
handling area. In addition, 300 feet of duct run would be required to
divert the flue gas from the boiler to the baghouse and back to the chimney.
Additional duct residence time could be made available for DSD application
if the existing ESPs were used. For FSI technology, ESP SCAs are small and
21-31
-------
upgrading of the ESPs would be very difficult and, as such, this technology
was riot considered for the Cheswick plant. Table 21.2.1-7 presents a summary
of the site access/congestion factors for DSD technology at the Cheswick
steam plant. Table 21.2.1-8 presents the costs estimated to retrofit DSD at
the Cheswick plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabil ity--
The AFBC retrofit and AFIC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Cheswick plant. The boiler would not be considered a
good candidate for AFBC retrofit due to its large boiler size (565 MW) and
young age (built in 1970) and high capacity factor.
21-32
-------
TABLE 21.2.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CHESWICK UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSDJ HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 3931
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ •' 115
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) NA
A NEW BAGHOUSE CASE (DSD) 4046
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1.58
21-33
-------
Table 21.2.1-8. Suimary of DSO/FSI control Costs for the cheswick Plant (Jine 1988 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (%> Content (SHM) (S/ky) <1UK) (miUs/kuh) (X) (tons/yr) (1/ton)
Factor (%}
DSB*FF 1 1.00 600 57 1.6 84.5 140.8 39.4 13.1 71.0 26638 1477.5
OSD+FF-C 1 1.00 600 57 1.6 84.5 140.8 2Z.9 7.7 71.0 26638 860.7
21-34
-------
21.3 METROPOLITAN EDISON COMPANY
21-3.1 Portland Steam Plant
The Portland steam plant is located within North Hampton County,
Pennsylvania, as part of the Metropolitan Edison Company system. The plant
contains two coal-fired boilers with a total net generating capacity of
426 MW. The two units sit side-by-side parallel to the Delaware River.
Figure 21.3.1-1 presents the plant plot plan showing the location of all
boilers and major associated auxiliary equipment.
Table 21.3.1-1 presents operational data for the existing equipment at
the Portland plant. Both boilers burn medium sulfur coal (2.0 percent
sulfur). Coal shipments are received by railroad and conveyed to a coal
storage and handling area located south of the plant.
Particulate matter emissions from both units are controlled with
retrofit ESPs which are located north of unit 2. The plant has a dry fly ash
handling system and ash is disposed south of the plant below the coal pile.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.3.1-1 shows the general layout and location of the FGD control
system. The absorbers for L/LS-FGD and LSD-F6D for both units could be
located between the chimneys and the river but, because of the close
proximity (chimneys to the river), they were located north of the retrofit
ESPs. No major relocation or demolition would be required for either unit;
therefore, a factor of 5 percent was assigned to general facilities. The
lime storage/preparation area and waste handling area would be located north
of the plant in a very large open area.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for both units would be located in an open area north of
the ESPs with no major obstacles or underground obstructions. The sites are
very accessible and the absorbers were assigned a low site access/ congestion
factor for L/LS-FGD and LSD-FGD technologies.
For flue gas handling, short duct runs for the units would be required
for the L/LS-FGD cases. A low site access/congestion factor was assigned to
21-35
-------
Sin
3c%400
N,
°tto
s°a/e
^9 *a»W,
tr
{~p-~i"l|
**&«•
Employee
Parking Area!
>7
90te
*1.3
'1-1
°mi
*ritf
P19t)t
*1.
3$
Plot
0hn
-------
TABLE 21.3.1-1. PORTLAND STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1 2
GENERATING CAPACITY (MW) 171 255
CAPACITY FACTOR (PERCENT) 52 53
INSTALLATION DATE 1958 1962
FIRING TYPE TANG TANG
COAL SULFUR CONTENT (PERCENT) 2.0 2.0
COAL HEATING VALUE (BTU/LB) 12800 12800
COAL ASH CONTENT (PERCENT) 9.0 8.9
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL/ON-SITE
STACK NUMBER 1 2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1987 1989
EMISSION (LB/MM BTU) 0.04 0.04
REMOVAL EFFICIENCY 99.6 99.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.0-2.3 1.0-2.3
SURFACE AREA (1000 SQ FT) 113 113
EXIT GAS FLOW RATE (1000 ACFM) 584 868
SCA (SQ FT/1000 ACFM) 166 243
OUTLET TEMPERATURE (*F) 266 266
21-37
-------
the flue gas handling system due to the available space around the units with
no obstructions.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 21.3,1-2. No large scope adder cost
is required for the Portland plant. The overall retrofit factor determined
for the L/LS-FGD cases was low.
The absorbers for LSD-FGD would be located in the same location as the
L/LS-FGD cases. LSD-FGD with reuse of the existing ESPs was the only LSD-FGD
technology considered for both units. For flue gas handling, moderate duct
runs would be required and a low site access/congestion factor was assigned
for both units in a similar fashion as L/LS-FGD. The retrofit factor
determined for the LSD technology case was low and did not include additional
costs which might be necessary if upgrading of the existing ESPs is required.
A separate retrofit factor was developed for the ESP upgrading and was low
because there are no major obstacles around the areas close to the ESPs and
the sites are easily accessible. This factor was used in the IACPS model to
estimate the upgrading costs.
Table 21.3.1-3 presents the cost estimates for L/LS and LSD-FGD cases.
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.
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. SQg 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 21.3.1-4.
21-38
-------
TABLE 21.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR PORTLAND UNITS 1 OR 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
RAGHHIJSF ffl^F 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 1.20 1.20
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
21-39
-------
Table 21.3.1-3. Sutmery of FDD Control Costs for the Portland Plant (June 1988 Dollars)
Techrwlofly Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 $02 Cost
Nuifcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (S/kV> (WW) (mi11s/kwh) (X) (tors/yr)
-------
Table 21,3,1*4. Sutmary of Coal Switching/Cleaning Costs for the Portland Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Sfie Factor Sulfur Cost Cost Cost Coat Removed Removed Effect.
Difficulty (MW5 (X) Content [WW) it/kW) (SMH) (miUs/knh) (X) Ctons/yr) (Vtor)
Factor (%>
CS/B»$15
CS/B+S15
CS/B+S15-C
CS/B+S15-C
CS/8+S5
CS/B»I5
CS/B+S5-C
CS/B*$5-C
.00
.00
.00
.00
.00
.00
,00
,00
171
255
171
2S5
171
255
171
255
52
53
52
53
52
53
52
53
2.0
2.0
7.1
8.9
7.1
8.9
5.3
6.3
5.3
6.3
41.3
35.0
41.3
35.0
30.9
24.6
30.9
24.6
12.1
17.7
6.9
10.2
5.3
7.4
3.1
4.3
15.5
14.9
8.9
S.6
~.s
~.3
3.9
3.6
52
52
52
52
6047
9190
6047
9190
6047
9190
6047
9190
1993.2
1920.7
1147.2
1104.8
876.7
305.2
506.2
464.4
21-41
-------
N0X Control Technology Costs--
This section presents the performance and costs estimated for NO
A
controls at the Portland 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 171 and
255 MW, respectively. The combustion modification technique applied for this
evaluation was OFA. As Table 21.3.1-5 shows, the OFA N0X reduction
performance for each unit was estimated to be 20 percent. This reduction
performance level was assessed by examining the effects of heat release
rates and furnace residence time through the use of the simplified NO
A
procedures. Table 21.3,1-6 presents the cost of retrofitting OFA at the
Portland boilers.
Selective Catalytic Reduction--
Table 21.3.1-5 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 both units were located in an open area north of
the ESPs with no major obstacles. For this reason, the reactors for units 1
and 2 were assigned low site access/congestion factors. The ammonia storage
system was placed in a remote area having a low access/ congestion factor.
For this report, all N0X control techniques were evaluated
independently from those evaluated for S02 control. As a result for this
plant, the FGD absorbers were in the same location as the SCR reactors. If
both S02 and N0X emissions have to be reduced at this plant, the SCR
reactors would have to be located downstream of the FGD absorbers in an area
having little obstructions and easy access. The access/congestion factors
that would be assigned to each SCR reactor would be the same as that
21-42
-------
TABLE 21.3.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR PORTLAND
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
1
TANG
2
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
12.1
13.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
71.1
88.7
FURNACE RESIDENCE TIME (SECONDS)
2.74
2.97
ESTIMATED NOx REDUCTION (PERCENT)
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
41
55
New Duct Length (Feet)
o
o
CM
200
New Duct Costs (1000$)
1361 .
1714
New Heat Exchanger (1000$)
2581
. 3268
TOTAL SCOPE ADDER COSTS (1000$)
3983
5037
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
21-43
-------
Table 21.3.1-6. NO* Control Cost Results for the Portland Plant (June 1983 Dollars)
Technology Boiler Main Soilar Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty
-------
discussed above. Table 21.3.1-6 presents the estimated cost of retrofitting
SCR at the Portland boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SOg control
technologies that are under development but have riot 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 beside the
ESPs. The retrofit of DSD and FSI technologies at the Portland steam plant
for all units would be relatively easy. There is sufficient flue gas ducting
residence time between the boilers and the ESPs for sorbent injection. A low
retrofit factor was estimated for upgrading the existing ESPs since the sites
are accessible with no obstacles or congestion. Tables 21.3.1-7 and 21.3.1-8
present a summary of the site access/congestion factors for DSD and FSI
technologies at the Portland steam plant. Table 21.3.1-9 presents the costs
estimated to retrofit DSD and FSI at the Portland 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 Portland plant. Both boilers would be considered good
candidates for AFBC retrofit due to their small boiler sizes (<300 MW) and
their old ages (built before 1960's).
21-45
-------
TABLE 21.3.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR PORTLAND UNIT 1
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 45
TOTAL COST (1000$)
ESP UPGRADE CASE 45
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-46
-------
TABLE 21.3.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR PORTLAND UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$ 60
TOTAL COST (1000$)
ESP UPGRADE CASE 60
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-47
-------
Table 21.3.1-9. S urinary of OSD/FS! Control Costs for the Portland Plant (June 1988 Collars)
Technology Boiler Hain Boiler Capacity Coal Capital Capital Annual Annual S02 S02 $02 Cost
Hunter Retrofit Size Factor Sulfur Coat Cost Cost Cost Removed Removed Effect.
Difficulty (NW> CX) Content Wm <»«) {mills/knh) (X) (tons/yr) (t/ton)
Factor (Jt)
OSD+iSP
DSD+ESP
DSD+ESP-C
DSD+ESP-C
FSl+ESP-50
FSl+ESP-50
FSI+ESP-50-C 1
FSI+ESP-50-C 2
FSI+ESP-70 1
FSI+ESP-70 2
.00
.00
,00
.00
,00
,00
.00
.00
,00
CO
171
255
171
2SS
171
255
171
255
171
255
52
53
52
53
52
53
52
53
52
53
2.0
2.0
2.0
2.0
10.2
11.8
10.2
11.8
11.1
13.2
11.1
13.2
11.2
13.&
59.5
46.1
59.5
46.1
65.1
51.9
65.1
51.9
65.7
52.4
7.4
9.0
4.3
5.2
7.7
10.1
4.5
5.8
7.8
10.2.
9.5
7.6
5.5
4.4
9.9
0.5
5.7
4.9
10.0
8.6
48.0
49.0
48.0
49.0
50.0
50.0
50.0
50.0
70.0
70.0
5654
8626
5654
8626
5836
8869
5836
B869
8170
12417
1314,1
1044,3
761.0
604.4
1320.5
1135.8
765.1
657.4
956.9
824.2
FSI+ESP-70-C
FSI+ESP-70-C
1.00
1.00
171
255
52
53
2.0
2.0
11.2
13.4
65.7
52.4
4.5
5.9
5.8
5.0
70.0
70.0
3170
12417
554.4
477.1
21-48
-------
21.4 PENNSYLVANIA ELECTRIC COMPANY
21.4.1 Conemaugh Steam Plant
The Conemaugh steam plant is located within Indiana County,
Pennsylvania, and operated by the Pennsylvania Electric Company system. The
plant contains two coal-fired boilers with a total gross generating capacity
of 1,872 MW. The two units sit side-by-side and are beside the Conemaugh
River. Figure 21.4.1-1 presents the plant plot plan showing the location, of
all boilers and major associated auxiliary equipment.
Table 21.4.1-1 presents operational data for the existing equipment at
the Conemaugh plant. Both boilers burn medium sulfur coal (2.2 percent
sulfur). Coal shipments are received by truck, rail, and conveyors from a
nearby coal mine and conveyed to a coal storage and handling area located
north of the plant.
Particulate matter emissions for all units are controlled with ESPs
which are located behind each unit. The plant has a dry fly ash handling
system and ash is disposed at a landfill located north of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.4.1-1 shows the general layout and location of the FGD control
system. The boilers are situated such that space from the chimney to the
Conemaugh River is available for the FGD equipment additions. There are two
large recirculating absorbers with natural draft cooling towers located
north of the powerhouse between the river and coal pile. The absorbers for
L/LS-FGD would be located behind the chimneys (south) and, for LSD-FGD, the
absorbers would be located on either side of the ESPs. No major relocation
or demolition would be required for the L/LS-FGD absorbers; therefore, a
factor of 5 percent was assigned to general facilities. However, a storage
building and parking area would need to be demolished and relocated in order
to make space available for the LSD absorbers. As such, a factor of
10 percent was assigned to LSD-FGD general facilities. The lime storage/
preparation area and waste handling area would be located south of the plant
in a very large open area between the coal storage/handling area and river.
21-49
-------
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11-50
-------
TABLE 21.4.1-1. CONEMAUGH STEAM PLANT OPERATIONAL DATA "
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 900
CAPACITY FACTOR (PERCENT) 87.8, 76.2
INSTALLATION DATE 1970,71
FIRING TYPE TANGENTIAL
COAL SULFUR CONTENT (PERCENT) 2.3, 1.9
COAL HEATING VALUE (BTU/LB) 12300
COAL ASH CONTENT (PERCENT) 14.6
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL/ON-SITE
STACK NUMBER k 1-2
COAL DELIVERY METHODS CONVEYOR,TRUCK,RAIL
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1970
EMISSION (LB/MM BTU) 0.05-0.09
REMOVAL EFFICIENCY 99.3
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.5
SURFACE AREA (1000 SQ FT} 557.4
GAS EXIT RATE (1000 ACFM 3100
SCA (SQ FT/1000 ACFM) 181
OUTLET TEMPERATURE ( F) 340
21-51
-------
Retrofit Difficulty and Scope Adder Costs--
The absorbers for both units would be located south of the plant
immediately after the chimneys for both L/LS-FGD and LSD-FGD cases.
The absorbers were assigned a low site access/congestion factor for
L/LS-FGD and LSD-FGD technologies which reflects no major obstacles or
underground obstructions.
For flue gas handling, medium duct runs for both units would be
required for L/LS-FGD cases. A low site access/congestion factor was
assigned to the flue gas handling system due to the fact that there were no
major obstructions around the chimneys.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 21.4.1-2. No large scope adder cost
is required for the Conemaugh plant. The overall retrofit factor determined
for the L/LS-FGD cases was low to medium (1.31).
The absorbers for LSD-FGD would be located on either side of the ESPs.
After demolition and relocation of the storage area and employee parking
area, space would be available for the LSD absorbers with low site
access/congestion factors. LSD-FGD with reused ESP was originally
considered, but with the limited information it was not clear if the ESPs
could handle the increased PM; therefore, LSD with a new FF was considered
for both units. For flue gas handling for LSD cases, moderate duct runs
would be required and a low site access/congestion factor was assigned for
both units. The retrofit factor determined for the LSD technology case was
low (1.27) and did not include particulate control costs. A separate
retrofit factor was developed for new FFs and a low site access/congestion
factor was assigned. This factor was used in the IACPS model to estimate the
new particulate control costs.
Table 21.4.1-3 presents the estimated costs for L/LS and LSD-FGD cases.
The low cost control case reduces capital and annual operating costs. The
significant reduction in costs is primarily due to the elimination of spare
scrubber modules and the optimization of scrubber module 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
21-52
-------
TABLE 21.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CONEMAUGH UNITS 1 OR 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
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
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
1.31
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
10
21-53
-------
Table 21.4.1-3. Sunmery of FGO Control Costs for the Conemaugh Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 $02 Cost
Number Retrofit Size factor sulfur Cost Cost Cost Cost. Removed Removed Effect.
Difficulty (HU) (X) Content (MM) <«/kW> (SW) (miUs/kxh) (%> (tons/yr>
-------
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 21.4.1-4.
Table 21.4.1-4 presents the IAPCS cost results for physical coal
cleaning at the Conemaugh 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 costs estimated for N0x
controls at the Conemaugh steam plant. These controls include LNC
modification and SCR. The application of NOx control technologies is
determined by several site-specific factors which are discussed in
Section 2. The NO technologies evaluated at the steam plant were: OFA and
SCR.
low N0X Combustion--
Units 1 and 2 are dry bottom, tangential-fired boilers, each rated at
936 MW. The combustion modification technique applied for this evaluation
was OFA. As Table 21.4.1-5 shows, the OFA N0X reduction performance for each
unit was estimated to be 20 percent. This reduction performance level
was assessed by examining the effects of heat release rates and furnace
residence time through the use of the simplified N0X procedures.
Table 21.4.1-6 presents the cost of retrofitting OFA at the Conemaugh boilers.
Selective Catalytic Reduction--
Table 21.4.1-5 presents the SCR retrofit results for each unit. The
results include process area retrofit factors and scope adder costs. The
21-55
-------
Table 21.4.1-4. Sunary of Coal 5mitelling/Cleaning Costs for the Conemaugh Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S32 S02 Cost
Nunber Retrofit size Factor sulfur cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (*) Content (SMM) (S/kU) CSMH> (tnills/kyh) (tons/yr)
-------
TABLE 21,4,1-5. SUMMARY OF NQx RETROFIT RESULTS FOR CQNEMAUGH
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)
14.2
14.2
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
84
84
FURNACE RESIDENCE TIME (SECONDS)
3.41
3.41
ESTIMATED NOx REDUCTION (PERCENT)
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
140
140
New Duct Length (Feet)
325
325
New Duct Costs (1000$)
5823
5823
New Heat Exchanger (1000$)
6966
6966
TOTAL SCOPE ADDER COSTS (1000$)
12929
12929
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
21-57
-------
Table 21,4.1-6. NOx Control Cost Results for the Cenemaugh Plant (June 1988 OollarsJ
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NO* HOx Cost
Mwber Retrofit Size Fector Sulfur Cost Cost Cost Cost Removed Renwved Effect.
Difficulty (X) Content <$MM> <*/kU> CW«> (mills/kwh)
-------
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 both units were located south of the plant
immediately after the respective chimneys in an open area on either side of
each unit. For this reason, the reactor locations 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. As a result, for this
plant, the FGD absorbers were in the same location as the SCR reactors. If
both S(L and N0„ emissions have to be reduced at this plant, the SCR
L X
reactors would have to be located downstream of the FGO absorbers in an area
having little obstructions and easy access. The access/congestion factors
that would be assigned to each SCR reactor would be the same as that
discussed above. Table 21.4.1-6 presents the estimated cost of retrofitting
SCR at the Conemaugh boilers.
Sorbent Injection and Repowering--
Both ESPs have marginal SCAs and are located in congested areas making
their upgrades very difficult. As such, they were not considered good
candidates for sorbent injection technologies.
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 Conemaugh plant. None of the boilers would be
considered good candidates for AFBC retrofit due to their large sizes
(936 MW), age (built after I960), and high capacity factors.
21-59
-------
21.4.2 Homer Citv Steam Plant
The Homer City steam plant is located within Indiana County,
Pennsylvania, as part of the Pennslyvania Electric Company and New York State
Electric & Gas. The plant contains three coal-fired boilers with a total
gross generating capacity of 1,850 MW. Figure 21.4.2-1 presents the plant
plot plan showing the location of all boilers and major associated auxiliary
equipment.
Table 21.4.2-1 presents operational data for the existing equipment at
the Homer City pi ant. The boilers burn medium sulfur coal (1.3 to
2.2 percent sulfur). Coal shipments are received by trucks and conveyors
from a nearby coal mine. Coal for unit 3 is extensively cleaned to achieve a
boiler emission rate of 1.2 lb SO^ per million Btu.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit. The plant has a dry fly ash handling system and
is disposed at a landfill located west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
Figure 21.4.2-1 shows the general layout and location of the FGD control
system. Each unit is served by Its own chimney. There are three natural
draft cooling towers located south of the plant close to unit 3. The
absorbers for L/LS-FGD and LSD-FGD for all units would be located immediately
behind the chimneys in a relatively open area. No major relocation or
demolition would be required for any of the units; therefore, a factor of
5 percent was assigned to general facilities. The lime storage/preparation
area would be located west of the plant on the other side of the road and
close to the absorbers; the waste handling area would be located adjacent to
it.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for all units would be located west of the plant behind
the chimney. Ample space is available for the FGD absorbers. The absorber
locations for all units were assigned a low site access/congestion factor
which reflects no major obstacles/obstructions around the absorbers.
21-60
-------
lime/limestone
Storage/Preparation
Area
Ash
Landfill
Waste
Handling Area
NH, Storage
System
Coal
Conveyors
Absorbers
SCR
Reactors
SCR
Reactor
£3
Precipitator
tators
Parking
Storage
Buildings
Cooling
Towers
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Not to scale
Figure 21.4.2-1. Homer City plot plan
21-61
-------
TABLE 21.4.2-1. HOMER CITY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-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
1,2 3
600 650
57.5,72.4 84.7
1969 1977
OWF OWF
1.6 1.6
11300 11900
21.9 14.9
DRY DISPOSAL
LANDFILL/ON-SITE
1-2 3
NEARBY MINE/CONVEYOR,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
1977
0.09-0.06
0.02
99.5
99.3
2.8
2.1
417.9
1144.8
2050
2600
182
410
290
270
21-62
-------
For flue gas handling, medium duct runs for all units would be required
for L/LS-FGD cases since the absorbers are located close to the chimney. A
low site access/congestion factor was assigned to the flue gas handling
system due to major obstacles surrounding the chimney.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 21.4.2-2. There are no large scope
adder costs for the Homer City plant. The overall retrofit factor
determined for the L/LS-FGD cases was low.
The absorbers for LSD FGD would be placed in the same low site
access/congestion locations as L/LS-FGD cases. LSD-FGD with reused ESPs was
the only LSD-FGD technology considered for all units because of their
adequate ESP sizes (SCA-200). For flue gas handling for LSD cases, medium
duct runs would be required to divert the flue gas from the upstream of the
ESPs to the absorbers and back to the ESPs. A medium site access/congestion
factor was assigned to the flue gas handling system for all units. For
units 1-2, the congestion resulted due to the close proximity of the ESPs.
For unit 3, the access difficulty to the upstream of the ESPs resulted from
the close proximity of the ESPs and the powerhouse building. The retrofit
factor determined for the LSD technology case was low (1.31) and did not
include particulate control upgrading costs. Separate retrofit factors were
developed for upgrading the ESPs; low to medium site access/congestion
factors were designated which reflects the available space around the ESPs
if additional plate area is required. The medium site access/congestion
factor reflects the congestion created around units 1 and 2 due to the close
proximity of the ESPs, These factors were used in the IAPCS model to
estimate particulate control upgrading costs.
Table 21.4.2-3 presents the estimated costs for L/LS-FGD and LSD-FGD
cases. The LSD-FGD costs include upgrading the ESPs for boilers 1-3. 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.
Coal Switching and Physical Coal Cleaning Costs--
Coal for unit 3 is already washed, therefore, was not considered in this
study; only costs for units 1 and 2 are presented here. Coal switching can
21-63
-------
TABLE 21.4.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR HOMER CITY UNITS 1,2, OR 3
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
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
300-600
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE (1-2,3)
NA
NA
MEDIUM, 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$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.31
1.31
ESP REUSE CASE
1.31
BAGHOUSE CASE
NA
ESP UPGRADE (1-2,3)
NA
NA
1,36, 1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
5
5
21-64
-------
Table 21.4.2-3. Sunary of FGD Control Costs for the Homer City Plant (Jun* 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annuel
Annual
S02
S02
S02 Cost
Nuntoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (NW>
<*)
Content
(SUM)
(SAW)
(swo
(mflls/icMh)
m
(tons/yr)
($/ton)
Factor
(X)
LC FGD
1-3
1.31
1850
72
1.6
218.8
118.3
137.6
11.8
90.0
142142
968.2
IC FGD-C
1-3
1.31
1850
72
1.6
218.8
118.3
79.8
6.9
90.0
142142
561.6
IFGO
1
1.31
£00
58
1.6
104.0
173.4
52.9
' 17.5
90.0
37617
1406.0
LFGD
2
1.31
600
- 72
1.6
104.0
173.4
57.7
15.2
90.0
47365
1218.0
LFGD
3
1.31
650
85
1.6
111.0
170.7
66.1
13.7
90.0
56569
1168.8
LFGD-C
1
1.31
600
58
1.6
104.0
173.4
30.8
10.2 "
90.0
37617
817.9
L FGD-C
2
1.31
60 0
72
1.6
104.0
173.4
33.5
8.8
90.0
47365
707.7
LFGD-C
3
1.31
650
85
1.6
111.0
170.7
38.4
8.0
90.0
56569
678.4
LS0«ESP
1
1.31
600
58
1.6
75.5
125.9
33.0
10.9
54.0
22439
1470.6
LSD«E$P
2
1.31
600
72
1.6
75.5
125.9
35.4
9.3
54.0
28254
1253.1
".SD»ESP
3
1.31
660
85
1.6
6 7.7
132.6
34.7
7.1
61,0
38914
890.3
LSD+ESP-C
1
1.31
600
58
1.6
75.5
125.9
19.2
6.4
54.0
22439
857.7
LS0*ESP-C
2
1.31
600
72-
1.6
75.5
125.9
20.6
5.4
54.0
28254
729.9
LSD'ESP-C
3
1.31
660
85
1,6
67.7
102.6
20.2
4.1
61.0
38914
518.Z
21-65
-------
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 IARCS 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 21.4.2-4.
Table 21.4.2-4 presents the IAPCS cost results for physical coal
cleaning at Homer City plant. These costs do not include reduced pulverizer
operating costs or system modifications that may be necessary to handle deep
cleaned coal.
NCX Control Technology Costs--
This section presents the performance and costs estimated for N0x
controls at the Homer City steam plant. These controls include LNC
modification and SCR. The application of NOx control technologies is
determined by several site-specific factors which are discussed in
Section 2. The NO technologies evaluated at the steam plant were: LNB' and
SCR.
Low N0X Combustion--
Units 1-3 are dry bottom, opposed wall-fired boilers rated at 600, 600,
and 650 MW, respectively. The combustion modification technique applied for
these boilers was LNB. As Table 21.4.2-5 shows, the LNB N0X reduction
performance for each unit was estimated to be 50 percent. This reduction
performance level was assessed by examining the effects of heat release rates
and furnace residence time through the use of the simplified NOx procedures.
Table 21.4.2-6 presents the cost of retrofitting LNB at the Homer City
boilers.
21-66
-------
Table 21,4.2-4. Surmary of Coat Stiitehirig/Cleaning Costs far the Homer City Plant (June 1988 Dollars)
technology Boiler Main Boiler
Number Retrofit Size
difficulty
Factor"
Capacity Coal Capital Capital Annuel
Factor Sulfur Cost Cost Cost
(X) Content <$WO C»/kW> (SMtt)
Annual S02 S02 SQ2 Cost
Cost Removed Removed Effect,
(milts/kwh) (%)
-------
TABLE 21.4.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR HOMER CITY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
OKF
OWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.8
14.8
11.9
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
79.2
79.2
73
FURNACE RESIDENCE TIME (SECONDS)
3.31
3.31
3.52
ESTIMATED NOx REDUCTION (PERCENT)
50
50
50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
104
104
110
New Duct Length (Feet)
125
125
150
New Duct Costs (1000$)
1767
1767
2222
New Heat Exchanger (1000$)
5461
5461
5730
TOTAL SCOPE ADDER COSTS (1000$)
7332
7332
8062
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
21-68
-------
Table 21.4,2-6. NOx Control Cose Results for the Homer City Plant (June 1988 Dollars)
Technology
Soiler
Ha in
Bailer Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NO* Cost
Nuitoer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
-------
Selective Catalytic Reduction--
Table 21.4.2-5 presents the SCR retrofit results for units 1-3. The
results include process area retrofit factors and scope adder costs. The
scope adders include costs estimated for ductwork demolition, new flue gas
heat exchanger, and new duct runs to divert the flue gas from the ESPs to
the reactor and from the reactor to the chimney.
The SCR reactors for units 1-2 were located immediately behind their
respective chimneys; whereas, the SCR reactor for unit 3 was located west of
the ESPs for unit 3. The three reactors were located in easy access and
open areas. No major relocation or demolition would be required for any of
the units. Therefore, the reactors for units 1-3 were assigned low access/
congestion factors. All reactors were assumed to be in areas with high
underground obstructions. The ammonia storage system was placed in a remote
area having a low access/congestion factor.
As discussed in Section 2, all NO control techniques were evaluated
A
independently from those evaluated for SO^ control. If both SO^ and N0X
emissions needed to be reduced at this plant, the SCR reactors would have
to be located downstream of the FGD absorbers in an area immediately west of
the absorbers. In this case, low access/congestion factors would again be
assigned to all three SCR reactors. Table 21.4.2-6 presents the estimated
cost of retrofitting SCR at the Homer City boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO^ control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located west of the
plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Homer City steam plant for all units would be difficult.
This is due to insufficient flue gas ducting residence time between the
boilers and the ESPs. In addition to the short duct residence time,
21-70
-------
units 1-2 have marginal size ESPs and, as such, they were not considered for
sorbent injection technologies. By contrast, unit 3 ESPs are large and the
first part of the ESPs could be modified for sorbent injection (E-S0X
technology) or humidificat 1 on. Therefore, only unit 3 was considered for
both DSD and FSI applications. Table 21.4.2-7 presents a summary of the site
access/congestion factors for DSD and FSI technologies at the Homer City
steam plant. Table 21.4.2-8 presents the costs estimated to retrofit DSD
and FSI at the Homer City 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 Homer City plant. None of the boilers would be
considered good candidates for AFBC retrofit due to their large sizes
{>600 MW) and high capacity factors.
21.4.3 Keystone Steam Plant
The Keystone steam plant is located within Armstrong County,
Pennsylvania, as part of the Pennsylvania Electric Company system. The plant
contains two coal-fired boilers with a total gross generating capacity of
1,872 MW. Figure 21.4.3-1 presents the plant plot plan showing the location
of all boilers and major associated auxiliary equipment.
Table 21.4.3-1 presents operational data for the existing equipment at
the Keystone plant. Both boilers burn medium sulfur coal (1.5 percent
sulfur). Coal shipments are received by trucks and conveyors from a nearby
coal mine and conveyed to a coal storage and handling area located north of
the plant.
Particulate matter emissions for the boilers are controlled with ESPs
between the boilers and the chimneys. The plant has a dry ash handling
system and the ash is disposed at a landfill located east of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.4.3-1 shows the general layout and location of the FGD control
system. Each boiler has its own chimney and there are four natural draft
21-71
-------
TABLE 21.4.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR HOMER CITY UNIT 3
HEM
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$) 122
TOTAL COST (1000$)
ESP UPGRADE CASE 122
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSENA
21-72
-------
Table 21.4.2-3. Suirary of OSO/FSI Control Costs for the Homer City Plant (June 1988 Dollars)
Technology Bailer Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 SOZ SQ2 Cost
Nuifccr Retrofit Size Factor Sulfur cost cost Cost cost Removed Removed Effect.
Difficulty (MW) (X} Content (MM) C*/kU> (tMN) {.Tii I ls/kuh) (Y) (tons/yr) (S/ton)
Factor
DSO+ESP
3
1.00
660
85
1.6
21.2
32.1
19.7
4.0
41.0
26158
752.1
DSMSP-C
3 •
1.00
660
85
1.6
21.2
32.1
11.4
2.3
41.0
26159
434.6
FStȣSP-50
3
1.00
660
35
1.6
19.8
30.0
25.9
5.3
50.0
31910
812.3
FSI+ESP-5Q-C
3
1.00
660
85
1.6
19.8
30.0
14.9
3.1
50.0
31910
468.2
fSt*ESP-?0
3
1.00
660
85
1.6
20.1
30.4
26.5
5.4
70.0
44674
592.3
•SS+ESP-70-C
3
1.00
660
85
1.6
20.1
30.4
15.2
3.1
70.0
44674
341.4
21-73
-------
N
Office
Building
Absorber
for Unit 2
/-v Cooling
Towers
NHj wtOf3Q6
System
Switchyard
Waste
Handling Area
Cooling
Towers
Lime/Limestone
Absorber Storage/Preparation
for Unit 1 Area
Coal Storage/
Handling Area
Coai
Conveyor
Not to scale
FGD Waste Handling/Absorber Ares
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 21.4.3-1. Keystone plant plot pi
an
21-74
-------
TABLE 21.4.3-1. KEYSTONE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-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
1,2
936
89.3, 72.7
1967, 68
TANGENTIAL
1.5
12350
14.1
DRY
QN-SITE/LANDFILL
1-2
NEARBY MINE/CONVEYORS,TRUCK
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
...
rn
ESP
1967,1968
0.05
99.3
1.3-1.5
561.6
3000
187
330
21-75
-------
cooling towers (two on each side of the powerhouse). The absorbers for
L/LS-FGD and LSD-FGD for both units would be located adjacent to the
powerhouse and chimneys. The unit 1 absorbers would be located to the
southwest of the unit 1 chimney while the absorber for unit 2 would be
located to the east of the powerhouse, beside the unit 2 chimney. A factor
of 5 percent was assigned to general facilities for unit 1 since there would
be no major relocation/demolition required. For unit 2, relocation or
demolition of a storage building and relocation of a road would be required;
therefore, a factor of 8 percent was assigned to general facilities. The
lime storage/preparation area would be located in a large open area south of
the coal storage and handling area close to the unit 2 absorbers; the waste
handling area would be located adjacent to the storage/preparation area.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for unit 1 would be located immediately west of the
respective chimney, the unit 2 absorbers would be located beside the chimney
in a very large open area.
A low site access/congestion factor was assigned to the unit 1
absorbers since there will be no other obstructions in the area after
demolition of the storage building. The location of the absorber for unit 2
was also assigned a low site access/congestion factor which reflects the
available space behind the chimney.
For flue gas handling, medium duct runs for both units would be required
for L/LS-FGD cases. A low site access/congestion factor was assigned to the
flue gas handling system due to the close location of the absorbers to the
chimneys with no major obstructions in the surrounding area.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 21.4.3-2 and 21.4.3-3. No large
scope adder cost is required for the Keystone plant. The overall retrofit
factor determined for the L/LS-FGD cases was low to medium (1.31).
The absorbers for LSD-FGD would be located in the same location as
L/LS-FGD cases. LSD-FGD with new FFs was the only LSD-FGD technology
considered for both units. For flue gas handling for LSD cases, moderate
duct runs would be required. A low site access/congestion factor was
assigned to flue gas handling for both units. The retrofit factor determined
21-76
-------
TABLE 21.4.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR KEYSTONE UNIT 1
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 , NA
RAGHfilJSF fASF I OW
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 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 1.31 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
21-77
-------
TABLE 21.4.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR KEYSTONE 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 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 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 1.31 1.31
ESP REUSE CASE NA
BAGHOUSE CASE 1.27
ESP UPGRADE . NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 8 8 8
21-78
-------
for the LSD technology case was low (1.27) and did not include new
particulate control costs. A separate retrofit factor was developed for the
new FFs (1.16). This factor was used 1n the IAPCS model to estimate new
particulate control costs.
Table 21.4.3-4 presents the estimated costs for L/LS-FGD and LSD-FGD
cases. The LSD-FSD costs include new FFs 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.
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.
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 21.4.3-5.
Table 21.4.3-5 presents the IAPCS cost results for physical coal
cleaning at Keystone 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 costs estimated for N0X
controls at the Keystone 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 NQX technologies evaluated at the steam plant were:
OFA and SCR.
21-79
-------
Table 21.4.3-4. $ urinary of FGD Control Costs for the Keystone Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity coal Capital capital Annual Annual S02 SQ2 SG2 Cost
Nunber Retrofit Size Factor Sulfur Cost Cast Cost Cost Removed Removed Effect.
Difficulty (HW) (X) content (IMK5 Cf/kW) (SHM) (mHls/kuh) <%) (tsns/yr) ($/ten)
Factor (X)
LC FGD
LC FCD-C
1-2
1-2
1.31 1872
1.31 1872
64
81
1.5
219.8 117.4 127.0 12.1
219.9 117.5 82.5 6.2
90,0 110594
90.0 139970
1H8.0
589.2
LFGO
IFGD
1.31
1.31
936
936
89
73
1.5
1.5
142.5 152.2 87.3
144.8 154.7 80.4
11.9
13.5
90.0
90.0
77156
62814
1131.2
1280.4
LFGD-C
LFGD-C
1 1.31 936 89 1.5 142.5 152.2 50.6 6.9 90.0 77156 656.4
2 1.31 936 73 1.5 144.8 154.7 46.7 7.8 90.0 62814 743.9
LSD+FF
LSD+FF
1 1.27 936 89 1.5 170.0 181.6 74.9 10.2 87.0 74156 10Q9.4
2 1.27 936 73 1.5 171.6 183.3 70.1 11.8 87.0 60371 1161.5
LSD+FF-C
LSD+FF-C
1.27 936 39 1.5 170.0 181.6 43.6 6.0 87.0 74156 588.6
1.27 936 73 1.5 171.6 183.3 40.9 6.9 87.0 60371 678.2
21-80
-------
Table 21.4.3-5. Sunnary of Coal Switehfng/Cleaning Costs for the Keystone Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitaer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NU> (X> Content ($MH) (S/kW) (aills/kuh) (X) (tons/yr) (i/ton)
Factor (X)
CS/B+S1S
CS/B+S15
1.00
1 .DO
936
936
89
73
1.5
1.5
33.2
33.2
35.5
35.5
1Q0.4
83.1
13.7
13.9
38.0
33.0
32860
26752
3056.9
3107.9
CS/8+S15-C
CS/3»H5-C
CS/B+*5
CS/B+$5
CS/8»t5"C
CS/B«-$5-C
PCC
PCC
PCC-C
PCC-C
.00
.00
.00
.00
00
00
00
00
00
00
936
936
936
936
936
936
936
936
936
936
89
73
89
73
89
73
89
73
89
73
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
1.5
33.2
33.2
23.5
23.5
23.5
23.5
17.2
17.2
17.2
17.2
35.5
35.5
25.2
25.2
25.2
25.2
16.4
18.4
18.4
18.4
57.7
47.8
33.3
32.2
22.0
18.6
19.4
16.6
11.2
9.6
7.9
8.0
5.2
5.4
3.0
3.1
2.6
2.8
1.5
1.6
38.0
38.0
33.0
38.0
33.0
38.0
28.0
28.0
28.0
28.0
32860
26752
32860
26752
32860
26752
24052
19581
24052
19551
1756.0
1786.2
1164.8
1203.9
670.6
693.7
805.4
845.5
464.6
488.3
21-81
-------
Low N0X Combustion--
Units 1 and 2 are dry bottom, tangential-fired boilers, each rated at
936 MW. The combustion modification technique applied for this evaluation
was OFA. As Table 21.4.3-6 shows, the OFA NOx reduction performance for each
unit was estimated to be 20 percent. This reduction performance level was
assessed by examining the effects of heat release rates and furnace residence
time through the use of the simplified NOx procedures. Table 21.4.3-7
presents the cost of retrofitting OFA at the Keystone boilers.
Selective Catalytic Reduction--
Table 21.4.3-6 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 building and ductwork demolition,
new flue gas heat exchanger, and new duct runs to divert the flue gas from
the ESPs to the reactor and from the reactor to the chimney.
The SCR reactor for unit 1 would be located near the chimney for unit 1
and west of the coal storage and handling area. The SCR reactor for unit 2
would be located to the east of the powerhouse in an area near the chimney
for unit 2. Demolition of a storage building would be needed for
retrofitting the reactor. After demolition of the storage building, the
reactor would be located in an easy access area having no major
obstructions. Therefore, the reactors for units 1 and 2 were assigned low
access/congestion factors. Both reactors were assumed to be in areas with
high underground obstructions. The ammonia storage system was placed in a
remote area having a low access/congestion factor.
As discussed in Section 2, all N0X control techniques were evaluated
independently from those evaluated for SO^ control. As a result for this
plant, the FGD absorbers were in the same location as the SCR reactors. If
both SC>2 and N0X emissions have to be reduced at this plant, the SCR
reactors would have to be located downstream of the FGD absorbers in an area
having little obstructions and easy access. The access/congestion factors
that would be assigned to each SCR reactor would be the same as that
discussed above. Table 21.4.3-7 presents the estimated cost of retrofitting
SCR at the Keystone boilers.
21-82
-------
TABLE 21.4.3-6. SUMMARY OF NQx RETROFIT RESULTS FOR KEYSTONE
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
1
TANG
2
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.4
14.4
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
84.2
84.2
FURNACE RESIDENCE TIME (SECONDS)
6.78
6.78
ESTIMATED NOx REDUCTION (PERCENT)
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
173
NA
Ductwork Demolition (1000$)
145
145
New Duct Length (Feet)
150
150
New Duct Costs (1000$)
2750
2750
New Heat Exchanger (1000$)
7131
7131
TOTAL SCOPE ADDER COSTS (1000$)
10199
10026
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
21-83
-------
Table 21.4.3-7. NOx Control Cost Results for the Keystone Plant tJune 1988 Dollars)
;;;ssss=s3s:sssssssss3issS3s;sss3s3ssssssssss3sss==3s:sssss3Ss:sb3bss::s:sss35:5"":ssss:ssss£;9si39ss;:s;s=::::s
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NQx Cost
Nuifcer Retro-fit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty l$/kU) (SMtt) (miUi/kwh) (X) Ctons/yr)
-------
Sorbent Injection and Repowering--
The ESPs are small and may not be able to handle the increased PM load
if sorbent injection technologies are applied. As such, sorbent injection
technologies were not considered for this 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 Keystone plant. Neither of the boilers would be
considered good candidates for AFBC retrofit due to their large boiler
sizes (>900 MW) and high capacity factors.
21.4,4 Seward Steam Plant
The Seward steam plant is located within Indiana County, Pennsylvania,
as part of the Pennsylvania Electric Company system. The plant is bounded by
the Conemaugh River and a railroad track. The plant contains two active
coal-fired boilers with a total gross generating capacity of 200 MW.
Figure 21.4.4-1 presents the plant plot plan showing the location of all
boilers and major associated auxiliary equipment.
Table 21.4.4-1 presents operational data for the existing equipment at
the Seward plant. The boilers burn low to medium sulfur coal (1.5 percent
sulfur). Coal shipments are received by truck and conveyed to a coal storage
and handling area located south of the plant.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit. Flue gases from the ESPs are combined into one
common chimney. The plant has a dry fly ash handling system and is disposed
on-site at a landfill located beside the coal pile.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.4.4-1 shows the general layout and location of the FGD control
system. The boilers share a common chimney located between the coal pile and
powerhouse. The absorbers for L/LS-FGO and LSD-FGD for both units would be
located in the current employee parking area east of the powerhouse. Part of
the plant roads and employee parking area would need to be demolished/
21-85
-------
¦N
Employee
Parking Area
Switchyard
Powerhouse
cm C3
_ o ,
'Chimney/
Coal
' Conveyors <
Absorbers
/ NH, Storage
/ System
k
SCR
Reactors
Coal Handling
Area
Waste
Handling Area
llme/Umestone
^Storage/Preparation
Area
H f-
Not to scale
FG0 Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 21.4.4-1. Seward plant plot plan
21-86
-------
TABLE 21.4.4-1. SEWARD 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
4 5
63 137
63.1 62.1
1950 19S7
FRONT WALL
1.5 1.5
12100 12100
13.5 13.5
DRY DISPOSAL
ON-SITE LANDFILL
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
1960
= 1957
0.06
0.06
99,5
99.4
NA
1.5
29.6
180
200
580
148
310
310
290-320
21-87
-------
relocated; therefore, a factor of 10 percent was assigned to general
facilities. The lime storage/handling area would be located adjacent to the
coal pile south of the absorbers with the waste handling area located
adjacent to the absorbers.
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 the employee parking area
with no major obstacles or major underground obstruction close to the coal
pile beside the powerhouse.
For flue gas handling, long duct runs for the units would be required
for L/LS-FGD cases to divert the flue gas from the boilers 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 21.4.4-2. No large scope adder cost
is required for the Seward plant. The overall retrofit factor determined
for the L/LS-FGD cases was medium (1.37).
The absorbers for LSD-FGO would be located in a similar location as in
L/LS-FGD cases. A long duct run would be required and a low site
access/congestion factor was assigned for the same reasons as stated above in
L/LS-FGO cases. The ESPs are located in a very high site access/congestion
area and cannot be upgraded easily. Therefore, a new baghouse was the only
LSD-FGD technology considered for the units. The baghouse location would be
the same as for L/LS-FGD and a low site access/congestion factor was assigned
to this location. For flue gas handling for LSD cases, long duct runs would
be required to divert the flue gas from the boilers to the absorbers/baghouse
and back to the chimney. The retrofit factor determined for the LSD
technology case was medium (1.34) and did not include particulate control
costs. A separate retrofit factor was developed for the new baghouse for the
units. A low retrofit factor (1.16) was assigned to the baghouse location
for the units due to its location in the present employee parking area. This
factor was used in the IAPCS model to estimate particulate control costs.
21-88
-------
TABLE 21.4,4-2. SUMMARY OF RETROFIT FACTOR DATA FOR SEWARD UNITS 4 OR 5
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 NA
BAGHOUSE CASE LOW
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 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 1.37 1.37
ESP REUSE CASE NA
BAGHOUSE CASE 1.34
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 10 10 10
21-89
-------
Table 21.4.4-3 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 4 and 5. 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.
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. SO^ conditioning was assumed to reduce the needed plate area up to
25 percent.
Costs were generated to show the impact of two different coal fuel cost
differentials. The costs associated with each boiler for the range of fuel
cost differential are shown in Table 21.4.4-4.
NOx Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Seward 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: LNB and SCR.
Low N0X Combustion-
Units 4 and 5 are dry bottom, front wall-fired boilers rated at 68 and
125 MM, respectively. The combustion modification technique applied for
these boilers was LNB. As Table 21.4.4-5 shows, the LNB NCL reduction
x
performance for only unit 5 was estimated to be 50 percent. No boiler
information could be found for unit 4 to assess its NOx reduction
21-90
-------
Tabl* 21.4,4-3. Suimary of FSD Control Costa for the Sewerd Plant (June 1988 Dollars)
3S 3 SSSSSS33 3 383 SS&SSB9SSBS5S S33S5SS9SS23893SZSS3S SSSS33SSSSBBBS3S SSES2™2SSS2SS85SSS""*"'""'S5SS™?™2" —¦~3SB2;**--<
Technology
Soiler Main
Boiler Capacity Coal
Capital Capital.Annual
Annual
S02
S02
502 Cost
Miraber Retrofit
Six#
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Rwnoved
Effect.
Difficulty
LC PCS
4*5
1.37
200
62
1.5
37.1
185.3
20.4
18.6
90.0
11794
1726.1
LC FGD-C
4-5
1.37
200
62
1.5
37.1
185.3
11.8
10.8
90.0
11794
1003.0
ifgd
4
1.37
63
63
1.5
30.6
486.2
14.1
40.4
90.0
3757
3747.3
LFGC
5
1.37
137
62
1.5
44.3
323.2
20.7
27.8
90.0
3040
2580.7
LFGD
4-5
1.37
200
62
1.5
55.7
278.3
26.4
24.1
90.0
11794
2236.1
LFGD-C
4
1.37
63
63
1.5
30.6
486.2
8.2
23.6
90.0
3757
2183.5
LFGD-C
5
1.37
137
62
1.5
44.3
323.2
12.1
16.2
90.0
8040
1503.2
LFOD-C
4-5
1.37
200
62
1.5
55.7
278.3
15.4
14.0
90.0
11794
1302.3
LS0*FF
4
1.34
S3
63
1.5
19.4
308.5
8.9
25.6
87.0
3611
2472.5
LSD+FF •
5
1.34
137
62
1.5
33.5
244.6
14,1
18.9
87.0
7727
1826.4
ISD+Ff-C
4
1,34
63
63
1.5
19.4
308.5
5.2
14.9
87.0
3611
1440.7
LSD+FF-C
5
1.34
137
62
1.5
33.5
244.6
8.2
11.1
87.0
7727
1065.8
S555S5S
BISS8IZ1S1
ISSSSSS3
'IIBBSZS1
•suasaaj
IS9SSS88S
;i88BSiai
wsaisss
«»KB8SBXHS
S18I1B!
II
H
N
H
11
N
558S5SSS
21-91
-------
Table 21.4.4-4. Simmry of Coal Switching/Cleaning Costs for the Seward Plant (Ji#w 1985 Dollars)
Technology Boiler Nain Boiler Capacity Coal Capital Capital Annual Annual S02 SQ2 S02 Cost
Ninber Retrofit Site factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
TABLE 21.4.4-5. SUMMARY OF NOx RETROFIT RESULTS FOR SEWARD UNITS 4-5
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
12.9
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR}
NA
49.8
FURNACE RESIDENCE TIME (SECONDS)
NA
3.01
ESTIMATED NOx REDUCTION (PERCENT)
25
50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
19
34
New Duct Length (Feet)
550
600
New Duct Costs (1000$)
2080
3574
New Heat Exchanger (1000$)
1413
2251
TOTAL SCOPE ADDER COSTS (1000$)
3511
5860
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
25
25
21-93
-------
performances. Since unit 4 is relatively old, it is estimated that a NO
A
reduction of 20 to 30 percent can be achieved by this boiler retrofitted with
LNB; unit 4 was Installed in 1950. The reduction performance level for unit
5 was assessed by examining the effects of heat release rates and furnace
residence time through the use of the simplified NQX procedures.
Table 21.4.4-6 presents the cost of retrofitting LNB at the Seward
boilers. The cost of retrofitting LNB for unit 4 was estimated assuming a
25 percent N0X reduction.
Selective Catalytic Reduction-
Table 21.4.4-5 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 ESP to the
reactor and from the reactor to the chimney.
The SCR reactors for units 4 and 5 would be located side-by-side in the
current parking lot east of the powerhouse. Part of the plant road and
employee parking lot would need to be demolished and relocated; therefore, a
factor of 25 percent was assigned to general facilities for both reactors.
Since the reactors were located in an open area having easy access with no
major obstacles, the reactors for units 4 and 5 were assigned low access/
congestion factors. Both reactors were assumed to be in areas with high
underground obstructions. The ammonia storage system was placed in a remote
area having a low access/congestion factor.
As discussed in Section 2, all N0X control techniques were evaluated
independently from those evaluated for S02 control. Using this scheme, both
the SCR reactors and the FSD absorbers were located in the same area. If
both SOg and N0X emissions needed to be reduced at this plant, the SCR
reactors would have to be located downstream of the FGD absorbers
(i.e., north of the absorbers) in an relatively open area. In this case, low
access/congestion factors again would be assigned to both SCR reactors.
Table 21.4.4-5 presents the estimated cost of retrofitting SCR at the Seward
boilers.
21-94
-------
Table 21.4.4-6. mqx Control Cost Results for the Seward plant (June 1988 Dollars)
Technology Sotler Ha in Boiler Capacity Coat Capital Capital Annual Annual NQx NO* NQx Cost
Nunber Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HWJ (X) Content (SMM) (»/kM> («H) (raitls/kMh) «) Ctons/yr) ($/ton>
Factor (X)
LNC-INB 4 1.00 63 63 1.5 2.1 33.7 0.5 1.3 25.0 375 1229.8
INC-LNfi 5' 1.00 137 62 1.5. 2.9 21.1 0.6 0.8 50.0 1601 392.1
LNC-INB-C 4 1.00 63 63 1.5 2,1 33.7 0,3 0.8 25.0 375 730.1
LNC-LNB-C 5 1.00 137 62 1.5 2.9 21.1 0.4 0.5 50.0 1603 232.8
SCR-J 4 1.16 63 63 1.5 15.9 252.9 4.9 14.2 80.0 1199 4125.2
SCR-3 5 1.16 137 62 1.5 26.2 191.0 8.5 11.4 80.0 2565 3310.3
SCS-3-C 4 1,16 63 61 1.5 15,9 252.9 2,9 8.3 80.0 1199 2423.0
SCR-3-C 5 1.16 137 62 1.5 26,2 191.0 5.0 6.7 80.0 2565 1942.3
SCR-7 4 1.16 63 63 1.5 15.9 252.9 4.4 12.7 80.0 1199 3693.9
SCR-7 5 1.16 137 62 1.5 26.2 191,0 7.4 9.9 80.0 2565 2872.0
SCR-7-C 4 1.16 63 63 1.5 15.9 252.9 2.6 7.5 80.0 1199 2175.9
SCR-7-C 5 1.16 137 62 1.5 26.2 191.0 4.3 5.8 80.0 2565 1691.2
21-95
-------
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 retrofit of DSD and FSI technologies at the Seward steam plant for
the units would be difficult. There is not sufficient duct residence time
between the boilers and the ESPs, and the ESPs themselves are small as well.
As such, sorbent injection technologies were not considered for this plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi1 ity--
The AFBC retrofit and AFBC/CG repowering applicabi1ity criteria present-
ed in Section 2 were used to determine the applicability of these technolo-
gies at the Seward plant. Both boilers would be considered good candidates
for AFBC retrofit because of their small boiler sizes (<130 MW) and ages
(built before 1960).
21.4.5 Shawville Steam Plant
The Shawville steam plant is located on the Susquehanna River in Clear-
field County, Pennsylvania, and is operated by the Pennsylvania Electric
Company. The Shawville plant contains four coal-fired boilers with a gross
generating capacity of 627 MW.
Table 21.4.5-1 presents operational data for the existing equipment at
the Shawville plant. Coal shipments are received by truck and transferred
to a coal storage and handling area east of the plant. PM emissions from the
boilers are controlled by the retrofit ESPs which were added to the original
ESPs. The ESPs for units 1 and 2 are roof mounted and for units 3 and 4 they
are located behind the boilers. Flue gases from boilers 1 and 2 are directed
to a chimney located between units 2 and 3. Another chimney located behind
the ESPs/old chimneys serves units 3 and 4. Dry fly ash from the units is
1andfi1 led by the utility.
21-96
-------
TABLE 21.4.5-1. SHAWVILLE 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
132
68.4,75.6
1954
FRONT WALL
50.7
NO
3,4
181.5
21.2,57.8
1959,60
TANGENTIAL
96
NO
2.0
12200
13.3
DRY DISPOSAL
LANDFILL
2
TRUCK
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (4F)
ESP
ESP
1976
1976
0.04
0.06
99.4
99.5
2.0
2.0
124
206
550
660
225
311
300
290
21-97
-------
Lime/Limestone arid Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located behind the
boilers. The general facilities factor is high (15 percent) for this
location because several storage buildings and a parking lot would have to be
relocated. The site access/congestion factor is also high for this location
because of the proximity of the coal pile, coal conveyor, and the unit 3 and
4 ESPs. Between 300 and 600 feet of ductwork would be required to reach the
roof- mounted ESPs for units 1 and 2. A high site access/congestion factor
was assigned to flue gas handling because of the difficulty in accessing the
chimney. L/LS-FGD absorbers for units 3 and 4 would be located west of the
unit 3 and 4 chimney next to the coal pile. A high general facilities factor
was assigned to this location because a large storage building would have to
be relocated. The site access/congestion factor was high for this location
because of the proximity of the coal pile and a railroad line. Between 300
and 600 feet of ductwork would be required and a high site access/congestion
factor was assigned to flue gas handling.
LSD with reuse of the existing ESPs was not considered for units 1 and
2 because of the difficulty involved with upgrading the roof mounted ESPs.
However, LSD with a new baghouse could be used for these units. The LSD-FGD
absorbers and baghouses would be located similarly to the wet FGD absorbers
with similar site access/congestion and general facilities factors as well
as ductwork requirements. LSD-FGD with reuse of the existing ESPs was
considered for units 3 and 4. The absorbers would be located similarly to
the wet FGD absorbers for these units with similar site access/congestion and
general facilities factors. About 700 to 900 feet of ductwork would be
re-quired to access the upstream side of the unit 3 and 4 ESPs. A high site
access/congestion factor was assigned to flue gas handling for both units
because of the congestion caused by the ductwork between the ESPs and the
old chimneys for these units.
Tables 21.4.5-2 through 21.4.5-4 present retrofit factor inputs to the
IAPCS model and cost estimates for installation of conventional FGD
technologies at the Shawville plant.
21-98
-------
TABLE 21.4.5-2. SUMMARY OF RETROFIT FACTOR DATA FOR SHAWVILLE
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.91
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.92
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT) 15
0
15
21-99
-------
TABLE 21.4.5-3. SUMMARY OF RETROFIT FACTOR DATA FOR SHAWVILLE
UNIT 3 OR 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH . NA
ESP REUSE CASE HIGH
BAGHOUSF fASF NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER YES YES
RETROFIT FACTORS
FGD SYSTEM 1.91 NA
ESP REUSE CASE Z.06
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
21-100
-------
Table 21.4.5-4. Summary of FGD Control Costs for the Shawville Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capitat Capital Annual
Annual
S02
502
S02 Cost
Nuifcer
Retrofi t
Si le
Factor Sulfur
Cost
Cost
Cost
Cost
Removes
Removed
Effect.
D
ifficulty (MM)
(X)
Content
(SHN)
Ct/kH)
(SMM)
(mHis/lcuh)
<*>
(tons/yr)
(S/ton)
............
.........
Factor
.......
.......
(X)
.........
........
.......
...........
.......
.........
........
LC FGD
1-2
1.91
264
¦72
2.0
61.0
231.1
32.6
19.6
90.0
23726
1376.1
LC FGD
3-4
1.91
363
40
2.0
83.2
229.3
36.7
29.2
90.0
17897
2050.1
IC FfiC-C
1-2
1.91
264
72
2.0
61.0
231.1
19.0
11.4
90.0
23726
799.9
LC FGD-C
5-4
1.91
363
40
2.0
83.2
229.3
21.4
17.0
90.0
17897
1195.4
I FGD
1
1.91
132
68
2.0
62.0
469.4
27.5
34.8
90.0
11270
2438.9
I FGD
2
1.91
132
76
2.0
62.0
469.4
28.1
32.2
90.0
12456
2256.8
LFGD
3
1.91
182
21
2.0
74.3
409.3
27-8
82.5
90.0
4803
5789.4
LFGD
4
1.91
182
58
2.0
74.3
409.6
32.2
35.0
90.0
13094
2456.7
LFGD
1-2
1.91
264
72
2.0
93.7
354.9
43.3
26.0
90.0
23726
1824.6
LFGD
3-4
1.91
363
40
2.0
111.8
307.9
46.0
36.6 -
90.0
17897
2568.8
LFGO-C
1
1.91
132
68
2.0
62.0
469.4
16.0
20.3
90.0
11270
1422.0
LFGD-C
2
1.91
132
76
2.0
62.0
469.4
16.4
18.7
90.0
12456
1315.3
LFCD-C
3
1.91
1B2
2!
2.0
74.3
409.3
16.3
48.3
90.0
4803
3386.3
LFCO-C
4
1.91
182
58
2.0
74.3
409.6
18.8
20.4
90.0
13094
1433.0
LFGD-C
1-2
1.91
264
72
2.0
93.7
354.9
25.2
15.1
90.0
23726
1Q63.1
LFGD-C
3-4
1.91
363
40
2.0
111.8
307.9
26.8
21.4
90.0
17897
1499.B
LSD+ESP
3
2.06
162
21
2.0
37.4
206.1
14.2
42.3
70.0
3732
3817.7
LSD+ESP
4
2.06
182
58
2.0
37.4
206.1
16.1
17.5
70.0
10176
1583.8
ISC+CSP-C
3
2.06
182
21
2.0
37.4
206.1
8.3
24.7
70.0
3732
2232.3
LSD+ESP-C
4
2.06
182
58
2.0
37.4
206.1
9.4
10.2
70.0
10176
923.9
LSO+FF
1
1.92
132
68
2.0
46.3
350.4
18.2
23.0
85.0
10627
1709.9
LSD+FF •
2
1.92
132
76
2.0
46.3
350.4
18.5
21.2
85.0
11746
1576.9
LSO+FF-C
1
1.92
132
68
2.0
46.3
350.4
10.6
13.4
85.0
10627
999.2
LSD+FF-C
2
1.92
132
76
2.0
46.3
350.4
10.8
12.4
85.0
11746
921.1
21-101
-------
Coal Switching and Physical Coal Cleaning Costs--
Table 21.4,5-5 summarizes the IAPCS cost results for CS at the Shawville
plant. These costs do not include boiler and pulverizer operating cost
changes or any coal handling system modifications that may be necessary. FCC
was not evaluated because the Shawville plant is not a mine mouth plant.
NQX Control Technologies--
LNBs were considered for control of NO^ emissions from units 1 and 2
which are front wall-fired boilers. OFA was considered for units 3 and 4
which are tangential-fired boilers. Tables 21.4.5-6 and 21.4.5-7 present
NO performance and cost estimates for NO control technologies at the
A A
Shawville plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the boilers at the Shawville plant would be
located similarly to the wet FGD absorbers behind units 1 and 2 and west of
the unit 3 and 4 chimney. High general facilities values (38 percent) and
site access/congestion factors were assigned to all of the reactor locations.
Approximately 400 feet of ductwork would be required to span the distance
between the SCR reactors and the chimneys. Tables 21.4.5-6 and 21.4.5-7
present the retrofit factors and costs for installation of SCR at the
Shawville plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
units 1 and 2 because of the difficulty in upgrading and reusing the roof-
mounted ESPs. FSI and DSD were considered for units 3 and 4 because there
is sufficient duct residence time between the boilers and the ESPs and the
ESPs are large enough to handle the additional particulate load.
Tables 21.4.5-8 and 21.4.5-9 present retrofit data and costs for installation
of FSI and DSD technologies at the Shawville plant.
21-102
-------
Table 21.4,5-5. Suimary of Coal Snitching/Cleaning Costs for the ShawviUe Plant (Jvme 1988 Dollars)
SSSSESSSSSSI35SSZBSSB81SSBSSSlIS9SS3aSSSSSSSSSSSS3SSISBSBnai3BBS8IB183S8S3SSa33SSSS3SS3SS3SSSS3SS5SS3S3&SS:S3Sa
Technology Bailer Mb in Bofler Capacity Coal Capital Capital Annual Annual $02 S(J2 502 Cost
Nimber Retrofit Size
Difficulty (MW)
Factor
Factor
Sulfur
Content
(X)
Cost
(MM)
Cost
i
Cost
:vm
Cost Removed Removed
(milli/kwh) (X) (tons/yr)
Effect.
(S/ton)
CS/S+S15
1
•• 1.00
132
68
2.0
4.8
36.3
11.5
14.5
54.0
6811
1689.1
CS/8«$15
2
1.00
132
76
2.0
. 4.8
36.5
12.6
14.4
54.0
7528
1673,5
CS/B»$15
3
1.00
182
21
2.0
6.3
34.5
5.8
17.2
54.0
2903
1998,7
CS/B+I15
4
1.00
182
58
2.0
6.3
34.S
13.4
14.5
54.0
7915
1689.3
CS/8+S15-C
1
1.00
132
68
2.0
4.8
36.5
6.6
8.4
54.0
6811
970.9
C$/B+t15-C
2
1.00
132
76
2.0
4.8
36.5
7.2
8.3
54.0
7528
961.7
CS/B+J15-C
3
1.00
182
21
2.0
6.3
34.5
3.4
9.9
54.0
2903
1154.8
CS/B+fl5-C
4
1.00
182
58
2.0
6.3
34.5
7.7
8.4
54.0
7913
971,4
CS/B+S5
1
1.00
132
68
2.0
3.4
26.1
4.7
6.0
54.0
6811
694.7
CS/8+S5
2
1.00
132
76
2.0
3.4
26.1
5.1
5.9
54.0
7528
682.5
CS/B**5
3
i.oa
132
21
2.0
4.4
24.1
2.7
8.0
54.0
2903
925.9
CS/B<-$5
4
1.00
132
58
2.0
4.4
24.1
5.4
5.9
54.0
7913
688.4
CS/B+IS-C
1
1.00
132
68
2.0
3.4
26.1
2.7
3.4
54.0
6811
400.3
CS/B*$5-C
2 '
1.00
132
76
2.0
3.4
26.1
3.0
3.4
54.0
7528
393.1
cs/a+$5-c
3
1-.Q0
132
21
2.0
4.4
24.1
1.6
4.6
54.0
2903
537.2
CS/B+S5-C
4
1.00
182
58
2.0
4.4
24.1
3.1
3.4
54.0
7913
396.9
11
II
11
It
fl
<1
it
11
li
1!
11
11
11
12
fl
11
li
11
U
II
1)
II
11
11
11
II
11
11
I!
11
IS
II
II
11
II
II
II
II
II
IE
it
II
II
U
11
;i
ll
11
ii
II
isss55-ssi
li
Jl
li
II
II
II
II
II
21-103
-------
TABLE 21,4.5-6, SUMMARY OF NOx RETROFIT RESULTS FOR SHAWVILLE
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3,4
FIRING TYPE
FWF
TANG
TYPE OF NOx CONTROL
LNB
OFA
FURNACE VOLUME (1000 CU FT)
50.7
96
BOILER INSTALLATION DATE
1954
1959, 1960
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
26
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
33
42
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
2332
2809
New Heat Exchanger (1000$)
2202
2665
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
4566
6890
5516
8324
RETROFIT FACTOR FOR SCR
1.82
1.82
GENERAL FACILITIES (PERCENT)
38
38
21-104
-------
Table 21.4.5-7, NO* Control Cost Results for the ShawvUte Plant (June 1988 Dollars)
ss==s==
===5=5==S
¦CSS388!
issssss:
sssssssx
SSS3SSS2I
I1XI81SS!
.niaiai
iiaiasisaiss
3=====
sssassssss
(1
11
11
II
II
II
II
II
Technology
Boiler
Haiti
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Murfeer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU>
(%>
Content
(tons/yr)
(S/ton)
Factor
(%)
LNC-LNB
1
1.00
132
68
2.0
2.9
21.6
0.6
0.8
26.0
877
706.5
LMC-LNB
2
1.00
132
76
2.0
2.9
21.6
0.6
0.7
26.0
969
639.3
LNC-LM8-C
1
1.00
132
68
2.0
2.9
21.6
0.4
0.5
26.0
877
419,4
LNC-LNB-C
2
1.00
132
76
2.0
2.9
21.6
0.4
0.4
26.0
969
379.4
LNC-QFA
3
1.00
182
21
2.0
0.8
4.3
0.2
0.5
25.0
257
665.0
-HC'OFA.
4
1.00
182
58
2.0
0.8
4.3
0.2
0.2
25.0
700
243.9
lnc-ofa-c
3
1.00
182
21
2.0 .
0.8
4.3
0.1
0.3
25.0
257
394.8
INC-OFA-C
4
1.00
182
58
2.0
0.8
4.3
0.1
0.1
25,0
700 .
144.8
SCR-3
1
1.82
132
68,
2.0
33.2
251.3
10.3
13.1
80.0
2697
3831.2
SCR-3
2
1.82
132
76
2.0
33.2
251.4
10.4
11.9
80.0
2981
3487.9
SCR-3
3
1.82
132
21
2.0
41.3
227.4
12.5
37.2
80.0
821
15275.6
SCR-3
4 ¦
1.82
182
58
2.0
41.3
227.5
12.9
14.0
80.0
2238
5750.2
SCR-3
1-2
1.82
264
72
2.0
54. S
207.6
17.8
10.7
80.0
5678
3130.7
SCR-3
3-4
1.82
563
40
2.0
68.5
188.8
21.9
17.4
80,0
3059
7157.4
SCR-3-C
1
1.82
132
68
2.0
33.2
251.3
6.1
7.7
80.0
2697
2250.2
SCR-3-C
2
1.82
132
76
2.0
33.2
251.4
6.1
7.0
80.0
2981
2048.2
SCR-3-C
3
1.82
182
21
2.0
41.3
227.4
7.4
21.9
80.0
821
8977.3
SCK-3-C
4
1.82
182
sa
• 2.0
41.3
227.5
7.6
8.2
80.0
2238
3377.1
SCR-S-C
1-2
1.82
264
72
2.0
54.8
207.6
10.4
6.3
80-. 0
5678
1836.9
SCR-3-C
3-4
1.82
363
40
2.0
68.5
188.8
12.9
10.2
80.0
$059
4201,2
SCR-7
1
1.82
132
68
2.0
33.2
251.3
9.3
11.7
80.0
269?
3430.0
SCR-7
2
. 1.82
132 •
76
2.0
33.2
251.4
9.3
10.7
80.0
2981
3124.9
SCR-7
3
1.82
182
21
2.0
41.3
227.4
11.1
32.8
80.0
821
13463.3
SCR-7
4
1.82
182
58
2.0
41.3
227.5
11.4
12.4
80.0
2238
5085.4
SCR-7
1-2
1.62
264
72
2.0
54.8
207.6
15.6
9.4
80.0
5678
2749.5
SCR-7
3-4
1.82
363
.40
2.0
68.5
188.8
18.9
15.1
80.0
3059
6184.9
SCR-7-C
1
1.82
132
68
2.0
33.2
251.3
5.4
6.9
80.0
2697
2020.3
5CR-7-C
2
1.82
132
76
2.0
33.2
251.4
5.5
6.3
80.0
2981
1840.2
SCR-7-C
3
1.82
182
21
2.0
41.3
227.4
6.5
19.3
80.0
821
7939.0
SCR-7-C
4
• 1.82
182
58
2.0
41.3
227.5
6.7
7.. 3
80.0
223a
2996.3
SCR-7-C
1-2
1.82
264
72
2.0
54.8
207.6
9.2
5.5
80.0
5678
1618.6
SCR-7-C
3-4
1.82
363
40
2.0
68.5
188.8
11.1
8.9
80.0
3059
3643.9
II
tl
il
il
1!
il
ii
il
II
II
II .
.......
=====3===
5S85S3S
s=sas==s
........
........
SSSSSSS335S.
sssasss
38SS3C3S3S
ssstssss
21-105
-------
TABLE 21.4.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SHAWVILLE UNIT 3 OR 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$) 48
TOTAL COST (1000$)
ESP UPGRADE CASE 48
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
21-106
-------
Table 21.4.5-9. Sunwry of DSO/FSI Control Costs for the Shawville Plant (June 1980 Dollars)
Technology Boiler Hain Boiler Capacity Coal
Number letrofit Size Factor Sulfur
Difficulty (MW) (X) Content
Factor (%>
Capital Capital Annual Annual S02 S02 SQ2 Cost
Cost Cost Cost Cost Removed Removed Effect.
(M4) CS/ku; (SW) (tail Is/kwh) (tcxw/yr) (S/ton)
DSD+ESP 3
dsd+esp 4
DSD+ESP-C 3
dsd+esp-c 4
FSI+ESP-50 S
FSI+ESP-50 4
FSI+ESP-50-C 3
FSI+ESP-50-C 4
FSI+ESP-7Q 3
FSI+ESP-70 4
FSJ+ESP-7C-C 3
FSI+E5P-70-C 4
1.00 182 21
1.00 182 58
1.00 182 21
1.00 182 58
1.00 182 21
1.00 182 58
1.00 182 21
1.00 182 58
1.00 182 21
1.00 182 58
1.00 182 21
1.00 182 58
2.0 10.0 54.8
2.0 10.0 54.9
2.0 10.0 54.8
2.0 10.0 54.9
2.0 10.6 58.4
2.0 10.6 58.4
2.0 10.6 58.4
2.0 10.6 58.4
2.0 10.7 59.1
2.0 10.7 59.2
2.0 10.7 59.1
2.0 10.7 59.2
6.2 -18.1 45.0
7.8 8.5 45.0
3.6 . 10.6 45.0
4.5 4.9 45.B
5.5 16.5 50.0
8.4 9.1 50.0
3.2 9.6 50.0
4.9 5.3 50.0
5.6 16.7 70.0
8.5 9.3 70.0
3.3 9.7 70.0
4.9 5.4 70.0
2426 2535.7
6615 1185.5
2426 1471.2
6615 685.9
2668 2079.6
7275 1152.8
2668 1209.3
7275 667.0
3735 1505.3
10184 837.5
3735 875.3
10184 434.5
21-107
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All four boilers at the Shawville power plant are good candidates for
repowering technologies because of their small sizes and potentially short
remaining useful lifetimes. However, the high capacity factors could result
in high replacement power costs for extended downtime.
21-108
-------
21.5 PENNSYLVANIA POWER AND LIGHT COMPANY
21.5.1 Brunner Island Steam Plant
The Brunner Island steam plant is located within York County,
Pennsylvania, as part of the Pennsylvania Power and Light Company system.
The plant contains three coal-fired boilers with a total gross generating
capacity of 1,558 MW. Figure 21.5.1-1 presents the plant plot plan showing
the location of all boilers and major associated auxiliary equipment.
Table 21.5.1-1 presents operational data for the existing equipment at
the Brunner Island plant. All boilers burn medium sulfur coal (1.9 percent
sulfur). Coal shipments are received by railroad and conveyed to a single
coal pile located north of the plant.
Particulate matter emissions for unit 1 is controlled with a retrofit
baghouse located west of the plant away from the boiler building. Unit 2
ESPs are located at the back of the boiler house. The ESPs for unit 3 are
directly behind the boiler house. There are two chimneys, one serving unit
1 and unit 2 and another chimney serving unit 3. Ash from all units is wet
sluiced to a pond located south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.5.1-1 shows the general layout and location of the FGD control
system.- The absorbers for L/LS-FGD and LSD-FGD for all units would be
located west of the plant between the particulate controls and the railroad
south of the coal pile. Warehouse buildings would need to be demolished/
relocated; therefore, a factor of 8 percent was assigned to general
facilities. The lime storage/preparation area would be located south of the
absorbers between the railroad and ash pond. The waste handling area would
be located adjacent to the storage/preparation area.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for all units were located west of the plant, close to
the railroad, and behind the ESPs/ baghouse.
After relocating the storage buildings, there would be no major
obstacles but some underground obstructions. Plant personnel indicated that
21-109
-------
Lime/Limestone
Storage/Preparation
Area
NH, Storage
System
N-
Baghouse
Waste
Handling Area
Absorbers for
AH Units
Unit 3
ESPs
Ash
Pond
Unit 2
Coal
Conveyor
Powerhouse
Storage
Area
Switchyard
Not to scale
[//) FQD Waste Handling/Absorber Area
i * A Lime/Limestone Storage/Preparation Area
SCR Reactors
Figure 21.5.1-1. Brunner Island Plot Plan
21-110
-------
TABLE 21.5.1-1. BRUNNER ISLAND 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
EMM 1ST ON (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT) ^
GAS EXIT RATE (1000 ACFMJ
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
1
2
3
363
405
790
71
71
70
1961
1965
1969
TANG
TANG
TANG
1.9
1.9
1.9
12500
12500
12500
12.7
12.7
12.7
WET SLUICE
POND/ON-SITE
1 1 2
RAILROAD
ESP ESP
1965 1969
0.05 0.05
99.2 99.5
166+248 461+952
560+840 2600+2600
296 272
310 .310
BAGHOUSE
1980
0.05
99.7
NA
1100
310
21-111
-------
underground obstructions caused by running ducts and piping could be
substantial. As a result, a medium site access/congestion factor was
assigned to the absorber location.
For flue gas handling for L/LS-FGD cases, moderate duct runs for all
units would be required since the absorbers are close to the particulate
controls.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 21.S.1-2 and 21.5.1-3. The largest
scope adder for the Brunner Island plant would be the conversion of units 1-3
fly ash conveying/disposal system from wet to dry for conventional L/LS-FGD
and LSD-FGD cases, and a new chimney for unit 2. It was assumed that dry fly
ash would be necessary to stabilize scrubber sludge waste and to prevent
plugging of sluice lines 1n the LSD-FGD for the baghouse/ESP reuse case.
This conversion is not necessary for forced oxidation L/LS-FGD. The overall
retrofit factors determined for the L/LS-FGD cases ranged from moderate to
high (1.43-1.55).
LSD-FGD with a reused baghouse was considered for unit 1, while reused
ESP was considered for units 2 and 3 (independent ESPs) due to the boilers
presently having moderate size SCAs (>270) amd easy access. For flue gas
handling for LSD cases, medium duct runs would be required for units 1 and 3,
and longer ducts for unit 2. A low site access/congestion factor was
assigned to the unit 1-3 flue gas handling system. The retrofit factors
determined for the LSD technology case were high (1.47-1.55) and did not
include particulate control upgrading costs for units 2 and 3. It was
assumed that the unit 1 baghouse could be reused with no additional
upgrading. A separate retrofit factor was developed for upgrading ESPs for
units 2 and 3 (1.16). This factor was used in the IAPCS model to estimate
particulate control upgrading costs for units 2 and 3.
FGD Retrofit Costs-
Table 21.5.1-4 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 2 and 3. The low cost control case reduces capital and annual
operating costs due to the benefits of economies-of-scale when combining
21-112
-------
TABLE 21.5.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BRUNNER ISLAND UNIT 1 OR 3
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
REUSE BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
REUSE BAGHOUSE
ESP REUSE
REUSE BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
REUSE BAGHOUSE CASE
ESP UPGRADE
REUSE BAGHOUSE
MEDIUM MEDIUM
LOW LOW
300-600 300-600
NA
NA
YES
NA
NA
NO
2978,5980 NA
NO
0
NO
1.48
NA
NA
NO
0
NO
1.43
NA
NA
MEDIUM
LOW
NA
300-600
NA
LOW
NA
YES
2978,5980
NO
0
NO
1.47
1.47
1.16
NA
GENERAL FACILITIES (PERCENT) 8
8
8
21-113
-------
TABLE 21.5.1-3, SUMMARY OF RETROFIT FACTOR DATA FOR BRUNNER ISLAND UNIT 2
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
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
300-600
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST (1000$)
3285
NA
3285
NEW CHIMNEY
YES
YES
NO
ESTIMATED COST (1000$)
2835
2835
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.50
1.45
ESP REUSE CASE
1.55
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
8
8
21-114
-------
Table 21.5.1-4. Summary of FG0 Control Costs for the Brunrter Island Plant (June 1988 Dollars)
s==;;;sss3ss
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual-
S02
S02
sss=;;s=s
S02 Cost
Member Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
LC FGD
1-3
1.48
1558
65
1.9
211.5
135.8
121.4
13.7
90.0
116782
1039.7
LC FGO-C
1-3
1.48
1558
65
1.9
211.5
135.8
70.5
7.9
90.0
116782
603.8
LFGO
1
1.48
363
71
1.9
84.6
233.2
43,1
19.1
90.0
29721
1450.5
LFGD
2
1.50
405
71
1.9
91.2
225.2
46.8
18.6
90.0
33159
1410.2
LFGO
3 '
1.48
790
70
1.9
145.2
183.8
77.6
16.0
90.0
63770 '
1217.3
LF80-C
1
1.4*
363
71
1.9
84.6
233.2
25.1
11.1
90.0
29721
843.8
IFGD-C
2
1.50
405
71
1,9
91.2
225.2
27.2
10.8
90.0
33159
820.3
LFGO-C
3
1.48
790
70
1.9
145.2
183.8
45.1
9.3
90,0
63770
707.7
ISD+ESP
2
1.55
405
71
1.9
56.9
140.6
27.0
10.7
76.0
26112
959.4
LSD+ESP
3
1.47
790
70
1.9
97.9
123.9
46.3
9.6
76.0
54063
855.9
LSO+ESP-C
2
1.55
405
71
1.9
56.9
140.6
15.7
6.2
76.0
2B112
558.8
LSD*ESP-C
3
1.47
790
70
1.9
97.9
123.9
. 26.9
5.6
76.0
54063
498.5
LSO-'PFF
1
1.47
363
71
1.9
45.1
124.3
22.3
9.9
87.0
28565
781.4
LSEH-PFF-C
1
1.47
363
71
1.9
45.1
124.3
13.0
5.8
87.0
28565
454.8
II
II
II
II
II
it
II
II
tl
II
II
II
II
II
II
II
II
11
II
w
SS53I1SSSS
isasaasi
BHIIS5SS
II
U
li
u
m
u
li
¦*
II
II
II
M
!
II
II
II
II
II
II
II
II
II
It
It
It
II
II
H
H
II
II
li
ssssasiaass
.....5SS
21-115
-------
process areas, elimination of spare scrubber modules, and optimization of
scrubber module 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 S03 conditioning or additional plate area
was needed. SO^ conditioning was assumed to reduce the needed plate area up
to 25 percent. Costs were generated to show the impact of two different
coal fuel cost differentials. The costs associated with each boiler for the
range of fuel cost differential are shown in Table 21.5.1-5.
N0X Control Technology Costs--
This section presents the performance and costs estimated for NO
A
controls at the Brunner Island 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 technologies evaluated at the steam plant were: OFA and
A
SCR.
Low N0X Combustion--
Units 1, 2, and 3 are dry bottom, tangential-fired boilers rated at 363,
405, and 790 MW, respectively. The combustion modification technique applied
for this evaluation was OFA. As Table 21.5.1-6 shows, the OFA N0X reduction
performances for units 1, 2, and 3 were estimated to be 25, 15, and
15 percent, respectively. These reduction performance levels were assessed
by examining the effects of heat release rates and furnace residence time
through the use of the simplified NQX procedures. Table 21.5.1-7 presents
the cost of retrofitting OFA at the Brunner Island boilers.
21-116
-------
Table 21.5,1-5. Summary of Coal Switching/Cleaning Costs for the Brimer Island Plant (June 1988 -Dollars)
Technology
Bailer Main
Boiler Capacity coal
Capital Capital Annual'
Annual
S02
S02
S02 Cost
Nwfeer Betrofit
siz*
factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty (HU)
<%)
Content
CSMM)
(t/kw>
(two
CmilU/kwh}
(*)
-------
TABLE 21.5,1-6. SUMMARY OF NQx RETROFIT RESULTS FOR BRUNNER ISLAND
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)
13
15.8
14.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
80.8'
118.6
92.5
FURNACE RESIDENCE TIME (SECONDS)
3.56
2.7
1.61
ESTIMATED NOx REDUCTION (PERCENT)
25
15
15
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
71
77
127
New Duct Length (Feet)
200
200
300
New Duct Costs (1000$)
2106
2246
4980
New Heat Exchanger (1000$)
4,040
4,314
6,441
TOTAL SCOPE ADDER COSTS (1000$)
6,218
6,637
11,548
RETROFIT FACTOR FOR SCR
1.52
1.52
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
21-118
-------
Table 21.5.1-7. HO* Control Cost Results for the Srumer Island Plant (June 1988 Dollars)
Technology
Soi Ler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NOx
NOx Cost
Ninfcer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
(X)
Content
(SMH)
($/kw>
(SMH)
Cmills/ICHh)
«>
(tors/yr)
(I/ton)
Factor
<*>
INC-OfA
1
1,00
363
71
1.9
1.0
2.9
0.2
0.1
25.0
1671
134,6
LNC-OFA
2
1.00
405
71
1.9
1.1
2.7
0.2
0.1
15.0
1119
210.2
LNC-OFA
3
1,00
790
70
1.9
1.4
1.8
0.3
0.1
15.0
2152
142.8
INC-QFA-C
1
1,00
363
71
1.9
1.0
2.9
0.1
0.1
25.0
1671
79.9
INC-OFA-C
2
1,00
405
71
1.9
1.1
2.7
0.1
0.1
15.0
1119
124.8
LNC-OFA-C
3
1.00
790
70
1.9
1.4
1.8
0.2
0.0
15.0
2152
84.7
SCR-2
1
1.52
363
71
1.9
54,6
150.4
19.1
8.5
80.0
5348
3571.1
SCR-3
Z
1.52
405
71
1.9
59.7
147.4
21.0
8.3
80.0
5967
3520.0
SCR-3
3
1.16
790
70
1.9
92.3
116.9
34.9
7.2
80.0
.11475
3043.7
SCR-J-C
1
1.52
363
71
1.9
54.6
150.4
11.2
5.0
80.0
5348
2091,8
SCR-3-C
2
1.52
405
71
1.9
59.7
147.4
12.3
4.9
80.0
5967
2061.6
SCR-3-C
J
1.16
790
70
1.9
92.3
116.9
20.4
4.2
80.0
11475
1779.9
SCR-7
1
1.52
363
71
1.9
54.6
150.4
16.1
7.1
80.0
5348
3016.7
SCR-7
2
1.52
405
71
1.9
59.7
147.4
17.7
7.0
80.0
5967
2965.6
SCR-7
3
1.16
790
70
1.9
92.3
116.9
28.5
5.9
80.0
11475
2481.4
SCR-7-C
1
1.52
363
71
1.9
54.6
150.4
9.5
4.2
80.0
5348
1774.1
SCR-7-C
2
1.52
405
71
1.9
59.7
147.4
10.4
4.1
80.0
5967
1744.0
SC8-7-C
3
1.16
790
70
1.9
92.3
116.9
16.7
3.5
80.0
11475
1457.7
21-119
-------
Selective Catalytic Reduction--
Table 21.5.1-6 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 building and ductwork demolition,
new flue gas heat exchanger, and new duct runs to divert the flue gas from
the PM control device to the reactor and from the reactor to the chimney.
The SCR reactors for units 1 and 2 were located west of unit 2 between
the ESPs for unit 3 and the baghouse for unit 1. The SCR reactor for unit 3
was located south of the ESPs for unit 3 and west of the powerhouse.
Reactors for units 1 and 2 were assigned high access/congestion factors
because they were surrounded on two sides by the ESPs for unit 3 and the
baghouse for unit 1. On the other hand, the SCR reactor for unit 3 was
assigned a low access/congestion factor since it was in an easy access area
surrounded only on one side by the ESPs for unit 3. All three reactors were
assumed to be in areas with high underground obstructions. The ammonia
storage system was placed in a remote area having a low access/congestion
factor. Table 21.5.1-7 presents the estimated cost of retrofitting SCR at
the Brunner Island boilers.
Sorbent Injection and Repowerlng
This section presents the cost/performance estimates for SO., control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately from
the commercialized technologies because the cost/performance estimates have a
high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located west of the
plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Brunner Island steam plant for units 1 and 3 would be
easy. There is sufficient flue gas ducting residence time between the
boilers and the particulate controls for units 1 and 3. Unit 2 has a short
duct residence time and application of sorbent injection technologies would
be difficult. It was assumed that the unit 1 baghouse can handle the
increased particulate load; units 2-3 ESPs have adequate SCAs (>290). Unit 3
21-120
-------
has a large amount of space available to upgrade with a low site access/
congestion factor, however, the unit 2 ESPs would be more difficult to
upgrade. The major scope adder cost for DSD and FSI would be the conversion
of the fly ash handling system from wet to dry. Tables 21.5.1-8 through
21.5.1-10 present a summary of the site access/congestion factors for DSD and
FSI technologies at the Brunner Island steam plant. Table 21,5.1-11 presents
the costs estimated to retrofit DSD and FSI at the Brunner Island 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 Brunner Island plant. None of the boilers would be
considered good candidates for AFBC retrofit due to their large boiler sizes
(>300 MW) and high capacity factors.
21.5.2 Martins Creek Steam Plant
The Martin's Creek steam plant is located within Northampton County,
Pennsylvania, as part of the Pennsylvania Power and Light Company system.
The plant contains four boilers with a total gross generating capacity of
2,013 MW; units 1 and 2 are coal-burning while units 3 and 4 are
petroleum-burning boilers. Therefore, only boilers 1 and 2 were considered
for this study. Figure 21.5.2-1 presents the plant plot plan showing the
location of all boilers and major associated auxiliary equipment.
Table 21.5.2-1 presents operational data for the existing equipment at
the Martins Creek plant. Boilers 1 and 2 burn medium sulfur coal (1.9
percent sulfur). Coal shipments are received by railroad and conveyed to a
coal storage and handling area located north of the plant.
Particulate matter emissions for the boilers are controlled with
retrofit ESPs located behind each boiler. Ash from the units is wet sluiced
to ponds located south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.5.2-1 shows the general layout and location of the FGD control
system. The two coal burning boilers are located beside each other parallel
21-121
-------
TABLE 21.5.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRUNNER ISLAND UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE NA
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2980
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 79
TOTAL COST (1000$)
BAGHOUSE REUSE CASE 3059
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS :
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
BAGHOUSE UPGRADE NA
NEW BAGHOUSE NA
21-122
-------
TABLE 21.5.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRUNNER ESLAND UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 3285
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 3370
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
21-123
-------
TABLE 21.5.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BRUNNER ISLAND UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 5983
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 141
TOTAL COST (1000$)
ESP UPGRADE CASE 6124
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-124
-------
Table 21.5.1-11, Summary of DSD/FSI Control Costs for the Brunner Island Plant (June 1988 Dollars)
Technology Boiler Main Boil#r Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Sit* Factor Sulfur cost Cost cost Cost Removed Removed Effect.
Difficulty
-------
-Z.
¦N
Units 3-4
(oil burning)
Absorbers
Chimney
Chimneys
o.
Cooling
Towers
Employee
Parking Area
Convevors
Coal Storage
Area
LSD Absorbers
for Unit 1
NHj Storage
System
Waste Handling
Area
Not to scale
on
Tanks
Lime/Limestone
Storage/Preparation
Area
Oil Pipeline
to Units 3-4
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NHj Storage System
SCR Boxes
Figure 21.5.2-1. Martins Creek plant plot plan
21-126
-------
TABLE 21.5.2-1. MARTINS CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 156
CAPACITY FACTOR (PERCENT) 50
INSTALLATION DATE 1954,56
FIRING TYPE FRONT WALL
COAL SULFUR CONTENT (PERCENT) 1.9
COAL HEATING VALUE (BTU/LB) 12500
COAL ASH CONTENT (PERCENT) 12.4
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD POND/ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS ' RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1971
EMISSION (LB/MM BTU) 0.09
REMOVAL EFFICIENCY 99.2-99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.6
SURFACE AREA (1000 SQ FT) 165.2
GAS EXIT RATE (1000 ACFM) 550
SCA (SQ FT/1000 ACFM) 300(TESTED=270)
OUTLET TEMPERATURE ( F) 310
21-127
-------
to the Delaware River and share a common chimney, while the two petroleum
burning boilers are located further away beside each other. All four units
are located parallel to the Delaware River. There are two natural draft
cooling towers located northwest of the plant beside units 3 and 4, adjacent
to the coal handling and storage area. The absorbers for L/LS-FGD and
LSD-FGD for both units would be located between the powerhouse (for units 1
and 2) and the riverside. Some relocation or demolition (e.g. storage
building) would be required for either unit; therefore, a factor of 10
percent was assigned to general facilities. The lime storage/preparation
area would be located west of the plant and the temporary waste handling
area would be located nearby.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for L/LS-FGD would be located behind the common chimney
parallel to the river. However, the LSD absorbers could also be located on
either side of the ESPs for easier access to the upstream of the ESPs. A
low site access/congestion factor was assigned to the absorber locations
since there are no major obstacles/obstructions around the chimneys and
ESPs.
For flue gas handling, short duct runs for both units would be required
for L/LS-FGD cases. A low site access/congestion factor was assigned to the
flue gas handling system due to the close location of the absorbers to the
chimney with no major obstructions in the surrounding area. .
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 21.5.2-2 and 21.5.2-3. The largest
scope adder for the Martins Creek plant would be the conversion of fly ash
conveying/disposal system from wet to dry for conventional L/LS-FGD and
LSD-FGD. It was assumed that dry fly ash would be necessary to stabilize
scrubber sludge waste and to prevent plugging of sluice lines in LSD-FGD
system (for the ESP-reuse case). However, this conversion is not necessary
for forced oxidation L/LS-FGD. The overall retrofit factors determined for
the L/LS-FGD cases were low (1.20 to 1.27).
The absorbers for LSD-FGD would be located close to the ESPs in the
same location and in similar fashion as L/LS-FGD cases. LSD-FGD with reused
ESPs was the only LSD-FGD technology considered for both units due to the
21-128
-------
TABLE 21.5.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MARTINS CREEK UNIT 1
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 MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE . 300-600
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS ¦
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 1397 NA 1397
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 1.20
' ESP REUSE CASE . 1.38
BAGHOUSE CASE NA
ESP UPGRADE . NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
21-129
-------
TABLE 21.1.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR MARTINS CREEK UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 1397 NA 1397
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 1.20
ESP REUSE CASE 1.38
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
21-130
-------
large ESP sizes (SCAs - 300). For flue gas handling for LSD cases, medium
duct runs would be required and a low site access/congestion factor was
assigned for both units in a similar fashion as L/LS-FGD. The retrofit
factor determined for the LSD technology case was medium (1.38) and did not
include particulate control upgrading costs. Two separate retrofit factors
were developed for upgrading ESPs for each unit (1.35 for unit 1 and 1.16
for unit 2). For unit 1, a medium site access/congestion factor was
associated with the upgrading which reflected the accessibility and
congestion around the ESPs because of the duct runs, chimneys, and unit 2
ESPs. Unit 2 was assigned a low site access/congestion factor due to the
available space around the ESPs. Both factors were used in the IAPCS model
to estimate particulate control upgrading costs.
Table 21.5.2-4 presents the estimated costs for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boilers 1 and 2. The low cost control case reduces capital and annual
operating costs due to the benefits of economies-of-scale when combining
process areas, elimination of spare scrubber modules, and optimization of
scrubber module 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 S03 conditioning or additional plate area
was needed. SOj conditioning was assumed to reduce the needed plate area up
to 25 percent. Costs were generated to show the impact of two different
coal fuel cost differentials. The costs associated with each boiler for the
range of fuel cost differential are shown in Table 21.5.2-5.
21-131
-------
Table 21,5.2*4. Surmary of FGD Control Costs for the Martins Creek Plant (June 1988 Dollars)
Technology
Soiler
Main
Boiler Capacity coal
Capital
Capital Annual
Annual
502
S02
502 Cost
Nuifcer
RetrofIt
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty ;hu)
(%)
Content
($*M)
Ci/ktf)
(niUs/kwh)
<*)
(tons/yr)
(J/ton)
Factor
(S3
tC FED
1-2
1.27
312
50
1.9
51.1
163.9
26.7
19.5
90.0
17990
1481.7
LC FGD-C
1-2
1.27
312
50
1.9
51.1
163.9
15.5
11.3
90.0
17990
861.7
L FGD
1
1.27
156
50
1.9
45.4
290.8
20.8
30.5
90.0
8995
2315.8
tFGD
2
1.27
156
50
1.9
45.4
290.8
20.8
30.5
90.0
8995
2315.8
I FGD
1-2
1.27
312
50
1.9
68.7
220.3
32.3
23.7
90.0
17990
1796.6
LFGO'C
1
1.27
156
50
1.9
45.4
290.8
12.1
17.8
90.0
8995
1349.4
LFGD-C
2
1.27
156
50
1,9
45.4
290.8
12.1
17.8
90.0
8995
1349.4
-FGO-C
1-2
1.27
312
50
1.9
68.7
220.3
18.8
13.8
90.0
17990
1046.4
LSD+ESP
1
1.38
156
50
1.9
23.4
150.3
11.3
16.5
76.0
7626
1482.9
LSD+ESP "
2
1.38
116
50
1.9
23.1
148.4
11.2
16.4
76.0
7626
1473.1
LSD+ESP-C
1
1.38
156
50
1.9
23.4
150.3
6.6
9.6
76.0
7626
863.4
ISO+ESP-C
2
1.38
156
50
1.9
23.1
148.4
6.5
9.6
76.0
7626
857.6
...........
..........
ISS33SSS
========
>========
II
II
II
II
II
II
II
II
:======*=
====s„====
==»=»==
21-132
-------
Tabte 21.5.2-5. Sunrary of Coal Switching/Cleaning Costs for the Martins Creek Plant (June 19B0 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 502 $02 SC2 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty {«•<) (mUU/kwh) (X) (tons/yr) ($/ton)
Factor (X)
CS/B*S15
CS/B*S15
1.00
1.00
156
156
50
50
1.9
1.9
5.6
5.6
36.2
36.2
10.3
10.3
15.0
15.0
51.0
51.0
5060
5060
2030.8
2030.8
CS/B+S15-C
CS/B*$15-C
CS/B+S5
CS/B±*5
CS/l*t5-C
CS/B+$5-C
.00
.00
.00
.00
.00
.00
156
156
156
156
156
156
50
50
50
50
50
50
5.6
5.6
4.0
4.0
4.0
4.0
36.2
36.2
25.9
25.9
25.9
25.9
5.9
5.9
4.3
4.3
2.5
2.5
6.4
6.4
3.7
3.7
51.0
51.0
51.0
51.0
51.0
51.0
5060
5060
5060 ,
5060
5060
5060
11 S3.5
1168.5
859.6
859.6
496.1
496.1
21-133
-------
NOx Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Martins Creek 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:
LNB and SCR.
Low NO Combustion--
A
Units 1 and 2 are dry bottom, front wall-fired boilers each rated at
156 MW. The combustion modification technique applied for these boilers was
LNB. As Table 21.5.2-6 shows, the LNB N0X reduction performance for each
unit was estimated to be 40 percent. Table 21.5.2-7 presents the cost of
retrofitting LNB at the Martins Creek boilers.
Selective Catalytic Reduction-
Table 21.5.2-6 presents the SCR retrofit results for units 1 and 2. The
results include process area retrofit factors and scope adder costs.
The scope adders include costs estimated for ductwork demolition, new flue
gas heat exchanger, and new duct runs to divert the flue gas from the ESPs to
the reactor and from the reactor to the chimney.
The SCR reactors for units 1 and 2 were located behind the common
chimney. Since the reactors were located in open area having easy access
with no major obstacles, the reactor locations for units 1 and 2 were
assigned low access/congestion factors. Both reactors were assumed to be in
areas with high underground obstructions. The ammonia storage system was
placed in a remote area having a low access/congestion factor.
As discussed in Section 2, all N0X control techniques were evaluated
independently from those evaluated for SO2 control. If both SO^ and N0X
emissions needed to be reduced at this plant, the SCR reactors would have to
be located downstream of the FGD absorbers in an area north of the
absorbers. In this case, low access/congestion factors would again be
assigned to both SCR reactors. Table 21.5.2-7 presents the estimated cost
of retrofitting SCR at the Martins Creek boilers.
21-134
-------
TABLE 21.5.2-6, SUMMARY OF NOx RETROFIT RESULTS FOR MARTINS CREEK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
1-2 '
FIRING TYPE
FWF
FWF
NA
TYPE OF NOx CONTROL
LNB
LNB
NA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
14.2
14.2
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
20.7
20.7
NA
FURNACE RESIDENCE TIME (SECONDS)
3.49
3.49
NA
ESTIMATED NOx REDUCTION (PERCENT)
40
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$)
38
38
63
New Duct Length (Feet)
140
120
140
New Duct Costs (1000$)
900
771
1350
New Heat Exchanger (1000$)
2434
2434
3689
TOTAL SCOPE ADDER COSTS (1000$)
3371
3243
5102
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
21-135
-------
Table 21.S.2-7. NOx Control Cost Results for the Martins Creek Plant , (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nunber
Retrofit
Size
factor Sulfur
Cost
Cost.
Cost
cost
Removed
Removed
Effect.
Difficulty (HVJ
(X)
Content
($XM)
(S/kw)
(mi Its/kwh)
(%)
(tons/yrj
($/ton)
Factor
(*>
LNC-LN8
1
1.00
156
50
1.9
3.1
19.6
0.7
1.0
40.0
1133
534.4
U.C-U.B
2
1.00
156
50
1.9
3.1
19.6
0.7
1.0
40.0
1133
584.4
LNC-INB-C
1
1.00
156
50
1.9
3.1
19.6
0.4
0.6
40.0
1133
346.9
LNC-INB-C
2
1.00
156
50
1.9
3.1
19.6
0.4
0.6
40.0
1133
346.9
SCR-3
1
1.16
156
50
1.9
24.7
158.4
8.5
12.4
80.0
2266
3738.3
SCR-3
2
1.16
156
50
1.9
24.6
157,5
8.4
12.4
80.0
¦ 2266
3728.2
SCR-3
1-2
1.16
312
50
1.9
42.2
135.4
15.0
11.0
80.0
4532
3320.6
SCR-3-C
1
1.16
156
50
1.9
24.7
158.4
5.0
7.3
80.0
2266
2190.7
SCR-3-C
2
1.16
156
50
1.9
24.6
157.5
5.0
7.2
80.0
2266
2184.6
SCR-3-C
1-2
1.16
312
50
1.9
42.2
135.4
s.a
6.4
80.0
4532
1944.3
SCR-7
1
1.16
156
50
1.9
24.7
158.4
7.2
10.5
80.0
2266
3176.0
SCR-7
2
1.16
156
50
1.9
24.6
157.5
7.2
10.5
80.0
2266
3165.9
SCR-7
1-2
1.16
312
50
1.9
42.2
135.4
12.5
9.1
80.0
4532
2758.3
SCR-7-C
1
1.16
156
50
1.9
24.7
158.4
4.2
6.2
80.0
2266
1868.5
SCR-7-C
2
1.16
156
50
1.9
24.6
157.5
4.2
6.2
80.0
2266
1862.4
SCR-7-C
1-2
1.16
312
50
1.9
42.2
135.4
7.4
5.4
80.0
4532
1622.1
21-136
-------
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 were located west of the
coal pile in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Martins Creek steam plant for both units would be
possible. This is due to the adequate flue gas ducting residence time
between the boilers and the ESPs as well as the adequate size of the ESPs
(SCAs = 300). It was assumed that the ESPs could also be upgraded for FSI
technologies. Additionally, the conversion of the wet ash handling system
to dry handling would be required for reusing ESPs. Tables 21.5.2-8 and
21.5.2-9 present a summary of the site access/congestion factors for DSD and
FSI technologies at the Martins Creek steam plant. Table 21.5.2-10 presents
the costs estimated to retrofit DSD and FSI at the Martins Creek 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 Martins Creek plant. Both boilers would be considered
good candidates for AFBC repowering due to their small boiler sizes (156 MW)
and old ages (built before I960). However, the high capacity factors make
these units not a good candidate because of replacement power costs during
boiler downtime.
21.5.3 Montour Steam Plant
The Montour steam plant is located within Montour County, Pennsylvania,
as part of the Pennsylvania Power and Light Company system. The plant
contains two coal-fired boilers with a total gross generating capacity of
1,641 MM (net capacity 1s 1515 MW). Figure 21.5.3-1 presents the plant plot
21-137
-------
TABLE 21.5.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MARTINS CREEK UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1397
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 42
TOTAL COST (1000$)
ESP UPGRADE CASE 1439
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
21-138
-------
TABLE 21.5.2-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MARTINS CREEK UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1397
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 42
TOTAL COST (1000$)
ESP UPGRADE CASE 1439
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
a
21-139
-------
I
Table 21.5.2-10. Sunmary of 0S0/FSI Control Costs for the Martins Creek Plant (June 1986 Dollars]
Technology Boiler Main 801ler Capacity Coal Capital Capital Annual Annual $02 S02 S02 Cost
Musber Retrofit Site Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (WW) ($/kW> (MM) (mills/kuh) (S> (tons/yr) (S/ton>
Factor (X)
OSO+ESP 1 1.00 156 SO 1.9 10.0 64.4 7.1 10.3 49.0 4862 1453.4
CSD-"ESP 2 i.OO 156 50 1.9 9.7 61.9 7.0 10.2 49.0 4662 1433.6
DSD+SSP-C 1 1.00 156 50 1.9 10.0 64.4 ' 4.1 S.O 49.0 4862 842.0
0S0+ESP-C 2 1.00 156 50 1.9 9.7 61.9 4.0 5.9 49.0 4862 830.3
FSI+ESP-SC 1 1.00 156 50 1,9 10.6 67.7 6.9 10.1 50.0 4997 137S.3
FSI+ESP-50 2 1.00 156 50 1.9 10.1 64.9 6.8 9.9 50.0 4997 1355.4
FSt+ESP-50-C 1 , 1,00 156 50 1.9 10.6 67.7 4.0 , 5.S 50.0 4997 799.1
FS1+ESP-S0-C 2 1.00 156 50 1.9 10.1 64.9 3.9 5.7 50.0 4997 785.6
FSI+ESP-70 1 1.00 156 50 1,9 10.7 66.3 7.0 10.2 70.0 6996 998.3
FSt*ESP-70 2 1.00 156 SO 1.9 10.2 65.4 6.9 10.1 70.0 6996 981.6
FSI-ESP-70-C 1 1.00 156 50 1.9 10.7 68.3 4.0 5.9 70.0 6996 578.8
FS1+ESP-70-C 2 1.00 156 50 1.9 10.2 65.4 4.0 5.8 73.0 6996 568.9
21-140
-------
rbets
Hot to
scale
Flmre
J&83»«^. s"°"
Area
21.5
3-1,
MOnta»r PUnt
Plot
Phn
-------
plan showing the location of all boilers and major associated auxiliary
equipment.
Table 21.5.3-1 presents operational data for the existing equipment at
the Montour plant. Both boilers burn medium sulfur coal (1.5 percent
sulfur). Coal shipments are received by railroad and conveyed to a coal
storage and handling area located southwest of the plant.
Particulate matter emissions for all units are controlled with ESPs
which are located behind each unit. The plant has a dry fly ash handling
system and ash is disposed to a storage area on-site. A large ash pond site
is also available north of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.5.3-1 shows the general layout and location of the FGD control
system. There are two natural draft cooling towers located northeast and
northwest of the plant between the powerhouse and ash pond. The absorbers
would be located between the chimneys and coal pile for L/LS-FGD and on either side
relocation would be required for the storage area and auxiliary building;
therefore, a factor of 8 percent was assigned to general facilities. The
lime storage/preparation area would be located east of unit 2 and the waste
handling area would be located adjacent to it.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for both units would be located southwest of the plant
between the chimneys and coal pile for L/LS-FGD and on either side of the
ESPs for LSD-FGD cases.
The absorbers were assigned a low site access/congestion factor for
L/LS-FGD and LSD-FGD technologies; other than part of the storage building
which would need to be demolished, there are no additional major obstacles
or obstructions.
For flue gas handling, short to moderate duct runs for the units would
be required for L/LS-FGD cases. A low site access/congestion factor was
assigned to the flue gas handling system due to the absorbers being located
directly behind the chimneys.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 21.5.3-2 and 21.5.3-3. No large
21-142
-------
TABLE 21.5.3-1. MONTOUR STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-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
1,2
822, 819
75
1972 73
TANGENTIAL
1.5
12600
12.2
DRY DISPOSAL
STORAGE AREA/ON-SITE
1,2
RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1972-73
EMISSION (LB/MM BTU) 0.03
REMOVAL EFFICIENCY 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.7
SURFACE AREA (1000 SQ FT) 460.8
GAS EXIT RATE (1000 ACFM) 2260
SCA (SQ FT/1000 ACFM) 204
OUTLET TEMPERATURE ( F) 310
21-143
-------
TABLE 21.5.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR MONTOUR UNIT 1
FGD TECHNOLOGY
L/LS FGD
FORCED
OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
LOW
LOW
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
100-300
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
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
1.36
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
8
8
21-144
-------
TABLE 21.5.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR MONTOUR UNIT 2
F6D TECHNOLOGY
FORCED
L/LS F6D OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW
FLUE GAS HANDLING LOW
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE
ESP REUSE
BAGHOUSE
ESP REUSE NA
NEW BAGHOUSE NA
LOW
LOW
(FEET) 100-300 100-300
NA
NA
LOW
MEDIUM
NA
300-600
NA
LOW
NA
SCOPE ADJUSTMENTS
WET TO DRY NO
ESTIMATED COST (1000$) NA
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.24
NA
NA
NO
NA
NO
0
NO
1.24
NA
NA
NO
NA
NO
0
NO
1.31
NA
1.16
NA
GENERAL FACILITIES (PERCENT) 8
8
8
21-145
-------
scope adder cost is required for the Montour plant. The overall retrofit
factor determined for the L/LS-FGD cases was low (1.24).
The absorbers for LSD-FGD would be located on either side of the ESPs.
LSD-FGD with reused ESP was the only LSD-FGD technology considered for both
units. For flue gas handling for LSD cases, moderate duct runs would be
required and a medium-to-high site access/congestion factor was assigned for
both units. The retrofit factors determined for the LSD technology case
were moderate (1.31-1.36) and did not include particulate control upgrading
costs. Two separate retrofit factors were developed for upgrading ESPs.
For unit 1, a medium site access/congestion factor was assigned (1.36) due
to the ESPs being bounded by the coal conveyor on one side and the chimney
on the other. Unit I was assigned a low site access/congestion factor
(1.16) because of the large available space on either side of the ESPs.
These factors were used in the IAPCS model to estimate the particulate
control upgrading costs.
Table 21.5.3-4 presents the estimated costs for L/LS-FGD 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 due to
the elimination of spare scrubber modules and the optimization of scrubber
module 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 21.5.3-5.
21-146
-------
Table 21.S.3-4, Summary of FGD Control Costs for the Hontour Plant (June 1988 Dollars)
Technology Boiler Main Boiler
Nutter Retrofit Size
Difficulty CHW)
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
<%> Content (MM) (VkW) (SWO
<%>
Annual SQ2 SC2 S02 Cost
Cost Removed Removed Effect.
(tons/yr) (S/ton)
LC FCD 1-2
LC FGB-C 1-2
IFOD 1
IFGD 2
LFGD-C 1
LFGD-C 2
LSD+6SP 1
ISD+ESP 2
LSD+ESP-C 1
LSD+ESP-C 2
1.24 1641 75
1.24 1641 75
1.24 822 75
1.24 819 75
1.24 822 75
1.24 819 75
1.36 822 75
1.31 819 75
1.36 822 75
1.31 819 75
1.5 185.7 113.2
1.5 185.7 113.2
1.3 126.3 153.6
1.5 125.8 153.5
1.5 126.3 153.6
1.5 125.8 153.5
1.5 98,9 120.3
1.5 94.0 114.8
1.5 98.9 120.3
1.5 94.0 114.8
118.1 11.0 90.0
68.5 6.4 90.0
71.6 13.3 90.0
71.4 13.3 90.0
41.6 7.7 90.0
41.5 7.7 90.0
45.5 8.4 76.0
44.0 8.2 76.0
26.5 4.9 76.0
25.7 4.8 76.0
111028 1063.5
111028 616.8
55615 1288.0
55412 1288.1
55615 748.1
55412 74fl.2
47149 964.2
46977 937.4
47149 561.8
46977 546.1
21-147
-------
Table 21,5.3-5. Summary of Coal Switching/Cleaning Costs for the Montour Plant (June 19S8 Dollars)
Technology Boiler Hain Boiler Capacity Coal Capital Capital Annual Annual S02 S02 $02 Cost
Nimber Retrofit Size Factor Sulfur Cast Cost Cost Cost Ramoved Removed Effect.
Difficulty (MW) <*> Content CSMH)
-------
NOx Control Technology Costs--
Thls section presents the performance and costs estimated for N0X
controls at the Montour steam plant. These controls include LNC
modification and SCR. The application of NQX control technologies is
determined by several site-specific factors which are discussed in
Section 2. The NGX technologies evaluated at the steam plant were: OFA and
SCR.
Low NO Combustion--
A
Units 1 and 2 are dry. bottom, tangential-fired boilers rated at 822 and
819 MW, respectively. The combustion modification technique applied for
this evaluation was OFA. As Table 21.5.3-6 shows, the OFA N0x reduction
performance for each unit was estimated to be 20 percent. This reduction
performance level was assessed by examining the effects of heat release
rates and furnace residence time through the use of the simplified N0X
procedures. Table 21.5.3-7 presents the cost of retrofitting OFA at the
Montour boilers.
Selective Catalytic Reduction-
Table 21.5.3-6 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 building and 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 both units were located southwest of the plant
between the respective chimneys and the coal pile. The SCR reactor
locations for units 1 and 2 were assigned a low access/congestion factor
since the reactors would be located in a relatively open area. Other than a
storage building which would be demolished, there are no major obstacles or
obstructions; therefore, a factor of 20 percent was assigned to general
facilities. 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.
21-149
-------
TABLE 21.5.3-6, SUMMARY OF NOx RETROFIT RESULTS FOR MONTOUR
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)
14.7
14.7
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
92.7
92.7
FURNACE RESIDENCE TIME (SECONDS)
3.64
3.64
ESTIMATED NOx REDUCTION (PERCENT)
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
376
Ductwork Demolition (1000$)
131
131
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
3,401
3,391
New Heat Exchanger (1000$)
6,602
6,582
TOTAL SCOPE ADDER COSTS (1000$)
10,134
10,480
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
21-150
-------
Table 21.5.3-?. NOx control Cost Results for the Nontour.Plant (June 1988 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annul Annual NOx NOx NQx Cost
Number Retrofit Size Factor Sulfur Cast Cost Cost Cost Removed Removed Effect.
Difficulty Content E$*M> (SUM) Cmills/ltwh> (X)
-------
As discussed in Section 2, all NOx control techniques were evaluated
independently from those evaluated for S02 control. As a result for this
plant, the FGD absorbers were in the same location as the SCR reactors.
If both SOg and NQX emissions have to be reduced at this plant, the SCR
reactors would have to be located downstream of the FGD absorbers in an area
having little obstructions and easy access, A low access/congestion factor
would be assigned to both SCR reactors. However, the duct runs to the
chimney would be longer than that presented in Table 21.5.3-6.
Table 21.5.3-7 presents the estimated cost of retrofitting SCR at the
Montour boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO^ control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located east of the
plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Montour steam plant for both units would be difficult.
This difficulty reflects the insufficient duct residence time between the
boilers and ESPs and inadequate ESP sizes. Therefore, costs of sorbent
injection technologies were not developed for the Montour 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 Montour plant. None of the boilers would be considered
good candidates for AFBC retrofit due to their large sizes (>800 MW), their
ages (built after 1970), and high capacity factors.
21-152
-------
21.5.4 Sunburv Steam Plant
The Sunbury steam plant is located within Snyder County, Pennsylvania,
as part of the Pennsylvania Power and Light Company system. The plant con-
tains four coal-fired boilers with a total gross generating capacity of 409
MW. The plant is located on a narrow site bounded by the railroad to the
west and Susquehanna River to the east. Figure 21.5.4-1 presents the plant
plot plan showing the location of all boilers and major associated auxiliary
equipment.
Table 21.5.4-1 presents operational data for the existing equipment at
the Sunbury plant. Boilers 1 and 2 burn low sulfur coal (0.6 percent sulfur)
as well as Petroleum, coke and anthracite (2.0 percent sulfur for overall
fuel blend) while boilers 3 and 4 burn medium sulfur coal (1.9). Coal ship-
ments are received by railroad and trucks and conveyed to a coal storage and
handling area located north of the plant.
Particulate matter emissions for boilers 1 and 2 are controlled with
retrofit baghouses; units 3 and 4 are controlled with retrofit ESPs. Ash
from all units is wet sluiced to ponds located south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.5.4-1 shows the general layout and location of the FGD control
system. The absorbers for L/LS-FGD and LSD-FGD for all units would be locat-
ed north of the plant between the coal pile and powerhouse. Major relocation
or demolition would be required consisting of the oil tank, warehouses, a
major part of the employee parking area {for the absorbers), and the prepara-
tion and storage area. Therefore, a high factor of 20 percent was assigned
to general facilities. The lime storage/preparation area would be located
northwest of the plant between the powerhouse and railroad track; the waste
handling area would be located southwest of the storage/preparation area.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for all units would be located north of plant between the
coal pile and the powerhouse. However, units 1 and 2 are burning low sulfur
coal (0.6 percent) and it is unlikely that these units would be scrubbed.
As such, costs were riot developed for these two units.
21-153
-------
Absorbers
Coal Storage and
Handling Area
%
%
Coal
Conveyor
Chimneys
_ Powerhouse
\J Units 14
Employee
Parking Area
Switchyard
NH, Storage
System
Railroad
Lime/Limestone
Storage/Preparation
Area
Waste Handling
Area
Not to scale
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 21.5.4-1. Sunbury plant plot plan
21-154
-------
TABLE 21.5.4-1. SUNBURY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE VERT
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
EMMISION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
— Mj
( F)
1,2
3
4
75
103
156
70
70
70
1949
1951
1953
DOWN-
•FIRED FRONT
WALL
0.6
1.9
1.9
9120
12400
12400
10.5
10.5
10.5
WET SLUICE
POND/ON-SITE
12 3
RAILROAD/TRUCK
BAGHOUSE
ESP
ESP
1973
1979
1979
0.01
0.04
0.07
99.7
98.8
97.0
0.8
0.8
-
NA
NA
-
222
222
-
NA
NA
310
310
310
21-155
-------
The absorbers for all units were assigned a high site access/congestion
factor which reflects the congestion created by the coal-conveyors, river,
coal pile, and other auxiliary equipment around the site.
For flue gas handling, long duct runs for all units would be required
for L/LS-FGD cases. A high site access/congestion factor was assigned to
the flue gas handling system due to the high site access difficulty caused
by the coal conveyors, an office building, and congestion around the
powerhouse.
The major scope adjustment costs and retrofit factors estimated for the
FGO technologies are presented in Tables 21.5.4-2 and 21.5.4-3. The largest
scope adder for the Sunbury plant would be the conversion of units 1 to 4
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 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 high (1.73 to 1.76).
LSD-FGD with reused particulate controls (baghouse and ESPs) were the
only LSD-FGD technologies considered for all units based on the presumption
that baghouses for units 1 and 2 can handle the particulate load from
LSD-FGD and the units 3 and 4 ESPs have large SCAs. For flue gas handling
for LSD cases, long duct runs would be required and a high site access/
congestion factor was assigned for all units in a similar fashion as
L/LS-FGD. The retrofit factor determined for the LSD technology case was
high (1.78) and did not include particulate control costs. A separate
retrofit factor was developed for upgrading ESPs for units 3 and 4. This
factor was high (1.58) and reflects the congestion around the ESPs due to
the powerhouse building, auxiliary equipment, and coal conveyors. This
factor was used in the IAPCS model to estimate particulate control upgrading
costs.
Table 21.1.4-4 presents the estimated costs for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boilers 3 and 4 and ash
handling systems for all boilers. As mentioned in the previous section,
units 1 and 2 are burning low sulfur coal and it is unlikely that these
units would need to be scrubbed. If, however, scrubbing is required, it
21-156
-------
TABLE 21.5.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR SUNBURY UNITS 1 OR 2
FED TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING HIGH HIGH
BAGHOUSE REUSE CASE HIGH
NEW BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 600-1000 600-1000
BAGHOUSE REUSE 600-1000
NEW BAGHOUSE NA
BAGHOUSE REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 724 NA 724
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.76 1.73
BAGHOUSE REUSE CASE 1.78
NEW BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 20 20 20
21-157
-------
TABLE 21.5.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR SUN8URY UNITS 3 OR 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONSESTION
SO2 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 600-1000 600-1000
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
MET TO DRY YES NO YES
ESTIMATED COST (1000$) 967 NA 967
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.76 1.73
ESP REUSE CASE 1.78
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 20 20 20
21-158
-------
Table 21.5.4-4. suimary of FGD Control Costs for trie Sunbury Plant (June 1938 Dollars)
Technology Boiler Main Boiler Capacity Coal Capitat Capital Annual Annual 502 $02 SQ2 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HW> (X) Content (IMM) (S/lrU) (S«HJ (ftfU$/kwh) :%> (tons/yr) CVton)
Factor (X)
LC FGO
LC FGD-L
I FGO
LFGD
LFGD-C
LFGD-C
LSD+ESP-C
LSD+ESP-C
3-4 1.76 259 70 1.9 57.8 223.1 30.8 19.4 90.0 21101 1461.6
3-4 1.76 259 70 1.9 57.5 223.1 17.9 11.3 90.0 21101 849.7
3 1.76 103 70 1.9 51.0 495.2 22.8 36.1 90.0 8391 2717.0
4 1.76 156 70 1.9 65.9 422.7 29.7 31.0 90.0 12709 2335.7
3 1.76 103 70 1.9 51.0 495.2 13.3 21.0 90.0 8391 1583.9
4 1.76 156 70 1.9 65.9 422.7 17.3 13.1 90.0 12709 1361.5
LSD+ESP 3 1.78 103 70 1.9 23.4 227.3 11.1 17.6
LSD+ESP 4 1.73 156 70 1.9 30.8 197.4 14.2 14.9
1.78
1.73
103
156
70
70
1.9
1.9
23.4 227.3
30.8 197.4
6.5
a.3
10.3
8.7
76.0 7114
76.0 10775
76.0 7114
76.0 10775
1563.4
1322.5
910.5
770.5
21-159
-------
would be more cost effective to switch to a higher coal sulfur content,
taking into consideration the fuel cost differential, in estimating cost
effectiveness for these units.
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.
Coal Switching Costs-
Units 1 and 2 already have switched to low sulfur coal. As such, these
two units were not considered for coal switching or coal cleaning. 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.
Costs were generated to show the impact of two different coal fuel cost
differentials. The costs associated with units 3 and 4 for the range of fuel
cost differential are shown in Table 21.5.4-5.
NO^ Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Sunbury 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: LNB and
SCR.
Low N0X Combustion--
Units 1 and 2 are dry bottom, vertical/down-fired boilers each rated at
75 HW. Units 3 and 4 are dry bottom, front wall-fired boilers rated at 103
and 156 MW, respectively. The combustion modification technique applied for
these boilers was LNB. As Tables 21.5.4-6 and 21.5.4-7 show, the LNB N0„
x
reduction performance for unit 4 was estimated to be 50 percent. No boiler
information could be found for units 1 to 3 to assess their N0X reduction
performances. Since these boilers are relatively old, it is estimated that
21-160
-------
Tabte 21.5.4-5. Simmary of Coal Sultching/Cleaning Costs for the Sunbury Plant (June 1988 Dollars)
a«SSX3St3S:S»SSS:38S3S£S38SS3«8a8SXa8»8SSa:£:3SSS3:3SBa8»»8S8S9«S8SSS8eSS>SS:S±SX££a^S£=3»S£=:3:£:SS33£3==S=:s
Tcchrology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 502 S02 SC2 Cost
Nurfcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
difficulty (MO (SO Content (MM) (toris/yr)
-------
TABLE 21.5.4-6.- SUMMARY OF NOx RETROFIT RESULTS FOR SUN3URY UNITS 1-2
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
. VERTICAL/DOWN-FIRED
TYPE OF NOx CONTROL
LNB
LNB
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)
25
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
22
22
New Duct Length (Feet)
500
600
New Duct Costs (1000$)
2094
2512
New Heat Exchanger (1000$)
1568
1568
TOTAL SCOPE ADDER COSTS (1000$)
3684
4102
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
25
25
21-162
-------
TABLE 21.5.4-7. SUMMARY OF NOx RETROFIT RESULTS FOR SUNBURY UNITS 3-4
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
14.6
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
28,4
FURNACE RESIDENCE TIME (SECONDS)
NA
5.43
ESTIMATED NOx REDUCTION (PERCENT)
25
50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
28
38
New Duct Length (Feet)
850
500
New Duct Costs (1000$)
4310
1607
New Heat Exchanger (1000$)
1908
2434
TOTAL SCOPE ADDER COSTS (1000$)
6246
5685
RETROFIT FACTOR FOR SCR
1.16
1.52
GENERAL FACILITIES (PERCENT)
25
13
21-163
-------
a N0X reduction of 20 to 30 percent can be achieved by these boilers
retrofitted with LNB. Units 1 to 3 were installed between 1949 and 1951.
The reduction performance level for unit 4 was assessed by examining the
effects of heat release rates and furnace residence time through the use of
the simplified N0X procedures. Table 21.5.4-8 presents the cost of
retrofitting LNB at the Sunbury boilers.
Selective Catalytic Reduction-
Tables 21.5.4-6 and 21.5.4-7 present the SCR retrofit results for each
unit. The results include process area retrofit factors and scope adder
costs. The scope adders include costs estimated for ductwork demolition,,
new flue gas heat exchanger, and new duct runs to divert the flue gas from
the particulate matter control device to the reactor and from the reactor to
the chimney.
The SCR reactors for units 1 to 3 were located west of the powerhouse in
the parking lot. Since the reactors were located in open area having easy
access with no major obstacles, the reactors for units 1 to 3 were assigned
low access/congestion factors. However, a 25 percent general facilities
factor was assigned to these reactors for relocating the parking lot in an
area south or southwest of the powerhouse. The SCR reactor for unit 4 was
located northeast of the powerhouse and bordering the river. A high
access/congestion factor was assigned to the reactor for unit 4 since it is
in a high congestion area with difficult access surrounded by the coal
conveyor and the river. All reactors were assumed to be in areas with high
underground obstructions. The ammonia storage system was placed in a remote
area having a low access/congestion factor. Table 21.5.4-8 presents the
estimated cost of retrofitting SCR at the Sunbury 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.
21-164
-------
Table 21,5,4-8, MOx Control Cost Results for the Sunbury Plant (June 1988 Dollars)
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NQX
NOX
NOx Cost
Nirnber Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
-------
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located northwest
of the plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Sunbury steam plant for all units would be difficult.
There is not sufficient flue gas ducting residence time between the boilers
and the particulate controls; therefore, new baghouses were considered for
all units. The new baghouses would be located north of the plant adjacent
to the coal conveyor, river, and coal pile. A high retrofit factor was
assigned to the new baghouses (1.55). Long duct runs would be needed
(600 feet) to divert the flue gas from the boilers to the baghouses and back
to the chimney. However, for FSI technology, it was assumed that the
existing baghouses can handle the increased load and the ESPs could be
upgraded at an equivalent cost of additional plate area and assuming a high
site access/congestion factor (1.55). Additionally, the conversion of the
wet ash handling system to dry handling would be required when reusing the
ESPs/baghouses for FSI technology. Tables 21.5.4-9 through 21.5.4-11 present
a summary of the site access/congestion factors for DSD and FSI technologies
at the Sunbury steam plant. Table 21.5.4-12 presents the costs estimated to
retrofit DSD and FSI at the Sunbury 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 Sunbury plant. All of the boilers would be considered
candidates for AFBC retrofit due to their small sizes (<160 MW) and their
old ages (built before 1950). However, the high capacity factors make these
units poor candidates for repowering because of replacement power costs
during boiler downtime.
21-166
-------
TABLE 21.5.4-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SUNBURY UNITS 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION HIGH
BAGHOUSE UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 724
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 600
ESTIMATED COST (1000$) 2329
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 24
TOTAL COST (1000$)
AN EXISTING BAGHOUSE CASE (FSI) 748
A NEW BAGHOUSE CASE (DSD) 2353
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.37
BAGHOUSE UPGRADE (FSI) NA
NEW BAGHOUSE fDSD) : 1.55
21-167
-------
TABLE 21.5.4-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SUNBURY UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION HIGH
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 967
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 600
ESTIMATED COST (1000$) 2812
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 31
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 998
A NEW BAGHOUSE CASE (DSD) 2843
RETROFIT. FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.37
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) : 1,55
21-168
-------
TABLE 21.5.4-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SUNBURY UNIT 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION HIGH
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1399
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 500
ESTIMATED COST (1000$) 3579
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 42
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 1441
A NEW BAGHOUSE CASE (DSD) 3621
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.37
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1.55
21-169
-------
Table 21.5.4-12. Summary of OSD/FSI Control Costs for the Sunbury Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
$02
$02
S02 Cost
Hotter
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removec
Removed
Effect.
Difficulty IMU)
(X)
Content
<»*>
(toos/yr)
-------
21.6 PENNSYLVANIA POWER COMPANY
21-6.1 Bruce Mansfield Steam Plant
The Bruce Mansfield steam plant is located within Beaver County,
Pennsylvania, as part of the Pennsylvania Power Company system. The plant
is located beside the Ohio River and contains three coal-fired boilers with
a total gross generating capacity of 2,505 MW. Three natural draft cooling
towers are located between the units and the river.
Table 21.6.1-1 presents operational data for the existing equipment at
the Bruce Mansfield plant. The boilers burn high sulfur coal. Coal
shipments are received by barge and transferred to a coal storage and
handling area north of the plant and adjacent to the river.
PM emissions for the boilers are controlled with wet scrubbers for
units 1-2 and ESPs for unit 3. The plant has a dry fly ash handling system.
Fly ash is used to stabilize sludge produced by FGD. Units 1 and 2 are
served by a common chimney while unit 3 is served by another chimney. All
units are equipped with new FGD units and, as such, this plant was not
considered for further S02 reduction.
Low NQ„ Combustion--
x
Units 1 through 3 are dry bottom boilers with a gross unit rating of
835 MW each. Unit 3 is equipped with OFA. As such, N0X reduction using
combustion controls was not evaluated for this unit.
Selective Catalytic Reduction-
Cold side SCR reactors for units 1-2 would be located behind the
chimneys and downstream of the existing FGD units to the east of units 1-2.
The SCR reactors for unit 3, however, would be located on the side of unit 3
close to the employee parking area and beside the chimney. Because of the
space availability for SCR reactors, a low site access/congestion factor was
assigned to all the reactor locations. Approximately 450 feet of duct
length would be needed for either of the units 1 or 2. For unit 3, 250 feet
of duct length was estimated. All reactors were assumed to be in areas with
high underground obstructions. The ammonia storage system was placed close
21-171
-------
TABLE 21,6.1-1. BRUCE MANSFIELD STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOX COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM
FGD TYPE
FGD INSTALLATION DATE
1-3
780 net
60,68,71
1976,77,80
OPPOSED WALL
734
NO,NO,OFA
3.8
11900
12 5
DRY HANDLING
PAID DISPOSAL
1, 1. 2
BARGE
YES
VENTURI/SPRAY CHAMBER
1975,77,80
PARTICULATE CONTROL
TYPE WET SCRUBBER/ESP
INSTALLATION DATE 1976,77,80
EMISSION (LB/MM BTU) 0.04,0.08
REMOVAL EFFICIENCY 99.8,99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 4.8
SURFACE AREA (1000 SQ FT,UNIT 3) 645
GAS EXIT RATE (1000 ACFM) 2610
SCA (SQ FT/1000 ACFM,UNIT 3) 247
OUTLET TEMPERATURE (°F) 126
21-172
-------
to the FGD waste treatment area. A road and a small portion of the parking
area have to be relocated for SCR reactor locations; therefore, a factor of
20 percent was assigned to general facilities.
Table 21.6.1-2 presents the SCR 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.
Table 21.6.1-3 presents the estimated cost of retrofitting SCR at the Bruce
Mansfield boilers,
21.6.2 New Castle Steam Plant
The New Castle steam plant is located within Lawrence County,
Pennsylvania, as part of the Pennsylvania Power Company system, a subsidiary
of Ohio Edison Company. The plant is located beside the Beaver River. The
plant contains five coal-fired boilers with a total gross generating capacity
of 425 MW. Figure 21.6.2-1 presents the plant plot plan showing the location
of all boilers and major associated auxiliary equipment.
Table 21.6.2-1 presents operational data for the existing equipment at
the New Castle plant. The boilers burn low to medium sulfur coal. Coal
shipments are received by truck and conveyed to a coal storage and handling
area located northeast of the plant.
Particulate matter emissions for the boilers are controlled with
retrofit ESPs located between unit 5 and a common chimney. The plant has a
dry fly ash handling system and is disposed at a landfill located north of
the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 21.6.2-1 shows the general layout and location of the FGD control
system. The boilers sit close to the river and flue gas from all units is
converged into a common duct going into a single chimney. The absorbers for
L/LS-FGD and LSD-FGD for all the units would be located immediately east of
the chimney and south of the coal pile in a relatively open area. Part of
the plant road and employee parking area would need to be demolished/
relocated; therefore, a factor of 8 percent was assigned to general
21-173
-------
TABLE 21.6.1-2. SUMMARY OF NCx RETROFIT RESULTS FOR BRUCE MANSFIELD
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
OWF
OWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
OFA
FURNACE VOLUME (1000 CU FT)
734
734
734
BOILER INSTALLATION DATE
1976
1977
1980
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
50
50
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$)
133
133
133
New Duct Length (Feet)
450
450
250
New Duct Costs (1000$)
7717
j j |
4287
New Heat Exchanger (1000$)
6659
6659
6659
TOTAL SCOPE ADDER COSTS (1000$)
14509
14509
11079
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
21-174
-------
Table 21.6,1-3, NOx Control Cost Results for the Bruce Mansfield Plant (Jun# 1988 Dollars)
Technology
8oiler
Ha in
Boiler Capacity Coal
Capital
Capital Annual
Annual
NOX
NOx
MO* Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficult
Y
-------
N
Waste
Handling
Area
NHS Storage
System
Coal Storage/
Handling Area
Creak
Lime-Limestone
Storage/Preparation
Area
Absorbers
Cos)
Conveyor
Units 1-5
Storage
Building Chimney
Beaver River
FGD Waste Handling/Absorber Area
Lima/Limestone Storage/Preparation Area
NH, Storage System
SCfl Boxes
Not to scale
Figure 21.6.2-1. New Castle plant plot plan
21-176
-------
TABLE 21.6.2-1. NEW CASTLE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
3
4,5
GENERATING CAPACITY (MW-each)
37.5-40
97.8
113-136
CAPACITY FACTOR (PERCENT)
20,20
51
49,44
INSTALLATION DATE
1939,47
1952
1958,64
FIRING TYPE
FWF
FWF
FWF
COAL SULFUR CONTENT (PERCENT)
1.5
1.5
1.5, 1.:
COAL HEATING VALUE (BTU/LB)
12200
12200
12200
COAL ASH CONTENT (PERCENT)
11.1
11.1
11.1
FLY ASH SYSTEM
DRY
HANDLING
ASH DISPOSAL METHOD
ON-SITE/LANDFILL
STACK NUMBER
1
COAL DELIVERY METHODS
TRUCK
PARTICULATE CONTROL
TYPE
ESP
ESP
ESP
INSTALLATION DATE
1978
1978
1977
EMM IS ION (LB/MM BTU)
0.02
0.02
0.01
REMOVAL EFFICIENCY
98.7
99.2
99.2
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
1.5-3.0
1.5-3.0
i.5-3.0
5URFACE AREA (1000 SQ FT)
161
146
146,200
GAS EXIT RATE (1000 ACFM)
520
450
432,835
SCA (SQ FT/1000 ACFM)
310
324
338,315
OUTLET TEMPERATURE (°F)
340
302
272,292
21-177
-------
facilities. The lime storage/handling area would be located south of the
absorbers and east of the powerhouse, with the waste handling area located
adjacent to the absorbers.
Retrofit Difficulty and Scope Adder Costs--
A low site access/congestion factor was assigned to the absorber
locations due to the absorbers being located beside the chimney and close to
the ESPs in an area with no major obstacles/obstructions.
For flue gas handling, short duct runs for the units would be required
for L/LS-FGO cases since the absorbers would be close to the common duct
run/chimney. A low 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 Table 21.6.2-2. No large scope adder cost
is required for the New Castle plant. The overall retrofit factor determined
for the L/LS-FGD cases was low (1.19).
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. Even though the total collection surface areas for ESPs
were not available, the SCAs were assumed to be large enough based on the
ESPs performance. Therefore, the ESPs could be reused for the LSD-FGD
technology. For flue gas handling for LSD cases, short-moderate duct runs
would be required to divert the flue gas from the absorbers to the boilers
and back to the ESPs. A medium site access/congestion factor was assigned
to the flue gas handling system which reflects moderate congestion created
by the ESPs. The retrofit factor determined for the LSD technology case was
low (1.24) and did not include particulate control upgrading costs. A
separate retrofit factor was developed for upgrading the ESPs. A low
retrofit factor (1.16) was assigned for upgrading ESPs for all units due to
the available space around the ESPs with easy access and low congestion.
This factor was used in the 1APCS model to estimate particulate control
upgrading costs.
Table 21.6.2-3 presents the estimated costs for L/LS-FGD and LSD-FGD
cases. The LSD-FGD costs include upgrading the ESPs for boilers 1-5. The
low cost control case reduces capital and annual operating costs due to the
elimination of spare scrubber modules and the optimization of scrubber
module size.
21-178
-------
TABLE 21.6.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR NEW CASTLE UNITS 1-5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
LOW
LOW
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
0-100
0-100
ESP REUSE
100-300
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
1.19
1.19
ESP REUSE CASE
1.24
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
. NA
GENERAL FACILITIES (PERCENT) 8
8
8
Chimney liner and boiler draft controls are included in
retrofit factors.
21-179
-------
Table 21,6.2-3, Sumwry of FGO Control Costs for the New Castle Plant (June 1988 Dollars)
Technology
Soiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nutter
Retrofit
size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW>
(S3
content
E«W>
(SMM)
(mi lli/lcvh)
m
(tans/yr)
(S/ton)
Factor
IE FGO
1-5
1.19
424
43
1.5
53.5
137.9
29.6
18.5 ¦¦
90.0
17080
1733.4
LC FGO-C
1-5,
1.19
424
43
1.5
58.5
137.9
17.2
10.8
90.0
17080
1008.5
LFGO
1
1.19
38
20
1.5
21.2
564.2
8.7
132.0
90.0
702
12350.7
IFGD
2
1.19
40
20
1.5
21.7
541.7
8.9
'126.5
90.0
749
11840.8
LFGD
3
1.19
98
55
1.5
33.4
341.2
15.3
35.1
90.0
4669
3280.6
LFGO
4
1.19
113
49
1.5
34.7
306.6
16.0
33.0
90.0
5184
3084.4
LFGD
5
1.19
136
44
1.5
38.8
285.1
17.5
33.3
90.0
5602
3116.2
LFGD
1-5
1.19
424
• 43
1.4
78.5
185.0
36.0
22.5
90.0 -
16254
2213.2
LFGD-C
, 1.
1.19
38
20
1.5
21.2
' 564.2
5.1
77.1
90,0
702
7211.2
LFSO-C
2
1.19
40 .
20
1.5
21.7
541.7
5.2
73.9
90.0
749
6913.6
LFGD-C
3
1.19
98
51
1.5
33.4
341.2
8.9
20.4
90.0
4669
1911.6
LFGD-C
4
1.19
113
49
1.5
34.7
306.6
9.3
19.2
90.0
5184 •
1797.1
LFGD-C
5
1.19
136
44
1.5
3s.a
285.1
10.2
19.4
90.0
5602
1816.4
LFGD-C
1-5
1.19
424
43
1.4
78.5
185.0
21.0
13.1
90.0
16254
1289.7
LSD+ESP
1
1.24
38
20
1.5 •
8.2
218.3
4.9
75.0
76.0
595
8271.5
LSD+6SP
2
1.24
40
20
1.5
8.5
212.9
5.0
71.8
76.0
635
7928.6
LSD+ISP
3
1.24
98
51
1.5
14.7
149.9
7.8
17.9
76.0
3958
197D.9
LSD+ESP
4
1.24
113
49
1.5'
15.9
140.6
3,2
17.0
74.0
4242
1940.8
LSD+ESP
5
1.24
136
44
1.5
18.3
134.2
9.1
17.3
76.0
4749
1907.8
LSD+ESP-C
1
1.24
38
20
1.5
8.2
218.3
'2.9
43.5
76.0
595
4804.6
LSD+ESP-C
2
1.24
40
20
1.5
8.5
212.9
2.9
41.7
76.0
635
4602.6
LS0*ESP-C
5
1.24
98
51
1.5
14.7
149.9
4.5
10.4
76.0
3958
1145.8
LSD+E5P-C
4
1.24
113
49
1.5
15.9
140.6
4.8
9.9
74.0
4242
1128.7
LSD*ESP-C
5
1.24
136
44
1.5
18.3
134.2
5.3
10.1
76.0
4749
1110.3
21-180
-------
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. SO^ conditioning was assumed to reduce the needed plate area up to
25 percent.
Costs were generated to show the impact of two different coal fuel cost
differentials. The costs associated with each boiler for the range of fuel
cost differential are shown in Table 21.6.2-4.
N0„ Control Technology Costs--
X
This section presents the performance and costs estimated for NO
A
controls at the New Castle 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 technologies evaluated at the steam plant were: LNB and SCR.
A
Low N0X Combustion--
Units 1 to 5 are dry bottom, front wall-fired boilers rated at 38, 40,
98, 114, 136 MW, respectively. The combustion modification technique applied
for these boilers was LNB. As Tables 21.6.2-5 and 21.6.2-6 show, the LNB NO
X
reduction performances for units 3 to 5 were estimated to be 40, 43, and
37 percent, respectively. No boiler information could be found for units 1
and 2 to assess their N0X reduction performances. Since these boilers are
relatively old (1939 to 1947 in-service dates), it is estimated that a NO
A
reduction of 20 to 30 percent can be achieved by these boilers retrofitted
with LNB. Units 1 and 2 were installed between 1937 and 1947. The reduction
performance levels for units 3 to 5 were assessed by examining the effects of
heat release rates and furnace residence time on NO reduction through the
A
21-181
-------
Table 21,6.2-4. S unitary of Coal Snitching/Cleaning Costs for the New Castte Plant {June 1988 Dollars)
Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cast
Cost
Cost
Removes
Removed
Effect.
Difficulty
<$MM)
CmilU/kwh)
(X)
(tons/yr)
CS/B+S15
1
1.00
38
20
1.5
2.0
54.3
1.5
¦ 22.4
39.0
306
4821,9
CS/B«t15
2
1.00
40
20
1.5
2.1
53.0
1.5
22.1
39.0
326
4711.1
CS/8»S15
3
1.00
98
51
1.5
4.0
40.7
6.8
15.6
39.0
2033
3355.1
CS/B+I15
4
1.00
113
49
1.5
4.4
39.3
7.5
15.5
39.0
2257
3333.2
CS/0+I15
5
1.00
136
44
1.5
5.1
37.8
8.1
15.5
39.0
2439
3339.4
CS/B»I15-C
1
1.00
38
20
1.5
2.0
54.3
0.9
13.0
39.0
306
2792.5
CS/B+I15-C
2
1.00
40
20
1.5
2.1
53.0
0.9
12.8
39.0
326
2731.1
CS/I*$15-C
3
1.00
98
51
1.5
4.0
40.7
3.9
9.0
39.0
2033
1931.0
CS/B+J15-C
4
1.00
113
49
1.5
4.4
39.3
4.3
8.9
39.0
2257
1913,6
CS/B+J15-C
5
1.00
136
44
1.5
5.1
37.8
4.7
8.9
39.0
2439
1922.7
CS/B*t5
1
1.00
38
20
1.5
1.6
43.9
0.9
13.1
39.0
306
2824.2
CS/B*S5
2
1.00
40
20
1.5
1.7
42,7
0.9
12.8
39.0
326
2752.9
CS/B+S5
3
1.00
98
51
1.5
3.0
30.3
3.0
6.9
39.0
2033
1492,7
CS/B+S5
4
1.00
113
49
1.5
3.3
28.9
3.3
6,8
39.0
2257
1467.1
C5/B+S5
5
1.00
136
44
1.5
1.7
27.4
3.6
6.8
39.0
2439
1463.1
CS/B+S5-C
1
1.00
38
20
1.5
1.6
43.9
0.5
7.6
39.0
306
1642.1
CS/B*$5-C
2
1.00
40
20
1.5
1.7
42.7
0.5
7.4
39.0
326
1600.8
CS/B+S5-C
3
1.00
98
51
1.5
3.0
30.3
1.8
4.0
39.0
2033
861.7
CS/B+S5-C
4
1.00
113
49
1.5
3.3
28.9
1.9
3.9
39.0
2257
847.1
CS/B+S5-C
5
1.00
136
44
1.5
3.7
27.4
2.1
3.9
39.0
2439
845.2
21-182
-------
TABLE 21.6.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR NEW CASTLE UNITS
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
3
4
5
FIRING TYPE
FWF
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 Btu/CU.FT-HR)
NA
20.2
18
21.2
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 Btu/Sq.FT-HR)
NA
44.8
63.6
77.5
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
3.75
4.38
ESTIMATED NOx REDUCTION (PERCENT)
25
40
43
37
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
NA
NA
NA
NA
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
NA
NA
NA
NA
Ductwork Demolition (1000$)
NA
NA
NA
NA
New Duct Length (Feet)
NA
NA
NA
NA
New Duct Costs (1000$)
NA
NA
NA
NA
New Heat Exchanger (1000$)
NA
NA
NA
NA
TOTAL SCOPE ADDER COSTS (1000$)
NA
NA
NA
NA
RETROFIT FACTOR FOR SCR
NA
NA
NA
NA
GENERAL FACILITIES (PERCENT)
NA
NA
NA
NA
21-183
-------
TABLE 21.6.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR NEW CASTLE UNITS 1-5
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1-5
FIRING TYPE NA
TYPE OF NOx CONTROL NA
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) NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 80
New Duct Length (Feet) 250
New Duct Costs (1000$) 2892
New Heat Exchanger (1000$) 4447
TOTAL SCOPE ADDER COSTS (1000$) 7419
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
21-184
-------
use of the simplified NO procedures. Table 21.6,2-7 presents the cost of
A
retrofitting LN3 at the New Castle boilers.
Selective Catalytic Reduction--
Tables 21.6.2-5 and 21.6.2-6 present the SCR retrofit results for
reducing NOx emissions from the total flue gas from units 1 to 5, Because
the total flue gas from units 1 to 5 is ducted into one chimney, one SCR
reactor is sized for the total flow rate instead of sizing an SCR reactor for
each boiler flue gas. The results in Tables 21.6.2-5 and 21.6.2-6 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 common duct to the reactor
and from the reactor to the chimney.
The SCR reactor for units 1 to 5 would be located east of the chimney
and south of the coal pile in a relatively open area. Since the reactor was
located in an open area having easy access with no major obstacles, the
reactor for units 1 to 5 was assigned a low access/congestion factor. 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 NO control techniques were evaluated
A
independently from those evaluated for S02 control. If both S02 and N0X
emissions were reduced at this plant, the SCR reactor would have to be
located downstream of the FGD absorbers (north of the absorbers) in an area
having no major obstructions with easy access. In this case, a low access/
congestion factor again would be assigned to this SCR reactor.
Table 21.6.2-7 presents the estimated cost of retrofitting SCR at the New
Castle 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.
21-185
-------
Table 21.6,2-7, NOx Control Cost Results for the New Castle Plant (June 1988 Dollars)
__________asa5BBS________________________S3asas____=_______3________ca_ssaaa3.a______=_333as;ssssssssas=as_5SS____
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number
Retrofit
Site
Factor Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HWJ
«)
Content
(mi IIs/kwh)
LNC-LNB
1
1.00
38
20
1.5
1.7
45.6
0.4
•5.7
25.0
71
5305.7
INC-LMB
2
1.00
40
20
1.5
1.8
44.3
0.4
5.5
25.0
75
5144.8
INC-LMB
3
1.00
98
51
1.5
2.5
25.9
0.5
1.3
40.0
745
737.6
LNC-LNB
4
1.00
113
49
1.5
2.7
23.7
0.6
1.2
43.0
889
654.9
LNC-LNB
5
1.00
136
44
1.5
2.9
21.2
0.6
1.2
37.0
827
758.2
IWC-LNB-C
1
1.00
38
20
1.5
1.7
45.6
0.2
3.4
25.0
71
3149,0
LNC-LNB-C
2
1.00
40
20
1.5
1.8
44.3
0.2
3.3
25.0
75
3054.5
LNC-LNB-C
3
1.00
98
51
1.5
2,5
25,9
0.3
0,7
•40,0
745
437.8
LNC-LNB-C
4
1.00
113
49
1.5
2.7
23.7
0.3
D.7
43.0
889
388.8
LNC-LNB-C
5
1.00
13d
44
1.5
2.9
21.2
0.4
0,7
37.0
827
450.1
SCR-3
1-5
1.16
424
43
1.5
53.5
126.0
19.3
12.1
80.0
5450
3533.9
SCR-3-C
1-5
1.16
424
43
1.5
53.5
126.0
11.3
7.1
80.0
5450
2068.7
SCR-7
1-5
1.16
424
43
1.5
53,5
' 126.0
15.8
9.9
80.0
5450
2895.7
SCR-7-C
1-5
1.16
424
43
1.5
53,5
126.0
9.3
5.8
80,0
5450
1703.0
21-186
-------
The sorbent receiving/storage/preparation areas were located in a
similar fashion as LSD-FGD. The retrofit of DSD arid FSI technologies at the
New Castle steam plant for all the units would be easy. There is sufficient
duct residence time between the boilers and the retrofit ESPs. Because the
ESPs were reported to have good removal efficiencies, it was assumed that
only an ESP upgrade would be required to handle the increased load from DSD
and FSI. A low site access/congestion factor was assigned for upgrading the
ESPs for the same reasons as mentioned in the previous section.
Tables 21.6.2-8 through 21.6.2-12 present a summary of the site access/
congestion factors for DSD and FSI technologies at the New Castle steam
plant. Table 21.6.2-13 presents the costs estimated to retrofit DSD and FSI
at the New Castle 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 New Castle plant. All the boilers would be considered
good candidates for AFBC retrofit because of their small size (<140 MW) and
their ages (built before 1960).
21-187
-------
TABLE 21.6.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NEW CASTLE UNIT 1
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$) 14
TOTAL COST (1000$)
ESP UPGRADE CASE 14
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-188
-------
TABLE 21.6.2-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NEW CASTLE 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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 15
TOTAL COST (1000$)
ESP UPGRADE CASE 15
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE .1.13
NEW BAGHOUSE NA
21-189
I
-------
TABLE 21.6.2-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NEW CASTLE UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 29
TOTAL COST (1000$)
ESP UPGRADE CASE 29
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-190
-------
TABLE 21.6.2-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NEW CASTLE UNIT 4
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$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000S) NA
ESP REUSE 'CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 33
TOTAL COST (1000$)
ESP UPGRADE CASE 33
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-191
-------
TABLE 21.6.2-12. DUCT SPRAY DRYING AND FURNACE SQRBENT INJECTION
TECHNOLOGIES FOR NEW CASTLE UNIT 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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 38
TOTAL COST (1000$)
ESP UPGRADE CASE 38
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
21-192
-------
Table 21.6,2-13. Summary of DSD/FSt Control Costs for the New Castle Plant (June 1988 Dollars)
:sssss==:=5s:sssssx:===:::siss=:s:s:ss::8iass:ssss=ss:ssisaaB3saa8sa:s:xfs«asassis:::s:iisaaiaBssasiic3:::ssssas
Technology Boiler wain Boiler Capacity Coal Capitat Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Size Factor Sylfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (tons/yr) (S/ton)
Factor £%)
OSD+ISP
1
1.00
38
20
1.5
3.5
94.3
3.6
54.2
49.0
380
9377.3
DSD+ESP
2
1.00
40
20
1.5
3.6
91.1
3.6
51.4
49.0
405
8890.8
DSO+ESP
3
1.00
98
51
1.5
5.7
58.1
5.1
11.6
49.0
2524
2014.3
dso+esp
4
1.00
113
49
1.5
6.2
54.9
5.3
10.9
47.0
2726
1945.2
DSO+ESP
5
1.00
136
44
1.4
¦ 6.8
50.3
5.6
10.6
49.0
2885
1934.1
oso+esp-c
1
1.00
38
20
1.5
3.5
94.3
2.1
31.3
49.0
380
5414.5
OSO+ESP-C
2
1.00
40
20
1.5
3.6
91.1
2.1
29.7
49.0
405
5134.4
DSD+iSP-C
3
1.00
98
51
1.5
5.7
58.1
2.9
6.7
49.0
2524
1164.2
DSD+ESP-C
4
1.00
113
49
1.5
6.2
54.9
3.1
6.3
47.0
2726
1124.7
dso+esp-c
5
1.00
136
44
1.4
6.8
50.3
3.2
6.2
49.0
2885
1118.7
FSI+ESP-50 '
i
1.00
38
20
1.5
4.1
108.5
2.5
38.0
50.0
390
6408.9
FSI+ESP-50
2
1.00
40
20
1.5
4.2
103.9
2.5
36.2
50.0
416
6099.4
FSI+ESP-50
3
1.00
98
51
1.5
6.1
62.4
4.4
10.1
50.0
2594
1694.7
fsi+esp-so
4
1.00
113
49
1.5
6.4
56.4
4.6
9.6
50.0
2880
1609.2
FSt+ESP-50
S
1.00
136
44
1.5
7.4
54.5
5.0
9.6
50.0
3112
1621.7
FSi-ESP-SQ-C
1
1.00
38
20
1.5
4.1
108.5
1.5
22.1
50.0
390
3718.7
FSI+ESP-50-C
2
1.00
40
20
1.5
4.2
103.9
1.5
21.0
50.0
416
3539.4
FSI+ESP-50-C
3
1.00
98
51
1.5
6.1
62.4
2.5
5.8
50.0
2594
' 981.5
FSI+ESP-50-C
4
1.00
113
49
1.5
6.4
56.4
2.7
5.5
50.0
2880
931.9
FSI+ESP-50-C
5
1.00
136
44
1.5
7.4
54.5
2.9
5.6
50.0
3112
939.8
FSI+ESP-70
i
l.OO
38
20
1.5
4.1
110,0-
2.5
38.4
70.0
546
4614.2
FSI+ESP-70
2
1.00
40
20
1.5
4.2
105.3
2.6
36.5
70.0
583
4392.1
FSI+ESP-70
3
1.00
98
51
1.5
6.2
63.0
4.5
10.2
70.0
3632
1225.4
FSI+ESP-70
4
1.00
113
49
1.5
6.5
57.1
4.7
9.7
70.0
4032
1164.7
FSI+ESP-70
5
1.00
136
44
1.5
7.5
55.2
5.1
9.8
70.0
4357
1174.4
Fsi+esp-70-e
1
1.00
38
20
1.5
4.1
110.0
1.5
22.3
70.0
546
2677.5
FSI+ESP-70-C
2 .
l.OO
40
20
1.5
4.2
105.3
1.5
21.2
70.0
583
2548.8
FSI+ESP-70-C
3
1.00
98
51
1.5
6.2
63.0
2.6
5.9
70.0
3632
709.7
FS1+ESP-70-C
4
1.00
115
49
1.5
6.5
57.1
2.7
5,6
70.0
4032
674.5
FSI+ESP-70-C
5
1.00
136
44
1.5
7.5
55.2
3.0
5.7
70.0
4357
680.6
21-193
-------
21.7 PHILADELPHIA ELECTRIC COMPANY
21.7.1 Eddystone Steam Plant
The Eddystone steam plant is located within Delaware County,
Pennsylvania, as part of the Philadelphia Electric Company system. The plant
contains four coal-fired boilers with a total gross generating capacity of
1,490 MW. Units 1 and 2 are coal-burning while units 3 and 4 are petroleum
burning. Figure 21.7.1-1 presents the plant plot plan showing the location
of all boilers and major associated auxiliary equipment.
Table 21.7.1-1 presents operational data for the existing equipment at
the Eddystone plant. The units 1 and 2 boilers burn medium sulfur coal
(1.7 percent sulfur). Coal shipments are received by railroad and conveyed
to a coal storage and handling area located south of units 1-2, adjacent to
the Delaware River.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit. The plant has a dry fly ash handling system and
is disposed off-site to a landfill.
Lime/Limestone and Lime Spray Drying F6D Costs--
Figure 21.7.1-1 shows the general layout and location of the FGD control
system. The coal-burning boilers (units 1-2) are located north of the coal
pile and each have their own chimney. Units 3-4 are at a separate location
west of units 1-2, close to two large oil tanks, and share a common chimney
located south of the boiler buildings. Units 3-4 will not be considered in
this study since they are petroleum-burning. Units 1-2 have a retrofit FGD
system (built by United Engineers using magnesium oxide as sorbent) and would
not be considered in this study.
Coal Switching and Physical Coal Cleaning Costs-
Coal switching/physical coal cleaning was not an option since a wet FGD
system is already installed for units 1-2.
21-194
-------
Existing
FGD Units,
V"
Coal
Conveyor
^ ESP's . \/—a
% \\ *
%W <*
Switchyard
o
tchyara
o'
O
Coal Storage,'
Handling Area
Centrifuge
Dryer
Units
4-3
Chimney
Oil
Tanks
«NHj Storage
System
o
FGD Waste Handllng^Absorbef Area
Lime/Limestone Storage/Preparation Area
Not to scale
SCR Reactors
Figure 21.7.1-1, Eddystone plant plot plan
21-195
-------
TABLE 21.7.1-1. EDDYSTONE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
FUEL TYPE
GENERATING CAPACITY (HW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
COAL/PET SULFUR CONTENT (PERCENT)
COAL/PET 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
1 2
COAL COAL
354 354
43 34
1960 1960
TANG TANG
1.5 1.4
12700 13000
7.7 8.2
DRY HANDLING
PAID/SOLD DISPOSAL/OFF-SITE
1 2 3
RAIL ROAD
YES YES NO
1982 1982
Mg OXIDE
WET SCRUBBER
3,4
PET
391
1976
TANG
0.5
14900
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
1981
1982
1974-76
0.04
0.04
0.01
99.2
99.3
NA
2.6
2.6
0.5
122.9
122.9
961
1050
1095
860
117
112
112
122
125
650
21-196
-------
N0X Control Technology Costs--
This section presents the performance and costs estimated for NO
controls at the Eddystone 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 NOx technologies evaluated at the steam plant were: OFA and SCR.
Low N0X Combustion--
Units 1 and 2 are dry bottom, tangential-fired boilers, each rated at
354 MW. The combustion modification technique applied for this evaluation
was OFA. As Table 21.7.1-2 shows, the OFA NOx 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 and furnace residence
time on N0X reduction through the use of the simplified N0X procedures.
Table 21.7.1-3 presents the cost of retrofitting OFA at the Eddystone
boilers.
Selective Catalytic Reduction-
Table 21.7.1-2 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 to the reactor and from the reactor to the chimney.
Space is limited for SCR reactors at Eddystone Plant. Therefore, both
reactors have to be placed on the top of the existing FGD units by including
additional support equipment. A high site access/congestion factor was
assigned to the SCR reactor location. 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 NO control techniques were evaluated
independently from those evaluated for SOg control. For this plant, FGD
absorbers for both coal-fired units are already in place and currently are
operating. Therefore, the above results for SCR would not change since NQX
would be the only pollutant to be controlled at this plant. Table 21.7.1-3
presents the estimated cost of retrofitting SCR at the Eddystone boilers.
21-197
-------
TABLE 21.7.1-2. SUMMARY OF NOx RETROFIT RESULTS FOR EDDYSTONE
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)
. 12.3
12.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
35.3
41.6
FURNACE RESIDENCE TIME (SECONDS)
2.89
2.78
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$)
70
70
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
3,114
3,114
New Heat Exchanger (1000$)
3,979
3,979
TOTAL SCOPE ADDER COSTS (1000$)
7,163
7,163
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
13
13
21-198
-------
Table 21,7.1-3. MQx Control Cost Results for the Eddystone Plant (June 1933 Dollars)
Technology Boiler Hain Boiler
Number Retrofit Size
Difficulty
-------
Sorbent Injection and Repowering--
Duct spray drying, furnace sorbent injection, and AFBC retrofit were not
options in this study since a wet FGD system is already installed for these
units.
21-200
-------
SECTION 22.0 SOUTH CAROLINA
22.1 SOUTH CAROLINA ELECTRIC & GAS
22.1,1 Cariadvs
Sorbent injection technologies (FSI and DSD) were riot considered for
the Canadys plant because of the small size of the existing ESPs and the
short duct residence time between the boilers and ESPs.
TABLE 22.1.1-1. CANADYS 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
136 .
55,46
1962,1964
TANGENTIAL
52.5
NO
3
220
45
1967
OPPOSED WALL
89
NO
1.5
13000
9.4
WET DISPOSAL
POND/ON-SITE
1,2 3
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE ('F)
ESP
ESP
1972
1970
0.25
0.25
95
95
1.5
1.5
70.6
110
519
789
182
186
255
285
22-1
-------
TABLE 22.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CANADYS
UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
LOW
LOW
100-300
NA
NA
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.27
NA
NA
GENERAL FACILITIES (PERCENT) 8
NA
NA
NA
NA
NA
NA
NA
NA
LOW
NA
LOW
100-300
NA
LOW
YES
NA
NO
1235
NA
NA
NO
NA
NO
0
0
0
NO
NO
NA
1.16
NA
1.16
8
* Absorbers and new FFs for unit 1 would be located north of
unit 1; and absorbers and new FFs for unit 2 would be located
north of the unit 2 chimney.
22-2
-------
TABLE 22.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CANADYS UNIT 3 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE NA
BAGHOUSE CASE MEDIUM
DUCT WORK DISTANCE (FEET) 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$) 1901 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS -
FGD SYSTEM 1.42 NA
ESP REUSE CASE NA
BAGHOUSE CASE . 1.31
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 8 0 8
* Absorbers and new FFs for unit 3 would be located south of
unit 3, beside the coal conveyor.
22-3
-------
fable 22,1.1-4. Suimary of FGD Control Costs for the Canadys Plant (June 19B8 Dollars)
II
If
M
II
II
II
II
>«*=*=====
=======
========:
========:
II
II
II
II
II
II
II
II
II
II
II
II
II
1!
:=== = ===
3JS5SIJI3:!
=========
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
SQ2 Cost
Munber Retrofit
Size
Factor
sulfur
Cost
cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MV)
<%>
Content
(SMM)
(J/ItU)
CtWI)
(mills/kwh!
c%>
(tcns/yr)
(I/ton)
Factor
C%}
l/S FGD
1
1.27
136
55
1.5
42.9
315,2
17,7
27.0
90.0
6510
2721.7
L/S fGD
2
1.27
136
46
1.5
42.9
315.1
17.1
31.2
90.0
5445
3137.0
L/S FGD
3
1.42
220
45
1.5
61.3
278.5
24.0
27.7
90.0
S616
2787.7
L/S FGD
1-2
1.27
272
51
1.5
63.6
233.9
26.4
21.7
90,0
12074
2188.3
L/S FGD-C
1
1.27
136
55
1.5
42.9
315.2
10.3
15.8
90.0
6510
1588.9
L/S FGD-C
2
1.27
136
46
1.5
42.9
315.1
10.0
18.2
90,0
5445 ¦
1832.6
L/S FGD-C
3
1.42
220
45
1.5
61.3
278.5
14.0
16.2
90.0
6616
1629.1
L/S FGD-C
1-2
1.27
272
51
1.5
63.6
233 .a
15.4
12.7
90.0
12074
1277.4
LC FGD
1-2
1.27
272
51
1.5
42.3
155.4
20.1
16.5
90.0
12074
1664.3
LC FGD
3
1.42
220
45
1.5
41.9
190.6
18.3
21.0
90.0
8616
2118.1
LC FGD-C
1-2
1.27
272
51
1.5
42.3
155.4
11.7
9.6
90.0
12074
969.2
LC FGD-C
3
1.42
220
45
1.5
41.9
190.6
10.6
12.3
90.0
8616
1235.4
LSD+fF
1
1.16
136
55
1.5
28.4
208.7
11.0
16.8
86.0
6210
1777.0
LSO+FF
2
1.16
136
4 6
1.5
28.4
208.6
10.7
19.6
86.0
5194
2063.3
LSD*FF
3
1.31
220
45
1.5
46.6
211.9
16.3
18.8
87. D
8281
1971.4
LSO+FF-C
1
1.16
136
55
1.5
28.4
203.7
6.4
9.8
86.0
6213
1038.6
LSD+FF-C
2
1.16
136
46
1.5
23.4
20S.6
6.3
11.4
86.0
5194
1206.7
LSD-FF-C
3
1.31
220
45
1.5
46.6
211.9
9.6
11.0
87.0
8281
1154.7
22-4
-------
Table
22.1.1-5
Swinery of Coal
Sw i t eh ing/C lean iris Casts for the Caradys Plant
(June
1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
:ss;assES33S8a»8883asss:
Capital Capital Annual
Annual
S02
$02
S02 Cost
Nuitoer
Retrofit
Silt
factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty (HU>
<%>
Content
(SWO
(S/kW>
(SW)
(mills/kwh)
(X)
Itons/yrj
-------
TABLE 22,1,1-6, SUMMARY OF NOx RETROFIT RESULTS FOR CANAPYS
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
1-2
FIRING TYPE
TANG
OWF
NA
TYPE OF NOx CONTROL
OFA
LNB
NA
FURNACE VOLUME (1000 CU FT)
52.5
89
NA
BOILER INSTALLATION DATE
1962,64
1967
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
28
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
34
49
57
New Duct Length (Feet)
200
400
200
New Duct Costs (1000$)
1186
3144
1779
New Heat Exchanger (1000$)
2241
2991
3397
TOTAL SCOPE ADDER COSTS (1000$)
3462
6184
5234
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for units 1, 2, and 3 would be located
north of unit 1, north of the unit 2 chimney, and south of
unit 3, respectively.
22-6
-------
Table 22.1,1-7, nqx control Cost Rssults for th# canmfys Plant CJune 1988 Dollars}
SS3£»8S88S;
;:=3=2sss
s»a»s»asa:
:ss8bss:
BSSSlSaSSSSSISS&SS SS99SS!
mmn
«»nn
S SS S S SSS SS 8S s
SSS
ess:
S SS S S —5 S 5.-5
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NO*
NOx Cost
Nunber
Retrofit
Si*e
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (NW)
(X)
Content
(JSMM)
(S/kW)
(SUM)
(mi IIs/kwh)
(X)
(tons/yr)
<*/ton)
factor
C%!
LNC-INB
3
1.00
220
45
1.5
3.5
15,9
0.7
0.8
28.0
962
763.0
IMC-INB-C
3
1.00
220
45
1.5
3.5
15,9
0.4
0.5
28.0
962
453.5
INC-OFA
1
1.00
136
55
1.5
0.7
5.1
0.1
0.2
25
0
464
316.8
LMC-OFA
2
1.00
136
46
1.5
0.7
5.1
0.1
0.3
25
0
388
371.8
INC-OFA-C
1
1.00
136
55
1.5
0.7
5.1
0.1
0.1
25
0
464
188.3
tNC-CFA-C
2
1.00
136
46
1.5
0.7
5.1
0.1
0.2
25
0
388
225.1
SCR-3
1
1.16
136
55
1.5
22.8
167.9
7.4
11.3
80.0
1484
5000.5
SCR-3
2
1.16
136
46
1.5
22.3
167.9
7.4
13.4
80
0
1241
5929.0
SCR-3
3
1.16
220
45
1.5
34.4
156.5
11.2
12.9
80
0
2749
4084.4
SCR-3
1-2
1.16
272
51
1.5
38.5
141.6
13.0
10.7
80
0
2752
4727.0
SCR-3-C
1
1.16
136
55
. 1.5
22.8
167.9
4.4
6.6
80
0
1484
2934.0
SCR-3-C
2
1.16
136
46
1.5
22.8
167.9
4.3
7.9
so
0
1241
3479.4
SCR-3-C
3
1.16
220
45
1.5
34.4
156,5
6.6
7.6
80
0
2749
2396.2
SCR-3-C
1-2
1.16
272
51
1.5
38.5
141,6
7.6
6.3
80
0
2752
2771.1
SCR-7
1
1.16
136
55
1.5
22.8
167.9
6.3
9.6
80
0
1484
4256.3
SCR-7
2
1.16
136
46
1.5
22.3
167.9
6.3
11.4
80
0
1241
5039.1
SCR-7
3
1.16
220
45
1.5
34,4
156.5
9.4
10,9
TO
0
2749
3434.6
SCR-7
1-2
1.16
272
51
1.5
38.5
141.6
10.8
8.9
80
0
2752
3924.3
SCR-7-C
1
1.16
136
55
1.5
22.8
167.9
3.7
5.7
80
0
1484
2507.6
SCR-7-C
2
1.16
136
46
1.5
22.8
167.9
3.7
6.7
80
0
1241
2969.5
SCR-7-C
3
1.16
220
45
1.5
34.4
156.5
5.6
6.4
80
0
2749
2024.0
SCR-7-C
. 1-2
1.16
272
51
1.5
38.5
141.6
6.4
5.2
80
0
2752
2311.2
22-7
-------
22.1.2 Silas C. McMeekin Steam Plant
The McMeekin steam plant is located on Lake Hurray in Lexington
County, South Carolina, and is operated by the South Carolina Electric and
Gas Company. The McMeekin plant contains two coal-fired boilers with a
gross generating capacity of 294 MW.
Table 22.1.2-1 presents operational data for the existing equipment at
the McMeekin plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area north of the plant. PM emissions from
the boilers are controlled by retrofit ESPs located behind each boiler. Wet
fly ash is ponded, then removed and landfilled.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for both boilers would be located beside their
respective chimney. The site access/congestion factor is medium for both
locations. No relocations or demolitions would be required for either
location; hence, a low general facilities factor of 5 percent was assigned.
For each unit, a short duct length of about 200 feet would be needed to span
the distance from the chimney to the absorbers and back to the chimney. A
low site access/congestion factor was assigned to flue gas handling for both
boilers since there are no complications in accessing the duct.
LSD with reuse of the existing ESPs was not considered for the McMeekin
plant since the ESPs are relatively small and would probably have trouble
handling the additional load of LSD. Since the boilers at the McMeekin
plant are burning a low to medium sulfur coal, LSD with a new baghouse was
considered for both boilers. The LSD absorbers would have the same location
as the L/LS-FGD absorbers; therefore, similar site access/congestion factors
and general facility factors were assigned to these locations. The new FFs
would be located adjacent to the LSD absorbers. A duct length of 100 to
300 feet would be required and the site access/congestion factor for flue
gas handling would be low. Tables 22.1.2-2 and 22.1.2-3 present the
retrofit factor input to the IAPCS model and cost estimates for installation
of conventional FGD systems at the McMeekin plant.
22-8
-------
TABLE 22.1.2-1. SILAS C. HCMEEKIN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 147
CAPACITY FACTOR (PERCENT) 80
INSTALLATION DATE 1958
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) 52.5
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.4
COAL HEATING VALUE (BTU/LB) 13000
COAL ASH CONTENT (PERCENT) 9.0
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD STORAGE/OFF-SITE
STACK NUMBER 1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1970
EMISSION (LB/MM BTU) NA
REMOVAL EFFICIENCY 94.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.5
SURFACE AREA (1000 SQ FT) 70.6
GAS EXIT RATE (1000 ACFM) 387
SCA (SQ FT/1000 ACFM) 182
OUTLET TEMPERATURE (4F) 255
22-9
-------
TABLE 22.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MCMEEKIN
UNIT 1 OR 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
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 1324 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS ¦
FGD SYSTEM 1.37 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.29
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.36
GENERAL FACILITIES (PERCENT) 5 0 5
22-10
-------
Table 22,1,2-3. Sunttary of FGO Control Costs for the HcMeekin Plant (June 1983 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuiiier Retrofit Sire Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content CSMM) (S/kW) <$MM) CS!
-------
Coal Switching and Physical Coal Cleaning Costs--
Table 22.1,2-4 presents the IAPCS cost results for CS at the McMeekin
plant. These costs do not include reduced pulverizer operating costs or any
system modifications that may be necessary for blending coals, PCC was not
evaluated because the McMeekin plant is not a mine mouth plant.
NO Control Technologies--
A
OFA was considered for NQX emissions control for the two
tangential-fired boilers at the McMeekin plant. Tables 22.1.2-5 and
22.1.2-6 present the NQx performance and cost estimates for installation of
OFA at the McMeekin plant.
Selective Catalytic Reduction--
Cold side SCR reactors for each boiler would be located behind their
respective chimney. As in the FGD case, low site access/congestion factors
and low general facility values (13 percent) were assigned to each location.
Approximately 200 feet of ductwork would be required to span the distance
between the SCR reactors and the chimneys. Tables 22.1.2-5 and 22.1.2-6
present the retrofit factors and costs for installation of SCR at the
McMeekin plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the McMeekin plant because the existing ESPs are too small to handle the
additional load imposed by these technologies and the duct residence time
between the boilers and ESPs is too short.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Both boilers at the McMeekin plant would be candidates for repowering
technologies because of their small boiler size and short remaining useful
life. However, both boilers have relatively high capacity factors which
might result in high replacement power costs in the case of extensive boiler
downtime.
22-12
-------
Table 22.1.2-4. Surinary of Coal Switching/Cleaning Costs for ttie McHeekin Plant (June 1988 Dollars)
Technology 3oiler Main Boiler Capacity Coal Capital Capitat AnnuaI
lunber Retrofit Six* Factor Sulfur Cost Coat Cost
Difficulty (MV) (X) Content (SW) (»/ltW) (W4IO
Factor (%>
Annual S02 SD2 502 Cost
Cost Removed Removed Effect.
(tons/yr) (t/ton)
CS/B+S1S
CS/B*t15
1.00
1.00
147
147
80
80
1,4
1.4
6.0
6.0
41.1
41.1
15.2
15.2
14.7
14.7
30.0
30.0
3176
3176
4780.6
4780.6
CS/8+I15-C
CS/8*115-C
1.00
1.00
147
147
80
80
1.4
1.4
6.0
4.0
41.1
41.1
8.7
8.7
30.0
30.0
3176
3176
2747.5
2747.5
CS/B+J5
CS/B+S5
1.00
1.00
147
147
SO
80
1.4
1.4
4.5
4.5
30.8
30.8
6.4
6.4
30.0
30.0
3176
3176
2017.1
2017.1
CS/B*$S-C
CS/8*$5-C
1.00
1.00
147
147
80
80
4.5
4.1
30.8
30.8
3,7
3.7
30.0
30.0
3176
3176
1162.1
1162.1
S3SSS1SS35
SSIBSSI3S
SSSS8SS8
sastsaBsasBsssssBiasasssassssas
22-13
-------
TABLE 22,1.2-5. SUMMARY OF NPx RETROFIT RESULTS FOR MCMEEKIN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 52.5
BOILER INSTALLATION DATE 1958
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 36
New Duct Length (Feet) 200
New Duct Costs (1000$) 1242
New Heat Exchanger (1000$) 2349
TOTAL SCOPE ADDER COSTS (1000$) 3626
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
22-14
-------
Table 22,1,2-6. NO* Control Cost Results for the HcHeekin Plant {June 1988 Dollars)
Technology Boiler Main Bailer Capacity Coat Capital Capital Annual Annual NOx NOx NQx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
Factor <*>
iNC-OFA. 1
LMC-OFA 2
LHC-OFA-C 1
LNC-OFA-C 2
SCR-3 1
SCS-3 2
SCR-3-C 1
SC8-3-C 2
SCR-7 1
SCR-7 2
SCR-7-C .1
SCR-7-C 2
1.00 147 SO
1.00 147 80
1.00 147 80
1.00 147 80
1.16 147 80
1.16 147 80
1.16 147 80
1,16 147 80
1.16 147 80
1.16 147 80
1.16 147 80
1.16 147 80
1.4 0.7 4.9
1.4 0.7 4.9
1.4 0.7 4.9
1.4 0.7 4.9
1.4 23.6 160.6
1.4 23.6 160.6
1.4 23.6 160.6
1.4 23.6 160.6
1.4 23.6 160.6
1.4 23.6 160.6
1.4 23.6 160.6
1.4 23.6 160.6
0.2 0.1 25.0
0.2 0.1 25.0
0.1 0,1 25.0
0.1 0.1 25.0
8.0 7.7 80.0
8.0 7.7 80.3
4,7 4.5 80.D
4.7 4.5 80.0
6.8 6.6 80.3
6.8 6.6 30.3
4.0 3,9 80.0
4.0 3.9 80.0
729 207.8
729 207.B
729 123.5
729 123,5
2333 3411,4
2333 3411.4
2333 1999.8
2333 1999.8
2333 2899,6
2333 2899.6
2333 1706.6
2333 1706.6
22-15
-------
22.1.3 Urauhart Steam Plant
Sorbent injection technologies {FSI and DSD) were not considered for
the Urqubart plant because of the inadequate size of the ESPs and the short
duct residence time between the boilers and the ESPs.
TABLE 22.1.3-1. URQUHART 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
75,75,100
50,45,70
1953,54,55
TANGENTIAL
44.6,44.6,60.9
NO
1.2
12900
9.2
DRY DISPOSAL
LANDFILL/ON-SITE
1,2,3
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
ESP
1968,68,69
0.33,0.38,0.29
99,0
1.5
45.0,45.0,60.0
315,344,494
199,199,191
305,294,292
22-16
-------
TABLE 22.1,3-2. SUMMARY OF RETROFIT FACTOR DATA FOR URQUHART
UNIT 1, 2 OR 3 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
LOW
MEDIUM
300-600
NA
NA
NO
NA
NO
0
NO
1.35
NA
NA
GENERAL FACILITIES (PERCENT) 5
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
0
LOW
NA
MEDIUM
300-600
NA
LOW
NO
NA
NO
0
NO
NA
1.31
NA
1.16
* Absorbers and new FFs for each unit would be located behind
their respective chimney.
22-17
-------
Table 22.1,3-3. 5untiery of FG8 Control Costs for the Urquhsrt Plant (June 1988 Dollars)
Technology
Botler
Main
Boiler Capacity Coal
Capital
Capital Annuai
Annual
S02
S02
S02 Cost
Nunber
Retrofit
Si je
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HW)
w
Content
(SUM)
CS/KU)
(»«>
(milts/kyh)
<%>
(toris/yr)
($/ton(
Factor'
m
L/S FGD
1
1.35
75
50
1.2
33.0
439.6
13.0
39.6
90.0
2634
4935.1
l/S FGD
2
1.35
75
46
1.2
32.9
439.1
12.8
42.4
90.0
2424
5292,8
L/S FGD
3
1.35
100
70
1.2
36.6
366.5
15.6
25.5
90.0
4917
3176.9
L/S FGD-C
1
1.35
75
50
1.2
33.0
439.6
7.6
23.1
90.0
2634
2883.6
l/S FGD-C
2
1.35
75
46
1.2
32.9
439.1
7.5
24.8
90,0
2424
3093.4
L/S FGO-C
3
1.35
100
70
1.2
36.6
366.5
9.1
14.9
90.0
4917
1853.6
LC FGD
1-3
1.35
250
57
1.2
4i,a
167.1
19.8
15,9
90.0
10010
1982.3
IC FGD-C
1-3
1.35
250
57
1.2
41.8
167.1
11.6
9.3
90.0
10010
1154.4
ISD+FF
1
• 1.31
75
50
1.2
20.1
266.4
8.0
24.2
87.0
2532
3144.9
ISQ+FF
I
1.31
75
46
1.2
20.0
266.4
7.8
26.0
87.0
2329
3370,0
LSD+FF
3
1.31
100
70
1.2
24.4
243.8
9.8
16.0
87.0
4726
2071.9
LSD+FF-C
1
1.31
75
50
1.2
20.1
268.4
4.7
14.2
87.0
2532
1837.4
LSD+FF-C
2
1.31
75
46
1.2
20.0
266.4
4.6
• 15.2
87.0
2329
1969,3
LSO+FF-C
3
1.31
100
70
1.2
24-4
243.S
5.7
9.3
87.0
4726
1210.2
22-18
-------
Ta&le 22.1,1-4. Sunrtary of Coal Switching/Cleaning Costs for the urquhflft Plant (June 1988 Dollars)
iBSsasaassss5SSS9SS3:s=5::aa::s:ss==issssaSBs338ss:r:=sasaaaas3==3=====;;8S3ss===;:;;;;:assess=3as;35:::ss«ra::=
Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
SQ2
S02
SOZ Cost
Nurijer Retrofit
Size
Factor
Sulfur
Cost
Coat
Cost
Cost
Removed Removed
Effect.
Difficulty <«0
(X)
Content
(MM)
(i/kt!)
-------
TABLE 22,1.3-5, SUMMARY OF NOx RETROFIT RESULTS FOR URQUHART
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 3
FIRING TYPE TANG ' TANG
TYPE OF NOx CONTROL OFA OFA
FURNACE VOLUME (1000 CU FT) 44.6 60.9
BOILER INSTALLATION DATE 1913,1954 1955
SLAGGING PROBLEM __N0 NO
ESTIMATED NOx REDUCTION (PERCENT) 25 25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0
Ductwork Demolition (1000$) 22 27
New Duct Length (Feet) 300 300
New Duct Costs (1000$) 1257 1487
New Heat Exchanger (1000$) 1568 1864
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 2847 3378
COMBINED CASE (1-3) 5824
RETROFIT FACTOR FOR SCR 1.15 1.16
GENERAL FACILITIES (PERCENT) 13 13
* Cold side SCR reactors for units 1,2 and 3 would be located
behind the chimney for that unit.
22-20
-------
Table 22.1.3-6. NQx Control Cost Results for the Urquhart Plant (June 1988 Dollars)
=ss===2s===2SSS=====3r==a==j!!s=:==2s==s=5====ssaass=3====sB=========s===s=====!SSS=asss;5=S5ss=s5;s====5=='3aassaa
Technology
Boiler
Main
Boiler Capacity Coat
Cap!tal
Capital
Annual
Annual
HO*
NOX
MO* cost
Nurtxr
Retrofit
Size
Factor
Sulfur
cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (WW!
CX>
Content
<««>
(i/kM)
($HM>
{miUs/kwh)
(%)
(tons/yr)
C$/ton>
Factor
m
LNC-OFA
1
1.00
75
50
1.2
0.6
7.4
0.1
0.4
25.0
235
493.3
LNC-OFA
1
1.00
75
46
1.2
0.6
7.4
0.1
0.4
25.0
216
536.2
LNC-OFA
3
1.00
100
70
1.2
0.6
6.2
0.1
0.2
25.0
438
296.7
INC-GFA-C
1
1.00
n
50
1.2
0.6
7.4
0.1
0.2
25.0
235
293.4
LNC-OFA-C
2
1.00
75
46
1.2
0.6
7.4
0.1
0.2
25.0
216
318.9
LNC-OFA-C
3
1.00
100
70
1.2
0.6
6.2
0.1
0.1
25.0
438
176.3
SCR-3
1
1.16
75
50
1.2
15.9
211.8
4.9
14.8
80.0
751
6496.5
SCR-3
2
1.16
75
46
1.2
15.9
211.6
4.9
16.1
80.0
691
7034.8
SCR-3
3
1.16
100
70
1.2
18.9
188.9
6.0
9.8
80,0
1401
4304.6
SCR-3
1-3
1.16
250
57
1.2
36.5
145.3
12.2
9.8
80.0
2852
, 4288.6
SCR-3-C
1
1.16
75
50
1.2
15.9
211.8
2.9
8.7
80,0
751
3817,0
SCR-3-C
2
1.16
75
46
1.2
15.?
211.6
2.9
9.4
80.0
691
4133.5
SCR-3-C
3
1.16
100
70
1.2
18.9
188.9
3.5
5.8
80.0
1401
2526.7
SCR-3-C
1-3
1.16
250
57
1.2
36.5
us.e
7.2
5.7
80.0
2852
2514.4
SCS-7
1
1.16
75
50
1.2
15.9
211.8
4,3
13,0
80.0
751
5684.1
SCR-7
2
1.16
75
46
1.2
15.9
211.6
4.2
14.1
80.0
691
6151.9
SCR-7
3
1.16
100
70
1.2
18.9
188.9
5.2
8.5
80.0
1401
3724.3
SCR-7
1-3
1.16
250
57
1.2
36.5
145.8
10.2
S.2
80.0
2852
3575,9
5CR-7-C
1
1.16
75
50
1.2
15.9
211.8
2.5
7.7
80.0
751
3351.5
SCR-7-C
2
1.16
75
46
1.2
15.9
211.6
2.5
8.3
80.0
691
3627.6
SCR-7-C
3
1.16
100
70
1.2
18.9
188.9
3.1
5.0
80.0
1401
2194.2
SCR-7-C
1-3
1.16
250
57
1.2
36.5
145.8
6.0
4.8
80.0
2852
2106.1
ssaassas
II
II
11
II
l»
II
11
II
II
II
II
ssssssss
sssssss
ssasassssss
SS33SS
sssssssssS3
II
II
II
¦1
II
II
II
22-21
-------
22.1.4 Wateree Steam Plant
Sorberit injection technologies were not considered for the Wateree
plant because the boilers are equipped with small ESPs which might not be
able to handle the increased load.
TABLE 22.1.4-1. WATEREE 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
386 386
65 65
1970 1971
OPPOSED WALL
199 199
NO NO
1.4
12800
9.0
WET DISPOSAL/DRY
PONDS/ON-SITE/PAID
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 ACFMJ
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
1970
1971
0.35
0.35
97.1
96.9
1.5
1.5
204.2
265.5
1232
1232
166
143
280
270
22-22
-------
TABLE 22.1.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR WATEREE
UNIT 1 OR 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 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$) 3147 NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.48 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.40
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 0 5
* L/LS-FGD absorbers, LSD-FGD absorbers, and new FFs for units 1
and 2 would be located east of their respective chimney.
22-23
-------
Table 22.1.4-3. Summary of FGD Control Costs for the Watsre# Plant (June 1983 Dollars)
Technology BoiUr Main Bailer Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cast
Nwber Retrofit Slit Factor sylfur Cost Cost Cost Cost Raitoved Removed Effect.
Difficulty (KU) (%} content (S/kU) (IMH) (miIIs/kwh) {X) (tsns/yr) <$/tcn)
Factor <%>
90.0
90.0
20747
20747
l/S FGD 1 1.41 386 65 1.4 87.5 226.fi 38.2 17.4 90.0 20747
L/S FGD 2 1.48 386 65 1.4 87.4 226.5 38.3 17.4 90.0 20747
l/S FGD-C 1 1.48 386 65 1.4 87.5 226.fi 22.3 10,1
L/S FGD-C 2 t.48 386 65 1.4 87.4 226.5 22.3 10.2
LC FGD 1*2 1.48 772 65 1.4 110.6 143.3 55.1 12.5 90.0 41494
LC FGD-C 1-2 1.48 772 65 1.4 110.6 143.3 32.1 7.3 90.0 41494
ISD+FF 1 1.40 386 65 1.4 70.5 182.6 26.2 11.9 87.0
ISD+FF 2 1.40 386 65 1.4 69.9 181.1 26.0 11.8 87.0
LS0*FF"C 1 1.40 386 65 1.4 70.5 182.6 15.3 7.0 87.0
L SO+FF-C 2 1.40 386 65 1.4 69.9 181.1 15.2 6.9 87.0
19940
19940
19940
19940
1842.6
1844.5
1074.6
1075 .7
1328.8
771.3
1313.7
1305.2
768.5
763.5
22-24
-------
Table 22.1.4-4. suimary of Caal SHitchlrig/Cleanirsa costs far th# uattrt# Plant (Junt 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Muil5«r Retrofit Siz« factor Sulfur Cost Cost Cost Cost Removed tamovad Efftct.
Difficulty (MO (S) Content ($t«) (S/irtJ) (««> (mills/kwh) !X> (tons/yr) ct/ton)
Factor
-------
TABLE 22.1.4-5. SUMMARY OF NOx RETROFIT RESULTS FOR WATEREE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) 199
BOILER INSTALLATION DATE 1970, 1971
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 35
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 74
New Duct Length (Feet) 300
New Duct Costs (1000$) 3276
New Heat Exchanger (1000$) 4191
TOTAL SCOPE ADDER COSTS (1000$) 7542
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for units 1 and 2 would be located east of
their respective chimney.
22-26
-------
Table 22.1.4-6. MOx Control Cost Results for the yateree Plant (June 1988 Dollars)
Technology Sailer Main BoiUr Capacity Coal Capital Capital Annual Annual NO* NOx NQx Cost
Nurber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty cmo <%) Content (SMM) (S/kW) (tm) {*) (cans/yr) (S/ton)
Factor {%)
LNC-LNB
LNC-LNB
00
00
386
386
65
65
4.4
4.4
11
11
0.9
0.9
0.4
0.4
35.0
35.0
3103
3103
296.2
296.2
INC-LN8-
LMC-LNB-
00
00
386
386
65
65
4.4
4.4
11
11
0.5
0.5
0.2
0.2
35,
35,
3103
3103
176.0
176.0
SCR-3
SCR-3
16
16
386
396
61
65
49.6
49.6
128
128
17.7
17.7
80.0
80.0
7093
7093
2499,
2499,
SCR-3-C
SCR-3-C
16
16
386
386
65
65
49.6
49.6
128
128
10.4
10.4
4.7
4.7
80.0
80,0
7093
7093
1463.4 '
1463.4
SCR-7
SCR-7
16
16
386
386
65
65
49.6
49.6
128
128
14.6
14.6
6.6
6.6
80.0
80.0
7093
7093
2056,6
2356.5
SCR-7-C
SCR-7-C
16
16
386
386
65
65
49.6
49.6
128
128
8.6
8.6
3.9
3.9
80.0
80.0
7093
7093
1209.7
1209.6
22-27
-------
22.2 SOUTH CAROLINA GENERATING
22,2.1 Arthur M, Williams Steam Plant
The 608 MW unit at the Arthur H. Williams power plant fires a low
sulfur coal; therefore, CS was not evaluated. Retrofit factors were
developed for FGD; however, costs are not shown since the low sulfur coal
would result in low estimates of capital/operating costs arid high cost per
ton of SOg removed.
TA8LE 22.2.1-1. ARTHUR M. WILLIAMS 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
608
70
1973
TANGENTIAL
270
NO
1.0
12900
8 3
DRY DISPOSAL
LANDFILL/OFF-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/1D00 ACFM)
OUTLET TEMPERATURE (*F)
ESP
1984
0.02
99.6
1.5
637.6
2800
228
310
22-28
-------
TABLE 22.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR WILLIAMS
UNIT 1 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.20
NA
ESP REUSE CASE
1.27
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
8
0
8
* The L/LS-FGD absorbers would be located northeast of the
chimney and the LSD-FGD absorbers would be located north of
unit 1.
22-29
-------
TABLE 22.2.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR WILLIAMS
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
I
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 270
BOILER INSTALLATION DATE 1973
SLAGGING PROBLEM NO__
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 105
New Duct Length (Feet) 200
New Duct Costs (1000$) 2849
New Heat Exchanger (1000$) 5505
TOTAL SCOPE ADDER COSTS (1000$) 8458
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
* Cold side SCR reactors would be located northeast of the chimney.
22-30
-------
Table 22.Z.1-4, NO* Control Cost Results for the Uilliams Plsnt (June 1986 Dollars)
Technology Boiler Main Boiler
Number Retrofit Size
Difficulty (MU>
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
(two
Annual NO* NO* NOx Cost
Cost Betnovfid Removed Effect,
(mills/kwh) <%} (tons/yr) (J/ton)
LNC-OFA 1
LNC-OFA-C 1
sea-3 1
SCR-3-C 1
scn-7 1
sea-?-: 1
1.00 608 70
1.00 608 70
1.16 60S 70
1.16 608 70
1.16 608 70
1.16 60S 70
1.0 1.3 2.1
1.0 1.3 2.1
1.0 73.2 120.4
1.0 73.2 120.4
1.0 73.2 120.4
1.0 73.2 120.4
0.3 0.1 25,0
0.2 0.0 25.0
26.8 7.2 80.0
15.7 4.2 80.0
21.8 5.9 80.0
12.8 3.4 80.0
2662 100.5
2662 59.7
8518 3143.7
8518 1839.7
8518 2563.4
8518 1507,2
22-31
-------
TABLE 22.2.1-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ARTHUR M. WILLIAMS UNIT 1
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 116
TOTAL COST (1000$)
ESP UPGRADE CASE 116
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
FSI and DSD were considered due to the adequate size of the ESPs
arid the sufficient duct residence time between the boiler and
ESPs.
22-32
-------
Table 22,2.1-6. Surma ry of BSO/FSI Control Costs for the Will fans Plant (Jure 1988 Dollars)
¦ ¦HiamlBiiiuaiBsiiusinuminnfaiiinamBasKUH
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 $02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (SHM) (mills/kwh) (%) (tons/yr) CS/ton)
Factor (X)
DSD+ESP
DSD+ESP-C
FSl*ESP-50
FSI+ESP-50-C
FSI+ESP-70
FS1+ESP-70-C 1
1.00 608 70 1.0 19.0 31.2 13.2 3.5 49,0 13467 976.8
1.00 608 70 1.0 19.0 31.2 7:6 2,0 49.0 13467 566.0
1.00 60S 70 1.0 23.0 37.8 15.6 4.2 50.0 13841 1129.9
1.00 608 70 1.3 23.0 37.8 9.1 2.4 50.0 13841 654.8
1.00 608 70 1.0 22.9 37.7 15.8 4.2 70.0 19378 815.6
1.00 608 70 . 1.0 22.9 37.7 9.2 2.5 70.0 19378 472.6
22-33
-------
22.3 SOUTH CAROLINA PUBLIC SERVICE
22.3.1 Gralnaer Steam Plant
The Grainger Steam Plant is located in Horry County, South Carolina, as
part of the South Carolina Public Service system. The plant contains two
coal-fired boilers with a total gross generating capacity of 164 MW.
Tables 22.3.1-1 through 22.3.1-8 summarize the plant operational data and
present the S02 and N0X control cost and performance estimates.
TA8LE 22.3.1-1. GRAINGER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 82
CAPACITY FACTOR (PERCENT) 44,50
INSTALLATION DATE 1966
FIRING TYPE FRONT WALL
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.8
COAL HEATING VALUE (BTU/LB) 12700
COAL ASH CONTENT (PERCENT) 10.2
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD POND/ON-SITE
STACK NUMBER 1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1966
EMISSION (LB/MM BTU) 0.34,0.103
REMOVAL EFFICIENCY 95
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.2
SURFACE AREA (1000 SQ FT) 66.1
GAS EXIT RATE (1000 ACFM 191.4
SCA (SQ FT/1000 ACFM) 345
OUTLET TEMPERATURE (°F) 300
22-34
-------
TABLE 22.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR GRAINGER
UNIT 2 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 HIGH
RAGHOUSF TASF NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 785 NA 785
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE 1.43
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10,5 0 10,5
* Absorbers for unit 1 would be located east of unit 1.
Absorbers for unit 2 would be located south of the unit 2
chimney. The general facilities for unit 1 and 2 are 10,
and 5 percent, respectively.
22-35
-------
Table 22.3.1-3. Stmmary of FGD Control Costs for the Grainger Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 SQ2 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Sfftct.
Difficulty (HM> (X> Content (X) (tons/yr) <$/ton)
Factor (X>
L/S FGD 1 1.27 82 44 1.8 35.5 433.0 13.8 43.8 90.0 3871 3575.0
l/S FGD 2 1.27 82 50 1.8 34.5 420.3 13.8 38.5 90.0 4398 3141.8
L/S FG0-C 1 1.27 82 44 1.8 35.5 433.0 8.1 25.6 90.0 3871 2089.4
l/S FG0-C 2 1.27 82 SO 1.B 34.5 420.3 8.1 22.5 90.0 4398 1835.2
LC FGD 1-2 1.27 164 47 1.8 33.4 203.4 15.0 22.3 90.0 8269 1818.8
IC FSD-C 1-2 1.27 164 47 1.8 33.4 203.4 8.8 13.0 90.0 8269 1060.1
tSD+ESP 1 1.43 82 44 1.8 15.5 188.6 7.0 22.3 76.0 3281 2144.3
ISO+ESP 2 1.43 82 50 1.8 15.1 183.8 7.1 19.6 76.0 3729 1892.3
LSC+ESP-C 1 1.43 82 44 1.8 15.5 188.6 4.1 13.0 76.0 3281 1249.7
ISB+ESP-C 2 1.43 82 50 1.8 15.1 183.8 4.1 11.4 76.0 3729 1102.3
22-36
-------
Table 22.3,1-4. Suumary of Coal Switching/Cleaning Costs for the Grainger Plant (June 1988 Dollars)
s=s====;355=s5sss=:======:ssss:s::ss:===s=s:ssss=ss::s:s:ss:sssss:sssss:sssssssss:3:::ssSSSSssssss=:;s::s:;sss;s
Technology Boiler Main Boiler Capacity Coal Capital Capital Annuel Annual SQ2 SC2 SQ2 Cast
Nmfcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Seffloved Removed Effect.
Difficulty (NW) C*> Content (MM) (SAW) (MM)
-------
TABLE 22.3.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR GRAINGER
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME {1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1966
1966
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
40
40
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
23
23
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
882
882
New Heat Exchanqer (1000$)
1655
1655
TOTAL SCOPE ADDER COSTS (1000$)
2560
2560
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
13
* Cold side SCR reactors for unit 1 would be located east of
unit 1, and cold side SCR reactors for unit 2 would be located
south of the unit 2 chimney.
22-38
-------
Table 22,3.1-6. NOx Control Cost Results for the Grainger Plant (June 1988 Dollars}
Technology Boiler Main Boiler Capacity Coil Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size factor Sulfur Cost Cost Cast Cost Removed Removed Effect.
Difficulty (mo (*> Content (SMttl (IMM) (mills/kuh) <%> (tons/yrj
LNC-INB
INC-INB
1.00
1.00
82
82
44
50
1,8
1.8
2.4
2.4
28.8
28.8
0.5
0.5
1.6
1.4
40.0
40.0
515
585
961.3
846.0
INC-LH8-C
INC-LNB-C
ECS-3
SCR-3
SC8-3-C
SCA-3-C
SCR -7
SCR-7
SCR-7-C
SCS-7-C
,00
,00
6
6
6
6
6
6
6
6
82
82
82
32
82
82
82
82
82
82
44
50
44
50
44
50
44
50
44
50
1.8
1.8
1,8
1.8
1.8
1.8
1.8
1,8
1.8
1.8
2.4
2.4
16.5
16.2
16.5
16.2
16.5
16.2
16.5
16.2
2S.8
28.8
201.5
197.3
201.5
197.3
201.5
197.3
201.5
197.3
0.3
0.3
5.2
5.1
3.0
3.0
4.5
4.4
2.6
2.6
0.9
0.8
16.3
14.2
9.6
8.4
14.2
12.4
8.4
7.3
40.0
40.0
80.0
80.0
80
80
80
80
80
80
515
585
1029
1170
1029
1170
1029
1170
1029
1170
571.3
502.8
5017.5
4369.5
2946.7
2565.5
4368.1
3798.1
2574.6
2238.1
22
-39
-------
f
TABLE 22.3.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GRAINGER UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 785
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$)
ESP UPGRADE CASE 811
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE ' NA
Short duct residence time exists between the boilers and
ESPs. Although ESPs are of an adequate size, the space
around the ESPs for upgrading is limited and a high factor
was assigned to ESP upgrade.
22-40
-------
Table 22.3.1-8. Sumnry of dsd/fsi control Costs for the crainger Plant (June 1988 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Munber Retrofit Site factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HU) (X) Content ($m> (S/WO (SMH) (mills/kwh) (tons/yr> (t/ton)
Factor (%>
DSD+ESP
DSD+6SP
DSO+ESP-C
DSD«-6SP-C
fsi+esp-50
FSI+SSP-50
FSI+ESP-50-C
FSI+ESP-50-C
. FSI+ESP-70
FS1+ESP-70
FSI+ISP-70-C
FS1»ESP*70-C
.00
.00
.00
.00
,00
.00
.00
.00
.00
.00
,00
.00
82
82
82
82
82
32
82
82
82
82
32
82
44
50
44
50
44
50
44
50
44
50
44
50
1.8
1,8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
1.8
6.8
6.8
6.8
6.8
7.0
7.0
7.0
7-0
7.1
7.1
7.1
7.1
82.4
82.4
32.4
82.4
34.9
84.9
84.9
84.9
86.2
86.2
86.2
36.2
4.5
4.6
2.6
2.7
4.0
4.1
2.3
2.4
4.0
4.2
2.3
2.4
14.3
12.9
8.3
7.5
12.5
11.5
7.3
6.7
12.7
11.7
7.4
6.8
49.0
49.0
49.0
49.0
,50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
2092
2378
2092
2378
2150
2444
2150
2444
3010
3421
3010
3421
2161.6
1951.1
1252.9
1130.6
1843.6
1697.1
1070.7
985.1
1336.
1230.
776.0
714.1
223S SSSS3S
22 ~41
-------
22.3,2 Jefferies Steam Plant
The Jefferies Steam Plant is located in Berkley County, South Carolina,
as part of the South Carolina Public Service system. The plant contains two
coal-fired boilers with a total gross generating capacity of 346 MW.
Tables 22.3.2-1 through 22.3.2-9 summarize the plant operational data and
present the SOg and N0X control cost and performance estimates.
TABLE 22.3.2-1. JEFFERIES STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1, 2
GENERATING CAPACITY (MW-each) 50
CAPACITY FACTOR (PERCENT) PETROLEUM
INSTALLATION DATE BURNING
FIRING TYPE
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON'
COAL HEATING VA
COAL ASH CQNTEN
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1000 CU FT)
ON
ENT (PERCENT)
UE (BTU/LB)
(PERCENT)
3, 4
173
34,45
1970
FRONT WALL
82
NO
I.6
12200
II.0
WET DISPOSAL
POND/ON-SITE
3, 4
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 (4F)
ESP
1978
0.079,0.061
94.6,98.2
1.5-1.9
78.9
307
257
300
22-42
-------
TABLE 22.3.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR JEFFERIES UNIT 3 *
FGD TECHNOLOGY
L/LS FGD
FORCED
OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
1532
NA
1532
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.53
NA
ESP REUSE CASE
1.56
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT
) 8
0
8
* Absorbers for unit 3 would be placed east of unit 3, south
of the coal pile.
22-43
-------
TABLE 22.3.2-3, SUMMARY OF RETROFIT FACTOR DATA FOR JEFFERIES UNIT 4 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM NA MEDIUM
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 1532 NA 1532
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1211 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.59 NA
ESP REUSE CASE 1.69
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
, GENERAL FACILITIES (PERCENT) 8 0 8
* Absorbers for unit 4 would be located east of unit 4, south
of the coal pile.
22-44
-------
Table 22.3,2*4. Suimary of FGO Control Costs for the Jefferies Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity coal
Capital
Capital Annual
Annual
SQ2
S02
SOB Cost
Nmtoer
Retrofit
Site
Factor
Sul fur
Cost
Cost
Cose
Cost
Removed
Removed
Effect.
Oifffeulty (MW)
<*>
Content
(SMM)
<»/ky>
(two
{milts/MO
ay
Ctons/yr)
(S/ton)
Factor
(X)
L/S FGO
3
1 .S3
173
34
1.6
59.8
345.8
22.0
42.6
90.0
5873
3738.8
t/S FGO
4
1,59
173
45
1.6
62.0
358.2
23.6
34.6
90.0
7774
3038.3
L/S FGO
3-4
1.56
346
39
1.6
90.3
261.0
34.3
' 29.0
90.0
13474
2548.2
L/S FGO-C
3
1 .S3
173
34
1.6
59.8
345.8
12.8
24.9
90.0
5873
2187.7
L/S FQD-C
4
1.59
173
45
1.6
62.0
358.2
13.8
20.3
90.0
7774
1776.5
L/S FGO-C
3-4
1.56
346
39
1.6
90.3
261.0
20.1
17.0
90.0
13474
1490.0
LC FGD
3-4
1.56
346
39
1.6
68.0
196.4
27.7
23.4
90.0
13474
2054.4
LC FGO-C
3-4
1.56
346
39
1.6
68.0
196.4
16.2
13.7
90.0
13474
1199.6
LSO+ESP
3
1.56
173
34
1.6
27.7
160.2
10.8
21.0
76.Q
4979
2176.4
LSO+ESP
4
1.69
171
45
1.6
29.6
171.1
11.8
17,3
76.0
6590
1794.8
LSD+ESP-C
3
1.56
173
U
1.6
27.7
160.2
6.3
12.3
76.0
4979
1271.9
LSO'ESP-C
4
1.69
173
45
1.6
29.6
171,1
6.9
10.1
76.0
6590
1048.5
II
II
II
II
II
II
II
u
II
II
II
II
ii
ii
ii
ii
ii
ii
H
II
11
SSSSSSSSi
.......
It
11
II
II
N
H
II
II
II
II
II
N
II
II
u
II
II
II
II
¦
II
M
II
......
II
II
II
II
II
II
II
II
II
H
II
II
II
II
II
II
II
II
H
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
fl
22-45
-------
Table 22.3.2-5. Simary of Coal Snitching/Cleaning Costs for the Je'ffsries Plant (June 1988 Dollars)
Technology
ssistuatssisnaiBiisisiBS
Uoiier Main Boiler Capacity Coal .Capital Capital Annual Annual $02 S02 502 Cast
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (*) Content (SMM) . (t/kW) (WWJ (mi IIs/kwh) (X) (tons/yr) (S/ton>
Factor (X)
CS/B*S15
CS/B*$15
1.00
1.00
173
173
34
45
1.6
1.6
6.3
6.3
36.1
34.1
8.2
10.4
15.8
15.2
43.0
43.0
2806
3713
2907.6
27aa.4
CS/8+f15-C
CS/B+S13-C
1.00
1.00
173
173
34
45
1.6
1.6
6.3
6.3
36.1
34.1
4.7
6.0
43.0
43.0
2806
3713
1675.9
1605.1
CS/B»SS
CS/8*S5
l.OO
1.00
173
173
34
45
1.6
1.6
4.S
4.J
25.8
25.8
3.6
4.4
43.0
43.0
2806
3713
1278.6
1186.8
CS/1+I5-C
C5/B+S5-C
1.00
1.00
173
173
34
45
1,6
1.6
4.5
4.5
25.8
25.8
2.1
2.5
43.0
43.0
2806
3713
739.7
685.3
S33SSSSS8S
SBS8SISS11ISS
22-46
-------
TABLE 22.3.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR JEFFERIES
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (1000 CU FT)
82
82
BOILER INSTALLATION DATE
1970
1970
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
33
33
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
41
41
New Duct Length (Feet)
300
600
New Duct Costs (1000$)
2048
4097
New Heat Exchanger (1000$)
2590
2590
TOTAL SCOPE ADDER COSTS (1000$)
4679
6727
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for units 3
of unit 3, south of the coal pile.
and 4 would
be located east
22-47
-------
Table 22.3.2-7. MO* Control Cost Results for the Jefferies Plant tJurie 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MO* NO* NO* Cost
Nuttier Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content (SMK) (1/kH) <»#0 CmiUs/k*h) (%) Ctors/yO ($/ton)
Feetor (X)
LNC-tNB S 1.00 173 34 1.6 J.2 18.4 0.7 1.3 33,0 725 920.0
LKC-LNB 4 1.00 173 45 1.6 3.2 18.4 0.7 1.0 33.0 959 695.1
LNC-IM-C 3 1.00 173 34 1.6 3.2 18.4 0.4 0.8 33.0 725 546.8
INC-LNB-C 4 1.00 173 45 1.6 3.2 18.4 0.4 0.6 33.0 959 413.1
SCR-I 3 1.16 173 34 1.6 28.1 162.5 9.1 17.6 80.0 1717 5154.3
SCR-3 4 1.16 173 45 1.6 30.2 174.6 9.5 14.0 80.0 2325 4100.4
SCR-S-C 3 1.16 173 34 1.6 28.1 162.5 5.3 10.3 80.0 1757 3024.1
SCR-3-C 4 1.16 173 45 1.6 30.2 174.6 5.6 8.2 80.0 2325 2407.5
SCR-7 3 1.16 173 34 1.6 28.1 162.5 7.6 14.8 80.0 1757 4347.2
SCR-7 4 1.16 173 45 1.6 30.2 174.6 8.1 11.9 80.0 2325 3490.6
SCR-7-C 3 1.16 173 34 1,6 28.1 162.5 4.5 8.7 80.0 1737 2562.4
SCR-7-C 4 1.16 173 45 1.6 30.2 174.6 4.8 7,0 80.0 2325 2058.1
22-48
-------
TABLE 22.3.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JEFFERIES UNIT 3 OR 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO ORY HANDLING YES
ESTIMATED COST (1000$) 1532
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$) 45
TOTAL COST (1000$)
ESP UPGRADE CASE 1577
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
Short duct residence time exists between boilers 3 and 4 and
their respective ESPs. ESP upgrade for both units was high
because of the lack of available space around the ESPs.
22-49
-------
Table 22.3.2-9. Summary of DSC/FS1 Control Costs for the Jefferies Plant (June 1938 Dollars)
Teennolojy Boiler Main Sailer Capacity Coal Capital Capital Annual Annual $02 $02 SQ2 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) Ctons/yr) (»/ton>
Factor <%>
QSD*ESP
DSD+ESP
OSD+ESP-C
BSO+ESP-C
FSI+ESP-50
FSH-ESP-50
FS1*6SP-5Q-C
FS1+ESP-50-C
FSI+ESP-70
FSI+ESP-70
FSt+ESP-70-C
FSI*€SP-70-C
.00
.00
00
00
00
00
00
00
00
00
.00
,00
173
173
173
173
173
173
173
173
173
173
173
173
34
45
34
45
34
45
34
45
34
45
34
45
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.6
11.2
11.2
11.2
11.2
12.S
12.5
12.5
12.5
12.6
12.6
12.6
12.6
64.7
64.7
64.7
64.7
72.1
72.1
72.1
72.1
72.8
72.8
72.8
72.8
6.1
6.5
3.5
3.8
6.0
6.6
3.5
3.8
6.0
6.7
3.5
3.9
11.8
9.6
6.9
5.6
11.6
9.7
6.7
5.6
11.7
9.8
6.S
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
3175
4202
3175
4202
3263
4319
3263
4319
4568
6046
4S68
6046
1919.8
1554.0
1115.8
902.3
1824.8
1532.1
1062.
890.
1320.4
1109.7
768.8
645.1
22-50
-------
22.3.3 Winvah Steam Plant
Units 2, 3, and 4 at the Winyah plant are equipped with FGD systems;
therefore no further S02 control technologies were evaluated for these
units. All units are equipped with LNBs for NO^ control, hence SCR was the
only NO control evaluated for these units. Although cost estimates are
presented for DSD and FSI, the short straight duct run distance for unit 1
makes application of these technologies difficult without enlarging the duct
work.
TABLE 22.3.3-1. WINYAH STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY ^
CAPACITY FACTOR (PER^ENt)
INSTALLATION DATE
CTDTNR TYPF
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE)
FGD SYSTEM (INSTALLATION DATE)
1 2 3
315 315 315
58 34 28
1975 1977 1980
FRONT WALL OPPOSED WALL
NA
YES
1
NA
NA
NA NA
YES YES
1.1
12300
10
WET DISPOSAL
POND/ON-SITE
2 3
RAILROAD
TRAY TYPE
4
315
24
1981
NA
YES
1977
1980
LS-FGD
1981
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1975
EMISSION (LB/MM BTU) 0.132
REMOVAL EFFICIENCY 99.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0
SURFACE AREA (1000 SQ FT) 305
EXIT GAS FLOW RATE (1000 ACFM) 881
SCA (SQ FT/1000 ACFM) 343
OUTLET TEMPERATURE (*F) 277
ESP
ESP
ESP
1977
1981
1981
0.045
0.037
0.044
99.4
99.4
99.4
2.0
2.0
2.0
285
285
285
881.5
881.5
881,5
323
323
323
270
270
270
22-51
-------
TABLE 22.3.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR WINYAH UNIT 1 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
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$)
2622
NA
2622
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.35
NA
ESP REUSE CASE
1.35
BAGHOUSE CASE
. NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
15
* L/S-FGD and LSD-FGD absorbers for unit 1 would be located
behind or beside the unit 1 chimney.
22-52
-------
Table 22.3.3-3, Suima ry of FED Control Costs far the Winyah Plant 1988 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SC2 S02 S02 Cost
Nuitier Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (WO
-------
Table 22.3.3-4. Sutmary of Coal Switching/Cleaning Costs for the Uinyah Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 SQ2 S02 Cost
Kunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty Content <$NM> ($/kW) (*/ton>
Factor
-------
TABLE 22.3.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR WINYAH
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2,3 ,
4
FIRING TYPE
NA
NA
NA
TYPE OF NOx CONTROL
NA
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
NA
BOILER INSTALLATION DATE
NA
NA
NA
SLAGGING PROBLEM
NA
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
64
64
64
New Duct Length (Feet)
200
200
200
New Duct Costs (1000$)
1939
1939
1939
New Heat Exchanger (1000$)
3710
3710
3710
TOTAL SCOPE ADDER COSTS (1000$)
5713
5713
5713
RETROFIT FACTOR FOR SCR
1.16
1.52
1.16
GENERAL FACILITIES (PERCENT)
38
38
38
* Cold side SCR reactors for unit 1 would be located behind the
unit 1 chimney. Cold side SCR reactors for units 2, 3, and 4
would be located behind their respective FGD system.
22-55
-------
Table 22.3.3-6. NOx Central Cose Results for the yiriyah Plant (June 1988 Dollars)
Technology Soiler Ha in Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Htmber
Retrofit
St le
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
<%>
Content
(KW)
(S/kW)
(two
(fflUU/kwh)
m
(tons/yr)
($/tonJ
Factor
m
SCR-3
1
1.16
315
58
1.1
45.7
145.1
15.7
9.8
80.0
5407
2898.9
SCR-3
2
1.52
315
34
1.1
53.9
171.1
17.2
18.3
80.0
3169
5417.4
SCR-3
3
1.52
315
28
1.1
53.9
171.1
17,1
22.1
80.0
2610
6537.6
SCR-3
4
1.16
315
24
1,1
45.7
•145.0
15.0
22.7
80.0
2237
6723.0
SCR-3-C
1
1.16
315
58
1.1
45.7
145.1
9.2
5.7
80.0
5407
1698.8
SCR-3-C
2
1.52
315
34
1.1
53.9
171.1
10.1
10.7
80.0
3169
3180.1
SCR-3-C
3
1.52
315
28
1.1
53.9
171.1
10.0
13.0
80.0
2610
3838.2
SCS-3-C
4
1.16
315
24
1.1
45.7
145.a
8.S
13.3
80.0
2237
3943.4
SCR- 7
1
1.16
315
58
1.1
45.7
145.1
13.1
8.2
80.0
5407
2421.9
SCR-7
2
1.52
315
34
1.1
53.9
171.1
14.6
15.6
80.0
3169
4603.6
SCR-7
3
1.52
315
28
1.1
55.9
171.1
14.5
18.7
80.0
2610
5549,4
sea-r
4
1.16
315
24
1.1
45.7
145.0
12.5
18.8
80.0
2237
5570.2
SCR-7-C
1
1.16
315
58
1.1
45.7
145.1
7.7
4.8
80.0
5407
1425-5
SCR-7-C
2
1.52.
315
34
1.1
53.9
171.1
8.6
9.2
80.0
3169
2713.8
SCR-7-C
3
1.52
315
28
1.1
53.9
171.1
8.5
11.1
80.0
2610
3272.0
SCR-7-C
4
1.16
315
24
1.1
45.7
145.0
7.3
11.1
80.0
2237
3282.9
ssaviflsaas:
•¦ilium
iHiiimnim
niimnis
¦¦ SS3 33!
22-56
-------
TABLE 22.3.3-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR WINYAH UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000S) 2622
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 71
TOTAL COST (1000$)
ESP UPGRADE CASE 2693
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
The duct residence time between unit 1 and the unit 1 ESPs is
short; however, the ESPs are of an adequate size for sorbent
injection technologies.
22-17
-------
*
Table 22.3.3-8, Sunwary of DSD/FS1 Control Costs for the Winyah Plant (June 1988 Collars)
Technology Boiler Main Boiler Capacity Coat Capital Capital Annual Annual $02 S02 S02 Cost
Number letrofit Size factor Sulfur Cost Cost Cost Cost Removed leraoved Effect.
Difficulty (MV) <*> Content (SMI) (S/kU) (SMM) (mills/kwh) «)
Factor (%)
DSO+ISP 1
1.00
315
58 1.
13.6
43.2
3.4
,5.2
49.0
6717
1245.3
DSO*ESP-C 1
1.00
315
58 1.
13.6
43.Z
4.9
3.0
49.0
6717
722.5
FS1+ESP-50 1
1.00
315
58 1.
14.0
44.6
8.6
5.3
50.0
6903
1239.1
FSI+ESP-50-C 1
1.00
315
58 1.
14.0
44.6
5.0
3.1
50.0
6903
719.0
FSi-»ESP-7Q 1
1.00
315
58 1.
14.2
45.0
8.?
5.4
70.0
9664
899.1
FSI+ESP-70-C 1
1.00
315
58 1.
1 14.2
45.0
5.0
3.2
70.0
9664
521.7
„„
SS5SSS31SSC8SS8SS5513
BB8SSSS3
IS5S3S3SSSI3S2S'
S5SSSSSS55S8
S5S3335
* Application of these technologies will be difficult due to the short,
straight duct run distance between the airheater and ESP unless the ductwork
is enlarged. The above costs do not include this expense.
22-58
-------
SECTION 23.0 TENNESSEE
23.1 TENNESSEE VALLEY AUTHORITY
23.1.1 Allen Steam Plant
The Allen steam plant is located within Shelby County, Tennessee, as
part of the TVA system. The plant contains three coal-fired boilers with a
total gross generating capacity of 990 MW. Figure 23.1.1-1 presents the
plant plot plan showing the location of all boilers and major associated
auxiliary equipment.
Table 23.1.1-1 presents operational data for the existing equipment at
the Allen steam plant. All boilers burn medium sulfur coal (2.20 percent
sulfur). Coal shipments are received by freight barge and conveyed to a
coal storage and handling area located east of the plant.
Particulate matter emissions for all three boilers are controlled with
ESPs located directly behind each boiler. Ash from all units is wet sluiced
to ponds located northwest of the plant. On-site waste disposal
availability is a significant problem and TVA is considering two options to
address the future problem: the purchase of more land adjacent to the plant
or dry disposing of the waste off-site.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 23.1.1-1 shows the general layout and location of the FGD control
system. Absorbers for L/LS-FGD and LSD-FGD for all three units would be
located behind the chimneys north of each unit. The storage area would need
to be demolished and relocated to make more space available for the FGD
equipment. The limestone and lime preparation/storage and waste handling
areas were located in the open area west of unit 1. A factor of 10 percent
was assigned to general facilities because of the demolition and relocation
of the storage area.
23-1
-------
FGD WASTE m .NHj STORAGE
ABSORBERS
mar MCKtujm
SYSTEM
HANDLING
W
r«lrt
1 \
LIMESTONE PREPARATION/
STORAGE AREA
rf
ci s&rj
—ft *39
*¦*40
mrvswfro^mj
m
LEGEND
#'s
INDICATE
BOILER NUMBER
0 100 200
Figure 23.1.1-1. Allen plant plot plan
23-2
-------
TABLE 23.1.1-1. ALLEN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-3
GENERATING CAPACITY (MW-each) 330
CAPACITY FACTOR (PERCENT) 44, 51, 39
INSTALLATION DATE 1959
FIRING TYPE CYC
COAL SULFUR CONTENT (PERCENT) 2.20
COAL HEATING VALUE (BTU/LB) 11700
COAL ASH CONTENT (PERCENT) 9.0
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD POND/QN-SITE
STACK NUMBER 1, 2, 3
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1972
EMISSION (LB/MM BTU) 0.06-0.09
REMOVAL EFFICIENCY 95-97.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.5
SURFACE AREA (1000 SQ FT) 253.4
GAS EXIT RATE (1000 ACFM) 1265
SCA (SQ FT/1000 ACFM) 200
OUTLET TEMPERATURE (JF) 310
23-3
-------
Retrofit Difficulty and Scope Adder Costs--
The FGD control equipment/absorbers were located in the area directly
behind (north) the ESPs and powerhouse. The absorber location for unit 1 was
assigned a low site access/congestion factor because the designated location
is currently an open area/parking lot. The location of the absorbers for
units 2 and 3 was assigned a medium to high site access/congestion factor for
two reasons. First, the. water intakes are located close to (on the north
side) units 2 and 3 and, second, the coal conveyor is also close to unit 3.
All units were assigned a low site access/congestion factor for L/LS-FGD and
LSD-FGD flue gas handling. Short to moderate duct runs would be required for
all technologies. The limestone storage and preparation area was located in
a low site access/congestion area west of unit 1. This area is an abandoned
ash pond site. The sludge dewatering area was located in a low site access/
congestion area just north of the limestone storage and preparation area.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables 23.1.1-2 through 23.1.1-4.
The largest scope adder for the Allen plant would be the conversion of units
1 to 3 fly ash conveying/disposal system from wet to dry for conventional
L/LS-FGD cases. 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 ranged from low to moderate (1.24 to 1.51).
LSD-FGD with a new baghouse was the only LSD case considered for the
Allen plant because the ESPs are small and the access/congestion factor for
ducting to the front of the ESPs would be very high. The retrofit factors
determined for the LSD technology case ranged from low to moderate (1.27 to
1.53). Separate retrofit factors were estimated for new particulate
controls. These factors were low to high (1.16 to 1.58) for units 1 to 3
and reflect the access/congestion associated with the location of the new
particulate controls. The factors were used by the IAPCS model to estimate
additional costs required for installation of new bagbouses.
Table 23.1.1-5 presents the costs estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include installing new baghouses to handle the additional
particulate loading for boilers 1-3.
23-4
-------
TABLE 23.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ALLEN UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS F6D 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) 100-300 100-300
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$) 2734 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.31 1.24
ESP REUSE CASE NA
BAGHOUSE CASE 1.27
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 10 10 10
23-5
-------
TABLE 23.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR ALLEN UNIT 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
MEDIUM MEDIUM
LOW LOW
100-300 100-300
NA
NA
NA
NA
MEDIUM
NA
LOW
NA
300-600
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY YES NO
ESTIMATED COST (1000$) 2734 NA
NEW CHIMNEY NO NO
ESTIMATED COST (1000$) 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.41
NA
NA
1.36
NA
NA
NO
NA
NO
0
NO
NA
1.40
NA
1.36
GENERAL FACILITIES (PERCENT) 10
10
10
23-6
-------
TABLE 23.1.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR ALLEN UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE NA
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA HIGH
SCOPE ADJUSTMENTS
WET TO DRY YES NO NO
ESTIMATED COST (1000$) 2734 NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.51 1.48
ESP REUSE CASE NA
BAGHOUSE CASE 1.53
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.58
GENERAL FACILITIES (PERCENT) 10 10 10
23-7
-------
Table 23.1.1-5. Sunmary of FGD Control Costs for the Allen Plant
........
........
.........
............
......
...........
........
l/S FGD
t
1.31
330
44
2.2
ai.2
246.0
33,8
26,6
90.0
20917
1616.7
L/S FCD
2
1.41
330
51
2.2
86.6
262.4
36,8
25,0
90.0
24244
1518.2
l/s m
3
1.51
330
39
2.2
92.0
278.7
36.2
32,1
90.0
18540
1954,6
L/S F5D-C
1
1.31
330
44
2.2
81.2
246.0
19,7
15.5
90.0
20917
943.7
L/S FGD-C
2
1.41
330
51
2.2
86.6
262.4
21.5
14.6
90.0
24244
885.9
L/S FGO-C
3
1.51
330
39
2.2
92.0
278.7
21.2
18.8
90.0
18540
1142.1
LC FGD
1-3
1.41
990
45
2.2
155.7
157.3
71.3
18.3
90.0
64176
1110.9
LC FQD-C
1-3
1.41
990
45
2.2
155.7
157.3
41.5
10.6
90.0
64176
647.3
LSO+FF
!
1.27
330
44
2.2
65.2
197.5
24.0
18.8
87.0
20103
1191.7
'.SD-FF
2
1.40
330
51
2.2
73,1
221.6
26.a
18.2
87.0
23301
1151.3
LSD+FF
3
1.53
330
39
2.2
81.7
247.6
27.6
24.5
87.0
17819
1551.2
-SC-FF-C
1
1.27
330
44
2.2
65.2
197.5
14.0
11.0
87.0
20103
697.3
ISD'FF-C
2
1.40
330
51
2.2
73.1
221.6
15.7
10.6
87.0
23301
673.7
LSD+FF-C
3
1.53
330
39
2.2
81.7
247.6
16.2
14.4
87.0
17819
909.3
SI«SS3S:SSBSSSSSSS3SSSSSSSSSSS3S8SSSBS3SSasS:S3SS8SSSSSSSSSS3SSSSSSSSBSSSSSSi:3S:3SSSSSSBSC3ISSSS3SS33SSS3SllS8BS
23-8
-------
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare
scrubber, optimization of scrubber size, and use of organic acid additives.
Coal Switching Costs-
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined. This is particularly true for cyclone boilers because obtaining
a low sulfur bituminous coal having the correct ash fusion temperature may
be quite expensive due to limited availability or transportation distance.
Therefore, Allen plant was not considered for the coal switching option.
N0X Control Technology Costs--
This section presents the performance and costs estimated for NQX
controls at the Allen steam plant. These controls include NGR and SCR. NGR
was the LNC modification control for the Allen units because LNB and
OFA are not applicable to cyclone-fired boilers.
Low NO Combustion--
Units 1-3 are wet bottom, cyclone-fired boilers rated at 330 MW. The
combustion modification technique applied to all three boilers was NGR. As
Table 23.1.1-6 shows, the NGR N0X reduction performance for the boilers was
estimated to be 60 percent.
Table 23.1.1-7 presents the cost of retrofitting NGR at the Allen plant.
Selective Catalytic Reduction-
Table 23.1.1-6 presents the SCR retrofit results for each unit. The
results include a process area retrofit factor and scope adder costs. The
scope adders include costs estimated for building and 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.
23-9
-------
TABLE 23.1.1-6, SUMMARY OF NQx RETROFIT RESULTS FOR ALLEN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
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
LOW
MEDIUM
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
117
0
Ductwork Demolition (1000$)
66
66
66
New Duct Length (Feet)
100
100
100
New Duct Costs (1000$)
996
996
996
New Heat Exchanger (1000$)
3,815
3,815
3,815
TOTAL SCOPE ADDER COSTS (1000$)
4,877
4,994
4,877
RETROFIT FACTOR FOR SCR
1.16
1.34
1.52
GENERAL FACILITIES (PERCENT)
13
13
13
23-10
-------
Table 23.1.1-7, NO* Control Cost Results for the Allen Plant (June 1988 Oollars)
H
li
It
li
(l
If
li
II
II
It
II
j 35 jj aEjfa J8 jj ;
II
II
II
II
II
11
M
iiiiiiiininiu
lamillis:
======
= I=IIIIIi=:
Technology
Boi Ler
Main
Bailer Capacity Coal
Cap]tal
Capital
Annual
Annual
NOx
NOx
MO* Cost
Nurtoer
Retrofit
Size
Factor
Sulfur
Cost
Cast
Cast
Cost
Removed Removed
Effect.
Difficulty (MU)
m
Content
($/kW5
($HH)
trail Is/kwh)
(%>
(tans/yr)
(S/ton)
.. ......
......
•actor
........
. . w.,
<%)
..
MGR
1.QD
330
44
2.2
5.4
16.2
7.3
5.7
60.0
5526
1314.3
MGR
2
1.00
330
51
2,2
5.4
16.2
8.3
5.6
60.0
6405
1295,0
,NGR
I
1.00
330
39
2.2
5.4
16.2
6.5
5.8
60.0
4898
1332,3
NGR-C
1
1.00
330
44
2.2
5.4
16.2
4.2
3.3
60.0
5526
757.3
MGfi-C
2
1.00
330
51
2,2
5.4
16.2
4.8
3.2
60.0
6405
745.7
NGR-C
3
1.00
330
39
2.2
5.4
16.2
3.8
3.3
60.0
4898
768.2
SCR-3
1
1.16
330
44
2.2
44.1
133.5
15.7
12.4
80.0
7368
2137.5-
SCR-3
2
1.34
330
51
2.2
43.0
145.4
16.9
11.4
80,0
8540
1976.?
SCR-3
3
1.52
330
39
2.2
51.6
156,5
17.4
15.5
80.0
6530
2669.8
SCR-3-C
1
1.16
330
44
2.2
44,1
133.5
9.2
7.2
80.0
7368
1251.4
SCR-3-C
2
1.34
330
51
2.2
48.0
145.4
9.9
6.7
80.0
8540
. 1157.4
SCR-3-C
3
1.52
330
39
2.2
51.6
156.5
10.2
9.1
80.0
6530
1565.1
SCR-7
1
1.16
' 330
44
2.2
44.1
133.5
13.0
10.2
80.0
7368
1768.1
SCR-7
2
1.34
330
51
2.2
48.0
145.4
14.2
9.6
80.0
8540
1657.5
SCR-7
3
1.52
330
39
2.2
51.6
156.5
14.7
13.1
80.0
6530
2253.0
SGR-7-C
1
1.16
330
44
2.2
44.1
133.5
7,7
6.0
80.0
7368
1039.8
SCR-7-C
2
1.34
330
51
2.2
48.0
145.4
8.3
5.6
80.0
8540
974.9
SCR-7*C
3
1.52
330
39
2.2
51.6
156.5
8.7
7.7
80.0
6536
1326.3
23-11
-------
All reactors were located directly behind the chimneys (south of each
unit). The reactor for unit 1 was located in a relatively open area bounded
on one side by the parking lot and on another by the reactor for unit 2.
The reactor for unit 2 was located in a more congested area blocked on two
sides by the chimney and the office/storage building. The reactor for
unit 3 was located in a severely congested area blocked on three sides by
the chimney, the gas metering/regulating area, and the coal conveyor. The
ammonia storage system was located northwest of the plant, close to the old
ash disposal area.
As discussed previously, the SCR reactors were placed in various access/
congestion areas. The reactor for unit 1 was assigned a low factor, the
reactor for unit 2 assigned a medium factor, and the reactor for unit 3 had a
high factor. All reactors were located in areas with high underground
obstructions. The ammonia storage system was located in a low access/
congestion area with no significant underground obstructions. Table 23.1.1-7
presents the estimated cost of retrofitting SCR at units 1 to 3.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO^ control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas for all units were
located northeast of the plant in a relatively open area in the same manner
as LSD-FSD technology. The retrofit of DSD at the Allen steam plant would
be difficult because of the short duct residence time (<1 second) between
the boilers and the ESPs. Also, the marginal size ESPs (SCAs = 200) might
not be able to handle the increased particulate load from DSD. However,
space is available to upgrade the ESPs by adding plate area, assuming a
medium to high site access/congestion factor for ESP upgrade. Additionally,
the conversion of the wet ash handling system to dry handling would be
required when reusing the ESPs for FSI. Sufficient duct residence time
23-12
-------
could be made available for DSD if the existing ESPs were used to provide
duct residence time and fabric filters were installed behind the chimneys.
The fabric filters would be located in low to high access/congestion areas.
Tables 23.1,1-8 through 23,1.1-10 present a summary of site access/
congestion factors, scope adders, and retrofit factors estimated for DSD and
FSI technologies at the Allen steam plant. Table 23.1.1-11 presents the
costs estimated to retrofit DSD and FSI at the Allen plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability were determined
using the criteria presented in Section 2. The boilers at the Allen plant
are marginal candidates for AFBC retrofit because the boilers are larger
than 300 MW, are of moderate age, have moderate capacity factors, and have
small furnace volumes.
23.1.2 Bull Run Steam Plant
The Bull Run steam plant is located within Anderson County, Tennessee,
as part of the TVA system. The plant contains one coal-fired boiler with a
total gross generating capacity of 950 MW, Figure 23.1.2-1 presents the
plant plot plan showing the location of the boiler and major associated
auxiliary equipment.
Table 23.1.2-1 presents operational data for the existing equipment at
the Bull Run steam plant. The boiler burns low sulfur coal (0.80 percent
sulfur). Coal shipments are received by rail and conveyed to a coal storage
and handling area located east of the plant.
Particulate matter emissions are controlled with retrofit ESPs located
behind the old ESPs. Ash is wet sluiced to ponds located southwest of the
plant. On-site waste disposal is limited and TVA is considering two future
options: the purchase of more land adjacent to the plant or dry disposing
the waste off-site.
Lime/Limestone and Lime Spray Drying FGD Costs--
Figura 23.1.2-1 shows the general layout.and location of the FGD control
system. Absorbers for L/LS-FGD and LSD-FGD could be located in three
23-13
-------
TABLE 23.1.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ALLEN UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) MEDIUM
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2734
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 2771
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 73
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 2807
A NEW BAGHOUSE CASE (DSD) 2844
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.34
NEW BAGHOUSE (DSD) 1.13
23-14
-------
TABLE 23.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ALLEN UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) MEDIUM
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2734
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 2771
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 73
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 2807
A NEW BAGHOUSE CASE (DSD) 2844
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1,34
23-15
-------
TABLE 23.1.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ALLEN UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2734
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 2771
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 73
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 2807
A NEW BAGHOUSE CASE (DSD) 2844
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1.55
23-16
-------
Table 23.1.1-11. Summary of DSD/FSI Control Costs for tie Allen Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
SC2
$02
SC2 Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removes
Removed
Effect.
Difficulty CMU;
m
Content
C$MM)
(miIts/kwh)
(%)
(tons/yr)
(I/ton)
Factor
E%)
OSD+FF
1
1.00
330
44
2.2
40.8
123.6
16.3
' 13.2
71.0
16443
1020.8
OSD+FF
2
1.00
330
51
2.2
45.4
137,7
18.7
12.7
71,0
19059
981.1
0SD+FF
3
1.00
330
39
2.2
50.3
152.5
18.6
16.5
71.0
14574
1274.6
OSO+FF-C
1
1.00
330
44
2.2
40.8
123.6
9.8
7.7
71.0
16443
596.0
DSD+FF-C
2
1.00
330
51
2.2
45.4
137.7
10.9
7.4
71.0
19059
572.8
DSD+FF-C
3
1.00
330
39
2.2
50.3
152.5
10.9
9.6
71.0
14574
745.7
TSHESP 50
1
1.00
330
44
2.2
22.7
68.9
13.6
ID.7
50.0
11620
1170.8
FSHESP-50
2
1.00
330
51
2.2
24.0
72.9
15.1
10.2 "
50.0
13469
1119.6
FSI+ESP-50
3
1.00
330
39
2.2
24.0
¦•72.9
13.1
11.6
50.0
10300
1273.0
FSI+ESP-50-C
1
1.00
330
44
2.2
22.7
68.9
7.9
6.2
50.0
11620
679.6
FS1+ESP-50-C
2
1.00
330
51
2.2
24.0
72.9
8.7
5.9
50.0
13469
649.4
FSI+ESP-50-C
3
1.00
330
39
2.2
24.0
72.9
7.6
6.8
50.0
10300
739.8
FSI+ESP-70
1
1.00
330
44
2.2
22.6
68,6
13.7
10.8 .
70.0
16268
845.0
FSI+ESP-70
2
1.00
330
51
2.2
23.9
72,5
15.2
10.3
70.0
18857
808.3
FSt+ESP-70
3
1.00
'330
39
2.2
23.9
72.5
13.2
11.7
70.0
14420
917.3
FSI+ESP-70-C
1
1.00
330
44
2.2
22.6
68.6
8.0
6.3
70.0
16268
490.3
FSI+ESP-70-C
2
1.00
330
51
2.2
23.9
72.5
8.8
6.0
70.0
18857
468.8
FSI+ESP-70-C
3
1.00
330
39
2.2
23.9
72.5
7.7
6.8
70.0
14420
533.0
23-17
-------
LEGEND
- SCR i
0 IOC 200
rs - INDICATE
BOILER NUMBER
Figure 23.1.2-1. Bull Run plant plot plan
23-18
-------
TABLE 23.1.2-1. BULL RUN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1
GENERATING CAPACITY (MW) 950
CAPACITY FACTOR (PERCENT) 62
INSTALLATION DATE 1967
FIRING TYPE TANG
COAL SULFUR CONTENT (PERCENT) 0.80
COAL HEATING VALUE (BTU/LB) 11400
COAL ASH CONTENT (PERCENT) 13.5
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD POND/OFF-SITE
STACK NUMBER 1
COAL DELIVERY METHODS RAIL
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1977
EMISSION (LB/MM BTU) 0.02
REMOVAL EFFICIENCY 99.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.60
SURFACE AREA (1000 SQ FT) 1472.7
GAS EXIT RATE (1000 ACFM) 2600
SCA (SQ FT/1000 ACFM) 566
OUTLET TEMPERATURE (*F) 310
23-19
-------
different locations: north, east, or south of unit 1. For this evaluation,
the absorbers were located south of the precipitators which would require
the relocation of a plant road and employee parking lot; therefore, a factor
of 1 percent was assigned to general facilities. The limestone and lime
preparation/storage area was located south of the powerhouse and the waste
handling area was placed directly west of the preparation/storage area.
Retrofit Difficulty and Scope Adder Costs--
Since the Bull Run plant already has switched to a low-sulfur coal, it
is unlikely that scrubbing is needed. However, should this become necessary,
it would be more cost effective to switch to a higher sulfur content coal,
taking into account the fuel cost differential in estimating cost
effectiveness. Costs presented in this report, consequently, are variable
and could change, being dependent upon type of coal utilized, as well as acid
rain legislation.
As mentioned above, the FGD control equipment for unit 1 could be
located to the north, east, or south of the plant. There is high ductwork
access/congestion north of the plant because of the coal conveyor. There is
moderate site access/congestion east of the plant and the railroad would have
to be relocated. It seemed most appropriate to locate the equipment south of
the ESPs where it would be in a low site access/congestion area (employee
parking lot) with no major underground obstructions. However, this location
reduces the space available for an additional unit of similar size. Moderate
duct runs would be required for routing the flue gas from the units to the
absorbers.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Table 23.1.2-2. The most
significant scope adder for lull Run would be the conversion of unit 1 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
conventional L/LS-FGD 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 moderate (1.31 to 1.38).
The LSD with reused ESP was the only LSD-FGD technology evaluated at
Bull Run. The retrofit factor determined for this technology was
23-20
-------
TABLE 23.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR BULL RUN UNIT 1
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW
FLUE GAS HANDLING LOW
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA
NEW BAGHOUSE NA
SCOPE ADJUSTMENTS
LOW
LOW
300-600 300-600
NA
NA
WET TO DRY YES NO
ESTIMATED COST (1000$) 7055 NA
NEW CHIMNEY NO NO
ESTIMATED COST (1000$) 0 0
OTHER NO NO
LOW
MEDIUM
NA
300-600
NA
MEDIUM
NA
YES.
7055
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.38
NA
NA
1.31
NA
NA
1.38
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 7
7
7
23-21
-------
moderate (1.38). Medium access/congestion was assigned to the flue gas
handling system for this case because there is little space available between
the ESPs and the existing boiler. Although no ESP plate area addition is
expected due to the large SCA (>500) of the existing retrofit ESPs, a
separate factor was developed for the upgrade of the ESPs"and used by the
IAPCS model to estimate any additional plate area costs, if required. This
factor, estimated for the ESP upgrading cost, was medium (1.36) and reflects
the congestion which exists around the existing ESPs because of the close
proximity of the coal conveyor/chimney.
Table 23.1.2-3 presents the cost estimated for L/lS-fGD and LSD-FGD
cases. The LSD-FGD costs include upgrading the ESPs and ash handling
systems for boiler 1.
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare
scrubber module, and optimization of scrubber size.
Coal Switching Costs--
The Bull Run steam plant has already switched to low sulfur coal.
NO Control Technology Costs--
A
This section presents the performance and various related costs
estimated for NO controls evaluated at the Bull Run plant. These controls
A
include LNC and SCR. The application of N0X controls is determined by
several site-specific factors which are discussed in Section 2. The NO
A
technologies applied at Bull Run were: OFA and SCR.
Low NO Combustion--
A
Unit 1 is a dry bottom, tangential-fired boiler with a net generating
capacity of 950 MW. The N0X combustion control considered in the analysis
for this unit was OFA. Minimal data was available in both the EIA-767 form
and POWER and, as a result, N0X reduction performance could not be assessed
using the simplified procedures as presented in Table 23.1.2-4. However,
other boilers of this size and age are estimated to have NO reductions in
A
23-22
-------
Table 23.1.2-3, Suimary of FGD Control Costs for the Bull Run Pl»nt (June 1980 Dollars)
SSSSSSSSSSS«S3«a»Sa8SS3»SSSSSS882SS28S3SSSSS83SS9XSSI8S8SSSSS83»8a»a3S8a3a8SS9£3==S8aSta3SSS:=:S=:SSS==:SS=;;;
Technology ioiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nimber Retrofit Size Factor Sulfur Coat Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (MM) (S/kW) (SUM) (mi Us/k»h) (X) (tons/yr) (S/tcn)
Factor (%}
L/S FGD
1
1.38
950
62
0.8
159.2
167.6
72.5
14.1
90.0
31788
2281.7
L/S fCO-C
t
1.38
950
62
0.8
159.2
167.6
42.3
8.2
90.0
31788
1329.7
LC FGD
t
1.38
950
62
0.8
132.4
139.4
64.4
12.5
90.0
31788
2026.9
LC FGD-C
1
1.33
950
62
0.8
132.4
139.4
37.5
7.3
90.0
31788
1179.9
LSO+ISP
1
1.38
950
62
0.8
100.6
105.9
40.9
7.9
76.0
26949
1516.6
LSO-ISP-C
1
1.38
950
62
0.8
100.6
105.9
23.9
4.6
76.0
26949
•885.6
23-23
-------
TABLE 23.1.2-4. SUMMARY OF NOx RETROFIT RESULTS FOR BULL RUN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
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) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Deirol ition (1000$) 146
New Duct Length (Feet) 550
New Duct Costs (1000$) 10171
New Heat Exchanger (1000$) 7195
TOTAL SCOPE ADDER COSTS (1000$) 17513
RETROFIT FACTOR FOR SCR 1.22
GENERAL FACILITIES (PERCENT) 13
23-24
-------
the range of 25 to 30 percent. Table 23.1.2-5 presents the estimated cost
of retrofitting OFA to this boiler.
Selective Catalytic Reduction--
Table 23.1.2-4 presents the SCR retrofit results for unit 1. The
results include a process area retrofit factor 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.
The SCR reactor and the ammonia storage system were placed in low
access/congestion areas with no significant underground obstructions. The
reactor was' located to the east of the piant/ESPs and in close proximity to
part of the railroad. The ammonia storage system location was similar to
that of the limestone storage/preparation area: adjacent to the live coal
storage area (southwest) and directly south of the ESPs and fly ash silo.
Table 23.1.2-5 presents the estimated cost of retrofitting SCR at this boiler.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO^ control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located south of
the plant in a relatively open area in the same manner as LSD-FGD technology.
The retrofit of DSD and FSI technologies at the Bull Run steam plant would be
relatively easy due to the sufficient flue gas ducting residence time
(4.3 seconds) between the boilers and the retrofit ESPs. No additional
particulate controls would be needed. The conversion of the wet ash handling
system to dry handling would be required when reusing the ESPs for DSD and
FSI technologies. Table 23.1.2-6 presents a summary of site access/
congestion factors, scope adders, and retrofit factors for DSD and FSI
23-25
-------
Table 23.1.2-5. NDx Control Cost Results for the Bull Run Plant (June 1988 Dollars)
Technology Boiler Main Boiler
Number Retrofit Size
Difficulty (MW>
. Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
(56 5 Content (SMHJ (S/kW) (JMM)
m
Annual NOx NO* NOx Cost
Cost Removed Removed Effect.
(mUla/kwh) <%) (tons/yr) (f/ton)
LNC-OFA 1
LNC-OFA-C 1
SCR-3 1
SCR-3-C 1
SCR-7 1
SCR-7-C 1
1.00 950 62
1.DO 950 62
1.22 950 62
1.22 950 62
1.22 950 62
1.22 950 62
0.8 1.5 1.6
0.8 1.5 1.6
0.8 117.3 123.5
0.8 117.3 123.5
0.8 117.3 123.5
0.8 117.3 123.5
0.3 0.1 25.0
0.2 0.0 25.0
42.4 8.2 80.0
24.8 4.8 80.0
34.5 6.7 80,0
20.3 3.9 80.0
4245 • 75.9
4245 45.1
13584 3118.4
13584 1825.3
13584 2539.3
13584 1493.6
23-26
-------
TABLE 23.1.2-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BULL RUN UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
ESP UPGRADE
NEW BAGHOUSE
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000S) 7055
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 100
DEMOLITION COST (1000$) 324
TOTAL COST (1000$)
ESP UPGRADE CASE 7379
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.34
NEW BAGHOUSE NA
LOW
MEDIUM
NA
23-27
-------
technologies at the Bull Run steam plant. Table 23.1.2-7 presents the
estimated cost of retrofitting DSD and FSI at this boiler.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Using the applicability criteria for AFBC retrofit and AFBC/coal
gasification/combined cycle repowering discussed in Section 2, the boiler at
the Bull Run plant is too large to be considered a candidate for retrofit or
repowering. The boiler would not be considered a candidate for AFBC/CG
repowering retrofit because the boiler size is much larger than 300 MW with
moderate age and high to moderate capacity factor.
23.1.3 Cumberland Steam Plant
Information on Cumberland steam plant appears in U.S. EPA report number
EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility SO^ and NO^
Retrofit Study (NTIS PB88-244447/AS).
23.1.4 Gallatin Steam Plant
The Gallatin steam plant is located within Summer County, Tennessee, as
part of the TVA system. The plant contains four boilers with a total gross
generating capacity of 1,256 MW. Figure 23.1.4-1 presents the plant plot
plan showing the location of all boilers and major associated auxiliary
equipment.
Table 23.1.4-1 presents operational data for the existing equipment at
the Gallatin steam plant. All four boilers burn medium to high sulfur coal
(2.8 percent sulfur). Coal shipments are received by rail and conveyed to a
coal storage and handling area located west of the plant.
Particulate matter emissions for all four boilers are controlled with
retrofit ESPs located behind each unit. Ash from all units is wet sluiced
to ponds on the far side of the coal storage area south of the plant. A
very large on-site waste disposal area is available.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 23.1.4-1 shows the general layout and location of the FGD control
system. Absorbers for L/LS-FGD and LSD-FGD for units 1 and 2 were located in
23-28
-------
Table 23.1.2-7. Suranary of DSD/FSI Control Costs for the Bull tun Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 502 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty <*W> (X) Content (WK) <«/W> I MM) (mills/kwh) (%)
-------
ABSORBERS
FOR UNITS
ABSORBERS FOR
UNITS _ ^
NH- STORAGE^/ '
SYSTEM
fgd waste
HANDLING
LIMESTONE *?/
PREPARATION/ x
STORAGE AREA
LEGEND
ea - fm
SCR
O 100 200
#'s - INDICATE
BOILER NUMBER
Figure 23.1.4-1. Gallatin plant plot plan
23-30
-------
TABLE 23.1.4-1. GALLATIN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-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
1,2 3,4
300 328
52, 57 72, 76
1956-57 1959
TANG TANG
2.8, 2.7 2.8, 2.
12300 12300
8.5 8.5
WET SLUICE
POND/ON-SITE
1 2
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
1979-78
1979
0.02
0.0235
99.5
99.5
1.0
1.0
391.7
391.7
920
1000
425
427
310
310
23-31
-------
a relatively open area west of and adjacent to the units 1 and 2
precipitators between the plant cooling water discharge channel and the coal
storage area. Absorbers for units 3 and 4 were located in a large open area
south of unit 4, The lime and limestone preparation/storage area and the
waste handling area were placed south of unit 4. No significant
demolition/relocation was associated with the retrofit of FGD control
technologies at Gallatin; therefore, a low factor of 5 percent was assigned
to general facilities.
Retrofit Difficulty and Scope Adder Costs-
Due to the location of the coal conveyor and discharge channel, a medium
access/congestion factor was assigned to the FGD control equipment for
units 1 and 2. The absorbers for units 3 and 4 were located in a large, open
area, south of the plant and the location was assigned a low site access/
congestion factor. For flue gas handling, moderate duct runs for the units
would be required for L/LS-FGD cases since the absorbers are located close to
the ESPs. Medium access/congestion factors were assigned to the L/LS-FGD
flue gas handling for all units reflecting the limited accessibility
associated with routing the duct runs from the ESPs to the absorbers and back
to the chimneys.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 23.1.4-2 and 23.1.4-3. The
largest scope adder for Gallatin would be the conversion of units 1 through 4
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 conventional L/LS-FGD scrubber sludge waste and to prevent plugging
of the sluice lines in LSD-FGD cases. However, this conversion would not be
necessary for the application of forced oxidation L/LS-FGD. The overall
retrofit factors determined for the L/LS-FGD cases were moderate (1.35 to
1.53).
The LSD with reused ESP was the only LSD-FGD technology considered
because the existing ESPs have large SCAs (>400). The absorbers would be
located in the similar locations as in L/LS-FGD cases. High access/
congestion factors were assigned to the LSD-FGD flue gas handling because of
the need for duct runs from each boiler to the LSD chambers and back to the
23-32
-------
TABLE 23.1.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR GALLATIN UNITS 1-2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE
ESP REUSE
MEDIUM
MEDIUM
MEDIUM
MEDIUM
(FEET) 300-600 300-600
MEDIUM
HIGH
NA
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$)
2510
NA
2510
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.53
1.47
ESP REUSE CASE
1.56
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
5
5
23-33
-------
TABLE 23.1,4-3. SUMMARY OF RETROFIT FACTOR DATA FOR GALLATIN UNITS 3-4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING MEDIUM MEDIUM
ESP REUSE CASE HIGH
BAGHOUSF CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 2719 NA 2719
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 1.43
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) S
23-34
-------
ESPs. The retrofit factors determined for the LSD technologies were
moderate (1.43 to 1.56), A separate factor of 1,58 was estimated for
particulate control upgrading. This factor reflects the ESPs plate area
addition difficulty caused by the access/congestion associated with the
close proximity of the existing ESPs and was used by the IAPCS model to
determine new particulate control upgrading costs.
Table 23.1.4-4 presents the costs estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boilers 1-4.
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--
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. SQ^ 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 23.1.4-5.
NOx Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at Gallatin. These controls include LNC and SCR.
The application of NO control technologies is determined by several
A
site-specific factors which are discussed in Section 2. The NQX
technologies evaluated at Gallatin were: OFA and SCR.
23-35
-------
Table 23.1.4-4, Suimary of FGD Control Costs for the Gallatin Plant (Jane 1986 Dollars)
Technology Soiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 SOZ SQ2 Cost
Nuitoer Retrofit Size Factor sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HW) (%) Content (MM) (S/lcW) (MM) (mills/kwti) (X) (tons/yr) ($/tor)
factor (%)
L/S FGD
1
1.53
300
52
2.8
85.0
283.3
36.1
26.5
90.0
27006
1338.5
l/S FGD
2
1.53
300
57
2.7
84.7
282.5
36.8
24.6
90.0
28545
1290.1
L/S FGD
3
1.42
328
72
2.8
83.6
254.9
40.3
19.5
90.0
40883
985.9
L/S FGD
4
1.42
328
76
2.7
83.3
254.1
40.8
18.7
90.0
41613
980.3
l/S FGD-C
1
1.53
300
52
2.B
85.0
283.3
21.1
15.4
90.0
27006
781.0
w/S FGD-C
2
1.53
300
57
2,7
84.7
282.5
21.5
14.3
90.0
28545
752.5
L/S FGD-C
3
1.42
328
72
2.0
83.6
254.9
23.5
11.3
90.0
40883
574.0
l/S FGO-C
4
1.42
328
76
2.7
83.3
254.1
23.7
10.9
90.0
41613
570.6
LC F6D
1-2 '
1.53
600
55
2.7
109.3
182.2
52.5
18.2
90.0
55038
953.4
LC FGD
3-4
1.42
655
74
2.7
108.8
166.1
60.8
14.3
90.0
80912
751.1
LC FGD-C
1-2
1.53
600
55
2.7
109.3
182.2
30.6
10.6
90.0
55088
555.2
LC FGD-C
3-4
1.42
655
74
2.7
108.8
166.1
35.3
8.3
90.0
80912
436.4
LSD+ESP
1
1.56
300
52
2.8
46.3
154.4
20.3
14.9
76.0
22895
886.6
LSD+ESP
2
1.56
300
57
2.7
46.0
153.4
20.6
13.7
76.0
24200
850.5
LSD+ESP
3
1.43
328
72
2.8
45.3
138.0
22.9
11.1
76.0
34659
661.7
LSD+ESP
4
1.43
328
76
2.7
45.0
137.1
23.1
10,6
76.0
35278
653.9
LSD+ESP-C
1
1.56
300
52
2.8
46.3
154.4
11.8
8.7
76.0
22895
517.0
LSD+ESP-C
2
1.56
300
57
2.7
46.0
153.4
12.0
8.0
76.0
24200
495,8
LSD+ESP-C
3
1.43
328
72
2.8
45.3
138.0
13.3
6.4
76.0
34659
385.0
LSD+ESP-C
4
1.43
328
76
2.7
45.0
137.1
13.4
6.1
76.0
35278
380.4
saaa;
23-36
-------
Table
23,1,4-5.
Sutmary of Coal
Switching/Cleaning Costs for the Gallatin Plant
(June
1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
502 S02 Cost
Nunber
Retrofit
Sue
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU3
c%>
Content
(SUM)
(S/kU3
(SMM) "
(mi Us/kyhJ
<%)
ttons/yr)
(S/ton)
Factor
m
CS/8+115
1
1.00
300
52
2.8
10.3
34.2
23.2
i
. 14.8
67.0
20139
1004.9
CS/B+S15
2
1.0Q
300
57
2,7
10.3
34.2
22.0
14.7
66.0
20901
1051.2
CS/B+I15
3
1.00
323
72
2.8
11.1
33.8
29.6
14.3
67.0
30487
971.8
CS/8+S15
4
1.00
328
76
2.7
11.1
33.8
31.1
14.3
66.0
30469
1022.1
CS/8*S15-C
1
1,00
300
52
2.8
10.3
34.2
11.6
B.5
67.0
20139
578.1
CS/8+S15-C
2
1,00
300
57
2.7
10,3
34.2
12.6
8.4
66.0
20901
604.5
CS/8+I15-C
3
1.00
328
72
2.8
11.1
33.8
17,0
8.2
67.0
30487
558.4
CS/B»tl5-C
4
1,00
328
76
2.7
11.1
33.S
17,9
8.2
66.0
30469
587.2
C5/B*I5
1
1.00
300
52
2.8
7.2
23.8
8.4
6.2
67.0
20139
417.4
CS/B+I5
2
1.00
300
57
2.7
7.2
23.8
9.1
6.0
66.0
' 20901
433.2
CS/8+SS
3
1,00
325
72
2.8
7,7
23.4
11.9
5.8
67.0
30487
391.8
CS/8*I5
4
1.00
328
76
2.7
7.7
23.4
12.5
5.7
66,0
30469
410.6
CS/B+S5-C
1
1.00
300
52
2.8
7.2
23.8
4.B
3.5
67.0
20139
240.7
CS/B+S5-C
2
1.00
300
57
2.7
7.2
23.8
5.2
3.5
66.0
2C901
249.7
CS/B+I5-C
3
1.00
328
72
2.8
7.7
23.4
6.9
3.3
67.0
30487
225.6
CS/B+IS-C
4
1,00
328
76
2.7
7.7
23.4
7.2
3.3
66.0
30469
236.4
23-37
-------
Low N0X Combustion--
Units 1 to 4 are dry bottom, tangential-fired boilers. Units 1 and 2
are rated at 300 MW each and units 3 and 4 are rated at 328 MW each. The NO
A
combustion control considered in this analysis was OFA. Tables 23.1.4-6 and
23.1.4-7 present the OFA NO reduction performance results for units 1-2 and
X
3-4. The N0X reduction performance estimated for units 1 and 2, was
25 percent. The N0V reduction for units 3 and 4 was estimated to be
15 percent. The N0X reduction performance for units 3 and 4 was lower than
that for units 1 and 2 because units 3 and 4 have higher heat release rates
and lower furnace residence time than units 1 and 2. Table 23.1.4-8 presents
the estimated cost of retrofitting OFA at units 1-4.
Selective Catalytic Reduction--
Tables 23.1.4-6 and 23.1.4-7 also present the SCR retrofit results for
each unit. The results include process area retrofit factors and scope adder
costs. The scope adders include costs estimated for ductwork demolition, new
heat exchanger, and new duct runs to divert the flue gas from the ESPs to the
reactor and from the reactor to the chimneys.
The SCR reactors for units 1 and 2 were located west of the plant in a
relatively high access/congestion area. They would be bounded by the coal
conveyor and water discharge channel. The SCR reactors for units 3 and 4
were located southwest of the plant in a relatively low access/congestion
area. The ammonia storage system for all units was also located southwest
of the plant in a relatively open area.
A high access/congestion factor was assigned to the reactors for
units 1 and 2, because each is blocked on three sides by the ESPs, the coal
conveyor, and the discharge channel. Reactors for units 3 and 4 were
assigned a low access/congestion factor because they were located in an
easily accessible and relatively open area adjacent to boi1er/ESPs of
unit 4. All reactors were assumed to be in areas with high underground
obstructions. Table 23.1.4-8 presents the estimated cost of retrofitting SCR
at units 1-4.
23-38
-------
TABLE 23.1.4-6. SUMMARY OF NOx RETROFIT RESULTS FOR GALLATIN UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
a
3
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
15.4
15.4
16.4
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
34.8
34.8
68.7
FURNACE RESIDENCE TIME (SECONDS)
3.85
3.85
2.89
ESTIMATED NOx REDUCTION (PERCENT)
25
25
15
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
62
62
66
New Duct Length (Feet)
500
500
490
New Duct Costs (1000$)
4711
4711
4864
New Heat Exchanger (1000$)
3603
3603
3801
TOTAL SCOPE ADDER COSTS (1000$)
8376
8376
8732
RETROFIT FACTOR FOR SCR
1.52
1.52
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
23-39
-------
TABLE 23.1,4-7. SUMMARY OF NOx RETROFIT RESULTS FOR GALLATIN UNIT 4
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) 16,4
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 68.7
FURNACE RESIDENCE TIME (SECONDS) 2J39
ESTIMATED NOx REDUCTION (PERCENT) 15
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
Ductwork Demolition (1000$)
New Duct Length (Feet)
New Duct Costs (1000$)
New Heat Exchanger (1000$)
TOTAL SCOPE ADDER COSTS (1000$)
RETROFIT FACTOR FOR SCR
GENERAL FACILITIES (PERCENT)
LOW
0
66
290
2879
3801
6746
1.16
13
23-40
-------
Table 23,1.4-8.
NQx Control Cost Results for the Gallatin Plant (June 1988 Dollars!
Technology
9oiler
Ha in
Bailer Capacity Coal
Capital Capital
Annual
Annua I
NQx
NOX
NOx Cost
Nwnber Retrofit
Size
factor
Sulfur
Cost
Cost
Cost
cost
Removed Removed
Effect.
Difficulty (Mw)
-------
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 were located west of the
plant for units 1 and 2 and south of the plant for units 3 and 4 in
relatively open areas where they would be close to the units. The retrofit
of DSD and FSI technologies at the Gallatin steam plant would be possible
primarily because the retrofit ESPs are large (SCA >400). For reusing the
ESPs, the conversion of wet to dry fly ash handling system would be required
for FSI and DSD technologies. Tables 23.1.4-9 and 23.1.4-10 present a
summary of site access/congestion factors, scope adders, and retrofit factors
for DSD and FSI technologies at Gallatin steam plant.
Table 23.1.4-11 presents the costs estimated to retrofit DSD and FSI at
the Gallatin plant. Where additional ESP plate area was needed, a high
access/congestion factor (1.55) was applied.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabil1ty--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Gallatin units. Because boiler sizes at the Gallatin
plant are not less than 300 MM and the units have moderate/high capacity
factors, they were not considered good candidates for AFBC retrofit and AFBC
or CG/combined cycle repowering.
23.1.5 Johnsonville Steam Plant
Information on Johnsonville steam plant appears in U. S. EPA report
number EPA-600/7-88/014 entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02
and NOx Retrofit Study (NTIS PB88-244447/AS).
23-42
-------
TABLE 23.1.4-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GALLATIN UNITS 1-2
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$) 2510
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 68
TOTAL COST (1000$)
ESP UPGRADE CASE 2578
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.55
NEW BAGHOUSE NA
23-43
-------
TABLE 23.1,4-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GALLATIN UNITS 3-4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE 4 HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2719
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$) 73
TOTAL COST (1000$)
ESP UPGRADE CASE 2792
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.55
NEW BAGHOUSE NA
23-44
-------
Table 23.1.4-11. S miliary of OSD/FSI Control Costs for the Gallatin Pl»rtt (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
S02
S02
S02 Cost
Number
Rat-oft t
Size
Factor
Sulfur
Cast
Cost
Cost
Cost
Removed
ReiMoved
Effect,
Difficulty (MM)
-------
23.1.6 Kingston Steam Plant
The Kingston steam plant is located within Roane County, Tennessee, as
part of the TVA system. The plant contains nine coal-fired boilers with a
total gross generating capacity of 1700 MW. Figure 23.1.6-1 presents the
plant plot plan showing the location of all boilers and major associated
auxiliary equipment.
Table 23.1.6-1 presents operational data for the existing equipment at
the Kingston steam plant. All boilers burn low sulfur coal (1.1 percent
sulfur). Coal shipments are received by rail and conveyed to a coal storage
and handling area located west of the plant. Coal can also be received by
truck.
Particulate matter emissions for all boilers are controlled with
retrofit ESPs located west of the old ESPs and chimneys. Ash from all units
is wet sluiced to a new off-site ash pond.
Lime/Limestone and Lime Spray Drying FGD Costs- -
Figure 23.1.6-1 shows the general layout and location of the FGD control
system. The absorbers for units 1 to 4 for L/LS-FGD would be located
northwest of the plant in a relatively open area. The location of the
absorbers for units 5 to 9 west of the plant would involve the costly
demolition and relocation of the plant railroad. The absorbers were, as a
result, placed south of the unit 9 powerhouse. The absorbers for units 1 to
9 for LSD-FGD technology would be located in the area between the old
ESPs/chimneys and the retrofit ESPs, The old ESPs/chimneys would have to be
demolished to make space available for LSD-FGD absorbers.
The limestone and lime preparation/storage area and waste handling area
for units 1-4 were located north of units 1-4. The limestone and lime
preparation/storage area and the waste handling area for units 5-9 were
placed adjacent to the absorbers for units 5 to 9.
Retrofit Difficulty and Scope Adder Costs--
The FGD equipment for all units was assigned a low access/congestion
factor. The absorbers for units 1 to 4 were placed on what is currently an
employee parking lot while the absorbers for units 5 to 9 were placed in an
23-46
-------
LIMESTONE STORAGE FGD WASTE /
PREPARATION AREA . HANDLING "m
FOR UNITS 1-4
NH, STORAGE,-
* SYSTEM
§1 4-
ABSORBERS
UNITS
u> "P
J* O
\un m
zc
Oo m
LSD ABSORBERS
I " .Ml .
I /X!-'1 1 i
1 :
it."
:-^lwl-.^J| ABSORBERS
i • * ¦ .? i i.n a «\
7 ¦ x
- UNITS 5-9
FGD WASTE
HANDLING
LIMESTONE
STORAGE/PREPARATION
AREA FOR UNITS 5-9
LEGEND
- SCR
- FGD
INDICATE
BOILER NUMBER
0 100200
i
% Figure 23.1.5-1. Kingston plant plot plan
23-47
-------
TABLE 23,1.6-1. KINGSTON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-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
PARTICULATE CONTROL
1-4
175
50-53
1954
TANG
1.10
12000
12
5-9
200
50-67
1955
TANG
1.10
12000
12
WET SLUICE
POND/OFF-SITE
1 2
RAIL/TRUCK
TYPE
INSTALLATION DATE
EMISION (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
1977-76
1976
0.02
0.01
99.9
99.9
0.9
0.9
287.6
388.8
500
700
575
555
310
310
23-48
-------
open area below (south) the powerhouse. For flue gas handling, short duct
runs for units 1-4 would be required for L/LS-FGD because the absorbers are
located close to the chimney. Long duct runs for units 5-9 would be
required because absorbers are located away from the ESPs. A low flue gas
handling factor was assigned to units 1 to 4 for L/LS-FGD and a medium
factor was assigned to units 5 to 9. The low flue gas handling factor
reflects the location of the absorber next to the chimney and the fact that
no significant ductwork would be required to route the flue gas from the
absorbers to the chimney. On the other hand, the location chosen for the
units 5 to 9 absorbers would involve routing the flue gas around units 8 and
9 and then to the absorbers. Also, the duct runs would be adjacent to the
coal conveyor.
The major scope adjustment costs and estimated retrofit factors for the
F6D control technologies are presented in Tables 23.1.6-2 and 23.1.6-3. The
largest scope adder for Kingston was the conversion of units 1 through 9 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
conventional L/LS-FGD scrubber sludge waste and to prevent plugging of the
sluice lines for 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 ranged from low (1.24 for units 1-4) to
high (1.71 for units 5-9).
The only LSD-FGD case evaluated was LSD with ESP reuse. The LSD-FGD
absorbers were located in a high site access/congestion area between the old
ESPs/chimney and retrofit ESPs. To reduce the boiler's downtime, a bypass
duct would be used to reroute the flue gas around each absorber under
construction. This bypass duct could also be used for other absorbers
during construction. For flue gas handling short duct runs would be
required and a medium site access/congestion factor was assigned to the
flue gas handling system because of access difficulty created by the
powerhouse, ESPs, and existing duct runs. The retrofit factors estimated
were medium (1.53) for all units and did not include particulate control
upgrading costs. A separate retrofit factor was developed for the ESPs
upgrade and used by the IAPCS model to estimate the particulate control
upgrading costs. This factor, estimated for the ESP upgrading cost, was
23-49
-------
TABLE 23.1.6-2. SUMMARY OF RETROFIT FACTOR DATA FOR KINGSTON UNITS 1-4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW
FLUE GAS HANDLING LOW
ESP REUSE CASE
RAGHOUSF CASF
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA
NEW BAGHOUSE NA
LOW
LOW
100-300 100-300
NA
NA
HIGH
MEDIUM
NA
0-100
NA
HIGH
NA
SCOPE ADJUSTMENTS
WET TO DRY YES
ESTIMATED COST (1000$) 1548
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER (old ESP's demolition) NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.31
NA
NA
NO
NA
NO
0
NO
1.24
NA
NA
YES
1548
NO
0
YES
1.53
NA
1.58
NA
GENERAL FACILITIES (PERCENT) 7
10
23-50
-------
TABLE 23.1.6-3. SUMMARY OF RETROFIT FACTOR DATA FOR KINGSTON UNITS 5-9
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
HIGH
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
MEDIUr
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
1000 +
1000 +
ESP REUSE
0-100
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
. NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST
(1000$)
1745
NA
1745
NEW CHIMNEY
YES
YES
NO
ESTIMATED COST
f10005)
1400
1400
0
OTHER (old ESP's
demolit ion)
NO
NO
YES
RETROFIT FACTORS
FGD SYSTEM
1.71
1.63
ESP REUSE CASE
1.53
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
5
10
23-51
-------
high (1.58) and reflects the congestion which exists around the existing
ESPs because of the close proximity of ESPs.
Table 23.1.6-4 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 1-9.
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare
scrubber module, and optimization of scrubber size.
Coal Switching Costs--
The plant has already switched to low sulfur coal.
NQX Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at Kingston. 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 NO
A
technologies evaluated at Kingston were: OFA and SCR.
Low NO Combustion--
A
Units 1 to 9 are dry bottom, tangential wall-fired boilers. Units 1 to
4 are rated at 175 MW each and units 5 to 9 are rated at 200 MW each. The
N0„ combustion control considered in this analysis was OFA. Tables 23.1.6-5
x
through 23.1,6-7 present the estimated OFA N0X reduction performance levels
for units 1 to 9. The NO reduction performance estimated for each of the
A
nine units was 20 percent which was obtained by examining the effects of heat
release rate and furnace residence time on NQX reduction using the simplified
N0X procedures. Table 23.1.6-8 presents the costs estimated for retrofitting
OFA at the Kingston plant nine boilers.
Selective Catalytic Reduction--
Tables 23.1.6-5 through 23.1.6-7 also present the SCR retrofit results
for each unit. The results include a process area retrofit factor and scope
23-52
-------
Table 23.1.6-4. Summary of FGO Control Costs for the Kingston Plant (June '988 Dollars)
Technology
Boil«r
Main
Bailer Capacity Coal
Capital Capital Annual
Annual
SQ2
SQ2
S02 Cost
Nunoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
(mi Us/Swh)
(X)
Ctons/yr)
(i/tsn)
Factor
-------
TABLE 23.1.6-5. SUMMARY OF NOx RETROFIT RESULTS FOR KINGSTON UNTIS 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
(IOOO BTU/CU FT-HR)
14.5
14.5
14.5
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(IOOO BTU/SQ FT-HR)
30.2
30.2
30.2
FURNACE RESIDENCE TIME (SECONDS)
3.01
3.01
3.01
ESTIMATED NOx REDUCTION (PERCENT)
20
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
"i.
V
LOW
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
41
41
41
New Duct Length (Feet)
267
267
200
New Duct Costs (1000$)
1835
1835
1375
New Heat Exchanger (1000$)
2608
2608
2608
TOTAL SCOPE ADDER COSTS (1000$)
4484
4484
4024
RETROFIT FACTOR FOR SCR
1.15
1.16
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
23-54
-------
TABLE 23.1.6-6. SUMMARY OF NOx RETROFIT RESULTS FOR KINGSTON 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
16.1
16.1
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
30.2
25.4
25.4
FURNACE RESIDENCE TIME (SECONDS)
3.01
2.58
2.58
ESTIMATED NOx REDUCTION (PERCENT)
20
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
41
45
45
New Duct Length (Feet)
167
250
333
New Duct Costs (1000$)
1148
1858
2475
New Heat Exchanger (1000$)
2608
2825
2825
TOTAL SCOPE ADDER COSTS (1000$)
3797
4729
5346
RETROFIT FACTOR FOR SCR
1.34
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
23-55
-------
TABLE 23.1.6-7. SUMMARY OF NOx RETROFIT RESULTS FOR KINGSTON UNITS 7-9
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
7
8
9
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
16.1
16.1
16.1
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
25.4
25.4
25.4
FURNACE RESIDENCE TIME (SECONDS)
2.58
2.58
2.58
ESTIMATED NOx REDUCTION (PERCENT)
20
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
45
45
45
New Duct Length (Feet)
267
167
267
New Duct Costs (1000$)
1985
1241
1985
New Heat Exchanger (1000$)
2825
2825
2825
TOTAL SCOPE ADDER COSTS (1000$)
4855
4112
4855
RETROFIT FACTOR FOR SCR
1.34
1.34
1.52
GENERAL FACILITIES (PERCENT)
25
25
25
23-56
-------
Table 23.1.6-8. NOx Control Cost Results for the Kingston Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
NOx
NOx
NOx Cost
Number
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
(MO
<%>
Content
(SUM)
(S/kW)
($MM)
Crni Us/kuh)
(tons/yr)
(i/ton)
Factor
C»
-NC-QfA .
1
1.0C
175
50
1.1
0.8
4.4
0.2
0.2
20.0
476
344.6
LNC-OFA
2 •
1.00
175
40
1,1
- 0.8
4,4
0.2
0.3
20.0
381
430.7
LNC-OFA
3
t.00
175
60
>•1.
0.8
4.4
0.2
0.2
20,0
571
287.1
LNC-OFA
4
1.00
175
63'
1.1
0,8
4.4
0,2
0,2
20.0
599
273.5
LNC-OFA
5
1.00
200
55
1.1
D.8
4.1
0.2
0,2
20.0
598
289,3
LNC-OFA
6
1.00
200
79
1.1
0.8
4.1
0.2
0.1
20.0
859
201.4
LNC-OFA
7
1.00
200
61
1.1
0.8
4.1
0.2
0.2
20.0'
663
260,9
LNC-OFA
a
1.00
200
60
1.1
0.8
4.1
0.2
0.2
20.0
652
265.2
LNC-OFA
9
1.00
200
80
1.1
0.8
4.1
0.2
0.1
20.0
87Q
198,9
LNC-OFA-C
1
1.00
175
50
1.1
0.3
4.4
0.1
0.1
20.0
476
204.8
LNC-OFA-C
2
1.00
175
40
1.1
o.a
4,4
0.1
0.2
20,0
381
256.0
LNC-OFA-C
3
1.00
175
60
1.1
0.8
4.4
0.1
0.1
20.0
571
170.6
LNC-OFA-C
4
1.00
175
63
1.1
0.8
4.4
0.1
0.1
20.0
599
162.5
LNC-OFA-C
5
1.00
200
55
1.1
0.8
4.1
0.1
0.1
20,0
593
171.7
LNC-OFA-C
6
1.00
200
79
1.1
• 0.8
4.1
0.1
0.1
20.0
859
119.6
LNC-OFA-C
7
1.00
200
61
1.1
0.8
4.1
0.1
0.1
20.0
663
154.9
LNC-OFA-C
8
1.00
200
60
1.1
o.a
4,1
0.1
0.1
20.0
652
157.4
LNC-OFA-C
9
1,00
200
ao
1.1
0.8
4.1
0.1
0.1
20.0
870
118,1
SCR-3
1
1.16
175
so
1.1
27.7
158.3
9.2
12.0
80.0
1903
4814.8
SCR-3
2
1.16
175
40
1.1
27.7
158.3
9.1
14.8
80.0
1522
5959.1
SCR-3
3
1.34
175
60
1.1
29.6
169.3
9.7
10.6
80.0
2283
4268.8
SCR-3
4
1.34
175
63
1.1
29.4
167.9
9.7
10.1
80.0
2397
4060.3
SCR-3
5
1.16
200
55
1.1
30.4
152.1
10.2
10.6
80.0
2392
4274.5
SCR-3
6
1.16
200
n
1.1
31.1
155.3
10.6
7.7
80.0
3436
3088.3
SCR-3
7
1,34
200
61
1.1
34.3
171.6
11.2
10.5
80.0'
2653
4231.4
SCR-3
a
1.34
200
60
1.1
33.6
167.8
11.1
10.5
80,0
2609
4246.7
SCR-3
9
1.52
200
80
1.1
37.1
185.4
12.1
8.6
80.0
3479
3481.6
SCR-3-C
1
1.16
175
50
1.1
27.7
158.3
5.4
7.0
80.0
1903
2823.3
SCR-3-C
2
1.16
175
40
1.1
27.7
15B.3
5,3
8.7
80.0
1522
3495.8
SCR-3-C
3
1.34
175
60
1.1
29.6
169.3
5.7
6.2
80.0
2283
2503.9
continued . . .
23-57
-------
Table 21.1.6-8. NO* Control Cost Results for the Kingston Plant (June 1988 Dollars) continued
Technology
Boiler
Main
Boiler Capacity Coal
Capi tat
Capi tal
Annual
Annual
NOx
NOx
NOx Cost
Nutter
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removec
Removed
Effect.
Difficulty (MM)
(S3
content
C$MH)
CS/kW)
(mills/kuh)
(X)
(tons/yr)
(S/tonj
Factor
CX5
SCR-3-C
4'
1.34
175
63
1.1
29.4
167,9
5.7
5.9
so.o
2397
2381.5
SCR-3-C
5
1.16
200
55
1.1
30.4
152.1
6.0
6.2
30.0
2392
2506.1
SCR-3-C
6
1.16
200
79
1,1
31.1
155.3
6.2
4.5
80.0
3436
1809.9
SCR-3-C
7
1.34
200
61
1.1
34.3
171.6
6.6
6.2
80,0
2653
2482.3
SCR-3-C
8
1.34
200
60
1.1
33.6
167.8
6.5
6.2
80.0
2609
2490.8
SCR-3-C
9
1.52
200
80
1.1
37.1
185.4
7.1
5.1
80.0
3479
2042.5
scr-7
1
1.16
175
50
1.1
27.7
158.3
7.7
10.1
80.0
1903
4058.9
SCR-7
2
1.16
175
40
1.1
27.7
158.3
7.6
12.4
80.0
1522
5014.1
SCR-7
3
1.34
175
60
1.1
29.6
169.3
8.3
9.0
ao.o
2283
3638.9
SCR *7
4
1.34
175
63
1.1
29.4
167.9
8.3
8.6
80.0
2397
3460.9
SCR-7
5
1.16
200
55
1.1
30.4
152.1
8.6
8.9
80.0
2392
3587.5
SCR-7
6
1.16
2Q0
79
1.1
31.1
155.3
9.0
6.5
80.0
3436
2610.0
SCR-7
T
1.34
200
61
34.3
171.6
9,6
9.0
80.0
2653
3611,9
SCR-7
8
1.34
200
60
1.1
33.6
167.8
9.4
9.0
80.0
' 2609
3617,0
SCR-7
9
1.52
200
80
1.1
37.1
185.4
10.5
7.5
80.0
3479
3009.2
SCR-7-C
1
1,16
175
50
27,7
158.3
4.5
5.9
80.0
1903
2390.7
SCR-7-C
2
1.16
175
40
27.7
158,3
4.5
7.3
80.0
1522
2954.4
SCR-7-C
3
1,34
175
60
1,1
29.6
169.3
4.9
5.3
80.0
2283
2143.0
SCR-7-C
4
1.34
175
63
1.1
29,4
167.9
4.9
5.1
80.0
2397
2037.8
SC8-7-C
5
1.16
200
55
1,1
30.4
152.1
5,1
5.2
80.0
2392
2112.4
SCR-7-C
6
1.16
200
79
1,1
31.1
155.3
5.3
3.8
80.0
3436
1535.9
SCR-7-C
7
1,34
200
61
1,1
34.3
171,6
5.6
5.3
80.0
2653
2127.4
SCR-7-C
8
1.34
200
60
1.1
33.6
167.8
5.6
5.3
80.0
2609
2129.9
SCR-7-C
9
1.52
200
80
1.1
37.1
185.4
6.2
4.4
80.0
3479
1771.9
23-58
-------
adder costs. The scope adders include costs estimated for ductwork
demolition, a new flue gas heat exchanger, and new duct runs to divert the
flue gas from the ESP outlets to the reactor and from the reactor to the
chimney.
The reactor for unit 1 was located north of the units near the ESPs
between both parking lots in a relatively low access/congestion area. The
reactors for units 2 to 9 were located northwest of the plant approximately
behind the ESPs of each unit in low to high access/congestion areas. The
ammonia storage system was located north of the plant in a relatively open
area.
Reactors for units 1, 2, 5 and 6 were located in low access/congestion
areas. Reactors for units 1 to 2 were located close to the parking lots and
those for units 5 and 6 were located between the ESPs and the railroad
tracks. The reactors for units 3, 4, 7 and 8 were in medium access/
congestion areas because they were placed on either side of the chimneys.
The reactor for unit 9 was located in a high access/congestion area being
blocked on three sides by the ESPs, railroad tracks, and a building. All
reactors were assumed to be in areas with high underground obstructions.
Table 23.1.6-8 presents the costs estimated for retrofitting SCR at the
Kingston plant 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 would be
located west of the plant similar to the LSD-FGD equipment layout. The
retrofit of DSD and FSI technologies at the Kingston steam plant would be
relatively easy because of sufficient flue gas ducting residence time
(5 seconds) before the retrofit ESPs and no additional particulate controls
would be needed because of the large ESP sizes (SCA >500). Tables 23.1.6-9
23-59
-------
TABLE 23.1.6-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR KINGSTON UNITS 1-4
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$) 1548
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 46
TOTAL COST (1000$)
ESP UPGRADE CASE 1594
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.55
NEW BAGHOUSE NA
23-60
-------
and 23.1.6-10 present a summary of site access/congestion factors, scope
adders, and retrofit factors for DSD and FSI technologies at the Kingston
steam plant. Table 23.1.6-11 presents the costs estimated for retrofitting
DSD and FSI at the Kingston plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Using the applicability criteria presented in Section 2 for AFBC
retrofit and AFBC/CG/combired cycle repowering, the boilers at Kingston would
be considered good candidates because of their small boiler sizes (<300 MW)
and their age (built prior to 1960). However, the high capacity factor could
result in large downtime penalties, if reserve capacity or purchase power is
not available at an equipment cost.
23.1.7 John Sevier Steam Plant
The John Sevier steam plant is located within Hawkins County,
Tennessee, as part of the TVA system. The plant contains four coal-fired
boilers with a total gross generating capacity of 846 MW. Figure 23.1.7-1
presents the plant plot plan showing the location of the four boilers and
major associated auxiliary equipment.
Table 23.1.7-1 presents operational data for the existing equipment at
the John Sevier steam plant. All boilers burn medium sulfur coal
(1.3 percent sulfur). Coal is received by rail and conveyed to a coal
storage and handling area located southwest of the plant. All units share
the same conveyor.
Particulate matter emissions for all four boilers are controlled with
ESPs located directly behind each boiler. Ash from all units is wet
sluiced to ponds located on the opposite side of the water discharge
channel, west of the plant. On-site waste disposal is limited and TVA is
considering two options to address this problem: the purchase of more land
adjacent to the plant or dry disposing of the waste off-site.
23-61
-------
TABLE 23.1.6-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR KINGSTON UNITS 5-9
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$) 1745
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 50
TOTAL COST (1000$)
ESP UPGRADE CASE 1795
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.55
NEW BAGHOUSE NA
23-62
-------
Table 23.1.6-11. Summary of OSD/FSI Control Costs for the Kingston Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capi taI
AnnuaI
Annua I
S02
S02
SC2 Cost
Wutiser
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Renwves
Removed
Effect.
Oi ffieulty
(WO
;%>
Content
($MM)
(I/kWJ
(SWO
(mi IIs/kwh)
(X)
(tons/yr)
WtenJ
Factor
-------
Table 23,1.6-11. Sunmary of DSO/FSI Control Costs for the Kingston Plant (June 1983 Dollars! continued , . .
»»¦»¦=
sissansissi
ual«<>
Technology
Boiler Main
Boiler capacity Coal
Capi cat
Capital Annual
Annual
S02
S02
S02 Cost
Niwber Retrofit
size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
-------
FGO WASTE
HANDLING^
NH„ STORAGE
SYSTEM-)
LIMESTONE PREPARATION/
STORAGE AREA /
ABSORBERS
I
m".
irn/n
LEGEND
- SCR
- FGD
#'s - INDICATE
BOILER NUMBER
O 100 200
I
II
Figure 23,1.7-1. John Sevier plant plot plan
23-65
-------
TABLE 23.1.7-1. JOHN SEVIER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MV-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
1-4
200, 200, 223, 223
€8, 68, 83, 85
1955-57
TANG
I.30
12500
II.0
WET SLUICE
POND/ON-SITE
1-2
RAIL
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1973-74
EMISSION (LB/MM 8TU) 0.02-0.03
REMOVAL EFFICIENCY 99.6-99.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.0
SURFACE AREA (1000 SQ FT) 315
GAS EXIT RATE (1000 ACFM) 920
SCA (SQ FT/1000 ACFM) 342
OUTLET TEMPERATURE (*F) 310
23-66
-------
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 23.1.7-1 shows the general layout arid location of the FGD control
system. Absorbers for L/LS-FGD and LSD-F6D would be located west and
northwest of the plant in a relatively open area. The limestone
preparation/storage area was located directly north of the powerhouse with
the waste handling area being located west of the preparation/storage area.
Retrofit Difficulty and Scope Adder Costs-
Most of the FGD control equipment would be located in a relatively low
to medium site access/congestion area with high underground obstruction
created by the cooling water intakes. For flue gas handling, a low access/
congestion factor was assumed for all the L/LS-FGD cases evaluated because
there are no obstructions between the absorber locations and the ESPs/
chimneys.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Table 23.1.7-2. The largest scope
adder for the John Sevier steam plant was the conversion of units 1 to 4 fly
ash conveying/disposal systems 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 the L/LS-FGD scrubber sludge waste and to prevent plugging of the
sluice lines in LSD-FGD cases. However, this conversion is not necessary
for forced oxidation L/LS-FGD. The overall retrofit factors determined for
the L/LS-FGD cases were moderate (1.33 to 1.38).
The LSD with a new baghouse was the only LSD-FGD technology considered.
Though large (SCA >300), reuse of the ESPs is not possible given the high
access difficulty for routing of the flue gas from upstream of the ESPs to
the LSD absorbers and back. For the LSD-FGD with a new baghouse case, the
retrofit factor was also moderate (1.51), A medium site access/congestion
factor was assigned to the location of the new baghouses and flue gas
handling systems. This factor reflects congestion created by the designed
LSD chambers.
Table 23.1,7-3 presents the cost estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the„ESPs and ash handling systems for
boilers 1-4.
23-67
-------
TABLE 23.1.7-2. SUMMARY OF RETROFIT FACTOR DATA FOR JOHN SEVIER UNITS 1-4
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
MEDIUM
DUCT WORK DISTANCE (FEET)
0-100
0-100
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST (1000$)
1,745
NA
1,745
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
YES
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.38
1.33
ESP REUSE CASE
NA
BAGHOUSE CASE
1.51
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.34
GENERAL FACILITIES (PERCENT)
7
7
7
23-68
-------
Table 23,1,7*3. Suimary of FGD Control Costs for the John Sevier Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Caal
Capital
Capital
Annual
Annual
S02
SC2
S02 Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HW)
<%)
Content
(SUM)
(J/kW)
($HM)
(milIs/kwh)
m
(tons/yr)
C$/ton)
Factor
(Xl
l/S FGD
1, z
1.38
200
68
1.3
57.0
285.0
25.0
21.0
90.0
10731
2326.4
t/S FGD
3
1.38
223
83
1.3
60.5
271.1
28,2
17.4
90.0
14604
1930.0
L/S FGD
4
1.38
223
85
1.3
60.5
271.1
28.4
17.1
90.0
14956
1898.5
L/S FGD-C
1- 2
1.38
O
o
68
1.3
57.0
285.0
14.6
12.2
90.0
10731
1356,7
L/S FGD-C
3
1.38
223
83
1.3
60.5
271.1
16.4
10.1
90.0
14604
1124.3
L/S FGD-C
4
1.38
223
85
1.3
60.5
271.1
16.5
10.0
90.0
14956
1105.8
LC FED
1-4
1.33
546
76
1.3
112.6
133.0
61.7
11.0
90.0
50730
1217.0
LC FGD-C
1-4
1.38
846
76
1.3
112.6
133.0
35.9
6.4
90.0
50730
707.2
LSD+FF
1, 2
1.51
200
sa
1.3
50.7
253.6
18.S
15.8
87.0
10313
1820.9
LSD+FF
3
1.51
223
S3
1.3
53.3
247.9
21.3
13.1
87.0
14036
1518.3
LSD+FF
4
1.51
223
85
1.3
55.3
247.9
21.4
12.9
87.0
14374
1491.5
LSD+FF-C
1, 2
1,51
200
68
1.3
50.7
253.6
11.0
9.2
87.0
10313
1065.3
LSD+FF-C
3
1.51
223
83
1.3
55.3
247.9
12.5
7.7
87.0
14036
887.6
LSD+FF-C
4
1.51
223
85
1.3
55.3
247.9
12.5
7.5
87.0
14374
871.8
23-69
-------
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-
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. SO^ conditioning was assumed to reduce the needed plate area up
to 25 percent.
Costs were generated to show the impact of different coal fuel cost
differentials. The costs associated with each boiler for the range of fuel
cost differential are shown in Table 23.1.7-4.
NO Control Technology Costs--
x
This section presents the performance and various related costs
estimated for NO controls at the John Sevier steam 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 steam plant were;
OFA and SCR.
Low NOx Combustion--
Units 1 to 4 are dry bottom, tangential-fired boilers. Units 1 and 2
are each rated at 200 MW while units 3 and 4 are each rated at 223 MW. The
NO combustion control considered in this analysis was OFA. Tables 23.1.7-5
A
and 23.1.7-6 present the OFA N0x estimated reduction performance results for
units 1 to 4. The estimated N0X reduction performance, using the simplified
NO procedures, was 20 percent for each unit. This performance was used
A
23-70
-------
Table 23.1.7-4, Summary of Coal Switching/Cleaning Costs for the John Sevier Plant (June 1988 Dollars)
Technology
Boi ler
Main
Boiler Capacity Coal
Capi tal
Capital
:s=;;;s:
Annual
Annual
S02
SC2
SC2 Cost
Number
Retrofit
Si ze
Factor
Sulfur
Cost
Cost
Cost
Cost
Removec
Removed
Effect.
Difficulty (MU)
(X)
Content
(SMM3
<$/kU5
(SUM)
(mi I is/
Ctons/yr)
($/ton)
factor
OS)
cs/b+*15
1, 2
1.00
200
68
1.3
7.1
35.4
17.2
14.5
28.0
3320
5184.8
CS/B*$15
3
1.00
223
83
1.3
7.8
34.8
23.0
14.2
28.0
4519
5079.2
CS/B*S15
4
1.00
223
85
1.3
7,8
34.8
23.5
14.1
2a.o
4628
5070.3
CS/B+S15-C
1, 2
1.00
200
66
1.3
7.1
35.4
9.9
a.3
28.0
3320
2980.1
CS/8+S15-C
3
1.00
223
93
1.3
7.8
34.8
13.2
8.1
28.0
4519
2917.8
CS/B*$15-C
4
1.00
223
as
1,3
7.8
34.8
13.5
8.1
28.0
4628
2912.5
CS/3*t5
1. 2
1.00
200
68
1.3
5.0
25.0
7.0
5.9
28.0
3320
2111.8
CS/B*$5
3
1.00
223
83
1.3
5.4
24.4
5.2
5.6
28.0
4519
2026.1
CS/8+15
4
1.00
223
85
1.3
5.4
24.4
9.3
5,6
28.0
4628
2019.3
CS/S+S5-C
1, 2
1.00
200
68
1.3
5.0
25.0
4.0
3.4
28,0
3320
1216.7
CS/8+I5-C
3
1.00
223
83
1.3
5.4
24.4
5.3
3.3
28.0
4519
1166.2
CS/B+S5-C
4
1.00
223
85
1.3
5.4
24.4
5.4
3.2
28.0
4628
1162.2
23-71
-------
TABLE 23.1.7-5. SUMMARY OF NOx RETROFIT RESULTS FOR SEVIER UNITS 1-2
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
16.1
16.1
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
25.4
25.4
FURNACE RESIDENCE TIME (SECONDS)
3.02
3.02
ESTIMATED NOx REDUCTION (PERCENT)
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
Ductwork Demolition (1000$)
45
45
New Duct Length (Feet)
93
93
New Duct Costs (1000$)
691
691
New Heat Exchanger (1000$)
2825
2825
TOTAL SCOPE ADDER COSTS (1000$)
3562
3562
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
23-72
-------
TABLE 23.1.7-6. SUMMARY OF NOx RETROFIT RESULTS FOR SEVIER UNITS 3-4
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
16.1
16.3
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
25.4
25.2
FURNACE RESIDENCE TIME (SECONDS)
3.02
3.01
ESTIMATED NOx REDUCTION (PERCENT)
20
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
NA
0
Ductwork Demolition (1000$)
45
45
New Duct Length (Feet)
93
93
New Duct Costs (1000$)
691
691
New Heat Exchanger (1000$)
2825
2825
TOTAL SCOPE ADDER COSTS (1000$)
3562
3562
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
23-73
-------
based on examining the effects of heat release rates and furnace residence
time on NO reduction using the simplified procedure. Table 23.1.7-7
A
presents the costs estimated for retrofitting OFA at the John Sevier plant
boilers.
Selective Catalytic Reduction--
Tables 23.1.7-5 and 23.1.7-6 present the SCR retrofit results for each
unit. The results include process area retrofit factors and scope adder
costs. The scope adders include costs estimated for ductwork demolition, new
flue gas heat exchanger, and new duct runs to drive the flue gas from the
ESPs to the reactors and from the reactors to the chimney.
The SCR reactors and ammonia system were located in a relatively low
access/congestion area. Specifically, the reactors were located west of the
plant behind each unit's ESPs while the ammonia system was located northwest
of the powerhouse. Although the reactors were assigned a low access/
congestion, they were assumed to be in areas with high underground
obstruction. Table 23.1.7-7 presents the costs estimated for retrofitting
SCR at the John Sevier plant 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 all units were
located west of the plant in a relatively open area. The short duct runs
from the boiler to the ESPs do not provide, sufficient duct residence time.
However, developments in particulate control technology may be used to
modify the existing ESPs by combining advanced ESP technology and spray
dryer technology to remove SO^ and particulate (E-SQX technology). Since
all units have large ESP sizes (SCA >340), it was assumed that DSD with ESP
reuse is an alternative low cost method to the new baghouse option. A high
23-74
-------
Table 23.1,7-7. NOx Control Cost Results for the John Sevier Plant (June 1988 Dollars}
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
N-mber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
($MH)
(mi tls/kwhl
(%>
ttons/yr5
(S/ton)
Factor
(X>
INC-OFft
1, 2
1.00
200
68
1.3
0.8
4.1
0.2
0.1
20.0
706
245.2
LNC-OFA
3
1.00
223
83
1.3.
0.9
3.8
0.2
0.1
20.0
960
188.0
LNC-OFA
4
1.00
223
as
1.3
0.9
3.8
0.2
0.1
20.0
983
183.6
INC-OFA-C
1, 2
1.00
200
66
1.3
0.8
4.1
0.1
0.1
20.0
70S
145.6
INC-OFA-C
3
1.00
223
S3
1.3
0.9
3.8
0.1
0.1
20.0
960
111.7
INC-OFA-C
4
1.00
223
85
1.3
0.9
3.8
0.1
0.1
20.0
983
109.0
SCR-3
1, 2
1.16
200
68
1.3
29.2
146.1
10.1
8.5
80.0
2822
3586.7
SCR-3
3
1.16
223
83
1,3
31.6
141.6
11.2
6.9
80.0
3841
2927.3
SCR-3
4
1.16
223
85
1.3
31.6
141.6
11.3
6.8
80.0
3933
2865.2
SCR-3-C
1, 2
1.16
200
68
1.3
29.2
146.1
5.9
5.0
80.0
2822
2101.3
SCS-3-C
3
1.16
223
. 83
1.3
31.6
141.6
6.6
4.1
80.0
3841
1714.0
SCR-3-C
4
1.16
223
85
1.3
31.6
141.6
6.6
4.0
80.0
3933
1677.6
SCR-7
1, 2
1.16
200
68
1.3
29.2
146.1
8.5
7.1
80.0
2822
3007.8
SCR-7
3
1.16
223
83
1.3
31.6
141.6
9.4
5.8
80.0
3841
2453.1
SCS-7
4
1.16
223
85
1.3
31.6
141.6
9.4
5.7
8C.0
3933
2402.2
SCR-7-C
1, 2
1.16
200
68
1.3
29.2
146.1
5.0
4.2
80.0
2822
1769.7
SCR-7-C
3
1.16
223
83
1.3
31.6
141.6
5.5
3.4
80.0
3841
1442.3
SCR-7-C
4
1.16
223
85
1.3
31.6
141.6
5.6
3.3
80.0
3933
1412.3
23-75
-------
site access/congestion factor was assigned to the ESP upgrade for the same
reason specified in the LSD-FGD section. The conversion of wet to dry ash
handling system would also be required for reusing the ESPs for the FSI and
DSD technologies. Table 23.1.7-8 presents a summary of site access/
congestion factors, scope adders, and retrofit factors for DSD and FSI
technologies at the John Sevier plant. Table 23.1.7-9 presents the costs
estimated for retrofitting FSI and DSD at the John Sevier plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabili ty- -
Using the applicability criteria presented in Section 2 for AFBC
retrofit and AFBC/CG/combined cycle repowering, all boilers at John Sevier
would be considered potential candidates for AFBC retrofit and AFBC and
CG/combined cycle repowering because of their small boiler sizes. However,
the high capacity factors of the units indicates marginal benefits for
retrofit/repowering due to downtime cost penalties and minimal heat rate
improvements.
23-76
-------
TABLE 23.1.7-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JOHN SEVIER UNITS 1-4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE HIGH
NEW BAGHCUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1,745
ADDITIONAL DUCT WORK (FT)
NEW IAGHOUSE CASE 200
ESTIMATED COST (1000$) 1,378
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 50
TOTAL COST (1000$)
ESP UPGRADE CASE 1,795
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.55
NEW BAGHOUSENA
23-77
-------
Table 23,1.7-9, Suimary of DSD/FSI Control Costs for the John Sevier Plant (June 1988 Dollars)
S3S33333S3333
II
II
II
N
11
383
II
H
II
Ml
N
II
M
II
>323 85?
II
u
II
H
II
11
II
II
II
11
II
II
II
II
ssasasssi
II
11
11
H
II
II
II
nttiui
S SS3 S SS53SSS3SS5SS
siaiiiicsx
5=33=2323
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annua I
S02
S02
S02 Cost
Number
Retrofit
Sire
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect,
Difficulty (MU)
(%i
Content
(SHM)
(i/ku>
-------
SECTION 24.0 VIRGINIA
24.1 APPALACHIAN POWER COMPANY
24.1.1 Clinch River
The boilers at the Clinch River plant have large roof-mounted ESPs
which are difficult to access; therefore, LSD-FGD with a new baghouse was
considered for these units. Due to the low sulfur coal being fired at this
plant, FGD costs were not presented and CS was not evaluated. Sorbent
injection technologies were not considered because of the short duct
residence time between the boilers and ESPs and the difficulty in accessing
the roof-mounted ESPs. For N0X control, neither LNB nor OFA were an option
since these technologies are not applicable to roof-fired boilers.
24-1
-------
TABLE 24.1.1-1. CLINCH RIVER STEAM PLANT OPERATIONAL DATA *
BOILER NUMBER 1,2,3
GENERATING CAPACITY (MW-each) 240
CAPACITY FACTOR (PERCENT) 82,88,70
INSTALLATION DATE 1958,58,61
FIRING TYPE ROOF-FIRED
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 0.8
COAL HEATING VALUE (BTU/LB) 12800
COAL ASH CONTENT (PERCENT) 11.6
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL/SOLD
STACK NUMBER 1,1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1975,74,74
EMISSION (LB/MM BTU) 0.05,0.06,0.06
REMOVAL EFFICIENCY 98.9,99.5,99.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.5
SURFACE AREA (1000 SQ FT) 722.3
GAS EXIT RATE (1000 ACFM) 900
SCA (SQ FT/1000 ACFM) 803
OUTLET TEMPERATURE (*F) 250
* Some information was obtained from plant personnel.
24-2
-------
TABLE 24.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CLINCH RIVER
UNIT 1, 2 OR 3 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
IAGHOUSE 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$)
1680
0
1680
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
NO
BAGHOUSE CASE
1.43
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 10,10,15
0
10,10,15
* L/LS-FGD and LSD-FGD absorbers would be located north of
unit 1, on either side of the coal conveyor.
24-3
-------
TABLE 24.1.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR CLINCH RIVER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2,3
1-2
FIRING TYPE
ROOF-FIRED
NA
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1958,58,61
NA
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
52
88
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
3308
4962
New Heat Exchanger (1000$)
3152
4777
TOTAL SCOPE ADDER COSTS (1000$)
6511
9826
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20,20,38
20
* Cold side SCR reactors for units 1 and 2 would be located north
of unit 1, west of the coal conveyor. Cold side SCR reactors
for unit 3 would be located north of unit 3, east of the coal
conveyor.
24-4
-------
Table 24.1.1-4, NOx Control Cost Results for the Clinch River Plant (June 1988 Dollars)
Technology
Boiler
Main
Bailer Capacity Coal
Capital Capital Annual
Annual ,
NOx
NOx
NOx Cost
Number
Retrofic
Size
Factor
Sul fur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
(X)
Content
CSMM3
-------
24.2 VIRGINIA ELECTRIC & POWER
24,2.1 Chesterfield
The four coal firing boilers considered for this evaluation are firing
a low sulfur coal, hence FGD costs were not presented and CS was not
evaluated.
TABLE 24.2.1-1. CHESTERFIELD 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
3 4 5 6 7
112 188 359 694 210
27 58 67 46 COMBINED
1952 1960 1964 1969 CYCLE
TANGENTIAL PLANNED
39 NA 154.5 330
NO NO NO NO
1.0
12700
8.5
WET DISPOSAL
POND/ON-SITE
12 3 4
RAILROAD
PARTICULATE CONTROL
TYPE ESP*
INSTALLATION DATE NA
EMISSION (LB/MM BTU) NA
REMOVAL EFFICIENCY NA
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) NA
SURFACE AREA (1000 SQ FT) NA
GAS EXIT RATE (1000 ACFM) NA
SCA (SQ FT/1000 ACFM) NA
OUTLET TEMPERATURE (°F) NA
* It was assumed that units 3, 4, 5, and 6 are equipped with
ESPs.
24-6
-------
TABLE 24.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CHESTERFIELD
UNIT 3, 4, OR 5 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL i 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 YES NA NO
ESTIMATED COST (1000$) 1038-2949 NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 784-2513 0 784-2513
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.60 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/LS-FGD absorbers, LSD-FGD absorbers and new FFs for units 3,
4 and 5 would be located west of unit 6. LSD with a new
baghouse was considered because access to the upstream of the
existing ESPs is difficult.
24-7
-------
TABLE 24.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CHESTERFIELD
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
SAGHOUSE 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 YES NA
ESTIMATED COST (1000$) 5324 NA
NEW CHIMNEY NO NA
ESTIMATED COST (1000$) 0 0
OTHER NO
NO
NA
NO
2513
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.46
NA
NA
GENERAL FACILITIES (PERCENT) 10
NA
NA
NA
0
NA
1.36
NA
1.16
10
* L/LS-FGD and LSD-FGD absorbers for unit 6 would be located west
of unit 6.
24-8
-------
TABLE 24,2,1-4. SUMMARY OF NOx RETROFIT RESULTS FOR CHESTERFIELD
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
5
6
FIRING TYPE
TANG
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
39
NA
154.5
330
BOILER INSTALLATION DATE
1952
1960
1964
1969
SLAGGING PROBLEM
NO
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
29
43
71
116
New Duct Length (Feet)
250
400
600
500
New Duct Costs (1000$)
1324
2867
6280
7695
New Heat Exchanger (1000$)
1995
2722
4013
5960
TOTAL SCOPE ADDER COSTS (1000$)
3348
5633
10363
13770
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 3, 4 and 5 would be located
north of the unit 3 chimney. Cold side SCR reactors for unit 6
would be located west of unit 6.
24-9
-------
Table 24.2.1-5. MOx Control Cost Results for the Chesterfield Plant (June 1983 Dollars)
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
MOx
NOx
NOx Cost
Nunber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
(%3
Content
(WM3
{mills/kuh)
(X)
(tons/yr)
(I/ton)
Factor
-------
(%>
--------
LNC-OFA
3
1.00
112
27
1.0
0.6
5.8
0.1
0.5
25.0
193
711.5
LHC-OF*
4
1.00
188
58
1.0
0.8
4.2
0.2
0.2
25.0
694
242.8
LHC-OFA
5
1.00
359
67
1.0
1.0
2.9
0.2
0.1
25.0
1532
142.5
INC-OFA
6
1.00
694
46
1.0
1.3
1.9
0.3
0.1
25.0
2033
139.7
UIC-OFA-C
3
1.00
112
27
1.0
0.6
5.8
0.1
0.3
25.0
193
422.8
LNC-QFA-C
4
1.00
188
5B
1.0
0.8
4.2
0.1
0.1
25.0
694
144.2
INC-OFA-C
5
1.00
359
67
1.0
1.0
2.9
0.1
0.1
25.0
1532
84.6
LNC-OFA-C
6
1.00
694
46
1.0
1.3
1.9
0.2
0.1
25.0
2033
83.0
SCR-3
3
1.52
112
27
1.0
25.6
229.0
7.7
28.9
60.0
616
12431.2
SCR-3
" 4
1.52
iaa
58
1.0
37.8
200.9
11.7
12.3
80.0
2222
5283.5
SCR-3
5
1.52
359
67
1.0
62.5
174.0
20.1
9.6
80.0
' 4901
4111.1
SCR-3
6
1.16
694
46
1.0
86.7
125.0
30.3
10.9
80.0
6505
4665.6
SCR-3-C
3
1.52
112
27
1.0
25.6
229.0
4.5
17.0
80.0
616
7308.8
SCR-3-C
4
1.52
188
58
1.0
37.8
200.9
6.9
7.2
80.0
2222
3103.3
SCR-3-C
5
1.52
359
67
1.0
62.5
174.0
11.8
5.6
80.0
4901
2412.5
SCR-3-C
6
1.16
694
46
1.0
86.7
125.0
17.8
6.4
80.0
6505
2732.9
scr-7
3
1.52
112
27
1.0
25.6
229.0
6.7
25.5
80.0
616
10949.9
SCR-7
4
1.52
188
58
1.0
37.8
200.9
10.2
10.7
80.0
2222
4594.0
scr-7
5
1.52
359
67
1.0
62.5
174.0
17.2
8.2
80.0
4901
3514.2
SCR-T
6
1.16
694
46
1.0
86.7
125.0
24.7
8.8
80.0
6505
3796.2
SCR-7-C
3
1.52
112
27
1.0
25.6
229.0
4.0
15.0
80.0
616
6460.2
SCR-7-C
4
1.52
188
58
1.0
37.8
200.9
6.0
6.3
80.0
2222
2708.3
SCR-7-C
5
1.52
359
67
1.0
62.5
174.0
10.1
4.8
80.0
4901
2070.5
SCR-7-C
6
1.16
694
=S333X=
46
1.0
86.7
125.0
14.5
5.2
80.0
6505
2234.8
24-10
-------
24.2.2 Portsmouth Steam Plant
FGD retrofit factors were developed for units 3 and 4 at the Portsmouth
plant; however, costs are not shown since the boilers fire a low sulfur
coal. In addition, CS was not evaluated. Units 1 and 2 were not evaluated
because they are oil-fired.
TABLE 24.2.2-1. PORTSMOUTH 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
113 113
RESERVE SHUTDOWN
1953 1954
TANGENTIAL
PETROLEUM
BURNING
3
185
45
1959
FRONT WALL
84.7
NO
4
239
44
1962
TANGENTIAL
122
NO
WET
POND/OFF-SITE
2 3
RAILROAD
1.0
12800
7.5
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
NA ,
NA
NA
NA
NA
NA
NA
NA
ESP*
NA
NA
NA
NA
NA
NA
NA
NA
* The SCA size of the ESPs was assumed to be 300.
24-11
-------
TABLE 24.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR PORTSMOUTH
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 HIGH NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 1627,2047 NA 1627,2047
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1295,1673 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.41 NA
ESP REUSE CASE 1.43
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
. NEW BAGHOUSE NA NA NA
GENERAL- FACILITIES (PERCENT) 10 0 10
~
L/S-FGD and LSD-FGD absorbers for units 3 and 4 would be
located east of the chimneys behind the retrofit ESPs.
24-12
-------
TABLE 24,2.2-3. SUMMARY OF NOx RETROFIT RESULTS FOR PORTSMOUTH
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
FIRING TYPE
FNF
TANG
TYPE OF NOx CONTROL
LNB
OFA
FURNACE VOLUME (1000 CU FT)
84.7
122
BOILER INSTALLATION DATE
1959
1962
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
31
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
43
52
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1420
1650
New Heat Exchanger (1000$)
2696
3144
TOTAL SCOPE ADDER COSTS (1000$)
4159
4846
RETROFIT FACTOR FOR SCR
1.16
1.16 .
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for units 3
beside the retrofit ESPs.
and 4 would
be located
24-13
-------
Table 24,2.2-4. _,4ox Control Cost Results for the Portsmouth Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx MO* NOx Ccst
NuAer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CHWJ (%> Content (SUM) (1/kU) (SMI) (niIls/kyh) (X) {tons/yr) ($/tcn)
Factor (S>
LNC-LN8 3 1.00 185 45 1.0 3.3 17.6 0.7 0.9 31.0 912 756.5
INC-WB-C 3 1.00 185 45 1.0 3.3 17.6 0.4 0.6 31.0 912 449.5
INC-OFA 4 1.00 23? 44 1.0 0.9 3.7 0.2 0.2 25,0 664 279.4
LNC-OFA-C 4 1.00 239 U 1.0 0.9 3.7 0.1 0.1 25.0 664 • 166.1
SCR-3 3 1.16 185 45 1.0 28.7 155.3 9.6 13.1 80.0 2353 4060.3
SCR-3 4 1.16 239 44 1.0 35.1 146.7 11.7 12.7 80.0 2124 5520.9
SCR-3-C 3 1.16 185 45 1.0 28.7 155.3 5,6 7.7 80.0 2353 2381.0
SCR-3-C 4 1,16 239 44 1.0 35.1 146.7 6,9 7.5 80.0 2124 3237.2
SCR-7 3 1.16 185 45 1.0 28.7 155.3 8.1 11.0 80.0 2353 3420.5
SCR-7 4 1.16 239 44 1.0 35.1 146.7 9.8 10.6 80.0 2124 4604.8
SCR-7-C 3 1.16 185 45 1.0 28.7 155.3 4,7 6.5 80.0 2353 2014.4
SCR-7-C 4 1.16 239 44 1.0 35.1 146.7 5,8 6.3 80.0 2124 2712.2
24-14
-------
TABLE 24.2.2-5, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR PORTSMOUTH UNITS 3 AND 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 1627,2047
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$ 47,57
TOTAL COST (1000$)
ESP UPGRADE CASE 1674,2104
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
Long duct residence time exists between the boilers and
their respective ESPs, A low factor was assigned to ESP
upgrade since space is available.
24-15
-------
Table 24.2.2-6. Suimary of DSO/FSI Control Coses for Che Portsmouth Plant (June 1938 Dollars)
Technology Boiler Main Boiler
Nunber Retrofit Sfze
Difficulty (NU)
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
<*/kW> (WW)
(%)
Annual 502 502 S02 Cost
Cost Removed Removed Effect,
(mi I Is/kwh)
-------
24.2.3 Possum Point Steam Plant
Retrofit factors were developed for units 3 and 4 at the Possum Point
plant; however, costs are not shown due to the low sulfur content of the
coal. CS was not evaluated since the boilers currently fire a low sulfur
coal. Sorbent injection technologies (FSI and DSD) were not considered for
unit 3 due to the short duct residence time between the boilers and the
small size of the ESPs.
TABLE 24.2.3-1. POSSUM POINT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 12 3
GENERATING CAPACITY (MM) 69 69 114
CAPACITY FACTOR (PERCENT) RESERVE SHUTDOWN 31
INSTALLATION DATE 1948 1951
FIRING TYPE
FURNACE VOLUME (1000 CU FT) PETROLEUM
LOW NOx COMBUSTION BURNING
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER 1 2
COAL DELIVERY METHODS
4
239
50
1955 1962
TANGENTIAL
41 124
NO NO
1.0
12800
8.2
WET DISPOSAL
POND/ON-SITE
3 4
RAILROAD
882
6
1975
PETROLEUM
BURNING
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
1955
1982
0.2
0.02
95
99.7
1.0
0.7
44.6
615.6
360
951
124
647
300
265
24-17
-------
TABLE 24.2.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR POSSUM POINT
UNIT 3 *
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
YES
NA
NO
ESTIMATED COST (1000$)
1054
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
798
0
798
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.55
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.51
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 3
would be located south of unit 1.
24-18
-------
TABLE 24.2.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR POSSUM POINT
UNIT 4 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM NA MEDIUM
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 2047 NA 2047
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 1673 0 1673
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.55
NA
NA
GENERAL FACILITIES (PERCENT) 10
NA
NA
NA
0
1.58
NA
1.58
NA
10
* L/S-FGD and LSD-FGD absorbers for unit 4 would be located
south of unit 1.
24-19
-------
TABLE 24.2,3-4, SUMMARY OF NOx RETROFIT RESULTS FOR POSSUM POINT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
41
124
BOILER INSTALLATION DATE
1955
1962
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS --
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
30
52
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1070
16S0
New Heat Exchanger (1000$)
2016
3144
TOTAL SCOPE ADDER COSTS (1000$)
3116
4846
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
38
38
* Cold side SCR reactors for units 3
behind the chimney for that unit.
and 4 would
be located
24-20
-------
Table 24.2.3-5. NOx Control Cost Results for the Possun Point Plant (June 1908 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nuifcer Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW> <%> content (tWO ($/kU) (SHJO {mills/kwhj (X) (tons/yr) (S/ton)
Factor (X)
LWC-0FA 3 1.00 114 31 1.0 0.7 5.7 0.1 0.4 25.0 223 617.9
LNC-OFA 4 1.30 239 50 1.0 0.9 3.7 0.2 0.2 25.0 754 245.9
LMC-OFA-C 3 1,00 114 31 1.0 0.7 5.7 0.1 0.3 25.0 223 367.3
LNC-OFA-C 4 1.00 239 50 1.0 0.9 3.7 0.1 0.1 25.0 754 146.1
SCR-3 3 1.52 114 31 1.0 25.6 224.8 7.7 24.9 80.0 714 10813.0
SCR-3 4 1.52 239 50 1.0 43.4 181.7 13.8 13.2 80.0 2413 5726.0
SCR-3-C 3 1.52 114 31 1.0 25.6 224.8 4.5 14.7 80.0 714 6356.2'
SCR-3-C 4 1.52 239 50 1.0 41.4 1S1.7 8.1 7.7 80.0 2413 3361.3
SCR-7 3 1.52 114 31 1.0 25.6 224.8 6.8 21.9 80.0 714 9512.7
SCR-7 4 1.52 239 50 1.0 43.4 181.7 11.9 11.3 30.0 2413 4919.7
SCR-7-C 3. 1.52 114 31 1.0 25.6 224.8 4.0 12.9 80.0 714 5611.1
SCR-7-C 4 1.52 239 50 1.0 43.4 181.7 7.0 6.7 80.0 2413 2899.4
=sa:ssss=sssB3i8SS8SssaBssssssssssaass88Sss8SSSSsaS8SSssBssssaBaaaBSSsaBSSBsassaBS38aBssassas=assassssss=3s«s=s==s
24-21
-------
TABLE 24.2.3-6. . DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR POSSUM POINT UNIT 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2047
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 57
TOTAL COST (1000$)
. ESP UPGRADE CASE 2104
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
Short duct residence time exists between unit 4 and the
unit 4 retrofit ESPs. A high factor was assigned to ESP
upgrade since little space is available for upgrading.
24-22
-------
Table 24.2.3-7. Smmary of DSD/FSI Control Costs for the Possum Point Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuntoer Retrofit Size Factor sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HU) <%> Content <$MM> (tons/yr) (S/ton)
Factor
-------
I
i
i
-------
SECTION 25.0 WISCONSIN
25.1 DAIRY LAND POWER COOPERATIVE
25.1.1 Genoa #3 Steam Plant
The Genoa #3 steam plant is located on the Mississippi River in Vernon
County, Wisconsin, and is operated by the Dairy!and Power Cooperative. The
Genoa #3 plant contains one coal-fired boiler with a gross generating
capacity of 346 MW.
Table 25.1.1-1 presents operational data for the existing equipment at
the Genoa #3 plant. Coal shipments are received by barge and transferred to
a coal storage and handling area south of the plant. PM emissions are
controlled by ESPs installed at the time the unit was constructed. The ESPs
are located behind the boiler. Flue gases from the unit are directed to a
chimney behind the ESPs. Wet fly ash from the unit is disposed of in a pond
south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for the unit would be located at the north end of
the unit. The general facilities factor would be medium (8 percent) for the
FGD absorber location because of a plant road relocation. The site
access/congestion factor would be low for this location. Approximately
400 feet of ductwork would be required for installation of the L/LS-FGD
system. A low site access/congestion factor was assigned to flue gas
handling for the unit.
LSD with reuse of the existing ESPs was not considered for this unit
because of the small ESP size and poor performance of the existing ESPs, LSD
with a new FF was considered instead. The LSD absorbers would be located
similarly to the wet FGD absorbers with similar general facilities and site
access/congestion factors as well as ductwork requirements.
Tables 25.1.1-2 and 25.1.1-3 present the retrofit factors and cost
estimates for installation of FGD technologies at the Genoa #3 plant.
25-1
-------
TABLE 25.1.1-1. GENOA #3 STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1
GENERATING CAPACITY (MW-each)
346
CAPACITY FACTOR (PERCENT)
51
INSTALLATION DATE
1969
FIRING TYPE
TANGENTIAL
FURNACE VOLUME {1000 CU FT)
205
LOW NOx COMBUSTION
NO
COAL SULFUR CONTENT (PERCENT)
1.8
COAL HEATING VALUE (BTU/LB)
10500
COAL ASH CONTENT (PERCENT)
9.0
FLY ASH SYSTEM
WET DISPOSAL
ASH DISPOSAL METHOD
ON-SITE/SOLD
STACK NUMBER
1
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL
TYPE
ESP
INSTALLATION DATE
1969
EMISSION (LB/MM BTU)
0.2
REMOVAL EFFICIENCY
97.1
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
3.0
SURFACE AREA (1000 SQ FT)
173
GAS EXIT RATE (1000 ACFM)
1200
SCA (SQ FT/1000 ACFM)
144
OUTLET TEMPERATURE (eF)
335
25-2
-------
TABLE 25.1.1 2. SUMMARY OF RETROFIT FACTOR DATA FOR GENOA #3
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
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$)
2853
NA
0
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.38
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.27
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
25-3
-------
Table 25.1.1-3, Surmary of FGD Control Costs for the Genoa Plant (June 1968 Dollars!
Technology Boiler Main Bolter Capacity Coal Capital Capital Annual Annual S02 SQ2 S02 Cost
Nunber Retrofit Siie Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) <%) Content <$KMJ
-------
Coal Switching and Physical Coal Cleaning Costs-
Table 25.1.1-4 presents the IAPCS cost results for CS at the Genoa #3
plant. These costs do not include the effect of any changes to the boiler
and pulverizer operation. PCC was not considered at the Genoa #3 plant
because it is not a mine mouth plant.
NQX Control Techno!ogies--
The Genoa #3 unit 1 is a dry bottom, tangential-fired boiler rated at
346 MW. OFA was considered for NOx emission control at the Genoa #3 plant.
Performance and cost estimates developed for OFA at unit 1 are presented in
Tables 25.1.1-5 and 25.1.1-6.
Selective catalytic Reduction-
Hot side SCR reactors for the Genoa #3 plant would be located north of
the unit close to the ESPs. A medium general facilities value (20 percent)
was assigned to the location. A low site access/congestion factor was
assigned to the absorber location. Approximately 200 feet of ductwork would
be required to span the distance between the SCR reactors and the chimney.
Tables 25.1.1-5 and 25.1.1-6 present the retrofit factors and cost for
installation of SCR at the Genoa #3 plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Genoa #3 plant because of the insufficient duct residence time between
the boilers and the ESPs and the small sizes of the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The 346 MW boiler at the Genoa #3 plant is large and has a long
remaining service life and would not likely be considered as a near term
candidate for AFBC/CG repowering.
25-5
-------
Table 25.1.1-4. Summary of Coat Snitching/Cleaning Costs for the Genoa Plant (June 1988 Dollars)
Technology ' Bailer Hain Boiler Capacity Coat Capital Capital Annual Annual ' S02 S02 S02 Cost
Muifcer Retrofit Site Factor Suifur Cost Cost Cost Cost RwnovwJ Removed Effect.
Difficulty (MW) (X) Content (JMM) (WttO (mUlsAwh) <%> (tans/yr) (S/ton)
Factor <%)
CS/B+115 1 1.00 346 51 1.8 15.1 43.5 23.6 ' 15.3 57.0 15003 1574.1
CS/8+S15-C 1 1.00 346 51 1.8 15.1 43.5 13.6 8.8 57,0 15003 906.4
CS/B»$5 1 1.00 .346 51 1.8 11.5 33.2 10.2 6.6 57.0 15003 681.2
CS/B+$5-C 1 1.00 346 51 1.8 11.5 33.2 5.? 3.8 57.0 15003 393.7
25-6
-------
TABLE 25.1.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR GENOA #3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
TYPE OF NOx CONTROL
FURNACE VOLUME {1000 CU FT)
BOILER INSTALLATION DATE
SLAGGING PROBLEM
ESTIMATED NOx REDUCTION (PERCENT)
SCR RETROFIT RESULTS .
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 69
New Duct Length (Feet) 200
New Duct Costs (1000$) 2048
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$) 2117
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20_
1
TANG
OFA
205
1969
NO
25
25-7
-------
Table 25.1.1-6. MO* Control Cost Results for the Genoa Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx NO* Cost
Nuifcer Retrofit size Factor Sulfur cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU> (X> Content ($XM>
LNC-OFA
1
1.00
346
51
1.8
no .
2,9
0.2
0.1
25.0
1398
155.5
IHC-OFA-C
1
1.00
346
51
1.8
1.0
2.9
0.1
0.1
25.0
1398
92.4
sea-3
1
1.16
346
51
1.8
41.9
121.2
15.6
10.1
SO. 0
4473
3489.6
SCR-3-C
1
1.16
346
51
1.8
41.9
121.2
9.1
5.9
ao.o
4473
2041.3
SCR-7
1
1.16
346
51
1.8
41.9
121.2
12.7
8,2
80.0
4473
2841.3
SCB-7-C
1
1.16
346
51
1.8
41.9
121.2
7.5
4.3
80.0
4473
1669.9
25-8
-------
25.2 WISCONSIN ELECTRIC POWER COMPANY
25.2.1 North Oak Creek Steam Plant
The North Oak Creek steam plant is located on Lake Michigan in
Milwaukee County, Wisconsin, and is operated by the Wisconsin Electric Power
Company. The North Oak Creek plant contains four coal-fired boilers with a
gross generating capacity of 500 MW. Units 3 and 4 are retired and units 1
and 2 will be retired in 1990.
Table 25.2.1-1 presents operational data for the existing equipment at
the North Oak Creek plant. Coal shipments are received by railroad and
transferred to two coal storage and handling areas east and west of the
plant. PM emissions are controlled by retrofit ESPs located behind the
boilers. Flue gases from units 1 and 2 are directed to one chimney and flue
gases from units 3 and 4 are directed to another chimney. Both chimneys are
located behind the ESPs. Dry fly ash is stored in silos.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1-2 would be located at the north end of
the plant between the two coal piles. The general facilities factor would
be high for the FGD absorber location because relocation of a storage silo
and demineralization building would be necessary. The site
access/congestion factor would be medium for the L/LS-FGD absorber
locations. Because of the difficulty in accessing the old chimneys and the
length of ductwork that would be required, a new chimney would be
constructed at the north end of the plant. After construction of the new
chimney, close to 600 feet of ductwork would be required for installation of
the L/LS-FGD system for units 1 and 2. A high site access/congestion factor
was assigned to flue gas handling for all units because of the obstruction
caused by the coal conveyor and the congestion around the existing chimneys.
LSD was not considered for the North Oak Creek plant because of the
lack of access to the ductwork between the boilers and the ESPs and the
small size of the existing ESPs. LSD with a new baghouse was not considered
because of the medium to high sulfur content of the coal being burned at the
plant.
25-9
-------
TABLE 25.2.1-1. NORTH OAK CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER+
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)*
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2
120
28,32
1953,54
ARCH
107
NO
1.6
12200
7.2
DRY DISPOSAL
ON-SITE/STORED
1
RAILROAD
3,4
130
RETIRED
1957
ARCH
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.5
SURFACE AREA (1000 SQ FT) 123.1
GAS EXIT RATE (1000 ACFM) 600
SCA (SQ FT/1000 ACFM) 205
OUTLET TEMPERATURE ('F) 290
ESP
1970
0.03,0.07
99.4,99.2
+ Units 1 and 2 will be retired in 1990, units 3 and 4 were
retired in 1988.
* Based on 1988 data.
25-10
-------
Table 25.2.1-2 presents the retrofit factors for installation of
L/LS-FGD at the North Oak Creek plant. Costs were not developed because
both units will be retired soon.
Coal Switching and Physical Coal Cleaning Costs-
Costs were not devloped for CS because both units will be retired soon.
N0X Control Technologies--
Both units are dry bottom, arch-fired boilers having low N0x emission
levels. As such, LNC technologies were not considered for this plant.
Selective Catalytic Reduction
Cold side SCR reactors for the North Oak Creek plant would be located
beside the chimneys toward the coal pile. High site access/congestion and
general facility factors (38 percent) were assigned to the SCR reactor
locations. Approximately 300 feet of ductwork would be required for the SCR
reactors. Table 25.2.1-3 summarizes the retrofit factors for installation
of SCR at the North Oak Creek plant. Again, costs were not presented since
the units will be retired soon.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the North Oak Creek plant because of the lack of access to the ductwork
between the boilers and the ESPs and the small size of the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All boilers at the North Oak Creek plant would be good candidates for
AFBC/CG repowering because of their small boiler sizes (120-130 MW) and
likely short remaining useful lives.
25-11
-------
TABLE 25.2.1-2. SUMMARY OF RETROFIT FACTOR OATA FOR
NORTH OAK CREEK UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
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
NO
NA
NA '
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NA
ESTIMATED COST (1000$)
840
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
0
25-12
-------
TABLE 25,2,1-3. SUMMARY OF NOx RETROFIT RESULTS FOR NORTH OAK CREEK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 3,4
FIRING TYPE
ARCH
ARCH
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
106
107,106
BOILER INSTALLATION DATE
1953,54
1955,57
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
o
0
Ductwork Demolition (1000$)
' 31
33
New Duct Length (Feet)
300
300
New Duct Costs (1000$)
1654
1733
New Heat Exchanger (1000$)
2079
2182
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
3764
5685
3948
5962
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
38
38
25-13
-------
25.2.2 Pleasant Prairie Steam Plant
Retrofit factors were developed for the two units at the Pleasant
Prairie plant, however, costs are not presented since the low coal sulfur
content would yield low capital/operating costs and high cost per ton of SO^
removal. Sorbent injection technologies were not considered because of the
short duct residence time between the boilers and ESPs and difficulties in
upgrading the existing ESPs due to the congestion around the units.
TABLE 25.2.2-1. PLEASANT PRAIRIE STEAM PLANT OPERATIONAL DATA *
BOILER NUMBER
1,2
GENERATING CAPACITY (MW-each)
617
CAPACITY FACTOR (PERCENT)
68,74
INSTALLATION DATE
1980,1985
FIRING TYPE
OPPOSED WALL
FURNACE VOLUME (1000 CU FT)
869.9
LOW NOx COMBUSTION
YES
COAL SULFUR CONTENT (PERCENT)
0.4
COAL HEATING VALUE (BTU/LB)
8400
COAL ASH CONTENT (PERCENT)
6.4
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
SOLD/ON-SITE
STACK NUMBER
1
COAL DELIVERY METHODS
RAILROAD
PARTICULATE CONTROL
TYPE
ESP
INSTALLATION DATE
1980,1985
EMISSION LB/MM BTU)
0.03,0.01
REMOVAL EFFICIENCY
<100
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
0.4
SURFACE AREA (1000 SQ FT)
1223.4
GAS EXIT RATE (1000 ACFM)
4000
SCA (SQ FT/1000 ACFM)
306
OUTLET TEMPERATURE ("F)
280
* Based on 1988 data.
25-14
-------
TABLE 25.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR PLEASANT PRAIRIE
UNIT 1*
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.31 NA
ESP REUSE CASE 1.47
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
* Absorbers for unit 1 would be located beside the common
chimney.
25-15
-------
TABLE 25.2.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR PLEASANT PRAIRIE
UNIT 2*
FGD TECHNOLOGY
forced lime
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE ' 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 "l_
FGD SYSTEM 1.31 NA
ESP REUSE CASE 1.31
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
* Absorbers for unit 2 would be located beside the common
chimney.
25-16
-------
TABLE 25.2,2-4, SUMMARY OF NOx RETROFIT RESULTS FOR PLEASANT PRAIRIE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
1-2
FIRING TYPE
OWF
OWF
NA
TYPE OF NOx CONTROL
EQUIPPED WITH LNB
NA
FURNACE VOLUME (1000 CU FT)
869.9
869.9
NA
BOILER INSTALLATION DATE
1980
1985
NA
SLAGGING PROBLEM
NA
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
NA
SCR RETROFIT RESULTS*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0 .
0
Ductwork Demolition (1000$)
106
106
178
New Duct Length (Feet)
300
200
250
New Duct Costs (1000$)
4310
2873
5388
New Heat Exchanger (1000$)
5554
5554
8418
TOTAL SCOPE ADDER COSTS (1000$)
9970
8533
13983
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for both units would be located beside the
common chimney.
25-17
-------
Table 25.2.2-5. NOx Control Cost Results for the Pleasant Prairie Plant (June 1963 Dollars)
¦HSflB&aa&assnxsstassESBSEsanKEataaBsxaHBasaBSSSBSsssassisssssaasssssssssasssssassssssssssssassssssssssssssssssssss!
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nuifaer Retrofit Size factor Sulfur cost Cost Cost Cost Removed Removed Effect.
Difficulty CMW) IX) Content (SJW) (MM) (milla/kwh) (X) Ctons/yr) (S/ton)
Factor (S)
SCR-3 •
1
1.16
617
66
0.4
77.0
124.7
29.8
8.1
80.0
19237
1548.4
SCR-3
1.16
617
74
0.4
75.5
122.4
29.9
7.5
80.0
20934
1426.0
SCR-3
1-2
1.16 '
1234
71
0.4
142.1
115.1
57.2
7.5
80.0
40171
1424.2
SCR-3-C
1
1.16
617
6a
0.4
77.0
124.7
17.4
4.7
80.0
19237
905.1
SCR-3-C
1.16
617
74
0.4
75.5
122.4
17.4
4.4
80.0
20934
833.2
SCR-3-C
1-2
1.16
1234
71
0.4
142.1
115.1
33.4
4.4
80.0
40171
831.8
SCR-7
1
1.16
617
68
0.4
77.0
124.7
24.4
6.7
ao.o
19237
1270.6
SCR-7
1.16
617
74-
0.4
75.5
122.4
24.5
6.1
80.0
20934
1170.6
SCR-7
1.-2
1.16
'1234 '
71
0.4
142.1
115.1
46.5
6.1
80.0
40171
1158.1
SCR-7-C •
1.16
617
68
0.4
77.0
124.7
14.3
3.9
80.0
19237
745.9
SCR-7-C
1.16
617
74
0.4
75.5
122.4
14.4
3.6
io.o
20934
686.9
SCR-7-C
1-2
1.16
S8K1I8I
1234
71
0.4
142.1
115.1
27.3
1 3.6
SS5BS988I!
80.0
40171
679.4
25-18
-------
25.2.3 Port Washington Steam Plant
The Port Washington steam plant 1s located within Ozaukee County,
Wisconsin, as part of the Wisconsin Electric Power Company system. Located
on the western side of Lake Michigan, the plant contains five coal-fired
boilers with a total gross generating capacity of 400 MW.
Table 25.2.3-1 presents operational data for the existing equipment at
the Fort Washington plant. The boilers burn medium sulfur coal. Coal
shipments are received by barge and transferred to a coal storage and
handling area east of the plant and adjacent to the lake.
PM emissions for the boilers are controlled with retrofit ESPs located
behind each unit. The plant has a dry fly ash handling system. Fly ash is
disposed of in a landfill five miles away from the plant. Bottom ash is
dewatered in a settling basin east of the plant and south of the coal pile
and then trucked to a landfill with the fly ash. Units 1 through 3 are
served by a common chimney while units 4 and 5 are served by another
chimney.
Lime/Limestone and Lime Spray Drying FGD Costs--
The five boilers are located beside each other parallel to Lake
Michigan. The absorbers for units 1 through 5 would be located behind the
chimneys south of the settling basin. The limestone preparation, storage,.
and handling area would be located behind the absorbers. Some of the roads
east of the plant and the bottom ash settling pond would have to be
relocated; therefore, a factor of 15 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 absorbers would have to be disposed of off-site in the
same manner as the fly ash.
A high site access/congestion factor was assigned to the FGD absorber
locations due to the access difficulty to this area created by the water
intake, discharge channel, and the units. The area is surrounded by water
from three sides making it difficult to access.
For flue gas handling, because the absorbers are placed behind the
chimneys, short duct runs would be required (about 200 feet). A high site •
25-19
-------
TABLE 25.2,3-1. PORT WASHINGTON STEAM PLANT OPERATIONAL DATA*
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR
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
80
9,23,18,20,10+
1935,43,48,49,50
ARCH-FIRED
72
NO
1.6
13200
6.0
DRY HANDLING
OFF-SITE
7.7.7.6.6
SHIP
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
1965-68
0.05-0.1
98.6-99.3
3.1
87,87,87,91,87
450
193,193,193,202,193
390,450,450,390,390
* Based on 1988 data.
+ 1985 data used for boiler 5.
25-20
-------
access/congestion factor was assigned to the flue gas handling system due to
access difficulty for this location.
LSD with reuse of the existing ESPs was not considered for this plant
because the ESPs are small (SCA*193) and would require major upgrading and
plate area additions to handle the increased PM generated from the LSD
application. LSD with a new baghouse was also 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 25.2.3-2. Table 25.2,3-3 presents
the capital and operating costs for commercial FGD technologies. The low
cost FGD option reduces capital costs due to combining the FGD systems,
eliminating spare absorber modules, and maximizing the absorber modules
s i ze.
Coal Switching and Physical Coal Cleaning Costs-
Table 25.2.3-4 presents the IAPCS cost results for CS at the Port
Washington 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
Units 1 through 5 are dry bottom, arch-fired boilers rated at 80 MW
each. The arch-fired boilers have very low NO levels (<0.5 lb per million
A
Btu). As such, LNC technologies were not considered for the Port Washington
boilers.
Selective Catalytic Reduction--
Cold side SCR reactors for all units would be located immediately
behind the chimneys. All five reactors are located in high site congestion
areas for the same reasons as were outlined in the FGD section. All
reactors were assumed to be in areas with high underground obstructions.
Duct lengths of 200 feet would be required for the unit 1 through 5 SCR
reactors. Because a plant road and part of the bottom ash pond relocation
was required, a factor of 38 percent was assigned to general facilities.
The ammonia storage system was placed close to the reactors east of the
plant.
25-21
-------
TABLE 25.2.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR PORT WASHINGTON UNITS 1-5
(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
8AGH0USE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
. NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.53
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA ,
GENERAL FACILITIES (PERCENT)
15
0
0
25-22
-------
Table 25.2.3-3. Surmary of FfiD Control Costs for the Port Washington Plant (June 1988 Dollars)
¦I
II
II
II
II
II
II
II
II
li
(1
S3*SS3»*S
:=sassassi
SSSS3SSS
isssaastsi
S3 BS3B#S!
ssaatssBSs
ssassssa:
;ssassss
II
II
II
H
II
II
II
II
II
(1
il
ssss:s
s==sss=a==:
S=S3S3S==
technology
BoiUr
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)
<*)
Content
(*/kV>
(»W)
(mills/kMtij
m
(tons/yr)
Ct/ton!
Factor
. <*J
LC Fffl
t-5
1.53
400
16
1.6
71.3
178.3
26.3
46.9
90.0
5838
4504.3
IC FGD-C
1-5
1.53
400
16
1.6
71.1
178.3
15.4
27.4
90.0
5838
2635.5
IFGO
1
1.53
80
9
1.6
39.2
490.6
13.7
217.3
90.0
657
20870.6
LFGO
2
1.53
80
23
' 1.6
39.5
494.0
14.6
90.8
90.0
1678
8721.3
IF 60
3
1.53
80
18
1.6
39.5
493.9
14.3
113.7
90.0
1314
10923.?
LFGD
4 .
1.53
80
20
1.6
39.3
490.8
14.4
102.7
90.0
1460
9865.9
LFGD
5
1.53
80
10
1.6
J9.3
490.6
13.8
196.6 ¦
90. a
730
18877.7
LFGO
' 1-5
1.53
400
16
1.6
95.7
239.3
33.9
60.4
90.0
5838
5804.3
LFGD
1-3
1.53
240
17
1.6
69.8
290.8
24.9
69.7
90,0
3722
6691.6
LFGD
4-5
1.53
160
15
1.6
54.6
341.5
19.4
92.3
90.0
2189
8867.?
LFGO-C
1
1.53
80
9
1.6
39.2
490.6
¦ 8.0
127.3
90.0
657
12225.3
LFGD-C
2
1.53
80
23
1,6
39.5
494.0
S.6
53.1
90.0
1678
5102.3
LFGD-C
3
1.53
80
18
¦1.6
39.5
493.9
8.4
66.6
90.0
1314
6393.5
LFGO-C
4
1.51
80
20
1.6
39.3
490.8
8.4
60.1
90.0
1460
5773.1
LFGD-C
5
1.53
80
10
'1.6
39.3
490.6
8.1
115.1
90,0
730
11056.8
LFGB-C
1-5
1.53
400
¦ 16
1.6
95.7
239.5
19.8
35.4
90.0
5828
3399.0
LFCO-C -
. j-3
1.53
240
1?
1.6
69.8
290.8
14.6
40.8
90.0
3722
3917.9
LFGD-C
4-5
' 1.55
160
15
1.6
54.6
341.5
11.4
54.1
90.0
2189
5192.5
25-23
-------
Table 25.2.3-4. Surmary of Coat Switching/Cleaning Costs for the Port Washington Plant Nine 1988 Dollars)
Technology
Boiler
Main
Boiler Calcify Coal
Capital Capital Annual
Annual
SQ2
S02
S02 Cost
Number
Retrofit-
Size
Factor
Sulfur
Cost
Cost
Coat
Cost
Removed Removed
Effect,
Difficulty (HH)
(%>
Content
(SHH)
(S/W)
(SMM)
(mills/kwh)
(X)
(tora/yr)
(S/ton)
_
mmm
Factor
-------
ay
........
.........
CS/B+$15
1
1.00
80
9
1.6
4.3
54.0
1.9
30.4
38.0
274
6978.9
CS/B*S15
2
1.00
SO
a
1.6
4.2
52.0
3.3
20.2
38.0
701
4635.9
CS/B*S15
3
1.00
80
18
1.6
4.2
52.0
2.6
21.9
38.0
549
5028.8
C5/B+I15
4
1.00
80
20
1.6
4.3
53.1
3.0
21.2
38.0
610
4884.1
CS/B+S15
5
1.00
80
10
1.6
4.3
54.0
2.0
28.7
38.0
305
6603.2
CS/B*115-C
1
1.00
80
9
1.6
4.3
54.0
1.1
17.7
38.0
274
4069.0
CS/B**15-C
2
1.00
80
23
1.6
4.2
52.0
1.9
11.7
38.0
701
2682.5
CS/B+S15-C
3
1.00
80
.18
¦ 1.6
4.2
52.0
1.6
12.7
38.0
549
2915.2
CS/B+S15-C
4
1.00
80
20
1.6
4.3
53.1
1.7
12.3
38.0
610
2829.6
CS/B*S15-C
5
1.00
80
10
1.6
4.3
54.0
1.2
16.7
38.0
. 305
3846.8
CS/B*S5
1
1.00
80
9
1.6.
3.5
43.6
1.2
19.8
38.0
274
4549.7
CS/B*S5
2
1.00
80
23
1.6
3.3
41.6
1.8
11.0
38.0
701
2529.9
CS/B+S5 •
3
1.00
80
18
1.6
3.3
41.6
1.6
12.5
38.0
549
Z865.3
CS/B+S5
• 4
1.00
80
20
1.6
3.4
42.8
1.7
11.9
38.0
610
2746.9
CS/B+S5
,5
1.00
80
10
1.6
3.5
43.6
1.3
18.4
38.0
305
4227.6
CS/8+S5-C
1
1.00
80
9
1.6
3.5
43.6
0.7
11.6
38.0
274
2663.9
CS/B+S5-C
2
1.00
80
23
1.6
3.3
41.6
1.0
6.4
38.0
701
1470.7
CS/B«»5-C
3
1.00
80
18
1.6
3.3
41.6
0.9
7.3
38.0
549
1668,9
CS/B+I5-C
4
1.00
80
20
1.6
3.4
42.8
1.0
7.0
38.0
610
1599.0
CS/B+J5-C
5
1.00
80
10
1.6
3.5
43.6
o.a
1C.8
38.0
305
2473.3
25-24
-------
Table 25.2.3-5 presents the SCR process area retrofit factors and scope
adder costs. Table 25.2.3-6 presents the estimated cost of retrofitting SCR
at the Port Washington boilers.
Duct Spray Drying and Furnace Sorbent Injection--
• The retrofit of FSI and DSD technologies at the Port Washington steam
plant for all units would be difficult for two major reasons: 1) The ESPs
have small SCAs (<200) and probably would not be able to handle the
increased PM thereby requiring major upgrading and plate area additions;
2) the short duct residence time between the boilers and ESPs would not be
sufficient for either huiridification (for FSI application) or sorbent
droplet evaporation (for DSD application). Therefore, costs were not
developed for sorbent injection technologies for the Port Washington 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 Port Washington plant. All units might be considered
candidates for repowering retrofit because of their small boiler sizes,
age, and low capacity factors.
25.2.4 South Oak Creek Steam Plant
The South Oak Creek steam plant is located on Lake Michigan, south of
the North Oak Creek plant, in Milwaukee County, Wisconsin, and is operated
by the Wisconsin Electric Power Company. The South Oak Creek plant contains
four coal-fired boilers with a gross generating capacity of 1,170 MW.
Table 25.2.4-1 presents operational data' for the existing equipment at
the South Oak Creek plant. Coal shipments are received by barge and
transferred to a coal storage and handling area northeast of the plant. PM
emissions are controlled by retrofit ESPs for units 5 and 6 and ESPs
installed at the time of construction for units 7 and 8 (retrofit ESPs are
currently being installed for units 7 and 8). Flue gases from the units 5
and 6 are directed to one chimney and flue gases from units 7 and 8 are
directed to another chimney. Both chimneys are located behind the ESPs.
Dry fly ash is stored in silos.
25-25
-------
TABLE 25.2.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR PORT WASHINGTON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1-5 (each)
FIRING TYPE ARCH
TYPE OF NOx CONTROL NA
FURNACE VOLUME (CUBIC FT) NA
BOILER INSTALLATION DATE 1935-50
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS-- •
Building Demolition (1000$)
Ductwork Demolition (1000$)
New Duct Length (Feet)
New Duct Costs (1000$)
New Heat Exchanger (1000$)
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL
COMBINED (1-3)
COMBINED 4-5
COMBINED (1-5)
RETROFIT FACTOR FOR SCR
GENERAL FACILITIES (PERCENT) .
0
23
200
870
1630
2523
3814
4858
6588
1.52
38
25-26
-------
Table 25,2.3-6. NO* Control Cost Results for the Part Washington Plant (June 1983 Collars)
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NO*
IIO* Cost
Nunber Retrofit
Si ze
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
(mi tls/kwh)
(St)
Jtoris/yr)
• <$/:on)
Factor
<%5
SCR-3
1
1.52
80
9
.1-6
20.7
259.0
6.1
96.8
80.0
140 ¦
43494.0
SCS-J
2
" 1,52
80
23
1.6
21.0
262.3
6.2
38.5 '
80.0
359
17314.9
SCR-3
3
1.52
80
¦ 18
1.6
21.0
262.3
. 6.2
49,1
80.0
281
22064.4
SCR-3
4
1.52
80
20
1.6
20.7
259.0
6.1
43.8
80.0 .
312
19689.3
SCR-3
5
1.52
SO
10
1.6
20.7
259.0
6.1
87.2
ao.o
156
39167.7
SCR-3
1-3
1.52
240
17
1.6
43.3
180.6
13.6
38.1
80.0
795
17139.1
S'CR-3
' 4-5
1.52
160
15
1.6
33.6
210.1
10.1
48.2
80.0
, 468
21676.5
SCR-3
1-5
1.52
400
16
1.6
64.2
160.6
20.6
36.8
80.0
1248
16547.0
SCR-3-C
1
- . 1.52
80
9
1.6
20.7
259.0
3.6
56.9
ao.o
140
25580.8
SCR-3-C ,
2
1.52,
eo
23
. 1.6
21.0
262.3
3.7
22.7
80.0
. 359
10182.5
SCR-3-C
3
. 1.52
60
18
1.6
21.0
262.3
3,6
28.9
80.0
231
12976.7
SCR-3-C
' 4
.1.52
B0
20
1.6
20.7
259.0
3.6
25.8
ao.o
312
11578.7
SCR-3-C
5
' 1.52
80
10 •
1.6
20.7
259.0
3.6
' 51.3
80.0
156
.23036.2
SCR-3-C
1-3
• 1.52
240
17
1.6
43.3
180.6
8.0
22.4
bo. a
795
'10063.9
SCR-3-C
4-5
1.52
160
15
1.6
33.6
•210.1
6.0
28.4
80.0
468
12741.2
SCR-3-C
1-5
1.52
400
16
1.6
64.2
.160.6
12.1
21.6
80.0
1248
971* 1.1
SCR-7
1
1.52
80
' 9
1.6
19.6
244.8
5.2
82.0
80.0
140
36835.3
SCR-7
2
1.52
BO
23
1.6
21.0
262.3
5.6
34.1 •
80.0
359
15507.4
SCR-7
3
1.52
80
18
1.6
21.0
262.3
5.5
44.0
80.0
281
19755.1
SCR-7
4
1.52
80
, 20
1.6
20.7
259.0
5.5
39.2
80.0
312
17610.9
SCR-7
5
1.52.
80
10
1.6
20.7
259.0
5.5
77.9
80.0
156
35010.2
SCR-7
1-3
1.52
240
17
1.6
.43,3
180.6
11.7
32.7
80.0
795
14693.7
SCR-7
4-5
1.52
160
' 15
1.6
33.6
210.1
8.8
: 42.1
80.0
468
18904.8-
SCR-7
1-5
1.52
4 DO
16
' 1.6
64.2
160.6
17.4
31.0
80.0
1248
13949.0
SCR-7-C
1
1.52
80
9 '
1.6
19.6
244.8
3.0
48.4
80.0
140
21729.5
SCR-7-C
2
1.52
80
23
1.6
21.0
262.3
3.3
20.4
80.0
359
9146.9
SCR-7-C
3
1.52
80
18
1.6
21.0
262.3
3,3
25.9
80.0
281
11653.6
SCR-7-C
-4
. 1.52
80
20
1.6
20.7
259.0
3.2
23.1
80.0
312
10387.8
SCR-7-C ••
5
' '1.52
80
10
1.6
20.7
259.0
3.2
46.0 ¦
80.0
156
20654.5
SCR-7-C
1-3
1.52
240
17
1.6
43.3
180.6
6.9
19.3
ao.o
795
8662.7
SCR-7-C
4*5
1.52
160
. 15
1.6
33.6
210.1
5.2
24.8
80.0
468
11153.4
SC8-7-C
1-5
1.52
400
16
1.6
64.2
160.6
10.3
18.3
80.Q
.1248
8222.6
1!
II
11
II
II
11
II
II
»
II
II
II
II
II
II
II
It
11
II
II
==========
II
11
II
II
II
11
II
M
II
II
II
II
,-==a=s-=
,======3-
========
.===¦===
:==.*=======
II
11
11
II
II
It
:==========
If
II
II
11
H
II
25-27
-------
TABLE 25.2.4-1. SOUTH OAK CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
5,6
7,8
275
310
58,43
48,38
1959,61
1965,67
ARCH
TANGENTIAL
172
136
NO
LNC+
1.6
1.6
12200
12200
7.2
7.2
DRY DISPOSAL
STORED IN SILOS
3 4
BARGE
PARTICULATE CONTROL
"TYPE
ESP
ESP
INSTALLATION DATE
1972
1965,67
EMISSION (LB/MM BTU)
0.09,0.01
0.09,0.10
REMOVAL EFFICIENCY
98.6,98.9
98.5,98.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
2.0
2.5
SURFACE AREA (1000 SQ FT)
413.3
155.5
GAS EXIT RATE (1000 ACFM)
1200
840
SCA (SQ FT/1000 ACFM)
344
185
OUTLET TEMPERATURE (*F)
280
275
* Based on 1988 data.
+ Installed in 1985-86.
25-28
-------
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for all of the units would be located at the south
end of .the plant close to retrofit ESPs. The general facilities factor
would be medium (10 percent) for the FGD absorber location because
relocation of some storage buildings and roads would be necessary. The site
access/congestion factor would be medium for the L/LS-F6D absorber location.
More than 1000 feet of ductwork would be required for installation of the
L/LS-FGD system for units 5 and 6 and 500 feet would be required for units 7
and 8. A high site access/congestion factor was assigned to flue gas
handling for all units because of the proximity of Lake Michigan and the
obstruction caused by the ash silos and the unit 7 and 8 chimney. A new
chirnney would be constructed beside the absorbers to reduce duct length and
congestion created around the units.
LSD with reuse of the existing ESPs was not considered for the South
Oak Creek plant because of the lack of access to the ductwork between the
boilers and the ESPs.
Tables 25.2.4-2 through 25.2.4-4 present the retrofit factors and cost
estimates for installation of L/LS-FGD at the South Oak Creek plant.
Coal Switching and Physical Coal Cleaning Costs--
Table 25.2.4-5 presents the IAPCS cost results for CS at the South Oak
Creek plant. PCC was not considered at the South Oak Creek plant because it
is not a mine mouth plant. These costs do not include changes in boiler and
pulverizer operating cost changes or any system modifications that may be
necessary for coal handling.
NQX Control Technologies--
Units 5 and 6 are arch-fired boilers having low N0X emission levels and
were not considered for LNC. Units 7 and 8 were retrofitted with LNC in
1985-86. .
Selective Catalytic Reduction-
Cold side SCR reactors for units 5-7 would be located behind the
respective ESPs and close to the chimneys. SCR reactors for unit 8 would be
located close to the unit, south of the retrofit ESPs. A high general
25-29
-------
TABLE 25.2.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR
SOUTH OAK CREEK UNIT 5 OR 6
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM NA NA
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 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$) 1925 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.82 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 0 0_
25-30
-------
TABLE 25.2.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR
SOUTH OAK CREEK UNIT 7 OR 8
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
NA
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA,
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA ;
NA .
ESTIMATED COST (1000$)
2170
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.52
NA
ESP REUSE CASE
NA
- BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
0
25-31
-------
Table 25.2.4-4, smmary of fgo Control Costs for the South Oak Cretk Plant (June 1988 Dollars}
:sssss:=:s£ss:
======
II
(1
li
<1
II
II
If
11
II
fl
II
II
II
II
II
M
M
II
U
H
M
II
IIBBS88X!
<8889332
Itttuaimi
StlSSS
SS5SSHH
Technology
Boiler
Main
Boiler Capacity Coal
Capi tal
Capital Annual
Annual •
502
S02
S02 Cast
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW)
(X)
Content
(SHM)
(I/kuj
(SMM)
(mills/kuh)
(tons/yr)
($/ton)
......
Factor
......
........
(X)
........
........
.......
......
..........
L/S FGD
5
t .82
275
58
1.6
93.6
340.4
38.5
27.6
90.0
. 15927
2419.5
L/S FGO
6
' t .82
275
43
1.6
93.6
340.3
36.4
35.2
90.0
11808
3084,0
L/S FGD
7
1.52
310
48
1.6
84.9
273.9
35.1
26.9
90.0
14859
2359.7
L/S FGD
8 •
1.52
310
38
1.6
84,9
273.8
33.5
32.4
90.0
11763
2846.1
US FGD
5-6
1.82
550
50 .
1.6
143,5
261,0
59.0
24,5
90.0
27460
. 2147.8
L/S FGD
7-8
1.52
620
43
1.6
131.9
212.8
• 54.6
¦ 23.4
90.0
26621
2052.2
L/S FGO-C
5
1.82
275
58
1.6
.93.6
340.4
22.5
16.1
90.0
. 1592?
1412.6
L/S FGD-C
6
1.82
275
43
1.6
. 93.6
340.3
21.3
20.5
90.0
11808
1802.5
L/S FGD-C
7
1.52 •
310
48
1.6
84,9
273 .9
20.5
15.7
90.0
14859
1377.6
L/S FGD-C '
a
! 1.52
31(3
38
1.6
84.9
273.8
. 19.6
19.0
90.0
11763
1663.0'
L/S FGD-C
• 5-6
1.82
550
50
1.6
143.5
261.0
34,4
14.3
90.0
¦ 27460
1254,0
L/S FGD-C
7-8
1.52
620
43
1.6
131.9
212.8
31.9
13.7
90.0
26621 .
1198.0
LC FGD
5-8
1.66
1170
47
1.6
198.1
169.3
87.5
18.2
90.0
54910
1593.5
LC FGD-C
. 5"8
SSSS8SS
1.66
1170
47
1.6
198.1
169.3
51.0
10.6
90.0
54910
929,1
25-32
-------
Table 25.2.4-5. Sumtary of Coal Switching/Cleaning Costs for the South Oak Creek Plant (June 1988 Dollars)
- Technology Baiter Main Boiler Capacity Coal Capital Capital Annual Annual 502 502 S02 Cost
Munber
Retrofit
Size
Factor
Sulfur
Cast
Cost
Cost
Cost
Removec
Removed
Effect.
Di fficulty
CMW)
(X)
Content
<#«)
9.7
35.1
20.7
14.8
43.0
7608
2718.2
CS/B*t15
6
1.00 -
275
. 41
1.6
9.7
35.1
15.9
15.3
43.0
5640 ,
, 2815.2
CS/B«S15
7
1,00
310
46
1.6 •
11.4
36.3
19.8
15.2
43.0
7097
2791.9
CS/B+S15
a
1.00
310
38
1.6
11.4
36.8
16.2
15.7
43.0
5619
, 2884.9
CS/B»I15-C .
5
1.00
275
58 '
1.6
9.7
35.1
11.9
8.5 '
43 0
7608
1563.1
CS/8*t15-C
6
1.00
275
43
1.6
9.7
35.1
9.1
8.8
43.0
5640
1620.6
CS/B+I15-C
7
1.00
310
48
1.6
11.4
36.8
11.4
8.7
43.0
7097
1606.8
CS/8+t15-C
8
1.00
310
38
1.6
11.4
36.3
9.3
9.0
43.0
5619
1662.0
CS/S*I5 '
5
1.00
275
58
1.6
6.8
24.7
8.6
6.2
43.0
7608
1135.6
CS/S*15
6
1.00
275
43
1.6
6.8
24.7
6.8
6.6
43.0
5640
1209.6
CS/B*S5
7
1.00
310
48
1.6
8.2
26.4
8.5
6.5
43.0
7097
1195.5
cs/a*$5
8
1.00
310
38
1.6
8.2
26.4
7.1
6.9
43.0
5619
1267.7
CS/8*S5-C
5'
1.00
275
58
1.6
6.8
24.7
5.0
3.6
43.0
7608
654.6
CS/8+J5-C
6
1.00
275
43
1.6
6.8
24.7
3.9
3.8
43.0
. 5640 •
698.5
CS/8+I5-C "
7
1.00
310
48
1.6
8.2
26.4
4.9
3.8
43.0
7097
690,2
CS/8+I5-C
a
1.00
310
38
1.6
8.2
26.4
4.1
4.0
43.0
5619
732.8
25-33
-------
facilities value (38 percent) was assigned to units 5-7 due to relocation
and demolition of ash silos and a plant road. A medium general facilities
value {20 percent) was assigned to units 7-8 because of a plant road
relocation. A high site access/congestion factor was assigned to unit 5-7
SCR reactor locations because of the congestion created by the lake and
ESPs/chimneys. Some space is available for unit 8 SCR reactor and a medium
site access/congestion factor was assigned to this location. About 300 feet
of ductwork would be required for all units. Tables 25.2.4-6 and 25.2.4-7
present the retrofit factors and cost estimates for installation of SCR at
the South Oak Creek plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
units 7 and 8 because of the lack of access to the ductwork between the
boilers and the ESPs and the small ESP size. However, sorbent injection
technologies were considered for units 5 and 6 because of the large size
ESPs. It is assumed that the first section of the ESPs could possibly be
modified for slurry injection (E-SOx). Tables 25.2.4-8 and 25.2.4-9 present
retrofit factors and costs for FSI and DSD technologies for units 5 and 6.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 5 and 6 would be considered good candidates for AFBC/CG
repowering because of their small boiler size (<300 MW). Units 7 and 8
would be less likely candidates because of their larger size (>300, MW)
and higher capacity factors. Plant/boiler site congestion would
significantly increase the cost of repowering for all the boilers.
25-34
-------
TABLE 25.2.4-6, SUMMARY OF NOx RETROFIT RESULTS FOR SOUTH OAK CREEK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
5,6
7,8
FIRING TYPE
ARCH
TANGENTIAL
TYPE OF NOx CONTROL
NA
LNC
FURNACE VOLUME (1000 CU FT) ,
173
136
BOILER INSTALLATION DATE
1959,61
1965,67
SLAGGING PROBLEM
NO
YES
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH,MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
61 •
63
New Duct Length (Feet)
300
300
New Duct Costs (1000$)
2799
2881
New Heat Exchanger (1000$)
3567
3675
TOTAL SCOPE ADDER COSTS (1000$)
6427
6619
RETROFIT FACTOR FOR SCR
1.52
1.52,1.34
GENERAL FACILITIES (PERCENT) •
38
38.20
25-35
-------
Table 25.2.4-7, NOx Control Cost Results,for the South Oak Creek Plant (June 1988 Dollars)
BS38V8IVSBI3
sssassaa
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S8SS3SSBSS!
SSSSSSSS"
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ISSllISSItSX
¦ S 3SS525Z
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»«»¦«.»««
Technology
Beiler
Main
Soiler Capacity Coal
Capital Capital Annual
Annuat
NOx
NOx
NOx Cost
Nurfeer
Retrofit
Size
Factor Sulfur
Cost
Cost'
Cast
Cost
Removed Removed
Effect.
Difficulty CHW)
<%>
Content
(SHK)
CS/kW>
(SWO
(mi iIs/kuh)
(X)
< t ons'/y r 3
(S/ton)
............
. .
- Factor
........
.......
(X)
.........
•••.«••
...... ......
......
...........
......
SCR-3
5
1.52
275
58
1.6
49.5
180.0
16.0
" ' 11.5
80.0
3403
4708.9
SCR-3
6
1,52
275
43
•1.6 .
49.5
180.0
15.8
15,3
80.0
2523
6265.9
SCR-3
7
•1.52
310
' 48
1.6'
54.3
175.0
17.5
13.5
80.0
3175
' 5524.6
SCR-3
a
1.34
310
' 38
" 1,6
47.8
154.2
15.8
15,3
80,0
2513
6281.8
SCR-3-C
5
1.52.
275
58
1.6
49.5
180.0
9.4
6.7
80.0
3403
2761.1
SCi-3-C
- 6
1.52
' 275
43
1.6
49.5
180.0
9.3
9.0
80. D
2523
3677.9
SCR-3-C
7
1.52
. 310
48
1.6
54.3
175.0
10.3
7.9
80.0
3175
3241.8
SCR-3-C
8
1.34
' 310
38
1.6
47.8
154.2
9.3
9.0
80.0
2513
3684.4
SCR-7
5 •.
1.52
275
58
'•6
49.5
180.0
' 13.8
9.9
80.0
3403
4046.5
SCR-7
6
1.52
275
43
.1.6
49.5
180,0
13.6
13.1
80.0
2523
5372.4
SCR-7
7
1.52
310
48
'1.6
54.3
175.0
15.0
11.5
. 80.0
3175
4724.2
SCR-7
8
1.34
310
38
1.6
47.8
154.2
13.2
12.8
80.0
2513
5270.8
SCR-7-C
5
1.52
275
58
1.6
49.5
180.0
8.1
5.8
80.0
3403
2383.6
SCR-7-C
6
1.52
275
• 43
1.6
49.5
180.0
8.0
7.7
80,0
2523
. 3166.0
SCR-7-C
7
1.52
310
48
1.6
54.3
175.0
8.8
6.8
ao.o
3175
2783.3
SCR-7-C
8
1.34
310
38
1.6
47.8
154,2
7.8
7.6
80.0
2513
3105.1
25-36
-------
TABLE 25.2.4-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SOUTH OAK CREEK UNIT 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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 64
TOTAL COST (1000$)
ESP UPGRADE CASE 64
A NEW BAGHOUSE CASE . NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE ' NA
25-37
-------
Table 25.2,4-9. Suwary of B5D/FSI Control Costs for the South Oak Creek Plant (June 1988 Dollars}
Technology
loi.ler Ha in Boiler
Nunfoer Retrofit Size
Difficulty (MW>
Factor
Capacity Coal
Factor Sulfur
(X) Content
(X)
Capital Capital Annual
Cost Cost Cost
(SMH) ($/kU) (SMM)
Anoual S02 . S02 $02 Sest
Cost Removed Removed Effect,
CmilU/kwh) (X) (tons/yr) !$/con)
DSD'ESP
OSD'ESP
1.00
1.00
275
275
58
43
It.
It.
40.9
40.9
8.6
7.7
6.1
7.5
49,
49,
8609
6389
997.5
'1210.0
0S0*ESP-C
DSD*£SP-C
1.00
1.00
275
275
58
43
1.6
1.6
11.3
11.3
40.9
40.9
5.0
4.5
3.6
4.3
49
49
8609
6383
577.4
701.1
FSI*ESP-50
FSf+ESP-50
1.00
1.00
275
275
58
43
1.6
1.6
12.0
12.0
43.7
43.7
9.6
8.1
6.8
7.9
50.
SO.
8S48
6560
1079.8
1240.7
FSI'ESP-50-C
FSI*ESP-50-C
1.00
1.00
273
275'
58
43
1.6
1.6
12.0
12.0
43.7
43.7
5.5
4.7
4.0
4.6
50,
50,
8848
6560
624.8
719,1
FSI+ESP-70
FSI+E$P-7a
1.C0
1.00
275
275
58
43
1.6
1.6
12.2
12.2
44.3 '
44.3
9.7
8,3
7,0
8.0
70.
70.
12387
9184
784.7
900.6
FS1+ESP-7Q-C
FSS+ESP-73-C
1.00
1.00
275
275
58
43
1.6
1.6
12.2
12,2
44.3
44.3
5.6
4.8
4.0
4.6
70.0
70.0
12387
9184
454.0
522.0
UlBaSSSlSSSISSaSS8SlSSSS88SSSC3SSnSUSlIIS8SSa«SSSSSI8SSBSSIKBaS9SSSB33asSSS8!
25-38
-------
25.2.5 Vallev Steam Plant'
LSD with reuse of the existing ESPs was riot considered for the Valley
plant because the ESPs are small and would not be able to handle the
additional load. Space around the Valley plant is very limited; therefore,
LSD with a new baghouse was not evaluated. Furnace sorbent injection
technologies were not considered since the ESPs are not of an adequate size
to be reused and the duct residence time between the boilers and ESPs is
short. •
TABLE 25.2.5-1. VALLEY 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
68
26
1968
3,4
68
27
1969
FRONT WALL
41.5
NO
41.5
NO
1.4
12700
9.1
DRY DISPOSAL
LANDFILL/OFF-SITE
2
SHIP/BARGE
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP ESP
1968 1969
0.05,0.11 0.1,0.11
99.3,98.4 98.6,99.1
2.5
50.5
277
182
310
2.5
50.5
277
182
310
* Based on 1988 data.
25-39
-------
TABLE 25.2.5-2.
SUMMARY OF RETROFIT FACTOR DATA FOR VALLEY
UNITS 1-2 OR 3-4*
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
NO
, NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
YES
RETROFIT FACTORS
FGD SYSTEM
1.73
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA .
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 15
0
0
* L/LS-FGD absorbers for units
the common chimney for units
1-2 and
1-2 and
3-4 would be located behind
3-4, respectively.
25-40
-------
Table 25.2.5-3. Suimary of. FGD Control Costs for the Valley Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 SZ2 Cost
Nuitier Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty Content (SHH) (X) (tcns/y) <%/tsn>
Factor £%)
L/S FCO * 1-2 1.73 136 26 1.4 60.3 443.1 21.9 -70.7 90.0 2950 7419.3
L/S FC0 3-4 1.73 136 , 27 1.4- 60.3 443.1 22.0 68.3 90.0 3064 ' 7169.8
L/S FGO-C 1-2 1.73 136 26 1.4 " -60.3 443.1 12.8 41.4 90.0 2950 4342.4
l/S FGD-C 3-4 1.73 136' 27 1.4 60.3 443.1 '12.9 40.0 90.0 3064 4196.0
tC FED 1-2 1.73 ' 136 26 1.4 . 41.5 305.3 16.0 51.7 90.0 2950 .• 5425.2
IC FGD 3-4 ' 1.73 136 27 1.4 . 41.5 305.3 16.1 " 50.0 90.0 3064 5249.5
IC FGD-C 1-2 1.73 136 26 1.4. 41.5 305.3 9.4 30.2 90.0 2950 3171.3
IC FGO-C 3-4 1.73 136 27 1.4 41.5 305.3 9.4 29.2 90.0 3064 3C68.4
25-41
-------
Table 25.2.5-4, Surmary of Coat Snitching/Cleaning Costs for the Valley Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal
Number Retrofit Size Factor Sulfur
Difficulty (NW) (S) Content
Factor (X)
Capital Capital Annual
Cost Cost Cost
(SMM) (S/kU) (SWO
Annual . S02 S02 S02 Cost
Cost Removed Removed Effect,
(fii I ls/kah) (X)
-------
TABLE 25.2.5-5. SUMMARY OF NOx RETROFIT RESULTS FOR VALLEY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS "
1-2
' .3-4
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (1000 CU FT) ,
41.5
41.5
BOILER INSTALLATION DATE
1968
1969
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
42
40
SCR RETROFIT RESULTS*
*
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0,
. 0
Ductwork Demolition (1000$)
34
34
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1186
1186
New Heat Exchanger (1000$)
2241
2241
TOTAL SCOPE ADDER COSTS (1000$)
3462
3462
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
behind the unit 1-2 and 3-4 chimney, respectively.
25-43
-------
Table 25.2.5*6. NO* Control Cost Results for the Valley Plant (June 1988 Dollars)
Technology Boiler 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 (X> Content (SWt) (S/kU) (SMM) (mi Us/kwh) <%)
-------
25.3 WISCONSIN POWER AND LIGHT
25.3.1 Columbia Steam Plant
The Columbia steam plant is located on the Wisconsin River in Columbia
County, Wisconsin, and is operated by Wisconsin Power and Light. The
Columbia plant contains two coal-fired boilers with a gross generating
capacity of 1054 MW.
Table 25.3.1-1 presents the operational data for the existing equipment
at the Columbia plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area south of the plant.
PM emissions from the unit 1 boiler are controlled by the original hot-side
ESP located behind the unit. PM emissions from the unit 2 boiler are
controlled by the modified ESP that was converted from hot-side to cold-side
operation in 1988. Flue gases from the units are directed to separate
chimneys located behind the ESPs. Dry fly ash is disposed of in landfills
east of the plant or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for both units would be located behind their
respective chimney. A low site access/congestion factor was assigned to
these locations. A plant road and ash silos would have to be relocated for
the unit 1 absorbers; therefore, 15 percent was assigned to general
facilities. For unit 2, a plant road would need relocating; therefore,
8 percent was assigned to general facilities. For each unit, a duct length
of 100 to 300 feet would be required to span the distance from the chimney
to the absorbers and back to the chimney. A low site access/congestion
factor was assigned to flue gas handling. New chimneys were considered
because the existing chimneys are carbon steel.
LSD with reuse of the existing ESPs was not considered for unit 1
because the unit is equipped with hot side ESPs. LSD with a new baghouse
was considered for unit 1. LSD with reuse of the existing ESPs was
considered for unit 2. The LSD absorbers would have the same location as
the wet FGD absorbers; hence, similar site access/congestion and general
facility factors were assigned to'the locations. The new FFs for unit 1
25-45
-------
TABLE 25.3.1-1. COLUMBIA STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
GENERATING CAPACITY (MW-each)
527
CAPACITY FACTOR (PERCENT)
55,70*
INSTALLATION DATE
1975,1978
FIRING TYPE
TANGENTIAL
FURNACE VOLUME (1000 CU FT)
421
LOW NOx COMBUSTION
NA
COAL SULFUR CONTENT (PERCENT)
0.6,0.3
COAL HEATING VALUE (BTU/LB)
8800
COAL ASH CONTENT (PERCENT)
8.4,4.6
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
LANDFILL/SOLD
STACK NUMBER
1,2
COAL DELIVERY METHODS
RAILROAD
PARTICULATE CONTROL
TYPE
HOT ESP, COLD ESP
INSTALLATION DATE
1975,1978
EMISSION (LB/MM BTU)
0.08,0.02
REMOVAL EFFICIENCY
99.1,99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
0.7,0.4
SURFACE AREA (1000 SQ FT)
743
GAS EXIT RATE (1000 ACFM)
3800,2200
SCA (SQ FT/1000 ACFM)
196,338
OUTLET TEMPERATURE ("F)
800,275
* 1990 estimate.
25-46
-------
would be adjacent to the LSD absorbers. Duct lengths of 200 and 500 feet
would be needed for units 1 and 2, respectively. The site access/congestion
factor for flue gas handling was low for unit 1 and high for unit 2.
Table 25.3.1-2 presents the retrofit factor results for the Columbia
plant. However, costs are not estimated since the boilers at the Columbia
plant are burning a low sulfur coal and it is unlikely that the current low
sulfur coal would be used if scrubbing were required. FGD cost estimates
based on the current low sulfur coal would result in low estimates of
capital and operating costs and high unit costs.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Columbia plant since the boilers
are c; rently burning a low sulfur coal. Plant personnel indicated that
switching to a very low sulfur coal would require conversion of the unit 1
ESP to cold side operation.
NOx Control Technologies--
The boilers at the Columbia plant are probably already meeting the
1971 NSPS emissions and were riot considered for any combustion modification
in order to reduce N0X emissions.
Selective Catalytic Reduction--
Hot side and cold side SCR reactors for units 1 and 2, respectively,
would be located behind each chimney, similar to the L/LS-FGD absorbers. As
before, the site access/congestion factor for both locations was low. For
unit 1, a high general facilities factor of 38 percent was assigned due to
the need to relocate a plant road and ash silos, A plant road would need to
be relocated for unit 2; hence, a medium factor of 20 percent was assigned
to general facilities. For each unit, approximately 200 feet of duct would
be required to span the distance between the reactors and the chimneys. The
site access/congestion factor for flue gas handling was low.
Tables 25.3.1-3 and 25.3.1-4 present the retrofit factors and cost for
installation of SCR at the Columbia plant.
25-47
-------
TABLE 25,3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR COLUMBIA
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 (UNIT 2)
HIGH
BAGHOUSE CASE (UNIT 1)
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE (UNIT 2)
300-600
BAGHOUSE (UNIT 1)
100-300 .
ESP REUSE (UNIT 2)
NA
NA
MEDIUM
NEW BAGHOUSE (UNIT 1)
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY '
YES
NA
YES '
ESTIMATED COST (1000$)
3689
0
3689
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.22
NA .
ESP REUSE CASE (UNIT 2)
1.43
BAGHOUSE CASE (UNIT 1)
1.23
ESP UPGRADE (UNIT 2)
NA
NA
•1.35 '
NEW BAGHOUSE (UNIT 1)
NA
NA
1.15
GENERAL FACILITIES (PERCENT)
15,8
• 0
15,8
25-48
-------
TABLE 25.3.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR COLUMBIA
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
NA
NA
TYPE OF NOx CONTROL
NA
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
NA
NA
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
SCR RETROFIT RESULTS
SITE' ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
.. 0 '
Ductwork Demolition (1000$)
94
94
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
2620
2620
New Heat Exchanger (1000$)
0
5052
TOTAL SCOPE ADDER COSTS (1000$) 2715 7767
RETROFIT FACTOR FOR SCR 1.16 1.16
GENERAL FACILITIES (PERCENT) 38 20
25-49
-------
Table 25.3.1-4. NOx Control Cost Results for Me Celwfcia Plant {June 198B Dollars)
¦8SSSSSBSSS3K=3 3SSS3 5SSSSSSaSS&SaS8SXB*8SSS3=£HBSSa3Sa«S»XSSSaBSa8SSaS8SSaS9SSSS3SSSSSSS£SSSSSSS8SS8SSaSBSSS=£S
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual t NOx NO* NOx Cost
Number Retrofit Siie factor- Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty £MW> (X) Content (SMMi (S/kU) (MM) (miUs/kwh) CX} Ctons/yrJ (J/tc)
factor (%i
SCR-5 1 1.16 527 55 ' 0.6 ' 68.6 130.1 ' 25.4 13.0 80.0 8999 2826.3
SCR-3 2 1,16 527 '70 0.3 65.S 124.3 24.9 • 7.7 80.0 11453 ' 2175.6
SCR-3-C 1 ' .1.14 527 55 0.6 68.6 130.1 14.9 5.9 80.0 8999 1653.4
SCS-3-C 2 1.16 527 70 '0.3 65.5 124.3 -14.6 ' 4.5 80.0 11453 " 1272.1
SCR-7 1 - 1.16 527 55 0.6 68.6 130.1 20.9 . 8.2 80.0 8999 ' 2322.4
SCR-7 2 1.16 527 70 0.3 65.5 124.3 20.4 6.3 80.0 11453 ' 1779.7
SCS-7-C 1 1.16 527 55 0.6 68.6. 130.1 12.3 4.8 80.0 8999 • 1364.8
SCT-7-C 2 1.16 527 70 0,3 65.5 124.3 12.0 3.7 80.0 11453 - 1045.3
25-50
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
unit 1 because the boiler is equipped with hot side ESPs. Both technologies
were considered for unit 2 because of the sufficient ESP SCA size and duct
residence time. Tables 25,3.1-5 'and 25.3.1-6 present retrofit data and
costs for installation of FS.I and DSD technologies for unit 2 at the
Columbia-plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Appli cab i1i tv- -
The two 527 MW boilers at the Columbia plant are too large and their
remaining useful life is too long to be considered good candidates for
AFBC/CG repowering.
25.3.2 Edaewater Steam Plant
The Edgewater steam plant is located on Lake Michigan in Sheboygan
County, Wisconsin, and is operated by the Wisconsin Power and Light Company.
The Edgewater plant contains three coal-fired boilers with a gross
generating capacity of 770 MW.
Table 25.3.2-1 presents operational data for the existing equipment at
the Edgewater plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area south of the plant. PM
emissions from units 3 and 4 are controlled by a retrofit ESP on unit 3 and
the original ESP on unit 4. Emissions from unit 5 are controlled by ESPs
which were installed at the time of construction. All of the ESPs are
located behind the boilers. Flue gases from boilers 3 and 4 are directed to
a chimney located behind the units and flue gases from unit 5 are directed
to a chimney located behind unit 5. Dry fly ash from the units is
landfilled or sold by the utility.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-F6D absorbers for all of the units would be located south of
unit 3, northeast of the coal pile. The general facilities factor is high
(15 percent) for this location because several storage buildings, silos, and
a road would have to be relocated. The site access/congestion factor is
25-51
-------
TABLE 25.3.1-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR COLUMBIA UNIT 2
I TEH
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$) 104
TOTAL COST (1000$)
ESP UPGRADE CASE " 104
A NEW BAGHOUSE CASE. - NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.34
NEW BAGHOUSE • NA
25-52
-------
Table 25.3.1-6. 'Sutmary of DSD/FSI Control Costs for the Colombia Plant (June 19S8 Dollars!
ssHBtaa ¦¦¦¦iiiaatiias
Technology Boiler Main Boiler Capacity CosI Capita! Capital Annual AnnusI S02 S02 S02 Cost
Kunber Retrofit Size Factor Sulfur Cost . Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (*) Content U) (tons/yr) (»/ton)
Factor _ (%)
DSD+ESP 2 ' 1.00 527 70 0.3 10.7 20.3 8.3 2.6 49.0 5433' 1524.4
DSD*ESP-C 2 1.00 527 70 0.3 10.7 20.3 4.8 1.5 49.0 5433 882.2
FSI~ESP-50 2 1.00 527 70 0.3 13.1 24.8 8.2 ' 2.5 50.0 5583 1475.7
fSI+ESP-50-C 2 1.00 527 70 0.3 13.1 24.8 4,8 1.5 . 50.P 5583 8S6.0
fSi-ESP-70 , 2 1.00 527 70 0.5 13.2 25.0 8.4 2.6 70.0 . 7817 1068.3
fSI+ESP-70-C 2 1-00 ' 527 70 0.3 13.2 25.0 4.8 • 1.5 70.0 . 7817 619.6
25-53
-------
TABLE 25.3.2-1. EDGEWATER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
3
4
5
GENERATING CAPACITY (MW-each)
' 60
330
380
CAPACITY FACTOR (PERCENT)
40
72
51
INSTALLATION DATE
1951
' 1969
1985
FIRING TYPE
CYCLONE
OPPOSED WALL
FURNACE VOLUME (1000 CU FT)
24.1
137
355
LOW NOx COMBUSTION
, NO
NO
. NO
COAL SULFUR CONTENT (PERCENT)
2.0
2.0
• 0.4
COAL HEATING VALUE (BTU/LB)
10800
10800
8200 '
COAL ASH CONTENT (PERCENT)
9.3
9.3
5.5
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
LANDFILL/SOLD -
STACK NUMBER-
- 1,2
1,2
3
COAL DELIVERY METHODS
RAILROAD
PARTICULATE CONTROL
TYPE
ESP
ESP
ESP
INSTALLATION DATE
1972
1959
1985
EMISSION (LB/MM BTU)
0.11
0.15
0.009
REMOVAL EFFICIENCY
93.6
94.9
99.96
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
2.9
2.8
0.48
SURFACE AREA (1000 SQ FT)
95
172.8
958.5
GAS EXIT RATE (1000 ACFM)
300
1050
1700
SCA (SQ FT/1000 ACFM)
317
165
564
OUTLET TEMPERATURE (*F)
330
275
279
25-54
-------
medium for this location because of the proximity of the coal conveyor and
the lake. In addition, there is some underground obstruction in this area.
About 500 feet of ductwork would be required for units 3 and 4 and.400 feet
of ductwork with a new chimney would be required for unit 5. A low site
access/congestion factor was assigned to flue gas handling for units 3 and
4, and a high site access/congestion factor was assigned to unit 5 because
of the obstruction due to the unit 3 and 4 chimney.
LSD with reuse of the existing ESPs was not considered for units 3-5
because of the difficultly in accessing the existing ESPs and the inadequate
SCA for additional grain loading of LSD. LSD with a new FF was considered
for these units. LSD-FGD absorbers for units 3-5 would be located similarly
to the wet FGD absorbers south of unit 3. As in the L/LS-FGD case, a high
general facilities factor and a high site access/congestion factor were
assigned to this location. About 400 to 500 feet of ductwork would be
required for units 3-5 with a new chimney for unit 5. A high site
access/congestion factor was assigned to flue gas handling for units 3-5
because of the limited space between the boiler, and the ESPs.
Tables 25.3.2-2 through 25.3.2-4 present retrofit factor inputs to the
IAPCS model and cost estimates for installation of conventional FGD
technologies at the Edgewater plant. Costs for unit 5 are not presented
since unit 5 is burning a Tow sulfur coal and would yield high unit costs.
Coal Switching and Physical Coal Cleaning Costs--
CS was not considered for unit 5 of the Edgewater plant because this
unit already fires a very low sulfur coal. CS was not considered for
units 3 and 4 because a low ash fusion temperature and low sulfur coals
required for cyclone boilers are not readily available in the eastern United
States. PCC also was not evaluated because the Edgewater plant is not a
mine mouth plant. Plant personnel indicated that switching to a lower
sulfur coal is currently under investigation for units 3 and 4.
N0„ Control Technologies--
x 3
NGR was considered for control of NQ„ emissions from units 3 and 4
x
which are cyclone-fired. Unit 5 is an NSPS unit and probably meets N0X
emission limits using LNB. Tables 25.3.2-5 and 25.3.2-6 give a summary of
25-55
-------
TABLE 25.3.2-2. ' SUMMARY OF RETROFIT FACTOR DATA FOR EDGEWATER
UNIT 3 OR. 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY PRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
LOW
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
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
1.52
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
25-56
-------
TABLE 25.3.2-3. SUNMARY OF RETROFIT FACTOR DATA FOR EDGEWATER
UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 300-500 NA
ESP REUSE
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA . NA , HIGH
SCOPE ADJUSTMENTS \
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 2660 0 2660
OTHER "NO NO
RETROFIT FACTORS
FGD SYSTEM 1.63 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
25-57
-------
•Table 25.3,2-4, Sunrnry of ffiO Control Costs far the Edgewater Plant (June 1988 Oollsrs)
bsi8si::zis2
Technology
Boiler
Main
mSSIaSS ii j< » «2^SSSSSS!
Boiler Capacity Coil
Capital Capital Annual
Amuil
. 302
. S02
S02 cost
Number
Retrof i t-
Siie
Factor
Sulfur
• Cost
Cost
Cost
Cost
Removed
Removed
Effect.'
Difficulty
(mllls/kwh>
(X)
{tons/yr>
(t/ten)
Factsr
a) ¦
L/S FGO
3
1.52
- 60
• 40
2.0
39.5
658.3
15.4
'73.1
90.0
3445
4461.4
l/S FGD
4
1.52
330
72
2.0
98.9
299.6
46.1
22.2
90.0
34110
1351.9
L/S FGD
3-4
1.52
390
67
2,0
109,6
280.9-
50.5
22. T ¦
90.0
37513
1347.!
L/S fGC-C
3
1.52
£0
40
2.0
39.5
658.3
9.0
42.7
90.0
3445
2607.5
L/S FGD-C
4
1.52
330
72
2.0
98.9
299.6
26.9
12.9
90.0
34110
787.5
L/S FGO-C
3-4
1.52
390
67
2.0
109.6
280.9
29.4'
12.9
90.0
37513
784.9
LC FGD
3-4
1.52
, 390
67
2.0
83.1
213.2
42.3
18.5
90.0
3(513
1128.0
LC FGD-C
3-4
1.52
' 390
67
2.0,
83,1
213.2
24.6
10.8
90.0
37513
656.2
LS0*FF
3
1.62
SO
40
2.0
24.0.
400.1
9.3
,44.1
87.0
3311
2798.0
LSD+FF
4
1.62
330
n
2.0
80.4
243.5
30.5
14,7
87.0
32783
931.9
LSO+FF-C
3
1,62
60
40
2.0 '
24.0
400.1
5.4
25.8
87.0
3311
1635.6
LSD+FF-C
4
1,62
330
72
2.0
80.4
243. S
17.9
8.6
87.0
32783
544.9
.............
II
II
II
II
II
II
II
il
II
II
II
II
II
II
II
II
II
=======
: ========
! = ==== = = =
========
========
=s=3sass
25-58
-------
TABLE 25,3,2-5. SUMMARY OF NOx RETROFIT RESULTS FOR EDGEWATER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
5
FIRING TYPE ,
CYCLONE
CYCLONE
NA
¦ TYPE OF NOx CONTROL
NGR
NGR
NA,
FURNACE VOLUME (1000 CU FT)
24.1
137
NA
BOILER INSTALLATION DATE
195,1 ..
1969
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
18
66
74
New Duct Length (Feet).
500
500
100
New Duct Costs (1000$)
1838
4981
1082
New Heat Exchanger (1000$)
1372
3815
4152
TOTAL SCOPE ADDER COSTS (1000$)
COMBINED CASE
3228
9785
8863
5308
RETROFIT FACTOR FOR SCR
1.34
1.34
1.52
GENERAL FACILITIES (PERCENT)
38
38
38
25-59
-------
Table 25.3.2-6. NO* Control Cost Results for the Edgcwatcr Plant (June 1988 Dollars)
Technology Boiler Main Boiter Capacity Coal Capital Capital Annual Annual NO* KOx MO* Cost
Nimber Retrofit Site Factor Sulfur Cost Cost Cost ' Cost Removed Removed Effect.
Difficulty CHU> (X) Content (1HH) (t/kU) (SUM) (nsills/kwh) (5) (tors/yr) (S/ton)
Factor (X>
NOR
3
1.00
£0
40
2.0
1.6
.26.0
1.3
£.4
60.0
1090
1233.9
NOR
4
1.00
330
72
. 2.0
5.4
16.3
11.5
5.5
60.0
10787
1062.5
HGR-C
3
1.00
60
40
2.0
1.6
26.0
0.8
3.7
60,0
1090
713.3
(fCR-C
4
1.00
¦ 330
72
2.0
5.4
16.3
6.6
3.2
60.0
10747 ,
611.a
SCR-3
3
1.34'
60
40
2.0
17,5
291.2
5.2
24.8
80.0
1453
3592.1
SCR-3
4
1.34
330
72
2.0
55,4
167.9
19.5
9.4
BD.O •
14332
1355.7
SCR-J
3-4 '
1.34
390
67
2.0 ¦
61.3
157.3
21.9
9.6
80.0
.15817
1383.0
SCR-J
5
1.52
380
61
0.4
60.8
160.0
21.5
' 10.6
80.0
10926
1970.2
SCR-3-C
3 •
1-.34
60
40
2.0
17.5
291.2
3.1
14.6
80.0
1453
2112.4
SCR-3-C
¦ 4 ¦
1.34
330
72
2.0
55.4
167.9
11.4
5.5
80.0 "
14382
794.0
SCR-3-C
3-4
'• 1.34
390
67
2.0
61.3
157.3
12.ft
5.6
80.0
15817
809.8
SCS-3-C
5
1.52
380
61
0.4
60.8
160.0
12.6
6.2
80.0
10926
1153.8
SCR-7
3
1.34
60
40
2.0
17.5
291.2
4.7
22.4
80.0
1453
3248.2
SCR-7
4
. 1.34
330
72
2.0
55.4
167.9
16.7
8.0
30.0
-14382
1164.2
SCR-7
3-4
1.34
390
67
2.0
61.3
157.3
18.6
3.1
30.0
15817
1177.3
SCR-7
5
1.52
380
61
0.4
60.8
160.0
18.2
9.0
80.0 •
10926
1667.8
SCR-7-C
3
1.34
60
40
2.0
17.5
291.2
2.8
13.2
80.0
1453
1914.8
SCR-7-C
4
1.34
330
72
2.0
55.4
167.9
9.8
4.7
80.0
14382
684.3
SCR-7-C
3-4
1.34
390
67,
2.0
61.3
157.3
10.9
4.8
80.0
15817 ,
691.9
SCR-7-C
5
1.52
380
61
0.4
60.8
160.0
1C.>
5.3
80.0
10926
980.5
(1
II
II
II
II
II
<1
tl
==*s===s
:z3skss:
:s=irasss
SSS3S3&SS
:sssss2=:
us-.-,.,,
' = = = = = = = 23
,„..==..
25-
60
-------
retrofit factors and costs, respectively, for N0X control technologies at
the Edgewater plant.
Selective Catalytic Reduction--
Cold side SCR reactors for units 3 and 4 at the Edgewater plant would
be located south of unit 1. A high general facilities factor (38 percent)
and a medium site access/congestion factor were assigned to the reactor
location, A cold side SCR reactor for unit 5 would be located beside its
chimney with a high site access/congestion and general facilities factor
assigned to it. Approximately 500 feet of ductwork would be required to
span the distance between the SCR reactors and the chimney for units 3 and 4
and about 100 feet would be required for unit 5. Tables 25.3.2-5 and
25.3.2-6 present the retrofit factors and costs for installation of SCR at
the Edgewater plant.
Furnace Sorbent Injection and Duct Spray Drying Costs--
FSI and DSD were not considered for units 3 through 5 because of the
short duct residence time and/or the ESPs not being large enough to handle
the additional particulate load. ,
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability-
Unit 3 is the only boiler at the Edgewater plant which is old enough to
be considered a good candidate for repowering. Units 4 and 5 are large and,
have long remaining useful lives; therefore, are not considered good
candidates for AFBC/CG technologies.
25.3.3 Nelson Dewev Steam Plant
The units at the Nelson Dewey plant have hot side ESPs for control of
their particulate matter, hence LSD with reuse of the existing particulate
control was not an option. Sorbent injection technologies were not
considered again because the existing particulate control device cannot be
reused.
25-61
-------
TABLE 25.3.3-1. NELSON DEWEY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 100
CAPACITY FACTOR (PERCENT) 54,60
INSTALLATION DATE 1959,62
FIRING TYPE CYCLONE
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.4,0.7
COAL HEATING VALUE (BTU/LB) 11400,10400
COAL ASH CONTENT (PERCENT)¦ 5.1,6.0
FLY ASH SYSTEM WET SLUICE
ASH DISPOSAL METHOD LANQFILL/ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE - HOT.SIDE ESP
INSTALLATION DATE 1974
EMISSION (LB/MM BTU) 0.10
REMOVAL EFFICIENCY 95
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.6
SURFACE AREA (1000 SQ FT) 132.8
GAS EXIT RATE (1000 ACFM) 487
SCA (SQ FT/1000 ACFM) 273
OUTLET TEMPERATURE (*F) 500,550
25-62
-------
TABLE 25.3.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR NELSON DEWEY
, UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED . LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
- LOW
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
.. HIGH
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP.REUSE
NA
BAGHDUSE
300-600
ESP REUSE
NA
NA '
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
. NA
ESTIMATED COST (1000$)
938
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
. 700
0
700
OTHER
NO
NO
NO
RETROFIT FACTORS .
FGD SYSTEM
1.48 .
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.43
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
5
0
5 •.
* Absorbers for units 1 and 2 would be placed southeast of unit I.
25-63
-------
Table 25.3.3-3. Summary of FGD Control Costs for the Nelson Dewey Plant {June 1983 Dollars}
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
" $02
S02
S02 Cost
Nixnber
Retrofit
Size
Factor Sut fur
Cost
Cost
Cost'
Cost
Removed
Removed
Effect,
Difficulty
f MW >
m
Content
CWM)
<$AW)
($•«)
{mi IIs/kuh)
C%)
(tons/yr)
($/ton>
• Factor
(X>
L/S FOB
1
¦ 1.48
100
54
1.4
45.0
450.4
18.3
38.8
90.0
5100
3596.7
L/S FGD
2
1.48
100
60 •
0,7
45.0
449,7
18.4
.35,1
90.0
3148
5854.3
L/S FGD
1-2
1.48
200
57
1,0
67.J
336.6
27.9
28.3
,90.0
8544
3267.5
L/S FGD-C
1.
. 1.48
100
54
1.4
45.0
450.4
10.7
22.6
90.0
5100
, 2100,3
l/S FGC-C
2
1.4S
100
60
0.?
45.0
449.7
10,8
20.5
90.0
3148
3418.2
L/S FGD-C
1-2
1.48
200
57
1.0
67.3
336.6
16.3
16.3
90.0
8544
1907,4
LC FGD
1-2
1.48.
200
57
' 1.0
45.7
228.5
21.2
21.2
90.0
8544
2480.9
LC FO0-C
1-2
. 1.48
200
57
1.0
45.7
228.5
12,4
12.4
90.0
8544
1445.4
LSD+FF
1
1.43
100
54
1.4
29.4
294.2
11.2
23.6
87,0
4902
2279.7
LSD*FF
Z
1.43
100
60
' 0-7
29.8
297.8
11.0 ,
" 20.9 '
87,0
3026
3637.7
lS0*fF-C
1
1.43
100
¦ 54
1.4 •
29.4
294.2
6.5
13.8
87,0
4902
1333.0
IS>FF-C .
2
1.43
100
60
0.7
29.8
297.8
6.4
12.3
87.0
3026
2128.3
............
tassssstss:
W
It
II
II
II
11
II
11
II
H
11
11
25-64
-------
TABLE 25.3.3-4. SUMMARY OF NQx RETROFIT RESULTS FOR NELSON DEWEY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE . • • CYC
TYPE OF NOx CONTROL NGR
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE 1959,1962
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$) 0
Ductwork Demolition (1000$) 27
New Duct Length (Feet) 450 •
New Duct Costs (1000$) 2230
New Heat Exchanger (1000$) 1864 .
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 4121
COMBINED CASE 6215
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for units 1 and 2 would be located
southeast of unit 2.
25-65
-------
Table 25.3.3-5- no* Control Cost Results for the Net son Dewey Plant (June 1988 Dollars)
stsatsssisss
========
SSSSSSBSS]
ISllISS
:s ===flBB=:
=====B==3S=aasSBS==ftS2ftEI
:= = = ¦¦ = = = = ==
=======
tfSB B3S = = Si
ISS S8SSS5
Technology
loi!er
Main
Boiler Capacity C;al
Capital Capital Annual
Annual
NOx
NOx
M0* C05t
Number
Retrof i t
Si ze
Factor
Sulfur
Cost
Cost
Cose'
Cost
Removed
Removed
1ffeet.
Difficulty (MY)
C*3
Content
(SUM)
(1/kW)
(SMM)
(mil'ls/kuh}
m
(tons/yr)
CS/ton)
Factor
C%)
NGR
1
1.00
100
54
1.4
6,3
63.2
3.5
7.4
60.0 ¦
2304
1525.5
NGR'
2
; 1.00
100
60
0.7
6.3
63.2
3,8
7.2
60,0
2645
1339.3
wgr-c
1
1.00
100
54
1.4
6.3
63.2
2.0
4.3
60.0
2304
886.3
HGR-C "
. a
1.00
. 100
60
0.7
6.3
63.2
2.2
4.2
60.0
2845
777.3
SCR-3
:i
1.16
100
54
1.4
20.2
202.2
6.6
13.9
80,0
. 3072
2135.9
SCR- 3
2
1.16 •
100
60
' 0.7
20.4
204.2-
6.7
12.B
80,0
3793
1773.3
sea-3
1-2
1.16
200
57
1.0
33.4
166.9
11.5
'11.'5
80,0
7206
1596,3
SCB-3-C
1
1.16
10D
54
1.4
. 20.2
202.2
3.9
8.1
80,0
3072
1253.2
SCR;3-C
2
1.16
100
60
0.7
20.4
204.2
3.9
7.5
80.0
3793
1040.1
SCR-3-C
1-2
1.16
200
57
1.0
" 33.4
166.9
6.7
6.7
80.0
7206
935.4
SCR* 7
1
1.16
100
54
1.4
20,2
. 202.2
5.7
12.1
80.0
3072
1366.4
SCR "7
¦ 2
1.16
100
60
0.7
20.4
204.2
5.9
11.2
80,0
3793
1552.1
SCR-7
1-2
1.16
200
57
1.0
33.4
164.9
9.8
9.8
80.0
7296
1363.4
SCR-7-C '
1
1.16
10Q
54
1,4
20.2
202.2
3.4
7.1
80.0
3072 ¦
1098.8
SCR-7-C
2
1.16
100
60
0.7
' 20.4
204,2
3.5
6.6
80.0
3793
913.4
SCR-7-C
1-2
. 1.16
200
57
1.0
33.4
¦ 166.9
'5.8
5.8
80.0
7206
801.9
25-66
-------
25.3.4 Rock River Steam Plant
Coal switching was not evaluated for the Rock' River plant because the .
units are cyclone boilers requiring low sulfur bitlminous coals having low
ash fusion temperatures which are not readily available in the east (plant
personnel indicated that coal switching is currently under investigation by
the plant). The duct residence time between the boilers and the roof-
mounted ESPs is short for both units and the ESPs are small; therefore,
sorbent injection technologies (FSI and DSD) were also not considered.
TABLE 25.3.4-1. ROCK RIVER 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
75
49,39
1954,55
CYCLONE
17.3
NO
2.0
11000
8.1
WET SLUICE
LANDFILL/ON-SITE
1)2 ,
RAILROAD
PARTICULATE CONTROL ¦
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU) -
REMOVAL EFFICIENCY
OESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
¦ SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM) .
SCA [SQ FT/1000 ACFM)
OUTLET TEMPERATURE ( F)
ESP
1971,72
0.10,0.07
95.3,98.6
3.1
63.2
297
213
290,300
25-67
-------
TABLE 25.3.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR ROCK RIVER •
UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED 'LIME
L/IS FGD OXIDATION SPRAY DRYING
LOW
NA
HIGH
300-600
NA
LOW
NO
NA
YES
525
NO
NA
1.43
NA
1.15
5
* Absorbers and new FFs for units 1 and 2 would be located on
either side of unit 1 and 2, respectively.
25-68
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
SCOPE ADJUSTMENTS
WET TO DRY YES NA
ESTIMATED COST (1000S) 724 NA
NEW CHIMNEY YES NA
ESTIMATED COST (1000$) 525 0
OTHER . NO
RETROFIT FACTORS
FGD SYSTEM 1.48 NA
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE NA NA
NEW BAGHOUSE NA NA
GENERAL FACILITIES (PERCENT) 5 0
-------
Table 25,3.4-3, Summary of FGO Control Costs for the Rock River Plant {June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity. Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Number
Retrofit.
Si is
Factor
Sulfur
Cost
Cost
CoSC
Cost
Removed
Removed
EMec:.
Difficulty (MW)
(X)
.Content
(»«>
(S/W)
(MM)
(mlls/kNh)
C»
(tons/yf)
($/tor>)
Factor ,
tS5
i/s m -
1
. 1,48
75
49
2.0
41.5
552.7
16.6
52.3
90.0
5166
3260.1
L/S FGO
2
1.48
75
39
2.0
41.5
553.1
16.3
63.5
90.0
4112
3959.9
i/s rco
1-2
1.48
150
44
2.0
57.8
385.3
23.4
40.5
90.0
9278
2525.5
L/S FGD-C
1
¦ 1.48
75
49 '
2.0
41.5
552.7
9.8
30.5
90.0
¦ 5166'
1903.8
L/S fCO-C
2
1.48
75
39
2.0
41.5
553.1
9.5
37.1
90.0
4112
2314.0
L/S fSO-C
1-2
1.48
150
44
2.0
57.8
385.3
13.7
23.7
90.0
9278
1474.9
LC FGD
1-2
1.48
150
44
2.0
39.7
264.5
17.8
30.8
90.0
9278
1917.8
LC FED-C
1-2
1.48
150
44 ,
2.0
39.7
264.5
10.4
17.9
90.0
9278
1118.0
LSD*ff ¦
1
. 1.43
75
49
2.0
21.2
283.2
8.9
27.6
87.0
4965 •
1791.4
LSD*fF
2
1.43
75
' 39
2.0
21.4
285.1
8.7
34.0
87.0
3952
2203.9
ISO+FF
1-2
. 1.43
150
44
2.0
35.0
233.2
13.3
23.1
87.0
8917
1494.7
ISD*FF-C
1\
1.43
75
49
2.0
21.2
233.2
5.2
16.1
•87.0
4965
1045.6
LSO+FF-C
2 '
1.43
75
39
2.0
21.4
235.1
5.1
19.8
87.0
3952
1286.9
ISO+FF-C
1-2
1,43
150
44
2.0
. 35.0
233.2
7.8
13.5
87.0 .
8917
873.9
25-69
-------
TABLE 25.3.4-4. SUMMARY OF NOx RETROFIT RESULTS FOR ROCK RIVER
' BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE CYCLONE
TYPE OF NOx CONTROL NGR
FURNACE VOLUME (1000 CU FT) 17.3
BOILER INSTALLATION DATE '1954,1915
SLAGGING PROBLEM - NO
ESTIMATED NOx REDUCTION (PERCENT) 60
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
. Building Demolition (1000$) 0
Ductwork Demolition (1000$) 22
New Duct Length (Feet) 400
New Duct Costs (1000$) 1675
New Heat Exchanger (1000$) 1568
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 3265
COMBINED CASE 4926
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for units 1 arid 2 would be located on
either sides of the unit 1 and 2 ESPs, respectively.
25-70
-------
Table 25.3.4--$. NOx Control Cost Results for the Rock River Plant (June 1988 .Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital"Aonual Annual NOx MOx * NO* Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty (tcns/yr) (I/tan)
Factor -C
1
1.16
75
49
2.0
16.4
218.7
2.7
8.5
80
0
2178
1249.6
SCR-7-C
2
1.16
75
39
2.0
16.4
218.7
2.7
10.5
80.0
1734
1546.7
scit-r-c
1-2
1.16
150
44
2.0
25.8
171.8
4.3
7.5
SO.
0
3912
1108.3
=«======*==
!ssas»::ss
::::::::
SSSSIJSSS
__=.
11
it
11
II
II
II
II
!=!!S!SS:
25-71
-------
25.4 WISCONSIN PUBLIC SERVICE CORPORATION
25,4.1 J. P. Pulliam Steam Plant
The J. P. Pulliam steam plant is located on Green Bay in Brown County,
Wisconsin, and is operated by the Wisconsin Public Service Corporation. .The
J, P. Pulliam plant contains six coal-fired boilers with a gross generating
capacity of 373 MW.
Table 25.4.1-1 presents" operational data for the existing, equipment at
the J. P. Pulliam plant. Coal shipments are received by rail and lake and
transferred to a coal storage and handling area south of the plant. PM
emissions from units 3, 4, and 5 are controlled by retrofit ESPs and
emissions from units 6, 7, and 8 are controlled by ESPs installed at the
time of construction. All of the ESPs are located behind their respective
boilers. Flue gases from units 3-6 are directed to a common chimney built
in 1985 and units 7 and 8 each have a'separate chimney. Dry fly ash from
the units is stored in silos for use in road construction or disposal
off-site.
Lime/Limestone and Lime Spray Drying.FGD Costs--
L/LS-FGD absorbers for units 3-7 would be located behind the common
chimney east of the units and north of the coal pile toward the bay.
Absorbers for unit 8 would be located west of the coal pile and south of
unit 8. The general facilities factor would be low (5 percent) for
units 3-7 and medium (8 percent) for unit 8 because of the relocation of a
plant road for the FGD absorber locations. A low site access/congestion
factor was assigned to the FGD absorber locations. Approximately 200 feet
of ductwork would be required for installation of the L/LS-FGD system for
units 3-6, 500 feet for unit 7, and 400 feet for unit 8. A low site access/
congestion factor was assigned to flue gas handling for units 3-6, A medium
site access/congestion factor was assigned to flue gas handling for
units 7-8 because of the obstruction caused by the coal conveyor and the
coal pile.
LSD with reuse of the existing ESPs was not considered for the J. P. .
Pulliam plant because of the small sizes of the existing ESPs. The medium
25-72
-------
TABLE 25.4.1-1. PULLIAM 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
3,4 5 6 7 8
30 50 63 75 125
5,7 20 21 52 55
1943,47 1949 1951 1958 1964
FRONT WALL
NA NA NA 46.1 72.7
NO
2.2
11400
9.4
DRY DISPOSAL
ON-SITE
1 112 3
RAIL/LAKE
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
1958,55
1953
1951
1958
1964
NA
NA
NA
NA
NA
97.6,99
99.3
98.8
98.3
99.4
2.3
2.3 .
2.3
2.3
2.3
33,29
51
63
45
112
187,163
268
345
285
580
176,178
190
183
158
193
360,335 370
370
300
350
25-73
-------
to high sulfur content of the coal being burned at the plant would not be
ideal for LSD with a new baghouse. Therefore LSD-FGD was not considered for
this plant.
Tables 25.4.1-2 through 25.4.1-4 present retrofit factors and cost
estimates for installation of L/LS-FGD at the J. P. Pull iam plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 25.4,1-5 presents the IAPCS cost results for CS at the J. P.
Pulliam plant. . These costs do not include the effect of any changes to
boiler and pulverizer operation. PCC was not considered at the J. P.
Pul1iam plant because it is not a mine mouth plant.
N0X Control Technologies--
LNBs were considered for N0X control for the six front wall-fired, dry
bottom boilers at the J. P. Pulliam plant. Performance results and costs
developed for the six units are presented in Tables 25,4.1-6 and 25.4.1-7. For
those boilers that furnace volumes were not available, furnace volumes were
estimated based on similar size and age boilers.
Selective Catalytic Reduction--
Cold side SCR reactors for the J. P. Pulliam plant would be located
beside the common chimney for units 3-6 and south of unit 8 and west of the
coal pile for unit 8. As in the FGD case, low general facility values
{13 percent) and site access/congestion factors were assigned to the reactor
locations for units 3-7. For unit 8, a medium general facilities value
(20 percent) was assigned and a low site access/congestion factor was
assigned because a plant road has to be relocated. Approximately 200 feet
of ductwork would be required for units 3-6, 500 feet for unit 7, and about
400 feet for unit 8. Tables 25.4.1-6 and 25.4.1-7 present the retrofit
factors and cost estimates for installation of SCR at the J. P. Pulliam
plant.
25-74
-------
TABLE 25.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR J. P. PULL IAM
UNIT 3,4,5,-OR 6
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
NA
. FLUE GAS HANDLING
LOW
. NA
ESP REUSE CASE
' NA ¦'
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NA
ESTIMATED COST (1000$) ..
NA
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
Q
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.20
NA .
ESP REUSE CASE
NA
.BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
0
25-75
-------
TABLE 25.4.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR J. P. PULLIAM
UNIT 7 OR 8
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
NA
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO -
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.35
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5,8
0
0
25-76
-------
- Table 25.4.1-4. Suimary of FGD Control Costs for the Pultiam Plant (June 1988 Dollars)
- .Technology Boiler Main Boiler Capacity Coal ' Capital Capital Annual Annual. S02 S02 - S02 Cost
Number Retrofit
Site
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Content
(INK)
(VkU>
(*MK>
(mil'ls/kwh)' (X)
Ctons/yr>
CS/ton}
• factor ¦
(X)
L/S FGD
3
1.20
30
5
2.2
21.6
720.2
7.8
591.4
90
0
223
34910.7
L/5 FGO
4
1.20
. 30
7
2.2
21.6
719.1
7.9
427.4
90
0
312
25226.9
L/S FGO
5
1.20
SO
' ' 20
2,2
26.6
531.2
10.2
115.9
90
0
1484
6841.3
L/S FGO
6
1.20
63
21
2.2
31.2
495.6
11.8
101,9
90
0
1963
6016.5
L/S FGO
7
1.35
75
52
2.2
37.4
499.3
15.7
46.0
90
0
5788
2713.1
L/S FGO
8
1.35
125
55
2.2
48.5
388.1
20.7
34,4
90
0
10203
2032.7
1/5 FGO
3-6
1.20
173
16
2.2
' 50,6
292.4
18.4
75.9
90
0
4108
4482.5
L/S FGO-C
' 3
1.20
30
5
2.2
21.6
720.2
4.5
346.2
90
0
223
20436.7
L/S FGD-C
4
1.20
30
7
2.2
21.6
719.1
4.6
250.1
90
0
312
14763.7
L/S FGO-C
5
1.20
50
20
2.2
26.6
531.2
5.9
67.8
90
0
1484
3999.8
L/S FGO-C
6
1.20
63
21
2.2
31.2
495.6
6.9
59.6
90
0
1963
3518.4
L/S FCD-C
7
1.35
75
52
2.2
37.4
' 499.3
9.2
26.8
90
0
5788
1583.4
L/S FGO-C
8
1.35
125
55
2.2
48.5
388.1
•12.1
20.1
90
0'
10203
1185.9
L/S FGD-C
3-6
¦ 1.20
173
16
2.2
50,6
292.4
'10.8
44,4
90
0
4108
2623.4
LC FGD
3-7
1.25
248
27
2.2
49.4
199.1
20.3
34.6
90
0
9933
2044.0
LC FGO
8
1.35
125
55
2.2
33.8
270.7
16.2
26.8
90
0
10203
1583.8
LC FGO-C .
3-7
1.25
248
27
2.2
49.4
199.1
11,9
20.2
90
0
9938
1193.4
LC FGO-C
a '
1.35
125
55
2.2
,33.8"
,270.7
9.4
15.6
90
0
10203
922.3
25-77
-------
Table 25.4.1-5. Summary of. Coal Switching/Cleaning Costs for the Pulliaffl Plant (June 1988 Dollars)
Technology
Boiler
Main.
Boiler Capacity Coal'
Capital Capital Annual
Amual
' soz
(38SSISISS
¦ SOZ .
S02 Cost
Nirfeer Retrofit
Site
Factor
Sulfyr
Cost .
Cost
Cost
Cost
Removed Removed'
Effect.
D
"ffieulty {My)
'<%>
Content
<««>
(S/kU)
(JMM)
.........
....
......
.....
CS/B*i15
3 "
1.00
30 '
5
2.2
2.1
69.3
0.7
55.1
62.0
153
47S0.3
CS/B+S15
4
1.00
30 '
7
2.2
2.0
68.2
0.8
43.2
62.0
214
3724.3
CS/B+115
5
noo
50
20
2.2 ¦
2.9
57.9
2.0
22.3
62.0
1017
1921.8
CS/B+115
• 6
1.00
63
21
2.2 .
'3.5
55.0
2.5
21.2
62.0
1345 ¦
1824.2
CS/S+S15
7
1.00
75
52
2.2
3.7
49.0
5.6
16.3
62.0
3964
1405.8
CS/I+S15
8
1.00
125
55.
2.2
5.7
•. 45.9
9.4
15.6
62.0
6988
1347.6
CS/B*$15-C
3
1.00
30
5
2.2
2.1
69.3
. 0.4
32.3
62.0
153
2782.8
CS/B*f15-C
4
1.00
30
7
2.2
2.0
66.2
0.5
25.3
62.0
214
2176.9
CS/8+S15-C
5
1.00
50
20
2.2
2.9
57.9
1.1
- 12.9
62.0
1017
1113.8
CS/B+I15-C
6
1.00
63
. 21
2.2
3.5
55.0
1.4
12.3
62.0
1345
1056.7
CS/8»*15-C
7
1.00
75
52
2.2
3.7
49.0
3.2
9.4 ¦
62.0
. 3964
809.6
CS/8+S15-G
8
1.00
125
55
2.2
5.7
45.9
5.4
9.0
62.0
6988
775.8
CS/B*$5
3
1.00
30
5
2.2
1.8
5S.9
0.6
42.7
62.0
153
3680.0
CS/i*i5
4
1.00
30
7
2.2
1.7
57.9
0.6
32.0
62.0
214.
2756.9
CS/B+15
5
1.00
SO
20
2.2
2.4
47.5
1.1
.13.0
62.0
1017
1120.7
CS/B+iS
6
, 1-.00
63
21
2.2
2.8
44.6
1.4
, 11.9
62.0
1345
1027.4
CS/B»$5
7
1.00
75
52
2.2
2.9
38.7
2.6
7.7
62.0
3964
659.6
CS/B*S5
a
1.00
125
55
2.2
4.4
35.6
4.2
7.0
62.0
" 6988
603.3
CS/8+I5-C
3
.1.00
30
5
2.2
i.a
58.9
0.3
25.1
62.0
153
2160.4
CS/8H5-C
4
1.00
30
7
2.2
1.7
57.9
0.3
18.7
62.0
214 .
1615.7
cs/a+M-c
5
1.00
50
20
2.2
2.4
47.5
0.7
7.6
62.0
1017
652.5
CS/B+S5-C
6
1.00
63
21
2;2
2.8
44.6
0.8
6.9
62.0
1345
598.0
CS/B+$5-C
7
1.00
¦ 75
52
2.2
2.9
38.7
1.5
4.4
62.0
3964
381.2
CS/B*J5-C
8
1.00
125
. 55 .
2.2
4.4
35.6
2.4
4.0
62.0
6988
348.5
25-78
-------
TABLE 25,4.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR J.. P. PULLIAM
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3,4,5,OR,6 7 8
FIRING TYPE FWF FWF FWF
TYPE OF NOx CONTROL LNB -LNB LNB
FURNACE VOLUME (1000 CU FT) NA 45.1 72.7
BOILER INSTALLATION DATE 1943,43,47,51 .1958 1964
SLAGGING PROBLEM NO NO NO
ESTIMATED NOx REDUCTION (PERCENT)* 40 42 40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW LOW LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0 0
Ductwork Demolition (1000$) 41 22 32
New Duct Length (Feet) 200 500 400
New Duct Costs (1000$) 1366 2094 2258
New Heat Exchanger (1000$) 2590 1568 2131
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE NA 3684 4421
COMBINED CASE 3996 NA NA
RETROFIT FACTOR FOR SCR - 1.16 1.16 1.16
GENERAL FACILITIES (PERCENT) _J3 13 20
25-79
-------
Table 25.4.1-7. HO* Control Cost Results.for the Pulliam Plant (June 1988 Bollars)
Technology
Boiler
Main
Bailer Capacity Coal
Capitat Capital Annual
" Annual '¦
NO*
NOx
NOx Cost
Kiraoer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
¦ cost
Removed
Removed
Effect.
Difficulty
(I/kU)
LNC-INB
3
1.00
¦ 30
5
2.2
1.6
52.6
0.3
25.6
40.0
24
13907.9
tNC-LNS
• 4 '
1.00
30
7
2.2
1.6
52.6
0.3
18.3
40.0
34
9934.2
IKC-LNB
5
1.00 -
50
20
2.2
1.9
38.7
0.4
4.7
40.0
161
• 2558.8
LNC-LNB
' 6
1.00
21
2.2
2.1
. 33.7
0,5
3.9
40.0
214
2122.8
LNC-LMB
7
1.00
75 !
52
2.2
2.3
30.3
0.5
1.4 ¦
42.0
661
735.0
LNC-LNB
8
1.00
125
55
2.2
2.8
22.3
0.6
-1.0"
40.0
1110
537.4
INC-LNB-C
3
1.00
30
5
2.2
1.6
52.6
0.2
15.2
40.0
24
8258.9
LNC-INB-C
' 4
1.00
. 30'
7
2.2
1.6
52.6
0.2
10.9
40.0
34
5899.2
LNC-LNB-C
5
1.00
'50
20
2.2
1.9
38.7
0.2
2.8
40.0
161
1520.0
INC-LNB-C
6
1.00
63
21
2.2
2.1
33.7
0.3
2.3
40.0
214
1260.4
LNC-LNB-C
7
1.00
75
52
2.2
2.3
" 30.3
0.3
o.a
42.0
661
436.5
LNC-U3-C
8
1.00
125
• 55
2.2
2.8
•22.3
0.4
0.6
40.0
1110
319.2
SCR-3
3-6
1.16
173 •
16
2.2'
27.4
158.1
8.9
36.8
80.0
894
9973.7
SCR-3
7
1.16
73
52
2.2
16.8
223.8
5.2
15.3
80.0
1259
4138.8
SCR-3
8 '
1.16
125
55
2.2
23.1
185.1
7.5
12.5
eo.o
2220
3384.4
SCS-3-C
3-6
1.16
173
16
2.2
27.4
158.1
5.2
; 21.6
80.0
894
5851.5
SCR-3-C
7
1.16
75
52
2.2
16.8
223.8
3.1
9.0
80.0
1259 ¦
2431.0
SCR-3-C
8
1.16
125
55
2.2
23.1
185.1
4,4
7.3
80.0
2220
1985.8
SCR-7
3-6
1.16
173
16
2.2
27.4
158.1
7.5
, 30.9
80,0
894
8370.8
SCR-7
.7
1.16
75
52
2.2
16.8
223.8
4.6
13.4
80.0
1259
3645.7
SCt-7
' 8
1.16
125
55
2.2
23.1
185.1
6.5
10.8
80.0
2220
2918.2
SCS-7-C
3-6
1.16
173
16
2.2
27.4
158.1
4.4
18.2
80.0
894
4933.2
scu-r-c
7
1.16
75
52 !
2.2
16.8
223.8
2.7
7.9
80.0
1259
2148.5
SCH-7-C
8
1.16
125
55 . .
2.2
23.1
185.1
3.8
6.3
80.0
2220
1718.7
25-80
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--,
Sorbent injection technologies (FSI and DSD) were not considered for
the J. P. Pulliam plant because of the small sizes of the ESPs and short
duct residence time between the boilers and the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All units would be good candidates for AFBC/CG repowering because of
their small boiler size and limited remaining useful life. This is
particularly true for units 3-6 which have low capacity factors.
25-81
-------
25.4.2 Weston Unit 1,2.3 Steam Plant
Although FGD was evaluated for unit 3, costs were not presented since
the unit is firing a low sulfur coal. In addition, due to the low sulfur
coal, CS was not evaluated for unit 3. Sorbent injection technologies were
not considered for units 1 and 2 due to the inadequate size of the ESPs for
these units. For unit 3, SCR was the only N0X control considered since the
unit is equipped with OFA.
TABLE 25.4.2-1. WESTON UNIT 1, 2, 3 STEAM PLANT OPERATIONAL DATA *
BOILER NUMBER
1 2
3
GENERATING CAPACITY (MW-each)
60 75
322
CAPACITY FACTOR (PERCENT)
35 61
78
INSTALLATION DATE
1954 1960
1981
FIRING TYPE
FRONT WALL
TANGENTIAL
FURNACE VOLUME (1000 CU FT)
NA 49.3
NA
LOW NOx COMBUSTION
NO NO
YES
COAL SULFUR CONTENT (PERCENT)
1.8
0.4
COAL HEATING VALUE (BTU/LB)
11000
9000
COAL ASH CONTENT (PERCENT)
8.5
4.6
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
PAID/OFF-SITE
STACK NUMBER
1 2
3
COAL DELIVERY METHODS
RAILROAD
PARTICULATE CONTROL
TYPE
ESP ESP
ESP
INSTALLATION DATE
1972 1973
1981
EMISSION (LB/MM BTU)
NA NA
NA
REMOVAL EFFICIENCY
99.2 99.5
99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
1.9 1.9
0.3
SURFACE AREA (1000 SQ FT)
NA NA
404
GAS EXIT RATE (1000 ACFM}
NA NA
1405
SCA (SQ FT/1000 ACFM)
NA NA
287
OUTLET TEMPERATURE (*F)
410 330
353
* Some information obtained from plant personnel.
25-82
-------
TABLE 21.4.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR WESTON
UNIT 1 OR 2*
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.20
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.27
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
* L/LS-FGD and LSD-FGD absorbers for units 1 and 2 would be located
on either side of the units. The new FFs would be located
adjacent to the LSD-FGD absorbers.
25-83
-------
TABLE 25.4.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR WESTON UNIT 3*
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
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
1.35
NA
ESP REUSE CASE
1.31
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
* L/LS-FGD and LSD-FGD absorbers for unit 3 would be located east
of unit 3.
25-84
-------
Table 25.4.2-4. Siimry of FGD Control Costs for the Weston Plant (Jine 1988 Dollars)
sssaaBBaaass
33SSE55S
3S8XSSS3S.
83338132
I39I33S!
isaaxssas
K
II
If
It
II
It
II
tl
U
II
«
II
11
3SBSSS
SSSSsasSSSiSS
«SSaS33S
Technology
Boiler Plain
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
$02
$02 Cost
*imber Retrofit
Sue
Factor Sulfur
Cost
Coat
Cost
Cost
Removed Removed
Effect.
Difficulty.(KM)
it)
Content
(WH)
-------
Tabla 25.4.2-5. Suntiary of Coal Switching/Cleaning Costs for the Weston Plant (Jim 1988 Dollars)
Technology Boiler Msfn Boiler capacity Coal capital capital Annual
Nunfeer Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (My) (X) content (MN> ($/ku) (SMO
Factor (%)
Annual $02 S02 S02 Cast
Cost Removed Removed Effect,
(mi IU/kufi) (I) (tons/yr) (t/tan)
CS/B+S15
CS/B+115
1.00
1.00
60
75
35
61
1.8
1.8
2.9
3.4
47.8
44.8
3.3
6,3
17.7
15.7
55.0
55.0
1624
3537
2010.4
1783,7
CS/8*f15-C
CS/B*$15-C
1.00
1.00
60
75
35
61
1.8
1.8
2.9
3.4
47.8
44.8
1.9
3.6
10.2
9.1
55.0
55.0
1624
3537
1159.7
1026.2
CS/B+S5
CS/B*f5
1.00
1.00
60
75
35
61
1.8
1.8
2.2
2.6
37.4
34.4
1.6
2.9
8.9
7.1
55.0
55.0
1624
3537
1007.3
809.4
CS/B*f5 -C
C$/B«*5-C
1.00
1.00
60
75
35
61
1.8
1.8
2.2
2.6
37.4
34.4
0.9
1.7
5.1
4.1
55.0
55.0
1624
3537
583.3
467.0
25-86
-------
TABLE 25.4,2-6. SUMMARY OF NOx RETROFIT RESULTS FOR WESTON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
FWF
FWF
NA
TYPE OF NOx CONTROL
LNB
LNB
NA
FURNACE VOLUME (1000 CU FT)
NA
49.3
NA
BOILER INSTALLATION DATE
1954
1960
NA
SLAGGING PROBLEM
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
40
45
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
22
65
New Duct Length (Feet)
300
300
400
New Duct Costs (1000$)
1103
1256
3928
New Heat Exchanger (1000$)
1372
1568
3759
TOTAL SCOPE ADDER COSTS (1000$)
2493
2846
7753
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for units 1 and 2 would be located on
either side of the units. Cold side SCR reactors for unit 3
would be located east of unit 3.
25-87
-------
Table 25.4.2-7, NOx Control Cost Results for the Weston Plant (Jine 1988 Dollars)
llBaacaiBBiBcaBas&BasasiassvacsDiiBESSlsiosasss33SiBiS933a38asTissi8>c33>iD88SBaflaBaaaasB35sasaBsassaBaB39SS3asD
Technology Boiler Nafn Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cast
Nuitjer Retrofit
Size
Factor Sulfur
Coat
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
(X)
Content
CW*f)
CSMM)
(Mflls/kuN)
(XJ
(tons/yr)
<$/tonj
Factor
(X)
INC-IN8
1
1.00
60
35
1.8
2.1
34.7
0.4
2.4
40.0
353
1258.7
UiC-lNB
2
1.00
75
61
1.8
2.3
30.3
0.5
1.2
45.0
, 866
561.3
INC-INB-C
1
1.00
60
35
1.8 ,
¦ 2.1
34.7
0.3
1.4
40.0
353
747.4
LNC-IM8-C
2
1.00
75
61
1.8
2.3
30.3
0.3
0.7
45.0
866
333.4
SCR-3
1
1.16
, 60
35
1.8
14.5
242.2
4.5
24.2
80.0
706
6304.0
SCR-3
2
1.16
75
61
1.8
16.3
217.0
5.2
13.0
80.0
1539
3381.9
SCR-3
3
1.16
322
78
0.4
45.7
141.9
16.5
7.5
80.0
7599
2176.3
SCR-3-C
1
1.16
60
35
1.8
14.5
242.2
2.6
14.2
80.0
706
3704.1
SCR-3-C
2
1.16
75
61
1.8
16.3
. 217.0
3.1
7.6
80.0
1539
1985.0
SCR-3-C
3
1.16
322
78
0.4
45.7
141.9
9.7
4.4
80.0
7599
1273.8
SCR-7
1
1.16
60
35
1.8
14.5
242.2
4.0
21.5
80.0
706
5597.1
SCR-7
2
1.16
75
61
1.S
16.3
217.0
4.6
11.4
80.0
1539
2976.3
SCR-7
3
1.16
322
78
0.4
45.7
141.9
13.8
6.3
80.0
7399
1812.9
SCR-7-C
1
1.16
60
35
1.8
14.5
242.2
2.3
12.7
80.0
706
3299.1
SCR-7-C
2
1.16
75
61
i;b
16.3
217.0
2.7
6.7
80.0
1539
1752.7
SCR-7-C
3
1.16
321
78
0.4
45.7
141.9
8.1
3.7
80.0
7599
1065.7
25-88
-------
TABLE 25.4.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR WESTON UNIT 3
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$) NA
DUCT DEMOLITION LENGTH (FT) SO
DEMOLITION COST (1000$) 72
TOTAL COST (1000$)
ESP UPGRADE CASE 72
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE • NA
Medium duct residence time exists between unit 3 and the unit
3 ESPs. A medium factor was assigned to ESP upgrade due to the
congestion around the ESPs.
25-89
-------
Table 23.4.2-9. Sumary of OSO/FSI Control Costs for the Weston Plant {Jmw 1988 Dollars?
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 802 SOS Cost
Nuitoer Retrofit Site Factor Sulfur Cost Cost Cost Cost Renewed Removed Effect.
Difficulty (NW) Content
Factor (t)
DSO+ESP 3 1.00 322 78 0.4 8.3 25.7 7.0 3.2 49.0 4806 1462.1
DSO+ESP-C 3 1.D0 322 78 0.4 8.3 25.7 4.1 1.1 49.0 4806 845.4
F$t*ISP*50 3 1.36 322 78 0.4 10.9 33.8 7.2 3.3 50.0 4939 1460.0
FSMSP-SO-C 3 1.36 322 71 0.4 10.9 33.1 4.2 1.9 50.0 4939 846.4
F$I»ESP-70 3 1.36 322 78 0.4 11.0 34,1 7.3 3.3 70.0 6915 1057.3
FSI*£SP-70-C 3 1.36 322 78 0.4 11.0 34.1 4.2 1.9 70.0 6915 612,9
isssssasasas
=a:sc=:a8ssss
25-90
-------
SECTION 26.0 WEST VIRGINIA
26.1 ALLEGHENY POWER SERVICE CORPORATION
26.1.1 Albright
The Albright Steam Plant is located in Preston County, West Virginia,
as part of the Allegheny Power Service Corp. system. The plant contains
three coal-fired boilers with a total gross generating capacity of 278 MW.
Tables 26.1.1-1 through 26.1.1-10 summarize the plant operational data and
present the S02 and NOx control cost and performance estimates.
TABLE 26.1.1-1. ALBRIGHT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME f1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2
69
81,82
1952
FRONT WALL
44.2
NO NO
1.7
12300
12.8
DRY DISPOSAL
LANDFILl/QFF-SITE
1,2 3
TRUCK
3
140
86
1954
TANGENTIAL
93
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (F)
ESP
ESP
1975
1975
0.02
0.02
NA
NA
1.0-1.3
144
259.2
375
675
384
384
400
385
26-1
-------
TABLE 26.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ALBRIGHT
UNIT 1 OR 2 *
FGO TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA •
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.20
NA
ESP REUSE CASE
1.36
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
10
* Absorbers for units 1 and
respective chimneys.
I would be
located behind their
26-2
-------
TABLE 26.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR ALBRIGHT UNIT 3
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOU
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST {1000$)
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
1.31
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
10
* Absorbers for unit 3 would
chimney.
be located
behind the unit 3
26-3
-------
Table 26.1.1-4. Summary of FED Control Costs for the Albright Plant (June 1988 Dollars}
ssR*aB3SBSssscBaasaac«aissssasa«8aRSss8a«c«asscta«iBasaa3«aisaaant«as*aiB»SBBaBi«iiaMaissiaaBCsias3&sa)issas8is
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 502 Cost
Muntoer Retrofit
Size
Factor Sylfur
Cost
cost
Cost
Cost
Removed
Removed
tffeet.
Difficulty
C*J
Content
<*«)
(WN)
(mills/lcwh)
-------
Table 26.1.1*5. SURMfy of Coal SyitcMr>g/C leaning cost* lor th« Albright Plant IJun* 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annuel Annual ,502 SOS S02 Cost
Nuifcer Retrofit
Size
Factor Sulfur
Cost
Cost
cost
Cost
Removed Removed
Effect.
Difficulty (MV)
Content
(SMM)
(I/ton)
Factor
(X)
CS/B+S15
1
1.00
69
81
1.7
3.0
43.0
7.4
15.1
46.0
2992
2471.3
CS/9*S15
2
1.00
69
82
1.7
3.0
43.0
7.5
15.1
46.0
3029
2468.5
CS/B»$15
3
1.00
140.
86
1.7
S.1
36.5
15.1
14.3
46.0
6445
2335.5
CS/i+»15-C
1
1.00
69
81
1.7
3.0
43.0
4.2
8.7
46.0
2992
1420.4
CS/B+S15-C
2
1.00
69
82
1.7
3.0
43.0
4.3
8.7
46.0
3029
1418.7
CS/B+S15-C
3
1.00
140
S6
1.7
'5.1
36.5
8.6
8.2
46.0
6445
1341.6
CS/B»«5
1
1.00
69
81
1,7
2.2
32.6
3.2
6.6
46.0
2992
1077.8
cs/s+$s
2
1.00
69
82
1.7
2.2
32.6
3.3
6.6
46.0
3029
. 1075.5
CS/B+S5
3
1.00
140
86
1.7
3.7
26.2
6.1
5.8
46.0
6445
944.4
CS/B+S5-C
1
1.00
69
81
1.7
2.2
32.6
1,9
3.8
46.0
2992
620.9
CS/B+S5-C
• 2 •
1.00
69
82
1.7
2.2
32.6
1.9
3.8
46.0
1029
619.5
CS/B+S5-C
3
1.00
140
86
1.7
3.7
26.2
3.5
3.3
46.0
. 6445
543.6
II
H
H
II
II
II
II
II
H
II
-------
===*¦=
SSSSSS*
SS 53 S 2 SSS S S
Bsnsawnms
¦5355SB3S2
siMHSsa:
=*==«=
II
»
H
II
It
H
II
It
»
II
26-5
-------
TABLE 26.1.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR ALBRIGHT
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
FIRING TYPE
FWF
TANG
TYPE OF NOx CONTROL
LNB
OFA
FURNACE VOLUME (1000 CU FT)
44.2
93
BOILER INSTALLATION DATE
1952
1954
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
44
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
- 0
0
Ductwork Demolition (1000$)
20
35
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
798
1207
New Heat Exchanger (1000$)
1492
2281
TOTAL SCOPE ADDER COSTS (1000$)
2310
3522
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for all units
their respective chimneys.
would be
26-6
located behind
-------
Table 26,1.1-7. NOx Control Cost Results for the Albright Plant CJme 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Coital Capital Annual Amual NOx NOx NOx Cost
Nwber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU)
Factor
CX5
Content
(X)
(MH>
CS/kH)
(SIW>
(fflllle/kMh)
m
(tons/yr)
(l/ton)
LNC-LMS
1
1.00
69
SI
1.7
2.2
31.9
0.5
1.0
44.0
910
524.3
INC*IMB .
2
1.00
69
82
1.7
2.2
31.9
0.5
1.0
44.0
921 •
517.9
LNC-LN8-C
1
1.00
69
SI
1.7
2.2
31.9
0.3
0.6
44.0
910
311.2
IWC-INB-C
2
. 1.00
69
82
1.7
2.2
31.9
0.3
0.6
44.0
921
307.4
INC-QFA
3
1.00
140
86
1.7
0.7
5.1
0.2
0.1
25.0
795
193.0
LNC-OFA-C
3
1.00
140
86
1.7
0.7
5.1
0.1
0.1
25.0
795
114.7
SCR-5
1
1.16
69
31
1.7
15.2
220.2
5.0
10.2
so.o
1654
3031.7
SCR-S
2
1.16
69
82
1.7
15.2
220.2
5.0
10.1
80.0
1674
2997.6
SCR-3
3
1.16
140
36
1.7
23.9
170.4
8.2
7.8
80.0
2545
3231.6
SCR-3-C
1
1.16
69
ai
1.7
15.2
220.2
2.9
6.0
80.0
1454
1778.2
SCR-3-C
2
, 1.16
69
32
1.7
15.2
220.2
2.9
5.9
so. a
1674
1758.1
SCR-3-C
3
1.16
140
m
1.7
23.9
170.4
4.8
4.6
so.o
2545
1B9J.5
SCR-7
1
1.16
69
81
1.7
15.2
220.2
4.4
9,t
BO. 0
1654
2690.1
SCR-7
2
1.16
69
82
1.7
15.2
220.2
4.5
9.0
SO.O
1674
2660.2
SCR-T
3
1.16
140
86
1.7
23.9
170.4
7.1
6.7
SO.O
2545
2781.3
SCR-7-C
1
1.16
69
81
1.7
15.2
220.2
2.6
5.3
80.0
1654
1582.4
SCR-7-C
2
1.16 '
69
82
1.7
15.2
220.2
2.6
5.3
80.0
1674
1564.8
SCR-7-C
3
1.16
140
86
1.7
23.9
170.4
4.2
3.9
80.0
2545
1635.5
26-7
-------
TABLE 26.1.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ALBRIGHT UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 23
TOTAL COST (1000$)
ESP UPGRADE CASE 23
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS ,
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
ESP size was adequate and sufficient duct residence time
exists between the boilers and their respective ESPs.
26-8
-------
TABLE 26.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ALBRIGHT UNIT 3
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 38
TOTAL COST (1000$)
ESP UPGRADE CASE 38
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
ESP size was adequate and sufficient duct residence time
exists between boiler 3 and the unit 3 ESPs.
LOW
MEDIUM
NA
26-9
-------
Table 26.1.1*10. Surma ry of 0S0/FSI Control Cost* for the Albright Plant (June 1MB Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual 502 S02 SC2 Cost
MkjiAer Retrofit'
Size
Factor Sulfur
Cost
cost
cost
Cost
Removed Removed
Effect.
Difficulty (HUJ
(X)
Content
<*wo
(»/kv>
(SHH)
(mi I Is/kith)
<%>
Ctons/yr}
(S/ton)
Fastor
<%>
DSD»ESP
1
1.00
69
81
' 1.7
5.7
82.6
5.4
10.9
49.0
3175
1637.0
OSO'CSP
2
1.00
69
82
1.7
5.7
82.6
5.4
10.8
49,0
3215
1671.8
DS0*E$P
3
1.00
140
86
1.7
8.0
56.9
7.6
- 7.2
49.0
6841
1108.2
oso«*esp-c
1
. 1.00
69
81
1.7
5.7
82.6
3.1
6.3
49,0
3175
974.6
OSO*ESP-C
2
1.00
69
82
1.7
5.7
82.6
3.1
6.3
49.0
3215
965.8
0SB*ESP-C
3
1.00
140
86
1.7
8.0
56.9
4.4
¦ 4.2 '
49.0
6841
640,1
FSI*fSP-50
1
1.00
69
81
1.7
5.8
84.8
4.7
9.7
50,0
3264
1455.3
FSI+ESP-50
2
1.00
69
82
1.7
5.8
84.8
4.8
9.6
50.0
3304
1445.5
FSi+ESP-50
3
1.00
140
86
1.7
7.8
55.8
7.6
7.2
50.0
7030
1079.7
FS1+ESP-50-C
1
1.00
69
81
1.7
5.8
B4.8
2.7
5.6
50.0
3264
B4t ,9
FSi»ESP-50*C
2
1.00
69
82
1.7
5.8
84.8
2.8
5.6
50.0
3304
836.1
FS1+ESP-50-C
2
1.00
140
86
1.7
7.8
55.8
4.4
4.2
50.0
7030
623,6
FSl*ESP-70
1
1.00
69
fit
1.7
6.0
86.2
4.8
9.9
70.0
4569
1055.7
FSHESP-70
2
1.00
69
82
1.7
6.0
86.2
4.8
9.8
70.0
4625
1048.5
FSI-ESP-70
3
1.00
140
86
1.7
7.9
56.7
7.7
7.3
70.0
9843
784.8
FSI-ESP-70-C
1
1,00
69
#1
1.7
6.0
86.2
2.8
5.7
70.0
4569
610.7
F51+I5P-70-C
2
1.00
69
82
1.7
6.0
86.2
2.8
5.7
70.0
4625
606.5
FSt+ESP-70-C
3
1.00
140
86
1.7
7.9
56.7
4.5
4.2
70.0
9843
453,3
:ss:3s:::sss
«s»
SSS3XC
5S338X1
ssssssss:
—,T1—
3S-533SSS
ssanssa
====3=
11
II
II
II
II
II
tl
II
26-10
-------
26,1.2 Fort Martin Steam Plant
The Fort Martin steam plant is located on the Monongahela River in
Monongalia County, West Virginia, as part of the Allegheny Power Service
system and is operated by the Monongahela Power Company. The Fort Martin
plant contains two coal-fired boilers with a gross generating capacity of
1,107 MW.
Table 26.1.2-1 presents operational data for the existing equipment at
the Fort Martin plant. Coal shipments are received by barge and transferred
to a coal storage and handling area east of the plant. PM emissions from
the boilers are controlled by retrofit ESPs which augment ESPs put in at the
time of construction. The old and new ESPs are installed in series behind
the boilers. Flue gases from each boiler are directed to a chimney between
the old and new ESPs. The utility landfills the dry fly ash from the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located beside the boilers at the east and
west sides of the respective units. The general facilities factor is high
(15 percent) for the FGD absorber locations because several storage
buildings and plant roads would have to be relocated to accomodate space for
a sorbent preparation, waste handling area, and absorbers. The site
access/congestion factor is high for these locations because of interfer-
ences caused by acid/caustic storage, fuel oil storage, miscellaneous
buildings, transmission line and wastewater treatment tank. Approximately
400 feet of ductwork would be required to span the distance from the
chimneys to the absorbers and back to the chimneys. A medium site
access/congestion factor was assigned to flue gas handling because of the
congestion around the chimneys due to the ESPs.
LSD-FGD with reuse of the existing ESPs was considered for the
Fort Martin plant. The LSD absorbers would be located similarly to the wet
FGD absorbers with similar site access/congestion and general facilities
factors as well as ductwork requirements.
Tables 26.1.2-2 and 26.1.2-3 present retrofit factor and cost results for
Installation of FGD technologies at the Fort Martin plant. The low cost
option shows the effect of eliminating spare absorber modules and large
absorber size (-300 MVI).
26-11
-------
TABLE 26.1.2-1. FORT MARTIN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1
2
GENERATING CAPACITY (MW-each)
552
555
CAPACITY FACTOR (PERCENT)
72
68
INSTALLATION DATE
1967
1968
FIRING TYPE
TANGENTIAL
OPPOSED WALL
FURNACE VOLUME (1000 CU FT)
NA
NA •
LOW NOx COMBUSTION
NO
NO
COAL SULFUR CONTENT (PERCENT)
1.8
1.8
COAL HEATING VALUE (BTU/LB)
12500
12500
COAL ASH CONTENT (PERCENT)
11.3
11.3
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
LANDFILL
STACK NUMBER
1
2
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL
TYPE
ESP
ESP
INSTALLATION DATE
1967,82
1968,82
EMISSION (LB/MM BTU)
0.01
0.01
REMOVAL EFFICIENCY
99.7
99.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
1.5-3.5
1.5-3.5
SURFACE AREA (1000 SQ FT)
475.5
475.5
GAS EXIT RATE (1000 ACFM)
2150
2150
SCA (SQ FT/1000 ACFM)
221
221
OUTLET TEMPERATURE (*F)
310
310
26-12
-------
TABLE 26.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR FORT MARTIN
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
MEDIUM
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
1,57
NA
ESP REUSE CASE.
1.58
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
.1.36 -
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
25-13
-------
Table 26.1.2-3. Sunnary of FGD Control Costs for the Fart Hartin Plant (June 1986 Dollars)
Technology Boiler Main Boi ter Capacity Coal Capital Capital Annual Annual S02 S02 502 Cost
MLitber Retrofit Sile Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (Mw) (SJ Content (SMM) [S/lctf) (miits/khh) (%) ttons/yr] (S/ton)
factor (%>„
US FGD
1
1.57
552
Ti
1.8
128.1
232.1
61.3
" 17.6
90.0
"43419
1412.7
US FGO
2
1.57
555
68
" 1.8
128.5
231.6
60.5
18.3
9(3.0
41230
1467.3
u* fgd-c
1
• 1.57
552
72
1.8
128.1
232.1
35.7
10.3
90.0
43419
822.6
l/S FGO-C
2 •
1.57
555 '
68
1.8
128.5
231.6
35.2
10.7
90.0
41230
854.7
LC FQD
1
1.57
552
72
1.8
95.e
172.2
50.7
14.6
90.0
43419
1167.2
LC FGO
2
1.57
555
68
1.8
95.5
172.0
49.8
15.1
90.0
41230
1209.0
LC FGO-C
1 '
1.57
552
72
1.8
95.0
172.2
29.5
8.5
90.0
43419
678.6
IC FGD-C
2
1.57
555
68
T.8 .
95.5
172.0
29.0
8.8
90.0
41230
703.0
LSO+ESP
1
1.58
552
72
1.8
79.4
143.8
35.7
10.3
76.0
36810
969.6
ISD+ESP
2
1.58
555 '
68 "
1.8
79.6
143.5
35.2
10.7
76,0
34954
1007.8
ISD+ESP-C
1
1.58
552
n
1.8
79.4
143.8
20,8
6.0
76.0
36810
565.2
LSO+ISP-C
2
1.58
555
68
1.8
79.6
, ,143.5
20.5
6.2
76.0
34954
587.6
26-14
-------
Coal Switching and Physical Coal Cleaning Costs-
Table 26.1.2-4 presents the IAPCS cost results for CS at the Fort
Martin plant. These costs do not include boiler and pulverizer operating
cost changes or any coal handling system modifications that may be
necessary. PCC was not considered for this plant because it is not a mine
mouth plant.
N0X Control Technologies--
OFAs and LNBs were considered for N0X emissions control for boilers 1
and 2, respectively. Furnace values were not available for units 1 and 2
and were estimated based on similar size and age boilers. Tables 26.1.2-5
and 26.1.2-6 present performance and cost estimates for installation of LNC
technologies at the Fort Martin plant.
Selective Catalytic Reduction-
Cold side SCR reactors for boilers at the Fort Martin plant would be
located adjacent to the ESPs and chimney. A medium site access/congestion
factor was assigned to the locations. Approximately 400 feet of ductwork
would be required to span the distance between the SCR reactors and the
chimneys for a cold side application. Tables 26.1.2-5 and 26.1.2-6 present
the retrofit factor inputs to the IAPCS model and cost estimates for
installation of SCR at the Fort Martin plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for the
Fort Martin plant because of the long duct residence time between the old
and retrofit ESPs. A medium site access/congestion factor was assigned to
the ESP locations because of the proximity of the ESPs to the river.
However, plate area can be added on the east or west side of the ESPs, if
required. Tables 26.1.2-7 and 26.1.2-8 presents retrofit factor inputs to
the IAPCS model and costs for installation of sorbent injection technologies
at the Fort Martin plant.
26-15
-------
Tabte 26.1.2-5. Sumary of Coal Snitching/Cleaning Costs for the Fort Martin Plant (Juna 1988 Dollars)
Technology Boiler Wain Boiler Capecity Coal Capital Capital Annual Annual S02 SOS S02 Cost
Nunfeer Retrofit Size Factor Sulfur cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
TABLE 26.1.2-5. SUMMARY OF NOx RETROFIT RESULTS FOR FORT MARTIN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
"2
FIRING TYPE
TANG
OWF
TYPE OF NOx CONTROL
OFA
LNB
FURNACE VOLUME (1000 CU FT)
. NA
NA
BOILER INSTALLATION DATE
1967
1968
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
. SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
97
98
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
5384
5402
New Heat Exchanger (1000$)
5195
5212
TOTAL SCOPE ADDER COSTS (1000$)
10677
10711
RETROFIT FACTOR FOR SCR
1.34
1.34
GENERAL FACILITIES (PERCENT)
20
20
26-17
-------
Table 26.1,2-6. NO* Control Cost Results for the Fort Martin Plant (June 1988 Dollars}
Technology Boiler Main Boiler capacity Coel Capital Capital.Annual Annuel nox - NQx NO* Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content
-------
TABLE 26.1.2-7, DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR FORT MARTIN UNIT 1 OR 2
ITEM'
SITE ACCESS/CONGESTION
REAGENT PREPARATION ¦" LOW
ESP UPGRADE . MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$). - NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 111
TOTAL COST (1000$)
ESP UPGRADE CASE 111
. A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
26-19
-------
Table 26.1.2-8, Surinary of DSD/F5I Control" Costs for the fort Hartin Plant (June 1988 Oollers)
Technology Boiler Main Boiler Capacity Coat Capital Capital Annual
Number Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (KW> (X> Content (StH} (t/kU) <»W)
Factor (X)
Annual , S02 * $02 • S02 Cost
Cost Removed Retwved Effect,
(oilts/kwh) (%) (tons/yr) (t/ton)
DS0+ESP
DS0«€SP
1.00
1,00
552
555
72
68
1.8
1.8
24.6
24.7
44.6
44.6
19.0
18.5
5.5
5.6
49.0
49.0
23470
22287
808.6
830.4
BSO+ESP-C
DSD+ESP-C
1.00
1.00
552
555
72
68
1.8
1.8
24.6
24.7
44.6
44.6
11.0
10.7
-3.2
3.2
49.0
49.0
23470
22287
468.0
480.7
FSl+fSP-50
PSJ»i$P-50
1.00
1.00
552
555
72
63
1.8
1.8
26.5
26.6
48,0
47.9
23.1
22.3
6.6
6.8
50.0 24122
50.0 22905
956.3
974,7
FSHESP-50-C
fSI*ESP-50-C
1.00
1.00
552
555
72
68
1.8
1.8
26.5
26.6
48.0
47.9
13.3
12.9
3.8
3.9
50.0
50.0
24122
22905
552.8
563.6
f$l*ESP-70
FSI+6SP-7C
1.00
1.00
512
555
72
68
1.8
1.8
26.5
26.6
48.0
47.9
23.4
22.7
6.7
6.9
70.0
70.0
33770
32068
693.6
706.7
f$t«€SP-7C-C
FSI»E5P-70-C
1.00
1.00
552
555
72
63
1.8
1.8
26.5
26.6
48.0
47.9
13.5
13.1.
3.9
4.0
70.0
70. D
33770
32068
400.9
408.6
26
-20
-------
Atmospheric Fluidlzed Bed Combustion and Coal Gasification Applicabil1ty--
The boilers at the Fort Martin plant are too large and new to be
considered for repowering technologies.
26.1.3 Harrison Steam Plant "
The Harrison steam plant is located on the West Fork River in Harrison
County, West Virginia, as part of the Allegheny Power Service system and
operated by Monongahela Power Company. The Harrison plant contains three
coal-fired boilers with a gross generating capacity of 1920 MW.
Table 26.1.-3-1 presents operational data for the existing equipment at
the Harrison plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area east of the plant. PM emissions from
the boilers are controlled by ESPs which were installed at the same time as
the boilers. The ESPs are located behind the boilers. Flue gases from the
three boilers are directed to two chimneys located behind the ESPs. The
first chimney serves unit 1 and the second chimney serves unit 3. Flue
gases from unit 2 are distributed between the two chimneys. Dry fly ash
from the units is landfilled by the utility.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for the three units would be located west of unit 3
in a relatively open area. The general facilities factor is medium
(8 percent) for the FGD absorber location because several plant roads would
have to be relocated. The site access/congestion factor is low for this
location. From 300 feet (for unit 3} and 600 feet (for unit 1J of ductwork
would be required to span the distance from the chimneys, to the absorbers,
to a new chimney for each of the units. Because of the access difficulties
and duct length required to reuse the existing chimneys, a new chimney would
be constructed adjacent to the absorbers. A high site access/congestion
factor was assigned to flue gas handling.
LSD-F6D with reuse of the existing ISPs was not considered for the
Harrison plant because of the small sizes of the ESPs. LSD with new
baghouses was not considered because of the high sulfur content of the coal
being burned.
26-21
-------
TABLE 26.1.3-1. HARRISON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2,3
GENERATING CAPACITY (MW-each) 640
CAPACITY FACTOR (PERCENT) 59,65,48
INSTALLATION DATE 1972,73,74
FIRING TYPE OPPOSED WALL
FURNACE VOLUME (1000 CU FT) 431
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 3.0
COAL HEATING VALUE (BTU/LB) 13000
COAL ASH CONTENT (PERCENT) . 7.7
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL
STACK-NUMBER 1;1,2;2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1972,73,74
EMISSION (LB/MM BTU) ¦ 0.01
REMOVAL EFFICIENCY 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.5-4.5
SURFACE AREA (1000 SQ FT) 187.2
GAS EXIT RATE (1000 ACFM) . 2060
SCA (SQ FT/1000 ACFM) 91
OUTLET TEMPERATURE (*F) ' 270
26-22
-------
Tables 26.1.3-2 and 26.1.3-3 give a summary of retrofit data and costs,
respectively, for installation of L/LS-FGD technologies at the Harrison
pi ant.
Coal Switching and Physical Coal Cleaning Costs-
Table 26 1.3-4 summarizes the IAPCS results for CS at the Harrison
plant. These costs do not include boiler and pulverizer operating cost ,
changes or any coal handling system modifications that may be necessary.
PCC was not evaluated because the Harrison plant is not a mine mouth plant,
N0X Control Technologies--
LNBs were considered for control of N0X emissions from the three
opposed wall-fired furnaces. Tables 26.1.3-5 and 26.1.3-6 give a summary of
performance and cost results, respectively, for NQx control technologies at
the Harrison plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the boilers at the Harrison plant would be
located behind the chimneys. A medium general facilities value of
20 percent and a medium site access/congestion factor were assigned to the
reactor locations. Approximately 300 feet of ductwork would be required to
span the distance between the SCR reactors and the chimneys.
Tables 26.1.3-5 and 26.1.3-6 summarize the retrofit factors and costs for
installation of SCR at the Harrison plant.
Furnace Sorbent Injection and Duct Spray Drying F6D Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the boilers at the Harrison plant because of the small size of the ESPs and
short duct residence time between the boilers and the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The three 640 MW boilers at the Harrison plant are too large to be
considered for AFBC/CG technologies.
26-23
-------
TABLE 26.1.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR HARRISON
UNIT 1,2 OR 3
F6D 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
NO
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA ¦
NA
ESTIMATED COST (1000$)
4480
0
"¦ 0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.41
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
¦ ESP UPGRADE .
NA
' NA
NA
NEW BAGHOUSE.
NA
NA
NA
GENERAL FACILITIES (PERCENT)
8
0
0
26-24
-------
Table 26.1.3-3. Surmary of FGD Control Costs for the Harrison Plant (June 1988 Dollars)
ssssassa
SBXSSSSttSSi
taiBBss::
ss===ss«a=i
II
fl
II
11
II
11
;»ks==ss;s:=:2::=s:;
Technology
Boiler
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
<%>
Concent
CSHM)
JS/ton)
' Factor
c%>
L/S FGD
1
' 1.41-
¦ 640
59
3.0
129.3
202.1
63.8
19.3
90.0
65729
970.0
L/S FGD
2
1.41
640
65
3.0
129.3
202.1
65.9
- 18.1
90.0
72413
910.5
L/S FGD
3
1.41
640
48
3.0
129.3
202.0
59.8
22.2
90.0
53474
1117.7
L/S FGD
1-3
1.41
1920
57
3.0
294.9
153.6
152.8
15.9
90.0
190502
'802.3
L/S FGD-C
1
1.41
640
59
3.0
129.3
202.1
37.1
11.2
90.0
65729
564.6
L/S FGD-C
2
1.41
640
65
3.0
129.3
202.1
38.4
10.5.
90.0
72413
529.6
L/S FGD-C
3
1.41
640
48
3.0
129.3
202.0
34. a
12.9
90.0
. 53474
651.2
L/S FGD-C
1-3
1.41
1920
, 57
3.0
294.9
153.6
88.9
9.3
90.0
190502
466.6
LC FGD
1-3
1.41
1920
57
3.0
263.3
137.2
142.8
14.9
90.0
190502
749.4
LC FGD-C
1-3
1.41
1920
' 57
3.0
263.3
137.2
83.0
8.7
90.0
190502
, 435.5
26-25
-------
Table 26.1.3-4. Surmary of Coal Suitching/Cleaning Costs for Che Harrison Plant (June 1988 Dollars)
Technology
Boiler
Main
BoiIer
Capacity Coal
Capital Capital Annual
Annual
$02-
S02
S02 Cost
Nimber
Retrofi t
Size
Factor
Sulfur .
Cost
Cost
Cost
Cost
Rertoved Renteve
(%)
Content'
C$MM)
ts/ku)
ClHM>
(mi Us/knH
(X)
(toris/yr!
(S/ton)
.Factor
«)
CS/8+S15
' 1
1.00
640,
59
3.0
26.7
41.7
49.8
15.0 _
67.0
-49146
1012,6
CS/B+S15
2
1.00
640
65
3.0,
26.7
41.7
54.2
14.9
67.0
54144
1001.3
CS/B»$15
3
1.00
640
48 .
3.0
26.7
41.7
41.6
15.5
67.0
39983
. 1040.6
CS/B+S15-C
1
1.00
640
59
3.0
26.7
41.7
28.6
8.7
67.0
49146
. 582.6
CS/6tS15-C
2
1.00
640
65
3.0
26.7
41.7
31.2
8.6
67,0
54144
575.9
CS/B+S15-C
3
1.00
640
48
3.0
26.7
- 4-1.7
24.0
8.9
67.0
39963
599.2
CS/B+S5
1
1.00
640
59
3.0
20.1
¦ 31.3
21.3
6.4
67.0
49146
433.1
CS/B+S5
2
1.00
640
65
3.0
20.1
31.3
23.0
6.3
67.0
54144
¦ 424.0
CS/B+S5
3
1.00
640
48
3.0
20.1
31.3
18.2
/ 6.8
67.0
39983
455.6
CS/6+S5-C
1
1.00
640
59
3.0
20.1-
31.3
12.3
3.7
67.0
49146
249.9
CS/B+S5-C
2
1.00
640
65
3.0
20.1
31.3
13.2
3.6
67.0
• 54144
244.6
CS/B+S5-C
3
1.00
640
48
3.0
20.1
31.3
10.5
3,9
67.0
39983
263.3
26-26
-------
TABLE 26.1.3-5. SUMMARY OF NOx RETROFIT RESULTS FOR HARRISON
COMBUSTION MODIFICATION RESULTS
_ FIRING TYPE
TYPE OF NOx CONTROL .
FURNACE VOLUME (1000 CU FT)
BOILER INSTALLATION DATE
SLAGGING PROBLEM
ESTIMATED NOx REDUCTION (PERCENT)
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
Ductwork' Demolition (1000$)
New Duct Length (Feet)
New Duct Costs (1000$)
New Heat Exchanger (1000$)
TOTAL SCOPE ADDER COSTS (1000$)
RETROFIT FACTOR FOR SCR
GENERAL FACILITIES (PERCENT)
BOILER NUMBER
1,2 OR 3
OWF
LNB
431
1972,1973,1974
NO
43
MEDIUM
0
109
300
4403
5677
10189
1.34
20
26-27
-------
Table 26.1,3-6. NQx Control Cost Results for the Harrison Plant (June 1988 Dollars)
isuninnn
========
11
II
II
»
II
II
II
II
s===s===
S==S=BBSS
:s=s===*s
II
II
II
II
II
II
asssssss:s=
:3SSS£~
s=:sssssss!
S55SSS3E8
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annua I
Annual
NQx
NOX
NOx Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
0
ifficulty CKW)
(%>
Content
(SHU) .
tl/ku)
CSMK)
(mills/kwh)
t%)
(tons/yr)
($/ton)
Factor
(X)
LNC-LNB
1
1.00
640
59
3.0
5.4
8.4
1.2
0.4 '
43.0
5636
206.3
LNC-LN8
2
1.00
640
65
3.0
5.4
8.4
1.2
0.3
43.0
6210
187.2
LNC-INB
3
1.00
640
4S
3.0
5.4
8.4
1.2
0.4
43.0
4586
253.5
LNC-LMB-C '
1.
1.00
640
59
3.0
5.4
8.4
0.7
0.2
43;0
5636
122.4
LNC-LNB-C
2
1.00
640
65
3.0
• 5.4'
8.4
0.7
0.2
43.0
6210
111,1
LNC-LMB-C
3
1.00
640
48
3.0
5.4
8.4
0.7
0.3
43.0
4586
' 150.5
SCR-3*
1
1.34
640
59
3.0
84.4
. 131.9
30.6
9.2
80.0
¦' 10486
2913.4
SCR-3
2-
1.34
640
65 ,
, 3.0
84.4
131.9
30.a,
8.4
80.0
11553
2665.2
SCR-3
3
' 1.34
640
48
3.0
84.4
¦ 131.9
30.1
15.2
. 80.0
8531
3531.5
SCR-3-C
1
1.34
640 ,
59
. 3.0
84.4
131.9
17.9-
5.4
80.0
10486
.1705.3
SC«:3*C
2
1.34
640
65
3.0
84.4
131.9
18.0
4.9
80.0
11553
1559.8
SCR-3-C ¦ -•
3
1.34
640
48
3.0
84.4
131.9
17.6
6.6
80.0
8531
2067.7
SCR-7
1
1.34
640
59
3.0
84.4
131.9
25.4
7.7
80.0
10486
2417.8
SCR-7
2
1.34
640
65
3.0
84.4
131.9
25.6
7.0
ao.o
11553
2215.3
SCR-7
3
1.34
640
48
3.0
84.4
131.9
24.9
9.3
80.0
8531
2922.4
SCR-7-C
1
1.34
640
59
3.0
84.4
131.9
14.9
4.5
80.0
10486
1421.4
SCR-7-C
2 '
1.34
640
65
3.0
84.4
131.9'
15.0
4.1
80.0
11553
1302.0
SCR-7-C
3
1.34
"640
4a
3.0
84.4
131.9
14.7
5.4
80.0
8531
1718.7
26-28
-------
26.1.'4 Pleasants Steam Plant
Both units at the Pleasants plant are equipped with a Lime Tray FGD
system; therefore, no further S02 control technologies were considered for
these units
this unit.
Unit 2 has LNBs so SCR was the only N0X control considered for
TABLE 26.1.4-1. PLEASANTS STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME {1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM (TYPE) .
FGD SYSTEM (INSTALLATION DATE)
1, 2
684
81, 80
1979, 1980
OPPOSED WALL
503
NO, YES
2.7
12400
12
DRY DISPOSAL
STORAGE/ON-SITE
1, 2
RAILROAD/BARGE
WET LIME FGD
1979, 1980
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 (SO FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
1979,
0.02
NA
1980
1,8-3.5
746.5
2400
311
200-300
26-29
-------
TABLE 26.1.4-2, SUMMARY OF NOx RETROFIT RESULTS FOR PLEASANTS
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
OWF
OWF
TYPE OF NOx CONTROL "
LNB
EQUIPPED WITH LNB
FURNACE VOLUME (1000 CU FT)
503
503
BOILER INSTALLATION DATE
1979
1980
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
51
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
114
114
New Duct Length (Feet)
300
300
New Duct Costs (1000$)
4578
4578
New Heat Exchanger (1000$)
5908
5908
TOTAL SCOPE ADDER COSTS (1000$)
10600
10600
RETROFIT FACTOR FOR SCR
1.52
1.16
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for unit 1 would be located northeast
of the unit 1 chimney beyond the coal conveyor. Cold side SCR
reactors for unit 2 would be located southwest of the unit 2
chimney next to the coal pile.
26-30
-------
Table 26.1.4-3'. MOx Control Cost Results for. the Pleasants Plant (Jjn« 1988 Dollars)
Technology Boiler Cain Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Huifcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect,
Difficulty CKWJ fX) Content cSMM) (S/KV) (Mm) (nltls/kuh) CS) ttons/yr) (t/ton)
Factor (X)
LUC-IMS
LUC-LMS-C
SCR-3
SCR-3
SCR-3-C
SCR-3-C
SCS-7
SCR-7
SCR-7-C
SCR-7-C
1.00
1.00
1.52
1.16
1.12
1.16
1.52
1.16
1.52
1.16
634
.634
684
684
684
684
684
684
684
684
81
81
81
80
81
80
81
80
81
80
2.7
2.7
2.7
2,7
2.7
2.7
2.7
2.7
'2.7
2.7
5.5
5.5
8.1 1.2
8.1 0.7
97.4 142.4 35.6
82.9 121.2 31.9
97.4 142.4 ' 20.8
82.9 121.2 16.6
97.4 142.4 30.0
82.9 121.2 26.3
97.4 142,4 17.6
82.9 121.2 15.4
-0.2
0.1
7.3
6.7
4.3
3.9
6.2
5.5
3.6
3.2
51
'51
8D
SO
SO
30
80
80
80
60
10355
10355
16244
16043
16244
16043
16244
16043
16244
16043
115.3
•68.4
2189.0
• 1987.3
1281.1
1161.8
1844.7
1638.7
1083.8
962.0
26-31
-------
26.2 APPALACHIAN POWER COMPANY
26.2.1, J.E. Amos Steam Plant.
Retrofit factors for FGD were evaluated for the boilers at the Amos
plant; however, costs are not presented due to the low sulfur content of the
coal that is presently being fired. CS was not evaluated since the boilers
currently fire a low sulfur coal.
TABLE 26.2.1-1. AMOS STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1
2
3
816
' 816
1300
44
71
56
1971
1972
1973
OPPOSED
WALL
NA
480
NA
NO
NO
NO
0.7
12260
10.8
DRY
DRY
WET
LANDFILL POND
1 1 2
BARGE/RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM ITU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
ESP
1978
1977
1973
0.01
0.01
0.05
99.8
99.8
99.5
0.8
0.8
0.8
2194.9
2194.9
1773.
3000
3000
4402
732
732
403
370
370
328
26-32
-------
TABLE 26.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR AMOS
UNITS 1 AND 2 *
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
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM, LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000S)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.38
NA
ESP REUSE CASE
1.49
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.37, 1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
* L/S-FGD and LSD-FGD absorbers for units 1 arid 2 would be
located behind the common chimney and ESPs for units 1 and 2,
after relocating a warehouse and maintenance buildings. A
medium site access/congestion factor was selected (instead of
low) to account for moving the above mentioned buildings.
26-33
-------
TABLE 25.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR AMOS UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA .
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
100-300
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
9346
NA
9346
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000S)
0
o
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
1.35
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
* L/S-FGD and LSD-FGD absorbers for unit 3 would be.located
beside the unit 3 chimney. The LSD-FGD absorbers would be
located beside the ESPs.
26-34
-------
TABLE 26.2.1-4. SUMMARY Of NOx RETROFIT RESULTS FOR AMOS
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2 3
FIRING TYPE OWF OWF
TYPE OF NOx CONTROL ' : LNB LN8
FURNACE VOLUME (1000 CU FT) NA, 480 NA
BOILER INSTALLATION DATE 1971, 1972 1973
SLAGGING PROBLEM , NO NO
ESTIMATED NOx REDUCTION (PERCENT) 40 55
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0
Ductwork Demolition (1000$) 131 185
New Duct Length (Feet) 300 200
New Duct Costs (1000$) 5076 4444
New Heat Exchanger (1000$) 6568 8685
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 11774 13314
COMBINED CASE 17788 NA
RETROFIT FACTOR FOR SCR 1.34 1.16
GENERAL FACILITIES (PERCENT) 38 20
* Cold side SCR.reactors for units 1 and 2 would be located
beside their common chimney. Cold side SCR reactors for
unit 3 would be located beside the unit 3 chimney.
26-35
-------
Table 26.2.1-5
NOx
Control'
Cast Results for
the Ames Plant
(June 1988 Dollars)',
sssscaKsaBsa
technology
Btiefasssa
Boi ter
S332S3333-
Nain
saasaasasasaasaaaaaaass
Boiler Capacity Coal .
Capital Capital Annuel
Annual
NOX
' NOx
NQX Cost
Nurfcer
Bet rof it
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty CUM)
m
Content
(MO
(SMM)
(mi 1Is/knh)
(«
(S/ton)
Factor
m
WC-lM
1
1.00
816
44
0.7
5.9
7.2
1.3
0.4
40
0
5332
240.3
LNC-LNB
2
1.00
816
71
0.7
5.9
7.2
1.3
0.3
40
0
8604
148.9
INC-LNB
3
.1.00
1500
. 56
0.7
7.1
5.5
1.5
0.2
55
0
14866
103.8
LNC-LNB-C
1
1.00
816
64
0.7
5.9
7.2
o.a
0.2
40
0
¦5332 i
142.6
ING-INB-C
2
1.00
816
71
0.7
5.9
7.2
0.8
0.1
40
0
8604
88.4
IHC-IUB-C
3
1.00
1300
56
0.7 '
7.1
5.5
0.9
0.1
55
0
14866
61.6
SCR-3
1
1.34.
816
44
0.7
111.8
137.0
39.4
12.5
80
0
10665
3698.4
SCR *3
2
1.34
816
71
0.7
,111.8
137,1
40.8
8.0
80
0
17209
2373.2
SCR-3
i-z
1.34
1632
58
0.7
210.6
129.0
77.2
9.3
80
a
28116
2747,4
sen-3
3
1,16
.1300
56
0.7
146.0
112.3
56.1
8.8
80
0
21624
2592.8
SCR-3-C
1
1.34
816
44
0.7
111.8
137.0
23.1
7.3
80
0
10665
2165.9
SCR-3-C
2 .
1.34
816
71
0.7
111.8
137,1
23.9
4.7
80
0
17209
1388.8
SCR-3-C
1-2
1.34
1632
58
0.7
210,6
129.0
45.2
5.5
80
0
23116
1607.6
SCR-3-C
'3.
1.16
1300
56
0.7
146.0
112.3
32.8
5.1
SO
0
21624
1515.8
SC8-7
1
1.34
816
44
0.7'
111.8
137.0
32.8
10.4
80
0
10665
3071.6
SCR-7
2
• 1.34
816
71
0.7
111.8
137.1
34.2,
6.7
80
0
17209
1984.8
SCR-7
¦ 1-2
1.34
1632
58
0.7
210.6
129.0
63.9
7.7
60
0
28116
2271.9
SCR-7
3
1.16
1300
56
0,7
146,0
112.3
45.4
7.1
80
0
21624
2100.4
SCR-7-C
1
1.34
116
44
0.7
111.8
137.0
19.3
6.1
80
a
10665
1806.8
SC8-7-C
. 2
1.34
816
71
0.7
111.8
137.1
20.1
4.Q
60
0
17209
1166.3
SCR-7-C
1-2
1.34
1632
58
0.7
210.6
129.0
37.5
4.5
60
0
28116
1335.2
SCR-7-C
3
1.16
1300
56
¦0.7
146.0
112.3
26.7
4.2
80
0
21624
1233.7
a8SS«£335S = SSS3SSa3535SSSSSaS3SS3S3SXSSSSSSSSSS3SBSSSSS£SS5aSSSrSS53SS3SSXS*?=SSa3S3SSSSS2S=a3C=SS5S3SS:SSS*SS:2:8S3
26-36
-------
TABLE 26.2.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR AMOS UNITS 1 AND 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$) 144
TOTAL COST (1000$).
ESP UPGRADE CASE 144
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE ; NA
Long duct residence time exists between the units and their
respective ESPs.
26-37
-------
TABLE 26.2.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR AMOS UNIT 3
ITEM
SITE ACCESS/CONGESTION
,REAGENT PREPARATION
LOW
ESP UPGRADE
LOW
NEW BAGHOUSE
NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING
YES
ESTIMATED COST (1000$)
9346
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
NA
ESTIMATED COST (1000$)
NA
ESP REUSE CASE
NA
ESTIMATED COST (1000$)
NA
DUCT DEMOLITION LENGTH (FT)
50
DEMOLITION COST (1000$)
205
TOTAL COST (1000$)
ESP UPGRADE CASE
9551
A NEW BAGHOUSE CASE
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.13
ESP UPGRADE
1.16
NEW BAGHOUSE
- NA
Short duct residence time exists between unit 3 and the
unit 3 ESPs. A low factor was assigned to ESP upgrade
since space is available around the ESPs. If the duct
residence time at full load is less than 1-2 seconds,
these technologies will not be able to achieve 50-70%
reduction.
26-38
-------
Table 26.2.1-8. Sunnary cf DSB/FSt Control Costs for the Amos Plant (June 1988 Dollars)
=============
=====
===========:
=======
===»===«===*====:
=========
!=======:
:==================
;====*=
:S33==SBS3
ssssacBssar
Technology
Boiler Main
Sailer Capacity Coal
Capital Capita: Annual
Annual
$02
502
S02 Cost
Nmiber Retrofit
Size
Factor
Sulfur
Cost
Cost ,
"Cost
Cost
Removed Removed
Effect.
Difficulty,(MW)
(X)
Content
(SUM)
(SUM)
(mills/kwh]
(*>
.(tons/yr)
(t/ton)
Factor
<*3
DSD-ESP
1
1,00
8.16
44
0.7
19.1
23.4
12.6
4.0
49.0
8431
1495.4
DSD* ESP
2
1.00
816
71 '
0.7
19.1
23.4
15.6
3.1
49.0
136Q5
1143.2
DSD+ESP
3
1.C3
814
56
0.7
29^0
35.5
15.6
3.9
49.0'
10730
1449.5
CSD*ESP-C
1
'.1.00
816
44
0,7
19.1
23.4
7.3
2.3
'49.0
8431
866.9
DSC+ESP-C
2
1.0(5
816
71
0.7
19.1
23.4
9.0
1.8
49.0
13605
661.3
DSD-ESP-C
3
1.09
816
56
0.7
29.0
35.5
. 9.0
2.3
49.0
10730
842.6
FSI+ESP-50
1
1.00
816
44
. 0.7'
20,3'
24.9
12.2
3.9
50.0
8665
1402.3
FSI+ESP-50
2
1.0(3
816
•71
0.7
20.5
24.9
15,7
'3.1
50.0
139B2
1122.3
FSH-ESP-50 .
3
1.00
1300
56
0.7
38.5
29.6
21.8
3.4
50.0
17569
1242.8
FSI*ESP-50-C
1
1.00
816
44
0.7
20.3
24.9
7.1
2.2
50.0
8665
.813.9
FSI'fSP-50-C
2
1.00
816
71
0.7
20.3
24.9
9.1
1.8
50,0
13982
649.6
FSI»E5P-50-C
3
1.00
1300
56
0.7
.38,5
29.6
12.7
2.0
50.0
17569.
721.9
FSI+ISP-70
1
1.00
816
44
0.7
20.5
25.1
12.3
3.9
70.0
12131
' 1015.5
FSI*ESP-70
' 2
1.00
816
71
. 0.7
20.5
25.1
15.9
3.1 '
70.0
19575
814.3
FSI*€SP-70
3
1,00
1300
56
0.7'
38.7
29.8
22.2
: 3.5
7C.0
. 24S97
900.7
FSl*ESP-70-C
1
1.00
816
44
0.7
20.5
25.1
7.1
2.3
70.0
12131 •
589,4
FSi+ESP-70-C
,2
1.00
816
71
0.7 '
20:5
2S.1
9.2
1.8
70.0
19575
471.2
FSI~ESP-7D-C ¦
3
1.00
1300
56 '
0.7
38.7
29.8
12.9
2.0
70.0
24597
523.1
26-39
-------
26.2.2 Mountaineer Steam Plant
The Mountaineer steam plant is located on the Ohio River in Mason
County, West Virginia, and is operated by the Appalachian Power Company.
The Mountaineer plant contains one coal-fired boiler with a gross generating
capacity of 1,300 MW.
Table 26.2.2-1 presents operational data for the existing equipment at
the Mountaineer plant. Coal shipments are received by barge and transferred
to a coal storage and handling area north of the plant. PM emissions from
the boiler are controlled by ESPs which were built at the same time as the
boiler. The ESPs are located behind the boiler. Flue gases from the boiler
are directed to a chimney behind the ESPs. The utility pays for disposal of
fly ash off-site. Because the boiler complies with the 1971 NSPS, SO^ and
NOx control costs were not developed for many of the technologies.
Li me/Li me stone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located behind the chimney. The general
facilities factor is medium (8 percent) for the FGD absorber location
because a plant road would have to be relocated. The site access/congestion
factor is low for this location. Approximately 200 feet of ductwork would
be required to span the distance from the chimney to the absorber and back
to the chimney. A low site access/congestion factor was assigned to flue
gas handling.
LSD with reuse of the existing ESPs was considered for the Mountaineer
plant because of the large size of the existing ESPs. The LSD absorbers
would be located on the north side of the ductwork leading from the boiler
to the ESPs. The general facilities value for this location is medium
(8 percent) because a road would have to be relocated. The site access/
congestion factor for the location is low. Approximately 400 feet of
ductwork would be required and the site access/congestion factor for flue
gas handling is low.
Table 26.2.2-2 presents the retrofit factor data for installing L/LS
and LSD-FGD technologies at the Mountaineer plant. FGD cost estimates 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 low
26-40
-------
TABLE 26.2.2-1. MOUNTAINEER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1
GENERATING CAPACITY (MW-each) 1300
CAPACITY FACTOR (PERCENT) 79
INSTALLATION DATE 1980
FIRING TYPE OPPOSED WALL
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION YES
COAL SULFUR CONTENT (PERCENT) 0.7
COAL HEATING VALUE (BTU/LB) 12600
COAL ASH CONTENT (PERCENT) 10.2
FLY ASH SYSTEM DRY
ASH DISPOSAL METHOD PAID DISPOSAL
STACK NUMBER 1
COAL DELIVERY METHODS BARGE
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1980
EMISSION (LB/MM BTU) 0.01
REMOVAL EFFICIENCY 99,9
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.0-1.0
SURFACE AREA (1000 SQ FT) 4390
GAS EXIT RATE (1000 ACFM} . 5100
SCA (SQ FT/1000 ACFM) 861
OUTLET TEMPERATURE (*F) 355
26-41
-------
TABLE 26.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MOUNTAINEER
UNIT 1
FGD TECHNOLOGY
L/LS FGD
FORCED
OXIDATION
' LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA -
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO •
NO
RETROFIT FACTORS
FGD SYSTEM
] .20
NA
ESP REUSE CASE
1.27
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
26-42
-------
sulfur coal would result in low estimates of capital/operating costs and
high cost effectiveness values.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Mountaineer plant because low
sulfur coal is already being burned at the plant.
N0X Control Technologies--
The Mountaineer plant has LNBs installed; therefore, additional
combustion modification techniques for control of N0X emissions were.not
considered. ' ' .
Selective Catalytic Reduction--
Hot side SCR reactors for the boiler at the Mountaineer plant would be
located adjacent to the ESPs north of the air preheaters. A medium general
facilities value (20 percent) and a low site access/congestion factor were
assigned to the location. About 300 feet of ductwork would be required to
span the distance between the SCR reactors and the ESPs. Tables 26.2.2-3
and 26.2.2-4 present the retrofit factors and cost estimates for
installation of SCR at the Mountaineer plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) would be particularly well
suited for the Mountaineer plant because of the sufficient duct residence
time between the boiler and the ESPs and the large size of the ESPs.
Tables 26.2.2-5 and 25.2.2-6 present retrofit factors and costs for
installation of sorbent injection technologies at the Mountaineer plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The 1,300 MW boiler at the Mountaineer plant is too large and new to be
considered for AFBC/CG repowering.
26-43
-------
TABLE 26.2.2-3. SUMMARY OF NOx RETROFIT RESULTS FOR MOUNTAINEER
BOILER NUMBER
' COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE NA
TYPE OF NOx CONTROL , NA
FURNACE VOLUME (IOOO CU FT) NA
BOILER INSTALLATION DATE NA
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS _ .
, SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 185
New Duct Length (Feet) 300
New Duct Costs (1000$) 6665
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$) 6851
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
26-44
-------
Table 26.2,2-4, NOx Control Cost Results far the Mountaineer Plant (June 1983 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital ftmual Annual HO* NOx VQx Cost
Number Retrofit Size Factor Sulfur Cost Cost -Cost Cost Removed Removed Effect.
Difficulty Content (tMM) (t/kWJ (WM) (mills/huh) (X)
-------
TABLE 26.2.2-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MOUNTAINEER UNIT 1
ITEM : ; '
SITE ACCESS/CONGESTION 1
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$} NA
DUCT DEMOLITION LENGTH (FTJ 50
DEMOLITION COST (1000$) 205
TOTAL COST (1000$)
ESP UPGRADE CASE 205
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
26-46
-------
Table 26.2.2-6. sunwry of BSO/FSI control Costs for the Nouritiln««r Plant (tons/yr) (S/tort)
Factor (*>
DS0«ES» 1
DSD+ESP-C 1
FSI+ESP-50 ' 1
FSI+ESP-50-C - 1
FSI*ESP-ra , 1
FSt*ESP-70-C 1
1.00 1300 79 0.7 27.0 20.B 25.1 . 2.6 49.0 23371 987.1
1.00 1300 '79 0.7 27.0 20.B 13.3 - 1.S 49.0 23371 570.7
1,00 . 1300 79 0.7 • 29.4 22.6 24.7 2.7 50.0 24019 1028.0
1.00 1300 79 0.7 ' 29.4 22.6 14.3 1.6 50.0 24015 594.5
1.00 1300 '¦ 79 0.7 29.6 22.8 25.1' 2.8 70.0 33627 746.7
1.00 1300 79 ' 0.7 29.6 22.8 14.5 1.6 70.0 33627 431.7
BaBEaBaaBBBBBBBaBBataBBBsaaaBEaBsaBSBasBssasaBBaBsaasBasaaBaaaBEaBBMMRBsaMBBaBBaBaaaBBaBaBaaBaaaBBaaaaaaaaaaasaac
26-47
-------
26.3 'CENTRAL OPERATING COMPANY
26.3.1 Philip Sporn Steam Plant
The Philip Sporn steam plant is located on the Ohio River in Mason
County, West Virginia, and is operated by the Central Operating Company.
The Philip Sporn plant contains five coal-fired boilers with a total gross
generating capacity of 1,108 MW.
Table 26.3.1-1 presents operational data for the existing equipment at
the Sporn plant. Coal shipments are received by barge and transferred to a
coal storage and handling area north of the plant. PM emissions from the
boilers are controlled by retrofit ESPs. The ESPs are located behind the
boilers and stacks. Flue gases from the boilers are directed to two
chimneys; one for units 1-4 and one for unit 5. The chimney for units 1-4
is located between the unit 2 and unit 3 ESPs. The chimney for unit 5 is
located behind the unit 5 boiler. Fly ash from the units is disposed of in
ponds to the north of the plant or stored in ash silos.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-F6D absorbers for units 1-4 would be located, behind the unit 1-4
chimney and absorbers for unit 5 would be located on the west side of the
unit 5 ESPs. The general facilities factor is high (15 percent) for the
unit 1-4 L/LS-FGD absorber location because a plant road, several ash silos,
and part of an employee parking area would have to be relocated. The
general facilities value is medium (8 percent) for the unit 5 location
because a storage building would have to be relocated. The site access/
congestion factor is low for all the absorber locations. Approximately
400 feet of ductwork would be required to span the distance from the chimney
to the absorber and back to the chimney for units 1-5. A medium site
access/congestion factor was assigned to flue gas handling for the L/LS-FGD
absorbers for all units because of the obstruction caused by the ESPs,
LSD with reuse of the existing ESPs was considered for units 1-5 at the
Philip Sporn plant because of the adequate sizes of the existing ESPs. The
LSD absorbers for units 1 and 4 would be located on the north and south
sides of the unit 1 and 4 ESPs, respectively. The absorbers for
26-48
-------
TABLE 26.3.1-1. PHILIP SPORN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
IOOO CU FT)
ON
ENT (PERCENT)
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON
COAL HEATING VALUE (8TU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2,3,4 5
153 496
39,32,45,36 50
1950,50,51,52 1960
FRONT WALL OPPOSED WALL
NA
NO
I.0
12300
II.5
DRY
SILOS
1
NA
NO
I.0
12300
II.5
WET
POND
BARGE
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1980,80,79,79 1978
EMISSION (LB/MM BTU) 0.01. 0.01
REMOVAL EFFICIENCY 99.6 99.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0 2.0
SURFACE AREA (1000 SQ FT) 424.2 424.2
GAS EXIT RATE (1000 ACFM) 600 1759
SCA (SQ FT/1000 ACFM) 707 241
OUTLET TEMPERATURE (*F) 315 310
26-49
-------
units 2 and3 would be located between the unit 2 and 3 ESPs and the unit 5
absorbers would be located on the west side of the unit 5 boiler. The
general facilities value for the unit 1,3, 4, and 5 locations is medium
(8 percent) and high (15 percent) for unit 2 because several ash silos and a
plant road would have to be relocated. The site access/congestion factor is
low for these locations. The flue gas handling site access/congestion
factor is low for units 1-4 absorber locations and medium for the unit 5
location because of the limited space between the ESPS and the boiler for
this unit. About 300 feet of ductwork would be required for installation of
the LSD system for units 1-4 and 400 feet would be required for unit 5.
Tables 26.3.1-2 through 26.3.1-5 present the retrofit factors and cost
estimates for installation of conventional FGD technologies at the Philip
Sporn steam plant.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Philip Sporn plant because low
sulfur coal is already being burned at the plant.
N0X Control Technologies--
LNBs were considered for N0X emissions control for the four front
wall-fired furnaces and one opposed wall-fired furnace at the Philip Sporn
plant. Tables 26.3.1-6 and 26.3.1-7 present performance and cost estimates
for installation of N0X emission control technologies at the Philip Sporn
plant.
Selective Catalytic Reduction-
Cold side SCR reactors for the boilers at the Philip Sporn plant would
be located beside the ESPs. A medium general facilities value (20 percent)
and a low site access/congestion factor were assigned to the reactor
locations. About 400 feet of ductwork would be required to span the
distance between the SCR reactors and the chimneys. Tables 26.3.1-6 and
26.3.1-7 present the retrofit factors and cost estimates for installation of
SCR at the Philip Sporn plant.
26-50
-------
TABLE 26.3.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR
UNIT 1, 3 OR 4
PHILIP SPORN
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING MEDIUM NA
'ESP REUSE CASE LOW
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE . NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATEO COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.35 NA
ESP REUSE CASE 1.27
BAGHOUSE CASE . NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL: FACILITIES (PERCENT) 15 0 8
26-51
-------
TABLE 26.3.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR PHILIP SPORN
UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE .
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO .
NA
NO •
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.35
NA
ESP REUSE CASE .
1.27
BAGHOUSE CASE
NA •
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
26-52
-------
TABLE 26.3.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR PHILIP SPORN
UNIT 5
FGD TECHNOLOGY
FORCED / LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-500
BAGHOUSE
NA-
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
3940
NA
3940
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.42
NA
ESP REUSE CASE
1.38
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1,36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
26-53
-------
Table 26.3.1-5. Stmmary of FGO Control Costs for the Sporn Clint (Jlvw 1983 Dollars)
Technology
Boilee
Main
Boiler Capacity Coal
Capital Capital Annual
Annual -
S02
S02 '
S02 Cost
Member
Retrofit
Size
Factor
Sulfur
Cost
cost
Cost
.Cost
Removed Removed
Effect.
Difficulty (NU5
-------
TABLE 26,3,1-6. SUMMARY OF NOx RETROFIT RESULTS FOR PHILIP SPORN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS '•
1,2,3,4 5
FIRING TYPE FWF OWF
TYPE OF NOx CONTROL LNB LNB
FURNACE VOLUME (1000 CU FT) NA NA
BOILER INSTALLATION DATE 1950,50,51,52 1960
SLAGGING PROBLEM NO NO
ESTIMATED NOx REDUCTION (PERCENT) 40 40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR " LOW LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0
Ductwork Demolition (1000$) 37 90
New Duct Length (Feet) 400 400
New Duct Costs (1000$) 2537 5058
New Heat Exchanger (1000$) 2401 4872'
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 4975 10020
COMBINED CASE 11351 NA
RETROFIT FACTOR FOR SCR 1.16 1.16
GENERAL FACILITIES (PERCENT) 20 20
26-55
-------
Table 26.3.1-7. NOx Control Cost Remits for the Sporn Plant (Jirm 1988 Dollars)
assassasssa
iaS3383K3
5333SSB
3SS»t«E3
assssjaexssassBSaBaasasssaBsssBssss
S3SSS2
===========
¦ = s=a!S=a=
Technology
Sailer
Main
Boilar Capacity Coat
Capital Capital Annual
Annual
NOX
NOx
MOx Cost
Mwfcer
Retrofit
Size
factor
Sulfur
Cost"
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty <*W)
(X)
Content
amy
(VkU)
(mi lls/kyti)
«>
(torts/yrJ
(S/toriJ
factor
M
•
IKC-LHB
' 1 ,
1.00
153
39
1.0
3.0
19.8
0.7
1,3
40.0
883
742.9
IMC-U8
2
1.00
153
32
1.0
3.0
19.8
0.7
1.5
40,0
724
905.4
LNC-LNB
3
1.00
155
45
1.0
3.0
19.8
0.7
¦ 1-1
40.0
1019
643.9
IMC-1MB
4
1.00
151
36
1.0
• .3.0
19.8
0.7
1.4
40.0
815
804.8
IMC-LNB
5
1.00
496
50
1.0
4.8
9.8
1.0
0.5
40.0
3669
286.)
LHC-LNI-C
1
1.00
153
39
1.0
3.0
19.B
0.4
0.7
40.0
883
441.1
LUC-LNi-C
2
1.00
153
32
1.0
3.0
19.8
0.4
0.9
40.0
724
537.5
LNC-LNB-C*
3
1.0Q
153
45
1.0
3.0
19.8
0.4
0.6
40.0
1019
382.2
LNC-LNB-C
4
1.00
153
36
1.0
3.0
19.8
0.4
0.8
40.0
815
477.8
INC-Urt-C
: s
1.00
496
50
1.0
4.8
9.8
0.6
0.3
40.0
3669
169.9
SCR-3
1
1.16
153
39
1.0
26.4
- 172.8
8.6
16.5
80.0
1766
4890.9
SCR-3
2
1.16
153
32' .
1.0
26.4
172.8
8.6
20.0
80.0
1449
5917.9
SCR-J
3
1.16
153
45
1'.0 "
26.4
172.8
8.7
14.4
80.0
2037
4265.7'
SCR-3
4
1.16
153
36
1.0
26.4
172.8
8.6
17.8
80.0
1630
5282.0
SCR-3
1-4
1.16
612
38
1.0
76.7-
125.3
27.5
13.5
80.0
6882
3989.0
SCR-3
5
1.16
496
50
'l.O
64.2
129.5
23.0
. 10.6
80.0
7339
3130.7
SCR-3-C
1
1.16
153
39
1.0
26.4
172.8
5.1
9.7
80.0
1746
2869,3
SCR-3-C
2
1.16
153
32
1.0
26.4
172.8
5.0
11.7
80.0
1449
3472.4
SCR-3-C
3
1.16
153
45
1.0
26.4
172-9
5.1
8.5
80.0
2037
2502.1
SCR-3-C
4
1.16
153
36
1.0
26.4
172.8
5.1
10.5
80.0
1630
3099.0
SCR-3-C
1-4
1.16
612
38
1.0
76.7
125.3
16.1
7.9
80.0
6882
2335.4
SCR-3-C
5
1.16
496
50
1.0
64.2
129.5
13.5
6.2
80.0
7339
1832.9
SCR-7
1
1.16
153
39
1.0
26.4
172.8
7.4
14.1,
80.0
1766
4181,5
SCR-7
2
1.16
153
32
1.0
26,4
172.8
7.3
17.1
80.0
1449
5053.2
SCR-7
3
1.16
153
45
1.0
26.4
172.8
7.4
12.3
80.0
2037
3650.8
SCR-7
4
1.16
153
36
1.0-
26.4
172.8
7.4
15.2
80.0
1630
4513,4
SCR-7
1-4
1.16
612
38
1.0
76.7
125.3
22.4
¦ 11.0
80.0
6882
3260,9
SCR-7
5
1.16
496
50
1.0
64.2
129.5
18.9
8.7
80.0'
.7339
2577.4
SCR-7-C
1
1.16.
153
39
1.0
26.4
172.8
4.3
8.3 -
80.0
1766
2462,8
5CR-7-C
• 2
1.16
¦¦ 153
32
1.0
26.4
172.8
4.3
10.1
88.0
1449
2977.0
SCR-7-C
3
1.16
153
45
1.0
26.4
172.8
4.4
7.3
80.0
2037
2149,9
SCK-7-C
4
¦1.16
153
36
1.0
26.4
172.8
4.3
9.0
30.0
1630
2658.6
SCR-7-C
1-4
1.16
612
38
1.0
76.7
125.3
13.2
6.5
30.0
6882
1918.3
SCR-7-C
5
1.16
496
50
1.0
64.2
129.5
11.1
5.1
80.0
7339
1515.9
s=a==a==s
II
II
II
It
II
laieaaaaa;
nsiHsnsmsn
ssassass
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saaiSJtaaEssss
sasastsa
26-56
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) would be well suited for
units 1-4 at the Philip Sporn plant because of the length of ductwork
between the boilers and the ESPs and the large sizes of the ESPs. Unit 5
was not considered for sorbent injection technologies because of the small
size of the ESPs and short duct residence time before the ESPs.
Tables 26.3.1-8 and 26.3.1-9 present the retrofit factors and costs for
installation of sorbent injection technologies for units 1-4 at the Philip
Sporn pi ant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The four 153 MW boilers at the Philip Sporn plant would be considered
good candidates for AFBC/CG repowering. The unit 5 boiler is too large to
be considered for AFBC/CG repowering. Two of the units will be repowered
with a 330 MW Pressurized Fluidized Bed Combustion (PFBC) unit under the
clean coal technology program.
26-57
-------
TABLE 26.3.1-8.
DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR PHILIP SPORN UNITS 1,2,3 OR 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE - NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 41
TOTAL COST (1000$)
ESP UPGRADE CASE 41
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE - NA
26-58
-------
Table 26,5, 1-9. Siraary of SSO/FSi Control Costs for the Sporn Plant (Jme 1988 Doltars)
=sssssBszss32ss=s=:3:s3ss£3S3:s;siasa8Z3a3=s:3S39assss$=s:ss3S«e>s3s«:B3sS8:ss3a3Ss33:ss:3:9ss:£SSSs:ss:ss=s:ss3
Technology
Boiler Main
Boiler Capacity Coal
Capital Capital Annual
Annual-
SC2
S02
$02 Cost
Nwifcar Retrofit
Siza
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU)
(*)
Content
(SAW)
(WM>
(mi Its/kwh)
(X)
Ctons/yr!
(S/ton!
Factor
• <*>
DSB*ESP
I
1,00
153'
39
1.0
6.7
43.6
5.2
10.0
49.0
1994
2628.1
DSD+ESP
2
1.00
153
32
1.0
- 4.7
43.6
5.1
• 11.8
49.0
1636
3094,8
DSD+ESP
¦ 3
1,00
153
45
1.0 .
6.7
43 ;6
• 5.4
8,9
49.0
2301
2343.8
OSO*ESP
4
1.00
153
36
1.0
6.7
43.6
5.2
10.7
49.0
1841
2805.9
OS0»ESP-C
1
t .00
153
39
1.0
' 6.7
43.6
3.0
5.8
49.0
1994
1520.8
DSO-ESP-C
2
1.00
153
32
1.0
6.7
43.6
2.9
6.8
49,0
• 1636
1791,4
DSO+ISP-C
3
1.00
153
45
1.0
6.7
43.6
3,1
5.2
49.0
2301
1355.8
0S0*ESP-C
4-
1,00
153
36
1.0
6.7
43.6
3,0
6.2
49.0
1841
1623.9
FSl»ESP-53
1
1.00
153
39
1.0
6,9
45.2
4.3
8.2
50.0
2050
2088.)
FSJ*ESP-50
2
1,00
153
32
i.q:
6.9
45.2
4,0
9.4
50.0
1682
2405.6
FSi»ES»-50
' 3
1.00
153
¦ 45
' 1.0
6.9
45.2
4,5
7.4
50.0
2365
1894.7
FSI*ESP-53
. 4
1.00
153
36
1.0
6.9
45,2
4.2
8.7
SO.O
1892
2209,I
FSI»ESP-50-C
1
- '1.00
153
¦ 39
1.0
6.9
45.2
2.5
4.8
50.0
2050
1211.4
FSt+ESP-50-C
2
1.00
153
32
1.0
6.9
45.2
2.3
5.5
50.0
1682
1396.7
FSHfSP-50-C
3
1.00
153
45
1.0
6.9
45.2
2.6
4.3
50.0
2365
1098.7
FSI+ESP-50-C
4
1,00
153
36
1.0
6,9
45.2
2.4
5.0
50.0
1892
1282.1
FSI'ESP-70
1
1,00
153
3?
1.0
7.0
45.7
4.3
8.3
70.0
2869
1509.5
FSI*ES®-?3
2
1,00
153
32
1.0
, 7.0
45,7
4,1
9.5
70.0
2354
1737.8
FSltESP-70
3
1.00
153
45
1.0
7.0
45.8
4.5
7.5
70.0
3311
1370.4
WI»ESP-70
4
1.00
153
36
1.0
7.0
45.7
4.2
8.3
70.0
2649
1596.4
FSI*ESP-7D*C
1
1,00
153
39
1.0
7.0
45.7
2.5
4.8
70.0
2869
875.8
FSl»ESP-70-C
2
1.00
153
32
1.0
7.0
45.7
2.4
5.5
70.0
„ 2354
1009.0
FSI*ESP-70-C
3
1.00
153
45
1.0
7.0
45.8
2.6
4.4
70.0
3311
794,6
FSI*ESP-70-C
-4
1.00
153
36
1.0
7.0
45.7
2.5
5.1
70.0
2649
926.5
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26-59
-------
26.4 OHIO POWER COMPANY
26.4,1 Kammer Steam Plant .
The Kamrner steam plant is located on the Ohio River in Marshall County,
West Virginia, and is operated by the Ohio Power Company. The Kamrner plant
contains three coal-fired boilers with a gross generating capacity of 714 MW
Table 26.4.1-1 presents operational data for the existing equipment at
the Kamrner plant. Coal shipments are received by barge and transferred to a
coal storage and handling area north of the plant. PM emissions from the
three units are controlled by retrofit ESPs. The ESPs are located beside
boiler 3, west of the plant. Flue gases from the units are directed to a
common chimney beside unit 3. Wet fly ash from the unit is disposed of in a
pond west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for the three units would be located at the west end
of the units beside the unit 3 boiler and retrofit ESPs. The general
facilities factor would be low (5 percent) for the FGD absorber location.
The site access/congestion factor would also be low for this location.
Approximately 500 feet of ductwork would be required for installation of the
L/LS-FGD system. A medium site access/congestion factor was assigned to
flue gas hand!ing.
LSD-FGD with reuse of the existing ESPs was considered for the Kammer
plant. The LSD absorbers would be located similarly to the wet FGD
absorbers with similar general facilities and site access/congestion
factors. About 200 feet of ductwork would be required for installation of
LSD absorbers for all units. The flue gas handling site access/congestion
factor is low for installation of LSD for all units. A low site access/
congestion factor was also assigned to the ESP location for upgrading.
Tables 26.4.1-2 and 26.4.1-3 give a summary of retrofit factor inputs
to the IAPCS model and estimated costs for installation of conventional FGD
technologies at the Kammer plant.
26-60
-------
TABLE 26.4.1-1. KAMMER 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
238
72,73,76
1958
CYCLONE
NA
NO
4.2
11900
14.0
WET DISPOSAL •
PONDS/ON-SITE
1
BARGE
ESP
1978
0.05
99.8
1.0-6.0
925.3
835
1108
'360
26-61
-------
TABLE 26.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR KAMHER
UNIT 1,2 OR 3
FSD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
. LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
100-300
BAGHOUSE
NA
ESP REUSE ' '
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
2040
NA
2040
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS .
FGD SYSTEM
1.42
NA
ESP REUSE CASE
1.23
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
- NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5 .
0
5
26-62
-------
Tatsl# 26.4.1-3. Sunwry of FGO Control Casts far the Kamaer Plant (June 1988 Dollars)
SS8SgSSSSSSS"SiStSSSS3SSlSaS gf»«HKgaggg»ff f ff gyf f gf ga5g8gl8BSiir*f I*?""?*"*"*"*'"""'? *" 3S3S5SC
Technology loiter Main Boiler Capacity Coat Capital Capital Arruat Annual SOS S02 502 Cost
Number Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed -
. Effect.
Difficulty («w>
. m
Content
(*/ltU)
CSMO
«af Us/kwti)
<*)
-------
Coal Switching and Physical Coal Cleaning Costs-- . "
CS was not considered for the three cyclone boilers at the Kanmer plant
because low sulfur, low ash fusion temperature bituminous coals are not
readily available in the eastern United States. PCC was not considered at
the Kammer plant because it is not a mine mouth plant,
NC) Control Technologies--
X
NGR was considered for NO emissions control at the Kammer plant.
A
Performance results and costs developed for the three 238 MW cyclone boilers
are presented in Tables 26.4.1-4 and 26.4.1-5.
Selective Catalytic Reduction-- -
Cold side SCR reactors for the Kammer plant would be located adjacent
to the common chimney. As in the FGD case, a low general facilities value
(13 percent) was assigned to the location. A low site access/congestion
factor was also assigned to the reactor location. Approximately 200 feet of
ductwork would be required to span the distance between the SCR reactors and
the chimney for the units. A low site access/congestion factor was assigned
to the flue gas handling system. Tables 26.4.1-4 and 26.4.1-5 summarize the
retrofit factors and costs for installation of SCR at the Kammer plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for the
Kammer plant. The ESPs are large and the extensive ductwork distance
between the boilers and the ESPs make these units particularly well suited
for sorbent injection technologies. Tables 26.4.1-6 and 26.4.1-7 summarize
the retrofit factors and costs, respectively, for installation of sorbent
injection technologies at the Kammer plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi1ity--
The three boilers at the Kammer plant would be good candidates for
AFBC/CG repowering because of their small boiler size and likely short
remaining service life. However, the high capacity factors could result in
high replacement power costs for extended downtime.
26-64
-------
TABLE 26.4.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR KAMMER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 OR 3
FIRING TYPE CYC
TYPE OF NOx CONTROL NGR
FURNACE VOLUME (1000 CU.FT) NA
BOILER INSTALLATION DATE 1958
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$) 52
New Duct Length (Feet) 200
New Duct Costs (1000$) 1646
New Heat Exchanger (1000$) : 3136
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 4833
COMBINED CASE 9302
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
26-65
-------
TABLE 26.4.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR KAMMER UNIT 1,2 OR 3
ITEM • .
SITE ACCESS/CONGESTION
REAGENT PREPARATION ... LOW
ESP.UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS :
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2040
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) : NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 57
TOTAL COST (1000$)
ESP UPGRADE CASE 2097
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
26-57
-------
Fable 26,4.1-7. Suimery of DSO/FSi Control Costs for the Kanmer Plant' (June 1988 Dollars)
53X5253S5SSSS
3;;s::s:
ISSBS3SSSJ
53 = 3553
53=SS=SSS
ssaszsssssassssa:
!K2r3£833<53
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zszssssss
Technology
Boiler
Hein
Boiler Capacity Coal
Capital Capital Annuel
Annual
302
see
$02 Cost
NUltjer
Retrofit
Site
Factor
Sulfur
Coat
Cost
Cost
Cost
Removed Removed
• Effect.
Difficulty CMW)
<%>
Content
(S»t)
<*/kW>
(SMM)
(mi 1 ls/k*f>)
(*}
C tons/yr)
Cl/tonj
Factor
<%)
DSD+ESP
1
1.00
23a
72
4.2
' 17.9
75.0
15.3
10.2
49.0
24985
611.4
BSD+ESP
2
1.00
23S
73
' 4.2
17.9
75.0
15.4
10,1
49.0
25330
607.5
DS0+E5P
1
1.00
as
76
4.2
17.9
75.0
15.7
9.9
49.0
26371
596.4
OSB-ESP-C
1
1.00
238
72
4.2
17.9
75.0
8.8
5.9
49.0
24983
353.5
CSC»ESP-C
2
1.00
23a
73
4.2
17.9
75.0
8.9
5.8
49.0
25330
351.2
CS0*ISP-C
3
1.00
238
76
4.2 '
17.9
75.2
9.1
5.7 '
49.0
26371
344.6
FSI+ESP-50
1
1.00
238
72
4.2
• 16.3
70.6
20.7
13.8
50.0
25677.
807.9
FSI+ESP-50
2
1.00
238
73
4.2
16.8
70.6
21.0
. 13.8
50.0
26033
805.2
FSI+ESP-50
3
1.00
233
76
4.2
16.8
70.6
21.6
13.6
50.0
27103
797.4
FS!*6SF-50-C
1
1.00
238
72
4.2
16.8
70.6
12.0
8.0
50.0
25677
465.8
FSI+ESP-5C-C
2
1.00
238
73
4.2
16.8
70.6
12.1
7.9
50.0
26033
464.2
FSI+ESP-50-C
3
1.00
238
76
4.2
16.8
70.6
12.5
7.9
50.0
27103
459.6
PSJ+ESP-70
1
1.00
23B
72
4.2
17.1
71.7
21.2
14.1
70,0
35947
589.6
FSI«ESP-7C
2
1.00
238
73
4.2
17.1
71.7
21.4
14.1
70,0
36447
587.7
F5I*i5P-70
3
1,00
238
76
4.2
17.1
71.7
22.1
13.9
70.0
37944
582.0
FSS+E5P-7G-C
1
.1.00 ¦
230
72
4.2
17,1
71.7
12.2
8.1
70.0
35947
340.0
FSI*£SP-70-C
2
1.00
238
73
4.2
17.1
71.7
12.3
a.i
70.0
36447
338.8
FSI*ESP-70*C
3
1.00
238
76
4.2
17.1
71.7
12.7
a.o
70.0
37944
335.5
sa»Ksi:>ia
-------a
...slsass
SSSISS
sssaasisa
II
N
II
II
II
n
ii
ii
U
il
II
N
H
II
il
il
ssisaass
asaasea
26-68
-------
26.4,2 Mitchell Steam Plant
The Mitchell steam plant is located on the Ohio River in Marshall
County, West Virginia, and is operated by the Ohio Power Company. The
Mitchell plant contains two coal-fired boilers with a gross generating
capacity of 1,532 MW. -
Table 26.4.2-1 presents operational data for the existing equipment at the
Mitchell plant. Coal shipments are received by either barge or railroad and
transferred to a coal storage and handling area north of the plant. PM
emissions from the two units are controlled by retrofit ESPs. The ESPs are
located behind the boilers. Flue gases from the units are directed to' a
common chimney located between the ESPs. Wet fly ash from the units is
disposed of in ponds to the south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for the two units would be located at the north and
south ends of the ESPs. The general facilities factor would be low
(5 percent) for the unit 1 FGD absorber location and medium (8 percent) for
the unit 2 location. A parking lot and road would have to be relocated
before installation of the unit 2 absorbers. The site access/congestion
factor was low for these locations. Less than 200 feet of ductwork would be
required for installation of the L/LS-FGD system for either unit and a low
site access/congestion factor was assigned to flue gas handling. ,
LSD-FGD with reuse of the existing ESPs was also considered for the
Mitchell plant. The LSD absorbers would be located at the north and south
ends of the plant beside the boilers. A low site access/congestion factor
was assigned to both locations. A low general facilities factor was assigned
to the unit 1 absorber location. A medium general facilities factor was
assigned to the unit 2 absorber location since a road would have to be
relocated before LSD absorbers could be installed. Between 300 and 600 feet
of ductwork would be required for installation of LSD absorbers. The flue
gas handling site access/congestion factor would be low for unit 1 but medium
for unit 2 because of the obstruction caused by the coal conveyor.
Tables 26.4.2-2 through 26.4.2-4 present retrofit factor and cost estimates
for installation of conventional FGD technologies at the Mitchell plant.
26-69
-------
TABLE 26.4.2-1. MITCHELL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 816
CAPACITY FACTOR (PERCENT) 51,52
INSTALLATION DATE 1971
FIRING TYPE OPPOSED WALL
FURNACE VOLUME (1000 CU FT) 477
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.4
COAL HEATING VALUE (BTU/LB) 11950
COAL ASH CONTENT (PERCENT) 15.6
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS BARGE/RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1978
EMISSION (LB/MM BTU) 0.02
REMOVAL EFFICIENCY 99.8
. DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.0-6.0
SURFACE AREA (1000 SQ FT) 2195
GAS EXIT RATE (1000 ACFM) 3000
SCA (SQ FT/1000 ACFM) 731.5
OUTLET TEMPERATURE (4F) " 370
26-70
-------
TABLE 26.4.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MITCHELL
UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA .
ESP REUSE CASE
LOW
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
. NA ,
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
6156
NA
6156
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER ""
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
1.34
BAGHOUSE CASE
NA
. ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
. NA
NA
GENERAL FACILITIES (PERCENT)
5
0
5
26-71
-------
TABLE 26.4.2:3, SUMMARY- OF RETROFIT FACTOR DATA FOR MITCHELL
. UNIT 2 •
FED TECHNOLOGY
FORCED
LIME
L/LS FGD
OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
LOW
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA ¦
YES
ESTIMATED COST (1000$)
6155
NA
6155
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
1.38
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
8
0
8
26-72
-------
Table 26.4.2-4. sumnary of FGD Control Costs for the Mitchell Plant (June 1988 Dollars)
S«Sl|SSSS3BSZS=liaiXS»S8SSISSBSlS8BISIIS3VSI«E»SISS«|ISll8BSI8tISSSCSISISIISIZIISBS18S»
Technology Bailer- Main Boiler Capacity Coal Capital Capital Annual
wimber Retrofit Sii# Factor sulfur Cost * cost cost
Difficulty £MW) (I) Content • ($/kV) (SMM)
Factor (X).
Annual S02 S02 S02 Cost
Cost - Removed Removed Effect.
(mills/Ml) (%) (tons/yr) (t/tori)
L/S FGD
L/S FGD
L/S FGO-C
L/S FGD-C
IC FGD
IC FGD
IC FGD-C
IC FGD-C
LSO+ESP
LSD+ESP
ISD«ES»-C
IS0+E5P-C
1.27
1.27
! .27
1.27
1.27
1.27
1.27
1.2?
34
38
34
33
816
816
816
816
816
816
816
816
816
816
816
316
51
52
51
52
51
52
51
52
51
¦52.
51
52
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
131.0
133.2
131.0
133.2
102.9
104.6
102.9
104.6
'92.5
96.6
92.5
96.6
60.5
63.3
60.5
63.3
26.1
28.2
26.1
23.2
13.4
18.4
13.4
18.4
60.5
61.5
35.2
35.9
51.5
52.4
30.0
30.5
39.8
41.2.
23.2
24.1
16.6
16.6
9.7
9.6
14.1
14.1
8.2
3,2
6.4
6.5
90.0
90.0
90.0
90.0
90.0
90.0
90." 0
' 90.0'
76.0
76.0,
76.0
76.0
37234
37964
37234
37964
37234
37964
37234
37964
31567
32186
31567
32186
1623.8
1621.0
946.1
944.5
1382.6
1380.1
804.5
803.0
1261
1281
735.8
747.4
26-73
-------
Coal Switching and Physical Coal Cleaning Costs--
CS was considered for the Mitchell plant. Table 26.4.2-5 presents costs
for CS. These costs do not include boiler and pulverizer operating cost
changes or any coal handling system modifications that may be necessary. PCC
was not considered at the Mitchell plant because it is not a mine mouth
plant.
N0V Control Technologies--
X , '
LNBs were considered for N0X emissions control at the Mitchell plant.
Performance and cost estimates developed for the two 816 MW opposed wal1 -
fired boilers are presented in Tables 26.4.2-6 and 26.4.2-7.
Selective Catalytic Reduction--
Cold side SCR reactors for the Mitchell plant would be located at the
north and south sides, of the boilers. A low general facilities value
(13 percent) was assigned to the unit 1 location and a medium general
facilities value <20 percent) was assigned to the unit 2 location. A low
site access/congestion factor was also assigned to the absorber locations.
Approximately 400 feet of ductwork would be required to span the distance
between the SCR reactors and the chimney. A low site access/congestion
factor was assigned to flue gas handling for the units. Tables 26.4.2-6 and
26.4.2-7 present the retrofit factors and costs for installation of SCR at the
Mitchell plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
The Mitchell plant would be a good candidate for sorbent injection
technologies (FSI and DSD). The ESPs are large and the extensive ductwork
distance between the boilers and the ESPs make these units particularly well
suited for FSI or DSD technologies. Tables 26.4.2-8 and 26.4.2-9 present the
retrofit factors and cost estimates, respectively, for installation of sorbent
injection technologies at the Mitchell plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Thie two 816 MW boilers at the Mitchell plant are too large to be
considered good candidates for AFBC/CG repowering.
26-74
-------
Table 26.4.2-5. Suimary of Coal Switching/Cleaning Costs for the Mitchell Ptam (June 1983 Dollars) -
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 1 S02 • 502 Cost
Kunfaer Retrofit Site Factor Sulfur Cost' Cost. Cost Cost ' Removed Removed \ Effect.
Difficulty (MW) (X) Content (WM) (T.i I Is/kwh)
-------
TABLE 26.4.2-6.- SUMMARY OF NOx RETROFIT RESULTS- FOR MITCHELL
BOILER NUMI
BER '
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
OWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (IOOO CU FT)
477
477
BOILER INSTALLATION DATE
1971
1971
SLAGGING PROBLEM
NO
NO ¦
ESTIMATED NOx REDUCTION (PERCENT)
40
40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR .
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0.
Ductwork Demolition (1000$)
131
131
New Duct Length (Feet) -
400
400
New Duct Costs (1000$) '
6768
6768
New Heat Exchanger (1000$)
6568
6S68
TOTAL SCOPE ADDER COSTS (1000$)
13466
13466
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
20
26-76
-------
Table 26.4.2-7, NO* Control Cost Results for the Mitchell Plant' (June 19BS Sol tars)
Technology ioiler Main Boiler Capacity.Coat Capital Capital Annual
Ngrfcer Retrofit Size i Factor Sulfur . Cost • Cost Cost
Difficulty (*W) (X5 Content CIHH) (J/kW) (X) (tans/yr) (J/ton;
LNC-LNB
LNC-LNB
LNC-INB-C
LNC-LNB-C
SCR-3
SCR-3
SCR-3-C
SCR-3-C
SCR-7
SCR-7
SCR-7-C
SCR-7-C
00
00
00
00
15
16
16
16
16
16
16
16
816
816
816
816
816
816
816
816
,816
816
816
816
51
52
51
52
51
52
51
52
51
52
51
52
1.4
1,4
' 1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
1.4
5.9
5.9
5.9
5.9
7.2
7.2
7.2
7.2
97.8
67.3
119.9
•1C7.C
1.3
1.3
o.a
0.8
97.8 119.9 ' 36.2
87.3, 107.0 34.6
Z1.Z
20.2
97.8 119.9 29.5
87.3 107.C 27.8
97.8
87.3
119.9
1C7.C
17.3
16.3
0.4
0.3
0.2
0.2
9.9
9.3
5.8
5.4
8.1
7.5
4,8
4,4
40.0
40.0
40.0
40.0
80.0
80.0
80.0
80.0
80.0
80.0
80.
80,
6365
6490
6365
6490
12730
12980
12730
12980
12730
12980
12730
12980
201.3
197.4
115.5
117.2
2843.2
2661.9 '
1663.4
1555.3
2316.2
2145.0
1361.5
1259.1
25-77
-------
TABLE 26.4.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MITCHELL UNIT 1 OR 2
ITEM' '
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 6156
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$) 144
TOTAL COST (1000$)
ESP UPGRADE CASE 6300
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
26-78
-------
Table 26.4,2-9, Surma ry of DSD/FSI Control. Costs far the Mitchell Plant (June 1983 DolUrs)
Technology Bailer - Main Boiler Capacity Coat Capital Capital Annuai Annual SD2 SQ2 SOt Cost
Number Retrofit Size Factor Sylfur Cost Cost Cos: Cost, Removed Removed Effect.
Difficulty (%) Content (mitls/knh) (X) (tons/yr) (S/ton)
¦ Factor (*> .
CSO+ISP
0S0-»ESP
1.00
1.00
81ft
616
51
52
1.4
1,4
34.3 42.1 21.1
34.3 42.1 21.3
5.8
5.7
49.0
49.0
2012B
20522
1049.2
1038.4
DSC-E$?-C 1 1.00 816 51 ¦ 1.4 34.3 42.1 12.3 3.4 49.0 20125 608.8
DS0+ESP-C 2 1.00 816, 52 - 1.4 34.3 42.1 12.4 3.3 49.0 20522 602.4
FSI-eSP-50 1 1.00 816 • 51 1.4 30.3 37.2 21.4 5.9 50.0 ¦ 20686 1032.6
FSI+ESP-50 2 1.00 816 52 1.4 30.3 37.2 21.6 . 5.8 53.0 21092 1024,8
FSI+ESP-50-C 1 1.00 816 51 1.4 30.3 37.2 12.4 3.4 53.0 20686 598.2
FSI-f$P-50-C 2 1.00 816 52 1.4 30.3 37.2 12.5 3.4 50.0 21092- 593.6
¦ FS1+ESP-70
FSJ+ESP-70
1.00
1.00
816
816
51"
52 •
1.4
1.4
30.6 37.5 21.7
30.6 37.5 22.0
6.0
5.9
70.0
70.0
28961
29528
750.4
744.6
FSt+ESP-7ff-C t
FSHESF-70-: 2
1.00 816 , 51 1.4 30.6 37.5 12.6 3i5 70.0 28961 434.6
1.00 816 ' 52 1.4. 30.6 37.5 12.7 J.4 73.0 ' 29528 431.4
26-79
-------
26.5 VIRGINIA ELECTRIC AND POWER COMPANY
26.5.1 Mount Storm .Steam Plant
The Mount Storm steam plant is located on.the Stony River in Grant
County, West Virginia, and is operated by the Virginia Electric and Power
Company. The Mount Storm plant contains three coal-fired boilers with a
gross generating capacity of 1,662 MW.
Table 26.5.1-1 presents operational data for the existing equipment at
the Mount Storm plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area north of the plant. PM
emissions are controlled by ESPs located behind the boilers. Units 1 and 2
have retrofit ESPs which were installed behind the original chimneys for the
units. Flue gases exiting these ESPs are directed to a new chimney. Flue
gas from unit 3 is directed to a chimney located behind the unit 3 ESPs.
Dry fly ash from the units is landfilled by the utility.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located on the north side
of the unit 1 and 2 chimney and the absorbers for unit 3 would be located on
the south side of the unit 3 ESPs. The general facilities factor is low
(5 percent) for both locations because no major demolition or relocation
would be required. The site access/congestion factor is low for the unit 1
and 2 FGD absorber locations. The.site access/congestion factor is low for
the unit 3 location. Between 300 and 600 feet of ductwork would be required
for installation of the unit 1 and 2 absorbers arid between 100 and 300 feet
would be required for the unit 3 absorbers. A low site access/congestion
factor was assigned to.flue gas handling for all of the units.
LSD-FGD with reuse of the existing ESPs was considered for the Mount
Storm plant. It was assumed that the existing ESPs would be large enough to
handle the additional load imposed by LSD. The LSD absorbers would be
located similarly to the wet FGD absorbers at the north and south ends of
the units. Low general facilities factors were assigned to both locations.
A low site access/congestion factor was assigned to the unit 1 and 2
location and to the unit 3 location. Approximately 500 feet of ductwork
26-80
-------
TABLE 26.5.1-1. MOUNT STORM 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
570 522
66,75 71
1965,66 1973
TANGENTIAL
310 313
NO NO
1.8 1.8
12100 12100
14.5 14,5
DRY DISPOSAL
LANDFILL
1
3
RAILROAD
ESP
ESP
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
26-81
-------
would be required to access the upstream side of the retrofit ESPs for
unit 1, 800 feet .would be required for unit 2, and about 400 feet would be
required for unit 3. A medium site access/congestion factor was assigned to
flue gas handling for units 1 and 3 and a high site access/congestion factor
was assigned to unit 2 because of the congestion between the old and new
ESPs.
Tables 26.5.1-2 through 25.5.1-5 present a summary of retrofit data and
costs for installation of conventional FGD technologies at the Mount Storm
plant.
Coal Switching and Physical Coal Cleaning Costs--
Table 26.5.1-6 summarizes the IAPCS cost results for CS at the Mount
Storm plant. These costs do not include pulverizer and boiler operating
cost changes or any system modifications that may be necessary for coal
blending. PCC was not evaluated because the Mount Storm plant is not a mine
mouth plant.
N0X Control Technologies--
OFA was considered for control of NOx emissions from the three
tangential-fired boilers. Tables 26.5.1-7 and 26.5.1-8 present performance
and cost estimates for N0X control technologies at the Mount Storm plant,
Selective Catalytic Reduction-
Cold side,SCR reactors for units 1 and 2 and cold side SCR reactors for
unit 3 at the Mount Storm plant would be located similarly to the wet FGD
absorbers. The unit 1 and 2 reactors would be located beside the unit 1
retrofit ESPs and the unit 3 reactors would be located beside the unit 3
ESPs. As in the FSD case, low general facilities values of 13 percent were
assigned to both of the reactor locations. Low site access/congestion
factors were also assigned to the reactor locations. Approximately 200 feet
of ductwork would be required to span the distance between the SCR reactors
and the unit 1 and 2 chimney and about 300 feet would be required for the
unit 3 reactors, . Low site access/congestion factors were assigned to flue
gas handling for the three units. Tables 26.5.1-7 and 26.5.1-8 present the
retrofit factors and costs for installation of SCR at the Mount Storm plant.
26-82
-------
TABLE 26.S,1-2.
SUMMARY
OF RETROFIT FACTOR DATA FOR MOUNT STORM
UNIT 1
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST <1000$)
NEW CHIMNEY .
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
. FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
LOW
LOW
NA
NA
300-600 NA
NA
NA
NO
NA
NO
0
NO
1.31
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
LOW
MEDIUM
NA
300-600
NA
MEDIUM
' NA
NO
NA
NO
0
NO
1.31
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 5
0
25-83
-------
TABLE 26.5.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR MOUNT STORM
UNIT 2 ,
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
M
LOW
FLUE GAS HANDLING
LOW
M
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
M
ESP REUSE
600-1000 .
BAGHOUSE
NA
ESP REUSE
NA .
m
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
1.31
NA
ESP REUSE CASE
1.47
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5
0
5
26-84
-------
TABLE 26.5.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR MOUNT STORM
• UNIT 3 •
FED TECHNOLOGY
FORCED ' LINE
L/LS F6D 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 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 1.31
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 OS
26-85
-------
Table 26,5,1-5. Slimwry of FGO Control Costs for the Mount Stonn Plant (June 1968 Dollars!
S35SS35SSS=S=525=S23SS3SSS:arSBSSSr255i5a3SSSS:rsSSSSSSaS3SSSSSaSSaS3S3aSS»Sl=2SasSBSSSa=5=SS==SS3S==S3C=5S5S=S=
Technology BoUer Main Boiler Capacity Cost Capital Capital Annual, Annual SQ2 S02 S02 Cost
Nuifeer
Retrofit
Stz*
Factor
Sulfur
Cost
Cost
Coct
Cost
Removed Removed
Effect.
Difficulty
i>
<%3
(tons/yr)
Factor
(91)
1/5 FED
1
, 1.31
570
66
1.8
104.7
183.6
52.6
15.9
90.0
42662
1232.0
L/S fCit-
2
1.31
570
75
i.a
104.7
183.7
55.0
' 14.7
90.0,
48430
1134.8
US FGD
3
1.20
. 522
71
1.8
92.3
176.9
48.4
14.9
SO.O
42029 '
1152,2
L/S fGD
1-2
1.31
1140
71
1.8
183.6
161.0
96.5
* 13.6
90.0
9178S
1051. S
l/S fSD-C ,
1
1.31
570
66
1.8
104.7
183.6
30.6
9.3
90.0
„ 42662
716.9
L/S FOO-C
2
1.31
570
75
1.8
104.7
183.7
32.0
8.5
90.0
48480
659.9
.L/S fgd-c
3
1.20
522
71
1.8
92.3
176.9
28.2
8.7
90.0
42029
670.0
L/S FGO-C
1-2
1.31
1140
71
1.8
183.6
161.0
56.1
7,9
90.0
91788
611.5
LC FGD
1:2
1.31
1140
71
1.8
151.6
132.9
86.3
12.2
90.0
91788 '
940.0
LC. FGD -
3
1.20,
522
• 71
1.8
68.8
131.7
40.9
12.6
90.0
42029
972.9
LC FGD-C
1-2
1.31
1140
71
1.8
151.6
132.9
50.1
7.1. '
90.0
91788
545.9
LC FGO-C
"3
1.20
522
71
1.8
68.8
131.7
23.7
7,3
90.0
42029
564.7
LSD*£SP 5
1
1.31
570
66
1.8
65.0
114.1
31.3
9.5
71.0
33818
926.7
LSD+ESP
2
1.47
570
75
1.8
72.0
126.2
34.8
- 9.3
71,0
38430
905.2
ISD'ESP
3 .
1.31
522
' 71
1.8
58.0
111.1
29.2
9.0
71,0
33317
873,6
ISD*ESP-C
1
1.31
570
66
1.8
65.0
114.1
18.2
5.5
,71.0
33818
539.5
tSD«ESP-C
2
1.47
570
75
1.8
72.0
126.2
20.3
5.4
71.0
38430
527.0
LSD«ESP-C
3
1.31
522
71
1.8
58.0
111.1
17.0
5.2
71.0
33317
509.5
isiBsa:
26-86
-------
Table 26.5.1,-6. Surinary of Coal Switching/Cleaning Costs for the noun Storm Plant (June 1988 Bottarsi
IS3ssssssBssssasssiKsasssssssssssssssssssssssssassssEsssesssssss3s:sssis::sa::ssss3ii=zisssissis*8as:ssisissB5=ass
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 $02 $02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost , Cost Removed Removed Effect.
Difficulty (N¥> (X) Content (ml1tS/kwfl> (X)
-------
TABLE 26,5.1-7. SUMMARY OF NQx RETROFIT RESULTS FOR MOUNT STORM
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2 3
FIRING TYPE TANG TANG
TYPE OF NOx CONTROL OFA OFA
FURNACE VOLUME (1000 CU FT) 310 313
. BOILER INSTALLATION DATE 1965,66 1973
SLAGGING PROBLEM NO NO
ESTIMATED NOx REDUCTION (PERCENT) 25 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0
Ductwork Demolition (1000$) 100 93
New Duct Length (Feet) 200 300
New Duct Costs (1000$) 2743 3909
New Heat Exchanger (1000$) 5296 5024 -
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 8139 9026
COMBINED CASE 12310 NA
RETROFIT FACTOR FOR SCR 1.16 1.16
GENERAL FACILITIES (PERCENT) 13 13
26-88
-------
Table 26.5.1-8, NOx Control Cost Results for the Mount Storm Plant (June 1968 Dollars)
II
II
11
II
II
II
It
1)
II
II
1%
:==sss==
22SS25S"!
ES£=3SSS:
E=esas3=:
E5SCS 3 Ss
Technology
Boiler
Wain
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NCx .
NOx Cost
Nuaber Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HU>
(X)
Content
{S»0
(*/W
<»*>
(miILs/kwh}",
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs- -
Sorbent injection technologies (FSI and DSD) were considered for the
boilers at the Mount Storm plant. There is sufficient duct residence time
between the old and new ESPs for units 1 and 2 but limited residence time
exists before the unit 3 ESPs. Although ESP data was not available, the.
ESPs appear to be large enough to accommodate the additional particulate
load. Tables 26.5.1-9 and 26.5.1-10 present the retrofit factors and costs
for installation of sorbent injection technologies at the Mount Storm plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The boilers at. the Mount Storm power plant are too large and have too
long a remaining useful lifetime to currently be considered as candidates
for AFBC/CG repowering.
26-90
-------
TABLE 26.5.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MOUNT STORM UNIT 1, 2 OR 3
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 110
TOTAL COST (1000$)
ESP UPGRADE CASE . 110
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE . NA
26-91
-------
Table 26.5.1-101 summary "of DSD/FSt control Costs for the Hount Stem Plant (June 1988 Dollars)
Technology Boiler Main 3oil«r Capacity Coal ' Capital Capital Annual Annual S02 " S02 $02 Cost
• Mutter Retrofit Sixc Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
------- |