EPA/600/7-90/021d
November 1990
RETROFIT COSTS FOR S02 AND N0X CONTROL OPTIONS
AT 200 COAL-FIRED PLANTS
VOLUME IV - SITE SPECIFIC STUDIES FOR
ssouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
by
T. Emmel and M. Mai bodi
Radian Corporation
Post Office Box 13000
Research Triangle Park, NC 27709
EPA Contract No. 68-02-4286
Work Assignment 116
Project Officer
Norman Kaplan
U. S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
AIR AND ENERGY ENGINEERING RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NC 27711
-------
TECHNICAL REPORT DATA
(Please read Initruedons oti the rcvctsc before com/
y'
\ ALPORT NO. ?.
EPA/600/7-90/-21 d
4. TITLE ANOSUOTlTLF
Retrofit Costs for SO2 and N0X Control Options at
200 Coal-fired Plants; Volume IV - Site Specific
Studies for MO, MS, NC, NH, NJ, NY, OH
5. REPORT OATF
November 1990
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Thomas E. Emm el and Mehdi Maibodi
B. PERFORMING ORGANIZATION REPORT NO.
9. performing organization name and aodress
Radian Corporation
P. O. Box 13000
Research Triangle Park, North Carolina 27709
10. PROGRAM EttMENT NO.
1 1. CONTRACT/GRANT NO.
68-02-4286, Task 116
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, North Carolina 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 1985-1990
14. SPONSORING AGENCY CODE
EPA/600/13
is.supplementary notes A E ER L project officer is Norman Kaplan, Mail Drop 62, 919/541-
2556. This is one of five volumes and three diskettes comprising this report.'
is. abstract rep0rj. gives results of a study, the objective of which was to signifi-
cantly improve engineering cost estimates currently being used to evaluate the eco-
nomic effects of applying SC2 and NOx controls at 200 large S02~ emitting coal-fired
utility plants. To accomplish the objective, procedures were developed and used that
account for site-specific retrofit factors. The site-specific information was obtained
from aerial photographs, generally available data bases, and input from utility com-
panies. Cost estimates are presented for six control technologies: lime/limestone
flue gas desulfurization, lime spray drying, coal switching and cleaning, furnace and
duct sorbent injection, low NOx combustion or natural gas reburn, and selective cata-
lytic reduction. Although the cost estimates provide useful site-specific cost infor-
mation on retrofitting acid gas controls, the costs are estimated for a specific time
period and do not reflect future changes in boiler and coal characteristics (e.g. ,
capacity factors and fuel proces) or significant changes in control technology and per-
formance.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. descriptors
b.IDENTIFIERS/OPEN ENOED TERMS
c. COSATi Field/Gioup
Pollution Electric Power Plants
Silfur Dioxide
Nitrogen Oxides
Cost Estimates
Coal
Combustion
Pollution Control
Stationary Sources
Retrofits
13 B 10B
07B
05A, 14A
21D
21B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
526
20. SECURITY CLASS (This pagtj
Unclassified
22. PRICE
EPA Fo»m 2220*1 (9-73)
/
-------
ABSTRACT
This report documents the results of a study conducted under the
National Acid Precipitation Assessment Program by the U.S. Environmental
Protection Agency's Air and Energy Engineering Research Laboratory. The
objective of this research program was to significantly improve engineering
cost estimates currently being used.to evaluate the economic effects of
applying sulfur dioxide and nitrogen oxides controls at 200 large sulfur
dioxide emitting coal-fired utility plants. To accomplish the objective,
procedures were developed and used that account for site-specific retrofit
factors. The site-specific information was obtained from aerial
photographs, generally available data bases, and input from utility
companies. Cost estimates are presented for the following control
technologies: lime/limestone flue gas desulfurization, lime spray drying,
coal switching and cleaning, furnace and duct sorbent injection, low N0x
combustion or natural gas reburn, and selective catalytic reduction.
Although the cost estimates provide useful site-specific cost information on
retrofitting acid gas controls, the costs are estimated for a specific time
period and do not reflect future changes in boiler and coal characteristics
(e.g., capacity factors and fuel prices) or significant changes in control
technology cost and performance.
NOTICE
This document has been reviewed in accordance with
U.S. Environmental Protection Agency policy and
approved for publication. Mention, of trade names
or commercial products does not constitute endorse-
ment or recommendation for use.
ii
-------
TABLE OF CONTENTS
VOLUME I - INTRODUCTION AND METHODOLOGY
VOLUME II - SITE SPECIFIC STUDIES FOR
Alabama, Delaware, Florida, Georgia, Illinois
VOLUME III - SITE SPECIFIC STUDIES FOR
Indiana, Kentucky, Massachusetts, Maryland, Michigan, Minnesota
VOLUME IV - SITE SPECIFIC STUDIES FOR
Missouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
SECTION PAGE
ABSTRACT i i
LIST OF FIGURES vi
LIST OF TABLES" vii
ABBREVIATIONS AND SYMBOLS xx
ACKNOWLEDGEMENT . xxiii
METRIC EQUIVALENTS xxiv
14.0 MISSOURI 14-1
14.1 Associated Electric Cooperative System . . . 14-1
14.1.1 New Madrid Steam Plant 14-1
14.1.2 Thomas Hill Steam Plant 14-10
14.2 Empire District Electric Company 14-29
14.2.1 Asbury Steam Plant 14-29
14.3 Kansas City Power and Light . . . 14-42
14.3.1 Hawthorn Steam Plant . . . 14-42
14.3.2 Iatan Steam Plant . 14-54
14.3.3 La Cygne Steam Plant 14-60
14.3.4 Montrose Steam Plant ... 14-67
14.4 Missouri Public Service 14-77
14.4.1 Sibley Steam Plant 14-77
14.5 City Utilities of Springfield 14-92
14.5.1 James River Steam Plant 14-92
iii
-------
TABLE OF CONTENTS (Continued)
SECTION PAGE
14.6 Union Electric Company 14-109
14.6.1 Labadie Steam Plant 14-109
14.6.2 Meramec Steam Plant ". 14-124
14.6.3 Rush Island Steam Plant 14-146
14.6.4 Sioux Steam Plant 14-158
15.0 MISSISSIPPI 15-1
15.1 Mississippi Power Company 15-1
15.1.1 V. J. Daniel, Jr. Steam Plant 15-1
15.1.2 Jack Watson Steam Plant 15-5
16.0 NORTH CAROLINA 16-1
16.1 Carolina Power and Light Company 16-1
16.1.1 Mayo Steam Plant 16-1
16.1.2 Roxboro Steam Plant 16-4
16.2 Duke Power Company 16-19
16.2.1 Allen Steam Plant 16-19
16.2.2 Belews Creek Steam Plant 16-25
16.2.3 Cliffside Steam Plant 16-29
16.2.4 Marshall Steam Plant 16-40
17.0 NEW HAMPSHIRE 17-1
17.1 Public Service Company of New Hampshire 17-1
17.1.1 Merrimack Steam Plant 17-1
18.0 NEW JERSEY 18-1
18.1 Atlantic City Electric Company 18-1
18.1.1 B. L. England Steam Plant 18-1
18.2 Public Service Electric & Gas Company 18-11
18.2.1 Hudson Steam Plant 18-11
18.2.2 Mercer Steam Plant 18-15
19.0 NEW YORK 19-1
19.1 New York State Electric and Gas Corporation 19-1
19.1.1 Goudey Steam Plant 19-1
19.1.2 Greenidge Steam Plant 19-11
19.1.3 Mi 11iken Steam Plant 19-17
19.2 Niagara Mohawk Power Corporation 19-26
19.2.1 Dunkirk Steam Plant 19-26
19.2.2 C. R. Huntley Steam Plant 19-35
iv
-------
TABLE OF CONTENTS (Continued)
SECTION PAGE
19.3 Rochester Gas and Electric Company 19-46
19.3.1 Rochester 7 Russell Steam Plant ... 19-46
20.0 OHIO 20-1
20.1 Cardinal Operating Company . 20-1
20.1.1 Cardinal Steam Plant . 20-1
20.2 Cincinnati Gas and Electric Company . 20-19
20.2.1 Walter C. Beckjord Steam Plant 20-19
20.2.2 Miami Fort Steam Plant 20-33
20.3 Cleveland Electric Illuminating Company 20-53
20.3.1 Ashtabula Steam Plant ... 20-53
20.3.2 Avon Lake Steam Plant 20-59
20.3.3 Eastlake Steam Plant 20-73
20.4 Columbus and Southern Ohio Electric Company 20-93
20.4.1 Conesville Steam Plant 20-93
20.4.2 Picway Steam Plant 20-93
20.4.3 Poston Steam Plant 20-101
20.5 Oayton Power and Light Company 20-118
20.5.1 James M. Stuart Steam Plant 20-118
20.6 Ohio Edison Company 20-118
20.6.1 R. E. Burger Steam Plant 20-118
20.6.2 Niles Plant 20-118
20.6.3 W. H. Sammis Steam Plant . . . . 20-128
20.6.4 Toronto Plant 20-128
20.7 Ohio Power Company 20-144
20.7.1 General James M. Gavin Steam Plant 20-144
20.7.2 Muskingum River Steam Plant 20-155
20.8 Ohio Valley Electric Corporation 20-156
20.8.1 Kyger Creek Steam Plant . . 20-156
20.9 Toledo Edison Company 20-17Q
20.9.1 Bay Shore Steam Plant 20-170
VOLUME V - SITE SPECIFIC STUDIES FOR
Pennsylvania, South Carolina, Tennessee, Virginia,
Wisconsin, West Virginia
v
-------
LIST OF FIGURES
FIGURE
VOLUME IV - SITE SPECIFIC STUDIES FOR
Missouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
14.1.1-1 New Madrid Plant Plot Plan 14-2
14.1.2-1 Thomas Hill Plant Plot Plan 14-13
14.2.1-1 Asbury Plant Plot Plan 14-30
14.3.1-1 Hawthorn Plant Plot Plan 14-43
14.4.1-1 Sibley Plant Plot Plan 14-78
14.6.1-1 Labadie Plant Plot Plan 14-110
14.6.2-1 Meramec Plant Plot Plan 14-127
14.6.3-1 Rush Island Plant Plot Plan 14-147
14.6.4-1 Sioux Plant Plot Plan 14-161
20.1.1-1 Cardinal Plant Plot Plan 20-2
20.2.1-1 Beckjord Plant Plot Plan 20-20
20.2.2-1 Miami Fort Plant Plot Plan 20-37
20.3.2-1 Avon Lake Plant Plot Plan 20-60
20.3.3-1 Eastlake Plant Plot Plan 20-74
20.4.3-1 Poston Plant Plot Plan 20-102
20.6.4-1 Toronto Plant Plot Plan 20-129
vi
-------
LIST OF TABLES
TABLES PAGE
VOLUME IV - SITE SPECIFIC STUDIES FOR
Missouri, Mississippi, North Carolina, New Hampshire,
New Jersey, New York, Ohio
14.1.1-1 New Madrid Steam Plant Operational Data • 14-3
14.1.1-2 Summary of Retofit Factor Data for New Madrid Unit 1 or 2 . . . 14-5
14.1.1-3 Summary of FGD Control Costs for the New Madrid Plant
(June 1988 Dollars) 14-6
14.1.1-4 Summary of N0X Retrofit Results for New Madrid . . 14-8
14.1.1-5 NO Control Cost Results for the New Madrid Plant
(June 1988 Dollars) 14-9
14.1.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for New Madrid Units 1-2 14-11
14.1.1-7 Summary of DSD/FSI Control Costs for the New Madrid
Plant (June 1988 Dollars) 14-12
14.1.2-1 Thomas Hill Steam Plant Operational Data 14-14
14.1.2-2 Summary of Retrofit Factor Data for Thomas Hill Unit 1 ... 14-16
14.1.2-3 Summary of Retrofit Factor Data for Thomas Hill Unit 2 . . . 14-17
14.1.2-4 Summary of FGD Control Costs for the Thomas Hill
Plant (June 1988 Dollars) . 14-19
14.1.2-5 Summary of Coal Switching/Cleaning Costs for
the Thomas Hill Plant (June 1988 Dollars) 14-20
14.1.2-6 Summary of NO Retrofit Results for Thomas Hill 14-22
14.1.2-7 NO., Control Cost Results for the Thomas Hill Plant
(June 1988 Dollars) 14-23
14.1.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Thomas Hill Unit 1 . . 14-25
14.1.2-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Thomas Hill Unit 2 14-26
14.1.2-10 Summary of DSD/FSI Control Costs for the Thomas Hill
Plant (June 1988 Dollars) ..... 14-27
14.2.1-1 Asbury Steam Plant Operational Data 14-31
14.2.1-2 Summary of Retrofit Factor Data for Asbury Unit 1 14-33
14.2.1-3 Suirmary of FGD Control Costs for the Asbury Plant
(June 1988 Dollars) 14-34
14.2.1-4 Summary of Coal Switching/Cleaning Costs for the
Asbury Plant (June 1988 Dollars) . 14-36
14.2.1-5 Summary of NO Retrofit Results for Asbury 14-37
14.2.1-6 NO Control Cost Results for the Asbury Plant
(June 1988 Dollars) 14-38
14.2.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Asbury Unit 1 14-40
14.2.1-8 Summary of DSD/FSI Control Costs for the Asbury Plant
(June 1988 Dollars) ......... 14-41
14.3.1-1 Hawthorn Steam Plant Operational Data 14-44
14.3.1-2 Summary of Retrofit Factor Data for Hawthorn Unit 5 .... . 14-46
vii
-------
LIST OF TABLES (Continued)
TABLES PAGE
14.3.1-3 Summary of FGD Control Costs for the Hawthorn
Plant (June 1988 Dollars) 14-47
14.3.1-4 Summary of N0X Retrofit Results for Hawthorn 14-49
14.3.1-5 NO Control Cost Results for the Hawthorn Plant
(June 1988 Dollars) 14-50
14.3.1-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Hawthorn Unit 5 14-52
14.3.1-7 Summary of DSD/FSI Control Costs for the Hawthorn
Plant (June 1988 Dollars) 14-53
14.3.2-1 Iatan Steam Plant Operational Data 14-54
14.3.2-2 Summary of Retrofit Factor Data for Iatan Unit 1 14-55
14.3.2-3 Summary of NO Retrofit Results for Iatan 14-56
14.3.2-4 NO Control Costs Results for the Iatan Plant
(June 1988 Dollars) 14-57
14.3.2-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Iatan Unit 1 14-58
14.3.2-6 Summary of DSD/FSI Control Costs for the Iatan Plant
(June 1988 Dollars) 14-59
14.3.3-1 La Cygne Steam Plant Operational Data 14-61
14.3.3-2 Summary of Retrofit Factor Data for La Cygne Unit 2 14-63
14.3.3-3 Summary of NO Retrofit Results for La Cygne 14-64
14.3.3-4 N0V Control Cost Results for the La Cygne Plant
(June 1988 Dollars) 14-65
14.3.4-1 Montrose Steam Plant Operational Data ... .... 14-68
14.3.4-2 Summary of Retrofit Factor Data for
Montrose Units 1, 2, 3 14-70
14.3.4-3 Summary of N0y Retrofit Results for Montrose 14-71
14.3.4-4 NO Control Cost Results for the Montrose Plant
(June 1988 Dollars) 14-72
14.3.4-5 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Montrose Units 1, 2, 3 14-74
14.3.4-6 Summary of DSD/FSI Control Costs for the
Montrose Plant (June 1988 Dollars) .... 14-75
14.4.1-1 Sibley Steam Plant Operational Data 14-79
14.4.1-2 Summary of Retrofit Factor Data for Sibley Units 1 or 2 . . . 14-81
14.4.1-3 Summary of Retrofit Factor Data for Sibley Unit 3 14-82
14.4.1-4 Summary of FGD Control Costs for the Sibley Plant
(June 1988 Dollars) 14-84
14.4.1-5 Summary of N0y Retrofit Results for Sibley 14-85
14.4.1-6 N0y Control Cost Results for the Sibley Plant
(June 1988 Dollars) 14-86
14.4.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Sibley Units 1 or 2 14-89
viii
-------
LIST OF TABLES (Continued)
TABLES PAGE
14.4.1-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Sibley Unit 3 14-90
14.4.1-9 Summary of DSD/FSI Control Costs for the Sibley
Plant (June 1988 Dollars) 14-91
14.5.1-1 James River Steam Plant Operational Data. . . 14-93
14.5.1-2 Summary of Retrofit Factor Data for James River
Units 1 or 2 14-95
14.5.1-3 Summary of Retrofit Factor Data for James River Unit 3 . . . 14-96
14.5.1-4 Summary of Retrofit Factor Data for James River Unit 4 . . . 14-97
14.5.1-5 Summary of Retrofit Factor Data for James River Unit 5 . . . 14-98
14.5.1-6 Summary of FGD Control Costs for the James River Plant
(June 1988 Dollars) . . . . 14-99
14.5.1-7 Summary of Coal Switching/Cleaning Costs
for the James River Plant (June 1988 Dollars) ...... 14-100
14.5.1-8 Summary of NO Retrofit Results for James River 14-102
14.5.1-9 NO Control Cost Results for the James River Plant
(June 1988 Dollars) - 14-103
14.5.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for James River Units 1 or 2 14-105
14.5.1-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for James River Unit 3 14-106
14.5.1-12 Duct Spray Drying and Furnace Sorbent Injection
Technologies for James River Unit 4 14-107
14.5.1-13 Summary of DSD/FSI Control Costs for the James River
Plant (June 1988 Dollars) 14-108
14.6.1-1 Labadie Steam Plant Operational Data 14-111
14.6.1-2 Summary of Retrofit Factor Data for Labadie Unit 1 14-113
14.6.1-3 Summary of Retrofit Factor Data for Labadie Unit 2 14-114
14.6.1-4 Summary of Retrofit Factor Data for Labadie Unit 3 ..... 14-115
14.6.1-5 Summary of Retrofit Factor Data for Labadie Unit 4 14-116
14.6.1-6 Summary of FGD Control Costs for the Labadie Plant
(June 1988 Dollars) 14-118
14.6.1-7 Summary of Coal Switching/Cleaning Costs
for the Labadie Plant (June 1988 Dollars) . 14-119
14.6.1-8 Summary of SCR Retrofit Results for Labadie Units 1-3 ... . 14-120
14.6.1-9 Summary of SCR Retrofit Results for Labadie Unit 4 14-121
14.6.1-10 N0Y Control Cost Results for the Labadie Plant
(June 1988 Dollars) 14-123
14.6.1-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Labadie Units 1-4 .. . 14-125
14.6.1-12 Summary of DSD/FSI Control Costs for the Labadie Plant
(June 1988 Dollars) . 14-126
14.6.2-1 Meramec Steam Plant Operational Data 14-128
14.6.2-2 Summary of Retrofit Factor Data for Meramec Unit 1 ..... 14-130
14.6.2-3 Summary of Retrofit Factor Data for Meramec Unit 2 14-131
ix
-------
LIST OF TABLES (Continued)
TABLES PAGE
14.6.2-4 Summary of Retrofit Factor Data for Meramec Unit 3 14-132
14.6.2-5 Summary of Retrofit Factor Data for Meramec Unit 4 14-133
14.6.2-6 Summary of FGD Control Costs for the Meramec Plant
(June 1988 Dollars) 14-135
14.6.2-7 Summary of Coal Switching/Cleaning Costs for the
Meramec Plant (June 1988 Dollars) 14-136
14.6.2-8 Summary of NO Retrofit Results for Meramec Units 1-2 .... 14-138
14.6.2-9 Summary of NO Retrofit Results for Meramec Units 3-4 .... 14-139
14.6.2-10 NO Control Cost Results for the Meramec Plant
(June 1988 Dollars) 14-140
14.6.2-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Meramec Units 1-2 14-142
14.6.2-12 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Meramec Unit 3 14-143
14.6.2-13 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Meramec Unit 4 14-144
14.6.2-14 Summary of DSD/FSI Control Costs for the Meramec Plant
(June 1988 Dollars) 14-145
14.6.3-1 Rush Island Steam Plant Operational Data 14-148
14.6.3-2 Summary of Retrofit Factor Data for Rush Island Unit 1 ... 14-150
14.6.3-3 Summary of Retrofit Factor Data for Rush Island Unit 2 . . . 14-151
14.6.3-4 Summary of FGD Control Costs for the Rush Island Plant
(June 1988 Dollars) ..... 14-152
14.6.3-5 Summary of Coal Switching/Cleaning Costs for the
Rush Island Plant (June 1988 Dollars) 14-154
14.6.3-6 Summary of NO Retrofit Results for Rush Island 14-155
14.6.3-7 NO Control Cost Results for the Rush Island Plant
(June 1988 Dollars) 14-157
14.6.3-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Rush Island Units 1-2 .... 14-159
14.6.3-9 Summary of DSD/FSI Control Costs for the Rush Island
Plant (June 1988 Dollars) 14-160
14.6.4-1 Sioux Steam Plant Operational Data 14-162
14.6.4-2 Summary of Retrofit Factor Data for Sioux Unit 1 14-165
14.6.4-3 Summary of Retrofit Factor Data for Sioux Unit 2 14-166
14.6.4-4 Summary of FGD Control Costs for the Sioux Plant
(June 1988 Dollars) 14-167
14.6.4-5 Summary of NO Retrofit Results for Sioux . . 14-169
14.6.4-6 NO Control Cost Results for the Sioux Plant
(June 1988 Dollars) 14-170
14.6.4-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Sioux Units 1-2 14-172
14.6.4-8 Summary of DSD/FSI Control Costs for the Sioux Plant
(June 1988 Dollars) 14-173
15.1.1-1 V.J. Daniel Steam Plant Operational Data 15-1
x
-------
LIST OF TABLES (Continued)
TABLES PAGE
15.1.1-2 Summary of Retrofit Factor Data for V.J. Daniel Unit 1 or 2 . . 15-2
15.1.1-3 Summary of NO Retrofit Results for V.J.Daniel 15-3
15.1.1-4 N0y Control Cost Results for the V.J. Daniel Plant
(June 1988 Dollars) 15-4
15.1.2-1 Jack Watson Steam Plant Operational Data . 15-5
15.1.2-2 Summary of Retrofit Factor Data for Watson Unit 4 15-6
15.1.2-3 Summary of Retrofit Factor Data for Watson Unit 5 15-7
15.1.2-4 Summary of F6D Control Costs for the Watson Plant
(June 1988 Dollars) 15-8
15.1.2-5 Summary of Coal Switching/Cleaning Costs for the Watson Plant
(June 1988 Dollars) 15-9
15.1.2-6 Summary of N0X Retrofit Results for Watson ......... 15-10
15.1.2-7 N0y Control Cost Results for the Watson Plant
(June 1988 Dollars) 15-11
15.1.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Watson Unit 4 15-12
15.1.2-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Watson Unit 5 15-13
15.1.2-10 Summary of DSD/FSI Control Costs for the Watson Plant
(June 1988 Dollars) .;.... 15-14
16.1.1-1 Mayo Steam Plant Operational Data . . . 16-2
16.1.1-2 Summary of Retrofit Factor Data for Mayo Unit 1 16-3
16.1.1-3 Summary of NO Retrofit Results for Mayo 16-5
16.1.1-4 N0y Control Cost Results for the Mayo Plant
(June 1988 Dollars) 16-6
16.1.2-1 Roxboro Steam Plant Operational Data 16-7
16.1.2-2 Summary of Retrofit Factor Data for Roxboro Unit 1 16-10
16.1.2-3 Summary of Retrofit Factor Data for Roxboro Unit 2 ..... 16-11
16.1.2-4 Summary of Retrofit Factor Data for Roxboro Unit 3 16-12
16.1.2-5 Summary of Retrofit Factor Data for Roxboro Unit 4 16-13
16.1.2-6 Summary of NO Retrofit Results for Roxboro 16-14
16.1.2-7 NOy Control Cost Results for the Roxboro Plant
(June 1988 Dollars) • • 16-15
16.1.2-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Roxboro Unit 1 or 2 . 16-17
16.1.2-9 Summary of DSD/FSI Control Costs for the Roxboro Plant
(June 1988 Dollars) ' . . 16-18
16.2.1-1 Allen Steam Plant Operational Data 16-19
16.2.1-2 Summary of Retrofit Factor Data for Allen Unit 3 16-20
16.2.1-3 Summary of Retrofit Factor Data for Allen Unit 4 16-21
16.2.1-4 Summary of Retrofit Factor Data for Allen Unit 5 16-22
16.2.1-5 Summary of NO Retrofit Results for Allen 16-23
16.2.1-6 NOy Control Cost Results for the Allen Plant
(June 1988 Dollars) 16-24
xi
-------
LIST OF TABLES (Continued)
TABLES PAGE
16.2.2-1 Belews Creek Steam Plant Operational Data 16-26
16.2.2-2 Summary of Retrofit Factor Data for Belews Unit 1 or 2 ... 16-27
16.2.2-3 Summary of FGD Control Costs for the Belews Creek Plant
(June 1988 Dollars) 16-28
16.2.2-4 Summary of NO Retrofit Results for Belews ......... 16-30
16.2.2-5 NO Control Cost Results for the Belews Creek Plant
(June 1988 Dollars) 16-31
16.2.2-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Belews Unit 1 or 2 16-32
16.2.2-7 Summary of DSD/FSI Control Costs for the Belews Creek Plant
(June 1988 Dollars) 16-33
16.2.3-1 Cliffside Steam Plant Operational Data 16-34
16.2.3-2 Summary of Retrofit Factor Data for Cliffside Unit 5 .... 16-36
16.2.3-3 Summary of FGD Control Costs for the Cliffside Plant
(June 1988 Dollars) 16-37
16.2.3-4 Summary of NO Retrofit Results for Cliffside ........ 16-38
16.2.3-5 NO Control Cost Results for the Cliffside Plant
x(June 1988 Dollars) 16-39
16.2.4-1 Marshall Steam Plant Operational Data 16-41
16.2.4-2 Summary of Retrofit Factor Data for Marshall Unit 1 16-43
16.2.4-3 Summary of Retrofit Factor Data for Marshall Unit 2 .... . 16-44
16.2.4-4 Summary of Retrofit Factor Data for Marshall Unit 3 16-45
16.2.4-5 Summary of Retrofit Factor Data for Marshall Unit 4 .... . 16-46
16.2.4-6 Summary of NO Retrofit Results for Marshall 16-48
16.2.4-7 NO Control Cost Results for the Marshall Plant
(June 1988 Dollars) 16-49
16.2.4-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Marshall Unit 3 or 4 16-50
16.2.4-9 Summary of DSD/FSI Control Costs for the Marshall Plant
(June 1988 Dollars) 16-51
17.1.1-1 Merrimack Steam Plant Operational Data 17-2
17.1.1-2 Summary of Retrofit Factor Data for Merrimack Unit 1 or 2 . . . 17-3
17.1.1-3 Summary of FGD Control Costs for the Merrimack Plant
(June 1988 Dollars) 17-4
17.1.1-4 Summary of NO Retrofit Results for Merrimack 17-6
17.1.1-5 NO Control Cost Results for the Merrimack Plant
(June 1988 Dollars) 17-7
18.1.1-1 B.L. England Steam Plant Operational Data 18-2
18.1.1-2 Summary of Retrofit Factor Data for England Units 1 or 2 ... 18-4
18.1.1-3 Summary of FGD Control Costs for the England Plant
(June 1988 Dollars) 18-5
18.1.1-4 Summary of NO Retrofit Results for England 18-6
18.1.1-5 NO Control Cost Results for the England Plant
(June 1988 Dollars) 18-7
xii
-------
LIST OF TABLES (Continued)
TABLES PAGE
18.1.1-6 Duct Spray Drying and Furnace Sorbent Injection Technologies
for England Unit 2 18-9
18.1.1-7 Summary of DSD/FSI Control Costs for the England Plant
(June 1988 Dollars) 18-10
18.2.1-1 Hudson Steam Plant Operational Data . 18-11
18.2.1-2 Summary of Retrofit Factor Data for Hudson Unit 2 18-12
18.2.1-3 Summary of NO Retrofit Results for Hudson 18-13
18.2.1-4 NO Control Cost Results for the Hudson Plant
(June 1988 Dollars) 18-14
18.2.2-1 Mercer Steam Plant Operational Data 18-16
18.2.2-2 Summary of Retrofit Factor Data for Mercer Unit 1 or 2 ... 18-17
18.2.2-3 Summary of NO Retrofit Results for Mercer 18-19
18.2.2-4 NO Control Cost Results for the Mercer Plant
x(June 1988 Dollars) 18-20
18.2.2-5 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Mercer Unit 1 or 2 . . . 18-21
18.2.2-6 Summary of DSD/FSI Control Costs for the Mercer Plant
(June 1988 Dollars) 18-22
19.1.1-1 Goudey Steam Plant Operational Data 19-2
19.1.1-2 Summary of Retrofit Factor Data for Goudey Units 1-3 (each) . . 19-3
19.1.1-3 Summary of FGD Control Costs for the Goudey Plant
(June 1988 Dollars) 19-4
19.1.1-4 Summary of Coal Switching/Cleaning Costs for the Goudey Plant
(June 1988 Dollars) 19-6
19.1.1-5 Summary of NO Retrofit Results for Goudey . . 19-7
19.1.1-6 NO Control Cost Results for the Goudey Plant
(June 1988 Dollars) 19-8
19.1.1-7 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Goudey Unit 1, 2, or 3 19-9
19.1.1-8 Summary of DSD/FSI Control Costs for the Goudey Plant
(June 1988 Dollars) 19-10
19.1.2-1 Greenidge Steam Plant Operational Data 19-11
19.1.2-2 Summary of Retofit Factor Data for Greenidge Unit 4+5, or 6 . 19-12
19.1.2-3 Summary of FGD Control Costs for the Greenidge Plant
(June 1988 Dollars) 19-13
19.1.2-4 Summary of Coal Switching/Cleaning Costs for the Greenidge
Plant (June 1988 Dollars) ..... 19-14
19.1.2-5 Summary of N0„ Retrofit Results for Greenidge 19-15
19.1.2-6 NO Control Cost Results for the Greenidge Plant
(June 1988 Dollars) 19-16
19.1.3-1 Willi ken Steam Plant Operational Data 19-17
19.1.3-2 Summary of Retrofit Factor Data for Milliken Unit 1 19-18
19.1.3-3 Summary of Retrofit Factor Data for Milliken Unit 2 19-19
xiii
-------
LIST OF TABLES (Continued)
TABLES PAGE
19.1.3-4 Summary of FGD Control Costs for the Mi 11iken Plant
(June 1988 Dollars) 19-20
19.1.3-5 Summary of Coal Switching/Cleaning Costs for the Milliken Plant
(June 1988 Dollars) 19-21
19.1.3-6 Summary of NO Retrofit Results for Mi 11iken 19-22
19.1.3-7 N0„ Control Cost Results for the Mi 11iken Plant
(June 1988 Dollars) 19-23
19.1.3-8 Duct Spray Drying and Furnace Sorbent Injection Technologies
for Milliken Units 1 and 2 19-24
19.1.3-9 Summary of DSD/FSI Control Costs for the Milliken Plant
(June 1988 Dollars) 19-25
19.2.1-1 Dunkirk Steam Plant Operational Data 19-27
19.2.1-2 Summary of Retrofit Factor Data for Dunkirk Unit 1 or 2 . . . 19-29
19.2.1-3 Summary of Retrofit Factor Data for Dunkirk Unit 3 or 4 . . . 19-30
19.2.1-4 Summary of FGD Control Costs for the Dunkirk Plant
(June 1988 Dollars) 19-31
19.2.1-5 Summary of Coal Switching/Cleaning Costs for the Dunkirk Plant
(June 1988 Dollars) 19-32
19.2.1-6 Summary of N0„ Retrofit Results for Dunkirk 19-33
19.2.1-7 NO Control Cost Results for the Dunkirk Plant
(June 1988 Dollars) 19-34
19.2.2-1 Huntley Steam Plant Operational Data 19-36
19.2.2-2 Summary of Retrofit Factor Data for C.R. Huntley
Units 1-4 (63-66, Each) 19-38
19.2.2-3 Summary of Retrofit Factor Data for C.R. Huntley
Units 5 or 6 (67-68) 19-39
19.2.2-4 Summary of FGD Control Costs for the Huntley Plant
(June 1988 Dollars) 19-40
19.2.2-5 Summary of Coal Switching/Cleaning Costs for the Huntley Plant
(June 1988 Dollars) 19-42
19.2.2-6 Summary of NO Retrofit Results for C.R. Huntley 19-43
19.2.2-7 NO Control Cost Results for the Huntley Plant
(June 1988 Dollars) 19-44
19.3.1-1 Rochester 7 Russell Steam Plant Operational Data 19-46
19.3.1-2 Summary of Retrofit Factor Data for Rochester 7
Russell Unit 1 or 2 19-47
19.3.1-3 Summary of Retrofit Factor Data for Rochester 7
Russell Unit 3 or 4 19-48
19.3.1-4 Summary of FGD Control Costs for the Rochester 7
Russell Plant (June 1988 Dollars) . . 19-49
19.3.1-5 Summary of Coal Switching/Cleaning Costs for the Rochester 7
Russell Plant (June 1988 Dollars) 19-50
19.3.1-6 Summary of NO Retrofit Results for Rochester 7
Russell Units 1-2 19-51
xiv
-------
LIST OF TABLES (Continued)
TABLES PAGE
19.3.1-7 Summary of NO Retrofit Results for Rochester 7
Russell Units 3-4 19-52
19.3.1-8 N0y Control Cost Results for the Rochester 7 Russell Plant
(June 1988 Dollars) 19-53
20.1.1-1 Cardinal Steam Plant Operational Data .... 20-3
20.1.1-2 Summary of Retrofit Factor Data for Cardinal Unit 1 20-6
20.1.1-3 Summary of Retrofit Factor Data for Cardinal Unit 2 . ..... 20-7
20.1.1-4 Summary of Retrofit Factor Data for Cardinal Unit 3 20-8
20.1.1-5 Summary of FGD Control Costs for the Cardinal Plant
(June 1988 Dollars) 20-9
20.1.1-6 Summary of Coal Switching/Cleaning Costs for the
Cardinal Plant (June 1988 Dollars) 20-11
20.1.1-7 Summary of NO Retrofit Results for Cardinal 20-12
20.1.1-8 NO Control Cost Results for the Cardinal Plant
(June 1988 Dollars) ....... 20-13
20.1.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Cardinal Units 1-2 20-16
20.1.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Cardinal Unit 3 20-17
20.1.1-11 Summary of DSD/FS1 Control Costs for the
Cardinal Plant (June 1988 Dollars) . . . 20-18
20.2.1-1 Beckjord Steam Plant Operational Data . 20-21
20.2.1-2 Summary of Retrofit Factor Data for Beckjord Units 1-4 . . . 20-23
20.2.1-3 Summary of Retrofit Factor Data for Beckjord Unit 5 20-24
20.2.1-4 Summary of Retrofit Factor Data for Beckjord Units 6 .... 20-25
20.2.1-5 Summary of FGD Control Costs for the Beckjord Plant
(June 1988 Dollars) 20-27
20.2.1-6 Summary of Coal Switching/Cleaning for the
Beckjord Plant (June 1988 Dollars) ... 20-28
20.2.1-7 Summary of N0X Retrofit Results for Beckjord Units 1-3 . . . 20-30
20.2.1-8 Summary of NO Retrofit Results for Beckjord Units 4-6 ... 20-31
20.2.1-9 NO Control Cost Results for the Beckjord Plant
(June 1988 Dollars) 20-32
20.2.1-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Beckjord Unit 6 20-34
20.2.1-11 Summary of DSD/FSI Control Costs for the Beckjord
Plant (June 1988 Dollars) 20-35
20.2.2-1 Miami Fort Steam Plant Operational Data 20-38
20.2.2.2 Summary of Retrofit Factor Data for Miami Fort Unit 6 . . . . 20-40
20.2.2-3 Summary of Retrofit Factor Data for Miami Fort Unit 7 ... . 20-41
20.2.2-4 Summary of FGD Control Costs for the Miami Fort
Plant (June 1988 Dollars) . 20-43
20.2.2-5 Summary of Coal Switching/Cleaning Costs for the
Miami Fort Plant (June 1988 Dollars) 20-44
XV
-------
LIST OF TABLES (Continued)
TABLES PAGE
20.2.2-6 Summary of NOy Retrofit Results for Miami Fort
Units 5-7. 20-46
20.2.2-7 Summary of NO Retrofit Results for Miami Fort Unit 8 . . . . 20-47
20.2.2-8 NO Control Cost Results for the Miami Fort Plant
(June 1988 Dollars) 20-48
20.2.2-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Miami Fort Unit 7 . . 20-50
20.2.2-10 Summary of DSD/FSI Control Costs for the Miami
Fort Plant (June 1988 Dollars) 20-51
20.3.1-1 Ashtabula Steam Plant Operational Data 20-53
20.3.1-2 Summary of Retrofit Factor Data for Ashtabula Units 8-11 . . 20-54
20.3.1-3 Summary of FGD Control Costs for the Ashtabula Plant
(June 1988 Dollars) 20-55
20.3.1-4 Summary of Coal Switching/Cleaning Costs for the
Ashtabula Plant (June 1988 Dollars) 20-56
20.3.1-5 Summary of N0y Retrofit Results for Ashtabula 20-57
20.3.1-6 NO Control Cost Results for the Ashtabula Plant
(June 1988 Dollars) - 20-58
20.3.2-1 Avon Lake Steam Plant Operational Data 20-61
20.3.2-2 Summary of Retrofit Factor Data for Avon Lake
Unit 12 (Case 1) 20-63
20.3.2-3 Summary of Retrofit Factor Data for Avon Lake Unit 12.
(Case 2) 20-64
20.3.2-4 Summary of FGD Control Costs for the Avon Lake
Plant (June 1988 Dollars) 20-66
20.3.2-5 Summary of the Coal Switching/Cleaning Costs for the
Avon Lake Plant (June 1988 Dollars 20-67
20.3.2-6 Summary of NO Retrofit Results for Avon Lake 20-69
20.3.2-7 N0y Control Cost Results for the Avon Lake Plant
x(June 1988 Dollars) 20-70
20.3.2-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Avon Lake Unit 12 20-71
20.3.2-9 Summary of DSD/FSI Control Costs for the Avon Lake
Plant (June 1988 Dollars) 20-72
20.3.3-1 Eastlake Steam Plant Operational Data 20-75
20.3.3-2 Summary of Retrofit Factor Data for Eastlake Units 1-2 . . . 20-77
20.3.3-3 Summary of Retrofit Factor Data for Eastlake Units 3-4 . . . 20-78
20.3.3-4 Summary of Retrofit Factor Data for Eastlake Unit 5 20-79
20.3.3-5 Summary of FGD Control Costs for the Eastlake Plant
(June 1988 Dollars) . 20-81
20.3.3-6 Summary of Coal Switching/Cleaning Cost for the
Eastlake Plant (June 1988 Dollars) 20-83
20.3.3-7 Summary of NO Retrofit Results for Eastlake Units 1-3 ... 20-84
20.3.3-8 Summary of NO Retrofit Results for Eastlake Units 4-5 . . . 20-85
xvi
-------
LIST OF TABLES (Continued)
TABLES PAGE
20.3.3-9 NO Control Cost Results for the Eastlake Plant
(June 1988 Dollars) 20-86
20.3.3-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Eastlake Units, 1, 2, or 3 20-88
20.3.3-11 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Eastlake unit 4 . . . 20-89
20.3.3-12 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Eastlake Unit 5 20-90
20.3.3-13 Summary of DSD/FSI Control Costs for the Eastlake
Plant (June 1988 Dollars) 20-92
20.4.2-1 Picway Steam Plant Operational Data 20-93
20.4.2-2 Summary of Retrofit Factor Data for Picway Unit 9 20-94
20.4.2-3 Summary of FGD Control Costs for the Picway Plant
(June 1988 Dollars) 20-95
20.4.2-4 Summary of Coal Switching/Cleaning Cost for the
Picway Plant (June 1988 Dollars) 20-96
20.4.2-5 Summary of NO Retrofit Results for Picway .... 20-97
20.4.2-6 NOy Control Cost Results for the Picway Plant
(June 1988 Dollars) 20-98
20.4.2-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Picway Unit 9 20-99
20.4.2-8 Summary of DSD/FSI Control Costs for the Picway
Plant (June 1988 Dollars) 20-100
20.4.3-1 Poston Steam Plant Operational Data 20-103
20.4.3-2 Summary of Retrofit Factor Data for Poston Units 1-2 . . . 20-105
20.4.3-3 Summary of Retrofit Factor Data for Poston Units 3-4 .... 20-106
20.4.3-4 Summary of FGD Control Costs for the Poston Plant
(June 1988 Dollars) 20-108
20.4.3-5 Summary of Coal Switching/Cleaning Cost for the
Poston Plant (June 1988 Dollars) 20-109
20.4.3-6 Summary of N0y Retrofit Results for Poston Units 1-3 . . . 20-111
20.4.3-7 Summary of NO Retrofit Results for Poston Unit 4 20-112
20.4.3-8 NO,. Control Cost Results for the Poston Plant
(June 1988 Dollars) 20-113
20.4.3-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Poston Units 1-2 20-115
20.4.3-10 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Poston Unit 3-4 20-116
20.4.3-11 Summary of DSD/FSI Control Costs for the Poston
Plant (June 1988 Dollars) 20-117
20.6.2-1 Niles Steam Plant Operational Data 20-119
20.6.2-2 Summary of Retrofit Factor Data for Niles Unit 1 or 2 ... . 20-121
20.6.2-3 Summary of FGD Control Costs for the Niles Plant
(June 1988 Oollars) 20-122
20.6.2-4 Summary of N0X Retrofit Results for Niles 20-123
xvii
-------
LIST OF TABLES (Continued)
TABLES PAGE
20.6.2-5 NO Control Cost Results for the Niles Plant
(June 1988 Dollars) 20-124
20.6.2-6 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Niles Unit 1 or 2 20-126
20.6.2-7 Summary of DSD/FSI Control Costs for the Niles
Plant (June 1988 Dollars) ..... 20-127
20.6.4-1 Toronto Steam Plant Operational Data 20-130
20.6.4-2 Summary of Retrofit Factor Data for Toronto Units 9-11 . . . 20-132
20.6.4-3 Summary of FGD Control Costs for the Toronto
Plant (June 1988 Dollars) 20-133
20.6.4-4 Summary of Coal Switching/Cleaning Costs
for the Toronto Plant (June 1988 Dollars) . 20-135
20.6.4-5 Summary of NO Retrofit Results for Toronto 20-136
20.6.4-6 NO Control Cost Results for the Toronto Plant
(June 1988 Dollars) 20-138
20.6.4-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Toronto Unit 9 20-140
20.6.4-8 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Toronto Unit 10 ... 20-141
20.6.4-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Toronto Unit 11 20-142
20.6.4-10 Summary of DSD/FSI Control Costs for the Toronto
Plant (June 1988 Dollars) 20-143
20.7.1-1 Gavin Steam Plant Operational Data 20-145
20.7-1-2 Summary of Retrofit Factor Data for Gavin Unit 1 or 2 ... . 20-147
20.7.1-3 Summary of FGD Control Costs for the James M. Gavin
Plant (June 1988 Dollars) 20-148
20.7.1-4 Summary of Coal Switching/Cleaning Costs
for the James M. Gavin Plant (June 1988 Dollars) 20-149
20.7.1-5 Summary of NO Retrofit Results for Gavin 20-150
20.7.1-6 NO Control Cost Results for the James M. Gavin Plant
(June 1988 Dollars) 20-151
20.7.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Gavin Unit 1 or 2 ..... 20-153
20.7.1-8 Summary of DSD/FSI Control Costs for the James M. Gavin
Plant (June 1988 Dollars) . . . 20-154
20.8.1-1 Kyger Creek Steam Plant Operational Data 20-157
20.8-1-2 Summary of Retrofit Factor Data for Kyger Creek Unit 1 or 2 . 20-159
20.8-1-3 Summary of Retrofit Factor Data for Kyger Creek Unit. 3 . . . 20-160
20.8-1-4 Summary of Retrofit Factor Data for Kyger Creek Unit 4 . . . 20-161
20.8-1-5 Summary of Retrofit Factor Data for Kyger Creek Unit 5 ... 20-162
20.8.1-6 Summary of FGD Control Costs for the Kyger Creek Plant
(June 1988 Dollars) 20-163
20.8.1-7 Summary of N0X Retrofit Results for Kyger Creek 20-165
xviii
-------
LIST OF TABLES (Continued)
TABLES PAGE
20.8.1-8 NO Control Cost Results for the Kyger Creek Plant
(June 1988 Dollars) 20-166
20.8.1-9 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Kyger Creek Units 1, 2, 3, 4 or 5 . . . . 20-168
20.8.1-10 Summary of DSD/FSI Control Costs for the Kyger Creek.
Plant (June 1988 Dollars) 20-169
20.9.1-1 Bay Shore Steam Plant Operational Data 20-171
20.9.1-2 Summary of Retrofit Factor Data for Bay Shore
Units 1-4 (Combined) : 20-173
20.9.1-3 Summary of FGD Control Costs for the Bay Shore
Plant (June 1988 Dollars) 20-174
20.9.1-4 Summary of Coal Switching/Cleaning Costs
for the Bay Shore Plant (June 1988 Dollars) 20-175
20.9.1-5 Summary of NO Retrofit Results for Bay Shore . . 20-176
20.9.1-6 NO Control Cost Results for the Bay Shore Plant
(June 1988 Dollars) 20-177
20.9.1-7 Duct Spray Drying and Furnace Sorbent Injection
Technologies for Bay Shore Unit 1 or 2 . 20-178
20.9.1-8 Summary of DSD/FSI Control Costs for the Bay Shore
Plant (June 1988 Dollars) 20-179
xix
-------
ABBREVIATIONS ANO SYMBOLS
ABBREVIATIONS
acfm -- actual cubic feet per minute
AEERL --Air and Energy Engineering Research Laboratory
AEP -- Associated Electric Cooperative
AFDC -- allowance for funds during construction
AUSM -- advanced utility simulation model
-C -- constant dollars in cost tables
CG -- coal gasfication
CG&E -- Cincinnati Gas and Electric
CS -- coal switching
CS/B -- coal switching and blending
DOE -- Department of Energy
DSD -- duct spray drying
EIA-767 -- Energy Information Administration Form 767
EPA -- Environmental Protection Agency
EPRI -- Electric Power Research Institute
ESP -- electrostatic precipitator
FBC -- fluidized bed combustion
FF -- fabric filter
FGD -- flue gas desulfurization
FPD -- fuel price differential
FSI — furnace sorbent injection
ft -- feet
FWF -- front, wall-fired
IAPCS -- Integrated Air Pollution Control System
XX
-------
ABBREVIATIONS AND SYMBOLS (Continued)
IRS
Internal Revenue Service
KU
..
Kentucky Utilities
kW
--
kilowatt
kWh
--
killowatt hour
LC
--
low cost
LIMB
--
limestone injection multistage burner
L/LS
--
lime/limestone
LNB
--
low-NOx burner
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
NROC
--
Natural Resources Defense Council
NSPS
--
new source performance standard
NTIS
--
National Technical Information Service
OEUI
--
Ohio Electric Utilities
OFA
--
overfire air
OWF
--
opposed, wall-fired
O&M
--
operating and maintenance
PCC
--
physical coal cleaning
PM
--
particulate matter
psia
--
pounds per square inch absolute
xxi
-------
ABBREVIATIONS AND SYMBOLS (Continued)
SCA -- specific collection area (ft^/1000 acfm)
SCR -- selective catalytic reduction
SCR-CS -- selective catalytic reduction - cold side
SCR-HS -- selective catalytic reduction - hot side
sec -- second
SI -- sorbent injection
sq ft -- square feet
TAG -- Technical Assessment Guideline
TVA -- Tennessee Valley Authority
UARG -- Utility Air Regulatory Group
USGS -- U.S. Geological Survey
$/kW -- dollars per kilowatt
SYMBOLS
MgO -- magnesium oxide
NHg -- ammonia
N0X -- nitrogen oxides
S02 -- sulfur dioxide
SO, -- sulfur trioxide
xxii
-------
ACKNOWLEDGEMENT
We would like to thank the following people at Radian Corporation who hel
in the preparation of this report: Robert Page, Susan Squire,
JoAnn Gilbert, Linda Cooper, Sarah Godfrey, Kelly Martin, Karen Oliver, a
Janet Mangum.
xxiii
-------
METRIC EQUIVALENTS
Readers more familiar with the metric system may use the following
factors to convert to that system.
Non-metric
acfm
acre
Btu/lb
°F
ft
ft2-
ft3
gal.
1b/MMBtu
psia
ton
Times
0.028317
4046.9
0.5556
5/9 (°F-32)
0.3048
0.0929
0.028317
3.78533
1.8
0.0703
0.9072
Yields Metric
acms
m2
kg-calories/kg
m
™3
L
kg/kg-calorie
2
g/cm
ton
xxiv
-------
SECTION 14.0 MISSOURI
14.1 ASSOCIATED ELECTRIC COOPERATIVE SYSTEM
14.1.1 New Madrid Steam Plant
The New Madrid steam plant is located within New Madrid County,
Missouri,as part of the Associated Electric Cooperative system. The plant
contains two coal-fired boilers with a total gross generating capacity of
1,200 MW. Figure 14.1.1-1 presents the plant plot plan showing the general
layout and location of the boilers and major associated auxiliary equipment.
Table 14.1.1-1 presents operational data for the existing equipment at
the New Madrid steam plant. All boilers burn high sulfur coal (3.2 to
4.1 percent sulfur). Coal shipments are received by freight barge and
conveyed to a coal storage and handling area located northwest of the plant.
Particulate matter emissions for both boilers are controlled with
retrofit ESPs located south of Unit 2. Ash from all units is wet sluiced to
ponds located southeast of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 14.1.1-1 shows the general layout and location of the FGD
control system. Absorbers for both units and both FGD technologies were
located in a relatively open area south of unit 2 on either side of the
retrofit ESPs, adjacent to the chimney. The lime and limestone preparation/
storage area was placed west of the absorbers with the waste handling area
being located south of the preparation/storage area. No major demolition/
relocation would be required to locate the absorbers. Therefore, a low
general facility factor (5 percent) was assigned to all units and
technologies.
Retrofit Difficulty and Scope Adder Costs--
The FGD equipment for both units would be located in a relatively low
site access/congestion area on either side of the retrofit ESPs. No major
obstacles/obstructions exist in the surrounding area where the absorbers and
14-1
-------
NH, Storage
System
FGD Waste Handling/Absorber Area
lime/limestone Storage/Preparation Area
SCR Reactors
Not to scale
Figure 14.1.1-1. New Madrid plant plot plan
14-2
-------
TABLE 14.1.1-1. NEW MADRID STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
GENERATING CAPACITY (MW-each)
600
CAPACITY FACTOR (PERCENT)
49, 45
FIRING TYPE
CYC
INSTALLATION DATE
1972-77
COAL SULFUR CONTENT (PERCENT)
3.2
COAL HEATING VALUE (BTU/LB)
10500
COAL ASH CONTENT (PERCENT)
10.5
FLY ASH SYSTEM
WET SLUICE
ASH DISPOSAL METHOD
ON-SITE
STACK NUMBER
1-2
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL
TYPE
ESP
INSTALLATION DATE
1982
EMISSION (LB/MM BTU)
0.06-0.05
REMOVAL EFFICIENCY
98.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
4.7
SURFACE AREA (1000 SQ FT)
572
GAS EXIT RATE (1000 ACFM)
2200
SCA (SQ FT/1000 ACFM)
260
OUTLET TEMPERATURE (*F)
310
14-3
-------
tie-in ductwork would be located. As a result, a low site access/congestion
factor was assigned to the FGD absorbers and flue gas handling system for
all units and all FGD technologies. A short duct run was required to route
the flue gas to absorbers.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Table 14.1.1-2. The largest scope
adder for the New Madrid plant would be the conversion of units 1 and 2 fly
ash conveying/disposal system from wet to dry for conventional L/IS-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 sluice lines in LSD-FGD system (for the 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 were low (1.24 to 1.31).
The LSD with reused ESP was the only LSD-FGD technology considered
because the existing ESPs have moderate size SCAs (260). The retrofit factor
determined for the LSD technologies was low (1.27) and did not include
particulate control upgrading costs. A separate retrofit factor was developed
for upgrading the ESPs (1.16) and used in the IAPCS model to estimate the
particulate control costs of additional ESP plate area. The low factor is a
result of the space availability around the existing ESPs.
Table 14.1.1-3 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boilers 1 and 2.
The low cost control case reduces capital and annual operating costs.
The significant reduction in costs is primarily due to the benefits of
economies-of-scale when combining process areas, elimination of spare scrubber
module, and optimization of scrubber size.
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. Therefore, coal
switching was not evaluated for the New Madrid Plant.
14-4
-------
TABLE 14.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR NEW MADRID UNIT 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
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE 100-300
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 4673 NA 4673
NEW CHIMNEY* NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.31 1.24
ESP REUSE CASE 1.27
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
* The existing chimney is relined.
14-5
-------
Table 14.1.1-3. Sunmary of FGD Control Costs for the New Madrid Plant (June 1988 Dollars)
iii:ii3siisii:ssissii3iiiiiisai:sa2s::s:3issaissusss=::isss:::3=:ss:sss3;ss
::s:=::::;::a:szssasssiss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SC2 S02 SC2 Cost
Munber Retrofit Site Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty <$/kW) (SMM) (mills/kwh)
factor (X)
l/S FGD 1 1.31 600 49 3.2 132.6 221.0 64.9 25.2 90.0 69750 930.9
L/S FGD 2 1.31 600 45 3.2 132.6 221.0 63.2 26.7 90.0 64056 986.9
L/S FGD-C 1 1.31 600 49 3.2 132.6 221.0 37.3 14.7 90.0 69750 541.8
L/S FGD-C 2 1.31 600 45 3.2 132.6 221.0 36.8 15.6 90.0 64056 574.7
LC FGD 1-2 1.31 1200 47 3.2 199.7 166.4 103.9 21.0 90.0 133806 776.5
LC FGD-C 1-2 1.31 1200 47 3.2 199.7 166.4 60.4 12.2 90.0 133806 451.6
LSD*ESP 1 1.27 600 49 3.2 79.6 132.7 39.2 15.2 75.0 57908 677.6
LS0+ESP 2 1.27 600 45 3.2 79.6 132.7 38.1 16.1 75.0 53181 716.6
LSD+ESP-C 1 1.27 600 49 3.2 79.6 132.7 22.8 8.9 75.0 57908 394.4
LSD*ESP-C 2 1.27 600 45 3.2 79.6 132.7 22.2 9.4 75.0 53181 417.3
i2Bisai2Si3as3a8iaiss«si8i3iB3ti:ias38iss«i3iasaB«staiiaitta:iisiaia3tsiiai9aa3isiixas3tisaiasaasitHiiss3as:sr
14-6
-------
N0X Control Technology Costs--
This section presents the performance and various related costs estimated
for N0X controls at New Madrid. 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 New Madrid were: NGR and SCR.
Low N0X Combustion--
Units 1 and 2 are wet bottom, cyclone boilers, each rated at 600 MW.
The combustion modification technique that was applicable was NGR. The N0X
reduction performance estimated for the units was 60 percent. Table 14.1.1-4
presents the NGR N0X reduction performance result for the boilers.
Table 14.1.1-5 presents the costs of retrofitting NGR at the New Madrid
boilers.
Selective Catalytic Reduction--
Table 14.1.1-4 presents the SCR retrofit results for each unit. Results
include a process area retrofit factor and scope adder cost. The scope adders
include costs estimated for ductwork demolition, 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.
Each SCR reactor was located behind (south) the respective ESPs and to
either side of the chimney in areas of low congestion with easy access.
Therefore, both reactors were assigned a low access/congestion factor. The
reactors were assumed to be in areas with high underground obstructions. The
ammonia storage system was located southwest of the powerhouse in a relatively
open area. Table 14.1.1-5 presents the costs estimated to retrofit SCR at the
New Madrid plant.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SC^ 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.
14-7
-------
TABLE 14.1.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR NEW MADRID
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
CY
CY
TYPE OF NOx CONTROL
NGR
NGR
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
{1000 BTU/SQ FT-HR)
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
104
104
New Duct Length (Feet)
170
150
New Duct Costs (1000$)
2,403
2,191
New Heat Exchanger (1000$)
5,461
5,461
TOTAL SCOPE ADDER COSTS (1000$)
7,968
7,756
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
14-8
-------
Table 14.1.1-5. NOx Control Cost Results for the New Madrid Plant (June 1988 Dollars)
Technology Boiler Main Boiler
Number Retrofit Size
Difficulty (MW)
Factor
Capacity Coal Capital Capital Annual
Factor Sulfur Cost Cost Cost
CX) Content (SUM) (JAW) (SUM)
N3R 1 1.00 600 49 3.2 8.5 14.2 14.3 5.6 60.0 12668 1129.9
N3R 2 1.00 600 45 3.2 8.5 14.2 13.2 5.6 60.0 11634 1137.5
NCR-C 1 1.00 600 49 3.2 8.5 14.2 8.2 3.2 60.0 12668 650.4
NCR-C 2 1.00 600 45 3.2 8.5 14.2 7.6 3.2 60.0 11634 655.D
SCR-3 1 1.16 600 49 3.2 71.5 119.1 27.9 10.8 80.0 16891 1650.1
SCR-3 2 1.16 600 45 3.2 71.2 118.7 27.6 11.7 80.0 15512 1780.0
SCR-3-C 1 1.16 600 49 3.2 71.5 119.1 16.3 6.3 80.0 16891 964.4
SCR-3-C 2 1.16 600 45 3.2 71.2 118.7 16.1 6.8 80.0 15512 1040.4
SCR-7 1 1.16 600 49 3.2 71.5 119.1 22.8 8.9 80.0 16891 1352.4
SCR-7 2 1.16 600 45 3.2 71.2 118.7 22.6 9.5 80.0 15512 1455.9
SCR-7-C 1 1.16 600 49 3.2 71.5 119.1 13.4 5.2 80.0 16891 793.8
SCR-7-C 2 1.16 600 45 3.2 71.2 118.7 13.3 5.6 80.0 15512 854.7
14-9
-------
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas for both units were
located east of the plant in a relatively open area in a similar fashion as
LSD-FGD. The retrofit of DSD and FSI technologies at the New Madrid steam
plant would be very easy. There is sufficient flue gas ducting residence time
between the boilers and the retrofit ESPs and the ESPs are moderate in size
(SCAs >250). However, if additional ESP plate area was required, the ESP
access/congestion factor would be low (1.13) because of the space availability
around the ESPs with easy access. The conversion of wet to dry fly ash
handling system would be needed for reusing the ESPs. Table 14.1.1-6
presents a summary of the site access/congestion factors, scope adders, and
retrofit factors for DSD and FSI technologies at the New Madrid steam plant.
Table 14.1.1-7 presents the costs estimated to retrofit DSD and FSI at the
New Madrid 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 Madrid plant. The boilers at New Madrid would not be considered good
candidates for AFBC retrofit and AFBC or CG/combined cycle repowering because
of the large boiler sizes (600 MW).
14.1.2 Thomas Hill Steam Plant
The Thomas Hill steam plant is located within Randolph County,
Missouri, as part of Associated Electric Cooperative system. The plant
contains three coal-fired boilers with a total gross generating capacity of
1,140 MW. Figure 14.1.2-1 presents the plant plot plan showing the location
of all boilers and major associated auxiliary equipment.
Table 14.1.2-1 presents operational data for the existing equipment at
the Thomas Hill plant. The boilers burn high sulfur coal (4.1 percent
sulfur). Coal shipments are received by conveyors from a nearby coal mine
and transferred to two coal storage and handling areas located east of the
plant.
14-10
-------
TABLE 14.1.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NEW MADRID UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (lOOOS) 4673
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 115
TOTAL COST (1000$)
ESP UPGRADE CASE 4788
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
14-11
-------
Table 14.1.1-7. Sumtary of OSD/FSI Control Costs for the New Madrid Plant (June 19B8 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nutter Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty ($/kW> (SMM)
Factor (X)
Annual SQ2 S02 S02 Cost
Cost Removed Removed Effect.
(mills/Kwh) (X) (tons/yr) ($/ton)
CSD+ESP
0SD*ESP
1.00
1.00
600
600
49
45
3.2
3.2
39.6
39.6
66.0
66.0
26.2
25.1
10.2
10.6
48.0
48.0
37092
34064
706.4
738.0
0SD+ESP-C
DSD+ESP-C
1.00
1.00
600
600
49
45
3.2
3.2
39.6
39.6
66.0
66.0
15.2
14.6
5.9
6.2
48.0
48.0
37092
34064
409.5
428.0
FSI«ESP-50
FSH-ESP-50
1.00
1.00
6C0
600
49
45
3.2
3.2
32.9
32.9
54.8
54.8
32.6
30.7
12.7
13.0
50.0
50.0
38750
35587
841.0
861.6
FSI+ESP-50-C
FS1+ESP-50-C
1.00
1.00
600
600
49
45
3.2
3.2
32.9
32.9
54.8
54.8
18.8
17.7
7.3
7.5
50.0
50.0
38750
35587
485.6
497.8
FSI+ESP-70
FSI+ESP-70
1.00
1.00
600
600
49
45
3.2
3.2
32.6
32.6
54.4
54.4
33.1
31.1
12.8
13.1
70.0
70.0
54250
49821
609.6
624.3
FS1+ESP-70-C 1 1.00 600 49 3.2 32.6 54.4 19.1 7.4 70.0 54250 352.0
FSI*ESP-70-C 2 1.00 600 45 3.2 32.6 54.4 18.0 7.6 70.0 49821 360.6
14-12
-------
Existing FGD
Adsorbers
FGD Wast# Handltng/Absorbar Araa
Ume'Limastona Storaga/Preparation Araa
SCR Reactors
Not to scale
Figure 14.1.2-1. Thomas Hill plant plot plan
14-13
-------
TABLE 14.1.2-1. THOMAS HILL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM
INSTALLATION DATE
FGD TYPE
1
2
3
180
290
670
59
57
57
1966
1969
1982
CYC
CYC
OWF
4.1
4.1
4.1
10400
10406
10123
11.3
10.5
11.7
DRY HANDLING
OFF SITE/MINE FILL
1 2 3
CONVEYORS/NEARBY COAL MINE
NO NO YES
1982
LIMESTONE
WET SCRUBBER
PARTICULATE CONTROL
TYPE ESP ESP ESP
INSTALLATION DATE 1983 1969,79 1982
EMMISION (LB/MM BTU) 0.17 0.13 0.02
REMOVAL EFFICIENCY 99.5 99.0 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 4.0 4.0 4.8
SURFACE AREA (1000 SQ FT) 330.6 112,256 858
GAS EXIT RATE (1000 ACFM) 675 498,702 2900
SCA (SQ FT/1000 ACFM) 490 225,365 296
OUTLET TEMPERATURE (*F) 310 310 310
14-14
-------
Particulate matter emissions for the boilers are controlled with
retrofit ESPs located behind each unit. The plant has a dry fly ash
handling system.
Lime/Limestone and Lime Spray Drying FGD Costs--
Figure 14.1.2-1 shows the general layout and location of the FGD control
system. The three boilers are located beside each other close to the Middle
Fork Cliften River and adjacent to the Thomas Hill Reservoir. Each unit has
its own chimney. Unit 3 currently has a wet FGD system located behind the
chimney and its respective limestone storage/preparation area is located
north of the boiler. The absorbers for t/LS-FGD and LSD-FGD for units 1 and
2 would be located behind each respective chimney and the storage, preparation
and handling area for unit 3 would be expanded and used for all three boilers.
No major demolition/relocation would be required; therefore, a factor of
5 percent was assigned to general facilities.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for units 1 and 2 would be located north of the chimneys in
an area bounded by the conveyors. A medium site access/congestion factor was
assigned to units 1 and 2 absorber locations due to the access difficulty to
this area as well as underground obstruction. For flue gas handling, short
duct runs for both units would be required for L/LS-FGD cases.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 14.1.2-2 and 14.1.2-3. The major
scope adder cost would be installation of a new chimney. Plant personnel
indicated that the chimneys for units 1 and 2 would need to be replaced for
FGD systems. The overall retrofit factors determined for the L/LS-FGD cases
were moderate.
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. LSD-FGD with reused ESP was the only LSD-FGD technology
considered for the units because of the moderate size of the ESPs (SCAs
>365). For flue gas handling for LSD cases, short to moderate duct runs
would be required. A high site access/congestion factor was assigned to the
flue gas handling system because of the difficulty to tie into the upstream
of the ESPs in order to divert flue gas from the boilers to the absorbers
14-15
-------
TABLE 14.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR THOMAS HILL UNIT 1
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
MEDIUM
MEDIUM
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
100-300
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
YES
NO
ESTIMATED COST (1000$)
1260
1260
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.40
1.42
ESP REUSE CASE
1.49
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5
5
5
14-16
-------
TABLE 14.1.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR THOMAS HILL UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
¦SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
MEDIUM
MEDIUM
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
100-300
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
YES
NO-
ESTIMATED COST (1000$)
2030
2030
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.40
1.42
ESP REUSE CASE
1.49
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5
5
5
14-17
-------
and back to the ESPs. The retrofit factor determined for the LSD technology
case was moderate (1.49) and did not include particulate control upgrading
costs. Separate retrofit factors were developed for upgrading ESPs for each
unit. A moderate retrofit factor (1.36) was assigned for upgrading ESPs for
unit 1 due to the available space on one side of the ESPs and the close
proximity to unit 2 on the other side; for unit 2, a high retrofit factor
was assigned (1.58) because of the close proximity of the ESPs, powerhouse,
and chimney. These factors were used in the IAPCS model to estimate
particulate control upgrading costs.
Table 14.1.2-4 presents cost estimates for L/LS and LSD-FGD cases. The
LSD-FGD costs include upgrading the ESPs for boilers 1 and 2. The low cost
control case reduces capital and annual operating costs 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. This is particularly true for cyclone boilers; therefore, coal
switching was not evaluated.
Table 14.1.2-5 presents the IAPCS results for physical coal cleaning at
Thomas Hill 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 NOx
controls at the Thomas Hill steam plant. These controls include INC
modification and SCR. The application of N0X control technologies is
determined by several site-specific factors which are discussed in
Section 2. The N0X technologies evaluated at the steam plant were:
14-18
-------
Table 14.1.2-4. Surrary of FGD Control Costs for the Thomi Mid Plant (Jirte 1988 Doltars)
:22X3iiiix::axak8S32szi:
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nunber Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (X) Content (SUM) ssp-c
ISD+ESP-C
1 1.49 180 59 4.1 31.9 177.5 17.1 18.4 66.0 23915 714.2
2 1.49 290 57 4.1 49.4 170.3 25.3 17.4 67.0 38003 664.6
1.49
1.49
180
290
59
57
4.1
4.1
31.9 177.5 9.9 10.7
49.4 170.3 14.7
10.1
66.0 23915
67.0 38003
415.2
386.6
i:::;s:s:s:3ii:3::::sssiaiite3;:iiansis::isiBiiisai«iiiiiaiisa
14-19
-------
Table 14.1.2-5. Suimary of Coal Switching/Cleaning Costs for the Thomas Hilt Plant (June 1988 Dollars)
======"¦
Technology
Boiler
Hain
Boiler Capaci
ty Coal
Capi tal
Capital Annual
Annual
S02
S02
S02 Cost
Nunber
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
-------
NGR - units 1 and 2; LNB - unit 3; and SCR - all units. Even though Unit 3
already should have achieved 1979 NSP5 for N0X emissions, it was included
for consideration in this study.
Low NOx Combustion-
Units 1 and 2 are wet bottom, cyclone-fired boilers rated at 180 and
290 MW, respectively. The combustion modification technique applied to both
boilers was NGR. Unit 3 is dry bottom, opposed wall-fired boiler, rated at
670 MW. The combustion modification technique applied for this unit was LNB.
As Table 14.1.2-6 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 N0X procedures. However, this boiler probably
already is equipped with LNBs in which case additional NOx reductions
achievable with LNC technique would likely be less than 20 percent. As such,
no cost estimates were developed for unit 3. Table 14.1.2-7 presents the cost
of retrofitting NGR at the Thomas Hill plant.
Selective Catalytic Reduction-
Table 14.1.2-6 presents the SCR retrofit results for units 1 to 3. The
results include process area retrofit factors and scope adder costs. The
scope adders include costs estimated for ductwork demolition, new flue gas
heat exchanger, and new duct runs to divert the flue gas from the ESPs to
the reactor and from the reactor to the chimney.
The SCR reactors for units 1 and 2 would be located immediately behind
their respective chimneys; whereas, the SCR reactor for unit 3 would be
located south of both the existing FGD unit and chimney for unit 3. All
three reactors are located in low congestion and open areas. No major
relocation or demolition would be required for any of the units. Therefore,
the reactors for units 1 to 3 were assigned low access/congestion factors.
All reactors were assumed to be in areas with high underground obstructions.
The ammonia storage system was placed in a remote area having a low access/
congestion factor.
14-21
-------
TABLE 14.1.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR THOMAS HILL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
CY
CY
OWF
TYPE OF NOx CONTROL
NGR
NGR
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
10.7
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
120.6
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
3.79
ESTIMATED NOx REDUCTION (PERCENT) 60
60
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$)
42
71
113
New Duct Length (Feet)
100
100
350
New Duct Costs (1000$)
699
1,227
5,277
New.Heat Exchanger (1000$)
2,652
4,642
5,835
TOTAL SCOPE ADDER COSTS (1000$)
3,393
5,940
11,225
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
14-22
-------
Table 14.1.2-7. NO* Control Cost Results for the Thomas Hill Plant [June 1988 Dollars)
3isisssxxa83siiii3siittit:iiaii3iiiaaii8itaai3iitiiaiiiisiiiissiiiiiiaiiasssiiess:sii::s5s:i:::sss::s::::sss::=:
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Reiroved Removed Effect.
Difficulty (NU> (X) Content (MM) (S/kW) (SMH) (mills/lcuh) (Z) (tons/yr) (1/ton)
Factor (X)
NGR
1
1.00
180
59
4.1
3.4
19.0
5.3
5.7
60.0
4627
1143.3
NOR
2
1.00
290
57
4.1
4.9
16.8
8.1
5.6
60.0
7197
1130.5
NGfi-C
1
1.00
180
59
4.1
3.4
19.0
3.0
3.3
60.0
4627
658.3
NGR-C
2
1.00
290
57
4.1
4.9
16.8
4.7
3.2
60.0
7197
650.8
SCR-3
1
1.16
180
59
4.1
27.5
152.6
10.1
10.8
80.0
6169
1634.6
SCR-3
2
1.16
290
57
4.1
41.3
142.4
15.3
10.5
80.0
9595
1590.7
SCR-3
3
1.16
670
57
4.1
81.6
121.8
31.0
9.3
80.0
14133
2196.5
SCR-3-C
1
1.16
180
59
4.1
27.5
152.6
5.9
6.3
80.0
6169
956.5
SCR-3-C
2
1.16
290
57
4.1
41.3
142.4
8.9
6.2
80.0
9595
930.6
SCR-3-C
3
1.16
670
57
4.1
81.6
121.8
18.2
5.4
80.0
14133
1284.3
SCR-7
1
1.16
180
59
4.1
27.5
152.6
8.6
9.2
80.0
6169
1389.8
SCR-7
2
1.16
290
57
4.1
41.3
142.4
12.8
8.9
80.0
9595
1337.0
SCR-7
3
1.16
670
57
4.1
81.6
121.8
25.4
7.6
80.0
14133
1797.0
SCR-7-C
1
1.16
180
59
4.1
27.5
152.6
5.0
5.4
80.0
6169
816.2
SCR-7-C
2
1.16
290
57
4.1
41.3
142.4
7.5
5.2
80.0
9595
785.3
SCR-7-C
3
1.16
670
57
4.1
81.6
121.8
14.9
4.5
80.0
14133
1055.5
II
II
II
II
II
M
II
II
II
II
sszxss:
:==»=====
:ssiss:ai
ESSSS223
N
II
II
II
II
M
N
II
II
II
II
II
II
N
(1
II
II
li
==*=====!=
ll
II
M
M
II
II
M
II
14-23
-------
As discussed in Section 2, all N0X control techniques were evaluated
independently from those evaluated for SO2 control. If both SC^ and N0X
emissions were needed to be reduced at this plant, the SCR reactors would
have to be located downstream of the FGD absorbers. For unit 3, the SCR
reactor is already located downstream of the absorber; therefore, the
results listed above for retrofitting SCR to this boiler would apply in this
case. For units 1 and 2, the SCR reactors would be located downstream of
the absorber (i.e., west of the absorbers) in a relatively open area having
easy access. Therefore, low access/congestion factors would again be
assigned to SCR reactors for units 1 and 2. Table 14.1.2-7 presents the
estimated cost of retrofitting SCR at the Thomas Hill 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 were located north of the
plant in a similar fashion as LSD-FGD. The retrofit of FSI and DSD technol-
ogies at the Thomas Hill steam plant for both units would be relatively easy
due to the large ESP size (SCAs >300) of the ESPs. However, there appears
to be short duct residence time between the boilers and ESPs, making the
application of DSD more difficult. Because the ESPs are large, the E-S0x
technology may be applicable at these units. A medium to high site access/
congestion factor was assigned for upgrading the ESPs for the same reasons
as mentioned in the previous section. Tables 14.1.2-8 and 14.1.2-9 present
a summary of the site access/congestion factors for DSD and FSI technologies
at the Thomas Hill steam plant. Table 14.1.2-10 presents the costs
estimated to retrofit DSD and FSI at the Thomas Hill plant.
14-24
-------
TABLE 14.1.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR THOMAS HILL UNIT 1
I TEH
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW 8AGHOUSE 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$)
ESP UPGRADE CASE 46
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.34
NEW BAGHOUSE NA
14-25
-------
TABLE 14.1.2-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR THOMAS HILL UNIT 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$) 66
TOTAL COST (1000$)
ESP UPGRADE CASE 66
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.55
NEW BAGHOUSE NA
14-26
-------
Table 14.1.2-10. Sunmary of DSD/FSI Control Costs for the Thomas Hill Plant (June 1988 Dollars)
IZI1ZI1II211IIII1I3S
Technology Boiler
Main
Boiler Capacity Coal
XIIIZIIU
Capital
iiiiNiiiiiiiiiiiiz;:::3s;:
Capital Annual Annual .
S02
S02
S02 Cost
Nunber
Retrofit
Sile
Factor
Sulfur
cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
(HW)
(*)
Content
(S/kU)
(SUM)
(mi IIs/kwh)
(X)
(tons/yr)
(S/ton)
Factor
CX)
5SD+ESP
1
1.00
180
59
4.1
13.3
73.9
11.3
12.2
43.0
15765
717.9
0SD*ESP
2
1.00
290
57
4.1
20.2
69.5
16.2
11.2
44.0
24925
651.6
OSD+ESP-C
1
1.00
180
59
4.1
13.3
73.9
6.5
7.0
43.0
15765
415.1
0S0+ESP-C
2
1.00
290
57
4.1
20.2
69.5
9.4
6.5
44.0
24925
377.0
FSI*ESP-50
1
1.00
180
59
4.1
12.9
71.8
15.4
16.6
50.0
18132
850.3
FSl*ESP-50
2
1.00
290
57
4.1
16.5
63.8
22.9
15.8
50.0
28204
810.6
FSI+ESP-50-C
1
1.00
180
59
4.1
12.9
71.8
8.9
9.6
50.0
18132
490.3
FSI+ESP-50-C
2
1.00
290
57
4.1
18.5
63.8
13.2
9.1
50.0
28204
467.4
FSI-ESP-70
1
1.00
180
59
4.1
13.2
73.1
15.7
16.9
70.0
25385
620.4
FSI*ESP-70
2
1.00
290
57
4.1
18.9
65.0
23.4
16.1
70.0
39486
591.9
FS1-ESP-70-C
1
1.00
180
59
4.1
13.2
73.1
9.1
9.8
70.0
25385
357.8
FS1+ESP-7C-C
2
1.00
290
57
4.1
18.9
65.0
13.5
9.3
70.0
39486
341.2
SSSSSS3S
sasssss:
IISS3S3S3
SSSS8SS8
===»as
iibississs;
3SSS1SI
B8SSSSSS35
SISISSSS
14-27
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabillty--
The AFBC retrofit and AFBC/CG repowering applicability criteria presented
in Section 2 were used to determine the applicability of these technologies at
the Thomas Hill plant. Units 1 and 2 would be considered good candidates for
AFBC retrofit because of their small boiler size. However, their high
capacity factors make them less likely to be good candidates due to
replacement power costs and mixed potential improvement in unit heat rate.
14-28
-------
14.2 EMPIRE DISTRICT ELECTRIC COMPANY
14.2.1 Asbury Steam Plant
The Asbury steam plant is located within Jasper County, Missouri, as part
of the Empire District Electric Company system. The plant contains one
coal-fired boiler with a total net generating capacity of 213 MW.
Figure 14.2.1-1 presents the plant plot plan showing the location of the
boiler and major associated auxiliary equipment.
Table 14.2.1-1 presents operational data for the existing equipment at
the Asbury steam plant. The boiler burns high sulfur coal (5.5 percent
sulfur). Coal shipments are received by conveyor from a nearby mine and
conveyed to a coal storage and handling area located northeast of the plant.
Plant personnel indicated that Asbur., plant is in the process of converting
to low sulphur fuel bringing the plant emission within 1.2 lb SC^/million
Btu. The construction for this conversion is underway with completion
scheduled for mid 1990.
Particulate matter emissions for the boiler are controlled with ESPs
located behind the chimney. Ash from the unit is wet sluiced to ponds located
east of the plant. On-site waste disposal appears to be available and no
additional land purchases are anticipated for future FGD waste disposal.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 14.2.1-1 shows the general layout and location of the FGD control
system. The absorbers would be located southeast of the unit directly behind
the chimney for L/LS-FGD and on either side of the ESPs for the LSD-FGD. The
absorber area would be bounded by the construction building (southwest) and
the cooling towers (northeast). The lime and limestone preparation/storage
area and waste handling area were placed south and southwest of the absorber,
respectively. No major demolition/relocation would be required to locate the
absorbers. Therefore, a factor of 5 percent was assigned to general
facilities.
14-29
-------
"V
N
Parking
—| Afea
Lime/Umestone
Storage/Preparation
Area
NH, Storage
System
FGO Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
Ncit to scale
NH, Storage System
SCR Boxes
Figure 14.2.1-1. Asbury plant plot plan
14-30
-------
TABLE 14.2.1-1 ASBURY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1
GENERATING CAPACITY (HW) 213
CAPACITY FACTOR (PERCENT) 68
FIRING TYPE CYC
INSTALLATION DATE 1970
COAL SULFUR CONTENT (PERCENT)* 5.5
COAL HEATING VALUE (BTU/LB) 10700
COAL ASH CONTENT (PERCENT) 23
FLY ASH SYSTEM - WET SLUICE
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS CONVEYOR
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1970
EMISSION (LB/MM BTU) 0.134
REMOVAL EFFICIENCY 96.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (.1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (°F)
* Asbury is in the process of converting to low sulfur coal.
6.0
86.4/147.6
613.7
381
310
14-31
-------
Retrofit Difficulty and Scope Adder Costs--
The FGD equipment was located southeast of the unit 1 for L/LS-FGD and on
either side of the ESPs for LSD-FGO. No major obstacles/obstructions exist in
the surrounding area where the absorbers and tie-in ductwork would be located
and a short to medium duct run would be required. As a result, a low site
access/congestion factor was assigned to the absorber location and flue gas
handling for all FGD technologies.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Table 14.2.1-2. The largest scope
adder for Asbury would be the conversion of unit 1 fly ash conveying/disposal
system from wet to dry for conventional L/LS-FGD and LSD-FGD cases. It was
assumed that dry fly ash would be necessary to stabilize L/LS-FGD scrubber
sludge waste and to prevent plugging of sluice lines in the LSD-FGD system for
the ESP-reuse case). However, this conversion would not be necessary for
forced oxidation. The overall retrofit factors determined for the L/LS-FGD
cases were low to moderate (1.24 to 1.31).
The LSD with reuse ESP was the only LSD-FGD case evaluated because the
ESP presently has a moderate SCA size (>300) and the existing ESPs are located
in a low site access/congestion area. The retrofit factor determined for the
LSD technology was low to moderate (1.34) and did not include particulate
control upgrading costs. A separate retrofit factor was developed for
upgrading ESPs (1.16) and used in the IAPCS model to estimate the particulate
control costs. The low factor is a result of the space availability around
the existing ESPs.
Table 14.2.1-3 presents the cost estimates for L/LS 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 due to the benefits of elimination of spare scrubber module 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
14-32
-------
TABLE 14.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ASBURY 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 LOW
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 2001 NA 2001
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.31 1.24
ESP REUSE CASE 1.34
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
14-33
-------
Table 14.2.1-3. Surmary of FGD Control Costs for the Asbury Plant (June 1988 Dollars)
Technology
Boiler Hain
Boiler Capacity Coal
Capi tal
"Capital Annual
Annual
S02
S02
SC2 Cost
Nunber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
Content
ctwo
<$/kW)
(SUM)
L/S ?ao
1 1.31
213
68
5.5
64.7
303.7
35.7
28.1
90.0
57795
617.2
L/S FGD-C
1 1.31
213
68
5.5
64.7
303.7
20.7
16.3
90.0
57755
358.6
lC FGD
1 1.31
213
68
5.5
46.4
217.7
29.7
23.4
90.0
57795
513.2
LC FGD-C
1 1.31
213
68
5.5
46.4
217.7
17.2
13.6
90.3
57795
297.6
LSD'ESP
1 1.34
213
68
5.5
34.8
163.3
19.5
15.4
49.0
31609
618.2
ISD»ESP-C
1 1.34
213
68
5.5
34.8
163.3
11.4
8.9
49.0
31609
359.1
14-34
-------
determined. This is particularly true for cyclone boilers; as such, coal
switching was not evaluated.
Table 14.2.1-4 presents the IAPCS results for physical coal cleaning at
Asbury 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 Cost--
This section presents the performance and costs estimated for N0X
controls at the Asbury steam plant. These controls include NGR and SCR. The
application of N0X control technologies is determined by several site-specific
factors which are discussed in Section 2.
Low N0X Combustion--
The boiler at the Asbury plant is a wet bottom, cyclone boiler rated at
213 MW. The combustion modification technique that was applicable was NGR.
The N0x reduction performance estimated for the unit was 60 percent.
Table 14.2.1-5 presents the NGR N0X reduction performance result for the
boiler. Table 14.2.1-6 presents the costs of retrofitting NGR at the Asbury
boiler.
Selective Catalytic Reduction--
Table 14.2.1-5 presents the SCR retrofit results for unit 1. The results
include a process area retrofit factor and scope adder cost. The scope adders
include costs estimated for ductwork demolition, 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 reactor was located southeast of the powerhouse and the chimney and
the ammonia storage system was also located southeast of the chimney. The SCR
reactor was given a low access/congestion factor. Also, the ammonia storage
system was placed in an area with low access/congestion. The reactor was
assumed to be in an area with significant underground obstructions while the
ammonia system was not. Table 14.2.1-6 presents the estimated cost of
retrofitting SCR at the Asbury boiler.
14-35
-------
Table 14.2.1-4. SLmmary of Coal Switching/Cleaning Costs for the Asbury Plant (June 1989 Dollars)
==>==B=:tB=ii==ia=iz=ir:ii=:ai3iii3iatitaiiiizisiisi:3ai=izi:3i:iii3XS=ia=3:=iztsi
"echnology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cast
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content ($MM) (S/kW) <$*«> (mills/kwh) (X) Ctons/yr) ($/ton)
Factor (X)
PCC 1 1.00 213 68 5.5 2.7 12.7 2.7 2.2 97.0 62419 44.0
p:c-C 1 1.00 213 68 5.5 2.7 12.7 1.6 1.2 97.Q 62419 25.4
14-36
-------
TABLE 14.2.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR ASBURY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE CY
TYPE OF NOx CONTROL NGR
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) NA
FURNACE RESIDENCE TIME (SECONDS) NA
ESTIMATED NOx REDUCTION (PERCENT) 60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 48
New Duct Length (Feet) 115
New Duct Costs (1000$) 887
New Heat Exchanger (1000$) 2934
TOTAL SCOPE ADDER COSTS (1000$) 3868
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
14-37
-------
Table 14.2.1-6. NOx Control Cost Results for the Asbury Plant (June 1988 Dollars)
Technology Boiler Main Boiler
Number Retrofit Size
Difficulty
Annual NOx NCx NCx Cost
Cost Removed Removed Effect,
(mi IIs/kwh) (X) (tors/yr) (l/ton)
NGR 1 1.00 213 68 5.5 3.8 18.0 6.9 5.4 60.C 6107 1128.4
N5R-C 1 1.30 213 68 5.5 3.8 18.0 4.0 3.1 60.0 6107 649.3
SCR-3 1 1.16 213 68 5.5 31.1 146.2 11.7 9.2 80.0 8143 1437.4
SCR-3-C 1 1.16 213 68 5.5 31.1 146.2 6.8 5.4 80.0 8143 840.7
SCR-7 1 1.16 213 68 5.5 31.1 146.2 9.9 7.8 80.0 8143 1218.8
SCR-7-C 1 1.16 213 68 5.5 31.1 146.2 5.8 4.6 80.0 8143 715.5
14-38
-------
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 connercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas for unit 1 was located
southeast of the plant in a relatively open area. The retrofit of DSD and FSI
technologies at Asbury steam plant would be relatively easy. There is
sufficient flue gas ducting residence time between the boiler and the retrofit
ESPs which have moderate size SCAs (>380) and a large amount of space
available for plate area upgrade. A low retrofit factor was estimated for
upgrading the ESPs (1.13). Table 14.2.1-7 presents a summary of site access/
congestion factors, scope adders, and retrofit factors for DSD and FSI
technologies at the Asbury steam plant. Table 14.2.1-8 presents the cost
estimate to retrofit DSD and FSI at the Asbury unit 1.
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 technology at
the Asbury plant. The boiler at Asbury would be considered a good candidate
for AFBC retrofit and AFBC or CG/combined cycle repowering because of small
boiler size (213 MW). However, the high capacity factor indicates a good unit
heat rate and a potentially high replacement power cost which makes
retrofit/repowering of AFBC or CG less attractive economically.
14-39
-------
TABLE 14.2.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ASBURY 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 YES
ESTIMATED COST (1000$) 2001
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$) 56
TOTAL COST (1000$)
ESP UPGRADE CASE 2057
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
14-40
-------
Table 14.2.1-8. Suimary of DSD/FSI Control Costs for the Asbury Plant (June 1988 Dollars)
Technology Boiler Main Boiler capacity Coal Capital Capital Annual Annual S02 S32 S32 Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content (SHM) !Vky> C»MM) (mills/kuh) (X) (tons/yr> ($/ton)
Factor (%>
DSD+ESP 1
DSD»ESP-C 1
FSI«€SP-50 1
FSr*ESP-50-C 1
FS1+ESP-70 1
FS!*ESP-70-C 1
1.00 213 68 5.5 16.a 78.9 13,5 10.6 35.Q 22547 597.3
1.00 213 68 5.5 16.8 78.9 7.8 6.1 35.0 22547 345.6
1.00 213. 68 5.5 17.8 83.5 24.8 19.5 50.0 32108 772.3
1.00 213 68 5.5 17.8 83.5 14.3 11.3 50.0 32108 445.0
1.00 213 68 5.5 18.1 84.8 25.3 20.0 70.0 44951 563.8
1.00 213 68 5.5 18.1 84.8 14.6 11.5 70.0 44951 324.8
14-41
-------
14.3 KANSAS CITY POWER AND LIGHT
14.3.1 Hawthorn Steam Plant
The Hawthorn steam plant is located within Jackson County, Missouri, as
part of the Kansas City Power and Light Company system. The plant contains
five coal-fired boilers; units 1-4 are presently inactive. Unit 5 has a
total gross generating capacity of 515 MW. Figure 14.3.1-1 presents the
plant plot plan showing the location of all boilers and major associated
auxiliary equipment.
Table 14.3.1-1 presents operational data for the existing equipment at
the Hawthorn plant. The boiler burns low sulfur coal (1.1 percent sulfur).
Coal shipments are received by railroad and to a conveyed coal storage and
handling area located south of the powerhouse.
Particulate matter emissions for the boilers are controlled with
retrofit ESPs located northeast of the boilers. Fly ash is wet sluiced to
ponds located west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
Figure 14.3.1-1 shows the general layout and location of the FGD control
system. The five boilers sit beside each other, adjacent to the levee, close
to the Missouri River. Although they are inactive, units 3 and 4 currently
have a wet FGD system. The absorbers for L/LS-FGD and LSD-FGD for unit 5
would be located northwest of the boiler adjacent to the ESPs and close to the
levee in an open area. No major demolition/relocation would be required;
therefore, a factor of 5 percent was assigned to general facilities. The lime
and limestone storage/preparation area and waste handling area would be
located adjacent to the absorbers.
Retrofit Difficulty and Scope Adder Costs--
A low site access/congestion factor was assigned to the unit 5 absorber
location due to no major obstacles or obstructions in the surrounding area.
For flue gas handling, moderate duct runs for unit 5 would be required for
L/LS-FGD cases. A medium site access/congestion factor was assigned to the
14-42
-------
Waste Handling
Area
Lime/Limestone
Storage/Preparation
Area
Absorbers
ESP's
Levee
*4,
N
Existing FGD
Equipment
Chimneys'
•ESP'S
Coal
Conveyors'
Coal Storage
and Handling
Area
Not to scale
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 14.3.1-1, Hawthorn plant plot plan
14-43
-------
TABLE 14.3.2-1. HAWTHORN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
3,4
5
GENERATING CAPACITY (MW-each)
69
112,142
514
CAPACITY FACTOR (PERCENT)
46
INSTALLATION DATE
1951
1953-55
1969
FIRING TYPE
-
-
TANG
COAL SULFUR CONTENT (PERCENT)
-
-
1.1
COAL HEATING VALUE (BTU/LB)
-
-
9447
COAL ASH CONTENT (PERCENT)
-
-
7.3
FLY ASH SYSTEM
WET SLUICE
ASH DISPOSAL METHOD
POND/ON-SITE
STACK NUMBER
1
2
3
COAL DELIVERY METHODS
RAILROAD
FGD SYSTEM
NO
YES
NO
INSTALLATION DATE
-
NA
-
FGD TYPE
-
-
-
PARTICULATE CONTROL
TYPE
ESP
WET
ESP
SCRUBBER
INSTALLATION DATE
1977
1972
1978
EMMISION (LB/MM BTU)
0.02
0.17
0.04
REMOVAL EFFICIENCY
99.4
98.5
99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
0.6
6.4
0.2
SURFACE AREA (1000 SQ FT)
240
-
1357
GAS EXIT RATE (1000 ACFM)
324
346
2100
SCA (SQ FT/1000 ACFM)
740
-
646
OUTLET TEMPERATURE (*F)
300
185
310
Units 1-4 are no longer in service.
14-44
-------
flue gas handling system because the chimney is located between the two
ESPs boxes.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 14.3.1-2. The largest scope adder
cost for the Hawthorn plant would be the conversion of unit 5 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 in the L/LS-FGD system and to prevent
plugging of sluice lines in the LSD-FGD system for the 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 were moderate (1.35 to
1.42).
The absorbers for LSD-FGD would be located in a similar location close
to the boiler as in L/LS-FGD cases. LSD-FGD with reused ESP was the only
LSD-FGD technology considered for the unit because its ESPs are large
(SCA =646). For flue gas handling for LSD cases, moderate duct runs would
be required and a medium site access/congestion factor was assigned to the
flue gas handling system for the same reasons as stated above in L/LS-FGD
cases. The retrofit factor determined for the LSD technology case was
moderate (1.38) and did not include particulate control upgrading costs. A
separate retrofit factor was developed for upgrading ESPs. A low retrofit
factor (1.16) was assigned to the upgraded ESP location due to the available
space if additional plate area is required. This factor was used in the
IAPCS model to estimate particulate control upgrading costs.
Table 14.3.1-3 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boiler 5.
The low cost control case reduces capital and annual operating costs
due to the benefits of elimination of a spare scrubber module, optimization
of scrubber module size, and use of organic acid additives.
Coal Switching Costs--
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
14-45
-------
TABLE 14.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR HAWTHORN UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING MEDIUM MEDIUM
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 4073 NA 4073
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.42 1.35
ESP REUSE CASE 1.38
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
14-46
-------
fabli K.3.1-3. Suimary of fGD Control Costs for the Hawthorn Plant (June 1988 Dollars)
::s3:::sssrss:s:::5s:s::s:ssss::ssisss:sss:ssi3:s:::::ss9isiati«i«3ssitxif3assimassi3si:st::;:s3:s:3iiai:2ai::
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 SC2 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CHU) (SMM) (mi IIs/kyfc) (X) (tons/yr) <$/ton)
Factor (X)
L/S FGD 5 1.42 514 46 1.1 128.0 249.0 56.5 27.3 90.0 21770 2594.8
L/S FGO-C 5 1.42 514 46 1.1 128.0 249.0 32.9 15.9 90.0 21770 1513.0
LC FGD 5 1.42 514 46 1.1 102.1 198.7 48.0 23.2 90.0 21770 2206.3
LC FGD-C 5 1.42 514 46 1.1 102.1 198.7 28.0 13.5 90.0 21770 1285.1
ISD'ESP 5 1.38 514 46 1.1 58.4 113.6 25.0 12.0 76.0 18456 1352.1
ISD+ESP-C 5 1.38 514 46 1.1 58.4 113.6 14.6 7.0 76.0 18456 788.8
14-47
-------
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.
N0x Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Hawthorn steam plant. These controls include LNC
modification and SCR. The application of NO' control technologies is
determined by several site-specific factors which are discussed in
Section 2. The N0X technologies evaluated at the steam plant were:
OFA and SCR.
Low N0X Combustion--
Unit 5 is a dry bottom, tangential-fired boiler rated at 515 MW. The
combustion modification technique applied for this evaluation was OFA. As
Table 14.3.1-4 shows, the OFA N0x reduction performance for this unit was
estimated at 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 14.3.1-5 presents
the cost of retrofitting OFA at the Hawthorn boiler.
Selective Catalytic Reductions-
Table 14.3.1-4 presents the SCR retrofit results for unit 5. The results
include a process area retrofit factor 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 5 would be located northwest of the boiler,
adjacent to the ESPs and close to the levee, in an open area with no major
obstacles. Therefore, the reactor was assigned a low access/congestion
factor. No major relocation and demolition of existing equipment and
buildings would be required and a low factor of 13 percent was assigned to
14-48
-------
TABLE 14.3.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR HAWTHORN
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
TYPE OF NOx CONTROL
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
FURNACE RESIDENCE TIME (SECONDS)
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
5
TANG
OFA
13.4
154.7
2.93
20
LOW
0
92
500
6,463
4,983
11,538
1.16
13
14-49
-------
Table 14.3.1-5. NOx Control Cost Results for the Hawthorn Plant (June 1988 Dollars)
:£s::=s:saK=s=aaEasi=iasauiicasi:iiinii3iisaaisisB=ii£Sais:n:»:3is:ii£aissii:3icxiiiianxas3issai:aitaisi2a
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx KOx Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty IHW) (X) Content (SUM) (S/kU) (S*N> (mills/kyh) (X) (tons/yr)
-------
general facilities. The reactor was assumed to be in an area with high
underground obstructions. The ammonia storage system was placed in a remote
area having a low access/congestion factor.
As discussed in Chapter 2, all N0X control techniques were evaluated
independently from those evaluated for Sf^ control. As a result for this
plant, the FGD absorber was located in the same area as the SCR reactor.
If both S02 and N0X emissions have to be reduced at this plant, the SCR
reactor would have to be located downstream of the FGD absorber (i.e., west
of the absorber) in a relatively open area having easy access. A low
access/congestion factor again would be assigned to this SCR reactor.
Table 14.3.1-5 presents the estimated cost of retrofitting SCR at the
Hawthorn boiler.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO2 control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located in a similar
fashion as LSD-FGD. The retrofit of DSD and FSI technologies at the Hawthorn
steam plant of unit 5 would be very easy. This is due to the long duct
residence time between the boiler and the ESPs and the large SCA (640). The
major scope adder cost for DSD and FSI would be the conversion of the fly ash
from wet to dry. Table 14.3.1-6 presents a summary of the site access/
congestion factors for DSD and FSI technologies at the Hawthorn steam
plant. Table 14.3.1-7 presents the costs estimated to retrofit DSD and FSI
at the Hawthorn plant.
14-51
-------
TABLE 14.3.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR HAWTHORN 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 YES
ESTIMATED COST (1000$) 4073
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$) 102
TOTAL COST (1000$)
ESP UPGRADE CASE 4175
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
14-52
-------
Tabic 14.3.1-7. Suimary of DSD/FSI Control Costs for the Hawthorn Plant (June 1988 Dollars}
Technology
Boiler
Ha in
Boiler Capacity Coal
Capi tal
Capi tal
Annual
Annual
SC2
S02
SC2 Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
D
ifficulty (MW)
(X)
Content
(SM*>
(raiIls/k*h)
(X)
Ctens/yr)
(S/tor)
Factor
(X)
0SD*ESP
5
1.00
514
46
1.1
21.1
41.1
13.0
6.3
49.0
11768
1106.2
OSD+ESP-C
5
1.00
514
46
1.1
21.1
41.1
7.6
3.6
49.0
11768
641.8
FSi+ESP-SO
S
1.00
514
46
1.1
20.7
40.3
13.8
6.6
50.0
12094
1138.3
FS!»eSP-50-C
5
1.00
514
46
1.1
20.7
40.3
8.0
3.9
50.0
12094
659.8
FS!*ESP-70
5
1.00
514
46
1.1
20.9
40.7
14.0
6.8
70.0
16932
826.7
FSI*ESP-73-C
5
1.00
514
46
1.1
20.9
40.7
8.1
3.9
70.0
16932
479.2
14-53
-------
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 Hawthorn plant. The boiler would not be considered a good candidate for
AFBC retrofit due to its large boiler size (515 MW) and new age (1969).
14.3.2 Iatan Steam Plant
L/S-FGD and LSD-FGD retrofit factors for unit 1 at the Iatan plant were
developed; however, costs are not presented since the boiler fires a low
sulfur coal which would yuield low capital/operating costs and high cost per
ton of S02 removed. CS was not evaluated because the plant currently burns a
low sulfur coal. The unit is equipped with LNBs; however, for additional N0x
control, SCR was evaluated.
TABLE 14.3.2-1. IATAN 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)
NA
YES
0.4
8840
5
674
67
1980
OPPOSED WALL
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
WET DISPOSAL
POND/ON-SITE
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)
0.3
1728
2643
654
302
ESP
1980
0.02
99.4
14-54
-------
TABLE 14.3.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR IATAN 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)
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$)
5186
NA
5186
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
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
1.16
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
0
8
* L/LS-FGD absorbers for unit 1
would be
located
southeast of
the unit 1 chimney. LSD-FGD
absorbers
for unit
1 would be
located southeast of the unit
1 ESPs.
14-55
-------
TABLE 14.3.2-3. SUMMARY OF NOx RETROFIT RESULTS FOR IATAN
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$) 0
Ductwork Demolition (1000$) 113
New Duct Length (Feet) 200
New Duct Costs (1000$) 3026
New Heat Exchanger (1000$) 5856
TOTAL SCOPE ADDER COSTS (1000$) 8995
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) : 20
* Cold side SCR reactors for unit 1 would be located southeast
of the unit 1 chimney.
1
NA
NA
NA
NA
NA
NA
14-56
-------
Table 14.3.2-4. MOx Control Cost Results for the latan Plant (Ju-te 1983 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nmfeer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (SMM) (mi 11 j/kwh)
Factor (X)
SCS-3 1 1.16 674 67 0.4 81.8 121.3 32.3 8.2 80.0 19526 1655.9
SCR-3-C 1 1.16 674 67 0.4 81.8 121.3 18.9 4.8 80.0 19526 967.5
SCR-7 1 1.16 674 67 0.4 81.8 121.3 26.5 6.7 80.0 19526 1359.2
SCR-7-C 1 1.16 674 67 0.4 81.8 121.3 15.6 3.9 80.0 19526 797.5
14-57
-------
TABLE 14.3.2-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR IATAN UNIT 1
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS •
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 5186
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$) 125
TOTAL COST (1000$)
ESP UPGRADE CASE 5311
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
Sufficient duct residence time exist between unit 1 and the unit
1 ESPs. A low factor was assigned to ESP upgrade since the ESPs
are large in size and space is available around the ESPs.
14-58
-------
Table 14.3.2-6. Suwary of DS0/FS1 Control Costs for the latan Plant
-------
14.3.3 La Cyqne Steam Plant
The La Cygne steam plant is located within Linn County, Missouri, as
part of the Kansas City Power and Light Company system. The plant is
located adjacent to a lake and contains two coal-fired boilers with a total
gross generating capacity of 1,558 MW.
Table 14.3.3-1 presents operational data for the existing equipment at
the La Cygne plant. Boiler 1, which is equipped with a new FGD unit, is
burning high sulfur coal while boiler 2 is burning low sulfur coal. Coal
shipments are received by railroad and transferred to two coal piles east of
the plant. One pile is for the low sulfur coal and the other one is for
high sulfur coal.
PM emissions for boiler 1 are controlled with wet scrubbers and
boiler 2 by ESPs which are located behind each unit. Fly ash is disposed
on-site in several ash ponds north of the plant. Each unit has its own
chimney.
Lime/Limestone and Lime Spray Drying FGD Costs--
Both boilers are located southeast of the lake. Because unit 1 has a
new FGD system, it was not considered in this study. Unit 2 is burning a
very low sulfur coal. Retrofit factors were developed for unit 2, although
costs were not developed. FGD costs generated based on the current coal
burned would result in low capital and operating cost estimates relative to
burning a high sulfur coal. As 1s the case for unit 1, it is likely that
unit 2 would be switched to burn a high sulfur coal if an FGD unit was
needed due to acid rain legislation or due to the increased cost
differential between low and high sulfur coal.
The absorbers for unit 2 would be located behind its chimney, adjacent
to a storage building. The existing unit 1 limestone preparation, storage,
and handling area located northeast of the coal pile would be expanded for
unit 2. No major demolition/relocation would be required and a factor of
5 percent was assigned to general facilities.
A low site access/congestion factor was assigned to the unit 2 FGD
absorber location because of the space available behind the chimney.
Because the absorbers would be placed behind the chimney, a relatively short
14-60
-------
TABLE 14.3.3-1. LA CYGNE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
FGD SYSTEM
FGD TYPE
FGD INSTALLATION DATE
1
2
873
685
26
42
1973
1977
CYCLONE
OPPOSED WALL
529
NA
NO
YES
4.7
0.39
9100
8500
25.0
5.4
DRY HANDLING
ON-SITE
1
2
RAILROAD
YES
NO
VENTURI
LIMESTONE
1973
PARTICULATE CONTROL
TYPE WET SCRUBBERS ESP
INSTALLATION DATE 1973 1977
EMISSION (LB/MM BTU) 0.21 0.01
REMOVAL EFFICIENCY 98.0 99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 5.4 0.3
SURFACE AREA (1000 SQ FT) NA 1728
GAS EXIT RATE (1000 ACFM) 2500 2926
SCA (SQ FT/1000 ACFM) NA 590
OUTLET TEMPERATURE (*F) 151 302
14-61
-------
duct length would be required. A low site access/congestion factor was also
assigned to the flue gas handling system because of the easy accessibility
to the existing chimney.
LSD with reuse of the existing ESPs was considered for unit 2 because
the ESPs are large (SCA -590) and would not require major upgrading and
plate area additions to handle the increased PMs generated from the LSD
application. The absorbers would be located behind the chimney; hence, a
low site access/congestion factor was assigned to the absorber location. A
high site access/congestion factor was assigned to the flue gas handling
system because duct work has to go around the ESPs and access to the
upstream of the existing ESPs is difficult. Duct length of over 1,000 feet
would be required.
The major scope adjustment costs and retrofit factors estimated for the •
FGD technologies are presented in Table 14.3.3-2. Costs were not developed
for unit 2 because the unit is burning a very low sulfur coal which would
result in very high unit costs.
Coal Switching and Physical Coal Cleaning Costs-
La Cygne unit 2 is already burning a low sulfur coal and would not be
considered for CS/blending/cleaning.
Low NO Combustion--
A
Unit 2 is equipped with LNBs and, as such, was not considered a
candidate for LNC. Unit 1 is a cyclone boiler and the combustion
modification techniques applied to this boiler is NGR. Plant personnel
indicated that the La Cygne plant does not presently use natural gas,
therefore, the plant does not have a natural gas line. The projected cost for
installation of a natural gas pipeline is approximately ten million dollars.
Tables 14.3.3-3 and 14.3.3-4 present performance and cost results for
retrofitting NGR at the La Cygne plant.
Selective Catalytic Reduction--
Cold side SCR reactors for both units would be located immediately
behind the unit 2 chimney. The SCR reactors for unit 1 were not placed
behind its respective chimney because of the obstructions created by the
14-62
-------
TABLE 14.3.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR LA CVGNE UNIT 2
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 1000 +
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS __
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.20
NA
NA
NA
NA
NA
1.64
NA
1.16
NA
GENERAL FACILITIES (PERCENT) 5
14-63
-------
TABLE 14.3.3-3. SUMMARY OF NOx RETROFIT RESULTS FOR LA CYGNE
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
CYC
OWF
TYPE OF NOx CONTROL
NGR
NA
FURNACE VOLUME (1000 CU FT)
529
NA
BOILER INSTALLATION DATE
1973
1977
SLAGGING PROBLEM
NA
NO
ESTIMATED NOx REDUCTION (PERCENT)
60
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
137
114
New Duct Length (Feet)
600
200
New Duct Costs (1000$)
10561
3055
New Heat Exchanger (1000$)
6839
5913
TOTAL SCOPE ADDER COSTS (1000$)
17537
9082
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
14-64
-------
Table 14.3.3-4. MO* Control Cost Results for the La Cygne Plant (Jcne 1988 Dollars)
Technology. Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NQx NOx NOx Cost
Nutfcer Retrofit Sixe Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (KW> (X) Content (MM) (S/kW) (MM) (mi IIs/kuh) (X) (tons/yr) (S/ton)
Factor (X)
NGR
1
1.00
873
26
4
7
21.5
24.6
13.1
6.6
60.0
11527
1135.4
NGR-C
1
1.00
873
26
4
7
21.5
24.6 .
7.6
3.8
60.0
11527
658.9
SCR-3
1
1.16
873
26
4
7
10S.9
121.3
39.1
19.7
80.0
15369
2546.5
SCR-3
2
1.16
685
42
0
4
81.5
118.9
31.2
12.4
80.0
13013
2398.1
SCR-3-C
1
1.16
873
26
4
7
105.9
121.3
22.9
11.5
80.0
15369
1489.9
SCR-3-C
2
1.16
685
42
0
4
81.5
118.9
18.2
7.2
80.0
13013
1402.0
SCR-7
1
1.16
873
26
4
7
105.9
121.3
31.7
15.9
80.0
15369
2060.3
SCR- 7
2
1.16
685
42
0
4
81.5
118.9
25.3
10.0
80.0
13013
1942.9
SCR-7-C
1
1.16
873
26
4
7
105.9
121.3
18.6
9;4
80.0
15369
1211.3
SCR-7-C
2
1.16
685
42
0
4
81.5
118.9
14.9
5.9
80.0
13013
1141.2
SSS3S3SSSS
:S5S83SS35S
33388888
B8S33S889
8 S3
8S3
8I38S8SS83
88833333
333338
88888888
¦333338888
888883333838888888
14-65
-------
coal conveyors. The SCR reactors were assigned a low site access/congestion
factor for the same reasons as were outlined in the FGD section. Flue gas
duct length of 600 feet would be required for unit 1 and 200 feet would be
required for unit 2. The ammonia storage system was placed west of the
reactors. No major demolition/relocation would be necessary; therefore, a
base factor of 13 percent was assigned to general facilities.
Table 14.3.3-3 presents the SCR retrofit results for both units.
Table 14.3.3-4 presents the estimated cost of retrofitting SCR at the
La Cygne boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the La Cygne steam plant
for unit 2 would be difficult. This is caused by inadequate duct residence
time between the boilers and the ESPs for either humidification (FSI
application) or sorbent droplet evaporation (DSD application). However, the
ESPs are sufficiently large that the first ESP section can be used for
humidification or sorbent injection. A high site access/congestion factor
was assigned to the ESP locations if additional plate area or upgrading of
the existing ESPs is required. This factor reflects the access difficulty
to the existing ESPs as well as congestion created by the close proximity of
the ESPs, chimneys, and interferences created by the coal conveyor. Because
unit 2 is burning a very low sulfur coal, cost estimates for DSD/FSI are not
reported.
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 La Cygne plant. Neither of these units would be
considered good candidates for repowering or retrofit because of their large
boiler size and short service life.
14-66
-------
14.3.4 Montrose Steam Plant
The Montrose steam plant is located within Henry County, Missouri, as
part of the Kansas City Power and Light Company system. Located to the
north of Montrose Lake, the plant contains three coal-fired boilers and has
a total gross generating capacity of 564 MW.
Table 14.3.4-1 presents operational data for the existing equipment at
the Montrose plant. In the EIA-767 form, it is reported that the boilers burn
high sulfur coal (4.5 percent sulfur). However, plant personnel indicated
that the plant switched to a western low sulfur coal (0.5 percent sulfur) in
1987. Coal shipments were originally made by truck. After switching to
western coal, railroad transportation was used. Coal is 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. Even though the ESPs are large (SCA >500), some
difficulty has been observed in removing PM since the plant switched to low
sulfur coal. Plant personnel indicated that upgrading the ESP voltage
controls or gas conditioning is being considered to improve the ESP
performance. The plant has the capability of disposing the fly ash either
dry or wet.' Fly ash is disposed of on-site west of the plant. Originally,
there was one chimney serving each unit. Now, however, units 2-3 are served
by one chimney and unit 1 is served by a separate chimney. The middle
chimney behind unit 2 is out of service.
Lime/Limestone and Lime Spray Drying FGD Costs--
The three boilers are located beside each other and are parallel to the
lake. Water intake and discharge structures are located behind unit 3. For
retrofit FGD systems, the unit 1 through 3 absorbers would be located behind
the chimneys between the units and the lake. The limestone preparation,
storage, and handling area would be located west of the plant adjacent to the
existing ash pond site. The ash sluice lines, a road, and some storage
buildings would be relocated and, as such, a factor of 10 percent was
assigned to general facilities.
A medium site access/congestion factor was assigned to the FGD absorber
locations due to some congestion difficulties created by the water intake,
14-67
-------
TABLE 14.3.4-1. MONTROSE STEAM PUNT OPERATIONAL DATA *
BOILER NUMBER
1-3
GENERATING CAPACITY (MW-each)
188
CAPACITY FACTOR (PERCENT)
28,28,47
INSTALLATION DATE
1958,60,64
FIRING TYPE
TANGENTIAL
FURNACE VOLUME (1000 CU FT)
102
LOW NOx COMBUSTION
NO
COAL SULFUR CONTENT (PERCENT)
0.5
COAL HEATING VALUE (BTU/LB)
8800
COAL ASH CONTENT (PERCENT)
5
FLY ASH SYSTEM
WET/DRY HANDLING
ASH DISPOSAL METHOD
ON-SITE
STACK NUMBER
1-2
COAL DELIVERY METHODS
RAILROAD
PARTICULATE CONTROL
TYPE
ESP
INSTALLATION DATE
1972
EMISSION (LB/MM BTU)
0.11
REMOVAL EFFICIENCY
99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
5.0
SURFACE AREA (1000 SQ FT)
300
GAS EXIT RATE (1000 ACFM)
581.6
SCA (SQ FT/1000 ACFM)
516
OUTLET TEMPERATURE (#F)
290
* This table was revised after talking to the plarft personnel.
14-68
-------
discharge channel, and storage area. In addition, the absorbers would be
located in an area with high underground obstructions created by the
circulating water coming from the intake channel. For flue gas handling,
because the absorbers were placed immediately behind the chimneys, short
duct runs would be required for L/LS-FGD cases (about 250 feet). A low site
access/congestion factor was assigned to the flue gas handling system due to
easy access to the existing chimneys.
LSD with reuse of the existing ESPs was considered for the Montrose
plant because the units have relatively large ESPs. The absorbers would be
located behind the chimneys as in the L/LS-FGD cases and a medium site
access/congestion factor was assigned to the absorber location. For the
flue gas handling system, a high site access/congestion factor was assigned
because of the difficulties in gaining access upstream of the existing ESPs.
The major scope adjustment costs and retrofit factors estimated for the
F6D technologies are presented in Table 14.3.4-2. No large scope adder cost
is required for the Montrose plant.
Costs were not developed for FGD technologies based on the currently
fired coal because the plant has already switched to a low sulfur coal.
Cost estimates based on the current coal would result in lower capital and
operating costs than for a high sulfur coal. This plant would not scrub
unless the fuel price differential between high and low sulfur coal made FGD
economical.
Coal Switching and Physical Coal Cleaning Costs--
Montrose plant has already switched to a low sulfur coal; therefore,
costs were not developed for coal switching and cleaning.
Low N0X Combustion--
Units 1 through 3 are dry bottom, tangential-fired boilers rated at
188 MW each. The combustion modification technique applied to all boilers
was OFA. As Table 14.3.4-3 shows, the OFA N0X reduction performance for
each unit is 25 percent. Table 14.3.4-4 presents the cost of retrofitting
OFA at the Montrose plant.
14-69
-------
TABLE 14:3.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR MONTROSE
UNITS 1,2,3
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
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$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.30
NA
ESP REUSE CASE
1.49
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10.
14-70
-------
TABLE 14.3.4-3. SUMMARY OF NOx RETROFIT RESULTS FOR MONTROSE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2,3
1-3
FIRING TYPE
TANG
NA
TYPE OF NOx CONTROL
OFA,
NA
FURNACE VOLUME (1000 CU FT)
102
NA
BOILER INSTALLATION DATE
1958
NA
SLAGGING PROBLEM
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
43
99
New Duct Length (Feet)
250
250
New Duct Costs (1000$)
1792
3408
New Heat Exchanger (1000$)
2722
5262
TOTAL SCOPE ADDER COSTS (1000$)
4558
8769
RETROFIT FACTOR FOR SCR
1.34
1.34
GENERAL FACILITIES (PERCENT)
20
20
14-71
-------
table 14.3.4-4. NOx Control Cost Results for the Montrose Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
NOx
NOx
NOx Cost
Nimber Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HU)
«)
Content
(MM)
(mills/kwh)
(X)
(tons/yr)
(S/ton)
Factor
CX>
INC-OFA
1. 2
1.00
IBS
28
0.5
0.8
4.2
0.2
0.4
25.0
511
341.1
LNC-OFA
3
1.00
188
47
0.5
0.8
4.2
0.2
0.2
25.0
857
203.2
INC-OFA-C
1, 2
1.00
188
28
0.5
0.8
4.2
0.1
0.2
25.0
511
202.5
INC-OFA-C
3
1.00
188
47
0.5
0.8
4.2
0.1
0.1
25.0
857
120.6
SCR-3
1. 2
1.34
188
28
0.5
32.6
173.6
10.8
23.5
80.0
1634
6619.7
SCR-3
3
1.34
188
47
0.5
32.6
173.7
11.0
14.3
80.0
2743
4023.1
SCR-3
1-3
1.34 '
564
34
0.5
76.5
135.7
27.4
16.3
80.0
5953
4598.8
SCR-3-C
1, 2
1.34
188
28
0.5
32.6
173.6
6.3
13.8
80.0
1634
3882.2
SCR-3-C
3
1.34
188
47
0.5
32.6
173.7
6.5
8.4
80.0
2743
2358.3
SCR-3-C
' 1-3
1.34
564
34
0.5
76.5
135.7
16.0
9.5
80.0
5953
2692.4
5CR-7
1, 2
1.34
188
28
0.5
32.6
173.6
9.2
20.0
80.0
¦ 1634
5630.0
SCR-7
3
1.34
188
47
0.5
32.6
173.7
9.4
12.2
80.0
2743
3433.5
SCR-7
1-3
1.34
564
34
0.5
76.5
135.6
22.5
13.4
80.0
5953
3783.8
SCR-7-C
1. 2
1.34
188
28
0.5
32.6
173.6
5.4
11.7
80.0
1634
3315.2
SCR-7-C
3
1.34
188
47
0.5
32.6
173.7
5.5
7.2
80.0
2743
2020.5
SCR-7-C
1-3
1.34
564
34
0.5
76.5
135.6
13.2
7.9
80.0
5953
2225.5
14-72
-------
Selective Catalytic Reduction--
Cold side SCR reactors for all units would be located immediately behind
the chimneys. All three reactors are located in areas with medium site
access/congestion and high underground obstructions as outlined in the FGD
section. Because the SCR reactors are located close to the chimneys, a short
duct length of 250 feet was required for the flue gas handling systems. The
ammonia storage system was placed close to the reactors and east of the plant.
A plant road, ash silos, and sluice lines have to be relocated to open up
sufficient space for the SCR reactors. Therefore, a factor of 20 percent was
assigned to general facilities.
Table 14.3.4-3 presents the SCR retrofit results of all units.
Table 14.3.4-4 presents the estimated cost of retrofitting SCR at the
Montrose boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the Montrose steam plant
would be difficult since inadequate duct residence time exists between the
boilers and the retrofit ESPs for either humidification (FSI application) or
sorbent droplet evaporation (DSD application). However, the ESPs are large
and the first ESP section could be modified for humidification or sorbent
injection. A high site access/congestion factor was assigned to the ESP
locations for modifying and upgrading the existing ESPs. This factor
reflects the access difficulty for the existing ESPs due to congestion
created by the close proximity of the ESPs, chimneys, and ash silos. The
sorbent receiving/storage/preparation areas were located west of the plant
close to unit 3.
Table 14.3.4-5 presents the estimated retrofit factors and scope adder
costs for FSI and DSD technologies at the Montrose plant. Table 14.3.4-6
presents the costs for sorbent injection technologies. The estimated unit
costs are high because of the low coal sulfur content.
14-73
-------
TABLE 14.3.4-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MONTROSE UNITS 1,2,3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
LOW
ESP UPGRADE
HIGH
NEW BAGHOUSE
NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING
NO
ESTIMATED COST (1000$)
NA.
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
NA
ESTIMATED COST (1000$)
NA
ESP REUSE CASE
NA
. ESTIMATED COST (1000$)
NA
DUCT DEMOLITION LENGTH (FT)
50
DEMOLITION COST (1000$)
48
TOTAL COST (1000$)
ESP UPGRADE CASE
48
A NEW BAGHOUSE CASE
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.13
ESP UPGRADE
1.58
NEW BAGHOUSE
NA
14-74
-------
Table 14.3.4-6. Sutmary.of DSD/FSI Control Costs for the Montrose Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Sire Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content (SUN) (mills/knh) CX> (tons/yr) <$/ton)
Factor ESP-C
1. 2
3
1.00
1.00
188
188
28
47
0.5
0.5
7.1
7.1
38.0
38.0
3.0
3.2
6.5
4.2
49.0
49.0
1292
2169
2309.1
1487.9
FSI+ESP-50
FSI+ESP-50
1, 2
3
1.00
1.00
188
188
28
47
0.5
0.5
8.0
8.0
42.7
42.7
4.2
4.8
9.2
6.2
50.0
50.0
1328
2229
3178.0
2155.6
FSI+ESP-50-C
FS1+ESP-50-C
1. 2
3
1.00
1.00
188
188
28
47
0.5
0.5
8.0
8.0
42.7
42.7
2.5
2.8
5.3
3.6
50.0
50.0
1328
2229
1847.9
1251.2
FSI+ESP-70
FSI*ESP-70
1. 2
3
1.00
1.00
188
188
28
47
0.5
0.5
8.1
8.1
43.3
43.3
4.3
4.9
9.3
6.3
70.0
70.0
1859
3120
2295.5
1559.3
F5HESP-70-C
FSI+ESP-70-C
2
1.00
1.00
188
188
28
47
0.5
0.5
8.1
8.1
43.3
43.3
2.5
2.8
5.4
3.6
70.0
70.0
1859
3120
1334.8
905.1
14-75
-------
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 Montrose plant. All units would be considered good candidates for
repowering and retrofit because of their small boiler sizes and low capacity
factors.
14-76
-------
14.4 MISSOURI PUBLIC SERVICE
14.4.1 Sibley Steam Plant
The Sibley steam plant is located within Jackson County, Missouri, as
part of the Missouri Public Service system. The plant contains three coal-
fired boilers with a total gross generating capacity of 508 MW.
Figure 14.4.1-1 presents the plant plot plan showing the location of all
boilers and major associated auxiliary equipment.
Table 14.4.1-1 presents operational data for the existing equipment at
the Sibley plant. All boilers burn high sulfur coal (3.2 percent sulfur).
Coal shipments are received by railroad and conveyed to a coal storage and
handling area located west of the plant.
Particulate matter emissions for all boilers are controlled with ESPs
located behind each unit. Ash from all units is wet sluiced to ponds located
southeast of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 14.4.1-1 shows the general layout and location of the FGD control
system. The absorbers for L/LS-FGD and LSD-FGD for units 1 and 2 would be
located between the ESPs and the railroad, adjacent to the propane tanks
(east). The unit 3 absorber would be located east of the unit 3 boiler, be-
tween the railroad and the switch yard on the existing employee parking area.
The slag settling basin close to unit 1 and the process waste pond east of
unit 3, as well as the parking area beside unit 3 would have to be relocated;
therefore, a factor of 15 percent was assigned to general facilities. Lime was
used as the sorbent choice because of the limited space available. The lime
storage (silos)/preparation area and temporary waste handling area would be
located southwest of unit 1 between the coal pile and the switch yard.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for units 1 and 2 were located north of the ESPs, between
the railroad (south) and the propane tanks (east). The unit 3 absorbers were
located beside unit 3 (east), between the railroad (south) and the switch
yard (north).
14-77
-------
Initial
Pile
Chrusher
House
Slag Settling
Basin
\J
Absorbers
<"¦/
Common Duct
, . for Units 1 and 2
Unit 3
ESP Intake
Employee
Parking Area
N
NH3 Storage
System
Active
Storage
Waste
Handling Area
Absorbers
0
FGO Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
SCR Reactors
Not to scale
Figure 14.4.1-1. Sibley plant plot plan
14-78
-------
TABLE 14.4.1-1. SIBLEY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
FIRING TYPE
INSTALLATION DATE
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
I,2
53, 55
20, 36
CYC
1960,62
3.2
10800
II.2
3
400
26
CYC
1969
3.2
10800
11.2
WET SLUICE
POND/ON-SITE
1
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
1973,72
1969
95.2,97.2
96.5
3.2
3.2
48.6
161.3
188
1033
259
156
310
310
14-79
-------
The absorber locations for units 1 and 2 were assigned a high site
access/congestion factor, while for unit 3, a medium factor was assigned.
For units 1 and 2, this was due to the-area being surrounded by units 1 and 2
boilers (north), the railroad (south), and the propane tanks (east). For
unit 3, the medium site access/congestion factor was due to the office
building, roads and other minor obstacles.
Flue gas from all three boilers is currently converged into duct runs
going into a common chimney which is located over the railroad (the railroad
runs directly underneath the chimney). For flue gas handling, medium duct
runs for all units would be required for L/LS-FGD cases.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 14.4.1-2 and 14.4.1-3. The largest
scope adder for the Sibley plant would be the conversion of units 1 to 3 fly
ash conveying/disposal system from wet to dry for conventional L/LS-FGD
cases. It was assumed that dry fly ash would be necessary to stabilize
scrubber sludge waste. This conversion is not necessary for forced oxidation
L/LS-FGD.
The LSD-FGD with reused ESP was the only LSD-FGD technology considered
for units 1 and 2 because the boilers presently have large SCAs (>250). The
LSD-FGD with a new baghouse was the only LSD case considered for unit 3
because the ESPs are small (SCA <160). For flue gas handling for LSD cases,
moderate duct runs would be required for units 1-3. A high site access/
congestion factor was assigned for units 1 and 2 because of the difficulty of
routing the flue gas from the boilers to the absorbers and back to the ESPs.
A low site access/congestion factor was assigned for unit 3 flue gas handling
because the new baghouse would be installed close to the absorbers. The
retrofit factors determined for the LSD technology case were moderate
and did not include particulate control costs. Separate retrofit factors
were developed for upgrading ESPs for units 1 and 2 and for a new baghouse
for unit 3. These factors were used in the IAPCS model to estimate
particulate control costs. The access/congestion factor associated with
upgrading the ESPs would be moderate due to congestion created by the close
proximity of the ESPs. The access/congestion factor for the new baghouse
would be low due to the space availability to the east of unit 3.
14-80
-------
TABLE 14.4.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR SIBLEY UNITS 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
HIGH
HIGH
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
300-600
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$)
531,549
NA
531,549
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.64
1.60
ESP REUSE CASE
1.69
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
15
15
14-81
-------
TABLE 14.4.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR SIBLEY UNIT 3
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
MEDIUM
MEDIUM
FLUE GAS HANDLING
LOW
LOW
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
300-600
300-600
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
NO
ESTIMATED COST (1000$)
3249
NA
NA
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.48
1.43
ESP REUSE CASE
NA
BAGHOUSE CASE
1.40
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 15
15
15
14-82
-------
FGD Retrofit Costs-
Table 14.4.1-4 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
boilers 1 and 2 and installing a new baghouse to handle the additional
particulate loading for boiler 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. For the low cost case, all absorbers
were located next to unit 3.
Coal Switching Costs-
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined. This is particularly true for cyclone boilers; as such, coal
switching was not evaluated.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Sibley steam plant. These controls include NGR and SCR.
NGR was the LNC modification control for the three Sibley units because LNB
and OFA are not applicable to cyclone-fired boilers. SCR was considered to
be applicable to all coal-fired boiler types.
Low N0X Combustion--
Table 14.4.1-5 presents the NOx reduction performance and costs of NGR
for each unit at the Sibley plant. The NGR N0x reduction performance for
all units was estimated to be 60 percent. Table 14.4.1-6 presents the costs
of retrofitting NGR at the Sibley boilers. Natural gas is not currently
supplied to the plant and the closest source is about 30 miles away. The
plant estimated 59.75 million would be the cost of the pipeline, which was
added to the NGR capital cost.
14-83
-------
Table 14.4.1-4. Sminary of FCD Control Costs for the Sibtey Plant (June 1988 Dollars)
13SSIISSIIIU
11
II
M
M
H
n
tMX£3KS«:
B3SBHS3
•«x««xa:
X1SIIIIII
lamini
iaaa=sas«
!aass=s==ae=a8a"==
II
II
H
II
If
II
IIIIIIISII
laicuaas
Technoloay
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nurt>er
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (My)
(X)
Content
(SWI)
CS/kU)
-------
TABLE 14.4.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR SIBLEY
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
MEDIUM
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
17
17
76
New Duct Length (Feet)
300
400
400
New Duct Costs (1000$)
1,025
1,397
4,460
New Heat Exchanger (1000$)
1,273
1,302
4,282
TOTAL SCOPE ADDER COSTS (1000$)
2,316
2,716
8,818
RETROFIT FACTOR FOR SCR
1.36
1.36
1.36
GENERAL FACILITIES (PERCENT)
13
13
13
14-85
-------
Table 14.4.1-6. NOx Control Cost Results for the Sibley Plant (Jirw 1988 Dollars)
=====ss=ssa==
II
1!
II
II
II
II
:33:S2;sz:
:ss::is
:::sass3isasessi2
issiasasssasssti
:ssflssiss*ss
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nuitoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Renoved
Effect.
Difficulty (MV)
(X)
Content
(SWO
<$/kW>
(SMH)
(nills/kwh)
(X)
(tons/yr)
(I/ton)
factor
(X)
NCR
1
1.00
53
20
3.2
2.4
45.0
0.9
9.6
60.0
481
1843.2
NCR
2
1.00
55
36
3.2
2.5
45.9
1.3
7.6
60.0
899
1471.4
NCR
3
1.00
400
26
3.2
14.1
35.3
6.9
7.6
60.0
4722
1459.4
NGR-C
1
1.00
53
20
3.2
2.4
45.0
0.5
5.6
60.0
481
1078.3
NGR-C
2
1.00
55
36
3.2
. 2.5
45.9
. 0.8
4.4
60.0
899
855.6
NGR-C
3
1.00
400
26
3.2
. 14.1
35.3
4.0
4.4
60.0
4722 .
849.6
SCR -3
1
1.36
53
20
3.2
14.6
276.4
4.5
48.4
80.0
642
7008.3
SCR-3
2
1.34
55
36
3.2
15.3
277.3
4.7
27.3
80.0
1199
3943.9
SCR-3
3
1.36
400
26
3.2.
57.9
144.8
20.1
22.0
80.0
6295
3188.1
SCR-3-C
1
1.36
53
20
3.2
14.6
276.4
2.6
28.5
80.0
642
4117.6
SCR-3-C
2
1.36
55
36
3.2
15.3
277.3
2.8
16.0
80.0
1199
2316.7
SCR-3-C
3
1.36
400
26
3.2
57.9
144.8
11.8
12.9
80.0
6295
1867.8
SCR-7
1
1.36
53
20
3.2
14.6
276.4
4.1
43.7
80.0
642
6319.0
SCR-7
2
1.36
55
36
3.2
15.3
277.3
4.3
24.6
80.0
1199
3561.1
SCR-7
3
1.36
400
26
3.2
57.9
144.8
16.7
18.4
80.0
6295
2657.8
SCR-7-C
1
1.36
53
20
3.2
14.6
276.4
2.4
25.7
80.0
642
3722.7
SCR-7-C
2
1.36
55
36
3.2
15.3
277.3
2.5
14.5
80.0
1199
2097.3
SCR-7-C
3
1.36
400
26
3.2
57.9
144.8
9.8
10.8
80.0
6295
1564.0
siiisaasiiasi;
llllfal
iiaiiaiti:
BBKSSS3T
aiistissi
tars**==a:
:3
-------
Selective Catalytic Reduction-
Table 14.4.1-5 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 units 1 and 2 were located directly behind (north)
their respective ESPs between the railroad and the propane tanks. The SCR
reactor for unit 3 was located beside unit 3 between the railroad and the
switch yard.
The SCR reactors for all units were assigned medium access/congestion
factors because of access difficulty and interference of existing equipment
near the reactors. All reactors were assumed to be in areas with high
underground obstructions. The ammonia storage system was placed in an area
of low access and congestion. Table 14.4.1-6 presents the estimated cost of
retrofitting SCR at the Sibley 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 south of
the plant in a similar fashion as LSD-FGD. There is sufficient duct
residence time (-2 seconds) between boilers 1-2 and the respective ESPs to
evaluate FSI and DSD with ESP reuse. The retrofit of DSD and FSI for unit 3
would be difficult because of the short duct residence time (-1 second) and
small ESPs (SCA <160). Sufficient duct residence time could be made
available for DSD if a new baghouse is installed. For ESP upgrades and
addition of a new fabric filter, a medium access/congestion factor of 1.36
was assumed. Additionally, the conversion of the wet fly ash handling system
14-87
-------
to dry handling would be required when reusing the ESPs. Tables 14.4.1-7
and Table 14.4.1-8 present a summary of the site access/congestion factors
for DSD and FSI technologies at the Sibley steam plant. Table 14.4.1-9
presents the costs estimated to retrofit DSD and FSI at the Sibley 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 Sibley plant. Boilers 1 and 2 would be considered good
candidates for AFBC retrofit and AFBC or CG/combined cycle repowering
because of their small boiler sizes (53-55 MW) and low capacity factors.
Although the unit 3 boiler would not be a good candidate due to its large
boiler size (>300 MW), its low capacity factor indicates that purchased
power cost for unit downtime may not be significant and preclude application
of AFBC or CG.
14-88
-------
TABLE 14.4.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SIBLEY UNITS 1 OR 2
ITEH
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 531, 549
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 19
TOTAL COST (1000$)
ESP UPGRADE CASE 550, 568
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.36
NEW BAGHOUSE NA
14-89
-------
TABLE 14.4.1-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SIBLEY UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE (FSI) MEDIUM
NEW BAGHOUSE (DSD) MEDIUM
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING • YES
ESTIMATED COST (1000$) 3249
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 400
ESTIMATED COST (1000$) 4135
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 85
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 3334
A NEW BAGHOUSE CASE (DSD) 4220
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE (FSI) 1.36
NEW BAGHOUSE (DSD) 1.36
14-90
-------
Table 14.4.1-9. Surmary of DSO/FSI Control Costs for the Sibley Plant iss3s::ss:s3assiss::3ssziiiia
Technolofly Boiler Kain Boiler Capacity Coal Capital Capital Annual Annual 502 SO2 S02 Cost
Member Retrofit Sue
Difficulty i
Cost
CS/kU)•
Cost Cost Removed Removed
{»•») (mills/kuh) (X)
-------
14.5 CITY UTILITIES OF SPRINGFIELD
14.5.1 James River Steam Plant
The James River Power Station is located within Greene County, Missouri,
as part of the City Utilities of Springfield. The plant is located adjacent
to the James River and Lake Springfield and contains five coal-fired boilers
with a total gross generating capacity of 249 MW.
Table 14.5.1-1 presents operational data for the existing equipment at
the James River plant. The boilers burn high sulfur coal which is received
by railroad and transferred to a coal storage and handling area south of the
plant away from the lake. The coal handling system was upgraded in 1987 and
the coal pile was moved to the west portion of the coal storage and handling
area. The coal conveyors were also moved to the west.
Units 1-4 have retrofit ESPs and unit 5 has its original ESPs. Fly ash
and bottom ash are wet sluiced and disposed of in two ash ponds west of the
coal pile. Every 2 years ash is removed from these ponds and transferred to
another site on the other side of the James River. Units 1 and 2 are served
by a common chimney while the other units have separate chimneys.
Lime/Limestone and Lime Spray Drying FGD Costs--
The absorbers for units 1-3 would be located east of unit 1 toward the
lake and south of the employee parking area between the gas peaking turbines
and the coal pile. The absorbers for units 4-5 would be located west of unit
5 adjacent to the coal conveyor and north of the coal pile and fly ash sluice
lines. The limestone preparation, storage, and handling area would be
located east of the ash ponds and northwest of the coal pile. No major
demolition/relocation would be required for units 1-3 locations and a factor
of 5 percent was assigned to general facilities. By contrast, a storage
building adjacent to the unit 5 chimney has to be relocated for the unit 4, 5
location and a factor of 8 percent was assigned to general facilities.
Low site access/congestion factors were assigned to the FGD absorber
locations due to the space availability and easy accessibility to these
locations. For flue gas handling, the unit 1-2 chimney is boxed in by the
ESPs making access to it rather difficult. For unit 3, the chimney is placed
14-92
-------
TABLE 14.5.1-1. JAMES RIVER STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1, 2
3
4
5
23
45
62
96
12
28
40
45
1957 1960 1964 1970
TANGENTIAL FRONT WALL
NA NA 39.3 55.6
NO NO NO NO
4.2 4.2 4.2 4.2
12500 12500 12500 12500
12.0 12.0 12.0 12.0
WET SLUICE
ON-SITE/REMOVED EVERY 2 YEARS
1 2 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 (°F)
ESP
ESP
ESP
ESP
1980-81
1979
1976
1970
0.06
0.07
0.05
0.07
99.6
99.5
99.2
99.2
3.9
3.9
3.9
3.9
36.72
69.3
77.76
54.0
111.9
210
249.9
344
328
330
311
157
320
317
320
320
14-93
-------
in an open area behind the retrofit ESPs which can be accessed easily. The
unit 4 chimney is located behind the retrofit ESPs but access to it is
limited because of the unit 5 and coal conveyor interferences. Access to the
unit 5 chimney is also limited because of the coal conveyor. Duct lengths of
200 to 500 feet would be required for these units.
LSD with reuse of the existing ESPs was considered for units 1-4 because
the retrofit ESPs have adequate sizes (SCA >350) and would not require major
upgrading and plate area additions to handle the increased PM generated from
the LSD application. By contrast, unit 5 has very small ESPs which possibly
would not be able to handle the increased load. LSD with a new baghouse was
also not considered for unit 5. because the boilers are burning high sulfur
coal making wet FGD more practical. A medium site access/congestion factor
was assigned to the unit 1-4 ESP locations due to space limitations behind
the ESPs created by the coal pile. This factor was used by the IAPCS model
for particulate control cost estimates. Medium to high site access/
congestion factors were assigned to the flue gas handling system for units 3
and 4. This reflects the access difficulty to the upstream of the ESPs
caused mainly by other units. Ductwork has to go around the existing units
(1-2 and 5) before accessing units 3-4 ESPs. The low cost FGD option has 7
percent added to the retrofit factors to account for the cost of a new
chimney.
The major, scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 14.5.1-2 through 14.5.1-5.
Table 14.5.1-6 presents the process area retrofit factors and capital/
operating costs for commercial FGD technologies.
Coal Switching and Physical Coal Cleaning Costs-
Table 14.5.1-7 presents the IAPCS results for CS at the James River
plant. These costs do not include boiler and pulverizer operating cost
changes or any system modifications that may be necessary to the coal
handling system for blending. PCC was not evaluated because this is not a
mine mouth plant.
14-94
-------
TABLE 14.5.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR JAMES RIVER
UNITS 1 OR 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
MEDIUM
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$)
251
NA
251
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.35
NA
ESP REUSE CASE
1.31
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5
0
5
14-95
-------
TABLE 14.5.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR JAMES RIVER UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 458 NA 458
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 NA
ESP REUSE CASE 1.54
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5
14-96
-------
TABLE 14.5.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR JAMES RIVER UNIT 4
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
LOW
MEDIUM
300-600
NA
NA
YES
611
NO
0
NO
1.42
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
LOW
MEDIUM
NA
600-1000
NA
MEDIUM
NA
YES
611
NO
0
NO
1.45
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 8
8
14-97
-------
TABLE 14.5.1-5. SUMMARY OF RETROFIT FACTOR DATA FOR JAMES RIVER UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
NA
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
. NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NA
ESTIMATED COST (1000$)
904
NA
NA
NEW CHIMNEY
NO
NA
NA
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
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) 8
0
0
14-98
-------
Tab!# 14.5.1-6. Sinrory of FGD Control Costs for th* Jamas Rfvar Plant (Jure 1988 Dollars)
==3333=333333
ESS3SSSS:
3KS*5StSS!
issssssasssssss:
:sss:xs3i
13333333333333333
:3333333
iZlfSSSSSS
33333333
33=333=3=33
:ss:s=iss
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
S02
S02
S02 Cost
N utter
Retrof it
Six*
Factor
Sulfur
Cost
Cost
Cost
Cost
Ramoved Removed
Effect.
Difficulty (MW)
CX>
Content
(SMM>
(S/kW)
-------
Table 14.5.1-7; Sunnary of Coal Snitching/Cleaning Costs for the James River Plant (June 1988 Dollars)
SS3SS288888S
iSBBSSSl
SSSBSfSSSBSSBSSSBB
8B88SB888B8SBBS8!
B8BBBBBBBBBB88B888SS88BB1BS8BS88BBB
888888
88888888881
: srssss:=
Technology
Boiler 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)
<*)
Content
(SUM)
(*/kW)
<»«>
(niUs/kwfc)
(X)
(tons/yr)
(1/ton)
Factor
(X)
CS/B+S15
1.
2 1.00
23
12
4.2
1.5
64.9
0.8
32.2
78.0
607
1282.1
CS/B*S15
3
1.00
45
23
4.2
2.3
50.2
2.1
19.4
78.0
2772
772.6
CS/H+115
4
1.00
62
40
4.2
2.8
45.4
3.7
17.0
78.0
5456
677.3
CS/B*$15
5
1.00
96
45
4.2
4.4
46.3
6.2
16.3
78.0
9503
649.S
CS/B*$15-C
1,
2 1.00
23
12
4.2
1.5
64.9
0.5
18.7
78.0
607
745.6
CS/B»$15-C
3
1.00
45
28
4.2
2.3
50.2
1.2
11.2
78.0
2772
446.3
CS/B+I15-C
4
1.00
62
40
4.2
2.8
45.4
2.1
9.8
78.0
5456
390.4
CS/B+S15-C
5
1.00
96
45
4.2
4.4
46.3
3.6
9.4
78.0
9503
374.4
CS/B+S5
1,
2 1.00
23
12
4.2
1.3
54.6
0.5
22.2
78.0
607
884.5
CS/B*t5
3
1.00
45
28
4.2
1.8
39.8
t.1
10.4
78.0
2772
414.2
CS/8*$S
4
1.00
62
40
4.2
2.2
35.0
1.8
8.2
78.0
5456
327.8
CS/B+S5
5
1.00
96
45
4.2
3.5
36.0
2.9
7.6
78.0
9503
302.6
CS/B*»5-C
1.
2 1.00
23
12
4.2
1.3
54.6
0.3
13.0
78.0
607
516.0
CS/B»S5-C
3
1.00
45
28
4.2
1.8
39.8
0.7
6.0
78.0
2772
240.2
CS/B*$5-C
4
1.00
62
40
4.2
2.2
35.0
1.0
4.8
78.0
5456
189.6
CS/B*S5-C
S
1.00
96
45
4.2
3.5
36.0
1.7
4.4
78.0
9503
175.0
ss=:s:ss=ss;sHSs3«S3SsassaBS3«ssi>3a«S8issaississsi:aassBi3S«sssiS3i8S3i:s3SSSKSsa83S9Ss:8sssz:s3sss=sssssss=;s
14-100
-------
Low N0X Combustion-
Units 1-2 are tangential and units 3-5 are front wall-fired boilers. The
combustion modification techniques applied to these boilers was OFA for boil-
ers 1-2 and INB for boilers 3-5.
Table 14.5.1-8 presents the performance results and Table 14.5.1-9 pre-
sents the cost results of retrofitting OFA and LNB at the James River plant.
Although units 3-5 volumetric heat release rates indicate low to moderate N0X
reductions are possible, the small size of units 3 and 4 may preclude success-
ful application of LNB.
Selective Catalytic Reduction--
Cold side SCR reactors for all units would be located in a similar layout
to the FGD absorbers in low site congestion areas. For flue gas handling, the
duct lengths of 200, 250, 450, 500, and 200 feet were estimated for units 1-5,
respectively. The ammonia storage system was placed north of the coal pile
close to the ash ponds. No major relocation would be required for unit 1-3
reactors and a base factor of 13 percent was assigned to general facilities.
A storage building has to be relocated for units 4-5 reactor locations and, as
such, a factor of 20 percent was assigned to unit 4-5 general facilities.
Table 14.5.1-8 present the SCR retrofit results for all units.
Table 14.5.1-9 presents the estimated cost of retrofitting SCR at the James
River boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of FSI and DSD technologies at the James River steam plant
would be relatively easy for units 1-4 because ESPs are large and probably
would be able to handle the increased PM and would not require major ESP
upgrading and plate area additions. Units 3 and 4 have short duct residence
time but it was assumed that the first part of the retrofit ESPs could be
modified for humidification (FSI application) or sorbent evaporation (DSD
application). A medium site access/congestion factor was assigned to the
ESP locations for upgrading the ESPs because of the close proximity to the
coal pile. Unit 5 was not considered for sorbent injection technologies
because of inadequate ESP sizes. The sorbent receiving/storage/preparation
areas were located west of the plant in a similar fashion as L/LS-FGD.
14-101
-------
TABLE 14.5.1-8. SUMMARY OF NOx RETROFIT RESULTS FOR JAMES RIVER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1-2
3
4
5
FIRING TYPE
TANG
FWF
FWF
FWF
TYPE OF NOx CONTROL
OFA
LNB
LNB
LNB
FURNACE VOLUME (1000 CU FT)
NA
NA
39.3
55.6
BOILER INSTALLATION DATE
1957
1960
1964
1970
SLAGGING PROBLEM
NO
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
40
44
40
SCR RETROFIT RESULTS
SITE ACCESS' AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
15
15
19
26
New Duct Length (Feet)
250
450
500
200
New Duct Costs (1000$)
786
1398
1873
968
New Heat Exchanger (1000$)
1170
1154
1399
1819
TOTAL SCOPE ADDER COSTS (1000$)
1971
2567
3291
2813
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
20
20
14-102
-------
Table 14
.5.1-9.
NOx Control Cost
; Results
for the
i James River Plant (June
1988 Dollars)
SSSSXS2SSSS
S3S==s=xi:
=SSSSSS3S
>3=====:
---------
;as:s::s:
assassas
ssssssfi:
i=::saa3
tssssaaaaass
ssisss:
sssssssss
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
-------
Tables 14.5.1-10 through 12 present a summary of the site access/
congestion factors for FSI and DSD technologies at the James River steam
plant. Table 14.5.1-13 presents the costs estimated to retrofit FSI and DSD
at the James River boilers.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the James River plant. All units would be considered good
candidates for repowering and retrofit because of their small boiler sizes
and low capacity factors.
14-104
-------
TABLE 14.5.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JAMES RIVER UNITS 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 251
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 10
TOTAL COST (1000$)
ESP UPGRADE CASE 261
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
14-105
-------
TABLE 14.5.1-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JAMES RIVER UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 458
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$) 16
TOTAL COST (1000$)
ESP UPGRADE CASE 474 '
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
14-106
-------
TABLE 14.5.1-12. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR JAMES RIVER UNIT 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 611
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 21
TOTAL COST (1000$)
ESP UPGRADE CASE 632
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
14-107
-------
Table 14.S. 1-13. Sumary of D&/FSI Control Costs for tht Jama Rivar Plant (Jurn 1988 Dollars)
:sis:i:siBssszstis9*ssissssssisscs:aisritisiatiisftMi
Technology
Baiter Main
Bolter Capacity Coat
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nuifcer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
(X)
Content
(Vt<>
(S/kU)
(MM)
(mills/kwti)
(X)
(tons/yr)
(S/ton)
Factor
CX)
DSD+ESP
1, 2 1.00
23
12
4.2
4.2
183.9
3.8
156.0
45.0
353
10680.9
DSCHESP
3 1.00
45
28
4.2
5.9
132.0
4.7
42.2
45.0
1597
2917.5
DS0«ESP
4 1.00
62
40
4.2
7.1
114.2
5.5
25.4
45.0
3173
1736.0
dso*esp-c
1, 2 1.00
23
12
4.2
4.2
183.9
2.2
90.1
45.0
353
6173.3
DSO+ESP-C
3 1.00
45
28
4.2
5.9
132.0
2.7
24.4
45.0
1597
1688.2
DSO+ESP-C
4 1.00
62 '
40
4.2
7.1
114.2
3.2
14.7
45.0
3173
1004.6
FSI+ESP-50
1,2; 1.00
23
12
4.2
4.7
206.1
2.7
111.2
50.0
391
6880.4
FS1+ESP-S0
3 1.00
45
28
4.2
6.2
137.3
3.9
35.2
50.0
1784
2174.3
FSI+ESP-50
4 1.00
62
40
4.2
7.4
118.7
5.2
24.0
50.0
3512
1484.8
fsi*esp-50-c
1.2 1.00
23
12
4.2
4.7
206.1
1.6
64.6
50.0
391
3996.3
FSI*ESP-50-C
3 1.00
45
28
4.2
6.2
137.3
2.3
20.4
50.0
1784
1261.3
FSI»ESP-50-C
4 1.00
62
40
4.2
7.4
118.7
3.0
13.9
50.0
3512
860.1
FSI+ESP-70
1, 2 1.00
23
12
4.2
4.8
209.4
2.7
112.3
70.0
547
4959.9
FSHESP-70
3 1.00
45
28
4.2
6.3
139.5
3.9
35.6
70.0
2498
1573.9
FSI+ESP-70
4 1.00
62
40
4.2
7.5
120.5
5.3
24.4
70.0
4917
1076.6
FSI+ESP-70-C
1, 2 1.00
23
12
4.2
4.8
209.4
1.6
65.2 .
70.0
547
2881.2
FSI+ESP-70-C
3 1.00
45
28
4.2
6.3
139.5
2.3
20.7
70.0
2498
913.0
FSI*ESP-70-C
4 1.00
62
40
4.2
7.5
120.5
3.1
14.1 '
70.0
4917
623.6
zam==.m*=mmx*m
tSSIS«*SBIK3t«Sll
¦cssaaaa
l=3SC3ti:
saassaas:
arsssaassassssass?
iiesxss:
ssassaaasaas
II
U
II
II
tl
II
u
II
II
II
II
II
il
N
II
II
II
II
II
II
II
II
II
14-108
-------
14.6 UNION ELECTRIC COMPANY
14.6.1 Labadie Steam Plant
The Labadie steam plant is located within Franklin County, Missouri, as
part of Union Electric Company system. The plant contains four coal-fired
boilers with a total gross generating capacity of 2,482 MW. Figure 14.6.1-1
presents the plant plot plan showing the location of all boilers and major
associated auxiliary equipment.
Table 14.6.1-1 presents operational data for the existing equipment at
the Labadie steam plant. All boilers burn medium sulfur coal (2.5 percent
sulfur), a blend of high-sulfur and low-sulfur Illinois coals. Coal shipments
are received by railroad and conveyed to a coal storage and handling area
located west of the plant.
Particulate matter emissions are controlled with ESPs located behind each
boiler unit. Retrofit ESPs are added to the existing ESPs behind the
chimneys. The ESPs operate in parallel and 60 percent of the flue gases for
each unit go to the old ESPs while 40 percent go to the retrofit ESPs. Fly
ash from all units is sluiced to ponds located south and west of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 14.6.1-1 shows the general layout and location of the FGD control
system. The absorbers for L/LS-FGD for all units would be located southwest
of unit 4 between the railroads and east of the coal storage handling area.
For LSD-FGD cases, the absorbers for units 1 and 2 would be located beside
the water treatment area adjacent to unit 1 (northwest). The LSD absorbers
for units 3 and 4 would be located southwest of the plant in the same site
location as described above for L/LS-FGD. Some storage buildings would be
demolished to make space available for FGD equipment; therefore, a factor of
10 percent was assigned to general facilities. The lime and limestone
storage/preparation area and waste handling area would be located southeast
of the powerhouse adjacent to the absorbers.
14-109
-------
N
Missouri River
Sorbent Storage/
Preparation Area
Not to scale
FGD Waste Handling/Absorber Area
lime/Limestone Storage/Preparation Area
Figure 14.6.1-1. Labadie plant plot plan
14-110
-------
TABLE 14.6.1-1. LABADIE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1-4
GENERATING CAPACITY (MW-each) 620.5
CAPACITY FACTOR (PERCENT) 59,52,58,59
FIRING TYPE TANGENTIAL
INSTALLATION DATE 1970-73
COAL SULFUR CONTENT (PERCENT) 2.5
COAL HEATING VALUE (BTU/LB) 11300
COAL ASH CONTENT (PERCENT) 9.0
FLY ASH SYSTEM WET
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1-3
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1983
EMISSION (LB/MM BTU) 0.009-0.033
REMOVAL EFFICIENCY 99.4-99.8
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.3
SURFACE AREA (1000 SQ FT) 701.3
GAS EXIT RATE (1000 ACFM) 2,200
SCA (SQ FT/1000 ACFM) 319
OUTLET TEMPERATURE (°F) 310
14-111
-------
Retrofit Difficulty and Scope Adder Costs--
After demolition and relocation of the storage and shop buildings south
of unit 2, a relatively open area with no major obstacle/obstruction is
available for the placement of the FGD units. As such, a low site access/
congestion and underground obstruction factor is assigned to the L/LS-FGD
absorber location for all units. On the other hand, the lack of space around
the existing chimney due to the retrofit ESPs and the coal handling area
resulted in a high site access/congestion and underground obstruction factor
being assigned to the flue gas handling systems. Since units 1 and 2 are in
excess of 600 feet from the absorber area (south of unit 4) with high site
access/congestion, the cost of a new chimney for units 1 and 2 is included.
Interferences with the coal handling/blending operation are also reduced by
installing a new chimney. For flue gas handling, duct lengths range from
650 feet for unit 4 to 900 feet for unit 1.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables 14.6.1-2 through 14.6.1-5.
The largest scope adder cost is for the conversion of the fly ash handling
system from wet to dry. The overall retrofit factors determined for the
L/LS-FGD cases were moderate (1.45 to 1.62).
To be able to reuse the unit 1 and 2 ESPs, the LSD absorbers for units 1
and 2 could be located beside the water treatment area adjacent to unit 1
(northwest) without major demolition. The LSD absorbers for units 3 and 4
could be located southwest of the plant in the same manner as L/LS-FGD.
In LSD-FGD cases, units 1 and 2 absorber locations were assigned a high
site access/congestion factor due to the congestion created by the water
treatment area (north), railroad (west), ESPs (south), and unit 1 and an
office building (east). The absorber locations for units 3 and 4 (located
south of unit 4) were assigned a low access/congestion factor for the same
reason as in L/LS-FGD cases.
For units 1 and 4, a medium site access/congestion factor has been
assigned to the flue gas handling system for the following reason. Although
it is difficult to reach the upstream of the old ESP boxes (60 percent of
flue gas), it is relatively easy to access the inlet of the retrofit ESP box.
As such, an average (medium) congestion factor has been assigned. Access to
the unit 2 and 3 ESPs, on the other hand, is extremely difficult and a high
14-112
-------
TABLE 14.5.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR LABADIE 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$)
. OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
LOW
HIGH
LOW
HIGH
600-1000 600-1000
NA
NA
YES
4,714
YES
4,890
NO
1.64
NA
NA
NA
NA
NO
NA
YES
4,344
NO
1.57
NA
NA
HIGH
MEDIUM
300-600
NA
HIGH
NA
YES
4,714
NO
0
NO
1.67
NA
1.59
NA
GENERAL FACILITIES (PERCENT) 10
10
10
14-113
-------
TABLE 14.6.1-3., SUMMARY OF RETROFIT FACTOR DATA FOR LABADIE UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY PRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW HIGH
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 600-1000 600-1000
ESP REUSE 600-1,000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 4,714 NA 4,714
NEW CHIMNEY YES YES NO
ESTIMATED COST (1000$) 4,890 4,890 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.57 1.50
ESP REUSE CASE 1.82
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.59
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
14-114
-------
TABLE 14.6.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR LABADIE UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
HIGH
HIGH
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET) 600-1,000
600-1,000
ESP REUSE
600-1,000'
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST (1000$)
4,714
NA
4,714
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.59
1.52
ESP REUSE CASE
1.55
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.59
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
10
10
14-115
-------
TABLE 14.6.1-5. SUMMARY OF RETROFIT FACTOR DATA FOR LABADIE UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW '
FLUE GAS HANDLING
HIGH
HIGH
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
600-1,000
600-1,000
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST (1000$)
4,714
NA
4,714
NEW CHIMNEY .
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.54
1.47
ESP REUSE CASE
1.39
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.38
NEW BAGHOUSE
NA.
NA
NA
GENERAL FACILITIES (PERCENT) 10
10 '
10
14-116
-------
site access/congestion factor has been assigned to these two units for the
flue gas handling systems. In addition, a high underground obstruction
factor has been assigned to all units for flue gas handling. Duct lengths
range from 400 feet for unit 1 to 840 feet for unit 3 for the flue gas
handling system. Major scope adjustments are presented in Tables 14.6.1-2
through 14.6.1-5. The retrofit factors for LSD-F6D cases range from 1.39
for unit 4 to 1.82 for unit 2.
Table 14.6.1-6 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boilers 1-4. The low cost
control case reduces capital and annual operating costs by due to the
benefits of economies-of-scale when combining process areas, elimination of
spare scrubber modules, 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 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 14.6.1-7.
N0x Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Labadie 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
A
technologies evaluated at the steam plant were: QFA and SCR, as shown in
Tables 14.6.1-8 and 14.6.1-9.
14-117
-------
Table 14.6.1-fi. Suimary of FCC Control Costs for the Labadie Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunbar Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MO (X> Content CSMM) (S/kW) (SMI) (mills/kuh) (X> (tons/yr) (S/ton)
Factor (X)
L/S FGD
1
1.64
621
59
2.5
158.7
255.8
75.0
23.4
90.0
62370
1201.8
L/S FGD
2
1.57
621
52
2.5
152.7
246.1
70.3
24.9
90.0
54970
1279.6
L/S FGD
3 '•
1.59
621
58
2.5
154.4
248.9
73.1
23.2
90.0
61313
1193.0
L/S FGD
4
1.54
621
59
2.5
150.2
242.0
72.1
22.5
90.0
62370
1155.7
L/S FGD-C
1
1.64
621
59
2.5
158.7
255.8
43.7
13.6
90.0
62370
700.0
L/S FGD-C
2
1.57-
621
52
2.5
152.7
246.1
41.0
14.5
90.0
54970
745.6
L/S FGD-C
3
1.59
621
58
2.5
154.4
248.9
42.6
13.5
90.0
61313
694.8
L/S FGD-C
• 4
1.54
621
59
2.5
150.2
242.0
42.0
13.1
90.0
62370
673.0
LC FGD
1-4
1.59
2482
58
2.5
427.2
172.1
219.7
17.5
90.0
244828
897.5
LC FGD-C
¦ 1*4
1.59
2482
58
2.5
427.2
172.1
127.8
10.2
90.0
244828
522.0
LSO*ESP
1
1.67
621
59
2.5
96.5
155.5
44.0
13.7
76.0
52876
831.5
LSO+ESP
2
1.82
621
52
2.5
104.2
167.9
44.7
15.8
76.0
46602
958.4
LSO+ESP
3
1.55
621
58
2.5
90.3
145.5
41.9
13.3
76.0
51979
806.1
LSO+ESP ¦
4
1.39
621
59
2.5
81.6
131.4
39.6
12.3
76.0
52876
748.0
LSO+ESP-C
1
1.67
621
59
2.5
96.5
155.5
25.6
8.0
76.0
52876
484.6
LSO+iSP-C
2
1.82
621
52
2.5
104.2
167.9
26.1
9.2
76.0
46602
559.1
LSO+ESP-C
3
1.55
621
58
2.5
90.3
145.5
24.4
7.7
76.0
51979
469.7
LSD+ESP-C
4
1.39
621
59
2.5
81.6
131.4
23.0
7.2
76.0
52876
435.5
14-118
-------
Table "4.6.1-7. Suimary of Coal Switching/Cl#inins Costs for the Labedie Plant (Jirw 1968 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 $02 $02 Cost
Member Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HU) (X) Content (SUM) CS/kW)
-------
TABLE 14.6.1-8. SUMMARY OF NOx RETROFIT RESULTS FOR LABADIE UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1 2 3
FIRING TYPE TANG TANG TANG
TYPE OF NOx CONTROL OFA OFA OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) 13.2 13.2 13.2
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 98.4 98.4 98.4
FURNACE RESIDENCE TIME (SECONDS) 3.52 3.52 3.52
ESTIMATED NOX REDUCTION (PERCENT) 25 25 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH HIGH LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0 0 0
Ductwork Demolition (1000$) 106 106 105
New Duct Length (Feet) 400 700 800
New Duct Costs (1000$) 7,900 13,825 15,800
New Heat Exchanger (1000$) 5,575 5,575 5,575
TOTAL SCOPE ADDER COSTS (1000$) 13,581 19,506 21,481
RETROFIT FACTOR FOR SCR 1.52 1.52 1.16
GENERAL FACILITIES (PERCENT) 25 25 25
14-120
-------
TABLE 14.6.1-9. SUMMARY OF NOx RETROFIT RESULTS FOR LABADIE UNIT 4
BOILER NUMBER
4
COMBUSTION MODIFICATION RESULTS
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) 13.2
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 98.4
FURNACE RESIDENCE TIME (SECONDS) 3.52
ESTIMATED NOX REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 106
New Duct Length (Feet) 620
New Duct Costs (1000S) 12,245
New Heat Exchanger (1000$) 5,575
TOTAL SCOPE ADDER COSTS (1000$) 17,926
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 25
14-121
-------
Low N0X Combustion--
Units 1 to 4 are dry bottom, tangential-fired boilers rated at 621 MW
each. The combustion modification technique applied for this evaluation was
OFA. The OFA N0X reduction performance for units 1 to 4 was estimated to be
25 percent for all units. This reduction performance level was assessed by
examining the effects of heat release rates and furnace residence time
through the use of the simplified N0X procedures. Table 14.6.1-10 presents
the cost of retrofitting OFA at the Labadie boilers.
Selective Catalytic Reduction--
Tables 14.6.1-8 and 14.6.1-9 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
£SPs to the reactor and from the reactor to the chimney.
The SCR reactors for units 1 and 2 were located north of the ESPs for
unit 1 and west of the office building in a high congestion area. The SCR
reactors for units 3 and 4 were located south of the ESPs for unit 4 and east
of the track hopper in a low congestion area. The arrangement of all units
is similar to the LSD-FGD layout; therefore, similar retrofit factors are
also assigned to the SCR reactor. The ammonia storage system was placed to
the south of unit 4 in a remote area having a low access/congestion factor.
Table 14.6.1-10 presents the estimated cost of retrofitting SCR at the Labadie
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 sorbert receiving/storage/preparation areas for both units were
located south of unit 4 in a relatively open area. Forty percent of the flue
14-122
-------
Tabte 14.6.1-10. NOx Control Cost Results for the Labadie Plant (Jine 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
I Removed
Effect.
Difficulty (MU)
(X)
Content
(SMM)
(S/kU)
(SMM)
(mills/kwh)
(X)
< tons/yr)
C$/ton)
Factor
CX>
LNC-OFA
1
1.00
621
59
2.5
1.3
2.1
0.3
0.1
25.0
2665
105.4
LNC-OFA
2
1.00
621
52
2.5
1.3
2.1
0.3
0.1
25.0
2349
119.5
LNC-OFA
3
1.00
621
58
2.5
1.3
2.1
. 0.3
0.1
25.0
2620
107.2
LNC-OFA
4
1.00
621
59
2.5
1.3
2.1
0.3
0.1
25.0
2665
105.4
LNC-OFA-C
1
1.00
621
59
2.5
1.3
2.1
0.2
0.1
25.0
2665
62.5
LNC-OFA-C
2
1.00
621
52
2.5
1.J
2.1
0.2
0.1
25.0
2349
71.0
LNC-OFA-C
3
1.00
621
58
2.5
1.3
2.1
0.2
0.1
25.0
2620
63.6
LNC-OFA-C
4
1.00
621
59
2.5
1.3
2.1
0.2
0.1
25.0
2665
62.5
SCR-3
1
1.52
621
59
2.5
94.8
152.7
32.8
10.2
80.0
8529
3846.1
SCR-3
2
1.52
621
52
2.5
100.8
162.4
33.6
11.9
80.0
7517
4472.5
SCR-3
3
1.16
621
58
2.5
89.2
143.7
30.7
9.7
80.0
8385
3664.3
SCR-3
4
1.16
621
59
2.5
85.5
137.9
30.1
9.4
80.0
8529
3531.8
SCR-3-C
1
1.52
621
59
2.5
94.8
152.7
19.2
6.0
80.0
8529
2253.4
SCR-3-C
2
1.52.
621
52
2.5
100.8
162.4
19.7
7.0
80.0
7517
2622.5
SCR-3-C
3
1.16
621
58
2.5
89.2
143.7
18.0
5.7
80.0
8385
2147.1
SCR-3-C
4
1.16
621
59
2.5
85.5
137.9
17.6
5-5
80.0
8529
2068.5
SCR-7
1
1.52
621
59
2.5
94.8
152.7
27.7
8.6
80.0
8529
3243.0
SCR-7
2
1.52
621
52
2.5
100.8
162.4
28.5
10.1
80.0
7517
3788.2
SCR-7
3
1.16
621
58
2.5
89.2
143.7
25.6
8.1
80.0
8385
3050.9
SCR-7
4
1.16
621
59
2.5
85.5
137.9
25.0
7.8
80.0
8529
2928.7
SCR-7-C
1
1.52
621
59
2.5
94.8
152.7
16.3
5.1
80.0
8529
1907.8
SCR-7-C
2
1.52
621
52
2.5
100.8
162.4
16.8
5.9
80.0
7517
2230.5
SCR-7-C
3
1.16
621
58
2.5
89.2
143.7
15.1
4.8
80.0
8385
1795.6
SCR-7-C
4
1.16
621
59
2.5
85.5
137.9
14.7
4.6
80.0
8529
1722.9
::>ussn:s::
S3i::s«sb:
SBESBSS
lassssssa
t»:ss»z
33SBSEBS
ihiisii:
33CB3338B33S3SE333
333====
33=33X133?
===33333
14-123
-------
gas for each unit passes through a separate duct to a retrofit ESP located
behind the chimney. This duct has a sufficient residence time (-4 seconds)
and can be used for DSD application with relatively easy retrofit. However,
the other 60 percent of the flue gas has a short residence time (1.5
seconds) before the old ESPs. Therefore, application of DSD would be more
difficult. Since the old ESP boxes are adequate in size for the 60 percent
flow (SCA > 270), E-S0X technology can be applied to remove S02 and
particulate. If upgrading of the ESPs is needed, a medium to high access/
congestion factor was applied. Table 14.6.1-11 presents a summary of the
site access/congestion factors for DSD and FSI technologies at the Labadie
steam plant. Table 14.6.1-12 presents the costs estimated to retrofit DSD
and FSI at the Labadie 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 Labadie plant. The boilers at the Labadie plant would not be considered
good candidates for AFBC retrofit because of their large size (620 MW) and
high capacity factors (>50 percent).
14.6.2 Meramec Steam Plant
The Meramec steam plant is located within St. Louis County, Missouri, as
part of Union Electric Company system. The plant contains four coal-fired
boilers with a total net generating capacity of 923 MW. Figure-14.6.2-1
presents the plot plan showing the location of all boilers and major
associated auxiliary equipment.
Table 14.6.2-1 presents operational data for the existing equipment at
the Meramec steam plant. All boilers burn low sulfur coal (1.1 percent
sulfur). Coal shipments are received by barge and conveyed to a coal
storage and handling area located south of the plant.
Particulate matter emissions are controlled with ESPs located behind
each boiler unit. Retrofit ESPs are added behind the chimneys/existing ESPs.
Fly ash from all units is wet sluiced to several large'on-site ponds located
14-124
-------
TABLE 14.6.1-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR LABADIE UNITS 1-4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (UNITS 1-3) HIGH
ESP UPGRADE (UNIT 4) MEDIUM
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 4714
ADDTTIONAL DUCT WORK (FT)
-------
Table 14.6.1-12. Suimary of DSO/FSt Control Costs for the Labadie Plant (June 1988 Dollars)
ai::::::::::
= S = = ===:
= = ===B=a=:
====*¦=
II
II
It
II
N
II
II
n
II
II
N
II
II
II
M
II
II
N
II
N
II
tf
II
i*S=*S= =
;as==a=s=3s=
II
II
II
II
II
II
II
hkjssss:
:5:«s::s
Technology
8oiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nurtoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Reooved
Removed
Effect.
Difficulty (HW>
(X)
Content
DSD+ESP
1
1.00
621
59
2.5
34.0
54.7
24.1
7.5
49.0
33714
714.4
DSD+ESP
2
1.00
621
52
2.5
34.0
54.7
22.6
8.0
49.0
29714
760.S
DSD+ESP
3
1.00
621
58
2.5
34.0
54.7
23.9
7.6
49.0
33143
720.3
DSD+ESP
4
1.00
621
59
2.5
33.3
53.6
23.9
7.5
49.0
33714
709.2
DSD+ESP-C
1
1.00
621
59
2.5
34.0
54.7
14.0
4.4
49.0
33714
413.8
DSO+ESP-C
2
1.00
621
52
2.5
34.0
54.7
13.1
4.6
49.0
29714
440.9
OSD+ESP-C
3
1.00
621
58
2.5
34.0
54.7
13.8
4.4
49.0
33143
417.3
DSD+ESP-C
4
1.00
621
59
2.5
33.3
53.6
13.8
4.3
49.0
33714
410.8
FSI+ESP-50
1
1.00
621
59
2.5
29.4
47.4
29.4
9.2
50.0
34650
848.5
FSI+ESP-50
2
1.00
621
52
2.5
29.4
47.4
26.9
9.5
50.0
30539
880.4
FSI+ESP-50
3
1.00
621
58
2.5
29.4
47.4
29.0
9.2
50.0
34062
852.6
FSI+ESP-50
4
1.00
621
S9
2.5
28. S
46.0
29.2
9.1
50.0
34650
842.0
FSI+ESP-50-C
1
1.00
621
59
2.5
29.4
47.4
17.0
5.3
50.0
34650
490.0
FSI+ESP-50-C
2
1.00
621
52
2.5
29.4
47.4
15.5
5.5
50.0
30539
508.7
FSI+ESP-50-C
3
1.00
621
58
2.5
29.4
47.4
16.8
5.3
50.0
34062
492.4
FS1+ESP-50-C
4
1.00
621
59
2.5
28.5
46.0
16.8
5.3
50.0
34650
486.1
FSI+ESP-70
1
1.00
621
59
2.5
.29.1
46.9
29.8
9.3
70.0
48510
614.9
FSI+ESP-70
2
1.00
621
52
2.5
29.1
46.9
27.3
9.6
70.0
42754
637.5
FSI+ESP-70
3
1.00
621
58
2.5
29.1
46.9
29.5
9.3
70.0
47687
617.8
FSI+ESP-70
4
1.00
621
59
2.5
28.3
45.6
29.6
'•2
70.0
48510
610.5
FSI+ESP-70-C
1
1.00
621
59
2.5
29.1
46.9
17.2
5.4
70.0
48510
355.0
FSI+ESP-70-C
2
1.00
621
52
2.5
29.1
46.9
15.7
5.6
70.0
42754
368.3
FS1+ESP-70-C
3
1.00
621
58
2.5
29.1
46.9
17.0
5.4
70.0
47687
356.7
FSI+ESP-70-C
4
1.00
621
59
2.5
28.3
45.6
17.1
5.3
70.0 .
48510
352.4
14-126
-------
Not to scale
FQD Waste Handling/Absorber Area
Llme/Llmestons Storage/Preparation Area
Figure 14.6.2-1. Meramec plant plot plan
14-127
-------
TABLE 14.6.2-1. MERAMEC STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
FIRING TYPE
INSTALLATION DATE
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2
3
4
137.5
289
350
10, 13
11
12
TANG
FWF
FWF
1953-54
1959
1961
1.3
1.3
1.3
12000
12000
12000
6.6 .
6.6
6.6 -
WET HANDLING
ON-SITE/PONDS
1-2 3 i
¦ 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
ESP
1981
1982
1981
0.001
0.004
0.006
99.6
99.5
99.8
0.9
0.9
0.9
295.6
608.4
790.5
600
1,165
1,450
492
522
545
330
360
365
14-128
-------
above the coal storage area to the north of the plant. Each unit is served
by its own chimney located between the ESPs.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 14.6.2-1 shows the general layout and location of the FGD control
system. The retrofit ESPs are located between the chimneys and coal storage
and handling area. To the east of unit 1, the area is congested with office
buildings, coal conveyors, and other buildings. The only available space for
absorber placement is to the west of unit 4. This area is presently one of
several ash pond sites.
For absorber placement, relocation is necessary for a plant road and ash
sluice pipe lines. Consequently, a factor of 8 percent is assigned to
general facilities. The lime and limestone storage/preparation and waste
handling areas are located to the west of the absorbers.
Retrofit Difficulty and Scope Adder Costs--
The site to the west of unit 4 is an open area with no major obstacle/
obstruction. Consequently, a low site access/congestion factor is assigned
to the absorber location for all units. On the other hand, due to space
constraints around the existing chimney from ESP placements and the coal
handling area, a high site access/congestion and underground obstruction
factor is assigned to all flue gas handling systems. Since unit 1 through 3
absorbers are placed at a distance from the open area (west of unit 4) with
extremely difficult access, the cost of a new chimney for units 1-3 is
included resulting in a shorter duct length for the L/LS-FGD case. Building
a new chimney is cost effective, since construction of outlet ductwork with
high congestion factors would be eliminated, and interference would also be
reduced with other equipment. For flue gas handling, duct lengths range from
400 feet for unit 3 to 650 feet for unit 1.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables 14.6.2-2 through 14.6.2-5.
The largest scope adder cost are construction of a new chimney and conversion
of the fly ash handling system from wet to dry. The overall retrofit factors
determined for the L/LS-FGD cases were medium (1.32 to 1.59).
14-129
-------
TABLE 14.6.2-2. SUMMARY Of RETROFIT FACTOR DATA FOR MERAMEC UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 600-1,000 600-1,000
ESP REUSE 1,000+
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000S) 1,225 NA 1,225
NEW CHIMNEY YES YES NO
ESTIMATED COST (1000$) 1,898 1,898 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.59 1.54
ESP REUSE CASE 1.72
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.59
NEW BAGHOUSE NA NA NA.
GENERAL FACILITIES (PERCENT) 8 8 8
14-130
-------
TABLE 14.6.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR MERAMEC UNIT 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 1,000+
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 1,225 NA 1,225
NEW CHIMNEY YES YES NO
ESTIMATED COST (1000$) 1,898 1,898 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.53 1.48
ESP REUSE CASE 1.63
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.59
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 8 8
14-131
-------
TABLE 14.6.2-4. SUMMARY OF RETROFIT FACTOR DATA FOR MERAMEC UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING HIGH HIGH
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
ESP REUSE 600-1,000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO YES
ESTIMATED COST (1000$) 2,377 NA 2,399
NEW CHIMNEY YES YES NO
ESTIMATED COST (1000S) 2,975 2,975 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.48 1.41
ESP REUSE CASE 1.52
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.59
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 8 8
14-132
-------
TABLE 14.6.2-5. SUMMARY OF RETROFIT FACTOR DATA FOR MERAMEC UNIT 4
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
300-600 300-600
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW
FLUE GAS HANDLING MEDIUM MEDIUM
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA NA
NEW 8AGH0USE NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NO
ESTIMATED COST (1000$) 2,887 NA
NEW CHIMNEY NO NO
ESTIMATED COST (1000$) 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.38 1.32
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE NA NA
NEW BAGHOUSE NA NA
LOW
' MEDIUM
, NA
300-600
NA
MEDIUM
NA
YES
2,887
NO
0
NO
1.36
NA
1.38
NA
GENERAL FACILITIES (PERCENT) 8
8
8
14-133
-------
The LSD with reused ESP is the only LSD-FGD technology which is
considered for Meramec plant since all units presently have large SCAs
(>490). For the LSD-FGD case, absorbers are located west of unit 4 in the
same manner as L/LS-FGD. A low site access/congestion factor is also
assigned to the absorber locations. For units 1 through 3, it is extremely
difficult to reach the upstream of the ESPs due to the close proximity of the
ESPs to each other, the chimneys, and the boiler house. As a result, high
site access/congestion and underground obstructions are assigned to the
unit 1-3 flue gas handling area. For unit 4, a medium site access/congestion
factor is assigned to the flue gas handling system. Duct lengths range, from
500 feet for unit 4 to 1,300 feet for unit 1. The retrofit factors
determined for LSD-FGD cases range from 1.36 to 1.72.
Table 14.6.2-6 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boilers 1-4.
The low cost control case reduces capital and annual operating costs by
more than 50 percent. The significant reduction in costs is primarily 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 S0^ 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 14.6.2-7.
14-134
-------
Table 14.6.2-6. Surmary of FGO Control Costs for the Karamee Plant (June 1988 Dollars)
*=**!===»===
II
N
n
u
H
it
N
II
:i33=:=:si
SX3I9S3S!
II
it
H
M
It
H
N
It
It
!i
II
II
M
II
II
It
It
II
It
II
:zzssssu
i2s:scsas363
uiisnsu
II
II
II
II
II
II
II
II
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
so2 cost
Ntflfcer
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
(tons/yr)
($/ton)
Factor
CX)
L/S FGD
1
1.59
138
10
1.3
55.8
406.0
20.3
168.6
90.0
1137
17865.3
l/S FGD
2
1.53
138
13
1.3
53.9
392.0
19.9
127.4
90.0
1478
13496.2
l/S FGO
3
1.48
289
11
1.3
80.5
278.7
29.1
104.4
90.0
2629
11059.7
l/S FCD
4
1.38
350
12
1.3
84.3
240.9
30.7
83.3
90.0
3473
3829.7
C/S FGD-C
1
1.59
138
10
1.3
55.8
406.0
11.9
98.7
90.0
1137
10455.a
L/S FGD-C
2
1.53
138
13
1.3
53.9
392.0
11.7
74.5
90.0
1478
7895.9
l/S FGD-C
3
1.48
289
11
1.3
80.5
278.7
17.0
61.1
90.0
2629
6473.9
l/S FGD-C
4
1.38
350
12
1.3
84.3
240.9
17.9
48.8
90.0
3473
5167.6
LC FGD
1-4
1.46
914
12
1.3
141.9
155.2
51.9
54.1
90.0
9069
5726.6
IC FGD-C
1-4
1.46
914
12
1.3
141.9
155.2
30.4
31.6
90.0
9069
3351.1
ISD+ESP
1
1.72
138
10
1.3
24.3
177.1
9.9
81.9
76.0
964
10234.8
ISO+ESP
2
1.63
138
13
1.3
23.3
169.2
9.6
61.5
76.0
1253
7679.9
ISO+ESP
3
1.52
289
11
1.3
40.4
139.9
14.9
53.5
76.0
2228
6688.7
ISO+ESP
4
1.36
350
12
1.3
43.9
125.5
16.2
44.0
76.0
2944
5492.3
ISD+ESP-C
1
1.72
138
10
1.3
24.3
177.1
5.8
47.8
76.0
964
5977.2
ISD+ESP-C
2
1.63
138
13
1.3
23.3
169.2
5.6
35.9
76.0
1253
4483.3
ISO+ESP-C
3
1.52
289
11
1.3
40.4
139.9
8.7
31.3
76.0
2228
3913.5
LSD+ESP-C
4
1.36
350
12
1.3
43.9
125.5
9.5
25.7
76.0
2944
3213.6
=====*«»
,3_s-_===s
¦aissssBss
rsssacss;
I* = I==»S
II
II
II
It
It
<1
II
:==s=======
II
II
IS
It
II
:==aa*====s
=========
14-135
-------
Table 14.6.2-7. Suwvary of CMt Snitching/Cleaning Costs for the Mcramec Plant (June 1988 Dollars)
It
II
II
II
II
II
II
II
II
II
II
II
========
=========:
;== = == = =:
sssisss:
= = =»=== = :
ssssacsa:
:=•==«==¦
t=:«5ii
:3IBM«3>ISS
isaatu
II
M
U
N
N
II
M
N
II
M
N
II
It
M
II
N
II
II
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 (MW)
(X)
Content
(S»l>
C*/kw>
CS/B**15
1
1.00
133
10
1.3
5.5
40.1
2.9
24.3
31.0
394
7437.1
CS/B*I15
2
1.00
138
13
1.3
5.5
40.1
3.4
21.8
31.0
512
6678.3
CS/B+S15
3
1.00
289
11
1.3
10.1
35.0
6.0
21.5
31.0
910
6579.0
CS/B+S15
4
1.00
350
12
1.3
11.9
34.1
7.5
20.5
31.0
1202
6279.5
CS/B+S15-C
1
1.00
m
10
1.3
5.5
40.1
1.7
14.1
31.0
394
4323.9
CS/B»t15-C
2
' 1.00
13a
13
1.3
5.5
40.1
2.0
12.7
31.0
512
3874.6
CS/B+S15-C
3
1.00
2S9
11
1.3
10.1
35.0
3.5
12.5
31.0
910
3819.3
CS/8*S15-C
4
1.00
350
12
1.3
11.9
34.1
4.4
11.9
31.0
1202
3642.2
CS/B+S5
1
1.00
13a
10
1.3
4.1
29.7
1.7
14.0
31.0
394
4273.8
CS/B+S5
2
1.00
13a
13
1.3
4.1
29.7
1.9
12.0
31.0
512
3661.7
CS/B'S5
3
1.00
289
11
1.3
7.1
24.7
3.2
11.3
31.0
910
3473.7
CS/B*$5
4
1.00
350
12
1.3
a.3
23.7
3.9
10.5
31.0
1202
3222.2
CS/B*$5-C
1
1.00
13a
10
1.3
4.1
29.7
1.0
8.2
31.0
394
2495.2
CS/B+S5-C
2
1.00
ua
13
1.3
4.1
29.7
1.1
7.0
31.0
512
2133.8
CS/B+15-C
3
1.00
289
11
1.3
7.1
24.7
1.8
6.6
31.0
910
2025.3
CS/B+S5-C
4
1.00
350
12
1.3
8.3
23.7
2.3
6.1
31.0
1202
1877.1
<1
11
II
II
H
11
II
(1
II
II
II
========
<1
II
II
II
II
II
41
It
II
issssass:
It
II
II
tt
II
II
II
========;
:ss£ti:x:
:=====*;
II
II
It
II
II
II
14-136
-------
NOx Control Technology Costs--
This section presents the performance and costs estimated for N0x
controls at the Meramec 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 for units 1 and
2 and LNB and SCR for units 3 and 4.
Low N0X Combustion-
Units 1 and 2 are dry bottom, tangential-fired boilers, rated at 138 MW
each; whereas, units 3 and 4 are dry bottom, front wall-fired boilers, rated
at 289 and 359 MW, respectively. The combustion modification technique
applied for this evaluation was OFA for units 1 and 2 and LNB for units 3 and
4. As Table 14.6.2-8 and 14.6.2-9 shows, the OFA N0x reduction performance
for units 1 and 2 was estimated to be 30 percent and the LNB N0X reduction
performance for units 3 and 4 was estimated to be 40 percent. Both reduction
performance levels were assessed by examining the effects of heat release
rates and furnace residence time through the use of the simplified N0X
procedures. Table 14.6.2-10 presents the cost of retrofitting OFA and LNB at
the Meramec boilers.
Selective Catalytic Reduction-
Tables 14.6.2-8 and 16.6.2-9 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
ESPs to the reactor and from the reactor to the chimney.
The SCR reactors were placed west of unit 4. As such, low site access/
congestion factors and underground obstruction factors were assigned to the
SCR reactor locations. For scope adders, cost for a new chimney was added to
unit 1-3 SCR reactors to reduce duct work interferences with other equipment.
Table 14.6.2-10 presents the estimated cost of retrofitting SCR at the Meramec
boilers.
14-137
-------
TABLE 14.6.2-8. SUMMARY OF NOx RETROFIT RESULTS FOR MERAMEC 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)
12.8
12.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
27.6
27.6
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
30
30
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
New Chimney (1000$)
1898
1898
Ductwork Demolition (1000$)
34
34
New Duct Length (Feet)
650
520
New Duct Costs (1000$)
5317
4253
New Heat Exchanger (1000$)
2261
2261
TOTAL SCOPE ADDER COSTS (1000$)
9510
8446
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
14-138
-------
TABLE 14.6.2-9. SUMMARY OF NOx RETROFIT RESULTS FOR MERAMEC 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)
17.1
15.4
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
68.2
71.4
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
40
40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
New Chimney (1000$)
2975
0
Ductwork Demolition (1000$)
60
71
New Duct Length (Feet)
400
440
New Duct Costs (1000$)
5052
5468
New Heat Exchanger (1000$)
3523
4013
TOTAL SCOPE ADDER COSTS (1000$)
11,160
9552
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
14-139
-------
Tabte 14.6.2-10. NOx Control Cost Results for the Meranec Plant (Jixv* 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NCx Cost
Nurtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MM) Content (VQO («/kW) {MM) (mitls/ktfh) (%)
-------
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for S(>2 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--
For units 1 and 2, the flue gas ducting travels from the outlet of the
old boxes around the chimney and over the new boxes. As such, there is
plenty of droplet drying time for DSD and humidification time for FSI. For
units 3 and 4, the flue gas ductwork leaves the outlet of the old boxes, goes
around the chimney and directly into the new boxes. These duct runs are
short and have a number of turns, thus making these units poor candidates for
DSD and humidification injection. However, the old boxes would be good
candidates for sorbent injection for the E-SO technology in conjunction with
A
retrofit advance particulate control technology. Tables 14.6.2-11 through
14.6.2-13 present a summary of the site access/congestion factors for DSD and
FSI technologies at the Meramec steam plant. Table 14.6.2-14 presents the
costs estimated to retrofit DSD and FSI at the Meramec 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 Meramec plant. The unit 1, 2, and 3 boilers at the
Meramec plant would be considered good candidates for AFBC retrofit because
of the small boiler sizes (<300 MW). Although unit 4 may not be a good
candidate because of its large boiler size (>300 MW), its low capacity factor
would indicate it may be a good candidate because there would be low
replacement power costs for downtime and heat rate improvement benefits may
be significant.
14-141
-------
TABLE 14.6.2-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MERAMEC UNITS 1-2
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$) 1225
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 34
TOTAL COST (1000$)
ESP UPGRADE CASE 1259
A NEW BAGHOUSE CASE . NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.59
NEW BAGHOUSE NA
14-142
-------
TABLE 14.6.2-12. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MERAMEC UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2399
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000S) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 60
TOTAL COST (1000$)
ESP UPGRADE CASE 2459
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.59
NEW BAGHOUSE NA
14-143
-------
TABLE 14.6.2-13. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MERAMEC UNIT 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 2887
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$) 70
TOTAL COST (1000$)
ESP UPGRADE CASE 2957
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS •
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.38
NEW BAGHOUSE NA
14-144
-------
Table 14.6.2*14. Surmary of DSO/FSI Control Costs for the Maranec Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Ntmber Retrofit
Siie
Factor Sulfur
Cost
Coat
Cost
Cost
Removed
I Removed
Effect.
Difficulty
Content
(MM)
(S/kU)
-------
14.6.3 Rush Island Steam Plant
The Rush Island steam plant is located within Jefferson County,
Missouri, and is part of the Union Electric Company system. The plant
contains two coal-fired boilers with a net generating capacity of 1,241 MW.
The plant is bounded by the Mississippi River to the east and by rolling
hills to the west. Figure 14.6.3-1 presents the plant plot plan showing the
location of both boilers and major associated auxiliary equipment.
Table 14.6.3-1 presents the operational data for the existing equipment
at the Rush Island plant. Both boilers burn low sulfur coal (1.2 percent
sulfur). Coal shipments are received by freight barge or railroad. The
coal is conveyed to a coal storage area south of the boilers.
Particulate matter emissions for both boilers are controlled with ESPs
located behind each unit. Ash from the units is wet sluiced to ponds
located southwest of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
Figure 14.6.3-1 shows the general layout and location of the FGD control
system. The absorbers for both units are located west of the unit 2 ESPs and
north of the coal storage handling areas. No demolition/relocation of
existing equipment/buildings would be required for the placement of the
absorbers; therefore, a factor of 5 percent was assigned to general
facilities.
Retrofit Difficulty and Scope Adder Costs--
The FGD equipment was located in a low site access/congestion area. Two
site locations are possible for the placement of the unit 1 and 2 absorbers.
One location is between the coal pile and units 1 and 2, on either side of
the coal conveyor, close to the common chimney. The second location is to
the west of unit 2 and to the north of the coal storage and handling area.
The first location initially was considered for absorber placement since it
was thought that possible future units would be constructed to the west of
unit 2. However, plant personnel indicated that no additional units would be
added to the plant. As such, the second location to the west of the plant
was used for absorber placement in this study due to the large available
14-146
-------
Mississippi River
Pi pas
Area
l/A FQD Waste Handling/Absorber Area
' ' A Lime/Limestone Storage/Preparation Area
Not to scale
Figure 14.6.3-1. Rush Island plant plot plan
14-147
-------
TABLE 14.6.3-1. RUSH ISLAND STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 620.5
CAPACITY FACTOR (PERCENT) 42, 59
INSTALLATION DATE 1976-77
FIRING TYPE . TANGENTIAL
COAL SULFUR CONTENT (PERCENT) 1.2
COAL HEATING VALUE (BTU/LB) 10,600
COAL ASH CONTENT (PERCENT) 8.2
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1976-77
EMISSION (LB/MM BTU) 0.006
REMOVAL EFFICIENCY 99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.0
SURFACE AREA (1000 SQ FT) 933.1
GAS EXIT RATE (1000 ACFM) 3340
SCA (SQ FT/1000 ACFM) 279
OUTLET TEMPERATURE (°F) 270
14-148
-------
space. Space between the units and the coal handling area is limited, which
would result in a medium site access/congestion factor. By contrast, to the
west of unit 2 is an open area with no obstructions. Low site access/
congestion factors have been assigned to this location. For the flue gas
handling system a low site access/ congestion factor was assigned to both
units since space is available behind the chimney for the duct runs.
The major scope adjustment costs and estimated retrofit factors for the
FGD technologies are presented in Tables 14.6.3-2 and 14.6.3-3. The largest
scope adder for Rush Island was the conversion of the fly ash conveying
system from wet to dry for both boilers (conventional L/LS-FGD and LSD
technologies). It was assumed that the fly ash would be necessary to
stabilize the scrubber sludge waste resulting from conventional L/LS-FGD
application and to prevent plugging of the sluice lines in the LSD-FGD
system (for the ESP-Reuse case). The conversion of wet to dry ash handling
is not necessary for forced oxidation L/LS-FGD. The overall retrofit
factors estimated for the L/LS-FGD cases were moderate (1.25 to 1.39).
The LSD with reused ESP is the only LSD-FGD technology considered for
both units since both boilers have moderate size ESPs (SCA >270). The LSD
absorbers are placed in a similar location, as in the case of L/LS-FGD, with
the same site access/congestion and underground obstruction factors being
assigned. For the unit 1 flue gas handling, medium site access/congestion
and underground obstruction factors are assigned. These factors represent
access difficulty to the upstream of the unit 1 ESPs and congestion created
by the unit 1 ESPs. To access the unit 1 ESPs, duct runs pass over the
unit 2 ESPs, creating congestion and access difficulties. For unit 2,
medium site access/congestion and underground factors are assigned to flue
gas handling. Flue gas from the boiler is divided into two duct runs prior
to the ESPs. It is relatively easy to access the outer duct run upstream of
the unit 2 ESPs. By contrast, access to the inner duct run is difficult.
Therefore, a median of the two access difficulties is used in this study,
and a medium site access/congestion factor is assigned to the unit 2 flue
gas handling system for LSD-FGD. Duct runs of 900 and 560 feet are required
for units 1 and 2, respectively.
Table 14.6.3-4 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs and ash handling systems for
14-149
-------
TABLE 14.6.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR RUSH ISLAND UNIT I
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW MEDIUM
FLUE GAS HANDLING LOW HIGH
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA .
DUCT WORK DISTANCE (FEET) 600-1,000 600-1,000
ESP REUSE 600-1,000
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA . NA
SCOPE ADJUSTMENTS
WET TO DRY YES ' NO YES
ESTIMATED COST (1000$) 4,823 0 4,823
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.39 1.34
ESP REUSE CASE 1.53
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.38
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
14-150
-------
TABLE 14.6.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR RUSH ISLAND 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)
300-600
300-600
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$)
4,823
0
4,823
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
. NO
RETROFIT FACTORS
FGD SYSTEM
1.31
1.25
ESP REUSE CASE
1.36
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.38
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
5
5
14-151
-------
Table 14.6.3-4. Suimary of FGO Control Costs for the Rush Island Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
HiMber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
boilers 1 and 2. The low cost control case reduces capital and annual
operating costs due to the benefits elimination of spare scrubber modules,
optimization of scrubber module size, and use of organic acid additives.
Coal Switching Costs-
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined.
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 14.6.3-5.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0x
controls at the Rush 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 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 621 MW
each. The combustion modification technique applied for this evaluation was
OFA. As Table 14.6.3-6 shows, the OFA N0X reduction performance for units 1
and 2 was estimated to be 23 percent. This reduction performance level was
assessed by examining the effects of volumetric heat release rate and furnace
residence time through the use of the simplified N0X procedures. No
information was available in Power to calculate the boiler/waterwall surface
area heat release rate for determining the effect of this parameter on N0X
14-153
-------
Table 14.6.3-5. Suitnary of Coal Switching/Cleaning Costs for the Rush Island Plant e 1988 Oollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 S02 Cost
Nuttoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW) (X) Content (SHO <*/kW) (SKN) (millsAwh) (tons/yr)
-------
TABLE 14.6.3-6. SUMMARY OF NQx RETROFIT RESULTS FOR RUSH ISLAND
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
1
TANG
2
TANG
TYPE OF NOx CONTROL
OFA
OFA
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
9.1
9.1
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
2.63
2.63
ESTIMATED NOx REDUCTION (PERCENT)
23
23
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
106
106
New Duct Length (Feet)
160
160
New Duct Costs (1000$)
2,317
2,317
New Heat Exchanger (1000$)
5,581
5.581
TOTAL SCOPE ADDER COSTS (1000$)
8,004
8,004
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
14-155
-------
reduction. Table 14.6.3-7 presents the costs of retrofitting OFA at the
Rush Island boilers.
Selective Catalytic Reduction--
Table 14.6.3-6 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 ductwork demolition, new flue gas
heat exchanger, and new flue gas duct runs from the ESPs to the reactor and
from the reactor to the chimney.
The SCR reactors for units 1 and 2 were located directly behind (south)
their respective ESPs, to the north of the coal pile in a low congestion
area with easy access. Both reactors are assumed to be in areas with high
underground obstructions. The ammonia storage system is placed to the west
of unit 2 in a remote area having a low access/congestion factor. Both SCR
reactors were assigned low access/congestion factors, since they were in an
area surrounded on one side by the ESPs. 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.
Table 14.6.3-7 presents the estimated cost of retrofitting SCR at the Rush
Island 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 for both units were
located south of the boilers in a similar layout to that of LSD-FGD. There
is not sufficient flue gas ducting residence time (-1 second) between the
boilers and ESPs. However, all ESPs should be good candidates for the E-S0X
technology because of the overall good particulate removal performance
currently being achieved. The major scope adder for OSD and FSI would be
14-156
-------
Table 14.6.3-7. NOx Control Cost Results for the Rush Island 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 (MU) (X) Content (»M) <*/kU) (*•»> (mills/lew*) (%) (tons/yr) («/ton>
Factor (X)
INC-OFA 1 1.00 621 42 1.2 1.3 2.1 0.3 0.1 23.0 1879 149.5
IXC-OFA 2 1.00 621 S9 1.2 1.3 2.1 0.3 0.1 23.0 2639 106.4
INC-OFA-C 1 1.00 621 42 1.2 1.3 2.1 0.2 0.1 23.0 1879 88.7
LMC-OFA-C 2 1.00 621 59 1.2 1.3 2.1 0.2 0.1 23.0 2639 63.2
SCR-3 1 1.16 621 42 1.2 72.7 117.1 27.2 11.9 80.0 6534 4162.5
SCR-3 2 1.16 621 59 1.2 72.7 117.2 27.8 8.7 80.0 9179 3028.5
SCR-3-C 1 1.16 621 42 1.2 72.7 117.1 15.9 7.0 80.0 6534 2434.7
SCH-3-C 2 1.16 621 59 1.2 72.7 117.2 16.3 5.1 80.0 9179 1770.6
SCR-7 1 1.16 621 42 1.2 72.7 117.1 22.0 9.6 80.0 6534 3367.7
SCR-7 2 1.16 621 59 1.2 72.7 117.2 22.6 7.0 80.0 9179 2462.7
SCR-7-C 1 1.16 621 42 1.2 72.7 117.1 12.9 5.7 80.0 6534 1979.4
SCR-7-C 2 1.16 621 59 1.2 72.7 117.2 13.3 4.1 80.0 9179 1446.5
14-157
-------
the conversion of the fly ash from wet to dry for reusing the ESPs.
Table 14.6.3-8 presents a summary of site access/congestion factors, scope
adders, and retrofit factors for DSD and FSI technologies at the Rush Island
plant. The scope adder costs presented are on a dollar per boiler basis.
Table 14.6.3-9 presents the costs estimated to retrofit DSD and FSI at the
Rush 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 Rush Island plant. None of the boilers at Rush Island
would be considered good candidates for AFBC retrofit and AFBC or coal
gasification/combined cycle repowering because of their large boiler sizes
(621 MW).
14.6.4 Sioux Steam Plant
The Sioux steam plant is located along the Mississippi River within
St. Charles County, Missouri, as part of Union Electric Company system. The
plant contains two coal-fired boilers with a total gross generating capacity
of 1100 MW. Figure 14.6.4-1 presents the plant plot plan showing the
location of all boilers and major associated auxiliary equipment.
Table 14.6.4-1 presents operational data for the existing equipment at
the Sioux steam plant. All boilers burn medium sulfur coal (2.5 percent
sulfur), which is blend of two types, Illinois high-sulfur and western
low-sulfur. Coal shipments are received by railroad and conveyed to a coal
storage and handling area located east of the plant.
Particulate matter emissions for the boilers are controlled with ESPs
located behind each unit. Fly ash from all units is wet sluiced to ponds
located south of the plant. A very large on-site waste disposal area is
available.
14-158
-------
TABLE 14.6.3-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR RUSH ISLAND UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 4823
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 118
TOTAL COST (1000$)
ESP UPGRADE CASE 4941
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.38
NEW BAGHOUSE NA
14-159
-------
Table 14.6.3-9. Suimary of DSO/FSI Control Costs for the Rush island Plant (Jme 1980 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty Content (MO (S/kW> (H«> (Mills/kwh) (*} (tons/yr) (»/ton)
Factor
-------
Mississippi River
Figure 14.6.4-1. Sioux plant plot plan
14-161
-------
TABLE 14.6.4-1. SIOUX STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 550
CAPACITY FACTOR (PERCENT) 43, 33
FIRING TYPE CYCLONE
INSTALLATION DATE 1967 & 1968
COAL SULFUR CONTENT (PERCENT) 1.7
COAL HEATING VALUE (BTU/LB) 11,245
COAL ASH CONTENT (PERCENT) 7.1
FLY ASH SYSTEM WET
ASH DISPOSAL METHOD ON-SITE
STACK NUMBER 1-2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1973
EMISSION (LB/MM BTU) 0.08
REMOVAL EFFICIENCY 98.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.5
SURFACE AREA (1000 SQ FT) 536.4
GAS EXIT RATE (1000 ACFM) 2000
SCA (SQ FT/1000 ACFM) 268
OUTLET TEMPERATURE (*F) 310
14-162
-------
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 14.6.4-1 shows the general layout and location of the FGD control
system. The absorbers for L/LS-FGD and LSD-FGD for unit 1 would be located
north of the water treatment area beside the employee parking area, northeast
of unit 1. The absorbers for unit 2 would be located southeast of unit 2
beside the railroad and south of the ESPs, which is presently a part of the
future ash pond site. In the placing of the unit 1 absorbers, relocation is
necessary for part of the parking lot and storage area. As a result, a factor
of 8 percent was assigned to general facilities. No major relocation or demo-
lition would be required for unit 2; therefore, a factor of 5 percent was
assigned to general facilities. The lime and limestone storage/preparation
area and waste handling area would be located south of unit 2 {below the unit
2 absorbers), which is presently the future ash pond site.
Retrofit Difficulty and Scope Adder Costs-
Even though space is available for the unit 1 absorbers between the coal
storage area (west) and unit 1 adjacent to the chimney (east), major reloca-
tion and demolition would be required for the water treatment area and water
storage tank. Therefore, the site north of the water treatment area beside
the parking lot (east) and northeast of unit 1 was designated for the unit 1
absorbers. This site is between the railroad, parking area, and water
treatment area.
There are two possible site locations for the unit 2 absorber. For the
first location, space is available between the coal pile and unit 2, east of
the unit 2 ESPs and south of the coal conveyor. The second possible location
is in an open area south of unit 2 and what is presently the future ash pond
site. For this study, the latter location has been designated for the unit 2
absorbers due to its spacious area. However, it is possible that a future
unit 3 may be placed at this site and, if so, the absorber would then need to
be placed at the first location as described above.
The absorber locations for both units were assigned a low site access/
congestion factor because they were located in relatively open areas with no
major obstacles/interferences and no major underground obstruction.
For flue gas handling, short to moderate duct runs would be required for
both units for L/LS-FGD cases. A low site access/congestion factor was
14-163
-------
assigned to the flue gas handling system due to easy access to the chimneys
with no major obstructions.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables 14.6.4-2 and 14.6.2-3. The
largest scope adder cost is the conversion of the fly ash handling system from
wet to dry. The overall retrofit factors determined for the L/LS-FGD cases
ranged from low to moderate (1.23 to 1.36).
The LSD with reused ESP was the only LSD-FGD technology considered for
both units because of boilers presently having large SCAs (>260). For flue
gas handling for LSD cases, moderate duct runs would be required and a medium
site access/congestion factor was assigned. This was due to the site access/
congestion created by the ESPs to route flue gas from the boilers to the
absorbers and back to the ESPs. The retrofit factors determined for the LSD
technology case ranged from 1.35 to 1.39.
Table 14.6.4-4 presents the cost estimates for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boilers 1 and 2.
The low cost control case reduces capital and annual operating costs by
25 to 55 percent. The reduction in costs is primarily 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. This is particularly true for cyclone boilers; as such, CS was
not evaluated.
N0X Control Technology Costs--
This section presents the performance and costs estimated for NO^
controls at the Sioux steam plant. These controls include NGR and SCR. NGR
was the LNC modification control for the two Sioux units because LNB and OFA
are not applicable to cyclone-fired boilers. SCR was considered to be
applicable to al1 coal-fired.boiler types.
14-164
-------
TABLE 14.6.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR SIOUX UNIT 1
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
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
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
YES
ESTIMATED COST (1000$)
4,232
NA
4,232
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.36
1.29
ESP REUSE CASE
1.39
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.59
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 8
8
8
14.-165
-------
TABLE 14.6.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR SIOUX UNIT 2
F60 TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
LOW
FLUE GAS HANDLING
LOW
LOW
ESP REUSE CASE
MEDIUM
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
300-600
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY .
YES
NO
YES
ESTIMATED COST (1000$)
4,232
NA
4,232
NEW CHIMNEY
NO
NO
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.30
1.23
ESP REUSE CASE
1.35
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.34
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5
5
5
14-166
-------
Table 14.6.4-4. Suimary of FGD Control Costs for the Sioux Plant (Ji*ie 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 SC2 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Reflioved Removed Effect.
Difficulty (MM) (X) Content <*MH> <*/kW) (mills/kuh) (*) (tons/yr) (i/tor)
Factor (X)
L/S FGD 1
US FGD 2
L/S FGD-C 1
L/S FGD-C 2
LC FGD 1-2
LC FGO-C 1-2
LSD-ESP 1
LSD+ESP 2
LSD*ESP-C 1
LSD*ESP-C 2
1.36 550 43
1.30 550 33
1.36 550 43
1.30 550 33
1.33 1100 38
1.33 1100 38
1.39 550 43
1.35 550 33
1.39 550 43
1.35 550 33
1.7 117.1 212.9
1.7 110.7 201.3
1.7 117.1 212.9
1.7 110.7 201.3
1.7 165.7 150.7
1.7 165.7 150.7
1.7 63.6 115.6
1.7 60.3 109.6
1.7 63.6 115.6
1.7 60.3 109.6
51.9 25.0 90.0
46.7 29.6 90.0
30.3 14.6 90.0
27.3 17.3 90.0
75.9 20.7 90.O
44.2 12.1 90.0
26.2 12.6 76.0
24.0 15.2 76.0
15.3 7.4 76.0
14.0 8.9 76.0
27680 1876.5
21016 2223.8
27680 1094."
21016 1297.7
48696 1558.5
48696 908.2
23467 1117.6
17817 1346.9
23467 652.4
17817 786.8
14-167
-------
Low NO Combustion--
A-
Table 14.6.4-5 presents the NOx reduction performance and costs of NGR
for each unit. It also shows that the NGR NOx reduction performance for both
units was estimated to be 60 percent. Table 14.6.4-6 presents the costs of
retrofitting NGR at the Sioux boilers.
Selective Catalytic Reduction--
Table 14.6.4-5 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 ESPs to the
reactor and from the reactor to the chimney.
The SCR reactor for unit 1 was located north of the ESPs for unit 1 and
east of the parking lot in a low congestion area with easy access. The SCR
reactor for unit 2 was located south of the ESPs for unit 2 in a low
congestion area with easy access. Therefore, both reactors were assigned a
low site access/congestion factor. Table 14.6.4-6 presents the estimated
costs of retrofitting SCR at the Sioux boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for S0£ control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately from
the coimercial ized 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 Inject ion--
The sorbert receiving/storage/preparation areas for both units were
located south of unit 2 in a relatively open area in a similar fashion as
LSD-FGD (south of the unit 2 absorbers). There is sufficient flue gas
ducting residence time (2 seconds) between the boilers and the retrofit ESPs.
Additionally, developments in particulate control technology may be used to
modify the existing ESP by combining advanced ESP technology and spray dryer
technology to remove SOg and particulate (E-S0x technology). Since both
units have adequate ESP sizes (SCA >260), it was assumed that DSD and FSI
14-168
-------
TABLE 14.6.4-5. SUMMARY OF NOx RETROFIT RESULTS FOR SIOUX
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
1
CY
2
CY
TYPE OF NOx CONTROL
NGR
NGR
VOLUMETRIC NEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
97
97
New Duct Length (Feet)
560
440
New Duct Costs (1000$)
7558
5939
New Heat Exchanger (1000S)
5184
5184
TOTAL SCOPE ADDER COSTS (1000$)
12,839
11,220
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
14-169
-------
Table 14.6.4-6. NOx Control Cost Results for the Sioux Plant (Jine 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx Nix Cost
Ninfcer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty ON) (X) Content
Factor (X)
MGR
MCR
1.00
1.00
550
550
43
33
8.0
8.0
14.5
14.5
11.7
9.1
5.6
5.8
60.0
60.0
10298
7819
1138.5
1170.1
MGR-
NGR-
1.00
1.00
550
550
43
33
8.0
8.0
14.5
14.5
6.8
5.3
3.2
3.3
60.0
60.0
10298
7819
655.7
674.9
SCR
SCR
1.16
1.16
550
550
43
33
71.5
69.8
130.0
127.0
26.3
25.5
12.6
16.1
80.0
80.0
13731
10425
1915.6
2445.9
SCR-3-C
SCR-3-C
1.16
1.16
550
550
43
33
71.5
69.8
130.0
127.0
15.4
14.9
7.4
9.4
80.0
80.0
13731
10425
1120.9
1431.4
SCR
SCR
1.16
1.16
550
550
43
33
71.5
69.8
130.0
127.0
21.7
20.9
10.4
13.2
80.0
80.0
13731
10425
1583.3
2008.2
SCR-7-C
SCR-7-C
1.16
1.16
550
550
43
33
71.5
69.8
130.0
127.0
12.8
12.3
6.1
7.8
80.0
80.0
13731
10425
930.5
1180.6
14-170
-------
with ESP reuse is applicable. Table 14.6.4-7 presents a summary of the site
access/congestion factors for DSD and FSI technologies at the Sioux steam
plant. For upgrading the ESPs, a high access/congestion factor was assigned
to unit 1 and a medium factor was assigned to unit 2. Table 14.6.4-8
presents the costs estimated to retrofit DSD and FSI at the Sioux plant.
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 Sioux plant. The boilers at the Sioux plant would not
be considered good candidates for AFBC retrofit because of the large
sizes (550 MW).
14-171
-------
TABLE 14.6.4-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR SIOUX UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH/MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (lOOOS) 4,267
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 107
TOTAL COST (1000$)
ESP UPGRADE CASE 4,374
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.59, 1.34
NEW BAGHOUSE NA
14-172
-------
Table 14.6.4-8. Surmary of DSO/FSI Control Costs for the Sioux Plant (June 1988 Dollars)
s32::s:]::::9as:s::c3:ss::asi3:assa:ssasi3:s3isi:s:ssss:::sass»t:sasss«a::ans::3sis:s2 Content <»«) («/kW) (SMM) (mi 1 Is/kwh) (X) (to«s/yr) (»/ton)
Factor (X)
DSD+ESP
DSDfESP
DSD»6SP-C
DSO-ESP-C
FSl+ESP-SO
FSI+ESP-50
FSI*ESP-50-C
FSI*ESP-50-C
fSI*ESP-70
FS1+ESP-70
FSl*ESP-70-C
FSI*ESP-70-C
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
550
550
550
550
550
550
550
550
550
550
550
550
43
33
43
33
43
33
43
33
43
33
43
33
23.8
22.9
23.8
22.9
30.6
26.9
30.6
2B.9
30.5
28.9
30.5
28.9
43.2
41.7
43.2
41.7
55.6
52.6
55.6
52.6
55.4
52.5
55.4
52.5
13.8
12.3
B.O
7.2
18.3
15.6
10.6
9.1
18.5
15.7
10.7
9.1
6.6
7.8
3.8
4.5
8.8
9.9
5.1
5.7
8.9
10.0
5.2
5.8
49.0
49.0
49.0
49.0
50.0
50.0
50.0
50.0
70.0
70.0
70.0
70.0
14963
11361
14963
11361
15378
11676
15378
11676
21529
16346
21529
16346
919.6
1084 .-8
534.0
630.5
1192.4
1336.4
692.1
776.8
860.3
963.1
499.3
559.7
ssssisssrsxatss
14-173
-------
SECTION 15.0 MISSISSIPPI
15.1 MISSISSIPPI POWER COMPANY
15.1.1 V.J. Daniel Jr. Steam Plant
Both units at this plant fire a low sulfur coal with an emission rate
less than 1.2 lb S02/MBtu (1971 NSPS unit). Although retrofit factors for
FGD were developed, costs were not because it is unlikely that these units
would be scrubbed. Likewise, retrofit factors and costs were not estimated
for sorbent injection because of the low sulfur coal and small ESPs. Since
both units have OFA systems, the only N0X control technology considered was
SCR.
TABLE 15.1.1-1. V. J. DANIEL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 500
CAPACITY FACTOR (PERCENT) 49,37
INSTALLATION DATE 1977,1981
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) NA
OVER FIRE AIR YES
COAL SULFUR CONTENT (PERCENT) 0.5
COAL HEATING VALUE (BTU/LB) 11800
COAL ASH CONTENT (PERCENT) 7.8
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/ON-SITE
STACK NUMBER 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1977, 1981
EMISSION (LB/MM BTU) 0.04
REMOVAL EFFICIENCY 99.3
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.6
SURFACE AREA (1000 SQ FT) 201.6
GAS EXIT RATE (1000 ACFM) 2390
SCA (SQ FT/1000 ACFM) 84
OUTLET TEMPERATURE (°F) 622
15-1
-------
TABLE 15.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR V. J. DANIEL
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
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$)
3968
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.42
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.31
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for units 1
and 2 would be located south of the common chimney, beyond
the coal conveyor.
15-2
-------
TABLE 15.1.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR V. J. DANIEL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE NA
TYPE OF NOx CONTROL NA
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE NA
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 90
New Duct Length (Feet) 200
New Duct Costs (1000$) 2541
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE 2632
COMBINED CASE 3963
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Hot side SCR reactors for units 1 and 2 would be located
behind the common chimney for units 1 and 2.
15-3
-------
Table 15.1.1-4. MOx Control Cost Results for the V. J. Osniel Plant (Jine 1968 Dollars)
sssissxmaissisiiisBBiiiisiassiisssisicsiiutaiiBBiasiBaauaiiBiisasaiuiiiNsitnaiiiisiBvsisKsiaiiiiiisiBisas
Technology Boiitr Main Boiler Capacity Coal Capital Capital Annual Annual MOx NOx NOx Cost
Nuifeer Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed
R moved
Effect.
Difficulty (MU>
U)
Content
(SMM)
(t/kU)
CUM)
(mf Us/kMti)
(X)
(tons/yr)
-------
15.1.2 Jack Watson Steam Plant
The Jack Watson Steam Plant is located in Harrison County, Mississippi,
as part of the Mississippi Power Company system. The plant contains two
coal-fired boilers with a total gross generating capacity of 750 MW.
Tables 15.1.2-1 through 15.1.2-10 summarize the plant operational data and
present the S02 and N0X control cost and performance estimates.
TABLE 15.1.2-1. JACK WATSON STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3 4 5
75 112 250 500
53 70
1957,60 1962 1968 1973
TANGENTIAL OPPOSED WALL
PETROLEUM NA 272
BURNING NO NO
2.4
12300
8.5
WET DISPOSAL
PONDS/ON-SITE
4 5
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 (4F)
ESP
ESP
1968
1973
0.07
0.06
98
99
3.7
3.7
NA
NA
NA
NA
305
305
270
327
15-5
-------
TABLE 15.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR WATSON 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 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$) 2132 NA 2132
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.57 NA
ESP REUSE CASE 1.56
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW. BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
* L/S-FGD and LSD-FGD absorbers for unit 4 would be located
southwest of the unit 4 chimney, beyond the coal conveyor.
15-6
-------
TABLE 15.1.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR WATSON UNIT 5 *
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
MEDIUM
LOW
300-600
NA
NA
YES
3968
NO
0
NO
1.48
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
MEDIUM
MEDIUM
NA
300-600
NA
MEDIUM
NA
YES
3968
NO
0
NO
1.51
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 5
* L/S-FGD and LSD-FGD absorbers for unit 5 would be located
north of the unit 5 chimney.
15-7
-------
Table 15.1.2-4. Sumary of FGD Control Costs for the Watson Plant (June 1988 Dollars)
ssss=asass*==as
:as:2Bs:ata:ass«s
:tasssm:ssxr«a
MBsaaisssaisssscssssasss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Ninber Retrofit Size Factor Sulfur cost Cost Cost Cost Rtmoved Removed Effect.
Difficulty (HW) (X) Content (»«> (SAW) (SUM) (miIIs/kwh) (X) (tons/yr) (S/ton)
Factor (X)
l/S FGO 4 1.57 250 53 2.4 81.6 326.3 33.6 29.0 90.0 19661 1709.9
L/S FGO 5 1.48 500 70 2.4 112.9 225.8 54.0 17.6 90.0 51934 1039.9
l/S FGD-C
L/S FG0-C
LC FGO
LC FGD-C
4
5
4-5
4-5
1.57 250
1.46 500
1.51
1.51
750
750
53 2.4 81.6 326.3 19.6 16.9 90.0 19661 998.3
70 2.4 112.9 225.8 31.4 10.3 90.0 51934 605.5
64 2.4 126.9 169.1 64.7 15.4 90.0 712Z5 908.2
64 2.4 126.9 169.1 37.6 8.9 90.0 71225 528.3
LS0*£SP
LSD*ESP
1.56 250 53 2.4 40.7 162.8 17.2 14.8 73.0 16035 1072.3
1.51 500 70 2.4 67.0 134.0 31.6 10.3 76.0 44029 716.7
IS0*ESP-C 4 1.56 250 53 2.4 40.7 162.8 10.0 8.6 73.0 16035 625.8
LSD*ESP-C 5 1.51 500 70 2.4 67.0 134.0 18.4 6.0 76.0 44029 417.4
15-8
-------
Table 15.1.2-5. Sunmary of Coal SwItching/Cleaning Costs for the Watson Plant CJine 1988 dollars)
bibb Bissau:
sntBiinitisBiBtaii
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nuitoer Retrofit Siie Factor Sulfur Cost Cost Cost
Difficulty (MM) (X) Content (IMM) (S/kU) (tMM)
Factor (X)
Annual S02 S02 $02 Cost
Cost Removed Removed Effect,
(¦ills/kuh) (X) Ctons/yr) (S/ton)
CS/B+»15
CS/8+S15
1.00
1.00
250
500
53
70
2.4
2.4
8.8
16.1
35.1
32.2
17.3
43.6
14.9
14.2
62.0
62.0
13464
35566
1282.4
1225.7
CS/B»$15-C
CS/B+J15-C
1.00
1.00
250
500
53
70
2.4
2.4
8.8
16.1
35.1
32.2
9.9
25.0
8.6
8-2
62.0
62.0
13464
35566
737.
704.
CS/B+B5
CS/B*»5
1.00
1.00
250
500
53
70
2.4
2.4
6.2
10.9
24.8
21.6
7.2
17.4
6.2
5.7
62.0
62.0
13464
35566
536.
488,
CS/B*S5-C
CS/B*S5-C
1.00
1.00
250
500
53
70
2.4
2.4
6.2
10.9
24.8
21.8
4.2
10.0
3.6
3.3
62.0
62.0
13464
35566
309.
281.
15-9
-------
TABLE 15.1.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR WATSON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
FIRING TYPE
OWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
FURNACE VOLUME (1000 CU FT)
NA
272
BOILER INSTALLATION DATE
1968
1973
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
40
37
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
54
90
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1694
2541
New Heat Exchanger (1000$)
3230
4895
TOTAL SCOPE ADDER COSTS (1000$)
4977
7527
RETROFIT FACTOR FOR SCR
1.34
1.16
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for units
behind their respective chimneys.
4 and
5 would be located
15-10
-------
Table 15.1.2-7. MO* Control Cost Results for the Uatson Plant (Jixte 1988 Dollars)
ininiisiii»maHsiiiiiaBiiiii>HiiiiiiiiimmiBSiiixHa::«33xi::«»li3::i«iiic::3iiias£::tiiH«=>SHiaB
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NO* NO* Cost
Nuftoar Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (SMM) (mills/lcnh> (tons/yr) (»/ton>
Factor (X)
LNC-INB 4 1.00 250 53 2.4 3.7 14.7 0.8 0.7 40.0 1961 397.8
LNC-LNB 5 1.00 500 70 2.4 4.9 9.7 1.0 0.3 37.0 4790 214.7
LNC-INB-C 4 1.00 250 53 2.4 3.7 14.7 0.5 0.4 40.0 1961 236.3
INC-LNB-C 5 1.00 500 70 2.4 4.9 9.7 0.6 0.2 37.0 4790 127.6
SCS-3 4 1.34 250 53 2.4 39.4 157.5 13.2 11.4 80.0 3921 3366.3
SCR*3 5 1.16 500 70 2.4 62.2 124.4 23.1 7.5 80.0 10357 2228.B
SCS-3-C 4 1.34 250 53 2.4 39.4 157.5 7.7 6.7 80.0 3921 1973.7
SCR-3-C 5 1.16 500 70 2.4 62.2 124.4 13.5 4.4 80.0 10357 1303.9
SCR-7 4 1.34 250 53 2.4 39.4 157.5 11.2. 9.6 80.0 3921 2844.3
SCR-7 5 1.16 500 70 2.4 62.2 124.4 19.0 6.2 80.0 10357 1833.6
SCR-7-C 4 1.34 250 53 2.4 39.4 157.5 6.6 5.7 80.0 3921 1674.6
SCR-7-C 5 1.16 500 70 2.4 62.2 124.4 11.2 3.6 80.0 10357 1077.4
sssssazsitssssisiBsssiBsiBfssistisstsaisBBssaiisississiissBsaaiBaitiistiiiiiisiiiiiiiMiitiaatsssvsiivssssssasi:
15-11
-------
TABLE 15.1.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR WATSON 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$) 2132
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) . NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 59
TOTAL COST (1000$)
ESP UPGRADE CASE 2191
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
A medium duct residence time exists between unit 4 and the unit 4
ESPs. A high factor was assigned to ESP upgrade due to the
conjestion around the unit 4 tSPs.
15-12
-------
TABLE 15.1.2-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR WATSON UNIT 5
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 3968
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$ 100
TOTAL COST (1000$)
ESP UPGRADE CASE 4068
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
A medium duct residence time exists between unit 5 and the unit
5 ESPs. A medium factor was assigned to ESP upgrade since the
ESPs are somewhat conjested.
15-13
-------
Table 15.1.2-10. Smmary of DSD/FS1 Control Costs for the Watson Plant (June 1988 Dollars)
X ;i3i|xi;3CaC3| 3ISIIISI13I ISI|l|I|l|SI9l!ItlEII3MISIS8|B|l 2S2I9SH(|S||Stlll8miSI3SZBIZBII2C3CS BSIS
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 502 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (1HM) (S/kW) (*«) (miIIs/kub) (X) (tons/yr) (1/ton)
Factor (X)
DS0*ESP
0SD*£SP
1.00
1.00
250
500
53
70
2.4
2.4
15.1
25.5
60.3
50.9
9.6
19.0
8.3
6.2
47.0
49.0
10311
28073
934.9
675.7
DSD*ESP-C
DSD+ESP-C
1.00
1.00
250
500
53
70
2.4
2.4
15.1
25.5
60.3
50.9
5.6
11.0
4.8
3.6
47.0
49.0
10311
28073
542.2
391.2
FSI+ESP-50
FSI+ESP-50
1.00
1.00
250
500
53
70
2.4
2.4
16.0
25.2
63.9
50.4
11.5
24.6
9.9
8.0
50.0
50.0
10923
28852
1049.7
852.7
FS1+ESP-50-C
FSI+6SP-50-C
1.00
1.00
250
500
53
70
2.4
2.4
16.0
25.2
63.9
50.4
6.6
14.2
5.7
4.6
50.0
50.0
10923
28852
608.0
492.4
FSt+ESP-70
FSl*ESP-70
1.00
1.00
250
500
53
70
2.4
2.4
16.2
24.9
64.6
49.8
11.7
24.9
10.1
8.1
70.0
70.0
15292
40393
763.2
617.6
FSI+ESP-70-C
FSI+ESP-70-C
1.00
1.00
250
500
53
70
2.4
2.4
16.2
24.9
64.6
49.8
6.8
14.4
5.8.
4.7
70.0
70.0
15292
40393
442.0
356.6
15-14
-------
SECTION 16.0 NORTH CAROLINA
16.1 CAROLINA POWER AND LIGHT COMPANY
16.1.1 Mavo Steam Plant
The Mayo steam plant is located on Mayo Lake in Person County, North-
Carolina, and is operated by the Carolina Power and Light Company. The Mayo
plant contains one coal-fired boiler with a gross generating capacity of
736 MW.
Table 16.1.1-1 presents operational data for the existing equipment at
the Mayo plant. Coal shipments are received by railroad and transferred to
a coal storage and handling area west of the plant. PM emissions froi; the
boilers are controlled by ESPs installed at the time of construction. The
ESPs are located behind the units. Flue gas from the boiler is directed to
a chimney located behind the ESPs. Fly ash is disposed of in a pond north
of the plant or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located behind the chimney. Because no
major demolition or relocation would be required, a low (5 percent) general
facilities factor was assigned to the location. A low site access/conges-
tion factor was also assigned to the location. Between 100 and 300 feet of
ductwork would be required for installation of the wet FGD system. A low
site access/congestion factor was assigned to flue gas handling.
LSD-FGD with reuse of the existing ESPs was not considered because the
unit is equipped with hot side ESPs. LSD with a new FF was considered. The
LSD-FGD absorber and FF would be located west of the chimney. The site
access/congestion factor was low for this location. About 100 to 300 feet
of ductwork would be required for installation of the LSD absorbers. A low
site access/congestion factor was assigned to flue gas handling.
Table 16.1.1-2 presents the retrofit factor inputs to the IAPCS model.
Costs are not presented since the boiler at the Mayo plant is burning a low
sulfur coal in compliance with the 1971 NSPS.
16-1
-------
TABLE 16.1.1-1. MAYO STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1
GENERATING CAPACITY (MW) 736
CAPACITY FACTOR (PERCENT) 77
INSTALLATION DATE 1983
FIRING TYPE OPPOSED WALL
FURNACE VOLUME (1000 CU FT) NA
LOW NOx COMBUSTION YES (OFA)
COAL SULFUR CONTENT (PERCENT) 0.6
COAL HEATING VALUE (BTU/LB) 12300
COAL ASH CONTENT (PERCENT) 10.0
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/SOLD
STACK NUMBER 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1983
EMISSION (LB/MM BTU) 0.01
REMOVAL EFFICIENCY 99.6
- DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 0.6
SURFACE AREA (1000 SQ FT) 237.6
GAS EXIT RATE (1000 ACFM) 958
SCA (SQ FT/1000 ACFM) 248
OUTLET TEMPERATURE ('F) 715
16-2
-------
TABLE 16.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR MAYO UNIT 1
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE NA
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 3015 NA 0
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.16
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5
16-3
-------
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Mayo plant because the plant is
already burning low sulfur coal.
NOx Control Technologies--
OFA is already in use at the Mayo plant; therefore, no additional
combustion modification technologies were considered.
Selective Catalytic Reduction-
Hot side SCR reactors for the boiler at the Mayo plant would be located
similarly to the wet FGD absorbers, behind the chimney. A low general
facilities value (13 percent) and site access/congestion factor were
assigned to the location. About 200 feet of ductwork would be required for
installation of the SCR reactors and a low site access/congestion factor was
assigned to flue gas handling. Tables 16.1.1-3 and 16.1.1-4 present the
retrofit factor inputs to the IAPCS model ,and the estimated cost for
installation of SCR at the Mayo plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies were not considered at the Mayo plant
because the unit is equipped with hot side ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The 736 MW boiler at the Mayo plant is too large and has too long of a
remaining useful life to be considered a good candidate for AFBC/CG
repowering technologies.
16.1.2 Roxboro Steam Plant
The Roxboro steam plant is located on Lake Hyco in Person County, North
Carolina, and is operated by the Carolina Power and Light Company. The
Roxboro plant contains four coal-fired boilers with a gross generating
capacity of 2,558 MW.
¦Table 16.1.2-1 presents operational data for the existing equipment at
the Roxboro plant. Coal shipments are received by railroad and transferred
16-4
-------
TABLE 16.1.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR MAYO
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
FIRING TYPE NA
TYPE OF NOx CONTROL NA
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE NA
SLAGGING PROBLEM NA
ESTIMATED NOx REDUCTION (PERCENT) NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 121
New Duct Length (Feet) 200
New Duct Costs (1000$) 3186
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$) 3306
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13_
16-5
-------
Table 16.1.1-4. NOx Control Cost Results for the Kayo Plant
-------
TABLE 16.1.2-1. ROXBORO 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
12 3 4
411 657 745 745
65 68 46 64
1966 1968 1973 1980
OPPOSED TANG FRONT OPPOSED
WALL WALL WALL
194 330 203 200
NO NO NO YES
0.9 0.9 0.9 0.7
12500 12500 12500 12200
9.5 9.5 9.5 10
WET DISPOSAL
POND/ON-SITE
12 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 (#F)
ESP
ESP
ESP
ESP
1974
1974
1979
1980
0.05
0.03
0.1
0.09
99.2
98.9
99.6
99.7
0.7
0.7
0.7
0.7
430.3
670
518
831
1215
2200
2760
2158
354
305
375
385
290
290
305
770
16-7
-------
to a coal storage and handling area north of the plant. PM emissions from
units 1-3 are controlled by retrofit ESPs and emissions from unit 4 are
controlled by ESPs which were installed at the time of construction. All of
the ESPs are located behind the boilers. Flue gases from each boiler are
directed to a chimney located behind each unit. Fly ash from the units is
disposed of in a pond south of the plant. Unit 4 complies with the
1971 NSPS.
Lime/Limestone and Lime Spray. Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located near the unit 1
chimney, absorbers for unit 3 would be located on the west side of the
unit 3 ESPs, and absorbers for unit 4 would be located beside the unit 4
chimney. The general facilities factor is high (15 percent) for all of
these locations because the railroad spur for coal delivery would have to be
relocated. The site access/congestion factor is medium for the unit 1-3
locations because of the proximity of the coal pile, coal conveyor, and
railroad. The site access/congestion factor for the unit 4 location is low.
About 200 feet of ductwork would be required for units 1 and 4 and about 600
feet would be required for units 2 and 3. A low site access/congestion
factor was assigned to flue gas handling for units 1 and 4. A high site
access/congestion factor was assigned to flue gas handling for units
2 and 3.
LSD with reuse of the existing ESPs was considered for units 1 and 2.
LSD-FGD absorbers for unit 1 would be located beside the unit 1 ESPs and
absorbers for unit 2 would be located near the unit 1 chimney. High general
facilities factors were assigned to both locations because several storage
buildings would have to be relocated. A medium site access/congestion
factor was assigned to the unit 1 and 2 locations because of the congestion
caused by the coal conveyor, coal pile, and railroad. About 200 feet of
ductwork would be required for unit 1 and over 600 feet of ductwork would be
required for unit 2. High site access/congestion factors were assigned to
flue gas handling for units 1 and 2 because of the difficulty in accessing
the upstream side of the ESPs. The unit 3 ESPs are too small to be reused
for LSD-FGD and the unit 4 ESPs cannot be reused because they are hot side.
Therefore, LSD-FGD with new FF was considered for units 3 and 4. The
16-8
-------
LSD-FGD absorbers arid baghouse for unit 3 would be located similarly to the
L/LS-F6D absorbers for this unit, west of the unit 3 ESPs. A medium site
access/congestion factor and a high general facilities value (15 percent)
were assigned to the location. LSD-FGD absorbers and baghouse for unit 4
would be located near the unit 4 chimney. A high general facilities value
(15 percent) was assigned to this location because a large storage building
would have to be relocated. A low site access/congestion factor was
assigned to the location. Between 400 and 600 feet of ductwork would be
required for installation of LSD-FGD for unit 3 and about 200 feet would be
required for unit 4. A high site access/congestion factor was assigned to
flue gas handling for unit 3 because of the congestion around the unit 3
chimney. A low site access/congestion factor was assigned to flue gas
hand!ing for unit 4.
Tables 16.1.2-2 through 16.1.2-5 present retrofit factor results for
installation of conventional FGD technologies at the Roxboro plant. Costs
are not presented because the plant is burning low sulfur coal.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Roxboro plant because the plant
is already burning low sulfur coal.
N0X Control Technologies--
LNB was considered for control of N0X emissions from units 1 and 3
which are wall-fired. OFA was considered for unit 2 which is tangential -
fired. No combustion control technologies were considered for unit 4
because LNB is already in place for this unit. Tables 16.1.2-6 and 16.1.2-7
present retrofit factors and costs, respectively, for installation of N0X
control technologies at the Roxboro plant.
Selective Catalytic Reduction--
Cold side SCR reactors for units 1, 2, and 3 and hot side SCR reactors
for unit 4 would be located similarly to the LSD-FGD absorbers. Reactors
for unit 1 would be located beside the unit 1 ESPs, reactors for unit 2
would be located near the unit 1 chimney, reactors for unit 3 would be
located west of the unit 3 ESPs, and reactors for unit 4 would be located
16-9
-------
TABLE 16.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR ROXBORO
UNIT 1
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 100-300
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 3329 NA 3329
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER YES YES
RETROFIT FACTORS
FGD SYSTEM 1.47 NA
ESP REUSE CASE 1.58
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
16-10
-------
TABLE 16.1.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR ROXBORO
UNIT 2
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$) 5069 NA 5069
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER YES YES
RETROFIT FACTORS
FGD SYSTEM 1.67 NA
ESP REUSE CASE 1.79
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
16-11
-------
TABLE 16.1.2-4. SUMMARY OF RETROFIT FACTOR DATA FOR ROXBORO
UNIT 3
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
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
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
5674
NA
0
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.57
NA
ESP REUSE CASE
NA •
BAGHOUSE CASE
1.49
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
15
0
15
16-12
-------
TABLE 16.1.2-5. SUMMARY OF RETROFIT FACTOR DATA FOR ROXBORO
UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
5674
NA
0
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.27
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.16
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
15
0
15
16-13
-------
TABLE 16.1.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR ROXBORO
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
4
FIRING TYPE
OWF
TANG
FWF
NA
TYPE OF NOx CONTROL
LNB
OFA
LNB
NA
FURNACE VOLUME (1000 CU FT)
194
330
203
NA
BOILER INSTALLATION DATE
1966
1968
1973
NA
SLAGGING PROBLEM
YES
YES
YES
NA
ESTIMATED NOx REDUCTION (PERCENT)
27
20
14
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
MEDIUM
MEDIUM
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
78
111
122
122
New Duct Length (Feet)
200
500
400
200
New Duct Costs (1000$)
2266
7452
6417
3208
New Heat Exchanger (1000$)
4352
5767
6219
0
TOTAL SCOPE ADDER COSTS (1000$) 6696 13330
RETROFIT FACTOR FOR SCR 1.16 1.34
GENERAL FACILITIES (PERCENT) 38 38
12757 3330
1.34 1.16
38 38
16-14
-------
Table 16.1.2-7. NOx Control Cost. Results for the Roxboro Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capaci
ity Coal
Capital Capital Annual
Annua I
NOx
NOx
NOx Cost
Number
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Content
(SMM)
(I/kU)
($HM)
(imlls/kwh)
«>
(tons/yr)
($/ton)
Factor
(X)
LNC-LNB
1
1.00
411
65
0.9
4.5
10.9
0.9
0.4
27.0
2619
358.6
INC-LNB
3
1.00
745
46
0.9
5.7
7.7
1.2
0.4
14.0
1742
683.9
INC-LNB-C
1
1.00
411
65
0.9
4.5
10.9
0.6
0.2
27.0
2619
213.1
INC-INB-C
3
1.00
745
46
0.9
5.7
7.7
0.7
0.2
14.0
1742
406.5
IKC-OFA
2
1.00
657
68
0.9
1.3
2.0
0.3
0.1
20.0
2318
118.6
LNC-OFA-C
2
1.00
657
68
0.9
1.3
2.0
0.2
0.0
20.0
2318
70.5
SCR-3
1
1.16
411
65
0.9
54.9
133.7
19.5
8.3
80.0
7761
2506.6
SCR-3
2
1.34
657
68
0.9
94.3
143.5
32.2
8.2
80.0
9270
3472.0
SCR-3
3
1.34
745
46
0.9
103.7
139.2
35.3
11.8
80.0
9955
3545.4
SCR-3
4
1.16
745
64
0.7
91.6
122.9
33.8
8.1
80.0
14242
2376.0
SCR-3-C
1
1.16
411
65
0.9
54.9
133.7
11.4
4.9
80.0
7761
1467.9
SCR-3-C
2
1.34
657
68
0.9
94.3
143.5
18.9
4.8
80.0
9270
2034.8
SCR-3-C
3
1.34
745
46
0.9
103.7
139.2
20.7
6.9
80.0
9955
2078.0
SCR-3-C
4
1.16
' 745
64
0.7
91.6
122.9
19.8
4.7
80.0
14242
1390.1
SCR-7
1
1.16
411
65
0.9
54.9
133.7
16.1
6.9
80.0
7761
2074.1
SCR-7
2
1.34
657
68
0.9
94.3
143.5
26.8
6.9
80.0
9270
2893.2
SCR-7
3
1.34
745
46
0.9
103.7
139.2
29.2
9.7
80.0
9955
2934.2
SCR-7
4
1.16
745
64
0.7
91.6
122.9
27.7
6.6
80.0
14242
1947.2
SCR-7-C
1
1.16
411
65
0.9
54.9
133.7
9.5
4.0
80.0
7761
1220.1
SCR-7-C
2
1.34
657
68
0.9
94.3
143.5
15.8
4.0
80.0
9270
1703.2
SCR-7-C
3
1.34
745
46
0.9
103.7
139.2
17.2
5.7
80.0
9955
1727.8
SCR-7-C
4
1.16
745
64
0.7
91.6
122.9
16.3
3.9
80.0
14242
1144.5
16-15
-------
beside the unit 4 chimney. Low site access/congestion factors were assigned
to the unit 1 and 4 locations and medium site access/congestion factors were
assigned to the unit 2 and 3 locations. High general facilities values
(38 percent) were assigned to all of the reactor locations. About 200 feet
of ductwork would be required for units 1 and 4, 500 feet for unit 2, and
400 feet for unit 3. Tables 16.1.2-6 and 16.1.2-7 present the retrofit
factors and costs for installation of SCR at the Roxboro plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
units 3 or 4 because the existing ESPs for these units cannot be reused.
The unit 3 ESPs are too small and the unit 4 ESPs are hot side. FSI and DSD
were considered for units 1 and 2, There is a short duct residence time
between the boilers and ESPs; however, the ESPs are large enough to handle
the additional particulate load and -the first section of the ESPs can be
modified for slurry evaporation and humidification. Tables 16.1.2-8 and
16.1.2-9 present retrofit data and costs for installation of FSI and DSD
technologies at the Roxboro plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All of the boilers at the Roxboro plant are too large and have too long
of a remaining service live to be considered good candidates for AFBC/CG
technologies.
16-16
-------
TABLE 16.1.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ROXBORO UNIT 1 OR 2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
WET TO DRY FLY ASH HANDLING YES
ESTIMATED COST (1000$) (1,2) 3329,5069
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$) (1,2) 86,123
TOTAL COST (1000$)
ESP UPGRADE CASE (1,2) 3415,5192
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
16-17
-------
Table 16.1.2-9. $ urinary of D5D/FSI Control Costs for the Roxboro Plant (Jure 1988 Dollars)
sss3s$:sss:
Technology
s5c::3::sas:sss::s;3s3:ssa33:ssss9ss3ss
I33383CS3:
Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NU) (X) Content (SMM) (S/kU) ($MM) (miUs/kwh) (X) (tons/yr) (S/ton)
Factor (X)
DSO+ESP
OSD+ESP
1.00
1.00
411
657
65
68
0.9
0.9
15.9
23.0
38.6
35.1
9.6
13.9
4.1
3.5
49.0
49.0
7888
13192
1214.7
1051.7
DSO+ESP-C
OSC+ESP-C
1.00
1.00
411
657
65
68
0.9
0.9
15.9
23.0
38.6
35.1
5.6
8.1
2.4
2.1
49.0
49.0
7888
13192
705.0
610.4
FSI+ESP-50
FSMESP-50
1.00
1.00
411
657
65
68
0.9
0.9
16.1
26.6
39.2
40.5
9.8
15.8
4.2
4.0
50.0
50.0
8107
13558
1210.2
1164.9
FSI+ESP-50-C
FSI+ESP-50-C
1.00
1.00
411
657
65
68
0.9
0.9
16.1
26.6
39.2
40.5
5.7
9.2
2.4
2.3
50.0
50.0
8107
13558
702.3
676.2
FSl»ESP-70
FSI+ESP-70
1.00
1.00
411
657
65
68
0.9
0.9
16.3
26.8
39.6
40.8
10.0
16.0
4.3
4.1
70,
70.
11350
18981
878.5
845.3
FSI+ESP-70-C
FSl*ESP-70-C
1.00
1.00
411
657
65
68
0.9
0.9
16.3
26.8
39.6
40.8
5.8
9.3
2.5
2.4
70.0
70.0
11350
18981
509.8
490.6
16-18
-------
16.2 DUKE POWER COMPANY
16.2.1 Allen Steam Plant
Units 1 and 2 were not evaluated because these units are not in
service. Retrofit factors were developed for units 3, 4, and 5 at the Allen
plant; however, costs are not shown since the boilers fire a low sulfur
coal. Since the boilers fire a low sulfur coal, CS was not evaluated.
Sorbent injection technologies (FSI and DSD) were not considered because of
the short duct residence time between the boilers and their respective ESPs,
and the lack of ESP information such as SCA size.
TABLE 16.2.1-1. ALLEN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1
GENERATING CAPACITY (MW) 165
CAPACITY FACTOR (PERCENT) OUT OF
INSTALLATION DATE 1957
FIRING TYPE
FURNACE VOLUME (1000 CU FT) 112
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER 1
COAL DELIVERY METHODS
2 3 4
165 275 275
SERVICE 38 26
1957 1959 1960
TANGENTIAL
112 165 165
NO NO NO
I.0
12500
II.3
WET DISPOSAL
PONDS/ON SITE
2 3 4
RAILROAD
275
32
1961
165
NO
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 (4F)
ESP
ESP
ESP
0.06
0.05
0.07
97
97.3
96.9
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
16-19
-------
TABLE 16.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ALLEN UNIT 3 *
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
' NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
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$)
2322
NA
NA
NEW CHIMNEY
YES
NA
YES
ESTIMATED COST (1000$)
1925
0
.1925 •
OTHER
NO
NO '
RETROFIT FACTORS
FGD SYSTEM
1.46
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.41
ESP UPGRADE
NA
NA .
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 10
0
10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 3
would be located north of unit 5.
16-20
-------
TABLE 16.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR ALLEN
UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 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$) 2322 NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 1925 0 1925
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.40 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.34
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 10 0 10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for
unit 4 would be located north of unit 5.
16-21
-------
TABLE 16.2.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR ALLEN
UNIT 5 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE LOW
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 2322 NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 1925 0 1925
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.29 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.23
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 10 0 10
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 5
would be located north of unit 5.
16-22
-------
TABLE 16.2.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR ALLEN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
3
4
5
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
165
165
165
BOILER INSTALLATION DATE
1959
1960
1961
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM .
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
58
58
58
New Duct Length (Feet)
200
200
200
New Duct Costs (1000$)
1791
1791
1791
New Heat Exchanger (1000$)
3420
3420
3420
TOTAL SCOPE ADDER COSTS (1000$)
5269
5269
5269
RETROFIT FACTOR FOR SCR
1.34
1.34
1.16
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for all boilers would be located
behind their respective chimney.
16-23
-------
Table 16.2.1-6. MOx Control Cost Results for the Allen Plant (June 19S8 Dollars)
*S=3IBC3H=1
ia==a=S33
==S==3C==S===»=
ZSS3CSS33
BZSHSSSSl
E33aK=*S2
11
H
¦
II
N
¦
¦
II
[BSBHSa
,sss|saiss||
S31SS3S
issassKs
It
M
II
It
If
II
II
«
II
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
NOX
NOx ,
NOX Cost
Nunber
Retrofi t
Si2e
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (NM)
(X)
Content
<«M>
(t/kW)
(»•»>
(mills/kwh)
<%)
(tons/yr)
(i/ton)
Factor
<*>
LNC-OFA
3
1.00
Z75
38
1.0 .
0.9
3.4
0.2
0.2
25.0
678
286.2
INC-OFA
4
1.00
275
26
1.0
0.9
3.4
0.2
0.3
25.0
464
418.2
LliC-OM
5
1.00
275
32
1.0
0.9
3.4
0.2
0.3
25.0
571
339.8
LNC-OFA-C
3
1.00
273
38
1.0
0.9
3.4
0.1
0.1
25.0
678
170.2
LNC-OFA-C
4
1.00
275
26
1.0
0.9
3.4
0.1
0.2
25.0
464
248.7
INC-OFA-C
5
1.00
275
32
1.0
0.9
3.4
0.1
0.1
25.0
571
202.1
SCR-3
3
1.34
275
38
1.0
42.6
154.8
13.8
15.1
80.0
2168
6372.5
SCR-3
4
1.34
275
26
1.0
42.6
154.7
13.7
21.8
80.0
1484
9209.8
SCR-3
5
1.16
275
32
1.0
39.2
142.4
12.9
16.8
80.0
1826
7084.3
SCR-3-C
3
1.34
275
38
1.0
42.6
154.8
8.1
8.9
80.0
2168
3739.C
SCR-3-C
4
1.34
275
26
1.0
42.6
154.7
8.0
12.8
80.0
1484
5405.2
SCR-3-C
5
1.16
275
32
1.0
39.2
142.4
7.6
9.8
80.0
1826
4155.0
SCR-7
3
1.34
275
38
1.0
42.6
154.8
11.6
12.6
80.0
2168
5336.7
SCR-7
4
1.34
275
26
1.0
42.6
154.7
11.4
18.2
80.0
1484
7695.9
SCR- 7
5
1.16
275
32
1.0
39.2
142.4
10.7
13.9
80.0
1826
5854.3
SCR-7-C
3
1.34
275
38
1.0
42.6
154.8
6.8
7.5
80.0
2168
3145.6
SCR-7-C
4
1.34
275
26
1.0
42.6
154.7
6.7
10.7
80.0
1484
4537.8
SCR-7-C
s
1.16
275
32
1.0
39.2
142.4
6.3
8.2
80.0
1826
3450.3
It
II
II
u
N
s
II
II
II
II
U
II
II
ii
:ssssss:
II
N
N
II
M
N
II
II
II
ft
i!
S8SSS83
SSS3SB8B3
8S8SS8SSS
16-24
-------
16.2.2 Belews Creek Steam Plant
The Belews Creek steam plant is located on Belews Lake in Stokes
County, North Carolina, and is operated by Duke Power Company. The Belews
Creek plant contains two coal-fired boilers with a gross generating capacity
of 2,000 MW.
Table 16.2.2-1 presents operational data for the existing equipment at
the Belews Creek plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area northwest of the plant. PM
emissions from the boilers are controlled by retrofit ESPs. The ESPs are
located behind the boilers. Flue gases from each boiler are directed to a
chimney behind the ESPs. Dry fly ash is landfilled by the utility.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located behind the chimney for each unit.
Medium (8 percent) general facility factors were assigned to the FGD
absorber locations because a plant road would have to be relocated. Low
site access/congestion factors were assigned to the absorber locations.
About 200 feet of ductwork would be required to install the L/LS-FGD
absorbers and a low site access/congestion factor was assigned to flue gas
handling.
LSD with reuse of the existing ESPs was considered for both units
because the retrofit ESPs are large enough to handle the increased
particulate load of the LSD system. LSD absorbers would be located on
either side of the ESPs for easy access to the upstream of the ESPs. Low
site access/congestion factors were assigned to the LSD absorber locations.
About 400 feet of duct length with a high flue gas handling site access/
congestion factor would be required for each unit.
Tables 16.2.2-2 and 16.2.2-3 present the retrofit factors and cost
estimates for commercial FGD technologies.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Belews Creek plant because the
plant is already burning low sulfur coal.
16-25
-------
TABLE 16.2.2-1. BELEWS CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2
GENERATING CAPACITY (MW-each) 1000
CAPACITY FACTOR (PERCENT) 83,80
INSTALLATION DATE 1974,75
FIRING TYPE OPPOSED WALL
FURNACE VOLUME (1000 CU FT) 776
LOW NOx COMBUSTION NO
COAL SULFUR CONTENT (PERCENT) 1.0
COAL HEATING VALUE (BTU/LB) 12600
COAL ASH CONTENT (PERCENT) 10.0
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL
STACK NUMBER 1,2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1986
EMISSION (LB/MM BTU) 0.12,0.06
REMOVAL EFFICIENCY 98.7,99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) NA
SURFACE AREA (1000 SQ FT) NA
GAS EXIT RATE (1000 ACFM) NA
SCA (SQ FT/1000 ACFM) 305
OUTLET TEMPERATURE (9F) 300
16-26
-------
TABLE 16.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR BELEWS
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.20 NA
ESP REUSE CASE 1.36
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
16-27
-------
Table 16.2.2-3. Sunmary of FGD Control Costs for the Balaws Craek Plant (June 1938 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) - (X) Content (SMM) (S/kM) («Wf) (mills/lwh) (X) (tons/yr) (S/ton)
Factor (X)
L/S FGD 1 1.20 1000 83 1.0 152.0 152.0 77.5 10.7 90.0 49917 1552.9
L/S FGO 2 1.20 1000 80 1.0 152.0 152.0 76.3 10.9 90.0 48113 1586.S
t/S FGD-C 1 1.20 1000' 83 1.0 152.0 152.0 45.1 6.2 90.0 49917 903.4
L/S FGD-C 2 1.20 1000 80 1.0 152.0 152.0 44.4 6.3 90.0 48113 923.1
LC FGD 1-2 1.20 2000 82 1.0 ¦ 225.1 112.5 127.9 8.9 90.0 98631 1296.6
LC FGO-C 1-2 1.20 2000 82 K0 225.1 112.5 74.3 . 5.2 90.0 98631 753.1
ISD+ESP 1 1.36 1000 83 1.0 99.9 99.9 42.9 5.9 76.0 ,42318 1014.9
ISD+ISP 2 1.36 1000 80 1.0 99.9 99.9 42.4 6.1 76.0 40789 1040.0
ISD+ESP-C 1 1.36 1000 83 1.0 99.9 99.9 25.1 3.4 76.0 42318 592.1
LSD*ESP-C 2 1.36 1000 80 1.0 99.9 99.9 24.8 3.5 76.0 40789 606.8
16-28
-------
N0X Control Technologies--
Both units are dry bottom, opposed wall-fired boilers rated 1,000 MW
each. LNB was considered as the combustion modification technique to remove
N0X. Tables 16.2.2-4 and 16.2.2-5 present performance and cost estimates
for LNB at units 1 and 2.
Selective Catalytic Reduction-
Hot side SCR reactors for the Belews Creek plant would be located on
either side of the ESPs similar to the LSD absorbers. As in the LSD case, a
medium general facilities value (20 percent) and a low site access/
congestion factor were assigned to the locations. Approximately 400 feet of
ductwork would be required to span the distance between the SCR reactors and
the air preheaters. Tables 16.2.2-4 and 16.2.2-5 present the retrofit
factors and cost estimates for installation of SCR at the Belews Creek
plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs-
It was assumed that the existing ESPs at the Belews Creek plant are
large enough to accommodate sorbent injection technologies (FSI and DSD).
Tables 16.2.2-6 and 16.2.2-7 present the retrofit factors and cost estimates
for FSI and DSD technologies at the Belews Creek plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The 1,000 MW boilers at the Belews Creek plant are too large and have
too long of a remaining useful life to be considered for AFBC/CG repowering.
16.2.3 Cliffside Steam Plant
The Cliffside steam plant is located on the Broad River in Cleveland
and Rutherford Counties in North Carolina and is operated by the Duke Power
Company. The Cliffside plant contains five coal-fired boilers with a gross
generating capacity of 781 MW. Units 1-4 were not considered in this study
because they are out of service.
Table 16.2.3-1 presents operational data for unit 5 at the Cliffside
plant. Coal shipments are received by railroad and transferred to a coal
16-29
-------
TABLE 16.2.2-4. SUMMARY OF NOx RETROFIT RESULTS FOR BELEWS
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB .
FURNACE VOLUME (1000 CU FT) % 776
BOILER INSTALLATION DATE* 1974, 1975
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 53
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 152
New Duct Length (Feet) 400
New Duct Costs (1000$) 7623
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$) 7775
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
16-30
-------
Table 16.2.2-5. NOx Control Cost Results for the Be lews 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 (MW) (X) Content (SUM) (S/kW) ($MN> (mills/ltyh) (X) (tons/yr) (S/ton)
Factor (X)
LNC-IN8 1 1.00 1000 83 1.0 6.4 6.4 1.3 0.2 53.0 15828 84.7
LNC-LNB 2 1.00 1000 80 1.0 6.4 6.4 1.3 0.2 53.0 15256 87.9
INC-LNB-C 1 1.00 1000 83 1.0 6.4 6.4 0.8 0.1 53.0 15828 50.3
INC-LNB-C 2 1.00 1000 80 1.0 6.4 6.4 0.8 0.1 53.0 15256 52.2
SCR-3 1 1.16 1000 83 1.0 110.5 110.5 43.5 6.0 80.0 23892 1819.8
SCR-3 2 1.16 1000 80 1.0 110.5 110.5 43.3 6.2 80.0 23028 1879.0
SCR-3-C 1 1.16 - 1000 83 1.0 110.5 110.5 25.4 3.5 80.0 23892 1063.3
SCR-3-C 2 1.16 1000 80 1.0 110.5 110.5 25.3 3.6 80.0 23028 1098.1
SCR-7 1 1.16 1000 83 1.0 110.5 110.5 3S.3 4.9 80.0 23892 1478.3
SCR-7 2 1.16 1000 80 1.0 110.5 110.5 35.1 5.0 80.0 23028 1524.8
SCR-7-C 1 1.16 1000 83 1.0 110.5 110.5 20.7 2.9 80.0 23892 867.7
SCR-7-C 2 1.16 1000 80 1.0 110.5 110.5 20.6 2.9 80.0 23028 895.1
16-31
-------
TABLE 16.2.2-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BELEWS UNIT 1 OR 2
ITEM •
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) - 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$ . 168
TOTAL COST (1000$)
ESP UPGRADE CASE 168
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.36
NEW BAGHOUSE NA
16-32
-------
Table 16.2.2-7. Summary of OSO/FSI Control Costs for the Belews Creek Plant (June 1988 Dollars)
::s::=ssss:::s:::sx:xiiE:s:s:::s::3siEi±ss:s:2:::::£sss:::::33:=5:s:ss:rs::::3:s:3i3sssssss:£ss:iasi:ss3ss£s:szi
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual $02 S02 S02 Cost
Nircber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMW) (X) Content C$MN> (JAM) <$HH) (mills/kwh) (X) (tons/yr> (S/ton)
Factor (X)
DSD+ESP 1
DS0*ESP 2
OSO+ESP-C 1
DSD*ESP-C 2
FSI+ESP-50 1
FS1+ESP-50 2
FS1~ESP-SQ-C 1
FS1+ESP-50-C 2
FSI+ESP-70 1
FS1+ESP-70 2
FS1+ESP-70-C 1
FSI+ESP-70-C 2
1.00 1000 83
1.00 1000 80
1.00 1000 83
1.00 1000 80
1.00 1000 83
1.00 1000 80
1.00 1000 83
1.00 1000 80
1.00 1000 83
1.00 1000 80
1.00 1000 83
1.00 1000 80
1.0 24.7 24.7
1.0 24.7 24.7
1.0 24.7 24.7
1.0 24.7 24.7
1.0 29.7 29.7
1.0 29.7 29.7
1.0 29.7 29.7
1.0 29.7 29.7
1.0 29.7 29.7
1.0 29.7 29.7
1.0 29.7 29.7
1.0 29.7 29.7
21.2 2.9 49.0
20.8 3.0 49.0
12.3 1.7 49.0
12.0 1.7 49.0
25.9 3.6 50.0
25.3 3.6 50.0
15.0 2.1 50.0
14.6 2.1 50.0
26.3 3.6 70.0
25.7 3.7 70.0
15.2 2.1 70.0
14.8 2.1 70.0
26983 786.5
26007 798.1
26983 454.7
26007 461.5
27731 935.0
26729 945.7
27731 540.5
26729 546.8
38824 678.6
37421 686.3
38824 392.2
37421 396.8
16-33
-------
TABLE 16.2.3-1. CLIFFSIDE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2,3,4 5
GENERATING CAPACITY (MW-each) 40,40,65,65 571
CAPACITY FACTOR (PERCENT) OUT OF 47
INSTALLATION DATE SERVICE 1972
FIRING TYPE TANGENTIAL
FURNACE VOLUME (1000 CU FT) 428.7
LOW NOx COMBUSTION . NO
COAL SULFUR CONTENT (PERCENT) 1.0
COAL HEATING VALUE (BTU/LB) 12500
COAL ASH CONTENT (PERCENT) 9.5
FLY ASH SYSTEM WET DISPOSAL
ASH DISPOSAL METHOD PONDS/SOLD
STACK NUMBER 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP
INSTALLATION DATE 1972
EMISSION (LB/MM BTU) 0.01
REMOVAL EFFICIENCY 97.9
DESIGN SPECIFICATION'
SULFUR SPECIFICATION (PERCENT) NA
SURFACE AREA (1000 SQ FT) 211
GAS EXIT RATE (1000 ACFM) 1780
SCA (SQ FT/1000 ACFM) 118
OUTLET TEMPERATURE (#F) 300
16-34
-------
storage and handling area between units 1-4 and unit 5. PM emissions from
unit 5 are controlled by ESPs which were installed at the time of
construction. The ESPs are located behind the boiler. Flue gases are
directed to a chimney located behind the unit. Fly ash from the unit is
disposed of in ponds east of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for unit 5 would be located on the south side of the
boiler. A medium general facilities value (8 percent) was assigned to the
location because a plant road would have to be relocated. The site access/
congestion factor would be medium for this location because there is some
underground piping beneath the site. About 200 feet of ductwork would be
required to install the wet FGD system and a low site access/congestion
factor was assigned to flue gas handling.
LSD with reuse of the existing ESPs was not considered because of the
small sizes of the ESPs. However, a new baghouse could be installed to
accommodate the LSD system. The LSD absorbers and FF would be placed
similarly to the wet FGD absorbers south of the boiler. As in the wet FGD
case, a medium (8 percent) general facilities value and site access/
congestion factor were assigned to the location. About 200 feet of ductwork
would be required and a low site access/congestion factor was assigned to
flue gas hand!ing.
Tables 16.2.3-2 and and 16.2.3-3 present retrofit factor inputs to the
IAPCS model and the estimated cost for installation of conventional FGD
technologies at the Cliffside plant.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for unit 5 because low sulfur coal is
already being burned at the Cliffside plant.
N0X Control Technologies--
OFA was considered for control of NOx emissions from unit 5 because it
is tangential-fired. The estimated NOx reduction and costs developed for
the 571 MW boiler are presented in Tables 16.2.3-4 and 16.2.3-5.
16-35
-------
TABLE 16.2.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR CLIFFSIDE
UNIT 5
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
NO
ESTIMATED COST (1000$)
4470
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED .COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.37
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.29
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT) 8
0
8
16-36
-------
Table 16.2.3-3. Sunitary of FGD Control Costs for the Cliffside Plant- (Jure 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 502 SO2 Cost
Nurber Retrofit Size factor Sulfur Coat Coat Coat Coat Removed Removed Effect.
Difficulty (HU) (X) Content (MM) (S/kW> (SMM) (iRills/kuh) (X) (tons/yr) (S/ton)
Factor (X)
L/S FGD 5 1.37 571 47 1.0 107.8 188.8 43.5 18.5 90.0 16288 2670.0
L/S FGO-C S 1.37 571 47 1.0 107.8 188.8 25.4 10.8 90.0 16288 1559.4
LC FGO 5 1.37 571 47 1.0 85.8 150.3 37.0 15.8 90.0 16288 2273.6
IC FGO-C 5 1.37 571 47 1.0 85.8 150.3 21.6 9.2 90.0 16288 1326.2
LSO+FF 5 1.29 571 47 1.0 100.0 175.2 33.0 14.0 87.0 15655 2107.1
LS0*FF-C 5 1.29 571 47 1.0 100.0 175.2 19.3 8.2 87.0 15655 1235.9
SMS3S383S33SS33SS3S333SSSS33SS3 33S33333SS3 3S33S33S33 33S3S3SSSS3S3S8SSS3S33S2«3333S3SS338S8S33S33SS33 3S333 33S33S
16-37
-------
TABLE 16.2.3-4, SUMMARY OF NOx RETROFIT RESULTS FOR CLIFFSIDE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
5
FIRING TYPE TANG
TYPE OF NOx CONTROL OFA
FURNACE VOLUME (1000 CU FT) 428.7
BOILER INSTALLATION DATE 1972
SLAGGING PROBLEM __ NO
ESTIMATED NOx REDUCTION (PERCENT) 25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 100
New Duct Length (Feet) 200
New Duct Costs (1000$) 2746
New Heat Exchanger (1000$) 5301
TOTAL SCOPE ADDER COSTS (1000$) 8147
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 20
16-38
-------
Table 16.2.3-5. NOx Control Cost Results for the Cliffside Plant (June 1988 Dollars)
iiiitssiiiinaiiiiiiiiisisutiitsssssiiiimiiiiiiaisiiitsisiiisaiis
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NO* NOx NOx Cost
Nimber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
Selective Catalytic Reduction-
Cold side SCR reactors for unit 5 at the Cliffside plant would be
located similarly to the wet FGD absorbers south of the boiler. A medium
general facilities value (20 percent) and site access/congestion factor were
assigned to the reactor location. Approximately 200 feet of ductwork would
be required to span the distance between the SCR reactors and the chimney.
A low site access/congestion factor was assigned to flue gas handling.
Tables 16.2.3-4 and 16.2.3-5 present the retrofit factor inputs to the IAPCS
model and cost for installation of SCR at the Cliffside plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
unit 5 at the Cliffside plant because of the small sizes of the existing
ESPs and the short duct residence time between the boiler and the ESPs.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Unit 5 is large and has a long remaining service life; therefore, is
not considered a good candidate for repowering technologies.
16.2.4 Marshall Steam Plant
The Marshall steam plant is located on Lake Norman in Catawba County,
North Carolina, and is operated by Duke Power Company. The Marshall plant
contains four coal-fired boilers with a gross generating capacity of
1,996 MW.
Table 16.2.4-1 presents operational data for the existing equipment at
the Marshall plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area north of the plant. PM emissions from
the units are controlled by retrofit ESPs located behind the boilers. Flue
gases from the boilers are directed to four chimneys, one for each unit.
The Marshall plant has a dry fly ash handling system.
16-40
-------
TABLE 16.2.4-1. MARSHALL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
1000 CU FT)
ON
ENT (PERCENT)
FURNACE VOLUME
LOW NOx COMBUST
COAL SULFUR CON
COAL HEATING VALUE (fiTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3,4
350 648
56,49 61,50
1965,66 1969,70
TANGENTIAL
NA 366
NO NO
0.9 0.9
12500 12500
10.7 10.7
DRY DISPOSAL
ON-SITE/PAID
1,2 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 (°F)
ESP
ESP
1986
1986
0.03,.02
0.09,0.11
98.1
96.8,98.1
NA
NA
NA
NA
NA
NA
200
357
NA
NA
16-41
-------
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located at the north end
of the plant and the absorbers for units 3 and 4 would be located at the
south end of the plant. The general facilities factor would be low
(5 percent) for the L/LS-FGD absorber locations. The site access/congestion
factor would be low for the unit 3 and 4 locations but medium for the unit 1
and 2 locations because of the proximity of the coal conveyor and a storage
building. Over 200 feet of ductwork would be required for installation of
the wet FGD system for unit 1, 400 feet for unit 2, greater than 600 feet
for unit 3, and greater than 300 feet for unit 4. A low site access/
congestion factor was assigned to flue gas handling for all of the units.
LSD with reuse of the existing ESPs was considered because the ESPs are
large enough to accommodate the additional load imposed by an LSD system.
LSD absorbers would be located similarly to the L/LS-FGD absorbers with
similar site access/congestion and general facilities factors.
Approximately 300, 500, 700, and 300 feet of ductwork would be required for
installation of the LSD systems for units 1-4, respectively. A medium site
access/congestion factor was assigned to flue gas handling for units 1 and
4, while a high factor was assigned to units 2 and 3 because of the access
difficulties to the upstream of the ESPs. A high site access/congestion
factor was assigned for upgrading of the existing ESPs, if required.
Tables 16.2.4-2 through 16.2.4-5 present the retrofit factors for
installation of FGD systems at the Marshall plant. Costs were not developed
because it is unlikely that the current low sulfur coal would be used if
scrubbing were required. FGD cost estimates based on the current coal would
result in low estimates of capital/operating costs and high cost
effectiveness values.
Coal Switching and Physical Coal Cleaning Costs--
CS and PCC were not considered for the Marshall plant because this
plant is already burning low sulfur coal.
N0X Control Technologies--
All four units are dry bottom, tangential-fired boilers; therefore, 0FA
was considered for control of NOx emissions for the Marshall plant. Table
16-42
-------
TABLE 16.2.4-2. SUMMARY OF RETROFIT FACTOR DATA FOR MARSHALL
UNIT 1
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
100-300 NA
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE NA NA
NEW BAGHOUSE NA NA
SCOPE ADJUSTMENTS •
WET TO DRY NO NA
ESTIMATED COST (1000$) NA NA
NEW CHIMNEY NO NA
ESTIMATED COST (1000$) 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.30 NA
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE NA NA
NEW BAGHOUSE NA NA
MEDIUM
MEDIUM
NA
300-600
NA
HIGH
NA
NO
NA
NO
0
NO
1.44
NA
1.58
NA
GENERAL FACILITIES (PERCENT) 5
16-43
-------
TABLE 16.2.4-3. SUMMARY OF RETROFIT FACTOR DATA FOR MARSHALL
UNIT 2
F6D TECHNOLOGY
FORCED LIME
L/LS F6D OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM NA MEDIUM
FLUE GAS HANDLING LOW NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 .0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.41 NA
ESP REUSE CASE 1.49
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5
16-44
-------
TABLE 16.2.4-4. SUMMARY OF RETROFIT FACTOR DATA FOR MARSHALL
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) 600-1000 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 1.37 NA
ESP REUSE CASE 1.47
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5
16-45
-------
TABLE 16.2.4-5. SUMMARY OF RETROFIT FACTOR DATA FOR MARSHALL
UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING LOW NA
ESP REUSE CASE 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 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 1.31
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5
16-46
-------
Tables 16.2.4-6 and 16.2.4-7 present N0X performance and cost results for
application of OFA at the Marshall plant.
Selective Catalytic Reduction-
Cold side SCR reactors for units 1-4 would be located behind the
respective unit, adjacent to the chimneys. A low site access/congestion
factor was assigned to units 1 and 4 reactor locations. A medium factor was
assigned to unit 2 because of the close proximity to the water channel and
the chimney. A high factor was assigned to unit 3 because of the
underground obstruction created by the water intake channels. The duct
length requirement for units 1-4 would be 200 feet. A low general
facilities factor (13 percent) was assigned to the reactor locations.
Tables 16.2.4-6 and 16.2.4-7 present the retrofit factors and cost estimates
for installation of SCR at the Marshall plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for
units 3 and 4. It was assumed that the existing ESPs would be large enough
to accommodate the additional particulate load imposed by the sorbent
injection technologies and there is sufficient duct residence time between
the boilers and the ESPs. However, units 1 and 2 ESPs are not large and
there is not sufficient duct residence time between the boilers and the
ESPs. Therefore, FSI and DSD were not considered for units 1 and 2.
Tables 16.2.4-8 and 16.2.4-9 summarize the retrofit factors and cost
estimates for FSI and DSD technologies.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
None of the boilers would be considered good candidates for AFBC/CG
repowering because of the large boiler sizes, moderate capacity factors, and
moderate remaining base load life.
16-47
-------
TABLE 16.2.4-6. SUMMARY OF NOx RETROFIT RESULTS FOR MARSHALL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
4
FIRING TYPE
TANG
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA
NA
366
366
BOILER INSTALLATION DATE
1965
1966
1969
1970
SLAGGING PROBLEM
NO
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
MEDIUM
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
69
69
110
110
New Duct Length (Feet)
200
200
200
200
New Duct Costs (1000$)
2062
2062
2957
2957
New Heat Exchanger (10005)
3952
3952
5719
5719
TOTAL SCOPE ADDER COSTS (1000$)
6084
6084
8786
8786
RETROFIT FACTOR FOR SCR
1.16
1.34
1.52
1.16
GENERAL FACILITIES (PERCENT)
13
13
13
13
16-48
-------
Table 16.2.4-7. NOx Control Cost Results for the Marshall Plant (June 1988 Dollars)
tiiBasiiitaiB8isiaisiiiiaiBiisiaBiBfaaassiiss>«ssss::
Technology
Soller
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nuttoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Content
(SUM)
(i/k«>
LNC-OFA
1
1.00
350
56
0.9
1.0
2.9
0.2
0.1
25.0
1271
168.0
INC-OFA
2
1.00
350
49
0.9
1.0
2.9
0.2
0.1
25.0
1112
192.0
INC-OFA
3
1.00
648
61
0.9
1.3
2.0
0.3
0.1
25.0
2563
106.6
INC-OFA
4
1.00
648
50
0.9
1.3
2.0
0.3
0.1
25.0
2101
130.0
INC-QFA-C
1
1.00
350
56
0.9
1.0
2.9
0.1
0.1
25.0
1271
99.8
LNC-OFA-C
2
1.00
350
49
0.9
1.0
2.9
0.1
0.1
25.0
1112
114.1
LNC-OFA-C
3
1.00
648
61
0.9
1.3
2.0
0.2
0.0
25.0
2563
63.4
LNC-OFA-C
4
1.00
648
50
0.9
1.3
2.0
0.2
0.1
25.0
2101
77.3
SCR-3
1
1.16
350
56
0.9
45.0
128.6
15.8
9.2
80.0
4067
3873.3
SCR-3
2
1.34
350
49
0.9
49.0
140.0
16.6
11.0
80.0
3559
4654.0
SCR-3
3
1.52
648
61
0.9
89.3
137.8
30.9
8.9
80.0
8202
3761.6
SCR-3
4
1.16
648
50
0.9
75.9
117.1
27.3
9.6
80.0
6723
4064.1
SCR-3-C
1
1.16
350
56
0.9
45.0
128.6
9.2
5.4
80.0
4067
2268.7
SCR-3-C
2
1.34
350
49
0.9
49.0
140.0
9.7
6.5
80.0
3559
2728.2
SCR-3-C
3
1.52
648
61
0.9
89.3
137.8
18.1
5.2
80.0
8202
2203.9
SCR-3-C
4
1.16
648
50
0.9
75.9
117.1
16.0
5.6
80.0
6723
2379.1
SCR-7
1
1.16
350
56
0.9
45.0
128.6
12.9
7.5
80.0
4067
3170.4
SCR-7
2
1.34
350
49
0.9
49.0
140.0
13.7
9.1
80.0
3559
3850.7
SCR-7
3
1.52
648
61
0.9
89.3
137.8
25.6
7.4
80.0
8202
3116.3
SCR-7
4
1.16
648
50
0.9
75.9
117.1
22.0
7.8
80.0
6723
3276.9
SCR-7-C
1
1.16
350
56
0.9
45.0
128.6
7.6
4.4
80.0
4067
1866.1
SCR-7-C
2
1.34
350
49
0.9
49.0
140.0
8.1
5.4
80.0
3559
2267.9
SCR-7-C
3
1.52
648
61
0.9
89.3
137.8
15.0
4.3
80.0
8202
1834.2
SCR-7-C
4
1.16
648
50
0.9
75.9
117.1
13.0
4.6
80.0
6723
1928.0
16-49
-------
TABLE 16.2.4-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MARSHALL 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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 121
TOTAL COST (1000$)
ESP UPGRADE CASE 121
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
16-50
-------
Tabic 16.2.4-9. Sunnary of DSD/FS1 Control Costs for the Marshall Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital
Annual
Annual
S02
S02
S02 Cost
Nimber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MV)
(X)
Content
(SUM)
(S/kW>
<*MM)
(mills/kwh)
(X)
(tons/yr)
(S/ton)
Factor
DSD+ESP
1.00
648
61
0.9
18.2
38.0
12.5
3.6
49.0
11671
1074.2
DSO+ESP
4
1.00
648
50
0.9
18.2
28.0
11.5
4.0
49.0
9567
1200.1
DSO+ESP-C
3
1.00
648
61
0.9
18.2
28.0
7.3
2.1
49.0
11671
622.4
DSD+ESP-C
4
1.00
648
50
0.9
18.2
28.0
6.7
2.3
49.0
9567
696.1
FS1+ESP-50
3
1.00
648
61
0.9
17.6
27.2
12.9
3.7
50.0
11995
1073.9
FSI+ESP-50
4
1.00
648
50
0.9
17.6
27.2
11.5
4.1
50.0
9832
1169.4
FSI+ESP-50-C
3
1.00
648
61
0.9
17.6
27.2
7.5
2.2
50.0
11995
621.9
FSI+ESP-50-C
4
1.00
648
50
0.9
17.6
27.2
6.7
2.3
50.0
9832
678.0
FSI*ESP-70
3
1.00
648
61
0.9
17.8
27.5
13.1
3.8
70.0
16793
780.6
rsi*esp-7D
4
1.00
648
50
0.9
17.8
27.5
11.7
4.1
70.0
13765
849.4
FSl*ESP-70-C
3
1.00
648
61
0.9
17.8
27.5
7.6
2.2
70.0
16793
452.0
FSl*£SP-70-C
4
1.00
648
50
0.9
Z3Kt=31
17.8
27.5
6.8
2.4
70.0
13765
492.5
ZS3SSSSX
16-51
-------
SECTION 17.0 NEW HAMPSHIRE
17.1 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
17.1.1 Merrimack Steam Plant
The Merrimack steam plant is located on the Merrimack River in
Merrimack County, New Hampshire, and is operated by the Public Service
Company of New Hampshire. The Merrimack plant contains two coal-fired
boilers with a gross generating capacity of 459 MW.
Table 17.1.1-1 presents operational data for the existing equipment at
the Merrimack plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area west of the plant. PM
emissions from the boilers are controlled by the ESPs which were built at
the same time as the boilers. The ESPs are located behind the boilers and
flue gases are directed to chimneys behind the ESPs. Dry fly ash from the
units is either landfilled by the utility or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers would be located at the west and east ends of the
units beside the units 1 and 2 ESPs. Low (5 percent) general facilities and
site access/congestion factors were selected for the FGD absorber locations.
Approximately 100 to 300 feet of ductwork would be required to span the
distance from the chimney to the absorbers back to the chimney for each
unit, low site access/congestion factors were assigned to flue gas
handling.
LSD was not considered for the Merrimack plant. The existing ESPs
cannot be reused because of their small sizes and poor performance. The
medium to high sulfur content of the coal being burned at the plant would
not likely favor use of LSD with new FFs.
Tables 17.1.1-2 and 17.1.1-3 present the retrofit factor input to the IARCS
model and the estimated cost for installation of L/LS-FGD at the Merrimack
plant. The combined and low cost FGD cases show the benefits of economy of
scale. The low cost case also shows the benefits of no spare absorber
modules and large absorbers.
17-1
-------
TABLE 17.1.1-1. MERRIMACK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1 2
GENERATING CAPACITY (MW) 114 345
CAPACITY FACTOR (PERCENT) 73 45
INSTALLATION DATE 1960 1968
FIRING TYPE CYCLONE
FURNACE VOLUME (1000 CU FT) 37.1 NA
LOW NOx COMBUSTION NO NO
COAL SULFUR CONTENT (PERCENT) 2.3 2.3
COAL HEATING VALUE (BTU/LB) 13400 13400
COAL ASH CONTENT (PERCENT) 7.1 7.1
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD LANDFILL/SOLD
STACK NUMBER 1 2
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1960 1968
EMISSION (LB/MM BTU) 0.24 0.19
REMOVAL EFFICIENCY 88.9 97.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 3.5 3.0
SURFACE AREA (1000 SQ FT) 40.3 111.4
GAS EXIT RATE (1000 ACFM) 329 885
SCA (SQ FT/1000 ACFM) 122 126
OUTLET TEMPERATURE (°F) 245 300
17-2
-------
TABLE 17.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR MERRIMACK
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA NA
FLUE GAS HANDLING LOW NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE NA
BAGHOUSE NA
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NA NA
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NA NA
ESTIMATED COST (1000$) 0 0 0
OTHER NO
RETROFIT FACTORS
FGD SYSTEM 1.20 NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 0_
17-3
-------
Table 17.1.1-3. Smary of FGD Control Costs for the Merrimack Plant (Jine 1985 Dollars)
>K:»:::iKa=K3t::3x:£2xs:2:ssssr>K:ss:i3:ras=s:st>::£i:::sss:3XSE:a::3f3«3»sss:«s:3:s23S«3::s:3::;::ss:3x::
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nurber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MM) (X) Content (WO
Factor C%)
L/S FGD 1 1.20 m 73 2.3 36.9 323.5 17.6 24.2 90.0 10727 1641.5
L/S FGD 2 1.20 345 45 2.3 70.0 202.9 30.5 22.5 90.0 20010 1526.3
l/S FGO-C 1 1.20 114 73 2.3 36.9 323.5 10.3 14.1 90.0 10727 955.9
L/S FGD-C 2 1.20 345 45 2.3 70.0 202.9 17.3 13.1 90.0 20010 890.1
IC FGD 1-2 1.20 459 52 2.3 62.9 137.0 32.3 15.4 90.0 30764 1048.6
LC FGO-C 1-2 1.20 459 52 2.3 62.9 137.0 18.8 9.0 90.0 30764 610.0
17-4
-------
Coal Switching and Physical Coal Cleaning Costs--
CS was not considered for the Merrimack plant because these are wet
bottom (slagging) boilers requiring coals with low ash fusion temperatures.
Low sulfur, low ash fusion temperature bituminous coals required for cyclone
boilers are not readily available in the eastern United States and use of
western subbituminous coal would result in a significant unit derate. PCC
was not considered for the Merrimack plant because it is not a mine mouth
plant.
NOx Control Technologies--
NGR was considered for N0X emissions control for the two cyclone-fired
boilers at the Merrimack plant. Tables 17.1.1-4 and 17.1.1-5 present the N0x
reduction performance and the costs developed for installation of this
technology at the plant.
Selective Catalytic Reduction-
Cold side SCR reactors for the boilers at the Merrimack plant would be
located next to the ESPs, similar to the wet FGD absorbers. As in the FGD
case, low general facilities values (13 percent) and site access/congestion
factors were assigned to the locations. About 200 feet of ductwork would be
required. Tables 17.1.1-4 and 17.1.1-5 present the retrofit factor inputs
to the IAPCS cost model and the costs for installation of SCR at the
Merrimack plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were not considered for
the Merrimack plant because the existing ESPs are too small to handle the
additional load imposed by these technologies. In addition, the duct
residence time between the boilers and ESPs is insufficient for slurry
drying or humidification.
17-5
-------
TABLE 17.1.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR MERRIMACK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
CYCLONE
CYCLONE
TYPE OF NOx CONTROL
NGR
NGR
FURNACE VOLUME (1000 CU FT)
37.1
NA
BOILER INSTALLATION DATE
1960
1968
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
60
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
30
68
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1070
2045
New Heat Exchanqer (1000$)
2016
3918
TOTAL SCOPE ADDER COSTS (1000$)
3116
6032 .
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
17-6
-------
Table 17.1.1-5. NO* Control Cost Results for the Merrimack Plant (Ji*ie 1988 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
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The 345 MW boiler (unit 2) at the Merrimack plant is probably too large
and too new to be considered for AFBC/CG repowering at this time. Unit 1 is
a better candidate for AFBC/CG because of its small size and the available
space next to the unit. However, because of the high capacity factor for
unit I, a long boiler downtime would cause the cost of power replacement to
be high.
17-8
-------
SECTION 18.0 NEW JERSEY
18.1 ATLANTIC CITY ELECTRIC COMPANY
18.1.1 B. L. England Steam Plant
The 8. L. England steam plant is located on the Great Egg Harbor Bay in
Cape Hay County, New Jersey, and is operated by the Atlantic City Electric
Company. The B. L. England plant contains two coal-fired boilers and one
petroleum-burning boiler with a gross generating capacity of 475 MW.
Table 18.1.1-1 presents operational data for the existing equipment at
the B. L. England plant. Coal shipments are received by railroad and
transferred to a coal storage and handling area south of the plant. PM
emissions from the boilers are controlled by retrofit ESPs. The ESPs are
located on the north side of the boilers. Flue gases from the boilers are
directed to a common chimney located east of the unit 1 ESPs. Dry fly ash
is reinjected into the boilers.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for unit 1 and unit 2 would be located east of
unit 1. The general facilities factor would be medium (10 percent) for the
FGD absorber location because several storage buildings would have, to be
relocated. Plant personnel indicated that this area is a coastal area
which puts constraints on siting and process options, therefore a high site
access/congestion factor was assigned to the site. Approximately 200 feet
of ductwork would be required to span the distance from the chimney to the
absorbers and back to the chimney. A low site access/congestion factor was
assigned to flue gas handling. Plant personnel indicated that sufficient
disposal site is not available on site or in surrounding counties.
Therefore, waste has to be hauled off site, possibly out of state. The cost
of disposal was reported to be $30-$70/ton; in this study $30/ton was used.
LSD with reuse of the existing ESPs was considered for unit 2 because
its ESP size is adequate for LSD. Plant personnel indicated that virtually
no space exists between the unit 1 airheater and the ESP in which to tie in
18-1
-------
TABLE 18.1.1-1. B. L. ENGLAND 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
136 163
55 59
1962 1964
CYCLONE
46.6 62.4
NO NO
2.6 2.6
13000 13000
9.9 9.9
DRY DISPOSAL
REINJECTED INTO
BOILERS/ON-SITE
1 2
RAILROAD
3
176
35
1974
PETROLEUM
BURNING
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
1981
1982
0.03
0.02
99.0
99.5
3.0
3.0
209.5
265.4
593
760
353
349
290
290
18-2
-------
the FGD system. As such, LSD was not considered for unit 1. The LSD
absorbers for unit 2 would have a similar location to the wet FGD absorbers;
therefore, similar site access/congestion and general facility factors were
assigned to the LSD absorber location. Over 400 feet of ductwork would be
required to access upstream of the ESPs for unit 2. The site
access/congestion factor for flue gas handling would be high due to the
close proximity of the ESPs and the boilers.
Tables 18.1.1-2 and 18.1.1-3 present retrofit factors and cost
estimates for installation of FGD control technologies at the B. L. England
plant.
Coal Switching and Physical Coal Cleaning Costs--
CS was not considered for the B. L. England plant because low sulfur
bituminous coals having low ash fusion temperatures required for
cyclone-fired boilers are not readily available in the east. PCC was not
considered because the B. L. England plant is not a mine mouth plant. Plant
personnel indicated that Atlantic Electric is exploring coal switching
options. Conversion to oil is also considered as a potential alternative.
N0X Control Technologies--
NGR was considered for the wet bottom, cyclone boilers at the B. L.
England plant. Plant personnel indicated that there is no gas supply to the
station and as such NGR application might not be feasible. Tables 18.1.1-4
and 18.1.1-5 presents the performance results and cost estimates for
installation of NGR at the B. L. England plant.
Selective Catalytic Reduction--
Cold side SCR reactors for the boilers at the B. L. England plant would
be located east of unit 1. As in the FGD case, a medium general facilities
value of 20 percent and a high site access/congestion factor would be
assigned to the location. Approximately 200 feet of ductwork would be
required to span the distance between the SCR reactors and the chimney.
Tables 18.1.1-4 and 18.1.1-5 present the retrofit factors and cost estimates
for installation of SCR at the B. L. England plant.
18-3
-------
TABLE 18.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ENGLAND
UNITS 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
Unit 2 only
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA .
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (.1000$)
0
,0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.40
NA
ESP REUSE CASE
1.62
BAGHOUSE CASE
. NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
10
18-4
-------
Table 18.1.1-3. Suraiary of FGO Control Costs for the England Plant (June 1986 Dollars)
Technology
Boiler
Nain
Soiler Capacity Coal
Capi tal
Capital Annual
Annual
S02
S02
S02 Cost
Number
Refgf it
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MU)
(X)
Content
(SUM)
(S/kW)
(SWO
L/S FGD
1
1.40
136
55
2.6
49.9
367.2
24.4
37.2
90.0
11284
2162.8
l/S FGO
2
1.40
163
59
2.6
54.5
334.5
27.5
32.6
90.0
14508
1895.1
L/S FGD
1-2
1.40
299
57
2.6
77.8
260.3
40.4
27.0
90.0
25711
1570.0
l/S FGD-C
i
1.40
136
55
2.6
49.9
367.2
14.2
21.7
90.0
11284
1259.0
./S FGD-C
2
1.40
163
59
2.6
54.5
334.5
16.0
19.0
90.0
14508
1102.6
l/S FGD-C
1-2
1.40
299
57
2.6
77.8
260.3
23.5
15.7
90.0
25711
913.1
LC FGD
1-2
1.40
299
57
2.6
59.3
198.5
34.2
22.9
90.0
25711
1328.8
IC FGD-C
1-2
1.40
299
57
2.6
59.3
198.5
19.8
13.3
90.0
25711
771.7
:so*esp
2
1.62
163
59
2.6
27.2
166.9
14.5
17.2
76.0
12300
1175.9
LSD*ESP-C
2
1.62
163
59
2.6
27.2
166.9
8.4
10.0
76.0
12300
683.6
:3xs:==staii=s:3t
18-5
-------
TABLE 18.1.1-4. SUMMARY OF NOx RETROFIT RESULTS FOR ENGLAND
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
FIRING TYPE
CYCLONE
TYPE OF NOx CONTROL
NGR
NGR
FURNACE VOLUME (1000 CU FT)
46.6
62.4
BOILER INSTALLATION DATE
1962
1964
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
34
39
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1186
1319
New Heat Exchanger (1000$)
2241
2499
TOTAL SCOPE ADDER COSTS (1000$)
COMBINED CASE
3462
5538
3857
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
20
20
18-6
-------
Table 16.1.1-5. NOx Control Cost Results for the England Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nuttoer Retro-fit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HW) (X) Content (SMH) (t/kU) C*WO CmiUs/kwh) (X)
-------
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
FSI was considered for unit 2 at the B. L. England plant because its
ESP is of an adequate size. However, space is not available for injecting
sorbent or adding spray humidification and as a result FSI and DSD were not
considered for unit 1. The first section of the unit 2 ESP would have to be
modified in order to provide sufficient duct residence time for slurry
droplet evaporation or humidification. Tables 18.1.1-6 and 18.1.1-7 present
the retrofit factors and cost estimates for installation of FSI and DSD at
the B. L. England plant. Currently, units 1 and 2 have a recycle flyash
system, producing 100 percent bottom ash which is reusable and marketable.
FSI application would create a combined flyash/spent sorbent stream which
cannot be recycled. This would eventually increase the disposal cost
because of the loss of bottom ash sales.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
Units 1 and 2 at the B. L. England plant would be good candidates for
AFBC/CG repowering because of their small boiler size (<300 MW).
18-8
-------
TABLE 18.1.1-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR ENGLAND UNIT 2
ITEM
SITE ACCESS/CONGESTION FSI Only
REAGENT PREPARATION NA
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (lOOOS) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (lOOOS) NA
ESP REUSE CASE NA
ESTIMATED COST (lOOOS) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 43
TOTAL COST (1000$)
ESP UPGRADE CASE 43
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) NA
ESP UPGRADE 1.36
NEW BAGHOUSE NA
18-9
-------
Table 13.1.1-7. Sirmsry of DSO/FSI Control Costs for the England Plant (June 1988 Dollars)
i:isst«sas9s:9;:i!::zs:ss:ss3SSSSSSfl3S3assxssss2s:s:ss:ss3SS2SSSSSsns:azsst9sissis:is3is9«:sssssssBs>=;s=;BS3s:3
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 (MW) (X) Content (SMI) (S/kU) (SMM) (mills/kuii) (X) (tons/yr) (S/ton)
Factor (X)
FSI+ESP-50 2 . 1.00 163 59 2.6 9.9 60.7 10.7 12.7 50.0 B060 1331.0
FSHESP-50-C 2 1.00 163 59 2.6 9.9 60.7 6.2 7.3 50.0 8060 768.1
F S J~ESP-70 2 1.00 163 59 2.6 10.1 62.0 11.2 13.3 70.0 11284 994.7
FSHESP-70-C 2 1.00 163 59 2.6 10.1 62.0 6.5 7.7 70.0 11284 573.9
3iiif2ai3ii3s3Ss:i:sc::*33S3s:sf3sss3S3BS3ss:=ssxsss33S3as:ss:ss:3isr»sii3is3t:3B:»3ss:isstssiisiaNi3SifaKisa
18-10
-------
18.2 PUBLIC SERVICE ELECTRIC & GAS COMPANY
18.2.1 Hudson Steam Plant
Costs were not generated due to the use of low sulfur coal. CS was not
evaluated since the boilers currently fire a low sulfur coal. The ESPs were
assumed to be inadequate for an additional load, hence sorbent injection
technologies were not considered, and LSD with a new baghouse was
considered.
TABLE 18.2.1-1. HUDSON 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
383
21
1964
CYCLONE
PETROLEUM
BURNING
SOLD/OFF-SITE
2
BARGE
354.6
NO
0.9
13200
8.6
DRY
OPPOSED WALL
600
50
1968
2
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
1984
0.10
99
1.0
377.2
2500
164
275-325
18-11
-------
TABLE 18.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR HUDSON UNIT 2 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL MEDIUM NA MEDIUM
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE NA
BAGHOUSE CASE MEDIUM
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE . 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED
COST
(1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
• NO
ESTIMATED
COST
(1000$)
0
0
0
OTHER
NO
, NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.38
NA
NA
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
NA
1.37
NA
1.36
10
* L/S-FGD and LSD-FGD absorbers would be located behind the
unit 2 chimney.
18-12
-------
TABLE 18.2.1-3. SUMMARY OF NOx RETROFIT RESULTS FOR HUDSON
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
2
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) 354.6
BOILER INSTALLATION DATE 1968
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 41
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 104
New Duct Length (Feet) 200
New Duct Costs (1000$) 2827
New Heat Exchanger (1000$) 5461
TOTAL SCOPE ADDER COSTS (1000$) 8392
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 20
* Cold side SCR reactors would be located behind the unit 2
chimney.
18-13
-------
Table 18.2.1-4. NOx control Cost Results for the Hudson Plant (June 1988 Dollars)
tsssssBsrcssKstcsitssssssisstcssssaisMssssssnssssssssasscssssss::::::::::
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Number Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Refnoved Effect.
Difficulty (NW) (X) Content ($KH) (t/kW) (iWO (miIts/kwh) (%> (tons/yr) (!/:on)
Factor (%)
LNC-INB 2 1.00 600 50 0.9 5.2 8.7 1.2 0.4 41.0 4196 274.8
INC-INB-C 2 1.00 600 50 0.9 5.2 fl.7 0.7 0.3 41.0 4196 163.0
SCR-3 2 1.34 600 50 0.9 78.7 131.1 28.7 10.9 80.0 8187 -3503.3
SCR-3-C 2 1.34 600 50 0.9 78.7 131.1 16.8 6.4 80.0 8187 2050.2
SCR-7 2 1.34 600 50 0.9 78.7 131.1 23.8 9.1 80.0 8187 2909.5
SCR-7-C 2 1.34 600 50 0.9 78.7 131.1 14.0 5.3 80.0 8187 171C.0
18-14
-------
18.2.2 Mercer Steam Plant
The Mercer steam plant is located on the Delaware River in Mercer
County, New Jersey, and is operated by the Public Service Electric and Gas
Company. The Mercer plant contains two coal-fired boilers with a gross
generating capacity of 600 MW.
Table 18.2.2-1 presents operational data for the existing equipment at
the Mercer plant. Coal shipments are received by barge and transferred to a
coal storage and handling area southeast of the plant. PM emissions are
controlled by original ESPs located behind the respective chimney. Wet fly
ash from the units is disposed of in ash ponds north of the plant or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for units 1 and 2 would be located on either side of
the units. The site access/congestion factor for either location would be
low. For both locations, a plant road and storage buildings would have to
be relocated; therefore, the general facilities factor would be medium
(8 percent). Over 300 feet of ductwork would be required for both absorber
locations. A medium site access/congestion factor was assigned to flue gas
handling since the chimneys are surrounded by ESPs and original duct.
LSD with reuse of the existing ESPs was considered for the Mercer
plant. For both units, the LSD absorbers would have a similar location as
the wet FGD absorbers; thus, similar site access/congestion and general
facilities factors were assigned for these locations. Over 300 feet of
ductwork would be required. The site access/congestion factor for flue gas
handling would be medium just as in the wet FGD case.
Table 18.2.2-2 presents the retrofit factors for installation of FGD
control technologies at the Mercer plant. Since the boilers fire a low
sulfur coal, coal costs are not presented.
Coal Switching and Physical Coal Cleaning Costs
The boilers at the Mercer plant currently fire a low sulfur coal,
therefore, CS and PCC were no evaluated.
18-15
-------
TABLE 18.2.2-1. MERCER 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
300
55,69
1960,61
FRONT WALL
193
NO
0.89
13270
6.9
WET DISPOSAL
ASH PONDS/SOLD
1,2
BARGE
PARTICULATE CONTROL
TYPE , ESP
INSTALLATION DATE 1960,61
EMISSION (LB/MM BTU) 0.1
REMOVAL EFFICIENCY 99.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.0-0.0
SURFACE AREA (1000 SQ FT) NA
GAS EXIT RATE (1000 ACFM) 900
SCA (SQ FT/1000 ACFM) NA
OUTLET TEMPERATURE (°F) 269
* 1988 value.
18-16
-------
TABLE 18.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MERCER
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 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 (1000S) 2510 NA 2510
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
0
NO
0
0
NO
FGD SYSTEM
1.42
NA
ESP REUSE CASE
1.38
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
8
0
8
18-17
-------
N0X Control Technologies--
Both units are slagging, wall-fired, Foster Wheeler boilers rated at
300 MW each; as such, NGR was considered for both units at the Mercer plant.
Performance results and costs developed for the two units are presented in
Tables 18.2.2-3 and 18.2.2-4.
Selective Catalytic Reduction-
Hot side SCR reactors for units 1 and 2 would be located on either side
of the units. Low site access/congestion factors were assigned to these
locations. The general facilities factor was medium (20 percent) due to the
relocation of plant roads and storage buildings. About 300 feet of ductwork
would be required for either reactor location. Tables 18.2.2-3 and 18.2.2-4
present the retrofit factors and cost estimates for installation of SCR at
the Mercer plant.
Furnace Sorbent Injection and Duct Spray Drying F6D Costs--
Both units at the Mercer plant would be good candidates for sorbent
injection technologies because of the sufficient duct residence time between
the boilers and the ESPs. Approximately 200 feet of duct exist between the
boilers and the ESPs allowing for slurry droplet evaporation or
humidification. Tables 18.2.2-5 and 18.2.2-6 present retrofit factors and
cost estimates for installation of FSI and DSD at the Mercer plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabili ty- -
Both boilers at the Mercer plant currently are marginal candidates for
AFBC/CG repowering due to their large boiler size.
18-18
-------
TABLE 18.2.2-3. SUMMARY OF NOx RETROFIT RESULTS FOR MERCER
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE FWF
TYPE OF NOx CONTROL NGR
FURNACE VOLUME (1000 CU FT) 193
BOILER INSTALLATION DATE 1960,1961
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$) 62
New Duct Length (Feet) 300
New Duct Costs (1000$) 2827
New Heat Exchanger (1000$) 0
TOTAL SCOPE ADDER COSTS (1000$) 2889
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 20
18-19
-------
Table IB.2.2-4. NOx Control Cost Results for the Mercer Plant (June 1988 Dollars)
Technology Boiler Main Boilar Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (SUM) (f/kW) <$**) (mills/kuli) (X) (tons/yr) <$/ton)
Factor (X)
NGR 1 1.CO 300 55 0.9 5.0 16.6 8.0 5.5 60.0 5435 1470.6
NGR 2 1.Q0 300 69 0.9 5.0 16.6 9.9 5.4 60.0 6818 1444.8
NGR-C 1 1.00 300 55 0.9 5.0 16.6 4.6 3.2 60.0 5435 846.7
NGR-C 2 1.C0 300 69 0.9 5.0 16.6 5.7 .3.1 60.0 6818 831.0
SCR-3 1 1.16 300 55 0.9 39.2 130.6 14.8 10.2 80.0 7246 2043.1
SCR-3 2 1.16 300 69 0.9 39.2 130.6 15.1 8.4 80.0 9090 1665.8
SCR-3-C 1 1.16 300 55 0.9 39.2 130.6 8.7 6.0 80.0 . 7246 1194.8
SCR-3-C 2 1.16 300 69 0.9 39.2 130.6 8.9 4.9 80.0 9090 973.7
SCR-7 1 1.16 300 55 0.9 39.2 130.6 12.4 8.6 80.0 7246 1707.9
SCR-7 2 1.16 300 69 0.9 39.2 130.6 12.7 7.0 80.0 9090 1398.6
SCR-7-C 1 1.16 300 55 0.9 39.2 130.6 7.3 5.0 80.0 7246 1002.8
SCR-7-C 2 1.16 300 69 0.9 39.2 130.6 7.5 4.1 80.0 9090 820.6
assasssssssBsaasaBsBasaaaaaaiBaBsBKrBaxBsaBSBBaaBBSSBBBBaassaBsassBBB
18-20
-------
TABLE 18.2.2-5. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MERCER 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$) 2510
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 58
TOTAL COST (1000$)
ESP UPGRADE CASE 2578
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
18-21
-------
Table 18.2.2-4. Summary of DS0/FS1 Control Costs for the Mercer Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Number Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (HW) (X) Content <$#M) (SAW) (SMN)
Factor (X)
Annual S02 S02 SC2 Cost
Cost Removed Removed effect.
(mills/kMh) (X) (tons/yr) (t/ton)
DS0*ESP
DSD*ESP
1.00
1.00
300
300
55
69
0.9
0.9
14.9
14.9
49.7
49.7
8.5
9.0
5.9
5.0
49.0
49.0
4549
5707
1868.6
1578.5
DS0*ESP-C
DS0*ESP-C
1.00
1.00
300
300
55
69
0.9
0.9
14.9
14.9
49.7
49.7
4.9
5.2
3.4
2.9
49.0
49.0
4549
5707
1085.3
916.1
FSI*ESP-50
FSI*£SP-50
1.00
1.00
300
300
55
69
0.9
0.9
18.6
18.6
62.1
62.1
9.1
9.9
6.3
5.5
50.0
50.0
4675
5865
1950.1
1689.7
F$l*ESP-50-C 1 1.00 300 55 0.9 18.6 62.1 5.3 3.7 50.0 4675 1135.1
FSI*ESP-50-C 2 1.00 300 69 0.9 18.6 62.1 5.8- 3.2 50.0 5865 982.3
FSI+ESP-70
FSl*ESP-70
1.00
1.00
300
300
55
69
0.9
0.9
18.7
18.8
62.5
62.5
9.2
10.0
6.4
5.5
70.0
70.0
6545
8211
1407.6
1220.7
FSl»ESP-70-C 1 1.00 300 55 0.9 18.7 62.5 5.4 3.7 70.0 6545 819.3
FSI*ESP-70-C 2 1.00 300 69 0.9 18.8 62.5 5.8 3.2 70.0 8211 709.6
18-22
-------
SECTION 19.0 NEW YORK
19.1 NEW YORK STATE ELECTRIC AND GAS CORPORATION
19.1.1 Goudev Steam Plant
The Goudey steam plant is located on the Susquehanna River in Broome
County, New York, and is operated by New York State Electric and Gas
Corporation. The Goudey plant contains three coal-fired boilers with a
gross generating capacity of 127 MW.
Table 19.1.1-1 presents operational data for the existing equipment at
the Goudey plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area east of the plant. PM emissions from
the units are controlled by retrofit ESPs located behind the boilers. The
flue gas from all three boilers is directed to a common chimney located
behind unit 3. The plant has paid off-site disposal for its dry fly ash.
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for all units would be located east of unit 1. The
site access/congestion factor would be low. No equipment relocation or
demolition would be required; hence, a low percentage was assigned to
general facilities. Each unit would need 300 to 600 feet of ductwork. The
site access/congestion factor assigned to flue gas handling was medium for
all units due to the close proximity of the coal pile/railroad and the
chimney.
LSD with reuse of the existing ESPs was considered for all units at the
Goudey plant. The LSD absorbers for all three units would have the sane
location as the wet FGD absorbers; therefore, similar site access/congestion
and general facility factors were assigned. The site access/congestion
factor for flue gas handling was high for all units due to the close
proximity of the ESPs to the boilers.
Tables 19.1.1-2 and 19.1.1-3 present retrofit factors and cost for
installation of conventional FGD technologies at the Goudey plant.
19-1
-------
TABLE 19.1.1-1. GOUDEY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER 1,2 3
GENERATING CAPACITY (MW) 44(COMBINED) 83
CAPACITY FACTOR (PERCENT) 63 41
INSTALLATION DATE 1943 1951
FIRING TYPE OPPOSED WALL TANGENTIAL
FURNACE VOLUME (1000 CU FT) NA 44.6
LOW NOx COMBUSTION NO NO
COAL SULFUR CONTENT (PERCENT) 1.9
COAL HEATING VALUE (BTU/LB) 12200
COAL ASH CONTENT (PERCENT) 13.4
FLY ASH SYSTEM DRY DISPOSAL
ASH DISPOSAL METHOD PAID
STACK NUMBER 1 1
COAL DELIVERY METHODS RAILROAD
PARTICULATE CONTROL
TYPE ESP ESP
INSTALLATION DATE 1973 1973
EMISSION (LB/MM BTU) 0.05 0.05
REMOVAL EFFICIENCY 99.2,96.8 99.6
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 1.0 1.0
SURFACE AREA (1000 SQ FT) 67 201.6
GAS EXIT RATE (1000 ACFM) 110 335
SCA (SQ FT/1000 ACFM) 609 602
OUTLET TEMPERATURE ('FJ 325 275
19-2
-------
TABLE 19.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR GOUDEY
UNITS 1-3 (EACH)
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING 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 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 (1000S) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.35 NA
ESP REUSE CASE 1.36
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 0 5
19-3
-------
Table 19.1.1-3. Sumtary of FGO Control Costs for the Goudty Plant
-------
Coal Switching and Physical Coal Cleaning Costs-
Table 19.1.1-4 presents the IAPCS cost results for CS at the Goudey
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 because the Goudey plant is not a mine mouth plant.
N0X Control Technologies--
LNBs were considered for N0X emissions control for the two opposed
wall-fired boilers and OFA was considered for the tangential-fired boiler.
Tables 19.1.1-5 and 19.1.1-6 present the N0X performance and cost estimates
for LNC technologies at the Goudey plant.
Selective Catalytic Reduction--
Cold side SCR reactors for all three units would be located east of
unit 1, similar to the wet FGD absorber location. Low site access/
congestion and general facility factors {13 percent) were assigned to the
SCR reactor locations. The duct length needed to span the distance between
the SCR reactors and the chimney would be 400 feet for all units.
Tables 19.1.1-5 and 19.1.1-6 present the retrofit factors and estimated cost
for installation of SCR at the Goudey plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for all
boilers at the Goudey plant. Although there is not sufficient duct
residence time between the boilers and the ESPs, the ESPs are large enough
to handle the additional load generated by DSD or FSI. Tables 19.1.1-7 and
19.1.1-8 summarize the retrofit factors and cost for installation of sorbent
injection technologies at the Goudey plant.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The three boilers at the Goudey plant would be good candidates for
AFBC/CG repowering because of their small boiler size and likely short
remaining service life.
19-5
-------
Table 19.1.1-4. Suimary of Coal Switching/Cleaning Costs for the Goudey Plant (June 1988 Dollars)
=;SS;3;3VSSIS3tSIS«NiailISIIS
-------
TABLE 19.1.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR GOUDEY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
FIRING TYPE
OWF
TANG
TYPE OF NOx CONTROL
LNB
OFA
FURNACE VOLUME (1000 CU FT)
NA
44.6
BOILER INSTALLATION DATE
1943
1951
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
40
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (10005)
9
24
New Duct Length (Feet)
400
400
New Duct Costs (1000$)
817
1777
New Heat Exchanger (1000$)
751
1667
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE (1-3)
1577
4463
3468
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
19-7
-------
Table 19.1.1-6. NOx Control Cost Results for the Goudey Plant (Jim 1988 Dollars)
zsiisxissBSAsiBsiiiaiiiiisiiBiiiistiBiiimiaiiaiiiiaiissiiiiBistniisauaaBiiiiimiuaiiiiziisiiiiisiitaiisatt
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
NOX
NOx
NOx Cost
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
Content
(WM)
(S/kV)
(*«)
(mi IIs/kwh)
(tons/yr)
(i/ton)
Factor
LNC-LNB
1,2
1.00
22
63
1.9
1.4
63.3
0.3
2.5
40.0
207
1473.9
LNC-INB-C
1,2
1.00
22
63
1.9
1.4
63.3
0.2
1.5
40.0
207
874.9
LNC-OM
3
1.00
83
41
1.9
2.4
2B.6
0.5
1.7
25.0
318
1633.5
LNC-OFA-C
3
1.00
83
41
1.9
2.4
28.6
0.3
1.0
25.0
318
969.3
SCR-3
1,2
1.16
22
63
1.9
9.1
414.2
2.8
22.8
80.0
414
6685.4
SCR-3
3
1.16
83
41
1.9
17.2
207.4
5.5
18.5
80.0
1017
5425.8
SCR-3
1-3
1.16
127
49
1.9
22.7
179.0
7.5
13.8
80.0
1859
4049.7
SCR-3-C
1-2
1.16
22
63
1.9
9.1
414.2
1.6
13.4
80.0
. 414
3928.9
SCR-3-C
3
1.16
83
41
1.9
17.2
207.4
3.2
10.9
80.0
1017
3184.5
SCR-3-C
1-3
1.16
127
49
1.9
22.7
179.0
4.4
8.1
80.0
1859
2375.0
SCR-7
1,2
1.16
22
63
1.9
9.1
414.2
2.6
21.3
80.0
414
6249.6
SCR-7
3
1.16
83
41
1.9
17.2
207.4
4.8
16.2
80.0
1017
4756.2
SCR-7
1-3
1.16
127
49
1.9
22.7
179.0
6.5
11.9
90.0
1859
3489.7
SCR-7-C
1,2
1.16
22
63
1.9
9.1
414.2
1.5
12.5
80.0
414
3679.4
SCR-7-C
3
1.16
83
41
1.9
17.2
207.4
2.8
9.6
80.0
1017
2800.9
SCR-7-C
1-3
1.16
127
49
1.9
22.7
179.0
3.8
7.0
80.0
1859
2054.2
¦ ssssssr:
S3IS33SS3I
ISSCSSIl
tsssaits;
is<;is:=:
3e:itf=z»:stss3a
II
II
II
N
II
U
M
t|S3XS==|<:3
5338*333331
II
II
II
II
II
II
II
II
19-8
-------
TABLE 19.1.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GOUDEY UNIT 1, 2, OR 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) . 50
DEMOLITION COST (10005) 10,10,26
TOTAL COST (1000$)
ESP UPGRADE CASE 10,10,26
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.16
NEW BAGHOUSE NA
19-9
-------
Table 19.1.1-8. Summary of DSO/FSI Control Costs for the Goudey Plant (June 1988 Dollars)
sasiiiiMiisiMissiKssssssiBsasssssssissaiussiiissaiaiiMitiaBMisiiisiiiasiaaiiBiaiiaassaaiaztaBmsHMBssiics
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuttier Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) Content (»*) (S/kW) (SHH> (mills/kwh) (X)
-------
19.1.2 Greenidge Steam Plant
Sorbent injection technologies (FSI and DSD) were not considered for
any of the boilers at the Greenidge plant due to the marginal ESP size and
performance.
TABLE 19.1.2-1. GREENIDGE 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
4+5
59
46
1950
FRONT WALL
NA
NO
6
104
48
1953
TANGENTIAL
57.6
NO
1.9
11900
13.7
WET DISPOSAL
PONDS/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)
MECH. COLLECTOR
AND ESP
1971
0.13
96.2
20.8
210
99
300
1.0
ESP
1970
0.10
99.7
89.3
412
217
300
19-11
-------
TABLE 19.1.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR GREENIDGE
UNIT 4+5, OR 6 *
FGO TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA . NA LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NA NO
ESTIMATED COST (1000$) 584-971 NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 413-728 0 413-728
OTHER 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) 8 0 8
* Absorbers for boilers 4+5 and 6 would be located west of
boiler 6.
19-12
-------
Table 19.1.2-3. Suanary of FGO Control Costa for the Graenidge Plant (Jim 1988 Dollars)
aaaiBS9=«asx==3ia=
Technolosy Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HU> (X) Content (MM (S/kU) (MO («Uls/kwh) (%) (tons/yr> (S/ton>
Factor (X)
l/S FGO
L/S FGO
4«5 59 46 1.9 34.0 576.6 14.6 61.5 90.0 3312 4416.0
6 1.48 104 48 1.9 44.6 428.8 19.3 44.1 90.0 6091 3164.6
l/S FGD-C 4*5 1.48 59 46 1.9 34.0 576.8 8.5 35.9 90.0 3312 2576.1
l/S FGD-C 6 1.48 104 48 1.9 44.6 428.B 11.2 2S.7 90.0 6091 1846.0
IC FGO 4-6 1.48 163 47 1.9 39.3 241.3 18.8 28.0 90.0 9348 2009.3
LC FGD-C 4-6 1.48 163 47 1.9 39.3 241.3 10.9 16.3 90.0 9348 1170.1
IS0+FF
ISD+FF
4*5 1.43 59 46 1.9 19.2 324.8 8.8 36.8 84.0 3090 2833.0
6 1.43 104 48 1.9 28.6 275.3 12.1 27.7 84.0 5684 2132.9
ISO+FF-C
ISD»FF-C
4*5
6
1.43
1.43
59
104
46
48
1.9
1.9
19.2 324.8
28.6 275.3
5.1
7.1
21.5
16.2
84.0
84.0
3090
5684
1651.0
1244.6
sassssasxrsss
:ssssia:sss>MS3S2SS3c:sax«*i89as2si««ss:ss3BitiX3S9:*a«t33:saaiss3:a:3ss2Bzz3ss:
19-13
-------
Tabla 19.1.2-4. Surra ry of Coal Switching/Cleaning Costs for the Greenidge Plant (June 1988 Dollars)
Technology Boiler Main Boiler capacity Coal Capital Capital Annual Annual $02 $02 S02 Cost
Nutter Retrofit Size Factor Sulfur Cost Cost Cost Cost Renovad Removed Effect.
Difficulty <«U) (X) Content (SMM> <«/kW)
-------
TABLE 19.1.2-5. SUMMARY OF NQx RETROFIT RESULTS FOR GREENIDGE
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
4,5
6
FIRING TYPE
FWF
TANG
TYPE OF NOx CONTROL
LNB
OFA
FURNACE VOLUME (1000 CU FT)
NA
57.6
BOILER INSTALLATION DATE
1950
1953
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
40
25
SCR RETROFIT RESULTS *
BOILER NUMBER
4+5
6
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
18
28
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
728
1014
New Heat Exchanger (1000$)
1358
1908
TOTAL SCOPE ADDER COSTS (1000$)
2104
2950
RETROFIT FACTOR FOR SCR
1.52
1.52
GENERAL FACILITIES (PERCENT)
20
20
* Cold side SCR reactors for boilers 4+5 and 6 would be located
behind their respective chimney.
19-15
-------
Table 19.1.2-6. NOx Control Cost Results for the Greenidge plant (Jine 1988 Dollars)
siiisziBS8ai8si3iasaisBBiasaasait83is3aifaaassai8isssii88isa&s3SB8S9aai39S8SS8*ss38sss8S8S8s:ssss8isaas3isssax8B
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx MOx Cost
Ntmber Retrofit Size Factor Sulfur Cost Coat Cost Coat Removed Removed Effect.
Difficulty (NW) (X) Content (SWt) (X) (tons/yr) (S/ton)
Factor (X)
LMC-INB 4.5 1.00 30 48 1.9 1.6 52.6 0.3 2.7 40.0 221 1561.2
LNC-LM8-C 4,5 1.00 30 48 1.9 1.6 52.6 0.2 1.6 40.0 221 926.3
LMC-0FA 6 1.00 104 48 1.9 0.6 6.0 0.1 0.3 25.0 343 402.1
INC-OFA-C 6 1.00 104 i6 1.9 0.6 6.0 0.1 0.2 25.0 343 238.5
SCR-3 4*5 1.52 59 46 1.9 16.6 280.9 5.1 21.6 80.0 834 6164.8
SCR-3 6 1.52 104 48 1.9 23.0 220.7 7.3 16.7 80.0 1096 6679.7
SCR-3-C 4+5 1.52 59 46 1.9 16.6 280.9 3.0 12.7 80.0 834 3621.1
SCR-3-C 6 1.52 104 48 1.9 23.0 220.7 4.3 9.8 80.0 1096 3920.9
SCR-7 4+5 1.52 59 46 1.9 16.6 280.9 4.7 19.6 80.0 834 5582.9
SCR-7 6 1.52 104 48 1.9 23.0 220.7 6.5 14.8 80.0 1096 5899.0
SCR-7-C 4*5 1.52 59 46 1.9 16.6 280.9 2.7 11.5 80.0 834 3287.8
SCR-7-C 6 1.52 104 48 1.9 23.0 220.7 3.8 8.7 80.0 1096 3473.6
:333B3:a3:333333S»33333333333333SS:*833S333SS3S3S3333S333S33tZ33S£S388S«<833333S8S:8*3338333:33SX:3Sl3333S3333S
19-16
-------
19.1.3 Hilliken Steam Plant
The Milliken Steam Plant is located in Tompkins County, New York, as
part of the New York State Electric and Gas Corporation system. The plant
contains two coal-fired boilers with a total gross generating capacity of
316 MW. Tables 19.1.3-1 through 19.1.3-9 summarize the plant operational
data and present the SOg and N0X control cost and performance estimates.
TABLE 19.1.3-1. MILLIKEN STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
157
27
1955
2
159
73
1958
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
TANGENTIAL
93
NO
1.9
11800
14
DRY DISPOSAL
LANDFILL/SOLD/OFF-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)
ESP
1972
0.03
99.5
ESP
1972
0.05
99.6
GAS EXIT RATE (1000 ACF
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
188.6
650
290
300
188.6
650
290
300
19-17
-------
TABLE 19.1.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR MILLIKEN UNIT 1 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION : SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA ' LOW
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 1099 0 1099
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM " 1.41 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.43
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 0 _5
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 1
would be located north of unit 2.
19-18
-------
TABLE 19.1.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR MILLIKEN UNIT 2 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE HIGH
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE
BAGHOUSE 100-300
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 1113 0 1113
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.34 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.35
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 0 5
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for unit 2
would be located north of unit 2.
19-19
-------
Table 19.1.3-4. Sutmry of FGD Control Costs for theMilliken Plant (June 1988 Dollars)
H
tl
II
H
II
<1
II
II
II
11
II
II
=;==:5ss
=s*==a*
II
II
II
«
II
II
tt
II
:z==s=s=
:s==ss3sa
:= = ssasa
!SS«=SS3SS:
II
II
II
II
II
II
It
sss:s=:ss
it
ti
it
ii
ii
ii
ii
ii
ii
Technology
Boiler
Main
Boiler Capacity Coal
Cspital
Capital
Annual
Annual
S02
S02
S02 Cost
Ncnber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost:
Removed
Removed
Effect.
Difficulty
Content
(SHH)
<*/kW)
-------
Table 19.1.3-5. Summary of Coat Switching/Cleaning Costs for the Mi I liken Plant (June 1988 Dollars)
SSItSIKSSSSSSIBSSS
S333Z3SSSSS53
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nunbtr Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (MVI) (X) Content (SMM) (SAW) (SMM)
Factor (X)
Annual S02 502 S02 Cost
Cost Kenoved Removed Effect,
(mills/kwti) (X) (tons/yr) (»/ton)
CS/B+S15
CS/B+S15
1.00
1.00
157
159
27
73
1.9
1.9
5.4
5.4
34.3
34.2
6.1
14.4
16.3
14.2
54.0
54.0
3121
8547
1941.6
1689.8
CS/B+t15-C
CS/B+S1S-C
1.00
1.00
157
159
27
73
1.9
1.9
5.4
5.4
34.3
34.2
3.5
8.3
9.4
8.2
54.0
54.0
3121
8547
1120.2
971.0
CS/B*«5
CS/8*$5
1.00
1.00
157
159
27
73
1.9
1.9
3.8
3.8
24.0
23.9
2.7
5.8
7.3
5.7
54.0
54.0
3121
8547
867.6
673.4
CS/B»J5-C
CS/8*S5-C
1.00
1.00
157
159
27
73
1.9
1.9
3.8
3.8
24.0
23.9
1.6
3.3
4.2
3.3
54.0
54.0
3121
8547
502.5
387.8
SSSSS:S1533S3S3SSS3SS3S
IS::33333S333S3333338SS33SSaSX33333
sxxsBSSsssssa
19-21
-------
TABLE 19.1.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR1 MILLIKEN
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
•
1
2
FIRING TYPE
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
FURNACE VOLUME (1000 CU FT)
93
93
BOILER INSTALLATION DATE
- 1955
1958
SLAGGING PROBLEM'
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
i
LOW
SCOPE ADDER PARAMETERS--
i
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
38
38
New Duct Length (Feet)
200
200
New Duct Costs (1000$)
1290
13 0|0
New Heat Exchanger (1000$)
2443
2462
TOTAL SCOPE ADDER COSTS (1000$)
3771
3800
RETROFIT FACTOR FOR SCR
1.34
1.16
GENERAL FACILITIES (PERCENT)
20
13 ¦
* Cold side SCR reactors for unit 1 would be located south of
the unit 1 chimney, and cold side SCR reactors for unit 2
would be located north of the unit 2 chimney.
19-22
-------
Table 19.1.3-7. NOx Control Cost Results for the Mi I liken Plant (X) Content (UW) CS/kW) (UW> (mills/kwh) (X) (tons/yr) ($/ton)
Factor
IMC-OFA 1 1.00 1S7 27 1.9 0.7 4.7 0.2 0.4 25.0 294 553.0
INC-OM 2 1.00 159 73 1.9 0.7 4.7 0.2 0.2 25.0 804 203.1
LNC-0FA-C 1 1.00 157 27 1.9 0.7 4.7 0.1 0.3 25.0 294 327.9
LNC-OFA-C 2 1.00 159 73 1.9 0.7 4.7 0.1 0.1 25.0 804 120.5
SCR-3 1 1.34 157 27 1.9 28.0 178.3 9.1 24.6 80.0 940 9724.5
SCR-3 2 1.16 159 73 1.9 25.4 159.8 8.9 8.7 80.0 2573 3456.0
SCR-3-C 1 1.34 157 27 1.9 28.0 178.3 5.4 14.4 80.0 940 5705.0
SCR-3-C 2 1.16 159 73 1.9 25.4 159-8 5.2 5.1 80.0 2573 2024.3
SCR-7 1 1.34 157 27 1.9 28.0 178.3 7.8 21.1 80.0 940 8348.2
SCR-7 2 1.16 159 73 1.9 25.4 159.8 7.6 7.5 80.0 2573 2946.9
SCR-7-C 1 1.34 157 27 1.9 28.0 178.3 4.6 12.4 80.0 940 4916.5
SCR-7-C 2 1.16 159 73 1.9 25.4 159.8 4.5 4.4 80.0 2573 1732.7
a:::sts::s::ssss:s3sssKs:ss:3:5ssss:3Stssssss3ssssissss=3rssssisss;5Siss:3SSs:s::s22ss:ssa*:::S3S9tt:::szss==:si
19-23
-------
TABLE 19.1.3-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MILLIKEN UNITS 1 AND 2
ITEM ¦
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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$ 42
TOTAL COST (1000$)
ESP UPGRADE CASE 42
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE ; NA
Long duct residence time exists between the boilers and the
retrofit ESPs. A high factor was assigned to ESP upgrade
since little space is available around the ESPs.
19-24
-------
Table 19.1.3-9. Suimary of DSD/FSI Control Costs for the Mil liken Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 SC2 Cost
Nurber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
19.2 NIAGARA MOHAWK POWER CORPORATION
19.2.1 Dunkirk Steam Plant
The Dunkirk steam plant is located on Lake Erie in Chautauqua County,
New York, and is operated by Niagara Mohawk Power Corporation.. The Dunkirk
plant contains four coal-fired boilers with a total name plate generating
capacity of 583 MW.
Table 19.2.1-1 presents operational data for the'existing equipment at
the Dunkirk plant. Coal shipments are received by railroad and transferred
to a coal storage and handling area east of the plant. PM emissions are
controlled by retrofit ESPs located behind the boilers. Units 1 and 2 have
separate roof-mounted chimneys and units 3 and 4 share a common chimney
located between the unit 3 and 4 ESPs. The plant operates its own off-site
disposal area for dry fly ash. |
Lime/Limestone and Lime Spray Drying FGD Costs--
L/LS-FGD absorbers for all boilers would be located west of the unit 4
ESPs. A low site access/congestion factor was assigned to this location
because of the space availabile beside unit 4. In addition, the general
facilities factor was low (5 percent). The duct length requirements for
units 1 and 2 would be greater than 700 feet. A duct length of 400 feet
would be required for both units 3 and 4. Since units 1 and 2 have
roof-mounted chimneys, access to them would be difficult. Therefore, a new
chimney would be built beside the absorbers. Access to units 1 and 2 is
difficult because of the congestion created by the unit 3 and 4 ESPs and the
lake; therefore, a high site access/congestion factor was assigned to
units 1 and 2 flue gas handling. The access to the chimney for units 3 and
4 is somewhat difficult; hence, these units were assigned a medium site
access/congestion factor for flue gas handling.
LSD with reuse of the existing ESPs was not considered here because the
boilers are equipped with hot side ESPs which cannot be reused for LSD
application. Therefore, LSD with a new baghouse was considered for units 1
through 4. LSD absorbers would be placed in a location similar to the
L/LS-FGD case with similar general facility factors, site access/congestion
19-26
-------
TABLE 19.2.1-1. DUNKIRK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3,4
90 195,185
88,86 83,90
1950 1959,60
TANGENTIAL
NA 104
NO NO
2.1
12800
9.0
DRY DISPOSAL
OFF SITE LANDFILL
1,2 3
'RAILROAD/TRUCK
PARTICULATE CONTROL
TYPE
ESP
ESP
INSTALLATION DATE
1973,72
1972
EMISSION (LB/MM BTU)
0.03,0.08
0.14,0.03
REMOVAL EFFICIENCY
99.4,98.7
97.6,99.4
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
2.2
2.2
SURFACE AREA (1000 SQ FT)
223.4
446.9
GAS EXIT RATE (1000 ACFM)
715
1350
SCA (SQ FT/1000 ACFM)
304
322
OUTLET TEMPERATURE (*F)
600
600
* 1989 Projected.
19-27
-------
factors and duct length. Baghouses would be located behind the absorbers
with a low site access/congestion factor assigned to them.
Tables 19.2.1-2 through 19.2.1-4 present the retrofit factor inputs to
the IAPCS model and the estimated cost for the installation of L/LS-FGD and
LSD at the Dunkirk plant.
Coal Switching and Physical Coal Cleaning Costs-
Table 19.2.1-5 presents the IAPCS cost results for CS at the Dunkirk
plant. These costs do not include pulverizer and boiler operating cost
changes or any system modifications that may be necessary to the coal
handling system. Since the Dunkirk plant is not a mine mouth plant, PCC was
not considered.
N0x Control Technologies--
OFA was considered for N0X emissions control for the four tangential-
fired, dry bottom boilers at the Dunkirk plant. Tables 19.2.1-6 and
19.2.1-7 summarize the N0x performance estimates and costs for installing
OFA at the Dunkirk plant.
Selective Catalytic Reduction-
Hot side SCR reactors for units 1-4 would be located adjacent to their
respective ESPs. The site access/congestion factor for all locations would
be low. Ductwork requirements for all units would be 300 feet. Medium to
low general facility factors were assigned to all units. Tables 19.2.1-6
and 19.2.1-7 present the retrofit factors and costs for installation of SCR
at the Dunkirk plant.
Furnace Sorbent Injection and Duct Spray Drying F6D Costs--
Sorbent injection technologies were not considered for any of the units
at the Dunkirk plant because ESPs are hot side and cannot be reused for
sorbent injection technologies.
19-28
-------
TABLE 19.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR DUNKIRK
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) 600-1000 NA
ESP REUSE NA
BAGHOUSE 600-1000
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY NO NA NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY YES NA YES
ESTIMATED COST (1000$) 630 0 630
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.53 NA
ESP REUSE CASE NA
BAGHOUSE CASE 1.54
ESP UPGRADE NA NA NA
NEW BAGHOUSE NA NA 1.16
GENERAL FACILITIES (PERCENT) 5 0 5
19-29
-------
TABLE 19.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR,DUNKIRK
UNIT 3 OR 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
i
S02 REMOVAL
LOW
NA
i LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
i NA
BAGHOUSE CASE
. MEDIUM
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
NA
BAGHOUSE
300-600
ESP REUSE
NA
NA
. NA
NEW BAGHOUSE
NA
NA
! LOW
SCOPE ADJUSTMENTS
1
WET TO DRY
NO
NA
; NO
ESTIMATED COST (1000$)
NA
NA
NA .
NEW CHIMNEY
NO
NA
• NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
1
FGD SYSTEM
1.35
NA
1
ESP REUSE CASE
NA
BAGHOUSE CASE
1.31
ESP UPGRADE
NA
NA
, NA
NEW BAGHOUSE
NA
NA
: 1.16
GENERAL FACILITIES (PERCENT) 5
0
5
19-30
-------
Table 19.2.1-4. Surmary of FGD Control costs for the Dunkirk Plant (June 1988 Dollars)
ississssssssssssssssssas:
sssssss:
!«533SS5SS55
=======
'ssssasss
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
S02
S02
S02 Cost
Number
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (HW)
<%>
Content
(SMN)
(t/kW)
-------
Table 19.2.1-5. suimary of Coal Snitching/Cleaning Costs for the Dunkirk Plant (June 1988 Dollars)
II
it
II
II
II
II
II
ISIISIIS
usaisaisaissss:
==r=i===:
:=======:
= = = =="=
:s3:ss:ss::s
II
II
II
II
II
II
II
=========¦
II
II
tl
II
II
It
II
II
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capi tal
Annual
Annual
S02
S02
S02 Cost
Nurfcer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
(X)
Content
.<««>
(S/kU)
(SUM)
(mills/kwh)
(tons/yr)
<$/ton)
Factor
CS/B+S15
1
1.00
90
88
2.1
3.9
43.3
10.5
15.1
54.0
5905
1769.9
CS/8+S15
2
1.00
90
86
"2.1
3.9
43.3
10.2
15.,1
54.0
5771
1773.7
CS/B*$15
3
1.00
195
83
2.1
7.1
36.6
20. S
14.5
54.0
12068
1700.1
CS/B»t15
4
1.00
185
90
2.1
6.8
36.9
21.0
14.i
54.0
12415
1693.1
CS/B-I15-C
1
1.00
90
88
2.1
3.9
43.3
6.0
8.7
54.0
590S
1017.0
CS/B*S15 -C
2
1.00
90
86
2.1
3.9
43.3
5.9
8.7
54.0
5771
1019.2
CS/8*S15-C
3
1.00
195
83
2.1
7.1
36.6
11.8
8.3
54.0
12068
976.7
CS/B»S15-C
4
1.00
185
90
2.1
6.8
36.9
12.1
8.3
54.0
12415
972.5
CS/B-»$5
1
1.00
90
88
2.1
3.0
33.0
4.6
6.6
. 54.0
5905
771.9
CS/8+S5
2
1.00
90
86
2.1
3.0
33.0
4.5
6.6
54.0
5771
775.0
CS/B»$5
3
1.00
195
83
2.1
5.1
26.2
8.5
6.0
54.0
12068
700.4
CS/B*I5
4
1.00
185
90
2.1
4.9
26.6
8.6
5.9
54.0
12415
695.7
CS/B-S5-C
1
1.00
90
88
2.1
3.0
33.0
2.6
3.8
54.0
5905
444.5
CS/B»S5-C
2
1.00
90
86
2.1
3.0
33.0
2.6
3.8
54.0
5771
446.3
CS/B*S5-C
3
1.00
195
83
2.1
5.1
26.2
4.9
3.4
54.0
12068
403.2
CS/B»$5-C
4
1.00
185
90
2.1
4.9
26.6
5.0
3.4'
54.0
12415
400.4
19-32
-------
TABLE 19.2.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR DUNKIRK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
4
3-4
FIRING TYPE
TANG
TANG
TANG
NA
TYPE OF NOx CONTROL
OFA
OFA
OFA
NA
FURNACE VOLUME (1000 CU FT)
NA
104
104
NA
BOILER INSTALLATION DATE
1950
1959
1960
NA
SLAGGING PROBLEM
NO
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
0
Ductwork Demolition (1000$)
25
45
43
74
New Duct Length (Feet)
300
• 300
300
300
New Duct Costs (1000$)
1398
- 2197
2130
3246
New Heat Exchanger (1000$)
0
0
0
0
TOTAL SCOPE ADDER COSTS (1000$)
1422
2242
2173
3320
RETROFIT FACTOR FOR SCR
1.16
1.16
1.16
1.16
GENERAL FACILITIES (PERCENT)
20
13
13
13
19-33
-------
Tabie "9.2.:-?. NOx Control Cost Results for the Dunkirk Plant (June 1988 Dollars)
"echnclogy
Boiler
Ma;n
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Number
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
D i f f i cl.1 ty
(X>
Content
CSKM5
'.k'C-CFA
1
1.00
90
88
2.1
0.6
6.6
0.1
0.2
25.0
500
259.9
.NC-OFA
2
1 .30
90
86
2.1
0.6
6.6
0.1
0.2
25.0
488
266.0
.NC-OFA
3
1.00
195
83
2.1
0.8
4.1
0.2
0.1
25.0
1021
173.5
.NC-OFA
4
1.00
'85
90
2.1
0.8
4.3
0.2
0.1
25.0
1051
165.1
LNC-CFA-C
1
1.00
90
88
2.1
0.6
6.6
0.1
0.1
25.0
500
154.3
.NC-CFA-C
2
1.00
90
86
2.1
0.6
6.6
0.1
0.1
25.0
488
157.9
-NC-CFA-C
3
1.00
195
83
2.1
0.8
4.1
0.1
0.1
25.0
1021
102.9
UC-CFA-C
4
1.00
185
90
2.1
0.8
4.3
0.1
0.1
25.0
1C51
97.9
SCR - 3
1
1 . r6
90
88
2.1
16.9
188.1
5.9
8.5
80.0
1599
3677.5
SCR-3
2
1.16
90
86
2.1
16.9
188.1
5.9
8.7
80.0
1563
375 5 .9
SCR-3
3
1.16
195
83
2.1
28.8
147.8
¦ 10.5
7.4
80.0
3268
3204.6
SCR-3
4
1.16
185
90
2.1
27.6
149.3
10.1
6.9
80.0
3362
3002.3
SCR - 3
3-4
' .16
380
86
2.1
46.8
123.1
18.0
6.3
80.0
6599
2730.3
SCR-3-C
1
1.16
90
88
2.1
16.9
188.1
3.4
5.0
80.0
1599
2154.4
SCR-3-C
2
1.16
90
86
2.1
16.9
188.1
3.4
5.1
80.0
1563
2200.4
SCR-3-C
3
1.16
195
83
2.1
28.8
147.8
6.1
4.3
80.0
3268
1875.5
SCR-3-C
4
1.16
185
90
2.1
27.6
149.3
5.9
4.1
80.0
3362
1757.0
SCR-3-C
3-4
1.16
380
86
2.1
•46.8
123.1
10.5
3.7
80.0
6599
-.596.1
SCR - 7 ^
1
1.16
90
88
2.1
16.9
188.1
5.1
7.4
80.0
1599
3219.3
SCS-7
2
i.16
90
86
2.1
16.9
188.1
5.1
7.6
80.0
1563
3287.1
SCR- ?
3
1.16
195
83
2.1
28.8
147.8
8.9
6.3
80.0
3268
2719.0
SCR-7
4
1.16
185
90
2.1
27.6
149.3
8.6
5.9
80.0
3362
2554.5
SCR- 7
3-4
1.16
380
86
2.1
46.8
123.1
14.9
5.2
80.0
6599
2261.6
SCR-7-C
1
1.16
90
88
2.1
16.9
188.1
3.0
4.4.
80.0
1599
1891.9
SCR-7-C
2
1.16
90
86
2.1
16.9
188.1
3.0
4.5
80.0
1563
1931.8
SCR-7-C
3
1. "6
195
83
2.1
28.8
147.8
5.2
3.7
80.0
3268
1597.3
SCR-7-C
4
1.16
185
90
2.1
27.6
149.3
5.0
3.5
80.0
3362
1500.4
SCR-7-C
3-4
1.16
380
86
2.1
46.8
123.1
8.8
3.1
80.0
6599
1327.5
II
II
II
H
II
II
II
II
II
II
II
ssssssssss
S3SS3I3
BSSSSS1S3
S33VSSS*
========
======,====
======
xssasisss
19-34
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicabi 1 i ty - -
All four boilers at the Dunkirk plant would be considered good
candidates for retrofit or repowering technologies because of their small
boiler size and possibly short remaining useful life.
19.2.2 C. R. Huntley Steam Plant
The C. R. Huntley steam plant is located within Erie County, northwest
of Buffalo, New York, and is part of the Niagara Mohawk Power Company. The
plant has six coal-fired boilers with a total nameplate generating capacity
of 715 MW. The plant is located east of the East Niagara River which marks
the boundary between the United States and Canada.
Table 19.2.2-1 presents the operational data for the Huntley plant.
All six boilers burn medium sulfur coal. Coal shipments are received by
railroad and conveyed to a coal storage and handling area beside the East
Niagara River. The coal is crushed and conveyed to the first boilerhouse,
containing units 67 and 68, along the southeast side of unit 68; and then to
the second boilerhouse, containing units 63-66, along the southeast side of
unit 63.
PM emissions for all six boilers are controlled with retrofit ESPs.
The ESPs are located behind each boiler away from the river, (the
boilerhouses are situated between the ESPs and the river). Units 67-68 are
served by a common chimney centered behind the units. Units 63-66 are
served by another chimney located to the north and on the side of the
boilerhouse away from the ESPs.
The plant has a dry ash handling system. Waste ash is disposed of in
an off-site landfill because of limited space surrounding the plant. Also,
a small portion of the dry fly ash is sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
The absorbers for units 67-68 would be placed directly behind their
respective ESPs and close to the common chimney. The absorbers for units
63-66 would be placed behind their respective ESPs and adjacent to the
common chimney located to the side of unit 66. The lime/limestone
preparation, storage, and waste handling area was assumed to be located
19-35
-------
TABLE 19.2.2-1. HUNTLEY STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)*
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2,3,4 (63-66)
85
67,68,75,79
1942,48,53,54
ARCH
NA
NO
1.8
12,800
8.0
.5,6 (67-68)
185,190
80,81
1957,58
TANGENTIAL
104,104
NO
1.8
12,800
8.0
DRY DISPOSAL/SELL
OFF-SITE LANDFILL
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 ¦
1973 1973
0.02,0.02,0.07,0.13 0.15,0.09
99.5,99.2,98.4,96.2 98.2,98.6
1.7 1.7
NA NA
500 1352
246 312
310 650
* Average forecasted capacity factors over next 15 years (1990-2004).
19-36
-------
close to the coal unloading facility south of the plant. Because there is
limited space available for F6D waste, it would be dewatered and sent
off-site. For units 67-68, a paved road and storage building would need to
be relocated, therefore, a factor of 10 percent was assigned for general
facilities. For units 63-66, however, no major demolition/relocation of
existing equipment/buildings would be required and a base factor of 5
percent was assumed.
The FGD system absorber for units 67-68 would be located in a low site
access/congestion area after the demolition/relocation of the storage
building and road. For units 63-66, a low access/congestion factor was also
assigned to the absorbers.
Flue gas handling for units 67-68 would require about 300 feet of
ducting. A high access/congestion factor was applied to units 67-68 because
the common chimney is surrounded by the retrofit ESPs and it is difficult to
access on either side. Flue gas handling for units 63-66 would require
approximately 500 feet of ducting, since the absorbers would be located
behind the ESPs and the ducting must reach from the common chimney to the
absorbers and then back again. Because the common chimney for units 63-66
is located beside the boilerhouse and the main access road to the
switchyard, a medium site access/congestion factor was assigned to flue gas
hand!ing.
For LSD, reuse of the ESPs was not considered for units 67-68 because
the units are equipped with hot side ESPs. Therefore, a new baghouse was
considered. LSD absorbers and new FFs would be located in a similar
location to L/LS-FGD absorbers. For flue gas handling, units 67-68 would
require 300-500 feet of ducting with high site access/congestion. Reuse of
ESPs was not considered for units 63-66 because the building that houses the
ESPs would require major demolition in order to access the ESPs. For this
reason, new FFs were chosen for these units. The FFs would be positioned
close to their respective absorbers and have low site access/congestion
factors. A medium factor was assigned to flue gas handling.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 19.2.2-2 and 19.2.2-3.
Table 19.2.2-4 presents the process area retrofit factors and capital and
operating costs for commercial FGD technologies. These costs do not include
19-37
-------
TABLE 19.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR C.R. HUNTLEY
UNITS 1-4 (63-66, EACH)
FGO TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW NA LOW
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE NA
BAGHOUSE CASE MEDIUM
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE NA
BAGHOUSE 300-600
ESP REUSE NA NA NA
NEW BAGHOUSE NA NA LOW
SCOPE ADJUSTMENTS
WET TO DRY NO
ESTIMATED COST (1000$) NA
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER NO
NA
NA
NA
0
NO
NA
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.35
NA
NA
NA
NA
NA
NA
1.36
NA
1.16
GENERAL FACILITIES (PERCENT) 5
19-38
-------
TABLE 19.2.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR C.R. HUNTLEY
UNITS 5 OR 6 (67-68)
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$)
NEW CHIMNEY
ESTIMATED COST (1000S)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
LOW
HIGH
300-600
NA
NA
NO
NA
NO
0
NO
1.39
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
0
NA
NA
NA
LOW
NA
HIGH
NA
300-600
NA
LOW
NO
NA
NO
0
NO
NA
1.36
NA
1.16
GENERAL FACILITIES (PERCENT) 10
10
19-39
-------
Table 19.2.2-4. Sunnary of FGD Control Costs for the Huntley Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annua I
S02
S02
S02 Cost
Number
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
(%>
Content
($MM>
($/kW)
(SMM)
(miIts/kwh)
(%)
(tons/yr)
CS/ton)
Factor
(%)
L/S FGD
1
1.35
85
67
1.8
37.3
439.4
17.3
34.8
90.0
6055
2865.6
L/S FGD
2
1.35
85
68
1.8
37.3
439.4
17.4
34.4
90.0
6145
2832.1
L/S FGD
3
1.35
85
75
1.8
37.4
439.5
17.8
31.8
90.0
6778
2622.0
L/S FGD
4
1.35
85
79
1.8
37.4
439.5
18.0
30.6
90.0
7139
2518.5
L/S FGD
5
1.39
185
80
1.8
59.5
321.5
28.4
21.9
90.0
15732
1804.4
L/S FGD
6
1.39
190
81
1.8
60.2
317.0
28.9
21.4
90.0
16359
1766.4
L/S FGD
1-4
1.35
340
72
1.8
77.1
226.7
38.8
18.1
90.0
26026
1490.2
L/S FGD
5-6
1.39
375
81
1.8
89.7
239.2
44.5
16.7
90.0
32288
1379.6
L/S FGD-C
1
1.35
85
67
1.8
37.3
439.4
10.1
20.3
90.0
6055
1669.4
L/S FGD-C
2
1.35
85
68
1.8
37.3
439.4
10.1
20.0
90.0
6145
1649.9
L/S FGD-C
3
1.35
85
75
1.8
37.4
439.5
10.3
18.5
90.0
6778
1527.0
L/S FGO-C
4
1.35
85
79
1.8
37.4
439.5
10.5
17.8
90.0
7139
1466.4
L/S FGD-C
5
1.39
185
80
1.8
59.5
321.5
16.5
12.8
90.0
15732
1050.7
L/S FGD-C
6
1.39
190
81
1.8
60.2
317.0
16.8
12.5
90.0
16359
1028.6
L/S FGD-C
1-4
1.35
340
72
1.8
77.1
226.7
22.6
10.5
90.0
26026
867.1
L/S FGD-C
5-6
1.39
375
81
1.8
89.7
239.2
25.9
9.7
90.0
32288
802.9
LC FGD
1-6
1.37
715
76
1.8
105.5
147.6
59.6
12.5
90.0
57010
1044.7
LC FGD-C
1-6
1.37
715
76
1.8
105.5
147.6
34.6
7.3
90.0
57010
606.8
LSD+FF
1
1.36
85
67
1.8
23.0
271.1
10.5
21.0
87.0
5819
1804.3
LSD+FF
2
1.36
85
68
1.8
23.0
271.1
10.5
20.8
87.0
5906
1782.2
LSD+FF
3
1.36
85
75
1.8
23.0
271.1
10.7
19.2
87.0
6514
1643.7
LSD+FF
4
1.36
85
79
1.8
23.0
271.1
10.8
18.4
87.0
6861
1575 .8
LSD+FF
5
1.36
185
80
1.8
56.5
305.3
22.7
17.5
87.0
15123
1502.6
LSD+FF
6
1.36
190
81
1.8
57.7
303.9
23.3
17.3
87.0
15726
1479.1
LSD+FF-C
1
1.36
85
67
1.8
23.0
271.1
6.1
12.3
87.0
5819
1051.5
LSD+FF-C
2
1.36
85
68
1.8
23.0
271.1
6.1
12.1
87.0
5906
1038.6
LSD+FF-C
3
1.36
85
75
1.8 •
23.0
271.1
6.2
11.2
87.0
6514
957.6
LSD+Ff-c
4
1.36
85
7V
1.8
23.0
271.1
6.3
10.7
87.0
6861
917.9
LSD+FF-C
5
1.36
185
80
1.8
56.5
305.3
13.3
10.2
87.0
15123
877.6
LSD+FF-C
6
1.36
190
81
1.8
57.7
303.9
13.6
10.1
87.0
15726
863.9
-shxszshhs
========
========:
ISSSSSS
issiias::;
tsiiiiss;
:sasisss:
:========
____________
======
=======*==:
=========
19-40
-------
downtime needs in the case of LSD-FGD. The low cost FGD option shows the
effect of no spare absorber modules and economy of scale when combining FGD
systems and increased absorber size.
Coal Switching and Physical Coal Cleaning Costs--
Table 19.2.2-5 presents the IAPCS cost results for CS at the Huntley
plant. These costs do not include boiler and pulverizer operating cost
changes or any system modifications that may be necessary to blend coal.
PCC was not evaluated because this is not a mine mouth plant.
Low N0x Combustion--
Units 63-66 are wet bottom, arch-fired boilers rated at 85 MW each and
units 67-68 are dry bottom, tangential-fired boilers. The combustion
modification technique applied to units 67-68 was OFA. LNC was not
considered for units 63-66. Table 19.2.2-6 shows the estimated OFA N0x
reduction performances based on the volumetric heat release rate. Table
19.2.2-7 presents the cost of retrofitting OFA at the Huntley plant.
Selective Catalytic Reduction--
SCR reactors for all units would be located in a similar layout as the
FGD absorbers with all six reactors located in low site access/ congestion
areas. Units 67-68 are hot-side SCR and units 63-66 are cold side SCR. The
ammonia storage system was placed in the same manner as the lime/limestone
preparation, storage, and handling areas. Duct lengths of 300 and 500 feet
were estimated for units 67-68 and 63-66, respectively. A paved road and a
storage building behind units 67-68 would have to be relocated and a factor
of 20 percent was assigned to the general facilities. For units 63-66, a
base factor of 13 percent was assigned to general facilities because no
major relocation is required. Table 19.2.2-7 presents the estimated cost of
retrofitting SCR at the Huntley plant.
Duct Spray Drying and Furnace Sorbent Injection--
FSI and DSD technologies were not considered for units 67-68 because of
their hot-side ESPs. The sorbent injection technologies were not considered
19-41
-------
Table 19.2.2-5. Sinmary of Coal Switching/Cleaning Costs for the Huntley PlBnt
-------
TABLE 19.2.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR C.R. HUNTLEY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
,2,3,4(63-66)
5,6,(67-68)
FIRING TYPE
ARCH
TANG
TYPE OF NOx CONTROL
NA
OFA
FURNACE VOLUME (1000 CU FT)
40.3
104
BOILER INSTALLATION DATE
1942-54
1957,58
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
NA
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000S)
0
0
Ductwork Demolition (1000$)
24
44
New Duct Length (Feet)
500
300
New Duct Costs (1000$)
2253
2164
New Heat Exchanger (1000$)
1691
0
TOTAL SCOPE ADDER COSTS (1000$)
COMBINED
9021
3294
INDIVIDUAL
3967
2208
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
20
19-43
-------
fable 19.2.2-7. NOx Control Cost Results for the Huntley plant (June 1988 Dollars]
Technology
Boiler
Main
Boiler Capacity Coal
Capi tal
Capital Annual
Annual
NOx
NOX
NOx Cost
Hinber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removec
Removed
Effect.
Difficulty (NW)
(X)
Content
CSMM)
<$/W()
(MM)
(nills/kwh)
(X)
(tons/yr)
(J/ton)
Factor
-------
for units 63-66 because of the short duct residence time and the enclosed
ESPs which made access to them very difficult.
Atmospheric FTuidized 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 Huntley plant. All units would be considered good
candidates for repowering and retrofit because of their small boiler sizes.
19-45
-------
19.3 ROCHESTER GAS & ELECTRIC
19.3.1 Rochester 7 Russell
LSD with reuse of the existing ESPs was not considered for the
Rochester 7 Russell plant due to the inadequate size of the ESPs. LSD with
a new baghouse was also not considered since the boilers fire a high sulfur
coal. Sorbent injection technologies were not evaluated since the ESPs
cannot be reused.
TABLE 19.3.1-1. ROCHESTER 7 RUSSELL 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
12 3 4
46 63 63 82
21 45 41 53
1948 1950 1953 1957
TANGENTIAL
NA NA 30.4 54.1
NO
2.3
13100
8.0
DRY DISPOSAL
SELL/OFF-SITE
112 2
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP ESP ESP ESP
1948 1950 1953 1957
0.12 NA 0.23 NA
98.2 NA 96.5 97.6
2.4 2.4 2.4 2.4
27.7 29.8 29.8 34
200 230 230 251
139 130 130 136
300 298 298 280
19-46
-------
TABLE 19.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ROCHESTER 7
RUSSELL UNIT 1 OR 2 *
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA NA
FLUE GAS HANDLING HIGH NA
ESP REUSE CASE NA
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NA
ESTIMATED COST
(1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NA
ESTIMATED COST
(1000$)
322,441
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.55
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
10
0
0
* The L/LS-FGD absorbers for units 1 and 2 would be located
east of the unit 1 and 2 chimney, behind the fuel storage area.
19-47
-------
TABLE 19.3.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR ROCHESTER 7
RUSSELL UNIT 3 OR 4 *
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
NA
FLUE GAS HANDLING
HIGH
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
NA
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NA
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
NA
NA
ESTIMATED COST (1000$)
441,574
0
0
OTHER
NO
RETROFIT FACTORS
FGD SYSTEM
1.55
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
0
0
* The L/LS-FGD absorbers for units 3 and 4 would be located
east of the unit 3 and 4 chimney, behind the fuel storage area.
19-48
-------
Table 19.3.1-4. Sumary of FGD Control Costs for the Rochester 7 Russell Plant (Jin 1988 Dollars)
Technology Boiler Main Soiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nimber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
Table 19.3.1-5. Sutttbry of Coal Switching/Cleaning Costs for the Rochester 7 Russell Plant (Jwe 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annuel S02 S02 S02 Cost
Ntmber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty CMW)
(X)
Content
(SMK)
(S/kW)
(SUM)
(mills/kMfc)
Ctons/yr)
(*/too)
Factor
(%>
CS/8+S15
1
1.00
46
21
2.3
2.8
60.6
1.9
22.9
57.0
809
2395.1
CS/B+S15
2
1.00
63
45
2.3
3.5
55.9
4.4
17.7
57.0
2374
1847.8
CS/B+S15
3
1.00
63
41
2.3
3.5
55.9
4.1
18.0
57.0
2163
1884.0
CS/B+S15
4
1.00
82
53
2.3
4.2
51.7
6.3
16.6
57.0
3639
1738.0
CS/B*I15-C
1
1.00
46
21
2.3
2.8
60.6
1.1
13.3
57.0
809
1387.6
CS/B*S15-C
2
1.00
63
45
2.3
3.5
55.9
2.5
10.2
57.0
2374
1065.3
CS/B+S15-C
3
1.00
63
41
2.3
3.5
55.9
2.4
10.4
57.0
2163
1086.7
CS/B-S15-C
4
1.00
82
53
2.3
4.2
51.7
3.6
9.6
57.0
3639
1001.0
CS/B-»$5
1
1.00
46
21
2.3
2.3
50.2
1.2
13.6
57.0
809
1427.4
CS/B*S5
2
1.00
63
45
2.3
2.9
45.5
2.2
8.9
57.0
2374
935.5
CS/B*$5
3
1.00
63
41
2.3
2.9
45.5
2.1
9.2
57.0
2163
966.9
CS/B+S5
4
1.00
82
53
2.3
3.4
41.3
3.0
8.0
57.0
3639
833.0
:S/B»S5-C
1
1.00
46
21
2.3
2.3
50.2
0.7
7.9
57.0
809
830.6
CS/B*S5-C
2
1.00
63
45
2.3
2.9
45.5
1.3
5.2
57.0
2374
541.4
CS/B+S5-C
3
1.00
63
41
2.3
2.9
45.5
1.2
5.4
57.0
2163
559.9
CS/B+S5-C
4
1.00
82
53
2.3
3.4
41.3
1.8
4.6
57.0
3639
481.4
„ISS5====:=
0
H
il
II
II
II
It
II
=====*=
:::::::::
:=s==3*==
:i:sszes
II
N
II
II
N
II
M
N
tl
II
N
«
II
II
M
II
II
sisiaita
19-50
-------
TABLE 19.3.1-6. SUMMARY OF NOx RETROFIT RESULTS FOR ROCHESTER
7 RUSSELL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA
NA
30.4
BOILER INSTALLATION DATE
1948
1950
1953
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
15
19
19
New Duct Length (Feet)
400
400
400
New Duct Costs (1000$)
1259
1512
1513
New Heat Exchanger (1000$)
1170
1413
1413
TOTAL SCOPE ADDER COSTS (1000$)
2444
2944
2944
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for units 1, 2, and 3 would be located
east of the chimneys, behind the feuel storage area.
19-51
-------
TABLE 19.3.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR ROCHESTER
7 RUSSELL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
4
1-2
3-4
FIRING TYPE
TANG
NA
NA
TYPE OF NOx CONTROL
OFA
NA
NA
FURNACE VOLUME (1000 CU FT)
54.1
NA
NA
BOILER INSTALLATION DATE
1957
NA
NA
SLAGGING PROBLEM
NO
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
25
NA
NA
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
23
29
36
New Duct Length (Feet)
400
400
400
New Duct Costs (1000$)
1765
2084
2463
New Heat Exchanger (1000$)
1655
1963
2329
TOTAL SCOPE ADDER COSTS (1000$)
3443
4076
4828
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
20
20
20
* Cold side SCR reactors for unit 4 and the combined cases would
be located east of the chimneys, behind the fuel storage area.
19-52
-------
Table 19.3.1-8. NOx Control Cost Results for the Rochester 7 Russell Plant (Jirie 1988 Dollars)
Technology
::::isaa
8oiler
aaaassssaa
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
NOx
NOx
NOx Cost
Nimber
Retrofit
size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Oi fficulty
C»/ton)
Factor
IX)
LNC-OFA
1
1.00
44
21
2.3
0.5
9.9
0.1
1.2
25.0
59
1672.9
INC-QFA
2
1.00
63
45
2.3
0.5
8.2
0.1
0.5
25.0
174
647.0
INC-OFA
3
1.00
63
41
2.3
0.5
8.2
0.1
0.5
25.0
159
710.1
INC-OFA
4
1.00
82
53
2.3
0.6
7.0
0.1
0.3
25.0
267
469.2
LNC-OFA-C
1
1.00
46
21
2.3
0.5
9.9
0.1
0.7
25.0
59
994.0
L.NC-OFA-C
2
1.00
63
45
2.3
0.5
8.2
0.1
0.3
25.0
174
384.0
IMC-OFA-C
3
1.00
63
41
2.3
0.5
8.2
0.1
0.3
25.0
159
421.5
LWC-OFA-C
4
1.00
82
53
2.3
0.6
7.0
0.1
0.2
25.0
267
278.2
SCR-3
1
1.52
46
21
2.3
15.2
329.8
4.5
53.0
80.0
190
23594.3
SCR-3
2
1.52
63
45
2.3
17.9
283.9
5.4
21.8
80.0
557
9717.6
SCR-3
3
1.52
63
41
2.3
17.9
283.9
5.4
23.9
80.0
508
10641.0
SCR-3
4
1.52
82
53
2.3
20.6
251.1
6.4
16.7
80.0
855
7445.9
SCR-3
1-2
1.52
109
35
2.3
24.6
225.4
7.6
22.8
80.0
750
10151.1
SCR-3
3-4
1.52
145
48
2.3
29.8
205.3
9.4
15.5
80.0
1369
6903.4
SCR-3-C
1
1.52
46
21
2.3
15.2
329.8
2.6
31.1
80.0
190
13875.7
SCR-3-C
2
1.52
63
45
2.3
17.9
283.9
3.2
12.8
80.0
557
5711.4
SCR-3-C
3
1.52
63
41
2.3
17.9
283.9
3.2
14.0
80.0
508
6254.5
SCR-3-C
4
1.52
82
53
2.3
20.6
2S1.1
3.7
9.6
80.0
855
4374.1
SCR-3-C
1-2
1.52
109
35
2.3
24.6
225.4
4.5
13.4
80.0
750
5962.7
SCR-3-C
3-4
1.52
145
48
2.3
29.8
205.3
5.5
9.1
80.0
1369
4052.7
SCR-7
1
1.52
46
21
2.3
15.2
329.8
4.1
48.6
80.0
190
21630.6
SCR-7
2
1.52
63
45
2.3
17.9
283.9
4.9
19. B
80.0
557
8800.9
SCR-7
3
1.52
63
41
2.3
17.9
283.9
4.9
21.6
80.0
508
9634.9
SCR-7
4
1.52
82
53
2.3
20.6
251.1
5.7
15.0
80.0
855
6667.6
SCR-7
1-2
1.52
109
35
2.3
24.6
225.4
6.7
20.1
80.0
750
8972.6
SCR-7
3-4
1.52
145
48
2.3
29.8
205.3
8.3
13.6
80.0
1369
6043.9
SCR-7-C
1
1.52
46
21
2.3
15.2
329.8
2.4
28.6
80.0
190
12750.6
SCR-7-C
2
1.52
63
45
2.3
17.9
283.9
2.9
11.6
80.0
557
5186.2
SCR-7-C
3
1.52 .
63
41
2.3
17.9
283.9
2.9
12.7
80.0
508
5678.0
SCR-7-C
4 "
1.52
82
53
2.3
20.6
251.1
3.4
8.8
80.0
855
3928.1
SCR-7-C
1-2
1.52
109
35
2.3
24.6
225.4
4.0
11.9
80.0
750
5287.5
SCR-7-C
3-4
1.52
145
48
2.3
29.8
205.3
4.9
8.0
80.0
1369
3560.3
::::3£Z2::::=:::::::::£3aisir=::33:::asssi=:::a8=3:is3>ss3e::3=ssaisiS833BB3:::oxaii=aaniiiafa::2sia3:ai=aaa3as
19-53
-------
SECTION 20.0 OHIO
20.1 CARDINAL OPERATING COMPANY
20.1.1 Cardinal Steam Plant
The Cardinal steam plant is located within Jefferson County, Ohio, as
part of the Cardinal Operating Company system. The plant is located on a
long narrow site, bounded by the Ohio River on one side and a railroad and
major highway on the other. The plant contains three coal-fired boilers
with a total gross generating capacity of 1,880 MW. Figure 20.1.1-1 presents
the plant plot plan showing the location of all boilers and major associated
auxiliary equipment.
Table 20.1.1-1 presents operational data for the existing equipment at
the Cardinal plant. The boilers burn low (unit 3) to high (units 1 and 2)
sulfur coal (0.7-3.2 percent sulfur). Coal shipments are received by barge
and conveyed to a coal storage and handling area located beside the Ohio
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 to a landfill on-site or sold.
Lime/Limestone and Lime Spray Drying FGD Costs--
Figure 20.1.1-1 shows the general layout and location of the FGD control
system. Units 1 and 2 are located northeast of the coal pile, sitting beside
each other parallel to the Ohio River. They are each served by their own
chimney. The powerhouse is close to the river and the ESPs/chimneys (Units 1
and 2} are located away from the river on the north side of the powerhouse.
Unit 3 is located south of the coal pile and is served by its own chimney.
The unit 3 chimney and ESPs are close to the river and powerhouse near the
railroad track. There are natural draft cooling towers located south of
unit 3. Unit 3 was considered in this study even though it is a 1971 NSPS
boiler burning low sulfur coal (1.2 lb per million Btu) and may not require
scrubbing. If scrubbing is required, it is more cost effective to switch to
20-1
-------
Absorbers for
Units 1 & 2
Waste Handling
Area
NHj Storage
System
Lime/Limestone
Storage/Preparation
Area
O
Absoroer for
Unit 3
Cooling
Tower
Not to scale
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 20.1.1-1. Cardinal plant plot plan
20-2
-------
TABLE 20.1.1-1. CARDINAL STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1,2
3
GENERATING CAPACITY (MW-each)
615
650
CAPACITY FACTOR (PERCENT)
51,
55
53
INSTALLATION DATE
1966
-67
1977
FIRING TYPE
FWF
OWF
COAL SULFUR CONTENT (PERCENT)
3.2,
3.1
0.7
COAL HEATING VALUE (BTU/LB)
11652-775
11235
COAL ASH CONTENT (PERCENT)
12
17.2
FLY ASH SYSTEM
DRY DISPOSAL
ASH DISPOSAL METHOD
ON-SITE/SALE
STACK NUMBER
1-2
3
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL
TYPE
ESP
ESP
INSTALLATION DATE
1980
1977
EMISSION (LB/MM BTU)
0.04
0.03
REMOVAL EFFICIENCY
99.4
99.8
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
2.0
0.7
SURFACE AREA (1000 SQ FT)
891
1918.1
EXIT GAS FLOW RATE (1000 ACFM)
2100
3900
SCA (SQ FT/1000 ACFM)
424
492
OUTLET TEMPERATURE (*F)
350,
310
310
20-3
-------
a higher coal sulfur content, taking into account the fuel cost differential
while estimating cost effectiveness. Costs presented in this section for
unit 3 are dependent on acid rain legislation and plant Figure 20.1.1-1
decisions regarding the type of coal fired. For units 1 and 2, space is
available for the absorbers on either side of the ESP units. The absorbers
for L/LS-FGD and LSD-FGD for unit 1 would be located close to the ESPs
northeast of the unit in the present employee parking area. The unit 2
absorber would be located southwest of the respective ESPs in an open area
between the chimney and coal pile. For unit 3, the absorbers would be
located between the river and powerhouse close to the coal conveyor. Part
of the plant roads and employee parking area would need to be demolished/
relocated for the unit 2 absorbers; therefore, a factor of 10 percent was
assigned to general facilities. A 5 percent general facilities factor was
assigned to the unit 1 absorber location since no major relocation would be
required. For unit 3, part of the railroad and plant roads would need to be
demolished and relocated to make space for the storage/handling area; a
10 percent factor was assigned to general facilities for this location. The
lime storage/handling area for units 1 and 2 would be located southeast of
unit 1 in an open area between the coal pile and river. The storage/handling
area for unit 3 would be a separate location northwest of the unit away from
the absorbers and close to the railroad track. The waste handling area for
all three units would be located close to the coal pile between the highway
and railroad.
Retrofit Difficulty and Scope Adder Costs--
A low site access/congestion factor was assigned to the absorber
locations for units 1 and 2 due to the absorbers being located in a
relatively open area. The unit 3 location was assigned a high site access/
congestion factor because of its location east of the powerhouse between the
coal pile, powerhouse, and Ohio River with very high access difficulty.
For flue gas handling, short duct runs for units 1 and 2 would be
required for L/LS-FGD cases since the absorbers would be located adjacent to
the ESPs and close to the chimneys. Unit 3 would require moderate duct runs
for flue gas handling due to the absorbers being located away from the
chimney. A low site access/congestion factor was assigned to the flue gas
20-4
-------
handling system for units 1 and 2. A high factor was assigned to unit 3 due
to the access difficulty and congestion created by the ESPs and coal
conveyor.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 20.1.1-2 through 20.1.1-4. No large
scope adder cost is required for the Cardinal plant. The overall retrofit
factors determined for the L/LS-FGD cases were low to medium (1.24 for
units 1 and 2; 1.61 for unit 3).
The absorbers for LSD-FGD would be located in a similar location as in
L/LS-FGD cases. Reused ESPs was the only LSD-FGD technology considered for
the units because of the large SCAs (>420). For LSD-FGD flue gas handling
cases, short duct runs and a low site access/congestion factor was assigned
for units 1 and 2. Unit 3 would require a moderate duct run with a high
site access/congestion factor due to the access difficulty to the upstream
of the ESPs (because of their location adjacent to the powerhouse). The
retrofit factors determined for the LSD technology case for the units were
low (1.20-1.62) and did not include particulate control upgrading costs.
Separate retrofit factors were developed for upgrading ESPs for the units.
A low retrofit factor (1.16) was assigned to the upgraded ESP location for
units 1 and 2 due to the available space around the ESPs. The unit 3
location was assigned a medium retrofit factor (1.36) because the ESPs are
bounded by the powerhouse, chimney, and river. These factors were used in
the IAPCS model to estimate particulate control upgrading costs.
Table 20.1.1-5 presents the cost estimates for L/LS-FGD and LSD-FGD
cases for units 1 and 2. Costs are not presented for unit 3, because this
unit is burning a low sulfur coal resulting in a very high unit cost. The
LSD-FGD costs include upgrading the ESPs for boilers 1-2. 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
20-5
-------
TABLE 20.1.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR CARDINAL 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 LOW
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
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 (10005) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.24 1.24
ESP REUSE CASE 1.20
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
20-6
-------
TABLE 20.1.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR CARDINAL UNIT 2
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
LOW
LOW
100-300 100-300
NA
NA
LOW
LOW
NA
100-300
NA
LOW
NA
SCOPE ADJUSTMENTS
WET TO DRY NO
ESTIMATED COST (1000$) NA
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER NO
NO
NA
NO
0
NO
NO
NA
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.24
NA
NA
1.24
NA
NA
1.20
NA
1.16
NA
GENERAL FACILITIES (PERCENT) 10
10
10
20-7
-------
TABLE 20.1.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR CARDINAL UNIT 3
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 300-600
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 1.61 1.64
ESP REUSE CASE 1.62
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.36
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
20-8
-------
Table 20.1.1-5. Surma ry of FGD Control Costs for the Cardinal Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 S02 Cos:
Nintoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
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 20.1.1-6.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Cardinal 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 N0X
technologies evaluated at the steam plant were: LNB and SCR.
Low N0x Combustion--
Units 1 and 2 are dry bottom, front wall-fired boilers each rated at
615 MW. Unit 3 is a dry bottom, opposed wall-fired boiler rated at 650 MW.
The combustion modification technique applied for these boilers was LNB. As
Table 20.1.1-7 shows, the LNB N0X reduction performances for these units
could not be estimated using the simplified procedures. No boiler
information could be found for units 1 to 3 to assess their N0X reduction
performances. Since these boilers are relatively new, it is estimated that
a N0X reduction of 35 percent can be achieved by units 1 and 2 retrofitted
with LNB, and a N0X reduction of 45 percent can be achieved by unit 3
retrofitted with LNB. Units 1 and 2 were installed between 1966 and 1967
while unit 3 was installed in 1977.
Table 20.1.1-8 presents the cost of retrofitting LNB at the Cardinal
boilers, assuming an NOx reduction performance of 35 percent for units 1 and
2 and 45 percent for unit 3.
20-10
-------
Table 23.1.1-6. Sunnary of Coal Switching/Cleaning Costs for the Cardinal Plant (June 1988 Dollars)
isiiitsa2C2aisiaBsa3Sfiiiiisis:sissssssiiiaississsssiisiiiiii«sviii::::aiasa«aisis:s33iiiaiBS23Stiiii::s:x3Sissx
Technology Boiler Main 8oilcr Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Content (SMH)
-------
TABLE 20.1.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR CARDINAL
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
FWF
FWF
OWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
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) 35
35
45
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
106
106
110
New Duct Length (Feet)
350
350
500
New Duct Costs (1000$)
5019
5019
7406
New Heat Exchanger (1000$)
5543
5543
5730
TOTAL SCOPE ADDER COSTS (1000$)
10667
10667
13246
RETROFIT FACTOR FOR SCR
1.16
1.16
1.34
GENERAL FACILITIES (PERCENT)
13
25
13
20-12
-------
Table 20.1.1-8. NOx Control Cost Results for the Cardinal Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
ISSZ31SaS3SSIISI3Ss ss sss
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Number
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW)
(X)
Content
(S/kW)
(mi IIs/kwh)
<*>
(tons/yr)
(S/:on)
factor
(X)
INC-INB
1
1.00
615
51
3.2
5.3
8.6
1.1
0.4
35.0
. 4321
263.8
LNC-INB
2
1.00
615
55
3.1
5.3
8.6
1.1
0.4
35.0
4604
247.6
UiC-lNB
3
1.00
650
53
0.7
5.4
a.3
1.2
0.4
45.0
6363
183.2
INC-INB-C
1
1.00
615
51
3.2
5.3
8.6
0.7
0.2
35.0
4321
156.6
LNC-INB-C
2
1.00
615
55
3.1
5.3
8.6
0.7
0.2
35.0
4604
147.0
LNC-LUB-C
3
1.00
650
53
0.7
5.4
8.3
0.7
0.2
45.0
6363
108.8
SCR-3
1
1.16
615
51
3.2
75.5
122.8
27.8
10.1
80.0
9876
2812.0
SCR-3
2
1.16
615
55
3.1
77.6
126.3
28.4
9.6
80.0
10523
2703.5
s:r-3
3
1.34
, 650
53
. 0-7 .
88.0
135.4
31.4
10.4
80.0
11311
2776.1
SCR-3-C
1
1.16
615
51
3.2
75.5
122.8
16.3
5.9
80.0
9876
1645.4
SCR-3-C
2
1.16
615
55
3.1
77.6
126.3
16.6
5.6
80.0
10523
1582.0
5CR-3-C
3
1.34
650
53
0.7
88.0
135.4
18.4
6.1
80.0
11311
1625.4
SCR-7
1
1.16
615
51
3.2
75.5
122.8
22.7
8.3
80.0
9876
2298.1
SCR-7
2
1.16
615
55
3.1
77.6
126.3
23.4
7.9
80.0
10523
2221.9
SCR-7
3
1.34
650
53
0.7
88.0
135.4
26.0
8.6
80.0
11311
2299.2
SCR-7-C
1
1.16
615
51
3.2
75.5
122.8
13.3
4.9
80.0
9876
1350.9
SCR-7-C
2
1.16
615
55
3.1
77.6
126.3
13.7
4.6
80.0
10523
1306.1
SCR-7-C
3
1.34
650
53
0.7
88.0
135.4
15.3
5.1
80.0
11311
1352.2
S8SSSSS8S888ISSSS8SSIS8S8SSS8SSf8SSSSI8!21taSSS83S3S8S8S8SSSS8S8S8S88SSSSS:
20-13
-------
Selective Catalytic Reduction--
Table 20.1.1-7 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 reactor for unit 1 would be located southwest of the respective
ESPs in an open area between the chimney and coal pile. Since both reactors
were located in open area having easy access with no major obstacles, the
reactors for units 1 and 2 were assigned low access/congestion factors. The
SCR reactor for unit 2 would be located immediately north of the ESP for
unit 2 in the employee parking lot. A 25 percent general facility factor
was assigned to the reactor for unit 2 because part of the parking lot would
have to be demolished and relocated. For unit 3, the SCR reactor would be
located in a relatively high congested area, west of the respective ESP and
north of the cooling towers. Because access to this area is relatively
easy, a medium access/congestion factor was assigned to the reactor for
unit 3. All reactors were assumed to be in areas with high underground
obstructions. The ammonia storage system was placed in a remote area having
a low access/congestion factor.
As discussed in Section 2, all NOx control techniques were evaluated
independently from those techniques evaluated for SOg control. If both SC^
and N0X emissions needed to be reduced at this plant, the SCR reactors would
have to be located downstream of the FGD absorbers in highly congested areas.
The SCR reactors for units 1 and 2 would be located immediately north and south
of the absorbers for units 1 and 2, respectively. The SCR reactors for
unit 3 would be located east of the ESP and south of the absorber for unit 3,
near the banks of the river. In all three cases, high access/congestion
factors would be assigned to the three SCR reactors. Table 20.1.1-8 presents
the estimated cost of retrofitting SCR at the Cardinal boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO2 control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
20-14
-------
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located in a
similar fashion as LSD-FGD. The retrofit of DSD and FSI technologies at the
Cardinal steam plant for units 1 and 2 would be relatively easy. There is
sufficient duct residence time between the boilers and the ESPs and, in
addition, the ESPs have large SCAs (>400). There is not sufficient duct
residence time for unit 3; however, ESPs are large and can be modified for
sorbent injection technologies. A low retrofit factor for units 1-2 was
assigned to DSD and FSI for the same reasons as mentioned in the previous
section. Tables 20.1.1-9 and 20.1.1-10 present a summary of the site access/
congestion factors for DSD and FSI technologies at the Cardinal steam plant.
Table 20.1.1-11 presents the costs estimated to retrofit DSD and FSI at the
Cardinal 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 Cardinal plant. None of the boilers would be considered
good candidates for AFBC retrofit because of their large boiler sizes
(>600 MW), high capacity factors, and relatively new ages (built after 1960).
20-15
-------
TABLE 20.1.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CARDINAL UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 117
TOTAL COST (1000$)
ESP UPGRADE CASE 117
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
20-16
-------
TABLE 20.1.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR CARDINAL UNIT 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) 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) 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 1.36
NEW BAGHOUSE NA
20-17
-------
Table 20.1.1-11. Suimary of DSO/FSI Control Costs for the Cardinal Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capi tal
Annual
Annual
S02
S02
S02 Cost
N'jrtoer
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty
(Mil)
(X)
Content
(JMM)
(SUM)
(mi IIs/kwh)
CX)
(tons/yr)
(I/ton)
Factor
-------
20.2 CINCINNATI GAS AND ELECTRIC COMPANY
20.2.1 Walter C. Beck.iord Steam Plant
The Beckjord steam plant is located within Clermont County, Ohio, as
part of Cincinnati Gas and Electric Company system. The plant has six coal-
fired boilers with a total gross generating capacity of 1,201 MW.
Figure 20.2.1-1 presents the plant plot plan showing the location of all
boilers and major associated auxiliary equipment.
Table 20.2.1-1 presents operational data for the existing equipment at
the Beckjord steam plant. Boilers 1-4 bum low sulfur coal (1.0 percent
sulfur) while boilers 5-6 burn medium sulfur coal (2.5 percent). Coal
shipments are received by barge 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; the ESPs for boilers 1-5 are located behind each unit, while
the ESPs for unit 6 are located on the boiler building roof and at ground
level. Units 1-4 have a dry fly ash handling system and fly ash is disposed
off-site or sluiced to ponds located north of the plant. Fly ash from
units 5 and 6 are wet sluiced to ponds located south of the plant.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 20.2.1-1 shows the general layout and location of the FGD control
system. The absorbers for all units would be located between the unit 6 ESPs
and the ash pond. No major demolition/relocation would be required for
placing the absorbers; therefore, a base factor of 5 percent was assigned to
general facilities. The lime storage/preparation area and waste handling
area would be located south of the plant between the power house and the ash
pond site, adjacent to the turbines.
Retrofit Difficulty and Scope Adder Costs-
Absorbers for all units would be located south of the plant, parallel to
the river, and adjacent to the unit 6 ESPs.
Unit 1-6 absorber locations were assigned a medium site access/
congestion factor due to the closeness to the river (poor load bearing
capacity of soil).
20-19
-------
Han
-------
TABLE 20.2.1-1. BECKJORD 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
1,2
3
4
5
6
100
135
162
255
449
6,8
10
22
29
57
1952
1954
1958
1962
1969
TANG
FWF
TANG
TANG
TANG
1.0
1.0
0.9
2.5
2.5
11000
11000
11000
11000
11000
14.4
14.2
14.2
16.4
16.0
DRY
HANDLING
WET
SLUICE
OFF-SITE
ON-
SITE
1-2
3
4
5
5
BARGE
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
1974
1973
1975
1976
1969/79
0.05
0.05
0.05
0.05
0.05
99.5
99.5
99.5
99.5
99.5
1.0
1.0
1.0
1.0
2.5
82.6
123.1
119.9
216
203/832
350
505
585
875
1600
236
244
205
247
646
250
250
250
250
250
20-21
-------
For flue gas handling for L/LS-FGO cases, various length duct runs would
be required for each unit. Units 1-4 would require extreme length duct runs,
unit 5 long and unit 6 short. Separate site access/congestion factors for
both technologies were assigned to each unit for the flue gas handling system
as follows. For units 1-4, a high access/congestion factor was assigned
because of the location of the chimney and obstructions caused by other units
ESPs/chimneys. Unit 5 had a high access factor due to congestion created by
unit 5 ESPs and obstructions caused by the unit 6 ESPs to access unit 5. For
unit 6, a low access/congestions factor was designated because the ESPs are
located beside unit 6 and access to the existing duct work on both the
upstream and downstream of the ESPs would be easy.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables. 20.2.1-2 through 20.2.1-4.
The largest scope adder for the Beckjord plant would be the conversion of
unit 5 fly ash conveying/disposal system from wet to dry for conventional
l/LS-FGD cases. It was assumed that dry fly ash would be necessary to
stabilize scrubber sludge waste. However, this conversion would not be
necessary for units 1-4 because the existing fly ash handling system is dry.
An additional scope adder would be the construction of a new chimney for
units 1-5 to decrease the extreme duct runs. The retrofit factors determined
for the L/LS-FGD cases ranged from moderate to high (1.31-1.84).
LSD with reused ESP was the only LSD-FGD technology considered for
unit 6 because it has a large SCA (=646). LSD with a new baghouse was the
only case considered for units 3-5 because of the extreme difficulty to reuse
the ESPs for these units and the considerable amount of ESP upgrading
required. Also, the locations of the ESPs are in very congested areas and
there would be extreme difficulty to access and extend the duct runs
required. A new baghouse was located south of the plant close to the
absorbers. For flue gas handling for LSD cases, the duct runs and site
access/congestion factors would be the same as in L/LS-FGD cases as stated
earlier. The retrofit factors determined for the LSD technology case ranged
from moderate to high (1.31 to 1.87) and did not include particulate control
costs. A separate retrofit factor was developed for upgrading ESPs for
unit 6. This factor for unit 6 was low (1.16) due to the available space
around the ESPs. A separate retrofit factor developed for the new baghouse
20-22
-------
TABLE 20.2.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BECKJORD UNITS 1-4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
MEDIUM
MEDIUM
FLUE GAS HANDLING
HIGH
HIGH
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
1000 +
1000 +
ESP REUSE
NA
BAGHOUSE
1000 +
ESP REUSE
NA
NA
NA .
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
YES
YES
ESTIMATED COST (1000$)
1134
1134
1134
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.84
1.84
ESP REUSE CASE
NA
BAGHOUSE CASE
1.87
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
5
5
5
20-23
-------
TABLE 20.2.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR BECKJORD UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
MEDIUM
MEDIUM
FLUE GAS HANDLING
HIGH
HIGH
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
600-1000
600-1000
ESP REUSE
NA
BAGHOUSE
600-1000 '
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
MEDIUM
SCOPE ADJUSTMENTS
WET TO DRY
YES •
NO
NO
ESTIMATED COST (1000$)
2170
NA
NA
NEW CHIMNEY
YES
YES
YES
ESTIMATED COST (1000$)
1785
1785
1785
OTHER
NO
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.61
1.66
ESP REUSE CASE
NA
BAGHOUSE CASE
1.69
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.36
GENERAL FACILITIES (PERCENT)
5
5
5
20-24
-------
TABLE 20.2.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR BECKJORD UNIT 6
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 (10005)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
MEDIUM MEDIUM
LOW LOW
0-100
NA
NA
NO
NA
NO
0
NO
1.31
NA
NA
0-100
NA
NA
NO
NA
YES
1997
NO
1.27
NA
NA
MEDIUM
LOW
NA
0-100
NA
LOW
NA
YES
3603
NO
0
NO
1.31
NA
1.16
NA
GENERAL FACILITIES (PERCENT) 5
5
20-25
-------
for units 1-5 was medium (1.36) and reflects the site access difficulty
created by the location of the area being close to the turbines and river.
These factors were used by the IAPCS model to estimate the particulate
control costs for all units.
Table 20.2.1-5 presents the costs estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boiler 6 and installing new
baghouses to handle the additional particulate loading for boilers 1-5. 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 SO-j 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 20.2.1-6. CS was not evaluated for
units 1-4 since these units currently fire a low sulfur coal.
N0x Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Beckjord 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 for all
units except unit 3 and LNB and SCR for unit 3.
20-26
-------
Table 20.2.1-5. Sunnry of FGO Control Costi for the Beckjord Plant (Jine 1988 Dollars)
:::::ss:s£i3:::s:s:s:2aiss::ssa:ss:iis33t3:ssss:ssss3a*«s£3S3SS5S»s«sS8SBix::a93;3SSS=ss3=3:ss:s::ss333ss:=:ss::
Technoloay
Boiler Nain
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nimber Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW>
(X)
Content
(SMM)
(S/kW)
(SMM)
(nills/kuh)
(X)
(tons/yr)
(1/ton)
Factor
LC FGO
1-2
1.84
200
7
1.0
46.2
230.9
16.5
134.5
90.0
984
16760.4
IC FGO
3-6
1.54
1001
39
1.8
153.6
153.5
72.6
21.2
90.0
49390
1469.3
LC FGO-C
1-2
1.84
200
7
1.0
46.2
230.9
9.7
78.7
90.0
984
9813.1
LC FGO-C
3-6
1.54
1001
39
1.8
153.6
153.5
42.3
12.4
90.0
49390
855.8
LFGD
1
1.84
100
6
1.0
48.4
484.4
16.9
321.0
90.0
422
40010.7
LFGO
2
1.84
100
8
1.0
48.4
484.5
17.0
243.3
90.0
562
30322.1
I FGO
3
1.84
135
10
1.0
57.0
422.0
20.1
170.1
90.0
949
21196.5
LFGD
4
1.84
162
22
0.9
62.9
388.2
23.3
74.7
90.0
2255
10344.0
LFGD
5
1.61
255
29
2.5
78.5
307.8
31.6
48.9
90.0
12994
2435.4
LFGD
6
1.31
449
57
2.5
92.6
206.2
48.7
21.7
90.0
44971
1082.0
IFGD-C
1
1.84
100
6
1.0
48.4
484.4
9.9
188.1
90.0
422
23438.6
LFGD-C
2
1.84
100
8
1.0
48.4
484.5
10.0
142.5
90.0
562
17758.7
LFGO-C
3
1.84
135
10
1.0
57.0
422.0
11.8
99.6
90.0
949
12413.4
LFGD-C
4
1.84
162
22
0.9
62.9
388.2
13.6
43.7
90.0
2255
6051.5
LFGD-C
5
1.61
255
29
2.5
78.5
307.8
18.5
28.5
90.0
12994
1422.4
LFGD-C
6
1.31
449
57
2.5
92.6
206.2
28.3
12.6
90.0
44971
629.1
LSD*£SP
6
1.31
449
57
2.5
50.0
111.4
23.1
10.3
47.0
23505
984.0
LSO+ESP-C
6
1.31
449
57
2.5
50.0
111.4
13.5
6.0
47.0
23505
573.3
LSD*FF
1
1.87
100
6
1.0
31.4
314.1
11.0
208.8
75.0
351
31294.4
LSD»FF
2
1.87
100
8
1.0
31.4
314.2
11.0
157.2
75.0
468
23568.1
LSD+FF
3
1.87
135
10
1.0
38.6
285.6
13.1
110.5
75.0
791
16507.9
LSD+FF
4
1.87
162
29
0.9
43.6
269.3
15.2
36.8
75.0
2490
6090.8
LSD+FF
5
1.69
255
29
2.5
64.4
252.4
22.0
33.9
70.0
10046
2189.0
LSD+FF-C
1
1.87
100
6
1.0
31.4
314.1
6.4
122.3
75.0
351 ¦
18331.1
LSO+FF-C
2
1.87
100
8
1.0
31.4
314.2
6.5
92.1
75.0
468
13804.1
LSO+FF-C
3
1.87
135
10
1.0
38.6
285.6
7.7
64.8
75.0
791
9676.4
LSO+FF-C
4
1.87
162
29
0.9
43.6
269.3
8.9
21.6
75.0
2490
3568.2
LSO+FF-C
5
1.69
255
29
2.5
64.4
252.4
12.9
19.9
70.0
10046
1282.9
20-27
-------
Table 23.2.1-6. Sunnary of Coal Snitching/Cleaning Coses for the Beckjord Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Ccst
Nurtber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MV> (X) Content (SHH) (S/kW) ($W<) (miiIs/kwh) (X) Ctons/yr) ($/ton)
factor (X)
CS/B+S15 5 1.00 255 29 2.5 6.8 26.8 9.7 U.9 68.0 9760 988.7
CS/B-S15 6 1.00 449 57 2.5 12.0 26.6 30.6 13.7 68.0 33777 9C6.2
:S/B->$15-C 5 1.00 255 29 2.5 6.8 26.8 5.6 8.6 68.0 9760 569.6
CS/B-S15-C 6 1.00 449 57 2.5 12.0 26.6 17.6 7.8 68.0 33777 520.8
CS/8*$5 5 1.00 255 29 2.5 4.2 16.4 3.8 5.9 68.0 9760 393.1
CS/B+J5 6 1.00 449 57 2.5 7.3 16.3 11.3 5.0 68.0 33777 333.8
CS/B'S5-C 5 1.00 255 29 2.5 4.2 16.4 2.2 3.4 68.0 9760 227.1
CS/B»t5-C 6 1.00 449 57 2.5 7.3 16.3 6.5 2.9 68.0 33777 192.2
20-28
-------
Low N0X Combustion--
Units 1, 2, and 4 to 6 are dry bottom, tangential-fired boilers; units 1
and 2 are rated at 100 MW each while units 4, 5, and 6 are rated at 162, 255,
and 449 MW, respectively. Unit 3 is a dry bottom, front wall-fired boiler
rated at 135 MW. The combustion modification technique applied for this
evaluation to all units except unit 3 was OFA and that applied to unit 3 was
LNB. As Tables 20.2.1-7 and 20.2.1-8 show, the OFA N0X reduction performance
for units 1, 2, 4, 6 was estimated to be 20 percent while the OFA N0X
reduction performance for unit 5 was estimated to be 15 percent. The LNB NO^
reduction performance for unit 3 was estimated to be 43 percent. These
reduction performance levels were assessed by examining the effects of heat
release rates and furnace residence time through the use of the simplified
N0X procedures. Table 20.2.1-9 presents the cost of retrofitting OFA and
LNB at the Beckjord boilers.
Selective Catalytic Reduction-
Tables 20.2.1-7 and 20.2.1-8 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
ESPs to the reactor and from the reactor to the chimney.
The SCR reactors for units 1 to 6 were located south of unit 6 between
the ESPs for unit 6 and the ash pond. The SCR reactors for all units were
assigned medium access/congestion factors because of the foundation
difficulty caused by poor load bearing soil (close to the river). However,
the poor soil quality is offset by the reactors being located in a low
congestion area with easy access. All six reactors were assumed to be in
areas with high underground obstructions. Since access to the unit 3-4
chimneys are difficult, a new chimney was built for both units. The ammonia
storage system was placed in a remote area having a low access/congestion
factor. Table 20.2.1-9 presents the estimated cost of retrofitting SCR at
the Beckjord boilers.
20-29
-------
TABLE 20.2.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR BECKJORD UNITS 1-3
COMBUSTION MODIFICATION RESULTS
FIRING TYPE
TYPE OF NOx CONTROL
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
FURNACE RESIDENCE TIME (SECONDS)
ESTIMATED NOx REDUCTION (PERCENT)
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
SCOPE ADDER PARAMETERS--
New Chimney (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
3
TANG
TANG
FWF
OFA
OFA
LNB
14.7
14.7
15
26.2
26.2
69.4
3.04
3.04
2.46
20
20
43
MEDIUM MEDIUM MEDIUM
0
0
1134
27
27
34
1000+
1000+
1000+
4500
4500
6000
1864
1864
2232
6391
6391
9400
1.34
1.34
1.34
13
13
13
20-30
-------
TABLE 20.2.1-8. SUMMARY OF NOx RETROFIT RESULTS FOR BECKJORD 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)
13
15.8
13.9
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
69.6
73.3
147.6
FURNACE RESIDENCE TIME (SECONDS)
2.97
2.45
2.83
ESTIMATED NOx REDUCTION (PERCENT)
20
15
20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
MEDIUf1
SCOPE ADDER PARAMETERS--
New Chimney (1000$)
1134
0
0
Ductwork Demolition (1000$)
39
55
83
New Duct Length (Feet)
1000+
750
150
New Duct Costs (1000$)
9000
6426
1789
New Heat Exchanger (1000$)
2490
3268
4589
TOTAL SCOPE ADDER COSTS (1000$)
12662
9749
6462
RETROFIT FACTOR FOR SCR
1.34
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
20-31
-------
Table 20.2.1-9. NOx Control Cost Results for the Beckjord Plant a=ai
ciaisS;
:a33c:3i:
:taesa:aa
IIISSSII'
3*ss»=:
tflaaaeaacic:
*3XE=»
it
ii
$4
II
II
ft
U
11
II
H
II
Technology
Boiler
Main
Boiler Capacity coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nuitoer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MW)
(X)
Content
(SW)
<»/kW>
(SIM)
(mi Us/lcah)
(X)
<$/ton)
Factor
(X)
LNC-LNB
3
1.00
135
10
1.0
2.9
21.3
0.6
5.3
43.0
244
2546.9
LNC-LNB-C
3
1.00
135
10
1.0
2.9
21.3
0.4
3.1
43.0
244
1512.1
LNC-OFA
1
1.00
100
6
1.0
0.6
6.2
0.1
2.5
20.0
36
3706.7
LNC-OFA
2
1.00
100
8
1.0
0.6
6.2
0.1
1.9
20.0
48
2780.0
LUC-OfA
4
1.00
162
22
0.9
0.8
4.6
0.2
0.5
20.0
214
757.1
LNC-OFA
5
1.00
255
29
2.5
0.9
3.5
0.2
0.3
15.0
333
583.5
LNC-OFA
6
1.00
449
57
2.5
1.1
2.5
0.2
0.1
20.0
1537
158.6
LNC-OFA-C
1
1.00
100
6
1.0
0.6
6.2
0.1
1.5
20.0
36
2200.2
LNC-OFA-C
2
1.00
100
8
1.0
0.6
6.2
0.1
1.1
20.0
48
1650.1
LNC-OFA-C
4
1.00
162
22
0.9
0.8
4.6
0.1
0.3
20.0
214
449.3
LNC-OFA-C
5
1.00
255
29
2.5
0.9
3.5
0.1
0.2
15.0
333
346.4
LNC-OFA-C
6
1.00
449
57
2.5
1.1
2.5
0.1
0.1
20.0
1537
94.2
SCR-3
1
1.34
100
6
1.0
23.7
237.2
6.9
131.3
80.0
144
47883.5
SCR-3
2
1.34
100
8
1.0
23.7
237.2
6.9
98.6
80.0
192
35960.5
SCR-3
3
1.34
135
10
1.0
30.5
225.8
8.8
74.8
80.0
454
19478.2
SCR-3
4
1.34
162
22
0.9
36.8
227.3
10.6
34.0
80.0
856
12383.1
SCR-3
5
1.34
255
29
2.5
44.1
173.1
14.0
21.6
80.0
1777
7865.5
SCR-3
6
1.34
449
57
2.5
59.5
132.6
21.4
9.6
80.0
6150
3486.1
SCR-3-C
1
1.34
100
6
1.0
23.7
237.2
4.1
77.3
80.0
144
28171.5
SCR-3-C
2
1.34
100
8
1.0
23.7
237.2
4.1
58.0
80.0
192
21156.2
SCR-3-C
3
K34
135
10
1.0
30.5
225.8
5.2
44.0
80.0
454
11460.6
SCR-3-C
4
1.34
162
22
0.9
36.8
227.3
6.2
20.0
80.0
856
7287.6
SCR-3-C
5
1.34
255
29
2.5
44.1
173.1
8.2
12.7
80.0
1777
4617.8
SCR-3-C
6
1.34
449
57
2.5
59.5
132.6
12.5
5.6
80.0
6150
2040.7
SCR-7
1
1.34
100
6
1.0
23.7
237.1
6.1
115.5
80.0
144
42109.1
SCR-7
2
1.34
100
8
1.0
23.7
237.2
6.1
86.8
80.0
192
31629.7
SCR-7
3
1.34.
135
10
1.0
30.5
225.8
7.7
<5.3
80.0
454
17004.1
SCR-7
4
1.34
162
22
0.9
36.8
227.3
9.3
29.6
80.0
856
10808.7
SCR-7
5
1.34
255
29
2.5
44.1
173.1
11.9
18.3
80.0
1777
6671.0
SCR-7
6
1.34
449
57
2.5
59.5
132.6
17.7
7.9
80.0
6150
2878.4
SCR-7-C
1
1.34
100
6
1.0
23.7
237.1
3.6
68.2
80.0
144
24862.9
SCR-7-C
2
1.34
100
8
1.0
23.7
237.2
3.6
51.2
80.0
192
18674.7
SCR-7-C
3
1.34
135
10
1.0
30.5
225.8
4.6
38.6
80.0
454
10043.0
SCR-7-C
4
1.34
162
22
0.9
36.8
227.3
5.5
17.5
80.0
856
6385.4
SCR-7-C
5
1.34
255
29
2.5
44.1
173.1
7.0
10.8
80.0
1777
3933.4
SCR-7-C
6
1.34
449
57
2.5
59.5
132.6
10.4
4.6
80.0
6150
1692.5
ita9«isiissn:i*sai::
aissaistismaui
mteiii
imsaies
¦s=ias3ti;as=9t;
aiKS::
:az3»:a>s:
aasste
saazstssia:
isiaasaat
20-32
-------
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--
Units 1-5 were not considered for DSD or FSI application because of the
poor performance of the ESPs and no space is available between the units and
ESPS. Sorbent injection for DSD and humidification for FSI applications are
not possible because of very short duct residence time and poor ESP
performance. DSD or FSI as applied to unit 6 would be very easy due to the
long duct residence time, very large ESPs (SCA >600) and a great deal of
space is available if additional plate area is required. Table 20.2.1-10
presents a summary of the site access/congestion factors for DSD and FSI
technologies at the Beckjord steam plant. Table 20.2.1-11 presents the costs
estimated to retrofit DSD and FSI at the Beckjord 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 Beckjord plant. Boilers 1-5 at the Beckjord plant would
be considered good candidates for AFBC or coal gasification/combined cycle
repowering because of the small boiler sizes (<300 MW) and low capacity
factors. Boiler 6 would not make a good candidate due to its large boiler
size (>400 MW).
20.2.2 Miami Fort Steam Plant
The Miami Fort steam plant is located within Hamilton County, Ohio, as
part of Cincinnati Gas and Electric Company system. The plant contains four
coal-fired boilers with a total gross generating capacity of 1,308 MW.
Boiler 8 is located beside the Ohio River south of the plant, boiler 7 is
20-33
-------
TABLE 20.2.1-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BECKJORD UNIT 6
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION < MEDIUM
ESP UPGRADE LOW
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000S) 3603
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 92
TOTAL COST (1000$)
ESP UPGRADE CASE 3695
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.13
NEW BAGHOUSE NA
20-34
-------
Table 20.2.1-11. Summary of OSO/fSI Control Costs for the Beckjord Plant (mills/kMh)
DSO+ESP 6
DSD+ESP-C 6
FSl*ESP-50 6
FS!»ESP-50-C 6
FSl*ESP-70 6
FSI+ESP-70-C 6
1.00 449 57 2.5 21.0 46.7 13.6 6.1 34.0 16999 300.9
1.00 449 57 2.5 21.0 46.7 7.9 3.5 34.0 16999 464.4
1.00 449 57 2.5 21.3 47.5 21.3 9.5 50.0 24983 854.3
1.00 449 57 2.5 21.3 47.5 12.3 5.5 50.0 24983 493.3
1.00 449 57 2.5 21.6 48.1 21.8 9.7 70.0 34976 622.7
1.00 449 57 2.5 21.6 48.1 12.6 5.6 7D.0 34976 359.5
20-35
-------
located north of the plant away from the river, and boilers 5 and 6 are
in-between. Figure 20.2.2-1 presents the plant plot plan showing the
location of all boilers and major associated auxiliary equipment.
Table 20.2.2-1 presents operational data for the existing equipment at
the Miami Fort steam plant. Boilers 5, 6, and 7 burn medium sulfur coal (1.9
to 2.3 percent sulfur) while boiler 8 burns a low sulfur "compliance coal"
(0.7). Coal shipments are received by barge and conveyed to a coal storage
and handling area located east of the plant.
Particulate matter emissions for the boilers are controlled with ESPs
(units 5 and 6 are roof-mounted and units 7 and 8 are located behind each
respective boiler). Fly ash from units 5 and 6 are wet sluiced to ponds
located west of the plant. Units 7 and 8 have a dry fly ash handling system
and is disposed off-site (2 miles).
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 20.2.2-1 shows the general layout and location of the FGD control
system. Units 5-7 absorbers would be located in an open area to the
northwest of unit 7. The unit 8 absorbers would be located in a small
available space behind and to the east of its chimney between the coal
conveyors. Plant personnel indicated that unit 5 is an old unit with a very
low capacity factor and, if scrubbing is required, the unit would be put out
of service because it will be uneconomical to operate. In addition, unit 8
is a 1971 NSPS boiler burning low sulfur coal (1.1 lb per million Btu) and
might not require scrubbing. Therefore, retrofit factors and costs were not
developed for these two units because they are not potential candidates for
scrubbing. Units 6 and 7 would require the demolition/relocation of part of
the warehouse building and one paved road; therefore, a factor of 10 percent
was assigned to general facilities. The lime storage/preparation area would
be located to the north of unit 7 in a relatively open area between the
chimney/storage building, parallel to a major highway, and close to the
cooling towers (other side of the highway). The waste handling area would be
located to the northwest of the powerhouse, adjacent to the absorbers.
20-36
-------
*0® 4f»a
unit a
Abs?*ersf 0«
Unit a
** 'or
a i
6a r.
a*
am
BW®'
sc4fS^f sm8ro **
F'9ui»e 20
Miami
2'2-j _ ^
Fort
»"«nr hi.,
Phn
20-37
P',ot Plot
-------
TABLE 20.2.2-1. MIAMI FORT STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
5
6
7
8
GENERATING CAPACITY (MW)
85
175
524
524
CAPACITY FACTOR (PERCENT)
40
71
67
56
INSTALLATION DATE
1949
1960
1975
1978
FIRING TYPE
FWF
TANG
OWF
OWF
COAL SULFUR CONTENT (PERCENT)
1.9
2.1
2.3
0.7
COAL HEATING VALUE (BTU/LB)
11000
11000
11000
12300
COAL ASH CONTENT (PERCENT)
15.2
14.8
15.1
11.0
FLY ASH SYSTEM
WET
WET
DRY
DRY
ASH DISPOSAL METHOD
ON-
SITE
OFF-
SITE
STACK NUMBER
1
2
3
4
COAL DELIVERY METHODS
BARGE
PARTICULATE CONTROL
TYPE
ESP
ESP
ESP
ESP
INSTALLATION DATE
1977
1976
1975
1978
EMISSION (LB/MM BTU)
0.05
0.05
0.05
0.05
REMOVAL EFFICIENCY
99.7
99.4
99.4
99.7
DESIGN SPECIFICATION
SULFUR SPECIFICATION
1.0
1.0
3.0
0.7
(PERCENT)
SURFACE AREA (1000 SQ FT)
185.3
119.9
557.3
663.5
GAS EXIT RATE (1000 ACFM)
524
585
2020
2020
SCA (SQ FT/1000 ACFM)
354
205
275
328
OUTLET TEMPERATURE (*F)
310
310
310
310
20-38
-------
Retrofit Difficulty and Scope Adder Costs--
Units 6 and 7 were assigned a low site access/congestion factor due to
the relatively open space available with no major obstacles/obstructions and
very good accessibility.
For flue gas handling for L/LS-FGD cases, short to moderate duct runs
would be required for units 6 and 7. Separate site access/congestion factors
were assigned to each unit for the flue gas handling system as follows.
Unit 6 was assigned a medium access/congestion factor which reflects the
access difficulty associated with routing flue gas from the ESPs to the
absorbers. A low site access/congestion factor was assigned to unit 7 due to
the absorbers being located close to the chimney with no major obstacles/
obstructions surrounding the chimney.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables 20.2.2-2 and 20.2.2-3. The
largest scope adder for the Miami Fort plant would be the conversion of unit
6 fly ash conveying/disposal system from wet to dry for conventional L/LS-FGD
case. It was assumed that dry fly ash would be necessary to stabilize
scrubber sludge waste. However, this conversion would not be necessary for
unit 7 because the existing fly ash handling system is dry. The overall
retrofit factors determined for the L/LS-FGD cases ranged from low to medium
(1.24 to 1.44).
Unit 7 is the only candidate for LSD with reuse ESP technology. Unit 6
was not considered because of its marginal size SCA in addition to
roof-mounted ESPs which makes it difficult to add plate area. By contrast,
unit 7 has adequate size SCA with good removal efficiency. Moderate duct
length is required and medium access/congestion factors is assigned to the
flue gas handling system due to access difficulty created by the limited
space availability upstream of the ESPs. The retrofit factors 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 ESPs. Upgrading the two ESPs for unit 7 would be easy (with a low
retrofit factor of 1.16) because the ESPs are located in a relatively open
area with space availability around the two ESPs. This factor was used by
the IAPCS model to estimate the particulate control upgrading costs.
20-39
-------
TABLE 20.2.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR MIAMI FORT UNIT 6
FGD TECHNOLOGY
L/LS FGD
FORCED
OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
LOW
NA
FLUE GAS HANDLING
MEDIUM
MEDIUM
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
300-600
ESP REUSE
NA .
BAGHOUSE
NA
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NO
NA
ESTIMATED COST (1000$)
1548
NA
NA
NEW CHIMNEY
YES
YES
NA
ESTIMATED COST (1000$)
1225
1225
NA
OTHER
NO
NO
NA
RETROFIT FACTORS
FGD SYSTEM
1.44
1.37
ESP REUSE CASE
NA
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 10
10
NA
20-40
-------
TABLE 20.2.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR MIAMI FORT UNIT 7
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL LOW LOW LOW
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE MEDIUM
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NO NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000S) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.24 1.24
ESP REUSE CASE 1.24
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
20-41
-------
Table 20.2.2-4 presents the costs estimated for L/LS and LSD-FGD cases.
As mentioned in the previous section, boiler 8 is currently meeting 1971 NSPS
SO2 emission standards. It is unlikely that this unit would need scrubbing.
If, however, scrubbing is required for this unit, it would be more cost
effective to switch to a coal with a higher sulfur content, taking into
consideration the fuel cost differential. Therefore, the costs cannot be
presented realistically for unit 8 because they would possibly change
depending on acid rain legislation and plant decisions regarding the type of
coal used for unit 8. The LSD-FGD costs include upgrading the ESPs only for
boiler 7. 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. S03 conditioning was assumed to reduce the needed plate area up to
25 percent.
Unit 8 has already switched to low sulfur coal. Therefore, this unit
was not considered for coal switching and physical coal cleaning.
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 20.2.2-5.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Miami Fort steam plant. These controls include LNC
modification and SCR. Sum of the retrofit factor data for Miami Fort unit 8
20-42
-------
Table 20.2.2-4. Surmary of fCO Control Costs for the Miami fort Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Mwwber Retrofit Size factor Sulfur Cost Co9t Cost Cost Removed Removed Effect.
Difficulty (MU) «> Content (»*M)
-------
Table 20.2.2-5. Summary of Coal Switching/Cleaning Costs for the Miani Fort Plant (June 1988 Dollars!
IKS3BS==3*SS3*S3
:i=S3=2K55S
M
N
II
II
n
ssssasssss:
II
II
II
II
M
II
II
II
Technology
Boiler
Main
Boiler Capacity Coal
Capi tal
Capi tal
Annual
Annual
S02
S02
S02 Cost
Nuifcer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MU)
<3H
Content
(MM)
(J/kW)
-------
application of N0X control technologies is determined by several site-
specific factors which are discussed in Section 2. The NO technologies
A
evaluated at the steam plant were: LNB and SCR for units 5, 7, and 8; and
OFA and SCR for unit 6.
Low NOx Combustion--
Unit 5 is a dry bottom, front wall-fired boiler rated at 85 MW. Units 7
and 8 are dry bottom, opposed wall-fired boilers, each rated at 524 MW. The
combustion modification technique applied for these boilers was LNB. Unit 6
is a dry bottom, tangential-fired boiler rated at 175 MW. The combustion
modification technique applied for this boiler was OFA. As Tables 20.2.2-6
and 20.2.2-7 show, the LNB N0X reduction performance for units 7 and 8 was
estimated at 50 percent, and the OFA N0X reduction performance for unit 6 was
estimated at 20 percent. These reduction performance levels were assessed by
examining the effects of heat release rates and furnace residence time
through the use of the simplified N0X procedures. No boiler information was
available on unit 5 to assess the N0X reduction performance for this unit.
However, based on N0X performance results.from similar boilers of the same
age and size, LNB N0X reductions are expected to be between 20 and 30
percent. Table 20.2.2-8 presents the cost of retrofitting LNB and OFA at the
Miami Fort boilers.
Selective Catalytic Reduction-
Tables 20.2.2-6 and 20.2.2-7 present the SCR retrofit results for units
5 to 8. 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 5 would be located behind the respective unit
between the coal pile and the powerhouse. The SCR reactor for unit 6 would
be located in front of unit 6 in an open area east of the switch yard and
immediately west of unit 7. The SCR reactor for unit 7 would be located
immediately north of the respective chimney in an open area having easy
access. For unit 8, the SCR reactor would be located behind the respective
chimney between the coal pile and the powerhouse.
20-45
-------
TABLE 20.2.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR MIAMI FORT UNITS 5-7
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
5
6
7
FIRING TYPE
FWF
TANG
OWF
TYPE OF NOx CONTROL
LNB
OFA
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
' 13
14
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
69.6
71
FURNACE RESIDENCE TIME (SECONDS)
NA
2.97
2.95
ESTIMATED NOx REDUCTION (PERCENT)
25
20
50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
24
41
94
New Duct Length (Feet)
400
700
200
New Duct Costs (1000$)
1802
4812
2611
New Heat Exchanger (1000$)
1691
2608
5035
TOTAL SCOPE ADDER COSTS (1000$)
3517
7461
7740
RETROFIT FACTOR FOR SCR
1.52
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
17
13
20-46
-------
TABLE 20.2.2-7. SUMMARY OF NQx RETROFIT RESULTS FOR MIAMI FORT UNIT 8
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
8
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR) 11.8
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 38.3
FURNACE RESIDENCE TIME (SECONDS) 3^48
ESTIMATED NOx REDUCTION (PERCENT) 50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 94
New Duct Length (Feet) 100
New Duct Costs (1000$) 1306
New Heat Exchanger (1000$) 5035
TOTAL SCOPE ADDER COSTS (1000$) 6435
RETROFIT FACTOR FOR SCR 1.52
GENERAL FACILITIES (PERCENT) 13
20-47
-------
Table 20.2.2-8. NOx Control Cost Results for the Miami Fort Plant (June 1988 Dollars)
sti8iistis;tis>asiiiisi:39s:siBas3usst:±3SU::ist:3ss::ssKSfXi«iisstasi«isisinsaesits:a:iisaii:ii:;i:ii:i::;::
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
-------
Since the reactors for units 6 and 7 would be located in an open area
with easy access and no major obstacles, the reactors were assigned low
access and congestion factors. The reactor for unit 6 would require the
relocation of one paved road; therefore, a general facility factor of
17 percent was assigned to this unit. A low general facility factor of
13 percent was assigned to all the other reactor locations because no major
demolition or relocation would be required. 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 20.2.2-8
presents the estimated cost of retrofitting SCR at the Miami Fort boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SC>2 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 north of the plant along side the highway. The retrofit of DSD
technology at units 5 and 7 would be relatively difficult due to the short
duct residence time and the upgrading of the ESPs for unit 5 would be
difficult because they are roof-mounted. However, developments in
particulate control technology may be used to modify unit 7 ESPs by combining
advanced ESP technology and spray dryer technology to remove S02 and
particulate (E-SOx technology). Since unit 7 has adequate ESPs, it was
assumed that DSD with ESP reuse is an alternative low cost method to the new
baghouse option. Table 20.2.2-9 presents a summary of the site access/
congestion factors for DSD and FSI technologies at the Miami Fort steam
plant. Table 20.2.2-10'presents the costs estimated to retrofit DSD and FSI
at the Miami Fort plant.
20-49
-------
TABLE 20.2.2-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR MIAMI FORT UNIT 7
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$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 104
TOTAL COST (1000$)
ESP UPGRADE CASE 104
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.13
NEW BAGHOUSE NA
20-50
-------
Table 20.2.Z-10. Suimary of DSO/FSI Control Costs for the Miami Fort Plant (June 1988 Dollars)
Technology Be iter Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (SWt) (»/W) (SUM) (mills/k*h) (*) (tons/yr) (I/ton)
Factor (X)
DSD*ESP 7 1.00 524 67 1.6 18.3 34.9 15.0 4.9 49.0 16452 909.7
0SD+ESP-C 7 1.00 524 67 1.6 18.3 34.9 8.7 2.8 49.0 16452 526.2
FSI+ESP-S0 7 1.00 524 67 1.6 19.8 37.8 16.8 5.5 50.0 16908 996.1
FSI+ESP-50-C 7 1.00 524 67 1.6 19.8 37.8 9.7 3.2 50.0 16908 575.9
FS!*£SP-70 7 1.00 524 67 1.6 20.0 38.1 17.1 5.6 70.0 23671 724.3
FSI*ESP-70"C 7 1.00 524 67 1.6 20.0 38.1 9.9 3.2 70.0 23671 418.7
=:sii=i«ss9iis::z«s3Sisisii:isiiiaissstiiiasBiiiisssi:3iisis::::s:r:::
20-51
-------
Atmospheric Fluidlzed 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 Miami Fort plant. Boilers 5 and 6 at the Miami Fort
plant would be considered good candidates for AFBC retrofit because of the
small boiler sizes (<300 MW). Boilers 7 and 8 would not make good candidates
due to the large boiler sizes (524 MW) and high capacity factors. The high
capacity factor indicates that purchased power cost for unit downtime may be
significant for repowering.
20-52
-------
20.3 CLEVELAND ELECTRIC ILLUMINATING COMPANY
20.3.1 Ashtabula Steam Plant
The boilers at the Ashtabula plant are at two locations. The aerial
photograph for units 1-7 was not available. Units 1-6 are petroleum burning
and are not applicable to this study. For unit 7, average retrofit factors
of 1.5 and 1.36 were assumed for L/LS-FGD and SCR, respectively. The aerial
photograph was available for units 8-11. Sorbent injection technologies (FSI
and DSD) were not evaluated for units 8-11 due to the short duct residence
timo.
TABLE 20.3.1-1. ASHTABULA STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHOD
PARTICULATE CONTROL
1-6
7
8,9,10,11
PETROLEUM
244
44
BURNING
73
70,72,60,75
1958
1949,49,53,53
TANGENTIAL
FRONT WALL
RETIRED OR
NA
NA
ON STANDBY
NO
NO
4.0
2.6
12300
13000
10.6
6.7
DRY DISPOSAL
PAID/OFF-SITE
1 2
RAILROAD
TYPE ESP ESP
INSTALLATION DATE 1980 1979
EMISSION (LB/MM BTU) 0.04 0.04
REMOVAL EFFICIENCY 99.6 99.5
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT) 2.0-5.0
SURFACE AREA (1000 SQ FT) 609 101
GAS EXIT RATE (1000 ACFM 995 265
SCA (SQ FT/1000 ACFM) 607 380
OUTLET TEMPERATURE (°F) 280 310
* SCA size assumed to be larger than 300 since the ESPs are
1985 retrofit ESPs.
20-53
-------
TABLE 20.3.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR ASHTABULA
UNITS 8-11 *
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
HIGH
HIGH
300-600
NA
NA
NA
HIGH
NA
HIGH
BAGHOUSE
300-6(
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$)
1288
0
1288
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.83
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.89
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT)
15
0
15
* L/S-FGD absorbers, LSD-FGD absorbers and new FFs for
units 8-11 would be located north of the boilers. Plant
personnel indicated that sufficient space near the boilers
is not available for the absorbers.
20-54
-------
Table 20.3.1-3. Sumary of FGD Control Costs for th« Ashtabula Plant (Jun« 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annuel
NuiOer Retrofit Size Factor Sulfur Cost Cost Cost
Oifficulty (MW> «> Content (SAW) (*»«)
Factor (X)
ic3sstKssss^ssss3i==:s3=:ss::tizi::i
Annual S02 S02 S02 Cost
Cost Removed Removed Effect,
(nills/kwh)
-------
Table 20.3.1-4. Suimary of Coal Switching/Cleaning Costs for the Ashtabula Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nuitoer
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
Content
<««)
<«/kW)
(S*H>
(mi lls/kuti)
(X)
(tons/yr)
(S/ton)
Factor
(X)
CS/B*»15
7
1.00
244
73
4.0
8.4
34.4
22.3
14.3
77.0
37678
591.9
CS/B*I15
8
1.00
44
70
2.6
2.5
56.2
4.6
16.9
62.0
3215
1417.0
CS/B*t15
9
1.00
44
72
2.6
2.5
56.2
4.7
16.8
62.0
3306
1411.6
CS/B*t15
10
1.00
44
60
2.6
2.5
56.2
4.0
17.3
62.0
2755
1449.0
CS/B+J15
11
1.00
44
75
2.6
2.5
56.2
4.8
16.7
62.0
3444
1404.2
CS/B»$15-C
7
1.00
244
73
4.0
8.4
34.4
12.8
8.2
77.0
37678
340.1
CS/B*S15-C
S
1.00
44
70
2.6
2.5
56.2
2.6
9.7
62.0
3215
815.3
CS/B»H5-C
9
1.00
44
72
2.6
2.5
56.2
2.7
9.7
62.0
3306
812.1
CS/B*t15-C
10
1.00
44
60
2.6
2.5
56.2
2.3
9.9
62.0
2755
834.2
CS/B*t15-C
11
1.00
44
75
2.6
2.5
56.2
2.8
9.6
62.0
3444
807.7
CS/B+J5
7
1.00
244
73
4.0
5.9
24.0
9.0
5.8
77.0
37678
238.1
CS/B*t5
8
1.00
44
70
2.6
2.0
45.8
2.2
8.3
62.0
3215
698.8
CS/8*$5
9
1.00
44
72
2.6
2.0
45.8
2.3
8.3
62.0
3306
694.2
CS/B*»5
10
1.00
44
60
2.6
2.0
45.8
2.0
8.7
62.0
2755
726.7
CS/8*S5
11
1.00
44
75
2.6
2.0
45.8
2.4
8.2
62.0
3444
687.7
CS/B*t5-C
7
1.00
244
73
4.0
5.9
24.0
5.2
3.3
77.0
37675
137.1
CS/B+S5-C
8
1.00
44
70
2.6
2.0
45.8
1.3
4.8
62.0
3215
403.2
CS/B+J5-C
9
1.00
44
72
2.6
2.0
45.8
1.3
4.8
62.0
3306
400.4
CS/B*«5-C
10
1.00
44
60
2.6
2.0
45.8
1.2
5.0
62.0
2755
419.7
CS/B*I5-C
11
1.00
44
75
2.6
2.0
45.8
1.4
4.7
62.0
3444
296.6
===X==3*=»¦==
II
H
II
II
N
II
l(
:«=a«sst:
II
a
N
¦
II
lltSIHSIl
1!
N
U
II
n
:=*===*=
=======
H
II
II
it
II
II
II
II
H
II
II
H
II
II
It
It
II
20-56
-------
TABLE 20.3.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR ASHTABULA
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
7
8,9,10,11
FIRING TYPE
TANG
FWF
TYPE OF NOx CONTROL
OFA
LNB
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1958
1949,49,53,53
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
40
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
53
41
New Duct Length (Feet)
200
500
New Duct Costs (2000$)
1670
3449
New Heat Exchanger (1000$)
3183
2616
TOTAL SCOPE ADDER COSTS (1000$)
INDIVIDUAL CASE
COMBINED CASE
4906
NA
NA
6106
RETROFIT FACTOR FOR SCR
1.36
1.52
GENERAL FACILITIES (PERCENT)
20
38
* Cold side SCR reactors for units 8-11 would be located south
of the boilers behind the ESPs. Due to the lack of an aerial
photo, no SCR reactor location is reported for unit 7.
20-57
-------
Table 20.3.1-6, NOx Control Cost Results for the Ashtabula Plant (Jirte 1988 Dollars)
8si88s:aflisss8ss:3i882s8ss:sz::sssss::£ss::ss:s:s8ss:sa:ssss::£;sss:sssss:s8asss8sssss:s:s38:s;38s3:ssss::s:3::3
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nuiteer
Retrofit
Site
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (HW)
(X)
Content
<«N)
(S/kW)
(SWO
(¦ills/kwh)
<%)
(tons/yr)
<«/ton)
Factor
(X)
LNC-INB
8
1.00
44
70
2.6
1.8
41.8
0.4
' 1.5
40.0
428
928.7
LNC-LNB
9
1.00
44
72
2.6
1.8
41.8
0.4
1.4
40.0
440
902.9
LNC-INB
10
1.00
u
60
2.6
1.8
41.8
0.4
1.7
40.0
367
1083.5
LNC-INB
11
1.00
u
75
2.6
1.8
•41.8
0.4
1.4
40.0
458
866.8
LNC-LNB-C
3
1.00
44
70
2.6
1.8
41.8
0.2
0.9
40.0
428
551.4
LNC-LNB-C
9
1.00
44
72
2.6
1.8
41.8
0.2
0.8
40.0
440
536.0
LNC-LNB-C
10
1.00
44
60
2.6
1.8
41.8
0.2
1.0
40.0
367
643.2
LNC-LNB-C
11
1.00
44
75
2.6
1.8
41.8
0.2
0.8
40.0
458
514.6
LNC-OFA
7
1.00
244
73
4.0
0.9
3.6
0.2
0.1
25.0
1177
162.3
LNC-OFA-C
7
1.00
244
73
4.0
0.9
3.6
0.1
0.1
25.0
1177
96.3
SCR-3
7
1.36
244
73
4.0
39.1
160.1
13.4
8.6
80.0
3765
3562.8
SCR-3
8-11
1.52
176
69
2.6
36.7
208.5
11.7
11.0
80.0
3373
3470.0
SCR-3-C
7
1.36
244
73
4.0
39.1
160.1
7.9
5.0
80.0
3765
2387.8
SCR-3-C
a-ii
1.52
176
69
2.6
36.7
208.5
6.9
6.5
80.0
3373
2036.9
SCR-7
7
1.36
244
73
4.0
39.1
160.1
11.4
7.3
80.0
3765
3032.2
SCR-7
8-11
1.52
176
69
2.6
36.7
208.5
10.3
9.7
80.0
3373
3046.2
SCR-7-C
7
1.36
244
73
4.0
39.1
160.1
6.7
4.3
80.0
3765
1783.8
SCS-7-C
8-11
1.52
176
69
2.6
36.7
208.5
6.1
5.7
80.0
3373
1794.0
II
II
U
M
II
II
II
II
u
II
5533=53
icsssai::
-~-X3S---
SS5SX333
isssisss:
issasssa
II
II
II
II
II
'M
II
II
II
II
II
:mssmsi
20-58
-------
20.3.2 Avon Lake Steam Plant
The Avon Lake steam plant is located within Lorain County, Ohio, and is
part of the Cleveland Electric Illuminating Company system. The plant
contains 8 oil-fired boilers and 4 coal-fired boilers. Boiler 12 is the only
unit being considered for FGD retrofit in this evaluation with a gross
generating capacity of 680 MW. Figure 20.3.2-1 presents the plant plot plan
showing the location of the boilers and major associated auxiliary equipment.
Table 20.3.2-1 presents operational data for unit 12 at Avon Lake. This
unit burns medium sulfur coal (2.5 percent sulfur). Coal is received by rail
and transferred to the coal handling/storage area located a block away on the
other side of the highway.
Particulate matter emissions for unit 12 are controlled with retrofit
ESPs located behind the boiler/cHimney. Dry ash from all units is disposed
off-site.
Lime/Limestone and Lime Spray Drying FGD Costs-
Figure 20.3.2-1 shows the general layout and location of the FGD control
system. Two cases were considered for the placement of the FGD absorbers.
First, the absorbers for FGD technologies could be located northwest of
unit 12 between the retrofit ESPs and the highway. Second, the plant could
purchase the land adjacent to the unit 12 ESPs and place the absorbers in the
open, unobstructed area adjacent to the lake. For the first case, the lime
preparation/storage area and the waste handling area would be located
northwest of the plant (on the other side of the highway) on what is
presently a parking area and, for the second case, they would be located on
the purchased land (plant personnel indicated that this is a city park).
Demolition and relocation of miscellaneous buildings, a-road, and a parking
area would be required to locate the absorbers adjacent to unit 12 (first
case) and a factor 10 percent was assigned to general facilities. No
demolition/relocation would be required for the second case; therefore, 5
percent was assigned to general facilities.
20-59
-------
Railroad
Truck
OH
Tanks
Stacks
NK, Storage
System
Absorbers
(Case 2)
Not to scale
FGD Waste Handling/Absorber Area
Lime/limestone Storage/Preparation Area
NN, Storage System
SCR Boxes
Figure 20.3.2-1. Avon Lake plant plot plan
20-60
-------
TABLE 20.3.2-1. AVON LAKE 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 FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
12
680
50
1970
OPPOSED WALL
2.5
12300
10
PAID DISPOSAL/DRY
OFF-SITE
1
RAILROAD
ESP
1978
0.03
99.7
5.0
1687
2600
646
295
20-61
-------
Retrofit Difficulty and Scope Adder Costs--
As mentioned above, unit 12 is the only unit being considered for FGD
retrofit at the Avon Lake plant. As shown in Figure 20.3.2-1, the boiler is
located directly in front of the chimney and the retrofit ESPs are located
directly behind the chimney. The plant is bounded on one side by Lake Erie.
In the first case, the FGD absorbers were located on the side of unit 12
where they would be bounded by the conveyor and a bridge, the retrofit ESPs,
and a major highway. The second case would involve locating the FGD
absorbers in an open area behind the ESPs relatively close to the lake. The
site access/congestion factors assumed for the FGD cases reflect the
congestion associated with the absorber locations mentioned above: a high
site access/congestion factor for the first case and a low site
access/congestion factor for the second case.
High site access/congestion factors were assigned to the flue gas
handling system because significant congestion exists around the ESPs due to
the existing ductwork and the coal conveyor. On the other hand, for the
second case, the flue gas handling site access/congestion factors assigned
were low for L/LS-FGD technologies because there are no obstructions between
the absorber location and the ESPs. Short to moderate duct runs would be
required for either of the above cases for all technologies.
The major scope adjustment costs and estimated retrofit factors for the
FGD technologies are presented in Tables 20.3.2-2 and 20.3.2-3. There are no
significant scope adjustments and related costs required for the retrofit of
FGD control technologies at Avon lake. As shown in the table, there are no
significant scope adjustments and costs associated with the retrofit of FGD
control technologies at Avon Lake. The overall retrofit factors determined
for the L/LS-FGD cases were medium for the first scenario and low for the
second case.
LSD with reused ESP was the only LSD-FGD technology considered for
unit 12 because the available SCA is large (>400). The retrofit factor
determined for the LSD technology was medium to high (1.62) for the first
case and medium (1.43) for the second case. A separate retrofit factor was
developed for the upgrade of the ESPs for unit 12 and was used in the IAPCS
model to estimate the particulate control upgrading costs if additional plate
area was required. These factors, estimated for both scenarios discussed
20-62
-------
TABLE 20.3.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR AVON LAKE UNIT 12
(CASE 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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE 300-600
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NO NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO NO
RETROFIT FACTORS
FGD SYSTEM 1.53 1.56
ESP REUSE CASE 1.62
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 10 10 10
20-63
-------
TABLE 20.3.2-3. SUMMARY OF RETROFIT FACTOR DATA FOR AVON LAKE UNIT 12
(CASE 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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 0-100 0-100
ESP REUSE 600-1,000
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 1.43
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
20-64
-------
above, were high (1.58) for the first case and low (1.16) for the second
case. The low retrofit factor reflects the space availability in front of
the ESPs while the high factor reflects the limited space availability on
either side of the ESPs for the first case.
Table 20.3.2-4 presents the cost estimates for L/LS and LSO-FGD case 1.
The LSD-FGD costs include upgrading the ESPs for boiler 12. The low cost
control case reduces capital and annual operating costs due to the
elimination of spare scrubber modules, optimization of scrubber module size,
and use of organic acid additives. Costs for case 2 were not presented
because of the unlikelihood of purchasing the land where the city park is
located.
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 20.3.2-5.
N0X Control Technology Costs--
This section presents the performance and various related costs
estimated for N0X controls at Avon Lake boiler 12. These controls include LNC
modifications and SCR. The N0X technologies applied at the Avon Lake
boiler 12 were: LNB and SCR.
Low NOx Combust ion--
Unit 12 is a dry bottom, opposed wall fired boiler rated at 680 MW.
Thus, the N0x combustion control considered for this unit was LNB.
20-65
-------
Table 20.3.2-4. Surmary of FGD Control Costs for the Avon Lake Plant (June 1988 Dollars)
¦:3iis3tis:iis:ins:ui:l!3::siss9lssslti:siissa
Technology Boiler Main Uoilar Capacity Coal Capital Capital Annual Annual $02 S02 SQ2 Cost
Ninber Retrofit Size Factor Sulfur Cost Coat Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (SMH)
Factor (X)
LC'FGD<1> 12 1.53 680 50 2.5 117.6 17?.9 59.6 20.0 9C.0 52554 1134.7
IC FGD <1)-C 12 1.53 680 50 2.5 117.6 172.9 34.7 11.6 90.0 52554 660.1
LFGD (1) 12 1.53 680 50 2.5 138.5 203.6 66.3 22.3 90.0 52554 1261.5
LFGD (1)-C 12 1.53 680 50 2.5 138.5 203.6 38.6 13.0 90.0 52554 734.6
ISD*£SP (1) 12 1.62 680 50 2.S 94.9 139.5 39.8 13.4 65.0 37783 1054.7
.SD*ESP
-------
Table 20.3.2-5. Surinary of Coal Ski"tching/Cleaning Costs for the Avon Lake Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Number Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty
-------
Table 20,3.2-6 presents the NOx reduction performance results for this unit.
The NOx reduction performance was determined by examining the effects of heat
release rates and furnace residence time on NOx reduction through the use of
the simplified procedures. Table 20.3.2-7 presents the estimated cost of
retrofitting LNB on the coal-fired boiler at Avon Lake.
Selective Catalytic Reduction-
Table 20.3.2-6 presents the SCR retrofit results for unit 12. The
results include process area retrofit factor 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 reactor for unit 12 was located west of the retrofitted ESPs.
The reactor was assigned a medium access/congestion factor because it was
located in a highly congested area surrounded by the ESPs and two buildings;
however, access to this area is relatively low. The reactor was assumed to
be in an area with high underground obstructions. Table 20.3.2-7 presents the
estimated cost of retrofitting SCR at the Avon Lake 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 for unit 12 were located
west of the ESPs in the same manner as LSD-FGD technology. The retrofit of
DSD and FSI technologies at the Avon Lake steam plant would be relatively
easy. This is due to the long flue gas ducting residence time between the
boilers and the large retrofit ESPs and because of the large ESP SCA.
Table 20.3.2-8 presents a summary of site access/congestion factors, scope
adders, and retrofit factors for DSD and FSI technologies. Table 20.3.2-9
presents the costs estimated for FSI and DSD retrofit at Avon Lake.
20-68
-------
TABLE 20.3.2-6. SUMMARY OF NOx RETROFIT RESULTS FOR AVON LAKE
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$)
TOTAL SCOPE ADDER COSTS (1000S)
RETROFIT FACTOR FOR SCR
GENERAL FACILITIES (PERCENT)
BOILER NUMBER
12
OPPOSED WALL
LNB
NA
1970
NO
40
MEDIUM
0
114
300
4562
5887
10563
1.34
13
20-69
-------
Table 20.3.2-7. NOx Control Cost Results for the Avon lake Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx NOx NOx Cost
Nmfcar Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HU) (X) Content (MM) ($/kW) <**0 (X) (tons/yr) cVton)
factor (X)
LMC-LNB 12 1.00 680 50 2.5 5.5 8.1 1.2 0.4 40.0 5031 235.9
INC-LNB-C 12 1.00 680 50 2.S 5.5 8.1 0.7 0.2 40.0 5031 140.1
SCR-3 12 1.34 680 50 2.5 87.8 129.1 31.6 10.6 80.0 10061 3144.7
SCR-3-C 12 1.34 680 50 2.5 87.6 129.1 18.5 6.2 80.0 10061 1S40.8
SCR-7 12 1.34 680 50 2.5 87.8 129.1 26.1 8.8 80.0 10061 2591.4
SCR-7-C 12 1.34 680 50 2.5 87.8 129.1 15.3 5.1 80.0 10061 1523.8
stisaassiissssssesssssssssssssssassssssszsssssssssssssssssssesssississsisssiimiEstissississsiisatasaisssaisix::
20-70
-------
TABLE 20.3.2-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR AVON LAKE UNIT 12
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000S) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 126
TOTAL COST (1000S)
ESP UPGRADE CASE 126
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.55
NEW BAGHOUSE NA
20-71
-------
Table 20.3.2-9. Sumtary of 0S0/FSI Control Costs for tha Avon Like Plant (June 1988 Dollars}
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nu*er Retrofit Siza Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (%) Content (MM) (S/kU) (SW4> (mills/kuh) (X) (tons/yr) (I/ton)
factor (X)
DSD»ESP 12
DSD+ESP-C 12
FSt+ESP-50 12
FSl*ESP-50-C 12
FS!*ESP-70 12
FSI+ESP-70-C 12
1.00 680 50 2.5 27.9 41.1 19.7 6.6
1.00 680 50 2.5 27.9 41.1 11.4 3.8
1.00 680 50 2.5 23.0 33.8 24.6 8.3
1.00 680 50 2.5 23.0 33.8 14.2 4.8
1.00 680 50 2.5 23.4 34.4 25.1 8.4
1.00 680 50 2.5 23.4 34.4 14.S 4.9
43.0 25023 785.9
43.0 25023 455.3
50.0 29196 843.2
SO.O 29196 486.6
70.0 40874 615.2
70.0 40874 355.0
iiiss3i«ii»siiiiissssssisisiBiisisaisii2iiiisisiiiiiisiisiisssisinsa>iiissisaiiss3ziii:=3x«ii;s
20-72
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering criteria presented in Section 2
were used to determine the applicability of these technologies at the Avon
Lake plant. Boiler 12 at Avon Lake would not be considered a good candidate
for AFBC retrofit and AFBC or coal gasification/combined cycle repowering
because of its large size (680 MW).
20.3.3 Eastlake Steam Plant
The Eastlake steam plant is located within Lake County, Ohio, as part of
Cleveland Electric Illuminating Company system. The plant contains five coal-
fired boilers with a total gross generating capacity of 1,372 MW;
Figure 20.3.3-1 presents the plot plan showing the location of all boilers
and major associated auxiliary equipment.
Table 20.3.3-1 presents operational data for the existing equipment at
the Eastlake steam plant. All boilers burn high sulfur coal (3.0 percent
sulfur). Coal shipments are received by railroad and conveyed to a single
coal pile located behind the existing ESPs.
Particulate matter emissions for boilers 1-4 are controlled with
retrofit ESPs located behind the old ESPs/chimney of each unit. Particulate
emissions for boiler 5 are controlled with ESPs located immediately behind
the unit. Boilers 1-4 utilize four ducts each going into a common stack;
unit 5 has its own chimney. Fly ash from all units is dry and disposed
off-site as there is no space available on-site.
Lime/Limestone and Lime Spray Drying FGO Costs-
Figure 20.3.3-1 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 chimney between the coal pile and the lake. There is
just enough space available and only minor relocation and demolition would be
required
20-73
-------
SOfbe?i,St0ra9e/Preparatl°n Area
to scale
Figure 20.3.3-1. Eastlake plant plot plan
8
20-74
-------
TABLE 20.3.3-1. EASTLAKE 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
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS FLOW RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
1-3
4
5
144
260
680
62,65,74
56
60
1953
1954
1972
TANG
TANG
OWF
2.9
2.9
3.0
12100
12100
12100
10.7
10.7
10.7
DRY HANDLING
OFF-SITE
1
1
2
RAILROAD
ESP
ESP
ESP
1979-80
1981
1972
0.03
0.02
0.09
99.6
99.6
99.4
5.0
5.0
5.0
379
553
449
620
995
1950
611
556
230
300
280
285
20-75
-------
entailing moving the general facility equipment buildings. Therefore, a
5 percent general facilities factor was assigned. The lime storage/
preparation area and waste handling area would be located south of the coal
pile.
Retrofit Difficulty and Scope Adder Costs--
The absorbers for all units would be located on the lakeside beside
unit 1. A high site access/congestion factor was assigned to the absorber
locations due to the following reasons: access difficulty from the lake,
powerhouse, and coal pile and poor quality of the soil (low bearing soil) for
building because it is so close to the lake.
The flue gas from units 1-4 are going into a common chimney. For flue
gas handling, short to medium breaching duct runs would be required to divert
flue gas to the absorbers and back to the existing chimney. A low site
access/congestion factor was assigned to the flue gas handling system for
units 1-4 because of no significant obstacles around the existing chimney.
By contrast, flue gas handling for unit 5 would require long duct runs
for L/LS-FGD cases for diverting flue gas from the absorbers back to the
chimney. A high site access/congestion factor was assigned to the flue gas
handling system because of limited space below the unit 1-4 ESPs, the coal
conveyor, and other auxiliary equipment. For r=using the existing chimney,
more than 1,000 feet of duct run would be required in a high site access/
congestion area. Therefore, to decrease the duct run needed for L/LS-FGD
case at unit 5, a new chimney was constructed adjacent to the absorbers on
the side of the lake.
The major scope adjustment costs and retrofit factors estimated for the
FGD control technologies are presented in Tables 20.3.3-2 through 20.3.2-4.
No large scope adder cost is required for the Eastlake plant. The overall
retrofit factors determined for the L/LS-FGD cases ranged from moderate to
high (1.64 to 1.91).
LSD with reused ESP was the only LSD-FGD technology considered for
units 1-4 because of boilers presently having large SCA (>380). For flue gas
handling for LSD cases, medium duct runs would be required for units 1 and 2
and long duct runs for units 3 and 4. A high site access/congestion factor
was assigned for units 1-4 flue gas handling system. This was due to the
20-76
-------
TABLE 20.3.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR EASTLAKE UNITS 1-2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
SO2 REMOVAL HIGH HIGH HIGH
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 HIGH
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$) 0 0 0
OTHER YES NO YES
RETROFIT FACTORS
FGD SYSTEM 1.64 1.48
ESP REUSE CASE 1.82
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
20-77
-------
TABLE 20.3.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR EASTLAKE UNITS 3-4
FGO TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH HIGH HIGH
FLUE GAS HANDLING LOW LOW
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 100-300
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY NO NO NO
ESTIMATED COST (1000$) NA NA NA
NEW CHIMNEY NO NO NO
ESTIMATED COST (1000$) 0 0 0
OTHER YES NO YES
RETROFIT FACTORS
FGD SYSTEM 1.64 1.48
ESP REUSE CASE 1.91
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 5 5 5
20-78
-------
TABLE 20.3.3-4. SUMMARY OF RETROFIT FACTOR DATA FOR EASTLAKE UNIT 5
FGD TECHNOLOGY
FORCED
LIME
L/LS FGD OXIDATION
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
HIGH
HIGH
FLUE GAS HANDLING
HIGH
HIGH
ESP REUSE CASE
NA
BAGHOUSE CASE
HIGH
DUCT WORK DISTANCE (FEET)
600-1000
600-1000
ESP REUSE
NA
BAGHOUSE
600-1000
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
HIGH
SCOPE ADJUSTMENTS
WET TO DRY
NO
NO
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
YES
YES
YES
ESTIMATED COST (1000$)
4760
4760
4760
OTHER
YES
NO
YES
RETROFIT FACTORS
FGD SYSTEM
1.91
1.75
ESP REUSE CASE
NA
BAGHOUSE CASE
1.98
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.58
GENERAL FACILITIES (PERCENT) 5
5
5
20-79
-------
site access congestion created to route flue gas from the boilers to the
absorbers and back to the ESPs. This factor reflects the access difficulty
created by the old chimneys, old ESPs, and duct. runs. For unit 5, extremely
long duct runs would be required for LSD cases. Because the ESPs are small
(SCA = 230) and access congestion for ducting would be very high, a new
baghouse was considered for unit 5. The retrofit factors determined for the
LSD technology case for units 1-4 were high (1.82 to 1.91) and did not
include costs for upgrading existing particulate controls. A separate
retrofit factor was developed for upgrading units 1-4 ESPs (1.58) and was
used in the IAPCS model to estimate particulate control upgrading costs. The
access/congestion factor associated with the upgrading of the ESPs would be
high due to the close proximity of the ESPs, duct runs, and coal conveyor.
The retrofit factor determined for LSD technology for unit 5 was high (1.98)
and did not include new baghouse costs. A separate retrofit factor was
estimated for a new particulate control (1.58) and a high site
access/congestion factor was assigned to the new baghouse because of access
difficulty from the lake, powerhouse, and coal pile, in addition to poor
quality of the soil.
Table 20.3.3-5 presents the costs estimated for L/LS and LSD-FGD cases.
The LSD-FGD costs include upgrading the ESPs for boilers 1-4 and installing a
new baghouse to handle the additional particulate loading for boiler 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, optimization of scrubber size, and use of organic
acid additives.
Coal Switching. Costs-
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined.
The ESP performance impacts were evaluated using the IAPCS model to
estimate the needed plate area. This plate area was compared to the existing
20-80
-------
Table 20.3.3-5. Sumnary of FGD Control Costs for the Eastlake Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 502 SC2 Cos:
Nunber Retrofit Six* Factor Sulfur Cost Cost Cost Cost Removed Removed E'fect.
Difficulty (HU> (X) Content (SMM) (*/kU> CSWO '(¦ills/lculi) (X) (tons/yr)
-------
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 20.3.3-6.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the East Lake 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 for
units 1 to 4 and LNB and SCR for unit 5.
Low N0X Combustion--
Units 1 to 4 are dry bottom, tangential-fired boilers; units 1 to 3 are
rated at 123 MW each while unit 4 is rated at 208 MW. Unit 5 is a dry
bottom, opposed wall-fired boiler rated at 680 MW. The combustion
modification technique applied for this evaluation to units 1 to 4 was OFA
and that applied to unit 5 was LNB. As Tables 20.3.3-7 and 20.3.3-8 show,
the OFA N0X reduction performance for units 1 to 4 was estimated to be 20
percent and the LNB N0X reduction performance for unit 5 was estimated to be
40 percent. These reduction performance levels were assessed by examining
the effects of heat release rates and furnace residence time through the use
of the simplified N0X procedures. Table 20.3.3-9 presents the cost of
retrofitting OFA and LNB at the Eastlake boilers.
Selective Catalytic Reduction--
Tables 20.3.3-7 and 20.3.3-8 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
ESPs to the reactor and from the reactor to the chimney.
The SCR reactors for units 1 to 4 were located close to the lakeside
beside the chimeny. On the other hand, the SCR reactor for unit 5 was
20-82
-------
Table 20.3.3-6. Suimary of Coal Switching/Cleaning Costs for the Eastlake Plant
-------
TABLE 20.3.3-7. SUMMARY OF NOx RETROFIT RESULTS FOR EASTLAKE UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
TANG
TANG
TANG
TYPE OF NOx CONTROL
OFA
OFA
OFA
FURNACE VOLUME (1000 CU FT)
NA
NA
NA
BOILER INSTALLATION DATE
1953
1953
1953
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
25
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
.HIGH
HIGH
HIGH
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
NA
Ductwork Demoli t ion (1000$)
36
36
36
New Duct Length (Feet)
200
150
150
New Duct Costs (1000$)
1227
920
920
New Heat Exchanger (1000$)
2320
2320
2320
TOTAL SCOPE ADDER COSTS (1000$)
3582
3275
3275
RETROFIT FACTOR FOR SCR
1.52
1.52
1.52
GENERAL FACILITIES (PERCENT)
13
13
13
20-84
-------
TABLE 20.3.3-8. SUMMARY OF NOx RETROFIT RESULTS FOR EASTLAKE UNITS 4-5
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
4
5
FIRING TYPE
TANG
OWF
TYPE OF NOx CONTROL
OFA
LNB
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1954
1972
SLAGGING PROBLEM
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
25
40
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
NA
Ductwork Demolition (1000$)
55
114
New Duct Length (Feet)
200
950
New Duct Costs (1000$)
1733
14447
New Heat Exchanger (1000$)
3307
5887
TOTAL SCOPE ADDER COSTS (1000$)
5095
20448
RETROFIT FACTOR FOR SCR
1.52
1.16
GENERAL FACILITIES (PERCENT)
13
25
20-85
-------
Table 20.3.3-9. MOx Control Cost Results for the East lake Plant (Jirm 1988 Dollars)
Technology
Boiler
Ha in
Boiler Capacity Coal
Capital Capital Annual
Annual
NO*
NOx
NO* Cost
Winter
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (WW)
CM
Content
(W*)
(S/kU)
CSMM)
(mills/kwh)
(%)
-------
located in a parking lot area diagonally opposite those reactors for units 1
to 4 on the other side of the powerhouse.
High access/congestion factors were assigned to the SCR reactors for
units 1 to 4 due to access difficulty from the lake, powerhouse, and coal
pile and poor soil quality for building near the lake. The SCR reactor for
unit 5 was assigned a low access/congestion factor due to the relatively easy
access to this area and open space for construction. Because the parking lot
will have to be relocated, a 25 percent general facility factor was assigned
for the SCR reactor for unit 5. All five 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 20.3.3-9
presents the estimated cost of retrofitting SCR at the EastLake boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SO2 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 sorbert receiving/storage/preparation areas for all units were
located west of the existing chimney along the lakeside. For units 1-4, the
retrofit of DSD and FSI technologies at the Eastlake steam plant would be
relatively easy. There is sufficient flue gas ducting residence time between
the boilers and the retrofit ESPs and large SCAs (>380). The retrofit of FSI
and DSD unit 5 would be difficult because of the marginal ESP size.
Additionally, the unit 5 ESPs are located in a high site access/congestion
area making the addition of plate area more costly. Therefore, it was
assumed that for DSD new particulate controls would be needed resulting in
700 feet of duct run required to divert the flue gas from the boiler to the
baghouse. For FSI, it was assumed that the ESPs for all units could be
upgraded and reused. Tables 20.3.3-10 through 20.3.3-12 present a summary of
the site access/congestion factors for DSD and FSI technologies at the
20-87
-------
TABLE 20.3.3-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR EASTLAKE UNITS 1, 2 OR 3
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION HIGH
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$ 39
TOTAL COST (1000$)
ESP UPGRADE CASE 39
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.37
ESP UPGRADE 1.55
NEW BAGHOUSE NA
20-88
-------
TABLE 20.3.3-11. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR EASTLAKE UNIT 4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION HIGH
ESP UPGRADE HIGH
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 61
TOTAL COST (1000$)
ESP UPGRADE CASE 61
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.37
ESP UPGRADE 1.55
NEW BAGHOUSE NA
20-89
-------
TABLE 20.3.3-12. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR EASTLAKE UNIT 5
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE (FSI) HIGH
NEW BAGHOUSE (DSD) HIGH
SCOPE ADDERS
NEW CHIMNEY (DSD) YES
ESTIMATED COST (1000$) 4,760
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 700
ESTIMATED COST (1000$) 9869
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 126
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) 126
A NEW BAGHOUSE CASE (DSD) 14755
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE (FSI) 1.55
NEW BAGHOUSE (DSD) 1.55
20-90
-------
Eastlake steam plant. Table 20.3.3-13 presents the costs estimated to
retrofit DSD and FSI at the Eastlake 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 Eastlake plant. Boilers 1-4 at the Eastlake plant would
be considered good candidates for AFBC retrofit because of the small boiler
sizes (<300 MW). However, the high unit capacity factors make these units
poor candidates because of replacement power costs during downtime and
marginal heat rate improvements. Unit 5 would not be a good candidate due to
its large boiler size (680 MW) and because it is relatively new (built in
1972).
20-91
-------
Table 20.3.3-13. Sunnary of DSO/FSI Control Costs for the Eastlake Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 $02 S02 Cost
Nurtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MU) (X) Contant
BSO+ESP
1
1.00
.144
62
2.9
9.7
67.6
8.1
10.4
47.0
8535
952.3
OSO+ESP
2
1.00
144
65
2.9
9.7
67.6
8.3
10.1
47.0
8948
925.3
OSO'ESP
3
1.00
144
74
2.9
9.7
67.6
8.7
9.4
47.0
10187
857.3
DSO+ESP
4
1.00
260
56
2.9
13.9
53.5
10.7
8.4
44.0
12890
827.5
OSO+ESP-C
1
1.00
144
62
2.9
9.7
67.6
4.7
6.0
47.0
8535
550.7
OSJHESP-C
2
1.00
144
65
2.9
9.7
67.6
4.8
5.8
47.0
8948
535.0
DSO+ESP-C
3
1.00
144
74
2.9
9.7
67.6
5.0
5.4
47.0
10187
495.5
OSD+ESP-C
4
1.00
260
56
2.9
13.9
53.5
6.2
4.8
44.0
12890
478.9
DSO+FF
5
1.00
680
60
3.0
109.0
160.3
44.3
12.4
68.0
58416
759.1
DS0*FF-C
5
1.00
680
60
3.0
109.0
160.3
25.9
7.2
68.0
58416
443.3
FSI+ESP-50
1
1.00
144
62
2.9
9.3
64.8
9.0
11.5
50.0
9062
995.3
FSl+ESP-50
2
1.00
144
65
2.9
9.3
64.8
9.3
11.3
50.0
9501
977.5
FSI»ESP-50
3
1.00
144
74
2.9
9.3
64.8
10.1
10.8
50.0
10816
932.9
FSI-ESP-50
4
1.00
260
56
2.9
13.7
52.6
13.5
10.6
50.0
14779
916.5
FSI+ESP-50
5
1.00
680
60
3.0
35.1
51.6
36.1
10.1
50.0
42840
842.0
FSr*ESP-50-C
1
1.00
144
62
2.9
9.3
64.8
5.2
6.7
50.0
9062
574.9
FS1+ESP-50-C
2
1.00
144
65
2.9
9.3
64.8
5.4
6.5
50.0
9501
564.5
F$I*ESP-50-C
3
1.00
144
74
2.9
9.3
64.8
5.8
6.2
50.0
10816
538.4
FSI*ESP-50-C
4
1.00
260
56
2.9
13.7
52.6
7.8
6.1
50.0
14779
529.2
FSI»ESP-5D-C
5
1.00
680
60
3.0
35.1
51.6
20.8
5.8
50.0
42840
486.1
FSl*ESP-70
1
1.00
144
62
2.9
9.5
66.0
9.2
11.8
70.0
12687
724.9
F$l»ESP-70
2
1.00
144
65
2.9
9.5
66.0
9.5
11.6
70.0
13301
712.3
FSl»ESP-70
3
1.00
144
74
2.9
9.5
66.0
10.3
11.0
70.0
15142
679.8
FSI*E$P-70
4
1.00
260
56
2.9
13.9
53.6
13.8
10.8
70.0
20690
668.3
FSi+ESP-70
5
1.00
680
60
3.0
35.5
S2.2
36.8
10.3
70.0
59977
613.4
FSI*ESP-70-C
1
1.00
144
62
2.9
9.5
66.0
5.3
6.8
70.0
12687
418.7
FSI+ESP-70-C
2
1.00
144
65
2.9
9.5
66.0
5.5
6.7
70.0
13301
411.2
F$[*ESP-70-C
3
1.00
144
74
2.9
9.5
66.0
5.9
6.4
70.0
15142
392.3
FS!*ESP-70-C
4
1.00
260
56
2.9
13.9
53.6
8.0
6.3
70.0
20690
385.9
FSI~ESP-70-C
5
1.00
680
60
3.0
35.5
52.2
21.2
5.9
70.0
59977
354.1
20-92
-------
20.4 COLUMBUS AND SOUTHERN OHIO ELECTRIC COMPANY
20.4.1 Conesville Steam Plant
Information for Conesville steam plant appears in U.S. EPA report number
EPA-600/7-88/014, entitled "Ohio/Kentucky/TVA Coal-Fired Utility SOg and N0X
Retrofit Study" (NTIS PB88-244447/AS).
20.4.2 Picwav Steam Plant
The Picway steam plant is located in Coshocton County, Ohio as part of
the Columbus and Southern Ohio Electric Company system. The plant contains
one coal-fired boiler with a total gross generating capacity of 106 MW.
Tables 20.4.2-1 through 20.4.2-8 summarize the plant operational data and
present the SO2 and N0X control cost and performance estimates.
TABLE 20.4.2-1. PICWAY 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
11400
10.4
WET DISPOSAL
PONDS/ON-SITE
9
TRUCK
9
106
42
1955
NA
NO
2.5
FRONT WALL
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
1976
0.05
99.7
3.0-9.0
134.6
442
305
310
* Some information was obtained from plant personnel.
20-93
-------
TABLE 20.4.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR PICWAY UNIT 9 *
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
LOW
NA
LOW
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
MEDIUM
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
988
NA
988
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.42
NA
ESP REUSE CASE
1.43
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.36
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
5
0
5
* L/S-FGD and LSD-FGD absorbers for unit 9 would be located
south of unit 9.
20-94
-------
Table 20.4.2-3. Surma ry of FOD Control Costs for the Picway Plant (Jtne 1988 Dollars)
¦iBitiauBiBiaiitiaiiaamisMs::n::ssaaitiitiiMtitisa«»taaiaas>iasiaantiaiiia*uiaw«ats33:s:3scsi»5siastss
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Miafcer Retrofit Size Factor Sulfur Cost Cost Coat Cost Removed Removed Effect.
Difficulty Content (tttt) (*/kW) (WN) Onilts/kHh) (X) Ctons/yr) (»/ton)
Factor (X)
IC FGD 9 1.42 106 42 2.5 29.6 279.3 14.3 36.6 90.0 7508 1901.4
IC FGD-C 9 1.42 106 42 2.5 29.6 279.3 8.3 21.3 90.0 7508 1107.1
LFGD 9 1.42 106 42 2.5 . 43.3 408.4 18.7 47.8 90.0 7508 2485.3
LFGD-C 9 1.42 106 42 2.5 43.3 408.4 10.9 27.9 90.0 7508 1449.7
IS0+ISP 9 1.43 106 42 2.5 19.4 182.6 9.5 24.2 76.0 6365 1485.3
LS0+ESP-C 9 1.43 106 42 2.5 19.4 182.6 5.5 14.1 76.0 636S 864.6
20-95
-------
Table 20.4.2-4. Surinary of Coal Suitehing/Cleaning Costs for the Picuay Plant (Jtna 1986 Dollars)
S33SS5SS3Z3SSSS3S5SS38SI8SS33S5SSSSSI3SSSSS32SSSS3M33S35
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuirber Retrofit Siza Factor Sulfur Cost Coat Cost Cost Semoved Removed Effect.
Difficulty (HW> (X) Content («M> C»/kW) {»•() OatUs/ln*) (X) (tons/yr) <$/ton)
Factor (X)
•CS/B+I15
CS/B+S15-C
CS/8+S5
CS/B»S5-C
1.00 106
1.00 106
1.00 106
1.00 106
42
42
42
42
2.5
2.5
2.5
2.5
4.2 39.6 6.2 15.9
4.2 39.8 3.6 9.2
3.1 29.4 2.8 7.2
3.1 29.4 1.6 4.1
66.0
66.0
66.0
66.0
5527
5527
5527
5527
1123.9
647.3
506.2
292.6
333:23S3:3lB3333CS33l33333l3333ISZ3338tSSS83St81333SSS8338S3aS3333S«83333S>S33333SS83333fS&CS333t«3S3333S333333
20-96
-------
TABLE 20.4,2-5. SUMMARY OF NOx RETROFIT RESULTS FOR PICWAY
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
9
FIRING TYPE FWF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) NA
BOILER INSTALLATION DATE 1955
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 40
SCR RETROFIT RESULTS *
SITE ACCESS AND CONGESTION
FOR SCR REACTOR LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 28
New Duct Length (Feet) 300
New Duct Costs (1000$) 1538
New Heat Exchanger (1000$) 1930
TOTAL SCOPE ADDER COSTS (1000$) 3496
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
* Cold side SCR reactors for unit 9 would be located south
of unit 9.
20-97
-------
Table 20.4.2-6. NO* Control Cost Results for the Picway Plant (Jme 1988 Dollars)
SSSSSS=SSS3SS3»SSSa3SS3K«SSSsSSSS*3SSSS3mCSaS«XS3aSS*3SSSSKXXSSSSSaaa«S3a>a«CSSSC3S2S3=SaS=SS=35S3S3SCS=aa5S====
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual HOx MOx NOx Cost
Nurfcer Retrofit Size factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (WO <%> Content (SMM) C$/ky> {»»0 (niills/kwh) (%)
factor (X)
LNC-LNB 9 1.00 106 42 2.5 2.6 24.7 0.6 1.4 40.0 719 785.1
LNC-LMB-C 9 1.00 106 42 2.5 2.6 24.7 0.3 0.9 40.0 719 466.1
SCR-3 9 1.16 106 42 2.5 19.7 186.1 6.4 16.5 80.0 1438 4468.3
SCR-3-C 9 1.16 106 42 2.5 19.7 186.1 3-8 9.7 80.0 1438 2621.5
SCR-7 9 1.16 106 42 2.5 19.7 186.1 5.5 14.2 80.0 1438 3857.8
SCR-7-C 9 1.16 106 42 2.5 19.7 186.1 3.3 8.4 80.0 1438 2271.7
3iitiita;sit3:;a3SMs:::a:K:s:::st:::s::s3s:s::st:::sss::sas:M>s::9ii::si«essisi:ifia:si>S3iaii8acsiissais2iai
20-98
-------
TABLE 20.4.2-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR PICWAY UNIT 9
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$) 988
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 31
TOTAL COST (1000$)
ESP UPGRADE CASE 1019
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 9 and the unit 9 ESPs
is short; however, the ESPs are large enough for FSI and DSD.
20-99
-------
Table 20.4.2-8. Surinary of 0SD/FS1 Control Costs for the Picaay Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Neuter Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW> Content (SUN)
-------
20.4.3 Poston Steam Plant
The Poston steam plant is located within Athen County, Ohio, as part of
the Columbus and Southern Ohio Electric Company system. The plant contains
four coal-fired boilers with a gross generating capacity of 232 MW.
Figure 20.4.3-1 shows the plant and major associated auxiliary equipment at
the Poston plant.
Table 20.4.3-1 presents the operational data for the existing equipment
at the Poston plant. The boilers burn medium to high sulfur coal
(3.0 percent sulfur). The coal for the plant is received by truck and
conveyed to a coal storage/handling area located beside (east) unit 1.
Particulate matter emissions for all units are controlled with ESPs
located behind each unit. The ash from the units is wet sluiced to an ash
pond south of the switch yard.
Lime/Limestone and Lime Spray Drying FGD Costs--
The L/LS-FGD absorbers were located behind the chimney where several
small buildings and miscellaneous tanks would be relocated in order to make
space available. The LSD absorbers were located to the east of the
powerhouse in an area between the ESPs and the cooling towers. The lime
preparation/storage area was located adjacent to the absorbers to the
northeast, between the powerhouse and the cooling tower. Finally, the
temporary waste handling area was located to the west between the ash pond
and the switch yard. The 10 percent general facilities adjustment is
required for the demolition and replacement of several small buildings and
miscellaneous tanks for the placement of the absorbers as close as possible
to the chimney.
Retrofit Difficulty and Scope Adder Costs--
The equipment at the Poston plant includes four boilers, two abandoned
chimneys and one common chimney, old ESPs, and retrofit ESPs. The boilers
sit side by side in ascending order. The old ESPs are still in place and
are located immediately behind the boilers while the retrofit ESPs are
located directly behind these old ESPs. Although there are three chimneys
at the plant, only one is used and it is located behind (north) the units 2
20-101
-------
Lime/Limestone
NHj Storage Storage/Preparation
System Area
4 II
Ash Pond
Not to scale
FGD Waste Handling/Absorber Area
Lime/Limestone Storage/Preparation Area
NH, Storage System
SCR Boxes
Figure 20.4.3-1. Poston plant plot plan
20-102
-------
TABLE 20.4.3-1. P0ST0N 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
44
69, 75
34, 31
34, 50
1949-50
1952-54
FWF
FWF-TANG
3.0
3.0
11500
11500
9.5
9.5
WET SLUICE
POND/ON-SITE
S 3
TRUCK
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (#F)
ESP
1976
0.09-0.05
99.7
3.0
63.6
198
321
277-305
ESP
1977
0.09-0.08
99.7
3.0
83.2
267
312
316,
309
20-103
-------
and 3 retrofit ESPs. The cooling towers sit to the north of the equipment
discussed above. The flue gases from units 1-2 and 3-4 are routed from two
separate ducts to a single, common duct which feeds into the chimney. No
operational data was available for unit 4 during 1986.
The L/LS-FGD absorbers for all units were located north of the
powerhouse and ESPs. This location is bounded by the chimney, the cooling
towers, and an open area. A medium site access/congestion factor was
assigned to the L/LS-FGD absorber locations to account for this congestion.
The flue gas handling factor assigned to the L/LS-FGD cases were low
because of the short duct run required and the minimal congestion associated
with the placement of the L/LS-FGD absorbers.
The major scope adjustment costs and estimated retrofit factors for the
FGD control technologies are presented in Tables 20.4.3-2 and 20.4.3-3. The
largest scope adder at the Poston plant would be the conversion from wet to
dry ash handling/disposal for both conventional L/LS-FGD and LSD-FGD
technologies. 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. This conversion is not required for
forced oxidation FGD application. The overall retrofit factors determined
for the L/LS-FGD cases were medium (1.31 to 1.36).
The LSD technology evaluated at Poston was LSD with ESP reuse. This
technology was selected because of the moderate SCA (>310). For the LSD-FGD
cases, two absorber sites were designated. The absorbers for units 1 and 2
were placed adjacent and to the south of unit 1 in an open area with no
significant obstructions. The absorbers for units 3 and 4 were placed to
the east of the ESPs for units 3 and 4. This area is congested by the
chimney, ductwork and ESPs and, as such, a medium site access/congestion
factor was assigned to these absorber locations. A medium to high flue gas
handling factor was assigned to the LSD-FGD cases because of the limited
space available for the flue gas ducting from the boiler air heater outlet
to the absorbers and back. The retrofit factors for LSD-FGD were medium
(1.44 to 1.48) because of the space constraints created between the old
chimney and the duct. Separate factors were estimated for particulate
control upgrading at the plant. These factors were low to medium (1.16 to
1.36) and reflect the access/congestion around the existing ESPs. This
20-104
-------
TABLE 20.4.3-2. SUMMARY OF RETROFIT FACTOR DATA FOR POSTON UNITS 1-2
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 0-100 0-100
ESP REUSE 100-300
BAGHOUSE NA
ESP REUSE NA NA MEDIUM
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES
ESTIMATED COST (1000$) 449
NEW CHIMNEY NO
ESTIMATED COST (1000$) 0
OTHER NO
NO
NA
NO
0
NO
YES
449
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.36
NA
NA
1.31
NA
NA
1.48
NA
1.36
NA
GENERAL FACILITIES (PERCENT) 10
10
10
20-105
-------
TABLE 20.4.3-3. SUMMARY OF RETROFIT FACTOR DATA FOR POSTON UNITS 3-4
FGD TECHNOLOGY
FORCED
L/LS FGD OXIDATION
LIME
SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
ESTIMATED COST (1000$)
NEW CHIMNEY
ESTIMATED COST (1000$)
OTHER
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
MEDIUM
LOW
0-100
MEDIUM
LOW
0-100
NA
NA
YES
549
NO
0
NO
1.36
NA
NA
NA
NA
NO
NA
NO
0
NO
1.31
NA
NA
MEDIUM
MEDIUM
NA
100-300
NA
LOW
NA
YES
549
NO
0
NO
1.44
NA
1.16
NA
GENERAL FACILITIES (PERCENT) 10
10
10
20-106
-------
factor was used by the IAPCS model to estimate costs of plate area addition,
if required.
Table 20.4.3-4 presents the cost estimates for L/LS-FGD 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 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 SOj 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 20.4.3-5.
NO Control Technology Costs--
A
This section presents the performance and various related costs
estimated for N0X controls at Poston. 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 low N0X combustion modification controls evaluated were LNB for units 1
to 3 and OFA for unit 4. SCR was also evaluated for all four boilers.
Low N0x Combustion--
Units 1 and 3 are dry bottom, front wall-fired boilers; units 1 and 2 are
rated at 44 MW each and unit 3 is rated at 69 MW. Unit 4 is a dry bottom,
tangential-fired boiler rated at 75 MW. Thus, the combustion modification
20-107
-------
Table 20.4.3-4. Swmary of FGD Control Costs for the Poston Plant (June 1988 Dollars)
aaiisa«ii!iiiaauiisisssBiiiissi>is>iii«ssii9iMi:33i::£ss:::sas:sss:x:::s:si:=sxs3S£:r=ss==::::ss=::=2:::=zszs:
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
S02
S02
S02 Cost
Nurtoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
Cmills/kwh)
(X)
(tons/yr)
($/ton)
Factor
(X)
IC FGD
1-4
1.36
232
39
3.0
45.2
194.6
22.7
28.7
90.0
18129
1254.2
LC FGD-C
1-4
1.36
232
39
3.0
45.2
194.6
13.2
. 16.7
90.0
18129
729.7
lfgo
1
1.36
44
34
3.0
27.5
623.9
11.6
88.2
90.0
2998
3856.8
LFGD
2
1.36
44
31
3.0
27.5
625.2
11.4
95.6
90.0
2733
4180.3
LFCD
3
1.36
69
34
3.0
34.6
501.9
14.5
70.5
90.0
4701
3080.7
tFDD
4
1.36
75
50
3.0
36.2
482.4
16.3
49.5
90.0
7514
2164.8
iFGD-C
1
1.36
44
34
3.0
27.5
623.9
6.7
. 51.5
90.0
2998
2250.8
IFGD-C
2
1.36
44
31
3.0
27.5
625.2
6.7
55.8
90.0
2733
2440.2
LFGD-C
3
1.36
69
34
3.0 ¦
34.6
501.9
8.5
41.1
90.0
4701
1798.1
LFGD-C
4
1.36
75
50
3.0
36.2
482.4
. '-5
28.9
90.0
7514
1261.9
ISO+ESP
1
1.48
44
34
3.0
11.3
255.7
6.0
46.1
65.0
2172
2781.1
LSD+ESP
2
1.48
44
31
3.0
11.8
268.9
6.2
52.2
75.0
2277
2741.1
LSD+ESP
3
1.44
69
34
3.0
15.2
220.3
7.6
37.1
76.0
3985
1912.6
LSD+ESP
4
1.44
' 75
50
3-0
16.0
213.0
8.4
25.7
76.0
6370
1323.7
LSD*ESP-C
1
1.48
44
34
3.0
11.3
255.7
3.5
26.8
65.0.
2172
1616.7
ISD+ESP-C
2
1.48
44
31
3.0
11.8
268.9
3.6
30.4
75.0
2277
1593.8
ISD+ESP-C
3
1.44
69
34
3.0
15.2
220.3
4.4
21.6
76.0
3985
1112.9
LSD-ESP-C
4
1.44
75
50
3.0
16.0
213.0
4.9
14.9
76.0
6370
769.6
II
It
<1
II
II
II
II
II
II
II
II
:;:S3i^xs
zsssaass
:SSSS33S3
!»»sss:j
I31SSSCI
IRSS SSSSSSSf
a=s==B
20-108
-------
Table 20.4.3-5. Suimary of Coal Switching/Cleaning Costs for the Poston Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 S02 Cost
Nurfcer Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
Content
(MM)
(S/kW)
(MH>
(rat IIs/kwh)
(X)
(tons/yr)
(I/ton)
Factor
(X)
CS/B+J15
1 1.00
44
34
3.0
2.3
52.3
2.5
18.7
72.0
2384
1028.8
CS/B+S15
2 1.00
44
31
3.0
2.3
52.3
2.3
19.1
72.0
2174
1052.4
CS/B*t15
3 1.00
69
34
3.0
3.1
45.4
3.6
17.5
72.0
3739
960.5
CS/B+S15
4 1.00
75
50
3.0
3.3
44.3
5.3
16.1
72.0
5976
887.6
CS/B+J15-C
1 1.00
44
34
3.0
2.3
52.3
1.4
10.8
72.0
2384
593.7
CS/B+S15-C
2 1.00
44
31
.3.0
2.3
52.3
1.3
11.1
72.0
2174
607.7
CS/B+S15-C
3 1.00
69
34
3.0
3.1
45.4
2.1
10.1
72.0
3739
554.0
CS/B+S15-C
4 1.00
75
50
3.0
3.3
44.3
3.1
9.3
72.0
5976
511.0
CS/B+S5
1 1.00
44
34
3.0
1.8
42.0
1.3
9.8
72.0
2384
541.3
CS/B+S5
2 1.00
44
31
3.0
1.8
42.0
1.2
10.2
72.0
2174
561.7
CS/B*$5
3 1.00
69
34
3.0
2.4
35.0
1.8
8.6
72.0
3739
473.0
CS/B«*5
4 1.00
75
50
3.0
2.5
33.9
2.5
7.5
72.0
5976
410.8
CS/B*S5-C
1 1.00
44
34
3.0
1.8
42.0
0.7
5.7
72.0
2384
313.6
CS/B+J5-C
2 1.00
44
31
3.0
1.8
42.0
0.7
5.9
72.0
2174
325.6
CS/B+tS-C
3 1.00
69
34
3.0
2.4
35.0
1.0
5.0
72.0
3739
273.9
CS/B+S5-C
4 1.00
75
50
3.0
2.5
33.9
1.4
4.3
72.0
5976
237.3
20-109
-------
control considered for units 1 to 3 was INB and that considered for unit 4
was OFA. Tables 20.4.3-6 and 20.4.3-7 present the N0X reduction performance
results for the four units. The N0X reduction performance could not be
estimated for units 1 and 2 due to lack of information from POWER. Although
LNBs are applicable for these units, LNB may not be feasible from a cost
standpoint since both units are small and old. The N0X reduction performance
estimated for unit 3, equipped with LNBs, would be 50 percent while the N0X
reduction performance for unit 4, equipped with OFA, would be 20 percent.
The N0X reduction performances were determined by examining the effects of
heat release rates and furnace residence time on N0X reduction through the
use of the simplified procedures.
Table 20.4.3-8 presents the cost of retrofitting LNB and OFA at the
Poston plant. The unit cost of LNC was estimated to be 440 to 804 $/ton of
N0X removed. Application of LNC to all the boilers reduces NOx by 700 tons
per year.
Selective Catalytic Reduction-
Tables 20.4.3-6 and 20.4.3-7 present the SCR retrofit results for each
unit. The results include process area retrofit difficulty factors and scope
adder costs. For scope adders, costs are estimated for ductwork demolition,
new flue gas heat exchanger, and new duct runs to divert the flue gas from
the ESPs to the reactor and from the reactor to the chimney. The reactors
for units 1 and 2 were located behind their respective ESPs north of the
powerhouse; the reactors for units 3 and 4 were located northwest of their
respective ESPs and west of the common chimney.
Reactors for units 1-4 were assigned a medium access/congestion factor
since the reactors were located on a highly congested area surrounding the
common chimney with easy assess. All reactors were assumed to be on areas
with high underground obstructions. Table 20.4.3-8 presents the estimated
cost of retrofitting SCR at the Poston boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for S02 control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
20-110
-------
TABLE 20.4.3-6. SUMMARY OF NOx RETROFIT RESULTS FOR POSTON UNITS 1-3
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1
2
3
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
LNB
LNB
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
14
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
46.3
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
3.87
ESTIMATED NOx REDUCTION (PERCENT)
NA
NA
50
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
MEDIUM
MEDIUM
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
15
15
17
New Duct Length (Feet)
100
100
100
New Duct Costs (1000$)
307
307
349
New Heat Exchanger (1000$)
1139
1139
1466
TOTAL SCOPE ADDER COSTS (1000$)
1460
1460
1833
RETROFIT FACTOR FOR SCR
1.34
1.34
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
20-111
-------
TABLE 20.4.3-7. SUMMARY OF NOx RETROFIT RESULTS FOR POSTON 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) 17.5
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR) 29.6
FURNACE RESIDENCE TIME (SECONDS) 3.04
ESTIMATED NOx REDUCTION (PERCENT) 20
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$) 0
Ductwork Demolition (1000$) 20
New Duct Length (Feet) 150
New Duct Costs (1000$) 588
New Heat Exchanger (1000$) 1466
TOTAL SCOPE ADDER COSTS (1000$) 2074
RETROFIT FACTOR FOR SCR 1.34
GENERAL FACILITIES (PERCENT) 13
20-112
-------
Table 20.4.3-8.
NOx Control
Cost Results for '
the Poston Plant
(June 1988 Doll
.ars)
===««=======
--------
3 = s=3fc=s=:
I33S8Z3S
==r»x=
II
II
II
U
u
II
II
====S3=*:
istsxxc:
II
II
II
II
N
II
U
u
II
II
II
====*=
<1
II
<1
0
II
II
II
II
II
II
Technology
Boiler
Main-
Boiler Capacity Coal
Capital
Capital
Annual
Annual
NOx
NOx
NOx Cost
Nmtjer
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty CMU)
(X)
Content
-------
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 the plant were
located to the northeast of the units in a layout similar to that for
LSD-FGD. The retrofit of DSD and FSI would be relatively easy given the
large SCA of the units (>310) and sufficient duct residence. An access/
congestion factor of low to medium was assumed for any ESP upgrades. The
major scope adder cost for DSD and FSI would be the conversion of the fly
ash from wet to dry for reusing the ESPs. Tables 20.4.3-9 and 20.4.3-10
present a summary of site access/congestion factors, scope adders, and
retrofit factors for DSD and FSI technologies at the Poston plant.
Table 20.4.3-11 presents the cost estimated to retrofit DSD and FSI at the
Poston 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 Poston plant. All boilers at Poston would be considered
good candidates for AFBC retrofit and AFBC or coal gasification/combined
cycle repowering due to their small boiler sizes {<70 MW), age, and low
capacity factors.
20-114
-------
TABLE 20.4.3-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR POSTON UNITS 1-2
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION MEDIUM
ESP UPGRADE MEDIUM
NEW BAGHOUSE NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING YES
ESTIMATED COST (1000$) 449
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$) 16
TOTAL COST (1000$)
ESP UPGRADE CASE 465
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.34
NEW BAGHOUSE NA
20-115
-------
TABLE 20.4.3-10. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR POSTON UNITS 3-4
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION
MEDIUM
ESP UPGRADE
LOW
NEW BAGHOUSE
NA
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING
YES
ESTIMATED COST (1000$)
655
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE
NA
ESTIMATED COST (1000$)
NA
ESP REUSE CASE
NA
ESTIMATED COST (1000$)
NA
DUCT DEMOLITION LENGTH (FT)
50
DEMOLITION COST (1000$)
22
TOTAL COST (1000$)
ESP UPGRADE CASE
677
A NEW BAGHOUSE CASE
NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY)
1.25
ESP UPGRADE
1.13
NEW BAGHOUSE
NA
20-116
-------
Table 20.4.3-11. Suimary of DSO/FSI Control Costs for the Poston Plant (June 1988 Dollars)
siasiiisiai3is3ai3iiaiisiisaisiiiii«i3isaH:;
ssdz3i3aa3iis::s:
tsaassss:
:s::s:iiiisxaiiasa»xiiiiixiiisiEi=
ssssiaiai
Technology
Boilir
K»in
Boiler Capacity Coal
C8pi tal
Capital
Annual
Annual
S02
S02
SC2 Cost
Nunber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (NU)
(X)
Content
(SKH)
<$/kW)
<$**>
(mi IIs/kuh)
(X)
(tons/yr)
(S/ton)
Factor
(X)
DSD*ESP
1
1.00
44
34
3.0
5.2
118.5
4.2
32.2
43.0
1436
2936.1
0SD*ESP
2
1.00
44
31
3.0
5.6
126.2
4.3
36.4
48.0
1457
2983.8
DSO+ESP
3
1.00
69
34
3.0
6.8
98.2
5.1
24.7
49.0
2541
1994.7
DSO+ESP
4
1.00
75
50
3.0
7.1
94.0
5.7
17.3
49.0
4062
1403.0
DSD»ESP-C
1
1.00
44
34
3.0
5.2
118.5
2.4
18.6
43.0
1436
1698.5
DSD+ESP-C
2
1.00
44
31
3.0
5.6
126.2
2.5
21.1
48.0
1457
1726.7
DSD*ESP-C
3
1.00
69
34
3.0
6.8
98.2
2.9
14.3
49.0
2541
1154.8
DSD+ESP-C
4
1.00
75
50
3.0
7.1
94.0
3.3
10.0
49.0
4062
811.6
FSI+ESP-50
1
1.00
44
34
3.0
5.8
131.2
3.6
27.6
50.0
1665
2169.7
FSl*ESP-50
2
1.00
44
31
3.0
5.8
131.6
3.5
29.5
50.0
1518
2324.3
FSI+ESP-50
3
1.00
69
34
3.0
6.8
99.1
4.4
21.6
50.0
2611
1698.3
FSI+ESP-50
4
1.00
75
50
3.0
7.1
95.1
5.5
16.6
50.0
4174
1308.8
FSI+ESP-50-C
1
1.00
44
34
3.0
5.8
131.2
2.1
16.0
50.0
1665
1258.6
FSI*ESP-50-C
2
1.00
44
31
3.0
5.8
131.6
2.0
17.1
50.0
1518
1348.8
FSI+ESP-50-C
3
1.00
69
34
3.0
6.8
99.1
2.6
12.5
50.0
2611
984.8
FSI+ESP-50-C
4
1.00
75
50
3.0
7.1
95.1
3.2
9.6
50.0
4174
757.5
FSI+ESP-70
1
1.00
44
34
3.0
5.9
133.3
3.7
27.9
70.0
2331
1570.0
FS1+ESP-70
2
1.00
44
31
3.0
5.9
133.2
3.6
29.9
70.0
2126
1678.7
FS1-ESP-70
3
1.00
69
34
3.0
6.9
99.7
4.5
21.8
70.0
3656
1225.9
*S!*ESP-70
4
1.00
75
50
3.0
7.2
95.8
5.5
16.8
70.0
5844
947.1
FSI+ESP-70-C
1
1.00
44
34
3.0
5.9
133.3
2.1
16.2
70.0
2331
910.8
FSI+ESP-70-C
2
1.00
44
31
3.0
5.9
133.2
2.1
17.3
70.0
2126
974.1
FSI+ESP-70-C
3
1.00
69
34
3.0
6.9
99.7
2.6
12.6
70.0
3656
710.8
FS1+ESP-70-C
4
1.00
75
50
3.0
7.2
95.8
3.2
9.8
70.0
5844
548.1
iiiaaBtaiazaaaaaiaaaaaaainaaaiai
misi
isaaaas:
:s3ss*ataiati
tsasataisa
issassssss
ssaaass
ssaasssass;
ssssass:
II
M
II
II
II
II
II
II
20-117
-------
20.5 DAYTON POWER AND LIGHT COMPANY
20.5.1 James M. Stuart Steam Plant
Information on James M. Stuart Steam Plant appears in U.S. EPA report
number EPA-600/7-88/014, entitled "Ohio/Kentucky/TVA Coal-Fired Utility S02
and N0X Retrofit Study" (NTIS PB88-244447/AS).
20.6 OHIO EDISON COMPANY
20.6.1 R. E. Burger Steam Plant
Information on R. E. Burger Steam Plant appears in U.S. EPA report
number EPA-600/7-88/014, entitled "Ohio/Kentucky/TVA Coal-Fired Utility SO£
and N0X Retrofit Study" (NTIS PB88-244447/AS).
20.6.2 Niles Plant
The Niles plant is located within Trumbull County, Ohio, as part of the
Ohio Edison Company system. The plant is located beside the Mahoning River
northeast of the Meander reservoir and contains two coal-fired boilers with a
total gross generating capacity of 230 MW.
Table 20.6.2-1 presents operational data for the existing equipment at
the Niles plant. The boilers burn high sulfur coal which is received by
truck and transferred to a coal storage and handling area east of the plant
and adjacent to the river.
PM emissions for both boilers are controlled with retrofit ESPs located
north of units 1-2. The fly ash is wet sluiced and disposed to an ash pond
located west of the plant. A common chimney was constructed in the early
1980's on the south side of the plant.
Lime/Limestone and Lime Spray Drying FGO Costs--
The FGD absorbers would be located in a relatively open space beside
the chimney south of the coal conveyor. Because there are no major
obstacles or obstructions around the absorber locations, a low site access/
congestion factor was assigned. Short duct runs would be required for
20-118
-------
TABLE 20.6.2-1. NILES STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
1, 2
GENERATING CAPACITY (MW-each)
115
CAPACITY FACTOR (PERCENT)*
69,67
INSTALLATION DATE
1954
FURNACE VOLUME (1000 CU FT)
NA
LOW NOX COMBUSTION
NO
FIRING TYPE
CYCLONE
COAL SULFUR CONTENT (PERCENT)
3.2
COAL HEATING VALUE (BTU/LB)
11700
COAL ASH CONTENT (PERCENT)
12
FLY ASH SYSTEM
ON-SITE
ASH DISPOSAL METHOD
WET SLUICE
STACK NUMBER
1
COAL DELIVERY METHODS
TRUCK
PARTICULATE CONTROL
TYPE
ESP
INSTALLATION DATE
1981
EMISSION (LB/MM BTU)
0.02
REMOVAL EFFICIENCY
99.0
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
4.0
SURFACE AREA (1000 SQ FT)
278
GAS EXIT RATE (1000 ACFM)
535
SCA (SQ FT/1000 ACFM)
520
OUTLET TEMPERATURE ("F)
270
*1988 data.
20-119
-------
L/LS-FGO cases (about 200 feet) because the absorbers would be placed
immediately behind the chimneys. Plant personnel indicated that this area
will be used as a site for the Clean Coal II project (35MW, WSA-SNOX) in
mid-1990. Therefore, retrofit factors developed here might not be
appropriate in the future.
LSD with reuse of the existing ESPs was considered for this plant
because the retrofit ESPs are large (SCA =520) and would not require major
upgrading and plate area additions to handle the increased PM generated from
the LSD application. The LSD absorbers would be located beside the common
chimney with a low site access/congestion factor. To access the upstream of
the ESPs which are faced toward the river, duct runs would have to go under
the coal conveyor and around the ESPs. Therefore, a high site access/
congestion factor was assigned to the flue gas handling system. A separate
retrofit factor was developed for ESP upgrade, if needed. The assigned
factor was high because of the congestion around the ESPs. This congestion
is created by the river to the north, coal conveyor to the east, and close
proximity of the ESPs to each other and to the boilerhouse.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 20.6.2-2. Table 20.6.2-3 presents the
process area retrofit factors and capital/operating costs for commercial FGD
technologies. The low cost FGD option shows the cost reduction due to
eliminating spare absorber modules.
Coal Switching and Physical Coal Cleaning Costs
Both units at the Niles plant have wet bottom boilers and CS was not
considered because low sulfur bituminous coals having low ash fussion
temperatures are not readily available in the east. PCC was not evaluated
because this is not a mine mouth plant.
Low NOx Combustion--
Both units are cyclone boilers rated at 115 MW each and the combustion
modification technique applied to both boilers was NGR. As Table 20.6.2-4
shows, the NGR N0X reduction performance for each unit was assumed to be
60 percent. Table 20.6.2-5 presents the cost of retrofitting NGR at the
Niles plant.
20-120
-------
TABLE 20.6.2-2. SUMMARY OF RETROFIT FACTOR DATA FOR NILES
UNIT 1 OR 2
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION*
S02 REMOVAL
FLUE GAS HANDLING
ESP REUSE CASE
BAGHOUSE CASE
DUCT WORK DISTANCE (FEET)
ESP REUSE
BAGHOUSE
ESP REUSE
NEW BAGHOUSE
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
1063
NA
1063
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE
1.43
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT) 5
0
5
LOW
LOW
100-300
NA
NA
NA
NA
NA
NA
NA
LOW
HIGH
NA
300-600
NA
HIGH
NA
* This area will be used for Clean Coal II demonstration sites
in mid-1990, and retrofit factors developed here need to be
revised in the future.
20-121
-------
Table 23.6.2*3. Surmary of FGD Control Costs for the Miles Plant (June 1985 Dollars)
"ethnology
So i\cr
Mai n
Boiler
Capacity Coal
Capi tal
Capital
Annual
Annual
S02
S02
SQ2 Cost
Hurber
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Dif'iculty sii=zxi3imtiaiiisiiiziiE;ii=iicaaiSEas
sussas
53IS3ISSS
20-122
-------
TABLE 20.6.2-4. SUMMARY OF NOx RETROFIT RESULTS FOR NILES
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
1-2
FIRING TYPE
CYC
NA
TYPE OF NOx CONTROL
NGR
NA
FURNACE VOLUME (1000 CU FT)
NA
NA
BOILER INSTALLATION DATE
1954
NA
SLAGGING PROBLEM
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION*
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000$)
30
50
New Duct Length (Feet)
250
250
New Duct Costs (1000$)
1344
2016
New Heat Exchanger (1000$)
2027
3072
TOTAL SCOPE ADDER COSTS (1000$)
3401
5139
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
* This area will be used for Clean Coal II demonstration sites
in mid-1990, and retrofit factors developed here need to be
revised in the future.
20-123
-------
Table 20.6.2-5. NO* Control Cost Results for the Niles Plant (June 1988 Dollars)
Technology
Boiler
Main
Boiler Capacity Coal
Capital
Capital Annual
Annual
NOX
NO*
NOx Cost
Muifcer
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (MW)
(X)
Content
(SIM)
(S/kH)
(SUM)
(millsAwh)
(X)
(tons/yr)
(t/ton)
Factor
CX)
NGR
1
1.00
115
69
3.2
2.5
21.4
3.9
5.6
60.0
3286
1191.3
NCR
2
1.00
115
67
3.2
2.5
21.4
3.8
5.6
60.0
3191
1194.9
NGR-C
1
1.00
115
69
3.2
2.5
21.4
2.3
3.2
60.0
3286
685.9
NGR-C
2
1.00
115
67
3.2
2.5
21.4
2.2
3.3
60.0
3191
688.0
SCR-3
1
1.16
115
69
3.2
20.6
178.8
7.2
10.3
80.0
4382
1636.9
SCR-3
2
1.16
115
67
3.2
20.6
178.8
7.2
10.6
80.0
4255
1680.6
SCR-3
1-2
1.16
230
68
3.2
33.9
147.5
12.4
9.1
80.0
8636
1440.7
SCR-3-C
1
1.16
115
69
3.2
20.6
178.8
4.2
6.0
80.0
4382
958.9
SCR-3-C
2
1.16
115
67
3.2
20.6
178.8
4.2
6.2
80.0
4255
984.5
SCR-3-C
1-2
1.16
230
68
3.2
33.9
147.5
7.3
5.3
80.0
8636
843.0
SCR-7
1
1.16
115
69
3.2
20.6
178.8
6.2
9.0
80.0
4382
1420.4
SCR-7
2
1.16
115
67
3.2
20.6
178.8
6.2
9.2
80.0
4255
1457.7
SCR-7
1-2
1.16
230
68
3.2
33.9
147.5
10.5
7.7
80.0
8636
1221.1
SCR-7-C
1
1.16
115
69
3.2
20.6
178.8
3.7
5.3
80.0
4382
834.9
SCR-7-C
2
1.16
115
67
3.2
20.6
178.8
3.6
5.4
80.0
4255
856.8
SCR-7-C
1-2
1.16
230
68
3.2
33.9
147.5
6.2
4.5
80.0
8636
717.2
======s_
SSS3SSSSS:
:szz:ss:
II
tl
II
II
II
»
II
:a::ats::
srssssBs:
II
II
II
II
II
II
II
II
II
s===«=S ==:
20-124
-------
Selective Catalytic Reduction-
Cold side SCR reactors for both units would be located beside the
common chimney in a low site access/congestion areas with short flue gas
duct runs. No major demolition/relocation would be required for SCR reactor
locations. Therefore, a factor of 13 percent was assigned to general
facilities. Again, due to the Clean Coal II project, site access/congestion
and duct length would possibly be different.
Table 20.6.2-4 presents the SCR process area retrofit factors and scope
adder costs. Table 20.6.2-5 presents the estimated cost of retrofitting SCR
at the Niles boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of DSD and FSI technologies at the Niles steam plant for
both units would be possible for two major reasons: 1) ESPs have large SCAs
(>500) and would probably be able to handle the increased particulate matter;
and 2) sufficient duct residence time between the boilers and ESPs would
possibly provide sufficient time for humidification (FSI application) or
sorbent evaporation (DSD application). Table 20.6.2-6 presents a summary of
the site access/congestion factors for FSI and DSD technologies at the Niles
steam plant. Plant personnel indicated that installation of a bypass duct is
likely for sorbent injection technologies. Table 20.6.2-7 presents the costs
estimated to retrofit FSI and DSD at the Niles boilers.
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
The AFBC retrofit and AFBC/CG repowering applicability criteria
presented in Section 2 were used to determine the applicability of these
technologies at the Niles plant. Both units would be considered good
candidates for repowering or retrofit because of their small boiler size and
long service life. However, because of the small volumetric heat release
area, it would be difficult to convert the existing boilers to FBC units.
The relatively high capacity factors could result in high replacement power
costs for extended downtime.
20-125
-------
TABLE 20.6.2-6. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR NILES UNIT 1 OR 2
ITEH
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$) 1063
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 35
TOTAL COST (1000$)
ESP UPGRADE CASE 1098
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
20-126
-------
Table 20.6.2-7. Sunnary of DSO/FSI Control Costs for the Niles Plant (June 1988 dollars)
5S3S3IIIISSSSSSS3ZIIISSISS2SSSSSSIBIIIIS3I3SSS31I>IIIISSSSS3S3S535ISI85SSSSSSSS8SSSI-"SSSS5SSSSSSS33S55S5S5SSS53
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty CMW) (X) Content (SMM) (t/kW)
-------
20.6.3 W. H. Sammis Steam Plant
Information on W. H. Sammis 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).
20.6.4 Toronto Plant
The Toronto plant is located within Jefferson County, Ohio, as part of
the Ohio Edison Company system. The plant is bounded by the Ohio River and a
major highway. The plant contains 11 coal-fired boilers but units 1-8 are
retired. Only units 9-11 were considered for this study and they have a
total gross generating capacity of 181 MW. Figure 20.6.4-1 presents the
plant plot plan showing the location of all boilers and major associated
auxiliary equipment.
Table 20.6.4-1 presents operational data for the existing equipment at
the Toronto plant. Coal shipments are received by truck and conveyed to a
coal storage and handling area located southwest of the main plant building.
Particulate matter emissions for the boilers are controlled with
retrofit ESPs. The plant has a wet sluiced fly ash handling system and is
disposed to two ash ponds north of the plant (bottom ash ponds are located
southwest of the plant). The fly ash ponds are periodically taken out of
service on a rotational basis, dewatered, and the ash loaded into trucks and
taken to a landfill for disposal.
Lime/Limestone and lime Spray Drying FGD Costs-
Figure 20.6.4-1 shows the general layout and location of the FGD control
system. All 11 boilers sit side by side, parallel to the Ohio River. Flue
gas for units 9-11 is converged into a common duct to a common chimney,
located behind the powerhouse beside the switch yard. The absorbers for
L/IS-FGD and LSD-FGD for the units would be located close to the chimney
beside the powerhouse west of the river in a relatively open area. No major
demolition/relocation would be required. The Hme storage/handling area
would be located north of the absorbers in what is presently an ash pond with
the waste handling area located adjacent to it. Plant personnel indicated
that additional real estate has to be acquired to accommodate the FGD
20-128
-------
ChimrxY*
Not to
scale
F„ure 20.6.«->-
Toronto
plant P1ot
20-I*9
-------
TABLE 20.6.4-1.
TORONTO 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
9
10,11
45
68
34
41,45
1940
1949
FWF
FWF
3.4
3.4
11300
11300
14.7
14.7
WET-SLUICED
PONDS/ON-SITE
1
TRUCK
PARTICULATE CONTROL
TYPE
INSTALLATION DATE*
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
EXIT GAS FLOW RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
1970
1970
0.03
0.07-9
99.0
99.0
1.5
1.5
44.3
72
186
303
238
237
350
350
+ 1988 data.
* Upgraded in 1980.
20-130
-------
equipment. This cost was added to the FGD costs {5 percent increase in
general facilities).
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 with no major
obstacles/obstructions.
For flue gas handling, short to medium duct runs for the units would be
required for L/LS-FGD cases since the absorbers would be close to the common
duct run/chimney with easy accessibility. 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 20.6.4-2. No large scope adder cost
is required for the Toronto plant. The overall retrofit factor determined
for the L/LS-FGD cases was low (1.24).
The absorbers for LSD-FGD would be located in a similar location as in
the L/LS-FGD cases. LSD with a new baghouse was the only case considered
for the Toronto plant. Since the ESPs are roof-mounted and their sizes are
marginal with difficult to access, a baghouse was considered for placement
close to the absorbers. For flue gas handling for LSD cases, moderate duct
runs would be required to divert the flue gas from the boilers to the
absorbers and back to the ESPs. A low site access/congestion factor was
assigned to the flue gas handling system. The retrofit factors determined
for the LSD technology case were low (1.27) and did not include new
particulate control costs. A separate retrofit factor was developed for the
units. A low retrofit factor (1.13) was developed for a new baghouse. A
low site access/congestion factor was assigned since no major demolition or
relocation would be required. This factor was used in the IAPCS model to
estimate new particulate control costs.
Table 20.6.4-3 presents the costs estimated for L/LS-FGD and LSD-FGD
cases. The LSD-FGD costs include upgrading the ESPs for boilers 9-11.
Since flue gas from units 9-11 are converged into a common chimney, a
combined case for L/LS-FGD was also considered in this study. The Tow cost
control case reduces capital and annual operating costs even further than a
20-131
-------
TABLE 20.6.4-2. SUMMARY OF RETROFIT FACTOR OATA FOR TORONTO UNITS 9-11
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
LOW
LOW
100-300 100-300
NA
NA
LOW
NA
LOW
NA
300-600
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY YES NO
ESTIMATED COST (1000$) 458-663 NA
NEW CHIMNEY NO NO
ESTIMATED COST (1000$) 0 0
OTHER NO NO
NO
NA
NO
0
NO
RETROFIT FACTORS
FGD SYSTEM
ESP REUSE CASE
BAGHOUSE CASE
ESP UPGRADE
NEW BAGHOUSE
1.27
NA
NA
1.24
NA
NA
NA
1.27
NA
1.13
GENERAL FACILITIES (PERCENT) 10
10
10
20-132
-------
Table 20.6.4-3. Sutmary of fgd Control Costs for the Toronto Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coel Capital Capital Annual Annual S02 S02 S02 Cost
timber Retrofit Six* Factor Sulfur Cost Cost Cost Cost Renoved Removed Effect.
Difficulty (MW) (X) Content (MM) (t/kW) (VM) (nrills/kwh) (X) (tons/yr) ($/ton)
Factor (X)
IC FGD
9-11
1.27
181
41
3.4
37.2
205.7
19.4
29.9
90.0
17194
1129.4
LC FGD-C
9-11
1.27
161
41
3.4
37.2
205.7
11.3
17.4
90.0
17194
656.8
IFGD
9
1.27
45
34
3.4
26.2
582.8
11.2
83.9
90.0
3545
3170.7
I FGD
10
1.27
68
41
3.4
32.8
483.0
14.5
59.2
90.0
6460
2239.5
LFGD
11
1.27
68
45
3.4
32.8
483.1
14.7
55.0
90.0
7090
2079.1
I FGD
9-11
1.27
181
41
3.4
54.8
302.5
25.0
38.5
90.0
17194
1454.0
LFGD-C
9
1.27
45
34
3.4
26.2
582.8
6.6
48.9
90.0
3545
1849.8
LFGD-C
10
1.27
68
41
3.4
32.8
483.0
8.4
34.5
90.0
6460
1305.9
LFGO-C
11
1.27
68
45
3.4
32.8
483.1
8.6
32.1
90.0
7090
1212.0
LFGD-C
9-11
1.27
181
41
3.4
54.8
302.5
14.6
22.4
90.0
17194
847.3
LSD+FF
9
1.27
45
34
3.4
16.7
372.1
7.7
57.2
87.0
3407
2250.5
LSD*FF
10
1.27
68
41
3.4
22.3
327.5
9.8
40.2
84.0
6021
1629.3
LS£>*FF
11
1.27
68
45
3.4
22.3
327.5
10.0
37.1
84.0
6608
1506.9
LSD*FF-C
9
1.27
45
34
3.4
16.7
372.1
4.5
33.3
87.0
3407
1311.4
LSO+FF-C
10
1.27
68
41
3.4
22.3
327.5
5.7
23.4
84.0
6021
950.1
LSO+FF-C
11
1.27
68
45
3.4
22.3
327.5
5.8
21.7
84.0
6608
878.5
is«ss8rs:sssitiitsttts::s;:s3sssss:ssss3::siitiissitsits3:
20-133
-------
combined case alone due to the elimination of spare scrubber modules, and
optimization of scrubber module size, and use of organic acid additives.
Coal Switching Costs--
Coal switching can impact boiler performance in several ways. Key
parameters of concern include boiler capacity, furnace slagging, pulverizer
capacity, tube erosion, and coal rate. However, without an ash analysis for
the existing and switch coals, boiler derate or capacity increase cannot be
determined.
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 20.6.4-4.
N0X Control Technology Costs--
This section presents the performance and costs estimated for N0X
controls at the Toronto 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-
Unit 9 is wet and units 10-11 are dry bottom, front wall-fired boilers
rated at 44, 66, and 66 MW, respectively. The combustion modification
technique applied for these boilers was NGR for unit 9 and LNB for
units 10-11. As Table 20.6.4-5 shows, the LNB NO reduction performances
A
for these units could not be estimated using the simplified procedures. No
boiler information could be found for units 10 and 11 to assess their NQX
reduction performances. Based on NOx performance results from similar
boilers of the same age and size, it is estimated that a N0X reduction of
20 to 30 percent can be achieved by these boilers retrofitted with LNB.
20-134
-------
Tabie 20.6.4-4. Sjnmary of Coal Syitching/Cleanins Costs for th« Toronto Plant (June 1988 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual SQ2 S02 S02 Cost
Number Retrofit Siie Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW> Content (SNM) (mills/ICHh) (X) (tons/yr) (J/ton)
Factor (X)
CS/3+S15
9
1.00.
45
34
3.4
2.0
43.8
2.4
17.6
75.0
2971
793.3
CS/B*$15
10
1.00
68
41
3.4
2.8
40.6
3.9
16.2
75.0
5414
729.2
cs/a*si5
11
1.00
68
45
3.4
2.8
40.6
4.3
15.9
75.0
5942
718.3
cs/a*ti5-c
9
1.00
45
34
3.4
2.0
43.8
1.4
10.1
75.0
2971
457.5
CS/B*$15-C
10
1.00
68
41
3.4
2.8
40.6
2.3
9.3
75.0
5414
420.1
CS/B*S15-C
11
1.00
68
45
3.4
2.8
40.6
2.5
9.2
75.0
5942
413.6
CS/B+S5
9
1.00
45
34
3.4
1.5
33.5
1.2
8.7
75.0
2971
393.2
CS/B+J5
10
1.00
68
41
3.4
2.1
30.2
1.8
7.4
75.0
5414
333.8
CS/8+S5
11
1.00
68
45
3.4
2.1
30.2
1.9
7.2
75.0
5942
324.9
CS/8+S5-C
9
1.00
45
34
3.4
1.5
33.5
0.7
5.0
75.0
2971
227.6
CS/B+S5-C
10
1.00
68
41
3.4
2.1
30.2
1.0
4.3
75.0
5414
192.9
CS/B-'IS-C
11
1.00
68
45
3.4
2.1
30.2
1.1
4.2
75.0
5942
187.7
aata:rs:siaii::::s£iiass::s:si:s93::ssniss:s:::tiss:::::siii:a«cs::sattiaaixmiiiissa:iiiiiait>tiiiiiaasiiasa8
20-135
-------
TABLE 20.6.4-5. SUMMARY OF NOx RETROFIT RESULTS FOR TORONTO
BOILER
NUMBER
COMBUSTION MODIFICATION RESULTS
9
10,11
FIRING TYPE
FWF
FWF
TYPE OF NOx CONTROL
. NGR
LNB
VOLUMETRIC HEAT RELEASE RATE
(1000 BTU/CU FT-HR)
NA
NA
BOILER/WATERWALL SURFACE
AREA HEAT RELEASE RATE
(1000 BTU/SQ FT-HR)
NA
NA
FURNACE RESIDENCE TIME (SECONDS)
NA
NA
ESTIMATED NOx REDUCTION (PERCENT)
60
25
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
LOW
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
Ductwork Demolition (1000S)
15
20
New Duct Length (Feet)
150
200
New Duct Costs (1000$)
466
791
New Heat Exchanger (1000$)
1154
1479
TOTAL SCOPE ADDER COSTS (1000$)
1635
2290
RETROFIT FACTOR FOR SCR
1.16
1.16
GENERAL FACILITIES (PERCENT)
13
13
20-136
-------
Units 9 to 11 were installed between 1940 and 1949. Table 20.6.4-6 presents
the cost of retrofitting LNB at the Toronto boilers, assuming an N0X
reduction performance of 25 percent.
Selective Catalytic Reduction-
Table 20.6.4-5 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 ESPs to
the reactor and from the reactor to the chimney.
The SCR reactors for units 9 to 11 would be located side by side in a
relatively open area close to the chimney, north of the powerhouse and west
of the river. Since the reactors were located in open area having easy
access with no major obstacles, the reactors for units 9 to 11 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. Table 20.6.4-6
presents the estimated cost of retrofitting SCR at the Toronto boilers.
Sorbent Injection and Repowering--
This section presents the cost/performance estimates for SOj control
technologies that are under development but have not been demonstrated on
commercial utility boilers. These technologies are presented separately
from the commercialized technologies because the cost/performance estimates
have a high degree of uncertainty due to the lack of commercial scale data.
Duct Spray Drying and Furnace Sorbent Injection--
The sorbent receiving/storage/preparation areas were located north of
the plant in a similar fashion as LSD-FGD. The retrofit of DSD and FSI
technologies at the Toronto steam plant for the units would be very
difficult. This is due to the short duct residence time between the boilers
and the ESPs, as well as the ESP roof-mounted location in a high site access/
congestion area. Therefore, a new baghouse was considered for DSD which
would be located north of the plant, close to the chimney. Duct runs of
300-400 feet would be required to divert flue gas from all three boilers to
20-137
-------
Table 20.6.4-6. NOx Control Cost Results for the Toronto Plant (June 1988 Dollars)
:=as::::ax:
=»=======;
srrssssss:
SS2SSSS
ssssasss:
:ssssssss
===-3====
::s:3zc:s
:=a========"*=====
=»====
II
II
II
II
II
II
II
II
II
II
II
II
II
II
II
H
Technology
Boiler
Hain
Boiler Capacity Coal
Capital Capital Annual
Annual
NOx
NOx
NOx Cost
Nuitoer
Retrofi t
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty (MM)
(X)
Content
<«H)
(S/kW)
(WW)
(Riills/kuh)
(%>
(tons/yr)
(S/ton)
Factor
(X)
INC-LNB
10
1.00
68
41
3.4
2.2
32.2
0.5
1.9
25.0
284
1663.1
INC-INB
11
1.00
68
45
3.4
2.2
32.2
0.5
1.8
25.0
312
1515.2
LNC-INB-C
10
1.00
66
41
3.4
2.2
32^2
0.3
1.1
25.0
284
987.4
LNC-LNB-C
11
1.00
68
45
3.4
2.2
32.2
0.3
1.0 .
25.0
312
899.7
NGR
9
1.00
4S
34
3.4
1.3
28.2
0.9
6.7
60.0
606
1482.7
NGR-C
9
1.00
45
34
3.4
1.3
28.2
0.5
3.9
60.0
606
859.0
SCR-3
9
1.16
45
34
3.4
11.7
260.3
3.7
27.5
80.0
808
4555.4
SCR -3
10
1.16
68
41
3.4
14.8
217.2
4.7
19.3
80.0
909
5185.2
SCR-3
11
1.16
68
45
3.4
14.8
217.2
4.7
17.7
80.0
998
4741.9
SCR-3-C
9
1.16
45
34
3.4
11.7
260.3
2.2
16.1
80.0
808
2675.0
SCR-3-C
10
1.16
68
41
3.4
14.8
217.2
2.8
11.3
80.0
909
3043.6
SCR-3-C
11
1.16
68
45
3.4
14.8
217.2
2.8
10.4
80.0
998
2783.2
SCR-7
9
1.16
45
34
3.4
11.7
260.3
3.3
24.7
80.0
808
4093.8
SCR-7
10
1J6
68
41
3.4
14.8
217.2
4.2
17.0
80.0
909
4565.2
SCR-7
11
1.16
68
45
3.4
14.8
217.2
4.2
15.6
80.0
998
4177.1
SCR-7-C
9
1.16
45
34
3.4
11.7
260.3
1.9
14.5
80.0
808
. 2410.5
SCR-7-C
10
1.16
68
41
3.4
14.8
217.2
2.4
10.0
80.0
909
2688.4
SCR-7-C
11
1.16
68
45
3.4
14.8
217.2
2.5
9.2
80.0
998
2459.5
20-138
-------
the baghouses and then to the chimney. A low retrofit factor (1.13) was
assigned to the new baghouse location because of a low site access/
congestion. Tables 20.6.4-7 through 20.6.4-9 present a summary of the site
access/congestion factors for DSD technology at the Toronto steam plant.
Table 20.6.4-10 presents the costs estimated to retrofit DSD at the Toronto
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 Toronto plant. All three boilers would be considered
good candidates for AFBC retrofit because of their small boiler sizes
(<70 MM) and ages (built before 1950).
20-139
-------
TABLE 20.6.4-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR TORONTO UNIT 9
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 400
ESTIMATED COST (1000$) 1152
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 16
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) NA
A NEW BAGHOUSE CASE (DSD) 1168
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1.13
20-140
-------
TABLE 20.6.4-8. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR TORONTO UNIT 10
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 350
ESTIMATED COST (1000$) 1283
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 22
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) NA
A NEW BAGHOUSE CASE (DSD) 1305
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1.13
20-141
-------
TABLE 20.6.4-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR TORONTO UNIT 11
ITEM
SITE ACCESS/CONGESTION
REAGENT PREPARATION LOW
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) LOW
SCOPE ADDERS
CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO
ESTIMATED COST (1000$) NA
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE 300
ESTIMATED COST (1000$) 1100
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 22
TOTAL COST (1000$)
ESP UPGRADE CASE (FSI) NA
A NEW BAGHOUSE CASE (DSD) 1122
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE (FSI) NA
NEW BAGHOUSE (DSD) 1.13
20-142
-------
Table 20.6.4-10. Sirmary of DSO/FSI Control Costs for the Toronto Plant (June 1988 Dollars)
tniBiasi3SxiiiimiisiaiiBiaaisiiaiiatsiiiiiiiiiiiiiiiiii«iiiiuiiiis:ss:ssss;*isesiiiiissiiisiiu:s:sssiisissz
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nurtoer
Retrofit
Size
Factor Sulfur
Cost
Cost
Cost
Cost
Removed
Removed
Effect.
Difficulty (WW)
(X)
Content
(«H)
(S/kV)
<««>
(mills/kwft)
<%>
(tons/yr)
-------
20.7 OHIO POWER COMPANY
20.7.1 General James M. Gavin Steam Plant
The Gavin steam plant is located within Gallia County, Ohio, as part of
the Ohio Power Company system. The plant is located west of the Ohio River
and contains two coal-fired boilers with a total gross generating capacity
of 2,600 MW.
Table 20.7.1-1 presents operational data for the existing equipment at
the Gavin plant. The boilers burn high sulfur coal. Coal shipments are
received by barge and transferred to a coal storage and handling area west
of the plant and away from the river.
PM emissions for the boilers are controlled with ESPs located behind
each unit. Fly ash is wet sluiced and disposed of in an ash pond south of
the plant adjacent to the river. Both units are served by a common chimney
centered behind the two units toward the river.
Lime/Limestone and Lime Spray Drying FGD Costs--
The Gavin plant is located immediately north of the Kyger Creek plant.
Both boilers are located beside each other parallel to the river. Two
recirculating forced draft cooling towers are located on either side of the
units. The absorbers for both units would be located behind the chimneys to
the east of the units toward the river. The limestone preparation, storage,
and handling area would be located south of the coal pile and close to the
railroad tracks. It is assumed that the railroad tracks can be upgraded for
sorbent delivery. A warehouse building behind the chimney has to be
relocated to make space available for the FG0 absorbers. Therefore, a
factor of 8 percent was assigned to general facilities.
A low site access/congestion factor was assigned to the FGD absorber
locations due to the space availability after relocating the storage
building. Because absorbers are placed immediately behind the chimneys,
short duct runs would be required for L/tS-FGD cases (about 200 feet). The
common chimney is very easy to access and, as such, a low site access/
congestion factor was assigned to the flue gas handling system.
20-144
-------
TABLE 20.7.1-1. GAVIN 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
1300
60,58
1974,75
OPPOSED WALL
990
NO
3.4
11200
12
WET SLUICE
ON-SITE
1
BARGE/RAILROAD
ESP
1974-75
0.03
99.8
1.0
240.4
4400
546
300
20-145
-------
LSD with reuse of the existing ESPs was considered for this plant
because the ESPs are large (SCA-546) and would not require major upgrading
or plate area additions to handle the increased particulate load generated
from the LSD application. The LSD absorbers would be located behind the ESPs
with low site access/congestion factors. However, access to the existing
ESPs would be difficult because of the limited space between the ESPs and
the boilerhouse. Therefore, a high site access/congestion factor was
assigned to the flue gas handling system. Over 600 feet of duct length
would be required to divert the flue gas from upstream of the ESPs to the
absorbers and back to the ESPs. Because space is available behind the ESPs,
a low site access/congestion factor was assigned to the ESP upgrades.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Table 20.7.1-2. Table 20.7.1-3 presents the
process area retrofit factors and capital/operating costs for commercial FGD
technologies. The low cost FGD option reduces costs due to eliminating
spare absorber modules and maximizing absorber module size.
Coal Switching and Physical Coal Cleaning Costs-
Table 20.7.1-4 presents the IAPCS cost results for CS at the Gavin
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 Gavin is not a mine mouth plant.
Low NO Combustion--
A
Units 1 and 2 are opposed wall-fired dry bottom boilers rated at
1,300 MW each. The combustion modification technique applied to both
boilers was LNB. Tables 20.7.1-5 and 20.7.1-6 present the performance and
cost results of retrofitting LNB at the Gavin plant. A high N0X reduction
performance was estimated based on the low volumetric heat release rate.
Selective Catalytic Reduction-
Cold side SCR reactors for both units would be located immediately
behind the chimney in a similar layout as FGD absorbers. Both reactors are
located in low site/congestion areas for the same reasons as were outlined
in the FGD section. Access to the common chimney is easy and about 250 feet
20-146
-------
TABLE 20.7.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR GAVIN
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 100-300 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA LOW
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 9346 NA 9346
NEW CHIMNEY NO NA NO
ESTIMATED COST (1000$) 0 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.27 NA
ESP REUSE CASE 1.54
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.16
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 8 0 8
20-147
-------
Table 20.7.1-3. Surmary of FGO Control Costs for the James N. Gavin Plant (June 1988 Dollars)
:ss=s;:sss3scs:aiiiissiBiiisiiiiiiiiisiisiB3ianiissiiiBis::s«isiss3iiiis:5saaii=:asssii5
isaiassaiixasaiisssssii
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Ninfcer Retrofit Size Factor Sulfur Cost Cost Cost cost Removed Removed Effect.
Difficulty (MW> (X) Content (tons/yr) ($/con>
Factor
-------
Table 20.7.1-4. Sinmary of Coat Switching/Cleaning Coses for the Janes M. Gavin Plant (June 1988 Dollars)
Technology
Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (HW) (X) Content (SUM) CSMM) Cmills/kwh) (X) (tons/yr) ($/ton>
factor (X)
CS/B+S15
CS/B+S15
1.00
1.00
1300
1300
60
58
3.4
3.4
37.4
37.4
28.8
28.8
94.6
91.7
13.8
13.9
76.0
76.0
153525
148407
616.3
618.1
CS/B+S15-C
CS/B+S15-C
1.00
1.00
1300
1300
60
58
3.4
3.4
37.4
37.4
28.8
28.8
54.4
52.7
8.0
8.0
76.0
76.0
153525
148407
354.2
355.3
CS/B+S5
CS/B*t5
1.00
1.00
1300
1300
60
58
3.4
3.4
23.9
23.9
18.4
18.4
35.8
34.8
5.2
5.3
76.0
76.0
153525
148407
233.4
234.6
CS/B+15-C
CS/B*iS-C
1.00
1.00
1300
1300
60
58
3.4
3.4
23.9
23.9
18.4
18.4
20.6
20.1
3.0
3.0
76.0
76.0
153525
14S407
134.4
135.1
:zii3ia
20-149
-------
TABLE 20.7.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR GAVIN
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
FIRING TYPE OWF
TYPE OF NOx CONTROL LNB
FURNACE VOLUME (1000 CU FT) 990
BOILER INSTALLATION DATE 1974, 1975
SLAGGING PROBLEM NO
ESTIMATED NOx REDUCTION (PERCENT) 52
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) 250
New Duct Costs (1000$) 5554
New Heat Exchanger (1000$) 8685
TOTAL SCOPE ADDER COSTS (1000$) 14425
RETROFIT FACTOR FOR SCR 1.16
GENERAL FACILITIES (PERCENT) 13
20-150
-------
Table 20.7.1-6. NOx Control Cost Results for the James N. Gavin Plant (June 19S3 Dollars)
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual
Nuitoer Retrofit Size Factor Sulfur Cost Cost Cost
Difficulty (S) Content (»MM> (S/kU) (SWO
Factor (*)
Annual NOx NOx NOx Cost
Cost Removed Removed Effect,
(mills/kwh) (X) (tons/yr) (t/ton)
INC-LNB
INC-LNB
1.00
1.00
1300
1300
60
58
3.4
3.4
7.1
7.1
5.5
5.5
1.5
1.5
0.2
0.2
52.0
52.0
16706
16149
92.1
95.2
LNC-IMB-C
IHC-INB-C
1.00
1.00
1300
1300
60
58
3.4
3.4
7.1
7.1
5.5
5.5
0.9
0.9
0.1
0.1
52.0
52.0
16706
16149
54.7
56.5
SCR-3
SCR-3
SCR-3-C
SCR-3-C
SCR-7
SCR-7
SCR-7-C
SCR-7-C
1.16
1.16
1.16
1.16
1.16
1.16
1.16
1.16
1300
1300
1300
1300
1300
1300
1300
1300
60
58
60
58
60
58
60
58
3.4
3.4
3.4
3.4
3.4
3.4
3.4
3.4
144.3
144.3
144.3
144.3
144.3
144.3
144.3
144.3
11.0
11.0
11.0
11.0
11.0
11.0
11.0
11.0
56.2
56.1
32.9
32.8
45.4
45.3
26.7
26.6
8.2
8.5
4.8
5.0
6.7
6.9
3.9
4.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
80.0
25702
24845
25702
24845
25702
24845
25702
24845
2187.8
2256.2
1278.6
1318.7
1768.0
1821.8
1038.1
1069.8
:ssst33isiass:a:5sa3sssss3ss:ssa::::ss:::s:::s:s3sss::s:ss2
sssscasss
sssssss
20-151
-------
of duct length would be required to divert the flue gas from the downstream
of the ESPs to the reactors and back to the chimney. The ammonia storage
system would be placed immediately south of the reactors. No major
demolition/relocation would be needed for the placement of the SCR reactors.
Therefore, a base factor of 13 percent was assigned to general facilities.
Table 20.7.1-5 presents the SCR retrofit results for both units.
Table 20.7.1-6 presents the estimated cost of retrofitting SCR at the Gavin
boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The retrofit of conventional FSI and DSD technologies at the Gavin
steam plant for both units would be difficult due to the short duct
residence time between the boilers and ESPs. The duct residence time would
not be sufficient for humidification (FSI application) or sorbent
evaporation (DSD application). However, FSI and DSD technologies were
considered for this plant assuming the first ESPs section could be modified
for humidification or sorbent injection and additional plate area would not
be needed downstream of the remaining ESPs section due to their large size.
A low site access/congestion factor was assigned for modifying the ESPs
because of the space availability behind the ESPs. The sorbent receiving/
storage/preparation areas were located beside the coal pile in a similar
fashion as L/LS-FGD.
Table 20.7.1-7 presents a summary of the site access/congestion factors
for FSI and DSD technologies at the Gavin steam plant. Table 20.7.1-8
presents the costs estimated to retrofit FSI and DSD at the Gavin steam
pi ant.
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 Gavin plant. Neither of these units would be considered
good candidates for repowering/retrofit because of their large size, high
capacity factor, and short service life.
20-152
-------
TABLE 20.7.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR GAVIN 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$) 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
20-153
-------
Table 20.7.1-8. Suimary of DSD/FSI Control Costs for the Janes H. Gavin Plant (June 1988 Dollars)
:::::ss3;ssai:ss::;;cass:3ssss9:s3xis:::iBs:tsc:s:ssiiBssSBses3Sfsasisssai3SBBS>BStstiissassisssissss:ss:sss::ss
Technology Boiler Kain Bailer Capacity Coal Capital Capital Annual Annual 502 SQ2 S02 Cost
Nurfeer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (X) (tons/yr) <»/ton)
Factor (X)
DSO+ESP
DSD+ESP
1.00
1.00
1300
1300
60
58
3.4
3.4
72.9
72.9
56.1
56.1
50.6
49.7
7.4
7.5
42.0
42.0
85606
82753
591,4
600.2
DSD+ESP-C
DS0*ESP-C
1.00
1.00
1300
1300
60
58
3.4
3.4
72.9
72.9
56.1
56.1
29.3
28.8
4.3
4.4
42.0
42.0
85606
82753
342.7
347.8
FSI+ESP-50
FSi*ESP-50
1.00
1.00
1300
1300
60
58
3.4
3.4
57.1
57.1
43.9
43.9
75.6
73.5
11.1
11.1
50.0
50.0
101431
98050
745.2
750.0
FSI*ESP-50-C
FSI*ESP-50-C
1.00
1.00
1300
1300
60
58
3.4
3.4
57.1
57.1
43.9
43.9
43.6
42.4
6.4
6.4
50.0
50.0
101431
98050
429.5
432.3
FSI*ESP-70
F$I»ESP-70
1.00
1,00
1300
1300
60
58
3.4
3.4
57.8
57.8
44.5
44.5
77.2
75.1
11.3
11.4
70.0
70.0
142003
137270
544.0
547.4
FSI+ESP-70-C
FSl*ISP-70-C
1.00
1.00
1300
1300
60
58
3.4
3.4
57.8
57.8
44.5
44.5
44.5
43.3
6.5
6.6
70.0
70.0
142003
137270
313.5
315.5
20-154
-------
20.7.2 Muskingum River Steam Plant
Information on Muskingum River steam plant appears in U.S. EPA report
number EPA-600/7-88/014, entitled "Ohio/Kentucky/TVA Coal-Fired Utility SO^
and N0X Retrofit Study" (NTIS PB88-244447/AS).
20-155
-------
20.8 OHIO VALLEY ELECTRIC CORPORATION
20.8.1 Kyger Creek Steam Plant
The Kyger Creek steam plant is located within Gallia County, Ohio, as
part of the Ohio Valley Electric Corporation system. The plant is located
west of the Ohio River and directly south of the Gavin plant. It contains
five coal-fired boilers with a total design gross generating capacity of
1,085 MW.
Table 20.8.1-1 presents operational data for the existing equipment at
the Kyger Creek plant. The boilers burn high sulfur coal. Coal shipments
are received only 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 retrofit ESPs located
behind and away from each unit. A three-story service building is located
between the ESPs and the units. This building contains offices, lab,
machinery, and a cafeteria. In addition, underground tanks and equipment
are located in the vicinity of the building. The plant has a wet fly ash
handling system. Fly ash is disposed of in a large ash pond west of the
plant. Units 1 through 5 are served by a common retrofit chimney.
Lime/Limestone and L1me Spray Drying FGD Costs--
The absorbers for units 1-5 would be located west of the plant between
unit 5 and the ash pond on the existing employee parking area. The
limestone preparation, storage, and handling area would be located south of
the ash pond site. Some of the plant roads and two employee parking areas
have to be relocated to open up space for the FGD absorbers. Therefore, a
factor of 15 percent was assigned to general facilities.
A high site access/congestion factor was assigned to the FGD absorber
locations due to the space limitation between the unit 5 ESPs and a major
road beside the ash pond site. Absorbers for unit 5 would be located close to
the unit 5 ESPs and short duct runs of about 300 feet would be required. For
units 1-4, duct lengths of 400 to 800 feet would be required to divert the
flue gas from the chimney to the absorbers and back to the chimney. It is
relatively easy to Table 20.8.1-1 access unit 5 flue gas downstream of the
20-156
-------
TABLE 20.8.1-1. KYGER CREEK STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
PARTICULATE CONTROL
TYPE
INSTALLATION DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
1, 2, 3, 4, 5
217
89, 89, 86, 80, 89
1955
FRONT WALL
NA
NO
3.72
12008
10.1
WET SLUICE
ON-SITE
1
BARGE
ESP
1980
0.01-0.02
99.8-99.9
3.0-5.0
310.4
925
335
350
20-157
-------
ESPs and, as such, a low site access/congestion factor was assigned to the
unit 5 flue gas handling system. On the other hand, a medium site access/
congestion factor was assigned to the unit 1-4 flue gas handling systems
because the flue gas duct runs for units 1-4 have to go around the
unit 5 ESPs. Plant personnel indicated that the existing chimney cannot be
reused for the FGD system because the design velocity of the existing stack
is too great for a saturated plume.
LSD with reuse of the existing ESPs was considered for this plant
because ESPs are adequate in size (SCA =335) and have good particulate
removal efficiencies. The retrofit ESPs would probably not require major
upgrading or plate area additions to handle the increased PMs generated from
the LSD application. The LSD absorbers would be located in the same location
as the L/LS-FGD absorbers. Once again, a high site access/congestion factor
was assigned to the absorber locations. Duct lengths between 450 to over
1,000 feet would be required to divert the flue gas from upstream of the
ESPs to the absorbers and back to the retrofit ESPs. Because of the space
constraints in front of the retrofit ESPs created by the service building and
truncated old chimneys and underground obstructions created by the
underground tanks and equipment, high site access/congestion factors were
assigned to the flue gas handling systems for units 1-5.
The major scope adjustment costs and retrofit factors estimated for the
FGD technologies are presented in Tables 20.8.1-2 through 20.8.1-5. Table
20.8.1-6 presents the process area retrofit factors and capital/operating
costs for commercial FGD technologies. Plant personnel indicated that
retrofitting each individual boiler with a separate FGD system is the only
viable option; further consolidation of the control equipment for the units
might penalize future plant generating availability. In addition, O & M
calculations do not include the unavailability of the units due to FGD
systems maintenance (estimated by the plant to be 3% of total power
generated).
Coal Switching and Physical Coal Cleaning Costs-
All units are wet bottom boilers. Coal switching was not considered for
the Kyger Creek plant because low sulfur bituminous coal having low ash
20-158
-------
TABLE 20.8.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR KYGER CREEK
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 HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 600-1000 NA
ESP REUSE 1000 +
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 1878 NA 1878
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1519 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.74 NA
ESP REUSE CASE 2.03
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
20-159
-------
TABLE 20.8.1-3. SUMMARY OF RETROFIT FACTOR DATA FOR KYGER CREEK
UNIT 3 . .
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
MEDIUM
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
600-1000
NA
ESP REUSE
600-1000
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
1878
NA
1878
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
1519
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.74
NA
ESP REUSE CASE
1.83
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
20-160
-------
TABLE 20.8.1-4. SUMMARY OF RETROFIT FACTOR DATA FOR KYGER CREEK
UNIT 4
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL HIGH NA HIGH
FLUE GAS HANDLING MEDIUM NA
ESP REUSE CASE HIGH
BAGHOUSE CASE NA
DUCT WORK DISTANCE (FEET) 300-600 NA
ESP REUSE 600-1000
BAGHOUSE NA
ESP REUSE NA NA HIGH
NEW BAGHOUSE NA NA NA
SCOPE ADJUSTMENTS
WET TO DRY YES NA YES
ESTIMATED COST (1000$) 1878 NA 1878
NEW CHIMNEY YES NA NO
ESTIMATED COST (1000$) 1519 0 0
OTHER NO NO
RETROFIT FACTORS
FGD SYSTEM 1.66 NA
ESP REUSE CASE 1.83
BAGHOUSE CASE NA
ESP UPGRADE NA NA 1.58
NEW BAGHOUSE NA NA NA
GENERAL FACILITIES (PERCENT) 15 0 15
20-161
-------
TABLE-20.8.1-5. SUMMARY OF RETROFIT FACTOR DATA FOR KYGER CREEK
UNIT 5
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
HIGH
NA
HIGH
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
HIGH
BAGHOUSE CASE
NA
DUCT WORK DISTANCE (FEET)
300-600
NA
ESP REUSE
300-600
BAGHOUSE
NA
ESP REUSE
NA
NA
HIGH
NEW BAGHOUSE
NA
NA
NA
SCOPE ADJUSTMENTS
WET TO DRY
YES
NA
YES
ESTIMATED COST (1000$)
1878
NA
1878
NEW CHIMNEY
YES
NA
NO
ESTIMATED COST (1000$)
1519
0
0
OTHER
NO
NO
RETROFIT FACTORS
FGD SYSTEM
1.61
NA
ESP REUSE CASE
1.69
BAGHOUSE CASE
NA
ESP UPGRADE
NA
NA
- 1.58
NEW BAGHOUSE
NA
NA
NA
GENERAL FACILITIES (PERCENT)
15
0
15
20-162
-------
Table 20.8.1-6. Sunnary of FGD Control Costa for th* Xyger Cre«k Plant (Jixte 1988 Oollers)
:::s:zzx»xz::::siii8t33i3a:a::3i«s:ze3a33s:s=isiiaisi3=aisas8B8asssBBas323tss8£sacssB33aassssass::ts=azssiz3:::
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nuitoar Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MW) (X) Content (SUN) (SAW) (SIM) (miIIs/kwtO (X) (tons/yr) (S/ton)
Factor (X)
LC FGD
1
-5
1.70
108S
87
3.7
211.0
194.5
142.1
17.2
90.0
221969
640.1
LC FGO-C
1-
¦5
1.70
1085
87
3.7
211.0
194.5
82.4
10.0
90.0
221969
371.0
LFCO
1-
•5
1.70
1085
87
3.7
254.9
234.9
156.2
18.9
90.0
221969
703.5
LFGD
1
1.74
217
89
3.7
82.4
379.6
44.0
26.0
90.0
45414
968.3
IFGO
2
1.74
217
89
3.7
82.4
379.6
44.0
26.0
90.0
45414
968.3
LFGD
3
1.74
217
86
3.7
82.4
379.6
43.4
26.6
90.0
43884
989.4
LFGD
4
1.66
217
80
3.7
79.0
363.8
41.2
27.1
90.0
40822
1009.2
IFGO
5
1.61
217
89
3.7
76.8
354.1
42.2
24.9
90.0
45414
928.3
LFGO-C
1-
•5
1.70
1085
87
3.7
254.9
234.9
90.6
11.0
90.0
221969
408.2
IFGD-C
1
1.74
217
89
3.7
82.4
379.6
25.6
15.1
90.0
45414
562.9
LFGO-C
2
1.74
217
89
3.7
82.4
379.6
25.6
15.1
90.0
45414
562.9
LFGO-C
3
1.74
217
86
3.7
82.4
379.6
25.2
15.4
90.0
43884
575.3
LFGO-C
4
1.66
217
80
3.7
79.0
363.8
24.0
15.8
90.0
40822
586.9
LFGO-C
5
1.61
217
89
3.7
76.8
354.1
24.5
14.5
90.0
45414
539.5
LSHESP
1
2.03
217
89
3.7
53.6
246.8
26.6
15.7
76.0
38502
690.9
LSO+ESP
2
2.03
217
89
3.7
53.6
246.8
26.6
15.7
76.0
38502
690.9
LSO+ESP
3
1.63
217
86
3.7
48.9
225.4
24.9
15.3
76.0
37204
670.6
LSO+ESP
4
1.B3
217
80
3.7
48.9
225.4
24.3
16.0
76.0
34608
703.1
LSD»ESP
5
1.69
217
89
3.7
45.7
210.5
24.3
14.4
76.0
38502
631.6
LSD+ESP-C
1
2.03
217
89
3.7
53.6
246.8
15.5
9.1
76.0
38502
402.1
LSO+ISP-C
2
2.03
217
89
3.7
53.6
246.8
15.5
9.1
76.0
38502
402.1
LSO*ESP-C
3
1.83
217
86
3.7
48.9
225.4
14.5
8.9
76.0
37204
390.1
LSD*ESP-C
4
1.83
217
80
3.7
48.9
225.4
14.2
9.3
76.0
34608
409.2
LSD*£SP-C
5
1.69
217
89
3.7
45.7
210.5
14.1
8.4
76.0
38502
367.2
::::xia3s:::::3iyaBa:8aisaaaasa33aaiaa:33s:
20-163
-------
fusion temperatures are not readily available in the east. PCC was not
evaluated because this is not a mine mouth plant.
Low N0X Combustion-
Units 1-5 are front wall, wet bottom boilers rated at 217 MW each. The
combustion modification technique applied to all boilers was NGR.
Table 20.8.1-7 shows the NGR N0X reduction performance and Table 20.8.1-8
presents the cost of retrofitting NGR at the Kyger Creek plant.
Selective Catalytic Reduction-
Cold side SCR reactors for all units would be located immediately
behind the retrofit ESPs and adjacent to the coal pile. Reactors for
units 1-3 are located in a very congested area bounded by the ESPs, chimney,
and the coal pile. As such, a high retrofit factor was assigned to the SCR
reactor locations for units 1-3. For units 4-5, limited space is available
behind the ESPs close to the common chimney and the coal pile and, as such,
a medium site access/congestion factor was assigned to this location.
Because reactors were located close to the common chimney, short duct runs
of 200-300 feet would be required for all units. No major demolition/
relocation would be required for the SCR reactor locations and, as such, a
base factor of 13 percent was assigned to general facilities. All reactors
were assumed to be in areas with high underground obstructions. The ammonia
storage system was placed close to the reactors west of the plant and close
to the ash pond.
Table 20.8.1-7 presents the SCR retrofit results for all units.
Table 20.8.1-8 presents the estimated cost of retrofitting SCR at the Kyger
Creek boilers.
Duct Spray Drying and Furnace Sorbent Injection--
The Kyger Creek plant boilers are ideal for furnace sorbent injection
(FSI) or duct spray drying (DSD) technologies for two major reasons:
1) ESPs have adequate SCAs (=335) and probably would be able to handle the
increased PM not requiring major ESP upgrading or plate area additions, and
2) long straight duct residence time (>2 seconds) between the boilers and
ESPs would be sufficient for humidification (FSI application) or sorbent
20-164
-------
TABLE 20.8.1-7. SUMMARY OF NOx RETROFIT RESULTS FOR KYGER CREEK
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1, 2
3
4, 5
FIRING TYPE
FWF
FWF
FWF
TYPE OF NOx CONTROL
NGR
NGR
NGR
FURNACE VOLUME (1000 CU FT)
NA
NA
NA
BOILER INSTALLATION DATE
1959
1959
1959
SLAGGING PROBLEM
NO
NO
NO
ESTIMATED NOx REDUCTION (PERCENT)
60
60
60
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
HIGH
HIGH
MEDIUM
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
0
0
0
Ductwork Demolition (1000$)
81
48
81
New Duct Length (Feet)
300
300
200
New Duct Costs (1000$)
3508
2339
2339
New Heat Exchanger (1000$)
4497
2967
4497
TOTAL SCOPE ADDER COSTS (1000$)
COMBINED
INDIVIDUAL
8086
5354
NA
5354
6917
4574
RETROFIT FACTOR FOR SCR
1.52
1.52
1.34
GENERAL FACILITIES (PERCENT)
13
13
13
20-165
-------
Table 20.8.1-8. NOx Control Cost Results for the Kyjer Creek Plant (June 1988 Dollars}
iiiiiiiaiaiiiis3i33:s3i;:s:si>a3s:iati«3>iiis:sts8s:3tMitiaiiiigiiiiHiasMsiaiifBiiaiMsaaiitissiiausas::M:s
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 (NW) (X) content (SMN) (S/MO <»*> (miUs/knh> <*) (tons/yr)
-------
sorbent receiving/storage/preparation areas were located west of the plant in
a similar fashion as L/LS-FGD.
Table 20.8.1-9 presents a summary of the site access/congestion factors
for sorbent injection technologies at the Kyger Creek steam plant. Table
20.8.1-10 presents the costs estimated to retrofit FSI and DSD at the Kyger
Creek.
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 Kyger Creek plant. All units would be considered good
candidates for repowering or retrofit because of their small boiler sizes.
20-167
-------
I
TABLE 20.8.1-9. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR KYGER CREEK UNIT 1, 2, 3, 4 OR 5
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$) 1878
ADDITIONAL DUCT WORK (FT)
NEW BAGHOUSE CASE NA
ESTIMATED COST (1000$) NA
ESP REUSE CASE NA
ESTIMATED COST (1000$) NA
DUCT DEMOLITION LENGTH (FT) 50
DEMOLITION COST (1000$) 53
TOTAL COST (1000$)
ESP UPGRADE CASE 1931
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25
ESP UPGRADE 1.58
NEW BAGHOUSE NA
20-168
-------
Table 20.8.1-10. Stnnry of DSO/FSl Control Cost* for the Kyger Creek Plant (June 1988 Dollars)
:s::s:a:i3;s3i
tciaasa:
sssimssa
ISSSSSSI
ittssia::
:33SMiBaiaMiui
EIIIIHI
IMIIU1ISII
linn
iiisBviiisiaaiisitst
Technology
Boiler
Main
Boiler Capacity Coal
Capital Capital Annual
Annual
S02
S02
S02 Cost
Nintoer
Retrofit
Size
Factor
Sulfur
Cost
Cost
Cost
Cost
Removed Removed
Effect.
Difficulty
' (NW>
(X)
Content
(«">
<*/WO
(mills/kwh)
(X)
(tor*/yr>
(S/ton)
Factor
(X)
OSO+ESP
1
1.00
217
89
3.7
16.9
77.9
15.4
9.1
49.0
24549
625.8
DSD+ESP
2
1.00
217
89
3.7
16.9
77.9
15.4
9.1
49.0
24549
625.8
DSO+ESP
3
1.00
217
86
3.7
16.9
77.9
15.1
9.2
49.0
23722
635.4
OSO+ESP
4
1.00
217
80
3.7
16.9
77.9
14.5
9.5
49.0
22067
656.7
OSO+ESP
5
1.00
217
89
3.7
16.9
77.9
15.4
'•1
49.0
24549
625.8
DSD+ESP-C
1
1.00
217
89
3.7
16.9
77.9
8.9
5.2
49.0
24549
361.6
DSD+ESP-C
2
1.00
217
89
3.7
16.9
77.9
8.9
5.2
49.0
24549
361.6
DSD+ESP-C
3
1.00
217
86
3.7
16.9
77.9
8.7
5.3
49.0
23722
367.2
DSO+ESP-C
4
1.00
217
80
3.7
16.9
77.9
8.4
5.5
49.0
22067
37V.7
OSD+ESP-C
5
1.00
217
89
3.7
16.9
77.9
8.9
5.2
49.0
24549
361.6
FS1+ESP-50
1
1.00
217
89
3.7
IS.8
72.6
20.3
12.0
50.0
25231
802.7
FSI+ESP-50
2
1.00
217
89
3.7
15.8
72.6
20.3
12.0
50.0
25231
802.7
fsi+esp-50
3
1.00
217
86
3.7
15.8
72.6
19.7
12.1
50.0
24380
809.4
FSI+ESP-50
4
1.00
217
80
3.7
15.8
72.6
18.7
12.3
50.0
22679
824.4
FSJ+ESP-50
5
1.00
217
89
3.7
15.8
72.6
20.3
12.0
50.0
25231
802.7
FSI+ESP-50-C
1
1.00
217
89
3.7
15.8
72.6
11.7
6.9
50.0
25231
462.7
FSI+ESP-50-C
2
1.00
217
89
3.7
15.8
72.6
11.7
6.9
50.0
25231
462.7
FSI+ESP-50-C
3
1.00
217
36
3.7
15.8
72.6
11.4
' 7.0
50.0
24380
466.6
FSI+ESP-50-C
4
1.00
217
80
3.7
15.8
72.6
10.8
7.1
50.0
22679
475.4
FSI+ESP-50-C
5
1.00
217
89
3.7
15.8
72.6
11.7
6.9
50.0
25231
462.7
FSI+ESP-70
1
1.00
217
99
3.7
16.0
73.8
20.7
12.2
70.0
35323
586.0
FSI+ESP-70
2
1.00
217
89
3.7
16.0
73.8
20.7
12.2
70.0
35323
586.0
FSI+ESP-70
3
1.00
217
86
3.7
16.0
73.8
20.2
12.3
70.0
34132
590.8
FSI+ESP-70
4
1.00
217
80
3.7
16.0
73.8
19.1
12.6
70.0
31751
601.7
FSI+ESP-70
5
1.00
217
89
3.7
16.0
73.8
20.7
12.2
70.0
35323
586.0
FSI+ESP-70-C
1
1.00
217
89
3.7
16.0
73.8
11.9
7.1
70.0
35323
337.8
FSi+ESP-TO-C
2
1.00
217
89
3.7
16.0
73.8
11.9
7.1
70.0
35323
337.8
FS1+ESP-70-C
3
1.00
217
86
3.7
16.0
73.8
11.6
7.1
70.0
34132
340.6
FS1+ESP-70-C
4
1.00
217
80
3.7
16.0
73.8
11.0
7.2
70.0
31751
347.0
FSI+ESP-70-C
5
1.00
217
, 89
3.7
16.0
73.8
11.9
7.1
70.0
35323
337.8
SS33SIS8SII33:
ssscxsa
3=3333333;
xaams
II
M
8
N
II
II
U
233333 = 3!
!£»>»•£
iHasm
*******
II
M
¦
II
m
8
U
II
<1
¦333=3
38333333S3 as
issssaaaa
20-169
-------
20.9 TOLEDO EDISON COMPANY
20.9.1 Bay Shore Steam Plant
The Bay Shore steam plant is located on the Maumee Bay in Lucas County,
Ohio, and is operated by the Toledo Edison Company. The Bay Shore plant
contains four coal-fired boilers with a gross generating capacity of 658 MW.
Table 20.9.1-1 presents operational data for the existing equipment at
the Bay Shore plant. Coal shipments, are received by railroad and transferred
to a coal storage and handling are south of the plant. PM emissions from
units 1 and 2 are controlled by retrofit ESPs and emissions from units 3 and
4 are controlled by ESPs installed at the time of construction. All of the
ESPs are located behind their respective boiler. Flue gases from all units
are directed into a common chimney east of unit 4. Dry fly ash from the
units is disposed of in landfills north of the plant or sold.
Lime/Limestone and Lime Spray Drying F6D Costs--
L/LS-FGD absorbers for units 1-4 would be located beside the common
chimney. The site access/congestion factor for this location would be
medium. Plant personnel indicated that the preparation and waste handling
areas would have to be located away from the plant. Barge unloading
facilities would possibly be required for unloading sorbent. Some auxiliary
equipment and storage building would need to be relocated; hence, 10 percent
was assigned to the general facilities factor. Approximately 200 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.
LSD with reuse of the existing ESPs was not considered for the Bay Shore
plant. Even though the unit 1 and 2 ESPs could handle the additional load of
the LSD system, access to the ESPs would be difficult because of the
congestion created by the existing ESPs, old chimneys, and the water intake
structure. LSD with a new baghouse was considered for units 1-4 combined.
The LSD absorbers and new baghouse would have a similar location as the wet
FGD absorbers; thus, similar site access/congestion and general facilities
factors were assigned. A duct length of 200 feet would be required. The
site access/congestion factor for flue gas handling is low.
20-170
-------
TABLE 20.9.1-1. BAY SHORE STEAM PLANT OPERATIONAL DATA
BOILER NUMBER
GENERATING CAPACITY (MW-each)
CAPACITY FACTOR (PERCENT)
INSTALLATION DATE
FIRING TYPE
FURNACE VOLUME (1000 CU FT)
LOW NOx COMBUSTION
COAL SULFUR CONTENT (PERCENT)
COAL HEATING VALUE (BTU/LB)
COAL ASH CONTENT (PERCENT)
FLY ASH SYSTEM
ASH DISPOSAL METHOD
STACK NUMBER
COAL DELIVERY METHODS
1,2 3 4
141,143 150 224
84,47 83 65
1955,59 1963 1968
TOP FIRED FRONT WALL
98.4 54 103.54
NO NO NO
1.2 1.2 1.2
13200 13200 13200
7.0 7.0 7.0
DRY DISPOSAL
LANDFILL/SOLD
1 1 1
RAILROAD
PARTICULATE CONTROL
TYPE
INSTALLATION- DATE
EMISSION (LB/MM BTU)
REMOVAL EFFICIENCY
DESIGN SPECIFICATION
SULFUR SPECIFICATION (PERCENT)
SURFACE AREA (1000 SQ FT)
GAS EXIT RATE (1000 ACFM)
SCA (SQ FT/1000 ACFM)
OUTLET TEMPERATURE (*F)
ESP
ESP
ESP
1980
1963
1968
0.02
0.08
0.05
99.8
99.5
99.5
0.3-0.8
NA
NA
247.3
76
112.3
463
398
620
534
191
181
320
259
259
20-171
-------
Tables 20.9.1-2 and 20.9.1-3 present the retrofit factors and cost
estimates for installation of FGD control technologies at the Bay Shore
pi ant.
Coal Switching and Physical Coal Cleaning Costs-
Table 20.9.1-4 presents the IAPCS cost results for CS at the Bay Shore
plant. These costs do not include boiler and pulverizer operating cost
changes or any system modifications that may be necessary for coal blending.
PCC was not considered at the Bay Shore plant because it is not a mine mouth
plant.
N0X Control Technologies--
LNBs were considered for the two front wall-fired, dry bottom boilers at
the Bay Shore plant. Performance results and costs developed for the four
units are presented in Tables 20.9.1-5 and 20.9.1-6.
Selective Catalytic Reduction--
Cold side SCR reactors for units 1-4 combined would be located beside
the common chimney. A medium general facilities factor {20 percent) and a
low site access/congestion factor were assigned to the reactor location.
Approximately 200 feet of ductwork would be required. Tables 20.9.1-5 and
20.9.1-6 present the retrofit factors and cost estimates for installation of
SCR at the Bay Shore plant.
Furnace Sorbent Injection and Duct Spray Drying FGD Costs--
Sorbent injection technologies (FSI and DSD) were considered for
units 1 and 2 at the Bay Shore plant because of the sufficient duct
residence time between the old and retrofit ESPs, allowing for
humidification or slurry droplet evaporation. Units 1 and 2 also have
adequate ESPs to handle the increased load. For units 3 and 4, the duct
residence time between the boilers and the ESPs is not sufficient and the
ESPs are small; therefore, FSI and DSD were not considered for these units.
Tables 20.9.1-7 and 20.9.1-8 present retrofit factors and cost estimates for
installation of FSI and DSD at the Bay Shore plant.
20-172
-------
TABLE 20.9.1-2. SUMMARY OF RETROFIT FACTOR DATA FOR BAY SHORE
UNITS 1-4 (COMBINED)
FGD TECHNOLOGY
FORCED LIME
L/LS FGD OXIDATION SPRAY DRYING
SITE ACCESS/CONGESTION
S02 REMOVAL
MEDIUM
NA
MEDIUM
FLUE GAS HANDLING
LOW
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
LOW
DUCT WORK DISTANCE (FEET)
100-300
NA
ESP REUSE
BAGHOUSE
100-300
ESP REUSE
NA
NA
NA
NEW BAGHOUSE
NA
NA
LOW
SCOPE ADJUSTMENTS
WET TO DRY
NO
NA
NO
ESTIMATED COST (1000$)
NA
NA
NA
NEW CHIMNEY
NO
NA
NO
ESTIMATED COST (1000$)
0
0
0
OTHER
YES
YES
RETROFIT FACTORS
FGD SYSTEM
1.50
NA
ESP REUSE CASE
NA
BAGHOUSE CASE
1.48
ESP UPGRADE
NA
NA
NA
NEW BAGHOUSE
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
10
0
10
20-173
-------
Table 20.9.1-3. 5turnery of FCO Control Costs for the Bay Shore Plant (June 1988 Oollars)
:ss:::;z3:s«;Ms;:3»=:;szc5:sax:u«::ii::ax:ss8z:::si3:s»5ssszt»::a;^=cs»:s23i:s»s=:ss2:ss3::::s:::2;s::::
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nunber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (*W> (X) Content (MM) (»/W) (SHO (mil Is/lcwh) (%) (tons/yr)
-------
Table 20.9.1-4. Surinary of Coal Snitching/Cleaning Costs for the Bay Shore Plant (June 1988 Dollars)
:33t2i«ss3:ai::3:3s::s:cssssssssaaBasaxs3izxszxiiS3izassssss:sssssssss3iaesssss=zitsaasxsszasss:ss:ss:s::=:;s3s:
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 S02 Cost
Nimber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NW) (X) Content (U0O (SAW) (SWO CmUls/kufc) (X) (tons/yr) ;$/ton)
Factor (X)
CS/B*S15
1
1.00
141
84
1.2
5.6
40.0
15.4
14.8
17.0
1512
10168.0
CS/B*S15
2
1.00
143
47
1.2
5.7
39.9
9.3
15.8
17.0
858
10834.5
CS/B«*15
3
1.00
150
83
1.2
6.2
41.2
16.2
14.9
17.0
1590
10192.6
CS/B*»15
4
1.00
224
65
1.2
8.8
39.1
19.1
15.0
17.0
1859
10267.6
CS/B+J15-C
1
1.00
141
84
1-2
5.6
40.0
8.8
8.5
17.0
1512
5842.4
CS/B+J15-C
2
1.00
143
47
1.2
5.7
39.9
5.4
9.1
17.0
858
6237.3
CS/B+*15-C
3
1.00
150
83
1.2
6.2
41.2
9.3
8.5
17.0
1590
5857.2
CS/B+S15-C
4
1.00
224
65
1.2
8.8
39.1
11.0
8.6
17.0
1859
5903.8
CS/B+J5
1
1.00
141
84
1.2
4.2
29.6
6.5
6.3
17.0
1512
4331.4
CS/B*$5
2
1.00
143
47
1.2
4.2
29.5
4.2
7.1
17.0
858
4864.4
CS/B»$5
3
1.00
150
83
1.2
4.6
30.9
6.9
6.3
17.0
1590
4353.9
CS/B»$5
4
1.00
224
65
1.2
6.4
28.8
8.1
6.4
17.0
1859
4381.5
CS/B+S5-C
1
1.00
141
84
1.2
4.2
29.6
3.8
3.6
17.0
1512
2494.1
CS/B*S5-C
2
1.00
143
47
1.2
4.2
29.5
2.4
4.1
17.0
858
2809.1
CS/B+S5-C
3
1.00
150
83
1.2
4.6
30.9
4.0
3.7
17.0
1590
2507.6
CS/B+S5-C
4
1.00
224
65
1.2
6.4
28.8
4.7
3.7
17.0
1859
2525.9
:33a««iiss3sssssssss:s:s3sss33ssss3s3;
20-175
-------
TABLE 20.9.1-5. SUMMARY OF NOx RETROFIT RESULTS FOR BAY SHORE
BOILER NUMBER
COMBUSTION MODIFICATION RESULTS
1,2
3
4
1-4
FIRING TYPE TOP FIRED
FWF
FWF
NA
TYPE OF NOx CONTROL
NA
LNB
LNB
NA
FURNACE VOLUME (1000 CU FT)
98.4
54
103.54
NA
. BOILER INSTALLATION DATE
1955,59
1963
1968
NA
SLAGGING PROBLEM
NO
NO
NO
NA
ESTIMATED NOx REDUCTION (PERCENT)
NA
26
33
NA
SCR RETROFIT RESULTS
SITE ACCESS AND CONGESTION
FOR SCR REACTOR
NA
NA
NA
LOW
SCOPE ADDER PARAMETERS--
Building Demolition (1000$)
NA
NA
NA
0
Ductwork Demolition (1000$)
NA
NA
NA
111
New Duct Length (Feet)
NA
NA
NA
200
New Duct Costs (1000$)
NA
NA
NA
2984
New Heat Exchanger (1000$)
NA
NA
NA
5772
TOTAL SCOPE ADDER COSTS (1000$)
NA
NA
NA
8867
RETROFIT FACTOR FOR SCR
NA
NA
NA
1.16
GENERAL FACILITIES (PERCENT)
NA
NA
NA
20
20-176
-------
Table 20.9.1-6. HOx Control Cost Results for the Bay Shore Plant (Jirte 1988 Dollars)
:s:asisiss:sstsiiasaiiiisiiBsiiasiBiaiamiinaB:sss:sssss3
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual NOx MOx NO* Cost
Nurber Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (MM) Content (SMM) (tons/yr)
factor (X)
INC-INB 3 1.00 150 83 1.2 3.0 20.0 0.6 0.6 26.0 1104 587.2
LNC-INB 4 1.00 224 65 1.2 3.5 15.7 0.8 0.6 33.0 1639 464.5
INC-LNB-C 3 1.00 150 83 1.2 3.0 20.0 0.4 0.4 26.0 1104 348.7
LMC-INB-C 4 1.00 224 65 1.2 3.5 15.7 0.5 0.4 33.0 1639 275.8
SCR-3 1-4 1.16 658 69 1.2 78.3 119.0 29.7 7.5 80.0 12390 2395.3
SCR-3-C 1-4 1.16 658 69 1.2 78.3 119.0 17.4 4.4 80.0 12390 1400.7
SCR-7 1-4 1.16 658 69 1.2 78.3 119.0 24.3 6.1 80.0 12390 1965.0
SCR-7-C 1-4 1.16 658 69 1.2 78.3 119.0 14.3 3.6 80.0 12390 1154.1
SS::3sssSSSSS2aSSSSS35SSSS3SS5SSSS33SSSSS3SS3IS3SSSSSSS33IIIS5SSS3SSXSI1SSSSSS 33SSISSSS5SSS3::S5SSSISSSSSSSSSSSS
20-177
-------
TABLE 20.9.1-7. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION
TECHNOLOGIES FOR BAY SHORE 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 (10005) 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 (1000S) 39
TOTAL COST (1000$)
ESP UPGRADE CASE 39
A NEW BAGHOUSE CASE NA
RETROFIT FACTORS
CONTROL SYSTEM (DSD SYSTEM ONLY) 1.13
ESP UPGRADE 1.58
NEW BAGHOUSE NA
20-178
-------
Table 20.9.1-8. Sumiary of DSO/FSI Control Costs for th« Bay Shore Plant (June 1988 Dollars)
ss:ss::ss3st::s:ssi::ssa
Technology Boiler Main Boiler Capacity Coal Capital Capital Annual Annual S02 S02 502 Cost
Nmtoer Retrofit Size Factor Sulfur Cost Cost Cost Cost Removed Removed Effect.
Difficulty (NU) OS) Content CSM4) <*/kW> CWM) (nills/lttrtD (X) (tons/yr> (I/ton)
Factor (X)
DS0»ESP
DSD*ESP
1.00
1.00
141
143
84
47
1.2
1.2
6.5
6.S
45.a
45.5
6.0
5.2
5.7
8.8
49.0
49.0
4380
2486
1361.8
2082.5
DS0+ESP-C
DS0+ESP-C
1.00
1.00
141
143
84
47
1.2
1.2
6.5
6.5
45.8
45.5
3.4
3.0
3.3
5.1
49.0
49.0
4380
2486
786.8
1204.9
FS1+ESP-50
FSl*ESP-50
1.00
1.00
141
143
84
47
1.2
1.2
7.3
7.3
51.7
51.4
5.9
4.7
5.7
7.9
50.0
50.0
4502
2555
1310.4
1826.7
FSI+ESP-50-C
F5I+ESP-50-C
1.00
1.00
141
143
84
47
1.2
1.2
7.3
7.3
51.7
51.4
3.4
2.7
3.3
4.6
50.0
50.0
4502
2555
758.0
1059.4
FSI*ESP-70
fSI+ESP-70
1.00
1.00
141
143
84
47
7.4
7.5
52.5
52.2
6.0
4.7
5.8
8.0
70.0
70.0
6303
3577
951.2
1323.5
FSI+ESP-70-C
FSI<€SP-70"C
1.00
1.00
141
143
84
47
7.4
7.5
52.5
52.2
3.5
2.7
3.3
4.7
70.0
70.0
6303
3577
550.2
767.6
ssssaisss::
sss::::s3S38is:
rssBssssati:
20-179
-------
Atmospheric Fluidized Bed Combustion and Coal Gasification Applicability--
All units would be potential candidates for AFBC/CG repowering because
of their small boiler size (<300 MW). However, the high capacity factors
could result in high replacement power costs for extended boiler downtime.
20-180
------- |