CD A U-S- Environmental Protection Agency Industrial Environmental Research
•"• •» Office of Research and Development Laboratory
Research Triangle Park, North Carolina 27711
EPA-600/7-78-033
March 1978
EFFECTS OF ALTERNATIVE NEW
SOURCE PERFORMANCE
STANDARDS ON FLUE GAS
DESULFURIZATION SYSTEM
SUPPLY AND DEMAND
Interagency
Energy-Environment
Research and Development
Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
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commercial products constitute endorsemerit or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-033
March 1978
EFFECTS OF ALTERNATIVE NEW SOURCE
PERFORMANCE STANDARDS ON FLUE
GAS DESULFURIZATION SYSTEM SUPPLY
AND DEMAND
by
Vijay P. Patel and L Gibbs
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2603
Task 1
Program Element No. EHE624
EPA Project Officers:
John E. Williams and Kenneth R. Durkee
Industrial Environmental Research Laboratory Emission Standards and Engineering Division
Office of Energy, Minerals, and Industry Office of Air Quality Planning and Standards
Research Triangle Park, N.C. 27711 Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
and Office of Air and Waste Management
Washington, D.C. 20460
-------
ABSTRACT
This report assesses the capability of flue gas desul-
furization (FGD) system manufacturers to provide the nec-
essary equipment to control sulfur dioxide emissions from
new coal-fired steam generators. This assessment was made
by estimating the total electrical capacity of new coal-
fired boilers and then determining the FGD system manufac-
turers' capability to design, supply, and install the nec-
essary equipment.
In addition, factors that limit this capability, such
as labor supply and availability of key equipment compo-
nents, were also investigated. Information on system
guarantees is also presented.
-------
TABLE OF CONTENTS
Page
SUMMARY viii
1.0 INTRODUCTION 1-1
2.0 PROJECTED CAPACITY OF UTILITY COAL-FIRED UNITS 2-1
AND RESULTANT DEMAND FOR FLUE GAS DESULFURIZATION
3.0 CAPABILITIES OF MANUFACTURERS TO PRODUCE FGD 3-1
SYSTEMS
3.1 Survey of FGD Manufacturers 3-1
3.2 Assessment of FGD Manufacturers' Capabili- 3-7
ties Versus Projected Demand
3.3 Assessment of Guarantees by FGD Manufacturers 3-11
3.4 Assessment of Availability of Key FGD System 3-15
Components
4.0 INSTALLATION OF FGD SYSTEMS ON POWER PLANT 4-1
BOILERS
4.1 Construction Schedules 4-1
4.2 Design and Construction Force Availability 4-4
APPENDIX A - Planned Coal-Fired Units Through 1998 A-l
APPENDIX B - Assumptions Used in Calculating FGD System B-l
Component Demand
111
-------
LIST OF FIGURES
Figure Page
2-1 Coal-fired Capacity Growth Rate Predictions. 2-5
4-1 Construction Schedule for a Typical (500- 4-3
MW) Power Plant
4-2 Construction Schedule for a Typical Power 4-5
Plant Equipped with FGD System
4-3 Man-hours Required to Meet Alternative 4-11
Emission Standards
xv
-------
LIST OF TABLES
Table
2-1 Planned Number of Coal-fired Boilers and Their 2-3
Capacities Through the Year 2000
2-2 Differential Capacity to be Added to Coal-fired 2-6
Units Known to be Planned
2-3 Projected Coal-fired Capacity Additions Through 2-7
the Year 2000
2-4 Planned Utilization of Flue Gas Desulfurization 2-9
Systems on Future Coal-fired Boilers
2-5 Projected Utilization of Flue Gas Desulfurization 2-12
on New Coal-fired Units
2-6 Approximate Process Distribution of Planned FGD 2-13
Systems on New Coal-fired Utility Boilers
2-7 FGD Capacity Requirements by Process from 1978 2-14
to 2000
3-1 Manufacturers Responding to the Flue Gas Desul- 3-2
furization System Survey and the Process Offered
by Each
3-2 Number and Capacity of FGD Systems that Manufac- 3-4
turers can Design and Install over a 15-year Period
3-3 Sources of Personnel to Accomplish Various Stages 3-5
of FGD System Design and Installation
3-4 Time Required for FGD System Design, Installation, 3-6
and Start-up
3-5 Lead Time and Delay Frequency of Various Items in 3-8
the Design and Installation of an FGD System
v
-------
LIST OF TABLES (continued)
Table Page
3-6 Raw Material Specifications for Various FGD 3-9
Systems
3-7 Summary of By-products from Flue Gas Desulfuri- 3-9
zation Systems
3-8 Comparison of Supply Versus Demand for FGD 3-10
Systems on New Coal-fired Utility Boilers Under
Present NSPS
3-9 Comparison of Supply Versus Demand for FGD 3-11
Systems on Coal-fired Utility Boilers Under More
Stringent NSPS
3-10 Guarantees Offered by Manufacturers for S02 3-12
Removal
3-11 Summary of Performance Guarantees Offered by 3-14
Manufacturers
3-12 Willingness of Manufacturers to Provide Operation 3-15
and Maintenance Service for FGD Systems
3-13 Major Manufacturers of FGD System Components 3-17
3-14 FGD System Components that Would Change if More 3-18
Rigid Controls were Applied
3-15 Capability of Manufacturers to Meet the Demand 3-19
for Scrubbers
3-16 Capability of Manufacturers to Meet the Demand 3-20
for Pumps
3-17 Capability of Manufacturers to Meet the Demand 3-21
for Fans
3-18 Capability of Manufacturers to Meet the Demand 3-22
for Ball Mills
3-19 Capability of Manufacturers to Meet the Demand 3-23
for Clarifiers
VI
-------
LIST OF TABLES (continued)
Table Page
3-20 Capability of Manufacturers to Meet the Demand 3-24
for Vacuum Filters
4-1 Man-hours Required to Meet the Alternative SO^ 4-10
Emission Standards
VI1
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SUMMARY
This report presents data on the capability of flue gas
desulfurization (FGD) system manufacturers to provide the
necessary equipment to control sulfur dioxide emissions from
new coal-fired steam generators as required by hypothetical
revised New Source Performance Standards (NSPS). The
assessment was made by first estimating the total electrical
capacity of new coal-fired boilers (largely on the basis of
Federal Power Commission data), then surveying the FGD
system manufacturers to determine to what extent they are
capable of designing, supplying, and installing the neces-
sary equipment.
Based on the new coal-fired boilers now planned for
construction and a projected growth rate of 5.56 percent per
year for the construction of such units, approximately
510,000 MW of coal-fired boiler capacity will be built
between 1978 and the year 2000. The hypothetical alterna-
tive standards assumed in this study indicate that all of
these new units will require FGD systems. The distribution
of types of FGD processes for these new boilers was pro-
jected on the basis of FGD systems already planned, which
Vlll
-------
shows that limestone scrubbing systems will account for 52
percent of the installations; lime systems 25 percent; and
lime/fly ash systems 13 percent. The balance will be made
up of double alkali, sodium-based, and regenerable systems.
While this projection of system types is rather crude, it is
adequate for the purpose of assessing FGD equipment and
personnel requirements.
The responses from the 13 FGD system manufacturers
surveyed indicate that they will be capable of supplying the
design personnel and equipment for the FGD systems required
by the alternative standards. The capability of manufac-
turers to meet FGD system requirements is flexible and
increases in proportion to demand.
Shortages in specialized construction personnel are a
possibility, however, and shortages in large scrubber
modules are also predicted by several of the suppliers.
IX
-------
1.0 INTRODUCTION
The U.S. Environmental Protection Agency (EPA) has
undertaken a program to review the New Source Performance
Standards (NSPS) regulating emission of sulfur dioxide (SO-)
from new utility coal-fired steam generators. To perform
this review, EPA needs to know what effects NSPS revisions
will have on the ability of manufacturers to meet the demand
for flue gas desulfurization (FGD) systems for the utility
industry.
For consideration in this evaluation, the EPA specified
hypothetical regulations of 215.2 nanograms of SO., per joule
£*
(0.5 pound per 10 Btu) of heat input to the steam generator
or an alternative standard of 90 percent overall reduction
of potential S02 emissions. This report presents the re-
sults of an assessment of the capabilities of manufacturers
to meet the demand for FGD systems required to achieve the
alternative standards.
Section 2 presents forecasts of coal-fired utility
capacity additions through the year 2000 and the anticipated
demand for FGD systems under present NSPS and the hypothetical
alternative standards. Section 3 includes the results of a
survey of the manufacturers of FGD systems regarding their
1-1
-------
capabilities, guarantees, and other factors affecting their
ability to design and construct FGD systems for utilities
that meet the present or the hypothetical alternative
standards up to the year 1992. Section 4 contains an assess-
ment of manpower availability for the installation of FGD
systems on utility boilers and time schedules for their con-
struction .
1-2
-------
2.0 PROJECTED CAPACITY OF UTILITY COAL-FIRED UNITS AND
RESULTANT DEMAND FOR FLUE GAS DESULFURIZATION SYSTEMS
To assess the impact of revising the NSPS, one must
determine the number and capacity of planned coal-fired
units affected. Several sources of data are available
regarding planned coal-fired utility power plants. Because
the Federal Power Commission (FPC) has primary responsi-
bility for regulation of the power industry, they are a
source of extensive data. Data on planned unit additions
from the FPC Electric Utility Information File include
ownership, location, size, fuel type, capacity, scheduled
start-up dates, and planned pollution control equipment.
These data were used to develop a list of planned coal-fired
units through the year 2000. Additional data were obtained
from a Federal Energy Administration (FEA) listing of pro-
jected power plants, a report by Kidder, Peabody and Co.,
Inc., entitled "Fossil Boilers, A Status Report on Electric
2
Utility Generating Equipment," and a PEDCo Environmental,
Inc., report entitled "Summary Report - Flue Gas Desul-
furization Systems, May-June 1977." (The results, tabu-
lated by state and U.S. EPA Region, are presented in Ap-
2-1
-------
pendix A.) Scheduled year of start-up, ownership, unit name
or identification, capacity, coal type, and planned particu-
late and SCU control methods are listed for each unit.
These data are summarized in Table 2-1, which presents, by
year, the number and capacity of currently planned units.
The data in this table reflect only units for which specific
data were available. Data on units planned after 1986 are
insufficient and do not account for all the capacity pro-
j ected to meet future electricity needs. It appears that
the utilities have not projected their plans for specific
units that far in advance because so many factors must be
taken into account before definite plans are formulated for
a power plant.
Because of the lack of data, it was necessary to assume
a growth rate of coal-fired units to project capacities
beyond 1986. An PPC News Release on December 8, 1976,
presented a staff report on electric utility expansion plans
for 1986 to 1995. This report contained a forecast of an
annual growth rate of 5.56 percent in electric generation
capability through 1995. This represented all types of
generating capacity, including nuclear, hydroelectric,
turbine, and fossil-fuel-fired. FPC estimates 50.3 percent
of the generating capacity will be fossil-fuel-fired by
1995. In 1975 FPC estimated that 69.7 percent of the gen-
2-2
-------
Table 2-1. PLANNED NUMBER OF COAL-FIRED BOILERS AND
THEIR CAPACITIES THROUGH THE YEAR 2000
Year
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
No. of Boilers
26
29
31
36
30
32
31
31
37
12
9
6
3
4
1
0
2
1
0
0
0
0
0
0
Capacity, MW
12,938
11,948
13,196
19,739
15,509
15,331
17,216
16,319
19,519
6,433
6,025
3,950
1,975
2,700
800
0
1,150
300
0
0
0
0
0
0
2-3
-------
erating capacity at that time was fossil-fuel-fired, but did
not indicate what portion was coal-fired. To project coal-
fired capacity, it was assumed that the growth rate of coal-
fired units would be approximately the same as the growth
rate of the overall capacity (5.56%). Although the per-
centage of fossil-fuel-fired units is expected to decrease,
the portion of fossil-fuel-fired capacity comprised of coal-
fired units will increase because of the scarcity of oil and
natural gas. Figure 2-1 graphically illustrates the capa-
city of the projected coal-fired units by applying a 5.56
percent growth rate as compared with the cumulative capacity
of known coal-fired units and planned additions. Planned
additions appear to be sufficient through 1987 for the
projected demand, but more capacity will be needed after
1987 than that presently planned. The projected coal-fired
capacity additions presented in Table 2-2 are .based on
differences between the assumed 5.56 percent growth of coal-
fired capacity and the coal-fired additions that are known
to be planned.
Table 2-3 presents coal-fired capacity additions in-
cluding both the units known to be planned and the addi-
tional ones necessary to meet the demand predicted by FPC
through the year 2000. The capacity additions predicted for
1986 and 1987 appear small compared to additions for other
2-4
-------
.CO
O
i=
<
750
600
450
300
1975
GROWTH RATE OF 5.56% PER YEAR
KNOWN PLANNED ADDITIONS
BASE
1980
1985 1990
YEAR
1995
2000
Figure 2-1. Coal-fired capacity growth rate predictions.
-------
Table 2-2. DIFFERENTIAL CAPACITY TO BE ADDED TO
COAL-FIRED UNITS KNOWN TO BE PLANNED
CTl
Year
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Cumulative
capacity of planned
coal-fired units,
MW x 103
345
349
351
354
355
355
356
356
356
356
356
356
356
356
Cumulative capacity
of projected coal-fired
units based on
5.56% growth,
MW x 103
345
364
385
406
429
453
478
505
533
563
595
628
663
700
Cumulative
difference,
MW x 103
0
15
34
52
74
98
126
149
177
207
239
272
307
344
Additional
capacity
required
MW x 103
0
15
19
18
22
24
28
23
28
30
32
33
35
37
-------
Table 2-3. PROJECTED COAL-FIRED CAPACITY
ADDITIONS THROUGH THE YEAR 2000
Yeara
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Total projected and planned
capacity additions,
MW
11,950
13,100
19,700
15,500
15,300
17,200
16,300
19,500
6,400
6,000
19,000
21,000
21,000
24,000
24,000
29,000
23,000
28,000
30,000
32,000
33,000
35,000
37,000
1978 to 1987 are currently planned (see Table
2-1). 1988 to 2000 are projected capacity require-
ments .
2-7
-------
years. The data for these two years reflect the uncertainty
of known planned units this far in the future. Since the
growth rate of known units exceeds the assumed 5.56 percent
growth rate predicted by FPC, no additional units were
assumed for 1986 and 1987, thus the apparent incongruity
for these two years.
Availability of control technology to enable compliance
with the required emission levels also must be considered in
revising NSPS. Coal-fired boilers can attain compliance
with current NSPS by several methods—burning low-sulfur
coal, washing selected coals, applying flue gas desulfuriza-
tion, and combinations of these methods. FPC's Electric
Utility Information File and PEDCo Environmental1s "Summary
4
Report - Flue Gas Desulfurization Systems, May, June 1977"
indicate that flue gas desulfurization is a primary control
method planned for new coal-fired units. According to these
references, a sufficient number of FGD systems will be in-
stalled by the end of 1987 to serve approximately 60,000 MW
of capacity on new coal-fired utility boilers. Table 2-4
presents planned FGD capacity additions through the year
2000.
As indicated in Table 2-4, the percentage application
of planned FGD units drops drastically beyond 1980. This
does not necessarily mean that more utilities plan to fire
2-8
-------
Table 2-4. PLANNED UTILIZATION OF
FLUE GAS DESULFURIZATION SYSTEMS ON
FUTURE COAL-FIRED BOILERS
Year
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Planned coal- fired
capacity additions,
MW
12,938
11,948
13,196
19,739
15,509
15,331
17,216
16,319
19,519
6,433
6,025
3,950
1,975
2,700
800
0
1,150
300
0
0
0
0
0
0
Planned
utilization of FGD
under present NSPS,
MW
10,359
10,204
8,271
11,190
4,975
8,010
4,223
2,146
1,115
0
0
500
0
0
0
0
350
0
0
0
0
0
0
0
Percentage
using FGD,
%
80
85
63
57
32
52
25
13
6
0
0
13
0
0
0
0
30
0
0
0
0
0
0
0
2-9
-------
low-sulfur coal to attain compliance; rather it indicates a
lack of a commitment by the utilities to a specific control
<
technique. Many factors can change during the construction
of a power boiler, such as the cost of low-sulfur coal, the
state of development of a particular FGD system, applicable
regulations, and other economic and technological factors
that have a bearing on the attractiveness of particular
control options. These unknowns make utilities reluctant to
commit themselves to a particular control technique too far
in advance.
Approximately 3 years lead time is required for appli-
cation of an FGD system on a coal-fired utility boiler (dis-
cussed in Section 4.0). It is assumed, therefore, that
units coming on line through 1980 are definitely committed
to a particular S02 control strategy. The application of
FGD in 1979 and 1980 is planned for about 60 percent of the
units representing coal-fired capacity. This should provide
a good approximation of the extent of FGD application under
the present NSPS.
For purposes of this study, EPA has proposed the fol-
lowing alternatives as hypothetical NSPS revisions: (1) 90
percent reduction of S02 emissions regardless of the sulfur
content of the coal, and (2) an emission level of 215.2 (
nanograms SO- per joule (0.5 pounds of SC^ per 10 Btu) of
2-10
-------
heat input. If alternative (1) is adopted as the standard,
the overall effect would be the installation of FGD on all
new units subject to this regulation. Alternative (2) would
have essentially the same effect because coal reserves are
inadequate to meet such a standard. Therefore, for either
alternative it can be assumed that FGD will be required for
all new coal-fired units. Table 2-5 presents anticipated
FGD usage under present NSPS and under hypothetical NSPS re-
visions.
Several types of FGD systems are available for utility-
size boilers (discussed in Section 3). Utilities usually
have selected the process for FGD installations planned
through 1980, but they have not decided upon a specific type
of process for FGD systems installed after 1980. To eval-
uate the types of FGD systems required in the future, some
assumptions must be made regarding distribution. Table 2-6
presents a percentage distribution of different FGD proc-
esses based on currently planned FGD systems on new units
and on the assumption that all New England (U.S. EPA Region
I) utilities will use regerierable systems. This distribu-
tion assumption was applied to new units through the year
2000 and used to arrive at the FGD capacity requirements, by
process, for present NSPS and hypothetical revised standards
(as presented in Table 2-7).
2-11
-------
to
I
Table 2-5. PROJECTED UTILIZATION OF FLUE GAS DESULFURIZATION
ON NEW COAL-FIRED UNITS
Year
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Total projected
capacity additions,
MW
11,950
13,100
19,700
15,500
15,300
17,200
16,300
19,500
6,400
6,000
19,000
21,000
21,000
24,000
24,000
29,000
23,000
28,000
30,000
32,000
33,000
35,000
37,000
Projected
utilization of FGD
under present NSPS,a
MW
10,200
8,300
11,200
9,300
9,200
10,300
9,800
11,700
3,800
3,600
11,400
12,600
12,600
14,400
14,400
17,400
13,800
16,800
18,000
19,200
19,800
21,000
22,200
Total projected utilization of
FGD under a 0.5 lh S02/106 Btu
or 90% control regulation,'3
MW
11,950
13,100
19,700
15,500
15,300
17,200
16,300
19,500
6,400
6,000
19,000
21,000
21,000
24,000
24,000
29,000
23,000
28,000
30,000
32,000
33,000
35,000
37,000
2SS8SnaB?5
o|8utI!P2eaCt!oannolSF^eonnwUcoa-rea ii shown in Table 2-3.
-------
Table 2-6. APPROXIMATE PROCESS DISTRIBUTION OF PLANNED
FGD SYSTEMS ON NEW COAL-FIRED UTILITY BOILERS
FGD process
Percent application
to new units, %
Nonregenerable
Lime scrubbing
Lime/alkaline flyash scrubbing
Limestone scrubbing
Double alkali
Sodium carbonate
Regenerable
Sodium solution
Magnesium oxide
25
13
52
3
2
3
2
2-13
-------
Table 2-7. FGD CAPACITY REQUIREMENTS BY PROCESS FROM 1978 TO 2000
Regulation: 516.5 ng S02/J (1.2 Ib SO2/106 Btu)
Year
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Capacity by FGD process, MW
Lime
2550
2075
2800
2325
2300
2575
2450
2925
950
900
2850
3150
3150
3600
3600
4350
3450
4200
4500
4800
4950
5250
5550
Lime/flyash
1326
1079
1456
1209
1196
1339
1274
1521
494
468
1482
1638
1638
1872
1872
2262
1794
2184
2340
2496
2574
2730
2886
Limestone
5304
4316
5824
4836
4784
5356
5096
6084
1976
1872
5928
6552
6552
7488
7488
9048
7176
8736
9360
9984
10296
10920
11544
Double
alkali
306
249
336
279
276
309
294
351
114
108
342
378
378
432
432
522
414
504
540
576
594
630
666
Sodium
carbonate
204
166
224
186
184
206
196
234
76
72
228
252
252
288
288
348
276
336
360
384
396
420
444
Sodium
solution
306
249
336
279
276
309
294
351
114
108
342
378
378
432
432
522
414
504
540
576
594
630
666
Magnesium
oxide
204
166
224
186
184
206
196
234
76
72
228
252
252
288
288
348
276
336
360
384
396
420
444
ro
l
-------
Table 2-7 (continued). FGD CAPACITY REQUIREMENTS BY PROCESS FROM 1978 TO 2000
Regulation: 215.2 ng/J (0.5 Ib SO2/106 Btu) or 90% SO2 removal
Year
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Capacity by FGD process, MW
Lime
2988
3275
4925
3875
3825
4300
4075
4875
1600
1500
4750
5250
5250
6000
6000
7250
5750
7000
7500
8000
8250
8750
9250
Lime/ fly ash
1554
1703
2561
2015
1989
2236
2119
2535
832
780
2470
2730
2730
3120
3120
3770
2990
3640
3900
4160
4290
4550
4810
Limestone
6214
6812
10,244
8060
7956
8944
8476
10,140
3328
3120
9880
10,920
10,920
12,480
12,480
15,080
11,960
14,560
15,600
16,640
17,160
18,200
19,240
Double
alkali
359
393
591
465
459
516
489
585
192
180
570
630
630
720
720
870
690
840
900
960
990
1050
1110
Sodium
carbonate
239
262
394
310
306
344
326
390
128
120
380
420
420
480
480
580
460
560
600
640
660
700
740
Sodium
solution
359
393
591
465
459
516
489
585
192
180
570
630
630
720
720
870
690
840
900
960
990
1050
1110
Magnesium
oxide
239
262
394
310
306
344
326
390
128
120
380
420
420
480
480
580
460
560
600
640
660
700
740
to
I
M
Ul
-------
These projections provide a basis for making economic
and environmental impacts, and also for estimating the
capabilities of equipment manufacturers to meet this demand
(discussed in the next section).
REFERENCES FOR SECTION 2
1. Inventory of Power Plants in the United States. June
1977. Federal Energy Administration. Washington, D.C,
pp. 311-344.
2. Fossil Boilers, A Status Report on Electric Utility
Generating Equipment. Kidder Peabody & Co., Inc.
3. Summary Report - Flue Gas Desulfurization Systems -
May-June 1977. PEDCo Environmental, Inc.
4. Ibid. p. 215.
5. Ibid.
2-16
-------
3.0 CAPABILITIES OF MANUFACTURERS TO PRODUCE FGD SYSTEMS
This section contains an assessment of the capabilities
of manufacturers to supply and install the FGD systems re-
quired to meet present and alternative New Source Performance
Standards. The assessment includes an evaluation of the
availability of individual components required in FGD
systems, and conditions of the guarantees manufacturers are
willing to offer. To provide information related to the
evaluation, two separate surveys were conducted in which
projections were requested to the year 1992.
3.1 SURVEY OF FGD MANUFACTURERS
In the first survey, 18 representative manufacturers of
FGD systems were contacted. Thirteen of the 18 responded by
either completing or partially completing the survey form.
Table 3-1 lists these 13 and the FGD systems they market.
Basically, FGD systems fall into two classes: regen-
erative and nonregenerative. A regenerative flue gas de-
sulfurization system removes the SO- from flue gas and
converts it to a marketable by-product, usually, elemental
sulfur, sulfuric acid, or a concentrated SO,, gas stream.
£*
Examples of regenerative processes include magnesium oxide
3-1
-------
Table 3-1. MANUFACTURERS RESPONDING TO THE FLUE GAS DESULFURIZATION SYSTEM
SURVEY AND THE PROCESS OFFERED BY EACH
u>
I
10
Manufacturer
1 . Babcock i Wilcox
Company
2. Chemico Air Pollution
Control Company
3. Chiyoda International
Corp.
4. Combustion Engi-
neering, Inc.
5. Davy Powergas, Inc.
6. Environeering, Inc.
7. Flakt, Inc.
8. FMC Corp.
9. Peabody Process
Systems, Inc.
10. Pullman, Inc.
11. Research-Cottrell,
Inc. _
12. UOP, Inc.
13. Zurn Air Systems
Type of FGD System Offered
Regenerative system
Magnesium
oxide
X
Phosphate
X
Wei 1 man-
Lord
X
Catalytic
oxidation
X
i
i
Citrate
X
Nonregenerative system
Double
alkali
X
Lime
X
; X
X
X
X
X
X
X
X
X
Limestone
X
X
X
X
X
X
X
X
X
Chiyoda
thoroughbred
101
X
Sodium
carbonate
X
X
Hydro
X
-------
(MgO) scrubbing, the Wellman-Lord process, the citrate
process, the phosphate process, and the catalytic oxidation
system.
A nonregenerative system removes the S00 from flue gas
^
by reacting it with a compound that produces a sludge as the
product of reaction. The sludge must be disposed of in an
environmentally sound manner. The various processes of the
nonregenerative type include lime scrubbing, limestone
scrubbing, the sodium carbonate process, the double alkali
process, and the Chiyoda Thoroughbred 101 process.
Table 3-2 summarizes the cumulative number and capacity
of FGD systems that manufacturers can design and install
over three 5-year periods. These figures include estimates
with their present staff and with an expanded staff under
conditions of high market demand.
The manufacturers were also asked to identify the
sources of personnel to perform various stages of FGD system
design and installation. Table 3-3 summarizes the informa-
tion they provided.
In addition, the surveyed manufacturers were requested
to estimate the time required to design, install, and start
up the systems they offer. Table 3-4 presents the average
and range of time required to design, install, and start up
FGD systems of various sizes.
3-3
-------
Table 3-2. NUMBER AND CAPACITY OF FGD SYSTEMS THAT MANUFACTURERS
CAN DESIGN AND INSTALL OVER A 15-YEAR PERIOD3
Systems
designed'3
Number
Capacity , MW
Systems
installed13
Number
Capacity, MW
Five-year period (inclusive)
1978-1982
Present
staff
936
205,710
699
144,285
Expanded
staff
1,639
371,500
1,135
238,455
1983-1987
Present
staff
992
212,885
797
160,510
Expanded
staff
1,902
421,890 .
1,435
293,365
1988-1992
Present
staff
1,106
218,540
828
166,190
Expanded
staff
1,959
434,990
1,475
303,940
00
I
Represents the responses of 12 manufacturers. The capability shown in this table
refers to both regenerative and nonregenerative systems.
The difference between the number of systems designed and the number installed
results from the long lead time required for installation of FGD systems.
-------
Table 3-3. SOURCES OF PERSONNEL TO ACCOMPLISH VARIOUS
STAGES OF FGD SYSTEM
DESIGN AND INSTALLATION
a,b
Item
No. of
manufacturers using
in-house personnel
No. of
manufacturers using
outside labor
Process design
Detailed engineering
design
Equipment fabrication
Scrubber vessels/tanks
Fans/pumps
Sludge disposal
System installation
Supervision
Crafts
12
11
1
3
4
1
0
10
1
9
11
11
3
11
a Some manufacturers indicated that they use both in-house
personnel and outside labor to accomplish the different
stages of FGD system design and installation.
Represents the responses of 12 manufacturers.
3-5
-------
Table 3-4. TIME REQUIRED FOR PGD SYSTEM DESIGN, INSTALLATION, AND START-UP*
Size,
MW
<100
100-400
400-800
>800
Time required for
design and installation
Average
22.2 months
24.4 months
30.1 months
33.1 months
Range
6 months to 36 months
8 months to 36 months
18 months to 42 months
20 months to 42 months
Time required for start-up
Average
1 . 8 months
2 . 3 months
2 . 4 months
2 . 7 months
Range
0 . 5 months to 6 months
0 . 5 months to 6 months
0 . 5 months to 7 months
0 . 5 months to 7 months
OJ
I
Represents the responses of 12 manufacturers.
"Start-up" is defined as the time between completion of plant construction and
when plant is capable of operating at an acceptable level of capacity.
-------
In response to a request that they identify items that
could frequently delay installation schedules, the manu-
facturers furnished lead times and delay frequencies for
various items, as shown in Table 3-5. Equipment installa-
tion delays apparently effect project completion frequently.
The manufacturers responding to the FGD survey reported
ample availability of raw materials used in their FGD
systems. Lime and limestone are the most widely used raw
materials for FGD systems. The total amount of lime and
limestone production in the U.S. in 1976 amounted to 18.3
million Mg (20.2 million tons) and 601.4 million Mg (662.9
million tons), respectively. If all new FGD systems used
limestone, approximately 18 million Mg (20 million tons)
would be required in addition to current demand by 1985.
Table 3-6 shows the raw material specifications for five
different FGD systems.
The manufacturers were asked to supply information on
by-products generated by each type of FGD systems. Table
3-7 summarizes this information.
3.2 ASSESSMENT OF FGD MANUFACTURERS' CAPABILITIES VERSUS
PROJECTED DEMAND
As indicated earlier, FGD manufacturers were queried as
to their capacity to supply FGD systems for the time period
1978 through 1992 (Table 3-2). The demand for FGD systems
+ National Lime Association, Washington, D.C.
3-7
-------
Table 3-5. LEAD TIME AND DELAY FREQUENCY OF VARIOUS ITEMS IN
THE DESIGN AND INSTALLATION OF AN FGD SYSTEM
Item
Process design
Detailed engineering design
Equipment fabrication
0 Structural steel
0 Scrubber vessel/tanks
0 Fans
0 Pumps
0 Instrumentation
0 Motors
0 Piping
Equipment installation
Reactant procurement
(e.g., limestone)
Average lead time,
months3
2.6
8.6
6.0
7.6
11.4
9.4
8.3
8.0
7.2
12.5
2.0
Number of manufacturers replying
Critical path item
Yes
8
9
4
7
10
3
2
4
7
9
1
NO
2
1
6
3
0
7
8
6
3
1
9
Delay frequency
High
1
1
0
2
2
2
4
2
0
5
0
Average
4
6
6
4
6
5
3
4
9
4
5
Low
5
3
4
4
2
3
3
4
1
1
5
I
00
Represents the responses of 9 manufacturers
b Represents the responses of 10 manufacturers
-------
Table 3-6,
RAW MATERIAL SPECIFICATIONS FOR
VARIOUS FGD SYSTEMS
FGD system
Raw materials
Type
Specifications
1. Lime
2. Limestone
3. Magnesium oxide
4. Double alkali
5. Wellman-Lord
Calcium oxide
Calcium carbonate
Magnesium oxide
Sodium carbonate
Caustic soda
90% CaO
90% CaCO3
98.5% MgO
98% Na-SO-
50% NaOH in water
TABLE 3-7. SUMMARY OF BY-PRODUCTS FROM
FLUE GAS DESULFURIZATION SYSTEMS
Item
Regenerable system
Nonregenerable system
By-products
Quantity
Utilization/
disposal
technique
S, SO2 and H2SO4
Sold to other
industries
CaSO4 (Sludge)
2.47 kg dry per kg S09
(2.47 Ib dry per Ib
S0_) removed (Average)
1.8 to 4 kg dry per
kg SO2 (1.8 to 4 Ib
dry per Ib SO_) removed
(Range)
Landfilled
a The manufacturers were not asked to supply this informa-
tion.
3-9
-------
under present regulations was determined in Section 2 (Table
2-5). In Table 3-8, manufacturing capability is compared
with the projected market demand from 1978 to 1992. The
manufacturers appear to have more than sufficient capacity
to install FGD systems required under present NSPS.
Table 3-8. COMPARISON OF SUPPLY VERSUS DEMAND
FOR FGD SYSTEMS ON NEW COAL-FIRED UTILITY BOILERS
UNDER PRESENT NSPS
Time
period
1978-1982
1983-1987
1988-1992
Total
FGD
manufacturers '
capability
with present staff,
MWa
205,710
212,885
218,540
637,135
Projected demand,
MWb
48,200
39,200
65,400
152,800
Differential
capacity, MW
+ 157,510
+ 173,685
+ 153,140
484,335
From Table 3-2. These are largely lime and limestone systems
b From Table 2-5.
If the NSPS were revised to more stringent levels such
as 215.2 ng SO-/J (0.5 1-b SO~/106 Btu) or 90 percent S00
« fc £
emission reduction, the demand for FGD systems would be
greatly increased. Manufacturers would, of necessity, ex-
pand their staffs to cope with this high market demand.
Table 3-9 presents a comparison of the projected demand for
FGD under more stringent NSPS regulations versus the capa-
3-10
-------
bility of FGD manufacturers to supply systems under high
market demand conditions. The data indicate that the manu-
facturers believe they can supply all of the projected
demand for systems under conditions that would require every
new coal-fired power plant to have an FGD system.
Table 3-9. COMPARISON OF SUPPLY VERSUS
DEMAND FOR FGD SYSTEMS ON COAL-FIRED UTILITY BOILERS
UNDER MORE STRINGENT NSPS
Time
period
1978-1982
1983-1987
1988-1992
Total
FGD manufacturers'
capability
with expanded staff,
MWa
371,500
421,890
434,990
1,228,380
Projected
demand ,
MWb
75,550
65,400
109,000
249,950
Differential
capacity, MW
+ 295,950
+ 356,490
+ 325,990
978,430
a From Table 3-2. These are largely lime and limestone systems,
b From Table 2-5.
3.3 ASSESSMENT OF GUARANTEES BY FGD MANUFACTURERS
The results of the survey indicate that in most cases
the manufacturers are willing to guarantee 90 percent S02
removal. Many of the same manufacturers are prepared to
guarantee better than 90 percent SO2 removal on a case-by-
case basis. The levels of SO2 removal guarantees offered by
manufacturers are briefly summarized in Table 3-10. Terms
of the guarantees were not disclosed by manufacturers.
3-11
-------
Table 3-10.
GUARANTEES OFFERED BY MANUFACTURERS FOR S02 REMOVAL
U)
I
H
Company
C
D
E
F
Level of SO2 removal guaranteed
<90
Would normally
guarantee 80-85%
90%
Minimum guarantee given
Minimum guarantee given
This guarantee is normally
given
This guarantee is given
where S(>2 inlet concentra-
tion is 500-4,000 ppm
This guarantee is given
where low-sulfur coal is
utilized
Minimum guarantee given
This guarantee is usually
given with coal having 3-4%
sulfur
This guarantee is normally
given with low- or high-
sulfur coal
Minimum guarantee given
>90%
Is willing to offer 95%
guarantee on case-by-case basis
For >90%, it is based on inlet
SO. concentration
Would guarantee 95% in all cases
Would guarantee up to 92% in the
past. Currently case-by-case.
Have guaranteed >90% in the past
Depending upon the process, they
would guarantee >90%
Have guaranteed up to 95% in the
past
Are prepared to offer better than
90% with low- or high-sulfur coal,
but would not guarantee less than
50 ppm SO2 concentration in exit
stream :
In many cases they guarantee 95%
with high-sulfur coal
May guarantee up to 95% on a case
by case basis
Company names are deliberately withheld.
-------
More than half the manufacturers responding to the
survey indicated willingness to guarantee availability
(performance) of their FGD systems. The typical level of
performance guarantee was quoted as 90 percent. The levels
of performance guarantees are briefly summarized in Table
3-11.
All manufacturers responding to the survey were willing
to offer guarantees on the cost of their FGD systems:
0 Four manufacturers would base the guarantee
subject to an escalation clause.
0 One manufacturer would negotiate the terms of the
guarantee.
None of the other respondents specified the provisions of
their cost guarantees.
The manufacturers were asked to indicate their willing-
ness to contract for operation and maintenance of the FGD
system after installation. Two-thirds of them responded
affirmatively (Table 3-12).
3-13
-------
Table 3-11. SUMMARY OF AVAILABILITY GUARANTEES OFFERED
BY MANUFACTURERS
Company
Guarantee offered
Yes (level)
No
A
B
C
E
F
G
H
I
J
K
L
Normally better than 90%
Typically 90% during performance
testing; sometimes up to 95%
Maximum of 90% based on boiler
hours
Yes (level of guarantee not dis-
closed)
Have guaranteed in excess of 90%
Normally 85 to 90% for 1 or 2 years
Maximum of 90% on a case by case
basis
X
X
X
X
X
Company names are deliberately withheld.
3-14
-------
Table 3-12. WILLINGNESS OF MANUFACTURERS TO PROVIDE
OPERATION AND MAINTENANCE SERVICE FOR FGD SYSTEMS
Company
A
B
C
D
E
F
G
H
I
J
K
L
Provide operation and
maintenance service
Yes
X
X
X
X
X
X
X
X
NO
X
X
X
X
Those indicating a willingness to operate and maintain
the system also indicated that this could affect the guar-
antee, but did not specify the provisions affected.
3.4 ASSESSMENT OF AVAILABILITY OF KEY FGD SYSTEM COMPONENTS
Although FGD system manufacturers contract for the
entire design and installation of the system, various com-
ponents of the FGD system are supplied by other manufac-
turers under subcontract. An accurate assessment of the
ability of FGD manufacturers to supply complete systems
requires a determination of the subcontractors' ability to
supply the system manufacturers with the necessary com-
ponents. To determine the capability of subcontractors to
3-15
-------
meet future demands for individual components and to eval-
uate the effects of revised NSPS on this capability, a
survey was conducted of the manufacturers of the following
major FGD components:
0 Scrubbers
0 Pumps
0 Fans
0 Ball mills
0 Clarifiers
0 Vacuum filters
Table 3-13 lists the component manufacturers who were
contacted and the type of equipment they manufacture. Of
the 18 manufacturers contacted, 9 responded.
The demand for additional FGD system components for
various sized plants was calculated through the year 1992,
using standard engineering calculations and assumptions (,see
Appendix B). Table 3-14 shows those items that would
change if more rigid controls were implemented.
Data contained in the responses from these manufac-
turers were tabulated and summarized by component size and
year. For comparison, the projected demand for each com-
ponent was also tabulated. TabJ.es 3-15 through 3-20 present
the results of this survey.
The responses indicate that shortages of scrubbers and
fans may possibly occur in the future. The shortages would
not be as great as the data indicate, however, because all
3-16
-------
Table 3-13. MAJOR MANUFACTURERS OF FGD SYSTEM COMPONENTS
Manufacturers
1. Allis-Chalmers
2. American Air Filter
3. Bird Manufacturing
Co.
4. Buffalo Forge Co.
5. Combustion
Engineering
6. Denver Equipment
Co.
7. Dorr-Oliver Inc.
8. Environeering Inc.
9. Envirotech Corp.
10. FMC Corp.
11. Goulds Pump Inc.
12. Inger soil-Rand Co.
13. Joy Manufacturing
Co.
14. Kennedy Van Saun
Corp.
15. Koppers Co. Inc.
16. OOP Engineering
Products Corp.
17. Worthington Pump
Inc.
18. Zurn Industries
Inc.
FGD System Component
Fans
X
X
X
X
X
Scrubbers
X
X
X
X
X
X
-
Ball
mills
X
X
X
X
Pumps
X
X
X
X
X
X
Vacuum
filters
X
X
X
X
X
Clarifiers
X
X
X
X
X
3-17
-------
Table 3-14. FGD SYSTEM COMPONENTS THAT WOULD
CHANGE IF MORE RIGID CONTROLS WERE APPLIED
System
Limestone handling
Component
Conveyors
Changes
Speed-up conveyors or
increase belt width
Limestone crushing
Scrubber
Sludge disposal
Air pollution
control
Silos ]Acquire additional
Ball mills > equipment or increase
with clarifier) size of present equipment
Pumps
Tanks
Steel
I.D. fan
Switchgear
Transformer
Pumps
Vacuum filter
Weigh feeder
Vibrating
feeder
Air compressor
Fabric filter
Valves
7 Acquire additional equipment
>or increase size of present
j equipment
Increase AP
Acquire additional equipment
or increase size of present
equipment
3-18
-------
Table 3-15. CAPABILITY OF MANUFACTURERS TO MEET THE DEMAND FOR SCRUBBERS*
oo
I
Years
(inclusive)
1978
to
1982
1983
to
1987
1988
to
1992
Size m3/s @149°C (acfm @300°F)
85 (180,000) (50 MW)
Demand
19
lb
Ob
Capacity
144
150
150
142 (300,000) (90 MW)
Demand
66
9b
3b
Capacity
157
139
150
170 (360,000) (110 MW)
Demand
287
41b
13b
Capacity
234
174
200
198 (420,000) (140 MW)
Demand
800
263
852
Capacity
459
515
515
Represents the responses from three manufacturers.
The very low demand during certain time periods is based on the assumption that plants coming
on line after 1986 will be 500-MW units and will require larger equipment.
-------
Table 3-16. CAPABILITY OF MANUFACTURERS TO
MEET THE DEMAND FOR PUMPS3'b
Years
(inclusive)
1978
to
1982
1983
to
1987
1988
to
1992
Size H/s (gpm)
0-305
Demand0
56
3
0
0-5,000)
Capacity
112
6
112
305-610 (5,000-10,000)
Demand
3,132
850
2,342
Capacity
6,264
1,700
4,684
Assume specific gravity =1.06 and AH = 45.7 m (150 ft.)
Represents the responses of two manufacturers.
The very low demand during certain time periods is based
on the assumption that the plants coming on line after
1986 will be 500-MW units and will require larger equip-
ment.
3-20
-------
Table 3-17. CAPABILITY OF MANUFACTURERS TO MEET THE DEMAND FOR FANS
a,b
CO
I
CO
Years
(inclusive)
1978
to
1982
1983
to
1987
1988
to
1992
Size m /s (acfm)
85 (180,000) (50 MW)
Demand u
19
1
0
Capacity
450
625
625
142 (300,000) (90 MW)
Demand c
66
9
3
Capacity
410
575
575
170 (360,000) (110 MW)
Demand "-
287
41
13
Capacity
370
525
525
198 (420,000) (140 MW)
Demand
800
263
852
Capacity
330
475
475
Assume AP = 46 cm (18 in.), temperature = 149°C (300°F).
Represents the response from one manufacturer.
The very low demand during certain time periods is based on the assumption that the plants
coming on line after 1986 will be 500-MW units and these plants will require larger equipment.
-------
Table 3-18. CAPABILITY OF MANUFACTURERS TO MEET
THE DEMAND FOR BALL MILLS3
I
N)
M
Years
(inclusive)
1978
to
1982
1983
to
1987
1988
to
1992
Size kg/hr, (tons/hr}
0-7258b (0-8)
Demand
131
20
1
Capacity
662
860
860
7258-14,515 (8-16)
Demand*3
99
13
0
Capacity
594
710
710
14,515-21,773 (16-24)
Demand
186
86
426
Capacity
448
560
560
Represents the responses from two manufacturers.
The very low demand during certain time periods is based on the
assumption that the plants coming on line after 1986 will be 500~
MW units and these plants will require larger equipment.
-------
Table 3-19. CAPABILITY OF MANUFACTURERS TO MEET
THE DEMAND FOR CLARIFIERS&/
U)
l
to
U)
Years
(inclusive)
1978
to
1982
1983
to
1987
1988
to
1992
Size diameter - m (ft)
0-15.2 (0-50)
Demand0
50
2
0
Capacity
200
250
250
15.2-30.5 (50-100)
Demand0
119
21
2
Capacity
360
450
450
30.5-45.7 (100-150)
Demand
130
64
426
Capacity
400
500
500
Assume maximum height of 3.1 m (10 foot).
Represents the response of 1 vendor.
The very low demand during certain time periods is based on the
assumption that the plants coming on line after 1986 will be 500-
MW units and these plants will require larger equipment.
-------
Table 3-20. CAPABILITY OF MANUFACTURERS TO MEET
THE DEMAND FOR VACUUM FILTERS3
OJ
I
to
Years
( inclusive)
1978
to
1982
1983
to
1987
1988
to
1992
Size m~ (ft2)
o-rvs.Q. (n-??9)
Demand
141
21
1
Capacity
244
340
352
25.9-54.6 (279-588)
Demand*3
47
8
1
Capacity
260
260
260
54.6-77.4 (588-°.33)
Demand
114
46
212
Capacity
260
260
260
Represents the responses of two manufacturers; one of the two manu-
facturers did not predict the capacity in the size range 25.9 to
54.6 sq m (279 to 833 sq ft).
The very low demand during certain time periods is based on the
assumption that the plants coming on line after 1986 will be 500-
MW units and these plants will require larger equipment.
-------
the manufacturers did not respond. The data are further
qualified by the assumption used in calculating demand—that
all new units after 1986 will be 500 megawatts or greater in
capacity. This assumption slants the requirements for
equipment to larger capacities, whereas the manufacturers'
responses covered a wide size range.
The projected demand for scrubbers from 1978 through
1992 is estimated to be 1915 at a capacity of 198 m3/s
(420,000 acfm) at 149°C (300°F), 341 at 170 m3/s (360,000
acfm), 78 at 142 m3/s (300,000 acfm), and 20 at 85 m3/s
(180,000 acfm). The capacity of manufacturers to supply
scrubbers during this time period is 1489 at 198 m /s
(420,000 acfm), 608 at 170 m3/s (360,000 acfm), 446 at 142
m3/s (300,000 acfm), and 444 at 85 m3/s (180,000 acfm). The
only shortage is in the 198 m /s (420,000 acfm) size cate-
gory, whereas excess capacity exists in smaller size cate-
gories. An examination of the capacities on a total m /s
(acfm) handled basis shows a demand of 450,200 m /s
(954,060,000 acfm) from 1978 through 1992 versus a capacity
of 499,200 m /s (1,057,900,000 acfm). On this basis, it
appears the total demand for scrubbers can be met during
this period. This belief is further strengthened by the
fact that the manufacturers of FGD systems did not antici-
pate any shortages.
3-25
-------
The apparent shortage of fans can be qualified in a
like manner. The data are slanted toward the larger capa-
cities. Examined on a total volume treated basis, the
demand for fans between 1978 and 1992 is 450,200 m3/s
(954,060,000 acfm), whereas the capacity is 860,200 m /s
(1,822,800,000 acfm). On this basis, it appears that the
demand for fans from 1978 through 1992 can also be met.
The survey did not indicate anticipated shortages of
any of the other components.
3-26
-------
4.0 INSTALLATION OF FGD SYSTEMS ON POWER PLANT BOILERS
4.1 CONSTRUCTION SCHEDULES
The construction of a power plant involves two major
phases: (1) preliminary study and (2) detail design and
construction of the facility. Preliminary study includes
the following activities:
0 Site selection
0 Planning and agency approval
0 Construction fund appropriation
0 Preparation of specifications
0 Bid evaluation
0 Contract award
The major items of work that go into the design and con-
struction of a power plant include the following:
0 Site preparation
0 Construction of coal handling facility
0 Erection of powerhouse building
0 Erection of powerhouse mechanical system
0 Erection of powerhouse electrical system
0 Construction of transformer and switchyard
4-1
-------
0 Construction of service bay
0 Construction of water supply and discharge facil-
ity
0 Erection of control building
Industry reports indicate that the size of a typical
coal-fired power plant committed for construction between
1977 and 1996 ranges from 450 to 550 MW. The average time
required to design and construct a 500-MW power plant is
approximately 6 years. This includes the time from the
initiation of a preliminary study to commercial operation of
the plant, but does not include the installation of an FGD
system.
Figure 4-1 shows the construction schedule for a 500-MW
unit. The elapsed time needed to erect a complete power
plant is a function of man-hours. The number of men that
can be used during any one stage of erection is limited,
however, for any given size of unit due to space and in-
stallation equipment constraints.
In most cases, an FGD system can be installed on a new
power plant without its having a significant impact on the
construction time schedule. It is assumed that adequate space/
material and labor will be available, thereby making it
possible for a major portion of the construction of the FGD
4-2
-------
I
CJ
Preliminary Engineering
Planning end Agency Approved
Construction Fund Appropri-
ation
Preparation of Specifications
Bid Evaluation
Construction Plant
Yards and General
Coal Handling
Powsr House Building
Power Housa Hechanical
Power House Electrical
Trensrorner and Switchyard
Condenser Hater
Hater Treatment
Control Building
No.
1
2
3
4
5
6
7
a
9
ID
11
13
14
IS
16
17
IB
19
20
31
22
23
24
2S
27
29
I ten
Site selection 1
Draft and final environmental impact
statements
Obtain funds for construction
Preliminary design and layout
evaluate bids
Award contract
Sign contract
Grading and roads
Concrete plant
Cleaning end grading
General mechanical and electrical
Coal handling facility erection
Power house building erection
Steam and turbo generators
Ash disposal
Pans
stacks
Heaters, tanks, pimps
Piping
Power house electrical connection
Transformer and switchyard erection
Erection of condenser water supply
Hiscellaneaus wiring, grounding, and
lighting
IM
M
••
S
•
•
•
7
•
•
• •
a
wm
m
m
9
•
M
mt
tm
9
•
•
21
!
-1
16
f-
~l
-1
~l
-
*
-\-
IAL OPERATION Of
POKE* PLANT
Figure 4-1. Construction schedule for typical 500-MW power plants.
-------
unit to parallel the boiler erection, as illustrated in
Figure 4-2. The design and construction of a flue gas
desulfurization system usually takes less time than the
power plant construction. The estimated extension to the
construction schedule due to the installation of an FGD
system is about 6 months. This six month extention is
comprised of three months for check out and shakedown of
the FGD system and three months due to extra construction
time typically caused by space and labor constraints. De-
pending upon site specific conditions and assuming that the
erection of the boiler and the FGD system can occur simul-
taneously, there would be no impact on the overall construc-
tion schedule if the application of an FGD system was
decided upon six months after signing of a boiler design and
construction contract.
4.2 DESIGN AND CONSTRUCTION FORCE AVAILABILITY
Installation of power plants and FGD systems requires
the services of the same types of laborers. Because FGD
manufacturers subcontract construction labor, they are not
always aware of potential shortages.
The following are the key crafts required for power
plant and FGD system installation:
0 Boilermakers
0 Carpenters
0 Electricians
0 Ironworkers
4-4
-------
I
Ul
Preliminary Engineering
Planning 4nd Agency Approved
Construction Fund Appropri-
ation
Bid Evaluation
Yards and General
Coal *nd Linestone Handling
Power Bouse and PGD Building
Power Bouse and PGD Mechan-
ical
Potter Bouaa and PGD
Electrical
Transformer and Switchyard
' SeYvice Bay
Con.'onser Hater
Mater and Ha ate Treatment
Control Building
tin.
1
2
3
4
5
c
7
•
J
10
12
13
14
IS
16
17
ia
19
20
21
22
24
25
26
27
28
Item
Site selection 1
Economic evaluation 2
Environmental inpact anaessmont
Draft and final environmental inpact
statement a
Obtain funde for con a tract Ion
Specification writing
Evaluate bid*
Award contract
Sign contract
G di. ltd d
Building* and utilities
concrete plant
cleaning and grading
Coel and liaeatone handling facility
erection
Power haura and PGD building erection
SteeM and turbo generator*
Aih and sludge dispoaal
Pans
Stacks
Heaters, tanks, pimps
Power house end PGD electrical con-
nection
Tranefonter end switchyard erection
Erection of condenier water supply
and discharge structure
treatment facility
and lighting
H 1
m •
H
i •
J
J
A S
s-
0
i •
^
-------
0 Laborers
0 Millwrights
0 Pipe fitters
Because the domestic construction industry is in a
slump, an increase in construction activity could be manned
4
initially by those building tradesmen currently unemployed.
Short-term growth requirements for labor could be met with
few problems in most regions, except for highly skilled
mechanical craftsmen (including welders). As of mid-summer
1977, the following selected areas reported existing or
anticipated shortages of skilled craftsmen:
Location Craftsmen
Denver, Colorado Carpenters
Ironworkers
Detroit, Michigan Boilermakers
Pipe fitters
Boston, Massachusetts Electricians
Missouri and Nebraska Boilermakers
Pipe fitters
Raleigh, North Carolina Carpenters
The South's growing influx of people is expected to increase
industrial construction activity and, thus, the demand on
the available manpower in that area of the country.
A selected number of large national power plant con-
tractors that were contacted indicated that a shortage of
skilled craftsmen in all disciplines is possible, indeed
4-6
-------
probable. Unskilled laborers will be plentiful, but it
takes several years of training to acquire the various
skills required for power plant construction. The more
remote an area is from high-population centers, the more
acute the anticipated shortage.
The increasing demand for craftsmen in power plant
construction could possibly be met by the following course
of action:
1. Expansion of apprenticeship programs - Over the
past 20 years, apprenticeship programs have been
the major means of increasing the supply of con-
struction workers. In times of high construction
activity, apprenticeship programs have been ex-
panded and other supplemental training programs
initiated and accepted by local unions.
2. Training nonconstruction work forces for use in
industrial construction - If energy-related
construction schedules were to cause the demand
for craftsmen to greatly exceed the available
supply, high schools, vocational schools, and
community colleges would have to be contacted to
take the initial step in training nonconstruction
personnel.
3. Attracting workers to more remote areas - The
establishment of good housing, camp facilities,
and trailer parks with hookups for utilities would
be essential to attract workers for projects
located in more remote areas.
In summary, it is believed that it would be very dif-
ficult to realize the 10 percent annual increase in crafts-
men necessary for the anticipated construction of energy-
related facilities (including power plants) for any extended
period. The number and location of the facilities planned
4-7
-------
and the impact of their schedules over and above the current
workload will add greatly to some manpower problems already
being experienced.
To estimate labor requirements for installing FGD
systems, the manhours required to construct a plant of
known size was used as a basis for determining the devia-
tion in manhours required to increase or decrease the time
of installation. The known FGD system had four scrubbers,
Venturis, and hold tanks, ball mills, limestone storage
tanks, slurry tank, by-pass duct, fans, pumps, sludge pip-
ing, disposal pond, vacuum filter, electrical house, etc.
The scrubbers were rated at 177 m per second (375,000 acfm)
at 149°C (300°F). The known plant was a 550 MW capacity
unit burning coal with the following characteristics: 4
percent sulfur, 20 percent ash, 7 percent moisture, and had
a heating value of 24,500 J/g (10,500 Btu per pound). A
labor estimate was then made to design and construct a plant
with one less scrubber train and also for a plant with one
additional scrubber train. The regulation to be met was
516.5 ng S02/J (1.2 Ib S02/106 Btu). The following equa-
tion was then used to determine the labor relationship for
increasing or decreasing the amount of scrubber capacity:
A = B (-|-)X
where:
4-8
-------
A = Manhours for known plant
B = Manhours estimated for removing or adding one
scrubber train
a = Megawatt capacity of plant "A"
b = Megawatt capacity of plant "B"
The equation was solved for the exponent "x" which was 0.72.
In the case of 90 percent S02 removal and 215.2 ng
SO2/J (0.5 Ib SO2/106 Btu), the gas flow was constant but
other factors varied. Dwell time, liquid to gas ratio,
stochiometry of reactants, etc., were determined and allow-
ances in labor for installing larger equipment or greater
number of modules were made.
Table 4-1 shows the computed manhours using the above
formula. Figure 4-3 presents a graphical interpretation of
the computation. It can be seen from Figure 4-3 that the
manpower differential is insignificant for the alternative
emission standards.
Thus, although alternative NSPS for S02 emissions of
215.2 ng SCU/J (0.5 lb/10 Btu) and 90 percent control would
not significantly impact the demand for power plant construc-
tion forces above the present NSPS of 516.5 ng S02/J (1.2 Ib
,6
still exceed the supply in future years,
S02/10 Btu), the demand for skilled laborers will probably
4-9
-------
Table 4-1. MAN-HOURS REQUIRED TO MEET THE ALTERNATIVE S02 EMISSION STANDARDS
l
H
O
Alternative
SO, emission
standards
51.6 g/108 J
(1.2 lb/106 Btu)
90%
21.5 g/108 J
(0.5 lb/106 Btu)
Capacity, MW
140
485,400
492,100
498,900
200
627,522
636,184
644,975
300
840,262
851,861
863,632
400
1,033,644
1,047,911
1,062,391
500
1,213,797
1,230,551
1,247,555
550
1,300,016
1,317,960
1,336,172
600
1,384,065
1,403,169
1,422,559
700
1,546,530
1,567,876
1,589,542
Alternative
SC>2 emission
standards
51.6 g/108 J
(1.2 lb/106 Btu)
90%
21.5 g/108 J
(0.5 lb/106 Btu)
Capacity, MW
800
1,702,599
1,726,100
1,749,952
900
1,853,285
1,878,866
1,904,829
1000
1,999,345
2,026,942
2,054,950
-------
o
UJ
o-
oo
ce
10
9
8
7
6
5
4
3
2.5
2
1.5
10(
9
8
3
2.5
2
1.5
10'
i r i i i
o
o
215.2 ng S02/J
516.5 ng S02/J (1.2 Ib. S02/MM BTU)
90% S02 REMOVAL
I I
O
LT>
O O O
O LO O
CM CM n
o
o
o
o
LO
c o o o o
O O O O CD
VO 1^ CO CTt O
PLANT CAPACITY, MW
Figure 4-3. Manhours required to meet alternative
emission standards.
4-11
-------
REFERENCES FOR SECTION 4.0
1. Rittenhouse, R.C. New Generating Capacity: Who's
Doing What. In: Power Engineering, Volume 81. Tech-
nical Publishing Company. Harrington, Illinois.
August 1977.
2. Engineering Data. TVA Steam Plants, Supplements Nos. 1
and 2, Technical Monograph No. 55, Volume 3. Tennessee
Valley Authority. Knoxville, Tennessee. June 1963.
3. Personal Communications with Large National Power Plant
Contractors. August 1977.
4. Recession Keeps Cap on Labor Shortages. In: Engineer-
ing News Record. McGraw-Hill, Inc. Highstown, N.J.
June 23, 1977-
5. Ibid.
6. Op. Cit. 3.
7- Availability of Manpower for U.S. Energy Development
Programs. Bechtel Corporation, San Francisco. ERDA
Contract No. E(49-1)-3794. November 1976.
4-12
-------
APPENDIX A
PLANNED COAL-FIRED UNITS THROUGH 1998
A-l
-------
The following tables list the planned coal-fired units
through 1998, their capacities, and planned pollution con-
trol equipment. The following is a key for the abbrevia-
tions used for various types of pollution control devices.
A-2
-------
KEY FOR TABLE A-l.
Sulfur Control - Assign appropriate code from following list:
LSS - Limestone Scrubbers
LMS - Lime Scrubbers
LST - Limestone
LIM - Lime
MOS - Magnesium Oxide Scrubbers
CO - Catalytic Oxidation
WL - WeiIman-Lord
FUL - Low Sulfur Fuel
CB - Combination
LAFS - Lime/Alkaline Fly Ash Scrubbing
ASB - Aqueous Sodium Base Scrubbers
DA - Double Alkali
PNS - Process Not Selected
OTH - Other
HS - High Stack
NA - Not Applicable
SCR - Unknown Type of Scrubber
Particulate Control - Assign appropriate code from following
list:
PNS - Process Not Selected
GRAY - Gravitational or Baffled Chamber
SCTA - Single Cyclone - Conventional Reverse-flow,
Tangential Inlet
SCAX - Single Cyclone - Conventional Reverse-flow,
Axial Inlet
MCTA - Multiple Cyclones - Conventional Reverse-flow,
Tangential Inlet
MCAX - Multiple Cyclones - Conventional Reverse-flow,
Axial Inlet
CYCL - Straight-through-flow Cyclones
IMPE - Impellor Connector
VENT - Wet Collector; Venturi
WETC - Wet Collector; Other
BAGH - Baghouse (Fabric Collector)
OTHE - Other
ELEC - Electrostatic Precipitator
HOTP - Hot Precipitator
COMB - Combined Electrostatic and Mechanical precipitators
NA - Not Applicable
PREC - Unknown Type of Precipitator
DUST - Dust Collector
A-3
-------
U.S. EPA Region I State: Massachusetts
Capacity Coal Percent Planned Control
Year Utili.ty Name Unit Name MW Type Sulfur Part. SO-
1981 Mass. Mun. Wholesale Elec. Unnamed 1 400
-------
U.S. EPA Region II State: New Jersey
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO2
1990 GPU: Jersey Cen. Pow. & Light Gilbert 9 800
-------
U.S. EPA Region II State : New York
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
1982 Power Auth. State of N.Y. MTA-Arthur Kill 1 760 Elec. SCR
1983 N.Y. State Elec. & Gas Cayuga 1 850 Elec. FUL
1985 Niagra Mohawk Power Lake Erie 1 850 -
1987 Niagra Mohawk Power Lake Erie 2 850
-------
U.S. EPA Region ill State: Delaware
Capacity Coal Percent Planned Control
Year UtilJLty Name Unit Name MW Type Sulfur' Part. SO2
1979 Delmarva Power & Light Indian River 4 400 Elec. PNS
-------
U.S. EPA Region I*1 State: Maryland
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
1982 Potomac Elec. Power Dickerson 4 800 Elec.
SCR
>
00
-------
U.S. EPA Region
TI1
State: Pennsylvania
Year Utility Name
i
1977 Ohio Edison
1977 GPU: Penn. Elec. Co.
1980 Ohio Edison
1984 GPU: Penn. Elec. Co.
1987 Penn. Power Co.
1988 Philadelphia Elec.
1990 Philadelphia Elec.
1991 GPU: Metropolitan Edison
1993 Penn. Power Co.
Unit Name
Mansfield 2
Homer City 3
Mansfield 3
Seward 7
Coho 1
Unnamed 1
Unnamed 2
Scottsville 1
Wehrum 1
Capacity Coal Percent Planned Control
SO
MW
835
693
835
800
800
600
600
800
800
Type Sulfur
Bit. 4.7
Bit.
4.7
Part.
Prec.
Elec.
-
*•
LMS
PNS
LMS
-------
U.S. EPA Region III State: West Virginia
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO2
1979 APS/Allegheny Power System Pleasants 1 626 Bit. 4.5 Elec. LMS
1980 AEP: Appalachian Power Project 1301 1 1300
1980 APS: Allegheny Power Sys. Pleasants 2 626 Bit. 4.5 Elec. LMS
1980 AEP: Appalachian Power 1300-4 1300
1984 Allegheny Power Systems Unsited 1 630 - -
1985 Allegheny Power Systems Unsited 2 630
I-1
to
-------
U.S. EPA Region IV
Year Utility Name
1978 S. Co. Alabama Power
1978 Alabama Elec. Coop.
1979 Alabama Elec. Coop.
1981 So. Co. Alabama Power
1982 So. Co. Alabama Power
1983 So. Co. Alabama Power
1984 Alabama Power Co.
1985 Alabama Power Co.
State: Alabama
Unit Name
Miller 1
Tombigbee 2
Tombigbee 3
Miller 2
Miller 3
Miller 4
Unlocated 1
Unlocated 2
Capacity Coal Percent Planned Control
Type Sulfur Part. SO,
MW
718
235
235
718
718
718
881
801
Part.
PNS
Bit. .8-1.5
Bit. .8-1.5
PNS
2
PNS
LSS
LSS
PNS
-------
U.S. EPA Region IV
Year
Utility Name
State: Florida
Unit Name
Capacity Coal Percent Planned Control
MW Type Sulfur Part. S09
>
I
1981 Lakeland, City of
1982 So. Co. Gulf Power Co,
1983 Florida Power Co
1984 So. Co. Gulf Power Co,
1985 Tampa Electric Co.
1985 Florida Power Co
1985 Florida Power Co
1986 Tampa Electric Co.
Plant #3 (Mclntosh) 336
Ellis 1 553
Unsited C 1 600
Ellis 2 553
Beacon Key 1 425
Unsited C 2 600
Unsited C 3 600
Big Bend 4 425
FUL
HOTP PNS
HOTP
PNS
-------
U.S. EPA Region IV State: Georgia
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO-
1978 So. Co. Georgia Power Co. Wansley 2 952 Elec. HS
1981 So. Co. Georgia Power Co. Scherer 1 952 -
1982 So. Co. Georgia Power Co. Scherer 2 952 -
1984 So. Co. Georgia Power Co. Scherer 3 952 - -
1985 So. Co. Georgia Power Co. Scherer 4 952 - -
i
M
LO
-------
U.S. EPA Region IV
Year utility Name
1977 E. Ky. Power Coop
1977 Louisville Gas & Elec.
1979 Big Rivers Elec. Corp.
1980 E. Ky. Power Coop
1980 Louisville Gas & Elec.
1981 Ky. Utilities Co.
1981 Cincinnati Gas & Elec.
1981 Ky. Utilities Co.
1983 Ky. Utilities Co.
1983 Louisville Gas & Elec.
1984 Cincinnati Gas & Elec.
1984 Cincinnati Gas & Elec.
1984 Big Rivers Elec. Corp.
1984 E. Ky. Power Coop
1984 Ky. Utilities Co.
1984 E. Ky. Power Coop
1985 Ky. Utilities Co.
1985 Louisville Gas & Elec.
1987 Louisville Gas & Elec.
1989 liouisville Gas & Elec.
State: Kentucky
Unit Name
H.L. Spurlock 1
Mill Creek 3
Reid 2
H.L. Spurlock 2
Mill Creek 4
Ghent 2
East bend 2
Unsited 1
Unsited P 2
Trimble County 1
East Bend 1
East Bend 3
Reid 3
Unsited 2
Ghent 3
Unsited 1
Unsited 4
Trimble County 2
Trimble County 3
Trimble County 4
Capacity Coal Percent Planned Control
MW
300
425
200
500
495
500
600
500
500
495
600
600
200
500
500
500
650
495
675
675
Type Sulfur
Bit. 3.5-4.0
Bit. 3.5-4.0
Part.
HOTP
HOTP
Prec.
HOTP
HOTP
S02
FUL
LMS
LMS
PNS
LMS
FUL
PNS
-------
U.S. EPA Region IV State: Mississippi
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO2
1977 So. Co. Mississippi Power Co. Jackson County 1 548 Elec. HS
1978 So. Miss. Elec. Power Assn. Morrow 1 203 1.0 - LSS
1978 So. Miss. Elec. Power Assn. Morrow 2 203 1.0 - LSS
1980 So. Co. Miss. Power Co. Jackson County 2 548 Elec. HS
1985 Mid. So.: Miss. Power & Light Unsited P 1 700
1986 Mid. So.: Miss. Power & Light Unsited P 2 700
1986 Mid. So.: Miss. Power & Light Middle South Coal 7 700
1987 Mid. So.: Miss. Power & Light Middle South Coal 8 700
1987 Mid. So.: Miss. Power & Light Middle South Coal 9 700
1988 Mid. So.: Miss. Power & Light Middle South Coal 10 700
1988 Mid. So.: Miss. Power & Light Middle South Coal 11 700
1988 Mid. So.: Miss. Power & Light Middle South Coal 12 700
1989 Mid. So.: Miss. Power & Light Middle South Coal 13 700
1990 Mid. So.: Miss. Power & Light Middle South Coal 14 700
-------
U.S. EPA Region IV State: North Carolina
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
1980 Carolina Power & Light Roxboro 4 745 Elec. FUL
1983 Carolina Power & Light Mayo 1 720
1985 Carolina Power & Light Mayo 2 720
-------
I
M
'-J
U.S. EPA Region IV
State: South Carolina
Year Utility Name
1977 So. Carolina Public Service
1982 So. Carolina Public Service
1984 So. Carolina Elec. & Gas
1984 So. Caroline Public Service
Unit Name
Winyah 2
Unnamed 1
Unsited P 2
Unnamed 2
Capacity Coal Percent Planned Control
MW Type Sulfur Part. SO,
315
280
500
280
1.0
'2
LSS
-------
U.S. EPA Region
State: Illinois
H
GO
Year Utility Name
1977 Central 111. Public Service
1978 Springfield, City of
1978 Illinois Power Co.
1978 So. 111. Power Coop.
1978 Cen. 111. Light Co.
1981 Central 111. Public Service
1981 Western 111. Power Coop
1982 Central 111. Light
1984 Central 111. Public Service
1984 Commonwealth Edison
1984 Commonwealth Edison
1984 Western 111. Power Coop
1985 Commonwealth Edison
1985 Commonwealth Edison
1986 Central 111. Light
1986 Springfield, City of
1990 Central 111. Light
Unit Name
Newton 1
Dallman 3
Havana 6
Marion 4
Duck Creek #1 B
Newton 2
Unsited 1
Duck Creek 2
Newton 3
Unsited P 1
Unsited P 2
Unsited 2
Unsited P 3
Unsited P 4
Duck Creek 3
Unnamed 1
Duck Creek 4
Capacity Coal Percent Planned Control
MW Type Sulfur Part. SO.
600
192
450
173
300
550
20
400
550
550
550
20
550
550
600
203
600
Bit. 2.8-3.2 Elec.
'2
D.A.
HOTP
Bit. 4.5-5.0
Bit. 2.5-3.0
LSS
LSS
Bit. 2.5-3.0 Elec.
LSS
-------
U.S. EPA Region
State: Indiana
Year Utility Name
1977 Indianapolis Power & Light
1978 Public Service Co. Of Ind.
1979 Public Service Co. of Ind.
1979 So. Indiana Gas & Elec.
1979 No. Indiana Public Service
1981 Hoosier Energy
1981 Hoosier Energy
1982 Indianapolis Power & Light
1984 So. Indiana Gas & Elec.
1985 Indianapolis Power & Light
1985 Richmond Power & Light
1987 Indianapolis Power & Light
Unit Name
Petersburg 3
Gibson 3
Gibson 4
A.B. Brown 1
R.M. Schahfer 15
Merom 2
Merom 1
Petersburg
A.B. Brown 2
Unsited 1
Whitewater Valley 3
Unsited 2
Capacity Coal Percent Planned Control
SO,
MW
532
668
668
265
556
490
490
532
350
650
100
650
Type
Bit.
Bit.
Bit.
Bit.
Bit.
3.0-3.5
3.3
3.3
3.75
3.5
Part.
Elec.
Prec.
2
LSS
PNS
PNS
DA
Elec.
LSS
-------
U.S. EPA Region V
State: Michigan
Year Utility Name
1978 Upper Peninsula Gen.
1978 Upper Peninsula Gen.
1978 Upper Peninsula Power
1979 Upper Peninsula Gen.
1979 Upper Peninsula Power
1980 Consumers Power Co.
1980 Maquette, City of
•p 1980 Upper Peninsula Power
o '1981 Grand Haven Board of Light
and Power
1982 Upper Peninsula Power Co.
1982 Detroit Edison
1982 Coldwater, City of
1983 Consumers Power Co.
1983 Detroit Edison
1984 Upper Peninsula Power
1984 Consumers Power Co.
1986 Lansing, City of
Unit Name
Presque Isle 7
Presque Isle 8
Unsited 1
Presque Isle 9
Unsited 2
J.H. Campbell 3
Shiras 3
Unsited 3
Island 3
Undesignated
Belle River 1
Coldwater 7
J.H. Campbell 4
Belle River 2
Unsited 4
Unsited
Erickson 2
Capacity Coal Percent Planned Control
MW
80
80
80
80
80
800
43
80
20
90
697
20
800
697
80
800
160
Type Sulfur Part.
SO.
Elec.
FUL
Elec.
FUL
Elec.
FUL
-------
U.S. EPA Region V
State: Minnesota
Year Utility Name
1977 Northern States Power Co.
1980 Austin Utilities
1980 Minnesota Power and Light
1981 Northern States Power
1983 New. Ulm. Pub. Util. Conun.
1983 Northern States Power
1984 Minn. Power and Light
Unit Name
Sherburne 2
North East Sta. 2
Clay Boswell 4
Sherburne Co. 3
New. Ulm. 6
Sherburne Co. 4
Floodwood
Capacity Coal Percent Planned Control
MW
720
44
555
860
40
680
800
Type
Bit.
Bit.
Bit.
Bit.
Sulfur
0.8
0.8
0.8
.8
Part. S02
WETC LSS
- -
PNS
PNS
-
PNS
i
60
-------
U.S. EPA Region
V
State: Ohio
to
'to
Year Utility Name
1977 Cardinal Operating Co.
1978 Cincinnat Gas and Elec.
1978 Columbus and S. Ohio Elec.
1981 Columbus and S. Ohio Elec.
1982 Dayton Power and Light
1983 Columbus and S. Ohio Elec.
1985 Dayton Power and Light
1985 Columbus and S. Ohio Elec.
1985 Dayton Power and Light
1987 Columbus and S. Ohio Elec.
1989 Columbus and S. Ohio Elec.
Unit Name
Cardinal 3
Miami Fort 8
Conesville 6
Poston 5
Killen Sta. 2
Poston 6
Killen Sta. 1
Unsited P 1
Site C 2
Newbury 1
Newbury 2
Capacity Coal Percent Planned Control
MW
615
500
403
403
661
403
661
375
375
400
600
Type Sulfur
Bit. 4.5-4.9
Bit. 2.5
Part.
Elec.
Elec.
Elec.
Elec.
Elec.
S09
£•
PNS
LMS
CB
FUL
CB
FUL
-------
U.S. EPA Region
V
State:
Wisconsin
Year Utility Name
1978 Wisconsin Power and Light
1979 Dairyland Power Coop
1980 Wis. Elec. Power
1981 Wisconsin Public Service
1982 Wisconsin Power and Light
1982 Wisconsin Power and Light
Unit Name
Columbia 2
Alma 6
Pleasant Prarie 1
Weston 3
Edgewater 5
Pleasant Prarie 2
Capacity Coal Percent Planned Control
MW Type Sulfur Part. S00
512
350
617
350
400
617
Elec.
FUL
HOTP
PNS
NJ
U)
-------
U.S. EPA Region VI State; Arkansas
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
1978 Cen. and S.W. Southwestern
Electric Power Flint Creek 511 Elec. FUL
1980 Mid. So. Ark. Power and Light White Bluff 1 700 Elec. FUL
1981 Mid. So. Ark. Power and Light White Bluff 2 700 Elec. FUL
1983 Mid. So. Ark. Power and Light White Bluff 3 700
1983 Mid. So. Ark. Power and Light Arkansas Coal 1 700
1985 Mid. So. Ark. Power and Light White Bluff 4 700 -
1985 Mid. So. Ark. Power and Light Arkansas Coal 2 700
10
-------
U.S. EPA Region
VI
State: Louisiana
Ul
Year Utility Name
1977 Houma Light and Water
1979 Monroe Util. Comm.
1979 Cajun Elec. Power Coop.
1980 Cajun Elec. Power Coop.
1980 Cen. La. Elec. Co.
1983 Mid. So. La. Power and Light
1984 Mid. So. La. Power and Light
1985 Mid. So. La. Power and Light
1985 Cajun Elec. Power Coop.
1985 Gulf State Utilities
1986 Mid. So. La. Power and Light
1986 Central La. Elec. Co.
1986 Gulf State Utilities
Unit Name
Houma 16
Monroe 14
Big Cajun 2 1
Big Cajun 2 2
Rhodemacher 2
Unsited P 1
P 2
P 3
Big Cajun 2 3
R.S. Nelson 5
Unsited P 4
Rhodemacher 3
R.S. Nelson 6
Capacity Coal Percent Planned Control
MW
48
100
540
540
530
700
700
700
540
615
700
530
615
Type Sulfur Part.
SO.
Elec.
FUL
OTH
CB
-------
U.S. EPA Region VI
State: Oklahoma
Year Utility Name
1977 Oklahoma Gas and Elec.
1977 Ponca City
1978 Oklahoma Gas and Elec.
1979 Oklahoma Gas and Elec.
1979 Cen. S.W. Pub. Serv of Okl.
1980 Oklahoma Gas and Elec.
1980 Cen. S.W. Pub. Serv. of Okl,
> 1982 Oklahoma Gas and Elec.
to
|<3S 1983 Oklahoma Gas and Elec.
1983 Oklahoma Gas and Elec.
1984 Oklahoma Gas and Elec.
1984 Oklahoma Gas and Elec*
1984 Cen. S.W. Pub. Serv. of Okl.
Unit Name
Muskogee 4
Ponca Steam 2
Muskogee 5
Sooner 1
Northeastern 3
Sooner 2
Northeastern 4
Unsited P 1
Sooner 3
Unsited P 2
Sooner 4
Unsited P 3
CSR Joint 1
Capacity Coal Percent Planned Control
MW
572
43
572
567
450
567
450
700
515
700
515
700
240
Type Sulfur
Part.
Elec.
Elec.
Elec.
so2
FUL
FUL
FUL
-------
U.S. EPA Region VI
State: New Mexico
Year Utility Name
1977 Pub. Serv. Co. of N. Mexico
1979 Pub. Serv. Co. of N. Mexico
1981 Pub. Serv. Co. of N. Mexico
Unit Name
San Juan 1
San Juan 3
San Juan 4
Capacity Coal Percent Planned Control
Part. S0n
MW Type Sulfur
375 Bit. 0.8
461 Bit. 0.8
461 Bit. 0.8
Elec.
Elec.
WL
SCR
SCR
to
-J
-------
U.S. EPA Region VI
State: Texas
Year Utility Name
1977 San Antonio Pub. Serv.
1977 Cen. S.W. Elec. Power
1977 Tex. Util. Tex. Power & Light
1977 Cen. & S.W. West Tex. Util Co.
1977 San Antonio Pub. Serv.
1978 Tex. Util. Tex. Power & Light
1978 Tex. Util. Tex. Power & Light
> 1979 Houston Lighting and Power
00 1979 S. Tex. Elec. Coop.
1979 S.W. Public Service
1979 Tex. Util. Tex. Power & Light
1979 Lower Colorado River Auth.
1980 Cen. S.W. Cen. Power & Light
Unit Name
J.T. Deely 1
Welsh 1
Martin Lake 1
Fort Phantom 2
J.T. Deely 2
Martin Lake 2
Monticello 3
W.A. Parish 5
Texas Coop 1
Harrington 2
Martin Lake 3
Fayette 1
Coleto Creek 1
Capacity Coal Percent Planned Control
MW
418
528
793
200
418
793
793
734
400
360
793
550
550
Type Sulfur Part. SO,
HOTP FUL
Elec. FUL
Lig. 1.0 - LSS
HOTP FUL
Lig. 1.0 - LSS
Lig. 1.0 Prec. LSS
- -
- -
- -
Lig. 1.0 - LSS
FUL
FUL
-------
U.S. EPA Region VI State: Texas
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO2
1980 Cen. S.W. Cen. Power Co. Welsh 2 528
1980 Lower Colorado River Auth. Fayette 2 550 -
1980 S.W. Public Serv. Co. Harrington 3 360
1980 Texas Mun. Power Pool San Miguel 1 435 Lig.
1980 Texas Mun. Power Pool San Miguel 2 435 Lig.
1981 Houston Lighting and Power W.A. Parish 6 734
1981 Tex. Util. Tex. Power & Light Forest Grove 1 793 Lig.
J> 1981 Houston Lighting and Power W.A. Parish 7 750
Ni
^ 1981 S. Tex. Elec. Coop. Texas Coop 2 400
1982 Tex. Util. Tex. Power & Light Martin Lake 4 797 Lig. 1.0 - LSS
1982 Tex. Power and Light Sandow 4 575 Lig. - LSS
1982 Tex. Mun. Power Pool TPPI 1 (Bryan) 400 Lig.
1982 Cen. & S.W.: S.W. Elec. Welsh 3 528
Power Co.
1982 Houston Lighting and Power W.A. Parish 8 750
1982 S.W. Public Service South Plains 475
1982 Cen. fi, S.W.: W. Tex. Util Co. Unsited P 1 250
1983 Tex. Util.: Tex. Pwr. 5. Light Twin Oak 1 793 Lig. - FUL
-------
U.S. EPA Region VI State: Texas
j Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO2
1983 Tex. Mun. Pwr. Pool TPPI 2 (Bryan) 400 Lig.
1983 Houston Lighting and Power Unsited P 1 750
1983 San Antonio Pub. Service Unsited P 1 375
1984 Tex. Util.: Tex. Power & Light Twin Oak 2 793 Lig. - FUL
1984 Tex. Mun. Power Pool TPPI 3 (Bryan) 400 Lig.
1984 S.W. Public Service Co. South Plains 2 475 -
1985 Tex. Util.: Tex. Power & Light Unsited P 1 400
;> 1985 Tex. Util.: Tex. Power & Light Unsited P 2 750
o 1985 Houston Lighting and Power Unsited P 1 750
1985 Houston Lighting and Power Unsited P 2 750
1986 Cen. & S.W.: Cen. Power & Coleto Creek 2 550
Light
-------
U.S. EPA Region
VII
State; Missouri
CO
Year Utility Name
1977 Union Electric Co,
1977 Union Electric Co.
1977 Assoc. Electric Coop.
1980 K.C. Power & Light
1981 Assoc. Electric Coop.
1982 Springfield Utilities
1984 Empire District Electric Co.
1985 Missouri Public Service
1985 Empire District Electric Co,
1994 Empire district Electric Co,
Unit Name
Rush Island 1
Rush Island 2
New Madrid 2
latan 1
Thomas Hill 3
Southwest 2
Asbury 2
Unsited P 1
Energy Center X-3
Energy Center X-5
Capacity Coal Percent Planned Control
MW Type Sulfur Part. SO2
575 Elec.
575
600
726
600
200
300
100
300
300
Elec.
Elec.
PNS
PNS
PNS
PNS
-------
U.S. EPA Region VII
t
Year Utility Name
1977 Interstate Power Co.
1979 Iowa Public Service
1979 Iowa Power and Light
1981 Iowa Southern Utilities
State: Iowa
Unit Name
Lansing 4
George Neal 4
Council Bluffs 3
Ottumwa 1
Capacity Coal Percent Planned Control
MW
260
576
650
675
Type Sulfur Part. SO.
Elec. FUL
Elec. FUL
PNS PNS
u>
NJ
-------
U.S. EPA Region VII State: Kansas
• Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. SO9
1977 K.C. Power & Light La Cygne 2 686 Elec. FUL
1978 Kansas Power & Light Jeffrey 1 720 Bit. 0.3 Elec. LSS
1979 K.C. Board of Public Utilities Nearman Creek 1 250
1980 Kansas Power & Light Jeffrey 2 680 Bit. 0.3 Elec. LSS
1982 Sunflower Electric Coop Sunflower S-3 256
1982 K.C. Board of Public Utilities Nearman Creek 2 300
1983 Kansas Power & Light Jeffrey 3 680
1984 Kansas Power & Light Jeffrey 4 680
CO
U»
-------
U.S. EPA Region VII State: Nebraska
Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
i finn Elec. FUL
1978 Nebraska Public Power District Gentleman 1
, CTC ' Elec. PNS
1979 Omaha Public Power District Nebraska City 1 575
1981 Nebraska Public Power District Gentleman 2 600
1981 Grand Island Water & Light Unsited 1 I47
CO
-------
U.S. EPA Region VIII
State: Colorado
en
Year Utility Name
1978 Colorado - Ute Electric Assn.
1979 Colorado - Ute Electric Assn.
1979 Public Service of Colorado
1980 City of Colorado Springs
1981 Public Service of Colorado
1981 Colorado - Ute Electric Assn.
1982 Colorado - Ute Electric Assn,
1982 Public Service of Colorado
1983 Public-Service of Colorado
1983 Public Service of Colorado
1985 Public Service of Colorado
1985 Colorado Springs, City of
Unit Name
Craig 1
Craig 2
Pawnee 1
Ray D. Nixon 1
Pawnee 2
Craig 3
Craig 4 •
Major Joint Cap. 1
Southeastern 1
Major Joint Cap. 2
Southeastern 2
Ray D. Nixon 2
Capacity Coal Percent Planned Control
Part. SO.
MW
380
380
500
200
500
380
380
380
500
380
500
200
Type Sulfur
Bit. 0.45 HOTP
Bit. 0.45 HOTP
'2
LMS
LMS
-------
U.S. EPA Region VIII
States Montana
Year Utility Name
1980 Montana Power Co.
1981 Montana Power Co.
Unit Name
Colstrip 3
Colstrip 4
Capacity Coal Percent Planned Control
MW Type Sulfur Part. S02
LAPS
700
700
Bit.
Bit.
0.56
0.7
VENT
VENT
LAPS
UJ
-------
U.S. EPA Region VIII
State: North Dakota
Year Utility Name
1977 Minnkota Power Coop.
1977 Minnkota Power Coop.
1978 Cooperative Power Assn.
1979 Cooperative Power Assn.
1980 Basin Electric Power Coop.
1980 Basin Electric Power Coop.
1981 Otter Tail Power Co.
1981 Basin Electric Power Coop.
1982 Montana- - Dakota Utility
1983 Basin Electric Power Coop.
1983 Basin Electric Power Coop.
Unit Name
Milton R. Young 2
Square Butte 2
Coal Creek 1
Coal Creek 2
Missouri Basin 1
Missouri Basin 2
Coyote P 1
Antelope Valley 1
Coyote 2
Antelope Valley 2
Missouri Basin 3
Capacity Coal Percent Planned Control
MW
454
430
500
500
550
550
440
440
410
440
550
Type
Lig.
Lig.
Lig.
Lig.
Lig.
Lig.
Lig.
Lig.
Lig.
Sulfur
0.7
0.63
0.63
0.8
0.8
0.9
1.0
1.0
0.8
Part. S02
Elec. LAPS
Elec. LMS
Elec. LMS
LSS
LSS
- -
LAPS
-
PNS
-------
U.S. EPA Region VIII
State: Utah
Year Utility Name
1977 Utah Power & Light
1978 Utah Power & Light
1980 Utah Power & Light
1982 Nevada Power Co.
1983 Nevada Power Co.
Unit Name
Huntington Canyon 1 415
Emery 1 400
Emery 2 400
Warner Valley 1 250
Warner Valley 2 250
Capacity Coal Percent Planned Control
MW Type Sulfur Part. SO,
Type Sulfur Part.
Bit. 0.5
Bit. 0.5 Elec.
Elec.
'2
LMS
LSS
PNS
PNS
PNS
00
-------
U.S. EPA Region VIII
State: Wyoming
Year Utility Name
1978 Pacific Power & Light
1979 Pacific Power & Light
1980 Tri State Generating & Trans.
1982 Tri State Generating & Trans,
1982 Utah Power & Light
1983 Pacific Power & Light
1983 Tri State Generating & Trans,
1984 Utah Power & Light
Unit Name
Wyodak 1
Jim Bridger 4
Laramie River 1
Laramie River 2
Naughton 4
Wyodak 2
Laramie River 3
Naughton 5
Capacity Coal Percent Planned Control
MW
330
500
550
550
400
330
550
400
Type Sulfur
Bit.
0.56
Part.
Elec.
Elec.
Elec.
so2
PNS
WL
PNS
to
-------
U.S. EPA Region
IX
State: Arizona
, *-
o
Year Utility Name
1978 Arizona Public Service
1978 Arizona Electric Power Coop.
1978 Arizona Electric Power Coop.
1979 Arizona Electric Power Coop.
1979 Salt River Project
1979 Arizona Electric Power Coop.
1979 Arizona Public Service
1980 Salt River Project
1980 Arizona Public Service
1983 Arizona Public Service
1985 Tucson Gas & Electric
1985 Salt River Project
1993 Salt River Project
Unit Name
Choila 2
Apache Station 4
Apache Station 2
Apache Station 3
Coronado 1
Apache Station 5
Choila 3
Coronado 2
Choila 4
Choila 5
Springerville 1
Unsited 1
Coronado 3
Capacity Coal Percent Planned Control
SO.
MW
250
175
175
175
350
175
250
350
350
350
330
250
350
Type Sulfur Part.
Bit. 0.44-1.0
Bit. 0.5-0.8
Bit. 0.5-0.8
Bit. 1.0 PNS
Bit.
1.0
PNS
PNS
'2
LSS
LSS
LSS
PNS
LSS
PNS
Bit.
1.0
LSS
-------
U.S. EPA Region IX State: California
; Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
1983 Pacific Gas & Elec. Unsited C i 800
£>.
I-1
-------
U.S. EPA Region IX
State: Nevada
Year Utility Name
1982 Sierra Pacific Power
1983 Sierra Pacific Power
1985 L.A. Dept. of Water & Power
1985 Nevada Power
1986 L.A. Dept. of Water & Power
1986 Nevada Power
1987 L.A. Dept. of Water & Power
P 1987 Nevada Power
£ 1988 Nevada -Power
1988 L.A. Dept. of Water & Power
Unit Name
Valmy P 1
Valmy P 2
Intermountain 1
Allen 1
Intermountain 2
Allen 2
Intermountain 3
Allen 3
Allen 4
Intermountain 4
Capacity Coal Percent Planned Control
MW
250
250
750
500
750
500
750
500
500
750
Type Sulfur Part.
SO.
OTH
OTH
SCR
SCR
PNS
-------
U.S. EPA Region X State : Oregon
\ Capacity Coal Percent Planned Control
Year Utility Name Unit Name MW Type Sulfur Part. S02
1980 Portland General Elec. Boardman Coal 1 550
-------
APPENDIX B
ASSUMPTIONS USED IN CALCULATING FGD SYSTEM
COMPONENT DEMAND
B-l
-------
Assumptions Used In Calculating the Demand for FGD System
Components
1. The following characteristics of coal were used in
the calculations;
Characteristics Low-sulfur coal High-sulfur coal
Sulfur content, % 0.8 3.5
Heat value, Btu/lb 8500 12,000
2. Low-sulfur coal is expected to be used at the
following locations:
EPA Region State
VI New Mexico
Texas
VIII Colorado
Montana
North Dakota
Utah
Wyoming
Arizona
IX Nevada
3. A wet limestone nonregenerative system will be
used for the FGD effort to be constructed on a new
plant; retrofit systems are not considered.
4. Power plants due to come on line in 1977 and 1978
have, of necessity, already made commitments to
manufacturers and are not included in this report.
5. The additional capacity of the power plants
through year 2000 was projected by
a. Estimating the additional capacity per year.
b. Using the capacity of known coal-fired addi-
tions for the years 1979 to 1987; by using
the difference between the coal-fired addi-
tions predicted by the FPC and that of the
known additions for the years 1988 to 2000.
B-2
-------
6. The additional demand for FGD system components
was calculated in the following manner:
a. Standard engineering calculations were used
for the period 1979 to 1987.
b. For the period 1988 to 2000, calculations
were based on the assumptions that a typical
power plant (500-MW) burning 3.5 percent
sulfur coal requires
0 Two 22,681 kg/hr (25 ton/yr) ball mills
0 Four 198 m3/s (420,000 acfm) scrubbers
0 Eleven 6102&/s (10,000 gpm) pumps
0 One 54.6 m (588 ft2) vacuum filter
0 Two clarifiers with diameters of 31.3 M
(103 ft) each
0 Four 198 m3/s (420,000 acfm) fans
B-3
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-033
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE Effects of Alter nail ve New Source Per-
formance Standards on Flue Gas Desulfurization Sys-
tem Supply and Demand
5. REPORT DATE
March 1978
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Vijay P. Patel and L. Gibbs
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2603, Task 1
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development*
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PER
Task Final; 4-12/77
ERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES (*) Cosponsored by EPA's Office of Air and Waste Management.
Project officers are J.E.Williams (IERL-RTP, 919/541-2483) and K.R.Durkee
(OAQPS/ESED. 919/541-5301).
is. ABSTRACT
report discusses the capabilities of equipment vendors to supply and
install the quantity of flue gas desulfurization systems required to meet alternative
standards for coal-fired steam generators. It analyzes limiting factors affecting
supply capabilities (such as the availability of components, equipment, and skilled
labor). It discusses guarantees that equipment vendors have made and are willing to
make, and the penalties that they are willing to be assessed.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Performance Standards
Coal
Boilers
Air Pollution Control
Stationary Sources
New Source Perfor-
mance Standards
13B
21B
07A,07D
21D
13A
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
112
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
B-4
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