United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 277t t
Research and Development
EPA/600/S7-90/015 Jan. 1991
EPA Project Summary
Costs for Advanced Coal
Combustion Technologies
J.A. Martinez, G.C. Snow, and M. Maibodi
This project was undertaken to
evaluate the development status of ad-
vanced coal combustion technologies
and to prepare performance and eco-
nomic models for their application to
electric utility plants. The technologies
addressed were atmospheric fluidized
bed combustion (AFBC), pressurized
fluidized bed combustion (PFBC), and
integrated gasification combined cycle
(IGCC). The development status was also
reviewed for pulverized coal-fired boil-
ers incorporating supercritical steam
cycles. Although advanced combustion
technologies are attractive due to de-
creased SO2 and NOX emission charac-
teristics and potentially higher
generating efficiencies, full commercial
readiness does not appear feasible be-
fore the mid to late 1990s. Capital cost
estimates for a new plant at 500-MW
ranged from$1,250 to $1,910/kW(in1988
dollars) for the advanced technologies
and from $1,380 to $1,810/kW for the
conventional systems. Capital cost esti-
mates for PFBC (turbocharged cycle)
and conventional plants with add-on SO2
and NOx controls were within 4 % of the
median cost ($1,580/kW) of all of tech-
nologies evaluated. AFBC costs aver-
aged 12% less than this median while
integrated gasification combined cycle
costs averaged 11% above the median.
Potential capital cost savings for repow-
erlng an existing plant versus construct-
Inganew facility at the same final capacity
are between 10 and 40%.
This Project Summary was developed
by EPA's Air and Energy Engineering
Research Laboratory, Research Triangle
Park, NC, to announce key findings of
the research project that Is fully docu-
mented In a separata report of the same
title (see Project Report ordering infor-
mation at back.)
Introduction
This report documents performance and
economic models developed for advanced
coal combustion and conventional power
generation technologies. The models de-
veloped in this report are simplified to mini-
mized computational time and data
requirements, but they incorporate impor-
tant parametersthat have significant impacts
on performance and costs. The models are
based on recent information available from
Electric Power Research Institute (EPRI)
reports and other published sources. The
sources of information are referenced in the
report.
The advanced power generation tech-
nologies covered in the report include: at-
mospheric fluidized bed combustion
(AFBC), pressurized fluidized bed combus-
tion (PFBC), and integrated gasification
combined cycle (IGCC). These technolo-
gies incorporate processes for removal of
sulfur dioxide (SO2), nitrogen oxides (NOX),
and particulate matter (PM).
The conventional power generation
technology covered in the report is pulver-
ized coal-fired (PC) plants. The economic
model developed in this study for PC plants
excludes the costs for flue gas desulfuriza-
tion (FGD) and selective catalytic reduction
(SCR) NOx controls. The costs for these
control systems were drawn from other
models and were combined with the PC
base plant costs. The user has the option to
include or exclude the cost of a baghouse
for PM control. As such, the user of the
model can add the desired control options
to the uncontrolled PC boiler and compare
the cost of a PC plant with those estimated
forthe advanced coal combustion technolo-
gies.
Printed on Recycled Paper
-------
Table 1 describes the technologies cov-
ered in this study. The FGD configuration
described has been considered as the EPA
"base case" system. The SCR system is a
hot-side, high-ash configuration, located up-
stream of the air heater. The nominal NOX
removal efficiency for this system is esti-
mated at 75%. The advanced technologies—
AFBC, PFBC, and IGCC—are near-term or
first generation versions of each system.
Both the AFBC and PFBC combustors are of
the bubblingbeddesign.ThePFBC reference
plant is aturbocharged design and does not
include a gas turbine generator for com-
bined cycle electricity production. The IGCC
reference plant utilizes an oxygen-blown,
entrained-f low gasif ier with cold gas cleanup
prior to combustion turbine firing.
Although both conventional and ad-
vanced technologies have been evaluated
in this study, direct economic comparisons
are difficult forseveral reasons. First, a tech-
nology such as FGD is mature and fully
commercialized with many vendors compet-
ing in the marketplace. Therefore, cost esti-
mates for FGD systems are developed from
adatabase of actual installation and operat-
ing costs. In contrast, the advanced tech-
nologies, particularly PFBC and IGCC, are in
relatively early stages of development with
commercial service unlikely before the mid
to late"! 990s. Cost estimates made during
such early stages of development can sig-
nificantly underpredict actual costs for the
first commercial version of a new technol-
ogy. However, costs for subsequent com-
mercial installations often decline as
improved versions of the technology are
built. Second, the cost effectiveness (cost
to remove a given quantity of pollutant) is
much easierto define for an add-on control
such as FGD or SCR than for integrated
technologies, to varying degrees, pro-
cesses for removal of SO2, NOX> and PM
are intrinsic to the basic designs of the
advanced generating technologies. Finally,
advanced technologies may offer signifi-
cant capacity increases and increased fuels
flexibility wheri retrofitting or repowering
existing plants. These features also need to
be considered when comparing technolo-
gies. ,
For each technology covered, the fol-
lowing information is presented:
description of the technology,
reference plant description defining
the coverage of process equipment
included in the cost models,
system performance models relating
to emission reduction,
capital cost model,
operating and maintenance cost
model, and
• key technical issues discussion -
dealing with technical factors that will
affect further development and use of
the technology.
Summary and Results
Algorithms [for the performance and
economic models are presented in the re-
port. These algorithms have also been in-
corporated in Version 4.0 of the Integrated
Air Pollution Control System (IAPCS) cost
model. Version 4.0 of IAPCS was used to
generate the cost presented herein.
Example cost estimates are presented
for newly constructed AFBC, PFBC, and
IGCC plants as well as for new PC plants
equipped with wet limestone FGD and SCR
systems. These capital and operating cost
estimates are based on early or near-term
versions of the advanced technologies. As
the advanced technologies are developed
further, revised capital cost estimates may
either increase or decrease. Revised an-
nual operating cost estimates, however are
likely to decrease as more efficient versions
of the technologies are evaluated. Cost
estimates are also presented for repower-
ing existing PC plants with advanced coal
combustion technologies. To compare the
repowering approaches, cost estimates are
presented for life extension and retrofit of
existing PC plants. Equipment refurbish-
ment and upgrade costs associated with a
20-year life extension were combined with
retrofit FGD and SCR costs for existing
plants.
Status of Advanced Coal Combustion
Technologies
Advanced coal combustion technolo-
gies have received considerable attention
because of decreased SO2 and NOX emis-
sions characteristics, potential improve-
ments in overall generating efficiency, and
the ability to increase generating capacity
when repowering existing stations. Table 2
compares net plant generating efficiencies
which are available currently or on a
near-term basis against projected efficiency
for mature or second generation configura-
tions for the technologies considered. Cur-
Tablo 1. General Descriptions of the Technologies Considered
Technology Process Description
FGD Forced oxidation wet limestone with in-line 'steam reheat; spray tower type absorber modules with liquid/
gas ratio of 80 gpm/1000 acfm*; three modules are assumed for 200 andJSOO MWe plants, and four
modules are assumed for 1000 MWe plants; sludge disposal is by landfill.'
SCR Hot-side location between economizer and air heater; economizer bypass to maintain nominal catalyst
temperature of 700 °F at low load operation; air heater modifications to resist impact of ammonia salt
formation; vertical reactor vessels with fly ash hopper and handling systems; complete catalyst replace-
ment at 3-year intervals.
AFBC Bubbling bed combustor; limestone sorbent; overbed coal and limestone feed system; dry waste disposal
by landfill.
PFBC Bubbling bed combustor; dolomite sorbent; underbed coal and sorbent feed system; turbocharged cycle;
dry waste disposal by landfill.
IGCC Texaco entrained flow gasif ier; oxygen blown; radiative and convective raw gas cooler; cold gas cleanup
by Selexol add gas removal; Glaus sulfur recovery; SCOT tail gas treatment; turbine firing temperature
2200 °F.
'Readers more familiar with metric units may use the factors at the end of this Summary to convert to that system.
-------
Table 2. Net Plant Generating Efficiencies1'
Technology
Current or Near-Term Efficiency
Mature Technology
Projected Efficiency %
Conventional PC/FGD
Supercritical PC/FGD
AFBC
PFBC (Turbocharged Cycle)
PFBC (Combined Cycle)
IGCC
33-35
39
34
33
34
34
35
41
35
35
45
40
*Net plant efficiency is the inverse of net plant heat rate times the conversion factor, 3413Btu/kWh.
rent or near-term achievable efficiencies for
advanced technologies show no improve-
ment overconventional PCplantswith FGD
systems. However, projected efficiencies
for mature (or second generation) versions
of IGCC and PFBC are about 14-29% higher,
respectively, than that achievable for the
conventional system. Supercritical PC
plants operate at steam cycle pressures
above the critical pressure of water, but
utilize an essentially conventional (low NOx)
PC firing system and FGD scrubbers.
Supercritical plants have been available in
the U.S. since the late 1950s. However, due
to materials-related reliability problems in
the boiler superheater and reheater sur-
faces, main steam lines, and high pressure
turbine valves, nozzle chambers, and cas-
ings, supercritical plants have not been fully
commercialized. Nearterm net plant gener-
ating efficiencies of about 39% are based
on the performance levels of the pre-NSPS
Philadelphia Electric Company Eddystone
No. 1 (Eddystone, Pennsylvania) and The
Ohio Power Company Philo No. 6 (near
Zanesville, Ohio) plants in the late 1950s
and early 1960s. Proposed supercritical
plant designs have efficiencies of about
41% or about 17-24% higher than current
subcritical designs.
Advanced coal combustion technolo-
gies may also be used to repower existing
steam electric plants. Repowering consists
of substantial modification or replacement
of the existing boiler. Where economically
feasible, the existing steam turbine genera-
tor and the remaining balance-of-plant
equipment is reused. In the combined cycle
configurations of PFBC and IGCC, addi-
tional electricity is produced by a new gas
turbine generator. Repowering cannot only
provide a plant service life extension, but
can also result in significant capacity in-
creases without developing new greenfield
power plant sites.
At their current status of development,
however, advanced technologies may not
be fully available for utility application until
the mid to late 1990s. Significantly technical
issues must be overcome before these
technologies will fully penetrate the utility
market. These issues include materials
limitations, process control, load following
ability, hot gas cleanup, and secondary
environmental impacts. Table 3 lists some
of the major issues and provides time frame
estimates of commercial availability for the
technologies. The development issues and
availability status of the advanced technolo-
gies are more fully discussed in the main
report.
General Costing Assumptions
Assumptions used to estimate both con-
stant and current 1988 dollars are shown in
Table 4. EPRI's general cost procedures
were used to incorporate inflation, cost of
capital, and levelization of future expenses.
Cost adjustments to account for the techni-
cal issues discussed above affecting further
development and future use of each tech-
nology are not presented in this cost analy-
sis.
Process contingencies are used to ad-
dress the uncertainty associated with de-
veloping technologies while project
contingencies reflect the level of detail in
estimating overall project cost. In develop-
ing detailed cost estimates for a technology,
process contingencies are determined for
each process area or section according to
its development and commercialization sta-
tus. For example, in an IGCC plant, the
steam turbine generator section is typically
assigned a process contingency at or near
Table 3. Development and Availability Status of Advanced Coal Combustion Technologies
Estimated Commercial Availability
Technology
Key Technical Issues
First Generation
Fully Mature
Second Generation
Supercritical s.uPerheater materials limita-
PC/FGD Uons
Main steam line creep and
expansion failure
Steam turbine erosion, creep,
and expansion failure
Load following and control
Plant trip critical pressure
letdown
1962
1993
AFBC
(Bubbling
Bed)
PFBC
IGCC
Modest combustion efficiency
Poor limestone utilization
Part-load efficiency and
emissions control
Solid waste production
Potential N2O emissions
Erosion-corrosion of in-
bad heat transfer
surfaces
Load following and
control
Solid waste production
Alkali and halogen
emissions
Potential N2O emis-
sions
Solid waste production from in-
situ sulfur capture
High temperature S, N, PM, and
alkali removal
High temperature gas turbine
development
1989
1995
1995
2000
1988
1996
-------
Tablo 4. Economic Assumptions Used in Cost Analysis
Current Dollars (1988)
Weighted Cost of Capitol
Inflation Rate
Carrying Charge Factor
Economic Life: 20 years
30 years
Levolization Factor
Economic Life: 20 years
30 years
12.5%
6.0
0.189
0.175
1.57
1.75
(Retrofit,
Repowered Plants)
(New Plants)
Current Dalian (1988)
Weighted Cost of Capital
Inflation Hate
Carrying Charge Factor
Economic Life: 20 years
30 years
Lovolization Factor
Economic Life: 20 years
30 years
6.1%
0%
0.123
0.105
1.00
1.00
(Retrofit,
Repowered Plants)
(New Plants)
Indirect Co»t Case 1
General Facilities 10%
Engineering and Home Office Fees 10%
Process Contingencies 10%
Project Contingencies 30%
Case 2
10%
10%
0%
15%
zero. However, given that hot gas cleanup
systems have generally not progressed from
pilot demonstration scale to full commercial
status, a process contingency within the
range of 20-35% is more appropriateforthis
section. A weighted average of the process
area contingencies can then be expressed
for the technology.
A range of contingency values was used
in the present costing analysis to represent
optimistic as well as conservative estimates.
Weighted average contingencies are shown
in the analyses for each technology rather
than individual process area contingencies.
Contingencies of 0% for process and 15%
for project are appropriate for mature pro-
cesses and detailed project cost estimates.
Contingencies of 30% for project and 10%
for process give more conservative cost
estimates corresponding to increased pro-
cess uncertainties and reduced detail in
project cost estimating, in other work, EPA
has used a 15% contingency factor for the
FGD base case estimate. Contingencies
inherent to the example cost estimates con-
tained in the 1986 Technical Assessment
Guide (TAG) are on the orderof 18-20%for
AFBC and IGCC and are >30% for PFBC.
As more experience is gained in some of
the process areas and with improved project
costing, these factors may be refined. Con-
tingency factors developed by EPRI follow-
ing detailed engineering and risk analyses
currently fall within the range of 15-20% for
AFBC, IGCC, and PFBC. Each technology
in this study has been evaluated using con-
tingency valuos representing both optimis-
tic and conseivative premises.
Table 5 presents coal characteristics
for a midwestern bituminous coal used in
the cost analysis. To be consistent with an
EPRI study of FBC, a coal cost of $2.00 /1C)6
Btu was used for a hypothetical Illinois coal.
(Note: Actual fuel costs may differfrom this
assumed price, thus affecting the relative
economic ranking between the technolo-
gies. Higher fuel costs will have a greater
impact on total annual operating costs for
low efficiency technologies as compared to
technologies with high generating efficien-
cies. Table 6 presents unit costs for esti-
mating operating and maintenance costs.
Annual costs were estimated using a ca-
pacity factor of 0.65. Costs are reported for
technologies firing 2 or 4% sulfur coal.
Table 7 presents design specifications
for acid gas control used to estimate costs
for each technology. For SO, control, 90%
removal is assumed for AFBC, PFBC, and
FGD; 95% removal is assumed for IGCC.
For NO control, a NOX emission limit of
0.6 lb/10* Btu corresponding to the current
New Source Performance Standard (NSPS)
level, is assumed for AFBC plants and PC
plants without SCR. For PC plants with
SCR, the design NOX removal efficiency is
assumed to be 80%, corresponding to an
emission level of 0.12 lb/106 Btu. Measured
NO emissions from a large demonstration
PFBC boiler ranged from 0.15 to 0.5 Ib/
10$ Btu. In this study, an NO emission level
of 0.2 lb/106 Btu is assumed based on con-
ceptual bubbling bed PFBC performance
levels. The NO emission level of 0.27 Ib/
106 Btu for IGCC is based on the use of wet
injection in the gas turbine for complying
with the gas turbine NSPS limit (75 ppm at
15%dryO).
Table 5. Coat Characteristics and Prices Used in the Cost Analysis
Coal Characteristics
Midwestern Bituminous Coal
Sulfur Content, %
Ash Content, %
Carbon Content, %
Heating Value; Btu/lb
Net Heat Rate1 for Conventional Plants
with FGD. Btu/kWh
Net Heat Rate\for Conventional Plants
with FGD and SCR, Btu/kWh'
Net Heat Rate for AFBC, Btu/kWh
Net Heat Rate for PFBC, Btu/kWh
Net Heat Rate for IGCC, Btu/kWh
Coal Price \$/ton
2.0-4.0
16
57.6
10,100
10,060
10,160
10,000
10,278
9,280
40.0
2.00
'Assumes thai SCR will increase the net heat rate by1% over that of conventional plants with FGD.
-------
Table 6. Unit Costs for Estimating Operating and Maintenance Costs (1988 Dollars)
Item Units Value
Operating Labor
Water
Limestone and Dolomite
Waste Disposal
Sulfur
Ammonia
SCR Catalyst
Steam
$/man-hour
$/1000gal
$/ton
$/ton
$/ton
$/ton
$/ton
$/1Os Btu
21.40
0.65
16.30
10
65
150
'• 20,300
7.00
New Plant Costs
Tables 8 and 9 present the capital and
annual costs of new AFBC, PFBC, and
IGCC plants firing 2 and 4% sulfur bitumi-
nous coals, respectively. The costs are re-
ported for 200-, 500-, and 1000-MW plant
sizes.
For comparison with advanced coal
combustion costs, costs are also reported
in Tables 8 and 9 for newly constructed PC
plants with wet limestone FGD and SCR
systems. Costs for new wet limestone FGD
and SCR systems were estimated from the
IAPCS model.The SCR costs are based on
a 3-year catalyst life. Tables 8 and 9 include
operating costs of conventional plants with
baghouses for PM control. Annual costs of
FGD and FGD plus SCR were added to the
new plant costs so that the annual conven-
tional plant cost can be compared directly
with those for advanced coal combustion
technologies.
The cost effectiveness, or unit cost per
ton of acid gas removed is also presented
for each technology in Tables 8 and 9. The
tons of acid gas removed were determined
by, applying advanced technology removal
efficiencies to emissions of NOX and SO2
from an uncontrolled PC plant at given
plantsizes. For integ rated techologies, FBC
and IGCC, it is difficult to separate costs
associated with acid gas control from the
rest of the costs attributed to electrical gen-
eration. To estimate effective costs for acid
gas control for new plants, annual costs
(including annualized capital costs) for the
conventional PC plant exclusive of FGD
and SCR costs systems were subtracted
from annual costs (including annualized
capital costs) for a new AFBC, PFBC, and
IGCC plant at the same plant size. This is
represented by the following equation:
(Effective acid gas control costs)
=(Annual cost for advanced technology)
- (Annual cost for PC plant without FGD
and SCR)
For conventional PC boilers, the cost for
acid gas control is sirhply the annual costs
for FGD and SCR.
Figures 1, 2, and 3 show the capital
costs, annual costs, and unit cost per ton of
acid gas removed from Table 8 as a func-
tion of plant sized for the 2% sulfur coal,
respectively. Only constant 1988 dollar costs
estimates and 30% for project and 10% for
process contingencies are presented in
these figures.
Repowered Plant Costs
Tables 10 and 11 present the capital
and annual costs of repowering AFBC,
PFBC, and IGCC on existing plants firing 2
and 4% sulfur bituminous coals, respec-
tively. These costs are based on repowered
plant final net capacity and are reported for
200-, 500-, and 1000-MW plant sizes.
Whereas plant capacity is assumed to re-
main unchanged for AFBC and turbocharged
PFBC repowering, ft is assumed that IGCC
repowering results in a tripling of net plant
output.Capital costs are based on reuse
and refurbishment factors for each technol-
ogy. They do not however, include the costs
for replacement power during the construc-
tion outage.
For comparison with costs of repower-
ing, costs are also reported in Tables 10
and 11 for life extension of an existing plant
for 20 years of additional operation and
retrofit of add-on wet limestone FGD and
SCR systems and fabric filter PM control.
Retrofit of FGD and SCR systems results in
decreased operating efficiency which may
derate the plant. This analysis assumes
that an FGD retrofit gives a 3% capacity
derate and the addition of an SCR system
gives another 1% derate. The capital cost
of life extension is $214/kW, which is the
average cost reported by EPRI without con-
sidering downtime costs. Costs for wet lime-
stone FGD systems'were estimated from
the IAPCS model. Capital costs for FGD
and SCR systems are based on retrofit
factors of 1.5 and 1.34, respectively, as
shown in Table 7.
Conclusions
Advanced coal combustion technolo-
gies are of interest due to decreased SO2
and NOX emissions characteristics, poten-
tial improvements in overall generating effi-
ciency, and the ability to increases
generating capacity when repowering ex-
isting stations. Existing NSPS emission lim-
its and proposed acid rain regulations are
expected to be met by most AFBC, PFBC,
and IGCC configurations. In addition, pre-
vention of significant deterioration (PSD)
requirements are expected to be satisfied
under repowering scenarios. Projected net
plant generating efficiencies for mature
technology combined cycle configurations
(IGCC and PFBC) are about 14-29% higher
than for conventional PC boilers equipped
with FGD scrubbers. Advanced supercritical
PC/FGD designs have generating efficien-
cies comparable to those of mature IGCC
plants but still about 8-9% below those of
second generation PFBC designs.
At their current status of development,
however, advanced technologies may not
be fully available for utility application until
the mid to late 1990s. Significant technical
issues must be overcome before these
technologies will fully penetrate the utility
market. These issues include materials
limitations, process control, load following
ability, hot gas cleanup, and secondary
environmental impacts.
Capital cost estimates for a new plant at
500-MW ranged from $1,250 to $1,910/kW
for advanced technologies and from $1,390
to $1,810/kW for conventional systems.
Capital cost estimates for PFBC (turbo-
charged cycle) and conventional plants with
add-on SO2 and NOX controls were within
4% of the median cost ($1,580/kW) of all of
technologies evaluated. AFBC costs aver-
aged 12% less than this median while IGCC
costs averaged 11% above the median.
Potential capital cost savings for repower-
ing an existing plant versus constructing a
new facility at the same final capacity are
between 10 and 40%.
Metric Conversion Factors
Readers more familiar with metric units
may use the following factors to convert to
that system:
British Multiplied by
Btu
Btu/lb
cfm
°F
gal.
gpm
Ib/ICf Btu
ton
1.06
2 33
0.000472
5/9fF-32)
0.00379
0.0000633
0.430
907
Yields Metric
kJ
kJ/kg
nf/s
"C
m3
nf/s
Ib/GJ
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Tabla 7. Design Specifications for Acid Gas Control
Design Specifications
Technologies Evaluated'
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
SOa Control:
- SO, Removal %
- SO- Control Method
- Sofoent Type
- Ca/S Ratio
-UG Ratio
- Stoichbmetric Ratio
90
in-situ
limestone
3.1
NA
NA
NA
90
in-situ
dolomite
1.5
NA
NA
NA
95
Selexol Process
Selexol
NAC
NA
NA
NA
90
wet limestone FGD
limestone
NA
80
1.15
1.5
90
wet limestone FGD
limestone
NA
80
1.15
1.5
NO. Control:
- NO, Emissions. Ib/WBtu
-NO, Control Method
-NK.: NO, Ratio
-SCR Space Velocity, 1/hr
- SCR Catalyst Replacement, years
- Retrofit Factor b
0.6
in-situ
NA
NA
NA
NA
0.2
In-situ
NA
NA
I NA
NA
0.27
wet injection
NA
NA
NA
NA
0.12
SCR
0.82
25,000
3
1.34
0.6
NA
NA
NA
NA
NA
AFBC » atmospheric fluidized bed combustion.
PFBC « pressurized fluidized bed combustion.
IGCC = integrated gasification combined cycle.
PC ** pulverized coal-fired plant
FGD « flue gas desulfurization.
SCR « selective catalytic reduction.
'For estimating new plant costs, retrofit factor is 1.0. For estimating repowered AFBC, PFBC, and IGCC costs,
costs of new plants were adjusted using the reuse and refurbishment factor approach discussed in this report.
"NA - Not applicable.
Table 8. New Plant Cost Estimates for Advanced Coal Combustion Technologies Firing 2% Sulfur Bituminous Coal1
Unit Cost per Ton of Acid
Net Plant Annual Costs, mills/kW-h Gas Removed, $/tonc
Capacity Capital Costs Constant Current Constant Current
Technology" MW $/kW $ $ $ $
Case 1, Project Contingencies^ 15%, Process Contingencies = 0%
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
200
500
1000
200
500
1000
200,
500,
1000
200
500 ..
1000
200
500
1000
1530
1250
1080
1800
1440
1220
1890
1540
1330
1840
1490
1310
1720
1390
1122
60
52
48
68
58
52
65
55
50
70
61
56
65
57
52
103
90
82
116
99
89
112
95
85
120
104
96
112
97
89
270
210
180
580
420
320
470
310
230
680
550
510
570
450
400
460
360
300
1000
720
560
800
540
390
1150
940
870
980
760
680
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Tables.
Technologyb
(Continued)
Unit Cost per Ton of Acid
Net Plant Annual Costs, mills/kW-h Gas Removed, $/tonc
Capacity Capital Costs Constant Current Constant Current
MW $/kW $ $ $ $
Case 2, Project Contingencies = 30%, Process Contingencies =10%
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
200
500
1000
200
500
1000
200
500
1000
200
500
1000
200
500
1000
1860
1510
1300
2190
1750
1470
2300
1880
1610
2150
1750
1540
2070
1670
1460
67
58
53
76
64
58
74
63
56
75
65
59
73
63
57 '
115
99
91
130
110
98
127
107
96
128
110
101
125
107
98
310
240
190
670
490
370
580
400
300
750
600
550
640
490
440
530
410
330
1150
830
630
990
680
520
1280
1030
940
1100
840
750
Cost are in 1988 dollars.
AFBC = atmospheric fluidized bed combustion.
PFBC = pressurized fluidized bed combustion.
IGCC = integrated gasification combined cycle.
PC/FGD/SCR = pulverized-coal plant with wet limestone Hue gas desulfurizaiion and selective catalytic reduction.
PC/FGD = PC plant with wet limestone FGD.
Tons of acid gas removed = sum of the tons of SO2 and NOxremoved.
Hypothetical acid gas control cost = annual cost for advanced technologies - annual cost for PC plant without FGD and SCR.
Table 9. New Plant Cost Estimates for Advanced Coal Combustion Technologies Firing 4% Sulfur Bituminous Coal'
Unit Cost per Ton of Acid
Net Plant Annual Costs, mills/kW-h Gas Removed, $/tonc
Capacity Capital Costs Constant Current Constant Current
Technology *
MW
$/kW
$
$
$
$
Case 1, Project Contingencies = 15%, Process Contingencies
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
200
500
1000
200
500
1000
200
500
1000
200
500
1000
200
500
1000
1550
1260
1090
1810
1440
1220
1930
1570
1350
1810
1480
1300
1690
1380
1200
63
55
51
70
60
54
65
55
50
69
60
55
64
56
52
108
95
87
120
103
93
112
95
85
117
102
95
110
96
88
= 0%
220
190
170
380
300
250
260
170
120
420
350
320
340
280
240
380
330
300
660
510
420
440
290
210
580
470
420
580
470
420
(Continued)
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Tabled. (Continued)
Technology11
Net Plant
Capacity
MW
Capital Costs
$/kW
Annual Costs, mills/kW-h
Constant Current
$ $
Unit Cost per Ton of Acid
Gas Removed, $Aon °
Constant Current
$ $
Case 2, Project Contingencies t= 30%, Process Contingencies
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
200
500
1000
200
500
1000
200
500
1000
200
500
1000
200
500
1000
1870
1520
1310
2200
1750
1480
2340
1910
1640
2230
1810
1590
2090
1690
1480
70
6,1
56
78
67
60
74
63
56
80
69
63-
75
64
59
120
104
96
134
114
102
127
107
96
136
113
108
128
110
101
= 10%
240
210
180
430
330
270
320
220
160
460
380
350
370
300
270
420
350
310
740
570
460
550
380
280
790
650
600
640
510
460
' Costs are in 1988 dollars.
* AFBC m atmospheric fluidized bed combustion.
PFBC * pressurized fluidized bed combustion.
IGCC s integrated gasification combined cycle.
PC/FGD/SCR = pulverized-coal plant with wet limestone flue gas desulfurization and selective catalytic reduction.
PC/FGD s PC plant with wet limestone FGD.
e Tons of acid gas removed = sum of the tons of SOS and NQxremoved.
Hypothetical acid gas control cost = annual cost for advanced technologies - annual cost for PC plantwithout FGD and SCR.
I
"53
I
200
400
600
Plant Size, MW
800
WOO
Figure 1. Capital costs for new plants as a function of size for plants using 2% sulfur coal (in constant 1988 dollars).
Contingencies of 30% for project and 10% for process are assumed.
8
-------
•2
1
w
8
1
I
80
78
76
74
72
70
68
66
64
62
60
58
56
54
52
200
m AFBC
+ PFBC
o IGCC
A PC/FGD/SCR
x PC/FGD
_L
J_
400
600
Plant Size, MW
800
1000
Figure 2. Annual costs for new plants as a function of size for plants using 2% sulfur coal (in constant 1988 dollars).
Contingencies of 30% for project and 10% for process are assumed.
i
o
I
to
CO
C3
800
700
600
500
400
300
200
100
• AFBC
+ PFBC
o IGCC
A PC/FGD/SCR
x PC/FGD
200
400
600
Plant Size, MW
800
1000
Figure 3. Unit cost of acid gas removed as a function of size for plants using 2% sulfur coal (in constant 1988 dollars).
Contingencies of 30% for project and 10% for process are assumed.
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Table 10. Retropowered and Retrofit Plant Cost Estimates for Advanced Coal Combustion Technologies Firing 2% Sulfur Bituminous Coal *
Base Net Final Net Annual Costs, mills/kW-h
Plant Capacity Plant Capacity0 Capital Costs Constant $ Current $
Technology" MW MW $/kW $ $
Case 1, Project Contingencies = 75%, Process Contingencies = 0%
AFBC
PFBC
IGCC
PC/FGD/SCR '
PC/FGD
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
200
500
1000
200
500
1000
70
170
330
208
520
1040
206
515
1030
Case 2,
200
500
1000
200
500
1000
70
170
330
208
520
1040
206
515
1030
200
500
1000
200
500
1000
200
500
1000
200
500
1000
200
500
1000
Project Contingencies
200
500
1000
200
500
1000
200
500
1000
200
500
1000
200
500
1000
790
660
[ 590
1190
950
. 810
1710
1400
; 72/0
630
540
570
490
, 420
400
46
42
39
58
50
45
67
56
51
45
40
39
40
36
34
72
65
61
90
78
71
104
88
79
70
63
61
62
56
53
= 30%, Process Contingencies = 10%
950
800
710
\ 1440
1150
970
2080
1700
1470
700
570
550
540
450
i 420
50
45
42
64
55
49
76
64
57
47
42
34
41
37
35
78
70
66
100
85
77
118
100
89
73
66
53
64
57
55
' Costs are In 1988 dollars.
* AFBC * atmospheric fluidized bed combustion. ;
PFBC = pressurized fluidized bed combustion.
IGCC * Integrated gasification combined cycle.
PC/FGD/SCR = pulverized-coal plant with wet limestone flue gas desulfurization and selective catalytic reduction.
PC/FGD m PC plant with wet limestone FGD.
e Station generating capacity is unchanged for simple cycle AFBC and PFBC repowering. Repowering with combined cycle
IGCC results in an approximate tripling of capacity. Retrofit with FGD and SCR results in a capacity derate.
10
-------
Table 11. Retropowered and Retrofit Plant Cost Estimates for Advanced Coal Combustion Technologies Firing 4% Sulfur Bituminous Coal'
Base Net Final Net Annual Costs, mills/kW-h
Plant Capacity Plant Capacity0 Capital Costs Constant $ Current $
Technology" MW MW $/kW $ $
Case 1, Project Contingencies = 15%, Process Contingencies = 0%
AFBC 200 200 800 49 76
500 500 670 44 69
1000 1000 600 42 65 '
PFBC 200 200 1200 60 94
500 500 960 52 81
1000 1000 810 48 74
IGCC 70 200 1750 67 104
170 500 1420 56 88
330 WOO 1230 51 79
PC/FGD/SCR 208 200 690 47 73
520 500 590 42 66
1040 1000 550 40 63
PC/FGD 206 200 550 41 64
515 500 470 37 58
1030 1000 430 36 56
AFBC
PFBC
IGCC
PC/FGD/SCR
PC/FGD
200
500
WOO
200
500
WOO
70
170
330
208
520
1040
206
515
1030
200
500
WOO
200
500
WOO
200
500
WOO
200
500
1000
200
500
WOO
960
810
720
1440
1150
980
2120
1730
1490
770
640
590
610
510
470
53
48
45
66
57
52
76
64
57
49
44
42
43
38
37
83
75
70
103
89
81
119
100
89
76
68
65
67
60
57
* Coste are in 1988 dollars.
6 AFBC = atmospheric f/uidized bed combustion.
PFBC = pressurized fluidized bed combustion.
IGCC = integrated gasification combined cycle.
PC/FGD/SCR = pulverized-coal plant with wet limestone flue gas desulfurization and selective catalytic reduction.
PC/FGD = PC plant with wet limestone FGD.
0 Station generating capacity is unchanged for simple cycle AFBC and PFBC repowering. Repowering with combined cycle
IGCC results in an approximate tripling of capacity. Retrofit with FGD and SCR results in a capacity derate.
11
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J. Martinez, G. Snow, and M. Maibodi are with Radian Corp., Research Triangle Park,
NC 27709. •
Norman Kaplan is the EPA Project Officer (see below).
The complete report, entitled "Costs for Advanced Coal Combustion Technologies,"
(Order No. PB 90-255 688/AS; Cost: $23.00, subject to change) will be available
only from: \
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at: •
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection
Agency
Center for Environmental Research
Information
Cincinnati, |OH 45268
BULK RATE
POSTAGE & FEES PAID
EPA PERMIT NO. G-35
Official Business
Penafty for Private Use $300
EPA/600/S7-90/015
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