United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park NC 27711
Research and Development
EPA/600/S7-90/021 Mar. 1991
EPA Project Summary
Retrofit Costs for SO2 and NOX
Control Options at 200
Coal-Fired Plants
Thomas E. Emmel and Mehdi Maibodi
This report documents the results of
a study to significantly improve engi-
neering cost estimates currently being
used to evaluate the economic effects
of applying sulfur dioxide (SO2) and ni-
trogen oxides (NO,) controls at 200
large SO2- emitting coal-fired utility
plants. To accomplish the objective,
procedures were developed and used
that account for site-specific retrofit
factors. The site-specific Information
was obtained from aerial photographs,
generally available data bases, and in-
put from utility companies. Cost esti-
mates are presented for six control
technologies: lime/limestone flue gas
desulfurlzation, lime spray drying, coal
switching and cleaning, furnace and
duct sorbent Injection, low NO, com-
bustion or natural gas reburn, a'nd se-
lective catalytic reduction. Although the
cost estimates provide useful site-spe-
cific cost information on retrofitting acid
gas controls, the costs are estimated
for a specific time period and do not
reflect future changes in boiler and coal
characteristics (e.g., capacity factors
and fuel prices) or significant changes
in control technology cost and perfor-
mance.
This Project Summary was developed
by EPA's Air and Energy Engineering
Research Laboratory, Research Tri-
angle Park, NC, to announce key find-
ings of the research project that is fully
documented in a separate report of the
same title (see Project Report ordering
information at back).
Introduction
The National Acid Precipitation As-
sessment Program (NAPAP) is respon-
sible for developing cost and performance
information on various methods for reduc-
ing the emissions of acid rain precursors.
Coal-fired utility boilers are major emitters
of sulfur dioxide (SO,,) and nitrogen oxides
(NOJ. However, estimating the cost and
performance of SO2 and NO controls for
coal-fired power plants is difficult due to
differences in plant layout and boiler de-
sign.
The objective of this study was to sig-
nificantly improve the accuracy of engi-
neering cost estimates used to evaluate
the economic effects of applying SO. and
NO controls at 200 large SO2-emitting
coal-fired utility plants. This project was
conducted in four phases as shown in
Figure 1. In Phase I, detailed, site-specific
procedures were developed with input from
the technical advisory committee. In Phase
II, these procedures were used to evalu-
ate retrofit costs at 12 plants based on
data collected from site visits. Based on
the results of this effort, simplified proce-
dures were developed to estimate site-
specific costs without conducting site vis-
its. In Phase III, the simplified procedures
were verified or modified based on utility
input by visiting 6 of the 50 plants. The
modified procedures were then used to
estimate retrofit costs at the remaining
138 plants. In Phase IV, utility comments
were incorporated into the final 200-plant
study report.
-------
Phase I
Develop Detailed
Procedures
Phase II
Select 12 Plants and
Develop Cost/
Performance Estimates
Revise Procedures and
Cost Estimates and
Develop Simplified
Procedures
Phase ///
Evaluate 50 Plants
Very Simplified
Procedures with Visits to
Six Plants
Modify Procedures and
Evaluate Remaining 138
Plants
Phase IV
Finalize 200-Plant
Study Report
Figure 1. 200-Plant study technical approach.
This report presents the cost estimates
developed for 631 out of 662 boilers in
200 plants using the simplified procedures.
Costs were not developed for 31 boilers
because either they were burning fuels
other than coal or they were new boilers
with S(X and NO, controls already in-
stalled. The commercial and developmen-
tal SO2 and NOH control technologies
evaluated in the study are listed in Table
1. The detailed cost estimates developed
for 55 boilers in the 12 plants evaluated
using the detailed procedures are pre-
sented in another report. The cost results
for all the boilers evaluated in this report
Technical Advisory
Committee
—EPRI
—EPA
—DOE
—Utility Air Regulatory Group
—TVA
—Natural Resource
Defense Council
—Vendors
Utility Companies
—Ohio Edison
—American Electric Power
—Ohio Electric Utility
Institute
—TVA
—Kentucky Utilities
—Union Electric
—Cincinnati Gas S Electric
200 Plant
Utility Companies
are presented in a database file for further
study and evaluation.
Methodology
For each plant, a boiler profile was
completed using sources of public infor-
mation, the primary source being the En-
ergy Information Administration (EIA) Form
767. Additionally, boiler design data were
obtained from generally available data
bases, and aerial photographs were ob-
tained from state and federal agencies.
The plant and boiler profile information is
used to develop the input data for ''
performance and cost models. The pc
mance and cost results incorporate .
ommendations from utility companies and
a technical advisory group. The advisory
group included utility industry, flue gas
desulfurization (FGD) vendor, and gov-
ernment agency representatives.
All of the cost estimates were devel-
oped using the Integrated Air Pollution
Control System (IAPCS) cost model. The
IAPCS model was upgraded to include all
of the technologies being evaluated in this
program. All of the cost estimates were
developed using the integrated technolo-
gies evaluated in this program. Evaluated
qualitatively without cost estimates were
life extensions using fluidized bed com-
bustion and coal gasification combined
cycle.
Figure 2 presents the methodology used
to develop IAPCS inputs to estimate site-
specific costs of retrofitting SO, and NOx
controls. The site-specific information
sources were used to develop process
area retrofit multipliers, scope adder costs,
and boiler and coal parameters. This in-
formation was input to the IAPCS cost
model that generated the capital, operat-
ing and maintenance (O&M), and levelized
annual costs of control and the emission
reductions. The process area retrofit
culty multipliers and scope adder c
used to adjust generic cost model outpu..
to reflect site-specific retrofit situations
were derived from an Electric Power Re-
search Institute (EPRI) report.
Table 2 summarizes the economic
bases used to develop the cost estimates.
Summary of Cost Results
This section summarizes the she-spe-
cific control cost estimates developed for
each boiler evaluated. The number of
boilers varied for each control technology
for reasons discussed under each control
technology summary. For example, low
NOt burners were not evaluated on cy-
clone-fired boilers because this technol-
ogy is not being developed for cyclone
boilers (slagging combustors were not ad-
dressed under this study). For cyclone
boilers and other wet bottom boilers,
natural gas reburning (NGR) was evalu-
ated for NOM control.
For each control technology, the follow-
ing three figures are presented: Capital
costs (dollars/kilowatt), levelized annual
costs (mills/kilowatt hour), and cost per
ton of acid gas removed (dollarsAon), each
plotted versus the sum of megawatts. The
x-axis (sum of megawatts) is the cumu'a-
tive sum of the boiler size sorted in r
from the lowest to the highest cxx
-------
'»1. Emission Control Technologies Selected
Development Status
Species Controlled
SO, NO,
Commercial
Limited
Commercial
Experience
Ongoing or
Near
Commercial
Demonstration
Lima/Limestone (L/LS) flue gas
desulfurization (FGD)
Additive enhanced L/LS FGD
Lima spray drying (LSD) FGD •
Physical coal cleaning (PCC)
Coa! switching and blending (CS/B)
Low-No^ combustion (LNC)
Furnace sorbent injection (FSI) with
humidification
Duct spray drying (DSD)
Natural gas rebuming (NGR)"
Selective catalytic reduction (SCR)
Fluktized bed combustion (FBC) or coal
gasification (CG) retrofitc
x
x
X
X
X
'Commercial on low-sulfur coals, demonstrated at pilot scale on high-sulfur coals.
Tnr wet bottom boilers and other boilers where LNC is not applicable.
'uated qualitatively as combined life extension and SO2 / NOM control option. No costs were developed.
...- 25. 50, and 75 sum of megawatt per-
cent points for the boilers included in the
figure. Each point on the curve represents
a specific boiler cost result. The first point
represents the boiler that had the lowest
capital cost and unit cost. The last point
represents the boiler that had the highest
cost. The curves turn up sharply because
each curve was developed starting with
the boiler having the lowest control cost
and ending with the boiler having the
highest control cost. The cost results do
not represent the average or cumulative
cost of control.
Each utility section in this report was
sent to the appropriate utility for review
concerning plant information. Costs devel-
oped in this report may not represent a
particular utility company's economic
guidelines. The cost results are static (not
dynamic) and represent a single year in
the 1986-1989 period with regard to ca-
pacity factor, coal sulfur, and pollution
control characteristics.
FGD Cost Estimates
Figures 3 through 5 summarize the
cost estimates developed for wet lime/
limestone (L/LS) FGD with adipic acid ad-
for 449 boilers. Two FGD configura-
were evaluated: a conventional New
Performance Standard (NSPS)
design having a single system for each
boiler, small absorber size, and one spare
absorber; and a low-cost design that has
combined boiler systems (when feasible),
but not a spare absorber. The target SO2
removal efficiency was 90%.
Cost estimates for FGD were devel-
oped for only 449 of 631 boilers because
46 boilers were already equipped with FGD
systems, 130 boilers were burning low
sulfur coals (many are 1971 NSPS units),
and 6 boilers were too small or already
retired. The percent increase in capital
cost for retrofitting an FGD system over a
typical new plant installation ranged from
19 to over 100%, with the average being
45%. The levelized annual cost of control
(mills/kilowatt hour) is also strongly influ-
enced by system size and design (e.g.,
percent reduction required or conventional
versus low-cost configuration design), and
operation (capacity factor and sorbent/
waste disposal costs).
Figures 6 through 8 summarize the cost
estimates for lime spray drying (LSD) for
all the boilers for which costs were devel-
oped. Two control options were consid-
ered for the retrofit of this technology:
reuse of the existing electrostatic precipi-
tator (ESP) or installation of a new fabric
filter (FF). Reuse of the existing ESP was
not considered:
• when the specific collection area (SCA)
of the existing ESP was small <43.3
m2/actual m3-sec or 220 ft!/1000 acfm,
and
• when the addition of new plate area
was impractical (e.g., roof-mounted
ESPs).
In such cases, a new FF was used for
paniculate control with the spray drying
system. However, if a unit is burning high
sulfur coal, use of a new FF was not
considered. Based on the cited criteria,
168 boilers were considered with a new
FF option, and 195 boilers were consid-
ered with reuse of the existing ESPs. The
cost of retrofitting new FFs results in a
high retrofit difficulty factor and a high
cost of control.
Coal Switching and Cleaning
For coal switching (CS), two fuel price
differentials (FPDs) were evaluated: $5
and $15Aon. The $5 to $15Aon FPD was
assumed to represent an estimated range
for switching to a low sulfur coal.
Figures 9 through 11 summarize the
costs for 329 boilers in the 200 plants for
which costs were developed for CS. The
cost estimates for CS are based on $5
and $15/ton FPD. CS was not considered
-------
Site Specific Information Sources
Aerial
Photographs
Retrofit Factors
Access/Congestion
Soil and Underground
Flue Gas Ducting
General Facilities
Regional Cost Factors
Energy Information Administration Form 767
Boiler/Coal Characteristics
Scope Adder Costs
Wet to Dry Ash System
Chimney or Liner
Paniculate Manor Controls
NT
Multiplier
Utility Comments and
Other Data Sources
Boiler/Coal Parameters
Boiler Characteristics
Coal Characteristics
Capacity Factor
PM Control Type/Size
Rue Gas Temperature
Dollars
Direct Inputs
Cost Model Inputs
Integrated Air Pollution Control System
Cost Model Outputs
Capital Costs O&M Costs Annualized Costs Emission Reduction
Figure 2. Site-specific cost estimation methodology.
7»W« 2. Economic Bases Used to Develop the Cost Estimates
Item January 1985 Value
Operating labor
Water
Lime
Limestone
Land
Waste disposal
Electric power
Catalyst cost
19.7
0.60
65
15
6.500
9.25
0.05
20,290
$/person labor
$/1000gaJ.'
$/ton*
$/ton
$/acre •
$/ton
$/kWh
$/ton
Levelization factors
Operating and maintenance
Carrying charges
Current dollars"
1.75
17.5%
Constant dollars'
1.0
10.5%
'For readers more familiar with metric units: 1 gal. = 3.8L, 1 ton = 907kg, and 1 acre = 4047m*
"Book life—30 years: tax life—20years; depreciation method—straight line; and discount rate—12.5%
based on a 6% escalation for inflation.
-------
Figures. Summary of capital cost results for
lime/limestone flue gas desulfurization.
20,000 40,000 60,000 80,000 700,000 »20,000
Sum ofMW
100
90-
80-
Figure 4. Summary of annual cost results for
lime/limestone flue gas desulfurization.
I
S
60
40
30
• WetFGD-NSPS
A low Cost FGD
(No spare absorbers, but
combined boilers.)
1988 Constant Dollars
75% of Total MW
50% of Total MW'
25% of Total MW yx
20,000 40,000
£0,000 80,000
Sum ofMW
100,000 120,000
9,000
8,000-
7,000 -
o
2 5,000
o
| 4,000
| 3,000
• WetFGD-NSPS
A Low Cost FGD
(No spare absorbers, but
combined boilers.)
1988 Constant Dollars
Figure 5. Summary of cost per ton ofSO2 removed
results for lime/limestone flue gas desulfurization.
20,000 40,000 60,000 80,000 100,000 120,000
Sum ofMW
-------
400
350
300
250
200
|
8
•5 '50
I
<3
700
Figure 6. Summary of capital cost results for lime
spray dry ing.
20.000
40,000 60.000
Sum ofMW
80,000 700,000
Figure 7. Summary of annual cost results for lime
spray drying.
1
I
3
35
30
25
20
15
10
5
1988 Constant Dollars
7596 of Total MW
I
50% of: Total MW
25% of Total MW v
20,000
40,000 60,000
SumofMW
80,000
100,000
5,000
25%ofTotalMW 50%ofTotalMW
Figure 8. Summary of cost per ton ofSO2 removed
results for lime spray drying.
20,000
40,000 60,000
Sum ofMW
80,000
-------
8
70
60
50
40
30
20
10
0
• $15 Fuel Price Differential
A $5 Fuel Price Differential
1988 Constant Dollars
75% of Total MW
25% of Total MW - 50% of Total MW \ \_
Figure 9. Summary of capital cost results for coal
switching and blending.
20,000 40,000 60,000
Sum ofMW
80,000
100,000
17
Figure 10. Summary of annual cost results for
coal switching and blending.
s
I
re
a
c
15 -
13
11
9
7
5
3
1
115 Fuel Price Differential
• $5 Fuel Price Differential
1988 Constant Dollars _|
75% of Total MW
50% of Total MW
25% of Total MW . \
9,000
20,000 40,000 60,000
Sum of MW
80,000
100,000
8,000 -
• % 15 Fuel Price Differential
^ J5 Fuel Price Differential
1988 Constant Dollars
Figure 11. Summary of cost per ton ofSO2 removed
results for coal switching and blending.
20,000
40,000 60,000
Sum ofMW
80,000
-------
already burn a low sulfur coal or have
wet-bottom boilers that can burn only coals
with special ash fusion properties. The
CS cost estimates are highly dependent
upon the FPD. The impacts of particulate
control upgrades and coal handling up-
grades are generally small by compari-
son.
Figures 12 through 14 summarize the
plant cost of physical coal cleaning (PCC).
Of 631 boilers, only 32 were evaluated for
PCC because either the coal already is
extensively cleaned or the plant is not
located at a mine mouth.
Sorbent Injection Cost and
Performance Estimates
Two sorbent injection technologies in
active research and development were
evaluated in this study: furnace sorbent
injection (FSI) with humidification and duct
spray drying (DSD). Figures 15 through
20 summarize the cost estimates devel-
oped for these technologies. Some boil-
ers were not considered good candidates
for these technologies because:
• FSI and DSD were not considered
practical for boilers having an ESP
SCA < 220 ft2/1000 acfm, and
• DSD was not considered if the duct
residence time from the injection point
after the air heater to the ESP inlet was
less than 2 sec (<100 ft—30.5 m—of
duct length).
Only 321 boilers were considered appro-
priate for DSD, and 289 were considered
for FSI applications. The costs presented
for FSI assume 50 and 70% SO2 control
with humidification.
Low NOX Combustion
Figures 21 through 23 summarize cost
estimates for application of low NOi burner
(LNB) on dry-bottom wall-fired boilers (20-
55% NOx reduction), overfire air (OFA) on
tangential-fired boilers (10-35% NOx re-
duction), and natural gas reburn (NGR)
on cyclone boilers (60% NO reduction).
The unit costs of LNB and OFA are low
(<$300Aon of NO removed). However, for
boilers where NGR is applied, the unit
costs are much higher ($400-$1100/ton of
NO, removed). This is due to the high
cost of natural gas relative to coal (as-
sumed to be a $2 /10e Btu* fuel price dif-
ferential in 1988 dollars). For this study,
228 boilers were candidates for LNB, 214
boilers for OFA, and 81 boilers for NGR.
Some of the boilers were not considered
Tor readers more familiar with metric units, 1 Btu ••
1.054KJ.
for low NOx combustion technologies
(LNC) because of the reservations of plant
personnel regarding applicability of these
technologies.
Selective Catalytic Reduction
(SCR) Cost Estimates
Figures 24 through 26 summarize the
cost estimates for application of SCR. For
most of the units, cold-side, tail-end sys-
tems were assumed (the reactor down-
stream of particulate control or scrubbers).
In some instances, due to space availabil-
ity limitations or the unit's being equipped
with a hot-side ESP, a hot-side, high-dust
system configuration was used (the reac-
tor between the economizer and the air
heater). Use of the tail-end system mini-
mizes unit downtime, which reduces the
uncertainty of estimating the cost of re-
placement power, and maximizes the
catalyst life. However, a significant energy
penalty is associated with flue gas reheat-
ing compared to that for a high-dust sys-
tem (equivalent to a 120°F—49°C—re-
heat). This cost was not considered in this
study because the current version of the
IAPCS model is unable to estimate it.
However, the cold-side SCR requires 60%
of the hot-side catalyst volume. Based on
a 1 -year catalyst life, the reheat and extra
catalyst volume costs offset each other.
For this study, 624 boilers were evaluated
for SCR retrofit.
Conclusion
For each SO2 and NOx control tech-
nology evaluated in this study, different
factors affected control cost and perfor-
mance estimates for retrofit applications
at coal-fired boilers. Table 3 identifies
factors found to have the most significant
effects. For the L/LS-FGD technologies,
site access/congestion and flue gas duct-
ing distances were major factors. For LSD-
FGD, the need to add new particulate
control was also a major consideration.
For CS and PCC, the major retrofit fac-
tors, excluding FPD, were particulate con-
trol upgrade costs and boiler performance
impacts. CS for wet-bottom boilers and
switching from a bituminous to a subbitu-
minous coal were not evaluated because
boiler performance impacts are likely to
be significant.
For the sorbent injection technologies,
FSI and DSD, paniculate control upgrade
costs would have the greatest impact. Ad-
ditionally, sufficient duct residence time
must be available for DSD to guarantee
good droplet drying.
For the LNC and NGR technologies,
boiler type and configuration are impor-
tant. LNB was applied only to dry-bottom,
wall-fired boilers. OFA was applied only to
8
tangential-fired units. NGR was applied '
wet-bottom boilers and other misc
neous boiler types. Boiler heat relt
rates and residence times in different fur-
nace zones would have significant effects
on NOK removal efficiency for LNC and
NGR technologies.
SCR costs would be greatly affected
by access and congestion near the
economizer area for hot-side applications.
For cold-side applications, access and
congestion near the chimney area and
flue gas ducting distances greatly affect
costs. For cold-side systems, the energy
penalty for flue gas reheat is balanced by
increased catalyst life and reduced cata-
lyst costs. For hot-side systems, boiler
downtime costs and catalyst life would be
significant cost and performance factors.
The cost and performance information
presented is a realistic guide regarding
the degree of retrofit difficulty for each
control option evaluated. However, as
noted in Table 1, the technologies evalu-
ated in this study are at various stages of
commercial development. There is a higher
degree of uncertainty regarding the cost/
performance for those technologies that
do not have extensive commercial appli-
cation in the U.S. Therefore, no attempt
has been made in this study to identify a
best option for each plant/boiler.
Additionally, a utility company's dec
concerning which retrofit control to app,
to a given boiler is very complex. Consid-
erations used in making such a decision
include:
• system reduction target and degree of
flexibility regarding means to achieve
the target,
• current and future toad pattern for each
boiler with or without controls,
• cost of purchased power and planned
new capacity,
• cost of capital and current/future finan-
cial strength, and
• public utility commission and state/re-
gional regulatory agency attitudes.
The data contained in this report can be
used to facilitate selection of least-cost
control options for specific plants/boilers
for planning scenarios that address the
above decision criteria.
The cost results for all the technologies
presented in this report are available in
three DBase III+ files and can be obtained
through the National Technical Informa-
tion Service (NTIS). Disks 1 and 2 *">
high density diskettes which contain: '
name, technology, boiler number, ca,
-------
90
80
70
60
50
40
30
20
10
0
1988 Constant Dollars
Figure 12. Summary of capital cost results for
physical coal cleaning.
50% of Total MW
75% of Total MW
.25% of Total MW
2,000 4.000 6,000 8,000
Sum ofMW
10,000 12,000 14,000
5
Figure 13. Summary of annual cost results for
physical coal cleaning.
I
3
50% of Total MW
25% of Total MW
1,200
9 1,000
0 2.000 4.000 6.000 8,000 10,000 12,000 14,000
Sum ofMW
o
c
u
,^
800
600
400
200
1988 Constant Dollars
75% of Total MW
50% of Total MW
25% of Total MW
Figure 14. Summary of cost per ton ofSO2 removed
results for physical coal cleaning.
2,000 4,000 6,000 8,000 10.000 12,000 14,000
-------
!
o
I
a:
6"
I
1
Figure 15. Summary of capital cost results for
duct spray drying.
20,000
40,000 60,000
SumofMW
80,000
100,000
Figure 16. Summary of annual cost results for 3
duct spray drying. ^—
s
20
76
72
1988 Constant Dollars
50% of Total MW
75% oi Total MW
\
25% of Total MW
20.000
3,800
3,400
3,000
2,600
7,800
7,400
7,000
600
1988 Constant Dollars
75% Of Total MW
50%ofTotalMW
25% offofa/MtV
>y
40,000 60,000
Sum ofMW
80,000
100,000
Figure 17. Summary ofcostperton of SO? removed
results for duct spray drying.
20,000 40,000 60,000
Sum ofMW
80,000
100,000
-------
1 IV -
700-
o/i -
Hn -
5
^J 70-
I 60-
3 6a-
2 so -
O 40 —
30-
?fl-
70-
7988 Constant Dollars
i
75% of Total MW v-*
5096 of Total MW ^^^
2596 of Total MW *^ >~^
^_^^
^
I
Figure 18. Summary of capital cost results for
furnace sorbent injection.
0 20,000 40,000 £0,000 80,000 700,000
Sum ofMW
•M -.--
17 -
^ is -
Figure 19. Summary of annual cost results for ^
2.400 -
2.200 -
2,000 -
* 7,600
o
I '
3 ovu
O
3 400-
n -
luriidie juruem injection. EI • •
— O -
^
S -
3 .
; .
1988 Constant Dollars
7596 of Total MW f
25% of Total MW \. ^^ , -~~^
^ _^— --^^"
^-^ ^*
0 20,000
• 5096 Removal
19SS Constant Dollars 1
I
I
I
\
//
7596 of Total MW f* 1
!>096oflotalMW ^\ J* \
2S96 of Total MW v\ \X -^ -/
_^— N>— ^J^A — *
^— *
40.000 60,000 80,000 100.000
Sum ofMW
Figure 20. Summary of cost per ton ofSO2 removed
results for furnace sorbent injection.
20,000 40,000 60,000
Sum of AM
00,000
700,000
-------
§
45
40 -
35-
30
25
20
15
10
5
0
A LNB
X OFA
m NGR
1988 Constant Dollars
75% of Total MW
50% of Total MW
25% of Total MW
20,000
40,000
Sum ofMW
Figure 22. Summary of annual cost results for
low NO, combustion.
!
I
|
'£
20,000 40,000
Sum ofMW
Figure 21. Summary of capital cost results for
low NO, combustion.
60,000
A LNB
X OFA
• NGR
1988 Constant Dollars \
75% of Total MW
\
50% of Total MW
20,000
40,000
Sum ofMW
60,000
A LNB
XOFA
m NGR
1988 Constant Dollars
75% of Total MW
50% of Total MW
' ~25% of Total MW
Figure 23. Summary of cost per ton of NO, removed
results for low NO, combustion.
60,000
-------
8
1
280
240
200
160
120
80
40-
0
1988 Constant Dollars
' 25% of Total MW
75% of Total MW
50% of Total MW \.
3 Year Catalyst Life
Figure 24. Summary of capital cost results for
selective catalytic reduction.
20,000 60,000 100,000
Sum ofMW
140,000
180.000
Figure 25. Summary of annual cost results for
selective catalytic reduction.
50% of Total MW
25% of Total MW \
0 20,000
60,000
/00,000
140,000
180.000
I
5*
;
Figure 26. Summary of cost per ton of NO, removed
results for selective catalytic reduction.
2,000 •
J,000
40,000 80,000 120,000
Sum ofMW
160,000
200,000
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Table 3. Retrofit Factors Affecting Cost/Performance
Control
Technology
Access and
Congestion
Ducting
Distance
Additional
Partticulate
Control
Boiler
Type
Boiler
Configuration
Lime/Limestone Flue Gas Desulfurization
Lime Spray Drying
Coal Switching/Blending
Physical Coal Cleaning
Furnace Sorbent Injection
Duct Spray Drying
Low NO, Combustion
Natural Gas Rebuming
Selective Catalytic Reduction
x
x
x
x
x
x
x
SO2 and NO removed per year, SO2 and
NO removal efficiencies, capital cost in
dollars, annual cost in dollars, dollars per
kilowatt, mills per kilowatt hour, dollars
per ton of SO2 removed, and dollars per
ton of NO. removed. Disk 1 is in current
1988 dollars, disk 2 is in constant 1988
dollars, and disk 3 contains a third DBase
file (200.DBF) with general plant, boiler,
and company information based on De-
partment of Energy Form 767 data. Disk 3
also contains an ASCII file (README.
ASC) listing abbreviations used in all three
database files. The cost result database
can be used to estimate total costs and
emissions for individual or combined con-
trol technologies for the 200 plants pre-
sented in this report.
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T. Emmel and M. Maibodi are with Radian Corporation, Research Triangle Park, NC
27709.
Norman Kaplan is the EPA Project Officer (see below).
Tha complete report, consists of five volumes and diskettes entitled "Retrofit Costs for
SO and NOt Control Options at 200 Coal-Fired Plants," (Set Order No. PB 91-133
314/AS; Cost $181.50, subject to change).
"Volume I. Introduction and Methodology" (Order No. PB 91-133 322/AS;
Cost: $17.00, subject to change).
"Volume II. Site-Specific Studies forAL, DE, FL, GA, IL" (Order No. PB 91-
133 330/AS; Cost: $45.00, subject to change).
"Volume III. Site Specific Studies for IN, KY, MA. MD, Ml, MN" (Order No.
PB 91-133 348/AS; Cost: $45.00, subject to change).
"Volume IV. Site Specific Studies for MO. MS, NC, NH, NJ, NY, OH" (Order
No. PB 91-133 355/AS; Cost: $53.00, subject to change).
"Volume V. Site Specific Studies for PA, SC, TN, VA, Wl, WV (Order No. PB
91-133 363/AS; Cost: $53.00, subject to change).
Related set of three diskettes (Order No. PB 91-506 295/AS; Cost $80.00
subject to change).
The above items 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 Resea:
Information
Cincinnati, OH 45268 ;
Official Business
Penalty for Private Use $300
EPA/600/S7-90/021
000047147 PS
US j£P A
LIBRARY SERVICES
RES TRI PARK
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