United States
Environmental Protection
Agency
Air and Energy Engineering
Research Laboratory
Research Triangle Park, NC 27711
Research and Development
EPA/600/S7-90/018 Jan. 1991
EPA Project Summary
Assessment of Control
Technologies for Reducing
Emissions of SO2and NOxfrom
Existing Coal-Fired Utility Boilers
David M. White and Mehdi Maibodi
A major objective of the National Acid
Precipitation Assessment Program is to
evaluate alternative methods for reduc-
ing SO2 and NOX emissions from com-
bustion sources and to identify options
which appear most promising from both
an emissions reduction and cost stand-
point. Part of this overall effort is to
develop up-to-date generic assessments
of commercial, near-commercial, and
emerging emission controltechnologies
applicable to existing coal-fired electric
utility boilers. This report reviews avail-
able information and estimated costs on
15 technology categories, including
passive controls such as least emission
dispatching, conventional processes,
and emerging technologies still under-
going pilot scale and commercial dem-
onstration.
The status of each technology is re-
viewed relative to four elements:
Description - how does the tech-
nology work?
Applicability - how does it apply to
existing plants?
Performance - what is the expected
emissions reduction?
Cost - what is the capital cost,
busbar cost, and cost per ton of SO2
and NOX removed?
Cost estimates are presented for new
and retrofit applications for various
boiler sizes, operating characteristics,
fuel qualities, and boiler retrofit diffi-
culties. Capital costs vary from $2/kW
for Overfire Air to $2,800/kW for Inte-
grated Gasification Combined Cycle in
1988 dollars.
This Project Summary was devel-
oped by EPA's Air and Energy Engi-
neering Laboratory, Research Triangle
Park, NC, to announce key findings of
the research project that is fully docu-
mented in a separate report of the same
title (see Project Report ordering infor-
mation at back).
Background and Purpose
One of the objectives of the National
Acid Precipitation Assessment Program
(NAPAP) is to evaluate the potential per-
formance and cost of alternative methods
for reducing SO2 and NO, emissions from
combustion sources. Part of this overall
effort is to develop up-to-date generic in-
formation on commercial, near-commer-
cial, and emerging emission control tech-
nologies applicable to coal-fired electric
utility boilers. This report reviews available
information on the technologies shown on
Table 1. Because the various acid rain
regulatory proposals focus on reduction of
SO2 and NOX in the eastern half of the
U.S., the report focuses on each
technology's potential for retrofit onto ex-
isting boilers in the eastern U. S. burning
medium- and high-sulfur coals.
Organization
The technology reviews are divided into
three major sections covering technolo-
gies which are commercial,
near-commercial, and emerging. These
three classes are respectively defined as
follows: technologies routinely used by U.
S. electric utilities, technologies undergo-
ing large-scale demonstration by U. S.
Printed on Recycled Paper
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Table 1. Control Technologies Reviewed
Potential Emission
Reductions (%)
Technology
Commercial
Fuel Switching and Blending
Least Emissions Dispatch
Physical Coal Cleaning
Low NO, Burners
OverfiraAir
LmoAJmeslone FGD*
Additive Enhanced FGD
Dual Alkali FGD
By-Product Recovery FGD
Spray Drying
Near Commercial
Integrated Gasification
Combined Cycle
Fluidized Bed Combustion
Selective Catalytic Reduction
Furnace Sorbent Injection
Low-Temperature Sorbent Injection
Robumlng
Emerging
Advanced Coal Cleaning
Electron Beam Irradiation
Copper Oxide FGD
SO,
50-80
0-90
20-50
0
0
90-95
90-95
90-95
90-95
70-90
90-95
80-90
0
50-70
50-70
15-20
45-60
80-95
90-95
NO,
0-10
0-40
0
30-50
15-30
0
0
0
0
0'
90-95
>50
80-90
0
0
35-50
0
55-90
90-95
' Flue Gas Desulfurization.
utilities or commercially used in Japan or
Europe, and those still undergoing labora-
tory or pilot-scale testing. Designation of a
technology to one of these three classes is
based on the technology's demonstrated
status on low and high sulfur coals.
Within each major section, the tech-
nologies are presented in the following
order: passive controls, precombustion
controls, combustion controls,
post-combustion controls, and combined
systems. The term "passive controls" refers
to technologies which in many cases re-
quire little or no capital expenditure (i.e.,
hardware) but which will require changes
in a utility's operating methods. The status
of each technology* is reviewed relative to
four elements:
Description - how does the technol-
ogy work?
Applicability - How does it apply to
existing plants burning low- and
high-sulfur coals?
Performance - what is the expected
emissions reduction?
Cost -what are the capital cost, busbar
cost, and cost per ton of SO2 and NO,
removed?
Because of the importance of consis-
tent treatment of each technology, consis-
tent economic procedures were used for
most technologies to allow comparisons.
The methodology used for this purpose is
discussed below.
Methodology
Because of the diversity of plant sizes
and designs, operating characteristics, fuel
quality, and financing arrangements found
throughout U. S. utilities, it was necessary
to define a uniform methodology for use in
the report. These procedures can be di-
vided into two major categories: boiler de-
sign and economic assumptions. Base
case, high, and low values were selected
for boiler design and economic param-
eters. The range in values was evaluated
to present boiler conditions which may fa-
vor the selection of one technology option
over another. Table 2 presents the boiler
design and economic assumptions se-
lected.
For the technologies addressed in this
report, order of magnitude cost estimates
are presented. The cost estimates pre-
sented in the text are based on a range of
boiler and coal parameters. The cost of
many technologies is site-specific and var-
ies significantly 'depending on the boiler
and coal characteristics.
The Integrated Air Pollution Control
Systems (IAPCS) cost model, which is
currently being updated to include more
technologies, was used to develop the cost
estimates for some of the technologies in
this report. The cost/performance as-
sumptions are the same as used under the
NAPAP site-specific retrofit cost study un-
der which the costs of retrofitting SO2 and
NOX controls at 200 coal-fired utility power
plants are being estimated. The IAPCS
cost model was used to develop cost esti-
mates for the following control technologies:
Coal switching and blending (CS/B),
Furnace sorbent injection (FSI),
Lime spray drying with reuse of the
existing electrostatic precipitators
(LSD+ESP),
Lime spray drying with a new fabric
filter (LSD+FF), ;
Lime/limestone FGD (L/LS FGD),
Natural gas reburn (NGR),
Low NOX burner (LNB),
Overfire air (OFA), '
Selective catalytic reduction (SCR),
Integrated gasification combined cycle
(IGCC), and
Atmospheric fluidized bed combustion
(AFBC).
For the other technologies addressed
in this report, costs are from referenced
publications. These costs are not included
in this section for comparison, since other
cost model assumptions were used in gen-
erating costs which may not be consistent
with assumptions used in the IAPCS cost
estimates. l
Economic Assumptions
Cost estimates are presented in 1988
dollars using both current and constant
dollar procedures. The Electric Power
Research Institute's (EPRI's) general
costing procedures were used to incorpo-
rate inflation, cost of capital, and levelization
of future expenses. The cost of replace-
ment power or lost capacity while a plant is
out-of-service during retrofit is not included
in the analysis. Downtime: replacement
power costs depend on the duration of the
downtime period and the difference be-
tween the cost of purchased or replaced
electricity and that of power generated by
the out-of-service unit. For example, as-
suming a power cost differential of 10 mills
/kWh for three different downtime periods
of 1,3, and 6 months with a capacity factor
of 50 percent, the following additional capi-
tal investments would be required:
Downtime Downtime Replacement
Period Power Costs
(Months)
1
3
6
($/kW)
4 i
11
22
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Table 2. Bases for Cost Estimates
Parameter Descriptions
Base Case
Value
High Case
Value
Low Case
Value
300
50
300
100
10
200
Boiler and Coal Characteristic Assumptions
Unit
Size, MW
Capacity factor, %
Specific collection area (SCA),
ff/1000 acfnf
Coal Characteristics
Sulfur content, %
Switched fuel sulfur content, %
Ash content, %
High heating value, Btu/lb
2.0
0.9
10.0
11,000
1.0
0.9
5.0
9,000
700
90
400
4.0
0.9
15.0
13,000
Capital Cost Indjrects
General facilities, %
Engineering, %
Project contingencies, %
Process contingencies, %
Retrofit factor (for FGD or SCR)
Economic Life
Carrying Charge Factor
O&M Levelizing Factor
Operating Costs
Fuel price differential, $/ton
Operating labor, $/hr
Steam, $/1000 Ib
Electricity, mills/kWh
Lime, $/ton
Limestone, $/ton
Organic acid, $/ton
Ammonia, $/ton
SCR catalyst, $/ton
Waste disposal, $/ton
Water, $/1000 gal
Natural gas, $/1O*Btu
Sulfur, $/ton
Economic Assumptions
10%
10%
30%
0-10%, commercial technologies
10-30%, developing technologies
1.3 1.5
20 15
0.189 0.205
1.57 1.45
1.0
30
0.175
1.75
10
21.4
7.0
57.0
60.0
16.0
1,725.0
150.0
20,300.0
10.0
0.65
2.0
65.0
15
Readers more familiar with metric units may use the factors at the end of this Summary to convert to
that system.
The new coal-fired plant cost of power
would be approximately 60 mills/kWh: half
the cost would be fixed cost and the re-
mainder, fuel and consumable costs.
For post combustion technologies the
downtime replacement power cost is less
of a factor than for in-situ technologies.
Constant dollar calculations are based on
standard return on investment (i.e., annu-
ity) calculations without consideration of
tax incentives (e.g., accelerated depre-
ciation, investment tax credits) or allow-
ance for funds used during construction
(AFDC). The cost calculations include a
state and federal income tax rate of 38%.
The costs presented in the appendices
are in current 1988 dollars and a 30-year
book life. To approximate the total
levelized busbar cost of power in constant
dollars, divide the current dollar costs by
1.75.
Summary of Results
Table 3 and Figures 1-3 summarize for
each technology the range of cost esti-
mates developed in Table 2 using the high
and tow case values. The most representa-
tive value, the base case, is shown on the
figures for each technology as a mid-way
point on the bar graphs. This is to show the
technology sensitivity to variation in boiler
and coal characteristics and that there is no
single "winner" for all retrofit applications.
Only those costs which were developed
using the IAPCS cost model were presented
in this section for consistency. Cost esti-
mates for other technologies which were
obtained from other references are pre-
sented in the respective technology sec-
tions.
Sensitivity case cost estimates devel-
oped using the IAPCS cost model are also
presented in the appendices. The major
cost parameters were varied for the sensi-
tivity analysis. Major cost parameters differ
for the different technologies. For example,
FGD costs are very sensitive to retrofit
factors, coal sulfur content, capacity fac-
tor, and boiler size, while coal switching is
mainly a function of fuel price differential
and percent reduction required. Sensitivity
case parameters for different technologies
are listed in Table 3.
Figures 1-3 present cost estimates for
both low and high cases for capital,
levelized annual, and unit costs. Costs as
well as pollutant removal efficiencies vary
for different technologies. These two fac-
tors should be balanced in choosing one
technology over another and determining
the cheapest technology for meeting acid
gas removal requirements for a given boiler
and coal characteristics.
In this study both high and tow sulfur
coals are switched to a 0.9% West Virginia
bituminous coal. Therefore, for high sulfur
coal (low case) over 80% SO2 removal is
achieved, while for tow sulfur coal (high
case) the removal value is less than 10%.
Because of a very low removal efficiency
due to switching from one low sulfur coal
to another low sulfur coal with less than
10% SO2 removal, the unit cost (dollar per
ton of SO2 removed) resulted'in a very large
number (the division denominator was a
very small value for tons of SO2 removal).
The AFBC and IGCC costs presented are
for new systems. The costs for these two
technologies are much higher than for other
presented technologies because pulver-
ized coal boiler costs (equivalent to AFBC
and IGCC) are not included with the other
technologies. For FSI, it is assumed that
70% SO2 removal can be achieved with
humidification and that existing ESPs are
adequate in size and can be reused.
Therefore the major cost items are sorbent
preparation and modification of the exist-
ing furnace for sorbent injection.
SCR costs are much greater than other
NO, removal technologies. This is mainly
due to the initial as well as the replaced
catalyst cost. However, unlike other NO,
removal technologies, SCR can achieve
more than 80% NOX removal.
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Metric Equivalents
Readers more familiar with metric units
may use the following factors to convert to
that system:
British Multiplied by Yields Metric
Btu
Btu/lb
(f/IOOOacfm
(SCA)
gal.
Ib
ton
1.055
2.326
197
0.00379
0.454
907
kJ
kJ/kg
irf/1000
rrP
kg
kg
arrf/s
Tablet 3. Summary of Cost Results Constant 1988 Dollars
Technology
Emission Reduction Capital Costs
Percent ($/kW)
Levelized
Annual Costs
mills/kWh)
Costs Per Unit of
Pollutant Removed
($/ton)
Most
Sensitive
Parameters
S02
Low Base High Low Base High Low Base High
Commercial
Fuel Switching and Blending 2-80
Lime/Limestone FGD 90
Lime Spray Drying with 76
Reuse of existing ESP
Lime Spray Drying with 86
New fabric filter
Low NO, Burners 0
Ovorfire Air 0
Near Commercial
Advanced Combustion Systems
Integrated Gasification 95
Combined Cycle*
Atmospheric Fluidized 90
Bed Combustion'
Add-on Controls
Furnace Sorbent Injection 70
Natural Gas Reburn 15
Selective Catalytic Reduction 0
MW - Size in megawatts.
%S - Coal sulfur content.
CF - Capacity factor.
SCA - Specific collection area of ESP.
FPD - Fuel price differential.
RF - Retrofit factor.
0
0
0
0
50
25
60-70
20-50
0
60
80
20
120
70
140
8
2
1,710
1,360
25
10
90
28
240
170
240
13
3
2,100
1,680
50
18
130
30
520
540
620
25
6
2,800
2,250
110
28
190
3
5
3
5
<1
<1
44
40
2
2
3
6
16
10
13
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OISI/L/
2800
2600
2400
2200
2000
^ 1800
o 1600
'3. 1400
CO
O
1200
1000
800
600
400
200
ft
Legend
= Base Case Value
-
" J
LS,
FSI
LNB NGR jip
0 +
1
1
LSC
;SP
SCfi
m
AFBC
ssasa
1
1
1
1
GCC
+
FF
FGL
10 20 30 40 50 60 70 80 90 100
A/OX or SO2 Removed (percent)
Figure 1. Capital costs constant 1988 dollars.
-------
I
700
600
500
400
300
200
700
Legend
= Base Case Value
1GCC
AFBCi
CS/8
0 TO 20 30 40 50 60 70 80 90 100
NOX or SO2 Removed (percent)
Figure 2. Levelized annual costconstant 1988 dollars.
-------
<§
10 20 30 40 50 60 70
NOX or SO2 Removed (percent)
80
90 100
Figure 3. Unit cost constant 1988 dollars.
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D.M. White andM. Maibodlare with Radian Corp., Research Triangle Park, NC 27709.
Norman Kaplan is the EPA Project Officer (see below).
The complete report, entitled "Assessment of Control Technologies for Reducing
Emissions of SO2 and NOX from Existing Coal-fired Utility Boilers," (Order No. PB90-
273574/AS; Cost: $31.00 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
Penalty for Private Use $300
EPA/600/S7-90/018
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