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.

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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 cost—constant 1988 dollars.

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<§

                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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