RETROFIT COSTS OF S02 AND NOX
CONTROL AT 200 U.S.
COAL-FIRED  PLANTS

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Report No. J1~~08'38
InfoTeam Inc.
Merton Allen Associates
P.O. Box 15640
Plantation, FL 33318-5640
-- ~100R90120
~ .

PROPERTY OF
EPA LlBRI\RY, RTP, NC
...
..
RETROFIT COSTS OF S02 AND NOx CONTROL
AT 200 U.S. COAL-FIRED POWER PLANTS
Thomas E. Emmel and
Mehdi Maibodi-
Radian Corporation
P. o. Box 13000
Research Triangle Park, NC 27709
Norman Kaplan
Air and Energy Engineering Research Laboratory
. U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
.'-
For Presentation-at the
1990 Pittsburgh Coal Conference
September 11, 1990

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ABSTRACT
This paper presents the results of a study conducted under the National Acid
Precipitation Assessment Program by the U.S. Environmental Protection Agency"s Air
and Energy Engineering Research laboratory. The objective of this research program
was to significantly improve engineering applying cost estimates currently being
used to evaluate the economic effects of applying sulfur'dioxide (S02) and nitrog~n
oxide (NO) controls at 200 large S02 emitting ~oal-fired utility plants. To I
accomplis~ the objective, procedures were developed and used that account for site- .
specific retrofit factors. The site-spedfic information was obtained from :aerial .
photographs, generally available data bases, and input from utility companies. Cost
results are presented for the following control technologies: lime/limestone flue
gas desulfurization, lime spray drying, coal switching, furnace and duct sorbent
injection, low NOx combustion or natural gas reburn, and selective catalytic
reduction. Although the cost estimates provide useful site-specific 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 performance.
2

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RETROFIT COSTS OF S02 AND NOxCONTROL
AT 200 U.S. COAL-FIRED POWER PLANTS
INTRODUCTION
"
The primary objective of the National Acid Precipitation Assessment Progran (NAPAP)
study of 200 U.S. coal-'fired power plants was to 'improve cost estimates for
retrofitting flue gas desulfurization (FGD) controls at 200 of the largest S02
emitting coal-fired power plants in the 31, eastern states. This study is probably
the most comprehensive conducted to date that evaluates boiler-sp~cific retr6fit
factors for large coal-fired power plants in the above cited region. 1he re~ults
may be used for broad analysis of the cost of ~ontrolling acid rain precursors.
Figure 1 shows the' phases in which the NAPAP study of 200 plants was conducfed. In
Phase I, detailed, site-specific procedures were developed with input from the
technical' advisory committee. In Phase II, these procedures were used to evaluate
, retrofit costs at 12 plants based on data collected from site visits. Based on the
results of this effort, simplified. procedures were developed to estimate site-
specific costs without conducting site visits. 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. Table 1 presents the commercial and developmental S02
,and NOx control technologies evaluated under,the NAPAP program.
COST METHODOLOGY
For each plant, a boiler profile was developed based either on site visits or from
sources of public information; the primary public source was Energy Information
Administration (EIA) Form 767. Additionally, ,boiler design data were obtained from
Powerplants Database magazine [1], and aerial photographs were obtained from state
and federal agencies. The plant and boiler profile information was used to develop
the input data for the performance and cost models. All of the cost estimates were
developed using the Integrated Air Pollution Control System (IAPCS) cost
model [2]. Figure 2 presents the methodology used to develop IAPCS inputs to
estimate site-specific costs of retrofitting S02 controls. The site-specific
information sources were used to develop process area retrofit multipliers, scope
adder costs, and boiler/coal parameters. This information was input to the IAPCS
cost model which generated the capital, operating and maintenance (O&M), and
, ' .
3
'.

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//
levelized annual costs ,of control and the emission reductions. The use of process
area retrofit difficulty multipliers and scope adder costs to adjust generic cost
model outputs to reflect site-specific retrofit situations was derived from an EPRI
report [3].
COST ESTIMATES FOR U.S PLANTS
"
Table 2 summarizes the economic bases used to develop the cost estimates. The
economic bases used in this study are not necessarily those that would be used
currently or by a utility company. This study was conducted between 1985 and 1990.
Economic assumptions such as inflation rate, cost of money, cost of consumables, and
expected plant life may be expected to vary with time. These parameters are from
the 1986 EPRI Technical Assessment Guide [4] escalated to 1988 dollars. The number
of boilers varied for each control technology because in some cases technology
application was technically not feasible. There were 631 boilers evaluated in the
200 plants.
For each control technology, the following three figures are presented: capital
cost (dollars/kilowatt), levelized annual costs (mills/kilowatt hour), and cost per
ton of S02 removed (dollars/ton) each plotted v~rsus the sum of controlled
megawatts. The x-axis (sum of megawatts) is the cumulative sum of the boiler size
sorted in order from the lowest to the highest cos~ to control. Also identified on
each curve are the 25, 50, and 75 sum of megawatt percent points for the bo~lers
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 ended with the boiler having th~..highest control
. ~ -.
cost. The cost results do not represent the ~verage or cumulative cost of control.
Costs developed in this report are based on economic assumptions which may not
represent a particular utility company's economic guidelines. The cost results are
static (not dynamic) and represent a single figure (1985 base year or other figures
specified by the individual utility company) with regard to capacity factor,coal
sulfur, and pollution control characteristics.
FGD Costs Estimates
Figures 3 through 5 summarize the cost estimates developed for wet lime/limestone
(L/LS) FGD for 449 boilers. Two FGD configurations were evaluated: a conventional
4

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New Source Performance Standard (NSPS) design Having a single system for each
boiler, small absorber size (125 MW or less), and one spare absorber; and a low-
cost design that does not have a spare absorber, uses larger absorber sizes when
feasible (up to 300 MW), and combined boiler systems when feasible.
Cost estimates for FGD were developed 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 about to be retired.
The percent increase in capital cost for retrofitting an FGD system over a typical
new plant installation ranged from 19 to 100 percent, with the average being 45
percent.
Figures 6 through 8 summarize the cost estimates for lime spray drying" (lSD) for all
the boilers for which costs were developed. Two control opti~ns were considered for
the retrofit of this technology: reuse of th~ existing electrostatic precipitator
(ESP) or installation of a new fabric filter (FF). Reuse of the existing ES~was
not considered for the following boiler situations: when the specific collection.
area (SCA) of the existing ESP was small  220 ft2/1000 actual ft3/min)l, and
when the addition of new plate area was impractical (e.g., roof-mounted ESPs).
In s~ch cases, a new FF was used for particulate matter control with the spray
prying system. If a unit is burning high sulfur coal (greater than 3 percent
sulfur), LSD with a new FF was not considered because it was assumed that wet FGD .
would be economically more attractive. Based. on the cited criteria, 168 ~oilers
were considered with a new FF option, and 195 boilers were considered with reuse of
existing ESPs. . ~.
For wet L/LS FGD;the'characteristics of the low, mid, and high unit cost boilers
are:
  Low S/ton Mid S/ton HiQh S/ton
Size, MW  496 194 100
Coal Sulfur, percent l.4 2.4 1.0
Capacity Factor 33.0 56 6
Retrofit Difficulty 1.38 1.54 1.84
lIt is EPA policy to use metric units. English units are used in this
paper because they are familiar to readers. Metric conversion factors
~re given at the end of this paper.
5

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For LSD FGD, the boiler characteristics of the low, mid. and ~igh unit cost boilers
are:
  Low S/ton Mid Siton Hiah S/ton
Size, MW  280 176 100
Coal Sulfur, percent 4.2 1.9 1.0
Capacity Factor 76 75 6
Retrofit Difficulty 1.23 1.55 1.87
Existing ESP or New ESP ESP FF
Fabric Filter   
Coal Switchina Cost Estimates
For coal switching (CS), two fuel price differentials (FPDs) were evaluated: $5/ton
and $15/ton. The $5 to Sl5/ton FPD was assumed to represent an estimated range for
the FPD after passage of acid rain legislation. The CS cost estimates are highly
dependent upon the FPD. The impacts of particulate matter control upgrades and coal
handling upgrades are generally small by comparison. Figures 9 through 11 summarize
the costs for 329 boilers in the 200 plants for which costs were developed for CS.
CS was not considered for some units because the units either already burn a low
sulfur coal or have wet bottom boilers that can b~rn only coals with s~eci~l ash
fusion properties. Capital costs for coal switching are predominantly from coal
inventory capital costs (30- to 60-day coal, inventory cost difference).
For coal switching, assuming a $15 per ton FPD, the low, mid, and high cost boilers
are:
 Low Siton Mid S/ton H~ah S/ton
Size, MW 496 900 497
Coal Sulfur, percent ~.4 1.9 1.1
Capacity Factor 33 76.2 43
6
. t

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Sorbent Injection Cost Estimates

~Two sorbent injection technologies in active research and development were evaluated
in this study: 1) duct spray drying (OSO) and 2) furnace sorbent injection (FSl-)
with humidifi~ation. Figures 12 through 17 summarize the cost estimates developed
for these technologies.
Some boilers were not considered good candidates for these technologies because:
.
FSI and OSO were not considered practical for boilers having an ESP SCA of
<220 ft2/1000 aCfm,2
(I
OSO was not considered if the duct residence time from the i~jection point
after the air heater to the ESP inlet was less than 2 sec 100 ft. of duct
length), and
.
FSI was not considered feasible for wet bottom and down-fired boilers.
, .
Only 321 boilers were considered' appropriate for OSO, and 289 were considered for
FSI applications. The costs presented for FSI assume 50 and 70 percent S02 control, .
with humidification to bracket the expected removal rate. No design parameter
changes were assumed to achieve either 50 or 70 percent S02 removal. Costs
presented for OSO assume 50 percent S02 'reduc~ion., '

For sorbent injection, the boiler characteristics of the low, mid, and high unit
cost boilers are:
. ,
'! Low Slton
Mid Slton
!llilJLjL1Qn
Size, MW
Coal Sulfur, percent
'Capacity Factor
Existing ESP or New
Fabric Filter
496
2.4
33
ESP'
585
1.2
56
ESP
23
1.3
20
ESP
7

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low NOx Combustion Cost Estimates
~~
Figures 18 through 20 summarize cost estimates for application of low NOx burner
(lNB) technology on dry bottom wall-fired boilers (20-55 percent NOx reduction),
overfire air (OFA) on tangential-fired boilers (10-35 percent NOx reduction), and
natural gas reburn (NGR) on all other boiler firing types (60 percent NOx
reduction). However, for boilers where NGR is-applied, the unit costs are S400 to
$1100 per ton of NOx removed. This is due to the cost of natural gas relative to
coal (assumed to be $2 per million Btu 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 for low NOx combustion technologies because of
the reservations of plant personnel regarding applicability of these technologies.
For low NOx combustion, the boiler characteristics of the low, mid, and high unit
cost boilers are:
 low $/tqn Mid S/ton HiQh $/ton
Size, MW 865 626 30
- Capacity Factor 79 65 5
lNC Type OFA OFA lNB
Selective Catalytic Reduction (SCR) Cost Estimates
Figures 21 through 23 summarize the cost estimates for application of SCR. For most
of the units, cold-side, tail-end systems were assumed (the reactor downstream of
the particulate control or scrubber). In some instances, due to space availability
limitations or the unit's being equipped with a hot-side ESP, a hot-side, high-dust
system configuration was used (the reactor between the economizer and the air
heater). Use of the tail-end system minimizes unit downtime, which reduces the
uncertainty of estimating the cost of replacement power, and maximizes the catalyst
life. However, a significant energy penalty is associated with flue gas reheating,
compared to a hot-side system (equivalent to 1200F reheat). This cost was not
included in this study. because the early version of IAPCS model did not estimate
this cost. Reheat costs estimated by the most recent version of IAPCS increase the
annual cost of control by 20 to 30 percent for cold-side systems. For this study,
624 boilers were evaluated for SCR retrofit.
8

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For SCR, the boiler characteristics of the low, mid, and high unit cost boilers are:
 Low Slton Mid Slton HiQh $/ton
Size, MW 217 543 25
Capacity Factor 94 49 2
Retrofit Difficulty 1.34 1.34 1.52
Hot-Side/Cold-Side Cold-Side Cold-Side Cold-Side
CONCLUSION
For each S02 and NOx control technology evaluated under this study, different
factors affected control cost and performance estimates for retrofit applications at
coal-fired boilers. Table 3 identifies those factors found to have the most
significant effects.
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 evaluated in this study are at various stages of
commerclal development. There is a higher degree of uncertainty regarding the cost
and performance of those technologies that do not have extensive commercial
~pplication 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 decision concerning which retrofit control to
apply to a given boiler is very complex. The data contained in .this report can
provide guidance in selecting the least-cost control options for specific
plants/boilers for various planning scenarios. The information can also be used by
technology developers to identify market niche and cost and performance go~ls.
Studies are currently ongoing to evaluate the market niche for two advanced sorbent
injection technologies and several advanced combustion technologies.
9

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REFERENCES
1.
2.
3.
4.
Elliot, T. C., ed. Powerplants Database, Details of the Equipment and Systems
in Utility and Industrial Powerplants, 1950-1984. McGraw-Hill, Inc.,
New York, New York, 1985.
Palmisano, P. J., and B. A. Laseke. User's Manual for the Integrated Air
Pollution Control System Design and Cost-Estimating Model, Version II,
Volume I. EPA-600j8-86-031a {NTIS PB87-127767}, U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, September 1986.
Shattuck, D. M., et al. Retrofit FGD Cost Estimating Guidelines. EPRI Report
CS-3696, Electric Power Research Institute {EPRI}, Palo Alto, California,
1984.
Electric Power Research Institute. Technical Assessment Guide (TAG),
Volume 1. Electricity Supply--1986. EPRI Report P-4463-SR, Palo A1to,
California, 1986.
CONVERSION FACTORS:
1 acfm = 0.000472 actual m3/sec
1 acre = 4046.9 m2
1 Btu = 0.2520 kg-cal
of
= c x 9/5 + 32
1 ft
= 0.3048 m
1 ft2 = 0.0929 m2
1 gal. = 3.785 liters
1 ton = 907 kg
10

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TABLE 1. EMISSION CONTROL TECHNOLOGIES EVALUATED
   Soecles Controlled  
 SO. NO. COIII11e rc \a 1
 Lime/limestone (L/LS) flue  X  X
 gas desulfurlzatlon (FGD)    
 Additive enhanced L/LS FGO  X  X
 Lime spray drying (LSD) FGD"  X  X
 Physical coal cleaning (PCC)  X  X
 Coal switching and blending (CS/B) X  X
 . Low-NO. combust I on (LNC)   X 
 Furnace sorbent Injection (FS 1) X
...... with humidification    
......     
 Duct spray drying (DSD)  X  
 Natural gas reburnlng (NGR)b  X X 
 Selective catalytic reduction (SCR)  X 
 Fluidized bed combustion (FBC) X X 
 or coal gasification (CG) retrofit.   
Development Status

LI ml ted
Conmerclal
. Experl ence
Ongoing Or
Near
Demonstration
X
X 
 X
 X
 X
X 
X 
"Commercial on low-sulfur coals; demonstrated at pilot scale on high sulfur coals.


bFor wet bottom boilers and other boilers where LNC Is not applicable.
.Evaluated qualitatively as combined life extension and SO./NO. control option. No costs were developed.

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TABLE 2
ECONOMIC BASES USED TO DEVELOP THE COST ESTIMATES
Item
Value
Operating labor.
19.7
$/person-hour
Water
0.60 $/1000 gallons
Limestone
65
15
$/ton
S/ton
Lime
Land
6,500
$/acre
Electric power
9.25 S/ton
0.05 $/kWh
Waste disposal
Catalyst cost
20,290
$/ton
'-"'''.
1988 constant dollar factors
Operating and maintenance
Capital carrying chargesa
1.0
0.105
aBook life - 30 years; Tax life - 20 years; Depreciation Method - Straight Line;
and Discount Rate - 6.1%.
12

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TABLE 3. RETROFIT FAcTORS AFFECTING COST/PERFORMANCE
   Additional 
Control Access and Ducting Particulate Boil er
Technology Congestion Distance Control Type
Lime/Limestone X X  
F1 ue Gas    
Desulfurization    
Lime Spray X X X 
Drying    "
Coal   X X
, Swi tchi ng    
Furnace Sorbent   X 
Injection    
Duct Spray  X X 
Drying    
Low NO    . X
Combustion   
Natural Gas    X
Reburning    
Selective X X  X
Catalytic    
Reduction    
13

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PHASE I 

Develop Detailed
Procedures
u
PHASE II
Select 12 Plants and
Develop Costl
Performance Estimates
Revise Procedures and
Cost E$.tlmates and
Develop Slmplliled
. Procedures
PHASE III
Evaluate 50 Plants

Verify Simplified
Procedures with Visits
to 6 Plants

Modify Procedures SInd
Evaluate Rsmslnlng 138
Pienta
PHASE IV
Finalize 200 Plant
Study Report
TECHNICAL ADVISORY
COMMITTEE
-EPRI
-EPA
-DOe
- Utility AIr Regulatory
Group
-TV A
- Natural Resource
Defense Council
- Vendors
UTILITY COMPANIES
- Ohio Edison
- American Electric Power
- Ohio Electric Utility .
Institute
-TV A
- Kentucky Utilities
- Union Electric
. Cincinnati Gas & Electric
200 Plant
Utility Companies
Figure 1. 200 Plant study t0chnlcal approach.
14
'.

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Site Specific Information Sources
Aerial
Photographs
Energy Information Administration - Form 767
Boller /Coal Characterls~lcs
Utility Comments and
Other Da~a Sources
Retrofit Factors
Scope Adder Cosb
BolI@r/Coall Paralmsters
Access/Congestion
Soli and Undarground
Flue Gao Ductlng
Genefsl Facilities
ReglooaB Cost Factorc
Wet to Dry Ash System
Chimney or liner
Particulate MaUer Controls
Boller Characteristics
Coal Characteristics
Capacity Factor
PM Control Type/Size
Flua Gae Tempera~ure
I-'
U'I
Multiplier

"
Dollars.
Direct Inputs
Cost Model Inputs
Integrated Air Pollution Contr08 System
Cost'Mod@1 OU~~lUts' .
Caplta8Coete
o &It M Cos~e
Annuellzed Costa
EmissIon Reduction.
FlgurCi 2. Site-opeclgic coat IIsUmstlon m
-------
~
~
"-
..
-
t-
en
o
o
-I
4:(
....
0:
~
o
700
600
. WET FGO . NSPS
.A LOW COST FGD
(No spare absorbers and
combi1ed boiers . )
1988 CONSTANT DOU.AA
500
400
50'lb of Totol MW
300
25~ of Total MW
200
50'lb of Total MW
"
100
15'1& of Total MW
25'11> of Total MW
o
120.000
o
20.000
40.000
60.000
SUM OF MW
80.000
100.000
Figure 3.
Summary of capital cost results for lime/limestone.
flue gas desulfurization.
100
m WET FGD . NSPS
A LOW COST FGD
(No spare absorbers and
corrUIed boaars . )
1988 CONSTANT DOLLARS
90
80
.....
s;
~
~
'-
~
E
......
70
60
to-
U)
o
(J
.....
~
::)
z
z
~
50
40
30
20
10
o
o
20,000
40.000
60.000
SUM OF MW
80.000
100.000
120.000
60% of Totol MW
25% of Total MW
~
60'11> of Totol MW
~
25% of Total MW
75' of Tota' MW
Figure 4.
Summary of annual cost results for lime/limestone
flue gas desulfurization.
16

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 9.000       
  III WET FGD . NSPS     
 8.000 A. LOW COST FGD     
.....  (No spare ab6abers and     
C      
W   COI'rDned bOiIsrs .)     
> 7.000 1988 CONSTANT DOLLARS    
0       
:s        
w        
a: 6.000       
ON        
(I)        
- 5.000       
0        
C        
0        
.. 4.000       
.......       
404        
-        
I- 3.000       
0       
0        
0        
to- 2.000  25'11> 01 Totlll MW     
Z       
~        
 1.000       
 0       
 0 20.000 40.000 60.000 80.000 100.000 120.000
     SUM OF MW   
Figure 5.
Summary of cost per ton of SO? removed results
for lime/limestone flue gas desulfurization.
17

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 400 
 1988 CONSTANT DOlLARS
 350 
 300 
"'"  
::  
~ 250 
" 
(jt  
..,  
...  110% 0' Tot., PAW
en 200
o  ~
CJ 
...I 

-------
5.000
-
c
~ ~.ooo
o
:'!
w
a:
ON
fn 3.000
-
o
c
o .
.,.
.......
. 2.000
-
D-
ei)
o
u
...
Z 1.000
:;)
1988 CONSTANT DOLLARS
28% of Totml MW
o
o
20.000
Figure 8.
. J
50'11:. of Totill MW
40.000
60.000
SUM OF MW
111<;1, 0' Tota' MW
80.000
100.000
Summary of cost per ton of S02 removed results'
for lime spray drying.
19

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70
60
i
~
"
-
-
50
40
30
20
10
o
o
I-
M
o
(J
.J
<
l-
s:
<
u
. $15 FU8.. PRICE DFFERENT1AL
A $5 FUEL PRICE DIFFERENTIAL

1988 CONSTANT DOLLARS
2S'II> of Tota. MW
~
20,000
Figure 9.
60'11> of Tota. MW
""
26'1b of Total MW
40.000
7 6~ of Tota. MW -
60'11> of Total MW
60,000
80,000
SUM OF MW
Summary of capital cost results for coal
switching.
 17  
  II $15 FUB.. PRICE DFFEREN11AL
 16 .6. $5 FUEl.. PRICE DFFERENT1AL
 15 1988 CONSTANT DOlLARS
 14  
..-   
~ 13  
~  
:Jt. 12  
.......   
== 11  
E 10  
-   
I- 9  
fA   
0 8  
(.)   
..J 7  
< 6  
:)  
Z 5  
Z  
< 4  
 3  
 2  
 0 
2&~ of Total MW
20.000
Figure 10.
60% of Total MW
'"
26'1b of Tota' MW
40.000
60"" of Total \lAW
7S~ of Tota' MW
60,000
80.000
SUM OF MW
Summary of annual cost results for coal
switching.
20
100.000
100,000

-------
.....
o
w
>
o
~
w
ex:
ON
en
-
o
C
o
~
........
(!)
-
9.000
3.000
7.000
6.000
5.000
4.000
t-
en
o
o
I-
Z
~
3.000
2.000
i.OOO
II $15 FU8.. mce DlFFERENT1AL
. $5 FUEL FRICE CXFFERemAL

1988 coNsTANT DOLLARS
o
o
20.000
Figure 11.
76% of Tota' MW
40.000
60.000
80.000
SUM OF MW
Summary of cost per ton of S02 removed results
for coal switching.
21
, 00.000

-------
 220         
   1988 CONSTANT DOLLARS      
 200         
 180         
-          
3 160         
~          
"          
fh 140         
-          
...          
(/) 120         
0         
(J          
..J 100    75% 0' Totsl MW  
         
F          
a: 80         
   28... 0' Tot.. MW SO'!b 0' Tot.1 MW     
(J       
 60         
 40         
 20         
  0 20.000 40.000 60.000 80.000 100.000
     SUM OF MW   
   Figure 12. Summary of capital cost results for 
    duct spray drying.     
 32         
   1988 CONSTANT DOllARS      
 28         
-          
J::. 24         
3:         
~          
......          
(/) 20         
E          
-          
~ 16         
fJJ          
0          
0 12         
..J         
          
:;)    SO~ of Totol MW     
Z        
Z 8         
   2S... of Totol MW      
 4         
 0         
  0 20.000 40.000 60.000 80.000 100.000
     SUM OF MW   
   Figure 13. Summary of annual cost results for 
    duct spray drying.     
     22     

-------
 3.800     
  1988 CONSTANT DOlLARS    
 3.400     
-      
Q      
LU 3.000     
:>     
0      
~      
W 2.600     
IX:     
ON      
en 2200     
-     
0      
C      
0 1.800     
_.     
"     
~.      
-.      
~, 1.400     
UI'     
'0      
(.)   60~ of Total MW   
... 1.000     
Z 26% of Total MW    
:;:)      
 600     
 200     
 0 20.000 40.000 60.000 80.000 100.000
   SUM OF MW   
Figure 14.
Summary of cost per ton of S02 removed results
for duct spray drying.
'.
23

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110
1988 CONSTANT DOLLARS
100
90
.....
~
~
"
o
.....
80
70
~
UJ
o
(,)
..J
4
l-
ii:
4
(,)
60
50
40
30
20
10
o
20.000
Figure 15.
 21 
  1988 CONSTANT DOllARS
 19 
..... 17 
.c  
3: 15 
~ 
"  
~ 13 
E 
.....  
I- 11 
en 
0  
(J 9 
...J  
ct  
::) 7 
Z 
Z  28~ of Tot.. MW

-------
 2.600   
  . 5O'J, REMOVAL 
 2.400 A 70% REMOVAL 
 2200 1988 CONSTANT DOLLARS 
-   
0    
W 2.000   
>   
0   ..
~ 1.800   
W    
a: 1.600   
O~   
en 1.400   
...   
0    
C 1.200   
0   
...    
........ 1.000   
.   
-   2G~ of Total MW GO~ of Totel MW
... BOO   
(/)   
0    
0 600   
....    
Z 400   
:::J    
 200   
 0   
 0  
7 e. of Totel MW
2 5~ of Total MW
50. of Totel MW
20.000
40.000
60.000
80.000
100.000
SUM OF MW
Fi gure 17.
Summary of cost per ton of S02 removed results
for furnace sorbent injection.
25

-------
45
40
35
,..
~
~
.......
o
--
30
25
I-
VJ
o
o
..J

-------
 1.600  
  A ue
  X aA
 1.AOO II NGR
-  1988 CONSTANT DOLLARS
C 
w   
> 1,200  
0  
~   
W   
cr: 1,COO  
0   
Z   
- 800  
0  
C   
0   
-   
........ eoo  
.,.  
-   
to-   
en   
0 400  
U   26% of Totel MW
to-   
Z 200  
~  
 0  
 0 20.000
40.000
so.ooo
SUM OF MW
Figure 20.
Summary of cost per ton of NOx removed results for low NOx combustion.
27

-------
 280 
  1988 CONSTANT DOlLARS
 240 
- 200 
:t 
~  
"  SO... of Total MW
o 160
- 
....  2S~ of Total MVt
en  ""
o 
0 120
..JI  
~  
....  
&L 80 
~  
Co)  
40
3 YEAR CATALYST LFE
o
o
20.000
eo.ooo
100.000
140.000
180.000
Figure 21.
SUM OF MW
Summary of capital cost results for selective catalytic reduction.
24
1eaa CONSTANT DOLLARS
20
-
J:.
3:
~
"-
.!
E
-
...
(I)
o
()
-I
~
::)
Z
Z
~
8
~
75' of Totel MW

~
16
12
28'160 0' Tota' MYt
4
3 YEAR CATALYST LR
o
o
20.000
60.000
100,000
140.000
180.000
SUM OF MW
Figure 22.
Summary of annual cost results for selective catalytic reduction.
28

-------
 7.000  
  1988 CONSTANT OOUARS 
- 6.000  
"   
W   
:>   
0   
:E 5.000  . .
 . ~
w   
a:   
0)(   
Z 4.000  
-   
0   
C   
0   
- 3.000  
"  
fh  .o~ 0' Total MW
- 
~  2'~ of Totol MW 
en 2.000  
0  
0   
...   
Z   
:;)   
1.000
3 YEAR CATA!.. YST lFE
o
o
20.000
40.000
60.000
80.000 100.000 120.000 11.000 160.000 180.000 200.000
SUM OF MW
Figure 23.
Summary of cost per ton of NO removed results
for selective catalytic redu2tion.
29

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