.RETROFIT COSTS OF S02 AND NOx CONTROL AT 200 U.S. 

COAL-FIRED PLANTS 
Report No. l1!\~OS38 InfoTeam Inc. 

Merton Allen Associates 

P.O. Box 15640 

Plantation, FL 33318-5640 

-- -100R90120 

~ 

PROPERTY OF 

EPA LlBRI\RY, RTP, rue 

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 
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 nitroge,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:aerhl 

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 
" 

INTRODUCTION 

RETROFIT COSTS OF S02 AND NOxCONTROL 

AT 200 U.S. COAL-FIRED POWER PLANTS 

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 retrofit 

factors for large coal-fired power plants in the above cited region. lhe 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 conduci'ed. 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 sitespecific 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. Additionaliy, ,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 
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 parameter.s 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 paint 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 .theboiler 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 
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 lowcost 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 ESP 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 FGO;the'characteristics of the low, mid, and high unit cost boilers 

are: 

Low S/ton Mid S/ton High $/ton 

Size, MW 496 194 100 

Coal Sulfur, percent a.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 
For LSD FGD, the boiler characteristics of the low, mid. and ~igh unit cost boilers 

are: 

Low Siton Mid Siton High Siton 

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 Switching Cost Estimates 

For coal switching (CS), two fuel price differentials (FPDs) were evaluated: $s/ton 

and $Is/ton. The $5 to SIS/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 

fus i on propert i es. Cap ita 1 costs for coal sw'itch i ng are predomi nant 1 y from coal 

inventory capital costs (30- to 60-day coal, inventory cost difference). 

For coal switching, assuming a SIS per ton FPD, the low, mid, and high cost boilers 

are: 

Low Siton Mid Siton High Siton 

Size, MW 496 900 497 

Coal Sulfur, percent ~.4 1.9 1.1 

Capacity Factor 33 76.2 43 

6 
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 

OSO was not considered if the duct residence time from the i~jection paint 

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: 

Size, MW 

Coal Sulfur, percent , Capaci ty Factor 

Existing ESP or New 

Fabric Filter 

" Low $Iton 

7 

496 

2.4 

33 

ESP' 

Mid Slton 

585 

1.2 

56 

ESP 

High $/ton 

23 

1.3 

2,0 

ESP 
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: 

Size, MW 

Capacity Factor 

lNC Type 

low S/tqn 

865 

79 

OFA 

Selective Catalytic Reduction (SCR) Cost Estimates 

Mid S/ton 

626 

~ 

OFA 

High S/ton 

30 

5 

lNB 

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 
For SCR, the boiler characteristics of the low, mid, and high unit cost boilers are: 

Low Slton Mid Slton High $/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 controi 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 
REFERENCES 

1. 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. 

2. 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-600/8-86-031a {NTIS PB87-127767}, U.S. Environmental Protection 

Agency, Research Triangle Park, North Carolina, September 1986. 

3. Shattuck, D. M., et al. Retrofit FGD Cost Estimating Guidelines. EPRI Report 

CS-3696, Electric Power Research Institute {EPRI}, Palo Alto, California, 

1984. 

4. Electric Power Research Institute. Technical Assessment Guide (TAG), 

Volume 1. Electricity Supply--1986. EPRI Report P-4463-SR, Palo Alto, 

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 
...... 

...... 

TABLE 1. EMISSION CONTROL TECHNOLOGIES EVALUATED 

SQecles Controlled 

SO. NO. 

Lime/limestone (L/LS) flue X 

gas desulfurlzatlon (FGD) 

Additive enhanced L/LS FGO X 

Lime spray drying (LSD) FGD' X 

PhYSical coal cleaning (PCC) X 

Coal switching and blending (CS/B) X 

. Low-NO. combust I on (LNC) X 

Furnace sorbent Injection (FSI) X 

with humidification 

Duct spray drying (OSO) X 

Natural gas reburnlng (NGR)b X X 

Selective catalytiC reduction (SCR) X 

Fluidized bed combustion (FBC) X X 

or coal gasification (CG) retroflt< 

'Commerclal on low-sulfur coals; demonstrated at pilot scale on high sulfur coals. 

"For wet bottom boll ers and other boll ers where LNC I s not appll cab 1 e. 

COIII1lerclal 

X 

X 

X 

X 

X 

<Evaluated qualitatively as combined life extension and SO./NO. control option. No costs were developed. 

Development Status 

LImited 

Conmerclal 

. Experl ence 

X 

x 

X 

Ongoing Or 

Near 

Demonstration 

X 

X 

X 

X 
TABLE 2 

ECONOMIC BASES USED TO DEVELOP THE COST ESTIMATES 

Item Value 

Operating labor 19.7 $/person-hour 

Water 0.60 $/1000 gallons 

Lime 65 $/ton 

Limestone 15 S/ton 

Land 6,500 $/acre 

Waste disposal 9.25 S/ton 

Electric power 0.05 $/kWh 

Catalyst cost 20,290 $/ton " 

1988 constant dollar factors 

Operating and maintenance 1.0 

Capital carrying chargesa 0.105 

aBook life - 30 years; Tax life - 20 years; Depreciation Method - Straight Line; 

and Discount Rate - 6.1%. 

12 
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 , Switching 

Furnace Sorbent X 

Injection 

Duct Spray X X 

Drying 

Low NO 

Combustion 

X 

Natural Gas X 

Reburning 

Selective X X X 

Catalytic 

Reduction 

13 
PHASE I 

Develop Detailed 

Procedures 

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 wHh Visits 

to 6 Plants 

Modify Procedures SInd 

Evaluate RsmSllnlng 138 

Pienta 

PHASE IV 

Finalize 200 Plant 

Study 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 . 

TV 

Institute - A - Kentucky Utilities 

.. Union Electric 

• Cincinnati Gas & Electric 

200 Plant 

Utility Companies 

Figure 1. 200 Plant study t0chnlcal approach. 

14 
Site Specific information Sources 

Aerial Energy Information Administration - Form 767 Utility Comments and 

Photographs Boller /Coal Characterls~lcs Other Da~a Sources 

Retrofit 

, 

r~' Factors Scope Adder 

¥~1' Coeb BolI@r/Coal! Paumstera 

Access/Congestion Wet to Dry Ash System Bollsr Chalracterlstlcs 

Soli and Underground Chimney or lIn@r Coal Charac.terlstica 

Flue Gao Ductlng Particulate MaUer Controls Capacity Factor 

Ganersl Facilities PM Control Typ@/Slze 

ReglonaD Cost factoi'm Flua Gae T@mpera~ure 

~ Multiplier 

" 

Dollars· Direct Inputs 

Coet Model Inputs 

Integrated Air Pollution Contr08 System 

CapBtaSCoete 0 &It M Coe.Qe Annu21llzed Coata Emluslon Reduction. 
een 

o 

o 

-I 

4:( 

.... 

0: 

~ 

o 

..... 

s; 

~ ~ 

'-

~ 

E 

...... 

toU) 

0 

(J 

..... 

~ 

::) 

Z 

Z 

~ 

7oo.-~--------------~----------------------------------------~ • WET FGO • NSPS 

.A LOW COST FGO 

600 (No spare absorbers and 

combi1ed boiers . ) 

1988 CONSTANT OOUAA 

~1-----------------------------------------------------~--~ 

~1-------------------------------------------------~~----~ 

50'lb of Totol MW 

~~------------------ --~~--------------~~~~--------4---~ 25'1l> of Total MW 

1oo~=---~~------~--------------~~----------~--~.----------~ 50'lb of Total MW 15'1& of Total MW 

25'11> of Total MW 

O;----.----r----r--~----~--_r--_.r_--~--_.----r_--_r--~--~ 

100 

90 

80 

70 

60 

50 

40 

30 

20 

10 

0 

o 

-

-

20,000 40,000 60,000 80,000 100,000 120.000 

SUM OF MW 

Figure 3. Summary of capital cost results for lime/limestone. 

flue gas desulfurization. 

m WET FGD • NSPS 

A . LOWCOSTFGD 

(No spare absorbers and 

conililed boilers . ) 

1988 CONSTANT DOU.ARS 

J 

7 6'Mo of Totol MW J 

60% of Totol MW 

25% of Total MW '", .~ /j ~. ' .. '-:-~ ../' 

1- ~ ----- 60'11> of Total MW 

~ 

o 

25% of Total MW 75' of Total MW I 

20,000 40,000 60,000 80.000 100.000 120,000 

Figure 4. 

SUMOFMW 

Summary of annual cost results for lime/limestone 

flue gas desulfurization. 

16 
9.000 

8.000 ...... 

C 

W 

> 7.000 0 

:s 

w 

a: 6.000 

ON 

(I) 

- 5.000 

0 

C 

0 

.. 4.000 ....... 

404 

-

0- 3.000 en 

0 

0 

to- 2.000 

Z 

~ 

1.000 

0 

III WET FGO • NSPS . A. LOWCOSTFGD - (No spare ab6abers and 

COI1'tlined bOiIsrs . ) 

- 1988 CONSTANT DOLLARS 

If 71l~ of Totel MW 77 . 

21l'MIOfT~W 50'1& of Tota. MW 

~-

, ~~ 

[P'" - I I --. -T -T --. --. --. o 20.000 40.000 60.000 80.000 100.000 120.000 

Figure 5. 

SUMOFMW 

Summary of cost per to'n of SO? removed resul ts 

for lime/limestone flue gas desulfurization. 

17 
,.. 

:: 

~ 

"-

(jt 

.., 

... 

(I) 

0 

(J 

...I 

~ 

... 

Ci: 

< (J 

,.. 

s:: 

~ :tt. 

"-

~ 

.., 

E 

lf/) 

0 

(J 

-' ct 

:l 

Z 

Z 

< 

400 

1988 CONSTANT DOllARS 

350 

300 

250 

110% 0' Tot.1 PAW 200 

150 

2S ... of Tot.1 MW 

~ 

100 

50 

o ~----~--~-----r----~---.-----.----'-----r---~----~--~ 

35 

30 

25 

20 

15 

10 

5 

0 

o 20.000 

Figure 6. 

40.000 60.000 80.000 

SUMOFMW 

Summary of capital cost results for 

lime spray drying. 

1988 CONSTANT OOI..l.ARS I . 

100.000 

j 

/ 78~ of Tot., MW 1 

211 ... of Toto. MW , 

~ ... 1/ 

I I 

o 20.000 

Figure 7. 

80~ of Total PAW 

~ / "" "- --

I 

40.000 60.000 80.000 

SUMOFMW 

Summary of annual cost results for 

lime spray drying. 

18 

100.000 
5.000 

-c 

W ':'.000 > 0 

:'! 

w 

a: 

ON 3.000 fn 

-0 

C 

0 

.,. 

....... 

• 2.000 

-

DU) 

0 

U 

... , .000 Z 

:;) 

o 

1988 CONSTANT DOlLARS I 

I-"" 

o 

.OJ 

) 

I 

~ - 711<;1, of Tota. MW 

211% of Total MW 50'11:. of TO~' MW 

~ 

~. 'x. .JJ:'r 

- - - -

I 

20,000 

Figure 8. 

'. 

I I 

40,000 60,000 80,000 , 00,000 

SUM OF MW 

Summary of cost per ton of S02 removed results . for lime spray drying. 

19 
70 

60 

-

~ 50 

~ 

-

" - 40 IM 

0 

(,) 

.J 30 

< ls:: 20 < 

U 

10 

0 

17 

16 

15 

14 ..-

~ 13 ~ :Jt. 12 ....... 

== 

11 

E 10 

-I- 9 

fA 

0 8 

(,) 

..J 7 

< 6 :l 

Z 5 Z 

< 4 

3 

2 

• $15 FU8.. PRICE CFFERENT1Al 

A $5 FUEL PRICE DIFFERENTIAL 

1988 CONSTANT DOLLARS 

7 !I'M. of Total MW 

as'M. of Total MW 60% of Total MW 

~ 

"" 7 5~ of Total MW 

GO'll> of Total MW 

2G'M. of Total MW 

0 20,000 40,000 60,000 80,000 

SUMOFMW 

Figure 9. Summary of capital switching. 

cost results for coal 

II $15 FUB.. PRICE OFFERENllAL - .6. $5 FUEl.. PRICE 0FFERENT1AL 

- 1988 CONSTANT DOlLARS 

- 75~ of Total MVi ~ 2&~ 0' Total MW GO'llbOfT~W 

~ / -

"" ~ '. - - - - - I - J:J. 

.... ~ 

'" -I~ '" ~ "'" 26'11> of Total MW 50"" of Total \lAW 7S~ of Tota' MW 

o 20.000 40.000 60.000 80.000 

SUMOFMW 

Figure 10. Summary of annual cost results for coal 

switching. 

20 

100,00C 

I -

100.000 
9.000 

3.000 ..... 

0 

W 

> 7.000 

0 

~ 

W 6.000 ex: 

ON 

en 5.000 

-

0 

C 

~ 

0 4.000 ........ 

~ 

-t- 3.000 

en 

0 

0 2.000 IZ 

:l i.OOO 

0 

II $15 FUEL mel: DlFFERENllAL . 

A- $5 FlJ/3.. PRICE CXFFERENTlAL 

- 1988 caNsT ANT OOtLARS 

<, 

.. " 

76% of Tota' MW 

50% of Tota' MW '" J 

25% of Totlll MW \ \\ ~I 

\ ~ ~ .J 

\\." ~"A , ---- I~ 'A' 

o I T I T I I 20,000 40,000 60,000 80,000 

SUMOFMW 

Figure 11. Summary of cost per ton of S02 removed result's 

for coal switching. 

21 

-

100,000 
220 

200 

180 

-

3 160 

~ 

"-

fh 140 

-... 

(/) 120 0 

(J 

..J 100 « 

to: 80 « 

(J 

60 

40 

20 

o 

32 

28 

-

J::. 24 

3: 

~ 

"-

(/) 20 

E 

-

~ 16 

fJJ 

0 

0 12 ..J 

« 

:;) 

z 8 Z 

« 

4 

0 

o 

1988 CONSTANT DOLLARS J 

/ 

75% 0' Totsl MW r ~ j 

211 ... of Tot., MW 

" 

~ 

~ 

20.000 

.-- " ... 

60'!b of TO~W 

~ 

40.000 

SUMOFMW 

L 

60.000 80.000 

Figure 12. Summary of capital cost results for 

duct spray drying. 

1988 CONSTANT DOllARS I 

1 

I 

-

, 

I 

7 6~ 0' Tot.1 MW 

60~ of Tot., MW / "" 26"'OfTotlll~ 

~ ~ 

- - I I I 

20.000 40.000 60.000 80.000 

SUM OF MW 

Figure 13. Summary of annual cost results for 

duct spray drying. 

22 

I 

I 

100.000 

- I 

100.000 
3.800 

3.400 

-

Q 

I.LI 3.000 > 

0 

~ 

W 2.600 a: 

ON 

en 2200 -

0 

C 

0 -. 1.eoo " ~. -. 

~, 

1.400 «II' 

0 

(.) 

... 1.000 Z 

:;:) 

600 

200 

o 

1988 CONSTANT DOlLARS I -

.. 

'. 'j 

I 

J 

18'1& of Totlll MW J -

80~ of Total MW ~ L 

28'1& 0' Total 

~ 

MW 

'- ~ 

~ - ~ 

I 

20.000 

Figure 14. 

I I 

40.000 60.000 80.000 100.000 

SUMOFMW 

Summary of cost per ton of S02 removed results 

for duct spray drying. 

23 
110 

100 

90 

..... 

~ 80 ~ 

0 " 70 ..... 

0-

f/) 

60 0 

(,) 

..J 50 4« 

lii: 40 4« 

(,) 

30 

20 

10 

21 

19 

..... 17 

.c 

3 

~ 15 

" 

~ 13 E ...., 

l- II en 

0 

(J 9 

...J 

cl 

:;:) 7 Z 

Z 

c:( 5 

3 

1 

1988 CONSTANT DOLLARS I 

70 ... of Total MW 

~ ,.rf 

-r--

SO% of Total 

"" 

MW 

~ 28"" of Total 

"-

~~ 

MW 

~ 

~ 

J 

o 20.000 

Figure 15. 

40.000 

SUMOFMW 

60.000 . 80.000 

Summary of capital cost results for 

furnace sorbent injection. 

1988 CONSTANT DOllARS I 

76'16. of Total PAW 

I ~. 

-

/ GO~ of Total MW "'" ) 

1-----

o 

a81llt of Total MW 

"-

~ 

~ .. 

20.000 

~ ~ 

40.000 

SUMOFMW 

...-r- ~~ 

60.000 SO.OOO 

Figure 16. Summary of annual cost results for 

furnace sorbent injection. 

24 

100.000 

. 

100.000 
2.600 

2.400 

- 2200 

0 

W 2.000 > 0 

~ 1.800 

W 

a: 1.600 O~ 

en 1.400 ... 

0 

C 1.200 

0 

... 

........ 1.000 • 

-... BOO (/) 

0 

(.) 600 

!:: 

Z 400 

::::» 

200 

0 

. 

• 5O'J, REMOVAL 

- A 70% REMOVAL 

1988 CONSTANT DOLLARS I 

2G~ of Total MW 

~ <W 

I~ 

o 20,000 

Fi gure 17. 

) .. 

.. 

I . , . 

) 

., G~ of Totol MW ~ GO~ of TO~I MW 

~ J / . 

" _.DI"" / -..u ~ 

A '- " '" ~., a_ of Totcl MW 

"- 50_ of Totel MW 2 5~ of Total \Ill'll 

1 -. I I -. 

40,000 80,000 80,000 100,000 

SUMOFMW 

Summary of cost per ton of SO removed results 

for furnace sorbent injection~ 

25 
..... 

~ 

3 

.:Jt. 

" :1 

E 

..... 

.... 

en 

0 

(J 

.... 

4 

:;:) 

Z 

Z 

4 

45 

.4 IH5 

40 X OFA 

iii NGR 

35 1988 CONSTANT DOU.ARS 

30 

25 

78% of Tot.1 MW 

20 

15i---~~~~----------------~~--~u-------------.--1 

60% of Totol MW 

O~------~------~--------.-------.--------r-------.------~ 

6 

5 

4 

3 

2 

1 

o 20.000 40.000 

SUM Or: MW 

60.000 

Figure 18. Summary of capital cost results for low NOx combustion. 

A LNS 

X OFA 

II NGR 

1988 CONSTANT DOU.ARS 

25% of Totol MW 

o 20,000 

't 

76% of Totol MW 

40.000 

SUMOFMW 

SO.OOO 

Figure 19. Summary of annual cost results for low NO

x 

combustion. 

26 
1,600 

A ue 

X aA 

1.AOO II NGR 

-C 1988 CONSTANT DOlLARS 

w 

> 1.200 0 

~ 

W 

cr: 1.000 

0 

Z 

- 800 0 

C 

0 

-........ 

.,. eoo 

-ten 

0 400 

(.) 26% of Totel MW 

tZ 

~ 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 NO

x 

combustion. 

27 
280 

1988 CONSTANT DOlLARS 

240 

- 200 :t 

~ 

" SO ... of Total MW 0 160 -.... as~ of Totlll Mvt 

en "" 0 

(,) 120 

..JI 

~ 

.... 

EL 80 

~ 

Co) 

4O~----------------------------------------------------------~ 

3 YEAR CATALYST lFE 

o 20.000 eo.ooo 100.000 140.000 180.000 

SUMOFMW 

Figure 21. Summary of capital cost results for selective catalytic reduction. 

24 . 

1S88 CONST~ DOLLARS I 

20 

-

J:. 

3: 

~ 

"- 16 

.! 

E 

-... 12 

(I) 

0 

() 

-I 

c:( 8 

:l 

Z 

Z 

) 

28'160 of Tota. MYI 

eo~ of Toto' MW T"·1T~7 "-

~na "'. --~ 

~ 4 1"""-

3 YEAR CATALYST LR 

o I I I I I I I I 1 I I -. T 

o 20.000 60,000 100.000 140,000 180.000 

SUMOFMW 

Figure 22. Summary of annual cost results for selective catalytic reduction. 

28 
7.000 ........----------.----------------------, 

1988 CONSTANT DOlLARS 

-

o ~~ ~-----------------------------------+--~ 

w 

:> 

o 

~ ~~4-------------------~------~.~.----------------------~--~ W 

c:c 

0)( 

Z 4.000 -+------------------------------------#---.-, -o 

c 

o 

-

"-

fh 

-

~ 

en 

o 

(,) 

... 

Z 

:;) 

aooo ~------------------~--~----~~----~ .o~ 0' Tota. MW 

2'~ of Totol MW 

~~~------~------------~~~~~~------------~ 

1.000 -+---,.."...~---------------------------------------~ 

3 YEAR CATA!.. YST lFE 

a 20.000 40.000 60.000 80.000 100.000 120.000 1«1.000 160.000 180.000 200.000 

Figure 23. 

SUMOFMW 

Summary of cost per ton of NO removed results 

for selective catalytic redu2tion. 

29