### .RETROFIT COSTS OF S02 AND NOx 

### CONTROL AT 200 U.S. COAL-FIRED PLANTSReport No.**l1!\~OS38** InfoTeam Inc. Merton Allen Associates P.O. Box 15640 Plantation, FL 33318-5640



## -- -100R90120**~** PROPERTYOF EPALlBRI\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
3levelized 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 4New Source Performance Standard (NSPS) design Having 

## asingle 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. 5For 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 fusion properties. Capita1 costs for coal sw'itching are predominant1 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

6Sorbent 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
,Capacity 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 ESPlow NOx Combustion Cost Estimates Figures 18 through 20 summarize cost estimates for application of low NO

### x 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.

8For 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.

9REFERENCES 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 m 3

/sec 1 acre 

### =4046.9 m 2 1 Btu 

### = 0.2520 kg-cal 

### OF 

### =

## °c x 9/5 + 32 1 ft 

### =0.3048 m 1 ft2 

### =0.0929 m 2 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. combustIon (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 bollers and other bollers where LNC Is not appllcab1 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

.Experlence

X

x X Ongoing Or Near Demonstration

X

X X XTABLE 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 Boiler Technology Congestion Distance Control Type Lime/Limestone X X 

### F1ue 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

13PHASE 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 Evaluate50 Plants

VerifySimplified ProcedureswHh Visits to6 Plants ModifyProcedures SInd Evaluate RsmSllnlng 138 Pienta

PHASE IV Finalize200 Plant Study Report TECHNICALADVISORY COMMITTEE

- EPRI -EPA -DOE • UtilityAIr 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 UtilityCompanies

Figure 1. 200 Plant studyt0chnlcal approach. 14Site Specific informationSources Aerial Energy InformationAdministration - Form 767 Utility Commentsand Photographs Boller/Coal**Characterls~lcs** Other**Da~a** Sources 

# ,

# r~'**¥~1'** Retrofit Factors ScopeAdder Coeb BolI@r/Coal! Paumstera Access/Congestion Wetto Dry Ash System Bollsr Chalracterlstlcs Soli andUnderground Chimneyor lIn@r CoalCharac.terlstica FlueGao Ductlng Particulate MaUer Controls Capacity Factor GanerslFacilities PMControlTyp@/Slze ReglonaD Costfactoi'm Flua Gae**T@mpera~ure**

# ~ Multiplier 

# " Dollars· Direct Inputs
Coet Model Inputs IntegratedAir PollutionContr08 System
CapBtaSCoete 0 &It M Coe.Qe Annu21llzed Coata EmluslonReduction.een 

### o o -I 4:(


### .... 0:**~** o

..... s;**~ ~**  '-**~** 

### E

......toU) 0 (J

.....**~** ::) Z Z**~ 7oo.-~--------------~----------------------------------------~**  • WET FGO • NSPS .A LOW COST FGO 600 (No spareabsorbers and combi1ed boiers. ) 1988CONSTANT 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 conililedboilers. ) 1988CONSTANT DOU.ARS

J
76'Mo of TotolMW 

# J 60% of Totol MW**.~** 

# /j 25% of Total MW '",

## ~. 

# '

..**'-:-~** 

## ../'
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. 169.000 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'tlinedbOiIsrs. )

- 1988CONSTANT DOLLARS 

# If**71l~** of TotelMW 

# 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 results 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 1988CONSTANT DOllARS 350 300 250
110%

### 0' Tot.1 PAW 200 2S... of Tot.1 MW

# ~ 150 100

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.

1988CONSTANT OOI..l.ARS 

# I

. 100.000

j 

# /**78~** ofTot., 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. 18 100.0005.000



# - c W ':'.000 > 0 :'! w a: ON 3.000 fn 

# - 0 C 0 .,.

....... 

# • 2.000 

# -DU) 0 U


# ... , .000 Z :;)
o 1988CONSTANT DOlLARS 

# I

I-"" o .OJ ) 

### I

# ~ - 711<;1, ofTota. MW 211% ofTotal 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.

1970
60



# -**~** 50**~** 

# " 

# - - 40IM 0 (,) .J 30 <l

### s:: 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 

# • $15FU8.. PRICECFFERENT1Al A $5FUEL PRICE DIFFERENTIAL 1988CONSTANT 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. $5FUEl.. PRICE 0FFERENT1AL

- 1988CONSTANT 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


### -

100.0009.000 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 2.000IZ :l i.OOO 0 II $15 FUELmel:DlFFERENllAL . A- $5FlJ/3.. PRICE CXFFERENTlAL



## - 1988caNsT ANTOOtLARS

<,

.."

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 

### -

100,000220 200 180



# - 3 160**~** "- fh 140 

# - ... (/) 120 0 (J ..J 100 

### «t

## o: 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 1988CONSTANT 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.

1988CONSTANT 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

100.0003.800 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 1988CONSTANT DOlLARS 

## I

-

.. '. 

# 'j I J
18'1& of Totlll MW 

# J

-**80~** ofTotal MW

# ~ 

# L
28'1&

## 0' TotalMW

## ~

# ~**~** 

# - 

# '-**~**
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.

23110 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 1988CONSTANT DOLLARS

## I

70
... ofTotal MW

## ~ 

# ,.rf SO% ofTotal MW

# ~ -r-- 

# ""**~** 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.

1988CONSTANT DOllARS

## I

76'16. ofTotal PAW 

# I**~.**

-



# /**GO~** of Total MW 

# "'" )

1----- o a81llt ofTotal 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

.

100.0002.600 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 !:: 400 Z ::::» 200 0 . 

# • 5O'J, REMOVAL



### - A 70% REMOVAL 1988CONSTANT DOLLARS I**2G~** ofTotal MW

## ~ <W

## I~ o 20,000
Figure 17. 

### ) ..

.. 

# I
.

, . 

## )

.,**G~** ofTotol MW

## ~**GO~** of**TO~I** MW

## ~ 

# J 

# /
. 

# " _.DI"" 

# /
-..u**~**

A 

### '-

" 

# '"**~.,**

### a_ ofTotcl MW "- 50_ofTotel MW 2**5~** ofTotal\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 1988CONSTANTDOU.ARS 30 25 78% ofTot.1 MW 20**15i---~~~~----------------~~--~u-------------.--1** 60% ofTotol 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 1988CONSTANT DOU.ARS

25%ofTotol MW

o 20,000 't

76% ofTotol MW

40.000 SUMOFMW SO.OOO Figure 19. Summary of annual cost results for low NOx combustion.

261,600 A ue 

### X aA 1.AOO II NGR 

# - C 1988CONSTANT DOlLARS w > 1.200 0**~** W cr: 1.000 0 Z 

# - 800 0 C 0 

# -

........ eoo 

# .,. 

# -ten 0 400 (.) 26% ofTotelMWtZ 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.

27280 1988CONSTANTDOlLARS 240



# - 200 

### :t**~** 

# " SO
...ofTotalMW 0 160 

# -

....**as~** ofTotlll Mvt en 

# "" 0 (,) 120 ..JI**~** 

## .... EL 80**~** Co)**4O~----------------------------------------------------------~** 3 YEAR CATALYSTlFE 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 8 c:( :l Z Z 

# )**eo~** ofToto' MW

# T"·1T~7 28'160 ofTota.MYI 

### "-

# ~na 

# "'.**~** 

# --**~** 4 1"""- 3 YEAR CATALYSTLR 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. 287.000 ........----------.----------------------, 1988CONSTANTDOlLARS



# -**~~ ~-----------------------------------+--~**  

### o w :> o**~ ~~4-------------------~------~.~.----------------------~--~**  W c:c 0)( Z 4.000 

## -+------------------------------------#---.-, 

# - o c o 

# - "- fh 

# -**~** en 

### o (,)


# ... Z :;) aooo**~------------------~--~----~~----~ .o~** 

### 0' Tota. MW**2'~** ofTotolMW**~~~------~------------~~~~~~------------~** 1.000**-+---,.."...~---------------------------------------~** 3YEAR 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