p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

315) IV-B-19 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:59 AM Sheet 315 of 325 
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. r-l A-83-27 

CORPORATION IV-B-19 

MEMORANDUM 

DATE: April 29, 1987 

TO: Fred Porter, EPA/SDB 

FROM: Jeff Shumaker and Tom Waddell, Radian Corporation 

SUBJECT: Use of a Generic Cost Algorithm to Represent the Costs of 

Industrial Flue Gas Desulfurization (FGD) Systems 

1.0 INTRODUCTION 

New source performance standards were proposed recently which require 

90 percent SO- reduction for all new coal- and oil-fired industrialcommercial -institutional boilers of greater than 100 million Btu (MMBtu) per 

hour heat input (51 Federal Register 22385, June 19, 1986). Cost analyses 

performed in support of the proposed standards used the sodium scrubbing 

cost algorithm as a "generic" cost algorithm to represent the costs of 

industrial FGD systems in general. 

During the public review period, comments were received questioning the 

use of the sodium scrubbing cost algorithm as a generic cost algorithm. 

Consequently, the costs predicted by cost algorithms for several sulfur 

dioxide control options were reviewed to determine if a cost algorithm other 

than the one for sodium scrubbing would better serve as a "generic" FGD cost 

algorithm. Cost algorithms for sodium scrubbing, dual alkali, Um e spray 

drying, and fluidized bed combustion (FBC) were available for this 

assessment. The cost algorithms for sodium scrubbing, dual alkali, and Um e 

2 

spray drying are outlined and discussed in the 1984 S0g Cost Report and 

Radian's recent memorandum examining the impact of new fuel prices on 

3 

annualized boiler costs. The cost algorithm for FBC units is outlined and 

4 

discussed in the 1984 FBC report. Fuel prices used in this analysis are 

3 

shown in Table 1; these prices reflect the revised energy scenarios. The 

Progress Center/3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box 13000/Research Triangle Park. N.C. 27709/(919)541-9100 
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analysis is based on model 150 MMBtu/hr heat input capacity boilers firing 

either coal (for Region V and VIII) or oil (Region V only). 

2.0 DISCUSSION 

Annualized costs were calculated for both coal-fired and oil-fired 

steam generating units. Previous analyses have generally shown that in 

response to standards requiring a percent reduction in SO- emissions, steam 

generating units find it more economical to fire high-sulfur fuels than 

low-sulfur fuels. Consequently, the annualized costs for steam generating 

units firing high-sulfur coal and high-sulfur oil were examined. For 

coal-fired steam generating units located in Region VIII, however, 

high-sulfur coal is generally not available and costs were examined for 

steam generating units firing medium-sulfur coal. 

The results are summarized in Table 2 and Figures 1 and 2. As shown, 

there is little difference in the total annualized costs of the steam 

generating unit and FGD system regardless of which cost algorithm is used to 

estimate the annualized costs of the FGD system. In fact, the difference in 

costs is less than 7 percent in all cases for coal-fired steam generating 

units and less than 9 percent for oil-fired steam generating units. From 

this point of view, therefore, it makes little difference which cost 

algorithm is used to represent the costs of FGD systems for industrial steam 

generating units. 

Closer examination of these two figures, however, indicates that the 

cost algorithm for sodium scrubbing generally yields the lowest costs, 

whereas the cost algorithm for dual alkali scrubbing yields the highest 

costs. Also, the variation in costs is seen to be considerably higher if 

one focuses on the costs of the FGD system alone. For example, the 

annualized costs of the FGD system for a coal-fired steam generating unit 

can vary by about 30 percent, depending on whether the cost algorithm for 

sodium scrubbing or that for dual alkali scrubbing is used. 

It appears, therefore, that the use of the cost algorithm for sodium 

scrubbing as a "generic" cost algorithm for industrial FGD systems is 
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probably not the most appropriate choice. Based on this assessment, a 

better choice would be the cost algorithm for lime spray drying. The costs 

generated using this cost algorithm seem to fall about midway between the 

costs generated by using the cost algorithm for sodium scrubbing and that 

for dual alkali scrubbing. 

This assessment, however, does not examine the full range of steam 

generating unit sizes, capacity factors, and fuels. For other combinations 

of these factors, the relative costs generated by these cost algorithms may 

change, and the costs generated by using the cost algorithm for lime spray 

drying would probably not fall midway between the costs generated by using 

the cost algorithms for sodium scrubbing and dual alkali scrubbing. 

Probably the best approach to estimate the costs associated with a 

"generic" industrial FGD system would be to estimate the costs for each 

steam generating unit using each of the cost algorithms for each specific 

case. The highest and lowest cost estimates could then be averaged to yield 

a cost estimate representing the costs for a "generic" industrial FGD 

system. 
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REFEREMCES 

1. U. S. Environmental Protection Agency, Summary of Regulatory Analysis 

for New Source Performance Standards: Industrial-CommercialInstitutional Steam Generating Units of Greater than 100 million Btu/hr 

Heat Input. EPA-450/3-85-005. June 1986. 

2. Laughlin, J. H. et al. (Radian Corporation). Industrial Boiler SOCost Report. Prepared for the U. S. Environmental Protection Agency, 

Research Triangle Park, NC. November 1984. 

3. Memorandum from'Aul, E. and Stackhouse, B., Radian Corporation, to 

Byrne, D., EPA/SDB, April 15, 1987. Impacts of New Fuel Prices on 

Costs and Cost Effectiveness Values for Industrial Coal and Oil-Fired 

Model Steam Generating Units. 

4. Aul, E. F., et al. (Radian Corporation). Fluidized Bed Combustion: 

Effectiveness as an SO- Control Technology for Industrial Boilers. 

Prepared for the U. S. Environmental Protection Agency, Research 

Triangle Park, NC. September 1984. 
<• , 

TABLE 1. FUEL PRICES AND CHARACTERISTICS3 

Region 

V 

VIII 

Fuel Type 

H-B1t. Coal 

Residual 011 

Natural Gas 

D-Subb1t. Coal 

Natural Gas 

(lb 

Fuel Sulfur 

Nominal 

S02/MMBtu) 

6.0 

3.0 

-

2.5 

-

* Content 

(lb 

Actual 

S02/MMBtu) 

5.5 

3.0 

-

1.44 

-

Heating 

Value 

(Btu/lb) 

11,660 

18,500 

-

8,620 

-

Ash 

Content 

(wt. %) 

12.0 

0.1 

-

6.9 

-

Fuel 

Price 

($/MMBtu) 

2.24 

2.90/4.15b 

3.77/4.82b'

c 

1.33 

3.14/3.72b'

c 

Source: Reference 3. 

'Low oil price scenario/high oil price scenario. 

'Non-carriage, rigid price. 
TABLE 2. ANNUALIZED COSTS FOR BOILERS WITH SQ2 CONTROL (a,b) 

0 1 

Fuel Fuel Sulfur Content Boiler Costs Sodiua Scrubber Dual Alkali Spray Dryer FBC 

Type (lbs S02/HHBtu) 

Fuel Non-fuel FGD Total F6D Total FSD Total Non-fuel Total 

Region V: 

Coal 6.0 1,770 3,B40 B70 6,480 1,140 6,750 970 6,590 4,e30 6,600 

Oil 3.0 2,950 1,170 580 4,700 840 4,960 -, 

(high price) 

Oil 3.0 2,060 1,160 590 3,810 850 4,070 -

(low price) 

Region VIII: 

Coal 2.5 1,050 4,070 490 5,610 B30 5,950 650 5,770 4.510 5,560 

la! All costs in June 1985 *1000/yr. 

(b) 150 HMBtu/hr boiler operating at 60 percent of capacity for oil firing and 55 percent of capacity for oil firing. 
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-HIGH OIL PRiCL LOW OIL PRICE DA-HIGH OIL PRICE LOW OIL PRICE 

FGD TYPE AND OIL PRICE SCENARIO 

FGD COS"