P.1 

OAR Box 1778 

Prepped by Ollie Stewart 

Document Number: 

28) ll-B-3 

Docket Number: 

A-90-06 

Printed 10/28/2008 9:50:52 AM Sheet 28 of 276 
P.2 

J2ADIAH 

CORPORATIO N 

August 5, 1988 

^ 10 1988 

U.S. FPA A°n 8r3ncrj 

•

cr7 t

 region V 

Ms. Donna Green 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY (REGION FIVE) 

230 South Deerhorn st. 

Box Number 5AR26 

Chicago, Illinois 60604 

Dear Ms. Green: 

As part of the National Acid Precipitation Assessment Program (NAPAP), 

Radian is conducting a program directed by EPA-AEERL to develop site specific 

retrofit costs for SO- and NO controls at the top 200 SOp emitting power 

plants. At your request, we ftave used the procedures developed under the 

NAPAP effort to estimate the cost of FGD systems at the Port Washington 

plant. Table 1 presents the information obtained from EIA-Form 767 (1986) 

which was used to estimate costs. Tables 2 and 3 present the site specific 

assumptions used to develop retrofit factors and scope adders for: 

D 

2) 

3) 

- conventional limestone wet FGD (L/LS-FGD), 

- furnace sorbent injection (FSI), and 

- duct sorbent injection (DSD). 

For L/LS-FGD, adipic acid was used as a chemical additive, and S0-

removal efficiency was 90 percent. Absorbers were placed behind the existing 

chimneys in an area which currently is the ash settling pond. Appendix A 

presents the FGD unit layout for all the boilers in Port Washington.- Table 4 

presents the cost estimates for the three technologies in March 1988 dollars. 

The breakdown of the cost for L/LS-FGD combined case are shown in Appendix B. 

For L/LS-FGD two costs are presented: for a single unit of 80 MW 

(100 percent estimated spare absorber capacity) and for combined FGD units of 

400 MW (33 precent estimated spare absorber capacity). 

For LIMB technology Electro Static Precipitator 

specific collection area being less than 200 square 

actual cubic feet per minute. It may not be feasibl 

ESPs without major ESP upgrades and plate area addit 

baghouse option is not presented here since it is no 

cost option. Duct Spray Drying technology (DSD) is 

because duct residence time between the boilers and 

in insufficient droplet evaporation residence time. 

ESPs are used for sorbent injection and new baghouse 

particulate matter control DSD could be applicable, 

is also presented in Table 4. 

s (ESPs) are small with 

feet per thousands of 

e to reuse the existing 

ions. LIMB with a new 

t considered to be a low 

not a low cost option, 

ESPs are short, resulting 

However, if the existing 

s are installed for 

costs for this technology 

Progress Center,3200 E. Chapel Hill Rd./Nelson Hwy./P.O. Box .3000/Research Triangle Park, N.C. 27709/(919)541-9100 
P.3 

-2-

Please note that these costs were generated using the Integrated Air 

Pollution Control Cost model (IAPCS) which is currently being revised by 

another EPA contractor. However, I do not expect any major changes to the 

model, and reported costs here should be reasonably accurate. Unfortunately, 

I did not receive the A&E cost estimates from the plant; however, based on my 

conversations with the plant personnel, Radian cost estimates for L/LS-FGD 

are reasonably close to the A&E cost estimates. Costs were not developed for 

LIMB and DSD technologies by the plant, and therefore these could not be 

compared with our estimates. 

Please call me if you have any questions or comments at 919-541-9100. 

Sincerely, . 

Mehdi Maibodi 

cc: Norm Kaplan, EPA 

Tomm Emmel, Radian 
P.4 

TABLE 1. PORT WASHINGTON STEAM PLANT OPERATIONAL DATA 

BOILER NUMBER 1.-5 

GENERATING CAPACITY (MW-each) 80 

INSTALLATION DATE 1935,43,48,49,50 

FIRING TYPE 

COAL SULFUR CONTENT (PERCENT) 2.0 

COAL HEATING VALUE (BTU/LB) 12000 

COAL ASH CONTENT (PERCENT) 7.0 

FLY ASH SYSTEM DRY HANDLING 

ASH DISPOSAL METHOD OFF-SITE 

STACK NUMBER 1-2 

COAL DELIVERY METHODS RAIL 

PARTICULATE CONTROL 

TYPE 

INSTALLATION DATE 

EMISSION (LB/MM BTU) 

REMOVAL EFFICIENCY 

DESIGN SPECIFICATION 

SULFUR SPECIFICATION (PERCENT) 

SURFACE AREA (1000 SQ.FT) 

GAS EXIT RATE (1000 ACFM) 

SCA (SQ.FT/1000 ACFM) 

OUTLET TEMPERATURE (°F) 

ESP 

1967-68 

0.05-0.1 

98.6-99.3 

3.1 

87 

450 

193 

390 
P.5 

TABLE 2. SUMMARY OF RETROFIT FACTOR DATA FOR PORT WASHINGTON UNITS 1-5 

SITE ACCESS/CONGESTION 

S02 REMOVAL 

FLUE GAS HANDLING 

ESP REUSE CASE 

BAGHOUSE CASE 

DUCT WORK DISTANCE 

ESP REUSE 

BAGHOUSE 

ESP REUSE 

NEW BAGHOUSE 

SCOPE ADJUSTMENTS 

WET TO DRY 

(FEET) 

ESTIMATED COST (1000$) 

NEW CHIMNEY 

ESTIMATED COST (1000$) 

OTHER 

RETROFIT FACTORS 

FGD SYSTEM 

ESP REUSE CASE 

BAGHOUSE CASE 

ESP UPGRADE 

NEW BAGHOUSE 

GENERAL FACILITIES 

FGD TECHNOLOGY 

FORCED 

L/LS FGD OXIDATION 

MEDIUM 

MEDIUM 

100-300 

NA 

NA 

NO 

NA 

NO 

0 

NO 

1.38 

NA 

NA 

(PERCENT) 10 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

0 

NA 

NA 

NA 

0 

LIME 

SPRAY DRYING 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

0 

NA 

NA 

NA 

NA 

0 
P.6 

TABLE 3. DUCT SPRAY DRYING AND FURNACE SORBENT INJECTION 

TECHNOLOGIES FOR PORT WASHINGTON UNITS 1-5 

ITEM 

SITE ACCESS/CONGESTION 

REAGENT PREPARATION MEDIUM 

ESP UPGRADE MEDIUM 

NEW BAGHOUSE NA 

SCOPE ADDERS 

CHANGE ESP ASH DISCHARGE SYSTEM TO DRY HANDLING NO 

ESTIMATED COST (1000$) NA 

ADDITIONAL DUCT WORK (FT) 

NEW BAGHOUSE CASE NA 

• ESTIMATED COST (1000S) NA 

ESP REUSE CASE NA 

ESTIMATED COST (1000$) NA 

DUCT DEMOLITION LENGTH (FT) 50 

DEMOLITION COST (1000S) 25 

TOTAL COST (1000$) 

ESP UPGRADE CASE 25 

A NEW BAGHOUSE CASE NA 

RETROFIT FACTORS 

CONTROL SYSTEM (DSD SYSTEM ONLY) 1.25 

ESP UPGRADE 1.34 

NEW BAGHOUSE NA 
TABLE 4. COST ESTIMATES FOR FGD TECHNOLOGIES AT PORT WASHINGTON PLANT (MARCH 1988 S) 

Case Unit 

Number 

Size 

(MW) 

Capacity 

factor 

(X) 

Retrofit 

factor 

Existing/Additional 

2 

SCA slze/SCA size 

Remova1 

efficiency 

Capital 

cost 

S/KW 

Unit 

cost 

51 ton 

LevelIzed 

cost 

(mLlls/Kvhr) 

L/LS -I- additive 

L/LS + additive 

L/LS + additive 

L/LS + additive 

4 

FSI +• ESP 

FSI + ESP 

1-5 (each) 

1-5 (each) 

1-5 (each) 

1-5 (each) 

80 

1-5 (total) 400 

80 

1-5 (total) 400 

80 

80 

14.3 

14.3 

50 

50 

14.3 

50 

1.38 

1.38 

1.38 

1.38 

1.34 

1.34 

193/0 

193/0 

193/0 

193/0 

193/174 

193/174 

90 

90 

90 

90 

70 

70 

481 

223 

481 

223 

115 

115 

7,336 

3,370 

2,392 

1,185 

3.794 

1.395 

106.5 

48.9 

34.7 

17.2 

42.86 

15.8 

DSD + FF 

DSD + FF 

DSD + FF 

DSD + FF 

1-5 (each) 

1-5 (each) 

80 

80 

2 units 160 

combined 

2 units 160 

combined 

14.3 

50 

14.3 

50 

1.34 

1.34 

1.34 

1.34 

193/NA 

193/NA 

193/NA 

193/NA 

77 

77 

77 

77 

411 

411 

223 

223 

7.157 

2,191 

3,894 

1.233 

89.5 

27.4 

48.7 

15.4 

'Retrofit factor for FSI and DSD is for ESP upgrade and baghouse site access /cogestion respectively. 

SCA, specific collection area in square feet per thousands actual cubic feet per minute of fluegas flow. 

L/LS-FGD with adipic acid as an additive. 

U 

Furnace sorbent injection with reused of the existing ESPs. 

Duct spray drying with new baghouses. 

Not applicable. 
P.8 

ATTACHEMENT A 

FGD SYSTEM LAYOUT FOR PORT WASHINGTON 
P.9 
P.10 

ATTACHMENT B 

DETAILED COST OUTPUT 
P.11 

PORT WASHINGTON 

klMESTONE FGD+ADDITIVE FOR UNITS 1-5 DRAFT 

USER INPUT SUMMARY DO NOT QUOTE OR CITE 

BOILER SIZE. 

CAPACITY FACTOR.T4.3 * 

WALL FIRED, DRY BOTTOM 

390. DEG.F 

DATE OF COMMERCIAL OPERATION OF BOILER: 1975 

CONSTRUCTION STATUS OF CONTROL SYSTEM: RETROFIT 

COAL CLEANING LEVEL: RUN-OF-MINE SORTED AND SCREENED 

COAL CHARACTERISTICS AT THIS CLEANING LEVEL: 

HHV (BTU/#) 

SULFUR CONTENT (%) 

ASH CONTENT (%) 

COST ($/T0N) 

CHLORINE CONTENT (%) 

MOISTURE CONTENT (%) 

VOLATILE MATTER CONTENT (%) 

FIXED CARBON CONTENT (%) 

12000.0 

2.00 

7.00 

0.00 

0.10 

4.00 

28.30 

52.60 

ASH CHARACTERISTICS AT THIS CLEANING LEVEL: 

NA20 CONTENT (%) 

ALKALINITY (%) 

FE203 CONTENT (%) 

1.00 

4.50 

25.90 

+ 

1 

CONTROL SYSTEM CONFIGURATION: 

1 - FGD 

ECONOMIC PREMISES (TVA/EPRI) 

EPRI 

INTEGRATED AIR POLLUTION CONTROL SYSTEM COSTING PROGRAM 

USER INPUT SUMMARY (CONTINUED) 

PARAMETER FILE USED: PARMFILE.EPR 

ADJUSTMENT FILE USED: DEFAULT.CAF 

BATCH DATA FILE USED: PORT.DAT 

THE FOLLOWING CHANGES WERE MADE TO THESE PARAMETER FILES FOR THIS RUN: 

NEW VALUE DESCRIPTION 

0.1800E+07 FLOW RATE, ACFM (CALCULATED IF ZERO) 

1.380 FGD RETROFIT FACTOR, DIMENSIONLESS 
P.12 

3 000 DURAT IDEALIZED TIME REQUIRED FOR CONSTRUCTION (YRS). 

3*376 - ' WASTE DISPOSAL, DRY ($/TON) 

0 2500 EXCESS AIR, FRACTION __ hn , ^ _ 

•51 00 XLG L/G RATIO FOR SCRUBBER, GALLONS/1000 CU. FT. DR/\P T 

2 000 ISR L/G, EFFICIENCY CONTROL VARIABLES,1,2,3) L/I\tt, I 

l'070 STOICHIOMETRIC RATIO (FGD) % DO NOT OUOTE 0«? PITF 

2 000 IADD CHEMICAL ADDITIVE OPTION (0,1,2) ¥ UU, t Ua CUE 

0 OOOO IFOX FORCED OXIDATION OPTION (0,1,2,3) 

i 000 IALK ALKALI ADDITION OPTION (1,2) 

5*200 PHLIME RECIRCULATION LIQUOR PH 

335 5 CE PLANT INDEX FOR CORRESPONDING YEAR AND MONTH OF COST 

364*9 CE MATERIAL INDEX FOR CORRESPONDING YEAR AND MONTH OF COST 1 258*9 CE LABOR INDEX FOR CORRESPONDING YEAR AND MONTH OF COST 

FGD 

+ 

THE CONFIGURATION OF THIS SYSTEM INCLUDES SPRAY TOWERS. 

LIMESTONE SLURRY. 

ADIPIC ACID CHEMICAL ADDITIVE IS USED. 

SPARE ABSORBER CAPACITY OF 3^*I S PROVIDED. 

THE L/G RATIO IS 60.9. 

DESIGN S02 REMOVAL OF 90.0% OCCURS IN THE TREATED GAS STREAM. 

0.% OF THE GAS STREAM IS BEING BYPASSED. 

0.% OF THE WASTES ARE DISPOSED OF IN AN ONSITE FACILITY. 

FANS 

THE TOTAL SYSTEM PRESSURE DROP IS 6.5 IN. H20. 

THE SYSTEM REQUIRES 4 FAN(S) RATED AT 432. HP EACH. 

BOILER/SYSTEM PERFORMANCE 

UNIT THERMAL EFFICIENCY 87.1% 

BOILER NET HEAT RATE 9929.1 BTU/KWH 

HEAT INPUT 3971.6 MMBTU/H 

COAL USE 165.5 TONS/H 

ANNUAL COAL CONSUMPTION.. 2.0730E+05 TONS/YR 

IAPCS ENERGY PENALTY 36.3 BTU/KWH 

SYSTEM NET GENERATION 398.5 MW 

SYSTEM MATERIAL BALANCE 

(100% CAPACITY CONDITION) 

AIR 

UNCONT-.HEATER 
P.13 

FLUE GAS,a 1000 ACFM 

.TEMPERATURE,DEG.F 

MOISTURE, LB/H 

ALKALINITY, LB/H 

PARTICULATE, LB/H 

S02, LB/H 

N02, LB/H 

1800. 1800. 1098. 

390. 390. 175. 

209608. 209608. 495997. 

886. 886. 886. 

19693. 19693. 19693. 

12908. 12908. 1291. 

3475. 3475. 3475. 

D8AFT 

M NOT QUO, c OR CITE 

POLLUTANT 

PARTICULATE 

S02 

N02 

EMISSION SUMMARY 

LB/HR 

19693. 

1291. 

3475. 

PERCENT 

REDUCTION 

0.0 

90.0 

0.0 

LB/MMBTU 

4.958 

0.325 

0.875 

PPM(V) 

134. 

771. 

INSTALLED CAPITAL COSTS AUGUST, 1986 

FGD $ 47796300 

MATERIAL HANDLING $ 1856900 

FEED PREPARATION $ 5046700 

GAS HANDLING S 8115400 

S02 SCRUBBING S 23544100 

OXIDATION $ 0 

REHEAT -- $ 5282800 

SOLID SEPARATION S 3950400 

PANS $ 5370500 

TOTAL DIRECT CAPITAL COSTS>»»»»»»»»»» $ 53166800 

INDIRECT COSTS-- - - — $ 31043900 

GENERAL FACILITIES $ 5316700 

ENGINEERING/HOME OFFICE...S 5316700 

PROJECT CONTINGENCY $ 1474700 

PROCESS CONTINGENCY S 14875900 

SALES TAX $ 0 

TOTAL PLANT COST. S 80150800 
P.14 

INVENTORY CAPITAL $ 1566900 

INITIAL CATALYST $ 0 

LAND $ 6200 

************* 

TOTAL CAPITAL REQUIREMENT»»»»»»»»»»* $

 8922Si22I 

TOTAL SYSTEM COST»»»»»»»»»»»»»>» $ 22-yytflHfc 

ANNUAL OPERATING COSTS AUGUST, 1986 

DRAFT 

*D0 NOT QUOTE OR CITE 

ITEM } 

OPERATING AND SUPERVISORY LABOR 

SYSTEM 0. 

ANALYSIS 0. 

MAINTENANCE LABOR 0. 

MAINTENANCE MATERIAL 0. 

ADMIN. & SUPPORT LABOR 0, 

FIXED COMPONENT 0 

VARIABLE COMPONENT 0 

UANTITY 

________ 

305E+05 MANHRS 

232E+04 MANHRS 

404E+07 $ 

404E+07 $ 

226E+07 $ 

536E+07 $ 

536E+07 $ 

RATE 

______ 

19.44 

23.33 

0.40 

0.60 

0.30 

0.14 

0.86 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

ANNUAL COST 

592500 

54200 

1615400 

2423100 

678600 

767000 

4596800 

CONSUMABLES 

SOLIDS DISPOSAL, WET 

ADIPIC ACID 

WATER 

STEAM 

ELECTRICITY 

LIMESTONE 

TOTAL FIRST YEAR O&M EXPENSE 

LEVELIZED CARRYING CHARGES 

BUSBAR COST OF POWER 

LEVELIZED FIRST YEAR O&M 

LEVELIZED CARRYING CHARGES 

LEVELIZED ANNUAL REQUIREMENTS 

0.246E+05 TONS 

16.6 TONS 

0.468E+05 K GAL 

0.846E+05 K LBS 

0.529E+07 KWH 

0.131E+05 TONS 

89226100 $ 

6708200 $ 

89226100 $ 

13.12 

1691.33 

0.64 

6.21 

0.04 

15.29 

16.6% 

1.452 

16.6% 

S 

S 

S 

S 

S 

$ 

$ 

$ 

S 

S 

S 

323100 

28100 

30100 

525500 

237600 

200000 

6708200 

14783400 

21491600 

9738300 

14783400 

24521700 

FIRST YEAR BUSBAR COST OF POWER 

LEVELIZED ANNUAL BUSBAR COST OF POWER 

42.89 MILLS/KWH 

48.94 MILLS/KWH 

PARTICULATE COST EFFECTIVENESS 

S02 COST EFFECTIVENESS 

NOX COST EFFECTIVENESS 

1 

0.00 $/TON 

3370.28 $/TON 

0.00 $/TON