•' --.. N ,
- :V-'
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
APPENDICES
L - X
PEDCo ENVIRONMENTAL
,- v, ',. .
)
?
.•-/:-
'• I .
-------
PEDCo ENVIRONMENTAL-
11-499 CHESTER ROAD
CINCINNATI. OHIO 45246
(513) 782-4700
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
APPENDICES
L - X
Prepared by
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
EPA Project Officer: Richard Atherton
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
'Strategies and Air Standards Division
Pollutant Strategies Branch
Research Triangle Park,
North Carolina 27711
September 24, 1978
!, :l ,1 'll,.
-JMlSi.,.
CHeSTER TOWERS
BRANCH OFFICES
Crown Center
Kannes City Mo.
C(-.«ool Hill. N.C.
-------
APPENDIX L
LOVETT POWER PLANT
LOVETT POWER PLANT L-l
-------
CONTENTS
Lovett Power Plant Survey Form
Lovett Power Plant Photographs
Page
L-4
L-17
Number
L-l
L-2
L-3
FIGURES
Site Plan Showing Possible Location of Major
Components for the Sodium Solution Regenerable
System for Boilers 3, 4, and 5 at the Lovett
Power Plant
Site Plan showing the Possible Locations of
Major Components for the Limestone System for
Boilers 3, 4, and 5 at the Lovett Power Plant
Site Plan Showing Possible Locations of New
ESP's for Boilers 3, 4, and 5 at the Lovett
Power Plant
Page
L-27
L-33
L-38
Number
L-l
L-2
L-3
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boilers 3, 4, and 5 at
the Lovett Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boilers 3, 4,
and 5 at the Lovett Power Plant (1978)
Retrofit Equipment and Facilities for the
Sodium Solution Regenerable System for Boilers
3, 4, and 5 at the Lovett Power Plant
Page
L-21
L-23
L-24
LOVETT POWER PLANT
L-2
-------
TABLES (continued)
Number Page
L-4 Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boilers
3, 4, and 5 at the Lovett Power Plant L-25
L-5 Estimated Capital Cost of a Limestone Scrubbing
System for Boilers 3, 4, and 5 at the Lovett
Power Plant (1978) L-27
L-6 Estimated Annual Operating Costs of a Limestone
Scrubbing System for Boilers 3, 4, and 5 at the
Lovett Power Plant (1978) L-29
L-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boilers 3,
4, and 5 at the Lovett Power Plant L-30
L-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boilers 3, 4, and
5 at the Lovett Power Plant L-31
L-9 Estimated Capital Cost of Electrostatic
Precipitators for Boilers 3, 4, and 5 at the
Lovett Power Plant (1978) L-33
L-10 Estimated Annual Operating Cost of Electrostatic
Precipitators for Boilers 3, 4, and 5 at the
Lovett Power Plant (1978) L-34
L-ll Electrostatic Precipitator Design Values for
Boilers 3 and 4 at the Lovett Power Plan L-35
LOVETT POWER PLANT L-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION:
1. COMPANY NAME: Orange & Rockland Utilities, Inc.
2. MAIN OFFICE: 75 West Route 59, Spring Valley, New York 10977
3. RESPONSIBLE OFFICER: Kenneth B. Field
4. POSITION: Assistant Vice President
5. PLANT NAME: Lovett Generating Station
6. PLANT LOCATION: Tomkins Cove, Town of Stony Point, Rockland
County, New York
7. RESPONSIBLE OFFICER AT PLANT LOCATION:
8. POSITION:
9. POWER POOL
DATE INFORMATION GATHERED:
PARTICIPANTS IN MEETING:
B. Baxter, Jr.
K. B. Field
Gerard J. Bogin
C. F. Wilkinson
Barry Tornich
Thomas C. Ponder, Jr.
Alan J. Sutherland
Douglas A. Paul
Orange and Rockland Utilities, Inc.
Orange and Rockland Utilities, Inc.
Orange and Rockland Utilities, Inc.
Orange and Rockland Utilities, Inc.
U.S. Environmental Protection Agency
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
LOVETT POWER PLANT
L-4
-------
B.
M
13
o
w
to
13
£
z
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO2 EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE SO EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/M:-! BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION {, SECTION NO.
LB/Mi-1 BTU
Boiler number
1
NYSDEC
2
3
4
.041*
Part 227
.10
NA
5
.096*
Part 227
.10
NA
a) Identify v/hether results are from stack tests or estimates
NOTE: Analysis based on stack tests burning .3% Sulfur Oil
-------
C. SITE DATA
1. U.T.M. COORDINATES.
2. ELEVATION ABOVE MEAN SEA LEVEL (FT)
3. SOIL DATA: BEARING VALUE
PILING NECESSARY
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE):
LOVETT POWER PLANT L-6
-------
o
<
w
H
t-3
13
O
&
M
£
z
D.
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (1975)
4 . SERVED BY STACK NO .
5 . BOILER MANUFACTURER
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9- FUEL CONSUMPTION: GAS 103 FT3/HR
COAL OR OIL RATED 100%OIL BBL/I
COAL TONS/HR
(TPH) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION GAS 10 J MCF
COAL (TPY) (1975) 103 TONS
OIL (GPY) (1975) 10 BBLS
11. HEAT RATE BTU/KWHR GAS
COAL
OIL
12. WET OR DRY BOTTOM
13. FLY ASH REINJECTION (YES OR NO)
14. STACK HGT ABOVE GRADE (FT.)
15. I.D. OF STACK AT TOP (INCHES)
Boiler number
1
119.86
0.72
1
B&W+
1949
19.1
R 41.6
9.6
11.8
1.490
-
_
?.-\t Qf!7
DRY-
NO
175
83
2
108.04
0.72
2
B&W+
1951
20
41.6
9.6
12.9
1.290
-
_
?4,?qi
DRY
NO
175
83
3
2845.31
17.24
3
CE°
1955
63
11Q.O
25.0
67.9
200.78
-
_
1 3, 215
DRY
NO
175
150
4
6,307.16
36.86
4
FW*
1966
202.1
1500
- 260
60.0
1402.6
810.09
-
9200
10,100
DRY
NO
212
156
5
8,116.51
47.68
5
B&W-+
1969
200.6
1528
275
- 65.0
1454.8
1360.5
-
9500
10,200
DRY
NO
245
192
* FW - FOSTER WHEELER, CORP.
Notes: + B&W -.BABCOCK & WILCOX, CO.
° CE - COMBUSTION ENGINEERING
-------
f
o
i
16. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%}
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
17. EXCESS AIR: DESIGN/ACTUAL (%)
1
WEST+
MCTA
85/-
NA
25
Boiler number
f.
WEST*
MCTA
85/-
NA
25
3
PRATT0
MCTA
85/-
NA
20
4
NA
COTT*
E
95/-
20
5
NA
COTT*
E
95/-
20
tr1
i
CD
Notes: * COTT - RESEARCH-COTTRELL, INC.
+ WESTERN PRECIPITATION DIVISION
0 PRATT DANIEL MECHANICAL PRECIPITATOR
-------
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£
z
18. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
§ 50% LOAD
20. EXIT GAS STACK VELOCITY (FPS)a
§ 100% LOAD
@ 75% LOAD
@ 50% LOAD
21. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
23. EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO STACK
25. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
1
110,000
61,600
27,500
335
300
280
49.0
27.4
12.2
2
125,000
70,000
31,200
335
300
280
55.7
31.2
13.9
3
252,000
141,800
63,000
310
300
225
34.1
19.1
8.0
i, "> i f\ o r\
4
648,000
362,880
162,000
300
285
250
85.5
38.21
17.0
5
785,000
440,980
196,280
288
286
267
68.5
38.3
17.3
f
I
VD
a) Identify source of values (test or estimate)
Notes:
-------
f
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w
o
s
M
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
1
NA
NA
2
NA
NA
3
NA
NA
4
NA
NA
5
NA
NA
Notes:
t*
i
-------
FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
3. ANALYSIS
HHV (BTU/LB)
13,500 - Design
S (%)
ASH (%)
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H.
FUEL OIL DATA (1975)
1. TYPE #6 F.O.
2. S CONTENT (%) Q. 33
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL) 144,533
I.
J.
NATURAL GAS HHV (BTU/FT3)
COST DATA
ELECTRICITY
1026
FUEL: COAL
GAS
OIL
WATER
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES
FEDERAL PROPERTY TAX
LOVETT POWER PLANT
L-ll
-------
K. PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
L. ADDITIONAL INFORMATION
F.E.A. LETTER
M,
OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
2.
Boiler No.
Yes or No.
1
YES
2
YES
3
YES
4
YES
5
YES
SYSTEM AVAILABILITY
2.1 COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Unloading equipment
Stack. Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
2.2 FUEL FIRING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
2 . 3 GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
Yes [3
YesS
0
YesD
D
D
D
Yes0
YesD
D
D
D
D
No Q
D
Yes D
a
a
a
a
a
NO D
a
a
a
•a
a
LOVETT POWER PLANT
NO D
a
NO a
a
D
a
NO a
a
No D
D
a
a
D
L-12
-------
2.4 ASH HANDLING
a. Is the system still installed? YesH NoD
b. Will it operate? 0 Q
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes Q NoD
Ash Pond n D
LOVETT POWER PLANT L_13
-------
N. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? Yes
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS?
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage? Yes
2.3 Handling facilities available for low
sulfur fuels Yes
If yes, describe
No
Yes Q No
No
No
3.
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?_
IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss :
5.
POWER PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(1) Sulfur Oxides - Continuous
- Intermittent
- Static
(2) Suspended particulates
- Intermittent
- Static
(3) Other (describe)
Meteorological instrumentation
If yes, describe NO
Yes
Yes
N° n
No
Yes [x] No
Number Type
Sulphur Pic ' 2
Dust Colled
c. Is the monitoring data available?
d. Is the monitoring data reduced and
analyzed?
e. Provide map of monitoring locations
Yes
Yes
No
No
LOVETT POWER PLANT
L-14
-------
5.2 Proposed system Yes Q No \~\
If yes, describe and provide map
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent ZZZ
- Static ZZZ
(2) Suspended particulate
- Intermittent
- Static ZHZ
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
LOVETT POWER PLANT L_15
-------
Photo No. 1. View from the roof of the ESP serving
Boiler 5 looking at the tie-in of Boiler 4's ESP to
the stack.
Photo No. 2. View from ground level facing north
showing the crusher house and the conveyors. A
view of the Lovett plant is in the background.
LOVETT POWER PLANT
L-16
-------
1
Photo No. 3. View from ground level facing southwest
showing electrical substation.
:•• BBft.
Photo No. 4. View from ground level facing south showing
the car shaker and the thaw house.
LOVETT POWER PLANT
L-17
-------
Photo No. 5. View from the roof of the ESP serving Boiler
5 facing south showing sludge ponds and stack 4. The
Hudson River, the rock quarry, and the surrounding area
are shown in the background.
Photo No. 6. View from the roof of the ESP serving Boiler
5 facing north showing the parking lot and the warehouse.
LOVETT POWER PLANT
L-18
-------
Photo No. 7. View from the roof of the ESP serving Boiler
5 facing northeast showing the Hudson River, Indian Power
Plant, and the surrounding area.
Photo No. 8. View from the roof of the ESP serving Boiler
5 facing southwest showing the residual fuel oil hold tank.
The rock quarry and the surrounding area are in the back-
ground.
LOVETT POWER PLANT
L-19
-------
Photo No. 9. View from the roof of the ESP serving Boiler
5 facing north showing the Hudson River and the surrounding
area.
Photo No. 10. View from the roof of the ESP serving Boiler
5 facing west showing the surrounding area.
LOVETT POWER PLANT
L-20
-------
TABLE L-l. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 3, 4, AND 5 AT
THE LOVETT POWER PLANT (1978)
Direct Costs
A. Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
B. S02 Scrubbing
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
C. Purge Treatment
Refrigeration unit
Heat exchangers
Tanks
Dryer
Elevator
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
(continued)
LOVETT POWER PLANT
Total A =
Total B =
Total C =
55,000
6,000
26,000
26,000
2,000
$ 115,000
$ 10,728,000
1,186,000
314,000
1,875,000
1,630,000
2,711,000
376,000
$ 18,820,000
$ 306,000
46,000
60,000
27,000
15,000
252,000
611,000
733,000
55,000
6,000
$ 2,111,000
L-21
-------
TABLE L-l (continued)
Regeneration
Pumps and motors $ 223,000
Evaporators and reboilers 2,867,000
Keat exchangers 374,000
Tanks 51,000
Stripper 115,000
Blower 122,000
Total D = $ 3,752,000
Particulate Removal
Venturi scrubber $ 4,710,000
Tanks 140,000
Pumps and motors 550,000
Total E = $ 5,400,000
Total direct costs = A + B + C + D + E = F=$ 30,198,000
Indirect Costs
Interest during construction $ 3,020,000
Field labor and expenses 3,020,000
Contractor's fee and expenses 1,510,000
Engineering 3,020,000
Freight 378,000
Offsite 906,000
Taxes 000
Spares 151,000
Allowance for shakedown 1,510,000
Acid plant 1,476,000
Total indirect costs G = $ 14,991,000
Contingency H = 9,038,000
Total =F+G+H= $ 54,227,000
Coal conversion costs 3,424,000
Grand total $ 57,651,000
$/kW 123.79
LOVETT POWER PLANT L~22
-------
TABLE L-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 3, 4, AND 5
AT THE LOVETT POWER PLANT (1978)
Quantity Unit Cost Annual Cost
Raw Materials
Soda ash
Utilities
0.45 ton/h $90.3/ton $ 139,000
Process water 2,068.3 gal/min 0.069 $/103 gal 29,000
Cooling water 8.8 x 103 gal/min 0.017 $/103 gal 31,000
Electricity 10,015 kW 55.7 mills/kWh 1,873,000
Reheat steam 71.2 106 Btu/h 2.835 $/106 Btu 679,000
Process steam 126.7 106 Btu/h 2.835 $/106 Btu 1,209,000
Operation Labor
Direct labor 4 men/day $10.67/man-hour 374,000
Supervision 15% of direct labor 56,000
Maintenance
Labor and materials 4% of fixed investment 2,169,000
Supplies 15% of labor and materials 325,000
Overhead
Plant 50% of operating and maintenance 1,462,000
Payroll 20% of operating labor 86,000
Fixed Costs
Depreciation (5.00%)
Interim replacement (0.35%)
Insurance (0.30%)
Taxes (4.00%), Z = 20.85% of fixed
investment
Capital cost (11.20%)
Total fixed cost $ 11,306,000
Total cost $ 19,738,000
Credits (byproducts)
Sulfuric acid 6.30 tons/h $65.24/ton (1,382,000)
Na2SO4 0.45 ton/h $79.34/ton (122,000)
Total byproduct credits $ (1,504,000)
Fuel credit (11,222,000)
Net annual cost $ 7,012,000
Mills/kWh 4.44
LOVETT POWER PLANT L-23
-------
Table L-3. RETROFIT EQUIPMENT AND FACILITIES FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS 3,
4, AND 5 AT THE LOVETT POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na-CO., storage
Na-CO, preparation
SO.., regeneration
Purge treatment
Sulfuric acid plant
5
5
1
1
1
1
1
93.4 MW capacity unit
Scaled to train size
324 tons (30-day storage)
900 Ib/hr, Na^CO.,
6746 Ib/hr, S02
900 Ib/hr, Na2S04
23.5 tons/day, H S04
LOVETT POWER PLANT
L-24
-------
Table L-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS
3, 4, AND 5 AT THE LOVETT POWER PLANT
Item
Number
required
Dimensions, ft
Na_CO_ storage
Absorber feed surge
tank
Turbulent contact
absorbers
Regeneration plant
Purge treatment plant
Acid plant
1
1
1
1
1
13 diam x 26 high
24 diam x 24 high
45 high x 15 wide x 39.4 long
34 wide x 130 long
41 wide x 170 long
57 wide x 124 long
LOVETT POWER PLANT
L-25
-------
f
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13
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M
I
A PURGE TREATMENT AND
S02 REGENERATION
B ACID PLANT
C SCRUBBERS
D STORAGE SILO
E SOLUTION TANK
i
ro
Figure L-l. Site plan showing possible location of major components for
the sodium solution regenerable system for Boilers 3, 4 and 5
at the Lovett power plant.
-------
TABLE L-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 3, 4, AND 5 AT THE
LOVETT POWER PLANT (1978)
Direct Cost
A. Limestone Preparation
Conveyors $ 410,000
Storage silo 76,000
Ball mills 642,000
Pumps and motors 128,000
Storage tanks 93,000
Total A = $ 1,349,000
B. Scrubbing
Absorbers $ 9,950,000
Fans and motors 1,519,000
Pumps and motors 786,000
Tanks 611,000
Reheaters 2,161,000
Soot blowers 652,000
Ducting and valves 3,242,000
Total B = $18,921,000
Sludge Disposal
Clarifiers $ 197,000
Vacuum filters " 299,000
Tanks and mixers 8,000
Fixation chemical storage 26,000
Pumps and motors 54,000
Sludge pond 1,347,000
Mobile equipment 64,000
Total C = $ 1,995,000
(continued)
LOVETT POWER PLANT L-27
-------
TABLE L-5 (continued)
D. Particulate Removal
Venturi scrubber $ 5,428,000
Tanks 165,000
Pumps and motors 225,000
Total D = $ 5,818,000
Total direct costs = A + B + C + D = E = $ 28,083,000
Indirect Costs
Interest during construction $ 2,808,000
Field overhead 2,808,000
Contractor's fee and expenses 1,404,000
Engineering 2,808,000
Freight 351,000
Offsite 842,000
Taxes 000
Spares 140,000
Allowance for shakedown 1,404,000
Total indirect costs F = $ 12,565,000
Contingency G = 8,130,000
Total =E+F+G= $ 48,778,000
Coal conversion costs 3,424,000
Grand total $ 52,202,000
$/kW 112.09
LOVETT POWER PLANT L-28
-------
TABLE L-6. ESTIMATED ANNUAL OPERATING COSTS OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 3, 4, AND 5 AT THE
LOVETT POWER PLANT (1978)
Quantity Unit Cost Annual Cost
Raw Materials ~~~
Limestone 8.8 tons/h $16.81/ton $ 498,000
Fixation chemicals 21.8 tons/h $ 2.20/ton 162,000
Utilities
Water 174.1 gal/min 0.068 $/103 gal 2,000
Electricity 9395 kW 55.6 mills/kWh 1,758,000
Fuel for reheat 82.0 x 10b Btu/h 2.835 $/10b Btu 782,000
Operating Labor
Direct labor 4 men/day $10.67/man-hour 374,000
Supervision 15% of direct labor 56,000
Maintenance
Labor and materials 4% of fixed investment 1,951,000
Supplies 15% of labor and material 293,000
Overhead
Plant 50% of operation and maintenance 1,337,000
Payroll 20% of operating labor 86,000
Trucking
Bottom/fly ash and 3,243,000
sludge removal
Fixed Costs
Depreciation (5.00%)
Interim replacement (0.35%), E = 20.85% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital costs (11.20%)
Total fixed charges 10,170,000
Total costs $ 20,712,000
Fuel credit (11,222,000)
Net annual cost $ 9,490,000
Mills/kWh 6.01
LOVETT POWER PLANT L-29
-------
Table L-7. RETROFIT EQUIPMENT AND FACILITIES
REQUIRED FOR THE LIMESTONE SCRUBBING SYSTEM FOR
BOILERS 3, 4, AND 5 AT THE LOVETT POWER PLANT
Module Description
Number
Required
Size/Capacity
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
1
1
5
6336 tons (30 day storage)
8.8 ton/hr limestone
93.4 MW capacity units
Scaled to train size
LOVETT POWER PLANT
L-30
-------
Table L-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILERS 3, 4, AND
5 AT THE LOVETT POWER PLANT
Item
Limestone storage pile
Limestone silos
Limestone slurry tanks
Ball mill building
Turbulent contact
absorbers
Clarifiers
Vacuum filter building
Number
Required
1
3
1
1
5
2
1
Dimensions, ft
115 W x 117 L
14 diam x 31 height
45 diam x 20 height
30 W x 30 L
45 height x 15 width x 29 length
49 diam x 20 height
30 W x 30 L
LOVETT POWER PLANT
L-31
-------
K
TJ
A SCRUBBER
B SLURRY TANK
C LIMESTONE SILOS
D BALL MILL BUILDING
E CLARIFIER
F VACUUM FILTER BUILDING
NJ
Figure L-2. Site plan showing the possible locations of major
components for the limestone system for Boilers 3, 4, and 5 at the
Lovett power plant.
-------
TABLE L-9. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 3, 4, AND 5 AT THE
LOVETT POWER PLANT (1978)
Direct Costs
ESP $ 9,701,000
Ash handling 1,563,000
Ducting 1,171,000
Total direct costs $ 12,435,000
Indirect Costs
Interest during construction 8% of direct costs $ 995,000
Contractor fee 10% of direct costs 1,244,000
Engineering 6% of direct costs 746,000
Freight 1.25% of direct costs 155,000
Offsite 3% of direct costs 373,000
Taxes ' 0% of direct costs 000
Spares 1% of direct costs 124,000
Allowance for shakedown 3% of direct costs 373,000
Total indirect costs $ 4,010,000
Contingency 3,289,000
Total $ 19,734,000
Coal conversion costs 3,424,000
Grand total $ 23,158,000
$/kW 49,73
LOVETT POWER PLANT L-33
-------
TABLE L-10. ESTIMATED ANNUAL OPERATING COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 3, 4, AND 5 AT THE
LOVETT POWER PLANT (1978)
Utilities
Electricity
Water
Quantity Unit Cost
1851 kW 55.7 mills/kWh
9784 x 103/gal $0.01/103 gal
Annual Costs
$ 346,000
1,000
Operating Labor
Direct labor 0.5 man/shift $10.67/man-hour 139,000
Supervision 15% of direct labor 21,000
Maintenance
Labor and materials 2% of fixed investment 395,000
Supplies 15% of labor and materials 59,000
Overhead
Plant 50% of operating and maintenance 307,000
Payroll 20% of operating labor 32,000
Trucking
Bottom/fly ash 1,856,000
removal
Fixed costs
Depreciation (4.00%)
Interim replacement (0.35%), I = 19.85% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed cost 3,917,000
Total cost $ 7,073,000
Fuel credit (11,222,000)
Net annual credit $ (4,149,000)
Mills/kWh (2.63)
LOVETT POWER PLANT L-34
-------
Table L-ll. ELECTROSTATIC PRECIPITATOR DESIGN
VALUES FOR BOILERS 3 AND 4
AT THE LOVETT POWER PLANT
Design Parameter
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area, ft2
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth) , ft
excluding hopper dimensions
Value
3
98.66
449
113,200
4.0
30 x 35 x 43
4
98.66
399
258,700
4.0
27 x 100 x 37
LOVETT POWER PLANT
L-35
-------
Table L-ll(Continued). ELECTROSTATIC PRECIPITATOR
DESIGN VALUES FOR BOILER 5
AT THE LOVETT POWER PLANT (1976)
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area,
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth) , ft
excluding hopper dimensions
98.66
312
245,300
4.0
21 x 156 x 28
LOVETT POWER PLANT
L-36
-------
I
w
13
o
Si
w
f
OJ
Figure L-3. Site plan showing possible locations of new ESP's for
Boilers 3, 4, and 5 at the Lovett power plant.
-------
APPENDIX M
MUSTANG POWER PLANT
MUSTANG POWER PLANT M-l
-------
CONTENTS
Mustang Power Plant Survey Form
Mustang Power Plant Photographs
Page
M-4
M-16
Number
M-l
FIGURES
Site Plan Showing Possible Locations of New
ESP's for Boilers 1 and 2 at the Mustang Power
Plant
Page
M-29
Number
M-l
M-2
M-3
M-4
M-5
M-6
TABLES
Estimated Capital Cost of Electrostatic Pre-
cipitators for Boilers 1 and 2 at the Mustang
Power Plant on High-Sulfur Coal (1978)
Estimated Annual Operating Costs of Electro-
static Precipitator for Boilers 1 and 2 at the
Mustang Power Plant on High-Sulfur Coal (1978)
Electrostatic Precipitator Design Values for
Boiler 1 at the Mustang Power Plant on High-
Sulfur Coal Burning
Electrostatic Precipitator Design Values for
Boiler 2 at the Mustang Power Plant on High-
Sulfur Coal Burning
Estimated Capital Cost of Electrostatic Pre-
cipitators for Boilers 1 and 2 at the Mustang
Power Plant on Low-Sulfur Coal (1978)
Estimated Annual Operating Costs of Electro-
static Precipitators for Boilers 1 and 2 at the
Mustang Power Plant on Low-Sulfur Coal (1978)
Page
M-21
M-22
M-23
M-24
M-25
M-26
MUSTANG POWER PLANT
M-2
-------
TABLES (continued)
Number Page
M-7 Electrostatic Precipitator Design Values for
Boiler 1 at the Mustang Power Plant on
Low-Sulfur Coal Burning M-27
M-8 Electrostatic Precipitator Design Values for
Boiler 2 at the Mustang Power Plant on
Low-Sulfur Coal Burning M-28
MUSTANG POWER PLANT M-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: Oklahoma Gas and Electric Company
2. MAIN OFFICE: P.O. Box 321, Oklahoma City, Oklahoma 73101
3. RESPONSIBLE OFFICER: G. L. Gibbons
4. POSITION: Vice President
5. PLANT NAME: Mustang
6. PLANT LOCATION: Oklahoma, Canadian Oklahoma City 73127
7. RESPONSIBLE OFFICER AT PLANT LOCATION: K.A. Ketchersid
8. POSITION: Plant Superintendant
9. POWER POOL Southwest Power Pool
DATE INFORMATION GATHERED: April 26, 1976
PARTICIPANTS IN MEETING:
George L. Gibbons Oklahoma Gas & Electric Co.
John D. Graham Oklahoma Gas & Electric Co.
V. T. Huckleberry Oklahoma Gas & Electric Co.
0. Wayne Beasley Oklahoma Gas & Electric Co.
Jerry Gouett Oklahoma Gas & Electric Co.
Jim Pollard Oklahoma Gas & Electric Co.
Pat Ryan Oklahoma Gas & Electric Go.
Cris Caenepeel EPA - OAQPS
Thomas C. Ponder, Jr. PEDCo Environmental, Inc
N. David Noe PEDCo Environmental, Inc.
Richard T. Price PEDCo Environmental, Inc.
MUSTANG POWER PLANT M_4
-------
B
z
o
O
S
w
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 (A . P . 42)
LB/MM BTU Gas-Firing Calc.
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (1975) Calc.
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO2 EMISSIONS3 (A. P. 42)
LB/MM BTU Gas-Firing Calc.
LB/HR (FULL LOAD)
TONS/YEAR (1975) Calc.
4. APPLICABLE SO2 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB /:•"•! BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO. *
LB/MM BTU
Boiler number
1
.014
19
AQCR
Section 6
0.25
.0006
< 1
Section 1
Ambient S
*
2
.014
19
184
. 2 , Figure
0.25
.0006
< 1
6.21
02 Standar
*
-
I
a
_, a) Identify v.-hether results are from stack tests or estimates *Accordin9 to th« State of Oklahom
The Mustang plant must comply with Federal NSPS (i.e. 1.2 Ibs/mmBtu S02) if converted to coal-firing.
-------
SITE DATA
1. U.T.M. COORDINATES N 25° 33' 19" W 97° 40' 2?"
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 1237.5'
3. SOIL DATA: BEARING VALUE
PILING NECESSARY Had to pile 65'
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE): 39' 11"
MUSTANG POWER PLANT
M-6
-------
S
Z
o
O
5
W
*o
£
z
>. BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (19 73
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
6 . YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS Gas
PEAK
9. FUEL CONSUMPTION:
COAL 9R-QJ£ RATED tons/hour
(T-PH) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION Gas (lOOOMG
COAL (TPY) (19 75}
OIL (GPY) (19 73
11. WET OR DRY BOTTOM
12. FLY ASH REINJECTION (YES OR NO)
13. STACK HGT ABOVE GRADE (FT.)
14. I.D. OF STACK AT TOP (INCHES)
Boiler number
1
7132.7
38.6
1
B & W*
1950
60
27
•)2,575
None
Non<=»
Dry
No
250
126
2
7868.1
44.2
»
2
B & W*
1951
58
27
2,710
None
N<^n°
Dry
Mr,
7Rn
126
•2.
I
Notes:
* B & W - The Babcock & Wilcox Co.
-------
G
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Z
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w
»
T3
tr1
>
Z
•-3
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(tf/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
16. EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
1
NA
NA
16/
2
NA
NA
16/
Notes
I
CO
-------
3
C
cn
1-3
CD
O
s:
ra
z
•-3
17. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
21. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS @ STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
1
134,115
115,000
89,000
290
273
247
25.8
22.2
17.1
2
134,115
115,000
89,000
290
273
247
25.8
22.2
17.1
2
I
a) Identify source of values (test or estimate)
Notes:
-------
S
G
C/5
O
w
JO
£
z
E. I .D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C.)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler number
1
14
8.2
2
14
8.2
Notes : No Controls Presently
Would Need Extra Capacity if ESP Added
3
I
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a .
b.
c.
d.
3. ANALYSIS
GHV (BTU/LB) 12,971
S (%) 1.3
ASH (%) 10.0
MOISTURE (%) 10.5
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE
2. S CONTENT (%}
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL) 126.353 Natural Gas - 1037 Btu/ft3
COST DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
MUSTANG POWER PLANT M-ll
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL? Not Full Time-only for El r<
Boiler No.
Yes or No.
1
Yes
2
Yes
2. SYSTEM AVAILABILITY
2.1
2.2
2.3
COAL HANDLING
a. Is the system still installed?
b. Will it operate?
Yes
D
a
Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
FUEL FIRING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
Yes D
D
D
YesD
D
YesQ
D
D
Q
No D
D
NO n
a
a
D
a
D
NoD
a
NO a
GAS CLEANING
a.
b.
c.
- No equipment is currently installed
is the system still installed? Yes Q No Q
Will it operate? D D
Of the following items which
need to be replaced:
Electrostatic Precipitator YesQ No D
Cyclones D D
Fly Ash Handling Equipment D D
Soot Blowers - Air Compressors Q D
Wall deslaggers D D
MUSTANG POWER PLANT
M-12
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes B No Q
b. Will it operate? Q 0
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes® No [j
Ash Pond $ D
MUSTANG POWER PLANT M-13
-------
L. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DHLS THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? Yes Q No
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULEUR FUELS? Yes Q No
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage? Yes [| No
2.3 Handling facilities available for low
sulfur fuels Yes No
If yes, describe
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
3. IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss _
Yes No
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss __
__ Yes [Jx] No
5. POWER PLANT MONITORING SYSTEM
5.1 Existing system Yes [ | No | |
a. Air quality instrumentation Number Type
(1) Sulfur Oxides - Continuous __ _
- Intermittent __ _
- Static _ _
(2) Suspended participates
- Intermittent _ _
- Static
(3) Other (describe)
Meteorological instrumentation
If yes, describe
c. Is the monitoring data available? Yes jj No [~|
d. Is the monitoring data reduced and
analyzed? Yes Q] No [j
MUSTANG POWER PLANT M-14
-------
b.2 Proposed system Yes fj No
If yes, describe '_
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
(2) Suspended particulate
- Intermittent
- Static ~
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe •
MUSTANG POWER PLANT M~15
-------
Photo No. 1 View from ground level facing west
showing the induced fan house, duct work,
and stack serving Boiler 1.
Photo No. 2 View from the boiler house looking
northwest. Stacks 1 and 2 and their lead-in
ducts are shown in the foreground of the photo.
Cooling towers and oil storage tanks are shown
in the background.
MUSTANG POWER PLANT
M-16
-------
Photo No. 3 View from the boiler house facing
northeast. Cooling towers and the waste water
pit are shown.
Photo No. 4 View from boiler house roof looking
west showing the coal pile and a portion of the
coal conveying system.
MUSTANG POWER PLANT
M-17
-------
Photo No. 5 View from ground level facing south-
west showing the coal conveyors and the transport
house.
Photo No. 6 View from the boiler house roof looking
southeast. A portion of a switchyard is shown in the
foreground of the photo. The ash pond is shown in the
left-center and the surrounding terrain is shown in
the background of the photograph.
MUSTANG POWER PLANT
M-18
-------
Photo No. 7 View from the boiler house roof facing
north showing oil storage tanks, natural gas meter and
regulator stations, and cooling towers.
Photo No. 8 View from the boiler house roof looking
south. The 138 KV substation is shown in the center
of the photograph. The surrounding farmland is shown
in the background.
MUSTANG POWER PLANT
M-19
-------
Photo No. 9 View from the boiler house roof facing
southwest. The top of the transfer house is shown
in the lower left of the photo. The surrounding
terrain and railroad lines are also shown.
Photo No. 10 View from the boiler house roof
looking northwest. Gas turbines are shown in
the lower right and an oil storage tank is
shown in the center of the photograph. A plant
storage area is shown in the background.
MUSTANG POWER PLANT
M-20
-------
TABLE M-l. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1 AND 2 AT THE MUSTANG
POWER PLANT ON HIGH-SULFUR COAL (1978)
Direct Costs
ESP $ 1,617,000
Ash handling 134 QOO
Ducting 421,000
Total direct costs $2,172,000
Indirect Costs
Interest during construction 8% of direct costs $ 174,000
Contractor's fee 10% of direct costs 217,000
Engineering 6% of direct costs 130,000
Freight 1.25% of direct costs 27,000
Offsite 3% of direct costs 65,000
Taxes 0% of direct costs 000
Spares 1% Of direct costs 22,000
Allowance for shakedown 3% of direct costs 65,000
Total indirect costs $700,000
Contingency 574,000
Total $3,446,000
Coal conversion costs 10,703,000
Grand total $ 14,149,000
5/kW 119.91
MUSTANG POWER PLANT M-21
-------
TABLE M-2. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSATIC
PRECIPITATOR FOR BOILERS 1 AND 2 AT THE MUSTANG
POWER PLANT ON HIGH-SULFUR COAL (1978)
Utilities Annual Costs
Electricity 335 kW at 27.5 mills/kWh $ 33,000
Water 4794 x 103 gal/yr at $0.01/103 gal 1,000
Operating Labor
Direct labor 0.5 man/shift at $7.52/h 66,000
Supervision 15% of direct labor 10,000
Maintenance
Labor and materials 2% of fixed investment 69,000
Supplies 15% of labor and materials 10,000
Overhead
Plant 50% of operating and maintenance 78,000
Payroll 20% of operating labor 15,000
Additional Operating and Maintenance
Coal conversion 866,000
Fixed costs
Depreciation (8.33%)
Interim replacement (0.35%), £ = 20.18% of fixed
investment
Insurance (0.30%)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost
Total cost
Fuel credit
Net annual credit
Mills/kWh
$
$
$
695,000
1,843,000
(2,145,000)
(302,000)
0.71
MUSTANG POWER PLANT M-22
-------
Table M-3 . ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 1 AT THE MUSTANG POWER PLANT
ON HIGH- SULFUR COAL BURNING
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.65
197
26,400
4
15 x 37 x 19
MUSTANG POWER PLANT
M-23
-------
Table M-4 . ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 2 AT THE MUSTANG POWER PLANT
ON HIGH-SULFUR COAL BURNING
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.65
197
26,400
4
15 x 37 x 19
MUSTANG POWER PLANT
M-24
-------
TABLE M-5. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1 AND 2 AT THE MUSTANG POWER
PLANT ON LOW-SULFUR COAL (1978)
Direct Costs
ESP $ 1,951,000
Ash handling 283,000
Ducting 388,000
Total direct costs $2,622,000
Indirect Costs
Interest during construction 8% of direct costs $ 210,000
Contractor's fee 10% of direct costs 262,000
Engineering 6% of direct costs 157,000
Freight 1.25% of direct costs 33,000
Offsite 3% of direct costs 79,000
Taxes 0% of direct costs 000
Spares 1% of direct costs 26,000
Allowance for shakedown 3% of direct costs 79,000
Total indirect costs $846,000
Contingency 694,000
Total $4,162,000
Coal conversion costs 10,703,000
Grand total $ 14,865,000
SAW 125.97
MUSTANG POWER PLANT M-25
-------
TABLE M-6. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1 AND 2 AT THE MUSTANG
POWER PLANT ON LOW-SULFUR COAL (1978)
Utilities Annual Costs
Electricity 158 kW at 27.5 mills/kWh $ 15,000
Water 4794 103 gal/yr at $0.01/103 gal 1,000
Operating Labor
Direct labor 0.5 man/shift $7.52/h 66,000
Supervision 15% of direct labor 10,000
Maintenance
Labor and materials 2% of fixed investment 83,000
Supplies 15% of labor and materials 13,000
Overhead
Plant 50% of operating and maintenance 86,000
Payroll 20% of operating labor 15,000
Additional Operating and Maintenance
Coal conversion 866,000
Fixed costs
Depreciation (8.33%)
Interim replacement (0.35%), E = 20.18% of fixed
investment
Insurance (0.30%)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost
Total cost
Fuel cost
Net annual cost
Mills/kWh
$
$
$
840,000
1,995,000
4,725,000
6,720,000
15.72
MUSTANG POWER PLANT M-26
-------
Table M-7 . ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 1 AT THE MUSTANG POWER PLANT
ON LOW-SULFUR COAL BURNING
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.65
417
55,900
4
30 x 19 x 42
MUSTANG POWER PLANT
M-27
-------
Table M-8 . ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 2 AT THE MUSTANG POWER PLANT
ON LOW-SULFUR COAL BURNING
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.65
417
55,900
4
30 x 19 x 42
MUSTANG POWER PLANT
M-28
-------
o
o
o
o
COOLING
TOWERS
0
o
WASTE
COOLING TOWER WATER
PIT
O
o
o
PRECIPITA-
TANKS
O/S
V-X
o
o
o
0
-i 1 »-
DGAS REGULATOR &
METERING STATIONS
t i 1 1 1 1
S STACKS ~~ESP~
TRANSPORTf)
HOUSE UJ
POWER PLANT
PARKING LOT
_X y x—. j—x—x x—.
• 66 KV I I I
J SWITCHYARD fj SWITCHYARD J
I—X X X—J I—X X^—X—J
138 KV
SUBSTATION
Figure M-l. Site plan showing possible locations of new ESP's
for Boilers 1 and 2 at the Mustang power plant.
MUSTANG POWER PLANT
M-29
-------
APPENDIX N
POSSUM POINT POWER PLANT
POSSUM POINT POWER PLANT N-l
-------
CONTENTS
Possum Point Power Plant Survey Form
Possum Point Power Plant Photographs
Page
N-4
N-16
Number
N-l
FIGURES
Site Plan Showing Possible Locations of New
ESP's for Boilers 2, 3, and 4 at the Possum
Point Power Plant
Page
N-30
Number
N-l
N-2
N-3
N-4
N-5
N-6
TABLES
Estimated Capital Cost for an Electrostatic
Precipitator for Boiler 2 at the Possum Point
Power Plant (1978)
Estimated Annual Operating Cost of an Electro-
static Precipitator for Boiler 2 at the Possum
Point Power Plant (1978)
Electrostatic Precipitator Design Values for
Boiler 2 at the Possum Point Power Plant
Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 3 at the Possum Point
Power Plant (1978)
Estimated Annual Operating Cost of an Electro-
static Precipitator for Boiler 3 at the Possum
Point Power Plant (1978)
Electrostatic Precipitator Design Values for
Boiler 3 at the Possum Point Power Plant
Page
N-21
N-22
N-23
N-24
N-25
N-26
POSSUM POINT POWER PLANT
N-2
-------
TABLES (continued)
Number Page
N-7 Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 4 at the Possum Point
Power Plant (1978) N-27
N-8 Estimated Annual Operating Cost of an Electro-
static Precipitator for Boiler 4 at the Possum
Point Power Plant (1978) N-28
N-9 Electrostatic Precipitator Design Values for
Boiler 4 at the Possum Point Power Plant N-29
POSSUM POINT POWER PLANT N-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION:
1. COMPANY NAME:
Virginia Electric & Power Co.
2. MAIN OFFICE: P-0. Box 26666, Richmond, Virginia 23261
3. RESPONSIBLE OFFICER: C' M' Callings
4. POSITION: vice President
5. PLANT NAME: Possuit^ Point Power Station
6. PLANT LOCATION: Prince William County, Dumfries Va. 22026
RESPONSIBLE OFFICER AT PLANT LOCATION:
POSITION: Plant Superintendent
7
8
Holland Simmons
9. POWER POOL
DATE INFORMATION GATHERED:
April 21, 1976
PARTICIPANTS IN MEETING:
Ned Kirby - VEPCO - Richmond
Ken Newsome - VEPCO - Richmond
Jim Cassada VEPCO - Richmond
Joe O'Rear - VEPCO -Richmond
Bob Combs - VEPCO - Richmond
R. H. Milliard - VEPCO-Possum Point
Rolland Simmons - VEPCO- Possum Point
Bernie Turlinski - U.S. Environmental Protection Agency
Daniel J. Gaston - Virginia Air Pollution Control Board
Frank Lalley - Federal Energy Administration
Thomas C.- Ponder, Jr. - PEDCo Environmental, Inc.
N. David Noe - PEDCo Environmental, Inc.
David M. Augenstein - PEDCo Environmental, Inc.
POSSUM POINT POWER PLANT
N-4
-------
O
to
to
C
S
13
O
w
JO
B.
Z
I
ui
*
ATMOSPHERIC EMISSIONS
1. PARTICIPATE EMISSIONS3
LB/MM BTU
GRAINS/A CF
LB/HR (FULL LOAD)
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
Part IV
0.1 Ib/i
less than
Part IV
1.06 Ib
ule Ex -
im B tu
20% opari t
ule Ex - '
mm Btu !
4.30
y ( Rn 1 p • ]
4.51 ( i
02
(a) 11
v 7 )
»
) 1
a) Identify whether results are from stack tests or estimates
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT)
3. SOIL DATA: BEARING VALUE
PILING NECESSARY_
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE):
POSSUM POINT POWER PLANT N_g
-------
G
3
Z
t-3
i
w
13
£
z
Z
I
-j
•^
D. BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (19? 5 )
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS - Summer
PEAK
9. FUEL CONSUMPTION:
COAL . -, ': , - TPH coal -
(TPH) OR (GPH) MAXIMUM CONTINUOUS
BBL/Hr. oil
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (1975)
OIL '^") BBI./yr
11. WET OR DRY BOTTOM
12. FLY ASH REINJECTION (YES OR NO)
13. STACK HGT ABOVE GRADE (FT.)
14. I.D. OF STACK AT TOP (INCHES)
Boiler number
1
Float
6,572.50
39.0
1
TF.
1948
69
74
31.5
132
525,050
Dry
Yes
175
156
2
Float
7,243.75
48.0
2
CE
1951
69
69.2
29.6
140
577,950
Dry
Yes
175
156
3
Float
5,057.60
34.0
3
PE
1955
113.64
101
38.5
162
551,950
Dry
Yes
177
156
4
Float
7,043.36
57.0
4
rv
1962 *•
239. 36
232.9
78. 3
338
1,970,600
Dry
f
Yes
175
168
5
rioating
3,585.38
23.3
5
CE
1975
882
805
0
1.220
3,212.690
NA
.Yes
358.5
276
Notes:
-------
O
Cfi
W
G
s
O
H
2
O
S
M
Z
-3
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
16. EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
1
N/A
COTT
E
95
249 . 7
2
N/A
COTT
E
96
170
3
N/A
COTT
E
96
210. 7
4
N/A
COTT
E
96
428 .5
t
5
UOP
MCAX
9112
206
N/A
2
00
Notes :
-------
O
cn
en
c
2
O
M
z
13
i
w
£
z
^
17. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/Yr.)
21. BOTTOM ASH: TOTAL COLLECTED (J.IGNS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/-T2QN)
22. EXHAUST DUCT DIMENSIONS @ STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
1
322r321
247,217
172,556
364
330
311
40.5
31 .0
21.7
0 .6 cal
Land fill
30, 700
0.1 ca]
Land fill
7,000
2
271r 776
210,945
144 ,692
303
275
255
34.4
26.5
18. 2
3
338 ,nqq
259,259
186 ,502
277
265
246
42.5
32.6
23.4
4
6Sn, 3RS
492,435
334,125
265
2'46
219
70.4
53.3
36. 2
5
?,ORO inn
1,583,500
1,103,500
260
255
249
83.4
63.5
44.3
z
I
a) Identify source of values (test or estimate)
Notes:
-------
o
to
to
c
2
13
O
E . I .D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C-)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler nunxber
O
s
w
13
tr1
>
Z
•-3
Notes :
z,
I
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES)
2_. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
ANALYSIS
GHV (BTU/LB)
S (%)
ASH (%)
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE //2
2. S CONTENT (%)
3. ASH CONTENT (%)
SPECIFIC GRAVITY
5. GHV (BTU/GAL) 146,680
COST DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
POSSUM POINT POWER PLANT N-ll
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler
Yes
or
SYSTEM
2.1
NO.
No.
1
Yes
AVAILABILITY
234 5
Yes YP« Yog - ifo
COAL HANDLING
a
b
c
. Is
the system still installed? Yes S No D Runn: {
OK
. Will it operate? D D
. Of
the following items which
need to be replaced:
Unloading equipment Repair Yes H No D
Stack Reclaimer S D
Bunkers
Conveyors
Scales
Coal Storage
2.2
B D
a D
D m
Area H D
FUEL FIRING
a
b
. Is
the system still installed? YesQ No Q
. Will it operate? D [3
Some replaced by
Of the following items which
need to be replaced:
Pulverizers or Crushers
fly ash reinject Feed Ducts
Fans
Controls
2.3 GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
Yes [x|
D
m
B
Yesgg
E
Yes
No D
D
D
D
No n
D
NoQ
Bon A
E
D x
Q
n
a
a
D
POSSUM POINT POWER PLANT
N-12
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes 0 Non
b. Will it operate? 0 Q
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes 0 NoD
Ash Pond D x Q
POSSUM POINT POWER PLANT N_13
-------
L. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? Yes D -No D
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS? Yes Q No Q
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage? Yes [~] No r~)
2.3 Handling facilities available for low
sulfur fuels ' Yes No
If yes, describe
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
3. IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss _
___ ; _ Yes Q No [J
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss _
Yes No
5. POWER PLANT MONITORING SYSTEM
5.1 Existing system ' Yes [~1 No [~|
a. Air quality instrumentation Number Type
(1) Sulfur Oxides - Continuous _ _
- Intermittent __ _
- Static _ _
(2) Suspended particulars
- Intermittent _ _
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
c. Is the monitoring data available? Yes f~j No (|
cl. Is the monitoring data reduced and
analyzed? Yes Q] No [j
POSSUM POINT POWER PLANT N-14
-------
!i.2 Proposed system Yes P] No
If yes, describe
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static ~
(2) Suspended particulato
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
POSSUM POINT POWER PLANT N-15
-------
Photo No. 1. View from the roof of Boiler 5 facing south
showing stacks 1, 2, 3, and 4. Cooling towers and Potomac
River are in the background.
Pholc No. 2. View from the roof of Boiler 5 facing north-
east: showing oil tanker unloading facilities on the Potomac.
POSSUM POINT POWER PLANT
N-16
-------
Photo No. 3. View from the roof of Boiler 5 facing north
showing Boiler 5 duct tie-ins to the stack. Oil storage
tanks are shown in the background.
Photo No. 4. View from the roof of Boiler 5 facing north-
west showing oil storage facilities and electrical sub-
station.
POSSUM POINT POWER PLANT
N-17
-------
Photo No. 5. View from the roof of Boiler 5 facing south-
west showing an electrical substation, coal storage area and
the Potomac River.
Photo No. 6. View from ground level showing electrostatic
pi:ecipitator serving Boiler 4 located on the northeast end
of the plant.
POSSUM POINT POWER PLANT
N-18
-------
Photo No. 7. View from ground level showing electrostatic
precipitator and tie-in to stack serving Boiler 3 located on
the east end of the plant.
Photo No. 8. View from ground level facing south showing
available space behind Stacks 1, 2, 3, and 4 on the east end
of the plant.
POSSUM POINT POWER PLANT
N-19
-------
I
Photo No. 9. View from ground level facing north showing
electrostatic precipitator and tie-in duct serving Boiler 1
Photo No. 10. View from ground level facing south showing
coal handling facilities. A portion of the coal storage
area is also shown.
POSSUM POINT POWER PLANT
N-20
-------
TABLE N-l. ESTIMATED CAPITAL COST FOR AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 2 AT THE
POSSUM POINT POWER PLANT (1978)
Direct Costs
ESP $2,356,000
Ash handling 850,000
Ducting 356,000
Total direct costs $3,562,000
Indirect Costs
Interest during construction 10% of direct costs $ 356,000
Contractor's fee 10% of direct costs 356,000
Engineering 10% of direct costs 356,000
Freight 1.25% of direct costs 45,000
Offsite 3% Of direct costs 107,000
Taxes 0% of direct costs 000
SPares 1% of direct costs 36,000
Allowance for shakedown 3% of direct costs 107,000
Total indirect costs $1,363,~000~
Contingency 985,000
To ta l $ 5,9 ToTo o o~
Coal conversion costs 137,000
Grand total $6,047,000
87.38
POSSUM POINT POWER PLANT N-21
-------
TABLE N-2. ESTIMATED ANNUAL OPERATING COST OF AN
ELECTROSTATIC PRECIPITATOR FOR BOILER 2 AT THE
POSSUM POINT POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 466 kW 27.50 mills/kWh $ 53,000
Water 1 x 103 gal/h $0.01/103 gal i,'000
Operating Labor
Direct labor 0.5 man/shift $8.50/man-hour 37 000
Supervision 15% of direct labor 6,'oOQ
Maintenance
Labor and materials 21 of fixed investment 118 000
Supplies i5-6 of labor and materials 18,'oOO
Overhead
Plant 50°o of operation and maintenace 90,000
Payroll 20-S of operating labor 9,000
Trucking
Bottom/fly ash 000
removal
Fixed Costs
Depreciation (7.69%)
Interim replacement (0.35C<;), I = 19.54% of fixed
investment
Insurance (0.30-c)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost $1,155,000
Total cost $1,487,000
Fuel credit
Net annual cost $ 836,000
Mills/kWh 2 87
POSSUM POINT POWER PLANT N-22
-------
TABLE N-3. ELECTROSTATIC PRECIPITATOR DESIGN VALUES FOR
BOILER 2 AT THE POSSUM POINT POWER PLANT
Design Parameter
Values
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area, ft2
Superficial velocity, ft/s
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.40
568
155,400
4.0
42 x 29 x 50
POSSUM POINT POWER PLANT
N-23
-------
TABLE N-4. ESTIMATED CAPITAL COST OF AN
ELECTROSTATIC PRECIPITATOR FOR BOILER 3 AT THE
POSSUM POINT POWER PLANT (1978)
Direct Costs
ESP $2,430,000
Ash handling 945,000
Ducting 387,000
Total direct costs $ 3,762,000
Indirect Costs
Interest during construction 1.0% of. direct costs $ 376,000
Contractor's fee 10% of direct costs 376,000
Engineering 10% of direct costs 376,000
Freight 1.25% of direct costs 47,000
Offsite 3% of direct costs 113,000
Taxes 0% of direct costs 000
Spares 1% of direct costs 38,000
Allowance for shakedown 3% of direct costs 113,000
Total indirect costs $1,439,000
Contingency 1,040,000
Total $6,241,000
Coal conversion costs 213 000
Grand total $6,454,000
$/kW 63>90
POSSUM POINT POWER PLANT N-24
-------
TABLE N-5. ESTIMATED ANNUAL OPERATING COST OF AN
ELECTROSTATIC PRECIPITATOR FOR BOILER 3
AT THE POSSUM POINT POWER PLANT (1978)
ULilUieS Quantity unit Cost
27.50 mills/kW ,
gal/h $0.01/103 gal i/000
lUectricity 538 kW 27.50 mills/kWh $ 43,000
WaLcr ! J
Operating Labor
Direct labor- 0.5 man/shift $8 . 50/man-hour
Supervision i5% of direct labor
Maintenance
Labor and materials 2", of fixed investment 125 QOO
Supplles 15"6 of labor and materials 19,000
Overhead
Payroll ™? °P opcration and nmintenace 94,000
layroli 20° of operating labor 9,000
Trucking
Bottom/fly ash nnn
removal °°°
Fixed Costs
Depreciation (5.88%)
Interim replacement (0.35%), L = 17.73% of fixed
investment
Insurance (0.305)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost C1 , n_ nnn
$1,107,000
Total cost ei
$1
POSSUM POINT POWER PLANT N-25
-------
TABLE N-6. ELECTROSTATIC PRECIPITATOR DESIGN VALUES FOR
BOILER 3 AT THE POSSUM POINT POWER PLANT
Design Parameter
Values
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area, ft2
Superficial velocity, ft/s
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.40
531
179,634
4.0
39 x 38 x 47
POSSUM POINT POWER PLANT
N-26
-------
TABLE N-7. ESTIMATED CAPITAL COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 4 AT THE
POSSUM POINT POWER PLANT (1978)
Direct Costs
ESP $3,463,000
Ash handling 1,455,000
Ducting 523,000
Total direct costs $ 5,441,000
Indirect Costs
Interest during construction 10% of. direct costs $ 544,000
Contractor's fee 10% of direct costs 544,000
Engineering 10% of direct costs 544,000
Freight 1.25% of direct costs 68,000
offsite 3% of direct costs 163,000
Taxes 0% of direct costs 000
SPares 1% of direct costs 54,000
Allowance for shakedown 3% of direct costs 163,000
Total indirect costs $2f080"f"000"
Contingency 1,504,000
Total $9,025,000
Coal conversion costs 341,000
Grand total $9,366,000
SAW 40.21
POSSUM POINT POWER PLANT N-27
-------
TABLE N-8. ESTIMATED ANNUAL OPERATING COST OF AN
ELECTROSTATIC PRECIPITATOR FOR BOILER 4 AT THE
POSSUM POINT POWER PLANT (1978)
Quantity unit Cost
Annual Cost
Electricity 863 kW 27.50 mills/kWh $ 118,000
Water 3 x 103 gal/h $0.01/103 gal 1,000
Ope rat ing Laboi:
Direct labor 0.5 man/shift $8 . 50/man-hour 37 QOO
Supervision 15°, o£ direct labor 6,000
Maintenance
Labor and materials 2:, of fixed investment 181,000
supplies is-j Of labor and materials . 27,000
Overhead
50°6 of operation and maintenace 126,000
1 20o of operating labor 9,000
Trucking
Bottom/fly ash 000
removal
Fixed Costs
Depreciation (4.17%)
Interim replacement (0.353), JJ = 16.02% of fixed
investment
Insurance (0.30°0)
Taxes (0.00°0)
Capital cost (11.20%)
Total fixed cost $ 1/446/000
Total cost s , 95,
Fuel rrprtil- ^ l,ybl,000
1 credlt (3,696,000)
Net annual credit S(1 74,--
Mills/kWh >U,/4b_,
POSSUM POINT POWER PLANT N_28
-------
TABLE N-9. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 4 AT THE POSSUM POINT POWER PLANT
Design Parameter
Values
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area, ft2
Superficial velocity, ft/s
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.40
442
287,760
4.0
33 x 83 x 40
POSSUM POINT POWER PLANT
N-29
-------
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M
i
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o
;ESP.I IESP.! I ESP.;
Figure N-l. Site plan showing possible locations of new ESP's for
Boilers 2, j, ana 4 at tne Possum Point power plant.
-------
APPENDIX 0
RAVENSWOOD POWER PLANT
RAVENSWOOD POWER PLANT 0-1
-------
CONTENTS
Ravenswood Power Plant Survey Form
Ravenswood Power Plant Photographs
Page
0-4
0-16
Number
0-1
0-2
FIGURES
Site Plan Showing Possible Locations of Major
Components for the Sodium Solution Regenerable
System for Boiler 30 at the Ravenswood Power
Plant
Site Plan Showing Possible Locations of Major
Components for the Limestone System for Boiler
30 at the Ravenswood Power Plant
Paqe
0-27
0-33
Number
0-1
0-2
0-3
0-4
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boiler 30 at the
Ravenswood Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boiler 30 at
the Ravenswood Power Plant (1978)
Retrofit Equipment and Facilities for the
Sodium Solution Regenerable System for Boiler
30 at the Ravenswood Power Plant
Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boiler
30 at the Ravenswood Power Plant
Page
0-22
0-24
0-25
0-26
RAVENSWOOD POWER PLANT
0-2
-------
TABLES (continued)
Number Page
0-5 Estimated Capital Cost of a Limestone Scrubbing
System for Boiler 30 at the Ravenswood Power
Plant (1978) 0-28
0-6 Estimated Annual Operating Cost of a Limestone
Scrubbing System for Boiler 30 at the Ravenswood
Power Plant (1978) 0-30
0-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boiler 30
at the Ravenswood Power Plant 0-31
0-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boiler 30 at the
Ravenswood Power Plant 0-32
RAVENSWOOD POWER PLANT 0-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: Consolidated Edison Company
2. MAIN OFFICE: 4 Irving Place, New York, New York 10003
3. RESPONSIBLE OFFICER: John J. Grob, Jr.
4. POSITION: Chief Nuclear and Emission Control Engineer
5. PLANT NAME: Ravenswood
6. PLANT LOCATION: Queens, New York
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Gene McGrath
8. POSITION: Plant Superintendent
9. POWER POOL N.Y. P.P.
DATE INFORMATION GATHERED: June 30, 1976
PARTICIPANTS IN MEETING:
Bertrum D. Moll
Demarest Romaine
Peter C. Freudenthal
John J. Grob
Ralph Morgan
Ray Werner
Robert N. Ogg
Richard T. Price
N. David Noe
Thomas C. Ponder
Consolidated Edison Company
Consolidated Edison Company
Consolidated Edison Company
Consolidated Edison Company
Consolidated Edison Company
USEPA - II - Air Branch
USEPA - II - Air Facilities Branch
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
RAVENSWOOD POWER PLANT
0-4
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B.
M
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I
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 Oil
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (1975)
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO..
LB/MM BTU
OPACITY, PERCENT
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3 Oil
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
i n
I
._— — — — — C^
0.10
"Da
0.33
?n
I
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0.10
rt 225 Tab:
0. 33
^n
0.06
1284
I
, \ _
. ) — —
0.10
0.29
6805
ST _
0.33
a) Identify whether results are from stack tests or estimates
-------
C. SITE DATA
1. U.T.M. COORDINATES.
2. ELEVATION ABOVE MEAN SEA LEVEL (FT)
3. SOIL DATA: BEARING VALUE
PILING NECESSARY
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE):
RAVENSWOOD POWER PLANT 0-6
-------
1
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I
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR ' (1975 )
4 . SERVED BY STACK NO .
5. BOILER MANUFACTURER
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTION:
RATED "^ ~*>
MAXIMUM CONTINUOUS
m ted Gas
10. ACTUAL FUEL CONSUMPTION
GAS (1975) 106 FT3
OIL (1975) 103 BBL
11. HEAT RATE BTU/KWHR GAS
COAL (1968)
OIL (1974)
12. WET OR DRY BOTTOM
13. FLY ASH REINJECTION (YES OR NO)
14. STACK HGT ABOVE GRADE (FT.)
15. I.D. OF STACK AT TOP (INCHES)
Boiler number
10
7862
67.8
1
CE
1963
400
568.1
None
3580
250.1
3110.7
No
515
170
?n
6228
55.7
2
CE
1963
400
568.1
None
3580
32.7
2487.8
No
515
170
in N
7552
63.6
3
CE
1965
TO Q
7333
62.5
3
CE
1965
1 0
— T>
No
"7 O
__ _ _"7 £
/O'
97,
— — — — QAi
Dry
No
51
28
ie
9___ _ _
"3 Q__ _ _
o . y — - -
19 --
4_
Dry
No
,
Notes:
-------
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13
O
16. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
17. EXCESS AIR: DESIGN /ACTUAL (%)
Boiler number
10
10
20
10
10
Pntt *
qq/
4qdd
1,008,000
700
25
o
I
oo
Notes
Cott - Research Cottrell, Inc.
-------
M
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s:
M
18. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
§ 50% LOAD
19. STACK GAS EXIT TEMPERATURE (°F)a
8 100% LOAD
§ 75% LOAD
@ 50% LOAD
20. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
21. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
23. EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO STACK
25. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
10
656.000
335
119
20
656.000
335
119
30
4 ,300, 000
700
105
o
I
a) Identify source of values (test or estimate)
Notes:
-------
o
o
D
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
O
5
W
JO
Notes:
O
I
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F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
3. ANALYSIS (19
HHV (BTU/LB)
S (%)
ASH (%)
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE.IN ATTACHMENT)
H. FUEL OIL DATA (1975)
1. TYPE
2. S CONTENT (%) 0.27
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL) 144,241
I. NATURAL GAS HHV (BTU/FT3) 1025
J. COST DATA
ELECTRICITY
FUEL: COAL GAS OIL
WATER
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES (No Sales Tax)
STATE PROPERTY TAX
RAVENSWOOD POWER PLANT
-------
K,
PLANT SUBSTATION CAPACITY
M.
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
ADDITIONAL INFORMATION
F.E.A. LETTER
OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
2. SYSTEM AVAILABILITY
2.1 COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer (Barge)
Bunkers
Conveyors
Scales
Coal Storage Area
2.2 FUEL FIRING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Pulverizer^ or Crushers
Feed Ducts
Fans
Controls
2.3 GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
Boiler
YesES
30
YesB
Yes
m
B
YesQ
a
NoD
D
YesH
D
B
H
H
D
No D
S
D
D
D
H
NoD
D
NoD
a
a
a
NO a
a
YesQ
a
0
a
s
NoD
n
n
n
D
RAVENSWOOD POWER PLANT
0-12
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes B No Q
b. Will it operate? H D
c. Of the following items which
need to be replaced:
Bottom Ash Handling YesB NoD
Ash Pond £] Q
RAVENSWOOD POWER PLANT O-13
-------
SUPPLEMENTARY CONTROL SYSTEM DATA
1 . DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)?
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS?
2.1 Storage capacity for low sulfur fuels
(tons , bbls > days)
2.2 Bunkers available for low sulfur coal
storage?
2.3 Handling facilities available for low
sulfur fuels
If yes, describe _
3.
5.
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss
POWER PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(1) Sulfur Oxides - Continuous
- Intermittent
- Static
(2) Suspended particulates
- Intermittent
- Static
(3) Other (describe) ___
b. Meteorological instrumentation
If yes, describe
c.
Is the monitoring data available?
d. Is the monitoring data reduced and
analyzed?
e. Provide map of monitoring locations
RAVENSWOOD POWER PLANT
Yes
No G
Yes Q No
Yes G No G
Yes No O
Yes
Yes
Yes
Number
Yes
Yes
No G
N° o
No
Type
No D
No D
0-14
-------
5.2 Proposed system Yes f"D No
If yes, describe and provide map
Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
Meteorological instrumentation
If yes, describe
RAVENSWOOD POWER PLANT 0_15
-------
Photo No. 1 View from the roof of Boiler 30 facing northeast.
The surrounding urbanized Queens area is shown across the center
of the photograph.
Photo No. 2 View from the roof of Boiler 30 looking east.
A portion of the ESP house is shown across the bottom of the
photo. Part of Stack 30 is shown on the right side of the
photograph.
RAVENSWOOD POWER PLANT
0-16
-------
Photo No. 3 View from the boiler house roof facing northwest.
Turbines 4 through 11 are shown in the center of the photo.
To their right are shown a fuel oil tank and two gas turbines.
The Welfare Island Bridge is shown just left of center.
Photo No. 4 View from the roof of Boiler 30 looking south-
southeast. Stacks 10 and 20 are shown in the center of the
photo from right to left, respectively.
RAVENSWOOD POWER PLANT
0-17
-------
Photo No. 5 View from the boiler house roof facing south-
southwest. The coal crusher house is shown in the center
of the photo. To its right and left, respectively, are shown
coal conveyors A and B. The top half of the photo shows the
59th Street Bridge crossing the East River.
£
i*
•'/£.'
<£•*
Photo No. 6 View from the roof of Boiler 20 facing east. Oil
transfer pumps for Boilers 10 and 20 are shown just left of
center. The natural gas meter and regulation station are shown
left of the pumps.
RAVENSWOOD POWER PLANT
0-18
-------
Photo No. 7 View from the boiler house roof looking southwest,
The Vernon switch station is shown in the bottom left portion
of the photo. The ash silo is shown just right of center.
Photo No. 8 View from the roof of Boiler 10 facing south.
Queensboro Park is shown in the center of the photograph.
The switchyard and 59th Street Bridge are shown at the
bottom and top of the photo, respectively.
RAVENSWOOD POWER PLANT
0-19
-------
Photo No. 9 View from ground level facing north. The coal
unloading tower is shown in the center of the photo. Conveyor
A is shown rising upward at left.
Photo No. 10 View from ground level looking south-southeast
Cooling water circulating pumps are shown in the center of
the photo.
RAVENSWOOD POWER PLANT
0-20
-------
Photo No. 11 View from the parking lot facing west. The
Ravenswood power plant is at left and its steam plant is shown
right of center. The steam plant's two stacks are a,lso shown.
Photo No. 12 View from ground level looking southwest. The
I.D. fan installations for Boilers 10 and 20 are shown respec-
tively, from left to right across the center of the photograph
RAVENSWOOD POWER PLANT
0-21
-------
TABLE 0-1. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 30 AT THE
RAVENSWOOD POWER PLANT (1978)
Direct Costs
A. Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
B. SO2 Scrubbing
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
C. Purge Treatment
Refrigeration unit
Heat exchangers
Tanks
Dryer
Elevator
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
89,000
6,000
32,000
26,000
2,000
Total A = $ 155,000
$20,570,000
2,275,000
602,000
3,595,000
2,608,000
10,690,000
1,674,000
Total B = $42,014,000
$ 585,000
87,000
101,000
32,000
15,000
493,000
1,171,000
1,405,000
89,000
6,000
Total C = $ 3,984,000
(continued)
RAVENSWOOD POWER PLANT
0-22
-------
TABLE O-l (continued)
D. Regeneration
Pumps and motors $ 317,000
Evaporators and reboilers 5,268,000
Heat exchangers 690,000
Tanks 77,000
Stripper 154,000
Blower 225,000
Total D = $ 6,731,000
Particulate Removal
Venturi scrubber $ 9,030,000
Tanks 262,000
Pumps and motors 2,642,000
Total E = $ 11,934,000
Total direct costs = A + B + C + D + E = F=$ 64,818,000
Indirect Costs
Interest during construction $ 6,482,000
Field labor and expenses 6,482,000
Contractor's fee and expenses 3,241,000
Engineering 6,482,000
Freight 810,000
Offsite 1,944,000
Taxes 000
Spares 324,000
Allowance for shakedown 3,241,000
Acid plant 2,498,000
Total indirect costs G = $ 31,504,000
Contingency H = 19,264,000
Total = F + G + H = $115,586,000
Coal conversion cost 863,000
Grand total $116,449,000
$/kW 145.56
RAVENSWOOD POWER PLANT 0-23
-------
TABLE 0-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 30 AT THE
RAVENSWOOD POWER PLANT (1978)
Quantity
Unit Cost Annual Cost
Raw Materials
Soda Ash 0.84 tons/h
Utilities
$90.36/ton $ 421,000
Process water
Cooling water
Electricity
Reheat steam
Process steam
Operation Labor
Direct labor
Supervision
Maintenance
4168 gal/min $0.66/10^ gal 912,000
16.5 x 103 gal/min $0.01/10 gal 56,000
19078 kW 33.3 mills/kWh 3,504,000
137 x 106 Btu/h $1.696/106 Btu 1,278,000
234 x 106 Btu/h $1.699/106 Btu 2,193,000
4 men/day
15% of direct labor
$10.67/man-hour
Labor and materials 4% of fixed investment
Supplies 15% of labor and materials
Overhead
374,000
56,000
4,623,000
694,000
Plant
Payroll
Fixed Costs
50% of operating and maintenance 2,874,000
20% of operating labor
86,000
Depreciation
(3.70%)
Interim replacement (0.35%)
Insurance (0.30%)
Taxes (4.00%)
E = 19.55% of fixed
investment
Capital cost (11.20%)
Total fixed cost
Total cost
Credits (byproducts)
22,597,000
$ 39,668,000
Sulfuric acid 11.64 tons/h
Na2S04 0.84 tons/h
Total byproduct credits
Fuel credit
Net annual cost
Mills/kWh
$58.41/ton (3,754,000)
$71.63/ton (334,000)
$ (4,088,000)
(26,149,000)
$ 9,431,000
2.13
RAVENSWOOD POWER PLANT
0-24
-------
Table 0-3. RETROFIT EQUIPMENT AND FACILITIES
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
FOR BOILER 30 AT THE RAVENSWOOD POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na-CO., storage
Na-CO., preparation
$©2 regeneration
Purge treatment
Sulfuric acid plant
8
8
1
1
1
1
1
100 MW capacity unit
Scaled to train size
605 tons (30-day storage
1680 Ib/hr, Na2CO3
12,850 Ib/hr, SO2
1680 Ib/hr, Na2SO.
146 tons/day, HSO.
RAVENSWOOD POWER PLANT
0-25
-------
Table 0-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
FOR BOILER 30 AT THE RAVENSWOOD POWER PLANT
Item
Number
required
Dimensions, ft
Na-CO, storage
Absorber feed surge
tank
Turbulent contact
absorbers
Regeneration plant
Purge treatment plant
Acid plant
1
1
1
1
1
20 diam x 45 high
40 diam x 40 high
45 high x 15 wide x 40 long
65 x 180
65 x 190
75 x 155
RAVENSWOOD POWER PLANT
0-26
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.
1
1
o
•z.
1
13
«x
_J
0.
EAST RIVER
gj^^j^^<^-"*^~^^===^^^ — *-- — ^^=^^~r-
FLY ASHQO
SILOS ^Y^
FUTURE
VERNON SUBSTATION
L-J DOCK COAL CONVEYORS U
T|NNSFER STATIONARY ST
T°WEP COAL TOWER
RAVENSWOOD POWER PLANT
BOILER BOILER BOILER
NO. 10 NO. 20 NO. 30
STACK STACK
ONO. 1 DNO. 2 STACK
(Pb (Hi (fli (ft* 1 v_x
,f~j, jtfSk *^» j/^i
°°r (QJ | Esp J| Esp |
X
G WHARF_____^ BULKHEAD LINE
r"^ ln'7Tflrii' ... .—
ACK^l \o5TACK
L 1 _J TURBINE HOUSE
L- L— r
BOILER
'USE A 2,000,000 GAL^
OIL TANK \J _ OIL
UTANK !
AB . — — — i i
UNIT 2 UNIT 3
V GAS TURBINES
cs:
CO
VERNON BOULEVARD
o
(o
A PURGE TREATMENT AND
S02 REGENERATION
B ACID
C SCRUBBERS
D STORAGE SILO
E SOLUTION TANK
Figure O-l. Site plan showing possible locations of major components
for the sodium solution regenerable system for Boiler 30 at the Ravenswood
power plant.
-------
TABLE 0-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILER 30 AT THE RAVENSWOOD POWER PLANT
(1978)
Direct Cost
A. Limestone Preparation
Conveyors $ 453,000
Storage silo 100,000
Ball mills 724,000
Pumps and motors 206,000
Storage tanks 171,000
Total A = $ 1,654,000
B. Scrubbing
Absorbers $16,557,000
Fans and motors 2,527,000
Pumps and motors 1,254,000
Tanks 992,000
Reheaters 3,595,000
Soot blowers 978,000
Ducting and valves 10,930,000
Total B = $36,833,000
Sludge Disposal
Clarifiers $ 346,000
Vacumm filters 484,000
Tanks and mixers 12,000
Fixation chemical storage 33,000
Pumps and motors 108,000
Sludge pond 2,103,000
Mobile equipment 64,000
Total C = $ 3,150,000
(continued)
RAVENSWOOD POWER PLANT O-28
-------
TABLE 0-5 (continued)
D. Particulate Removal
Venturi scrubber $ 9,030,000
Tanks 265,000
Pumps and motors 348,000
Total D = $ 9,643,000
Total direct costs =A+B+C+D=E= $ 51,280,000
Indirect Costs
Interest during construction $ 5,128,000
Field overhead 5,128,000
Contractor's fee and expenses 2,564,000
Engineering 5,128,000
Freight 641,000
Offsite 1,538,000
Taxes 000
Spares 256,000
Allowance for shakedown 2,564,000
Total indirect costs F = $ 22,947,000
Contingency G = 14,845,000
Total =E+F+G= $ 89,072,000
Coal conversion costs 863,000
Grand total $ 89,935,000
$/kW 112.42
RAVENSWOOD POWER PLANT 0-29
-------
TABLE 0-6. ESTIMATED ANNUAL OPERATING COST OF A
LIMESTONE SCRUBBING SYSTEM FOR BOILER 30 AT THE
RAVENSWOOD POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Limestone
Fixation chemicals
Utilities
Water
Electricity
Fuel for reheat
Operating Labor
Direct labor
Supervision
Maintenance
Labor and materials
Supplies
Overhead
Plant
Payroll
Trucking
Bottom/fly ash and
sludge removal
Fixed Costs
16.2 tons/h
67.0 tons/h
$16.81/ton
$2.20/ton
290 gal/min $0.66/10 gal
15,633 kW 33.3 mills/kWh
136.5 x 106 Btu/h $1.696/106 Btu
3 men/day
$10.67/man-hour
15% of direct labor
4% of fixed investment
15% of labor and material
50% of operation and maintenance
20% of operating labor
$ 1,510,000
817,000
64,000
2,872,000
1,278,000
281,000
42,000
3,563,000
534,000
2,210,000
65,000
12,242,000
Depreciation (3.70%)
Interim replacement (0.35%),
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed charges
Total cost
Fuel credit
Net annual cost
Mills/kWh
£ = 19.55% of fixed
investment
17,414,000
$42,892,000
(26,149,000)
$16,743,000
3.79
RAVENSWOOD POWER PLANT
O-30
-------
Table 0-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 30
AT THE RAVENSWOOD POWER PLANT
Module Description
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
Number
Required
1
1
8
Size/Capacity
11,700 tons (30 day storage)
16.2 ton/hr limestone
100 MW unit/s
Scaled to train size
RAVENSWOOD POWER PLANT
0-31
-------
Table 0-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 30
AT THE RAVENSWOOD POWER PLANT
Item
Number
Required
Dimensions, ft
Limestone storage pile
Limestone silos•
Limestone slurry tanks
Ball mill building
Turbulent contact
absorbers
Clarifiers
Vacuum filter building
1
3
1
1
8
2
1
115 wide x 170 long
17 diam x 38 high
60 diam x 20 high
40 x 40
45 high x 15 wide x 30 long
75 diam x 20 high
40 x 40
RAVENSWOOD POWER PLANT
0-32.
-------
s
EAST RIVER S
1
o
1
o
>-
CL
FLY ASH/7\O
SILOS yW
FUTURE
VERNON SUBSTATION
I— > DOCK COAL CONVEYORS U
TRANSFER STATIONARY ST
TOWER COAL TOWER
RAVENSWOOD POWER PLANT
BOILER BOILER BOILER
NO. 10 NO. 20 NO. 30
STACK STACK
QNO. 1 ONO. 2 STACK
©,<=•.,<=»,,«=>, f^NO 3
O' O O \^/
0^*. *•*. ^a.
^^ I ESP II ESP I
G WHARF______^ BULKHEAD LINE
loCTflrii' .— —
' L_j-^ TURBINE HOUSE
BU1LLK
HOUSE A x^=^
?,nnn,nnn GAI f^i
OIL TANK \J ^ OIL
LIMESTONE STORAGE UTANK '
® OOOLlJ UNIT 2 UNIT 3
C
©/~*\
(^} GAS TURBINES
UJ
CD
cn
5
m
o
2
VERNON BOULEVARD
O
w
u>
A SCRUBBERS
B SLURRY TANK
C LIMESTONE SILOS
D BALL MILL BUILDING
E CLARIFIER
F VACUUM FILTER BUILDING
Figure O-2. Site plan showing possible locations of major components for
the limestone system for Boiler 30 at the Ravenswood power plant.
-------
APPENDIX P
RIDGELAND POWER PLANT
RIDGELAND POWER PLANT P-l
-------
CONTENTS
Ridgeland Power Plant Survey Form
Ridgeland Power Plant Photographs
Page
P-4
P-21
Number
P-l
P-2
P-3
FIGURES
Site Plan Showing Possible Location of Major
Components for the Sodium Solution Regenerable
System for Boilers 1,2,3,4,5, and 6 at the
Ridgeland Power Plant
Site Plan Showing Possible Location of Major
Components for the Limestone System for Boilers
1,2,3,4,5, and 6 at the Ridgeland Power Plant
Site Plan Showing Possible Locations of New
ESP's for Boilers 1,2,3,4,5 and 6 at the
Ridgeland Power Plant
Paqe
P-31
P-37
P-41
Number
P-l
P-2
P-3
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boilers 1 through 6
at the Ridgeland Power Plant (1978)
Page
P-26
Estimated Annual Operating Costs of a Sodium
Solution Regenerable System for Boilers 1 through
6 at the Ridgeland Power Plant (1978) P-28
Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boilers
1,2,3,4,5, and 6 at the Ridgeland Power Plant P-29
RIDGELAND POWER PLANT
P-2
-------
TABLES (continued)
Number Page
P-4 Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boilers
1,2,3,4,5, and 6 at the Ridgeland Power Plant P-30
P-5 Estimated Capital Cost of a Limestone Scrubbing
System for Boilers 1 through 6 at the Ridgeland
Power Plant (1978) P-32
P-6 Estimated Annual Operating Costs of a Limestone
Scrubbing System for Boilers 1 through 6 at the
Ridgeland Power Plant (1978) P-34
P-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boilers
1,2,3,4,5, and 6 at the Ridgeland Power Plant P-35
P-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boiler 1,2,3,4,5,
and 6 at the Ridgeland Power Plant P-36
P-9 Estimated Capital Cost of Electrostatic
Precipitators for Boilers 1 through 6 at the
Ridgeland Power Plant (1978) P-38
P-10 Estimated Annual Operating Costs of Electro-
static Precipitator for Boilers 1 through 6
at the Ridgeland Power Plant (1978) P-39
P-ll Electrostatic Precipitator Design Values for
Boilers 1,2,3,4,5, and 6 at the Ridgeland
Power Plant P-40
RIDGELAND POWER PLANT P-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION:
1. COMPANY NAME: Commonwealth Edison
2. MAIN OFFICE: P.O. Box 767
3. RESPONSIBLE OFFICER: J- P. McCluskey
4. POSITION: Director of Environmental Affairs
5. PLANT NAME: Ridgeland Station
6. PLANT LOCATION: 4300 South Ridgeland Avenue
7. RESPONSIBLE OFFICER AT PLANT LOCATION: T. F. McKeon
8. POSITION: Station Superintendent
9. POWER POOL MAIN
DATE INFORMATION GATHERED: July 27, 1976
PARTICIPANTS IN MEETING:
J. P. McClusky
W. L. Ramsey
Mike Trykoski
Walter N. Kozlowski
Lee Hermansen
Ron Cook
A. 0. Courtney
Eugene H. Reinstein
Thomas C. Ponder, Jr.
N. David Noe
Richard T. Price
Commonwealth Edison Company
Commonwealth Edison Company
Commonwealth Edison Company
Commonwealth Edison Company
Commonwealth Edison Company
Commonwealth Edison Company
Commonwealth Edison Company
Ishan, Lincoln, and Beale
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
RIDGELAND POWER PLANT
P- 4
-------
B.
£
z
D
13
O
13
£
z
•-3
13
I
en
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (1975)
2 . APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO..
LB/MM BTU
OPACITY, PERCENT
b) FUTURE REQUIREMENT (DATE: )
REGULATION S, SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3 (Oil)
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU (liquid fuel)
LB/MM BTU (solid fuel)
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
.06
-
2
.06
—
Cook Count
Cook Counl
In
-1.8
3
.06
_
y Ordinanc
-0.1 Ib/Ml
-30% (6.1-
n Q r\
— A RQ f>— —
— 1 ? 7c;n-
J-^/JDU —
y Ordinanc
_ XT A _ _
Jl
.06
_
:e 6.2-2(b)
1 (t>) )
:e 6.31(d)
t;
.06
_
2\ i •; ^ ___ .
) ( i j
a) Identify whether results are from stack tests or estimates
-------
B.
M
D
n
w
o
=3
I
CTi
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO..
LB/MM BTU
OPACITY, PERCENT
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO- EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE S0_ EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
6
.06
-
__
nt
wl-
.ul
ire
om
icfc
st:
• e
aa1
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT)
3. SOIL DATA: BEARING VALUE
PILING NECESSARY yes
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR 128.0 ft.*
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE) ; N/A
* Height of stack: 213 ft.
RIDGELAND POWER PLANT p_7
-------
D
O
W
f
I
O
1
I
oo
D.
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (19 75)
3. AVERAGE CAPACITY FACTOR (1975 )
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER a
6. YEAR BOILER PLACED IN SERVICE
7 . REMAINING LIFE OF UNIT b
8. GENERATING CAPACITY (MW)
-RATED Summer Gross
Summer Net
PEAK
9. FUEL CONSUMPTION :CGas 1Q3 ft3/hr
COAL OR OIL RATED g°f (^f
MAXIMUM CONTINUOUS
PEAK
10. ACTUAL: FUEL CONSUMPTION
Gas (10* fWyr) (1975) -
COAL (TPY) (19 79
OIL (eW) (19 73
11. HEAT RATE BTU/KWHR GAS
COALd
OIL
12. WET OR DRY BOTTOM
13. FLY ASH REINJECTION (YES OR NO)
14. STACK HGT ABOVE GRADE (FT.)
15. I.D. OF STACK AT TOP (INCHES)
Boiler number
1
6302
52.7
1
B&W
1951
N/A
Unit 1
166
152
821.1
42.7
136.3
B?Wgr
None
1219.3
10.861
11,376 E
- Wet
No
213
96
2
Flc
5129
47.8
2
B&W
1951
N/A
—
—
821,1
42.7
136.3
1 and 2
11,216
TU/NKWH -
Wet
No
213
96
1
atinq
7134
56.1
3
B&W
1950
N/A
Unit 2
166
152
821 1
42.7
136.3
Boiler
20.3
None
1488.6
9,859
Station Tc
Wet
No
213
96
4
6666
51.8
4
B&W
1950
N/A
^_
—
R71 1
42,7
136.3
3 and 4
9.737
tal
Wet
No
213
96
q
3925
31 .2
5
B&W
1 95T
N/A
Unit 3
151
137
1423
74
.236.2
548.8
None
599.2
Wet -
No
213
118
Notes:
The Babcock & Wilcox Company
Plant - 1986.
L^.0^ it. va
data at
ra<_j.ng
Station avg. - 10,623 BTUAWn(net) on
Lno Coa
-------
D.
50"
M
a
o
w
z
D
o
s
ra
JO
£
25
I
vo
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (19 75)
3. AVERAGE CAPACITY FACTOR (1975)
4 . SERVED BY STACK NO .
5. BOILER MANUFACTURER **
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT b
8. GENERATING CAPACITY (MW)
)
PEAK
9. FUEL CONSUMPTION:0
COAL OR OIL RATED £°f (
-------
D
O
W
O
s;
w
£
z
16. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
17. EXCESS AIR: DESIGN /ACTUAL (%)
Boiler number
1
None
(1)
Res. Cott
(2) E
98%
4
25,200
?«S
18
•)
None
(1)
Res. Cott
(2)E
98%
4
25,200
385
18
T
None
(1)
Res. Cott
(2)E
98%
4
25,200
385
18
A
None
(1)
Res. Cott
(2) E
98%
4
25,200
385
18
5
Nonp
(1)
Res. Cott
(2) E
90%
4
60,500
334
10
13
I
Notes
(1) Res. Cott - Research Cottrell, Inc.
(2) E - Electrostatic Precipitator
-------
z
D
o
s;
w
1.6. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
17- EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
6
None
(1)
Res . Cott
(2) E !
90%
8
600,500
334
10
Notes:
(1) Res. Cott - Research Cottrell
(2) E - Electrostatic Precipitator
-------
D
O
W
f
>
z
a
13
o
s
w
£
z
18. FLUE GAS RATE (ACFM)
@ 100% LOAD (Design)
6 75% LOAD
@ 50% LOAD
19. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD (High)
@ 75% LOAD
@ 50% LOAD
20. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
21. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD b YEAR)
DISPOSAL COST ($/TON)
23. EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO STACK
25. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
1
384,000
288,000
192,000
335 <2)
310 ">
285 (2)
(2)
127.4
95.6(2)
63.7(2)
None
(See at-
2
384,000
288,000
192,000
335 (2)
310 (2)
285 (2)
(2)
127.4
95.6(2)
63.7(2)
ached drav
3
384,000
288,000
192,000
335(2>
3!0(2'
285(2)
(2)
127.4
95.6(2)
63.7(2)
500 tons
$66,000 tc
ings)
4
384,000
288,000
192,000
335{2)
310(2)
285(2)
(2)
127.4
95.6(2)
63.7(2)
tal
5
546,000
409,300
273,000
350 (2>
310 (2)
275 (2)
(2)
119.9
89. 9m
60.0 (2)
a) Identify source of values (test or Estimate)
Notes: bwaste Water Treatment.
-------
D
n
w
z
D
O
5
w
50
18. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
6 75% LOAD
@ 50% LOAD
20. EXIT GAS STACK VELOCITY (FPS)a
e 100% LOAD
@ 75% LOAD
@ 50% LOAD
21. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
23- EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO STACK
25. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
6
54 fi, nno
409.500
273.000
(2) 350
310 (2)
275 (2)
119.9(2)
39.9m
60.0 (2)
None
(See attac
hed drawir
gs)
I
t->
U)
a) Identify source of values (test or estimate)
Notes:
-------
o
en
n
|
a
o
w
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
1
(1)16
14.5
Bo
2
(1)16
14.5
iler numbe
1
(1)16
14.5
r
4
(1)16
14.5
*
(2)18.4
12.9
Notes:
' Based on 700,000 Ib/hr . steam
(2)
Based on 1,100,000 Ib/hr. steam
i
M
*».
-------
K
f
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
6
(2)
18.4
12.9
o
s
w
Notes:
13
£
Z
-------
FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) None
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
H.
I.
J.
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
Coal Analysis (1955):
Ash - 10.8% by wt (as received); 12.2% (dry)
Moisture - 14.0% by wt
Sulfur - 4.4% by wt (as received)
BTU/lb - 10,500 as received); 12,400 (dry); 14,000
(moisture and ash free)
(1) per our latest survey of January 1976... The disposal
area is 56.6% filled. Assuming present fuel, 86 years
storage remain.
(2) Distance from Stack #1: 500 ft.
Distance from Stack #6: 950 ft.
FUEL OIL DATA (19 73
1.
2.
3.
4.
5.
TYPE Residual
S CONTENT (%)
ASH CONTENT (%)
0.8
0.1
SPECIFIC GRAVITY N/A
HHV (BTU/GAL)
147,886
NATURAL GAS HHV (BTU/FT3) 1034
COST DATA
ELECTRICITY
FUEL : COAL
GAS
OIL
WATER
STEAM
TAXES ON A.
STATE
P.C. EQUIPMENT:
PROPERTY TAX
STATE SALES
Not Exempt.
Yes , Exempt
RIDGELAND POWER PLANT
P-16
-------
K. PLANT SUBSTATION CAPACITY
M.
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION? Will have to add additional
buses.
VOLTAGE AT WHICH POWER IS AVAILABLE?
ADDITIONAL INFORMATION
F.E.A. LETTER
OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
2.
Boiler No.
Yes or No.
1,2,3,4,5
Yes
,6,
SYSTEM AVAILABILITY
2.1 COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
D
Yes Q
m
D
0
a
El
No D
D
E
D
D
n
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
2.2 FUEL FIRING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
2.3 GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
Not Adequate For Coal Firing Under Current
Environmental Standards
RIDGELAND POWER PLANT
Yes0
D
Yes£]
a
n
S
NoD
NoD
No D
D
a
D
NOD
D
YesH
n
S
H
D
No D
a
n
n
a
P-17
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes 0 No Q
b. Will it operate? D S
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes 0 NoQ
Ash Pond 0 D
RIDGELAND POWER PLANT P-18
-------
N- SUPPLEMENTARY CONTROL SYSTEM DATA
1 . DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? Yes Q No [x]
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS? Yes Q No
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage? Yes No
2.3 Handling facilities available for low
sulfur fuels Yes No
If yes , describe
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
3. IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss
i Yes D No [xl
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss
Yes 0 No [J
5. POWER PLANT MONITORING SYSTEM
5.1 Existing system Yes Q No
a. Air quality instrumentation Number Type
(1) Sulfur Oxides - Continuous
- Intermittent
- Static
(2) Suspended particulates
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
c. Is the monitoring data available? Yes [~~j No |~)
d. Is the monitoring data reduced and
analyzed? Yes Q] No
. e. Provide map of monitoring locations
RIDGELAND POWER PLANT - • P-19
-------
5.2 Proposed system Yes F] No
If yes, describe and provide map
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
RIDGELAND POWER PLANT P-20
-------
\
\
Photo No. 1 View from ground level facing southwest.
The northern portion of the plant is shown. Two of the
69 kV transformers are in clear view in the center of the
photograph.
Photo No. 2 View from the roof of Boiler 1 looking east.
The top left of the photo shows the industrialized surround-
ing area, the center shows an ash pond, and the bottom of the
photo shows rail lines.
RIDGELAND POWER PLANT
P-21
-------
'. -v.
Photo No. 3 View from the boiler house roof facing north.
The gate house and road leading into the plant are shown in
the bottom left portion of the photo.
Photo No. 4 View from the roof of Boiler 6 looking west. A
portion of the plant's oil storage tank area is shown. The
densely wooded surrounding area is shown in the background.
RIDGELAND POWER PLANT
P-22
-------
_
Photo No. 5 View from the roof of Boiler 6 facing southwest.
Part of the coal storage area is shown in the bottom left
portion of the photograph. A rail spur line is shown leading
toward the plant.
.
>tacks
,6 View from the roof of Boiler 6 looking southeast
through 6 are shown from left to right.
RIDGELAND POWER PLANT
P-23
-------
Photo No. 7 View from the roof of Boiler 5 facing southeast.
The coal junction house is shown in the center of the photo.
The gantry crane is shown in the upper left hand corner. The
coal car dumper is shown in the right center of the photograph.
Photo No. 8 View from ground level near the Boiler 1 area
looking northwest. Some of the plant's 4 kV transformers are
shown in the right center of the photograph.
RIDGELAND POWER PLANT
P-24
-------
Photo No. 9 View from ground level facing east. Slag
tanks for Boilers 5 and 6 are shown in the foreground.
The coal junction house (upper right corner) is partially
blocking the breaker house shown in the upper center of the
photo.
Photo No. 10 View from the boiler house roof looking north.
The warehouse is shown in the bottom center of the photo. A
portion of the wooded residential area is shown across the
photograph, just below center.
RIDGELAND POWER PLANT
P-25
-------
TABLE P-l. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 1 THROUGH 6
AT THE RIDGELAND POWER PLANT (1978)
Direct Costs
A.
B.
Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
SO0 Scrubbing
$ 191,000
6,000
57,000
26,000
2,000
Total A = $ 272,000
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
C. Purge Treatment
Refrigeration unit
Heat exchangers
Tanks
Dryer
Elevator
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
Total B =
Total C =
$ 17,718,000
1,960,000
518,000
3^096,000
1,956,000
7,211,000
824,000
$ 33,283,000
$ 504,000.
76,000
104,000
48,000
15,000
827,000
1,008,000
1,210,000
191,000
6,000
$ 3,989,000
(continued)
RIDGELAND POWER PLANT
P-26
-------
TABLE P-l (continued)
D. Regeneration
Pumps and motors $ 603,000
Evaporators and reboilers 12,525,000
Heat exchangers 1,652,000
Tanks 138,000
Stripper 235,000
Blower 537,000
Total D = $ 15,690,000
Particulate Removal
Venturi scrubber $ 7,779,000
Tanks 212,000
Pumps and motors 571,000
Total E = $ 8,562,000
Total direct costs = A + B + C + D + E = F = $ 61,796,000
Indirect Costs
Interest during construction $ 6,180,000
Field labor and expenses 6,180,000
Contractor's fee and expenses 3,090,000
Engineering 6,180,000
Freight 772,000
Offsite 1,854,000
Taxes 000
Spares 309,000
Allowance for shakedown 3,090,000
Acid plant 3,659,000
Total indirect costs G = $ 31,314,000
Contingency H = 18,622,000
Total = F + G + H = $111,732,000
Coal conversion costs 17,795,000
Grand total $129,527,000
$AW 215.52
RIDGELAND POWER PLANT P-27
-------
TABLE P-2. ESTIMATED ANNUAL OPERATING COSTS OF A SODIUM SOLUTION
REGENERABLE SYSTEM FOR BOILERS 1 THROUGH 6 AT THE
RIDGELAND POWER PLANT (1978)
Raw Materials
Soda ash
Utilities
Quantity
2.01 tons/h
Unit Cost
$77.02/ton
Annual
$
Cost
636,000
Process water 8375 gal/min $0.66/10 gal 1,358,000
Cooling water 35.5 x 103 gal/min $0.01/103 gal 89,000
Electricity 19,004 kW 33.1 mills/kWh 2,568,000
Reheat steam 117.6 x 106 Btu/h $1.685/106 Btu 810,000
Process steam 560.6 x 106 Btu/h $1.685/106 Btu 3,861,000
Operation Labor
Direct labor 3 men/day $9.55/man-hour 250,000
Supervision 15% of direct labor 38,000
Maintenance
Labor and materials 4% of fixed investment 4,469,000
Supplies 15% of labor and materials 670,000
Overhead
Plant 50% of operating and maintenance 2,714,000
Payroll 20% of operating labor 58,000
Fixed Costs
Depreciation (7.69%)
Interim replacement (0.35%)
Insurance (0.30%)
Taxes (4.00%), E = 23.54% of fixed
investment
Capital cost (11.20%)
Total fixed costs 26,302,000
Total cost $ 43,823,000
Credits (byproducts)
Sulfuric acid 27.9 tons/h $51.90/ton (5,916,000)
Na2S04 2.01 tons/h $42.65/ton (352,000)
Total byproduct credits $ (6,268,000)
Fuel credit (18,516,000)
Net annual cost $ 19,039,000
Mills/kWh 7.73
RIDGELAND POWER PLANT p~28
-------
Table P-3. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS
1, 2, 3, 4, 5, AND 6 AT THE RIDGELAND POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorber
Flue gas fans
Na-CO., storage
Na2C03 preparation
SO- regeneration
Purge treatment
Sulfuric acid plant
4
1
1
6
1
1
1
1
1
80 MW unit
139 MW unit
144 MW unit
Scaled to train size
1450 tons (30-day storage)
4020 Ib/hr, Na2C03
36,500 Ib/hr, S02
4020 Ib/hr, Na2S04
305 ton/day, HS0
RIDGELAND POWER PLANT
P-29
-------
Table P-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS
1, 2, 3, 4, 5, AND 6 AT THE RIDGELAND POWER PLANT
Item
Number
Required
Dimensions, ft
Na^CO, storage
Absorber feed surge
tank
Turbulent contact
absorbers
Regeneration plant
Purge treatment plant
Acid plant
4
2
1
1
1
30 diam x 60 high
44 diam x 55 high
45 high x 15 wide x 37 long
45 high x 15 wide x 56 long
100 x 250
90 x 220
105 x 220
RIDGELAND POWER PLANT
P-30
-------
M
§
ra
TJ
I-1
r
i
RIDGELAND fRJ~!«
POWER PLANT \ '
L
A PURGE TREATMENT AND
S02 REGENERATION
B ACID
C SCRUBBERS
D STORAGE SILO
E SOLUTION TANK
Figure P-l. Site plan showing possible location of major components for the
sodium solution regenerable systen for Boilers 1,2,3,4,5, and 6 at the
Ridgeland power plant.
-------
TABLE P-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 1 THROUGH 6 AT THE
RIDGELAND POWER PLANT (1978)
Direct Cost
A. Limestone Preparation
Conveyors $ 586,000
Storage silo 175,000
Ball mills 971,000
Pumps and motors 379,000
Storage tanks 531'000
Total A = $ 2,642,000
B. Scrubbing
Absorbers $14,261,000
Fans and motors 2,176,000
Pumps and motors 1,148,000
Tanks 894,000
Reheaters 3,096,000
Soot blowers 978,000
Ducting and valves 8,035,000
Total B = $30,588,000
C. Sludge Disposal
Clarifiers $ 423,000
Vacuum filters 619,000
Tanks and mixers 14,000
Fixation chemical storage 58,000
Pumps and motors 137,000
Sludge pond 1,618,000
Mobile equipment 64,000
Total C = $ 2,933,000
(continued)
RIDGELAND POWER PLANT p~32
-------
TABLE P-5 (continued)
D. Particulate Removal
Venturi scrubber $ 7,778,000
Tanks 243,000
Pumps and motors 333,000
Total D = $ 8,354,000
Total direct costs = A + B + C + D = E = $ 44,517,000
Indirect Costs
Interest during construction $ 4,452,000
Field overhead 4,452,000
Contractor's fee and expenses 2,226,000
Engineering 4,452,000
Freight 556,000
Offsite 1,336,000
Taxes 000
Spares 223,000
Allowance for shakedown 2,226,000
Total indirect costs F = $ 19,923,000
Contingency G = 12,888,000
Total =E+F+G= $ 77,328,000
Coal conversion costs 17,795,000
Grand total $ 95,123,000
$/kW 158.27
RIDGELAND POWER PLANT P-33
-------
TABLE P-6. ESTIMATED ANNUAL OPERATING COSTS OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 1 THROUGH 6 AT THE RIDGELAND
POWER PLANT (1978)
Raw Materials
Limestone
Fixation chemicals
Quantity
38.9 tons/h
100 tons/h
Unit Cost
$13.06/ton
$2.20/ton
Annual Cost
$
2,079,000
903,000
Utilities
Water 250 gal/min $0.66/103 gal 41,000
Electricity 14,205 kW 33 mills/kWh 1,920,000
Fuel for reheat 117.6 x 106 Btu/h $1.685/106 Btu 810,000
Operating Labor
Direct labor 3 men/day $9.55/man-hour 251,000
Supervision 15% of direct labor 38,000
Maintenance
Labor and materials 4% of fixed investment 3,093,000
Supplies 15% of labor and material 464,000
Overhead
Plant 50% of operation and maintenance 1,923,000
Payroll 20% of operating labor 58,000
Trucking
Bottom/fly ash and 6,766,000
sludge removal
Fixed Costs
Depreciation (7.69%)
Interim replacement (0.35%), Z = 23.54% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital costs (11.20%)
Total fixed costs 18,203,000
Total costs $ 36,549,000
Fuel credit (18,516,000)
Net annual cost $ 18,033,000
Mills/kWh 7.32
RIDGELAND POWER PLANT P-34
-------
Table P-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED FOR
THE LIMESTONE SCRUBBING SYSTEM FOR BOILERS
1, 2, 3, 4, 5, AND 6 AT THE RIDGELAND POWER PLANT
Module Description
Number
Required
Size/Capacity
Limestone storage
Limestone slurry
Turbulent contact
absorbers
1
1
4
1
1
28,000 tons (30-day storage)
38.9 ton/hr limestone
80 MW unit
139 MW unit
144 MW unit
RIDGELAND POWER PLANT
P-35
-------
Table P-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
LIMESTONE SCRUBBING SYSTEM FOR BOILER 1, 2, 3, 4, 5, AND 6
AT THE RIDGELAND POWER PLANT
Item
Number
Required
Dimensions, ft
Limestone storage pile
Limestone silos
Limestone slurry tanks
Ball mill building
Turbulent contact
absorbers
Clarifiers
Vacuum filter building
1
3
1
1
4
2
2
1
115 wide x 325 long
23 diam x 50 high
95 diam x 20 high
40 x 40
45 high x 15 wide x 30 long
45 high x 15 wide x 45 long
165 diam x 20 high
40 x 40
RIDGELAND POWER PLANT
P-36
-------
I
U>
r
A
B
C
D
E
F
SCRUBBERS
SLURRY TANK
LIMESTONE SILOS
BALL MILL BUILDING
CLARIFIER
VACUUM FILTER BUILDING
\
Figure P-2. Site plan showing possible location of major components for the
limestone system for Boilers 1,2,3,4,5, and 6 at the Ridgeland power plant.
-------
TABLE P-9. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1 THROUGH 6 AT THE
RIDGELAND POWER PLANT (1978)
Direct Costs
ESP $ 10,518,000
Ash handling 1,701,000
Ducting 1,660,000
Total direct costs $ 13,879,000
Indirect Costs
Interest during construction 8% of direct costs $ 1,110,000
Contractor's fee 10% of direct costs 1,388,000
Engineering 6% of direct costs 833,000
Freight 1.25% of direct costs 173,000
Offsite 3% of direct costs 416,000
Taxes 0% of direct costs 000
Spares 1% of direct costs 139,000
Allowance for shakedown 3% of direct costs 416,000
Total indirect costs $ 4,475,000
Contingency 3,671,000
Total $ 22,025,000
Coal conversion costs 17,795,000
Grand total $ 39,820,000
$/kW 66.26
RIDGELAND POWER PLANT P-38
-------
TABLE P-10. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSTATIC
PRECIPITATOR FOR BOILERS 1 THROUGH 6 AT THE
RIDGELAND POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Costs
Electricity 2016 kW 33.1 mills/kWh $ 274,000
Water 1705 x 10"3 gal/yr $0.01/103 gal 1,000
Operating Labor
Direct labor 0.5 man/shift $9.55/man-hour 250,000
Supervision 15% of direct labor 38,000
Maintenance
Labor and materials 2% of fixed investment 441,000
Supplies 15% of labor and materials 66,000
Overhead
Plant 50% of operating and maintenance 398,000
Payroll 20% of operating labor 58,000
Trucking
Bottom/fly ash 1,774,000
removal
Fixed costs
Depreciation (7.69%)
Interim replacement (0.35%), Z = 23.54% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed cost 5,185,000
Total cost $ 8,485,000
Fuel credit (32,240,000)
Net annual credit $(23,755,000)
Mills/kWh (9.64)
RIDGELAND POWER PLANT P-39
-------
H
D
Q
M
2
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f
Table P-ll. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILERS 1,2,3,4,5, AND 6 AT THE RIDGELAND POWER PLANT
Design Parameter
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth) , ft
excluding hopper dimensions
Value
1
86.4
256
98,220
4
18x89x24
2
86.4
256
98,220
4
18x89x24
3
86.4
256
98,220
4
18x89x24
4
86.4
256
98,220
4
18x89x24
5
86.4
256
139,660
4
18x126x24
6
86.4
256
139, 660
4
18x126x24
I
£>
O
-------
r
\
Figure P-3. Site plan showing possible locations of new ESP's for
Boilers 1, 2, 3, 4, 5, and 6 at the Ridgeland power plant.
-------
APPENDIX Q
RIVERTON POWER PLANT
RIVERTON POWER PLANT Q-l
-------
CONTENTS
Riverton Power Plant Survey Form
Riverton Power Plant Photographs
Page
Q-3
Q-15
Number
Q-l
FIGURES
Site Plan Showing Possible Location of a New
ESP for Boiler 1 at the Riverton Power Plant
Page
Q-23
Number
Q-l
Q-2
Q-3
TABLES
Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 1 at the Riverton
Power Plant (1978)
Estimated Annual Operating Costs of an Electro-
static Precipitator for Boiler 1 at the
Riverton Power Plant (1978)
Electrostatic Precipitator Design Values for
Boiler 1 at the Riverton Power Plant
Page
Q-20
Q-21
Q-22
RIVERTON POWER PLANT
Q-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION:
Potomac Edison Company
1. COMPANY NAME: Allegheny Power Sejvi^e Corp.
2. MAIN OFFICE: 800 Cabin Hill Drive Greensburg, PA 15601
3. RESPONSIBLE OFFICER: C. G. McVay
4. POSITION: V.P. System Power Supply
5. PLANT NAME: River ton
6. PLANT LOCATION: Front Royal, P.O. Box 243, Warren County, Virginia
7. RESPONSIBLE OFFICER AT PLANT LOCATION: John Coulter 2263°
8. POSITION: Plant Superintendent
9. POWER POOL - ECAR
DATE INFORMATION GATHERED: April 22,1976
PARTICIPANTS IN MEETING:
Robert L. Ballentine - Allegheny Power Service Corporation
John W. Coulter - Station Superintendent
Bernie Turlinski - U.S. Environmental Protection Agency
D. J. Gaston - Virginia Air Pollution Control "Board
Wayne E. Peters - Federal Energy Administration
N. David Noe - PEDCo Environmental, Inc.
David M. Augenstein - PEDCo Environmental, Inc.
RIVERTON POWER PLANT Q-3
-------
B.
H
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O
* "- ' .
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 uncontrolled
LB/MM BTU Full load
GRAIK'S/ACF
LB/HR (FULL LOAD)
TONS/YEAR ( )
2. APPLICABLE • PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION 5, SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO2 EMISSIONS3
LB/MM BTU
LB/HR (FULL' LOAD)
TONS/YEAR ( )
4. APPLICABLE SO EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
Ib/hr (s = ?-64lO
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler numoer
1
G.06 (oi
NA
38 (oil
3.15 (c)
1
Part IV
0.1899
Same
0.253 (c
158 (c)
13 (c]
Part IV I
2. 64
1) 0.19 (c
)
ruld •. ^.x -
,
sal)
3 4 .30
il) 2.64 (coal)
ule Ex ~-
1782 Ib/hr
Same
4 .5]
(a) 11
?
i
'(a) 1
*re .
s or- e
-------
SITE DATA
1. U.T.M. COORDINATES Lat. 38° 57' 50" ; Long. 78° 10' 40"
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) APP 530
3. SOIL DATA: BEARING VALUE
PILING NECESSARY
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR) REVD
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL.STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE): ApRA
RIVERTON POWER PLANT Q-5
-------
w
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O
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s
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BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (19 75)
3. AVERAGE CAPACITY FACTOR (19 75)
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTION :
. OIL RATED
(GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (19 75)
OIL (GPY) (19 75)
11. WET OR DRY BOTTOM
12. FLY ASH REINJECTION (YES OR NO)
13. STACK HGT ABOVE GRADE (FT.)
14. l.D. OF STACK AT TOP (INCHES)
Boiler number
1
Peak
504
2. 2%
1
Riley
1949
40
40
114 Bar/
0
787,576
Dry
No
130
108
Hr .
Notes:
-------
o
2
o
w
I
•-3
15.
O
I
Notes:
FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(S/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT2")
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
16- EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
UOP
MCAX
85/79
38 (oi]
None
20
-------
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M
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17. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD 1973
DISPOSAL COST ($/TOH)
21. BOTTOM ASH: TOTAL COLLECTED (TONS/
1973 VFAR 1
DISPOSAL METHOD I£-rtK'
DISPOSAL COST ($/5'OW-)
22. EXHAUST DUCT DIMENSIONS @ STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
One week
Boiler number
1
212,000
180,000
120,000
360
340
300
S6
46
36
2,204
Land fill
$ 400.
1 ,Ub /
Land fil!
$1,400
4/18/77
5/8/78
,
Q
I
oo
a) Identify source of values (test or estimate)
Notes:
-------
w
»
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5
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E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C.)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler number
Notes:
O
I
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F. FLY ASH DISPOSAL AREAS Deteriorated 15 acre pond
1. AREAS AVAILABLE (ACRES) 2Q-3Q Acres
2. YEARS STORAGE (ASH ONLY) pOnd not in use
3. DISTANCE FROM STACK (FT.) 800
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT Po"d n°t in
G. COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
c .
d.
2. QUANTITY USED BY SEAM AND/OR MINE.
a.
b.
c .
d.
3. ANALYSIS
GHV (BTU/LB) U.62A
3.2
ASH (%) 21.4
MOISTURE (%) 2.6
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE No. 2
2. S CONTENT (%) u-20
3. ASH CONTENT (%) Q.QQ5
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL) 138.695
COST DATA
ELECTRICITY X
WATER N/A
STEAM N/A
J. PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED Transformer required?
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE? U^)-KW breaker
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE? 230 V A40V
RIVERTON POWER PLANT Q~10
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
1
Yes
*
2. SYSTEM AVAILABILITY
2.1
2.2
2.3
YesS
m
COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which do not
need to be replaced: Maintenance
Unloading equipment parts Yes 53
Stack Reclaimer belts D
Bunkers 9 month - lead time H
Conveyors
Scales
Coal Storage Area Maintenance H
FUEL FIRING Need a Bulldozer
a. Is the system still installed? YesQ
b. Will it operate? D x
c. Of the following items which do not
H
No D
D
No D
0
a
B
D
a
No
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
Yes
Rebuilding
NoD
par tially
0
NoQ
D
D
D
GAS CLEANING
a. Is the system still installed? Yes£] No Q
b. Will it operate? D D
c. Of the following items which do not
need to be replaced:
Electrostatic Precipitator N/A YesD No D
Cyclones H D
Fly Ash Handling Equipment S D
Soot Blowers - Air Compressors E D
Wall deslaggers £3 D
RIVERTON POWER PLANT
Q-ll
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes (*] No Q
b. Will it operate? & Q
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes D NoQ
Ash Pond Maintenance Q Q
RIVERTON POWER PLANT Q-12
-------
L. SyPPLff-lENTMY CONTROL SYSTEM DATA
1 . DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)?
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS? '
2.1 Storage capacity for low sulfur fuels
(tons , bbls , days)
2.2 Bunkers available for low sulfur coal
storage?
2.3 Handling facilities available for low
sulfur fuels '
If yes, describe _ -
3.
5.
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss
POWER PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(1) Sulfur Oxides - Continuous
- Intcrmittent
- Static
(2) Suspended participates
- Intermittent
- Static
(3) Other (describe)
Meteorological instrumentation
If yes, describe
c. Is the monitor ing data available?
cl. Is the monitoring data reduced and
analyzed?
Yes
Fl
1 '
Yes x No
Yes [~K| No
Yes [~X] No | ]
YCS rj NO rj
Yes [j No rj
Yes [~] No [ |
Number Type
Yes | j No | |
Yes HJ No [H
RIVERTON POWER PLANT
Q-13
-------
5.2 Proposed system Yes Q No
If yes, describe
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
RIVERTON POWER PLANT
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
Q-14
-------
-
Photo No. 1. View from the boiler roof facing southeast
showing the Shenandoah River and Blue Ridge Mountains.
Photo No. 2. View from ground level facing east
showing boiler stack and the west end of the plant.
RIVERTON POWER PLANT
Q-15
-------
Photo No. 3. View from ground level facing southeast
showing a portion of the oil storage facilities, boiler duct
tie-in to the stack, and the coal conveyor.
Photo No. 4. View from the roof facing southwest showing
the Shenandoah River and surrounding terrain including the
golf course which adjoins the plant.
RIVERTON POWER PLANT
Q-16
-------
Photo No. 5. View from the roof facing northwest showing
the surrounding terrain.
Photo No. 6. View from the roof facing north showing the
coal storage area transfer station, and a portion of the
electrical switchyard.
RIVERTON POWER PLANT
Q-17
-------
Photo No. 7. View from ground level facing north showing
coal transfer house and conveyors. The coal storage area is
in the background.
Photo No. 8. View from ground level facing northwest
showing coal handling facilities located at the north end of
the plant.
RIVERTON POWER PLANT
Q-18
-------
Photo No. 9. View from ground level facing southwest
showing inactive ash settling basin located approximately
500 feet west of the plant. Plans are being initiated to
pipe the plant effluent to this retired ash settling basin,
Photo No. 10. View from rooftop facing northeast showing
electrical substation serving the plant.
RIVERTON POWER PLANT
Q-19
-------
TABLE Q-l. ESTIMATED CAPITAL COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 1 AT THE RIVERTON POWER PLANT (1978)
Direct Costs
ESP
Ash handling
Ducting
Total direct costs
Indirect Costs
Interest during construction 8% of direct costs
Contractor's fee 10% of direct costs
Engineering 6% of direct costs
Freight 1.25% of direct costs
Offsite 3% of direct costs
Taxes 0% of direct costs
Spares 1% of direct costs
Allowance for shakedown 3% of direct costs
Total indirect costs
Contingency
Total
Coal conversion costs
Grand total
SAW
$ 1,514,000
220,000
87,000
$ 1,821,000
$ 146,000
182,000
109,000
23,000
55,000
000
18,000
55,000
$ 588,000
482,000
$ 2,891,000
2,269,000
$ 5,160,000
129.00
RIVERTON POWER PLANT
Q-20
-------
TABLE Q-2. ESTIMATED ANNUAL OPERATING COSTS OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 1 AT THE RIVERTON POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 260 kW 27.55 mills/kWh $ 11,000
Water 3003 103 gal/yr $0.33/103 gal 1,000
Operating Labor
Direct labor 1.5 men/shift $8.50/man-hour 37,000
Supervision 15% of direct labor 6,000
Maintenance
Labor and materials 2% of fixed investment 58,000
Supplies 15% of labor and materials 9,000
Overhead
Plant 50% of operation and maintenance 55,000
Payroll 20% of operating labor 9,000
Trucking
Bottom/fly ash
removal 000
Fixed Costs
Depreciation (7.69%)
Interim replacement (0.35%), E = 19.54% of fixed
investment
Insurance (0.30%)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost
Total cost
Fuel credit
Net annual cost
Mills/kWh
$
$
$
565,000
751,000
(142,000)
609,000
64.37
RIVERTON POWER PLANT Q-21
-------
Table Q-3. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 1 AT THE RIVERTON POWER PLANT
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
*2
Total collecting area, ftz
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.48
409
87,000
4
30 x 29 x 39
RIVERTON POWER PLANT
Q-22
-------
N
A. CRUSHER HOUSE
B. TRUCK HOPPER
COAL STORAGE
WASTEWATER
TREATMENT LAGOON
Figure Q-l. Site plan showing possible location of
a new ESP for Boiler 1 at the Riverton power plant.
RIVERTON POWER PLANT
Q-23
-------
APPENDIX R
VIENNA POWER PLANT
VIENNA POWER PLANT R-l
-------
CONTENTS
Vienna Power Plant Survey Form
Vienna Power Plant Photographs
Page
R-3
R-15
Number
R-l
FIGURES
Site Plan Showing Possible Location of a New
ESP for Boiler 7 at the Vienna Power Plant
Page
R-23
Number
R-l
R-2
R-3
TABLES
Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 7 at the Vienna Power
Plant (1978)
Estimated Annual Operating Costs of an Electro-
static Precipitator for Boiler 7 at the Vienna
Power Plant (1978)
Electrostatic Precipitator Design Values for
Boiler 7 at the Vienna Power Plant
Page
R-20
R-21
R-22
VIENNA POWER PLANT
R-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION;
1. COMPANY NAME: Delmarve Power & Light Co.
2. MAIN OFFICE: Wilmington, Delaware
3. RESPONSIBLE OFFICER: Hudson Hoen
4. POSITION: Director, Environmental Affairs
5. PLANT NAME: Vienna
6. PLANT LOCATION: Vienna, Maryland
7. RESPONSIBLE OFFICER AT PLANT LOCATION: David Windslow
8. POSITION: Superintendent
9. POWER POOL PJM
DATE INFORMATION GATHERED:
PARTICIPANTS IN MEETING:
Tom Evans - Delmarva Power & Light
Dick Parcels - Delmarva Power & Light
Bob Matthews - Delmarva Power & Light
D. Bruce McClenathan - Delmarva Power & Light
Clark I. Simms, Jr. - Delmarva Power & Light
Ralph Schumacher - Maryland Health Department
Bernie Turlinski - U.S. Environmental Protection Agency
N. David Noe - PEDCo Environmental, Inc.
Michael F. Szabo - PEDCo Environmental,. Inc.
David M. Augenstein - PEDCo Environmental, Inc.
VIENNA POWER PLANT R_3
-------
B.
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO..
LB/MM BTU
OPACITY, PERCENT
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO- EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE SO2 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
i-e/MH-BTO Coal
Residual Oil
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
5
7
«,
Area I\
Reg. 1(
0.35
1.0% Si
0.5% Si
6
I
.03.41.03.
0.30
ilfur
ilfur
7
17
B. (3).
0.35
fl
1140
Stack-Stac
0.30
k basis
ltd
re
>m
ck
;ts
e:
at
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 8' above mean low
3. SOIL DATA: BEARING VALUE
PILING NECESSARY Yes
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE):
VIENNA POWER PLANT R-5
-------
D.
M
w
2
Z
13
O
a
w
50
CTl
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (1975)
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT 28 yr. bookli
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTTON:
GO-A-fc OR OIL RATED
f'FRtr-e-R-firPH-)- MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (1971)
OIL (G23O- (1975) BBl/y
11. HEAT RATE BTU/KWHR GAS
COAL
OIL
12. WET OR DRY BOTTOM
13. FLY ASH REINJECTION (YES OR NO)
14. STACK HGT ABOVE GRADE (FT.)
15. I.D. OF STACK AT TOP (INCHES)
Boiler number
5
3,165
17.8
3&4
B&W
1947
fe
17
42
44,000
75,000
dry
No
133
6
6,447
37.4
4&5
B&W
1949
1
17
42
45,000
154,000
dry
No
133
7
2,490
15. 3
6
B&W
1951
3
40
104
97,000
1.38,000
dry
No
133
3
4,848
28.0
7
CE
1971
23
162
,_ 276
N.A.
736,000
dry
Yes
160
Notes:
-------
<
M
M
z
i
M
13
£
z
16. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FTZ)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
17. EXCESS AIR: DESIGN /ACTUAL (%)
Boiler number
5
BUEL
MCTA
85/60
6
UOP
MCAX
85/0
7
UOP
MCAX
85/0
8
UOP
MCTA
87.5/87.5
Notes
-------
tn
z
z
O
33
W
50
18. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
20. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
21. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
23. EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO STACK
25. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Stack number
3
52,000
40,700
28,000
350
325
300
27.5
20
14
76"
4
104,000
81,000
56,000
375
350
325
55
42
30
76"
5
52,000
40,700
28,000
350
325
300
27.5
20
14
76"
fi
242,000
185,900
127,000
380
360
340
95
65
44
88"
7
672,000
504,000
336,000
625
570
540
92
69
46
150"
oo
a) Identify source of values (test or estimate)
Notes:
Boiler 5
Boiler 6
Boiler 7
Boiler 8
Stacks 3&4
Stacks 4&5
Stack 6
Stack 7
-------
z
z
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
33
13
£
z
Notes:
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) 1QO
2. YEARS STORAGE (ASH ONLY) soon to be discontinued.
3. DISTANCE FROM STACK (FT.) 12 miles
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
G- COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a .
b.
c.
d.
3. ANALYSIS (19 )
HHV (BTU/LB)
S (%)
ASH (%)
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE. IN ATTACHMENT)
H . FUEL OIL DATA (197 5 )
1. TYPE #6 residual
2. S CONTENT (%) j_3
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY i
5. HHV (BTU/GAL) 145.628
I. NATURAL GAS HHV (BTU/FT3)
J. COST DATA
ELECTRICITY
FUEL: COAL GAS OIL
WATER
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES
FEDERAL PROPERTY TAX
VIENNA POWER PLANT R-10
-------
K.
PLANT SUBSTATION CAPACITY
M.
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
ADDITIONAL INFORMATION
F.E.A. LETTER
OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
5
Yes
6
Yes
7
Yes
8
No
Yes@
Q
YesB
H
H
H -
B
m D
No D
D
a
m
n
H
2. SYSTEM AVAILABILITY
2.1 COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer No rail service
Bunkers
Conveyors need extensive work
Scales corrosion
Coal Storage Area not enough room
2 .2 FUEL FIRING
a. Is the system still installed? YesD
b. Will it operate? D
c. Of the following items which
need to be replaced:
Pulverizers or Crushers Rebuilding g
Feed Ducts S
Fans modify S
Controls S
2.3 GAS CLEANING
a. Is the system still installed? Yes H 5
b. Will it operate? 13 5
c. Of the following items which
need to be replaced:
Electrostatic Precipitator YesD
Cyclones H
Fly Ash Handling Equipment D
Soot Blowers - Air Compressors Q
Wall deslaggers D
No D
a
NO a
a
NO a
a
D
a
No 0 6,7
06,7
NO a
a
a
a
a
VIENNA POWER PLANT
R-ll
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes B NoQ
b. Will it operate? B D
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes S NoD
Ash Pond H D
VIENNA POWER PLANT R~12
-------
N . SUPPLEMENTARY CONTROL SYSTEM DATA
1 . DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? Yes Q No
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS? Yes Q No [J
2.1 Storage capacity for Tow sulfur fuels
(tons , bbls , days)
2.2 Bunkers available for low sulfur coal
storage? Yes No
2.3 Handling facilities available for low
sulfur fuels Yes Q No
If yes, describe _
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
3. IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss _
Yes T No
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss __
__ Yes 0 No Q
5. POWER PLANT MONITORING SYSTEM
5.1 Existing system No S02 monitoring Yes [ [ No [ |
a. Air quality instrumenftfttiBnavailable Number Type
(1) Sulfur Oxides - Continuous __ _
- Intermittent __ _
- Static _
(2) Suspended participates
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
c. Is the monitoring data available? Yes Pj No
d. Is the monitoring data reduced and
analyzed? Yes Q] No
e. Provide map of monitoring locations
VIENNA POWER PLANT R-13
-------
b.2 Proposed system : Yes P] No
If yes, describe and provide map
- Intermittent
- Static
(2) Suspended particulato
- Intermittent
- Static •
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
VIENNA POWER PLANT R-14
-------
Photo No. 1. View from ground level at the entrance gate
facing east showing the entire plant. Boiler No. 8 is on
the left. The brick building houses Boilers 5, 6, and 7.
Photo No. 2. View from the roof of Boiler 8 facing south
showing Stacks 3, 4, 5, and 6. Nanticoke River and the
surrounding area are shown in background.
VIENNA POWER PLANT
R-15
-------
Photo No. 3. View from the roof of Boiler 8 facing north
showing plant surroundings and cooling tower which serves
Boiler 8.
Photo No. 4. View from the roof of Boiler 8 facing north
showing the coal storage area and coal handling facilities.
VIENNA POWER PLANT
R-16
-------
Photo No. 5. View from the roof of Boiler 8 facing south
showing electrical substation and the oil storage tanks.
Photo No. 6. View from the roof of Boiler 8 facing south-
west showing the electrical substation and the oil storage
facilities.
VIENNA POWER PLANT
R-17
-------
Photo No. 7. View from the roof of Boiler 8 facing east
across Nanticoke River. The existing ash disposal facil-
ities are located across the river.
Photo No. 8. View from the roof of Boiler 8 facing west
showing the plant surroundings. The equipment storage
buildings and areas are pictured in the foreground.
VIENNA POWER PLANT
R-18
-------
Photo No. 9. View from ground level facing south showing
the space between the boiler house and the Nanticoke River
Photo No. 10. View from ground level facing north showing
coal storage area, handling facilities, and the cooling
tower serving Boiler 8.
VIENNA POWER PLANT
R-19
-------
TABLE R-l. ESTIMATED CAPITAL COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 7 AT THE VIENNA POWER PLANT (1978)
Direct Costs
ESP $ 1,495,000
Ash handling 124,000
Ducting 347,000
Total direct costs $ 1,966,000
Indirect Costs
Interest during construction 8% of direct costs $ 157,000
Contractor's fee 10% of direct costs 197,000
Engineering 6% of direct costs 118,000
Freight 1.25% of direct costs 25,000
Offsite 3% of direct costs 59,000
Taxes 1.5% of direct costs 29,000
Spares 1% of direct costs 20,000
Allowance for shakedown 3% of direct costs 59,000
Total indirect costs $ 664,000
Contingency 526,000
Total $ 3,156,000
Coal conversion costs 446,000
Grand total $ 3,602,000
$/kW 90.05
VIENNA POWER PLANT R-2Q
-------
TABLE R-2. ESTIMATED ANNUAL OPERATING COSTS OF AN
ELECTROSTATIC PRECIPITATOR FOR BOILER 7 AT THE
VIENNA POWER PLANT (1978)
Utilities
Electricity
Water
Operating Labor
Direct labor
Supervision
Maintenance
Labor and materials
Supplies
Overhead
Quantity
146 kW
2660 103 gal/yr
Unit Cost
27.55 mills/kWh
$0.01/103 gal
0.5 man/shift $8.50/man-hour
15% of direct labor
2% of fixed investment
15% of direct labor
Annual Cost
$ 6,000
1,000
36,000
5,000
63,000
5,000
Plant
Payroll
Trucking
Bottom/fly ash
removal
50% of operation and maintenance
20% of operating labor
57,000
8,000
1,932,000
Fixed Costs
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed cost
Total cost
Fuel credit
Net annual cost
Mills/kWh
(7.69%)
(0.35%)
(0.30%)
(0.00%)
(11.20%)
Z = 19.54% of fixed
investment
$ 617,000
$2,734,000
(997,000)
$1,737,000
32.40
VIENNA POWER PLANT
R-21
-------
Table R-3 . ELECTROSTATIC PRECIPITATOR DESIGN
VALUES FOR BOILER 7 AT THE VIENNA POWER PLANT
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
Total collecting area, ft2
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
96.2
202
48,900.
4
15x67x19
VIENNA POWER PLANT
R-22
-------
It' SLKVE
TJ
WASTE WATER
DISPOSAL MT
VATHI
TREATMENT
CONDERSATE
STORAGE TANK
MAIN POWER Urn
TRANSFORMER ["[I |
HELL WATER STORAGE TAKI
—I KW >~n
STAIRWAY
VNEUTRALIZIHS TAN(
OUST
COUECTOI
I P.O. FANS.
ACID STORAGE TANK
CAUSTIC STORAGE TANK
EIISTING
SlINGER
EXISTINC POWER NOUSI
EXISTING—
20.000 GAL
COHO. 'STORAGE
TANK
UISTIM
STOCIt-OUi
CONVEYOR
EXISTING
CONVENOR TO BUNKERS
36' DISCHARGE FROM
SEAL CHAMBER
MAKE UP-WATER
INTAKE PIT
DISCHARGE CANAL EUSTINC
Oil IOOM ENCLOSURE
fLOW
MRTICOKE RIVER
Figure R-l. Site plan showing possible location of a new ESP
for Boiler 7 at the Vienna power plant.
U)
-------
APPENDIX S
WISDOM POWER PLANT
WISDOM POWER PLANT S-l
-------
CONTENTS
Page
Wisdom Power Plant Survey Form S-3
Wisdom Power Plant Photographs S-15
WISDOM POWER PLANT . S-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION;
1. COMPANY NAME: CORN BELT POWER COOPERATIVE
2. MAIN OFFICE: 1300 North 13th St., Humbolt, Iowa 50548
3. RESPONSIBLE OFFICER: Dan C. Adams
4. POSITION: Supt. of Plants
5. PLANT NAME: Wisdom
6. PLANT LOCATION: Clay County, Iowa - Spencer, Iowa 5130
7. RESPONSIBLE OFFICER AT PLANT LOCATION: P. J. Rath
8. POSITION: Plant Superintendent
9. POWER POOL
DATE INFORMATION GATHERED: December 31, 1975
PARTICIPANTS IN MEETING:
Dan C. Adams - Corn Belt Power Cooperative
•Philip J. Rath - Corn Belt Power Cooperative
John Metcalfe - Iowa Department of Environmental Quality
David A. Kirchgessner - U.S. Environmental Protection Agency
Thomas C. Ponder, Jr. - PEDCo Environmental, Inc.
N. David Noe - PEDCo Environmental, Inc.
Alan J. Sutherland - PEDCo Environmental, Inc.
WISDOM POWER PLANT S-3
-------
B
CO
o
i
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS*
* LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO. Sect.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( )
4. APPLICABLE SO2 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION S SECTION NO. Sect.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE : 7/31/78)
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
.0109
-
4.3 (2B)
= 8
4.3 (3a)
6.0
4.3 (3B)
5.0
CO
a) T
.*" wh~4-ver -~3ul*"- are from. -"-ack '--str ~T e-^
* STW Testing Inc., Denver, Colorado (7/17/75) at 38 MW
-------
M
C/3
a
o
s
i
W
13
2S
•-3
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE'
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT/)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
16- EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
Hagen
multiple
American
99 +
32,400
360°
20%
cyclones
Standard
^ Notes:
-------
M
to
D
•XI
O
a
w
£
25
17. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED. (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
21. BOTTOM ASH: TOTAL COLLECTED (TONS/
1975 data DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS @ STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
180,900
350°
59.78
500
Silo -*• tr
Oct. 1976
Turbine -
ucked
Boiler fo
r 3 weeks
en
I
oo
a) Identify source of values (test or estimate)
Notes: Breakdown cost (#21-22)
$540 - truck 1/2 mile (1 way) to dump site
$1875 - labor
$1375 - tractor $11,235 (cost for top & bottom)
$5100 - labor
-------
en
D
O
13
O
s
M
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C-)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler number
Notes:
to
I
10
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) Unlimited
2. YEARS STORAGE (ASH ONLY) 20 years
3. DISTANCE FROM STACK (FT.) 1/2 mile
4 . DOES THIS PLANT HAVE PONDING M
NO
PROBLEMS? DESCRIBE IN ATTACHMENT
G. COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a. 5 sources - districts 15, 22,
Mines b> oist. 15 - Welch Mine, Craig County, Okl.
Location c. Dist. 22 - Colstrip, Montana; Dist. 10 - Eagle Mine, Utah
d. Dist. 9 - Margareta, Hopkins County, Kentucky
2. QUANTITY USED BY SEAM AND/OR MINE
Total _*, a. 42.87 consumption/1000 tons of coal
Coal b>
Total ^c. 660.678 consumption/1000 mcf of gas
Gas ~~~
Analysis^' 1,000 Btu/cf for gas
3. ANALYSIS (Avg) from 1975
GHV (BTU/LB) 12,015
S (%) 3%
ASH (%) 11.6
MOISTURE (%) 8.6
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE
2. S CONTENT (%)
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL)
COST DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
WISDOM POWER PLANT S-10
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
1
Yes
2.
SYSTEM AVAILABILITY
2 .1 COAL HANDLING
a. Is the system still installed?
Will it operate?
b,
c,
Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
2.2 FUEL FIRING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
2.3 GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
Yes
YesD
D
D
D
D
D
YesD
D
YesQ
D
D
'D
Yesn
D
YesQ
D
D
D
P
NoD
D
No K)
K)
S
B
0
NoD
D
NoD
D
D
D
NOQ
D
NoQ
D
D
D
D
WISDOM POWER PLANT
S-ll
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes Q NoD
b. Will it operate? D D
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes Q NoD
Ash Pond D D
Milwaukee R.R. Line
Coal costs = $1.05 - $1.10/MW
WISDOM POWER PLANT S-12
-------
L. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? Yes
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS? Yes
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage? Derate Yes
2.3 Handling facilities available for low
sulfur fuels Yes
If yes, describe _
No
No
No
No
3.
5.
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?
IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss
POWER PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(1) Sulfur Oxides - Continuous
- Intermittent
- Static
(2) Suspended particulates
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
Yes
No
Yes Q] No j~]
Number Type
c. Is the monitoring -data available?
d. Is the monitoring data reduced and
analyzed? .
No env. complaints
ESP costs - $1.25 million
WISDOM POWER PLANT
Yes | j No
Yes Q No
S_13
-------
- Intermittent
- Static
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
5.2 Proposed system Yes Q No
If yes, describe
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
WISDOM POWER PLANT 3-14
-------
Photo No. 1. View from ground level facing northwest. The
electrostatic precipitator and its tie-in ducts are shown in
the center of the photograph.
WISDOM POWER PLANT
S-15
-------
Photo No. 2. View from ground level facing southwest. The
coal crusher, conveyor, coal pile, and coal car shaker are
shown in the center of the photograph.
Photo No. 3. View from ground level looking southwest
showing the ash silo and the coal pile.
WISDOM POWER PLANT
S-16
-------
Photo No. 4. View from ground level looking northeast. The
railroad spur is shown in the center of the photograph. A
portion of the boiler house is located in the foreground and
the electrical switchyard is shown in the background of the
photograph.
Photo No. 5. View from boiler house roof facing south
showing the cooling tower and the surrounding area.
WISDOM POWER PLANT
S-17
-------
Photo No. 6. View from the boiler house foof looking east,
The plant's access road and Stony Creek are shown in the
center of the photograph.
Photo No. 7. View from the boiler house roof facing west
showing the main railroad spur and a natural gas meter and
regulator station. The area surrounding the plant is shown
in the background of the photograph.
WISDOM POWER PLANT
S-18
-------
Photo No. 8. View from ground level looking north showing
the plant's nearest neighbor.
Photo No. 9. View from the boiler house roof facing west
showing the coal pile and the surrounding area.
WISDOM POWER PLANT
S-19
-------
Photo No. 10. View from the boiler house roof facing
southwest. The plant's switchyard and the surrounding area
are shown in the background.
WISDOM POWER PLANT
S-20
-------
APPENDIX T
L.D. WRIGHT POWER PLANT
L.D. WRIGHT POWER PLANT T-l
-------
CONTENTS
L. D. Wright Power Plant Survey Form
L. D. Wright Power Plant Photographs
Page
T-3
T-14
Number
T-l
FIGURES
Site Plan Showing Possible Locations of New
ESP's for Boilers 6 and 7 at the L. D. Wright
Power Plant
Page
T-23
Number
T-l
T-2
T-3
T-4
TABLES
Estimated Capital Cost of Electrostatic
Precipitators for Boilers 6 and 7 at the L. D.
Wright Power Plant (1978)
Estimated Annual Operating Costs of Electro-
static Precipitators for Boilers 6 and 7 at the
L. D. Wright Power Plant (1978)
Electrostatic Precipitator Design Values for
Boiler 6 at the L. D. Wright Power Plant
Electrostatic Precipitator Design Values for
Boiler 7 at the L. D. Wright Power Plant
Page
T-20
T-21
T-22
T-23
L. D. WRIGHT POWER PLANT
T-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION:
1. COMPANY NAME: Department of Utilities
2. MAIN OFFICE: 725 N. Park; Fremont, Nebraska
3. RESPONSIBLE OFFICER: Win. J. Sommers
4. POSITION: General Manager
5. PLANT NAME: Lon D. Wright Memorial
6. PLANT LOCATION: Fremont, Nebraska
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Jess Williams
8. POSITION: Superintendent
9. POWER POOL Omaha Public Power District
DATE INFORMATION GATHERED: April 28, 1976
PARTICIPANTS IN MEETING
Wm. J. Sommers
Forrest McGrew
Lyle Gill
Daniel Wheeler
N. David Noe
Robert Smolin
Department of Utilities
Department of Utilities
City Attorney; Fremont, Nebraska
U.S. Environmental Protection Agency -
Region VII
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
L.D. WRIGHT POWER PLANT
T-3
-------
jr1
a
B.
§
M
^
£
z
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 Coal
LB/MM BTU EST Gas
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (1975) EST
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: }
REGULATION & SECTION NO.
LB/MM BTU
3. SO_ EMISSIONS3
2 Coal
LB/MM BTU EST Gas
LB/HR (FULL LOAD)
TONS/YEAR (1975) EST
4. APPLICABLE SO EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/I-IM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
6
1.33
.005
213.8
0.23
.18
1.29
0.0006
207.6
2.5
7
1.33
.005
285.6
0.23
.18
1.29
0.0006
276. 8
2.5
With new
operat
Boiler No.
ion.
8 in
de
•y
th
res
fr
te
01
tii
-------
C. SITE DATA
1. U.T.M. COORDINATES Lat. 41°-26'-13", Long. 96°-27'-17"
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 1,176.74
3. SOIL DATA: BEARING VALUE
PILING NECESSARY No - On slab
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE):
L.D. WRIGHT POWER PLANT T_5
-------
D.
33
50
M
O
EC
1-3
O
33
W
50
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2 TOTAL HOURS OPERATION (1975)
3 AVERAGE CAPACITY FACTOR (1975)
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
6 YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT (years)
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS (Coal)
PEAK
9. FUEL CONSUMPTION:
COAL ' RATED
(TPH) '~ " MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (19 75)
GAS (19 75) MCF
11. WET OR DRY BOTTOM
12. FLY ASH REINJECTION (YES OR NO)
13. STACK HGT ABOVE GRADE (FT.)
14. I.D. OF STACK AT TOP (INCHES)
6
Floating
6,456
46%
6
B&W*
1957
21
18.5
15
8.3
15,600
388,400
Wet
No
176
96
Bo:
7
Floating
6,709
45%
7
ERIG+
1963
27
28.5
20
13.2
20,800
771,129
Wet
No
176
120
tier numbei
>•
Notes: * B&W - Babcock & Wilcox
+ ERIG - Erie City Iron Works
-------
f
•
D
CD
3C
13
O
s
M
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
16. EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
6
West
SCTA
81/70
N.A.
20
7
West
SCTA
81/70
N.A.
20
Notes:
-------
tr1
•
o
s:
SO
£
z
17. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
19. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
21. BOTTOM ASH: TOTAL COLLECTED (TONS/
YEAR}
DISPOSAL METHOD '
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS @ STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
6
66.100
335
275
295
300
770
Land Fill
200
Land Fill
8'-0"x
3'-8 1/2"
91'
1978
7
101.500
338
330
300
290
7'-0" x
5 '-6"
91'
1978
I
oo
a) Identify source of values (test or estimate)
Notes:
-------
D
•
S
o
ac
t-3
O
w
t)
5
z
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C.)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler number
Notes:
1-3
I
vo
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY) Yearly maintenance
3. DISTANCE FROM STACK (FT.)
4 . DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c .
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
3. ANALYSIS
GHV (BTU/LB) 10,300
0.7
ASH (%) 7.0
MOISTURE (%) 12.5
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE
2 . S CONTENT (%)
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL)
COST DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE? Would need enlargement
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
L.D. WRIGHT POWER PLANT T-10
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
6
Yes
7
Yes
2.
SYSTEM AVAILABILITY
2 .1 COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
2.2 FUEL FIRING
Is the system still installed?
Will it operate?
Yes El
YesD
NA D
D
D
D
D
Yes
Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
2 .3 GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced:
Electrostatic Precipitator NA
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
YesQ
D
D
D
0
YesQ
E
No D
D
No K! Frozen
n Coal
0 Problem
El
NoD
D
No H
No
D
NoQ
D
E ModifyD
D 53 May be
P K requir-
ed. •
L.D. WRIGHT POWER PLANT
T-ll
-------
2 .4 ASH HANDLING
a. Is the system still installed? Yes53 No Q
b. Will it operate? £) D
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes S NoQ
Ash Pond 53 D
L.D. WRIGHT POWER PLANT T-12
-------
L. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)?
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW
SULFUR FUELS?
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage?
2.3 Handling facilities available for low
sulfur fuels
If yes, describe
3.
4.
5.
Yes
Yes
No
No
Yes £
Yes
No
No
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)? N.A.
IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss
IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss
POWER PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(1) Sulfur Oxides - Continuous
- Intermittent
- Static
(2) Suspended participates
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
c. Is the monitoring data available?
d. Is the monitoring data reduced and
analyzed?
Yes
No fj[)
Yes
No
Yes Q No Q]
Number Type
Yes
Yes
No D
No
L.D. WRIGHT POWER PLANT
T-13
-------
ii.2 Proposed system Yes P[] No
If yes, describe
- Intermittent
- Static
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
L.D. WRIGHT POWER PLANT T_14
-------
Photo No. 1. View from ground level facing west showing
the Lon D. Wriqht Power Plant.
Photo No. 2. View from the boiler house roof facing north-
east showing the cooling tower and the surrounding area.
L.D. WRIGHT POWER PLANT
T-15
-------
Photo No. 3. View from the boiler house roof facing east
showing the warehouse and the surrounding area.
Photo No. 4. View from the boiler house roof facing south-
east showing the ash pond and part of the coal storage area
In the background, the surrounding area is shown.
L.D. WRIGHT POWER PLANT
T-16
-------
Photo No. 5. View from the boiler house roof facing south-
east showing the crusher house and part of the coal storage
area.
Photo No. 6. View from the boiler house roof facing north-
west showing the surrounding residential area.
L.D. WRIGHT POWER PLANT
T-17
-------
Photo No. 7. View from the boiler house roof facing south-
east showing stacks 6 and 7 and the ash ponds.
Photo No. 8. View from ground level facing southeast showing
the propane tank farm.
L.D. WRIGHT POWER PLANT
T-18
-------
Photo No. 9. View from ground level facing west showing the
ESP for Boiler 8.
Photo No. 10. View from the boiler house roof facing south
showing the top of the ESP for Boiler 8.
L.D. WRIGHT POWER PLANT
T-19
-------
TABLE T-l. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 6 AND 7 AT THE L. D. WRIGHT
POWER PLANT (1978)
Direct Costs
ESP $ 2,208,000
Ash handling 183,000
Ducting 259,000
Total direct costs $ 2,650,000
Indirect Costs
Interest during construction 8% of direct costs $ 212,000
Contractor's fee 10% of direct costs 265,000
Engineering 6% of direct costs 159,000
Freight 1.25% of direct costs 33,000
Offsite 3% of direct costs 80,000
Taxes 1.5% of direct costs 40,000
Spares 1% of direct costs 27,000
Allowance for shakedown 3% of direct costs 80,000
Total indirect costs $ 896,000
Contingency 709,000
Total $ 4,255,000
Coal conversion costs 475,000
Grand total > $ 4,730,000
$/kW 135.14
L.D. WRIGHT POWER PLANT T 20
-------
TABLE T-2. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 6 AND 7 AT THE L. D. WRIGHT POWER PLANT
(1978)
Utilities
Electricity
Water
Operating Labor
Direct labor
Supervision
Maintenance
Labor and materials
Supplies
Overhead
Plant
Payroll
Quantity
216 kW
2911 103 gal/yr
Unit Cost
27.5 mills/kWh
SO.01/103 gal
0.5 man/shift $8.50/man-hour
15% of direct labor
2% of fixed investment
15% of labor and materials
50% of operation and maintenance
20% of operating labor
Coal Cost Differentials
Operating and maintenance
Fixed Costs
Depreciation (4.55%)
Interim replacement (0.35%), Z = 16.40% of fixed
investment
Insurance (0.30%)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost
Total cost
Fuel cost
Net annual cost
Mills/kWh
Annual Cost
$ 24,000
1,000
73,000
11,000
85,000
13,000
91,000
17,000
83,000
$ 698,000
$ 1,096,000
118,000
$ 1,214,000
8.70
L.D. WRIGHT POWER PLANT
T-21
-------
Table T-3. ELECTROSTATIC PRECIPITATOR DESIGN
VALUES FOR BOILER 6 AT THE L.D. WRIGHT POWER PLANT
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
96.9
431
28,500
4
30 x 9 x 47
L.D. WRIGHT POWER PLANT
T-2.2
-------
Table T-4. ELECTROSTATIC PRECIPITATOR DESIGN
VALUES FOR BOILER 7 AT THE L.D. WRIGHT POWER PLANT
Design Parameter
Value
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
96.9
431
44,000
4
30 x 14 x 46
L.D. WRIGHT POWER PLANT
T-23
-------
NEW
; NEW i
! ESP !
WAREHOUSE
WATER
TREATMENT
BUILDING
Figure T-l. Site plan showing possible locations of
new ESP's for Boilers 6 and 7 at the L.D. Wright power plant.
L.D. WRIGHT POWER PLANT
T-2 4
-------
APPENDIX U
BASIS OF SODIUM SOLUTION REGENERABLE PROCESS DESIGN
U-l
-------
APPENDIX U
BASIS OF SODIUM SOLUTION REGENERABLE PROCESS DESIGN
A. DESIGN VALUES
The design basis for the sodium solution regenerable
system was determined after review of process designs now in
use or proposed for use, and discussions with Davy Power
Gas. A process flow sheet is presented in Figure U-l. A
list of equipment required for the sodium solution regen-
erable process is shown in Table U-l.
Values of the major design parameters are tabulated
below:
0 Variable design parameters: Table U-2
0 Constant design parameters: Tables U-3 and U-4
0 Flue gas pressure: atmospheric
0 Reheat: 50°F above dew point (from 125 to 175°F)
0 Soda ash consumption: 5% stoichiometric
Soda Ash System
Size: (unloading hoppers for the twenty plants):
200 tons
Feeders: capacity = 3.0 x maximum soda ash flow
Na~CO, slurry storage tank: 4 hours
Na^CO., slurry feed pump: 1 pump
Raw water pumps: two
U-2
-------
c
i
FROM TRAINS
*-* YEKTURI CIW. TWKSji
TO DISPOSAL
Figure U-l. Sodium solution regenerable system.
-------
COMPANY
LOCATION
EQUIPMENT LIST
• PEDCo-ENVIRONMENTAL
Cincinnati, Ohio
P.N.
CHECKED
BY
Sodium Solution Regenerate
COMPUTED
DATE
DATE
Tflhl^ "-I . FnuTPMFMT f-TST FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
NO.
Wl-Pl
VIL-P2
Ml -PI
UL-P5
WL-S1
WL-S2
WL-S3
WL-S4
WL-S5
WL-S6
WL-S7
WL-S8
WL-S9
WL-S10
WL-S11
WL-PT1
WL-PT2
Ul -PT"?
WL-PT4
WL-PT5
WLdPJ.6
WL-PT7
DESCRIPTION
NaCO, Preparation System
Storage Silo
Vibratinq Feeder
C «J
Ma TO Anitatrir*
Na^CO-, Make-up Pump
"2 ~
<;n Ahcnrhrr
Absorber Circulation Pumps
I.D. Fan
Hc-at Exchanger
Soot Blower
Butterfly Valving
Absorber Feed Surge Tank
Absorber Feed Surge Tank Agitator
Ducting
Absorber Product Surqe Tank
Absorber Product Surqe Tank Agitator
Purge Treatment
Purae Stream Heat Exchanger
Refriqeration Unit
Refrigeration Heat Exchanqer
Glycol Storage Tank
n wml Pnmn*;
Ccntri fune
NO . OF
ITEMS
.
H.P/
ITEM
TOTAL
H.P.
COST/
ITEM
TOTAL
COST
U-4
-------
COMPANY
LOCATION
EQUIPMENT LIST
PEDCo-ENVIRONMENTAL
Cincinnati, Ohio
P.N.
CHECKED
BY
Sodium Solution Regenerable
COMPUTED
BY
DATE
DATE
Table U-l. (Cont.) EQUIPMENT LIST FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
ITEM
NO.
WL-PT8
WL-PT9
WL-PT10
WL-PT11
WL-PT12
WL-PT13
WL-R1
Jl -P?
WL-R3
WL-R4
JL-R5
'.•IL-R6
UL-R7
UL-R8
UL-R9
ML- RIO
UL-R11
WL-R12
WU£RL_
ULdEB2_
'•JUP_R3_
'.^IL-PR4
DESCRIPTION
Centrate Tank
Dryer
Elevator
Na-,50, Storage Tank
c
-------
Table U-2. VARIABLE DESIGN PARAMETERS FOR SODIUM SOLUTION
REGENERABLE SYSTEMS
1 Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Cromby
Hudson
Lovett
Ravenswood
Ridge land
Boiler
No.
20
30
10
20
30
40
50
10
1
2
2
1
3
4
5
30
1
2
3
4
5
6
Flue gas
temp. , °F
300
293
300
300
300
300
300
281
269
269
240
291
310
300
288
700
385
385
385
385
334
334
Inlet S02 cone. ,
Ib/MM BtU
2.38
2.38
2.38
2.38
2.38
2.38
2.38
2.38
2.38
2.38
4.29
3.04
2.38
2.38
2.38
2.38
7.24
7.24
7.24
7.24
7.24
7.24
Outlet S02 cone.,
Ib/MM Btu
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.30
0.30
1.80
0.30
0.40
0.40
0.40
0.40
1.80
1.80
1.80
1.80
1.80
1.80
U-6
-------
Scrubbing System (Each Train)
Fan: double inlet centrifugal type (1-100% unit)
AP: 16.0" H20
Absorber: sieve tray type with two stages
AP: 8.0" H20
L/G: 3 gpm/MAcfin/stage (inlet gas to absorber
scrubber)
Slurry concentration: 25% (wt.)
S02 removal: see Table U-3
Gas velocity: 8 fps
Table U-3. S02 REMOVAL EFFICIENCY FOR SODIUM SOLUTION
REGENERABLE SYSTEMS
Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Cromby
Hudson
Lovett
Ravenswood
Ridgeland
SO removal efficiency, %
83.2
83.2
83.2
87.4
58.0
90.1
83.2
83.2
75.2
Solution storage tanks: 24-hour storage
Pumps: two/stage plus one spare pump for every
unit
U-7
-------
Table U-4. SIZES OF TURBULENT CONTACT ABSORBERS FOR THE
SODIUM SOLUTION REGENERABLE PROCESS
Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Cromby
Hudson
Lovett
Ravenswood
Ridgeland
No. of
absorbers
8
16
1
5
2
4
5
8
4
2
Dimensions (h
45 x 15
45 x 15
45 x 15
45 x 15
45 x 15
45 x 15
45 x 15
45 x 15
45 x 15
45 x 15
X W X 1) , ft
x 40
x 37
x 60
x 42
x 35
x 35
x 39
x 40
x 37
x 56
U-8
-------
Entrainment separator: Chevron vane type (two/absorber)
Number passes: two
AP: 2.0" H20
Gas velocity: 7 fps
Purge treatment:
Refrigeration: temperature = 40°F; flow = 5% of
recirculation rate
Centrifuge: solids = 5% of stoichiometric Na-CO^
^ *5
Acid Plant: 125% of average SO- flow
SO- regeneration:
Evaporators: 30% slurry of NaHSO-j based on SO2
absorbed. Evaporators are sized for 1 hour retention
and 50% free space.
Reboilers: 7.5°F temperature rise; 8 Ib of steam per
Ib of S02
Stripper: overhead is 1 Ib SO- and 1 Ib H-0 for every
1 Ib S02 ^ ^
Reheater: indirect tubular type
AT: 50°F (inlet temperature = 125°F;
outlet temperature = 175°F)
Heating medium: low-pressure steam
B. DESIGN RATIONALE
0 The soda ash storage silo is sized for 30 days
storage to allow the plant to continue operating
in the event of an interruption in the supply of
soda ash.
0 The feeders are sized at 3.0 times the maximum
soda ash flow.
0 The soda ash slurry storage is sized for 4 hours
storage.
U-9
-------
All critical pumps in the process are provided
with spares.
A sieve tray unit selected for removal of the bulk
of the SC>2 has 2 stages of sieve trays to provide
the contact area necessary for mass transfer to
S02 from the gas to the liquid phase. The absorber
is designed for an L/G of 3 GPM/MACFM/stage (inlet
gas to the absorber) and a pressure drop of 8 in.
H20. Slurry concentration will be 25%; gas velo-
city in the unit will be 8 FPS; and SOj removal is
specified to be about 90%. Standard sizes for
absorbers and Venturis for the sodium solution
regenerable process are showning Tables U-5 and
LJ-6, respectively. Standard scrubber modules are
presented in Figures U-2a through U-2d.
The absorbers have common solution storage tanks
sized to provide 24-hour storage of the slurry.
This storage time allows the absorbers to operate
for approximately 24 hours in the event the acid
plant should breakdown.
A Chevron vane-type entrainment separator removes
mist thatis carried over in the gas from the
absorber. This unit contains two stages of
Chevron vanes, which are washed continuously with
water. Superficial gas velocity through the unit
is 7 FPS and the pressure drop is expected to be
about 2 in. H20.
The gas leaving the entrainment separator must be
reheated to desaturate it and provide buoyancy for
adequate atmospheric dispersion. The number of
degrees of reheat necessary is variable and
dependent on a number of factors such as stack
height, local weather conditions, population
density, terrain, and maximum allowable S02
ground-level concentration. For this study, a
reheat AT of 50°F is used; this value is believed
to be about the minimum acceptable. Obviously,
the lowest acceptable reheat AT should be chosen,
since each increase of 50°F of the flue gas
temperature requires about 1.5% of the gross heat
input to the plant.
U-10
-------
Table U-5. TABLE OF ABSORBER STANDARD SIZES FOR THE SODIUM SOLUTION REGENERABLE PROCESS
G
i
Description
Flow rate @125°F, acfm
Flow rate @300°F, acfm
Nominal MW
Absorber
Length (A) , ft
Width (B) , ft
Height (C) , ft
Absorber tank
Diameter (D) , ft
Height (E) , ft
Entrainment Separator
Height (F) , ft
Hot duct
Dimension (G) , ft
Reheater to Separator
Overall
dimensions (H) , ft
Stack duct
Dimensions (J) , ft
I
300,000
398,000
150
39.0
15.0
45.0
44.0
20.0
15.0
12 x 11
30.0
14 x 13
II
250,000
325,000
110
28.0
15.0
'45.0
37.0
20.0
15.0
10 x 9
25.0
12 x 10
III
150,000
195,000
65
17.0
15.0
45.0
29.0
20.0
15.0
7x8
20.0
10 x 8
IV
100,000
130,000
45
11.0
15.0
45.0
23.5
20.0
15.0
6x6
20.0
7x7
V
50,000
60,000
20
6.0
15.0
45.0
17.0
20.0
15.0
4x5
20.0
5x5
-------
Table U-6. TABLE OF VENTURI STANDARD SIZES FOR THE SODIUM SOLUTION REGENERABLE PROCESS
c
i
i—1
NJ
Description
Flow rate @ 125°, acfm
Flow rate @ 300°, acfm
Nominal MW
Venturi
Length (K) , ft
Width (L) , ft
Height (M) , ft
Venturi tank
Diameter (N) , ft
Height (O) , ft
I
300,000
390,000
150
29.0
6.5
20.0
15.5
15.0
II
250,000
325,000
110
22.5
6.0
20.0
13.0
15.0
III
150,000
195,000
65
15.0
5.5
20.0
10.0
15.0 .
IV
100,000
130,000
45
10.0
5.5
20.0
8.25
15.0
V
50,000
65,000
20
5.6
5.0
20.0
6.0
15.0
-------
Y
\
FROM BOILER. TO STACK
x"l
xTd;:
•v
i
i
-
1
i
i
\
Y.
,'
« _
\
*"
-^
^
PLAN VIEW
TO STACK
/
REHEATER
ENTRAINMENT
SEPARATOR
LOCATION OF V
(IF APPLICABLE
SEE FIGURE
ENTURI
\
~*~7\ "G" (FAN
FROM BOILER
1
Af
1
JSORBE
R
ABSORBER
TANK
•^
ii n ii ^^
*
"E"
-, t
ELEVATION
Figure U-2a. Plan view and elevation of an absorber,
U-13
-------
•r •
i
•C"
I 1 ! •
SIDE VIEW
Figure U-2b. Side view of an absorber.
U-14
-------
FROM BOILER-
\ :
1
1
II
*
1
i
.
^ " N "_^.
~D33
y> *\_
' i i '
i i
i i
• i i •
"V t/~
r
\
•TO SCRUBBER
PLAN VIEW
FROM BOILER
TO SCRUBBER
ELEVATION
Figure U-2c. Plan view and elevation of a venturi scrubber,
U-15
-------
SIDE VIEW
Figure U-2d. Side view of a venturi scrubber,
U-16
-------
In the indirect finned tubular heat exchanger
selected for the reheater, the first 33% of the
rows of tubes are constructed of Alloy 20 for
corrosion resistance to the gas, which enters at
its dew point. The remaining 67% of the rows are
constructed of carbon steel. Heating medium for
the unit is low-pressure saturated steam. Pres-
sure drop through the reheater is calculated to be
about 4.0" H20.
Based on experience at Will County, a retractable
B&W type soot blower is used for each 25 ft2 of
scrubber exit duct cross-section for the heat
exchanger. Half of the soot blowers are on the
entry side, the remainder on the exit side of the
heat exchanger.
Cost of reheat is based purely on an oil con-
version cost in Btu's.
Purge treatment equipment is based mostly on TVA
cost estimates.
The acid plant costs are based on data furnished
by Wellman-Lord.
U-17
-------
APPENDIX V
BASIS OF LIMESTONE PROCESS DESIGN
V-l
-------
APPENDIX V
BASIS OF LIMESTONE PROCESS DESIGN
A. DESIGN VALUES
The process design basis for the wet limestone system
used in this study was determined after review of process
design used or proposed for use at various installations and
discussions with control system manufacturers. A flowsheet
of the limestone system is shown in Figure V-l. Table V-l
presents a complete list of equipment required for the
limestone process. Typical installation times for the
various stages of the limestone process are presented in
Figure V-2, the Critical Path Schedule.
Values of the major design parameters are tabulated
below:
0 Variable design parameters: Table V-2.
0 Constant design parameters: Tables V-3 and V-4.
0 Flue gas pressure: atmospheric
0 Reheat: 50°F above dew point (from 125 to 175°F)
0 Limestone consumption: 130% stoichiometric
Limestone System
Size: (unloading hoppers for the twenty plants): 200
tons
V-2
-------
(1IUCT
• tfPIl i» i.t.l
I
u>
—-L V W
c7cTFm*Vj t 4 S
uueci riiinei in*
ruio ituccc 10 iiiroiu-
Figure V-l. Limestone scrubbing system.
-------
COMPANY _
LOCATION
Table V-l.
EQUIPMENT LIST
PEDCo-ENVIRONMENTAL
Cincinnati, Ohio
P.N.
CHECKED
BY
COMPUTED
BY
DATE
DATE
ITEM
NO.
LL-L1
LL-L2
LL-L3
LL-L<*
LL-L5
LL-L6
LL-L7
LL-L8
LL-L9
LL-L10
LL-L11
LL-L12
LL-LI3
LL-LH
LL-L15
LL-S1
LL-S2
LL-S3
LL-S1*
LL-S5
. U-A1
U-A2
LL-A3
LL-A^
LL-CI
LL-C2
DESCRIPTION
Limestone Handling System
Hopper
Unloading Feeder
Tunnel Conveyor
Flop Gate
Stacker
Plant Conveyor
Tr iooer Bel t
Storage Si los
Vibrating Feeders
Weigh Feeders
Dust Col lector
Bal 1 Mills
Bal 1 Mill Tanks
Bal 1 Mill Tank Sump Pump
Limestone Classifier
Slurry Storage Tank
Slurry Mixer
Slurry Pumps
Slurry Surge Tank
Surge Pump
SO-) Scrubbing System
Absorber
Absorber Tank
Absorber Agi tator
Absorber Circulation Pump
Sludqe System
Clarifier Tank
Overflow Pump
NO. OF
• ITEMS
H.P/
ITEM
TOTAL
H.P.
COST/
ITEM
TOTAL
COST
V-4
-------
COMPANY
Table V-l (Continued).
EQUIPMENT LIST P.N.
LOCATION
PEDCo-ENVIRONMENTAL
Cincinnati, Ohio
CHECKED
BY
COMPUTED
BY
DATE
DATE
ITEM
NO.
LL-C3
LL-C^
LL-C5
LL-C6
LL-C7
LL-C8
LL-C9
LL-C10
LL-CI1
LL-SR1
LL-H1
LL-H2
LL-AP1
LL-AP2
LL-AP3
LL-V1
LL-V2
LL-V3
DESCRIPTION
Underflow Pump
Vacuum F i 1 ter
Vacuum Pump
Return Filtrate Pump
Mix Tank
Mixer
Sludge Pump
Add i t i ve Hopper
Water Make-Up Pump
Mobi le Equipment
Heat t'xchanqer System
Heat Exr.hanqer
Soot Blowers
Air Pipi ng System
Induced Draft Fans
Ducting
Butterfly Valves w/Operator
Particulate Removal System
Venturi System
Venturi Circulation Tank
Venturi Circulation Tank
NO. OF
ITEMS
H.P/
ITEM
TOTAL
H.P.
COST/
ITEM
TOTAL.
COST
V-5
-------
SECUT »IH«e
DESIGN PIPING. WE CV.S.
t P5tr«i BILL or E.-.H.;
'
riNALIIE
LAt CUTS/
IkDIUIU CRITICAL ACTIlin
• INDICATES OU«n ACTIVITY
u/ .QOJ -y:*
'[PARC PREUMIMN-
IVIL D»»JIM;S «x
till OF MATERIAL
FINALIZE 1C
CONTVC1 ro< I
AM) CPEMI
y m pV«ti
^\ ^,'1?;
[IZj \368J/ L
bccu>c
l.C't'-TSI
[1
CLt« i
cr«L
LEVEI
11
OBTAI
PAOCUR
DUCtIN
DESIGN 1 SPECIF
I.D. FAN
111
ursici i spccirr s
ILECiaiCAL EQUIP. I
LU \i
DESIGN SLUDGE S~*
STSIEH / l!
QO) li»|l
DESIGN fK>
i:r[siONC /*T7\
srsi'.i .( H A
llSJ \»ijj/
!•• TflW JL
IHIIIONI XT*N
c«i$ r \\\
(_ INSTALL t tRtCT
t«ui?»cirr
Figure V-2. Critical path schedule.
-------
Table V-2. VARIABLE DESIGN PARAMETERS FOR
LIMESTONE SYSTEMS
Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Cromby
Hudson
Lovett
Raven swood
Ridgeland
Boiler
No.
20
30
10
20
30
40
50
10
1
2
2
1
3
4
5
30
1
2
3
4
5
6
Flue gas
temp. ,°F
300
293
300
300
300
300
300
281
269
269
240
291
310
300
288
700
385
385
385
385
334
334
Inlet SO2 cone. ,
Ib/MM Btu
2.38
2.38
2.38
2.38
2.38
2.38
2.38
2.38
2.38
2.38
4.29
3.04
2.38
2.38
2.38
2.38
7.24
7.24
7.24
7.24
7.24
7.24
Outlet S02 cone. ,
Ib/MM Btu
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.40
0.30
0.30
1.80
0.30
0.40
C.40
0.40
0.40
1.80
1.80
1.80
1.80
1.80
1.80
V-7
-------
Feeders, Conveyors: capacity = 5.8 x maximum limestone
flow
Lime storage silos: 3 days storage
Limestone slurry storage tank; 24 hours storage
Limestone slurry feed pumps: two pumps/train with one
spare for each two operating pumps
Raw water pumps: two
Clarifier and sludge pond dimension: see Table V-3
Clarifiers: two per plant
Table V-3.
CLARIFIER AMD SLUDGE POND DIMENSIONS FOR
LIMESTONE SYSTEMS
Plant
Arthur Kill
Astoria
E.F« Barrett
Bergen
Cromby
Hudson
Lovett
Ravenswood
Ridgeland
Clarifier, ft _.
Diameter
75
100
49
65
60
56
49
75
165
Height
20
20
20
20
20
20
20
20
20
Sludge pond,
acre-ft/yr
44
73
26
64
45
49
17
43
115
V-8
-------
Scrubbing System (each train)
Fan: double inlet centrifugal (1-100% unit)
AP: 24.0" H20
Absorber: TCA type with two beds
L/G: 65 gpm/MAcfm (inlet gas to absorber scrubber)
Slurry concentration: 8% (wt.)
SO- removal: see Table V-4
Table V-4. S02 REMOVAL EFFICIENCY FOR
THE LIMESTONE SYSTEMS
Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Cromby
Hudson
Lovett
Ravenswood
Ridgeland
SO- removal, %
83.2
83.2
83.2
87.4
58.0
90.1
83.2
83.2
75.2
Gas velocity: 10 fps, absorber
Circulating tank: 10 minutes retention, absorber
Pumps: four/train plus one spare pump for each train,
absorber
V-9
-------
Entrainment separator: Chevron vane type
Number passes: two
AP: 2.0" H20
Gas velocity: 7 fps
Reheater: indirect tubular type
AT: 50°F (inlet temperature + 125°F; outlet
temperature = 175°F)
Heating medium: low pressure steam
B. DESIGN RATIONALE
0 The unloading hoppers are sized to hold 200 tons
to accomodate unloading of trains as well as
trucks.
0 The live storage silo is sized for 3 days storage.
0 The feeders and conveyors are sized at 5.8 times
the maximum limestone flow to allow the unloading
of limestone during a 40-hour week while the plant
operates continuously.
0 The limestone slurry storage tank is sized for 24
hours storage to allow the scrubbing trains to
continue operating this limestone for 24 hours if
supply is interrupted.
0 All critical pumps in the process are provided
with spares.
0 The thickeners and new pond are used with diking
to provide sufficient pond space for the life of
the plant. The thickener concentrates the ef-
fluent slurry from 15% solids to 30% solids and
then discharges the 30% effluent slurry to the
vacuum filtration units. The effluent leaves the
filtration unit with a slurry 60% by weight and
then enters a mixing tank where the fixation
additives are stirred in with the 60% slurry,
which is then pumped to the sludge pond. Figure
V-3 illustrates how sludge pond dimensions are
calculated.
V-10
-------
<
I
o
o
x:
o
Lul
O
C£.
O.
40--
20--
0 20 40 60 80 100 120 140 160 100 200 220 240 260 200 300 320 340 360 330
LENGTH L AND WIDTH W OF SLUDGE POND (FEET)
Figure V-3. Sludge pond size sheet.
-------
A UOP* Turbulent Contact Absorber (TCA) was selected
for removal of the bulk of the S02. This unit has
two beds of hollow plastic spheres, which move
randomly between support grids and provide the
contact area necessary for mass transfer of S02 from
the gas to the liquid phase. The absorber is
designed for an L/G of 65 gpm/MAcfm (inlet gas to
the absorber) and a pressure drop of 7 in. H20.
Slurry concentration will be 8%; gas velocity in
the unit will be 10 fps; and S02 removal is
specified to be about 85% plus. The size of the
turbulent contact absorbers is shown in Table V-5.
Standard sizes for absorbers and Venturis for the
limestone process are shown in Tables V-6 and V-7,
respectively. Standard scrubber modules are
presented in Figures V-4a through V-4d.
Each absorber has a circulating tank sized to
provide a 10-minute retention time based on the
slurry circulation rate. This retention time is
essentially the same as that reported by others
and should provide sufficient time for desuper-
saturation and thus reduce scaling potential. If
long retention time are required, the incremental
cost would be small since the circulating tanks do
not represent large cost items; space limitations
may require locating a secondary tank some dis-
tance away and providing additonal piping.
The Chevron vane-type entrainment separator is
incorporated to remove mist carried over in the
gas from the absorber. This unit contains two
stages of Chevron vanes, which are washed con-
tinuously with water. Superficial gas velocity
through the unit is 7 fps and the pressure drop is
expected to be about 2.0" H20. Design of the unit
is based on information from C-E, Chemico, and UOP.
The gas leaving the entrainment separator must be
reheated to desaturate it and provide buoyancy for
adequate atmospheric dispersion. The number of
degrees of reheat necessary is variable and
dependent on a number of factors such as stack
height, local weather conditions, population
density, terrain, and maximum allowable SO2
ground level concentration. For this study, a
*
Universal Oil Products Company (Air Correlation Division).
V-12
-------
Table V-5. SIZES OF TURBULENT CONTACT ABSORBERS FOR
THE LIMESTONE SYSTEMS
Plant
Arthur Kill
Astoria
E.F. Barrett
Bergen
Cromby
* Hudson
Lovett
Ravenswood
Ridgeland
No. of
absorbers
8
16
1
5
2
4
5
8
4
2
Dimensions (h x w x 1) , ft
45 x 15 x 32
45 x 15 x 30
45 x 15 x 45
45 x 15 x 31
45 x 15 x 28
45 x 15 x 35
45 x 15 x 29
45 x 15 x 30
45 x 15 x 30
45 x 15 x 45
V-13
-------
Table V-6. TABLE OF ABSORBER STANDARD SIZES FOR THE LIMESTONE PROCESS
Description
Flow rate @125°F, acfm
Flow rate @300°F, acfm
Nominal MW
Absorber
Length (A) , ft
Width (B) , ft
Height (C), ft
Absorber tank
Diameter (D), ft
Height (E), ft
Entrainment Separator
Height (F), ft
Hot duct
Dimension (G), ft
Reheater to Separator
Overall
dimensions (H), ft
Stack duct
Dimensions (J), ft
I .
300,000
455,000
150
39.0
15.0
45.0 '
44.0
20.0
15.0
12 x 11
30.0
14 x 13
II
250,000
325,000
110
28.0
15.0
45.0
37.0
20.0
15.0
10 x 9
25.0
12 x 10
III
150,000
195,000
65
17.0
15.0
45.0
29.0
20.0
15.0
7x8
20.0
10 x 8
IV
100,000
130,000
45
11.0
15.0
45.0
23.5
20.0
15.0
6x6
20.0
7x7
V
50,000
65,000
20
6.0
15.0
45.0
17.0
20.0
15.0
4x5
20.0
5x5
<
I
-------
Table V-7. TABLE OF VENTURI STANDARD SIZES FOR THE LIMESTONE PROCESS
Description
Flow rate @125°F, acfm
Flow rate @300°F, acfm
Nominal MW
Venturi
Length (K) , ft
Width (L) , ft
Height (M) , ft
Venturi tank
Diameter (N) , ft
Height (O) , ft
I
350,000
455,000
150
29.0
6. 5
20.0
15.5
15.0
II
250,000
325,000
110
22.5
6.0
20.0
13.0
15.0
III
150,000
195,000
65
15.0
5.5
20.0
10.0
15.0
IV
100,000
130,000
45
10.0
5.5
20.0
8.25
15.0
V
50,000
65,000
20
5.6
5.0
20.0
6.0
15.0
-------
II .
•fr"
FROM BOILER. TO STACK
—/•
;
l
—\-
PLAN VIEW
TO STACK
REHEATER
ENTRAPMENT
SEPARATOR
ABSORBER
LOCATION OF VE
(IF APPLICABLE
SEE FIGURE
-*-A "G" (
1NTURI
)
\
FAN
1
FROM BOILER
<»B">
ABSORBER
TANK
«* —
" D " -rm
u *^
A
II r it
L, t
ELEVATION
Figure V-4a. Plan view and elevation of an absorber,
V-16
-------
FROM BOILER
t
a
i
• i
•
II
i
I
i
i
^ " N "— ^
-rrn
/i "\
i i i
' , i : /
'AL, Jf
0 teu
TO SCRUBBER
PLAN VIEW
FROM BOILER
TO SCRUBBER
ELEVATION
Figure V-4b. Plan view and elevation of a venturi scrubber,
V-17
-------
•C"
I
I
I
r'
SIDE VIEW
Figure V-4c. Side view of an absorber,
I—~-~\
I I
!K"
SIDE VIEW
Figure V-4d. Side view of a venturi
scrubber.
-------
reheat AT of 50°F is used; this value is believed
to be about the minimum acceptable. Obviously,
the lowest acceptable reheat AT should be chosen,
since each increase of 50°F of the flue gas
temperature requires about 1.5% of the gross heat
input to the plant.
In the indirect finned tubular heat exchanger
selected for the reheater, the first 33% of the
rows of tubes are constructed of Alloy 20 for
corrosion resistance to the gas, which enters at
its dew point. The remaining 67% of the rows are
constructed of carbon steel. Heating medium for
the unit is low-pressure saturated steam. Pres-
sure drop through the reheater is calculated to be
about 4.0" H20.
Based on experience at Will County, a retractable
B&W type soot blower is used for each 25 ft2 of
scrubber exit duct cross-section for the heat
exchanger. Half of the soot blowers are on the
entry side, the remainder on the exit side of the
heat exchanger.
Cost of reheat is based purely on an oil con-
version cost in Btu's.
V-19
-------
APPENDIX W
ESP SUPPORT INFORMATION
W-l
-------
APPENDIX W
ESP SUPPORT INFORMATION
The design basis for the cost and installation of ESP's
was determined after review of process designs now in use
or proposed, and discussions with control system manufac-
turers. A list of equipment required for installation of
an ESP is presented in Table W-l. The critical path sched-
ule, Figure W-l, illustrates the time required for installa-
tion of various stages of an ESP. Standard layouts for an
ESP are shown in Figure W-2.
W-2
-------
COMPANY
LOCATION Electrostatic
Precioitator
Table W-l
EQUIPMENT LIST
PEDCo-ENVIRONMENTAL
Cincinnati, Ohio
P.M.
CHECKED
BY
COMPUTED
BY
DATE
DATE
ITEM
NO.
DESCRIPTION
ESP
ESP and Vaninq
Transformer and Rectifier Sets
Rappers (wires and plates)
ASH HANDLING SYSTEM
Ash Hoppers
Flv Ash Pipe and Fittinqs
Fly Ash Valves
Seqreqatinq Valves
Ash Silo
Primary Collector
Secondary Collector
Vent Filter
Dustless Unloader
Exhauster
Vacuum Breaker
TRANSITION DUCTING
Ductinq
Valves
NO. OF
• ITEMS
H.P/
ITEM
TOTAL
H.P.
.
COST/
ITEM
TOTAL
COST
W-3
-------
PIOCURE i EVALUATE Duenna
{ASRICATIOII «IOS/'T7>
INSTAll ClCailCAI.
EOUIPMENT AW
COMPLETE UIRINC
•s,
I
FIWlllE
DUCT INC CONTRACT
m
PROCME | EVALUAT
D
to tuit\n
DCSIH I SPECIFY
I.D. FIN
FINAI.IK
1.0. FAN OBOE
FABRICATt 1 OCUVEB 1.0. TABS
PREPAJ1I
COOBX
f>LJU AM) COVI.I-
. - SCMDUl
I > FQ« AGENCT
FINAIIH
ANS AHDSPC
FABRICATE « OEUVEI
PIPING COH.1iCTIOHS tSP-l
INSTALL 1.0.
FAN I CONNECT
TS: ESP.J
FABRICATE I DELIVER
tSP-l m SITE
SECURE CIVIL
CONTRACTOR
I RELATED iOUlPMEKT
EICAVATE 1 PREPARE
FOUNDATIONS FOR
ESP-l
PROCURE
CONSTRUCT 1011
MATERIAL
INSTALL I.D.
FAN I CONNECT |
DUCTING ESP-2 i
PRCPAJU PUllMlllUT COIL
DRAMlies I Bill or MATERIAL
4
I
IERECI CSP-Z
1 RELATED EQUIPMENT
flCAVME » PREPARE <
FOUnOAT IONS FOR
EOUIFMEKT
«T V«6I80
WIE
FOUNDATION
DUGS. .
0
DEBUG I
COKI SSI OH
fSP SYSTEM
SWITCH (M I
EST SYSTE
ACTIVITY DESCRIPTION
HAKE ELECTRICAL
t PIPING
CONNECTIONS
FOR ESP-2 .
EICAVATE I (RETIRE
FOUNDATIONS FOR csr-t
IKOICATES OLM1T ACTI»ITT
INDICATtS dlTICM.
Figure W-l. ESP Critical Path Schedule.
-------
s
ui
Figure W-2. ESP standard layout.
-------
APPENDIX X
COMPANY LETTERS TO THE FEDERAL ENERGY ADMINISTRATION
X-l
-------
APPENDIX X-l ARTHUR KILL POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Consolidated Edison
Company:
"The questions (on the FEA information request) were
answered on the basis that any order to convert to coal
firing would be on a non-emergency basis, and would be
for the long term. No allowance or consideration was
made for an AQCS further than adequate precipitators.
The cost figures used are estimates and should be used
as order of magnitude numbers."
Original Coal specifications for Boilers 20 and 30 are
shown below:
Boiler 20 Boiler 30
HHV, Btu/lb 13,600 13,600
Ash, % 7.2 7.2
Volatite, % 36.5 36.5
Ash fusion temp.,°F 1900-2300 2100
Moisture, % 3.4 3.4
Free carbon, % 52.9 52.9
Grindability 63 63
The anticipated acquistion or refurbishing of coal
handling and firing equipment that would be required to
reinstitute coal burning capability, and information rel-
evant to the adequacy of storage facilities for coal are
listed below. Costs and outage time are also provided.
ARTHUR KILL POWER PLANT X-2
-------
SC
C
f
f
i
w
13
£
z
Item
Arthur Kill
Unit 20
1) Install new precipitators
2) Install new bottom ash
system
3) Install new fly ash system
& storage facility
4) Overhaul raw coal system
5) Overhaul pulverizer system
6) Overhaul burner equipment
7) Check controls & checkout
system
Arthur Kill
Unit 30
1) Install new precipitators
2) Convert bottom to coal
firing
3) Install new fly ash system
4) Overhaul raw coal system
5) Complete pulverizer over-
haul
6) Change boiler orifices to
coal firing
7) Change combustion & burner
control to coal firing
8) Checkout coal firing system
Estimated lead
imated
$
6,000,
750,
1,500,
300,
100,
100,
cost, time & construction
time, yr
000
000
000
000
000
000
2 -
1 -
2 -
1/6
1/2
1/2
2 1/2
1 1/2
2 1/2
- 1/2
- 1
- 1
Estimated
plant out
time , wk
2-3
2
None
None
None
2
25,000
7,000,000
75,000
Incl. in Un.20
Incl. in Un.20
75,000
20,000
20,000
10,000
1/2
2-21/2
2 Wks
2-2 1/2
1/6 - 1/2
3 Wks
2 Wks
3 Wks
1 Wk
1/2 - 1 yr
2
None
None
None
2
2
1/2
"Coal storage (on ground) available, deliveries by rail only no river edge
loading or unloading available.
x
i
U)
-------
The differential operation and maintenance cost es-
timates are as follows:
Operation Maintenance Total
Unit 20 $ 79,557 $ 61,084 $140,641
Unit 30 $441,386 $294,465 $735,851
ARTHUR KILL POWER PLANT X-4
-------
APPENDIX X-2 ASTORIA POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal energy Administration by the Consolidated Edison
Company:
"The questions (on the FEA information request) were
answered on the basis that any order to convert to coal
firing would be on a non-emergency basis, and would be
for the long term. No allowance or consideration was
made for an AQCS further than adequate precipitators.
The cost figures used are estimates and should be used
as order of magnitude numbers."
Original coal specifications for Boilers 10 and 20, and
for Boilers 30, 40, and 50 are shown below:
Boilers 10-20 Boilers 30-50
HHV, Btu/lb 13,253 13,600
Ash,% 8.0 7.2
Volatile, % 37.8 36.5
Ash fusion temp.,°F 1900-2300 1900-2300
Moisture, % 4.1 3.4
Free carbon, % 50.1 52.9
Grindability 64 63
The anticipated acquisition or refurbishing of coal
handling and firing equipment that would be required to
reinstitute coal burning capability, and information rel-
evant to the adequacy of storage facilities for coal are
listed below. Costs and outage time are also provided.
ASTORIA POWER PLANT X-5
-------
The differential operation and maintenance cost estimates
are as follows:
Operation Maintenance Total
Units 10&20,$ 231,578 293,230 524,808
Units 30&40,$ 154,334 195,487 349,821
Unit 50,$ 231,540 293,947 525,487
ASTORIA POWER PLANT X-6
-------
en
i-3
O
po
O
3S
w
X
I
Astoria Units 10 & 20
1) Install new precipitator
2) Install new bottom ash
system
3) Restore fly ash system &
silo
4) Overhaul raw coal system
5) Overhaul pulverizer system
6) Overhaul burner equipment
7) Overhaul/Checkout coal
controls
Unit 30
1) Install new precipitator
2) Install new bottom ash
system
3) Restore fly ash system &
silo
4) Overhaul raw coal system
5) Overhaul pulverizer
system
6) Overhaul burner equipment
7) Overhaul/checkout coal
controls
Unit 40
1) Install new precipitator
2) Overhaul bottom ash
system
3) Overhaul fly ash system
4) Overhaul raw coal system
5) Overhaul pulverizer
system
6) Overhaul burners
7) Overhaul controls
4,
6,
Incl.
Incl.
6,
Incl.
Incl.
000,
750,
800,
500,
150,
100,
25,
000,
750,
in
in
150,
60,
50,
000,
50,
in
in
100,
100,
25,
000
000
000
000
000
000
000
000
000
Un. 10&20
Un. 10&20
000
000
000
000
000
Un. 10&20
Un. 10&20
000
000
000
2 -
1 -
1
1
1/2
1/2
2 -
1 -
1/2
1/2
1/2
2 -
1/3
1/2
1/2
2
1
-
—
1/2
2
1
1
1
_
—
-
2
—
1
1
—
-
1/2
1/2
1/2
1
1
1/2
1/2
1
1
1
1/2
1/2
1
1
2-3
2
2
None
None
4
2-3
2
2
None
None
3-5
2
Unit 50 - Same as Unit 40
-------
APPENDIX X-3 E. F. BARRETT POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Long Island Light-
ing Company:
1. Maximum and Minimum Values
These data reflect the range of each fuel character-
istic satisfactorily and reliably experienced in operation,
although it must be recognized not extremes of each char-
acteristic necessarily simultaneously. The coal and ash
handling systems were designed for 13,000 Btu/lb. coal. A
decrease in that level (usually as a function of increased
ash content) overloads both the coal unloading and coal
pulverizing systems reducing boiler capacity and/or re-
liability. Increased ash content overloads the ash handling
systems, decreases precipitator efficiency, produces plume
opacity problems and frequently requires load curtailment to
empty ash hoppers and associated transport piping. As an
additional consideration, ash disposal areas on Long Island
are extremely limited in availability. At the Barrett
Station resolution of environmental (water) problems must be
E. F. BARRETT POWER PLANT X-8
-------
accomplished before existing areas of limited capacity may
be used.
Btu/lb. - 13,000
Ash, %, maximum - 10%
Moisture, %, maximum - 5%
Volatile matter, % - 26-39
Grindability, Hardgrove, minimum - 60
Ash Characteristics
Initial deformation, °F - 1900°
Ash softening, temp., °F - 2100° min.
Ash fusion, temp. °F - 2250° min.
2. Coal Transportation
LILCO has great concern regarding the availability of
coal on a continuing reliable basis .... It is our
evaluation that significant revisions to our coal and ash
handling and dust collection equipment is required to place
this plant back on coal.
We are concerned over the capacity of the coal piers in
the New York harbor to accommodate additional tonnage for
unloading into barges. Of the three previous coal unloading
piers (Penn-Central, Central Railroad of New Jersey, and the
Reading R.R.), only the Reading Pier is in operation. The
financial condition of the other two railroads makes ques-
tionable their ability to restore their piers to an op-
erating status.
Historic coal deliveries to the E. F. Barrett plant
have been by rail to the Jersey side of the Hudson River, at
which point, they were floated on barges to a terminal of
E. F. BARRETT POWER PLANT X-9
-------
the Long Island Railroad (LIRR). The LIRR will no longer
accept coal on car floats and will not use passenger rail-
road tunnels under the Hudson and Fast Rivers for transit to
Long Island proper. Thus, an all-rail route north to
Selkirk, New York, thence south over the Hell Gate Bridge to
Long Island, is necessitated.
3. Acquisition and Refurbishment
Phase I - Revisions and additional equipment required
to provide reliable operating conditions,
exclusive of plume opacity considerations.
(1) Conversion of boiler ash pit, burners and ash
system from oil to coal firing.
Lead time 2 weeks
(2) Dredge ash pond for required additional
bottom ash capacity.
Lead time 2 months
(3) Rebuild existing coal pile storage area,
install impervious liner to prevent ground
water contamination, and provide drainage to
capture and treat runoff.
Lead time 6 months
(4) Install dust control system at coal pile and
railroad car unloading facility.
Lead time 9 months
(5) Alter railroad track egress to LILCO property
E. F. BARRETT POWER PLANT X-10
-------
from the Long Island Railroad (L.I.R.R.).
The LIRR (Metropolitan Transportation Au-
thority) notified LILCO in 1974 that it will
not deliver coal under existing railroad
track layouts, except in limited delivery
increments, to avoid blocking of Long Beach
Road for passenger and commercial traffic and
emergency vehicles of the Village of Island
Park.
Lead time 9-12 months
(6) Rotary railroad car dumper complete with pit,
building, tracks, positioner, etc.
Lead time 2 years
(7) Installation of waste water treatment system
for coal firing. This is necessary for
treatment of bottom ash waste water.
Lead time 2 years
(8) Hydrobin capacity is required to handle high
ash coal. The hydrobin is used for inter-
mediate storage of bottom ash and to decant
out hydraulic ash transfer medium. The
installation of a hydrobin is anticipated due
to environmental restrictions which would
prohibit the hydraulic deposit of ash in
previous fields draining into waterways.
E. F. BARRETT POWER PLANT X-ll
-------
Lead time 2 years
(9) Installation of dry fly ash system, ash silo
and building, equipment, etc.
Lead time 2 years
Phase I Total
Phase II - Precipitators required to meet efficiency
of 98% or higher.
(1) New precipitator parallel to existing unit.
Lead time 3 years
Phase III - S02 removal equipment if required by EPA or
State. (Present fuel requirement is 0.37%
sulfur.)
(1) SO- removal system.
Lead time 3 years (minimum)
4. Power Plant Outage Time
Upon receipt of notification, conversion from oil to
coal firing with existing equipment can be accomplished with
a two week outage for each unit. Such estimate is based on
converting to coal firing with original design conditions
and is exclusive of present day environmental standards.
5. Lead Time
The coal handling and stacking out equipment is over-
hauled and capable of stock-piling coal whenever it is
received. The ash system has been checked out and can be
operated. However, a minimum amount of ash can be removed
E. F. BARRETT POWER PLANT X~12
-------
before the ash field has to be dredged. The boiler is in a
state of readiness such that it requires a two week shutdown
for actual boiler conversion work. This would also be
sufficient time to develop the necessary coal inventory with
existing equipment.
However, a lead time of up to two years to acquire or
refurbish the equipment discussed in Response Nos. 4 and 5
would be necessary.
6. Local Laws
State laws that have an effect on coal utilization are
Parts 700-703, Title 6, New York State Water Quality Stan-
dards and Part 201.9 of 6 NYCRR, air pollution control.
In addition, Barrett is located in the Town of Hempstead
which has a noise code in Chapter 144.
E. F. BARRETT POWER PLANT X-13
-------
APPENDIX X-4 BERGEN POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Public Service
Electric and Gas Company:
1. Original design coal specifications:
Bergen Nos. 1 & 2 Units
Heating value - 13,000 Btu/lb as received
% Sulfur - 3.0 as received
% Ash - 10.0 as received
% Volatile matter - 36.0 as received
Grindability - 60 Hardgrove
Ash fusion temp. - 2100 F
Some variations in the original specifications could be
tolerated if these variations are not too great. Maximum
and minimum limits for the boilers are:
Heating value - 12,800 Btu/lb Mininum as received
% Ash - 11% Maximum as received
Volatile matter - 22% Minimum as received
Grindability - 55 Hardgrove Minimum
Ash fusion temp. - 2300 F Maximum
BERGEN POWER PLANT X-14
-------
2. Coal Conversion Costs Are:
COAL CONVERSION DATA AND
COSTS
Data
Capacity (MW)
Initial service (year)
Last burned coal (year)
Maximum lead time-material
(weeks)
Maximum lead time-conversion
(weeks)
Boiler outage required
(week)
Costs
Coal handling equipment
Pulverizers, burners, boilers
Ash and dust disposal
Pipeline penalty
Outage replacement energy
Total conversion costs
Additional Annual Operating Costs
Labor
Material
Ash and dust disposal
Total additional annual
operating costs
Bergen
Nos. 1 & 2
280 283
1959 1960
1971 1971
40
52
9 9
$ 588,500
372,000
2,298,500
4,450,000
$7,709,000
$ 407,000
200,000
652,000
$1,259,000
BERGEN POWER PLANT
X-15
-------
COAL CONVERSION
EQUIPMENT COSTS AND LEAD TIME
NOS. 1 AND 2 UNITS
BERGEN GENERATING STATION
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(1975)
Equipment
Coal Handling Equipment
Redlers
Coal silos & vibrators
Car thawing shed
Car dumper
Conveyors
Bradford breaker
Crushers
Swing Boom & swing
boom rest
Transfer tower
Miscellaneous
Bulldozer
Total
Cost
$ 200,000
18,500
8,500
10,500
124,500
18,500
20,500
7,500
14,000
16,000
150,000
$ 588,000
Pulverizers, Burners, Boilers
Combustion control $ 2,000
Feeder tables & assoc. 36,000
equipment
Pulverizer mills 64,500
Coal burning air syst. 20,500
Boiler tubing 110,000
Sootblowers 125,500
Air heaters 8,500
Boiler penthouse' 5,000
pressurizing fans
Total
$ 372,000
Ash and Dust Disposal
Dust transport
system
Ash sluice system
Slag system
Rebuild ash pond and
Water treatment
Total
$ 29,500
27,000
42,000
2,200,000
$2,298,000
Conversion
lead time
(weeks)
45
21
7
28
42
34
12
28
16
6
10
27
33
44
11
24
32
16
10
30
30
48
52
BERGEN POWER PLANT
X-16
-------
APPENDIX X-5 CROMBY POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Philadelphia Elec-
tric Company:
"1. Original specification coal characteristics, as
fired, for Cromby Unit No. 2.
Btu/lb 13,700
Sulfur, % 1.5
Ash, % 7.0
Volatile, % 26.0
Ash fusion temp. - Softening 2590°F
Liquid 2670°F
2. Range of characteristics compatible with design
tolerance.
Maximum Minimum
Btu/lb - 13,100
Sulfur, % 3 1.5
Ash, % 10 -
Volatile, % 40 24
Ash fusion temp. - Softening - 2,500
Liquid - 2,600
3. Coal and Transportation Information
(a) Availability of coal and transportation
Based on the quality of coal received in 1974, the
additional coal required for Cromby No. 2 would be
difficult to obtain and meet the specifications of
the equipment. New mines would have to be opened
CROMBY POWER PLANT X-17
-------
with cleaning equipment to produce the quality
required. Locomotive power and roadbed should be
adequate; car availability could be inadequate.
(b) Transportation Companies
Penn Central Railroad and lateral lines
Baltimore and Ohio Railroad and lateral lines
Western Maryland Railroad
Reading Company
(c) Estimated Increased Coal Consumption
Approximately 540,000 tons/year for next five
years.
Equipment refurbishing required and estimated
labor and material cost.
(a) Inspect coal burners and repair as required.
Inspect and repair mills as required. Labor
and material estimate is $10,000.
(b) Clean and inspect the ash handling system.
Inspect electrostatic precipitator and re-
place wiring as required. Install hopper
unloading rotary valves. Labor and material
estimate is $15,000.
(c) Replace tube shields on superheater tubes.
Labor and material estimate is $20,000.
(d) Clean and inspect combustion control for
coal-firing. Repair as required and adjust.
Labor and material estimate is $5,000.
(e) The increased operations and maintenance cost
for coal firing is estimated to be O.OSC/kWh.
Estimated Outage Time Required
Two weeks
Estimated Lead Time Required
Approximately one month to obtain material, plan
outage, and schedule manpower. Coal inventory is
already on hand for coal firing of Unit No. 1.
CROMBY POWER PLANT X-18
-------
Cromby Unit No. 2 is expected to retire in the
early 1990's. However, this date will be subject
to review as the date approaches. Final retire-
ment date will be determined by the in-service
dates of new capacity additions and the system
capacity requirements at the time.
7. State or Local Laws or Policies
Excluding air pollution controls, no other limi-
tations are known."
CROMBY POWER PLANT X-19
-------
APPENDIX X-6 HOWARD M. DOWN POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the City of Vineland
Electric Utility:
"Original Coal Specifications
Last contract - 1972:
% Moisture 3-5 maximum
% Volatile 22 to 37 maximum
% Asn 8.5 maximum
% Sulfur 1-° maximum
BTU/lb 14,000 minimum
Ash Fusion - Temp. °F 2,550 minimum
% Fe2 03 in Ash 15 maximum
Grindability (Hardgrove Index) 85 maximum
Burning characteristics Light to medium caking
"Maximum and Minimum Values of Coal
Unit No. 10 (Pulverizers)
% Moisture 2.5 - 10
% Volatile 20 - 40
% Fixed Carbon 40 - 70
% Sulfur 1-3.5
% Hydrogen
% Oxygen
% Ash 6.5 - 15
Heat Value - as fired -
BTU/lb 12,000 - 14,000
Ash Softening Temp. °F 2,000 - 2,500
Grindability, Hardgrove 45-80
HOWARD M. DOWN POWER PLANT X-20
-------
"The most recent purchases of coal were from the
Island Creek Coal Sales Company of West Virginia and
the Crown Coal and Coke Company of Pennsylvania.
"Coal must be available under contract consistent
with the public bidding laws of the State of New Jersey.
The Central Railroad (CRR) of New Jersey branch, to
Bridgeton, must be maintained in good condition to
provide a reliable supply route.
"Coal is delivered to the Down Station by the CRR
of New Jersey. They would receive the cars from var-
ious connecting railroads according to the point of
origin.
"Estimated Annual Coal Consumption Unit 10:
80,000 tons.
"The Down Station coal-handling and ash-handling
systems are operable and in satisfactory condition.
The firing equipment on the No. 10 unit is operable.
Storage facilities will accommodate approximately ten
(10) days supply of coal.
"Actual conversion of Unit No. 10 involves very
minimal cost. It will be necessary to stock replace-
ment parts for pulverizers and associated equipment.
This may require a ten thousand dollar ($10,000) in-
vestment.
"Unit No. 10 can be converted to coal-firing with
a few hours of partial outage.
"Coal handling facilities can be changed from
standby to operational status in about one (1) week.
If coal were obtained initially on a spot purchase
basis, it would probably require two (2) months or more
to build an adequate coal inventory.
"No laws or policies other than the Air Pollution
Control limit the utilization of coal in the Down
Station."
HOWARD M. DOWN POWER PLANT X-21
-------
APPENDIX X-7 FOX LAKE POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied
to the Federal Energy Administration by the Interstate
Power Company:
Coal Specifications Compatible with Design Tolerances
Btu/lb
Sultur
Ash
Volatile Matter
Ash Fusion Temp.
Maximum
12,000
-
12.0%
40.0%
2200°F
Minimum
8,000
0.5%
-
25.0%
1900°F
"The main coal supplier is Westmoreland Resources,
Sarpy Creek, Montana. No coal or transportation difficulties
are encountered. BN and CMSTP & P railroads are the prin-
cipal transportation companies.
"Based on 100% maximum capacity coal burning, coal
consumption would average 140,000 tons/yr based on 8,450 Btu/lb
coal.
"Additional equipment (i.e. bunkers, feeders, pulveri-
vers, burners, piping, soot blower, and controls) would have
to be purchased to attain 100% capacity on coal at a cost
of $1,500,000.
"Existing coal storage will handle 75,000 tons which
should be adequate.
"An estimated outage time of one month and a lead time
of eighteen months is needed to attain 100% coal burning
capacity.
"No existing state or local laws other than air pollu-
tion control laws would limit utilization of coal.
FOX LAKE POWER PLANT X-22
-------
APPENDIX X-9 HUDSON POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to the
Federal Energy Administration by the Public Service Electric and
Gas Company:
1. Original Design Coal Specifications:
Hudson No. 1 Unit:
Heating value
% Sulfur
% Ash
% Volatile matter
Grindability
Ash fusion temp.
- 13,000 Btu/lb as received
-3.0 as received
- 10.0 as received
- 36.0 as received
- 55 Hardgrove
- 2100 F
Some variations in the original specifications could be
tolerated if these variations are not too great. Maximum and
minimum limits for the boiler is:
Heating value
% Ash
% Volatile matter
Grindability
Ash fusion temp.
- 12,800 Btu/lb Minimum as received
- 11% Maximum as received
- 22% Minimum as received
- 55 Hardgrove Minimum
- 2300 F Maximum
HUDSON POWER PLANT
X-23
-------
2. Coal Conversion Costs Are:
COAL CONVERSION DATA AND COSTS
Data
Capacity (MW)
Initial service (year)
Last burned coal (year)
Maximum lead time-material (weeks)
Maximum lead time-conversion (weeks)
Boiler outage required (weeks)
Costs
Coal handling equipment
Pulverizers, burners, boilers
Ash and dust disposal
Pipeline penalty
Outage replacement energy
Total conversion costs
Additional Annual Operating Costs
Labor
Material
Ash and dust disposal
Hudson
No. 1
383
1964
1970
40
52
8
$ 3,833,500
451,000
4,868,000
3,350,000
$12,532,500
721,500
360,000
452,000
Total additional annual operating costs $ 1,533,500
HUDSON POWER PLANT
X-24
-------
COAL CONVERSION
EQUIPMENT COSTS AND LEAD TIME
NO. 1 UNIT
HUDSON GENERATING STATION
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(1975)
Equipment
Coal Handling Equipment
Modify coal handling
system
Silo level controls
Crushers
Bulldozer
Total
Feeders, Burners, Boiler
Combustion control
Fuel detectors
Gravimetric feeder
Coal conduits
Coal inlet gates
Cyclone wear blocks
Auxiliary cooling
Water jacket
Sandblast cyclones
Restud cyclones
Cyclone slag tags
Gunnite cyclones
Air dampers
Reheater shields
Deslag furnace
Floor
Slag tap
Cinder trap
Sootblowers
Combustion control
Total
Ash and Dust Disposal
Dust transport system
Ash sluice system
Slag system
Rebuild ash pond & water
treatment
Total
Cost
$3,640,000
21,500
22,000
150,000
$3,833,500
5,500
3,000
26,500
33,000
8,500
24,000
5,000
8,500
6,500
126,000
17,000
9,000
12,500
22,500
1,000
78,500
1,500
2,000
60,500
5,500
$ 451,000
$ 100,000
69,000
99,000
4,868,000
$4,868,000
Conversion
lead time
(weeks)
52
12
12
3
41
31
29
4
17
2
4
2
18
4
2
3
7
2
18
1
1
24
3
32
29
32
52
HUDSON POWER PLANT
X-25
-------
APPENDIX X-9 JONES STREET POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Omaha Public Power
District Company:
Boiler #27 at the Jones Street Power Station was con-
verted from coal to oil/gas in 1972. This was done because
the station could not meet air quality standards and the
cost to install air quality control equipment was prohibi-
tive vis-a-vis the age, available space, and worth of the
plant. Furthermore, it was agreed that no additional vari-
ances would be requested beyond June 1, 1973.
In connection with this conversion, two 1,000,000-
gallon oil tanks were installed in 1972, and two more
(1,600,000-gallon and 1,300,000-gallon) were installed in
1973. These tanks were all placed in the old coal handling
area, and also serve the two gas turbines installed on the
Station. Since that time, much of the coal conveying and
other coal handling equipment has been removed and disposed
of.
The Omaha Public Power District is presently an "inter-
ruptible customer" of Northern Natural Gas Company and has
been for several years. The District has been informed by
Northern Natural Gas that 1976 will be the last year that
gas will be available to fire boilers.
The Jones Street Power Station now consists of two old
boilers and turbines and is used for peaking operations only
as is evidenced by the following 1974 data:
JONES STREET POWER PLANT X-26
-------
BOILER #26 BOILER #27
Year Built 1949 1951
Net Capacity 36 MW 47 MW
Hours of Operation 856 920
% of Year 9.8% 10.5%
Capacity Factor 7.9% 7.4%
Total Oil Consumed 109,986 gallons (both boilers)
Total Gas Consumed 696,000 MCF (both boilers)
1977 Projections:
Total Oil 760,000 gallons #2 oil (18,095 bbls)
Total Gas NONE
To convert one of these two boilers, or both, back to
coal at this stage of plant life is not only economically
infeasible, it borders on the impossible due to the considera-
tions enumerated below.
1. Because of the age and efficiency of the boilers, air
quality standards, including particulate limits, could
not be met without the addition of air quality control
equipment. This equipment would have to be installed
in the former coal storage area, now occupied by fuel
storage tanks. This would necessitate the relocation
of the fuel storage tanks and the establishment of a
new coal storage area.
2. There are no ash settling ponds or similar facilities
at the site. With no means of handling coal pile
runoff or sluicing water used in the ash handling
system, water quality standards could not be met.
3. The Jones Street Power Station is located on the
Missouri River in downtown Omaha and is surrounded by
other commercial facilities. The size of the site is
approximately 16 acres. With no room to expand, the
addition of any major facility, such as a new fuel oil
storage area, coal storage area, or ash settling pond
£B not possible.
4. The deteriorated condition of the remaining coal and
ash handling equipment, and the need to rebuild large
segments of major coal handling systems already removed
would be costly and uneconomical.
JONES STREET POWER PLANT X-27
-------
In conclusion, should the Omaha Public Power District
be directed to convert the Jones Street Station to coal,
serious consideration would have to be given to decommission-
ing the plant rather than embarking on a costly, uneconomical
conversion.
Boiler No. 27 was designed to burn Kansas Bituminous
coal from the mines near Pittsburg, Kansas. The character-
istics are as listed below.
Kind - Kansas Coal, Bituminous
Grindability - 55
Surface Moisture, % - 6
BTU/LB - 11,380
Sulphur, % - 5.24
Ash, % - 16.70
Volatile Matter, % - 33.70
Ash Temperature, °F
Init. Def. - 1894
Liquid - 1955
Slagging Index, R_ - 2.96 (Severe slagging coal)
Fouling Index, Rp - 0.74 (High fouling coal)
The sintering characteristics of the coal have not been
determined as such.
Boiler No. 27 has not burned other types of coal to any
extent. However, it is felt that Hanna, Wyoming coal could
be burned with some reduction in capacity. Kansas coal is
no longer available and to determine the feasibility of
burning other types of coal would require a detailed engi-
neering study which has not been done. Hanna, Wyoming coal
is available at the present time and the characteristics are
listed below.
Kind - Wyoming, Sub-bituminous
Max. Min.
Grindability N.A. N.A.
Moisture, % 13.8 12.0
BTU/LB 10,800 10,000
Sulphur, % 0.95 0.75
Ash, % 13.8 5.3
Volatile Matter, % N.A. N.A.
Ash Temperature, °F
Init. Def. N.A. N.A.
Liquid N.A. N.A.
N.A. - Not Available
JONES STREET POWER PLANT X-28
-------
In order for the Omaha Public Power District to be
capable of burning coal in their Jones Street Station Boiler
#27, it would be necessary to purchase and install, modify,
or repair the following items:
1. Coal Handling System
2—* Cost
A. Purchase Locomotive to move coal $100,000
B. Purchase coal handling scraper 125,000
C. Install R.R. trackage over coal 75,000
scale, track hopper, repair remainder
of RR track
D. Purchase and install track scale 100,000
and scale house
E. Purchase and install shaker house 60,000
and shaker car
F. Purchase and install coal pit, 100,000
vibrating screens, coal conveyor
or vert, lift
G. Purchase and install stocking-out 200,000
conveyor system
H. Purchase and install vertical coal 20,000
lift basement to transfer belt
(w/some salvage material)
I. Purchase and install transfer belt, 30,000
coal sampling and weighing system
J. Purchase and install horizontal 20,000
drag conveyor above bunker
K. Purchase and install 480 volt motor 25,000
control center and wiring for coal
handling
L. Rework offices because of interference 3,000
with coal conveyor
Cost $858,000
2. Storage Facilities for Coal
Cost
A. Purchase land and provide diking $125,000
for control of surface water run-off
B. Process system for run-off water 10,OOP
Cost $135,000
JONES STREET POWER PLANT X-29
-------
3. Ash and Dust Handling System
Cost
A. Purchase and install ash hydrobin, $701,000
recir. system, ash piping, and
ash unloading equipment
B. Purchase and install dry fly ash 105,000
silo, dustless unloader, and dry
unloader
C. Purchase and install dry fly ash 114,000
pneumatic conveyor system
D. Purchase dump truck 10,000
Cost $930,000
4. Additions and Modification to Boiler No. 27 to Burn
Coal
COst
A. Purchase and install 480 volt motor $ 20,000
control center for equipment motors
B. Purchase and install new coal burners 30,000
and coal burner piping
C. Purchase and install new controls 60,000
for coal burning on boiler gauge
board and field installed panels
D. Modify burner deck oil burning 15,000
management control system
E. Relocate oil piping, controls, etc., 5,000
on burner front to accommodate new
coal burners i
Cost $130,000
5. Maintenance of Existing Coal Burning Related Equipment
Cost
A. Repair sluice water pumps and replace $ 12,000
piping
B. Repair ash removal pumps, etc. 5,000
C. Repair boiler ash hopper 5,000
D. Repair clinker grinder 3,000
E. Overhaul coal pulverizers, etc. 5,000
F. Repair soot blowers, soot blower 2,000
steam piping and valves
COSt $ 32,000
JONES STREET POWER PLANT X-30
-------
6. Storage Facilities for Coal
Since the District has used its former coal storage
area for the installation of two (2) oil fired gas turbines,
and four (4) large (2 - 1,000,000, 1 - 1,600,000, and 1 -
1,300,000 gal. each) oil storage tanks that area is no
longer available. In order to store coal at the Jones
Street Power Station, additional land would have to be
purchased, cleared and necessary diking constructed to
contain surface water run-off from the coal pile.
The costs associated to restore coal firing capability
are as follows:
1. Coal Handling System $ 858,000
2. Storage Facilities for Coal 135,000
3. Ash and Dust Handling System 930,000
4. Additions and Modifications 130,000
to Boiler #27 to Burn Coal
5. Maintenance of Existing Coal 32,000
Burning related equipment
Subtotal $2,085,000
6. Engineering Costs (15% of #l-#5) 312,750
7. Overhead and Interest (15% of #l-#6) 359,660
TOTAL RESTORATION COSTS $2,757,410
The estimate of operating and maintenance cost differential
per year associated with the necessary changes are as follows:
1. Maintenance cost differential/year $25,000
2. Operational cost differential/year $60,000
JONES STREET POWER PLANT X-31
-------
APPENDIX X-10 LOVETT POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration (FEA) by the Orange and
Rockland Utilities:
1) Maximum and Minimum values for types of coal
compatible with boilers' design tolerances.
Btu/lb.
% Sulfur
% Ash
% Volatile matter
Ash softening temp.
Btu/lb
% Sulfur
% Ash
% Volatile matter
Ash softening temp.
Lovett #4
Min.
12,000
0
0
30.0
2,150°F
Max.
4.0
15.0
Lovett #5
Min.
12,000
0
0
30.0
2,335°F
Max.
4.0
15.0
LOVETT POWER PLANT
X-32
-------
2) Anticipated acquisition or refurbishing of ash
handling facilities and costs in 1975 dollars.
Water Quality
Ash settling pond refurbish and waste treatment
facilities $1,900,000
Environmental Noise
Sound-proof coal car Shaker Building $ 120,000
3) Lead time to restore coal firing capability:
Settling pond and waste treatment - 1 1/2 years
Sound proof coal car shaker building - 1 year
a. Lead time is not necessary for initial oper-
ation if variance is granted for noise and
water quality standards.
4) Projected capacity factors:
Capacity factors - Unit No. 4 Unit No. 5
1974 actual 909,252 MWH output 1,125,871 MWH output
187 MW x 8,760 202 MW x 8.760
= 0.56 = 0.64
1975 0.46 0.37
1976 0.43 0.30
1977 0.47 0.35
1978 0.50 0.39
1979 0.55 0.45
LOVETT POWER PLANT X-33
-------
APPENDIX X-1T MUSTANG POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied
to the Federal Energy Administration by the Oklahoma Gas
and Electric Company:
"We have not purchased coal for the plant since 1963
when we bought 100 tons. The last purchase prior to that
Was in 1954. Past supplier's were Beribow Coal Company
(1963) and Leavell Coal Company (1954).
"This plant can be supplied only by rail. The only
carriers possible are the Chicago, Rock Island arid Pacific:
railroads.
"We had in 1973 only 1100 tons of coal in stdrage
(1.7 burn days) and the maximum amount of coal we have
ever had is 5900 tons or 3.9 burn days. The maximum
storage capacity is 7800 tons for 5.3 burn days at present
capacity factor of 33%.
"In short, the plant was designed and built to burn
coal on an emergency stahd-by basis and has been operated
in that manner.
Original Coal Specifications
Btu/lb 11,020
% Sulfur 1.1
% Ash 16.4
% Volatile Matter 30.2
% Moisture 5.5
Ash Fusion Temp. 1900-2000°F
"At present rates, the fuel cost will double on this
unit if coal is burned. The estimated cost for equipment
is $7,900,055, for operations and maintenance $731,000
per year, excluding the fuel.
MUSTANG POWER PLANT X-34
-------
APPENDIX X-12 POSSUM POINT POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by Virginia Electric and
Power Company:
The minimum and maximum values of coal compatible with
Vepco power plants design tolerances are as follows:
Btu/lb 11,300* - 14,000
Percent Sulfur 0.5 - 4.0
Percent Ash 2.5 - 20
Percent Volatile 15 - 34
matter
Ash Fusion Tempera- 2,300 - 2,900
ture (F)
* If Btu/lb is below 11,800 and Hardgrove Grindability
is less than 75, there is a possibility of reduction
in capability because of mill capacity.
Below are listed the work required, on Boilers 2 through
4 at Possum Point power plant, to convert to coal firing.
These are estimates and after inspection of the boilers and
associated coal auxiliaries additional work may be required
at additional cost, time, and effort.
Boiler
Burner corner repair (buckets, dampers)
Relocation of side igniters and oil guns
Replace cold end elements on air preheaters
Repair IR-soot blowers
Remove refractory from furnace walls
POSSUM POINT POWER PLANT X-35
-------
Change-out orifices in lower drums
Recalibration of boiler controls
Repairs to electrostatic precipitators
Coal Handling System
Inspection and repair of coal feeders and mills
Ash Handling System
Reinstall dry fly ash handling system
Bottom ash pond is no longer available due to construc-
tion of Unit 5. A small retention pond will have to
be constructed to handle bottom ash until a permanent
pumping system to the fly ash ponds can be constructed.
Coal Storage Equipment
Repair railroad tracks and install 1,500 feet of new
track
Repair coal unloading equipment (car shaker, feeders,
crusher, conveyors and scales)
Obtain locomotive and tractor
The estimated cost to restore coal firing capability
for Possum Point is as follows:
Possum Point 2 $ 35,000
Possum Point 3 $ 55,000
Possum Point 4 $ 88,000
Coal Handling Equipment $179,000
Temporary Bottom Ash Pond $220,000
Total - Possum Point 2-4 $577,000
The estimated annual increase due to conversion to
coal firing using 1975 Estimated Annual Expenses would be:
POSSUM POINT POWER PLANT X-36
-------
Possum Point
Operation $ 45,000
Coal Handling $150,000
Maintenance $190,000
Total - Possum Point 2-4 $405,000
"The estimated outage time required to make necessary
changes and convert the units to coal firing, if no
major problems are encountered or if work beyond that
envisioned has to be done because of inspection findings."
Possum Point 2 3 weeks
Possum Point 3 3 weeks
Possum Point 4 4 weeks
Total time required for Possum Point - 10 weeks
POSSUM POINT POWER PLANT X-37
-------
APPENDIX X-13 RAVENSWOOD POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Consolidated Edison
Company:
"The questions (on the FEA information request) were
answered on the basis that any order to convert to coal
firing would be on a non-emergency basis, and would be
for the long term. No allowance or consideration was
made for an AQCS further than adequate precipitators.
The cost figures used are estimates and should be used
as order of magnitude numbers."
Original coal specifications for Boiler 30 is shown
below:
Boiler 30
HHV, Btu/lb 14,080
Ash,% 7-2
Volatile, % 36-5
Ash fusion temp.,°F 1900-2300
Moisture, % 3-4
Free Carbon,% 52.9
Grindability 63
RAVENSWOOD POWER PLANT X-38
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I
M
o
a
o
s:
M
Ravenswood Unit 30 North
1) Overhaul & remove precipitator
blanks
2) Overhaul bottom ash system
3) Restore fly ash system & silo
4) Overhaul raw coal system
5) Overhaul pulverizers & burners
6) Overhaul controls
Unit 30 South
1) Repair precipitator
2) Same as Unit 30 N
3) Same as Unit 30 N
4) Same as Unit 30 N
5) Same as Unit 30 N &
repair damaged ductwork
6) Same as Unit 30 N
Estimated cost,
$
20,000
25,000
300,000
100,000
100,000
20,000
2,200,000
Incl. in Un. 30 N
Incl. in Un. 30 N
Incl. in Un. 30 N
175,000
Incl. in Un. 30 N
Estimated
lead time
& construction
time
3 wk.
4-6 mo.
4-6 mo.
4-6 mo.
1/2 - 1 yr,
1 mo.
4 mo.
1/2 - 1 yr
Estimated
Plant out
time
1 wk.
1 wk.
1 wk.
None
3 wk.
1 wk.
1 wk.
None
x
i
u>
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"No coal storage (on ground). All coal deliveries by
barge, direct to bunkers. No bottom ash or fly ash disposal
on site.
The differential operation and maintenance cost es-
timates are as follows:
Operation Maintenance Total
Unit 30, $ 299,059 277,863 576,922
RAVENSWOOD POWER PLANT X-40
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APPENDIX X-14 RIDGELAND POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Commonwealth
Edison Company:
(1) Original specification coal for Ridgeland based on
Illinois Seam 6 coal is analyzed as follows:
Moisture, % 15.00
Ash, % 15.00
Carbon, % 52.00
Hydrogen, % 3.85
Sulfur, % 4.65
Oxygen, % 8.70
Nitrogen, % 0.80
Btu/lb 10,000
Ash fusion temp. 2,000
"Performance estimates and criteria shall be based
on the coal specified above. The entire steam
generating and coal burning equipment, however,
shall be able to develop the maximum capacity and
operating efficiency with other Illinois, Indiana,
and Kentucky coals having heating values between
10,000 and 12,500 Btu/lb; ash fusion temperatures
varying between 1950°F and 2300°F and moisture up
to 15%."
(2) Range of characteristics compatible with design
tolerance:
Maximum Minimum
Btu/lb 10,000
Ash, % 15 -
Sulfur, % 4.5 -
Ash sintering strength, 5,000
psi
Ash fusion temperature 2,250
RIDGELAND POWER PLANT X-41
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(3) Identification of facilities to be acquired or
refurbished:
Equipment/facilities Cost, $
Coal unloading equipment - west dock 456,000
- east dock 100,300
Coal moving equipment 10,000
Conveyor belt junction hoppers, 81,000
gates, and belt system
Breaker house 49,000
Ash and slag handling 45,000
Boilers 1 through 6 - refitting 149,200
required for coal firing
Boiler instrument and controls 6,000
Ash handling systems 7,000,000
Coal and ash pile water runoff 3,300,000
control
Air heater and boiler fire side wash 2,500,000
water control facilities
Misc. drain collection, discharge, 1,700,000
and control facilities
Total cost of anticipated acquisi- 15,396,500
tion refurbishing of facilities
(4) Total increase in annual operating and maintenance
construction is estimated at $2,900,000.
- Other Considerations
Increased boiler maintenance can be expected with
coal-firing due to more rapid cyclone tube wear
and due to increased superheater wastage and
failure because of higher furnace temperatures.
This will result in more frequent Scheduled and
Emergency outages. Availability would be expected
to drop about 6%.
RIDGELAND POWER PLANT X-42
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Superheater tube replacement is an unkown factor.
We can expect that the more frequent failures will
require replacement of sections of tube banks
within a couple of years of conversion.
Boilers 1-4 might spend up to $150,000 each.
Boilers 5 and 6 might spend up to $300,000 each.
Manpower problems will include, in addition to
hiring of the 24 men for coal plant and operating:
a) Training of these new men for skilled and
unskilled positions. Former coal plant
people have left Ridgeland. Most of those
remaining at the Station are in other classi-
fications and will not desire returning to
coal plant work even (as some have indicated)
if a promotion is involved.
b) Selecting two men as supervisors for the coal
plant. We may have to go outside the station
and train them to handle our equipment.
c) Possible loss to retirement of operating
people due to the harder work which can be
encountered in handling wet coal, slag and
ash problems, both at the furnace tap or slag
tank and dust hoppers, and control problems
due to tripouts and difficulty of lighting
off the cyclone burners particularly on a
cold boiler. For maintenance and more
frequent outages resulting in harder, dirtier
work, callouts and longer hours.
We have two Shift Engineers who have requested
retirement at age 58 in 1975.
The number and ages of supervisors and
employees of concern are:
Supervisors
Total 33
No. at age 58 or 59 3
No. at age 60 to 64 4
RIDGELAND POWER PLANT X-43
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Employees
Total 179
Skilled
No. at age 58 or 59 13
No. at age 60 to 64 16
Semi-Skilled
No. at age 58 or 59 4
No. at age 60 to 64 2
In arriving at repair costs no consideration was
given to repair of car dumper. This can handle
only the lower height cars up to 100 tons. It
cannot handle tall railroad cars.
(5) A one month outage would be required for each
boiler. An outage of either Boiler 1 or Boiler 2
will decrease the capacity of Unit 1 by approxi-
mately one-half. A similar relationship exists
with respect to Boilers 3 and 4, and Unit 2. The
outage of Boiler 5 will mean the total loss of
capacity of Unit 3. The outage of Boiler 6 will
mean the total loss of capacity of Unit 4. As
discussed on page 3 of cover letter reference no.
2, Units 1 and 2 cannot be out of service at the
same time, and there are substantial constraints
against Units 3 and 4 being out of service simul-
taneously for periods 'as long as a month.
Because of the nature of the boiler rehabilitation
work, the boilers should not be returned to oil
firing after being refitted for coal. Therefore,
the refit work would be scheduled to coincide with
the stockpiling of adequate amounts of coal for
start-up. Such a stockpile cannot be established
until a system for collecting and treating the
coalpile rainfall runoff is installed and made
ready to operate.
(6) The restoration of coal firing capability at
Ridgeland Station is contingent upon two major
construction and reconstruction activities. These
are: 1) the construction of water quality systems
and 2) the restoration of existing coal associated
equipment. The critical path activities are
illustrated in Figure 1. You will note that the
most severe time constraint is imposed by the
RIDGELAND POWER PLANT X-44
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construction of the system to handle the coal and
ash pile runoff. The end date for this activity
is 45 months after start of design. The boiler
conversion activities proceed at the rate of a
boiler per month and the entire conversion is
completed approximately 51 months after initiation.
The estimated time to build an adequate coal
inventory is 100 days. This is based on starting
to build the storage pile before actual coal
burning starts. A coal supply for ninety days is
considered adequate at Ridgeland. The estimated
buildup is accomplished at 2500 tons per day.
This is not a critical path activity.
(7) Identify any state or local laws or policies,
other than air pollution control laws or policies,
that might limit the utilization of coal by the
power plant.
In summary, we cannot verify at this time whether
compliance with all of the regulations cited is
technically feasible (and indeed, such a determina-
tion cannot be finally made until a specific air
pollution control mode is chosen) . What d^s_
certain is that any program of attempted compliance
will strongly impact both the cost and the scheduling
of any coal conversion. These impacts are treated
in sections (4) and (6), above.
RIDGELAND POWER PLANT x_45
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APPENDIX X-l5 RIVERTON POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Potomac Edison
Company.
Riverton power plant's original specification for coal
and the maximum and minimum values for other types of coal
are presented below:
Unit's original specification coal as outlined in
Boiler Proposal:
Btu/lb.
Moisture
Volatile Matter
Fixed Carbon
Ash
Grindability
Btu/lb.
% Sulfur
% Ash
12,000 Ultimate Analysis
8.0% Proximate Analysis
29.0% Proximate Analysis
51.0% Proximate Analysis
12.0% Proximate Analysis
55 Hardgrove Minimum
10,800 minimum.
There is no coal with the 0.2%
sulfur required to meet ambient
requirements.
25% maximum for handling and main-
tenance considerations. There is
no coal with the less than 1% ash
that would be required to meet
emission requirements. This unit
does not have an electrostatic
precipitator, and one would have to
be installed.
RIVERTON POWER PLANT
X-46
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% Volatile and Ash Slagging/Sintering - We have never
encountered difficulty with either of these items
with bituminous coal on this boiler.
Provided below are listed the coal conversion costs and
coal handling equipment requiring maintenance.
Outage
Item Comment Cost Time
Install coal burners, Equipment available. $50,000 6 wks,
etc. Some 2 weeks would be
necessary to plan for
the outage work.
In addition to the above item:
(a) Differential plant manpower cost increase to use coal
instead of oil - $64,000/year.
(b) Some coal firing items were not maintained and will
require additional maintenance after returning to coal.
These include conveyor belting, pulverizers, coal
feeders, etc. They should not provide deterrents to
returning to coal firing.
(c) Water quality regulations may require expenditures, the
amount of which cannot now be determined if the unit is
reconverted to coal firing.
RIDGELAND POWER PLANT X-47
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APPENDIX X-16 VIENNA POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by Delmarva Power and
Light Company:
Unit 8 was designed and constructed to use heavy oil as
the only fuel. No space is available for the installation
of coal bunkers, pulverizers, coal pipes and conveyors. Ex-
tensive boiler modifications would be required and even
then, the effective capacity of the unit would be greatly
reduced because of furnace design limitations. Therefore,
this unit has not been considered as a candidate for conver-
sion to coal.
Tabulated below are the capacities and ages of the
remaining units at the station:
Unit Capacity - MW Installation Date/Age-yrs.
5 17 1947/27
6 17 1948/26
7 40 1951/23
In view of the age of these units, the extensive capi-
tal requirements for coal conversion, their probably future
use for cycling service and considering their small size and
the resultant minimal savings in oil consumption, we do not
believe the expense of conversion to coal is justifiable.
Further, a cooling tower serving Unit 8 has been installed
in the former location of the coal storage pile. It would
be possible to create a new coal pile of reduced size but
this would make the reliability of the station more vulner-
able to interruptions in coal supply caused by strikes,
transport problems, etc. In addition, a coal pile in close
proximity to the Unit 8 cooling tower would have a deleteri-
ous affect on the cooling tower and the water in the tower
with an adverse affect on the reliability of this unit.
VIENNA POWER PLANT X-48
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We believe that these units could be converted to coal
and possibly would not violate the primary air standards.
Improved particulate collection and SC>2 removal would be
required by 1978 to meet the SIP standards. However, there
does not appear to be space available for the installation
of scrubbers.
Conversion Costs
A. Convert to coal and possibly comply with primary
air standards - no SC>2 scrubbing or new particulate
removal equipment.
Conversion of Units 5, 6 & 7 to coal $300,000
B. Differential Annual Operating Costs (50% capacity
factor)
Operating & maintenance (excluding fuel) $ 35,000
Timing of Conversion - no S02 scrubbing, no new precipitators
Unit 5-1 month
Unit 6-6 months
Unit 7-8 months
RIDGELAND POWER PLANT X-49
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APPENDIX X-17 L. D. WRIGHT POWER PLANT
Given for the purpose of completeness, the following
information relative to the fuel conversion was supplied to
the Federal Energy Administration by the Department of
Utilities:
The original coal specifications for the two units were
as follows:
Crawford County, Kansas
Carbon - 49.0%
Ash - 10.0%
Volatie Matter - 34.1%
Sulfur - 3.5%
Moisture - 10.0%
Btu - 12,500/lb
Ash fusing temperature - 1900°F
Presently the coal being fired is from Carbon County,
Wyoming with the following analysis:
Moisture - 14 to 16%
Ash - 6 to 10%
Sulfur - 0.6 to 0.9%
Btu - 9,900 to 10,100/lb
Ash fusion - 2,100° to 2,200°F
Present coal storage area is 65,000 tons. There are no
facilities for unloading coal during winter weather.
L.D. Wright is in the midst of construction a new 91.5
MW addition to the present plant and until this is
completed, an increase in the area available for coal
storage is limited.
In order to handle the increase discharge of ash, a new
ash line will have to be installed, along with additional
ponding to contain the ash. Also, an enlarged coal
crusher will be needed and conveyor modifications.
L. D. WRIGHT POWER PLANT X-50
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With the slagging characteristics of the fuel, addi-
tional soot blowers will have to be installed. A new
loader will need to be purchased to handle additional
coal.
The estimated cost for additional equipment and refur-
bishing is as follows:
Coal crusher and conveyor modifications $ 18,000.00
Increase size of railroad siding 50,000.00
New ash line 20,000.00
Coal loader 70,000.00
Ash pond 15,000.00
Upgrading pulverizers - unknown
$173,000.00
The additional fuel cost at the
present price would be 263,925.00
Extra coal handling cost 25,218.00
Increased operating and maintenance cost 44,306.62
$333,449.62
Starting in April of 1976, the L.D. Wright plant has
a long term contract with the Stansbury Coal Co.,
Denver, Colorado, to purchase its future coal needs.
This amount of coal to be purchased takes into account
that the plant will be 100% coal fired by the end of
1976.
L. D. WRIGHT POWER PLANT X-51
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