V""N\
-
• •'.-
/ V
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
APPENDICES
\- K
PEDCo ENVIRONMENTAL
-------
PEDCo ENVIRONMENTAL
11499 CHESTER ROAD
CINCINNATI. OHIO 45246
(B13) 7S2-470O
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
APPENDICES
A- K
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
BRANCH OFFICES
CHESTEf: TOWERS
Ctsoter
Kanaan City. Mo.
ProfettOlonnl Village
CHapol Mill. M.C.
-------
PEDCo ENVIRONMENTAL
11499 CHESTER ROAD
CINCINNATI, OHIO 45246
(513) 782-47OO
EVALUATION OF THE FEASIBILITY
OF TOTAL CONVERSION TO COAL FIRING
20-PLANT REPORT
APPENDICES
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
BRANCH OFFICES
CHESTED
WERS
Crown Cantor
Kansas City. Mo.
Professional Village
Chapel Hill. N.C.
-------
APPENDIX A
ARTHUR KILL POWER PLANT
ARTHUR KILL POWER PLANT A-l
-------
CONTENTS
Arthur Kill Power Plant Survey Form
Arthur Kill Power Plant Photographs
Page
A-4
A-16
Number
A-l
A-2
A-3
FIGURES
Site Plan Showing Possible Locations of Major
Components for the Sodium Regenerable System
for Boilers 20 and 30 at the Arthur Kill Power
Plant
Site Plan Showing Possible Locations of Major
Components for the Limestone System for Boilers
20 and 30 at the Arthur Kill Power Plant
Site Plan Showing Possible Locations of New
ESP's for Boilers 20 and 30 at the Arthur Kill
Power Plant
Paqe
A-27
A-33
A-37
Number
A-l
A-2
A-3
A-4
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boilers 20 and 30 at the
Arthur Kill Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boilers 20 and
30 at the Arthur Kill Power Plant (1978)
Retrofit Equipment and Facilities for the Sodium
Solution Regenerable System for Boilers 20 and
30 at the Arthur Kill Power Plant
Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boilers
20 and 30 at the Arthur Kill Power Plant
ARTHUR KILL POWER PLANT
Page
A-22
A-24
A-25
A-26
A-2
-------
TABLES (continued)
Number
A-5 Estimated Capital Cost of a Limestone Scrubbing
System for Boilers 20 and 30 at the Arthur Kill
Power Plant (1978) A-28
A-6 Estimated Annual Operating Cost of a Limestone
Scrubbing System for Boilers 20 and 30 at the
Arthur Kill Power Plant (1978) A-30
A-7 Retrofit Equipment and Facilities Required
for the Limestone Scrubbing System for Boilers
20 and 30 at the Arthur Kill Power Plant A-31
A-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boilers 20 and
30 at the Arthur Kill Power Plant A-32
A-9 Estimated Capital Cost of Electrostatic Pre-
cipitators for Boilers 20 and 30 at the Arthur
Kill Power Plant (1978) A-34
A-10 Estimated Annual Operating Cost of Electro-
static Precipitators for Boilers 20 and 30 at
the Arthur Kill Power Plant (1978) A-35
A-ll Electrostatic Precipitator Design Values for
Boilers 20 and 30 at the Arthur Kill Power
Plant A-36
ARTHUR KILL POWER PLANT A-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION;
1 COMPANY NAME: Consolidated Edison Company
2. MAIN OFFICE: 4 Irving Place, N.Y., N.Y. 10003
3. RESPONSIBLE OFFICER: John J. Grob, Jr.
4. POSITION:Chief Nuclear and Emission Control Engineer
5. PLANT NAME: Arthur Kill
6. PLANT LOCATION: Richmond, New York 10314
7. RESPONSIBLE OFFICER AT PLANT LOCATION:
8. POSITION:
9. POWER POOL N.Y.P.P.
DATE INFORMATION GATHERED: June 30, 1976
PARTICIPANTS IN MEETING:
Bertrum D. Moll - Consolidated Edison Company
Demarest Romaine - Consolidated Edison Company
Peter C. Freudenthal - Consolidated Edison Company
John J. Grob - Consolidated Edison Company
Ralph Morgan - Consolidated Edison Company
Ray Werner - U.S. EPA - Region II - Air Branch
Robert N. Ogg - U.S. EPA - Region II - Air Facilities Branch
Richard T. Price - PEDCo Environmental, Inc.
N. David Noe - PEDCo Environmental, Inc.
Thomas C. Ponder - PEDCo Environmental, Inc.
ARTHUR KILL POWER PLANT A-4
-------
B.
EC
G
50
f
f
i
w
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 Oil
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (1975)
2. APPLICABLE PARTICULATE EMISSION
REGULATION
L
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 EMISSIONSa Oil
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR (1975)
4 . APPLICABLE SO- EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
?n
0.06
412
I
Part 22
0.10
0.32
2344
Part 22
0.33
™
0.06
411
I
.3 (c)
0.10
0.32
2339
i Table I
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):
ARTHUR KILL POWER PLANT A-6
-------
D.
EC
G
?0
X
H
tr1
f
i
w
*0
£
z
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:
COALOROIL HATED ^1"™)
(TPH) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (1975)
OIL (GPY) (1975) 10J BBL
11. HEAT RATE BTU/KWHR GAS
COAL (1970)
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
20
7289
33.9
2
B&W
1959
376
bl2
120.2
None
2451.2
Dry
No
518
232
30
5345
39.5
2
CE
1969
535
171.0
None
2445.8
9879
10,267
Dry
No
518
232
Notes: B&W - Bacock & Wilson
CE - Combustion Engineering
-------
3C
G
tr1
f
o
m
I
t-3
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
20
COTT
99/
184.6
246,400
300
25
30
AMST
99. 5/
136.8
270,400
293
25
>
00
Notes:
COTT- Research Cottrell, Inc.
AMST- American Standard, Inc.
-------
50
H
a
G
50
w
50
£
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
<-3
ac
G
f
t-1
i
w
Tl
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
Notes:
i
M
O
-------
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
G. COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a. Spot purchased
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
3. ANALYSIS (1974)
HHV (BTU/LB) 12,000
S (%) 0.3
ASH (%) 15-25
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA (19 )
1. TYPE
2. S CONTENT (%) 0.29
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL) 144,224
I. NATURAL GAS HHV (BTU/FTJ)
J. COST DATA
ELECTRICITY
FUEL: COAL GAS OIL
WATER
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES
STATE PROPERTY TAX
ARTHUR KILL POWER PLANT A-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?
Boiler No.
Yes or No.
20
Yes
30
Yes
2. SYSTEM AVAILABILITY
2.1 COAL HANDLING
a. Is the system still installed? Yes El NoQ
b. Will it operate? H D
c. Of the following items which
need to be replaced: - All need maintenance
Unloading equipment Yes D No D
Stack Reclaimer D d
Bunkers d d
Conveyors d d
Scales d d
Coal Storage Area D D
2.2 FUEL FIRING
a. Is the system still installed? Yes63 No D
b. Will it operate? Need maintenance Kl D
c. Of the following items which
need to be replaced: Need maintenance
Pulverizers or Crushers Yes E No D
Feed Ducts B D
Fans K) d
Controls B d
2.3 GAS CLEANING
a. Is the system still installed? Yesn No Q
b. Will it operate? D D
c. Of the following items which
need to be replaced:
Electrostatic Precipitator YesD No D
Cyclones d d
Fly Ash Handling Equipment D D
Soot Blowers - Air Compressors D d
Wall deslaggers 0 D
ARTHUR KILL POWER PLANT A-12
-------
2.4 ASH HANDLING* Boiler 20
a. Is the system still installed? Yes D Nog]
b. Will it operate? D B
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes D
Ash Pond D B)
* Systems for Boiler 30 need considerable rework.
ARTHUR KILL POWER PLANT A-13
-------
N. 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
Yes
Yes
No Q
No
Yes p No
Yes No
Yes
N° n
Yes
No
Yes p No
Number Type
Yes p No p
Yes p No
ARTHUR KILL POWER PLANT
A- 14
-------
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
5.2 Proposed system Yes Q No
If yes, describe and provide map
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
ARTHUR KILL POWER PLANT ' A-15
-------
Photo No. 1 View from the parking lot facing southeast. The coal
crusher house is shown in the center of the photo. The main office
area of the plant is shown in the left center portion of the phot.
graph.
ARTHUR KILL POWER PLANT
A-16
-------
^^^^V^^^M^B^MOT^W ™^M^-^—^^^B^^^^—^™^——
Photo No. 2 View from the roof of Boiler 20 looking southeast. The
coal storage pile is shown in the bottom left and right sections of
the photo. The switchyard is shown in the center of the photograph
just above the coal conveyors.
Photo No. 3 View from the roof of Boiler 20 facing east. The ESP
and ductwork for Boiler 20 are shown in the bottom left portion of
the photo. The small building just right of center is a pilot plant
for S0? scrubbing.
ARTHUR KILL POWER PLANT
A-17
-------
Photo No. 4 View from the roof of Boiler 20 looking northeast. The
ESP for Boiler 30 is shown left of center. Ductwork from Boilers 20
and 30 is shown leading into the one stack.
Photo No. 5 View from the roof of Boiler 30 facing north. The
bottom-ash pond is shown in the center of the photograph. The
Arthur Kill River is shown in the upper left corner.
•
ARTHUR KILL POWER PLANT
A-18
-------
Photo No. 6 View from the roof of Boiler 30 looking east. The West
Shore Expressway is shown across the center of the photo. The wooded
surroundings and gently rolling terrain are shown in the distance.
Photo No. 7 View from ground level facing north. The I.D. fan for
Boiler 30 is shown in the center of the photograph.
ARTHUR KILL POWER PLANT
A-19
-------
Photo No. 8 View from ground level lookir-._; v*st. .An oil tank
farm is shown in the center of the photo acrcr-.r. the Arthur Kill
River. A portion of the water intake for the pl^t is shown in
the left center of the photograph.
Photo No. 9 View from ground level facing west. A close-up of the
ESP for Boiler 20 is shown in the center of the photograph.
ARTHUR KILL POWER PLANT
A-20
-------
Photo No. 10 View from ground level looking southwest. The conveyor
from the coal pile to the crusher house is shown in the upper left
portion of the photo. The upper right corner shows a section of
Boiler 30's ductwork.
ARTHUR KILL POWER PLANT
A-21
-------
TABLE A-l. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 20 AND 30 AT THE
ARTHUR KILL POWER PLANT (1978)
Direct Costs
A. Soda Ash Preparation
Storage silos $ 81,000
Vibrating feeders 6,000
Storage tanks 31,000
Agitators 27<0°0
Pumps and motors 2'°°P
Total A = $ 147,000
B. SOg Scrubbing
Absorbers $21,718,000
Fans and motors 2,402,000
Pumps and motors 636,000
Reheaters 3,795,000
Soot blowers 2,608,000
Ducting 8,865,000
Valves 768,000
Total B = $40,792,000
C. Purge Treatment
Refrigeration unit $ 618,000
Heat exchangers 93,000
Tanks 105,000
Dryer 31,000
Elevator 14,000
Pumps and motors 447,000
Centrifuge 1,237,000
Crystallizer 1,483,000
Storage silo 81,000
Feeder 6,000
Total C = $ 4,115,000
(continued)
ARTHUR KILL POWER PLANT A-22
-------
Table A-l (continued)
D. Regeneration
Pumps and motors $ 300,000
Evaporators and reboilers 4,779,000
Heat exchangers 626,000
Tanks 72'000
Stripper 147,000
Blower 204,000
Total D = $ 6,128,000
E. Particulate Removal
Venturi scrubber $ 9,534,000
Tanks 271,000
Pumps and motors 1, 593,000
Total E = $ 11,398,000
Total direct costs =A+B+C+D+E=F=$ 62,580,000
Indirect Costs
Interest during construction $ 6,258,000
Field labor and expenses 6,258,000
Contractor's fee and expenses 3,129,000
Engineering 6,258,000
Freight 783,000
Offsite 1,878,000
Taxes °°°
Spares 313,000
Allowance for shakedown 3,129,000
Acid plant 1,952,000
Total indirect costs G = $ 29,958,000
Contingency H = 18,507,000
Total = F + G + H = $111,045,000
Coal conversion costs 10,597,OOP
Grand total $121,642,000
$/kW 133.53
ARTHUR KILL POWER PLANT A-23
-------
TABLE A-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 20 AND 30 AT THE
ARTHUR KILL POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Soda ash
Utilities
Process water
Cooling water
Electricity
Reheat steam
Process steam
Operation Labor
0.76 ton/h
$90/ton
3257 gal/min $0.66/10;; gal
15.3 x 103 gal/min 0.01/103 gal
19,879 kW
144 x 106 Btu/h
212 x 106 Btu/h
33.3 mills/kWh
$1.696/106 Btu
$1.696/106 Btu
Direct labor 4 men/day $10.67/man-hour
Supervision 15% of direct labor
Maintenance
Labor and materials 4% of fixed investment
Supplies 15% of labor and materials
Overhead
Plant
Payroll
Fixed Costs
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed cost
Total cost
50% of operating and maintenance
20% of operating labor
(5.50%)
(0.35%)
(0.30%)
(4.00%)
Z =
21.35% of fixed
investment
(11.20%)
Credits (byproducts)
Sulfuric acid 10.56 tons/h
Na2S04 0.76 ton/h
Total byproduct credits
Fuel credit
Net annual cost
Mills/kWh
$58/ton
$72/ton
269,000
543,000
37,000
2,570,000
950,000
1,400,000
374,000
56,000
4,442,000
666,000
2,769,000
86,000
$ 23,708,000
$ 37,870,000
(2,396,000)
(213,000)
$ (2,609,000)
(20,712,000)
$ 14,549,000
4.90
ARTHUR KILL POWER PLANT
A-24
-------
Table A-3. RETROFIT EQUIPMENT AND FACILITIES
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
FOR BOILERS 20 AND 30 AT THE ARTHUR KILL POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na~CO, storage
Na_CO- preparation
S02 regeneration
Purge treatment
Sulfuric acid plant
8
8
1
1
1
1
1
114 MW capacity unit
Scaled to train size
547 tons (30-day storage)
1520 Ib/hr, Na2C03
10,840 Ib/hr, S02
1520 Ib/hr, Na
86 tons/day,
ARTHUR KILL POWER PLANT
A-25
-------
Table A-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS
20 AND 30 AT THE ARTHUR KILL 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
23 diam x 45 high
43 diam x 43 high
45 high x 15 wide x 40 long
70 x 190
70 x 195
90 x 185
ARTHUR KILL POWER PLANT
A-26
-------
/" >
\ / J
\fc / MH POK) /
A PURGE TREATMENT AND
S02 REGENERATION
B ACID PLANT
C SCRUBBERS
D STORAGE SILO
E SOLUTION TANK
I
N)
Figure A-l. Site plan showing possible locations of major components for the
sodium solution regenerable system for Boilers 20 and 30 at the Arthur Kill power plant.
-------
TABLE A-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 20 AND 30 AT THE ARTHUR
KILL POWER PLANT (1978)
Direct Cost
Limestone Preparation
Conveyors
Storage silo
Ball mills
Pumps and motors
Storage tanks
Total A =
$ 444,000
96,000
707,000
193,000
154,000
$ 1,594,000
B. Scrubbing
Absorbers
Fans and motors
Pumps and motors
Tanks
Reheaters
Soot blowers
Ducting and valves
Total B =
$17,480,000
2,667,000
1,296,000
1,030,000
3,795,000
978,000
8,648,000
$35,894,000
Sludge Disposal
Clarifiers
Vacuum filters
Tanks and mixers
Fixation chemical storage
Pumps and motors
Sludge pond
Mobile equipment
Total C =
$ 329,000
458,000
11,000
32,000
104,000
1,710,000
64,000
$ 2,708,000
(continued)
ARTHUR KILL POWER PLANT
A-28
-------
TABLE A-5 (continued)
D. Particulate Removal
Venturi scrubber $ 9,534,000
Tanks 274,000
Pumps and motors 353,000
Total D = $ 10,161,000
Total direct costs =A+B+C+D=E= $ 50,357,000
F. Indirect Costs
Interest during construction $ 5,036,000
Field overhead 5,036,000
Contractors fee and expenses 2,518,000
Engineering 5,036,000
Freight 629,000
Offsite 1,511,000
Taxes 000
Spares 252,000
Allowance for shakedown 2,518,OOP
Total indirect costs F = $ 22,536,000
Contingency G = 14,579,000
Total =E+F+G= $ 87,472,000
Coal conversion costs 10,597,OOP
Grand total $ 98,069,000
$/kW 107.65
ARTHUR KILL POWER PLANT A-29
-------
TABLE A-6. ESTIMATED ANNUAL OPERATING COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 20 AND 30 AT THE
ARTHUR KILL 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
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed charges
Total cost
Fuel credit
Net annual cost
Mills/kWh
14.7 tons/yr
60.8 tons/yr
$16.81/ton
$ 2.2O/ton
306 gal/min $ 0.66/10J gal
16,406 kW 33.3 mills/kWh
144 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
(5.50%)
(0.35%)
(0.30%)
(4.00%)
(11.20%)
I = 21.35% of fixed
investment
963,000
521,000
47,000
2,121,000
950,000
281,000
42,000
3,499,000
525,000
2,174,000
65,000
7,812,000
$18,675,000
$37,675,000
(20,712,000)
$16,963,000
5.71
ARTHUR KILL POWER PLANT
A-30
-------
Table A-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM
FOR BOILERS 20 AND 30 AT THE ARTHUR KILL POWER PLANT
Module Description
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
Number
Required
1
1
8
Size/Capacity
10,600 tons (30 day storage)
14.7 ton/hr limestone
114 MW unit/s
Scaled to train size
ARTHUR KILL POWER PLANT
A-31
-------
Table A-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM
FOR BOILERS 20 AND 30 AT THE ARTHUR KILL 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 160 long
17 diam x 37 high
58 diam x 20 high
40 x 40
45 high x 15 wide x 32 long
75 diam x 20 high
40 x 40
ARTHUR KILL POWER PLANT
A-32
-------
A SCRUBBERS
B SLURRY TANK
C LIMESTONE SILOS
D BALL MILL BUILDING
E CLARIFIER
F VACUUM FILTER BUILDING
Figure A-2. Site plan showing possible locations of major components for the
limestone system for Boilers 20 and 30 at the Arthur Kill power plant.
-------
TABLE A-9. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 20 AND 30 AT THE ARTHUR KILL POWER
PLANT (1978)
Direct Costs
ESP
Ash handling
Ducting
$ 8,037,00.0
1,553,000
5,427,000
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 1.5% 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
$/kW
$ 15,017,000
$ 1,201,000
1,502,000
901,000
188,000
451,000
225,000
150,000
451,000
$ 5,069,000
4,017,000
$ 24,103,000
10,597,000
$ 34,700,000
38.09
ARTHUR KILL POWER PLANT
A-34
-------
TABLE A-10. ESTIMATED ANNUAL OPERATING COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 20 AND 30 AT THE ARTHUR KILL
POWER PLANT (1978)
Utilities
Electricity
Water
Operating Labor
Direct labor
Supervision
Maintenance
Labor and materials
Supplies
Overhead
Quantity
Unit Cost
1841 kW 33.3 mills/kWh
53,700 x 103 gal/yr $0.01/103 gal
1.0 man/shift
15% of direct labor
$10.67/man-hour
2% of fixed investment
15% of labor and materials
Annual Cost
$ 200,000
1,000
93,000
14,000
482,000
72,000
Plant
Payroll
Trucking
Bottom/fly ash
removal
Fixed Costs
Depreciation
50% of operation and maintenance
20% of operating labor
(5.50%)
Interim replacement (0.35%)
Insurance
Taxes
Capital cost
Total fixed costs
Total cost
Fuel credit
Net annual credit
Mills/kWh
(0.30%)
(4.00%)
(11.20%)
Z = 21.35% of fixed
investment
331,000
21,000
4,615,000
$ 5,146,000
$10,975,000
(20,712,000)
$(9,737,000)
(3.28)
ARTHUR KILL POWER PLANT
A-35
-------
Table A-ll. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILERS 20 AND 30 AT THE ARTHUR KILL POWER PLANT
Design Parameter
Value
20
30
Collection efficiency, %
(Overall)
Specific collecting area,
ftVlOOO acfm
Total collecting area, ft^
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
98.9
207
290,250
4
19 x 98 x!5
98.9
207
323,450
4
4 @ 19 x 104 x 15
ARTHUR KILL POWER PLANT
A-36
-------
Figure A-3. Site plan showing possible locations of new ESP's for Boilers
20 and 30 at the Arthur Kill power plant.
-------
APPENDIX B
ASTORIA POWER PLANT
ASTORIA POWER PLANT B-l
-------
CONTENTS
Astoria Power Plant Survey Form
Astoria Power Plant Photographs
Page
B-4
B-16
Number
B-l
B-2
B-3
FIGURES
Site Plan Showing Possible Location of Major
Components for the Sodium Solution Regenerable
System for Boilers 10, 20, 30, 40, and 50 at
the Astoria Power Plant
Site Plan Showing the Possible Locations of
Major Components for the Limestone System for
Boilers 10, 20, 30, 40, and 50 at the Astoria
Power Plant
Site Plan Showing Possible Locations of New
ESP's for Boilers 10, 20, 30, 40, and 50 at the
Astoria Power Plant
Page
B-25
B-31
B-35
Number
B-l
B-2
B-3
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boilers 10, 20, 30, 40,
and 50 at the Astoria Power Plant (1978)
Page
B-20
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boilers 10, 20,
30, 40, and 50 at the Astoria Power Plant (1978) B-22
Retrofit Equipment and Facilities for the Sodium
Solution Regenerable System for Boilers 10, 20,
30, 40, and 50 at the Astoria Power Plant B-23
ASTORIA POWER PLANT
B-2
-------
TABLES (continued)
Number
B-4 Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boilers
10, 20, 30, 40, and 50 at the Astoria Power
Plant B-24
B-5 Estimated Capital Cost of a Limestone Scrub-
bing System for Boilers 10, 20, 30, 40, and 50
at the Astoria Power Plant (1978) B-26
B-6 Estimated Annual Operating Costs of a Limestone
Scrubbing System for Boilers 10, 20, 30, 40, and
50 at the Astoria Power Plant (1978) B-28
B-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boilers 10,
20, 30, 40 and 50 at the Astoria Power Plant B-29
B-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boilers 10, 20,
30, 40 and 50 at the Astoria Power Plant B-30
B-9 Estimated Capital Cost of Electrostatic
Precipitators for Boilers 10, 20, 30, 40, and
50 at the Astoria Power Plant (1978) B-32
B-10 Estimated Annual Operating Costs of Electro-
static Precipitators for Boilers 10, 20, 30,
40, and 50 at the Astoria Power Plant (1978) B-33
B-ll Electrostatic Precipitator Design Values for
Boilers 10, 20, 30, 40 and 50 at the Astoria
Power Plant B-34
ASTORIA POWER PLANT B-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: Consolidated Edison Company
2. MAIN OFFICE: 4 Irving Place, N.Y. , N.Y. 10003
3. RESPONSIBLE OFFICER: John J. Grob, Jr.
4. POSITION:Chief Nuclear and Emissions Control Engineer
5. PLANT NAME: Astoria
6. PLANT LOCATION: Queens, New York - Woolsey 11105
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Dan Gormley
8. POSITION: Plant Superintendent
9. POWER POOL N.Y. P.P.
DATE INFORMATION GATHERED: June 29, 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.
ASTORIA POWER PLANT
B-4
-------
B.
CD
t-3
O
13
O
5!
w
£
z
03
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 S, SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3 Oil
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR (1975)
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
10
0.06
210
I
0.10
0.31
1154
0.33
20
0.06
141
I
0.10
0.31
111
,___„_ 'D=i>-+-
0.33
TO
0.06
249
I
227.3 (c)
0.10
0.31
1366
225 Table
0.33
AH
0.06
353
I
0.10
0.31
1939
0.33
t;n
0.06
476
I
0.10
0.31
2614
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):
ASTORIA POWER PLANT B-6
-------
en
•-a
O
O
3
W
50
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 *
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT
8 . GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTION:
COAL OR OIL RATED S£L JZ/S
MAXIMUM CONTINUOUS
Rated Gas (Mft3/HR)
10. ACTUAL FUEL CONSUMPTION
nsq.. (1975) 106 ft3
OIL (19 75) 1013 BBL
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
10
8007
56.5
1A & IB
B & W
1953
165
274
64
1676
559.3
1250
11,396
Dry
No
315
164
20
5885
33.8
2A & 2B
B & W
1954
165
274
64
1676
479.7
841.9
11,040
Dry
No
315
164
•*n
4409
29.4
3A & 3B
B & .W
1958
354
549 .
130.4
3362
304.3
1479.6
10.316
Dry
No
315
164
40
5513
38.0
4A & 4B
CE
1961
362
None
134.2
Nonp
87.3
?i nn.4
10, R37
Dry
No
31 5
164
-Rn
7677
55.8
5A & 5B
CE'
1961
365
None
134.2
Nop<=
73.3
9R71 7
i n, ifii
Drv
No
-n R
164
CD
I
Notes:
* B & W - Babcock & Wilcox
CE - Combustion Engineering
-------
to
i-3
O
13
i
M
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
10
West
q?/
2flfi.fi
48,360
300
20
West
Q7/
9ftfi.fi
48,360
300
30
Cott
9V
1 S4.fi
246,400
300
40
Cott
qq/
iq? n
246,400
30 n
50
Cott
qq/
1 q? n
246,400
300
CO
I
CO
Notes:* West - Western Precipitation Division
Cott - Research Cottrell, Inc.
-------
CO
>-3
O
»
M
>
*T3
O
s
M
£
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
10
710.000
300
60
20
710.000
300
59
30
1.400.000
300
59
40
1.400rOOO
300
59
50
i.400rnnn
300
59
to
vo
a) Identify source of values (test or estimate)
Notes:
-------
t-3
O
i
w
E.
I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
Notes:
f
>
2
w
-------
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
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 (1975)
1. TYPE
2. S CONTENT (%)
0.28
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL) 142,788
I.
J,
NATURAL GAS HHV (BTU/FT3)
COST DATA
ELECTRICITY
1025
FUEL: COAL
GAS
OIL
WATER
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES (NQ Sales Tax)
STATE PROPERTY TAX
ASTORIA POWER PLANT
B-ll
-------
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.
10
Yes
20
Yes
30
Yes
40
Yes
50
Yes
2. SYSTEM AVAILABILITY
2.1
2.2
2.3
COAL HANDLING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced/repaired:
Unloading equipment
Stack Reclaimer (Barge)
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/repaired:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
GAS CLEANING
a. Is the system still installed?
b. Will it operate?
c. Of the following items which
need to be replaced/repaired:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggnrs
YesS
B
Yes
D
E
H
B
D
Yes0
B
Yesg]
a
a
YesQ
D
NoQ
D
No D
n
D
D
a
NoD
D
NoD
a
a
a
NO a
a
Yes0
a
H
a
s
No D
D
D
D
D
ASTORIA POWER PLANT
B-12
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes D NoD
b. Will it operate? D D
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes D NoD
Ash Pond D D
ASTORIA POWER PLANT B_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? Yes
2.1 Storacje 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 _
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
ASTORIA POWER PLANT •
Yes
Yes
No
No D
No
No
N° n
N° n
Yes Q No D
Number Type
Yes D No D
Yes
No
B-14
-------
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
5.2 Proposed system Yes d] No
If yes, describe and provide map
Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent IZZZZ
- Static
(2) Suspended particulate
- Intermittent
- Static
ASTORIA POWER PLANT B-15
-------
Photo no. 1 View from ground level facing north. Ductwork
and twin stacks for Boilers 30, 40, 50, and 60 are shown
from left to right.
Photo No. 2 View from the boiler house roof looking southwest,
The coal unloading tower is shown in the right half of the
photo. The East River is shown in the upper portion of the
photograph.
ASTORIA POWER PLANT
B-16
-------
Photo No. 3 View from the unloading dock facing south. The
gantry crane is shown in the upper right hand corner of the
photo. The bridge in the bottom right corner connects Que<
and Manhattan.
Photo No. 4 View from the boiler house roof looking west.
The coal conveyor leading from the docking facility to the
plant is shown. The water (river) pumping station is shown
in the bottom right corner of the photograph.
ASTORIA POWER PLANT
B-17
-------
Photo No. 5 View from the barge unloading dock facing north,
Coal conveyor A is shown in the upper right portion of the
photo. A neighboring plant is shown in the left center of
the photograph.
Photo No. 6 View from the boiler house roof looking north-
west. The surrounding city area on the west bank of the
East River is shown in the upper left corner of the photo-
graph.
ASTORIA POWER PLANT
B-18
-------
Photo No. 7 View from ground level facing south. The
west portion of the plant is shown in the bottom left
corner of the photo. The plant's ash silos are shown in
the bottom center of the photograph.
Photo No. 8 View from the coal unloading area looking north.
Beneath the floor planks shown in the bottom right hand corner
is the water screen well area.
ASTORIA POWER PLANT
B-19
-------
TABLE B-l. ESTIMATED CAPITAL COST OF A SODIUM SOLUTION
REGENERABLE SYSTEM FOR BOILERS 10, 20, 30, 40, AND 50 AT
THE ASTORIA POWER PLANT (1978)
Direct Costs
Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
Total A =
135,000
6,000
40,000
26,000
2,000
209,000
B. SO2 Scrubbing
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
Total B =
$41,034,000
4,538,000
1,201,000
7,172,000
5,215,000
17,283,000
1,458,000
$77,901,000
C. Purge Treatment
Refrigeration unit
Heat exchangers
Tanks
Dryer
Elevator
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
Total C =
(continued)
ASTORIA POWER PLANT
$ 1,167,000
175,000
181,000
39,000
15,000
785,000
2,335,000
2,802,000
135,000
6,000
$ 7,640,000
B-20
-------
TABLE B-l (continued)
Regeneration
Pumps and motors $ 445,000
Evaporators and reboilers 8,599,000
Heat exchangers 1,132,000
Tanks 107,000
Stripper 196,000
Blower 368,000
Total D = $ 10,847,000
E. Particulate Removal
Venturi scrubber $ 18,015,000
Tanks 523,000
Pumps and motors 2,776,000
Total E = $ 21,314,000
Total direct costs = A + B + C + D + E = F = $117,911,000
Indirect Costs
Interest during construction $ 11,791,000
Field labor and expenses 11,791,000
Contractor's fee and expenses 5,896,000
Engineering 11,791,000
Freight 1,769,000
Offsite 3,537,000
Taxes 000
Spares 590,000
Allowance for shakedown 5,896,000
Acid plant 3,126,000
Total indirect costs G = $ 56,187,000
Contingency H = 34,820,000
Total = F + G + H = $208,918,000
Coal conversion costs 15,546,000
Grand total $224,464,000
$/kW 159.08
ASTORIA POWER PLANT B-21
-------
TABLE B-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 10, 20, 30
40, AND 50 AT THE ASTORIA POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Soda ash
1.38 tons/h
$90.36/ton
462,000
Utilities
Process water
Cooling water
Electricity
Reheat steam
Process steam
Operation Labor
Direct labor
Supervision
Maintenance
6003 gal/min $0.66/10 gal
27.9 x 103 gal/min 0.01/10J gal
37,359 kW
272 x 106 Btu/h
384 x 10b Btu/h
33.3 mills/kWh
$1.696/106 Btu
$1.696/106 Btu
8 men/day $10.67/man-hour
15% of direct labor
Labor and materials 4% of fixed investment
Supplies 15% of labor and materials
Overhead
Plant
Payroll
Fixed Costs
50% of operating and maintenance
20% of operating labor
Depreciation
(5.00%)
Interim replacement (0.35%)
Insurance (0.30%)
Taxes (4.00%)
, I = 20.85% of fixed
investment
Capital cost
Total fixed cost
Total cost
(11.20%)
Credits (byproducts)
Sulfuric acid
Na2S04
19.1 tons/h
1.38 tons/h
$58.41/ton
$71.63/ton
Total byproduct credits
Fuel credit
Net annual cost
Mills/kWh
879,000
64,000
4,591,000
1,706,000
2,405,000
748,000
112,000
8,357,000
1,254,000
5,236,000
172,000
$43,559,000
$69,545,000
(4,117,000)
(366,000)
$(4,483,000)
(40,233,000)
$24,829,000
4.77
ASTORIA POWER PLANT
B-22
-------
Table B-3. RETROFIT EQUIPMENT AND FACILITIES FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS 10,
20, 30, 40, AND 50 AT THE ASTORIA POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na-CO- storage
Na2CO3 preparation
SO- regeneration
Purge treatment
Sulfuric acid plant
16
16
1
1
1
1
1
94 MW capacity unit
Scaled to train size
995 tons (30-day storage)
2,760 Ib/hr, Na2C03
26,220 Ib/hr, S02
2,760 Ib/hr, Na2SO
153 tons/day, H_SO
ASTORIA POWER PLANT
B-23
-------
Table B-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS 10, 20,
30, 40, AND 50 AT THE ASTORIA 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
16
1
1
1
27 diam x 54 high
50 diam x 50 high
45 high x 15 wide x 37 long
90 x 230
85 x 210
100 x 205
ASTORIA POWER PLANT
B-24
-------
•-3
O
o
a
w
z
1-3
CD
NJ
Ul
EAST RIVER
OO OO OO OO OO
10 20 30 40 50
DUCTING
TRANSFORMERS
OO
60
PURGE
TREATMENT
AND
soz
REGENERATION
ACID
PLANT
SCRUBBERS
O O SOLUTION TANKS
O
STORAGE SILO
STORAGE AREA
1 GATE
I HOUSE
OIL TANK
O
TANKS
O
O
TANK
O
O
Figure B-l. Site plan showing possible location of major components
for the sodium solution regenerable system for Boilers 10, 20, 30, 40, and 50 at the
Astoria power plant.
-------
TABLE B-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 10, 20, 30, 40, AND 50
AT THE ASTORIA POWER PLANT (1978)
Direct Cost
A. Limestone Preparation
Conveyors $ 513,000
Storage silo 135,000
Ball mills 836,000
Pumps and motors 327,000
Storage tanks 312,000
(continued)
ASTORIA POWER PLANT
Total A = $ 2,123,000
B. Scrubbing
Absorbers $33,027,000
Fans and motors 5,040,000
Pumps and motors 2,587,000
Tanks , 2,030,000
Reheaters 7,172,000
Soot blowers 2,119,000
Ducting and valves 17,007,000
Total B = $68,982,000
Sludge Disposal
Clarifiers $ 443,000
Vacuum filters 526,000
Tanks and mixers 14,000
Fixation chemical storage 45,000
Pumps and motors 174,000
Sludge pond 2,538,000
Mobile equipment 64,000
Total C = $ 3,804,000
B-26
-------
TABLE B-5 (continued)
D. Particulate Removal
Venturi scrubber $ 18,015,000
Tanks 549,000
Pumps and motors 744,000
Total D = $ 19,308,000
Total direct costs =A+B+C+D=E= $ 94,217,000
F. Indirect Costs
Interest during construction $ 9,422,000
Field overhead 9,422,000
Contractor's fee and expenses 4,711,000
Engineering 9,422,000
Freight 1,413,000
Offsite 2,827,000
Taxes 000
Spares 471,000
Allowance for shakedown 4,711,000
Total indirect costs F = $ 42,399,000
Contingency G = 27,323,000
Total = E + F+ G = $163,939,000
Coal conversion costs 15,546,000
Grand total $179,485,000
$/kW 127.20
ASTORIA POWER PLANT B-27
-------
TABLE B-6. ESTIMATED ANNUAL OPERATING COSTS OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILERS 10, 20, 30, 40, AND 50 AT THE
ASTORIA 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
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed charges
Total cost
Fuel credit
Net annual cost
Mills/kWh
26.6 tons/yr
110 tons/yr
$16.81/ton
$2.20/ton
578 gal/min $0.66/10 gal
30,763 kW 33.3 mills/kWh
272 x 106 Btu/h $1.696/106 Btu
6 men/day $10.47/man-hour
15% of direct labor
4% of fixed investment
15% of labor and material
50% of operation and maintenance
20% of operating labor
(5.00%)
(0.35%),
(0.30%)
(4.00%)
(11.20%)
E = 20.85% of fixed
investment
$ 1,655,000
895,000
85,000
3,781,000
1,706,000
560,000
84,000
6,557,000
984,000
4,093,000
129,000
13,422,000
$ 34,181,000
$ 68,132,000
(40,233,000)
$ 27,899,000
5.36
ASTORIA POWER PLANT
B-28
-------
Table B-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM
FOR BOILERS 10, 20, 30, 40 AND 50
AT THE ASTORIA POWER PLANT
Module Description
Number
Required
Size/Capacity
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
1
1
16
15
19,150 tons (30 day storage)
26.6 ton/hr limestone
88 MW unit/s
Scaled to train size
ASTORIA POWER PLANT
B-29
-------
Table B-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM
FOR BOILERS 10, 20, 30, 40 AND 50
AT THE ASTORIA 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
16
2
1
115 wide x 240 long
20 diam x 45 high
80 diam x 20 high
40 x 40
45 high x 15 wide x 30 long
100 diam x 20 high
40 x 40
ASTORIA POWER PLANT
B-30
-------
13
EAST RIVER
UNLOADING DOCK
GANTRY
CRANE
n
ASH SILOS
SCREENHELL AREA
PARKING AREA
n
BOILER HOUSE
OO OO OO OO OO
10 20 30 40 50
DUCTING
,o
o.
TRANSFORMERS
S 88 S S S RQSCRUBBERS
oooo oooo
STORAGE AREA
[GATE
IHOUSE
OIL TANK
^
o
TAN
O
TANKS
O
1 VACUUM FILTER BLDG.
2 CLARIFIER
3 LIMESTONE STORAGE
4 BALL MILL BLDG.
5 STORAGE SILOS
6 SLURRY TANK
Figure B-2. Site plan showing the possible locations of major components for
the limestone system for Boilers 10, 20, 30, 40, and 50 at the
Astoria power plant.
-------
TABLE B-9. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 10, 20, 30, 40, AND 50 AT THE
ASTORIA POWER PLANT (1978)
Direct Costs
ESP $ 15,233,000
Ash handling 2,946,000
Ducting 8,564,000
Total direct costs $ 26,743.^000
Indirect Costs
Interest during construction 8% of direct costs $ 2,139,000
Contractor's fee 10% of direct costs 2,674,000
Engineering 6% of direct costs 1,.605,,000
Freight 1.25% of direct costs 334,000
Offsite 3% of direct costs 802,000
Taxes 0.0% of direct costs 0,00,000
Spares 1% of direct costs 267,000
Allowance for shakedown 3% of direct costs 802,000
Total indirect costs $ 8,623,000
Contingency 7,073,000
Total $ 42,439,000
Coal conversion costs 15,546,000
Grand total $ 57 ,,985,00,0
$/kW 41.09.
ASTORIA POWER PLANT B-32
-------
TABLE B-10. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 10, 20, 30, 40, AND 50 AT THE
ASTORIA POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 3489 kW 33.3 mills/kWh $ 428,000
Water 47,860 x 103 gal/yr $0.01/103 gal 1,000
Operating Labor
Direct labor 2.5 men/shift $10.67/man-hour 234,000
Supervision 15% of direct labor 35,000
Maintenance
Labor and materials 2% of fixed investment 849,000
Supplies 15% of labor and materials 127,000
Overhead
Plant 50% of operation and maintenance 623,000
Payroll 20% of operating labor 54,000
Trucking
Bottom/fly ash 5,422,000
removal
Fixed Costs
Depreciation (5.00%)
Interim replacement (0.35%), Z = 20.85% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed costs $ 8,849,000
Total cost $ 16,622,000
Fuel credit (40,233,000)
Net annual credit $(23,611,000)
Mills/kWh (4.54)
ASTORIA POWER PLANT
-------
o
»
H
o
s:
Table B-ll. ELECTROSTATIC PRECIPITATOR DESIGN VALUES FOR
BOILERS 10, 20, 30, 40 AND 50 AT THE ASTORIA POWER PLANT
Design parameter
Collection efficiency, %
(Overall)
Specific collecting area,
ftVlOOO acfm
2
Total collecting area, ft
Superficial velocity, fps
Overall ESP dimensions
(height x width x depth) ,
ft, excluding hopper
dimensions
Value
10
98.9
206
146,250
4
2<§
19x98x15
20
98.9
206
146,250
4
2@
19x98x15
30
98.9
207
290,250
4
4@
19x98x15
40
98.9
207
290,250
4
4@
19x98x15
50
98.9
207
290,250
4
4@
19x98x15
CD
u>
*>.
-------
EAST RIVER
V
o
03
u>
Ul
=E=~U~NuOADING DOCK'
00
C
ASH SILOS
SCREENWELL AREA
PARKING AREA
BOILER HOUSE
OO OO OO OO OO
10 20 30 40 50
DUCTING
TRANSFORMERS
60
NEW
/
'S^ -
r~ -7— ™j— "I
STORAGE AREA
JGATE
HOUSE
OIL TANK
o
o
TANK
O
TANKS
Figure B-3. Site plan showing possible locations of new ESP's for Boilers
10, 20, 30, 40, and 50 at the Astoria power plant.
-------
APPENDIX C
E. F. BARRETT POWER PLANT
E. F. BARRETT POWER PLANT C-l
-------
CONTENTS
E. F. Barrett Power Plant Survey Form
E. F. Barrett Power Plant Photographs
Page
C-2
C-16
Number
C-l
C-2
C-3
FIGURES
Site Plan Showing Possible Location of Major
Components for the Sodium Solution Regenerable
System for Boiler 10 at the E. F. Barrett
Power Plant
Site Plan Showing the Possible Locations of
Major Components for the Limestone System for
Boiler 10 at the E. F. Barrett Power Plant
Site Plan Showing the Possible Locations of
New ESP's for Boiler 10 at the E. F. Barrett
Power Plant
Page
C-26
C-32
C-36
Number
C-l
C-2
C-3
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boiler 10 at the E. F.
Barrett Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boiler 10 at
the E. F. Barrett Power Plant (1978)
Page
C-21
C-23
Retrofit Equipment and Facilities for the Sodium
Solution Regenerable System for Boiler 10 at the
E. F. Barrett Power Plant C-24
E. F. BARRETT POWER PLANT
C-2
-------
TABLES (continued)
Number Page
C-4 Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boiler
10 at the E. F. Barrett Power Plant C-25
C-5 Estimated Capital Cost of a Limestone Scrubbing
System for Boiler 10 at the E. F. Barrett Power
Plant (1978) C-27
C-6 Estimated Annual Operating Costs of a Limestone
Scrubbing System for Boiler 10 at the E. F.
Barrett Power Plant (1978) C-29
C-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boiler 10
at the E. F. Barrett Power Plant C-30
C-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boiler 10 at the
E. F. Barrett Power Plant C-31
C-9 Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 10 at the E. F. Barrett
Power Plant (1978) C-33
C-10 Estimated Annual Operating Costs of an Electro-
static Precipitator for Boiler 10 at the E. F.
Barrett Power Plant (1978) C-34
C-ll Electrostatic Precipitator Design Values for
Boiler 10 at the E. F. Barrett Power Plant C-35
E. F. BARRETT POWER PLANT C-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION:
Long Island Lighting Company
, , _ . _, Hicksville,
175 East Old Country Rd.,New York
(FPC Form 67) H. K. Branch
Manager, Operations Analysis
1. COMPANY NAME:
2. MAIN OFFICE:
3. RESPONSIBLE OFFICER:
4. POSITION:
5. PLANT NAME:
6. PLANT LOCATION:
7. RESPONSIBLE OFFICER AT PLANT LOCATION:
8. POSITION: Plant Manager
9. POWER POOL New York Power Pool
E. F. Barrett Station, Unit No. 1
Island Park, Nassau County,
K. R. Abrams
DATE INFORMATION GATHERED: July 2, 1976
PARTICIPANTS IN MEETING:
N. D. Noe
T. C. Ponder, Jr.
R. L. Hearn
J. J. O'Brien
R. V. Close
R. Werner
F. W. Lipfert
H. Cowherd
J. F. Cox
B. K. Kelly
J. J. Crowley
D. F. Josberger
K. R. Abrams
J. Peck
PEDCo Environmental, Inc.
PEDCc Environmental, Inc.
PEDCo Environmental, Inc.
NYSDEC
Nassau County - Dept. of Health
U. S. EPA - Region II
Long Island Lighting Co.
Long Island Lighting Co.
Long Island Lighting Co.
Long Island Lighting Co.
Long Island Lighting Co.
Long Island Lighting Co.
Long Island Lighting Co.
Long Island Lighting Co.
E. F. BARRETT POWER PLANT
C-4
-------
B.
03
>
50
i
w
f
1-3
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU oil
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
LB/MM BTU oil
LB/HR (FULL LOAD)
TONS/YEAR ( 1975)
4 . APPLICABLE SO2 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
% sulfur in fuel (oil)
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
10
0.010
0.003
17
43
6 NYCRR
Part 227.:
0.1 (for a]
20
Same
0.33 E
566 E
1417 E
Oil
6 NYCRR
Part 225
0.41
0.37
Same
(c)
1 fuels)
Gas
6 NYCRR
Part 227
0.40
Same
n
i
Ul
a) Identify whether results are from stack tests or estimates
-------
SITE DATA
1. U.T.M. COORDINATES 4496830 N, 614390 E
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 11'-0"
3. SOIL DATA: BEARING VALUE 1 KP/ft2
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) 162 ft
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE); None
E. F. BARRETT POWER PLANT
C-6
-------
D.
DO
>
50
»
W
i
w
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (1975)a
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:
COAL OR OIL RATED
(TPH-) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (19 75)
OIL (GPY) (19 75)
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
10
Base Load
7496
61
1
CE
1956
20 years
185
200
Oil
12579
13604
None
6.0 x 107
9808
10130
DRY .
No
250
192
._ -
o
i
-o
N
Island Light estimated that the capacity factor for coal firing is 60%
-------
w
CD
W
o
33
W
IT1
H
b
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
Buell
MCTA
83
(a)
Buell
Elect.
89.4
fa)
4
42,300
281
25
(~j Notes:
i
00
a depends on fuel burned.
t> These data (16-20) pertain to previous operation on coal,
not present operation on oil.
-------
oa
13
i
M
f
t-3
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
10
518,000*
281*
N/A
N/A
9x23
42
Attached
n
i
VO
a) Identify source of values (test or estimate)
Notes: * Based on rating of 150 MW (coal firing)
-------
M
to
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
10
22.7
18.75
Notes:
i
w
f
^3
n
i
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) 20
H
2. YEARS STORAGE (ASH ONLY) 2
3. DISTANCE FROM STACK (FT.) 2,000
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT YES
COAL DATA
COAL SEAM, MINE, MINE LOCATION
a. N/A
b.
c.
d.
QUANTITY USED BY SEAM AND/OR MINE
a. N/A
b.
c .
d.
ANALYSIS (19 )
HHV (BTU/LB) N/A
S (%)
ASH (%)
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
FUEL OIL DATA (19 79
1. TYPE
2. S CONTENT (%)
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL)
No. 6 Residual
0.37
0.05
0.904
142,696
I. NATURAL GAS HHV (BTU/FT3) 1026
J. COST DATA
ELECTRICITY
FUEL: COAL GAS OIL
~~ (jSl .114/
WATER lst-15,000 gal.@$1.274/1,OOP gal.,next 45,000 gal. IQQQ qal.
Above 45,000 gal.@$.538/1,OOP gal. Total water used;4/76-5/76;53,910gal
TAXES ON A.P.C. EQUIPMENT: STATE SALES
PROPERTY TAX Tax Rate/Book Value - .084
E. F. BARRETT POWER PLANT C-ll
-------
M,
SERVICE
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?
ADDITIONAL INFORMATION
F.E.A. LETTER
OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
13.7 MVA
8-9 MW
4 KV
Boiler No.
Yes or No.
10
Yes
I
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
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
* All require major repairs
E. F. BARRETT POWER PLANT
Yes
YesE
YesQ
D
D
D
YesQ
D
D
D
a
NO a
a
Yes D
a
a
£
D
E
No £3
a
a
n
o
n
NoD
D
n
NO
-B
NO
K)
H
0
K).
G-12
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes D No 0
b. Will it operate? D Q
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes 0 NoD
Ash Pond D 0
E. F. BARRETT POWER PLANT C-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 LOU
SULFUR FUELS? Yes jjf
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days) 90,000 bbls storage tanks
2.2 Bunkers available for low sulfur coal
storage?
2.3 Handling facilities available for low
sulfur fuels
If yes, describe
Yes
No
No
Yes || No fx|
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)?1
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)
Meteorological instrumentation*
If yes, describe
Yes
Yes
Yes
Number
3
No Lx]
No
No
Type
Philips
c. Is the monitoring data available?
d. Is the monitoring data reduced and
analyzed?
e. Provide map of monitoring locations
* Proposed to NYSDEC; not now in operation
E. F. BARRETT POWER PLANT
Yes [xj
Yes
No
No
C-14
-------
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
5.2 Proposed system Yes P] No [x~
If yes, describe and provide map
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
(2) Suspended particulate
- Intermittent
- Static
E. F. BARRETT POWER PLANT C-15
-------
Photo Ifo. 1 View from the roof of Boiler Ho. 10 facing
southwest showing a spur of the Long Island Railroad and
the shaker house. A former fly ash disposal area, now
designated wetlands, is shown to the left of the oil
storage tanks. Hog Island channel is shown in the background.
Photo Ho. 2 View from the roof of Boiler No. 10 facing west
showing the coal conveyors and crusher house. Five fuel
oil tanks are shown in the background.
E. F. BARRETT POWER PLANT
C-16
-------
Photo No. 3 - View from the roof of Boiler No. 10 facing
northwest showing Gulf's oil storage facilities. A portion
of the plant's water intake channel is shown in the bottom
right hand corner.
Photo No. 4 - View from the roof of Boiler i
-------
Photo Ho. 5 View from the roof of Boiler No. 20 facing
northeast showing the fly ash disposal area beyond the
channel. The construction area for a proposed gas turbine
installation is shown in the right foreground.
Photo No. 6 View from the roof of Boiler No. 20 facing
southeast showing the railroad siding and the adjacent
residential community.
E. F. BARRETT POWER PLANT
C-18
-------
Photo Ho. 7 - View from the roof of Boiler No. 20 facing
south shows the area available for control equipment.
Stack No. 1 and Stack No. 2 are shown on the right and
left, respectively.
Photo No. 8 - View from the southeast corner of the plant
looking west showing stack No. 1 on the left and
stack No. 2 on the right. The ESP and induced draft
fans on Boiler 10 are shcr-i* with lead-in ducts
connecting stack No. 1.
E. F. BARRETT POWER PLANT
C-19
-------
Photo No. 9 • View from the southwest corner of the plant
looking north. The ESP and lead-in ducts from Boiler
No. 10 to Stack No. 1 are shown at the right.
Photo No. 10 - View from the southwest corner of the plant
looking east showing the area available for control
equipment. Stack No. 1 is shown on the left and Stack
No. 2 is shown in the center.
E. F. BARRETT POWER PLANT
C-20
-------
TABLE C-l. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 10 AT THE E.F.
BARRETT POWER PLANT (1978)
Direct Costs
A. Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
B. SOp 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
Total A =
Total B =
Total C =
$ 30,000
6,000
17,000
26,000
2,000
$ 81,000
$3,879,000
429,000
114,000
678,000
326,000
726,000
202,000
$6,354,000
$ 110,000
17,000
29,000
22,000
15,000
100,000
221,000
265,000
30,000
6,000
$ 815,000
(continued)
E. F. BARRETT POWER PLANT
C-21
-------
TABLE C-l (continued)
D. Regeneration
Pumps and motors $ 149,000
Evaporators and reboilers . 1,049,000
Heat exchangers 135,000
Tanks 26,000
Stripper 71,000
Blower 43,000
Total D = $ 1,473,000
Particulate Removal
Venturi scrubber $ 1,704,000
Tanks 41,000
Pumps and motors 114,000
Total E = $ 1,859,000
Total direct costs = A + B + C + D + E = F = $10,582,000
Indirect Costs
Interest during construction $ 1,058,000
Field labor and expenses 1,058,000
Contractor's fee and expenses 529,000
Engineering 1,058,000
Freight 133,000
Offsite 317,000
Taxes 000
Spares 53,000
Allowance for shakedown 529,000
Acid plant 918,000
Total indirect costs G = $ 5,653,000
Contingency H = 3,247,000
Total = F + G + H = $19,482,000
Coal conversion costs 12,203,000
Grand total $31,685,000
$/kW 211.23
E. F. BARRETT POWER PLANT C-22
-------
TABLE C-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 10 AT THE
E.F. BARRETT POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Soda Ash
Utilities
Process water
Cooling water
Electricity
Reheat steam
Process steam
Operation Labor
Direct labor
Supervision
Maintenance
0.16 ton/h
810.3 gal/min
$83.75/ton
$1.17/10, gal
W .1. W • ** ^J W* .h/All^** T^r^rf^v^ ^ •—• —
3.2 x 103 gal/min $0.01/10J gal
33.3 mills/kWh
1.685/106 Btu
1.575/106 Btu
3655 kW
25.7 x 10b Btu/h
45.8 x 106 Btu/h
2 men/day
15% of direct labor
$10.67/man-hour
Labor and materials 4% of fixed investment
Supplies 15% of labor and materials
Overhead
Plant
Payroll
Fixed Costs
50% of operating and maintenance
20% of operating labor
Depreciation (5.56%)
Interim replacement (0.35%), E = 21.41% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed cost
Total cost
Credits (byproducts)
Sulfuric acid 2.27 tons/h
Na-SO. 0.16 ton/h
Total byproduct credits
Fuel credit
Net annual credit
Mills/kWh
$55.41/ton
$43.91/ton
73,000
299,000
10,000
635,000
228,000
406,000
186,000
28,000
779,000
117,000
555,000
43,000
$ 4,171,000
$7,530,000
(663,000)
(39,000)
(702,000)
(8,540,000)
(1,712,000)
(2.17)
E. F. BARRETT POWER PLANT
C-23
-------
Table C-3. RETROFIT EQUIPMENT AND FACILITIES
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM FOR
BOILER 10 AT THE E.F. BARRETT POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na»CO, storage
Na-CO-, preparation
S02 regeneration
Purge treatment
Sulfuric acid plant
1
1
1
1
1
1
1
150 MW capacity unit
Scaled to train size
115 tons (30-day storag
320 Ib/hr, Na2C03
2450 Ib/hr, S02
320 Ib/hr, Na2S04
26.5 tons/day, H2SO.
E. F. BARRETT POWER PLANT
C-24
-------
Table C-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILER 10 AT
E.F. BARRETT POWER PLANT
Item
Number
Required
Dimensions, ft
Na-CO-j storage
Absorber feed surge
tank
Turbulent contact
absorbers
Regeneration plant
Purge treatment plant
Acid plant
1
1
1
1
1
12 diam x 24 high
22 diam x 22 high
45 high x 15 wide x 60 long
31 x 125
39 x 168
53 x 116
E. F. BARRETT POWER PLANT
C-25
-------
HOG ISLAND CHANNEL
4.
«.. Af.-'u so fritT
'•'%>"*
Figure C-l. Site plan showing possible location of major
components for the sodium solution regenerable system
for Boiler 10 at the E.F. Barrett power plant.
E. F. BARRETT POWER PLANT
C-26
-------
TABLE C-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILER 10 AT THE E.F. BARRETT POWER
PLANT (1978)
Direct Cost
A. Limestone Preparation
Conveyors $ 379,000
Storage silo 58,000
Ball mills 581,000
Pumps and motors 70,000
Storage tanks 41,000
Total A = $1,129,000
B. Scrubbing
Absorbers $3,122,000
Fans and motors 476,000
Pumps and motors 226,000
Tanks 181,000
Reheaters 678,000
Soot blowers 163,000
Ducting and valves 928,000
Total B = $5,774,000
Sludge Disposal
Clarifiers $ 119,000
Vacuum filters 242,000
Tanks and mixers 4,000
Fixation chemical storage 19,000
Pumps and motors 30,000
Sludge pond 705,000
Mobile equipment 64,000
Total C = $1,183,000
(continued)
E. F. BARRETT POWER PLANT C-27
-------
TABLE C-5 (continued)
D. Particulate Removal
Venturi scrubber $ 1,703,000
Tanks 48,000
Pumps and motors 60,000
Total D = $ 1,811,000
Total direct costs = A + B + C + D = E = $ 9,897,000
F. Indirect Costs
Interest during construction $ 990,000
Field overhead 990,000
Contractor's fee and expenses 495,000
Engineering 990,000
Freight 128,000
Offsite 295,000
Taxes 000
Spares 50,000
Allowance for shakedown 495,000
Total indirect costs F = $ 4,433,000
Contingency G = 2,866,000
Total = E + F + G = $17,196,000
Coal conversion costs 12,203,000
Grand total $29,399,000
$/kW 195.99
E. F. BARRETT POWER PLANT C-28
-------
TABLE C-6.'
ESTIMATED ANNUAL OPERATING COSTS OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILER 10 AT THE
E.F. BARRETT POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Limestone
Fixation chemicals
3.1 tons/yr
7.9 tons/yr
$15.82/ton
$2.20/ton
$ 264,000
91,000
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
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed charges
Total cost
Fuel credit
Net annual credit
Mills/kWh
54.6 gal/min
3102 kW f.
25.7 x 10 Btu/h
$1.17/10 gal
33.3 mills/kWh
$1.685/106 Btu
2 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
20,000
541,000
228,000
187,000
28,000
688,000
103,000
503,000
43,000
000
(5.56%)
(0.35%)
(0.30%)
(4.00%)
(11.20%)
Z = 21.41% of fixed
investment
$ 3,682,000
$ 6,378,000
(8,540,000)
$(2,162,000)
(2.74)
E. F. BARRETT POWER PLANT
C-29
-------
Table C-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 10
AT THE E.F. BARRETT POWER PLANT
Module Description
Limestone storage
Limestone slurry
Turbulent contact
Flue gas fans
Number
Required
1
1
1
1
Size/Capacity
2232 tons (30-day storage)
3.1 ton/hr limestone
150 MW unit
Scaled to train size
E. F. BARRETT POWER PLANT
C-30
-------
Table C-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR
THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 10
AT THE E.F. BARRETT 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
1
2
1
50 wide x 62 long
10 diam x 22 high
27 diam x 20 high
30 x 30
45 high x 15 wide x 45 long
49 diam x 20 high
30 x 30
'E. F. BARRETT POWER PLANT
C-31
-------
HOC ISLAND CHANNEL
Figure C-2. Site plan showing the possible locations of major
components for the limestone system for Boiler 10 at the
E.F. Barrett power plant.
E. F. BARRETT POWER PLANT
C-32
-------
TABLE C-9. ESTIMATED CAPITAL COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 10 AT THE E.F. BARRETT POWER PLANT
(1978)
Direct Costs
ESP
Ash handling
Ducting
Indirect Costs
Interest during constuction
Contractor's fee
Engineering
Freight ]
Offsite
Taxes
Spares
Allowance for shakedown
Total indirect costs
Contingency
Total
Coal conversion costs
Grand total
$/kW
$ 1,393,000
269,000
768,000
Total direct costs $2,430,000
8% of direct
10% of direct
6% of direct
25% of direct
3% of direct
0% of direct
1% of direct
3% of direct
costs $
costs
costs
costs
costs
costs
costs
costs
$
194,000
243,000
146,000
30,000
73,000
000
24,000
73,000
783,000
643,000
$ 3,856,000
12,203,000
$ 16,059,000
107.06
E. F. BARRETT POWER PLANT
C-33
-------
TABLE C-10. ESTIMATED ANNUAL OPERATING COSTS OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 10 AT THE E.F. BARRETT POWER PLANT (1978)
Utilities
Electricity
Water
Operating Labor
Direct labor
Supervision
Maintenance
Labor and materials
Supplies
Overhead
Quantity
Unit Cost
318 kW . 33.3 mills/kWh
31,180 x 10 gal/yr $0.01/103 gal
0.5 man/shift $10.67/man-hour
15% of direct labor
2% of fixed investment
15% of labor and materials
Annual Cost
$ 55,000
1,000
47,000
7,000
77,000
12,000
Plant
Payroll
Trucking
Bottom/fly ash
removal
Fixed Costs
Depreciation
Interim replacement
50% of operation and maintenance
20% of operating labor
(5.56%)
(0.35%), E = 21.41% of fixed
investment
69,000
11,000
000
Insurance
Taxes
Capital cost
Total fixed costs
Total cost
Fuel credit
Net annual credit
Mills/kWh
(0.30%)
(4.00%)
(11.20%)
$ 826,000
$1,105,000
(8,540,000)
$(7,435,000)
(9.43)
E. F. BARRETT POWER PLANT
C-34
-------
Table C-ll. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 10 AT THE E.F. BARRETT 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
98.8
205
106,000
4
2 @ 21 x 51 x 27
E. F. BARRETT POWER PLANT
C-35
-------
HOG ISLA"0 CHANNEL
Figure C-3. Site plan showing possible locations of new
ESP's for Boiler 10 at the E.F. Barrett power plant.
E. F. BARRETT POWER PLANT
C-36
-------
APPENDIX D
BERGEN POWER PLANT
BERGEN POWER PLANT D-l
-------
CONTENTS
Bergen Power Plant Survey Form
Bergen Power Plant Photographs
Page
D-4
D-20
Number
D-l
D-2
D-3
FIGURES
Site Plan Showing Possible Locations of Major
Components for the Sodium Solution Regenerable
System for Boilers 1 and 2 at the Bergen Power
Plant
Site Plan Showing Possible Locations of Major
Components for the Limestone System for Boilers
1 and 2 at the Bergen Power Plant
Site Plan Showing Possible Locations of Add-On
ESP's for Boilers 1 and 2 at the Bergen Power
Plant
Page
D-30
D-36
D-40
Number
D-l
D-2
D-3
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boilers 1 and 2 at the
Bergen Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boilers 1 and
2 at the Bergen Power Plant (1978)
Page
D-25
D-27
Retrofit Eguipment and Facilities for the Sodium
Solution Regenerable System for Boilers 1 and 2
at the Bergen Power Plant D-28
BERGEN POWER PLANT
D-2
-------
TABLES (continued)
Number Page
D-4 Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boilers
1 and 2 at the Bergen Power Plant D-29
D-5 Estimated Capital Cost of a Limestone Scrub-
bing System for Boilers 1 and 2 at the Bergen
Power Plant (1978) D-31
D-6 Estimated Annual Operating Cost of a Limestone
Scrubbing System for Boilers 1 and 2 at the
Bergen Power Plant (1978) D-33
D-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boilers 1
and 2 at the Bergen Power Plant D-34
D-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boilers 1 and 2
at the Bergen Power Plant D-35
D-9 Estimated Capital Cost of Electrostatic
Precipitators for Boilers 1 and 2 at the
Bergen Power Plant (1978) D-37
D-10 Estimated Annual Operating Cost of Electro-
static Precipitators for Boilers 1 and 2 at
the Bergen Power Plant (1978) D-38
D-ll Electrostatic Precipitator Design Values for
Boilers 1 and 2 at the Bergen Power Plant D-39
BERGEN POWER PLANT D~3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION;
! COMPANY NAME: Public Service Electric and Gas Company
2. MAIN OFFICE: 80 Park Place, Newark, Nev Jersey 07101
3. RESPONSIBLE OFFICER: Edward S. Kirby
4. POSITION: General Solicitor
5 PLANT NAME: Bergen
6. PLANT LOCATION: Victoria Terrace, Ridgefield, Nev Jersey 0?65
7. RESPONSIBLE OFFICER AT PLANT LOCATION: L. J- Hartman
8. POSITION: Manager
9. POWER POOL PJM
DATE INFORMATION GATHERED: Juiy 13, 1976
PARTICIPANTS IN MEETING:
James A. Shissias - Public Service Electric and Gas Company
Sara P. Siebert - Public Service Electric and Gas Company
Paul H. Sutphen - Public Service Electric and Gas Company-
Michael W. Costic - Public Service Electric and Gas Company
Jeffrey A. Aynds - Public Service Electric and Gas Company
Theodore F. Glenhamn, Jr.- Public Service Electric and Gas Compan
David C. Hughes - Public Service Electric and Gas Company
William R. Duke - Public Service Electric and Gas Company
Jim Garofallou - Public Service Electric and Gas Company
Ray Werner - U.S. Environmental Protection Agency - Region II
Dr. C.F. Miranda - U.S. Environmental Protection Agency
N. David Noe - PEDCo Environmental, Inc.
Robert Hearn - PEDCo Environmental, Inc.
Alan J. Sutherland - PEDCo Environmental, Inc.
BERGEN POWER PLANT D~4
-------
B.
to
M
»
O
M
z
o
i
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. S02 EMISSIONS3 (Calculated)
- — --LB/MM BTU (Oil)
LB/HR (FULL LOAD) (oil)
TONS/YEAR (1975) (Oil)
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU (With control Device)
ft Rn 1 fur 1 n VHP!
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
Oil
Unlcnovn
1
NJAC
0.1
20
-
0.315
78U
153^
NJAC
0.3 for
0.3* 01
2
Oil
TTnknnun
1
7:27-3.1 e
0.1
20
-
0.315
781v
900
7:27-9-1
oil and c
, 1 .0* Pn
t seq . ant
t seq . (o
>al
1 Exlstin
U.I et s«
1) NJAC 7
Source r
1 •
••
27-10. 1 e
.P* noal
sei
(Coi
ew
our
a) Identify whether results are from stack tests or estimates
-------
SITE DATA
1. U.T.M. rnnpnTNATRS N^0° 30 Min 30 Sec. W7^° 01 Min .30 Sec
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) R.s fR^ndy Monk Datum)
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): -
D-6
BERGEN POWER PLANT
-------
GO
W
»
O
W
Z
O
s:
w
tr1
^
O
I
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (197 5)
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
6. YEAR BOILER PLACED IN SERVICE
7. REMAINING LIFE OF UNIT^^e ^on^^r
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTION: Oil(Bbls/hr)
Coal (Tons/hr)
. (TPTT) OP — (fiPH) M&VTMfTfvl i^rtiJTT^lUOUS
• PEAK
10. ACTUAL FUEL CONSUMPTION
ro&T. (TPV) (1975)Gas(lo3 MCF)
fVFfc teW-V (1975) (103 Bbls)
11. HEAT RATE BTU/KWHR GAS
(Full load at 60°F Circulat-COAL
4 n er Uotor- Tp TT1 TIP T R t U TG ) 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
Full load
Weekend
5838
U8.1
l
*FW
1959
'28
**267
lH 5
)2600
121
1779-1
1623.8
9950
9^50
9850
Wet
No
305.5
138
2
Days
Days
3092
23-8
2
*FW
I960
29
?R3
U15
2600
121
262.6
952.3
99^0
9^50
9850
Wet
No
305-5
138
Low load r
With Nozz
ghts and
•
e (instal
one
ed)
2oU 20U Without Nozzle
Notes- *FW - Foster Wheeler Corp.
NOT:es- **will be restored to 287 in 1978
-------
CO
w
»
o
w
2
o
s
w
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)
(jf/HR)
(If /MM BTU)
NO OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE (Design)
@ INLET ESP e 100% LOAD (°F)
17. EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
1
Cott*
C
98
See Attac
o Se t s
l6 Section s
86.UOO
300
-/15
2
Cott*
C
98
ned Sheet
be t s
l6Sec tion
86. ^00
300
-/15
Oil
•
* "
a
i
oo
Notes: Cott - Research-Cottrell, Inc.
15/17
15/17
Coal
-------
PUBLIC SERVICE ELECTRIC A?.;D CAS COV
__ BERGEN GENERATING STATIC!:
to
ra
w
z
i
M
S3
UI'IT 13
NO. 1H3
No. 2
i
DATE
10/8/68
10/8/68
10/7/68
11/9/62
10/30/62
1/72
10/70
10/70
10/11/6*
10/11/6C
5/5/66
5/3/66
TT. t • — * T
1 u :i Ii
I
'Coal
Coal
Coal .
Coal
Coal
Oil
Coal
Gas
Coal
Coal
Coal
Coal
i •
CO
0
0
30
0
0
S02
ppm
£ORR. TO
12$ CO? )
175
*
TEST DATA (FULL LOAD)
NOX
(ppn CORR.
to 3°/j 02)
Qkk2
1 ^75^
•
PRECIPITATOR i- FARTICU-AT'?
EFF.
96.65
9^.9
9^.5
TZMP 1
282
287
280
297
301
28U
282 '
. 277
285
GAS • -
FLOW x 10J
(acfn)
887.5
- . 915.6
*
9^3
928
SULF.
2.1+7
2.16
1.97
2.7
2.02
1.85
2.2U
1.17
ASH
L0.01
L0.96
L0.25
7.86
7.55
L0.2?
9.82
8.83
9.9^
MOTS.
5.09
5.02
1:11
?AP.T.
(" bA r )
650
559
763
395
U26
1,687
1,755
671
302
r-io:-: :OAL
o:; ?r.z:iz :r
CONDITIC ;s
1.6211
Vote 1:
lote 2:
Based on coal with 1.2% sulfur and 10.8% ash with 75$ of.the ash to the precipitator, past
test data, operating experience and present condition.
Normal full load operating conditions. • 3/6/7U
-------
ro
w
O
s:
w
TJ
tr1
D
I
18. FLUE GAS RATE (ACFM)
@ 100% LOAD
1,000,000
1,000,000
75% LOAD
50% LOAD
19 STACK GAS EXIT TEMPERATURE
(Design)
@ 100% LOAD
@ 75% LOAD
259
259
@ • 50% LOAD
"EXIT GAS STACK VELOCITY (FPS)a
(Design-with nozzles)
@ 100% LOAD
75% LOAD
-
50% LOAD
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED(TONS/
YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
Trucked ft
Estimated
77. 6
21,750*
Current Cojst -
23. EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO~STACK
^• "• ' " _ _ _ /
Trucked fi
Estimated
25. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
1
10'Wxl6'H
7,250*
om site
Current Cdst
10'Wxl6'H
/ton
11 .? > J
21Wks(lO/9J 0
Bottoi
0
a) Identify source of values (test or estimate)
Notes:
-------
w
JO
CD
M
2
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
1
-
-
2
-
-
w
Notes: Not Equipped
O
i
-------
51*, 000yds
With Cooling Tower h.
F. FLY ASH DISPOSAL AREAS -,
-^ ; .SO.OOOyds^
1. AREAS AVAILABLE (ACRES) Existing 6.7
2. YEARS STORAGE ^^fi-^Wfr^CAsh&Fly Ash ) lx^Bnti^°226gdg.?¥er
3. DISTANCE FROM STACK (FT.) 800 (to discharge point)~
4. DOES THIS PLANT HAVE PONDING Fly ash and bottom ash go^tt
PROBLEMS? DESCRIBE IN ATTACHMENT capacity": Requires aF
G. COAL DATA See Attached Sheets
1.
COAL SEAM, MINE, MINE LOCATION
a.
stant removal by truck to a
available at this time. Loi
range availability of this ~.
is unknown.
b.
c.
d.
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 Experience with other pr -
S FUELS (DESCRIBE.IN ATTACHMENT) expecte^loJI^^cSllIctiSi
H.
FUEL OIL DATA (1975)
1. TYPE No. 6
el:
.ciency
2. S CONTENT (%)
3. ASH CONTENT (%) 0.01 to 0.
4. SPECIFIC GRAVITY Q.889 to 0.908
5. HHV (BTU/GAL) 1^2.238
I.
J.
NATURAL GAS HHV (BTU/FT3) 1029
COST DATA (see Attached Economic Evaluation)
ELECTRICITY
FUEL: COAL
GAS$1. 50/mBtu OIL $1.96/mBtu
WATER $2.50/1000 gals
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES
FEDERAL PROPERTY TAX
BERGEN POWER PLANT
D-12
-------
BERGEN COAL DATA
HEATING VALUE
DRY SULFUR
DRY ASH
MOISTURE
13,100 Btu/lb
2.2%
10.0%
5.0$
FTA
HGI
VOL
2200
100
32%
1Q69 CALENDAR YEAR
MINE
Joanne
Consol
Adrian
Federal
Elliot
Peerless
Albright
Renee
Allison
Deep Hollow
Reitz
Shannon
Eureka
Bodger
0'Donnell
Valley Camp
Pepper
Valley Camp #5
LOCATION
W. Virginia
W. Virginia
W. Virginia
W. Virginia
Pennsylvania
W. Virginia
W. Virginia
W. Virginia
Pennsylvania
W. Virginia
Pennsylvania
Pennsylvania
Pennsylvania
W. Virginia
W. Virginia
W. Virginia
W. Virginia
SEAM
Pittsburgh
Pittsburgh
U. Freeport
Pittsburgh
U&L Freeport
Peerless
U. Freeport
Redstone
Clarion & Kitt.
U. Freeport
U&L Kittanning
U&L Freeport
U. Kittanning
Kittanning
Pittsburgh
Pittsburgh
Pittsburgh & Redstone
Cedar Grove & #5
TONS
QUANTITY
11,720
60,0^7
195,903
27, 25^
26,U59
32,857
27,173
66,952
110,869
5^,503
93,277
35,266
99,939
lU,885
12, ^50
BERGEN POWER PLANT
D-13
-------
K.
M.
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?
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 See Next Page
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
Sufficient for coal firir
without FGD Systems
Ul60
Yes D
D
a.
b.
c.
BERGEN POWER PLANT
2.3 GAS CLEANING
Is the system still installed?
Will it operate?
Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment •
Soot Blowers - Air Compressors
Wall deslaggers
NO a
D
YesD
D
D
D
D
a
No D
D
D
D
D
D
YesD
D
YesQ
D
D
D
Yesn
D
YesD
D
D
D
D
D-14
NoD
D
No D
a
D
D
NoD
D
No D
D
D
D
D
-------
2.4 ASH HANDLING
a. Is the system still installed? YesD NoQ
b. Will it operate? D D
c. Of the following items which
need to be replaced:
Bottom Ash Handling YesD NoD
Ash Pond D D
All equipment associated with coal firing initially installed
at the plant is in place. However, all of the equipment
requires an extensive major overhaul which would include
replacement of various components due to previous wear and
deterioration. Normal routine maintenance was not performed
during the months immediately prior to oil conversion. The
overhauled precipitators would not limit particulate emissions
to the levels required by the New Jersey Department of Environ-
mental Protection.
•BERGEN POWER PLANT D-15
-------
N . ^liPPm-OTARY CONTROL SYSTEM DATA
1 DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? YCS LJ
If yes, attach a description of the system.
2. IS THE PLANT CAPABLE OF SWITCHING TO LOW .,..„„.-, No r-|
SULFUR FUELS? Can fire natural gas if availableYeS [x] N0 LJ
2.1 Storage capacity for low sulfur fuels (i^tin^Ho,. }6 Fuel Oil
(tons, bbls, days) ^,000 Bblst
2.2 Bunkers available for low sulfur coal
storage? ' LJ
2.3 Handling facilities available for low
sulfur fuels (Coal) Yes [_\ no
If yes, describe __ _ - _
2.4 Time required to switch fuels and fire
the low sulfur fuel in the boiler (hrs)^ 1
3. IS THE PLANT CAPABLE OF LOAD SHEDDING?
If yes, discuss See Next Page
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss See Next Page _
No
5. POWER PLANT MONITORING SYSTEM
5.1 Existing system Contract Expires l2/?6 Yes H No Q
a. Air quality instrumentation Number Type
(1) Sulfur Oxides - Continuous _J - Flame_Phpto -t
- Intermittent _ -
- Static _: _ . -
(2) Suspended participates -
v ' -Intermittent (Dai ly_)_3__ P1
- Static _ .
(3) Other fdpscribel NO. NOo _ 3 Chemilumineooe
b. Meteorological instrumentation
If yes, describe Wind direction
and velocity at .plant
.
c. Is the monitoring data available? Yes [xj No
d. Is the monitoring data reduced and
analyzed? Yes &1 nu LJ
e provide map of monitoring locations
BERGEN POWER' PLANT D~16
-------
N-3
All plants are loaded economically to produce electrical
energy at the lowest cost. Specific plants could reduce
load with resultant increased production costs if gener-
ation is available at other locations and transmission
facilities are not fully loaded. Emergency plans for
high ambient pollutant levels are on file with the New
Jersey Department of Environmental Protection. These
plans include changes in normal operating procedures
such as reduction of sootblowing activities. Load
reductions would follow as a result of plans instituted
by the State to reduce energy consumption (closing of
commercial establishments, etc.).
BERGEN POWER PLANT D-17
-------
8639
M
s
Tl
M-
•n
M-
rti
)-•
0.
r»
3
H-
3
OQ
r*
I
00
if
03
a
3
a
M
00
*. \ w«t ""T^r^:^
£iV» w4>'r.
i — T» I ' '
/ '^...'V1 .-^
, .
MHVIRW.;' ^y J.
- 6"SO"NOX
«;•>
-------
5.2 Proposed system : yes Q No
If yes, describe and provide map
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent. HUZZ
- Static ^^^ • 2^^
(2) Suspended particulate
- Intermittent
- Static 2HH
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
• BERGEN POWER PLANT D-19
-------
Photo No. 1. View from the boiler house roof facing west showing
the residual oil tank and ESP for Boiler 2. In the background
is the Hackensack River and the surroundina area.
Photo No. 2. view from the boiler house roof facing north showing the
New Jersey Turnpike, the Overpeck Creek, and the surrounding area.
BERGEN POWER PLANT
D-20
-------
Photo No. 4. View from the boiler house roof facing
southeast showing the residual oil tank, coal pile,
the crusher house, the transfer house, and coal
conveying equipment. In the background is the
Hackensack River and the surrounding area.
BERGEN POWER PLANT
D-21
-------
Photo No. 5. View from the boiler house roof facing south showing
Stack 1, the residual oil tank, the coal pile, and the surrounding area,
Photo No. 6. View from the boiler house roof facing southwest showing
the Consolidated Rail Corporation rail lines and the surrounding area.
BERGEN POWER PLANT
D-22
-------
1 *^4 j,
Photo No. 7. View from ground level facing northwest showing Stack 2
and the dewatering bins.
Photo No. 8. View from the coal pile facing north showing the Bergen
power plant.
BERGEN POWER PLANT
D-23
-------
Photo No. 9. View from the boiler house roof facing south showing
the ESP ductwork on Stack 1.
Photo No. 10. View from ground level facing southwest showing the
residual oil tanks.
BERGEN POWER PLANT
D-24
-------
TABLE D-l. ESTIMATED CAPITAL COST OF A SODIUM SOLUTION
REGENERABLE SYSTEM FOR BOILERS 1 AND 2 AT THE
BERGEN POWER PLANT (1978)
Direct Costs
A.
Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Pumps and motors
$ 127,000
46,000
238,000
33,000
Total A = $ 444,000
B. SOp Scrubbing
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Valves and ducting
Hold Tank
C. Purge Treatment
Refrigeration unit
Precoolers
Tanks
Dryer
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
Total B =
Total C =
$21,227,000
2,392,000
805,000
3,505,000
3,286,000
3,992,000
296,000
$35,503,000
$ 589,000
173,000
43,000
716,000
270,000
1,946,000
159,000
399,000
771,000
$ 5,066,000
(continued)
BERGEN POWER PLANT
D-25
-------
TABLE D-l (continued)
D. Regeneration
Pumps and motors $ 277,000
Evaporators and reboilers 75,000
Heat exchangers 448,000
Tanks 269,000
Stripper 347,000
Condenser 123,000
Total D - $ 1,539,000
E. Particulate Removal
Venturi scrubber $ 11,543,000
Tanks 449,000
Pumps and motors 1,272,000
Total E = $ 13,264,000
Total direct costs = A + B + C + D + E = F = $ 55,816,000
Indirect Costs
Interest during construction $ 5,582,000
Field labor and expenses 5,582,000
Contractor's fee and expenses 4,742,000
Engineering 5,582,000
Freight 698,000
Offsite 1,678,000
Taxes 837,000
Spares 279,000
Allowance for shakedown 2,798,000
Acid plant 2,844,000
Total indirect costs G = $ 30,622,000
Contingency H = 17,288,000
Total = F + G + H = $103,726,000
Coal conversion costs 11,384,000
Grand total $115,110,000
$/kW 201.95
BERGEN POWER PLANT D-26
-------
TABLE D-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILERS 1 AND 2
AT THE BERGEN POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Soda ash
Utilities
0.5 ton/hr
$90.36/ton
Process water 3296.1 gal/min $0.01/10 gal
Cooling water 12.9 x 103 gal/min 10.261 mills/103 gal
Electricity 22924.1 kW 33.10 mills/kWh
Reheat steam 101.1 x 10^ Btu/h $1.685/106 Btu
Process steam 104.9 x 106 Btu/h $1.685/106 Btu
Operation Labor
Direct labor 5 men/day $10.67/man-hour
Supervision 15% of direct labor
Maintenance
Labor and materials 4% of fixed investment
Supplies 15% of labor and materials
Operating and Maintenance
Additional cost
Overhead
$ 143,000
6,000
25,000
2,399,000
538,000
559,000
467,000
70,000
4,149,000
622,000
1,491,000
Plant
Payroll
Fixed Costs
50% of operating and maintenance
20% of operating labor
Depreciation (5.00%)
Interim replacement (0.35%)
Insurance (0.30%)
Taxes (4.00%), Z
Capital cost
Total fixed cost
Total cost
(11.20%)
Credits (byproducts)
Sulfuric acid
Na2S04
8.8 tons/hr
0.7 ton/hr
Total byproduct credits
Fuel credit
Net annual cost
Mills/kWh
20.85% of fixed
investment
$58.71/ton
$57.13/ton
2,654,000
107,000
21,627,000
$ 34,857,000
(1,300,000)
(121,000)
$ (1,421,000)
(16,693,000)
$ 16,743,000
8.18
BERGEN POWER PLANT
D-27
-------
Table D-3. RETROFIT EQUIPMENT AND FACILITIES FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS 1 AND 2
AT THE BERGEN POWER PLANT
Module
Description
Absorbers
Flue gas fans
Na-CO.. storage
Na^CO., preparation
S02 regeneration
Purge treatment
Sulfuric acid plant
Number
Required
5
5
1
1
1
1
1
Size/Capacity
114 MW capacity unit
Scaled to train size
475.2 tons (30-day storage)
1320 Ib/hr, Na2C03
11,180 Ib/hr, S02
1320 Ib/hr, Na2S04
92.55 tons/day, HSO
BERGEN POWER PLANT
D-28
-------
Table D-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILERS 1 AND 2
AT THE BERGEN 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
19 diam x 38 high
36 diam x 36 high
45 high x 15 wide x 42 long
54 wide x 166 long
56 wide x 185 long
77 wide x 166 long
BERGEN POWER PLANT
D-29
-------
BERGEN
GENERATING
STATION
THAWING
SWITCHING
STATION
UJ
A PURGE TREATMENT AND S02 TREATMENT
8 ACID PLANT
C SCRUBBER
D STORAGE SILO
E SOLUTION TANK
Figure D-l. Site plan showing possible locations of major
components for the sodium solution regenerable system
for Boilers 1 and 2 at the Bergen power plant.
BERGEN POWER PLANT
D-30
-------
TABLE D-5. ESTIMATED CAPITAL COST OF A LIMESTONE SCRUBBING
SYSTEM FOR BOILERS 1 AND 2 AT THE
BERGEN POWER PLANT (1978)
Direct Cost
A. Limestone Preparation
Conveyors $ 780,000
Storage silo 173,000
Ball mills 1,316,000
Pumps and motors 48,000
Storage tanks 221,000
Total A = $ 2,538,000
B. Scrubbing
Absorbers $15,209,000
Fans and motors 2,243,000
Pumps and motors 3,885,000
Tanks 1,219,000
Reheaters 3,505,000
Soot blowers 3,286,000
Ducting and valves 3,990,000
Total B = $33,337,000
Sludge Disposal
Clarifiers $ 687,000
Vacuum filters 903,000
Tanks and mixers 82,000
Fixation chemical storage 28,000
Pumps and motors 80,000
Sludge pond 997,000
Mobile equipment 46,000
Total C = $ 2,823,000
(continued)
BERGEN POWER PLANT D-31
-------
TABLE D-5 (continued)
Particulate Removal
Venturi scrubber $ 10,492,000
Tanks 383,000
Pumps and motors 1,246,000
Total D = $ 12,121,000
Total direct costs =A+B+C+D=E= $ 50,819,000
Indirect Costs
Interest during construction $ 5,082,000
Field overhead 5,082,000
Contractor's fee and expenses 4,310,000
Engineering 5,082,000
Freight 623,000
Offsite 1,525,000
Taxes 747,000
Spares 249,000
Allowance for shakedown 2,550,000
Total indirect costs F = $ 25,250,000
Contingency G = 15,214,000
Total =E+F+G= $ 91,283,000
Coal conversion costs 11,384,000
Grand total $102 , 667 ,.000
$/kW 180.12
BERGEN POWER PLANT D-32
-------
TABLE D-6. ESTIMATED ANNUAL OPERATING COST OF A
LIMESTONE SCRUBBING SYSTEM FOR BOILERS 1 AND 2 AT THE
BERGEN POWER PLANT (1978)
Raw Materials
Limestone
Fixation chemicals
12.
3.8
Quantity
9 tons/h
tons/h
Unit Cost
$16
$20
.81/ton
.00/ton
Annual Cost
$ 685,
238,
000
000
Utilities
Water
Electricity
Fuel for reheat
Operating Labor
Direct labor
Supervision
Maintenance
628.5 gal/min
18,339.5 kW
$0.01/10J gal
33.10 mills/kWh
101.1 x 106 Btu/h $1.685/106 Btu
3-2/3 men/day $10.67/man-hour
15% of direct labor
Labor and materials 4% of fixed investment
Supplies 15% of labor and material
Operating and Maintenance
Additional costs
Overhead
Plant
Payroll
Trucking
Bottom/fly ash and
sludge removal
Fixed Costs
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed charges
Total cost
Fuel credit
Net annual
Mills/kWh
50% of operation and maintenance
20% of operating labor
(5.00%)
(0.35%),
(0.30%)
(4.00%)
(11.20%)
Z = 20.85% of fixed
investment
1,000
1,919,000
538,000
343,000
51,000
3,651,000
548,000
1,491,000
2,297,000
79,000
3,569,000
19,033,000
$ 34,443,000
(16,693,000)
$ 17,750,000
8.67
BERGEN POWER PLANT
D-33
-------
Table D-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED FOR
THE LIMESTONE SCRUBBING SYSTEM FOR BOILERS 1 AND 2
AT THE BERGEN POWER PLANT
Module Description
Number
Required
Size/Capacity
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
1
1
5
5
9216 tons (30-day storage)
12.8 ton/hr limestone
114 MW capacity unit
Scaled to train size
BERGEN POWER PLANT
D-34
-------
Table D-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
LIMESTONE SCRUBBING SYSTEM FOR BOILERS 1 AND 2
AT THE BERGEN 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
5
2
1
140 wide x 140 long
16 diam x 34 high
54 diam x 20 high
40 wide and 40 long
15 high x 45 wide x 31 long
65 diam x 20 high
40 wide x 40 long
BERGEN POWER PLANT
D-35
-------
N
BERGEN
GENERATING
STATION
THAWING
,
SWITCHING
STATION
UJ
A SCRUBBERS
B SLURRY TANK
C LIMESTONE SILOS
D BALL MILL
E CLARIFIER
F VACUUM FILTER BUILDING
Figure D-2. Site plan showing possible locations of major
components for the limestone system
for Boilers 1 and 2 at the Bergen power plant.
BERGEN POWER PLANT
D-36
-------
TABLE D-9. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1 AND 2 AT THE
BERGEN POWER PLANT (1978)
Direct Costs
ESP
Ash handling
Ducting
Indirect Costs
Interest during construction
Contractor's fee
Engineering
Freight
Offsite
Taxes
Spares
Allowance for shakedown
Total indirect costs
Contingency
Total
Coal conversion costs
Grand total
$/kW
$11,527,000
4,272,000
1,406,000
Total direct costs $17,205,000
10% of direct costs
10% of direct costs
10% of direct costs
1.25% of direct costs
3% of direct costs
1.5% of direct costs
1% of direct costs
3% of direct costs
$ 1,720,000
1,720,000
1,720,000
215,000
516,000
258,000
172,000
516,000
$ 6,837,000
4,808,000
$28,850,000
11,384,000
$40,234,000
70.59
BERGEN POWER PLANT
D-37
-------
TABLE D-10. ESTIMATED ANNUAL OPERATING COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1 AND 2 AT THE
BERGEN POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 2888 kW 33.10 mills/kWh $ 200,000
Water 18 x 103 gal/h $0.01/103 gal 1,000
Operating Labor
Direct labor 1.0 man/shift $10.67/man-hour 93,000
Supervision 15% of direct labor 14,000
Maintenance
Labor and materials 2% of fixed investment 577,000
Supplies 15% of labor and materials 87,000
Operating and Maintenance
Additional cost 1,491,000
Overhead
Plant 50% of operation and maintenance 386,000
Payroll 20% of operating labor 21,000
Trucking
Bottom/fly ash
removal 2,233,000
Fixed Costs
Depreciation (4.55%)
Interim replacement (0.35%), Z = 20.4% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed cost 5,885,000
Total cost $ 10,988,000
Fuel credit (16,693,000)
Net annual credit $ (5,705,000)
Mills/kWh (2.79)
BERGEN POWER PLANT D-38
-------
TABLE D-ll. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILERS 1 AND 2 AT THE BERGEN POWER PLANT
Design Parameter
Collection efficiency, %
(Overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, ft/s
Overall ESP dimensions
(height x width x depth) , ft
excluding hopper dimensions
Values
Boiler 1
98.46
718
718,200
4.0
45 x 101 x 60
Boiler 2
98.46
245
244,728
4.0
74 x 78 x 22
BERGEN POWER PLANT
D-39
-------
N
THAWING SHED
Figure D-3. Site plan showing possible locations
of add-on ESP's for Boilers 1 and 2
at the Bergen power plant.
BERGEN POWER PLANT
D-40
-------
APPENDIX E
BLUE VALLEY POWER PLANT
BLUE VALLEY POWER PLANT E-l
-------
CONTENTS
Blue Valley Power Plant Survey Form
Blue Valley Power Plant Photographs
Page
E-3
E-15
Number
E-l
FIGURES
Site Plan Showing Possible Locations of New
ESP's for Boilers 1, 2 and 3 at the Blue
Valley Power Plant
Page
E-23
Number
E-l
E-2
E-3
TABLES
Estimated Capital Costs of Electrostatic
Precipitators for Boilers 1, 2, and 3 at the
Blue Valley Power Plant (1978)
Estimated Annual Operating Costs of Electro-
static Precipitators for Boilers 1, 2, and 3
at the Blue Valley Power Plant (1978)
Electrostatic Precipitator Design Values for
Boilers 1, 2, and 3 at the Blue Valley Power
Plant
Page
E-20
E-21
E-22
BLUE VALLEY POWER PLANT
E-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION:
1. COMPANY NAME: City of Independence Power and Light Department
2. MAIN OFFICE: 21500 East Truman Road, Independence, Missouri 64056
3. RESPONSIBLE OFFICER: Robert J. Barnett
4. POSITION: Electric Utility Director
5. PLANT NAME: Blue Valley
6. PLANT LOCATION: Jackson County, Independence, Missouri 64056
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Phillip H. Hanson
8. POSITION: Plant Superintendent
9. POWER POOL Southwest Power Pool
DATE INFORMATION GATHERED: 12/31/75
PARTICIPANTS IN MEETING:
Robert G. Badder - Independence Power and Light Department
Phillip H. Hanson - Independence Power and Light Department
Robert Barnett - Independence Power and Light Department
Daniel J. Wheeler - EPA, Region VII
Francis M. Kirwan - EPA, Research Triangle Park
Robert Schreiber - State of Missouri
John W. Bailey - City of Independence, Air Pollution
Stephen J. Fortney - City of Independence, Water Treatment
Thomas C. Ponder - PEDCo Environmental, Inc.
N. David Noe - PEDCo Environmental, Inc.
Richard T. Price - PEDCo Environmental, Inc.
BLUE VALLEY POWER PLANT E-3
-------
B.
03
f
G
W
f
f
w
K
O
S
M
50
t)
t7<
I
t-3
W
I
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 ( Coal -Fir in]
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
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO2 EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR (1975)
4. APPLICABLE SO2 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/"M BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
)
1.58
_
359
AQCR 09'
Regu la t
0 . 24
4 . 3
-
980
AQCR 0
Ambient
2
1.58
_
_
523
Prior it)
.on III ( ]
0:24
4;3
-
1425
14 Priority
Air Fence
3
1. 58
_
.1368
I
C)
0.24
4 .3
-
3730
III ( Re
ine Stand
;ula t ion X^
ird
(1) )
a;
en ' vv ie: :su ai ro ;ac ss >r Imi
Based on 10,90V Btu/Lb, 2.47 % S, 13.5 % Ash Coal, Multicylone design trrieiencies
-------
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) :
BLUE VALLEY POWER PLANT E-5
-------
03
f
G
W
tr1
f
M
o
s
w
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)
Gas
MAXIMUM CONTINUOUS Coal
9. FUEL CONSUMPTION: Gas (Ft /hr
COAL OR OIL Oil (Bbl/hr
(T'PH) OR (GPH) MAXIMUM CONTINUOUS
Coal (TPY)
10. ACTUAL FUEL CONSUMPTION Gas (1000M
COAL (TPY) (19 73 (lOOOTons)
OIL (GPY) (19 73 (lOOOBbls)
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
Base
516.1.8
16.1
1
CE
19S8
24
24
260
49
16 . 1
!F)460.14
20. 88
1 . 00
Wet
No
152.5
65 .6
2
Ba se
7517 .0
SQ S
2
r.F.
1QSR
24
24
260
49
16 .1
944 .06
30 . 36
1 .11
Wet
No
152.5
65 .6
*
Base
7m y . y
SI A1
l
r.F
1 9 IS 5
60
54
?fin
116
2Q . 4
1537 .04
79.49
5.Q5
Wet
Nn
250
81
(start-uj
>>
W
I
Notes:
CE - Combustion Engineering Inc.
Net heat Rates - 12,000 (Boiler 1)
13,000 (Boiler 2)
11,200 (Boiler 3)
-------
CO
f
G
W
tr1
w
K
13
i
M
13
tr1
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: Est. ./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
1
MCTA
85/
NA
15/
2
MCTA
857
NA
157
3".
MCTA
90.3
NA
15/
n
i
Notes: *
MCTA = Multiple Cyclones - Conventional Reverse Flow; Tangential Inlet
-------
03
f
G
n
f
f
M
Kj
O
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
93,000
47,000
303
66
33 .4
Pond
Pond
2' x 8'
2
93,000
47,000
303
66
33.4
ing
ing
2 ' x 8'
.1
202,000
102,000
303
94
47 .5
w
I
oo
a) Identify source of values (test or estimate)
Notes:
-------
ro
r
c
w
>
f
r
M
K
>d
O
s
n
JO
E. I .D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C-)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler number
Notes:
M
I
-------
F. FLY ASli DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) 3.5
2. YEARS STORAGE (ASH ONLY) Pond Cleaned out Periodically
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a- District 14
b.
District 15
c .
District 16
d.
Distr ic t 19
2. QUANTITY USED BY SEAM AND/OR MINE
a. 33.9
b. 83.8
c. 4.9
d. 69.7
3. ANALYSIS
GHV (DTU/LB) 10,907
S (%) 2.47
ASH (%) 13.5
MOISTURE (%) 8.55
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE
2 . S CONTENT (%) ]_. 2
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL) 138.266 Gas = 986.8 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?
BLUE VALLEY POWER PLANT E-'l-O
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No. 1 2
Yes or No. Yes Yes Y
2. SYSTEM AVAILABILITY - 12/23/75 Plan
' 2.1 COAL HANDLING Coal- Fir ing.
3
es
t Converted to 100%
a. Is the system still installed? Yes D No D
b. Will it operate?
D
D
c. Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
2 .2 FUEL FIRING
Yes D No D
D
D
D
D
D
D
D
D
D
D
a. Is the system still installed? Yes D No D
b. Will it operate?
D
D
c. Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
2.3 GAS CLEANING
YesQ N
D
n
D
oD
D
D
D
a. Is the system still installed? Yes Q No D
b. Will it operate?
D
D
c. Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Fly Ash Handling Equipment
YesD No D
n
n
Soot Blowers - Air Compressors D
Wall deslaggers
p
D
n
n
D
BLUE VALLEY POWER PLANT E-ll
-------
2.4 ASH HANDLING
a. Is the system still installed? YesD NoQ
b. Will it operate? D D
c. Of the following items which
need to be replaced:
Bottom Ash Handling YesD NoD
Ash Pond D D
BLUE VALLEY POWER PLANT E-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 LOU
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 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
Yes
Yes
Yes
Yes
Number
No
No [J
No
No
N° cn
N° n
No
Type.
Yes D No [J
Yes Q] No [j
BLUE VALLEY POWER PLANT
E-13
-------
Proposed system Yes i ] No [_]
If yes, describe
a. Air monitorincj instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
(2) Suspended particulatc
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
BLUE VALLEY POWER PLANT E-14
-------
Photo No. 1. View from ground level looking north showing Stacks
1, 2, and 3 and the coal conveyor.
Photo No. 2. View from the boiler house roof showing the
lead-in ducts to Stacks 1 and 2.
BLUE VALLEY POWER PLANT .
E-15
-------
Photo No. 3. View from the boiler house roof facing east
showing the lead-in duct to Stack 3 and a clarifier in the
background.
Photo No. 4. View from ground level looking north showing
the ash collecting bins.
BLUE VALLEY POWER PLANT
E-16
-------
Photo No. 5. View from the boiler house roof looking east
showing the coal pile, coal conveying system, and the crusher
house. In the background, the surrounding area is shown.
Photo No. 6. View from ground level facing north showing
the cooling towers and a clarifier.
BLUE VALLEY POWER PLANT
E-17
-------
Photo No. 7. View from the boiler house roof looking northeast
showing the cooling tower, ash pond, and the surrounding area.
Photo No. 8. View from the boiler house roof facing west
showing the gas turbines that are under construction. In
the background, the surrounding residental area is shown.
BLUE VALLEY POWER PLANT
E-18
-------
Photo No. 9. View from the boiler house roof looking southeast
showing the administration and service building. The surrounding
area is shown in the background.
Photo No. 10. View from the boiler house roof looking northwest
showing the surrounding area and the tip of the substation.
BLUE VALLEY POWER PLANT
E-19
-------
TABLE E-l. ESTIMATED CAPITAL COSTS OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1, 2, AND 3 AT THE BLUE VALLEY
POWER PLANT (1978)
Direct Costs
ESP
Ash handling
Ducting
$ 2,338,000
194,000
395,000
Indirect Costs
Interest during construction
Contractor's fee
Engineering
Freight 1.
Offsite
Taxes
Spares
Allowance for shakedown
Total indirect costs
Contingency
Total
Coal conversion costs
Grand total
$/kW
Total direct costs
8% of direct costs
10% of direct costs
6% of direct costs
25% of direct costs
3% of direct costs
0% of direct costs
1% of direct costs
3% of direct costs
$ 2,927,000
$ 234,000
293,000
175,000
37,000
88,000
000
29,000
88,000
$ 944,000
774,000
$ 4,645,000
9,804,000
$14,449,000
141.66
BLUE VALLEY POWER PLANT
E-20
-------
TABLE E-2. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 1, 2, AND 3 AT THE BLUE VALLEY
POWER PLANT (1978)
Utilities
Electricity
Water
Quantity
229 kW
8434 103 gal/yr
Unit Cost
27.55 mills/kWh
$0.009/103 gal
Annual
$ 27
1
Cost
,000
,000
Operating Labor
Direct Labor 1.5 men/shift $8.50/man-hour 112,000
Supervision 15% of direct labor 17,000
Maintenance
Labor and materials 2% of fixed investment 93,000
Supplies 15% of labor and materials 14,000
Overhead
Plant 50% of operation and maintenance 118,000
Payroll 20% of operating labor 26,000
Trucking
Bottom/fly ash
removal 000
Fixed Costs
Depreciation (4.17%)
Interim replacement (0.35%), I = 16.02% of fixed
investment
Insurance (0.30%)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost $ 744,000
Total cost $ 1,338,000
Fuel cost 282,000
Net annual cost $ 1,434,000
Mills/kWh 3.15
BLUE VALLEY POWER PLANT E-21
-------
CO
f
G
n
tr1
f
w
K
O
s;
w
f
>
25
Table E-3. ELECTROSTATIC PRECIPITATOR DESIGN VALUES FOR BOILERS
1, 2, AND 3 AT THE BLUE VALLEY POWER PLANT
Design Parameter
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
Value
1
97.72
194
18,000
4.0
15x26x19
2
3
97.72 97.72
194
18,000
4.0
15x26x19
200
40,500
4.0
15x56x19
w
I
to
ro
-------
to
F
G
W
p
w
K
n
NJ
U>
' PROPERTY LINE
SUBSTATION A
Figure E-l. Site plan showing possible locations of new ESP's
for Boilers 1, 2 and 3
at the Blue Valley power plant.
-------
APPENDIX F
CROMBY POWER PLANT
CROMBY POWER PLANT F-l
-------
CONTENTS
Cromby Power Plant Survey Form
Cromby Power Plant Photographs
Page
F-4
F-16
Number
F-l
F-2
F-3
FIGURES
Site Plan Showing Possible Locations of Major
Components for the Sodium Solution Regenerable
System for Boiler 2 at the Cromby Power Plant
Site Plan Showing Possible Locations of Major
Components for the Limestone System for Boiler
2 at the Cromby Power Plant
Site Plan Showing Possible Locations of a New
ESP for Boiler 2 at the Cromby Power Plant
Page
F-26
F-32
F-36
Number
F-l
F-2
F-3
F-4
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boiler 2 at the Cromby
Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boiler 2 at the
Cromby Power Plant
Retrofit Equipment and Facilities for the Sodium
Solution Regenerable System for Boiler 2 at the
Cromby Power Plant
Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boiler
2 at the Cromby Power Plant
Page
F-21
F-23
F-24
F-25
CROMBY POWER PLANT
F-2
-------
TABLES (continued)
Number Page
F-5 Estimated Capital Cost of a Limestone Scrubbing
System at the Cromby Power Plant (1978) F-27
F-6 Estimated Annual Operating Cost of a Limestone
Scrubbing System at the Cromby Power Plant
(1978) F-29
F-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boiler 2
at the Cromby Power Plant F-30
F-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boiler 2 at the
Cromby Power Plant F-31
F-9 Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 2 at the Cromby Power
Plant (1978) F-33
F-10 Estimated Annual Operating Cost of an Electro-
static Precipitator for Boiler 2 at the Cromby
Power Plant (1978) F-34
F-ll Electrostatic Precipitator Design Values for
Boiler 2 at the Cromby Power Plant F-35
CROMBY POWER PLANT F-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: Philadelphia Electric Company
2. MAIN OFFICE: 2301 Market Street, Philadelphia, Penna 19101
3. RESPONSIBLE OFFICER: W. B. Willsey
4. POSITION: Superintendent, Services Division
5. PLANT NAME: Cromby
6. PLANT LOCATION: Township Line and Cromby Roads, Phoenixville,
7. RESPONSIBLE OFFICER AT PLANT LOCATION: 19460
8. POSITION: Plant Superintendent
9. POWER POOL PJM
DATE INFORMATION GATHERED: 7/21/76
PARTICIPANTS IN MEETING:
W. B. Willsey Philadelphia Electric Company (PECo)
P. X. English Philadelphia Electric Company (PECo)
George Kotnick Philadelphia Electric Company (PECo)
E. G. Boyer, Jr. PECo - Cromby Station
Henry F. Scheck PECo - Cromby Station
David R. Meyers PECo - Cromby Station
James Sydnor Environmental Protection Agency, Region III
John Howell Environmental Protection Agency, Region III
Thomas H. Jones Penna. Dept. of Environmental Resources
N. David Noe PEDCo Environmental, Inc.
Alan J. Sutherland PEDCo Environmental, Inc.
CROMBY POWER PLANT F-4
-------
B.
n
»
o
s
CO
i
f
>
2;
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONSa from AP 42
LB/MM BTU 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
OPACITY, PERCENT
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3 from AP 42
LB/MM BTU Caic
LB/HR (FULL LOAD)
TONS/YEAR (1975) Calc
4. APPLICABLE SO EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
Coal*
0.16
671>
AQCR 0
Section
0.1
20%
Priority
Coal
3.99
16,944
Section
1.8
2
Oil
0.05
205
15 Prior:
123.11 (:
0.1
20%
I
Oil
0.43
1. 610
123.22 (i)
1.8
ty I
!)
(iii)
I
Ul
a) Identify whether results are from stack tests or estimates
*Particulate Emissions on Coal Based on 98% Efficiency.
-------
C. SITE DATA
1. U.T.M. COORDINATES 400905 Long. - 753144 Lat.
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 108
3. SOIL DATA: BEARING VALUE
PILING NECESSARY No
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 247
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE): NA
CROMBY POWER PLANT F-6
-------
D.
O
»
o
O
s
w
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:
COAL QBapEL RATED Tons/hr
(TPH-) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (1975)
OIL (GPY) (1975) Bbl
11. HEAT RATE BTU/KWHR GAS
COAL (1970)
OIL (1975)
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
Base
7,229
82.5
1
*B&W
1954
187.5
48.5
343,000
24,000
Dry
No
300
168
2
Base
5,588
63.8
2
**CE
1955
230.0
67.5
0
1,221,000
9,789
10,406
Dry
No
300
168
t
I
-J
Notes:
* B&W - Babcock & Wilcox
** CE - Combustion Engineering
-------
o
50
O
s
CO
*
i
w
50
£
a
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: n DESIGN/ACTUAL (%)
with coal
Boiler number
NA
*AMST/Cot
C
98/
15
2
American
Blower
toriz. Spi
80/
1,817
.89
t AMST/Cot
Vlech. Rect
90/
-
182
.089
4
25,650
250°F
15 - 18
iners
-
B
Notes:
i
oo
'AMST - American Standard, Inc.
Cott - Research-Cottrell, Inc.
**Based on 10% ash coal and gas flows 600,000 CFM @ 250°F.
-------
n
»
o
s
w
K
•d
o
S
M
tr1
>
z
18. FLUE GAS RATE (ACFM)
@ 100% LOAD
@ ?5-%— fc©AB
@ 5-e-%— BOA-D
19. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
(?• — T-5-%— fceA-B
@ -SO*-BG-AB
20. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
@ -T-5-%— BeA-B-
e- — &
-------
n
»
o
s
ro
i
tn
50
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
Notes: Sufficient Fan Capacity When Firing Coal
I
M
O
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY) 15-20
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
Western Pennsylvania and Wes-h Virginia
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
3. ANALYSIS (1975) Coal Data For Boiler 1
HHV (BTU/LB) 12,382
S (%) 2._6
ASH (%) 11.5
MOISTURE (%) 5.9
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA (1975)
1. TYPE
2. S CONTENT (%) -4
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL) 147,447
I. NATURAL GAS HHV (BTU/FT3) NA
J. COST DATA 1975
ELECTRICITY
FUEL: COAL$1.2944 GAS OIL $2 .1363/mmBtu
WATER
STEAM NA
TAXES ON A.P.C. EQUIPMENT:STATE SALESNo
STATE PROPERTY TAX
CROMBY POWER PLANT F-ll
-------
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?
Inadequate to meet additi ia
Load
Boiler No.
Yes or No.
1
Yes
2
Yes
YesD
a
a
a
a
a
No H
8
m
B
B
m
2. SYSTEM AVAILABILITY
2.1 COAL HANDLING
a. Is the system still installed? Yes H No D
b. Will it operate? E D
c. Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers (Maintenance Required)
Conveyors
Scales
Coal Storage Area
2 .2 FUEL FIRING
a. Is the system still installed? YesS No D
b. Will it operate? B D
c. Of the following items which
need to be replaced:
Pulverizers or Crushers YesD No B
Feed Ducts D H
Fans D S
Controls D H
2.3 GAS CLEANING
a. Is the system still installed? Yes£]
b. Will it operate? E
c. Of the following items which
need to be replaced:
Electrostatic Precipitator YesQ
Cyclones d
Fly Ash Handling Equipment D
Soot Blowers -StS&m Compressors D
Wall deslaggers 0
CROMBY POWER PLANT F-12
No Q
D
No S
-------
2.4 ASH HANDLING (Maintenance Required)
a. Is the system still installed? Yes 0 NoD
b. Will it operate? 0 D
c. Of the following items which
need to be replaced:
Bottom Ash Handling YesQ No 0
Ash Pond NA D D
CROMBY POWER PLANT F-13
-------
N. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? NA
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 PJM
POWER PLANT MONITORING SYSTEM
5.1 Existing system NA
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.
d.
Is the monitoring data available?
Is the monitoring data reduced and
analyzed?
e. Provide map of monitoring locations
CROMBY POWER PLANT
Yes
Yes
No
NO
Yes
Yes
NO rj
No
Yes
No
Yes Q No
Number Type
Yes
Yes
No
No D
F-14
-------
5.2 Proposed system Yes P] 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 Rain gauge, temp.
wind direction and velocity
CROMBY POWER PLANT _ ,_
F-l 5
-------
>
Photo No. 1 View from ground level facing southeast
The ESP, induce fans, and ductwork serving Boiler 2
at the Cromby plant are shown.
^i1*''*-^ -AtiSifc.it.
Photo No. 2 View from the boiler house roof look-
ing northeast showing the coal crusher house, con-
veyors and the coal pile. The railroad facilities
and the area surrounding the plant are shown in
the background of the photograph.
CROMBY POWER PLANT
F-16
-------
Photo No. 3 View from ground level looking north
showing the coal transfer tower, conveyors, and a
portion of the coal pile. Storage tanks are also
shown.
Photo No. 4 View from ground level facing northwest
showing the dumper house containing a rotary dump.
The oil pump house is also shown.
CROMBY POWER PLANT
F-17
-------
Photo No. 5 View from the boiler house roof facing
north showing the ash pit. A section of ESP serving
Boiler 2 is shown in the foreground of the photograph.
Photo No. 6 View from the boiler house roof looking
west showing the two million gallon fuel oil tank.
Stack 2, the dumper house, and the surrounding area
are also shown.
CROMBY POWER PLANT
F-18
-------
Photo No. 7 View from ground level facing east showing
the parking area and transformers. The area in the
foreground of the photo is the future site of the
scrubber for Boiler 1.
Photo No. 8 View of the boiler house roof facing north
showing the terrain surrounding the plant. The crusher
house and coal pile are shown in the foreground of the
photograph.
CROMBY POWER PLANT
F-19
-------
Photo No. 9 View from the boiler house roof looking
northeast showing the surrounding agricultural area.
Photo No. 10 View from the boiler house roof facing
southeast showing the Schuylkill River. The surround-
ing plant area is also shown.
CROMBY POWER PLANT
F-20
-------
TABLE F-l. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 2 AT THE
CROMBY POWER PLANT (1978)
Direct Costs
A.
Soda Ash Preparation
Storage silos
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
$ 25,000
6,000
15,000
26,000
2,000
Total A = $ 74,000
B. S02 Scrubbing
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
Total B =
$ 4,690,000
518,000
137,000
820,000
651,000
1,997,000
156,000
$ 8,969,000
C. Purge Treatment
Refrigeration unit
Heat exchangers
Tanks
Dryer
Elevator
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
Total C =
134,000
20,000
30,000
21,000
15,000
86,000
266,000
320,000
25,000
6,000
923,000
(continued)
CROMBY POWER PLANT
F-21
-------
TABLE F-l (continued)
D. Regeneration
Pumps and motors $ 136,000
Evaporators and reboilers 651,000
Heat exchangers 84,000
Tanks 19,000
Stripper 57,000
Blower 27,000
Total D = $ 974,000
E. Particulate Removal
Venturi scrubber $ 2,058,000
Tanks 62,000
Pumps and motors 231,OOP
Total E = $ 2,351,000
Total direct costs =A+B+C+D+E=F= $ 13,291,000
Indirect Costs
Interest during construction $ 1,329,000
Field labor and expenses 1,329,000
Contractor's fee and expenses 664,000
Engineering 1,329,000
Freight 166,000
Offsite 398,000
Taxes
Spares 66,000
Allowance for shakedown 664,000
Acid plant 506,OOP
Total indirect costs G = $ 6,451,000
Contingency H = 3,948,000
Total =F+G+H= $ 23,690,000
Coal conversion costs 60,OOP
Grand total $ 23,75P,POO
$/kW 103.26
CROMBY POWER PLANT F-22
-------
TABLE F-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM SOLUTION
REGENERABLE SYSTEM FOR BOILER 2 AT THE CROMBY POWER PLANT
(1978)
Quantity
Unit Cost Annual Cost
Raw Materials
Soda ash 0.10 ton/h $79.34/ton $ 25,000
Utilities
Process water 580 gal/min $0.66/10 gal 73,000
Cooling water 2.2 x 103 gal/min $0.008/103 gal 3,000
Electricity 4217 kW $26.4 mills/kWh 352,000
Reheat steam 31.1 x 106 Btu/h $1.348/106 Btu 132,000
Process steam 28.2 x 1()6 Btu/h $1.348/106 Btu 120,000
Operation Labor
Direct labor 2 men/day $10.67/man-hour 188,000
Supervision 15% of direct labor 28,000
Maintenance
Labor and materials 4% of fixed investment 948,000
Supplies 15% of labor and materials 142,000
Overhead
Plant 50% of operating and maintenance 653,000
Payroll 20% of operating labor 43,000
Fixed Costs
Depreciation (5.88%)
Interim replacement (0.35%)
Insurance (0.30%)
Taxes (2.00%), £ = 19.73% of fixed
investment
Capital cost (11.20%)
Total fixed cost
Credits (byproducts)
Sulfuric acid 1.40 tons/h $54.55/ton
Na2S04 0.10 ton/h $55.65/ton
Total byproduct
, credits
Fuel credit
Net annual cost
Mills/kWh
$ 4,674,000
$ 7,381,000
(241,000)
(18,000)
$ (259,000)
(6,649,000)
$ (473,000)
(0.65)
CROMBY POWER PLANT F-23
-------
Table F-3. RETROFIT EQUIPMENT AND FACILITIES
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
FOR BOILER 2 AT THE CROMBY POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na_C03 storage
Na2C03 preparation
S0_ regeneration
Purge treatment
Sulfuric acid plant
1
1
1
1
1
115 MW capacity unit
Scaled to train size
72 tons (30 day storage)
200 Ib/hr, Na2C03
912 Ib/hr, S02
200 Ib/hr, Na2S04
6 ton/day, H SO
CROMBY POWER PLANT
F-24
-------
Table F-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 2
AT THE CROMBY POWER PLANT
Item
Number
required
Dimensions, ft
Na-CO-j storage
Absorber feed surge
tank
Turbulent contact
absorbers
Regeneration plant
Purge treatment plant
Acid plant
1
1
1
1
1
5 diam x 10 high
20 diam x 20 high
45 high x 15 wide x 35 long
120 x 30
165 x 40
105:x 50
CROMBY POWER PLANT
F-25
-------
n
8
3
03
o
73
f
I
I
to
N
s,,.
A |
•
n
.1
L'N'TS
n
OQ^ 5'~°r"'"RS
^^^
HAMBER -- ^~^^^;"i±i
SCK-JYL'.I'.L RIVER
A PURGE TREATMENT AND
S02 REGENERATION
B ACID PLANT
C SCRUBBERS
D STORAGE SILO
E SOLUTION TANK
Figure F-l. Site plan showing possible locations of major components
for the sodium solution regenerable system for Boiler 2
at the Cromby power plant.
-------
TABLE F-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEMS AT THE CROMBY POWER PLANT (1978)
Direct Cost
A. Limestone Preparation
Conveyors
Storage silo
Ball mills
Pumps and motors
Storage tanks
$ 398,000
69,000
618,000
97,000
72,000
Total A = $ 1,254,000
B. Scrubbing
Absorbers
Fans and motors
Pumps and motors
Tanks
Reheaters
Soot blowers
Ducting and valves
$ 3^774,000
575,000
256,000
205,000
820,000
163,000
1,646,000
Total B = $ 7,439,000
C. Sludge Disposal
Clarifiers
Vacuum filters
Tanks and mixers
Fixation chemical storage
Pumps and motors
Sludge pond
Mobile equipment
$ 197,000
299,000
8,000
23,000
45,000
885,000
64,000
Total C = $ 1,521,000
(continued)
CROMBY POWER PLANT
F-27
-------
TABLE F-5 (continued)
D. Particulate Removal
Venturi scrubber $ 2,058,000
Tanks 54,000
Pumps and motors 65 ,000
Total D = $ 2,177,000
Total direct costs = A + B + C + D = E = $ 12,391,000
E. Indirect Costs
Interest during construction $ 1,239,000
Field overhead 1,239,000
Contractor's fee and expenses 620,000
Engineering 1,239,000
Freight 155,000
Offsite 372,000
Taxes
Spares 62,000
Allowance for shakedown 620,000
Total indirect cost F = $ 5,546,000
Contingency G = 3,587,000
Total =E+F+G= $ 21,524,000
Coal conversion costs 60,OOP
Grand total $ 21,584,000
$/kW 93.84
CROMBY POWER PLANT F-28
-------
TABLE F-6. ESTIMATED ANNUAL OPERATING COST OF A LIMESTONE
SCRUBBING SYSTEM AT THE CROMBY POWER PLANT (1978)
Raw Materials
Limestone
Fixation chemicals
Utilities
Water
Electricity
Fuel for reheat
Operating Labor
Direct labor
Supervision
Maintenance
Labor and materials
Supplies
Overhead
Plant
Payroll
Quantity Unit Cost
6.6 tons/h $16.53/ton
21.9 tons/h $2.20/ton
66.0 gal/min $0.66/gal
38.13 kW 26.4 mills/kWh
31.1 x 106 Btu/h $1.348/106 Btu
2 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
Annual Cost
$ 345,000
152,000
8,000
318,000
132,000
187,000
28,000
861,000
129,000
603,000
43,000
Trucking
Bottom/fly ash and
sludge removal
Fixed Costs
Depreciation
Iterim replacement
Insurance
Taxes
Capital cost
Total fixed costs
Total cost
Fuel credit
Net annual cost
Mills/kWh
(5.88%)
(0.35%), £ = 19.73% of fixed
investment
(0.30%)
(2.00%)
(11.20%)
3,045,000
$ 4,247,000
$ 10,098,000
(9,099,000)
$ 999,000
1.38
CROMBY POWER PLANT
F-29
-------
Table F-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 2
AT THE CROMBY POWER PLANT
Module Description
Number
Required
Size/Capacity
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
1
1
2
4752 tons (30-day storage)
6.6 ton/hr limestone
115 MW capacity units
Scaled to train size
CROMBY POWER PLANT
F-30
-------
Table F-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED FOR THE
LIMESTONE SCRUBBING SYSTEM FOR BOILER 2 AT THE
CROMBY 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
2
2
1
100 wide x 100 long
13 diam x 28 high
39 diam x 20 high
30 x 30
45 high x 15 wide x 28 long
61 diam x 20 high
30 x 30
CROMBY POWER PLANT
F-31
-------
n
i
OJ
to
HEATING BOILER HOUSE
EI HOUSE
a nDD
fefRoiLM.R NO.2
FCTM'tU
- - --INTAKE CHA;-:SER — -
A SCRUBBERS
B SLURRY TANK
SCHUYLKILL RIVER C LIMESTONE SILOS
D BALL MILL BUILDING
E CLARIFIER
F VACUUM FILTER BUILDING
Figure F-2. Site plan showing possible locations of major components
for the limestone system for Boiler 2
at the Cromby power plant.
-------
TABLE F-9. ESTIMATED CAPITAL COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 2 AT THE CROMBY POWER PLANT (1978)
Direct Costs
ESP $ 1,620,000
Ash handling 313,000
Ducting 637,000
Total direct costs $ 2,570,000
Indirect Costs
Interest during construction 8% of direct costs $ 206,000
Contractor's fee 10% of direct costs 257,000
Engineering 6% of direct costs 154,000
Freight 1.25% of direct costs 32,000
Offsite 3% of direct costs 77,000
Taxes 0.0% of direct costs 000
Spares 1% of direct costs 26,000
Allowance for shakedown 3% of direct costs 77,000
Total indirect costs $ 829,000
Contingency 680,000
Total $ 4,079,000
Coal conversion costs 60,000
Grand total § 4,139,000
$/kW 18.00
CROMBY POWER PLANT F-33
-------
TABLE F-10. ESTIMATED ANNUAL OPERATING COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 2 AT THE CROMBY POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 371 kW 26.45 mills/kWh $ 31,000
Water 24,228 x 103 gal/yr $0.011/103 gal 1,000
Operating Labor
Direct labor 1.0 man/shift $10.67/man-hour 46,000
Supervision 15% of direct labor 7,000
Maintenance
Labor and materials 2% of fixed investment 82,000
Supplies 15% of labor and materials 12,000
Overhead
Plant 50% of operation and maintenance 74,000
Payroll 20% of operating labor 11,000
Trucking
Bottom/fly ash 1,888,000
removal
Fixed Costs
Depreciation (5.88%)
Interim replacement (0.35%), £ = 19.73% of fixed
investment
Insurance (0.30%)
Taxes (2.00%)
Capital cost (11.20%) $ 805,000
Total fixed cost
Total cost $ 2,957,000
Fuel credit (9,099,000)
Net annual credit $ (6,142,000)
Mills/kWh (8.47)
CROMBY POWER PLANT F-34
-------
Table F-ll. ELECTROSTATIC PRECIPITATOR DESIGN
VALUES FOR BOILER 2 AT THE CROMBY POWER PLANT
Design Parameter
Values
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
98.78
206.25
123,800
4.0
15x167x19
CROMBY POWER PLANT
F-35
-------
n
»
o
s
03
*
t-1
i-3
N
OIL PtlXP HOUSE
CD
riN3 BOILER
TRANSFER
„ | fill J TWER
DD
CONTROL' -' U'-R N0-2
J 132KV SUB-STATION
DEI
TRANSFORMERS
~ "INTAKE CHAMBER— -
SCH'JYLKItt RIVER
I
ui
(Ti
Figure F-3. Site plan showing possible location of a new ESP
for Boiler 2 at the Cromby power plant.
-------
APPENDIX G
HOWARD M. DOWN POWER PLANT
HOWARD M. DOWN POWER PLANT G-l
-------
CONTENTS
Howard M. Down Power Plant Survey Form
Howard M. Down Power Plant Photographs
Page
«*—»-
G-3
G-15
Number
G-l
FIGURES
Site Plan Showing Possible Location of an
Add-on ESP for Boiler 10 at the Howard M.
Down Power Plant
Page
G-24
Number
G-l
G-2
G-3
TABLES
Estimated Capital Cost of an Add-On Electro-
static Precipitator for Boiler 10 at the
Howard M. Down Power Plant (1978)
Estimated Annual Operating Cost of an Add-On
Electrostatic Precipitator for Boiler 10 at the
Howard M. Down Power Plant (1978)
Add-On Electrostatic Precipitator Design Values
for Boiler 10 at the Howard M. Down Power Plant
Page
G-21
G-22
G-23
HOWARD M. DOWN POWER PLANT
G-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: City of Vineland
2. MAIN OFFICE: City Hall, 7th & Wood St., Vineland, N. J,
3. RESPONSIBLE OFFICER: Raymond Smith
4. POSITION: General Manager
5. PLANT NAME: Howard M. Down Station
6. PLANT LOCATION: West Ave. & Plum Sts., Vineland, N. J.
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Ralph E. Spain
8. POSITION: Plant Superintendent
9. POWER POOL
08360
DATE INFORMATION GATHERED: 7/20/76
PARTICIPANTS IN MEETING:
Raymond Smith
Ralph E. Spain
Mohan L. Puri
Raymond V. Dyba
N. David Noe
Alan Sutherland
City of Vineland Electric Utility
City of Vineland Electric Utility
City of Vineland Electric Utility
N. J. Dept. of Environmental Protection
PEDCo Environmental, Inc.
PEDCo Environmental, Inc.
HOWARD M. DOWN POWER PLANT
G-3
-------
I
D
O
O
5
13
f
B.
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 from AP42
LB/MM BTU (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
OPACITY, PERCENT
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( 1975)
4 . APPLICABLE SO- EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
10 1
oil-firing
0.05
31.5
AOCR
0.10
Priority
0.75
433
1.5 (coc
150
IA
1-f irina)
1.0% sulfur - oil-
Priority I
firing
II
a)
• w
163
SU
ai
roi
:ac
.me
-------
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):
HOWARD M. DOWN POWER PLANT G-5
-------
D.
ffi
i
O
s
D
O
O
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
8. GENERATING CAPACITY (MW)
RATED
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTION:
COAL OR OIL RATED
(TPH) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (1975)
OIL (JHMf) (1975) IQ3 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
10
6346
43.6
10
ERIG
1970
25
13.3-
57.3
None
187.71
12,514
12,284
Dry
No
~138
116
9
7000
9
CE
1960
16.5
8.7
38.3
None
128.67
Dry
No
~138
118
- 8
1207
8
B&W
1955
12.5
6.. 5
24.5
None
18.06
Dry
No
~138
84
7
407
7
B&W
1952
7.5
4.5
20.1
None
5.11
Dry
No
~138
84
4
91 •
3
B&W
1973
9.0
None
20.9
None
1.34
Dry
No
~138
89.5
Notes: * ERIG -. Erie City Iron Works.
CE - - C'^bus4- •• ^n H-"-" nee"1-"5 *ig
B&w - Baocock and Wiicox
-------
33
o
o
o
i
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 (FT2)
FLUE GAS TEMPERATURE
@ INLET ESP @ 100% LOAD (°F)
17. EXCESS AIR: DESIGN/ACTUAL (%)
Boiler number
*COTT
**MCTA
78/
COTT
E
98/
50/
***WEST *
**MCTA
90/
None
16/
**WEST
**MCTA
92. 8/
None
28/
***WEST
**MCTA
92. 7/
None
None
None
38/
Notes: * COTT - Research-Cottrell, Inc.
** MCTA - Multiple cyclones - conventional reverse flow tangential inlet.
*** WEST - Western Precipitation Div.
ESP - Built in 1970 and design for 2.34%S, 6.74% ash and 13,187 Btu/lb coal.
-------
EC
O
s
D
S
O
O
o
32
w
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 (S/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
100,781
270
22.88
Truckc
Twic«
77.025
315
16.90
d to land!
i a year -
54.570
305
23.64
ill (3 mi]
2 weeks
44.356
335
19.21
es one wa^
i
I
oo
a) Identify source of values (test or estimate)
Notes:
-------
ac
O
E . I . D . FAN DATA *
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
o
o
Notes: * Adequate fan capacity for coal-firing.
13
i
W
-------
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- Island Creek Coal Sales Co., West Virginia
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d.
3. ANALYSIS (1974)
HHV (BTU/LB) 13,480
ASH (%) 9.6
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA (1975)
1. TYPE
2. S CONTENT (%) .7
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. HHV (BTU/GAL) 146,660
I. NATURAL GAS HHV (BTU/FT3)
J. COST DATA
ELECTRICITY
FUEL: COAL GAS OIL
WATER
STEAM
TAXES ON A.P.C. EQUIPMENT: STATE SALES
STATE PROPERTY TAX
HOWARD M. DOWN POWER PLANT G-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?
Adequate capacity
2.
Boiler No.
Yes or No.
10
Yes
(1 month)
Yes
SYSTEM AVAILABILITY
2 . 1 COAL HANDLING
a. Is the system still installed?
b. Will it operate? 121
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? Yes Q
b. Will it operate? Q
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? Q
c. Of the following items which
need to be replaced:
Electrostatic Precipitator Yes Q
Cyclones D
Fly Ash Handling Equipment D
Soot Blowers - Air Compressors D
Wall deslaggers D
Yes D
D
D
D
Yes
NO a
D
Yes D
D
D
D
D
D
No ES
B
E3
B
H
IX
No D
D
No H
H
H
IX
No Q
D
No El
13
El
IX
IX
HOWARD M. DOWN POWER PLANT
G-ll
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes H No Q
b. Will it operate? [^ D
c. Of the following items which
need to be replaced:
Bottom Ash Handling YesD No [3
Ash Pond N/A Q D
HOWARD M. DOWN POWER PLANT G-12
-------
N. SUPPLEMENTARY CONTROL SYSTEM DATA
1. DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)? N/A Yes
If yes, attach a description of the system.
3.
5.
No
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
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 N/A
4. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss N/A
POWER PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(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?
d. Is the monitoring data reduced and
analyzed?
e. Provide map of monitoring locations
Yes (2 No
10,000 ton capacity
Yes
Yes
No
No
Yes
No D
Yes Q No
Yes fx| No
Number Type
Yes
Yes
No D
No
* One monitor located in Vineland and one located in
Ridgeton. If converted to coal, 2 additional monitors
at Vineland will be required by the State.
HOWARD M. DOWN POWER PLANT G-13
-------
b.2 Proposed system Yes fx] 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
A long-range modeling study is currently being conducted
on AQCR 150 by Engineering Science, Inc. to evaluate
current State laws with respect to particulate and SO2
emissions.
HOWARD M. DOWN POWER PLANT G-14
-------
Photo No. 1 View from ground level facing south
showing the Howard M. Down plant. Stacks 3, 4, 7, 8 and
9 are shown from right to left in the photograph. Stack
10 is shown behind Stack 9 at the left of the photo.
Photo No. 2 View from ground level looking east showing
Stack 10 and its ESP. The ash silo serving Boiler 10 is
also shown.
HOWARD M. DOWN POWER PLANT
G-15
-------
.-
Photo No. 3 View from the boiler house looking northwest
showing the coal pile and the vertical coal conveyor.
The cooling tower serving Boiler 9 is shown in the right
background of the photograph.
Photo No. 4 View from the roof of Boiler 10 facing east
showing the cooling tower serving Boiler 10. Plum Street
and the surrounding residential area are also shown.
HOWARD M. DOWN POWER PLANT
G-16
-------
Photo No. 5 View from the roof of Boiler 10 looking
northwest showing the cooling towers serving Boilers 4, 7,
and 8 and the spray pond. The electrical service building
is shown in the background of the photo.
Photo No. 6 View from the roof of Boiler 10 facing north
showing two fuel oil storage tanks and the surrounding
area.
HOWARD M. DOWN POWER PLANT
G-17
-------
Photo No. 7 View from the roof of Boiler 10 looking
northwest showing the coal pile, vertical coal conveyor,
and the track hopper house. National Freight Lines is
shown in the background.
Photo No. 8 View from ground level looking west
showing the coal car shaker located within the track
hopper house. The coal crusher is located under-
ground beneath the car shaker.
HOWARD M. DOWN POWER PLANT
G-18
-------
Photo No. 9 View from ground level facing east
showing the area surrounding stack and ESP for
Boiler 10. A possible site for an add-on ESP.
Photo No. 10 View from the roof of Boiler 10 facing
west showing the boiler-stacks and the commercial-
residential area surrounding the plant.
HOWARD M. DOWN POWER PLANT
G-19
-------
Photo No. 11 View from the roof of Boiler 10 looking east
showing the area surrounding the plant. Vineland's City
Hall is shown in the background of the photograph.
Photo No. 12 View from the roof of Boiler 10 facing
northeast. The area surrounding the Howard M. Down plant
is shown.
HOWARD M. DOWN POWER PLANT
G-20
-------
TABLE G-l. ESTIMATED CAPITAL COST OF AN ADD-ON
ELECTROSTATIC PRECIPITATOR FOR BOILER 10 AT THE HOWARD M.
DOWN POWER PLANT (1978)
Direct Costs
ESP $ 1,151,000
Ash handling 96,000
Ducting 107,000
Total direct costs $ 1,354,000
Indirect Costs
Interest during construction 8% of direct costs $ 108,000
Contractor's fee 10% of direct costs 135,000
Engineering 6% of direct costs 81,000
Freight 1.25% of direct costs 17,000
Offsite 3% of direct costs 41,000
Taxes 0% of direct costs 000
Spares 1% of direct costs 14,000
Allowance for shakedown 3% of direct costs 41,000
Total indirect costs $ 437,000
Contingency 358,000
Total $ 2,149,000
Coal conversion costs 205,000
Grand total $ 2,354,000
$/kW 94.16
HOWARD M. DOWN POWER PLANT G-21
-------
TABLE G-2. ESTIMATED ANNUAL OPERATING COST OF AN ADD-ON ELECTROSTATIC
PRECIPITATOR FOR BOILER 10 AT THE HOWARD M. DOWN POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 113 kW 34.7 mills/kWh $ 14,000
Water 9589 x 103 gal/yr $.023/103 gal 1,000
Operating Labor
Direct labor 1.0 man/shift $10.67/man-hour 47,000
Supervision 15% of direct labor 7,000
Maintenance
Labor and materials 2% of fixed investment 43,000
Supplies 15% of labor and materials 6,000
Overhead
Plant 50% of operation and maintenance 51,000
Payroll 20% of operating labor 11,000
Trucking
Bottom/fly ash 68,000
removal
Fixed Costs
Depreciation (3.12%)
Interim replacement (0.35%), Z = 15.97% of fixed
investment
Insurance (0.30%)
Taxes (1.00%)
Capital cost (11.20%)
lutdj. rixea costs
Total cost
Fuel credit
Net annual cost
Mills/kWh
$
$
$
343,000
591,000
(479,000)
112,000
1.19
HOWARD M. DOWN POWER PLANT G-22
-------
Table G-3. ADD-ON ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 10 AT THE HOWARD M. DOWN POWER PLANT
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
96.54
377
38,000
4
30x14x39
HOWARD M. DOWN POWER PLANT
G-23
-------
a:
I
§
o
Q
f
H3
WEST AVENUE
ro
SECOND STREET
10 9
o
0
0
COOL ING
TOWERS
O
O
O
II
NATIONAL
FP.EISHT
LINES
ELECTRICAL
SIS'/ICE
BUILDING
Figure G-l. Site plan showing possible location of an add-on ESP
for Boiler 10 at the Howard M. Down power plant.
-------
APPENDIX H
FOX LAKE POWER PLANT
FOX LAKE POWER PLANT H-l
-------
CONTENTS
Page
Fox Lake Power Plant Survey Form H-3
Fox Lake Power Plant Photographs H-15
FOX LAKE POWER PLANT H-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: INTERSTATE POWER CO.
2. MAIN OFFICE: 1000 Main St., Dubuque, Iowa 52001
3. RESPONSIBLE OFFICER: E. *D. Forslund
4. POSITION: Chief Production Engineer
5. PLANT NAME: Fox Lake Power Station
6. PLANT LOCATION: Fox Lake, Martin County, Sherburn, Minn. 56171
7. RESPONSIBLE OFFICER AT PLANT LOCATION: A. H. Hanson
8. POSITION: Plant Superintendent
9. POWER POOL MAPP
DATE INFORMATION GATHERED: December 31, 1976
PARTICIPANTS IN MEETING:
Michael R. Chase - Interstate Power Company
. Allen H. Hanson - Interstate Power Company
Kenneth J. Kiss - Interstate Power Company
Frank L. Blackhall - Minnesota Pollution Control Agency
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.
'FOX LAKE POWER PLANT
H-3
-------
B.
Q
f
a-
w
i
w
f
^3
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS61
LB/MM BTU "•
GRAINS/ACF 1975 Fuel
LB/HR (FULL LOAD);@ 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 1975 Fuel
LB/HR (FULL LOAD) @ Full load
TONS/YEAR (1975 )
4. APPLICABLE SO2 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION: & SECTION NO.
JDB0M&kJBffiU ,% S
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
Estimate
- coal
9.89
3.24
1602
1 2^-fi
Stipulatio
APC 11
.6
Estimate
1.61
261.5
80.1
APC 4
2.0
4.0
2
Estimate
coal.
9.89
3.24
1602
133.8
n Agreemen
APC 11
• 6
Estimate
1.61
261.5
86.8
APC 4
2.0
4.0
3
Estimate
30 MW coal
9.95
3.90
3444
597 1
t- Unlimit
e
APC 11
.6
Estimate
1.62
562.4
1136.8
APC 4
2.0
4,0
3
Estimate
30 MW coal
+56 MW 01
T_fi4
1.36
3444
ed until 7
APC 11
.6
Estimate
1.78
.1685.2
1
-1-77
ult~ ire ^-
es
iatr •
-------
SITE DATA
1. HXXXM. COORDINATES ^at. 43°40'10" Long. 99°43'00"
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 1243
3. SOIL DATA: BEARING VALUE
PILING NECESSARY Existing Plant on Wood Friction Piling
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) 114' 6"
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE); None
FOX LAKE POWER PLANT H-5
-------
o
X
o
M
F<
>-3
3. BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
2. TOTAL HOURS OPERATION (1975)
3. AVERAGE CAPACITY FACTOR (19 )
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:
COAL OR OIL RATED
(TPH) OR (GPH) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION
GAS MMCF/Year
COAL (TPY) (1975)
OIL (GPY) (1975)
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
Peak
1629
12.7%
1
Riley
1950
>15 yrs
12 MW
II
II
Coal 9.3
TPH
n
ii
108
1435
10
DRY
NO
141
96
2
Peak
1740
14.0%
1
Riley
1 950
>15 yrs.
12 MW
M
»
Coal 9.3
TPH
n
n
117
1554
11
DRY
NO
3
Base
7826
38.0%
3
Ril PV
1 9fi?
>25 yrs
Joai Jy MW
3as 86 MW
Dil 86 MW
Tombinatio
M
M
Coal 20.0
TPH
M
n
1985
6934
175
DRY
NO
142
96
3
i 86 MW
Coal 20.0
& Ojll 3g6
It
g
EC
I
Notes: Flame Stabilization Oil Needed on #3 Boiler When Burning Coal
Minimum = 365 GPH
-------
o
X
w
hd
O
S
td
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)
(#/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
None
None
2
None
None
3
None
Ordered
Buell
BA l.Ix3bIS
QQ 0%
. n? ) PHI
=in fiV
BB )
1?
q^312
285
20%
444-2 . 3P
1 load wit
h. 30 MW on
COi
Notes:
a
i
-------
O
X
t-1
>
«
w
^
O
f
t-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
2
3
295000
215000
145000
285
265
245
97.8
71.3
48.1
7649
Ash Pond
1364
Ash Pond
Print
Print
Non-
Available
I
oo
a) Identify source of values (test or estimate)
Notes: i. Ash based on burning 100000 tons/year of coal (estimate)
2. We do not believe 100% capacity can be attained on 8450 Btu/#
coal as the boiler was designed for 11400 Btu/# coal.
-------
o
X
T)
o
s:
w
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C-)
2. WORKING STATIC HEAD (IN.'W.C.)
Boiler number
1
2
3
None
Existing
Ordered
Notes:
f
•-3
ffi
i
VD
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) 2.2
2. YEARS STORAGE (ASH ONLY) Bottom & Fly Ash - 1 year
3. DISTANCE FROM STACK (FT.) 1?Q ft to edge of pond
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT Available area is small
COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a • Westmoreland Resources
k • Sarpy Creek Mine
c.
Big Horn County, Montana
d. Robinson and Rosebud-McKay Seams
2. QUANTITY USED BY SEAM AND/OR MINE
a. 100000 tons/year
b.
c.
d.
3. ANALYSIS
GHV (BTU/LB) 8450
S (%) 0.73
ASH (%) 9.09
MOISTURE (%) 25.0%
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE #6
2. S CONTENT (%) 1.72
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL) 151379
COST DATA
ELECTRICITY Rate tariff
WATER lake Water
STEAM 4-12-76 Inventory fuel cost - #6 oil - $1.96/106 Btu Coal - $1.32/10 6:
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS A1-, -\ILABLE?
FOX LAKE POWER PLANT H-10
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes 0 NoD
b. Will it operate? (3 D
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes D
Ash Pond D
FOX LAKE POWER PLANT H-ll
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
1
Yes
2
Yes
3
Yes - 30MW
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
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 Eguipment
Soot Blowers - Air Compressors
Wall deslaggers
Yes
Yes
D
D
D
D
D
P
Yes
Q
D
D
D
D
Yes D
D
D
D
P
NoD
D
No D
All 1
to ge+-
full
capac y
NoD
n
No S Yes t
H get £~1
S capacity
5)
No
No D
D
D
D
FOX LAKE POWER PLANT
H-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? 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
Yes
Yes
Number
No El
No [x]
No [x]
Type
c. Is the monitoring data available?
d. Is the monitoring data reduced and
analyzed? .
Yes | j No [~|
Yes No H
FOX LAKE POWER PLANT
H-13
-------
(2) Suspended particulate
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
5.2 Proposed system Yes Q No [x]
If yes, describe
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
' FOX LAKE POWER PLANT H-14
-------
Photo No. 1. View from the boiler house roof looking north.
The stack for Boiler 3 and the tie-in ducts for air pre-
heating system are in the center of the photograph.
Photo No. 2. View from the boiler house roof facing north
showing the stack for Boiler 3 and water storage tank.
FOX LAKE POWER PLANT
H-15
-------
Photo No. 3. View from the boiler house roof facing south-
east. The coal conveyor is shown in the center foreground.
The coal pile is shown in the center of the photograph. The
darker area in the background illustrates the close prox-
imity of the nearby farmer's field.
Photo No. 4. View from the boiler house roof looking south.
Fuel oil storage tanks are shown in the center of the photo.
Interstate 90 and the nearby farmer's field are shown in the
background.
FOX LAKE POWER PLANT
H-16
-------
Photo No. 5. View from the boiler house facing west. The
discharge water canal is shown in the center of the photo.
The ash pond is shown in the extreme right-hand corner.
Photo No. 6. View from boiler house roof looking east
showing the surrounding area.
FOX LAKE POWER PLANT
H-17
-------
Photo No. 7. View from ground level facing northwest
showing base of Boiler-Stack 3 and its close proximity to
Fox Lake.
Photo No. 8. View from boiler house roof looking southwest.
The switchyard is shown in the right-hand corner of the
photograph. The oil storage tanks and the nearby farm house
are shown in the center of the photograph.
FOX LAKE POWER PLANT
H-18
-------
Photo No. 9. View from boiler house roof facing northwest
showing the ash pond and the surrounding area.
\
Photo No. 10. View from ground level looking northeast
showing the approximate area for the new electrostatic
precipitator addition.
FOX LAKE POWER PLANT
H-19
-------
APPENDIX I
HUDSON POWER PLANT
HUDSON POWER PLANT 1-1
-------
CONTENTS
Hudson Power Plant Survey Form
Hudson Power Plant Photographs
Page
1-4
1-21
Number
1-1
1-2
1-3
FIGURES
Site Plan Showing Possible Locations of Major
Components for the Sodium Solution Regenerable
System for Boiler 1 at the Hudson Power Plant
Site Plan Showing Possible Locations of Major
Components for the Limestone System for Boiler
1 at the Hudson Power Plant
Site Plan Showing Possible Location of an Add-On
ESP for Boiler 1 at the Hudson Power Plant
Page
1-31
1-37
1-41
Number
1-1
1-2
1-3
1-4
TABLES
Estimated Capital Cost of a Sodium Solution
Regenerable System for Boiler 1 at the Hudson
Power Plant (1978)
Estimated Annual Operating Cost of a Sodium
Solution Regenerable System for Boiler 1 at the
Hudson Power Plant (1978)
Retrofit Equipment and Facilities for the Sodium
Solution Regenerable System for Boiler 1 at the
Hudson Power Plant
Retrofit Equipment Dimensions Required for the
Sodium Solution Regenerable System for Boiler
1 at the Hudson Power Plant
Page
1-26
1-28
1-29
1-30
HUDSON POWER PLANT
1-2
-------
TABLES (continued)
Number Paqe
1-5 Estimated Capital Cost of a Limestone Scrubbing
System for Boiler 1 at the Hudson Power Plant
(1978) 1-32
1-6 Estimated Annual Operating Cost of a Limestone
Scrubbing System for Boiler 1 at the Hudson
Power Plant (1978) 1-34
1-7 Retrofit Equipment and Facilities Required for
the Limestone Scrubbing System for Boiler 1 at
the Hudson Power Plant 1-35
1-8 Retrofit Equipment Dimensions Required for the
Limestone Scrubbing System for Boiler 1 at the
Hudson Power Plant 1-36
1-9 Estimated Capital Cost of an Electrostatic
Precipitator for Boiler 1 at the Hudson Power
Plant (1978) 1-38
1-10 Estimated Annual Operating Costs of an Electro-
static Precipitator for Boiler 1 at the Hudson
Power Plant (1978) 1-39
1-11 Electrostatic Precipitator Design Values for
Boiler 1 at the Hudson Power Plant 1-40
HUDSON POWER PLANT 1-3
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION;
COMPANY NAME: Public Service Electric & Gas Company
2. MAIN OFFICE: go Park Place, Newark, New Jersey 07101
3. RESPONSIBLE OFFICER: Edward S. Kirby
4. POSITION: General Solicitor
5. PLANT NAME: Hudson
6. PLANT LOCATION: Duffield & Van Keuran Aves., Jersey City,N.J.O Oi
7. RESPONSIBLE OFFICER AT PLANT LOCATION: R> p> steinke
8. POSITION: Manager
9. POWER POOL PJM
DATE INFORMATION GATHERED: july 13, 1976
PARTICIPANTS IN MEETING:
James A. Shissias - Public Service Electric and Gas Co.
Sara P. Siebert - Public Service Electric and Gas Co.
Paul H. Sutphen - Public Service Electric and Gas Co.
Michael W. Costic - Public Service Electric and Gas Co.
Jeffrey A. Aynds - Public Service Electric and Gas Co.
Theodore F.. Glenhamn - Public Service Electric and Gas Co
David C. Hughes - Public Service Electric and Gas Co.
William R. Duke - Public Service Electric and Gas Co.
Jim Garofallou - Public Service Electric and Gas Co.
Dr. C.F. Miranda - U.S. EPA - Durham, North Carolina
Ray Werner - U.S. EPA - Region II Officer
Alan J. Sutherland - PEDCo Environmental, Inc.
Robert L. Hearn - PEDCo Environmental, inc.
N. David Noe - PEDCo Environmental, Inc.
HUDSON POWER PLANT 1-4
-------
B.
BC
G
a
en
o
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3 (calculated!1
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. SO- EMISSIONS3 (calculated)
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR (1975)
4. APPLICABLE SO, EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU (with Control Devicel
% Sulfur In Fup.1
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
1
Oil
Unknown
1
NJAC 7:27
0.1
20
-
0.315
1 r 11 5
2.900
NJAC 7:27
0.3 for
3.3% Oil.
—
BO.
-)
coal*
0.1
560
RR1
- 3.1 et s
0.1
20
-
2.15
11,200
14 P19
- 9.1 et
oi 1 xr\(\ f
L.Oft Coal
tier numbe
Pq *nrl 4
eq. (Oil)
^al
Ivisring S
r
0*- <=0q
N.Tar 7-?7
inrces ,0.2
••
10.1 &t-r^
Coal- New
Source
q
a
a) Identify whether results are from stack
Note: 1.5% sulfur variance for No. 2
tests or estimates
Unit - Expires 12/31/76
-------
SITE DATA
N40° 45 Min 0 Sec, N74Q Min 30 Sgg
1. u.T.M.
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) '8.39 (Sandy Hook Datum)
3. SOIL DATA: BEARING VALUE --- _ . -
PILING NECESSARY Yes
DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE)
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE):
HUDSON POWER PLANT I~6
-------
D. BOILER DATA
C
D
O
s;
M
i
-j
^ f- ——^—^—
Full load days, low load nigh :s and some, weekend
days
7217
AVERAGE CAPACITY FACTOR (1975)
SERVED BY STACK NO.
BOILER MANUFACTURER
YEAR BOILER PLACED~IN SERVICE
REMAINING LIFE OF UNIT
55.3
on 4 5
GENERATING CAPACITY
RATED
(MW)
*B&W
1964
383
Gas (103FT3/hr
Coal (Tons/hr
) 540
3780
124
PEAK
- 10. ACTUAL FUEL CONSUMPTION1975 CoalU-O^ons^
(103 Bbls)
Full load at 60°F Circulating
Water Temperature
12. WET OR DRY BOTTOM
9850
1350
13. FLY ASH REINJECTION (YES OR NO)
B&W - The Babcock & Wilcox Co.
Notes: FW - Foster Wheeler Corp.
No
325.5
168
1968
6000
197
529
2490.2
9550 (Ex
No
210
aected)
-------
EC
C
D
F
t-3
I
oo
1.6.. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
Boiler number
1
EFFICIENCY: DESIGN/ACTUAL (%) 1
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 (Design)
@ INLET ESP @ 100% LOAD (°F)
17. EXCESS AIR: DESIGN /ACTUAL (%)
West*
E
99
See Atte
2
Cott*
E
qq . e;
ched Sheet
1
10 Sets
fl «;fa/-"£ir-\]i^
191,808
300
16/12
16 Sets
3 32 Secrfei^
374,400
250 to 3(
s
)0
30/- Oil
West - Western Precipitator Division -/12 ~/17 Gas
Notes: Cott _ Research-C6ttfell", inc. 16/21 18/18 Coal
-------
PUBLIC SERVICE SL2CT?,IC'AND CAS COMPANY
HTIPSOW Gi::-:2?.ATIKG STATION
JERSEY CITY, HUDSON COUNTY. NEW JERSEY
ac
G
D
CO
s
0
M
»
•"T)
96.9
97.8
Sh-.Bl
98.5
98.2
TEMP .
( °? )
299
296
276
. 252
259
268
256
255
250
GAS ' ^
FLOV/ :•: 1C
(acfm)
1.0U3.-2
963.6
1,199.6
1,058.2
l
SULF .
(^)
2.UU
0.6U
2.58
2.U6
1.00
1.12
1.11
1.15
1.0U
AS:-;
( '/j)
5.93J
6.3^
6.8^
10.8:
10.16
9.2^1
9.73
8.91
i
MOI3. f
' ( *£)
3.68
U.96
U.90
6.80
8.U1
8.31
6.23
6.59
7.89
•"A.ST.
vL^.-rir )
211
157
U25
966
37^
601
83^
686
356
y?c:< COAL'
?i?.i::c J.ASZ
on ??.z5z::?
CG::DITIG::I
( lb /r.r ;
9021
'•
1
1
i
1
t *
Based on coal vith i.2% sulfur and 10.8% ash with 30% of the ash to the precipl^a^or , past test
data, operating experience and present condition.
tote 2: Normal full load operating conditions.
;ote 3: 88% Load
lote U: 93% Load ' • .
• .i.e. .v-- — «.^»%'n».'"'s-H/»no+RH
-------
G
D
en
o
O
Dates 3/29 to 6/13/74
Air Heater Outlet Temp. 230U to 345°:
Sulfur(%) 1.6 to 1.37
Ash(%) 9.9 to 13.5
Moisture(%) 6.09 to 9.88
PARTICIPATE EMISSIOKIS
Wo. 2 UM>T
WUDSOKJ GENERATING STATION
PUBLIC SERVICE ELECTRIC / GAS CO.
tr1
i-3
800
700
600
>. a 500
2
£, 400
•2
O
in .300
£
UJ
eoo
100
i
M
O
D CHAPTER 5 ALLOWABLE
O ACTUAL EMISSIONS
CHAPTER 5 ALLOWABLE
ACTUAL EMISSIONS
IOO
200
TOO
GROSS LOAD
-------
—^^= — —
Boiler number
G
O
C/)
O
z
F
>
Z
19.
LUE GAS RATE (ACFM)
@ 100% LOAD (Design)
@ 75% LOAD
@ 50% LOAD
TACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
@ 75% LOAD
@ ' 50% LOAD
:XIT GAS STACK V^OCITYj (FPS)a
@ 100% LOAD
(3 75% LOAD
i T
899,000
638.000
435.000
291
230
225
11 -5
lj
69.1
•)
L. 640, 000
i, IRQ rooo
B4i rnnn
?7Q
260
•?in
•1 -1 -5 -1
fll .5
Act
1,032,000
al
1,800,000
I
1
(§ 50% LOAD
21. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
22. BOTTOM ASH: TOTAL COLLECTED(TONS/
YEAR)
DISPOSAL METHOD
DISPOSAL COST ($/TON)
23. EXHAUST DUCT DIMENSIONS @ STACK
24. ELEVATION OF TIE IN POINT TO STACK
25 SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
19
1977
197
' 1979 6.wks (2/17) 15wks (9/11)
a) Identify source of values (test or estimate)
Notes. Estimated fly ash and bottom ask collected on No. 1 Unit xs calculated based on
N° burning coal with an equivalent Btu heat input of the oil actual fired in 1975.
Actual fly ash and bottom ash collected on No. 2 Unit is less than expected due
to outages of coal equipment.
-------
cn
O
Z
O
s
w
E. I.D. FAN DATA
C 1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD. (IN. W.G.)
Boiler number
Notes: Not Equipped
i
M
N)
-------
FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) 2:.6 (50,000 yds)
YEARS STORAGE tftSH-QNfcYfr (Ash & Fly Ash) 140 Days (Only No. 2 Unit on
' ~~ Coal)
3. DISTANCE FROM STACK (FT.) 1,500 (To discharge? point)
„__ _... ,...,_ ,7T,,7T? nnMHTMrFly ash and bottom ash go to same pond
4. DOES THIS PLANT HAVE PONDING^* g has Insufficient capacity .Require
PROBLEMS? DESCRIBE IN ATTACHMENT a1mns1. rnmf-nnt rrTn^»ni hy tr'"*"
POM DATA See Attached Sheets to site available at this time.
COAL DAI A availability of
1. COAL SEAM, MINE, MINE LOCATION site is unknown.
a.
b.
2. QUANTITY USED BY SEAM AND/OR MINE
c.
d.
ANALYSIS (19
HHV (BTU/LB)
S (%)
ASH (%)
MOISTURE (%)
4.
PPT PERFORMANCE EXPERIENCED WITH LOW Experience with low sulfur
S FUELS (DESCRIBE.IN ATTACHMENT) coa^ demons trafe^ff ejected
H. FUEL OIL DATA (1975)-
1. TYPE No. 6
2. S CONTENT (%) Oj3
3. ASH CONTENT (%) Oj01 to 0>04
4. SPECIFIC GRAVITY Q.889 to 0.9Q8
5. HHV (BTU/GAL) 142.810 .
I. NATURAL GAS HHV (BTU/FT3) 1030
j. COST DATA (See attached economic evaluations)
ELECTRICITY
FUEL: COAL $1. 51/MBtlCAS $1. 50/MBtUOIL $1.96/MBtu
WATER $2.50/1000 gals.
STEAM ^
TAXES ON A.P.C. EQUIPMENT: STATE SALES
FEDERAL PROPERTY TAX
HUDSON POWER PLANT
1-13
-------
HUDSON NO. 1 COAL DATA
Heating Value - 13,300 Btu/lb FTA - 2000 to 2100
Dry Sulfur - 2.6% HGI - 60
Dry Ash - 7.3% VOL-- 35%
Moisture - 4.0%
1968 CALENDAR YEAR
Tons
Mine Location Seam Quantity
Joanne W. Virginia Pittsburgh i?'~!
Consol W. Virginia Pittsburgh 52,068
Federal w- Virginia Pittsburgh
O'Donnell W. Virginia Pittsburgh
Valley Camp W. Virginia Pittsburgh
Compass W. Virginia Pittsburgh "o'^
„ „ V-i mini a Tiller 8,33^
Moss
Virginia Tiller
HUDSON POWER PLANT I~14
-------
HUDSON NO. 2 COAL DATA
Heating Value
Dry Sulfur
Dry Ash
Moisture
13,000 Btu/lb
1.2%
10.0%
5.0%
FTA 2650 to 2700
HGI 85
VOL 28
1976-77 FUEL YEAR PURCHASE
Deep Hollow
Bolair
Benjamin #3
Kitt
Wellmore #7
Black Watch
Dale Ridge
Location
W. Virginia
W. Virginia
W. Virginia
Pennsylvania
Pennsylvania
Virginia
Virginia
Virginia
Seam
U&L Kittanning
L. Freeport
U. Freeport
Fire Creek
11B" & "C"
Upper Freeport
Splashdam, Clintwood
Splashdam
Upper Banner
Tons
Quantity
168,000
420,000
84,000
84,000
84,000
84,000
42,000
42,000
HUDSON POWER PLANT
1-15
-------
K,
L,
M
Sufficient for coal
firing without FGD
Systems
4160
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STA??ON CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE?
ADDITIONAL INFORMATION
F.E.A. LETTER
OI_L/GAS TO COAL_CpNVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
~
Yes or No.
2 SYSTEM AVAILABILITY See Next Page
2 1 COAL HANDLING
a. is the system still installed? Yes D
b. Will it operate?
c Of the following items which
need to be replaced:
Unloading equipment
Stack Reclaimer
Bunkers
Conveyors
Scales
Coal Storage Area
D
2.2
FUEL FIRING
a. is the'system still installed?
Will it operate?
Of the following items which
need to be replaced:
Pulverizers or Crushers
Feed Ducts
Fans
Controls
b
c
YesQ
D
D
D
2.3
b
c
GAS CLEANING •
a. is the system still installed? *es Q
Will it operate?
Of the following items which
need to be replaced:
Electrostatic Precipitator
Cyclones
Flv Ash Handling Equipment
Soot Blowers - Air Compressors
Wall deslaggers
D
Yes D
D
D
D
D
NoQ
D
YesO
D
D
D
D
D
YesD
n
No D
D
D
D
D
D
NoD
D
NoD
D
D
D
No D
D
No D
D
D
D
D
HUDSON POWER PLANT
1-16
-------
2.4 ASH HANDLING
a. Is the system still installed? Yes D NoQ
b. Will it operate? D D
c. Of the following items which
need to be replaced: . '
Bottom Ash Handling YesD NoD
Ash Pond D Q
All equipment associated with coal firing initially installed
on No. 1 Unit is in place. However, all of the equipment requires
an extensive major overhaul which would include replacement of
various components due to previous wear and deterioration. Normal
routine maintenance was not performed during the months immediately
prior to oil conversion. The overhauled precipitator would not
limit particulate emissions to the levels required by the New Jersey
Department of Environmental Protection. No. 2 Unit is presently
burning coal.
HUDSON POWER PLANT 1-17
-------
N .
1.
3.
Yes
DOES THE PLANT NOW HAVE A SUPPLEMENTAL CONTROL
SYSTEM (SCS)?
If yes, attach a description of the system.
IS TIIF PLANT CAPABLE OF SWITCHING TO LOW .
SULFUR FUELS?Can fire natural gas if available «es
Mo
D
? 1 Storage capacity for low sulfur fuels (Existing No 6 Fuel Oil
(tons bbls days) Storage Tanks) 326,500 Bbls (9.5 ^^^ *t
(tons, DDib, j / iQ _ incnuding No- 2 Unit)
2 2 Bunkers available for tow sulfur coaT _ _
storage?
2.3 Handling facilities available for low
sulfur fuels
If yes , describe
2 /I 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 See Next Paqe
/I. IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss See
5. POV.'F.lt PLANT MONITORING SYSTEM
5.1 Existing system
a. Air quality instrumentation
(1) Sulfur Oxides - Continuous
- Intermittent
- Static
(2) Suspended parti culatcs
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe Wind direction
and ve 1 oc i ty a t__B.larvb. ______
c. Is the monitoring data available?
d. Is the monitoring data reduced and
analyzed?
e. Provide map of monitoring locations
D
Yes
No
Yes
No
Yes
No
Yes (J No
Number Type
Yes {Xj No
Yes No
HUDSON POWER PLANT
1-18
-------
N-3 & N-4
All plants are loaded economically to produce electrical energy
at the lowest cost. Specific plants could reduce load with
resultant increased production costs if generation is available
at other locations and transmission facilities are not fully
loaded. Emergency plans for high ambient pollutant levels are
on file with the New Jersey Department of Environmental Protection,
These plans include changes in normal operating procedures such
as reduction of sootblowing activities. Load reductions would
follow as a result of plans instituted by the State to reduce
energy consumption (closing of commercial establishments etc).
HUDSON POWER PLANT 1-19
-------
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 particulatc
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
HUDSON POWER PLANT -1
-------
Photo No. 1 • View of the power plant facing northwest,
Stack No. 1 is shown on the left and Stack No. 2 is shown
on the right. Coal conveyors stretch across the photograph
Photo No. 2 - View from the boiler roof near Stack No. 1
facing southwest, the Hackensack River is shown on the left.
Koppers coke plant is shown in the center across the River.
The Kearny power plant (5 stacks) is shown in the background
•HUDSON POWER PLANT
1-21
-------
Photo No. 3 - View from the roof of Boiler No. 1 looking
north, the 230 kv switchyard is shown. An ash disposal area is
shown to the left of the oil storage tank. The bank of the
Hackensack River is shown on the left.
Photo No. 4 - View from the roof of Boiler No. 2 looking
east, the 138 kv Marion switching station is shown. The
edge of the coal storage area is shown on the right.
HUDSON POWER PLANT
1-22
-------
Photo No. 5 - View from the roof of Boiler No. 2 looking
southeast, the coal storage area is shown. The breaker
tower is shown in the center with coal conveyors leading
to Boilers 1 and 2 on the right and left, respectively.
~
\
Photo No. 6 - View from the roof of Boiler No. 1 looking
south, the coal crusher tower with conveyors leading to
Boiler No. 1 is shown in the center. The Marion Generating
Station (retired) is shown in the background. Stack No. 1
is shown on the right.
HUDSON POWER PLANT
1-23
-------
Photo No. 7 - View from ground level, looking west, barge
unloading equipment is shown in the center. Transmission line
towers are shown in the foreground.
Photo No. 8 - View from ground level, looking south, the west
side of Boiler No. 1 is shown on the left and the barge
unloader is shown on the right. The Marion Station is
in the background.
HUDSON POWER PLANT
1-24
-------
Photo No. 9 - View from the roof of Boiler Ho. 1 looking
southwest, Stack and ESP for Boiler No. 1 are shown in the
center. Coal conveyor stretches across photograph.
"*"»-*
*"••».,
Photo No. 10 - View from ground level, facing east, showing
area available for control equipment. Underground gasoline
tank is located in the foreground. Stack No. 2 is shown
in the background.
HUDSON POWER PLANT
1-25
-------
TABLE 1-1. ESTIMATED CAPITAL COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 1 AT THE
HUDSON POWER PLANT (1978)
Direct Costs
A. Soda Ash Preparation
Storage silos $
Vibrating feeders
Storage tanks
Agitators
Pumps and motors
57,000
6,000
26,000
26,000
2,000
Total A =
117,000
B. S02 Scrubbing
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
Total B =
$ 9,192,000
1,017,000
269,000
1,607,000
978,000
1,960,000
322,000
$15,345,000
C. Purge Treatment
Refrigeration unit
Heat exchangers
Tanks
Dryer
Elevator
Pumps and motors
Centrifuge
Crystallizer
Storage silo
Feeder
(continued)
HUDSON'POWER PLANT
Total C =
262,000
39,000
56,000
27,000
14,000
256,000
523,000
628,000
56,000
6,000
$ 1,867,000
-------
TABLE 1-1 (continued)
D. Regeneration
Pumps and motors $ 226,000
Evaporators and reboilers 2,957,000
Heat exchangers 386,000
Tanks 52,000
Stripper 116,000
Blower 125,000
Total D = $ 3,862,000
E. Particulate Removal
Venturi scrubber $ 4,035,000
Tanks 109,000
Pumps and motors 555,000
Total E = $ 4,699,000
Total direct costs = A + B + C + D + E = F = $25,890,000
Indirect Costs
Interest during construction $ 2,589,000
Field labor and expenses 2,589,000
Contractor's fee and expenses 1,295,000
Engineering 2,589,000
Freight 323,000
Offsite 777,000
Taxes 000
Spares 129,000
Allowance for shakedown 1,295,000
Acid plant 1,386,000
Total indirect costs G = $12,972,000
Contingency H = 7,772,000
Total = F + G + H = $46,634,000
Coal conversion costs 15,080,000
Grand total $61,714,000
$/kW 161.13
HUDSON POWER PLANT I_27
-------
TABLE 1-2. ESTIMATED ANNUAL OPERATING COST OF A SODIUM
SOLUTION REGENERABLE SYSTEM FOR BOILER 1 AT THE
HUDSON POWER PLANT (1978)
Quantity
Unit Cost
Annual Cost
Raw Materials
Soda ash
Utilities
Process water
Cooling water
Electricity
Reheat steam
Process steam
Operation Labor
Direct labor
Supervision
Maintenance
0.47 ton/h
$ 90 /ton
2246.2 gal/min $0.041/10 gal
8.9 x 103 gal/min $0.010/10J gal
8744 kW 33.1 mills/kWh
61.0 x 106 Btu/h $1.685/10° Btu
130.8 x 106 Btu/h $1.685/106 Btu
2 men/day $lo.67/man-hour
15% of direct labor
Labor and materials 4% of fixed investment
Supplies 15% of labor and materials
Operating and Maintenance
Additional cost
Overhead
Plant
Payroll
Fixed Costs
Depreciation
Interim replacement
Insurance
Taxes
Capital cost
Total fixed cost
Total cost
Credits (byproducts)
50% of operating and maintenance
20% of operating labor
(5.00%)
(0.35%)
(0.30%)
(4.00%),
(11.20%)
Z = 20.85% of fixed
investment
$ 156,000
21,000
20,000
1,063,000
378,000
811,000
187,000
28,000
1,865,000
280,000
1,817,000
1,180,000
43,000
$ 9,723,000
$ 17,572,000
Sulfuric acid
Na2S04
Total byproduct
Fuel credit
Net annual cost
Mills/kWh
6.50
0.47
credits
ton/h
ton/h.
$58.
$71
71/ton
.4yton
$
$
V-L
(1
(14
1
, i v _>
(123
,528
.965
,079
,
f
i
i
0
U\J\J)
000)
000)
000)
000
.77
HUDSON POWER PLANT
1-28
-------
Table 1-3. RETROFIT EQUIPMENT AND FACILITIES
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM
FOR BOILER 1 AT THE HUDSON POWER PLANT
Module
Description
Number
Required
Size/Capacity
Absorbers
Flue gas fans
Na-CO- storage
Na2C03 preparation
SO- regeneration
Purge treatment
Sulfuric acid plant
4
4
1
1
1
1
1
96 MW capacity unit
Scaled to train size
338 tons (30-day storage)
940 Ib/hr, Na2CO_
7856 Ib/hr, S02
940 Ib/hr, Na2SO
59.4 tons/day, HSO.
HUDSON POWER PLANT
1-29
-------
Table 1-4. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE SODIUM SOLUTION REGENERABLE SYSTEM FOR BOILER 1
AT THE HUDSON 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
18 diam x 37 high
35 diam x 35 high
45 high x 15 wide x 35 long
51 wide x 160 long
54 wide x 183 long
75 wide x 161 long
HUDSON POWER PLANT
1-30
-------
/SWITCHING STATION
FUEL OIL
TANK
CRUSHER
HOUSE
COAL CONVEYING
SYSTEM /
MARION
GENERATING
STATION
BARGE
UNLOADER
HACKENSACK RIVER
A PURGE TREATMENT AND
SO- REGENERATION
8 ACID PLANT
C SCRUBBERS
D STORAGE SILO
E SOLUTION TANK
i
Ul
Figure 1-1. Site plan showing possible locations of major
components for the sodium solution regenerable system
for Boiler 1 at the Hudson power plant.
-------
TABLE 1-5. ESTIMATED CAPITAL COST OF A LIMESTONE
SCRUBBING SYSTEM FOR BOILER 1 AT THE
HUDSON POWER PLANT (1978)
Direct Cost
A.
Limestone Preparation
Conveyors
Storage silo
Ball mills
Pumps and motors
Storage tanks
$ 413,000
77,000
644,000
124,000
95,000
Total A = $ 1,353,000
B. Scrubbing
Absorbers
Fans and motors
Pumps and motors
Tanks
Reheaters
Soot blowers
Ducting and valves
Total B =
$ 7,280,000
1,111,000
581,000
455,000
1,581,000
488,000
2,261,000
$ 13,757,000
Sludge Disposal
Clarifiers
Vacuum filters
Tanks and mixers
Fixation chemical storage
Pumps and motors
Sludge pond
Mobile equipment
Total C =
(continued)
HUDSON POWER PLANT
$ 207,000
308,000
8,000
26,000
51,000
1,320,000
64,000
$1,984,000
1-32 '
-------
TABLE 1-5 (continued)
D. Particulate Removal
Venturi scrubber $ 3,971,000
Tanks 124,000
Pumps and motors 167,000
Total D = . $ 4,262,000
Total direct costs =A+B+C+D=E= $ 21,356,000
Indirect Costs
Interest during construction $ 2,136,000
Field overhead 2,136,000
Contractor's fee and expenses 1,068,000
Engineering 2,136,000
Freight 266,000
offsite 641,000
Taxes 000
sPares 107,000
Allowance for shakedown 1,068,000
Total indirect costs F = $ 9,558,000
Contingency G = 6., 183, 000
Total =E+F+G= $ 37,097,000
Coal conversion costs 15,080,000
Grand total $ 52,177,000
SAW 136.23
HUDSON POWER PLANT 1-33
-------
TABLE 1-6. ESTIMATED ANNUAL OPERATING COST OF A
LIMESTONE SCRUBBING SYSTEM *FOR BOILER 1 AT THE
HUDSON POWER PLANT (1978)
Quantity Unit Cost Annual Cost
Raw Materials
Limestone 9.0 ton/h $16.81/ton $ 562,000
Fixation chemicals 24.0 ton/h $2.20/ton 195,000
Utilities
Water 127.4 gal/min $0.041/103 gal 1,000
Electricity 7011 kW 33.1 mills/kWh 853,000
Fuel for reheat 60.0 x 106 Btu/h $1.685/106 Btu 372,000
. Operating Labor
Direct labor 2 men/day $10.67/man-hour 187,000
Supervision 15% of direct labor 28,000
Maintenance
Labor and materials 4% of fixed investment 1,484,000
Supplies 15% of labor and material 223,000
Operating and Maintenance
Additional cost 1,817,000
Overhead
nlant,, 50% of operation and maintenance 961,000
Payroll 20% of operating labor 43,000
Trucking
Bottom/fly ash and 2 924 QQ
sludge removal ^, 9^4,000
Fixed Costs
Depreciation (5.00%)
Interim replacement (0.35%), I = 20.85% of fixed
investment
Insurance (0.30%)
Taxes (4.00%)
Capital cost (11.20%)
Total fixed charges $ 7,735/000
Total cost c 17 TQC; nrm
crpdil- * I/, 385, 000
credit
(14,965,000)
Net annual cost 5 — •? /.on n^o
Mills/kWh $ 2'420n'°?S
- - _ __ _ ____ _ - _ -L • / ^
HUDSON POWER PLANT _
1-34
-------
Table 1-7. RETROFIT EQUIPMENT AND FACILITIES REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 1
AT THE HUDSON POWER PLANT
Module Description
Limestone storage
Limestone slurry
Turbulent contact
absorbers
Flue gas fans
Number
Required
1
1
4
4
Size/Capacity
6480 tons (30-day storage)
9.0 ton/hr limestone
96 MW capacity unit
Scaled to train size
HUDSON POWER PLANT
1-35
-------
Table 1-8. RETROFIT EQUIPMENT DIMENSIONS REQUIRED
FOR THE LIMESTONE SCRUBBING SYSTEM FOR BOILER 1
AT THE HUDSON 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
1
117 wide x 117 long
14 diam x 31 high
45 diam x 20 high
30 wide x 30 long
45 high x 35 wide x 15 long
56 diam x 20 high
30 wide x 30 long
HUDSON POWER PLANT
1-36
-------
COAL CONVEYING
SYSTEM /
HACKENSACK RIVER A SCRUBBER
B SLURRY TANK
C LIMESTONE SILOS
D BALL MILL BUILDING
E CLARIFIER
F VACUUM FILTER BUILDING
I
U)
-J
Figure 1-2. Site plan showing possible locations of major
components for the limestone system for Boiler 1
at the Hudson power plant.
-------
TABLE 1-9. ESTIMATED CAPITAL COST OF AN ELECTROSTATIC
PRECIPITATOR FOR BOILER 1 AT THE
HUDSON POWER PLANT (1978)
Direct Costs
ESP $ 3,323,000
Ash handling 642,000
Acting 2,143,000
Total direct costs $ 6,108,000
Indirect Costs
Interest during construction 8% of. direct costs $ 489,000
Contractor's fee 10% of direct costs 611,000
Engineering 6% of direct costs 366,000
Freight 1.25% of direct costs 76,000
Offsite 3% of direct costs 183,000
Taxes 0.0% of direct costs 000
sPares 1% of direct costs 61,000
Allowance for shakedown 3% of direct costs 183,000
Total indirect costs $ 1,969,000
Contingency 1,615,000
Total $ 9,692,000
Coal conversion costs 15,080,000
Grand total $24,772,000
SAW 64.68
HUDSON POWER PLANT 1-38
-------
TABLE I-10. ESTIMATED ANNUAL OPERATING COSTS OF AN
ELECTROSTATIC PRECIPITATOR FOR BOILER 1 AT THE
HUDSON POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 761.0 kW 33.1 mills/kWh $ 93,000
Water 48,681.0 x 103 gal/h 0.008/103 gal 1,000
Operating Labor
Direct labor 0.5 man/shift $10.67/man-hour 46,000
Supervision 151 of direct labor 7,000
Maintenance
Labor and materials 2j of fixed investment 194,000
Supplies 15% of labor and materials 29,000
Operating and Maintenance
Additional cost 1,817,000
Overhead
rlant 50°o of operation and rnaintenace 138,000
Payroll 20P0 of operating labor 11,000
Trucking
Bottom/fly ash 3,240,000
removal
Fixed Costs
Depreciation (3.85%)
Interim replacement (0.35%), £ = 19.70% of fixed
investment
Insurance (0.303)
Taxes (4.00S.)
Capital cost (11.20%)
Total fixed cost $ 1,909,000
Total cost $ 7,485,000
Fuel credit (14,965,000)
Net annual credit $ (7,480,000)
Mills/kWh 5.31
HUDSON POWER PLANT j_39
-------
Table 1-11. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 1 AT THE HUDSON POWER PLANT
Design Parameter
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
Value
41.52
207
253,700
4.0
15 x 85 x 19'
To meet the particulate emission regulation, four electro-
static precipitators are needed at the given dimensions.
HUDSON POWER PLANT
1-40
-------
i
N
COAL CONVEYING
SYSTEM /
MARION
'GENERATING
STATION
Figure 1-3. Site plan showing possible location of an add-on ESP
for Boiler 1 at the Hudson power plant.
-------
APPENDIX J
JONES STREET POWER PLANT
JONES STREET POWER PLANT J-l
-------
CONTENTS
Jones Street Power Plant Survey Form
Jones Street Power Plant Photographs
Page
J-3
J-15
Number
J-l
FIGURES
Site Plan Showing Possible Locations of New
ESP's for Boilers 26 and 27 at the Jones Street
Power Plant
Page
J-24
Number
J-l
J-2
J-3
J-4
TABLES
Estimated Capital Cost of Electrostatic
Precipitators for Boilers 26 and 27 at the
Jones Street Power Plant (1978)
Estimated Annual Operating Costs of Electro-
static Precipitators for Boilers 26 and 27 at
the Jones Street Power Plant (1978)
Electrostatic Precipitator Design Values for
Boiler 26 at the Jones Street Power Plant
Electrostatic Precipitator Design Values for
Boiler 27 at the Jones Street Power Plant
Page
J-20
J-21
J-22
J-23
JONES STREET POWER PLANT
J-2
-------
POWER PLANT SURVEY FORM
COMPANY INFORMATION;
1. COMPANY NAME: Omaha Public Power District
2. MAIN OFFICE: 1623 Harney St., Omaha, Nebraska 68102
3. RESPONSIBLE OFFICER: Gerald G. Bachman
4. POSITION: Coordinator of Environmental Affairs
5. PLANT NAME: Jones Street Station
6. PLANT LOCATION: 4th and Marcy Streets; Omaha, Nebraska 68102
7. RESPONSIBLE OFFICER AT PLANT LOCATION: William Jones
8. POSITION: Section Manager - Operations
9. POWER POOL
DATE INFORMATION GATHERED: April 29, 1976
PARTICIPANTS IN MEETING:
Gerald G. Bachman - Omaha Public Power District
Daniel Wheeler - U.S. Environmental Protection Agency
N. David Noe - PEDCo Environmental, Inc.
Robert Smolin - PEDCo Environmental, Inc.
JONES STREET POWER PLANT j-3
-------
O
a:
M
cn
w
w
B.
C-l
I
ATMOSPHERIC EMISSIONS
1.. :PARTICULATE EMISSIONS3 . Gas
LB/iMM BTU Oil
GRAIKS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (197-5) Total
2. APPLICABLE PARTICIPATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION. & SECTION NO.
LB/MiM: BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION -& SECTION NO.
LB/MM.BT.U
3. S02 EMISSIONS3 Gas
LB/MM BTU Oil
LB/HR (FULL LOAD)
TONS /YEAR (1975) Total
4. APPLICABLE ~.SO EMISSION REGULATION
a ) CURRENT --REQU IREMENT
REGULATION & SECTION NO.
LB/MM-"' BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
2fi
0.015
0.06
3.47
Rule
0.20
: o.oooe
0.285
7.04
Rule
2.5
?7
0.015
0.06
3.66
9. (a)
0.20
0.0006
0.. 285
7.45
6 . (b)
2.5
a) len
y v;
.he:
2SU
:ro
tac
:es-
or
lim:
-------
C. SITE DATA
1. U.T.M. COORDINATES at intake: Lat. 41° 15' 12" Long 95° 55' 15"
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 984
3. SOIL DATA:. BEARING VALUE
PILING NECESSARY Yes-Caissons also used
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) 116
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE): None-Removed
duringplant remodel-
ing
JONES STREET POWER PLANT j-5
-------
c,
O
z
M
en
en
M
t-3
O
M
1)
£
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 on coal
PEAK
9. FUEL CONSUMPTION:
HIGH SULFUR COAL OR-&I-L RATED
(TPH) OR fGPIt) MAXIMUM CONTINUOUS
PEAK
10. ACTUAL FUEL CONSUMPTION Gas - lO^CF
COAL (TPY) (1975)
OIL (GPY) (1975)
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
26
Peaking
1460
7.1%
26 & 27
R K. W
1 Q4Q
1 •*
in
36
17.2
272.634
None
354,690
Dry
No
147
132
27
Peaking
1??4
9.1%
26 & 27
R & W
1951
1 *
40
47
21.8
288.341
None
375.144
Dry
No
147
132
Notes:
-------
o
z
w
en
W
W
O
s
W
£
z
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN (%)
MASS EMISSION RATE:
(GR/ACF)
(#/HR)
(#/MM BTU)oil/Cfas
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 (%) Coal
Boiler number
9fi
Buell
MCTA1
85
0.009/0.00
25%
07
Buell
MCTA1
85
! 0.009.0.(
.
25%
102
Notes: MCTA: Multiple cyclones - conventional reverse flow; tangential inlet.
-------
o
z
w
en
en
W
W
13
I
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)
Stack Bei-ie-^r number
26 & 27
442,238
321,700
221,100
320
324
320
77.5
58.1
38.8
6.05
•
a) Identify source of values (test or estimate) 1969 FPC Form 67
Notes:
I
oo
-------
C,
O
Z
n
en
en
•-3
»
W
w
1-3
O
5
w
z
•-a
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.C.)
2. WORKING STATIC HEAD (IN. W.C.)
Boiler number
Notes:
Not fan limited
i
VO
-------
FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) None
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.
Hanna, Wyoming
C .
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
3. ANALYSIS
GHV (BTU/LB>
Q.4 - n.q
ASH (%)
8-13
MOISTURE (%)
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA
1. TYPE
2. S CONTENT (%) 0.25
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL) 137.698
COST DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE? Will need substation
NORMAL LOAD ON PLANT SUBSTATION?
VOLTAGE AT WHICH POWER IS AVAILABLE? 13.8
JONES STREET POWER PLANT j-10
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
26
Yes
27
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
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
YesD
D
YesD
D
Yes I
D
B
Yess
a
YesD
n
a
n
P
NO a
a
E3
S
0
a
0
E
No D
D
D
D
D
D
NoH
NoD
D
B
D
No
x
X
D
No D N/A
B
n
D
D
Major Mainten-
ance
JONES STREET POWER PLANT
J-ll
-------
2.4 ASH HANDLING
a. Is the system still installed? YesD No 0
b. Will it operate? U d
c. Of the following items which
need to be replaced:
Bottom Ash Handling YesS No Q
Ash Pond S Q
JONES STREET POWER PLANT J-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 TIIF 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 Coal handling will
require major expenditure to update
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
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 participates
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
c.
Is the monitoring data a vail a bit1?
d. Is the monitoring data reduced and
analyzed?
Yes
Yes
Yes
Yes
Yes
Number
No
No
No Coal Storage
Yes Q No QfJ
Yes
No
No
No Q
No QcJ
Typo
Yes fjj No
Yes No
JONES STREET POWER PLANT
J-13
-------
b.2 Proposed system Yes jJ No [x]
If yes, describe
a. Air monitoring instrumentation Number Typo
(1) Sulfur oxides - Continuous
- Intermittent ZHHI
- Static
(2) Suspended particulatc
- Intermittent
- Static IHH HIT
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
JONES STREET POWER PLANT J-14
-------
Photo No. 1. View from the roof of Boiler 26 facing south-
east showing the electrical substation and the Quaker Oats
Plant.
Photo No. 2. View from the roof of Boiler 26 facing south-
west showing the turbines and the surrounding area.
JONES STREET POWER PLANT
J-15
-------
Photo No. 3. View from the roof of Boiler 26 facing west
showing fuel oil tanks, electrical switch yard, and the
surrounding area.
Photo No. 4. View from the roof of Boiler 26 facing north-
west showing fuel oil tanks.
JONES STREET POWER PLANT
J-16
-------
Photo No. 5. View from the roof of Boiler 26 facing north-
west showing downtown Omaha.
Photo No. 6. View from the roof of Boiler 26 facing north
showing the demolition of Boiler 25. The Missouri River and
the surrounding area are shown in the background.
JONES STREET POWER PLANT
J-17
-------
Photo No. 7. View from the roof of Boiler 26 facing north-
east showing the Missouri River and the surrounding area.
Photo No. 8. View from the roof of Boiler 26 facing east
showing the railroad lines. The Missouri River and the
surrounding area are shown in the background.
JONES STREET POWER PLANT
J-18
-------
Photo No. 9. View from the roof of Boiler 26 facing south-
east showing the railroad lines and the Missouri River
Photo No. 10. View from the roof of Boiler 26 facing south
showing the parking lot and the electrical substation.
JONES STREET POWER PLANT
J-19
-------
TABLE J-l. ESTIMATED CAPITAL COST OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 26 AND 27 AT THE JONES STREET
POWER PLANT (1978)
Direct Costs
ESP
Ash handling
Ducting
Indirect Costs
Total direct costs
$ 3,091,000
522,000
321,000
$3,934,000
Interest during construction 8% of direct
Contractor's fee
Engineering
Freight
Offsite
Taxes
Spares
Allowance for shakedown
Total indirect costs
Contingency
Total
Coal conversion costs
Grand total
$AW
10% of direct
6% of direct
1.25% of direct
3% of direct
1.5% of direct
1% of direct
3% of direct
costs $
costs
costs
costs
costs
costs
costs
costs
$"
315,000
393,000
236,000
49,000
118,000
59,000
39,000
118,000
1,327,000
1,052,000
6,313,000
3,862,000
10,175,000
122.59
JONES STREET POWER PLANT
J-20
-------
TABLE J-2. ESTIMATED ANNUAL OPERATING COSTS OF ELECTROSTATIC
PRECIPITATORS FOR BOILERS 26 AND 27 AT THE JONES STREET
POWER PLANT (1978)
Utilities Quantity Unit Cost Annual Cost
Electricity 618 kW 22.0 mills/kWh $ 9,000
Water 1407 103 gal/yr $0.01/103 gal 1,000
Operating Labor
Direct Labor 1.0 man/shift $8.50/man-hour 74,000
Supervision 15% of direct labor 11,000
Maintenance
Labor and materials 2% of fixed investment 126,000
Supplies 15% of labor and materials 19,000
Overhead
Plant 50% of operation and maintenance 115,000
Payroll 20% of operating labor 17,000
Trucking
Bottom/fly ash
removal 99,000
Conversion Cost Differentials
Operating and maintenance 100,000
Fixed Costs
Depreciation (8.33%)
Interim replacement (0.35%), I = 20.18% of fixed
investment
Insurance (0.30%)
Taxes (0.00%)
Capital cost (11.20%)
Total fixed cost $ 1,274,000
Total cost $ 1,845,000
Fuel cost 128,000
Net annual cost $ 1,973,000
Mills/kWh 33.09
JONES STREET POWER PLANT J-21
-------
TABLE J-3. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 26 AT THE JONES STREET POWER PLANT
Design Parameter
Value
Collection efficiency, %
(overall)
Specific collecting area,
ft2/1000 acfm
2
Total collecting area, ft
Superficial velocity, ft/s
Overall ESP dimensions
(height x width x depth), ft
excluding hopper dimensions
97.4
466
89,400
4
30 x 27 x 45
JONES STREET POWER PLANT
J-22
-------
TABLE J-4. ELECTROSTATIC PRECIPITATOR DESIGN VALUES
FOR BOILER 27 AT THE JONES STREET POWER PLANT
Design Parameter
Value
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
97.4
466
116,800
4
30 x 35 x 44
JONES STREET POWER PLANT
J-23
-------
1
M
cn
en
I EQUIP. /
[STORAGE/
AREA./
A
SWITCH YARD
L , K > I, X ».
Figure J-l. Site plan showing possible locations of new ESP's for Boilers
26 and 27 at the Jones Street power plant.
-------
APPENDIX K
LAKE ROAD POWER PLANT
LAKE ROAD POWER PLANT
-------
CONTENTS
Page
Lake Road Power Plant Survey Form K-3
Lake Road Power Plant Photographs K-20
LAKE ROAD POWER PLANT K-2
-------
OMB No. 158S 74023
POWER PLANT SURVEY FORM
A. COMPANY INFORMATION;
1. COMPANY NAME: St. Joseph Light and Power Company
2. MAIN OFFICE: 520 Francis Street, St. Joseph, Missouri 64502
3. RESPONSIBLE OFFICER: R.B. Mayer
4. POSITION: Vice-President, Operations
5. PLANT NAME: Lake Road
6. PLANT LOCATION: Lower Lake Road, Buchanan County, Missouri 64502
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Richard A. Sullwold
8. POSITION: Manager of Production
9. POWER POOL None
DATE INFORMATION GATHERED: March 31, 1976
PARTICIPANTS IN MEETING:
Earl Meyers
Richard Sullwold
Daniel Wheeler
Francis Kirwan
Thomas Ponder
N. David Noe
David Augenstein
St. Joseph Light & Power Company
St. Joseph Light & Power Company
U.S. EPA, Region VII
U.S. EPA, Research Triangle Park, N.C,
PEDCo Environmental, Inc.
PEDCo Environmental, inc.
PEDCo Environmental, inc.
LAKE ROAD POWER PLANT
K-3
-------
B.
w
§
O
5
W
»
^
f
>
Z
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU estimates
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
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. SO2 EMISSIONS3
LB/MM BTU
LB/HR (FULL LOAD)
TONS/YEAR ( 1975) estimates
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU N.A.
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
1
Regula
0.16 lb/
20% op
Regulatic
Ambient A
<0.25 ppn
<0.07 ppn
2
tion III a
MM Btu inp
acity or 1
n XV
ir Quality
, 1-hr ave
, 24-hr av
3
nd V
ut (entire
sss
Standard :
. , once pe
e. , once f
4
plant)
r four day
er 90 days
5
2.05
861
7.81
2861
s max.
max.
bi:
he
It
•e
n ;
k
-S
es
ite
-------
B.
K
O
s:
£
z
I
Ul
ATMOSPHERIC EMISSIONS
1. PARTICULATE EMISSIONS3
LB/MM BTU
GRAINS/ACF
LB/HR (FULL LOAD)
TONS/YEAR (1974 )
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 ( 1974
4. APPLICABLE SO EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
Boiler number
6
0.369
226
Same
N.A.
7.18
25,640
Same
N.A.
7
a) Identify whether results are from stack tests or estimates
-------
SITE DATA
1. U.T.M. rnnRDTNATES MO. Coord. System: X=393,834, ¥=1,295,768 f
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 812 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
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE) 132
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE): 25
LAKE ROAD POWER PLANT K-6
-------
g
w
o
a
o
w
). 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 (1974 FPC 67)
MAXIMUM CONTINUOUS FPC
PEAK
9. FUEL CONSUMPTION: Gas (MCFH)
Coal (TPH)
Oil (bbl/hr)
MAXIMUM CONTINUOUS
10. ACTUAL FUEL CONSUMPTION Gas (1Q6 CF
(1975) Coal (1000 t)
(1975) Oil (1000 bbl)
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
366
2.5
1
C-E
1961
15
11
201
N.A.
26.2
) 27.986
N.A.
2.713
Dry
No
92
53
2
643
4.3
2
C-E
1961
15
11
201
N.A.
26.5
46.679
N.A.
5.108
Dry
No
92
53
3
Peak
3805
27.8
3
B&W
1938
4
16.5
238
N.A.
34.2
372.92
N.A.
21.353
Dry
No
92
43 x 78
4
Float
6374
56.3
4
B&W
1950
5
23.0
322
13.5 -
47.3
853.37
22.46
1.766
Dry
No
150
72
5
Base
7767
63.6
5
B&W
1957
12
27.5
382
15.9
55 . 7
1284.2
41.02
2.805
Dry
No
150
. 84
Notes:
-------
w
50
O
O
s
w
13
£
2
). 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 (1974 FPC 67)
MAXIMUM CONTINUOUS FPC
PEAK
9. FUEL CONSUMPTION: Gas (MCFH)
€€>Af,-f>R-ert -RATED Coal (TPH)
Oil (bbl/hr)
(!?f>U-}-&R--(G¥'Hi MAXIMUM CONTINUOUS
?EAK
10. ACTUAL FUEL CONSUMPTION M06C '
GOMi— (*P*} (19 75) Coal (1000 t
Oli— («*¥-) (19 79 Oil (1000 bb!
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
6
Base
1718
18.5
6
B&W
1967
22
103
1108
44.6
N.A.
210.85
61.35
) N/920
Wet
No
225
120
7
Peak
3621
40.5
7
West
1974
28
78.5
867
N.A.
129
3065.0
N.A.
1.582
Dry
No
52/36
84 x 144^
138 x 294*
i
oo
Notes: Stack #7.
Bypass
-------
o
s;
in
JO
£
z
15. FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE: Uncontrolle(
(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
1
N.A.
785
10
2
N.A.
785
107
3
N.A.
469
15/
4
Westa
MCAXb
85/86.8
1465
327
25/
5
Environ.
Elements
ESP
99
0.01
49.42
0.1522
3
45,900
314
25/
Notes :
a
I
<£>
West - Western Precipitation Division
MCAX - Multiple cyclones, conventional reverse flow, axial inlet
Universal Oil Products - on line by June 1976.
-------
w
so
o
>
o
*d
O
h3
£
a
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
UOPC
ESP
99
0.01
43.8
0.045
3
74,520
338
19/20
7
N.A.
435
/
Notes
i
M
O
-------
w
o
M
*a
£
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 @ STACK0];3,™'
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Boiler number
1
67,700
45,500
28,500
785
735
675
64.5
43.6
27.7
Trucked
Flyash anc
53
852
2
67,700
45,500
28,500
785
735
675
64.5
43.6
27.7
to city Ii
slag to <.
53
852
3
78,500
52,300
29,000
469
428
383
56.1
37.4
20.7
ndfill
sh pond
43 x 78
-
4
114,000
80,000
54,000
327
306
294
67.1
47.1
31.8
72
828
5
129,400
100,300
75,500
314
301
292
56.0
43.4
32.7
84
828
a) Identify source of values (test or estimate)
Notes: ash pond will be increased to larger size.
-------
w
33
o
s
f
>
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 ($/TON)
21. BOTTOM ASH: TOTAL COLLECTED (TONS/
DISPOSAL METHOD YEAR)
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS @ STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
6
323,800
238,400
158,900
365
313
290
68.7
50.6
33.7
Truck
Ash Pond
120
Boiler number
7
911,242
774,556
703,479
435
425
425
83.7
69.5
61.6
NA
NA
84 x 144/3
38 x 294
a) Identify source of values (test or estimate)
Notes:
-------
W
»
o
>
D
•X)
s
W
E . I . D . FAN DATA
1. MAXIMUM STATIC HEAD (IN. W.G.)
2. WORKING STATIC HEAD (IN. W.G.)
Boiler number
Notes:
5
2
-------
FLY ASH DISPOSAL AREAS
1. AREAS AVAILABLE (ACRES) 1.4 acres temporary holding pond
2 . YEARS STORAGE (ASH ONLY) twice a year cleaning _
3. DISTANCE FROM STACK (FT.) 450 ft. ____
4. DOES THIS PLANT HAVE PONDING Having to clean it semi-annually
PROBLEMS? DESCRIBE IN ATTACHMENT in compliance with NPDES
COAL DATA FPC and 75 coal summary
1. COAL SEAM, MINE, MINE LOCATION
a. BM District 15 _ __
b. _ _______ _ —
c . _ _____ _
d. _ _____ __
2. QUANTITY USED BY SEAM AND/OR MINE
a. 100% from BM District 15
c .
d.
ANALYSIS
GHV (BTU/LB) 10,050
S (%) 3.8
ASH (%) 15.2
MOISTURE (%) 15.0
4. PPT PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT) N.A.
H. FUEL OIL DATA
1. TYPE Residual
2. S CONTENT (%) 1.7
3. ASH CONTENT (%)
4. SPECIFIC GRAVITY
5. GHV (BTU/GAL) 148,074
I. 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?
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
1
No
2
NO
3
No
4
Yes
5
Yes
2. SYSTEM AVAILABILITY
2.1
2.2
2.3
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
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
E!
E
Yes
D
D
B)
H
D
YesB
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 Yes
Feed Ducts
Fans
Controls
K)
S
El
Yes
YesD
D
D
B
No Q
D
No
mod
mod
D
D
S
NoD
D
NoQ
D
D
D
No
D
No D
D
D
D
D
»w
LAKE ROAD POWER PLANT
K-15
-------
K. OIL/GAS TO COAL CONVERSION DATA
1. HAS THE BOILER EVER BURNED COAL?
Boiler No.
Yes or No.
6
Yes
7
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
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 D
D
YesD
D
D
D
D
D
YesD
D
YesD
D
D
D
Yesn
D
Yesn
D
D
D
D
NoD
D
No D
D
D
D
D
D
NoD
D
NoD
D
D
D
No
D
No D
D
D
D
D
LAKE ROAD POWER PLANT
K-16
-------
2.4 ASH HANDLING
a. Is the system still installed? YesD NoD
b. Will it operate? D D
c. Of the following items which
need to be replaced:
Bottom Ash Handling Yes D NoQ
Ash Pond D D
LAKE ROAD POWER PLANT K-17
-------
L. 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 D No D
2.1 Storage capacity for low sulfur fuels
(tons, bbls, days)
2.2 Bunkers available for low sulfur coal
storage? Yes Q 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 n No D
IS THE PLANT CAPABLE OF LOAD SHIFTING?
If yes, discuss _ _
Yes n No D
POWER PLANT MONITORING SYSTEM
5.1 Existing system Yes Q No D
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 fj No Q
d. Is the monitoring data reduced and
analyzed? Yes Q] No [_J
'LAKE ROAD POWER PLANT K-18
-------
5.2 Proposed system Yes P] No
If yes, describe
(2) Suspended particulatc
- Intermittent
- Static
(3) Other (describe)
b. Meteorological instrumentation
If yes, describe
a. Air monitoring instrumentation Number Type
(1) Sulfur oxides - Continuous
- Intermittent
- Static
LAKE ROAD POWER PLANT
K— 19
-------
Photo No. 1. View from the boiler roof facing southeast,
showing the stacks for boilers 1 and 2. A retired meat
packing plant to the left and a modern chemical plant are
shown in the background.
Photo No. 2. View from the left to the right boiler roof
facing north-northwest showing oil tank for boiler 3 and
plant's laboratory. The Missouri river is in the back-
ground.
LAKE ROAD POWER PLANT
K-20
-------
\
Photo No. 3. View from the boiler roof facing southwest,
shows active coal storage pile in the foreground and con-
struction of additional coal handling facilities. A reserve
coal storage pile is shown at center right.
Photo No. 4. View from the boiler roof facing southwest
showing the construction of new electrostatic precipitator
being installed to serve Boiler 6. Coal storage and con-
struction of the coal conveyors are shown in the background,
LAKE ROAD POWER PLANT
K-21
-------
Photo No. 5 View from ground level facing northeast showing
ESP and ash bins for Boiler 6.
Photo No. 6 View from ground level showing tie-in ducts and
stack for Boiler 6.
LAKE ROAD POWER PLANT
K-22
-------
Photo No. 7. View from the roof facing southeast showing
Boiler 6 stack and cooling towers. Shown in the lower
center is the waste heat boiler for the No. 7 gas turbine,
Photo No. 8. View from the roof facing east-southeast
showing Boiler 1 and 2 stacks and the retired meat packing
plant in background.
LAKE ROAD POWER PLANT
K-23
-------
Photo No. 9. View from the roof facing southwest showing
the existing coal handling facilities and active coal
storage. The surrounding area is shown in the background
Photo No. 10. View from the roof facing north showing the
switchyard and the Missouri river in the center background.
LAKE ROAD POWER PLANT
K-24
------- |