CONTROL OF SULFUR OXIDE EMISSIONS
FROM ELECTRIC-POWER-GENERATING PLANTS
Dr. B. J. Steigerwald
Director, Stationary Source
Pollution Control Programs
FOR IMMEDIATE RELEASE UPON RECEIPT
ENVIRONMENTAL PROTECTION AGENCY
Office of Air Programs
Research Triangle Park, N. C. 27711
April 25, 1972
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Kolbinsky (919) 688-8357
Control of Sulfur Oxide Emissions
From Electric-Power-Generating Plants
More than two-thirds of the 33,400,000 tons of sulfur oxides emitted
to the atmosphere of the United States in 1969 came from fuel combustion
in stationary sources. More than half of this total, 17,700,000 tons,
was emitted from steam-electric power-generating plants - 15,824,000
tons from coal and 1,919,000 tons from fuel oil.
Because fuel combustion is the principal source of sulfur oxide
emissions, attention has been focused in recent years on reduction of
sulfur in fuels and on equipment and processes that will control emissions
from this source, with emphasis on developing emission control technology
for power plants.
In the December 23, 1971, issue of the Federal Register the Environ-
mental -Protection Agency published "Standards of Performance for New
Stationary Sources." Fossil-fuel-fired steam generators are included
as a category in this standard. The standards for sulfur dioxide for
large new power plants are 0.80 and 1.2 pounds of S02 emitted per million
Btu of heat input for liquid and solid fossil fuel, respectively. Roughly
applied, the standard means that about 75 percent of the sulfur must be .
removed from either the fuel or the combustion gases in a power plant
burning 3 percent sulfur fuel.
Two utility companies developed and constructed sulfur control systems
on full-scale boilers several years before the Federal emission standards
were adopted, and numerous others are following their lead. As shown in
Table 1, some 20 power plants either have a full-scale sulfur dioxide
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removal system or have contracted to put one on stream within the next
several years. The total of these contracts is estimated to be $200
million, $140 million of which has been or will be spent for retrofit
equipment on existing power plants.
Although most of the contracts are for sulfur dioxide removal
systems that employ limestone or lime, other types of systems are also
being installed. In addition to the calcium-based scrubbing systems,
three other 802 abatement systems are being installed on four different
power plants. Two of the processes employ scrubbing, one with a sodium-
based system and the other with a magnesium oxide reactant. The third
system employs catalytic oxidation.
Among the firms that have contracts for full-scale flue-gas
desulfurization systems are: Babcock and Wilcox, Chemico, Combustion
Engineering, Combustion Equipment Association, Monsanto, Peabody
Engineering, Research Cottrell, and Zurn. Most of the control systems
being installed are designed for 70 to 90 percent sulfur dioxide removal,
and most of them accomplish high-efficiency particulate removal as well.
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Table 1. SULFUR DIOXIDE REMOVAL SYSTEMS AT STEAM-ELECTRIC PLANTS IN UNITED STATES
Utility company/plant
Limestone scrubbing
1. Union Electric Co. (St. Louis)/
Meramec No. 2
2. Union Electric Co. (St. Louis)/
Meramec No. 1
3. Kansas Power & Light/
Lawrence Station No. 4
4. Kansas Power & Light/
Lawrence Station No. 5
5. Kansas City Power & Light/
Hawthorne Station No. 3
6. Kansas City Power & Light/
Hawthorne Station No. 4
7. Kansas City Power & Light/
La Cygne Station
8. Detroit Edison Co. /St. Clair
Station No. 3
9. Detroit Edison Co. /River Rouge
Station No. 1
10. Commonwealth Edison (Chicago area)/
Will County Station No. 1
11. Northern States Power Co. (Minnesota)
Surban County Stations No. 1 and 2
12. Arizona Public Service Co./
Choi la Station
13. Tennessee Valley Authority/
Widow's Creek Station No. 8
14. Duquesne Light Co. (Pittsburgh)/
Philips Station
15. Louisville Gas & Electric Co./
Paddy's Run Station No. 6
16. City of Key West/Stock Island*
Sodium-based scrubbing
17. Nevada Power Co. /Reid Gardner
Station
Magnesium oxide scrubbing
18. Boston Edison/Mystic Station No. 6*
19. Potomac Electric & Power (Maryland)/
Dlckerson No. 3
Catalytic oxidation
20. Illinois Power/Wood River3
Unit size,
megawatts
140
125
125
430
130
140
820
180
270
175
680
680
115
550
100
70
37
250
150
195
100
Scheduled
startup
September
1968
Spring
1973
December
1968
November
1971
Mid-1972
Mid-1972
Late 1972
November
1972
December
1972
February
1972
May 1976
(first unit)
January
1973
April
1975
February
1973
Mid-Late
1972
June
1972
Mid-1973
March
1972
Early
1974
June
1972
Fuel
3.0% S coal
3.0% S coal
3.5% S coal
3.5% S coal
3.5% S coal
3.5% S coal
5.2% S coal
2.5-4.5% S coal
3-4% S coal
3.5% S coal
0.8% S coal
0.4-1% S coal
3.7% S coal
2.3% S coal
3.0% S coal
2.75%.S fuel oil
1 .0% S coal
2.5% S fuel oil
3.0% S coal
3.5% S coal
Partial funding by the Environmental Protection Agency.
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