-------
deviated from the conditions required for low NOV control. ''
X
Consequently, it is very important that NO emissions be monitored
A
continuously and accurately if real emission reduction is to be effected
by new source performance standards for NO emissions from combustion.
X
6.2.3 Foster Wheeler Energy Corporation and Riley Stoker Corporation
Foster Wheeler reports their modern units are equipped for overfire,
interstage, and curtain air, (boundary air) and are designed to limit
3
NO emissions by reducing combustion air to the firing zone. Curtain
X
air is used to prevent reduced air conditions at the boiler walls which
3
would cause accelerated tube wastage (corrosion) or slagging. A Foster
Wheeler coal-fired steam generator was started up in December 1976 at a
Western power plant firing 22.6 megajoules per kilogram (9700 Btu/lb),
111?
0.9 percent sulfur coal. ' This steam generator is subject to a State
of New Mexico regulation limiting NO emissions to no more than 193
X
nanograms per joule (0.45 lb/10 Btu). The steam generator is still in
the shakedown phase of NOV emission control. Foster Wheeler Corporation
X
is developing a low-turbulence dual throat coal burner with a double
annul us throat configuration for secondary air injection and individual
control of each annulus air supply. The primary mechanisms by which
the new burner limits NO emissions are control of turbulence and delayed
X '
mixing of fuel and air, thereby minimizing fuel NO conversion.
/\
17
6-24
-------
The special Foster Wheeler burner has been tested on three units;
two 265 MW opposed-fired units and one 75 MW front wall-fired unit. All
of these units were modified existing units. Modifications included
provision for overfire and boundary air. NO emissions were reduced about
X
48 percent by the special burner and were reduced about 67 percent when
full overfire air was used in conjunction with the dual throat burner.
18
NO was reduced to about 300-350 ppm by the special burner with the overfire
A
18
air 20 percent open. CO concentrations were below 50 ppm and unburned
fly ash carbon was less than one percent. When the overfire air was
opened 100 percent and the burners were adjusted for minimum NO , fly
f\
ash carbon increased to about 2.5 percent and slag began to accumulate
18
after about 24 hours of full-load operation. Slagging was substantially
alleviated, although not eliminated by the combined effect of the special
18
burner and by the use of boundary air. The furnaces were conservatively
ifi
sized because of the slagging characteristics of the coal. No tube
wastage was evident from firing the good quality 26.77 megajoules per
kilogram (11,500 Btu/lb), 0.6 percent sulfur coal.18
6-25
-------
Riley Stoker modern design units are equipped for underfire,
overfire, and sidefire air, and emissions of NO are limited by reducing
A
0
combustion air in the firing zone. These units are designed for about
280 megajoules per second per square metre (1.5 x 106 Btu/hr/ft2) heat
release rates as compared with heat release rates for older pulverized
coal-fired units of 430 megajoules per second per square metre (2.25 x
106 Btu/hr/ft2).2
Riley Stoker Corporation is currently modifying the burners used
in its furnace design to reduce NO emissions.
X
17
The new burners are
designed to control mixing of fuel and air to reduce thermal and fuel
NOX. With the new burners and changes in furnace design, Riley
Stoker expects to achieve low NOV emissions with its new boilers without
A
increased carbon or unburned hydrocarbon loss.
6.2.4 Summary of NO.. Control Status
11 - - T ~" A ^ -""
U. S. Environmental Protection Agency test results show that NO
" X
emissions from modern Combustion Engineering pulverized coal-fired
steam generators can be limited to levels less than 260 nanograms per
joule (0.6 lb/10 Btu) without any significant adverse side effects.
Combustion Engineering will guarantee its new units to meet this limit
for any type of coal.4'15 For plants firing coal which has little
tendency to cause slagging or tube wastage, any of the four manufacturers
is capable of furnishing coal-fired steam generators which will limit
NOX emissions to a level less than 210 nanograms per joule (0.5 lb/106
Btu).
4,15
There is not enough data or experience to indicate whether Babcock
and Wilcox, Foster Wheeler, or Riley Stoker modern pulverized coal-
6-26
-------
fired steam generators are capable of achieving low NO emission levels
A
without adverse side effects when slagging or corrosive coals are fired.
6.3 FEASIBILITY OF CONTINUOUS NO CONTROL
X
Table 6-14 shows data on NO emissions from tangentially fired
A
boilers firing Western subbituminous coal.19 This Western power plant is
required to control emissions to a level less than 300 nanograms per
joule (0.7 lb/10 Btu). As shown by Table 6-14, emissions were sub-
stantially below the foregoing level. The plant is equipped to reduce or
to increase N0x emissions from the two tangentially fired steam generators
by controlling the proportional quantities of overfire and secondary air.
The plant reports that it is seldom necessary to change overfire air
damper settings since, as shown, NO emission levels are characteristically
A
19
low. With constant overfire air damper settings, and by modulating
secondary air control, NO emission levels are the highest at full load.
A
N0x emissions decrease as the load is reduced. Any necessary changes in
overfire air damper settings are made by plant engineers or management
personnel and are not made by shift operators. The data show that NO
A
emissions from subbituminous coal-fired steam generators are continuously
and consistently controlled to a level less than 210 nanograms per joule
(0.5 lb/106 Btu).
6-27
-------
TABLE 6-14
NOVEMBER 1977 NOV EMISSION CHARACTERISTICS OF TWO 350 MW
TANGENTIALL? FIRED COAL FIRED STEAM GENERATORS
Nanograms per joule (lb/10 Btu),
19
Day
11-1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
2a
29
30
Unit
24 Hour Average
Peak
170 (.40)
175 (.41)
190 (.44)
210 (.49)
105 (.25)
205 (.48)
215 (.50)
205 (.48)
230 (.53)
215 (.50)
210 (.49)
190 (.44)
185 (.43)
180 (.42)
190 (.44)
195 (.451
210 (.49)
260 (.60)
150 (.35)
170 (.39)
180 (.42)
140 (.33)
135 (.31)
140 (.32)
115 (.27)
140 (.32)
115 (.27)
130 (.30)
135 (.31)
140 (.32)
205 (.48)
230 C-53)
230 (.53)
290. (.67)
195 (.45)
295 (.69)
235 (.55)
240 (.56)
245 (.57)
270 (.63)
240 (.56)
220 (.51)
200 (.47)
200 (.46)"
215 (.50)
220 (.51)
235 (.55)
290 (.67)
170 (.39)
190 (.44)
205 (.48)
170 ,(.40)
140 (.33)
150 (.35)
150 (.35)
155 (.36)
120 (.28)
155 (.36)
160 (.37)
165 (.38)
Uni;t 2
24 Hour Average
Peak
a
a
a
a
a
a
140" (.33) 150 (.35)
19,0 (.44) 220 (.51)"
180 (.42) 200 (.47)
155 (.36) 170 (.39)
175 (.41) 200 (.46)
180 (.42) 235 (.55)"
130 (.30) 185 (.43)
125 (.29) 190 (.44)
125 (.29) 140 (.32)
160 (.37) 215 (.50)
170 (,.4Q) 200 (.47.)
a
a
a
a
a
a
56 (.13) 120 (.28)
125 (.29) 195 (.45)
95 (.22) 130 (.30)
155 (.36) 170 (,39)
180 (.42) 200 (.47)
205 (".48) 225 (.52)
215 (.50
110 (.26
145 (.34
230 (.53)
180 (.42)
210 (.49)
200 (747) 205 (.48)
175 (741 ]
200 (.46)
170 (.40) - 230 (.53)
130 (".30) 175 (.41)
No data - Unit out of service
6-28
-------
REFERENCES FOR CHAPTER 6
Standards Support and Environmental Impact Statement for
Lignite Fired Steam Generators, Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, U. S.
Environmental Protection Agency, Research Triangle Park, North
Carolina, 1976.
Memorandum, J. Copeland to G. B. Crane, Meeting with Riley Stoker
Corporation, February 5, 1976, Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North
Carolina, March 29, 1976.
Memorandum, J. Copeland to G. B. Crane, Trip Report - Meeting
with Foster Wheeler Energy Corporation of February 6, 1976,
Emission Standards and Engineering Division, Office of Air
Quality Planning and Standards, U. S. Environmental Protection
Agency, Research Triangle Park, North Carolina, March 25, 1976.
Memorandum, J. Copeland and G. B. Crane to S. T. Cuffe, Trip
Report - Meeting with Combustion Engineering, Incorporated,
February 19, 1976, Emission Standards and Engineering Division,
Office of Air Quality Planning and Standards, U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina, April,
1976.
Memorandum, J. Copeland and G. B. Crane to S. T. Cuffe, Meeting
with Babcock and Wilcox Company, February 18, 1976, Emission
Standards and Engineering Division, Office of Air Quality Planning
and Standards, U. S. Environmental Protection Agency, Research
Triangle Park, North Carolina, April 15, 1976.
67-29
-------
6. Subpart D, Part 60, Subchapter C, Chapter 1, Title 40, Code of
Federal Regulations.
i ...'.
7. Brackett, C. E. and J. A. Barsin, The Dual Register Pulverized Coal
Burner - A N0x Control Device, Babcock and Wilcox Company,
Barberton, Ohio, February, 1976.
8. Campobenedetto, E. J., the Dual Register Pulverized Coal Burner -
Field Test Results, Presented at the Engineering Foundation
Conference on Clean Combustion of Coal, Franklin Pierce College,
Rindge, New Hampshire, July 31 to August 5, 1977.
9. Crawford, A. R., et al, The Effect of Combustion Modification on
Pollutants and Equipment Performance of Power Generation Equipment,
Exxon Research and Engineering, Linden, New Jersey, September, 1975.
10. Thompson, R. E., M. W. McElroy, and R. C. Carr, Effectiveness of
Gas Recirculation and Staged Combustion in Reducing NO on a 560 MW
X
Coal-Fired Boiler, Presented at the Electric Power Research
Institute NOX Control Technology Seminar, San Francisco,
California, February, 1976.
11. Telephone conversation J. 0. Copeland, Emission Standards and
Engineering Division, U. S. Environmental Protection Agency,
Research Triangle Park, North Carolina, with R.K. Thomson, Public Service
Company of New Mexico, July 19, 1978.
12. Steam Electric Plant Factors 1976, National Coal Association,
Washington, D. C., 1977.
13. Program for Reduction of N0x from Tangential Coal-Fired Boilers,
Phase II, EPA-650/2-73-005-a, U. S. Environmental Protection
Agency, Research Triangle Park, North Carolina, June, 1975.
6-30
-------
14. Overfire Air Technology for Tangentially Fired Utility Boilers Firing
Western U.S. Coal, EPA 600/7-77-117, U. S. Environmental Protection
Agency, Research Triangle Park, North Carolina, October 1977.
15. Private communication from H. E. Burbach, Combustion Engineering,
Incorporated, to J. 0. Cope!and, Emission Standards and Engineering
Division, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina, July 30, 1976.
16. Unpublished data, Emission Standards and Engineering Division,
Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina, 1976.
17. N0x Control Review, Vol. 2, No. 4, EPA Industrial Environmental
Research Laboratory, Research Triangle Park, North Carolina,
Fall, 1977.
18. Vatsky, J., Attaining Low NOX Emissions by Combining Low Emission
Burners and Off-Stoichiometric Firing, Foster Wheeler Energy
Corporation, Livingston, New Jersey, November 1977.
19. Unpublished data based on visit of Mr. Dan Bivins, Emission Standards
and Engineering Division, U. S. Environmental Protection Agency,
to Colstrip Station, Montana Power Company, January 17-19, 1978.
6-31
-------
-------
7. ENVIRONMENTAL IMPACT
7.1 GENERAL
As discussed in Chapter 6, N0v emissions from large pulverized
X
coal-fired steam generators can be controlled without loss of boiler
efficiency or an increase in carbon monoxide or particulate emissions.
Hydrocarbon emissions from low NOV emitting sources are below the limit
A
of detection of a flame ionization analyzer.1 Although it is logical
to conclude that if carbon monoxide emissions are not increased, poly-
cyclic organic matter emissions are not increased, there is not enough
data to prove this theory.
More effective control of NOX emissions from large pulverized
coal-fired steam generators using the design and operating techniques
discussed in Chapter 6 does not adversely affect solid waste, water
pollution, noise, or energy environmental impact.
7.2 AIR POLLUTION IMPACT
7.2.1 Effect on Ambient Air Quality
Table 7-1 shows emission source characteristics for various sized
model sources emitting NOX at full load capacity at the level of the
current NOX new source performance standard for pulverized coal-fired
steam generator of 300 nanograms per joule ("0.7 lb/106 $tu].2'3 As
shown, air quality was measured for three different stack heights.
7-1
-------
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7-2
-------
Modeling techniques are described in Appendix F.
Table 7-2 shows the impact of 25, 300, and 1000 megawatt sources
3
on air quality. The models assume that plants would be located in
flat or gently rolling terrain with a meteorological regime which is
o
unfavorable to the dispersion of pollutants. Downwash and retardation
effects were evaluated for the control building heights given in Table
3
7-1. The models assume that the plants are operated at full load
during an entire year. The values reported are the maximum ground
level concentrations that were calculated for downwash, retardation, or
characteristic dispersion, whichever was the greatest. Further information
on modeling techniques is given in Appendix F, As shown by Table 7-2,
impact on air quality increases with plant size and decreasing stack
height. In actual practice, the average annual concentrations would be
somewhat less, because plant load factors are usually less than 100
percent.
As shown by Table 7-1, nitrogen oxides emissions were estimated
for NO and N02. Nearly all of the nitrogen oxides emissions from
combustion are emitted as NO. Assuming oxidation of the NO of Table 7-2
to N02 and excluding Case No. 7 which reflects the effect of severe
downwash yields a range of annual NO concentrations (as NOo) of from
s\ £
less than 0.3 to less than 2 micrograms per cubic metre, compared to
the Primary and Secondary National Ambient Air Quality Standard for
nitrogen dioxide of 100 micrograms per cubic metre.
The maximum ground level concentrations of Table 7-2 are for
sources emitting at the level of the current NOV new source performance
A
7-3
-------
TABLE 7-2
MAXIMUM POLLUTANT CONCENTRATIONS9 (yg/m3)
Averaging
Period
Annual
Case
1
2
3
4
5
6
7
8
9
NOC
0.7
0.2
<0.1
1.6
0.5
0.2
930
0.7
0.4
Distance
N02 (km)
<0.1 0.9
<0.1 3.0
<0.1 2.3
<0.1 6.4
<0.1 14.8
<0.1. 20.01
14 0.3b
<0.1 20.5
<0.1 23.3
Concentrations have been pro-rated according to specific
emission rates.
First ring, downwash.
CNO oxidizes in atmosphere to N02. However, it is not
known what percentage of NO would be oxidized for the
9 cases.
7-4
-------
X
standard of 300 nanograms per joule (0.7 lb/106 Btu).2 Reducing NO
emissions to lower levels would proportionally reduce the NO concen-
A
trations shown in Table 7-2.
7.2.2 Effect on Air Emissions
Reducing N0x emissions from pulverized coal-fired steam generators
from the level of the current new source performance standard of 300
nanograms per joule (0.7 lb/106 Btu) to a level of 260 ng/J (0.6 lb/106
Btu) would be equivalent to about a 14 percent reduction in emissions. .
A 29 percent reduction in emissions would result from the restriction '
of emissions to a level of 210 nanograms per joule (0.5 lb/106 Btu).
Because it takes about 5 years to construct a pulverized coal-
fired power generation system, the air emission impact of a lower NO
J\
limit would not begin for at least five years after the lower limit
became effective. Thus, the earliest impact would begin about 1982 or
1983. According to power industry estimates compiled by the Federal
Power Commission, the total capacity of fuel burning power generation
facilities will increase by,about 189,400 megawatts during the 10 year
period from the end of 1983 to the end of 1993.6'7 It is estimated
about 161,000 megawatts (or 85 percent) of this new capacity will be
pulverized coal-fired other than lignite capacity.7 Based on the
foregoing estimate about 2.910 teragrams (3,210,000 short tons) of
additional NOX would be emitted in the 1993 year from new pulverized
coal (other than lignite) fired units which are added during the period
1983 through 1993, assuming that emissions are limited to the leve]
7-5
-------
of the current new source performance standard of 3QO nanograms per
.joule (0.7 lb/106 Btu). For control levels below the current standard,
nationwide NO emission rates would also be increased by power industry
A
expansion of coal-fired steam generating capacity. However, the increase
would not be as great as with the current 300 nanogram per joule limit.
This is demonstrated in Table 7-3. Beyond 1993 NOV control levels
A
below the current standard would continue to temper the impact of new
pulverized coal-fired steam generator activations on annual nationwide
NO emissions.
A
7.3 SOLID WASTE, WATER POLLUTION, NOISE, AND ENERGY IMPACT
As discussed in Chapter 6, the viable techniques for reducing NOX
emissions from pulverized coal-fired steam generators involve changing
the way the fuel and air are introduced into the combustion chamber.
Since no additional waste materials are generated, more effective NOX
control does not increase or decrease the quantity of wastes and does
not change the character of the wastes. The more effective NOX control
techniques discussed in Chapter 6 do not change the character or magnitude
of water or noise pollution.
Although the test results discussed in Chapter 6 fail to show any
statistically significant difference in boiler efficiency for normal
firing as compared with low NO 'firing, it is likely fuel consumption
A
will be slightly less when NOV emissions are controlled to a lower
A
limit. Thus, more effective NOV control will probably have a slight
A
beneficial impact on energy consumption.
As discussed in Chapter 6, NO emissions can be controlled to
lower levels without increasing energy losses which would be indicated
7-6
-------
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7-7
-------
by increased ash combustible content or increased CO emissions. Although
the quantity of total excess air used during low NOX firing is much the
same as that used during normal firing, it is likely that for long term
boiler operation the total excess air used will be less for low NO
/\
firing than for normal firing. This is because operators will need to
control combustion air rates within narrower limits when firing in the
low NO mode than when firing in the normal mode. Lower excess air
X
increases boiler efficiency.
7-8
-------
REFERENCES FOR CHAPTER 7
1. Program for Reduction of-NOX from Tangential Coal-Fired Boilers, Phase II,
i
EPA 650/2-73-005-a, U. S. Environmental Protection Agency> Research
Triangle Park, North. Carolina, June 1975.
2. Subpart D9 Part 60, Subchapter C, Chapter 1, Title 40, Code of Federal
Regulations.
3. Unpublished Data, Source Receptor Analysis Branch., Office of Air Quality
Planning and Standards, U. S. Environmental Protection Agency, Research
Triangle Park., N. C.,, May 1975.
4. Control Techniques for Nitrogen Oxides Emissions from Stationary Sources,
AP-67,. U. S. Environmental Protection Agency, Washington, D. C., March 1970.
5. Part 50, Subchapter C, Chapter 1, Title 40, Code of Federal Regulations.
6. Summary of Electric Reliability Council Power Industry Expansion Projections
1976-1995, Federal Power Commission, Washington, D. C., 1976.
7. Unpublished Data, Emission Standards and Engineering Division, Office of
Air Quality Planning and Standards, U. S. Environmental Protection Agency,
Research Triangle Park, North Carolina, 1976.
7-9
-------
-------
CHAPTER 8. ECONOMIC IMPACT ANALYSIS
8.1 INDUSTRY PROFILE
8.1.T General Industry Background
The market for large coal-fired boilers is dominated by the electric
utility industry. As shown in the table below, over 88 percent of all
coal-fired units and over 98 percent of the rated megawatts installed
since 1960 have been electric utility power generation applications.
Table 8-1.. COAL-FIRED UNITS INSTALLED, 1960-1976
1
# of units
installed
Installed megawatt
capacity
Electric
Utilities
404
159,051
%
88.8%
98.4%
Industry
51
2,519
%
11.2%
1.6%
Total
455
161,540
ct
100%
100%
The electric utility industry itself has undergone some significant
market perturbations in recent years. As Figure 8.1 shows, both energy
and peak load demand maintained a relatively stable growth rate of between
five and nine percent per year from 1961 through the early 1970's. In 1973
a worldwide recession coupled with the Arab oil embargo caused a drop in
annual peak power demand for electricity in 1973. Energy demand showed
virtually no growth in 1974, and only began to climb as the recession
8-1
-------
12
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6
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1960
.DECEMBER PEAK LOAD3
___.... ANNUAL ENERGY REQUIREMENTS
"REPRESENTED BY THE SUM OF THE INDIVIDUAL PEAK LOADS OF THE REGIONAL COUNCIL'S
REPORT TO THE FPC.
I I i
1962
1964
1966
1968
YEAR
1970
1972
1974
1976
Figure 8-12. Percentage growth rate over previous year reported by major U.S. utility systems3.
8-2
-------
bottomed out in 1973. Peak power demand for electricity rose at a rate of
two to seven percent in 1975 and 1976, an increase over 1973 and 1974 but
still somewhat lower than the 1960 to 1972 period.
With the long lead times in plant construction cycles in this industry.
the capital programs tend to build a great deal of momentum. It is not
possible to respond immediately to changes in the demand for electric
power. Figure 8-2 shows how reserves in the power industry soared in 1973
and 1974 to a high of over 50 percent excess capacity over winter peak de-
mand. The summer peak margins would be somewhat lower. Not only have the
utilities suffered from this overbuilt circumstance, but a coincidental
problem involves the precipitous drop in collective system capacity factor
for the industry. Figure 8-3 shows this distinctive drop in capacity factors
from 1973 to 1974. The result of these phenomena are utilities with over-
commited capital programs supported by systems generating less revenues
due to the lower plant utilization.
This problem has lessened more recently due to increased demand for
electric power, but peak winter reserve capacity is 46 percent and will
continue to be above 40 percent through the end of the decade. As a result,
orders were very slack for boilers since 1974. In 1974, 69 coal-fired
boilers with a rated capacity of 32,964 MWe were ordered; this number
shrank to 22 (10,774 MWe) in 1975 and 13 (6,312 MWe) in 1976. This down-
ward trend appears to have reversed itself in 1977. Orders for the current
year are expected to total at least 20, with capacity of approximately
3
13,000 MWe. Market analysts are confident of an increasingly strong market
as utilities convert to coal or prepare to construct new units that have
been delayed due to sluggish demand for electric power. However, it will be
at least several years before the dislocations that occured in 1973 and 1974
8-3
-------
LUMBERS FROM ALL FPC REGIONAL COUNCILS WERE AVERAGED TO OBTAIN ANNUAL
REPRESENTATION.
1962 1964 1966 1968 1970 1972 1974
Figure 8-24. Annual peak reserves as a percentage of total available capacity, 1961-19773.
8-4
-------
56
55
54
53
I 52
LU
NJ
51
50
g 49
.
2 48
QC
o
47
46
45
44
43
r~rr
i i i i i i i i i
CAPACITY FACTOR IS CALCULATED BY DIVIDING ANNUAL ENERGY PRODUCED BY TOTAL
DEPENDABLE ENERGY CAPACITY.
.42
I960
1962 1964 1966 1968 1970
YEAR
1972
,1974
1976
Figure 8-3^. Annual capacity factor for the major U.S. electric utilities3.
8-5
-------
are eliminated. A return to a pre-recession level of power boiler sales
probably cannot be expected for several years. Contributing to this cir-
cumstance is the large backlog of boilers already ordered but delayed due
to utility uncertainty over economic and regulatory conditions in the near
future and passage of a comprehensive national energy plan.
8.1.2 Coal As The Basic Fossil Fuel For Electric Generation
The economic and_political problems that have surrounded oil and natural
gas supplies over the past few years have brought on a strong interest in
coal as the basic fuel for electric generation. As was indicated in Chapter 3,
the major fossil fuel boiler manufacturers anticipate no new orders for oil-
and gas-fired power boilers.
Figure 8-4 depicts the total number of coal-fired units (over 25 MWe)
installed (or scheduled for installation) since 1960. The steep change in
1973 is indicative of the number of units being delayed or cancelled by the
utilities. There may be some additional delays among the units scheduled
out to 1978; however, the recovery from 1973 is apparent. Generally, coal
demand can be expected to grow faster than the growth of primary electric
demand since coal will most likely replace a sizeable portion of the genera-
tion that otherwise would have been supplied by oil or natural gas. As
discussed in Chapter 3, it is uncertain how much of this new generation
capacity will be from fossil fuels and how much will be nuclear.
Figure 8-5 shows the average size of coal-fired units installed since
1963. The slight downtrend in number of units installed shown in Figure 8-4
is more than offset through the early 1970's with consistently larger unit
sizes. The average size of a coal-fired unit stabilized in the early
1970's. To a limited extent this probably is attributable to technological limita-
tions in the size of the generation units, but more importantly the economic
8-6
-------
aUNITS UNDER CONSTRUCTION BUT NOT YET IN COMMERCIAL OPERATION.
bIN THIS AND SUBSEQUENT FIGURES, S-YEAR RUNNING AVERAGES ARE USED TO
SMOOTH OUT VARIATIONS CAUSED BY RELATIVELY SMALL ANNUAL SAMPLE SIZES
14
1962
1964 1966 1968 1970 1972
INITIAL OPERATION YEAR
1974
1976
1978
Figure 8-4^. Aggregate annual number of installed coal-fired units over 25MW ona 5-year
running average0.
3-7
-------
1962
1964
1966
1974
1976
1968 1970 1972
INITIAL OPERATION YEAR
Figure 8-5. Average size of newly installed coal-fired units on a 5-year running average. 7
1978
8-8
-------
implications of relying on one unit for too large a percentage of a utility's
total generation need had started to limit.the size of newly installed units.
However, unit size is beginning to escalate, and a new generation of boilers
installed in the mid- and late 1980's will be somewhat larger than the
generation of boilers constructed in the 1970's. The new boilers will
average about 554 MWe.
8.1.3 Competitors In The Coal-Fired Boiler Industry
There are four competitors in the large (greater than 25 MWe) coal-fired
boiler market: Combustion Engineering, Inc., Foster Wheeler Corporation,
Babcock and Wilcox Company, and the Riley Company. Table 8-2 shows compara-
tive financial data for the four companies. The data are aggregated and,
therefore, reflect all of the products each company produces, which vary
significantly. Combustion Engineering, Inc., and Babcock and Wilcox Company
both participate as primary contractors in the nuclear power generation
business; all four companies supply a wide variety of products and materials
closely related to the power generation industry.
Table 8-2 reflects the relative amounts of debt in the capital structure
of each company as well as the relative return on sales. These may offer
some insights on'each- company's ability to adjust to increased production
or design costs caused by environmental regulations.
8-9
-------
Table 8-2. FINANCIAL DATA FOR FOSSIL-FIRED BOILER INDUSTRY8
(million $, 1976)
Assets
Equity
Long-Term Debt
Revenues
Net Income
R&D
Combustion
Engineering
1274.6
398.4
108.8
1830.9
54.2
28.8
Babcock &
Wilcox
1129.1
415.6
92.9
1691.8
53:1
27.4
Foster
Wheeler
476.1
. 128.5
45.3
1061.7
20.5
17.3
Riley
Company
151.0
33.1
14.1
210.2
4.9
2.5
Table 8-3 shows that there is no significant disparity between the four
manufacturers' reliance on the coal-fired boiler market.
Table 8-3. RELIANCE ON COAL-FIRED BOILER MARKET FOR EACH SUPPLIER
(million $, 1976)
Million of
Dollars
Percent of
Total Revenue
Revet
Combustion
Engineering
245.0
13%
lues From Coal-F-
Babcock &
Wilcox
230.6
14%
'red Boilers
Foster
Wheeler
197.7
19%
Riley
Company
42.9
20%
Assumes that the equipment price for coal-fired units is $43/kW as quoted
by FPC sources. Installation costs are not included since boiler vendors
generally do not do site installation work.
Figure 8-6 shows the percentage market share of the coal-fired boiler
market for each of these suppliers. Figure 8-7 shows the market share in
total annual megawatts installed.
8-10
-------
60
co 50
o
3
LU
CC
40
CC
30
CD
Ul
<20
=5
a.
u-
o
HI
S 10
CO
COMBUSTION ENGINEERING
BABCOCK&WILCOX
FOSTER WHEELER
RILEY COMPANY
ACTUAL
I
I _
I PROJECTED3
."" -^*- .-
"*..
~t ...... "i v.^.
U - 1 - 1
aUNITS UNDER CONSTRUCTION BUT NOT YET IN COMMERCIAL OPERATION
1 - 1 -- 1 - 1 - 1 - 1 - 1 ' i i i
1962 1964 1966 1968 1970 1972
OPERATION YEAR
1974
1976
1978
Figure 8-6^°. Annual installed megawatt capacity as a percentage of the total coal-fired market on
a 5-year running average.
8-11
-------
6000
5000
4000
3000
< 2000
a
z
1000
.COMBUSTION ENGINEERING
-BABCOCK&WILCOX
.FOSTER WHEELER
. RILEY COMPANY
PROJECTED ACCORDING TO IN-PROCESS CONSTRUCTION
1962 1964 1966 1968 1970 1972
OPERATION YEAR
1974 1976 1978
Figure 8-71 1. Annual installed megawatt capacity for coal-fired units on a 5-year running average.
8-12
-------
By megawatt capacity installed, Combustion Engineering and Babcock
and Wilcox are the clear market leaders, with approximately 40 percent of
the total market each. Foster Wheeler and the Riley Company sh.are the
remaining 20 percent of the market. Figure 8-8 shows the distribution of
unit sizes by supplier for all large coal-fired units installed since 1960.
The Riley Company has clearly positioned itself in the small-size unit segment
of the market with one-third of its units in the 100-200 MWe class and no
Units over 500 MWe. The other three manufacturers have relatively similar
curves with Foster Wheeler, slightly skewing toward 600-900 MWe units.
There is no indication of further market segmentation either by fuel
type or geographic location of the plant. In some cases a particular supplier
may have an inordinate number of units in a particular area or on a particular
utility system. Ths is explained generally by the economies of plant dupli-
cation (design, maintenance, and operation factors) as well as the possibility
of more effective marketing efforts by one supplier in a particular area.
The market is generally mature enough so that thorough economic and tech-
nological evaluation of a bid may not indicate a clear best choice, in
which case somewhat "softer" measures such as duplication of plant controls
for easier operator training or more effective sales coverage may determine
the winning bid.
Historically the large coal-fired boiler industry appears to be a
relatively stable and mature industry with perhaps two primary segments by
unit size. Among the large unit suppliers, Combustion Engineering and Babcock &
Wilcox hold similar market shares in both segments. Foster Wheeler appears
quite capable of surviving in the large unit segment though securing a notice-
ably smaller number of units. The Riley Company, on the other hand, competes
primarily for smaller units and has shown some recent gains in market share for
8-13
-------
33r-
30 -
CO
o 27-
2 24-
fe 21 -
as
i 18~
£ 15 -
U- *n
PERCENT 0
> to en (o N
111-
PERCENT OF TOTAL INSTALLATIONS,
_»_»_» for-jrocjt.
OJ 01 co N) 01 co L»o«jou
U
E
ABC
OCK
&WI
_L
LCOX.
' I "
1 . 1
fllfiiiiili
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r-cMro«rmcot>«eo o
T\
c
OME
UST
ONI
ENGI
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NEERING
~r
33
an
27
24
21
18
15
12
9
6
3
33
30
27
24
21
18
15
9
6
3
n
-
F
OSTl
= R WHEELER
1 1
oooo oooooo -t-
0000 C900000C3
r-cMco«f in«oP7.opepog
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^CMCO * LO to r-. co e=
en
-
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LEY
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'ANY
OC300000000+ 00000
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a o o o o +
»- CM c*j » m to r^
PLANT CAPACITY, MW
CO O
en
PLANT CAPACITY, MW
! . t , ' 't " , : ,'':
Figure 8-812. Size distribution of coal-fired power plants installed 1960-1978 for 4 suppliers.
8-14
-------
this size unit. Even though the size of the total coal-fired boiler market
may be cyclical, there is no apparent reason to assume that there is going
to be a significant change in the relative market shares among these four
equipment suppliers in the foreseeable future.
8-15
-------
8.2 COST OF CONTROL
The degree to which the four major boiler manufacturers (Combustion
Engineering, Babcock and Wilcox, Foster Wheeler and the Riley Company can re-
duce NOx emissions below the current standard of performance (300 nanograms/
joule) is a function of their current boiler design, status of improved com-
bustors, and the type of coal burned. In order to account for these factors,
n
three scenarios have been proposed to provide a range for possible impacts.
The first scenario (Scenario I) under consideration is to postulate
that all of the major boiler manufacturers will be able to comply with the pro-
posed emission limits with their current modern design units or with insigni-
ficant modifications to current designs. This scenario would imply that none of
the four manufacturer's boilers would undergo any change in capital or
operating costs. This scenario is considered to be the most likely since
all manufacturers have indicated some optimism in reaching levels below
the current NSPS, although three manufacturers except Combustion Engineering
have expressed concern about the long-term effects on the boiler of operating at
such a low NOV level. By definition this scenario has no economic impact.
/\
The second scenario assumes that two of the manufacturers who have
demonstrated the lowest NOX emission levels (Combustion Engineering and
Babcock Wilcox) can meet the proposed emission limits on all coal types and that the
other manufacturers (Foster Wheeler and the Riley Company) need to modify cur-
rent designs when burning corrosive coal. The assumption in this scenario is
that the modifications to the current burners are relatively minor and can be
accomplished without loss of market. However, Foster Wheeler and the Riley
Company would have to invest in research and development to improve their
burner designs. The exact amount of this investment is unclear but an upper
bound approximation can be made. Babcock and Wilcox estimated in 1976 that
8-16
-------
the developmental costs for their burner system was about two million
-] o
dollars.10 It has been assumed that this represents an extreme upper limit
on the cost of modifying the Foster Wheeler and Riley Company systems to
achieve the proposed standard.
The third scenario (Scenario III) chosen for analysis is the most extreme.
This scenario assumes that three manufacturers do not meet the proposed emission
limits with their current boilers. In these circumstances the only alterna-
tives available to the manufacturers would be to use the tangential firing
system developed by Combustion Engineering or to develop a significantly
different combustion system. Since this system is no longer covered by
patents, there is no legal or institutional barrier in adapting the Combus-
tion Engineering technology. However, to use this technology the manufac-
turers would have to undergo major design and fabrication efforts and in
all probability would not be able to .compete effectively in the market until
designs were perfected. While.there are potentially large costs associated
with this retooling operation, the magnitude of these costs cannot be
estimated. As explained in Section 8.4, the potential loss of market share
for an extended period of time would far exceed any costs of retooling.
The economic implications of these design changes on industry structure will
be discussed in Section 8.4.
In addition, there are some minor peripheral considerations such as opera-
tor training costs for operation with less excess air; but considering that
this standard will apply only to new units which will be incurring operating
training costs anyway, these incremental costs will not be significant.
8-17
-------
8.3 COSTS OF OTHER ENVIRONMENTAL CONTROLS
The electric utility industry is subject to many environmental regu-
lations other than those re.lated to air pollution. The purpose of this
section is to summarize the expected capital and operating requirements
imposed on the industry as a whole and on a typical new utility boiler.
Unless otherwise noted all costs.are taken from "The Economic Impact of EPA's
Air and Water Regulations on the Electric Utility Industry."^
8.3.1 Environmental Control Costs for Typical New Installations
As was shown in Figure 8-5 the newly installed coal-fired units are
currently averaging slightly over 500 megawatts. Consistent with this, a
600 MWe coal-fired unit was selected as the model new utility boiler. This
plant is assumed to require chemical effluent treatment, a cooling tower, and
entrainment screens for water pollution control.
Table 8-4 shows the estimated capital and operating cost for these
devices.
8.3.2 Total Industry Environmental Control Costs
Table 8-5 shows the total capital costs attributable to environmental
control costs in the electric utility industry for the period 1975-1985. The
estimated cumulative total operating and maintenance costs associated with
this equipment between 1975 and 1985 is 6.1 billion dollars. In addition
to these costs an estimated 1.0 billion dollars will.be required to provide
for capacity losses due to the operation of water pollution control equipment.
8-18
-------
Table 8-4- ENVIRONMENTAL CAPITAL COST FOR NEW PLANTS3
(1975 dollars)
Control Device
Chemical Effluent
Treatment
Mechanical Cooling
Tower
Entrainment Screens
Total
Cost/kW
1.52
5.77
4.08
11.37
Total Cost (106$)
.9
3.46
2.45
6.81
Annual O&M
(Mills/kl
.3
.2
.1
.6
Costs
Vh)
Based on a new 600-MW coal-fired unit.
Table 8-5.
rnnT l975-1985 BY TYPE OF POLLUTION CONTROL
EQUIPMENT (excluding equipment built for reasons other than
compliance with federal regulations)
Amount Built
(million kWe)
Capital Expenditures
(billion 1975 dollars)
Mater Regulations
Chemical Treatment
Cooling Towers
Entrainment Screens &
Cooling Towers
469.1
102.2
13.4
$1.2
2.6
0.6
8-19
-------
8.4 ECONOMIC IMPACT OF ALTERNATIVE EMISSION CONTROL SYSTEMS
8.4.1 Penetration of New Units "
Since the nature of the proposed emission control change involves
a potential process change, the economic impacts will tend to accrue in
proportion to the introduction of the affected units in the U.S. power
generation base. As a result the economic impacts will increase annually
as these units come on line and become an increasingly larger percentage.,
of the industry's generating capacity. The long lead times between the
initial contracting for a large fossil-fired boiler and the initial
commercial operation create a natural lag in measuring the economic and
technological impacts of standards which affect these units. For example,
units which were designed subsequent to the original NOX standard in
1971 are only now coming on line. Units affected by this revision of the
standard would not be coming into service until the early to mid-1980'.s.
Table 8-6 projects the percentage of total electrical power supplied by units
potentially affected by this standard. The total additions of coal-fired
units were extrapolated out to 1990-
Making consistent assumptions about the growth in total generation capa-
bility over the same period, the table shows that by 1985 the units
affected by this standard will be approximately six percent of the total
generation capacity of the electric power industry. ' The actual energy
generated by these units will be a larger percentage of the total energy
produced nationally since these units will tend to be more efficient than
older units and therefore will be put in service preferentially to older,
less efficient units. This will give the newer units a higher capacity
8-20
-------
Table 8-6. PENETRATION OF NEW COAL-FIRED UNITS INTO U.S. GENERATING BASE
-
1982
1983
1984
1985
1986
1987
1988
1989
1990
T ; '-
Projected3 i Annual
Total U.S.
Generating
Capacity
(Gigawatts)
700.1
735.2
772.1
810, 9b
851.6
894.4
939,3
986.4
1035.9
Coali
Fired
Additions
(Giqawatts)
11.6
12.2
12.4
12.9b
13.5
14.2
14.9
15.7
16.5
i
Cumulative
Coal -fired
Additions
from 1982
(Gigawatts)^
11.6
23.8
36.2
49.1
62.6
76.8
91.7
107.4
123.9
Percent of
Total U.S.
Generating
Capacity
1.6
3.2 .
4.7
6.1
7.3
8.,6
9.8
10.9
12.0
Percent of
Total U.S.
Energy
Generation
2.1
4.2
6.1
7.9
' 9.5
11.2
12.7
14.2
15.6
Taken from Tables 3-6 and Footnote 15
Extrapolated from Tables 3-6 and Footnote 15 at constant growth factor.
References the same as shown on Chapter 3 tables.
cFrom the projections in Table 3-6 in Chapter III, approximately
4.96 percent of this capacity will be to replace retiring units.
The remainder goes toward net system expansion.
-8-21
-------
factor than the system average. We have assumed a 65 percent capacity
factor for a new base load coal-fired plant (5694 hours/year) compared
to overall system capacity factors of 50 percent. Using a rough calcu-
lation for the first few years, this factor would increase the impact
of this penetration by approximately 30 percent (5Q percent^' This
explains the last column in Table 8-6. These data indicate the considerable
lag in economic impact on this industry of a standard which only affects
new units as they are put into commercial service.
8.4.2 Scenario I Impacts
The economic impacts from Scenario I are by definition negligible.
This scenario presumes that all four manufacturers are able to meet the
lower NOX standard on large coal-fired boilers with their existing designs
incorporating staged combustion techniques and operated at controlled
levels of excess air. There are no design changes or efficiency losses
associated with this scenario and consequently there are no direct costs
of control. There are some minor peripheral considerations such as operator
training costs for operation with less excess air, but considering that
this standard will apply only to new units which will be incurring operating
training costs anyway, these incremental costs will not be significant.
Test data on several units (see Chapter 6) indicate that this scenario
Is the most likely to occur. I
8.4.3 Scenario II Impacts
This scenario presumes all four manufacturers are able to meet control
limits when firing coal with little potential for causing tube wastage,
but Foster Wheeler and Riley will have to develop a low NOX burner'for use
8-22
-------
when firing coal with a high potential for causing tube wastage. Possible
economic impacts resulting from this situation are the extra research and
development costs associated with designing a low NO burner.
J\
Research and development costs for designing a new burner are not
expected to be more than two million dollars (see Section S.2). For Foster
Wheeler, this is 11.5 percent of their research and development budget
for 1976 and less than 0.2 percent of total sales (see Section 8.1, Table
8-2). It is reasonable to believe that this cost would not have a signifi-
cant impact on Foster Wheeler's financial situation, for if such research
and development efforts were recovered in the first year the burner is put
into operation, the increase in price would be less than 1.0 percent.
The situation poses a somewhat different and possibly significant pro-
blem to the Riley Company. Riley's research and development budget for
1976 was 2.5 million dollars, and is projected to be 1.8 million dollars for
1977. The reason for the decrease is a slowdown on coal gasification
research. Increased costs of two million dollars would more than double
the research and development budget in 1977. While this may be viewed as
a serious problem, there are several mitigating circumstances. Should the
1977 research and development budget escalate to 3.8 million dollars,
research and development expenditures as a percent of total sales (projected
to be 242 million dollars in 1977) would be 1.6 percent. Overall, industry
research and development expenditures as a percent of total sales is a.lso 1.6
percent. Another mitigating factor is the current research Riley is
conducting, in low NOV burner design for its Turbofurnace. These
new
burners are designed to control mixing of fuel and air to reduce thermal
and fuel N0x. It is quite possible that Riley would not need to spend
8-23
-------
the full two minion dollars specified in o.rder to develop a burner that
can meet the proposed standard. Foster Wheeler is also currently engaged
in research to develop a new low NO burner, so there is a possibility that
X
both companies may not.have to spend a full two million dollars to perfect
a new, low NO burner. With or without this possibility, the economic
X
impact of increased research and development expenditures by both Foster
Wheeler and Riley should not be significant.
8.4.4 Scenario III Impacts
The most serious economic impact that could evolve from this standard
involves the inability of one or more suppliers to provide a unit which will
meet the standard even with the modifications discussed in Scenario II. ,
As has been noted all suppliers appear to be able to meet' the proposed
lower standard. However, if the results of the other suppliers' new units
(designed since the 1971 standard) are such that they cannot or will not
guarantee the lower standard, the impacts on the marketplace could be
significant.
If a supplier whose current design did not meet the standard chose
to adopt a tangentially-fired design he would face two obstacles:
1. The length of time and cost associated with
redesign effort;
2. Reluctance on the part of the electric power industry
to buy the design from a supplier who had not been
offering it previously.
On the first point, without anticipating the need to make such a major
redesign effort, a supplier effectively is likely to be "out of the market"
-------
for the period of the redesign effort. The potential damages that could
accrue from producing and selling.a unit that failed to meet the standard
could be very high if they involve plant shutdowns or major reductions in
efficiency by dropping preheat temperatures. If a supplier chose not to
take these risks and instead redesign to a tangentially-fired unit, he
would incur not only the costs of the redesign and retooling,, but for the
period of time the redesign takes, he would be trying to secure orders
without the support offered by "typical" drawings and other technical
documentation for the design he was offering. Similarly, performance and
construction guarantees for the new design for the most part would be
unsubstantiated. With the relatively long lead times between the order
date and the shipment date for a large coal-fired boiler it is not likely
that even a six-month redesign effort would create a period when a supplier
could not meet a shipment date as a result of the redesign effort. Although
design and manufacturing drawings may be later in the manufacturing process
for some parts of the units, the parts would probably still be shipped in
time to meet any normal construction schedules. Several factors could
complicate this; for example, the power generation business is cyclical.
As shown in Section 8.1 the industry has been in a sales "trough" since 1974,
and in the past year has just begun to climb slowly out of it. If
a sudden rush in orders (typical in this business) .occurs at the same time
as a major redesign effort, a supplier may have to forego bids that are
decided on a short-cycle installation basis.
It is important to distinguish between the type of dislocation being
produced here and the design changes that occur as the normal evolution
of the product. In the latter case the design changes tend to be logical
extrapolations of previous designs which are introduced in a carefully
8-25
-------
timed and coordinated fashion. The redesign involved in going from
opposed wall firing to tangential firing is not only more radical but
also could not be timed for the most opportune entry into the market.
The other obstacle involved with such a redesign effort concerns
buyer behavior. As Table 8-6 showed, there are only 20 to 25 new
coal-fired units being added per year out to the early 1980's. Since many
of these are multiple-unit purchases there may be as few as 10-15 discrete
purchase decisions per year. (This assumes a noncyclical market and sales
of units in a year occurring at the same approximate pace that units are
put in service.) Considering that the "average" utility might not be in the
market more frequently than every few years, these purchase decisions are
not only few in number but also likely to vary considerably in their decision
criteria. There are, of course, factors which tend to make these decisions
more homogenous, such as the broad regulation in the industry and all-company
competition in the same capital market environment. However, it is still
very difficult to depict a typical purchase decision for a large coal-fired
boiler. Different utility companies will have different criteria and method-
ology for making the decision, and there are so few data points (as a result
of the low number of transactions) that it is impossible to do statistical
analysis. These characteristics of the market place preclude the use of
elasticity considerations in evaluating such a highly differentiated product.
In conclusion, it is difficult if not impossible to anticipate the market
reaction to one of the non-tangential manufacturers to convert over to
tangential design. Some utilities may perceive this as a harmless change;
others may penalize such an offering for the likelihood of "learning curve"
problems often associated with radical redesign efforts. Even though
this difficulty exists it is possible to assess some of the impacts if
8-26
-------
they were to occur. Table 8-7 shows that a change in sales'billed
equivalent to one sale involving two 600 megawatt coal-fired units would
greatly impact any of these companies' share of the coal-fired market.
The fact that in the future the coal-fired market is likely to be signi-
ficantly larger relative to other fossil-fuel fired markets may tend to
overstate these numbers; but at the same time this large coal-fired market
proportionally increases the likelihood of occurrence of an order being
placed as a result of these design considerations.
Table 8-7.
ONE TWO-UNIT (600 MW) ORDER ON
: :
Company
Combustion
Engineering
percent or Annual Coal-
Fired Megawatts^
i
23% .
i
Babcock & Wilcox
Foster Wheeler
The Riley
Company
25%
88%
150%
Percent of Annual
Revenues"
4.2%
4.7%
6.9%
V
31.9%c
Figure 8-7)"^ rUnn1n9 &Vera9e °f coal-fl>ed installation in 1978 (see
the Rfiey
The comparison of the revenues from one such order to the total
revenues of the company reflects both the size and the diversity of the
four suppliers. The Riley Company is clearly the most vulnerable by this
measure; however, this impact is mitigated somewhat by the fact that
8-27
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Riley to some extent is segmented away from the other suppliers and there-
fore may be less likely to lose any given order as a result of redesign
considerations..
By way of summary, it is difficult to predict the possible market
share effects of one or all three non-tangentially-fired suppliers converting
their combustion system design. It is not likely that purchasers would
devalue such a bid on the basis of capital cost or efficiency since these
are not likely to change significantly; however, they may penalize such
bids for some period of time on the basis-of possible forced outage-rate
impacts or construction delays associated with such radical redesign
efforts. If such is the case and market shares are indeed shifted as a
result of such redesign, the impacts could be very severe, especially on
the two smaller,less diversified companies.
8.4.5 Modified/Reconstructed Facilities
The proposed standard is not to be applied on a retrofit basis.
Only neti units which commenced construction on or after the date of proposal
of these regulations will be affected. It is not anticipated that any
existing units will meet the requirements of being classified as modified or
reconstructed units as delineated in Chapter 5 of this standard support j
t
\
document. As a result there will be no economic impact on modified or |
|
reconstructed facilities. _,
8.5 POTENTIAL SOCIOECONOMIC AND INFLATIONARY IMPACT
8.5.1 Inflationary Considerations
All three scenarios do not have the potential for having any d'irect
inflationary impacts. Even under the most radical scenario, that of all
8-28
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manufacturers being forced to use tangential design, the costs would
only be in redesign and retooling efforts. These costs, when passed
along over a long period of time (attributable to the slow penetration of
units affected by this'standard) should prove to be minimal and non-infla-
tionary.
8.5.2 Energy Considerations
None of the three scenarios discussed entail any efficiency losses.
Consequently, the impact of the proposed standard on energy consumption
would be insignificant.I .
8.5.3 Secondary Socioeconomic Impact's
Clearly, Scenarios I and II could not involve any significant second
order impacts to society. The only concern over adverse socioeconomic
impacts centers on Scenario III. The differential impact on the four key
suppliers in this industry could have significant impacts on the industry.
structure. The industry by its nature is already highly concentrated.
Any circumstance that might tend to concentrate it'further may have serious
long-term impacts.
8.6 SUMMARY
There will be no additional cost of compliance under the most likely
scenario since compliance is achieved by changing the, structural configura-
tion of the boilers, not by adding control equipment. Therefore, with no
additional outlays, there will be no inflationary pressures generated nor
will there be any consumer cost increases. The small business section
will suffer.' no deleterious effects since none of the four companies
involved are in that category. Energy requirements will not increase.
If anything, with the lowered ratio of excess air, there may be a very
slight decrease.
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REFERENCES FOR CHAPTER 8
1. Experience sheets, Foster Wheeler Corp., Babcock and Wilcox Co.,
The Riley Company, Combustion Engineering, Inc., Emissions Standards and
t
Engineering Division, Office of Air Quality Planning and Standards, U.S.
Environemntal Protection Agency, Research Triangle Park, North Carolina,
1976.
2. Federal Power Commission, Electric Power Statistics, December, 1974,
Table 4, page 14, and Edison Electrical Institute, Annual Electric Power
Survey.
3. Kidder Peabody Co., A Status Report on Electric Utility Generating
Equipment. Fossil Boilers as of December 31, 1976, March, 1977.
4. FPC, Op_. cit., Table 15, page 14. December 13 and August 31, numbers
were averaged to get annual representation.
5. Ibid. Table 14 and Table 15, page 14. Capacity factor is calculated
by dividing dependable capacity (converted to kWh) by annual energy.
6. Op. cit., Experience Sheets.
7. Ibid.
8. Security Exchange Commission, Form 10K, Foster Wheeler Corp., Babcock
and Wilcox Co., The Riley Company, Combustion Engineering, Inc., 1976.
9. Ibid.
10. Ibid.
11. Ibid.
12. Ibid.
13. Meeting Notes, Meeting with Babcock and Wilcox Co., Barberton, Ohio,
October 1976.
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14. "The Economic Impact of EPA's Air and Water Regulations on the
Electric Utility Industry," Temple, Barker and Sloane, Inc., prepared for
EPA under Contract No. 68-01-2803, March, 1976.
15. Unpublished calculations or data, Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina.
16. FPC, op cit.
17. "NOX Control Review," United States Environmental Protection Agency,
Fall, 1977, page 5.
8-31
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9. RATIONALE FOR THE PROPOSED STANDARD
This Background Information document supports proposed nitrogen
oxides (NO ) emission limits for the combustion of pulverized coal
A
(except lignite and coal refuse) in new electric utility steam
generating units with heat input rates greater than 73 MW (250 million
Btu per hr). The proposed NOV emission limits for units which burn
A
lignite,1?2'3'4 coal refuse,,5'6'7 liquid and gaseous fuels,8'9'10
shale oil, and fuels derived from coal11'12'1'3'14'1^^ based on
other studies, as referenced, and are not discussed in this document.
Additional information may be found in the preamble and regulation for
Subpart Da in the Federal Register.
Also, all information EPA used in developing the proposed regulation
may be found in the Subpart Da docket (number OAQPS-78-1) at the EPA
Central Docket Section (A-130), Room 2903B, Waterside Mall, 401 M Street
S. W., Washington, D. C. 20460.
9.1 SELECTION OF SOURCE FOR CONTROL
Electric utility steam generating units contribute significantly to
national emission levels of nitrogen oxides (NO ). In 1976 total nation-
A
wide emissions of NOX amounted to about 23.0 teragrams (25.5 million tons);
electric utility units acounted for 29 percent of this, or 6.67 teragrams
(7.35 million tons). The total capacity of all U. S. units was about
9-1
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340 gigawatts in 1975 and is expected to rise to 470 gigawatts by 1985,
representing a capacity increase of 38 percent in only 10 years. About.
250 new units are expected to commence operation during this period.
Due to high emission levels and a strong growth rate, the electric
utility industry will continue to be a major source of nationwide NO emissions
X
in the future, second only 'to mobile source emissions. Consequently, EPA
believes there is an important i
utility-steam generating units.
believes there is an important need to control N0v emissions from electric
X
9.2 SELECTION OF POLLUTANTS AND AFFECTED FACILITIES
Electric utility units emit three major pollutants into the atmosphere:
sulfur dioxide, particulates, and NOV. Regulations have been developed for
/\
sulfur dioxide and particulates, and these are supported in separate
Background Information documents. ' Other air pollutants, including
carbon monoxide, and hydrocarbons are also emitted by electric utility
units. The quantities of these emitted into the atmosphere, however,
are small.
The affected facility to which the proposed emission limits would
apply would be defined as any steam generating unit which:
is located in an electric utility power plant;
is capable of combusting greater than 73 MW (250 million
Btu/hr) of fossil fuel either alone or in combination with other
fuels; and
commenced construction or modification on or after the date
of proposal of these emission limits in the FEDERAL REGISTER.
The proposed regulations would only cover steam generating units
which are located in electric utility power plants since study of
emission controls for industrial units would require a different economic
9-2
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analysis. Also, different control technology may be needed for industrial
units. Industrial units of more than 73 MU (25C million Btu/hr) heat input
are presently covered under Subpart D for fossil-fuel-fired steam generators,
and studies are in progress to develop revised emission limits for these types
of units.
Although the proposed emission limits are primarily concerned with the
combustion of fossil fuels, the regulations would also cover new units which
burn other fuels either alone or in combination with fossil fuels. A pro-
ration equation is included in the regulation which would simplify the
determination of an appropriate emission limit when a combination of fuels
is burned simultaneously in the same unit.
9.3 SELECTION OF THE BEST SYSTEM OF CONTINUOUS EMISSION REDUCTION
CONSIDERING COSTS
NOX emissions are controlled by modifying the way the fuel is
combusted in the boiler. EPA believes that the best system for control
of NOX emissions from electric utility steam generating units which burn
pulverized coal is a combination of staged combustion, low excess air,
and reduced heat release rate. These combustion modification techniques
are basically the same as those needed to achieve the original NO emission
A
limits for steam generators under Subpart D. The costs associated with
greater implementation of these combustion modification techniques, as
needed to comply with the revised NOV emission limits under Subpart Da,
'X
would be minimal. Another emission control technique, flue gas treatment,
has not yet been demonstrated effective for reducing NO emissions from
X '
coal-fired units.
9-3
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There are several potential side effects associated with operation
of a unit at NO levels as low as the proposed limits. These are: boiler
s\
tube wastage; slagging; increased emissions of particulates, carbon monoxide,
polycyclic organic matter, and other hydrocarbons; boiler efficiency losses;
carbon loss in the ash; low steam temperatures; and operating hazards
(including boiler explosions). EPA has evaluated these side effects and
believes that none would be a problem during operation of a boiler at
the NO levels required by the proposed emission limits. Concern over
A
several of the potential side effects, however, including tube wastage,
slagging, increased emissions of polycyclic organic matter and particulates,
and possible operating hazards has been expressed by industry. These concerns
are responded to below.
Tube wastage (or corrosion) is the deterioration of boiler tube
surfaces due to the corrosive effects of ash in the presence of a reducing
atmosphere. (A reducing atmosphere often accompanies low NO operation). The
J\
severity of tube wastage is believed to vary with several factors, but
especially with the quality of the coal burned. For example, high sulfur
Eastern coals are believed to cause more of a tube wastage problem than
low sulfur Western coals. Serious tube wastage can shorten the life of a
boiler and result in expensive repairs.
Concern over tube wastage is reflected in a statement made by one of
the four major boiler manufacturers, Combustion Engineering, that it would
guarantee its new units to meet an NO limit of 210 ng/J (0.5 Ib/million Btu)
A.
when burning low sulfur, low rank Western coals, but only 260 ng/J when
burning the higher sulfur Eastern bituminous coals (see Appendix C). The
other boiler manufacturers and several electric utilities have also
expressed concern over the potential for tube wastage with high sulfur
Eastern coals.
9-4
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Corrosion test results are available for five of the six units EPA
tested in support of the proposed emission limits. These tests involved
the measurement of metal loss from test coupons inserted into the boiler.
The results indicate that corrosion was not a serious problem for at
least four of the units during the testing. These were all tangentially-
fired boilers manufactured by Combustion Engineering. It should be
noted, however, that coupon corrosion tests indicate only relative
corrosion rates in selected areas of a boiler and do not demonstrate what
the long-term effects of corrosion would be on the life of a unit.
EPA believes that new units which would be designed to comply with
the proposed N0x emission limits would not experience serious tube wastage
for the following reasons:
Coupon corrosion tests indicate that tube wastage is
not significantly accelerated during low NO operation of
modern Combustion Engineering boilers. x.
Combustion Engineering has stated that its modern units
would be capable of achieving, without adverse long-term side
effects, a 260 ng/J (0.60 Ib/million Btu) emission limit when
burning Eastern bituminous coals and 210 ng/J (0.50 Ib/million
Btu) when burning lower rank Western coals and lignite. These
are essentially the same limits as those proposed by EPA.
Foster Wheeler and Babcock & Wilcox have executed
contracts to build units which will be required to comply
with the State of New Mexico's N0v emission limit of 190 nq/J
(0.45 Ib/million Btu). x
_Babcock & Wilcox has designed a new burner which will
permit a furnace to be maintained in an oxidizing environment,
thus, minimizing the potential for furnace wall/corrosion when
high sulfur bituminous coal is burned.
_ Foster Wheeler and Riley Stoker are developing new burners
which may have the same advantage as the new Babcock & Wilcox
burner. Also, Foster Wheeler incorporates "boundary air" in
its modern units to minimize reducing conditions near the boiler
wall where tube wastage occurs.
Unmanageable slagging was not reported during any of the EPA emission
tests conducted in support of the proposed limits. Based on the boiler
9-5
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manufacturers' experience with high slagging coals, EPA believes that
modern units which are designed with ample furnace volumes would
minimize slagging while complying with the proposed emission limits.
Polycyclic organic matter (POM) is a concern because some types of
POM have been identified as possible carcinogens. EPA has POM
emission data from only one unit. This is an old-style unit, however,
and its emissions are probably not representative of emissions from
modern-design units. It is reasonable to believe that POM emissions
should not increase on modern units because POM generation is closely
related to incomplete combustion, and poor combustion was not apparent
during the EPA tests. This is evidenced by CO emission levels which
were generally the same during normal and low NO operation. Also,
X
electric utility power plants contribute very little (less than one percent)
to total nationwide emission levels of POM. Thus, EPA does not believe
that POM emission increases will be significant as a result of these
revised regulations.
During EPA tests of modern units, particulate emission levels were
variable. However, no significant increases in particulate levels were
detected which could be directly attributed to boiler operation at low
NOV levels. Consequently, EPA does not believe that particulate
emissions would increase as a result of low NO operation.
A
There was no indication during EPA testing that operation of a
boiler at the NO levels required by the proposed limits could cause
A
boiler operating hazards. During discussions with the boiler manufacturers
in 1976, EPA asked if more effective NO control would increase safety
A
hazards. The three largest manufacturers indicated that they were not
9-6
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worried about safety hazards at reduced NO levels. Based on EPA field
. /\
experience and discussions with the boiler manufacturers, EPA does not
believe that NO control would result in serious safety hazards.
X
9.4 SELECTION OF THE FORMAT OF THE PROPOSED STANDARD
The Clean Air Act Amendments of 1977 require EPA to establish both
emission limits and percent reductions in uncontrolled emission levels
for new steam generators which burn fossil fuels. EPA has decided to
apply these requirements to the combustion of all fuels so as to simplify
enforcement and to effect greater environmental benefits.
The proposed emission limits are expressed as mass per unit heat
input (nanograms per joule, or pounds per million Btu). In 1971 when
emission limits for steam generators were promulgated under Subpart D,
EPA determined that units of mass per unit heat input were the most
practical of several options. EPA believes that it is still practical
to express the proposed revised emission limits for steam generators in
terms of these units.
It is impossible to specify a rational percent reduction in uncontrolled
NO emission levels because there is no direct relationship between NO
* x
emissions with and without control. Furthermore, since NO control with
X
combustion modification techniques occurs in the furnace at the instant
that NO is formed, there is no way to measure uncontrolled NO emission
" X
levels prior to combustion. However, to comply with the requirements
of the Act, EPA has defined representative uncontrolled emission levels
for solid, liquid, and gaseous fuels, and a percent reduction for each
fuel has been specified. The defined uncontrolled emission levels are
based on worst-case emission rates, according to published emission factors.
18
9-7
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The proposed percent emission reduction requirements are as follows:
A 25 percent emission reduction would be required for
gaseous fuels, based on an uncontrolled emission rate
defined as 290 ng/J (0.67 1 fa/million Btu).
A 30 percent emission reduction would be required for
liquid fuels, based on an uncontrolled emission rate
defined as 310 ng/J (0.72 Ib/million Btu).
A 65 percent emission reduction would be required for
solid fuels, based on an uncontrolled emission rate defined
as 990 ng/J (2.3 To/million Btu).
If a unit is in compliance with the appropriate NO emission limit, then
X
it will automatically satisfy the percent emission reduction requirement.
Thus, in the case of NO emissions, the percent reduction is not controlling,
A
and compliance testing for the emission limitation will automatically satisfy
all compliance testing requirements.
9.5 SELECTION OF EMISSION LIMITS
NO emission tests were performed on six modern pulverized coal-fired
A
electric utility steam generating units. Four of these units were new
Combustion Engineering designs, one was a Combustion Engineering unit
which had been retrofitted with overfire air, and one was a Babcock & Hilcox
unit which had been retrofitted with low-emission (dual register) burners.
During these tests NO emissions were consistently below 260 ng/J
A
(0.60 Ib/million Btu) and commonly below 210 ng/J (0.50 Ib/million Btu).
However, due to the potential for tube wastage associated with low NOX
operation, EPA has concluded that it would not be reasonable to establish
an NO emission limit for pulverized coal-fired units at 210 ng/J for
A
al1 types of coal.
As mentioned in section 9.3, tube wastage is of major concern,
expecially when Eastern coals are burned. EPA has concluded from field
9-8
-------
testing results, discussions with industry, and the advice of our research
laboratories that an NOV emission limit of 260 ng/J would be appropriate
X
for new units which burn Eastern coals. At this emission level, EPA
believes that tube wastage would not be accelerated as a result of the
application of combustion modification techniques.
Tube wastage does not appear to be a problem at emission levels as
low as 210 ng/J when low sulfur, low rank Western coals are burned.
Consequently, EPA has proposed an emission limit of 210 ng/J for new
units which burn these coals. Low sulfur, low rank Western coal would be
classified in the proposed regulations as "subbituminous coal," according
to ASTM standards. There may be some Western bituminous coals which have
high tube wastage potentials due to high sulfur contents. The combustion
of these coals would be subject to the same emission limit as Eastern coals.
9.6 VISIBLE EMISSION STANDARDS
There are.no visible emission regulations .associated with NO^ emissions.
An opacity standard has been proposed under Subpart Da, however, and this is
described in the Background Information Document for Particulate Matter,."17
9.7 MODIFICATION AND RECONSTRUCTION CONSIDERATIONS
A modification is defined in 40 CFR Part 60, Subpart A and in section 111
of the Clean Air Act as any physical or operational change to an existing
facility which results in an increase in the emission rate to the atmosphere
of any pollutant to which a standard applies. Upon modification, an
existing facility becomes an affected facility (i.e., it becomes subject
to new source performance standards) for each pollutant to which a standard
applies and for which there is an increase in the emission rate to the
atmosphere. Certain exceptions to the modification rule are explained in
9-9
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Subpart A and in Chapter 5. Also, Chapter 5 discusses several situations
where changes to the pulverizer system, combustion air system, steam
generation system, draft system, or fuel combustion system could cause
an increase in emissions, and thus, cause a facility to be subject to
the modification rule.
A reconstruction is defined in Subpart A as the replacement of
components of an existing facility to such an extent that:
The fixed capital cost of the new components exceeds
50 percent of the fixed capital cost that would be required
to construct a comparable entirely new facility; and
It is technologically and economically feasible to meet
the applicable emission standards.
An existing facility, upon reconstruction, becomes an affected facility
(i.e., it becomes subject to new source performance standards) irrespective
of any changes in emission rates. The reconstruction rule is further defined
in Subpart A.
Rather than modifying or reconstructing old units, electric utilities
generally prefer to transfer these units from base load to standby status.
Newer and more efficient units then assume base load responsibility.
Consequently, it is probable that few existing utility steam generating
units will be modified or reconstructed in the future.
9.8 SELECTION OF MONITORING REQUIREMENTS
The proposed regulations for NO require that an initial performance
X
test be performed just after startup of a new electric utility unit. Once
the performance test has been successfully completed, continuous compliance
with the proposed emission limits would be required during the life of the
unit.
9-10
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The initial performance test, as prescribed in section 60.8 of 40 CFR
Part 60, Subpart A, would be conducted within 60 days after achieving the
full load at which a new unit would be operated, but not later than 180
days after initial startup of the unit. Compliance would be determined
by averaging emissions over a 24-hour daily period, from midnight to midnight.
The 24-hour daily period would be assumed to constitute three 8-hour runs,
thereby satisfying the requirement under §60.8 that a performance test consist
of the average of 3 separate runs.
Following the initial performance test, continuous compliance with
the proposed emission limits would be required during the life of the unit.
Compliance would be determined by averaging all emission data recorded
for each 24-hour period. Each 24-hour period would constitute a separate
performance test, and the owner or operator of a unit would be required
to report emissions in excess of the proposed limits. The continuous
compliance requirement would not apply during startup and shutdown of a
unit.
The decision to select an averaging period of 24 hours for continuous
compliance with the proposed emission limits is supported with continuous
monitoring emission data from a modern unit in the Western U. S, which burns
subbituminous coal. These data indicate that NO emissions can.-be successfully
A
monitored on a continuous basis, and that emissions averaged over a 24-
hour period would not exceed the proposed emission limits.
Compliance with the proposed emission limitations would automatically
assure compliance with the required percent reduction in uncontrolled
emission levels. Thus, the percent reduction would not require performance
testing.
9-11
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EPA believes that continuous compliance with the proposed emission
limits is important to assure continuous operation of a boiler at low NO
X
levels. All testing would be performed according to procedures described in
Subpart Da and Reference Method 19.
9.9 SELECTION OF PERFORMANCE TEST METHODS
A continuous monitoring system which meets Performance Specification
12 for oxides of nitrogen and Performance Specification #3 for oxygen or
carbon dioxide, as described in 40 CFR Part 60 Appendix B, would be
required for performance testing. In addition, the zero and calibration
span drift of the monitors must be checked and monitoring data reported
according to procedures described in Appendix D (D.3) of this document
and in Reference Method 19.
Although departures were made from the performance specification
procedures during EPA testing, sufficient care was taken to assure that
the departures did not adversely affect the test results.
9-12
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REFERENCES FOR CHAPTER 9
1. Standards Support and Environmental Impact Statement, Volume 1:
Proposed Standards of Performance for Lignite-Fired Steam
Generators. Emission Standards and Engineering Division, Office
of Air Quality Planning and Standards, U. S. Environmental
Protection Agency. Research Triangle Park, North Carolina.
Report Number EPA-450/2-76-030a. December, 1976. 190 p.
2. U. S. Environmental Protection Agency. Proposed amendments to
Standards of Performance for New Stationary Sources (Lignite-
Fired Steam Generators). 40 CFR part 60, Subpart D. Washington,
D. C. Federal Register (41 FR 55792). December 22, 1976. 3 p.
3. Standards Support and Environmental Impact Statement, Volume 2:
Promulgated Standards of Performance for Lignite-Fired Steam
Generators. Emission Standards and Engineering Division, Office
of Air Quality Planning and Standards, U. S. Environmental
Protection Agency. Research Triangle Park, North Carolina.
Report Number EPA-450/2-76-030b. November, 1977. 30 p.
4. U. S. Environmental Protection Agency. Promulgated amendments to
Standards of Performance for New Stationary Sources (Lignite-Fired
Steam Generators). 40 CFR Part 60, Subpart D. Washington, D. C.
Federal Register (43 FR 9276). March 7, 1978. 3 p.
5. U. S. Environmental Protection Agency. Promulgated amendments to
Standards of Performance for New Stationary Sources (Coal Refuse).
40 CFR Part 60, Subpart D. Washington, D. C. Federal Register
(40 FR 2803). January 169 1975. 1 p.
9-13
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6. Test Report on Nitrogen Oxide Emission from Unit No. 1 at Southern
Illinois Power Cooperative, Marion, Illinois (Corrected). Burns
and McDonnell. Kansas City. Missouri. Project Number 73-108-1-000.
Test Dates: July 30 - August 2, 1974. 25 p.
7. Review of Burns and McDonnell Report on GOB Pile Burner NO Emissions,
A
Internal EPA Memorandum, Tom Logan to Don R. Goodwin. September 20,
1974.
8. Background Information for Proposed New Source Performance
Standards: Steam Generators, Incinerators, Portland Cement Plants,
Nitric Acid Plants, and Sulfuric Acid Plants. Office of Air
Programs, U.S. Environmental Protection Agency. Research Triangle
Park, North Carolina. Report Number APTD-0711. August, 1971. 54 p.
9. U. S. Environmental Protection Agency. Proposed Standards of
Performance for New Stationary Sources. 40 CFR Part 60, Subpart
D. Washington, D. C. Federal Register (36 FR 15704). August 17,
1971. 19 p.
10. U. S. Environmental Protection Agency. Promulgated Standards of
Performance for New Stationary Sources. 40 CFR Part 60, Subpart
D. Washington, D. C. Federal Register (36 FR 24876). December 23,
1971. 20 p.
11. Fuel Gas Environmental Impact: Phase Report. Industrial Environ-
mental Research Laboratory, Office of Research and Development,
U. S. Environmental Protection Agency. Research Triangle Park,
North Carolina. Report Number EPA-600/2-75-078. November, 1975.
314 p.
9-14
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12. Burner Design Criteria for NOX Control from Low-Btu Gas Combustion,
Volume 1: Ambient Fuel Temperature. Industrial Environmental
Research Laboratory, Office of Research and Development, U.S.
Environmental Protection Agency. Research Triangle Park, North
Carolina. Report Number EPA-600/7-77-094a. August, 1977. 119 p.
13. Burner Design Criteria for NOV Control from Low-Btu Gas Combustion,
/\
Volume II: Elevated Fuel Temperature. Industrial Environmental
Research Laboratory, Office of Research and Development, U. S.
Environmental Protection Agency. Research Triangle Park, North
Carolina. Report Number EPA-600/7-77-094b. December, 1977. 84 p.
14. Preliminary Environmental Assessment of Combustion Modification
Techniques, Volume II: Technical Results. Industrial Environmental
Research Laboratory, Office of Research and Development, U. S.
Environmental Protection Laboratory. Research Triangle Park, North
Carolina. Report Number EPA-600/7-77-119b. October, 1977. 578 p.
15. Characteristics of Solvent Refined Coal: Dual Register Burner Tests,
Electric Power Research Institute. Palo Alto, California. Report
Number EPRI FP-628. January, 1978. 109 p.
16. Electric Utility Steam Generating Units: Background Information for
Proposed Sulfur Dioxide Emission Standards. Emission Standards and
Engineering Division, Office of Air Quality Planning and Standards,
U. S. Environmental Protection Agency, Research Triangle Park,
North Carolina. Report Number EPA 450/2-78-007a. July, 1978.
9-15
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17. Electric Utility Steam Generating Units: Background Information for
Proposed Participate Matter Emission Standards. Emission Standards and
Engineering Division, Office of Air Quality Planning and Standards,
U. S. Environmental Protection Agency, Research Triangle Park,
North Carolina. Report Number EPA-450/2-78-006a. July, 1978.
18. Compilation of Air Pollutant Emission Factors (Second Edition).
Monitoring and Data Analysis Division, Office of Air Quality
Planning and Standards, U. S. Environmental Protection Agency,
Research Triangle Park, North Carolina. Report Number AP-42.
February, 1976. Two Parts, 462 p.
9-16
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APPENDIX A
EVOLUTION OF PROPOSED STANDARDS
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A.I GENERAL
New source performance standards for NOV emissions from steam
X
generators of more than 73 megawatts (250 x TO6 Btu/hr) heat input were
proposed on August 17, 1971, and were promulgated December 23, 1971,
under authority of the Clean Air Act of 1970. The foregoing Act pro-
vided that the Administrator should, from time to time, revise these
standards. During 1975 it was decided that there were enough new
developments in control of N0x emissions from large steam generators to
warrant considering revising these standards. The new developments
were, that although no new techniques had been developed sufficiently
since 1971 to warrant consideration for new source performance standards,
it appeared that the N0x control techniques recommended for achievement
of the 1971 standards were more effective than originally projected.
Consequently, the investigation was purposely directed toward deter-
mining if N0x emission limits lower than the 1971 limits should be
recommended.
At the onset, consideration of standards for lignite-fired steam
generators was eliminated because standards development for this
category of sources was nearly complete.
The study was initiated in late 1975 by making a thorough literature
search of the thousands of references of the Air Pollution Technical
Information Center of the U. S, Environmental Protection Agency (EPA),
In January, 1976, the engineering staff of the EPA activity responsible
for recommending new limits (Office of Air Quality Planning and Standards!
met with the engineering staff of the EPA activity responsible for
research and development (Control Systems Laboratory, now called the
A-l
-------
Industrial Environmental Research Laboratory). Important parts of the
data base used to recommend revised NO control limits were obtained
J\
from the Industrial Environmental Research Laboratory (IERL).
The data provided by IERL were sufficient to warrant further work
on standards revision. The foregoing preliminary study showed that at
the end of 1975 there were no sources on line which were subject to the
standards which became effective in 1971. This was because of the
five-year lead time between commencement of construction of a large
steam generator and activation of the unit. IERL advised, however,
that there were several Combustion Engineering units and that there was
one Babcock and Wilcox unit on line which, although not subject to the
1971 standard, were designed similar to the coal-fired steam generator
designs which were being furnished to achieve the 1971 standard. IERL
had data which showed these units were capable of controlling NO
X
emissions to levels substantially below the limit of 300 nanograms per
joule (0.07 lb/106 Btu) of the 1971 standard. There were no similar
data for large oil or gas-fired steam generators.
Separate meetings were arranged with Babcock and Wilcox, Com-
bustion Engineering, Inc., Foster Wheeler Energy Corporation, and Riley
Stoker Corporation which, in total, furnish nearly all of the large
steam generators installed in the United States. These meetings
occurred in February, 1976, and indicated to EPA that all of the four
manufacturers were capable of furnishing coal-fired steam generators
which limit NO emissions to levels substantially less than the 3QQ
/\
nanogram per joule ("0.07 lb/10 Btu]. limit promulgated in 1971.
A-2
-------
In February, 1976, the tangential designs of Combustion Engi-
neering, Incorporated, were the best established because several
Combustion Engineering units were on line which had been tested at low
N0x levels. There was one Babock and Wilcox unit on line which was an
old style unit equipped with new specially designed burners and which
was equally effective in limiting NO emissions. Neither Foster Wheeler
X
or Riley Stoker had any of their newest designs on line. All four
manufacturers said more new design coal-fired steam generators would be
coming on line during 1976 and subsequent years.
All of the four manufacturers indicated concern about potential
adverse side effects of NO control, such as corrosion, loss of boiler
A
efficiency, high CO, etc. (See Chapter 4 and 6.) Only Combustion
Engineering said they were confident their designs could achieve low
N0x emission levels without adverse side effects. The other three
boiler manufacturers were uncertain and said they needed more experience.
Subsequent to the February, 1976, meeting with the four boiler
manufacturers, a comprehensive data base was gathered based on the work
of IERL prior to February, 1976. This data base was supplemented by
IERL data and by Combustion Engineering data furnished later in 1976.
In November, 1976, EPA met with the National Air Pollution Control
Techniques Advisory Committee in San Francisco. At this meeting EPA
advised the Committee of plans to revise the NO standard for large
X
coal-fired steam generators from the 1971 limit of 300 nanograms per
joule (0.7 lb/10 Btu) to a new limit of 260 nanogramss per joule (0.6
lb/10 Btu) for all large solid fuel-fired sources except lignite-fired
sources. The concensus of the Committee was that the lower limit was
A-3
-------
feasible. The four boiler manufacturers expressed positions similar to
the positions already discussed in conjunction with the February, 1976,
meetings. In summary, Combustion Engineering said they were ready to
achieve the lower limit. The other three manufacturers said they would
like more time.
EPA work on NO standards revision was limited during the period
}\
between the November, 1976, National Air Pollution Control Techniques
Advisory Committee Meeting, and August, 1977. This was because it was
decided that it would be more efficient to propose changes in the NO
A
standard at the- same time as proposing revisions to the particulate and
S02 standards. Work on revising the particulate and S02 standards was
not as far advanced as the NOV standards revision project.
X
Another major change occurred in August, 1977, when the Clean Air
Amendments of 1977 were enacted. The Clean Air Act of 1970 provided for
NOX standards revision based on EPA judgment. The 1977 amendments
mandated that the standards be revised.
Further results of IERL emission and corrosion testing of tangentially-
f.ired units and test results of Babcock and Wilcox units equipped with
specially designed burning were added to the data base during 1977. It
was also learned that Babcock and Wilcox and Foster Wheeler had con-
tracted to each furnish a large coal-fired steam generator for the San
Juan Station of Public Service Company of New Mexico. These units were
to be subject to the New Mexico NO regulation of 190 nanograms oer
y\ '
joule (0.45 lfa/106 Btu).
Based on this additional data, EPA decided to revise the original
recommendation for solid fuel, other than lignite-fired sources, of 260
A-4
-------
nanograms per joule (0.6 lb/106 Btu) to one of 210 nanograms per joule
(0.5 lb/10 Btu) for large subbituminous coal-fired units and 260
nanograms per joule (0.6 lb/106 Btu) for all other large solid fuel (except
lignite) fired sources. In addition, the recommendations were revised
to require a percent emission reduction as stipulated by the Clean Air
Amendments of 1977.
During December, 1977, the revised recommendations were reviewed
before a Working Group composed of all interested EPA activities and at
a separate meeting of the National Air Pollution Control Techniques
Advisory Committee. The consensus of the participants of both meetings
was that recommendations for proposed N0y standards were feasible.
A
During the period between December 1977 and August 1978 further data
on control of NOX emissions from Babcock and Wilcox, Foster Wheeler, and
Riley Stoker boilers were incorporated in the document. Limited data was
also added on the effect of NOX control on polycyclic organic matter
emissions. Data on continuous monitoring of NO emissions was added in
/\
February, 1978. Further testing was conducted in April and again in June,
1978 to evaluate the integrity of the NOX continuous emission monitoring
data. Although the final results of the April and June testing are not
yet available, preliminary results indicate the data is probably valid.
A-5
-------
-------
APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
This appendix consists of a reference system Which is cross-indexed
with the October 21, 1974, Federal Register (39 FR 37419) containing EPA
guidelines for the preparation of Environmental Impact Statements. This
index can be used to identify sections of the document which contain data
and information germane to any portion of the Federal Register guidelines.
B-l
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-------
-------
APPENDIX C
SOURCE TEST DATA
-------
-------
EXHIBIT I
Basic Source Test Data References
1. Crawford, A. R., E. H. Manny, and W. Bartok, The Effect of
Combustion Modification on Pollutants and Equipment Performance
of Power Generation Equipment, Exxon Research and Engineering
Company, Linden, New Jersey, September 1975.
2. Program for Reduction of N0v from Tangential Coal-Fired
X
Boilers, Phase II, EPA-650/2-73-005-a, Office of Research and
Development, U. S. Environmental Protection Agency, Research
Triangle Park, North Carolina, June 1975.
3. Selker, A. P., Overfire Air as a NOV Control Technique for
A
Tangential Coal-Fired Boilers, Combustion Engineering, Incorporated,
Windsor, Connecticut, September 1975.
4. Campobenedetto, E. J., The Dual Register Pulverized Coal Burner--
Field Test Results, Presented at the Engineering Foundation
Conference on Clean Combustion of Coal, Franklin Pierce College,
Rindge, New Hampshire, July 31 to August 5, 1977.
5. Overfire Air Technology for Tangentially Fired Utility Boilers
Firing Western U. S. Coal, EPA 600/7-77-117, U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina,
October 1977.
Vatsky, J., Attaining Low NO Emissions by Combining Low Emission
X
Burners and Off-Stoichiometric Fining, Foster Wheeler Energy
Corporation, Livingston, New Jersey, November 1977.
6.
-------
-------
C-E Power Systems
Combustion Engineering. Inc.
1000 Prospect Hill Road
Windsor. Connocticut 06095
EXHIBIT II
Tel. 203/688-1911
Telex: 9-9297
POWER
SYSTEMS
FOR: John Cope!and, Room 754 RUSH
Telecopied October 8, 197F
October 8, 1976
Mr. John Copeland
United States Environmental Protection Agency
Office of Afr Quality Planning and Standards
Research Triangle Park
North Carolina 27711
Dear Mr. Copeland:
Would you please include the following disclaimer notice with
the data that we sent to you on April 6, 1976, since you are
publishing this data verbatim:
LEGAL NOTICE
"This data was prepared By Combustion Engineering, Inc.
for the United States Environmental Protection Agency.
Combustion Engineering, Inc. nor any person acting on
its behalf; (a) mattes any warranty or representation,
express or implied including the warranties of fitness
for a particular purpose or merchantability, with respect
to the accuracy, completeness, or usefulness of the
information contained in this report, or that the use
of any information, apparatus, method, or process dis-
closed in this report may not infringe privately owned
rights; or (b) assumes any liabilities with respect to
the use, of, or for damages resulting from the use of,
any information, apparatus, method or process disclosed
in this report."
Sincerely yours,
COMBUSTION ENGINEERING, INC,
Henry E/ Burbach
Director, Proposition Engineering
HEB:mm
C-II-1
-------
C-E Power Systems
Combustion Engineering. Inc.
1000 Prospect Hill Road
Windsor. Connecticut 06095
Tel. 203/688-1911
Telex: 9-9297
POWER
SYSTEMS
November 11, 1977
Mr. George B. Crane, P.E.
Industrial Studies Branch
Emission Standards & Engineering Division ,
United States Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Dear Mr. Crane:
The following are our answers to your questions posed in your October 21, 1977
letter:
Question 1: Does C-E maintain their statement made on our visit of February 19,
1977, to guarantee their new boilers to meet a 0.6 lb/10° Btu NOx
limit with Eastern coals and 0.5 Ib limit for other coals?
Answer: Yes, C-E still will maintain this position.
Question 2: Can new C-E boilers meet a 0.5 limit across the board? If so, could
C-E so guarantee?
Answer: No, C-E does not feel that 0.5 NOx limit can be met across the board
v/ith all fuels.
Question 3: Does C-E know of any feasible way to characterize or describe a
"Western" or an "Eastern" coal for purposes of standards setting?
Answer: Characterization of Eastern vs. Western coal can be accomplished by
evaluating the coal in the ASTM ranking scale. Those coals which
rank higher in heating value than 11,000 Btu/lb on a moist, mineral
matter free basis which classify as hi-volatile "C" or sub-bituminous
"A" (and above), we would characterize as Eastern coal. Those below
11,000 Btu/lb which are sub-bituminous "B", "C" and lignite would
classify as Western coal for this purpose. There are coals found
in the Rocky Mountain area which classify as hi-volatile "C", sub-
bituminous "A" and above.
Attached is a copy of a C-E standard sheet #61-038 which graphically
displays the ASTM ranking.
Question 4: Our trip report (item no. 1) states that C-E "does not recommend
tying the limits of a NOx standard tc coal analysis". Does C-E
maintain this opinion?
C-II-2
-------
Mr. Georcje B. Crane, P.E.
-2-
November 11, 1977
Question 4: cont'd
Answer:
HEB:mm
attach.
Yes, we still believe that we can not identify constituents in the
' Suffic1entl* wel1 to <"«*«* relate to a
Question 5:
Answer:
This would be beyond the classification outlined above for item no 3
where we make a gross differentiation of fuel type by analysis.
Do you have NOx source test data and boiler operation, maintenance
and performance reports for new boilers on line since spring«of
1976? is there any indication of tribe corrosion and wastage-however
small -for how NOx operation mode? "imever
The only recent tests for tube corrosion were at Utah Power & Liqht
Huntington Canyon Station and Wisconsin Power & Light, Columbia
Wh1ch indicated no evidence of
On other C-E units with OFA in operation, we have had no reports
of operational difficulties or corrosion on wastage problems
These units have not been specifically surveyed for problems.
Sincerely yours,
COMBUSTION ENGINEERING, INC.
-»-*"C-& &
Burba'ch
Proposal Engineering
C-II-3
-------
PULVERIZERS
COAL CLASSIFICATION
EHOIHEERIHG OEPT. STANDARDS SHEET HO. 61-038
o
h
78
1C.OCO
DEFINITIONS
ORy. H-H-FREE ra. PERCENT =
HOIST. M-M-FREE 8TU, PER POUS.O =
100 -
M-H - MINERAL HATTER
BTU - HEATIHG VALUE
FC - FIXED CARBON, %
VH - VOLATILE HATTER, 1
H .--BED MOISTURE, S
A - ASH, t
S '- SULPHUR, %
14.000
, A bit-
HI.-VO!
13.000 11.000 9.500
I MOIST. MINERAL-MATTES-FREE B.T.U.
Hi.-vol. C bit.
B bit ' or subbit A ' B
C-II-4
8,300
Subbit
-Lignite
X »0
r,w py r. I «F Ft? I wr. \uc
-------
C-E Power Systems
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
Tel. 203/688-1911
Telex: 9-9297
POWER
SYSTEMS
July 30, 1976
Mr. John 0. Copeland
Industrial Studies Branch
Emission Standards & Engineering Division
United States Environmental Protection Agency
Research Triangle Park
North Carolina 27711
Dear Mr. Copeland:
The attached information has been prepared in response to your letter of
June 2, 1976, for NOx emission data on C-E pulverized coal-fired steam gener-
ators. Specifically, you requested the following in addition to NOx emission
levels:
a. Ultimate analysis, ash analysis, and heating value of the coal fed to
the pulverizers during testing.
b. Description of combustion air adjustments during testing.
c. Boiler load during testing.
d. Concurrent data on CO, Q2> CQ2> ash combustible content, hydrocarbons,
and polynuclear organic matter emissions.
e. Corrosion test results.
f. Corrollary data on test methods.
The attached Summary of Field Test Data covers items "a" thru "e" of your request.
C-E field test data from 14 units, ranging in plan area from 408 sq. ft. to
2760 sq. ft. and in rating from 50 Mw to 600 Mw, is presented. The coals fired
in these units are as follows:
High Sodium Lignite
Texas Lignite
Western Sub "C"
Western Sub "B"
Western Bituminous
Mid-Western Bituminous
Eastern Bituminous
Units A,B
Unit C
Units D,E
Units F,6
Units H,I,J
Unit K
Units L.M.N
C-II-5
-------
Mr. John Cope!and
-2-
July 30, 1976
An analysis by you of the data presented should lead to the following conclusions:
a. That C-E tangenti ally-fired boilers are capable of meeting the present
EPA limit for all coal types at normal excess air levels (20-25% excess
air),
b. that excess air has a predominating effect on NOx emission levels for
all coal types,
c. that overfireair is extremely effective in reducing NOx emissions from
tangenti ally-fired boilers for all coal types,
d. that for Eastern Bituminous coals, tangenti ally-fired boilers would be
capable of meeting an 0.6 Ibs. N02/MMBTU emission limit when equipped
with overfire air,
e. that for the lower rank Western coals and lignite, tangenti ally-fired
boilers would be capable of meeting an 0.5 Ibs. N02/MMBTU emission
limit when equipped with overfire air, and
f. that increased waterwall corrosion rates, increased CO emissions, and
increased ash combustible content when operating with overfire air
for NOx control is not a problem on tangenti ally- fired boilers.
No data is given for unburned hydrocarbon or polynuclear organic matter emissions,
When measured, unburned hydrocarbons have always been less than 2 PPM on C-E
coal-fired boilers. C-E has never attempted to measure emission of polynuclear
organic matter.
The second attachment discusses the three NOx measurement methods employed by
C-E in our field test program. A brief discussion of the various methods,
including the advantages and disadvantages, as well as a comparison of actual
NOx field test data obtained by the three methods, is presented.
Should you require any additional information, please feel free to contact
me.
Very truly yours,
COMBUSJIQN NGINEERING, INC.
E. Burbach
Director, Proposition Engineering
:mm
attach.
C-U-6
-------
Summary of Field Test Data
Unit Identification
Unit Utility
A Ottertail Power
B Saskatchewan Power Corp.
C Industrial Generating Co.
D Public Service Co. of Colorado
E Minnesota Power & Light Co.
F Utah Power & Light Co.
G Utah Power & Light Co.
H Utah Power & Light Co.
I Public Service Co. of Colorado
J Utah Power & Light Co.
K Union Electric Co.
L Alabama Power
M Cincinnati Gas & Electric
N Tennessee Valley Authority
Station Tested
Hoot Lake #2 11/70
Boundary Dam #4 3/73
Big Brown #1 5/72-8/72
Comanche #1 2/74
Clay Boswell #3 4/74
Naughton #2 7/70-8/70
Naughton #3 9/72
Gadsby #3 5/71
Cherokee #4 1/72
Huntington Canyon #2 5/75-9/75
Labadie #1 6/71
Barry #4 1/73
Beckjord #6 10/69
Widows Creek #7B 4/71
Note:
1. 'NA' in the column labled OFA Damper Setting means the unit was not
equipped with overfire air.
2. * in the column labled OFA Damper Setting indicates that overfire air
was simulated by operating the top elevation of nozzles on air only.
3. All damper settings are given as percent open, 0 meaning fully closed,
100 meaning fully open.
4. 'NR1 means NOT RECORDED.
5. Higher heating value is given in BTU/LB, as received basis.
C-II-7
-------
1
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-------
NOx Measurement Techniques
Combustion Engineering's Field Testing Department currently employs
three methods for determining NOx emission levels- from coalfired steam
generators. These are the Phenol-Disulfonic Acid Method (ASTM 1608-60),
the Whittaker Dynascience Electrochemical NOx Analyzer, and the Scott
Chemiluminescence NOx Analyzer. The advantages and disadvantages of each
method are noted in Table 1. These methods compare favorably with each
from a standpoint of accuracy as shown in Figure 1 which is based on actual
test data obtained on a coalfired steam generator.
The Phenol-Disulfonic method was adopted in 1969 when C-E's NOx field
test program was initiated. In this method, a gas sample is admitted to
an evacuated flask containing an oxidizing absorbent consisting of hydro-
gen peroxide in dilute sulfuric acid. The nitrogen oxides in the gas
(both NO and N0?) are converted to nitric acid by the absorbing solution
and the resulting nitrate ion reacted with phenol-disulphonic acid to pro-
duce a yellow solution which is measured calorimetrically against calibra-
tion curves prepared from samples of known nitrate content. This method is
known to be accurate to 5 percent and is repeatable. A major disadvantage
is that this method is time consuming and not suitable for optimization
tests where immediate results and continuous monitoring are desirable.
The Phenol-Disulfonic Acid Method is employed by C-E whenever EPA NOx com-
pliance testing is being performed and also to verify the NOx content of
bottled gases used to calibrate the Whittaker and Scott instruments.. The
method is not used extensively in C-E's on-going field test program bacause
of the lengthy analysis period required.
C-II-22
-------
Waterwall Corrosion Testing
The effect of biased firing and overfire air operation on waterwall '
corrosion potential was evaluated during three thirty (30) day baseline,
biased firing and overfire air corrosion coupon tests conducted at the
Alabama Power Co., Barry Station #2 generator under EPA contract #68-02-
1367. The results of said testing are reported in detail in EPA-650/2-
73-005, entitled "Program for Reduction of NOx from Tangential Coal-Fired
BoilersPhase II", dated June 1975. Briefly, the results of these
corrosion tests indicated that the weight loss experienced by the test
coupons during the thirty day test periods were within the range to be
expected from the normal oxidation of carbon steel. That is, the results
did not show any significant increase in waterwall corrosion during biased
firing or overfire air operation for NOx control.
Additional waterwall corrosion testing, performed by C-E under EPA
contract, has recently been completed at Utah Power and Light, Huntington
Canyon #2. The .preliminary results again indicated no significant change
in waterwall corrosion when operating in the low NOx modes. Further infor-
mation should be available from the EPA Project Officer, Mr. David G.
Lachapelle.
Waterwall corrosion testing is to be carried on at Wisconsin Power and
Light, Columbia #2, under EPA contract later this year. No other waterwall
corrosion testing has been performed by C-E.
C-II-23
-------
-2-
In late 1969, C-E began using the continuous recording Whittaker
Dynascience Electrochemical NOx Analyzer when taking NOx measurements in
the field. This instrument is an electrochemical transducer in which the,
gas sample passes through a membrane, dissolves in a thin layer of electro-
lyte, diffuses to a sensing electrode where electrons are released with the
current flow being proportional to the NO partial pressure. The instrument
has been found satisfactory in accuracy and response when proper precautions
are taken to ensure that S0_ and So., are scrubbed out of the gas sample and
that the sensing cell is maintained at constant temperature. The instrument
requires calibration with a gas mixture of known NO content. The Whittaker
Dynascience Electrochemical NOx Analyzer is currently employed by C-E in
short duration field test programs.
In 1973, C-E received delivery of a Gaseous Emission Test System
developed by C-E's Field Test Department, in conjunction with Scott Labora-
tories, for performing environmental testing in the field. The system will
continuously monitor and record NOx, 0», CO and hydrocarbons present in the
flue gas. The system is contained in an air conditioned, self-propelled,
mobile emission van. The system is equipped with a Scott Chemiluminescence
NOx analyzer. This instrument monitors.the infra-red radiation which is
emitted when the gas stream containing NO is mixed with ozone in a reaction
chamber. An N0_ to NO converter is incorporated in the Chemiluminescence
analyzer so that the small amount of N0_ present in the flue gas will also
be measured. The Chemiluminescence analyzer can provide an extremely
stable, accurate, and fast response method of measuring NOx in combustion
gases if the gas sample is dried prior to measurement and a constant cell
temperature is maintained. The instrument requires calibration with a gas
mixture of knoxm NO content. C-E employs the Scott Chemiluminescence NOx
Analyzer in all longer duration field test programs.
C-II-24
-------
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Comparison of NOx Measurement Techniques
ASTM Method Vs. Whittaker & Scott Analyzers
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ASTM Phenoldisulfonic Method
PPM - Adj. to 3% 02, Dry Basis
C-II-26
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APPENDIX D
EMISSION MEASUREMENT AND CONTINUOUS MONITORING
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APPENDIX D. EMISSION
AND CONTINUOUS MONITORING
D.I EMISSION MEASUREMENT METHODS
The data gathered to support the oxides of nitrogen standard for'fossil
fuel-fired steam generators were taken from research and development studies
conducted by Exxon Research for EPA under contract £EPA Contract 68-02-1415
and EPA Report 650/2-73-005a). As described in these reports, a chemi-
luminescent instrument with a thermal reactor to measure both nitric oxide
and nitrogen dioxide and a nondispersive infrared (NDIR) analyzer for nitric
oxide and nondispersive ultraviolet (NDUV) for nitrogen dioxide were used.
Oxygen was also measured so that the oxides of nitorgen emissions could be
corrected to 3 percent oxygen.
The contractor reports included insufficient details on the test data
and sampling techniques (instrument zero and calibration responses and
sampling probe locations) to enable an evaluation of the quantitative accu-
racy of the measurements. However, from statements written in the reports,
it was concluded that the contractor followed all the necessary procedures
to ensure valid measurements, i.e., daily calibration, recalibration when
zero drift was appreciable, well maintained instruments, certified calibration
i
gases, and a multipoint sample system to remove any gas concentration
stratification.
D.2 CONTINUOUS MONITORING
EPA has established monitoring performance specifications in Appendix B
of 40 CER Fart 60. The specifications were developed for large industrial
-------
g sources, including power plants. Continuous monitoring data are available
to demonstrate the applicability of monitors to measure and record oxides
of nitrogen and oxygen or carbon dioxide.
The decrease in the level of the oxides of nitrogen standard will not
affect the feasibility of continuous monitoring at power plants. Oxygen or
carbon dioxide can also be measured to convert the concentration data into
units of the standard (nanograms per Joule).
The costs of gaseous pollutant monitors for oxides of nitrogen and
oxygen or carbon dioxide have been estimated in the range of $30,000 capital,
$5,000 installation, $3,000 to $7,000 performance tests, and $16,000 annual
operating. Facilities which have need for more than one monitor could
reduce their total cost by selecting an extractive, type system and by time
sharing the system between several locations.
D.3 PERFORMANCE TEST METHODS
1 A continuous monitoring system that meets Performance Specification #2
for oxides of nitrogen and Performance Specification #3 for oxygen or carbon
dioxide which are set forth in 40 CFR 60 Appendix B, is recommended as the
performance test method. In addition to the performance specifications, the
zero and calibration span drift of the monitors is recommended to be checked
at least once per 24-hour period of performance averaging time. These checks
should be made in accordance with 40 CFR 60.13 (Subpart A - General Provisions,
Monitoring Requirements). The monitoring data are recommended to be expressed
in terms of the proposed standard (nanograms/Joule heat input) by using
the calculation procedures specified in proposed EPA Method 19, "Determination
of Sulfur Removal Efficiency of Fuel Pretreatment and Sulfur Dioxide Control
Systems and Determination of Particulate, Sulfur Dioxide, and Nitrogen Oxides
Emission Rates from Fossil Fuel-Fired Steam Generators."
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APPENDIX E
ENFORCEMENT ASPECTS
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E.I GENERAL
The candidate affected facilities discussed in this document are
limited to electric utility (other than lignite) fired steam generators
of more than 73 megawatts (250 x 10 Btu) gross heat input.
As discussed in Chapter 5, some changes in steam generators can
cause existing sources to become subject to new source performance
standards for modified or reconstructed sources.
The rules and regulations for determining if a source will be
subject to new source performance standards by reason that the source
is new, modified, or reconstructed, are given in Subpart A, Part 60,
Subchapter C, Chapter 1, Title 40, Code of Federal Regulations. In
view of the multi-million dollar capital costs of Targe steajn generators,
it is suggested that interpretation of the foregoing rules and regu-
lations be reviewed through the U. S. Environmental Protection Agency
Regional Office Enforcement Division for the region where a source will
be located.
The locations and addresses of these regional offices are as
follows:
Region I - Connecticut, Maine, Massachusetts, New Hampshire
Rhode Island, Vermont
John F. Kennedy Federal Building
Boston, MA 02203
Telephone: 617-223-7210
Region II - New Jersey, New York, Puerto Rico, Virgin Islands
26 Federal Plaza
New York, NY 10007
Telephone: 212-264-2525
E-l
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I
Region III - Delaware, District of Columbia, Maryland,
Pennsylvania, Virginia, West Virginia
Curtis Building
6th and Walnut Streets
Philadelphia, PA 19106
Telephone: 215-597-9814
Region IV - Alabama, Florida, Georgia, Mississippi,
Kentucky, North Carolina, South Carolina,
West Virginia
345 Court!and, N.E.
Atlanta, GA 30308
Telephone: 404-881-4727
Region V - Illinois, Indiana, Michigan, Minnesota,
Ohio, Wisconsin
230 South Dearborn
Chicago, IL 60604
Telephone: 312-353-2000
Region VI - Arkansas, Louisiana, New Mexico, Oklahoma, Texas
First International Building
1201 Elm Street
Dallas, Texas 75270
Telephone: 214-767-2600
Region VII - Iowa, Kansas, Missouri, Nebraska
1735 Baltimore Street
Kansas City, MO 64108
Telephone: 816-374-5493
Region VIII - Colorado, Montana, North Dakota,
South Dakota, Utah, Wyoming
1860 Lincoln Street
Denver, CO 80295
Telephone: 303-837-3895
Region IX - Arizona, California, Hawaii, Nevada, Guam,
American Samoa
215 Fremont Street
San Francisco, CA 94051
Telephone: 415-556-2320
E-2
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Region X - Washington, Oregon, Idaho,, Alaska
1200 Sixth Avenue
Seattle, WA 98101
Telephone: 206-442-1220
E.3 COMPLIANCE
General procedures for compliance testing and emission monitoring
are specified in Subpart A, Part 60, Subchapter C, Chapter 1, Title 40,
Code of Federal Regulations. Special regulations for compliance testing
and emisssion monitoring for N0x emissions from electric utility steam
generators will be specified in Subpart D(a), Part 60, Title 40, Code of
Federal Regulations. In summary, these regulations would require that
new sources be tested for compliance after shakedown and that sources
be equipped for N0x continuous compliance monitoring. These emission
monitoring systems must be field tested for accuracy.
Continuous emission monitoring is the most important method for
determining if a source is in compliance with NO new source performance
/\
standards for pulverized coal-fired steam generators. As discussed in
Chapter 6, N0x emissions from modern low NOX emission design steam
generators can vary widely depending on the way the unit is operated.
Consequently, unless N0x emissions are monitored at all times, a source
tested for compliance after shakedown might be subsequently operated
with N0x emission levels substantially exceeding the regulatory limit,
thereby circumventing the purpose of the emission limitation.
E-3
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APPENDIX F
BASIS FOR DISPERSION ESTIMATES
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F.I GENERAL
An analysis war, made to assess the ambient concentrations of pollutants
which would result from HOX emissions from pulverized coal combustion/ For
the purpose of.the study, it was assumed NOX pollutants behave as non-reactive
gases.
F.2 PLANT CHARACTERISTICS
Table F-l gives information on the plants studied.1 All plants were
pulverized coal-fired steam generators controlled to meet an NOX limit of 300
nanograms per joule (0.7 lb/106 Btu).
Heat rate was assumed to be 10.56 megajoules (10,000 Btu) per kilowatt
hour generated from combustion. Plants equipped with 75, 175, 275 metre
(246, 574, and 902 ft) stacks were studied. Estimated heights of tall
structures near the stacks are'given in Table F.I.
It was assumed that plants would operate at all times during a year at
full load capacity.
F.3 MODEL TECHNIQUES
A suirmary description of the models is given in Sections F.5 and F.6.
. The model was programmed to derive a set of dispersion conditions for the
basic meteorological data for each hour of the given year. The calculations
simulated the interaction between the plant characteristics and these dispersion
conditions to produce a dispersion pattern for each hour. These computations
were performed for each point in an array of 180 receptors encircling the plant
and extending downwind from the site. Values were calculated at each of the
receptors for each hour and were integrated and averaged to calculate a mean
annual average.
F-l
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F-2
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The aerodynamic effects of surrounding structures were analyzed
according to the procedures summarized in Section F.6.
It was assumed the plant would be located in flat or gently
rolling terrain with a meteorological regime unfavorable to the
dispersion of effluents.
Preliminary analysis indicated that for the plants a combination
of unstable atmospheric conditions and relatively low wind speeds would
produce the highest short-term concentrations. If such conditions
occurred frequently at a given location, especially if they were
combined with a high directional bias in the wind, then longer term
impacts (e.g., 24 hours and annual) would tend to be high.
For Cases 1-3, preliminary analysis showed that Burbank, Calif-
ornia, satisfied the conditions of relatively low wind speeds with
moderate persistence and unstable atmospheric conditions. Upper air
sounding data from Santa Monica, California, were combined with the
surface station data.
For Cases 4-9, the preliminary analysis suggested slightly higher
wind speeds and unstable atmospheric conditions. Oklahoma City,
Oklahoma, satisfied these conditions. Although on an annual-average
basis the wind speed at Oklahoma City is quite high, two features
tend to offset this fact: a high annual wind-direction-frequency
(22 percent from SSE) and the fact that when the wind is from this
sector, atmospheric conditions tend toward the unstable. Upper air
observations from Oklahoma City, Oklahoma were combined with the
surface data.
Related to the choice of plant location is the selection of
source-receptor distances. Preliminary analysis indicated that the
F-3
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model plants exert maximum impact relatively close-in. In light of the
preliminary analysis, distances selected are shown in Table F-2.
F.4 RESULTS AND DISCUSSION
The maximum pollutant concentrations for the specified averaging
periods for all nine cases considered are listed in Table F-3.
These concentrations have been pro-rated according to their respective
emission rates. The five receptor distances chosen are listed in Table F-2.
Retardation, although it occurs frequently during the year in all
cases, is not the controlling .factor in producing maximum concentrations.
In Case No. 7, downwash occurs most of the time and does produce
the maxima concentrations. The 3- and 24-hour maxima values are
not representative of unique meteorological situations with the
exception of Case No. 7. Numerous values in the individual maxima
ranges were noted on different days at widely separated grid points
at source-receptor distances similar to those reported for each case
in Table F-3. This is to say then, that with the exception of Case
No. 7 (downwash), concentrations similar to those shown in Table F-3
for the individual pollutants are common. It is noticeable generally
that as the stack heights increased for a given plant size, the concentration
decreased.
The annual-average concentration distributions displayed the
expected dependence upon the wind-direction frequency distributions
for each meteorological choice. Generally, concentration values
similar to those shown in Table F-3 for each of the nine cases
(for each individual pollutant) are confined to a sector approximately
9P° in width. These concentration values were found at distances
similar to those shown in Table F-3 for each individual case.
F-4
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TABLE F-21
Case
No.
1
2
3
4
5
6
7
8
9
Ring
1
0.3
0.3
0.3
1.0
1.3
2.6.
0.3
2.6
3.4
Source Receptor Distances (km.)
Ring Ring Ring
2 3 4
0.9
1.0
0.9
2.1
2.9
5.0
0.6
5.1
6.6
2.5
3.0
2.3
3.7
6.4
10.2
1.2
10.1
12.3
7.8
9.2
11.0
. 6.4
14.8
20.1
2.4.
20.5
23.3
Ring
5
23.0
38. 5
42.1
11.2
33.7
42.0
5.1
41.3
40.8
These rings may be viewed as the radii of concentric circles around
the plant. Receptors are placed along each 174.5 mi 11iradian (10°) of azimuth,
thus accounting for th_e 180-receptor gH.d referred ;to_.previously.
F-5
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TABLE F-31
MAXIMUM POLLUTANT CONCENTRATIONS3
Averaging
Period
Annual
Case
1
2
3
4
5
6
7
8
9
NO
0.7
0.2
<0.1
1.6
0.5
0.2
930
0.7
0.4
Distance
N02 (km)
<0.1 0.9
<0.1 3.0
<0.1 2.3
<0.1 . . 6.4
<0.1 14.8
<0.1 20.01
14 0.3b
<0.1 20.5
<0.1 23.3
Concentrations have been pro-rated according to specific
emission rates.
First ring, downwash.
F-6
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F. 5 DESCRIPTION OF THE DISPERSION MODEL
. \
Jhe model used to estimate ambient concentrations;^ Table F-3 for the
pulverized coal-fired plants was one developed by the Meteorology
Laboratory, U.S. Environmental Protection Agency, Research Triangle
Park, N.C. This model is designed to estimate concentrations due
to sources at a single location for averaging times from one hour to
one year.
This model is a Gaussian plume model using diffusion coefficients
2
suggested by Turner. Concentrations are calculated for each hour
of the year, from observations of wind direction in increments of
17.45 milliradians (10 degrees), wind speed, mixing height, and
atmospheric stability. The atmospheric stability is derived by the
Pasquill classification method as described by Turner. In the
application of this model, all pollutants are considered to be
non-reactive and gaseous.
Meteorological data for 1964 are used as input to the model.
The reasons for this choice are: (1) data from earlier years
did not have sufficient resolution in the wind direction; and
(2) data after 1964 are available only for every third hour, where data
for 1964 are available on an hourly basis.
Mixing height data are obtained from the twice-a-day upper air
observations made at the most representative upper air station. Hourly
mixing heights are estimated by the model using an objective interpola-
tion scheme.
F-7
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A feature of this model is the modification of plume behavior to
account for aerodynamic effects for plants in which the design is-
not optimal. Another important aspect of the model is the ability
to add concentrations from stacks located closely together. In
this feature, no consideration is given to the physical separation between
the stacks since all are assumed to be.located at the same geographical
point.
Calculations are made for 180 receptors (at 36 azimuths and five
selectable distances from the source). The model used can consider
both diurnal and seasonal variations in the source. Separate
variation factors can be applied on a monthly basis to account
for seasonal fluctuations and on an hourly basis to account for
diurnal variations/ Another "feature of "the" mocisTis' the ability
to compute frequency distributions for concentrations of any
averaging period over the course of a year. Percentages of various
ranges in pollutant concentrations are calculated. One final
feature of the single source model is a program which can add
concentrations from two plants which are not co-located but which
do interact.
F.6. AERODYNAMIC-EFFECTS MODIFICATION OF THE DISPERSION MODEL
The aerodynamic-effects modification of the dispersion model
was developed by the Source Receptor Analysis Branch, Office" of
Air Quality Planning and Standards, U.S. Environmental Protection
Agency, Research Triangle Park, N.C.
F-8
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The single source model does not address the aerodynamic com-
plications which arise when plant design is less than ideal. These
effects result from the interaction of the wind with the physical
structure of the plant. Such interaction can retard, or in the
extreme, prevent plume rise. The extreme case is commonly referred
to as "downwash". With downwash, the effluent is brought downward
into the wake of the plant, from which point it diffuses as though
emitted very close to the ground. In the retardation case, some
of the dispersive benefits of plume rise are lost; while in the
downwash case, all of the benefits of plume rise are lost, along
with most of the benefits of stack elevation. Both phenomena -
but especially downwash - can seriously increase the resulting ambient
air impact.
The aerodynamic-effects modification then, is an attempt to include
these effects in a predictive model. Basically, it enables the model
to make an hour-by-hour, stack-by-stack assessment of the extent
(:if any) pf_ aerodynamic complications. The parameters used in
making the assessment are wind speed, stack-gas exit velocity,
stack height, stack diameter, and building height. If a particular
assessment indicates no aerodynamic effect, then for that stack
(for that hour) the model behaves just as the unmodified version.
If there are aerodynamic effects, the modified version contains
equations by which the impact of these effects on ground-level
concentrations is estimated.
F-9
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F.7. REFERENCES FOR APPENDIX F.
1. Unpublished Data, Source Receptor Analysis Branch, Office of
Air Quality Planning and Standards, U.S. Environmental Pro-
tection Agency, Research Triangle Park, North Carolina, June
1975.
2. Turner, D. B., "Workbook of Atmospheric Dispersion Estimates",
U.S. Dept. of H. E. W., PHS Publication No. 999-AP-24 (Revised
1970).
F-l8
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
1. REPORT NO.
EPA-450/2-78-005a
2.
4. TITLE AND SUBTITLE
Electric Utility Steam Generating Units: B
Information for Proposed Nitrogen Oxides Em
Standards
7. AUTHOR(S)
3. RECIPIENT'S ACCESSIONING.
5. REPORT DATE
ackground July, 1978
ISSiOn 6- PERFORM1NG ORGANIZATION CODE
B. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U. S. Environmental Protection Agency
Office of Air Quality Planning and Standard
Research Triangle Park, North Carolina 277
J2. SPONSORING AGENCY NArne AND AuOReSS
DAA for Air Quality Planning, and Standards
Office of Air and Waste Management
U.S. Environmental Protection Agency
Research Triangle Park. North Carolina 277
10. PROGRAM ELEMENT NO.
S 11. CONTRACT/GRANT NO.
11 . -.- ;/"":/"." '
, 13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY COOB
n ' EPA/200/04 ..''""
15. SUPPLEMENTARY NOTSS .
Revised Standards of Performance for the control .of emissions of parti
sulfur dioxide from electric utility steam generating units are also t
These standards are supported in separate Background. Information docun
IPA-450/2-78-006a for particulates and EPA-450/2-78-007.a for sulfur. d'
culate matter and
>eing -'proposed.
nents, numbered
i oxide. .. .
16. Abstract
Revised Standards of Performance for the control of 'emissions' of nitrogen oxides
from electric utility power plants are being proposed under the authori-ty of -
section 111 of the Clean Air Act. These standards would apply only to electric
utility steam generating units capable of combusting more than 73 MW heat input
(250 million B.tu) of fossil fuel and for which construction or modification began on
or after the date or proposal of the regulations. This document contains background
informations environmental and economic impact. assessments, and the rationale for
the standards, as proposed under 40 CFR Part 60, Subpart Da. ' . .
17.
KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
Air pollution
Pollution control
Standards of performance
Electric utility power plants
Steam generating units
Nitrogen oxides
13. DISTRIBUTION STATEMENT
Unlimited
b.lDENTIFlERS/OPEN ENDED TERMS
Air Pollution Control
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassified
c. COSAT! Field/Group
21. NO. OF PAGES
22. PRICH
EPA Form 2220-1 {9-73)
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