-------
scrubbing system without tail gas reheat increases the overall
energy consumption of a Glaus sulfur plant by about 17 percent.
Use of a reduction tail gas scrubbing system without tail gas
reheat, however, reduces the overall energy consumption by about
50 percent.
Based on the growth projections presented in chapter 8, by 1980
some 8100 LT/day of refinery sulfur plant capacity will be subject
to NSPS. Standards based on alternative I will have essentially
no impact on national energy consumption, since most SIP's already
require the use of this type of emission control system. Standards
based on alternative II, however, will reduce national energy
consumption by some 54 million kw-hr/yr, or about 90,000 barrels
of fuel oil per year, assuming half of the refinery sulfur plant
capacity subject to compliance with NSPS install oxidation tail
gas scrubbing systems without tail aas reheat and half install
reduction tail gas scrubbing systems without tail gas reheat.
7.5 Other Environmental Impacts
No environmental impacts other than those discussed above
are likely to arise from standards of performance for refinery
sulfur plants, regardless of which alternative emission control
system is selected as the basis for standards. Furthermore, other
than those resources initially required to construct either alternative
emission control system (most of which could probably be salvaged
in one way or another), there do not appear to be any irreversible or
irretrievable commitment of resources associated with these standards.
As discussed above, there is even no overall increase in the energy
requirements associated with refinery sulfur plants, since both
7.21
-------
Table 7.6
Environmental Impact of No Standards or
Delayed Standards
Sulfur Plant Canacity
Nationwide S02 Emissions (M Tons/Yr)
Year Affected by Standards' No SIP*
1976
1977
1978
1979
1980
TOTAL
3150
1425
1815
850
850
8090
130
60
75
35
35
335
SIPJ Alternative IJ
25
10
15
5
5
60
25
10
15
5
5
60
Alternative II'
2
1
1
0.5
C.5
5
Note
1. LT/day.
2. 95% control.
3. 99% control.
4. 99.9% control.
7.22
-------
emission control systems result in a net reduction in energy
consumption.
Based on the growth projections presented in Chapter 8, the adverse
environmental impact of no standards or delayed standards on nationwide
S02 emissions is summarized in Table 7.6. If alternative I is
selected as the basis for standards, there is no adverse impact on air
quality since alternative I does not reduce emissions beyond levels
currently required by most SIP's. If alternative II is selected
as the basis for standards, on the other hand, the adverse environmental
impact of delaying standards or not setting standards is an increase
in nationwide S02 emissions, of some 5,000 to 25:,000 tons per year,
reaching a total of about 55,000 tons per year by 1980.
Since there are essentially no adverse water pollution, solid
waste disposal or energy consumption impacts associated with either
of the alternative emission control systems which could serve as
the basis for standards, there is no "trade-off" of potentially
adverse impacts in these areas against the resulting adverse
impact on air quality of delaying standards or not setting standards.
Furthermore, there does not appear to be any emerging emission
control technology on the horizon that could achieve greater emission
reductions or result in lower costs than that represented by
the emission control alternatives under consideration here. Con-
sequently, delaying standards to allow further technical developments
appears to present no "trade-off" of higher SOg emissions in the
near future against lower S02 emissions in the distant future.
7.23
-------
References
1. "Air Quality Criteria for Sulfur Oxides," U.S. Dept. of Health,
Education and Welfare, Public Health Service, January 1969.
2. "Preliminary Air Pollution Survey of Hydrogen Sulfide,"
U.S. Dept. of Health, Education and Welfare, Public Health
Service, October 1969.
3. Peyton, Thomas 0., Steele, Robert V. and Mabey, William R.,
"Carbon Disulfide, Carbonvl Sulfide, Literature Review and
Environmental Assessment,'" EPA Contract 68-01-2940, Task 23,
July 1975.
4. Patty, Frank A., Industrial Hygiene and Toxicology, Vol. 2,
2nd Ed., Interscience, New York, 1963.
5. Genco, J.M., and Tarn, S.S., "Characterization of Sulfur Recovery
from Refinery Fuel Gas*11 EPA Contract 68-02-0611, June 1974, p. 54.
6. Reference 5, pp. 35, 37-38.
7. Reference 5, p. 6n.
8. Reference 5, p. 36.
9. Letter, Cole, D.F., J.F. Pritchard and Co. to W.D. Beers,
Process Research, Inc. dated June 5, 1972.
10. Reference 5, pp. 52, 57 and 64.
11. "Impact of Motor Gasoline Lead Additive Regulations on
Petroleum Refineries and Energy Resources - 1974-1980 Phase 1,"
EPA Contract 68-02-1332, Task"4, May 1974, p. V-38.
12. Beers, W.D., "Characterization of Claus Plant Emissions,"
EPA Contract 68-02-0242, Task 2, Anril 1973.
°f C°a1 Gasification Emission Control
7.24
-------
8. ECONOMIC IMPACT
8.1 INDUSTRY PROFILE
As of April 1975, there were 259 petroleuifi refineries in the United
States with a total capacity of 14.8 million barrels per calendar day
(BCD). These refineries ranged in size from 200 BCD to 445,000 BCD,
with an average size of approximately 57,300 BCD.1 In general, new
refineries are expected to be considerably larger than the current
industry average. Information is available on 12 refineries that have
been projected to be built after January 1, 1975. These refineries vary
in size from 5,000 BCD to 200,000 BCD, with an average size of approximately
97,000 BCD.2
Not all petroleum refineries currently include sulfur recovery
plants. At the 259 domestic refineries referred to above, only 81 included
sulfur recovery plants. There are currently 122 sulfur recovery plants
within the industry, either currently installed or due to be installed
in 1975, ranging in size from 4 long tons of. sulfur per day (LTD) to 375
LTD, with an average size of 72 LTD.1'2'3 Sulfur recovery plants tend
to be found in the larger refineries. Table 8-1 illustrates this point.
For example, there are 175 refineries with individual capacities less
than 50,000 BCD, amounting to 67 percent of the total number of 259
refineries. These refineries, however, account for only 16 percent of.
t'he total number of 122 sulfur recovery plants. Stated in another way,
the average size of a refinery which includes a sulfur recovery plant is
approximately 140,000 BCD. This compares to an average size of approximately
27,000 BCD for those refineries without sulfur recovery plants.
8-1
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Table 8-2 summarizes the current status of the domestic refining
industry with regard to sulfur recovery plants. Table 8-3 provides
additional, detail with regard to the sulfur recovery plants that are
currently installed or due to be installed in 1975.
8.2 COST OF ALTERNATIVE EMISSION CONTROL SYSTEMS
As outlined in Chapter 6, there are two alternative emission control
systems that could serve as the basis for refinery sulfur plant NSPS.
Alternative I, exemplified by the IFP-1 and the Sulfreen processes,
achieves an overall sulfur recovery of 99.0 percent measured against the
total sulfur in the Claus plant feed gases. Alternative II, exemplified
by the Beavon, SCOT, Wellman-Lord, Cleanair, and IFP-2 processes, achieves
an overall sulfur recovery of 99.9 percent.
Since more data was available, both from vendors as well as owners,
the IFP-1 and the Wellrnan-Lord and the Beavon processes were taken as
representative of the two alternative emission control systems. Costs
would have to be comparable for the other systems or they would not be
competitive in the marketplace. Tables 8-4, 8-5, 8-6, and 8-7 present
the operating costs for the basic Claus sulfur recovery plant, a Claus
plant with an alternative I emission control system (IFP-1), a Claus
plant with an oxidation alternative II emission control system (Wellman-
Lord), and a Claus plant with a reduction alternative II emission control
system (Beavon). The plant with the capacity of 10 long tons of sulfur
per day is believed to be representative of a unit required by a typical
small refinery. The plant with the 100 long ton per day sulfur capacity
is believed to be typical of a unit required by a typical large refinery.
A plant with a capacity of 5 long tons of sulfur per day, while believed
to be toe, snail to be generally utilized in typical refineries, is also
shown for comparison. — o o
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Tables 8-8, a-9, and 8-10 summarize the economics of installing an
alternative I or alternative II emission control system on a Claus
sulfur recovery plant. For a 100 LTD plant, use of an alternative I
system reduces the annual return from $265,900 to $15,800, a loss of
$250,100 per year. Use of an alternative II system increases the annuaT
costs to $314,600-462,800, depending on whether an oxidation or reduction
process is employed, or a loss of $580,500-728,700 per year. For a 10
LTD Claus plant, use of an alternative I emission control system increases
the annual costs to $198,800, a loss of'$65,200 per year. Use of an
alternative II system increases the annual costs to $352,200-442,000, or
a loss of $218,600-308,400 per year. Finally, for a 5 LTD plant, use of
an alternative I system increases the annual costs to $205,900, a loss
of $58,200 per year, and use of an alternative II system increases the
annual costs to $344,800-419,900, or a loss of $197,100-272,200 per
year.
8.3 ECONOMIC IMPACT
Impact by Company Size
Two financial profiles have beer, developed to evaluate the economic
impact of the two alternative emission control systems. The first
profile represents a large, integrated oil company and the second represents
a small oil company. The profile of the large, integrated company is
biased upon an analysis of the published financial statements of Exxon
Corporation, Mobil Oil Corporation, Shell Oil Company, Phillips Petroleum
Company, Cities Service Company, and Ashland Oil, Incorporated. These
companies considered together should adequately represent the major
integrated refiner sector of the domestic oil industry. The resulting
financial profile iis presented in Table 8-11.
8-10
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The financial profile of the smaller, less complex firm is based
upon an analysis of the published financial statements of Murphy Oil
Corporation, Quaker State Oil Refining Corporation, APCQ Oil Corporation,
United Refining Company, and Edgington Oil Company, These firms con-
sidered together should adequately represent the small refiner sector of-
the domestic oil industry. The resulting financial profile is presented
in Table 8-12.
The economic impact associated with standards of performance results
from the incremental cost imposed on a source to comply with these
standards above those imposed on a source to comply with existing state
or local air pollution regulations. As discussed in Chapter 3, most
State Implementation Plans to meet the national ambient air quality
standards for SC^ require new plants to achieve an overall sulfur recovery
of 99.0 percent. A few local air pollution control regulations require
an overall sulfur recovery of 99.9 percent. Consequently, most state or
local regulations already require the installation of an alternative I
emission control system and standards of performance based on this
alternative will have no economic impact.
To assess the economic impact associated with standards based on
emission control system alternative II, the effect of compliance with
standards on the financial profile of a typical refiner was evaluated.
Eleven cases covering various refinery and sulfur plant capacities were
examined, three representing a large refiner and eight representing a
small refiner. These cases are presented in Tables 8-13 through 8-23
and are summarized in Table 8-24.
8-15
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As shown by the large refiner cases of Table 8-24, standards based
on emission control system alternative II decrease the profitability (as
measured by return on assets) of a large integrated refiner by 0.37 to
1.48 percent, if unaccompanied by price increases. To maintain an 8.10
percent return on assets, a large refiner would"have to increase prices
for petroleum products by 0.02-0.27 percent, or about 0.4-4.5 cents per
barrel. It is highly unlikely that this impact would retard industry growth
among the large integrated refiner sector of the domestic petroleum refining
industry. The reduced profitability, or the increase in product prices
necessary to maintain profitability, are for all practical purposes negligible.
As might be expected, the impact of standards on a small refiner is
greater than that on a large refiner due to economies of scale. As shown
by the small refiner cases of Table 8-24, standards based on emission
control system alternative II decrease the profitability of a small
refiner by 1.28 to 7.50 percent, if unaccompanied by price increases. To
maintain a 6.27 percent return on assets, the small refiner would have to
increase prices for petroleum products by 0.16 to 0.93 percent, or about
1.8 to 10.6 cents per barrel. Although it appears that the impact of
standards on the smallest refiner may be from three to five times as severe
as that on the typical large refiner, the magnitude of this impact is still
quite small and not likely to retard industry growth among the small refiner
sector of the domestic petroleum refining industry. As with the large
refiner, the price increases necessary to maintain profitability are negligible,|
especially in light of price increases over the past three to five years.
8-29
-------
The impact analysis by refinery size is clouded by the relatively
small size of the control investment and annual cost compared with the
overall refinery operation. There is, however, a more pronounced effect
when the incremental differences between control units is considered.
Table 8-25, which is derived from Tables 8-8 - 8-10, presents'the incremental
costs of achieving alternative II utilizing five sizes of control units.
Due to economies of scale, the cost of controlling an incremental ton of
S02 at the level of alternative II goes from $468-678 for a TOO LTD
sulfur plant to $3,891-5,994 for a 5 LTD sulfur plant.
Nation-Wide
Table 8-26 provides the number and size distribution of Claus plant
affected facilities in the period 1976-1980. It should be noted that
the growth is greater than the projected annual increase of refinery throughput
for three reasons. First, approximately 30 percent of the current refining
capacity is not controlled by Claus units so the base is narrow. Second,
it is assumed that all future refinery capacity, will be controlled and
third there will be an annual replacement of 5 percent of the existing
Claus plants.
Table 8-27 develops the 1976-1980 forecast to show the national
impact of required investment dollars, the annual costs and the potential
emission reductions. Standards based on alternative I will have no impact.
Standards based on alternative II, on the other hand will require an
Incremental investment by the domestic petroleum refining industry of some
$110 MM over the five-year period of 1975 to 1980. In 1980, these standards
will increase the annual operating costs of the domestic industry by some
$16 MM per year. In return, the standards will reduce national S02 emissions
by some 57,000 tons per year.
8-30
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8.4 POTENTIAL SOCIO-ECONOMIC.AND INFLATIONARY IMPACT
Since the emission control systems required to comply with standards
based on either emission control system alternatives represent such a
small proportion of the overall equipment or investment required by a
petroleum refinery, there should be no more socio-economic impact associated
with standards than associated with the addition of any new processing
unit to a refinery.
The inflationary impact associated with standards of performance
for refinery sulfur plants is negligible. If standards are based on
emission control system alternative I, there is no inflationary impact
at all. If standards are based on emission control system alternative
II, the fifth-year annualized costs are about $16 MM/year, and the price
Increases necessary to maintain the current industry average return on
investment varies from $0.004 to $0.106 per barrel, depending on the
size of the refinery affected. These are well below the Environmental
Protection Agency's guidelines for preparation of inflationary impact
statements.
8-34
-------
REFERENCES - CHAPTER 8
1. Oil and GSs Journal, April 7, 1975, pgs. 100-118.
2. Hydrocarbon Processing, February, 1975, pgs. 3-15.
3. Characterization of Sulfur from Refinery Fuel- Gas. (Contract No.
68-02-0611, Task 4), Battelle Columbus Laboratories, June 28, 1974,
pgs. 22-27.
4. Department of Labor, Monthly Labor Review, October 1975, p. 96.
5. Ford, Bacon and Davis, Sulfur Recovery Plants, 1971, p. 80.
6. Federal Power Commission, Typical Electric Bills, 1974 FPCR-83.
7. Beers, W. D., Characterization of Claus Plant Emission, Final
Report from Process Research, Inc., to the United States E.P.A.
Contract No. 68-02-0242, Task No. 2, Report No. EPA-R2-73-188
(April 1973). p. 75.
8. Letter, Hanley, D. L. Union Oil Company to Sedman, C. B, E.P.A,,
dated 12-4-73.
g. Comparative Assessment of Coal Gasification Emission Control Systems,
(Contract No. 68-01-2942, Task 007), Booz-Allen & Hamilton, Inc.,
October 1975, page A-3.
10. Letter, Andrews, J. W., J. F. P. to Genco, J. M., Battelle dated
12-21-75.
11. Letter, Turner, W. W., Stauffer Chemical Co. to Goodwin, D. R.
E.P.A., dated 6-14-74.
12. Letter, Ballard, B. F., Phillips Petroleum Co. to Sedman, C. B.
E. P. A., dated 12-18-74.
13. Trip Report: Sedman, C. B., Standard Oil Company of California, El
Segundo Refinery, 10-15-73.
14. Hydrocarbon Processing, April 1973, p. 116.
8-35
-------
15. Op. Cit, Booz-Allen & Hamilton, page A-ll, 12.
16. Moody's Industrial Manual, 1974 and 1975,
.17. Beers, W. D., op. cit., page 94.
18. Beers, W. D., op. cit., page 93.
19 Op. Cit., Booz-Allen & Hamilton, page A-5.
8-36
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9. RATIONALE FOR THE STANDARDS
9.1 SELECTION OF SOURCE FOR CONTROL
Sulfur dioxide emissions from petroleum, refineries are a
function of the sulfur content of the crude oil processed and the
complexity of the refinery itself. A major portion of the sulfur
which enters the refinery in the crude oil leaves the refinery in
the various petroleum products produced. Most of the sulfur
not accounted for in these petroleum products is recovered
as elemental sulfur, or emitted to the atmosphere as S02-
The major S02 emission sources in petroleum refineries are
gas and liquid fuel combustion, fluid catalytic cracking unit
catalyst regeneration and elemental sulfur recovery. Standards
of performance limiting S02 emissions from gaseous fuel combustion
were promulgated on March 4, 1974 (39 FR 9308). These standards
essentially require the removal of H2S from fuel gas before
it is burned, thus forcing increased elemental sulfur recovery
within petroleum refineries.
Petroleum refinery sulfur recovery plants, however, as mentioned
above, are responsible for a sizeable portion of the total S02 emissions
emitted from petroleum refineries. In 1975, nationwide refinery
sulfur recovery plant S02 emissions were estimated to be 0.272 x 10° MT/
yr, or about 10% of total domestic refinerv S02 emissions. Although
refinery sulfur recovery plants are responsible for only a small
portion (about 1%) of the total unabated U.S. S02 emissions, the
expected rapid growth of these facilities emphasizes the need for their
control. As of April 1975, there were 122 sulfur recovery plants
located in 81 domestic refineries. Between 1976 and 1980, 107 new
-------
olants are expected to be built. Well over half of these new
plants (about 62%) will have an average size of 100 LTD. The total
combined capacities of these new plants will be about 6,000 LTD
so that by 1980 the number of refinery sulfur recovery plants will
double.
A very important consideration of developing standards for
refinery sulfur recovery plants is that most refineries are located
in or near urban areas. As the size and number of these refineries
increase and the average sulfur content of the crude oil processed
increases, control of S02 emissions becomes much more critical.
9.2 SELECTION OF THE BEST SYSTEM OF EMISSION REDUCTION
As discussed in chanter 6, two alternative emission control
systems are considered candidates to serve as the basis for standards
of performance (i.e. best system of emission reduction, considering
costs). These systems are the third-stage low temperature Claus
reactor system (alternative I) and various tail gas scrubbing
systems (alternative II).
Considering only the nerformance of these systems, the
alternative II systems are clearly superior to the alternative I
systems. (See chapters 4 and 6,0 Use of an alternative II emission
control system increases the overall sulfur recovery of a refinery
sulfur nlant from about 95 percent to 99.9 percent, comnared to
99 percent with use of an alternative I emission control system.
In terms of emission reduction, the alternative II systems reduce
emissions by 98-99 percent, compared to an emission reduction of
only 80-85 percent achieved bv the alternative I systems. Also,
9.2
-------
the alternative II emission control systems are essentially insensitive
to fluctuations which might occur in the composition of the tail
gases from the sulfur plant. The alternative I systems, however,
require strict maintenance of a 2:1 H2S/S02 ratio to function properly.
Thus* the alternative II systems are much less prone to upsets and
are able to limit emissions to lower levels over a wider variety
of operating conditions than the alternative I systems.
Considering the various environmental impacts associated with
both alternatives, the alternative II emission control systems again
emerge as clearly superior to those of alternative I. (See chapter 7.)
In terms of ambient air quality, although the alternative I emission
control systems result in a significant reduction in the maximum
ambient air concentrations of S02 arising from the operation of a
refinery sulfur nlant, the alternative II systems result in a
substantially greater reduction of these concentrations.
More importantly, however, most State implementation plans (SIP)
already require a level of control essentially equivalent to the
alternative I emission control systems. Consequently, standards
based on this alternative would have little or no impact on emissions
of S02 from new or modified refinery sulfur plants. Standards based
on the alternative II systems, however, will reduce these emissions
by about 90 percent and will lead to a reduction in the growth of
national S02 emissions by 1980 of some 55,000 tons per year.
Considerinq possible environmental impacts in other areas,
there are essentially no potential adverse water pollution or solid
waste impacts associated with either alternative emission control
9.3
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system1. With regard to energy consumption, both alternatives
reduce the overall energy consumntion associated with a refinery
sulfur plant. Since most SIP's already require the installation
of alternative I emission control systems, no reduction in energy
consumption can be associated with standards based on this alternative.
If standards are based on the alternative II systems, however, the
growth in-national energy consumption will be reduced by some 54
million kw-hr/yr (90,000 barrels of fuel oil per year) by 1980.
With regard to other areas of potential environmental impacts,
there appear to be no noise or radiation impacts, or any irreversible
or irretrievable commitment of resources associated with either
of these alternative emission control systems. Neither does there appear
to be any incentive for not developing or delaying standards.
In terms of the economic impacts associated with the alternative
emission control systems, the alternative II systems generally cost
about twice as much to install and about 2 1/2 times as much to
operate as the alternative I systems. Again, however, since most
SIP's already require the installation of alternative I emission
control systems, there will be no economic impact if standards are
based on this alternative. If standards are based on alternative II,
the impact on a typical large integrated refinery will reduce its
profitability from about 8.10 percent return on assets to about
7.98-8.09 percent. To maintain an 8.10 percent return on assets,
the refiner would have to increase prices for petroleum products
by only 0.03-0.12 cents per gallon, or less than 0.5 percent. The
magnitude of this impact, therefore, is negligible.
9.4
-------
The impact on a typical small refinery is larger than that on a
large refinery due to the "economies-of-scale". In this case the
impact of standards based on the alternative II emission control
systems will reduce the profitability of a small refinery from about
6.27 percent return on assets to about 5.80-6.18 percent. To
maintain a 6.27 percent return on assets,, the small refiner would
have to increase prices on petroleum products by about 0..06-0.25
cents per gallon, or 0.16-0.94 percent. While this impact is about
twice as severe on the small refiner as on the large refiner,
its magnitude is still quite small and not likely to retard
growth among the small refiner sector of the domestic refining
industry. As with the large refiner, the price increases necessary
to maintain profitability are negligible, certainly in light of price
increases over the past three to five years.
In terms of the national impact on the domestic petroleum
refining industry, standards based on the alternative I emission
control systems will have no impact. Standards based on the
alternative II systems,, however, will increase the national investment
required by the domestic industry by some $115 MM over the five-year
period from 1975 to 1980; and the annual operating costs of the
industry will be increased by some $16 MM per year in 1980.
The potential inflationary impact of these standards is
essentially negligible. If standards are based on the alternative I
emission control systems, there is no impact, and if standards
are based on the alternative II systems, the increased fifth-year
annualized costs and increased,product prices are well below the
9.5
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Agency's guidelines of $100 MM per'year and 5 percent for signalling
potential inflationary impact.
It is clear, therefore, that the alternative II emission control
systems must be selected as the "best system of emission reduction,
considering costs" and that standards of performance for refinery
sulfur plants must be based on the use of these systems.
9,3 SELECTION OF POLLUTANTS FOR CONTROL
As discussed above, sulfur recovery olants in petroleum refineries
are major point sources of S02 emissions. .The objective of standards
of nerformance, therefore, is to reduce these emissions from new
and modified refinery sulfur plants. Selecting emission control
system alternative II as the basis for standards, however, complicates
the selection of pollutants for control.
Emission control system alternative II refers to two different
processes: oxidation-scrubbing and reduction-scrubbing. Residual
emissions released to the atmosphere from oxidation-scrubbing
processes consist of S02- Residual emissions released to the
atmosphere from reduction-scrubbing processes, however, consist
of S02 if the tail gases are incinerated before release to the
atmosphere, or a mixture of reduced sulfur compounds such as
hydrogen sulfide (HaS), carbonyl sulfide (COS) and carbon disulfide
(C$2), if the tail gases are not incinerated (see chapters 4 and 6).
A limit on S02 emissions alone, therefore, while appropriate for
the oxidation-scrubbing processes, and those reduction-scrubbing
processes with tail gas incineration, is inappropriate for those
reduction-scrubbing processes without tail gas incineration.
9.6
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While emissions of H2S from the reduction-scrubbing processes
without tail gas incineration can vary widely depending on the
design and operation of the process, emissions of COS and CS2
will not exceed 90-100 ppm unless the reduction catalyst in the
process is permitted to deteriorate. Consequently, the major
potential air pollution problem posed by these processes is emissions
of H2S.
Minimizing emissions of H2S from reduction-scrubbing processes
without tail gas incineration requires design and operation: of the
scrubbing portion of the process to reduce emissions of H2S to
very low levels initially. If standards of performance do not limit
emissions of H2S, owners or operators of these processes could
operate only the reduction portion of these systems and by-pass
the scrubber portion. The S02 originally present would merely be
converted to H2$ and released directly to the atmosphere. Although
this is possible, it is unlikely because at the ambient air concen-
tration of H2S which would result (500-2000 yg/m3, with short-
o
term peaks, 2-10 second, approaching 25,000 yg/m} an extremely
severe odor problem would result (see chapter 7). Sources would
tend to control these HLS emissions to very low levels due to
the offensive odors which would otherwise result if they were
not controlled.
Even in the more likely situation, however, where emissions
of H2S were reduced to the range of 200-300 ppm before release
to the atmosphere, ambient air concentrations of H2S ranging from
15 to 60 yg/m3 could arise with short-term peaks as high as 500
to 800 yg/m3. Since the odor threshold for H2S is 45 yg/m3, an
odor air pollution problem could still arise.
9,7
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Although emissions of COS and CS2 are normally very low,
as mentioned above, if the reduction catalyst is permitted to
deteriorate, emissions of these compounds from reduction-scrubbing
processes without tail gas incineration can approach 1000 ppm.
Under these conditions, ambient air concentrations of COS and C.^2
ranging from 100 to 400 yg/m3 could arise, with short-term peaks
approaching 3500 to 5500 yg/m3, respectively. While ambient air
C
concentrations of COS and CS2 at these levels probably do not
pose health problems, so little health effects data is available
on COS and CS2 that this is questionable. (The little data
available indicate adverse health effects occurring only at
levels greater than 15,000 yg/m3 for CS2, with no data available
for COS—see chapter 7.) The data do indicate, however, that
these short-term peak ambient air concentrations of CS2 are at
the odor threshold level for CS2, so that transitory odo,rs could
also arise if the reduction catalyst is permitted to deteriorate.
Developing standards of performance to limit emissions of S02
from refinery sulfur recovery plants, therefore, gives rise to
a rather unusual situation. In some cases, compliance with these
standards, while eliminating SOz emissions, would lead to emissions
of reduced sulfur compounds (i.e. H2S, COS and CS2), which could
lead to an odor air pollution problem. Consequently, two alternative
courses of action emerge with regard to selecting the pollutants
for control by standards of performance for refinery sulfur recovery
plants:
9.8
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1. Limit emissions of S02 only
2. Limit emissions of both S02 and reduced sulfur compounds
Limiting emissions of reduced sulfur compounds (i.e. ^S,
COS and CS2) from reduction-scrubbing emission control systems
without tail gas incineration, however, would make these pollutants
"designated pollutants," and all existing reduction-scrubbing emission
control systems without tail gas incineration installed on refinery
sulfur recovery plants "designated facilities," under section lll(d)
of the Clean Air Act. ERA's regulations implementing section lll(d)
(40 CFR §60) would require the Agency to issue a draft guideline
document containing the necessary information for states to develop
plans for controlling these pollutants from these existing facilities
and to solicit public comments on this document. Following considera-
tion of these comments, the Agency would make appropriate changes
to the guideline document and issue it in final form. Those states
containing reduction-scrubbing emission control systems without
tail gas incineration installed on refinery sulfur plants would
then be required to develop plans for controlling emissions of these
pollutants from these facilities with public hearings to solicit
the views of interested parties. These plans would then be submitted
to the Agency for approval or disapproval. If a State's plan were
disapproved, the Agency would have to develop a plan for that state.
Currently, there are about 25 reduction-scrubbing emission
control systems without tail gas incineration now operating on
petroleum refinery sulfur recovery plants in some seven states.
Developing State plans to limit emissions of reduced sulfur compounds
9.9
-------
from these facilities, therefore, could be a significant undertaking
requiring the expenditure of considerable resources at the Federal,
State and 1 oca! 1 eve!.
Emissions of reduced sulfur compounds, from these existing
reduction-scrubbing emission control: systems without tail gas
incineration, however, are quite low. These systems have been
installed to comply with State or local air pollution regulations
limiting emissions of SO^ from existing refinery sulfur recovery
plants. To ensure that the installation of these emission control
systems do not lead to local odor problems,., these.regulations
also limit emissions, of H^S, COS and CSz» either directly or
indirectly. Where emissions of reduced sulfur compounds are
limited directly, local regulations specify the maximum concentrations
of H£S> COS and CS2 that can be present in the tail gases discharged
to the atmosphere. In each case where this approach has been
followed, emissions of H2S are limited to 10 ppm and emissions
of total sulfur (H2S, COS and CS2) are limited to either 300 or
500" ppm.
Where emissions of reduced sulfur compounds are limited indirectly
by local regulations, these regulations require that the best available
emission control technology be installed. In the process of
specifying what the best emission control technology is, local air
pollution control agencies generally contact EPA, vendors of various
emission control systems and, other local air pollution control
agencies where various emission control systems have been installed.
9.10
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In terms of -emissions .of reduced sulfur compounds from existing
reduction-scrubbing emission control systems without tail gas
incineration, this approach lias achieved the same end result
as that above, and all 25 of these systems which are now operating
have been designed and guaranteed toy the -vendors of these systems
to limit emissions to less than 10 ppm ^S and less than 300 otf
500 ppm total sulfur (M?S, COS and CS^J
Consequently, existing reduction-scrubbing emission control
systems without tail gas incineration are not considered significant
sources of reduced sulfur compound emissions. Developing State
regulations to control emissions of these pollutants from the'se
facilities, therefore, would accomplish no additional reduction i;n
reduced sulfur compound emissions.
Probably the major reason why existing reduction-scrubbing
emission control systems without tail gas Incineration are not
sources of reduced sulfur compound emissions is that to date-,
these systems have only been installed in heavily industrialized
metropolitan areas. In these areas, the :need for air pollution
control is generally well recognized and the local air pollution
control agencjes have been in a position to develop and enforce
strong air pollution regulations.
Standards of performance for refinery sulfur plants, however,,
will require the installation of oxidation-scrubbing or reduction-
scrubbing emission control systems on new or modified refinery sulfur
recovery plants throughout the United States. In some areas
9.11
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where these systems might be installed, the need for stringent air
pollution control might not be as great as it is in these areas
where these systems have already been installed. In these areas,
owners and operators who installed a reduction-scrubbing emission
control system without tail gas incineration would not face stringent
regulation of reduced sulfur compounds and they might permit
emissions of H2S to increase to the range of 200 to 300 ppm. At
this point the resulting ambient air concentrations of F^S would
lead to noticeable but intermittent and transitory odors as discussed
earlier. It is quite possible, therefore, that in complying with
standards of performance, some new refinery sulfur plants could
become sources of emissions of reduced sulfur compounds unless
the standards specifically limit emissions of these pollutants.
Preventing new air pollution problems from arising, however,
is one of the primary goals of standards of performance. Also,
standards of performance are to reflect the best systems of emission
reduction, taking into account the costs of installing and operating
these systems. Considered from this perspective, since the technology
for reducing emissions of reduced sulfur compounds from reduction-
scrubbing systems without tail gas incineration is well demonstrated,
the costs of controlling these emissions are reasonable, and not
controlling these emissions could lead to an adverse environmental
impact in some cases; reduction-scrubbing emission control systems
without tail gas incineration can only be included among the best
systems of emission reduction if emissions of reduced sulfur compounds
are controlled.
9.12
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It is also through standards of performance that the Agency
identifies the best systems of emission reduction for various
industrial sources of air pollution. If the Agency were not to
limit emissions of reduced sulfur compounds, therefore, it would
imply that the Agency does not consider controlling these emissions
from reduction-scrubbing processes necessary. This view could
serve to undercut or weaken those local air pollution regulations
which are now effectively controlling these emissions from existing
sulfur recovery plants which have installed reduction-scrubbing
emission control systems without tail gas incineration.
A number of good reasons exist, therefore, for extending the
standards to cover emissions of reduced sulfur compounds. However,
a problem may arise if the burden of the state plan submission required
by 40 CFR §60.23 outweighs its possible benefits. To resolve this
problem, it is appropriate to consider the intent of both standards
of performance and section lll(d).
Briefly, the intent of standards of performance is to require
the installation of the best systems of emission control at the
time a source is being constructed or modified. The intent of
section lll(d) is to reduce emissions of pollutants emitted from
existing facilities which pose a danger to the public health or
welfare, but which on the basis of the information available
cannot be controlled under sections 108, 109 and 110 of the Act
as criteria pollutants, and which cannot be controlled under
section 112 of the Act as hazardous pollutants.
9.13
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Where an emission control system installed to comply with a
standard of performance might lead to the emission of a pollutant
not originally emitted by a source, the logical course of action
is to limit emissions of this new pollutant to ensure that it
does not lead to a new air pollution problem. In cases where the
new pollutant is a non-criteria pollutant, it must be decided
whether or not to initiate the chain of events leading to the
development of state regulations for limiting emissions of this
pollutant from existing sources already well controlled for this
pollutant.
The pollutants selected for control by these standards,
therefore, are S02 and reduced sulfur compounds. A determination
of the effort involved in developing state plans will enable EPA
to determine whether or not to develop a guideline document or
initiate the chain of events leading to the development of state
plans for controlling emissions of reduced sulfur compounds from
existing reduction-scrubbing emission control systems without
tail gas incineration which have been installed on refinery sulfur
plants.
9.4 SELECTION OF FORMAT FOR THE STANDARDS
A number of different,formats could be selected to limit
emissions from refinery sulfur plants. Mass standards limiting
emissions in terms of overall sulfur recovery (i.e. emissions
oer unit of sulfur produced or contained in the feed to the
9.14
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plant), or concentration standards limiting the concentration
of emissions in the stack gases discharged into-the atmosphere,
could be developed.
While mass standards may appear more meaningful in the sense
that they relate directly to the quantity of emissions discharged
into the atmosphere, enforcement of mass standards is more costly
and the results more subject to error than enforcement of concen-
tration standards. Determining mass emissions, for example,
invariably requires developing a material balance of some form
and this requires process data concerning the operation of
the plant, whether it be input material flow rates or production
flow rates. Gathering this data increases the. testing or monitoring
necessary and consequently increases the costs. Manipulation
of this data increases the number of calculations necessary,
compounding the error inherent within the data and increasing
the chance for human error.
Enforcement of concentration standards, however, requires
a minimum of data and information, decreasing the costs and
minimizing the chances for error in determining compliance.
Concentration standards are also somewhat more consistent with
the concept of basing standards of the "best systems of emission
reduction," since vendors of emission control equipment normally
guarantee the performance of their equipment in terms of the
concentration of emissions discharged.
The primary disadvantage normally associated with concen-
tration standards is that of possible circumvention by dilution
9.15
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of the gases discharged to the atmosphere lowering 'the concen-
tration of emissions, but not reducing the total mass emitted.
To ensure that compliance with concentration standards is not
achieved by dilution, however, section 60.12 of 40 CFR Part 60
specifically prohibits the use of dilution as a means of complying
with concentration standards.
Consequently, considered primarily from the perspective of
enforcement, concentration standards are selected as the format
for standards of performance for refinery sulfur plants. The
lower resource requirements of concentration standards over
mass standards far outweigh their drawbacks.
9.5 SELECTION OF EMISSION LIMITS IN THE STANDARDS
Specific emission limits need to be selected to limit
emissions of S02 from refinery sulfur plants which employ either
oxidation-scrubbing emission control systems or reduction-scrubbing
emission control systems with tail gas incineration. Emission
limits also need to be selected to limit emissions of H2S and
reduced sulfur compounds (H2S, COS and CS2) from refinery sulfur
plants which employ reduction-scrubbing emission control systems
without tail gas incineration.
The data and information to support selection of these emission
limits is summarized in chapter 4 and consists primarily of emission
source tests by the Agency or local air pollution control agencies.
Since the amount of emission data available is quite limited, a
number of factors need to be considered in selecting the specific
emission limits.
9.16
-------
Considering first the limit for S02 emissions, the emission
source test data from oxidation-scrubbing emission control systems
shows emissions in the range of 10-50 ppm (tests A-j, A2, A3,
Figure 4-10). These data, however, were collected from a unit
operating at less than half its design capacity immediately
following a major equipment turnaround. Consequently, the data
do not reflect emission levels that could be maintained by a
unit operating at full capacity over a period of time. According
to both vendors and owners and operators, unavoidable equipment
deterioration and chemical aging will lead to lower efficiency.
Generally, these systems operate for about a year between major
equipment turnarounds and during this time, emissions increase
by as much as 100 to 200 ppm. Basing the emission limit solely on the
basis of this emission data, therefore, would significantly
shorten the normal run length between major turnarounds and
increase maintenance and chemical replacement costs considerably.
The emission source test data available from reduction-scrubbinq
emission control systems with tail gas incineration shows emissions
of about 200 ppm S02 (test C, Figure 4-10). Although this data
is not EPA data, but is data from a test bv a local control agency
(EPA's source testing at this facility was invalidated due to
operating problems), the source testing method emploved by this
local aqency is considered comparable to EPA's.
9.17
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This emission level, however, is considered higher than normal
for a typical reduction-scrubbing emission control system with tail
gas incineration. According to the operators at this source, this
particular facility is significantly under-designed and, in fact,
shortly after this emission test data was gathered, it was "de-
bottle-necked" and expanded to improve its performance.
In EPA's discussions with the vendors of this facility, they agreed
with the operators that it was "under-designed." They also indicated,
however, that emissions from typical reduction-scrubbing emission
control systems with tail gas incineration are normally comparable
to those from oxidation-scrubbing emission control systems, and that
emissions from both systems increase to about the same extent between
turnarounds due to unavoidable equipment deterioration and chemical
aging.
As pointed out in chapters 4 and 7, the reduction-scrubbing
emission control systems with tail gas incineration (as opposed
to those without tail gas incineration) have a number of advantages
over oxidation-scrubbing emission control systems. Operation
of these systems involves techniques with which most refiners
have had a great deal of experience and thus refiners understand
these systems better, tend to experience fewer problems with them
and generally tend to favor these systems. More importantly, however,
these reduction-scrubbing emission control systems with tail gas
incineration produce no wastewater streams that require disposal.
Both the oxidation-scrubbing systems and the reduction-scrubbing
systems without tail gas incineration generate a wastewater stream.
9.18
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Considering all these factors, the emission limit for S02
emissions is set at 250 ppm. This limit applies to both the
oxidation-scrubbing emission control systems and to the reduction-
scrubbing emission control systems with tail gas incineration.
In view of the limited emission data available and the comments
of. both the owners and operators and the control system vendors,
this appears to be a reasonable emission limit consistent with the
performance of these emission control systems. This limit will
also ensure that these alternative II emission control systems are
installed and well operated.
Considering the emission limit for emissions of H2S and reduced
sulfur compounds, the available emission source testing data from
reduction-scrubbing emission control systems without tail gas
incineration shows that emissions of these pollutants from these
systems are quite low. Emissions of H2S, for example, were
frequently not detectable (tests B], B2, E1 and F-J , Figure 4-11).
In the one test in which emissions of H2S were detected (test B2),
an analytical method different from that employed by the Agency
was used and simultaneous testing by the Agency detected no emissions
(test 63). Review of both the Agency's test method and this other
test method indicated that this method which detected H2S emissions
was not as selective as the Agency's in identifyina I'2S, and was
including some of the COS and C$2 present as H?S.
The emission source test data available on emissions of reduced
sulfur compounds (H2S, COS and CS2) from these emission control
9.19
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systems shows that emissions of these pollutants are in the range
of 10-20 ppm (tests B-,, 82-,, B3, E-, and F-,, Figure 4-12). Here
again, however, this data was collected from these systems shortly
after major equipment turnarounds, or when they were operating
well below their design capacity (as low as 1/3 of design capacity
in one case).
Discussions with the vendors of these control systems also
indicated that unavoidable equipment deterioration and chemical
aging leads to a gradual increase in emissions with time. Pilot
plant data, for example, indicates that emissions increase by
about 200 ppm over a vear's operation. Thus, as discussed above
for the oxidation-scrubbing systems and the reduction-scrubbing
systems with tail gas incineration, basing the emission limits
for reduction-scrubbing emission control systems without tail gas
incineration solely on the emission data available would significantly
shorten the normal run length between major turnarounds and increase
the costs of maintenance and chemical replacement considerably.
Considering these factors, the limit on emissions of H2S
and reduced sulfur compounds from reduction scrubbing emission control
systems without tail gas incineration is set at 10 ppm and 300 ppm
respectively. The 10 ppm limit on H2S emissions will ensure that
installation of these emission control systems will not lead to a
local odor air pollution problem. The 300 ppm limit is equivalent
to the 250 ppm limit on S02 emissions in the sense that both limits
reduce sulfur emissions—be they S02 or H2S, COS and CS2—to the
9.20
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same level. (The 250 ppm S02 limit reflects the larger volume
of gases discharged to the atmosphere.)
9.6 SELECTION OF MONITORING REQUIREMENTS AND PERFORMANCE TEST METHODS
The objective of monitoring reouirements is to provide a quick
and easy means for enforcement oersonnel to ensure that an emission
control system; installed to comply with standards of performance
is DTOp-erly operated and maintained. For refinery sulfur recovery
olants» the most straightforward means of ensuring proper operation
ancf maintenance is to monitor emissions released to the atmosphere.
Consequently, where oxidation-scrubbing processes or reduction-
scrubbing processes with tail gas incineration are installed to
comply- with the standards, monitoring of S02 emissions is required.
Where reduction-scrubbing processes without tail gas incineration
are installed, monitoring of H£S and reduced sulfur compound emissions
is required.
Although monitoring requirements are included for l^S and
reduced sulfur compound emissions, the Agency has not yet developed
performance specifications for these monitors. Consequently, owners
and operators of reduction-scrubbing emission control systems without
tail gas incineration, who are subject to these requirements, will
not have to install these monitors until these specifications have
been promulgated in the Federal Register. The requirement for
monitoring is included in the regulations to ensure that when
these monitors become available, sources which became subject
to standards of performance before the monitors were available
will then be required to install monitors to aid enforcement personnel
in determining if the emission control system is being properly
operated and maintained.
9.21
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For determining compliance with the standards, Method 6 -
Determination of Sulfur Dioxide Emissions from Stationary Sources
will be used where oxidation-scrubbing processes or reduction-
scrubbing processes with tail gas incineration are installed.
Where reduction-scrubbing processes without tail gas incineration
are installed, Method 18 - Determination of Hydrogen Sulfide,
Carbonyl Sulfide and Carbon Disulfide Emissions from Stationary
Sources will be used. These methods were the methods used to gather
the emission data contained in chapter 4 and Appendix C, which support
the standards. Details as to why these methods were selected over
other methods for gathering this data mav be found in Appendix D.
9.7 REFERENCES
1. Telephone conversation, F.L. Porter (EPA) with G.L. Tilley
(Union Oil), April 28, 1976.
9.22
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APPENDIX A
EVOLUTION OF STANDARDS
A.I
-------
EVOLUTION OF STANDARDS
8/73
9/73
10/5/73
10/10-10/19/73
10/17/73
11/73
10/73-2/74
Surveyed and reviewed process operations and
emission control systems for all domestic
Glaus sulfur recovery plants.
Sent letters to control enuinment vendors
requestina desion data for the Wellman-Lord,
Beavon, Cleanair, SCOT, and Aquae!aus orocesses,
.and location of well-controlled Claus nlants.
Selected eioht refineries for initial nlant
inspections.
Contracted for detailed ennineerina studv of
Claus tail gas control systems v/ith Battelle-
Columbus.
Inspected eiqht refineries with well-controlled
Claus plants, pre-surveyed for emission testina,
and sent 114 letters to refineries.
Met with Los Anqeles APCD for discussion of
their regulations for sulfur recovery plants.
Contractor sent additional letters to vendors
for design data on the IFP-1, IFP-2, Sulfreen,
Cataban/and Chivoda Thoroughbred processes
for tail qas sulfur removal.
Test methods for determining gaseous sulfur.,
compounds in Claus tail gas ("i.e., COS, ,C.S2i
H2$, S0£, Sx) investigated and developed.
Presurveys made of three likely test sites.
1/11/74
2/25-3/13/74
Inspection made of IFP-1 process on a Claus
sulfur plant.
Emission tests completed for Mellman-Lord,
Beavon, and SCOT control svstems.
A.2
-------
4/1/74
5/7/74
6/10-6/12/74
6/74
8/74- 2/75
3/75
4/29/75
5/5-5/6/75
5-7/75
8-9/75
10/75-4/76
Inspection made of second IFP-1 orocess on a
Glaus sulfur plant. 114 letters on IFP-1
process sent to operators.
Meeting with API's Committee on Environmental
Affairs to discuss emission test.results and
Dotential standards.
Emission test of IBP-1 control system completed.
Study entitled "Characterization of Sulfur
Recovery From Refinery Fuel Has" completed
by BatteH e-Columbus Labs. Report circulated
to API for review.
Emission control costs developed, monitoring
and emission test methods finalized, and
dispersion analyses completed. Developed first
draft of EPA Standards Support and Environmental
Impact Document (SSEID).
Revised SSEID and sent to NAPCTAC and Workina
Group members.
Met with EPA Uorkinn Group to discuss findinas
of SSEID and the recommended standard.
Met with NAPCTAC to review the recommended
standard for refinerv sulfur plants and the
basis 'for the standard outlined in the SSEID.
Delayed action to resolve potential 111(d)
aspects of standards for refinery sulfur
plants.
Responsibility for SSEID informally trans-
ferred to Standards Development Branch.
SSEID reviewed, edited and rewritten by
Standards Develonment Branch to conform
with the general outline for a SSEID.
A.3
-------
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APPENDIX B
INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
B.I
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INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS (continued)
elines f or _ Preparing Location Within the Standards Support
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-------
APPENDIX C
EMISSION! SfMECE TEST DATA*
C.I
-------
EMISSION SOURCE TEST DATA
C.I INTRODUCTION
This appendix summarizes the emfssion test data gathered during
the development of standards for refinery sulfur plants. Detailed
information on each facility tested is presented herein. Each
facility is identified by the -same coding used in Chapter 4. Any
reference in this appendix to commercial products or processes
by name does not constitute an endorsement by the Environmental
Protection Agency.
C.2 SUMMARY OF TEST DATA
Four different processes for removing sulfur from Claus
sulfur plant exhaust gases were tested by EPA to determine the
best available control technology as required by section 111
of the Clean Air Act. Pollutants measured included total sulfur
by EPA Method 18 (gas chromatograph/flame photometric detection),,
SOg by EPA Method 6, H2S by EPA Method 11, carbon monoxide .by
EPA Method 10, NOX by EPA Method 7, hydrocarbons by a flame
ionization detector, Orsat gases by EPA Method 3, and moisture
by EPA Method 4.
C.3 DESCRIPTION OF FACILITIES
Plant A - Plant A consists of three fdentfcal 150 long ton/day
(LT/D) Claus trains, two of which operate with the third on stand-by.
Emissions from each Claus train is controlled by a Wellman-Lord
scrubber. Design basis of these Wellman-Lord scrubbers is 250 ppmv
SOg. Tests Al and A2 were performed by EPA and refinery personnel,
respectively, during the period March 11-13, 1974. In Test Al
sulfur compounds were determined by EPA Method 18 (gas chromatograph/
flame photometric detection) for total sulfur and EPA Method 6 for S02,
C.2
-------
Carbon dioxide, carbon monoxide, and oxygen were determined by continuous
methods (non-dispersive infrared for C02 and CO and paramagnetic for 02)
and by the Orsat method. Nitrogen oxides were determined by EPA Method 7,
visible emissions by EPA Method 9, moisture and flow rates by EPA
Methods 1, 2, and 4, and hydrocarbon concentrations by a flame
ionization detector.
In Test A2 SO? and NO were determined by a fuel cell electro-
£ X
chemical method, COS and CS2 by a gas chromatograph flame photometric
detector, CO and C02 by Orsat, 02 by Orsat and a paramagnetic oxygen
analyzer, and hydrocarbons By a hydrogen flame gas chromatograph.
During Tests Al and A2 only one sulfur plant was operating
due to low refinery throughputs, caused by the OPEC oil embargo.
Sulfur feed rates during the tests averaged 113 LT/D for three runs.
Test A3 was conducted by the Los Angeles APCD, January 10-11, 1973,
on all three Claus plants. Hydrogen sulfide was determined by a ZnC03
impinger train, and S02 by impingers containing a 5% NaOH solution.
Nitrogen oxides, hydrocarbons, carbon monoxide, carbon dioxide,
moisture, and flow rates were determined according to methods described
In the Source Testing Manual of the Los Angeles APCD.
Sulfur feed to the three plants during Test A3 was 116.6, 76.9,
and 68.8 LT/D, respectively, averaging well below design rates.
plant B - Plant B consists of two parallel 100 LT/D Claus trains,
each of which exhausts into a Beavon tat! gas treating unit. Design
basis of each Beavon tail gas treating unit is 200 ppmv total sulfur,
with less than 10 ppmv H2S.
C.3
-------
Tests Bl and B2 were performed by EPA and refinery personnel,
respectively, during the period March 5-7, 1974. In Test Bl sulfur
compounds were determined by EPA Method 18 (gas chromatograph/flame photo-
metric detection) for total sulfur and EPA Method 6 for S02. Carbon
dioxide, carbon monoxide, and oxygen were determined by continuous
methods (a non-dispersive infrared instrument for C02 and CO, and
paramagnetic analyzer for 02) and by the Orsat method. Nitrogen
oxides were determined by EPA Method 7, visible emissions by EPA
Method 9, moisture and flow rates by EPA Methods 1, 2, and 4,
and hydrocarbon concentrations by a flame ionization detector.
In Test B2 mass spectrometry was used to determine CH4, COS,
S02> H£S, C$2, H2j CO/N2» 02, Ar, and C02. Gas chromatography
was then used to obtain the CO/N2 split.
During Tests Bl and B2 the sulfur plants were operating well
below design levels due to the OPEC oil embargo. Sulfur feed rate
to each or both Claus tra?n(s) averaged 34.2 LT/D for three runs.
Test B3 was conducted by the Los Angeles APCD on three separate
occasions: July 10, August 8, and September 24, 1974. The August 8
and September 24 tests were performed before and after overhaul to
determine the effect of overhaul on emissions.
Sampling techniques included a 5% HC1 solution in an impinger
to collect ammonia, a 3% ^2^2 solution in an impinger to collect
SOgj and a ZnCOs slurry in an impinger for H2S collection. Grab
samples were made for subsequent determinations of H2S, COS, and
CS2 by gas chromatograph with a flame photometric detector and
carbon monoxide by non-dispersive infrared absorption.
C.4
-------
Plant C - Plant C consists of one small 16 LT/D, two-stage
Claus unit followed by a SCOT tail gas treating unit. Design
basis of the SCOT unit is 400 ppmv total sulfur emissions calculated
as H2S. An incinerator oxidizes the 400 ppm H2S to S02 before
discharge to the atmosphere.
Test C3 was conducted by the Los Angeles APCD on February 14, 1974.
Hydrogen sulfide was determined by a ZnCOs train at the outlet of the
SCOT system. At the incinerator stack S02 was determined by an NaOH
train; combustion gases (CO, C02, and CH4) were analyzed by total
combustion analysis using a non-dispersive infrared instrument
and NOX was determined by hydrogen peroxide/sulfuric acid impinger
trains. Water vapor, gas flow and Orsat gases were also analyzed
using Los Angeles APCD methods.
During Test C3 sulfur feed averaged 11:1 LT/D.
plant D - Test Dl was conducted June 10-12, 1974,
by EPA on a large, 395 LT/D, three-stage Claus plant followed by
an IFP-1 tail gas process. The Claus nlant recovers sulfur from
acid gases produced in a carbon disulfide plant. Emission design
for the IFP-1 unit is 90 percent conversion of (H2S + S02) from the
Claus plant. This corresponds to 1640 ppmv total sulfur (wet) or
2540 ppmv total sulfur (dry).
In the first test total sulfur compounds were determined by EPA Method 18
(gas chromatograph/flame photometric detection). S02 was determined by
EPA Method 6, H2S by EPA 'Method 11, NOX by EPA Method 7, moisture
by EPA Method 4, gas flow by EPA Methods 1 and 2, and visible
emissions by EPA Method 9. C02, CO and 02 were determined by
C.5
-------
continuous methods (non-dispersive infrared for C02 and CO, para-
magnetic analyzer for 02). C0£ and 02 were also determined by a gas
chromatograph with thermal conductivity detection.
The second test was conducted using a Meloy Analyzer, which
oxidizes all sulfur compounds to S02 and then measures S02 by a
flame photometric detector. The third test was conducted using
a DuPont analyzer, which also oxidizes all sulfur compounds to
S02> but which then measures S02 by UV absorption.
During these tests, sulfur feed to the Claus unit averaged
336 LT/D.
Plant E - Plant E consists of two 96 LT/D Claus plants each with
a Beavon tail gas treating unit. Test El was conducted December 12,
1974, by the Los Angeles APCD. Analyses for COS, CS_, H-S, SO ,
, total sulfur, CO, and NOX were conducted. Details on test
methodology were not specified, though assumed the same as in previous
tests conducted by Los Angeles County (Tests A3 and B3). No process
data were available. The Beavon units were designed at 200 ppmv
total sulfur, 10 ppmv I^S emission levels.
Plant F - Plant F consists of a Beavon tail gas treating unit
which removes sulfur from four combined Claus plant tail gas streams
in a petroleum refinery. No design or operating data are available.
Los Angeles County conducted tests November 6, 1974, for total
sulfur, H2S, and carbon monoxide (test Fl). Again, test methods
are assumed to be Los Angeles APCD methods as described for
Tests A3 and B3.
C.6
-------
Table 1
FACILITY A
Summary of Results
Test Number
Run Number
Date
•Stack Effluent:
Flow rate - DNMJ/min
Water vapor - Vol. %
C02 - Vol. % drya
02 - Vol. % dry9
CO - Vol. % dry3
C02 - Vol
02 - Vol.
CO - ppmv dry
dryc
dryb
b
S02 - ppmv dryc
S02 - ppmv dry
COS - ppmv dry
CS? - ppmv dry
.
I^S - ppmv dry
TS - ppmv dry
NOX - ppmv dry6
THC - ppmv dry
Visible emissionsS
Al
1 2
3/11/74 3/12/74
197.1
13.0
4.3
0.9
95
5.9
38
3.2
2.5
<0.1
46.2
17.2
7.5
0
135.4
10.6
7.2
0.8
0.0
5.6
0.2
100
21.8
16
1.9
3.4
<0.1
24.7
9.0
6.2
n
3
3/13/74
209.7
11.2
5.35
2.95
0.0
3.8
1.5
39
7.4
10
0.9
1.1
13.1
21.0
4.6
0
Averagi
180.4
11.6
6.3
1.9
0.0
4.6
0.9
78
11.7
21
2.0
2.3
•f~ r\ i
^ w • 1
28
15.7
6.1
0
Orsat analysis
NDIR/Paramagnetic
CEPA-6
dGC/FPD (EPA-18)
SEPA-7
Total hydrocarbons as methane by flame ionization
9EPA-9
Source: Reference 1 ^"'
-------
Test Number
Run Number
Date
Stack Effluent:
Flow rate DNM3/MIN
Water vapor - vol.
C02 - vol. % drya
02 - vol. % dr.va
CO - vol. % drya
S02 - ppmv dryb
COS - ppmv dryc
CS2 - ppmv dryc
NOX - ppmv dryb
HC - ppmv dryd
TABLE 2
FACILITY A
Summary of Results
A2
1 2
3/12/74 3/13/74
6.6
1.3
0.3
10
0.3
1.5
21.7
3.0
15
25
Averane
6.6
1.3
0.3
12.5
0.3
1.5
23.4
3.0
Orsat analysis
fuel cell electrochemical
CGC/FPD (EPA-18)
Hydrogen flame chroma!oaraphy
Source: Reference 2
C.8
-------
TABLE 3
FACILITY A
Summary of Results
Test Number
•Run Number
Date
Stack Effluent:
Flow rate, DNM3/M
Water vapor - vol.
C02 - vol. % wet
CO - vol. % dry
SOg - ppmv dry
H2S - ppmv
COS - ppmv
C$2 - ppmv
NOX - Ib/hr
HC - Ib/hr
1
1/10/73
229.37
14.0
16.0
0.36
31
<.10
15
13
0.57
0.90
A3
2
1/11/73
150.08
10.0
16.0
0.20
38
<.10
1
2
0.59
0.44
3
1/11/73
127.43
12.0
19.0
0.067
47
1.7
<1
1
0.46
0.21
Averaqe
169.05
12.0
17.0
0.41
40
0.6
6.0
5.7
0.54
0.52
Source: Reference 3
C.9
-------
TABLE 4
FACILITY B
Summary of Results
Test Number
Run ftaber
Date
Stack Effluent:
Flow rate, DNM3/M
Water vapor - vol
C02 - vol. % drya
02 - vol. % drya
CO - vol. % drya
C02 - vol. % drvb
02 - vol. % dryb
CO - vol. % dryb
S02 - pwnv dryc
S02 - ppmv drvd
COS - ppmv dryd
CS2 - pomv dryd
H2S - ppmv dryd
TS - ppmv dryd
NOV - ppmv dry6
* f
THC - ppmv dry7
Visible emissions
1
3/5/74 .
65.5
4.2
5.4
0.6
0
5.8
0.02
566
3.6
1.5
17
0.15
19
1.1
Bl
2
3/6/74
71.6
5.0
5.5
0.5
0
5.7
0.09
565
3.8
0.7
17
-
17
0
3
3/7/74
68.8
3.3
6.0
0.3
0
5.9
0.02
604
4.5
0.76
15
-
16
0
Average
68.6
4.2
5.6
0.5
0
5.8
0.04
578
4.0
1.0
16
-
17
0.4
0
Orsat analysis
NDIR/Paramagnetic
cEPA-6
dGC/FPD (EPA-18)
eEPA-7
Total hydrocarbons as methane by flame tonization
9EPA-9
Source: Reference A
C.10
-------
TABLE 5
FACILITY B
Summary of Results
Test Number
Run Number
Date
Stack Effluent:
Flow rate, DNM3/M
Water vapor - vol,
H2 - vol. %
CO - ppm
CH4 - ppm
N2 - vol. %
02 - vol. %
H2S - ppm dry
Ar - vol. %
COo -vol. %
COS - ppm dry
SOg - ppm dry
C$2 - ppm dry
1
3/5/74
5.0
479
125
87.7
0
7
1.0
63
9
0
0
B2
2
3/6/74
6.0
620
206
87.0
0
1
1.0
6.0
9
0
0
3
3/7/74
5.8
595
332
86.9
0
0
1.0
6.3
9
5
0
Averaae
5.6
565
221
87.2
0
2.7
1.0
6.2
9.0
1.7
0
Source: Reference 5
c.n
-------
TABLE 6
FACILITY B
Summary of Results
Test Number
Run Number
Date
Stack Effluent:
Flow rate, DNM3/M
Water vapor - vol,
C02 - vol. %
CO - ppm
S02 - ppmv dry1
COS - ppmv dry1
CS2 - ppmv dry1
- ppmv dry1
B3
1
7/10/74
2
8/8/74
3
9/24/74
4
9/24/74
Averane
-
0
23.0
9.7
0
-
0
16.0
0
0
346
0
6.8
0
0
335
0
7.0
0
0
341
0
13.0
2.4
0
Source: Reference 6
Note:
T "Assume moisture level of 5.6% based on test 62-
C.12
-------
Table 7
FACILITY C
Summary of Results
Test Number
Run Number
Date
Stack Effluent:
Flow rate - DNM3/M
I-LS - ppmva
u c b
H9S - ppmv
S02 - ppmva
S02 - Ib/hr1
SO
NO
x
- Whr
b
- ppmv
CO - ppmv
02 - Vol.
C02 - Vol .
HC - Vol .
2/14/74
11.33
197
<10
0
5.5
0
14
1500
12.5
Incinerator inlet
Incinerator outlet
Source: Reference 7
C.13
-------
Test Number
Run Number
Date
Stack Effluent:
\
Table 8
FACILITY D
Summary of Results
(See below)
1 2 3
6/10/74 6/11/74 6/12/74
Average
Flow rate - DNM°/min
Water vapor - Vol . %
C02 - Vol . % drya
02 - Vol . % drya
CO - Vol. % drya
C02 r Vol . % dry5
02 - Vol. % dryc
CO - ppmv dry
S02 - ppmv dry
S02 - ppmv dry6
S02 - ppmv dry
COS - ppmv dryf
H?S - ppmv dry
f
CSp - ppmv dry
TS (l)""""- ppmv dryf
TS (2) - ppmv dry6
TS (3) - ppmv dry9
NO - ppmv dry
421
30.9
1.3
0.28
_
1.5
0.1
3240
59
420
82
132
1190
460
2310
2390
2380
7.8
431
37.7
1.1
0.35
_
1.6
_
2450
42
430
72
77
1410
180
1920
2590
2540
1.0
414
39.0
1.1
0.31
—
1.8
0.1
3140
42
360
80
133
1950
300
2760
_
2070
4.0
422
35.9
1 .2
0.31
..
1.6
0.1
2940
48
400
78
114
1520
310
2330
2490
2330
4.3
Visible emissions1
aOrsat
bNDIR
paramagnetic
dEPA-6
Q
DuPont Analyzer(includes elemental sulfur)
fGC/FPD (EPA-18)
9Meloy Analyzer
hEPA-7
EPA-9
Source: Reference 8
C.14
-------
Table 9
FACILITY E
Summary of Results
Test Number
Run Number
Date
Stack Effluent:
Flow rate, DNM /tnin
Water vapor - Vol. %
COS - ppm dry1
CS2 - ppm dry1
H2S - ppm dry1
S02 - ppm dry1
S04 - ppm wet
H2S04 - ppm wet
TSa - ppm
TSb - ppm
CO - ppm wet
N0v(as N0?) - ppm wet
X £•
El
1
12/12/74
5
0.5
<1
<0.4
2
<0.3
8+
14
250
I
aTotal of separately measured constituents
bTotal as measured by sulfur detector (includes mercaptans)
Source: Reference 9
Note:
1. Assume moisture level of 5.6% based on test 82-
C.15
-------
Table 10
FACILITY F
Summary of Results
Test Number
Run Number
Date
Stack Effluent:
Flow rate - DNM3/M
COS - ppm dry
C$2 - ppm dry
H2S - ppm dry
S02 - ppm dry
Total sulfur - ppm dry
CO - ppm dry
Source: Reference 10
Fl
11/6/74
311.49
15.2
0.1
0
0
15.4
670
C.16
-------
References
1. Source Test Report No. 74-SRY-l, EPA Contract No. 68-02-0232,
Task Order No. 34, Environmental Science and Engineering, Gainesville,
Fla., March 1974.
2. Letter, Thron Rigqs, Standard Oil Co. of California to C. Sedman,
ESED, OAQPS, EPA, dated August 9, 1974.
3. Source Testing Section Report No. C-1895, Los Anqeles County APCD,
February 28, 1973.
4. Source Test Report No. 74-SRY-2, EPA Contract No. 68-02-0232,
Task Order No. 34, Environmental Science and Enqineerina, Rainesville,
Fla., March 1974.
5. Letter, George L. Tilley, Union Oil Company of California, to
C. Sedman, ESED, OAQPS, EPA, dated Auaust 26, 1974.
.6. Source Testing Section Report No. C-2082, Los Anaeles County,
APCD, Dec. 27, 1974.
7. Source Test Section Report Mo. C-2104, Los Angeles County, APCD,
April 25, 1974.
8. Source Test Report No. 74-SRY-4, EPA Contract No. 68-02-0232,
Task Order No. 34, Environmental Science and Engineering Gainesville,
Florida, June 1974.
9. Source Testing Section Report No. C-2234, Los Anaeles County APCD,
Feb. 20, 1975.
10. Source Testing Section Report No. C-2226, Los Angeles Countv APCD,
Nov. 6, 1974.
C.17
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APPENDIX D
EMISSION MEASUREMENT AND CONTINUOUS MONITORING
D.I
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D.I EMISSION MEASUREMENT METHODS
A review of the literature revealed that four different
analytical methods could be used for analysis of sulfur compounds:
colorimetry, coulometry, direct spectrophotometry, and gas
chromotography. Although these methods were developed in most
cases for measurement of ambient air concentrations, this did not
preclude their application to measurement of stack gas emissions.
Colorimetr.y. In this method a sample is bubbled through a
solution which selectively absorbs the component or components
desired. The solution is then reacted with specific reagents to
form a characteristic color which is measured spectrophotometrically.
An example of a colorimetric method is the methylene blue
method which involves the absorption of reduced sulfur compounds
in an alkaline suspension of cadmium hydroxide to form a cadmium
sulfide precipitate. The precipitate is then reacted with a
strongly acidic solution of N, N dimethyl-P-phenylene-diamine and
ferric chloride to give methylene blue, which is measured spectro-
photometrically. Automated sampling and analytical trains using
sequential techniques are available for this procedure. Inherent
deficiencies for stack sampling applications however include
variable collection efficiency, range limitations, and interference
from oxidants.
Another colorimetric method is the use of paper tape samplers
impregnated with either lead acetate or cadmium hydroxide. These
compoundsreact specifically with H2S to form a colored compound
which can be measured directly with a densitometer. Tape samplers
D.2
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would not be appropriate for all reduced sulfur compounds unless
they were first reduced quantitatively to H^S. In addition, the
range is limited, the method requires precise humidity control and
suffers from light sensitivity, fading, and variability in tape
response.
Coulometry. In this method a gas sample is bubbled through
a solution containing an oxidizing or reducing agent (titrant).
The concentration of the titrant in solution is buffered by the
presence of a titrant precusor. Passage of an electric current
through the solution causes the titrant precusor to break down,
releasing additional titrant into solution. Consequently, as the
titrant is consumed by reaction with specific compounds contained
in the gas sample, an electric current is passed through the
solution to maintain the titrant concentration. The electric
current required is a measure of the reactive compounds in the
gas sample. Normally, the titrant is a free halogen such as
bromine or iodine in solution as an oxidizing agent, or a metal ion
such as silver in solution as a reducing.agent.
For determining emissions coulometric titration has the
advantage of responding to a wide variety of sulfur compounds. The
response to each compound is quite different, however, and this
makes standardization and reporting of data difficult in many cases.
In addition, the method suffers from high maintenance and requires
frequent calibration to reduce drift to acceptable levels.
Spectrophotometry. Although infrared and mass spectrophotometric
methods are well established analytical techniques, most of these
D.3
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seven-fold that to S02> S02 cannot be analyzed by this method
if appreciable elemental sulfur is present. The Model 464
has not yet been used as a continuous monitor in sulfur recovery
pi ants.
Gas cJiromatography/flame photometric detection (GC/FPD) is
another method for monitoring SC^ emissions. Systems using
this principle include the Bendix Model 8700, Tracer Model 250H.
These systems cost about the same as the DuPont 464 system discussed
above and are also semi continuous in operation. Recently, however,
one vendor announced a complete sampling, analysis, and recording
system for $14,000 (Tracer Model 270H). Again, automated data
reduction can be added at additional cost. Integrators compatible
with GC analyzers can be programmed to print the concentration of each
sulfur compound. Cost of these integrators is in the range of
$3,000-$49000.
The GC/FPD system has several advantages. It can separate and
detect each individual sulfur comoound. These systems are extremely
sensitive, however, and require sample dilutions of 100:1 or more.
This presents a potential source of error and frequent calibration
is necessary to minimize such errors.
Other continuous monitoring instruments are commercially
available. Many of these are summarized according to their
capabilities by Nader et.al. (EPA-650/2-74-013). To date, however,
they have not been evaluated for use on sulfur plants.
D.6
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For montiroing emissions of total sulfur and H^S, the two
systems described previously can be used. The Da-Font Model 454
ultraviolet analyzer is capable of oxidizing the gas sample and
measuring all sulfur compounds including elemental sulfur as SCh?.
This system, however, is not able to monitor H^S emissions.
The GC/FPD system: is capable of monitoring individual sulfur
emissions (except sulfur vapor). Total sulfur can be determined
by adding the individually measured components tp the estimated
sulfur vapor. Sulfur vapor may be calculated from the partial
pressure of sulfur at the gas stream temperature. Since H^S
vapor is one of the compounds determined by GC/FPD„ it can be
reported separately.
Although continuous monitors are available to monitor emissions
of reduced sulfur compounds, compliance with the monitoring
requirements included in the standards will he delayed until
EPA promulgates performance specifications for these monitors.
Since the standards specify that emissions must be determined
at zero percent oxygen, continuous monitorinq of the oxygen concen-
tration in the tail gases discharged to the atmosphere is required.
A number of systems are available to monitor oxygen concentration
and performance specifications for these systems were promulgated
by EPA in 40 FR 46268 on October 6, 1975.
D.3 PERFORMANCE TEST METHODS
EPA Method 18, "Semicontinuous Determination of Sulfur
Emissions from Stationary Sources," has been prepared for use
in determining compliance with new source performance standards at
refinery sulfur plants. This method requires use of the GC/FPD
D.7
UU—UNC—[J UfcM-l-Vj—I-I=CC—U-l \^l-Itl-l-^C I-I-UIII . =
Public Information Center (PM-21:5), EPA,
2O. SECURITY CLASS (TKispage)
Unclassified
22rPRl'CE-
EPA Form 2220-1 (9-73)
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system discussed above and utilized during the emission testing
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