23 July 1982
EPA-450/3-79-035b
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BENZENE EMISSIONS FROM ETHYLBENZENE/STYRENE
PLANTS—BACKGROUND INFORMATION FOR
PROMULGATED STANDARD
Emission Standards and Engineering Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
July 1982
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This report has been reviewed by the Emission Standards and Engineering
Division of the Office of Air Quality Planning and Standards, EPA, and
approved for publication. Mention of trade names or commercial products
is not intended to constitute endorsement or recommendation for use.
Copies of this report are available through the Library Services Office
(MD-35), U.S. Environmental Protection Agency, Research Triangle Park,
N.C. 27711, or from National Technical Information Services, 5285 Port
Royal Road, Springfield, Virginia 22161.
PUBLICATION NO. EPA-450/3-79-035b
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ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Final
Environmental Impact Statement
for Ethylbenzene/Styrene Plants
Prepared by:
Don R. Goodwin (Date)
Director, Emission Standards and Engineering Division
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
1. The promulgated national emission standard for hazardous air pollutants
will limit benzene emissions from all existing and new ethylbenzene/
styrene plants. The promulgated standards implement Section 112 of
the Clean Air Act and are based on the Administrator's determination
of June 8, 1977 (42 FR 29332), that benzene presents a significant
risk to human health as a result of air emissions from one or more
stationary source categories, and is therefore a hazardous air pollut-
ant. Plants in four States (Louisiana, Michigan, Pennsylvania, Texas)
will be affected by these standards.
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Transporta-
tion, Agriculture, Commerce, Interior, and Energy; the National Science
Foundation; the Council on Environmental Quality; members of the State
and Territorial Air Pollution Program Administrators; the Association
of Local Air Pollution Control Officials; EPA Regional Administrators;
and other interested parties.
3. For additional information contact:
Ms. Susan R. Wyatt
Standards Development Branch (MD-13)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
4. Copies of this document may be obtained from:
U.S. EPA Library (MD-35)
Research Triangle Park, NC 27711
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
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TABLE OF CONTENTS
Section Page
Li st of Tab! es vi
1 Summary 1-1
1.1 Summary of Changes Since Proposal 1-1
1.2 Summary of Impacts of the Promulgated Action 1-3
1.2.1 Environmental Impacts of the Promulgated
Action 1-3
1.2.2 Energy Impacts of the Promulgated Action 1-3
1.2.3 Cost and Economic Impacts of the Promulgated
Action 1-5
1.2.4 Health Impacts of the Promulgated Action 1-5
2 Summary of Public Comments 2-1
2.1 Selection of Ethylbenzene/Styrene Plants for
Regulation 2-1
2.1.1 Appropriateness of Regulating EB/S Plants
Under Section 112 2-1
2.1.2 Criteria for Unreasonableness of Residual
Risks 2-9
2.1.3 Cost-Effectiveness 2-10
2.2 Health and Environmental Impacts 2-12
2.2.1 Estimated Current Emissions and Risks 2-12
2.2.2 Superheater Control Efficiency 2-15
2.2.3 Control Device Efficiencies 2-16
2.3 Flare Control Efficiency 2-16
2.4 Cost and Economic Impacts 2-23
2.4.1 Compliance Costs 2-23
2.4.2 Executive Order 12291 2-28
2.5 Selection of the Basis of the Promulgated Standard 2-29
2.5.1 Emissions Floor, Current Control Devices,
Excess Emissions 2-29
2.6 Selection of Emissions Limit 2-50
2.6.1 Attainability of 5-ppmv Standard 2-50
2.6.2 Flue Gas Oxygen Limit 2-54
2.7 Reporting and Recordkeeping 2-55
2.7.1 Thirty-Day Startup/Shutdown Notification 2-55
2.7.2 Ambiguous Wording in Enforcement Section 2-55
2.7.3 Ninety-Day Compliance Requirement 2-57
2.7.4 Monitoring Requirements 2-58
2.7.5 Reporting and Recordkeeping Requirements 2-64
IV
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TABLE OF CONTENTS (CONTINUED)
Section Page
2.8 Exemption Requests 2-65
2.8.1 Exemption of Hydroperoxielation Process 2-65
2.8.2 Exemption of Pilot and Experimental
Facilities 2-67
2.9 Legal Issues 2-68
2.9.1 The Airborne Carcinogen Policy as Basis
for Rul emaki ng 2-68
Appendix A. Emissions Data and Environmental Impacts A-l
Appendix B. Methodology for Estimating Leukemia Incidence
and Maximum Lifetime Risk from Exposure
to Benzene Emissions from Ethylbenzene/Styrene
Process Vents B-l
Appendix C. Cost Data and Economic Impacts C-l
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LIST OF TABLES
Number Page
1-1 Summary of Environmental, Energy, Economic, and
Health Impacts of the Promulgated Action 1-4
2-1 List of Commenters on the Proposed National Emissions
Standard for Benzene Emissions from Ethylbenzene/Styrene
Plants 2-2
2-2 Plant-by-Plant Baseline Emission Rates for Benzene
in 1978 and 1981 .- 2-14
2-3 Flare Emissions Studies Complete as of May 1982 2-18
2-4 EPA and CMA Cost Estimates of Compliance with the
Proposed Standard on a Plant-by-plant Basis 2-25
2-5 Revised EPA Costs of Compliance with the Proposed
Standard on a Plant-by-plant Basis 2-27
2-6 Emissions Rates and Costs for Controlling Uncontrolled
Continuous Benzene Emissions Sources 2-33
2-7 Costs and Emissions Associated with Implementing
a 0.03-g/s Benzene Emissions Cutoff Rate (Emissions
Routed to Boilers) 2-35
2-8 Costs and Emissions Associated with Implementing
a 0.03-g/s Benzene Emissions Cutoff Rate (Emissions Routed
to Boilers or Smokeless Flares) 2-37
2-9 Capital and Annualized Costs, Total Emissions Reduced,
Cost Per Unit of Total Emissions Reduced, and Residual
Total Emissions Associated with Controlling Continuous
Process Emissions 2-38
2-10 Costs and Emissions Associated with Routing All
Uncontrolled Excess Emissions to Smokeless Flares 2-41
2-11 Industry-Wide Costs and Emissions for Each Regulatory
Alternative 2-48
2-12 Industry Reporting and Recordkeeping Burden Calculations 2-66
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1. SUMMARY
The U.S. Environmental Protection Agency (EPA), on December 18,
1980, proposed a national emission standard for hazardous air pollutants
(NESHAP) (45 FR 83448) that would regulate benzene emissions from
ethylbenzene/styrene (EB/S) plants under the authority of Section 112
of the Clean Air Act as amended. Public comments were requested on
the proposal in the Federal Register publication. Twelve comment
letters were received, and six interested parties testified at the
public hearing. These comments were made by EB/S manufacturers, the
Chemical Manufacturers Association (CMA), and State and Federal Govern-
ment offices. The comments that were submitted, along with the responses
to these comments, are summarized in this document. The summary of
comments and responses serve as the basis for the revisions that have
been made to the standard between proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
Several significant changes have been made to the standard since
proposal. The proposed standard would have required that benzene
emissions from all continuous process emission sources not exceed 5
parts per million by volume (ppmv) corrected to 3 percent oxygen over
a time-weighted average of 3 hours, based on the use of boilers* as
control devices. The proposed standard also would have required that
all excess emissions during startup, shutdown, and malfunction be
combusted by one or more smokeless flares at all times during startup,
shutdown, and malfunction. Based on public comments, the cost and
environmental impacts were reexamined and revised.
*The term "boiler" in this document includes boilers, process
heaters, superheaters, and reboilers.
1-1
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Upon revaluation of the impacts, the Administrator concluded
that the costs to meet the proposed standard were unreasonably high in
light of the emissions reduced for certain continuous vent streams.
These streams include those with relatively low benzene flow rates and
those already controlled by smokeless flares. Consequently, it was
concluded that it would be reasonable to require that only the vent
streams not already controlled by a smokeless flare as of the proposal
date (December 18, 1980) with the larger benzene flow rates (greater
than 0.03 g/s) meet the 5-ppmv limit. The standard has been revised
to include this requirement. The benzene flow rate would be measured
after all volatile organic compound (VOC) recovery equipment, before
the combustion device for all vent streams controlled by a combustion
device, and where the stream exits to the atmosphere for all streams
not controlled by a combustion device. Continued use of smokeless
flares to control continuous process emissions as of the proposal date
are allowed and are not required to limit emissions to 5 ppmv. The
standard does not require the flaring of excess emissions during
startup or shutdown. EB/S plants are restricted to 16 hours of excess
emissions during malfunction of process or control equipment. This
time period is reasonable for making repairs for the commonly occurring
causes of excess emissions due to malfunctions. However, EB/S owners
or operators, in lieu of this requirement, have the option of sending
excess emissions to a smokeless flare as at proposal.
The proposed standard would have required all owners or operators
to monitor benzene emissions using either a gas chromatograph and
three flow meters or a temperature and oxygen monitor and three flow
meters and to perform weekly visual checks to determine if all process
vents were being routed to the air pollution control device. Each
owner or operator also would have been required to report emissions in
excess of the numerical emissions limit within 10 days of each occur-
rence. Based on public comments, the Administrator concluded that the
monitoring, reporting, and recordkeeping costs could be reduced while
still obtaining the type of information needed to enforce the standard.
Consequently, the requirement for the monitoring of temperature and
1-2
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oxygen for sources that use boilers as air pollution control devices
has been deleted. The standard requires sources that use smokeless
flares to control continuous benzene emissions to monitor the flare's
pilot flame using a heat-sensing device. The monitoring requirements
for sources that do not use boilers or smokeless flares as air pollution
control devices remain unchanged. The oxygen level and firebox temper-
ature monitoring requirements have been deleted from the definition of
excess emissions, and the requirements of keeping records of temperature
and oxygen levels have been deleted. The proposed requirement for
30-day advance notice of anticipated startups and shutdowns has been
deleted. The proposed requirement for reporting within 10 days of
each occurrence of excess emissions has been revised to require report-
ing on a quarterly basis. The same information that would have been
required in a 10-day report is required for the quarterly report.
1.2 SUMMARY OF IMPACTS OF THE PROMULGATED ACTION
1.2.1 Environmental Impacts of the Promulgated Action
The promulgated standard will reduce benzene emissions from EB/S
process vents by about 60 percent, from approximately 370 Mg/yr
(410 ton/yr) to about 140 Mg/yr (150 ton/yr). The standard will
reduce total VOC emissions by about 60 percent, from approximately 980
Mg/yr (1,100 ton/yr) to approximately 450 Mg/yr (500 ton/yr).
Because the promulgated standard is based on the use of combustion
devices, no solid waste or wastewater impacts are expected. The
environmental impacts of the promulgated standard are summarized in
Table 1-1.
1.2.2 Energy Impacts of the Promulgated Action
Because the promulgated standard is based on the use of boilers
as the air pollution control device, no significant energy impacts are
expected. Due to heat recovery in the form of steam from the combustion
of waste gas, the control device on which the standard is based would
provide an energy savings of about 50 x 103 GJ/yr. The energy impacts
of the promulgated standard are summarized in Table 1-1.
1-3
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TABLE 1-1. SUMMARY OF ENVIRONMENTAL, ENERGY, ECONOMIC, AND HEALTH IMPACTS OF THE PROMULGATED ACTION
Air impact
Action
No standard
Promulgated standard:
Benzene emissions
Volatile organic compound
emissions
Emissions
reduced
(Mg/yr)
0
230
530
Residual
emissions
(Mg/yr)
370
140
450
Economic impact Health impact
Capital
costs
($l,000's)
0
456
456
Annual i zed
costs
($l,000's)
0
68
68
$/Mg
reduced Deaths/yr
0 0.0058-0.04
300 7.5 x 10~* to
5.2 x 10 3
130 7.5 x 10'4. to
5.1 x 10" J
Maximum
lifetime
risk Energy impact
1.7 x 10~4 to 0
1.1 x 10 J
3.0 x 10~!? to (50 x 103 GJ/yr)a
2.0 x 10 4
3.0 x 10~;?'to (50 x 103 GJ/yr)a
2.0 x 10~*
Energy savings based on recovery of all recoverable volatile organic compounds.
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1.2.3 Cost and Economic Impacts of the Promulgated Action
The capital investment required by the EB/S industry to comply
with the promulgated standard will be about $456,000, and industry-wide
total annualized costs will be about $68,000 by 1986. Styrene prices
could increase by a maximum of 0.07 percent. No significant interna-
tional trade or employment effects are expected. The economic impacts
of the promulgated standard are summarized in Table 1-1.
1.2.4 Health Impacts of the Promulgated Action
As a result of the emissions reduction estimated for the promul-
gated standard, the estimated leukemia incidence for the 2.7 million
people living within 20 kilometers (12.5 miles) of existing plants
-3 -2
will be reduced from a range of 5.8 x 10 to 4.0 x 10 cases per
-4 -3
year, to a range of 7.5 x 10 to 5.2 x 10 cases per year.
The maximum lifetime risk to the most exposed individuals due to
-4
process vent emissions will be reduced from a range of 1.7 x 10 to
_q _c -4
1.1 x 10 to a range of 3.0 x 10 to 2.0 x 10 . The health impacts
of the promulgated standard are summarized in Table 1-1. Due to the
assumptions which were made in calculating the maximum lifetime risk
and leukemia incidence numbers, there is considerable uncertainty
associated with them beyond the ranges presented here. They may
represent overestimates or underestimates. The uncertainties associ-
ated with the risk numbers are explained in Section 2.1.1.
1-5
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2. SUMMARY OF PUBLIC COMMENTS
The commenters, their affiliations, and docket numbers are listed
in Table 2-1. Twelve letters contained comments and six people testi-
fied at the public hearing on the proposed standard and its background
information document (BID). The significant comments have been combined
into the following nine major areas:
1. Selection of Ethylbenzene/Styrene (EB/S) Plants for Regulation
2. Health and Environmental Impacts
3. Flare Control Efficiency
4. Cost and Economic Impacts
5. Selection of the Basis of the Promulgated Standard
6. Selection of Emissions Limit
7. Reporting and Recordkeeping
8. Exemption Requests
9. Legal Issues
The comments, issues, and their responses are discussed in the
following subsections of this chapter. Changes to the standard are
summarized in Subsection 1.1. Responses to comments on the health
effects, listing, and regulation of benzene are contained in Responses
to Public Comments on EPA's Listing of Benzene Under Section 112 and
Relevant Procedures for the Regulation of Hazardous Air Pollutants.
EPA-450/5-82-003.
2.1 SELECTION OF ETHYLBENZENE/STYRENE PLANTS FOR REGULATION
2.1.1 Appropriateness of Regulating EB/S Plants Under Section 112
Comment: Several commenters stated that EB/S plants do not
present the magnitude of risk to health for which a national emission
2-1
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED NATIONAL
EMISSIONS STANDARD FOR BENZENE EMISSIONS
FROM EB/S PLANTS
Commenter3 Affiliation
IV-F-1 Public Hearing Transcript
IV-F-2 Chemical Manufacturers Association (CMA)
IV-F-3b Oxirane Chemical/ARCO Chemical
IV-F-4b Dow Chemical
IV-F-5 Applied Meteorology, Inc.
IV-F-6b Cos-Mar
IV-D-1 Wilmer, Cutler, and Pickering (CMA)
IV-D-2 Dow Chemical, U.S.A.
IV-D-3 Federal Energy Regulatory Commission (FERC)
IV-D-4 Department of Environmental Regulation, State of
Florida
IV-D-5 Public Health Service, Department of Health and Human
Services
IV-D-6 Wilmer, Cutler, and Pickering (CMA)
IV-D-7 Air Products and Chemicals, Inc.
IV-D-8 Wilmer, Cutler, and Pickering (CMA)
IV-D-9 American Petroleum Institute
IV-D-10 Wilmer, Cutler, and Pickering (CMA)
IV-D-11 Dow Chemical, U.S.A.
IV-D-12 Gulf Oil Chemicals
aThese designators represent docket entry numbers for Docket Number
A-79-49. These docket entries are available for public inspection
at:
Central Docket Section
West Tower Lobby, Gallery 1
Waterside Mall
401 M Street, S.W.
Washington, DC 20460
bThese references are transcripts submitted by commenters at the
public hearing and are essentially identical to their oral testimony.
2-2
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standard for hazardous air pollutants (NESHAP) is appropriate. Section
112 of the Clean Air Act defines a hazardous air pollutant as "an air
pollutant to which no ambient air quality regulation is applicable and
which, in the judgment of the Administrator, causes or contributes to,
air pollution which may reasonably be anticipated to result in an
increase in mortality or an increase in serious irreversible or incapac-
itating reversible illness." Currently, ambient air quality standards
for ozone regulate benzene emissions. Also, the risk from benzene
emissions from stationary sources is far below the threshold level for
induction of benzene-related leukemia. Therefore, emissions from EB/S
plants do not present the kind of health risk that Congress foresaw
when it enacted Section 112 to deal with the limited number of very
hazardous pollutants. Furthermore, current control technologies and
standards for VOC emissions are generally suitable for limiting benzene
emissions (IV-F-1; IV-F-2; IV-F-5; IV-D-10).
Response: On June 8, 1977, the Administrator listed benzene as a
hazardous air pollutant under Section 112 of the Clean Air Act, based
on strong evidence that induction of leukemia is causally related to
benzene exposure (42 FR 29332). This relationship is based on findings
of elevated leukemia incidence among workers with histories of occupa-
tional benzene exposure. Although ambient benzene levels are charac-
teristically much lower than are those in the work place and leukemia
risks would be expected to be correspondingly smaller, much larger
populations are exposed. Because no known threshold exists for benzene's
carcinogenic effects, EPA concluded that there is reason to believe
that populations residing near stationary benzene sources face an
increased risk of leukemia as a result of exposure to benzene emitted
from those sources.
Section 112 allows benzene deli sting only if it is found, on the
basis of information contained in public comment, that benzene clearly
is not a hazardous air pollutant. During the public comment period,
while acknowledging the causal relationship between benzene and leukemia
at high exposure levels, commenters pointed to the inconclusive evidence
that benzene is a leukemogen at ambient levels but offered no evidence
to the contrary. On the grounds that the commenters supplied no new
2-3
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information demonstrating that benzene clearly is not a hazardous air
pollutant, there is no basis for delisting. Comments concerning the
listing of benzene are addressed more fully in Response to Public
Comments on EPA's Listing of Benzene under Section 112 and Relevant
Procedures for the Regulation of Hazardous Air Pollutants, EPA-450/5-
82-003.
At the time of the proposed standard, total EB/S industry-wide
process benzene emissions were estimated to be 2,100 Mg/yr based on
100 percent production capacity and actual plant-by-plant control
levels. (After publication of the proposal preamble (45 FR 83448),
this number was revised to 2,400 Mg/yr because of miscalculations in
the industry-wide total.) It was estimated that 2.5 million people
live within 20 kilometers of EB/S plants. As a result of exposure to
these benzene concentrations, maximum lifetime risk was estimated to
-4 -3
be within a range of 6.2 x 10 to 4.4 x 10 . In addition, a range
of leukemia incidence of 0.027 to 0.20 cases per year within this
population due to benzene exposure from EB/S plants was estimated.
Maximum lifetime risk is the probability of someone within the assumed
exposed population contracting leukemia if he or she were exposed to
the highest maximum annual average benzene concentration during an
entire lifetime (70 years).
The assumptions and procedures discussed above for extrapolation
and for exposure estimates are subject to considerable uncertainty.
The ranges of maximum lifetime risk and leukemia incidence presented
here represent the uncertainty of estimates concerning benzene concen-
trations to which workers were exposed in the occupational studies of
Infante, Aksoy, and Ott that served as the basis for developing the
benzene unit risk factor (II-A-8). Ranges are based on a 95-percent
confidence interval that assumes benzene concentrations to which the
workers in the studies were exposed are within a factor of two.
Quantitative risk estimates at ambient concentrations involve an
analysis of the effects of the substance in high-dose epidemiological
or animal studies and extrapolation of these high-dose results to
relevant human exposure routes at low doses. The mathematical models
2-4
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used for such extrapolations are based on observed dose-response
relationships for carcinogens and assumptions about such relationships
as the dose approaches very low levels or zero.
The risks to public health from a carcinogen's emissions may be
estimated when the dose-response relationship obtained from this
carcinogenicity strength calculation is combined with an analysis of
the extent of population exposure to the substance through the ambient
air. Exposure in this context is a function of both a substance's
concentration and the length of time the concentration is encountered.
Exposure analyses are based on air quality models, available estimates
of emissions from EB/S plants, and approximations of population distri-
butions near their sources.
The air quality models used estimated exposures of up to 20 kilo-
meters, and population and growth statistics were examined. Along with
the existing carcinogenic strength determinations, the information
collected was used to estimate the degree of risk to individuals and
the range of increased cancer incidence expected from ambient air
exposures associated with EB/S plants at various possible emissions
levels.
The decision to employ estimates of carcinogenic risks despite
their imprecision rests on the belief that, although they are subject
to considerable uncertainties, current analytical models and techniques
can, with due consideration of the uncertainties, provide useful
estimates of relative carcinogenic strength and of the probable general
ranges of excess cancer incidence and individual risks. This view has
been supported by the National Academy of Sciences,* the National
Cancer Advisory Board,t and others.f
*Drinking Water and Health. Part 1, Chapters 1-5, Draft, National
Research Council, National Academy of Sciences, Washington, D.C. (1977)
•{•"General Criteria for Assessing the Evidence for Carcinogenicity
of Chemical Substances," Report of the Subcommittee on Environmental
Carcinogenesis, National Cancer Advisory Board, Journal of the National
Cancer Institute, 58:2, February 1977.
fHoel, David G., et al. "Estimation of Risks of Irreversible,
Delayed Toxicity," Journal of Toxicology and Environmental Health,
1:133-151, 1975.
2-5
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Several other uncertainties are associated with the estimated
health numbers not quantified in these ranges. Maximum lifetime risk
and death numbers were calculated based on a no-threshold linear
extrapolation of leukemia risk associated with a presumably healthy
white male cohort of workers from benzene concentrations in the parts-
per-million range to the general population, which includes men,
women, children, nonwhites, the aged, and the unhealthy who are exposed
to concentrations in parts per billion. These widely diverse population
segments may or may not have differing susceptibility to leukemia than
do workers in the studies. In addition, the exposed population is
assumed to be immobile, remaining at the same location 24 hours per
day, 365 days per year, for a lifetime (70 years). This assumption is
counterbalanced to some extent (at least in the calculation of
incidence) by the assumption that no one moves into the exposure area
either as a permanent resident or as a transient. Assumptions that
must be made to estimate ambient concentrations by dispersion modeling
and exposed populations by census tract also introduce uncertainties
into the risk estimates. Modeled ambient benzene concentrations
depend upon (1) plant configuration, which is difficult to determine
for more than a few plants; (2) emission point characteristics, which
can be different from plant to plant and are difficult to obtain for
more than a few plants; (3) emission rates, which may vary over time
and from plant to plant; and (4) meteorology, which is seldom available
for a specific plant. The particular dispersion modeling used can
also influence the numbers. The best model to use (ISC) is usually
too resource intensive for modeling a large number of sources. Less
complex models introduce further uncertainty through a greater number
of generalizing assumptions. Dispersion models also assume that the
terrain in the vicinity of the source is flat. For sources located in
complex terrain, the maximum annual concentration could be under-
estimated by several fold due to this assumption. Furthermore, death
from leukemia is not the only benzene health effect possible. Other
health effects, such as aplastic anemia and chromosomal aberrations,
are not as easily quantifiable and are not reflected in the risk
2-6
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estimates. Although these other health effects have been observed at
occupational levels, it is not clear if they occur due to ambient
benzene exposure levels. Additionally, benefits to the general popu-
lation that would accrue from the indirect control of other VOC
emissions from benzene sources in the process of controlling benzene
emissions also are not included in the estimates. Finally, these
estimates do not include the cumulative or synergistic effects of
concurrent exposure to benzene and other substances. As a result of
these uncertainties, the leukemia incidence and the maximum lifetime
risk calculated around EB/S plants could be overestimated. More
importantly, however, they could just as likely be underestimated for
the same reasons.
Based on the magnitude of benzene exposures from this source
category, the resulting estimated maximum individual risks and leukemia
incidence in the exposed population, and consideration of the uncer-
tainties of quantitative risk assessment, the Administrator determined
at proposal that benzene emissions from EB/S plants pose a significant
cancer risk.
2-6A
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After noting the status of changes in the EB/S industry since
proposal (see Response 2.2.1 of this document), EPA reassessed whether
EB/S process vents remain a significant source category.
While EB/S plants are neither the sole cause of benzene emissions
to the atmosphere nor the largest source category emitter, they contri-
bute significantly to nationwide benzene emissions. In the absence of
a standard, the industry would be emitting about 370 Mg/yr (410 ton/yr)
from all process vents based on actual 1980 production and current
control (IV-D-13). It must be noted that uncontrolled vents within
the industry are responsible for the majority of the current emissions
rate that could be controlled at reasonable cost.
An estimated 2.7 million people live within 20 kilometers of
benzene-emitting EB/S plants and, thus, are exposed to higher levels
of benzene from EB/S plants than the general population is. Because
no known threshold exists for benzene's carcinogenic effects, these
people run a greater risk of contracting leukemia due to that exposure.
Using the revised emissions estimates, EPA recalculated the
maximum lifetime risk and leukemia incidence numbers. In the absence
of a standard, the revised estimated maximum lifetime risk would range
-4 -3
from 1.7 x 10 to 1.1 x 10 to the most exposed individuals. Addi-
-3 -2
tionally, a range of 5.8 x 10 to 4.0 x 10 cases per year due to
benzene emissions from EB/S process vents is estimated (see Appendix B).
In examining these numbers, EPA considered their limited value. Because
of their uncertainties, these numbers cannot be the sole factor con-
sidered in a determination of significant risks.
Thus, based on the amount of benzene currently emitted from the
EB/S process vents, the human carcinogenicity of benzene, the extent
of exposure to the general population, and uncertainties associated
with the risk estimates, EPA concluded that EB/S process vents continue
to pose a significant carcinogenic risk to the general public.
Several other factors were also considered in the Administrator's
determination. First, if no standard were promulgated, new sources
could remain uncontrolled. Such construction could increase maximum
lifetime risk of leukemia and would increase the estimated incidence of
2-7
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leukemia. Second, if no standard were promulgated, five plants would
contribute approximately 280 Mg/yr (310 ton/yr) to this total: American
Hoechst, Louisiana, 120 Mg/yr (130 ton/yr); ARCO, Pennsylvania, 40 Mg/yr
(44 ton/yr); Dow Chemical, Texas, 40 Mg/yr (44 ton/yr); Dow Chemical,
Michigan, 60 Mg/yr (66 ton/yr); and Sun Oil, Texas, 20 Mg/yr (22 ton/yr).
First, of the 280 Mg/yr (310 ton/yr), approximately 240 Mg/yr (260 ton/yr)
represent benzene emissions not routed to a control device and, therefore,
considered uncontrolled. Second, as previously unused capacity comes
on line, emissions would increase, especially for the uncontrolled
vents. Third, a nationwide benzene standard for EB/S plants would
ensure that existing sources control their emissions on a continuing
basis. Of the States where EB/S plants currently are located, only
Texas has a VOC regulation that applies to EB/S plants (IV-J-4).
Fourth, although plants have already taken steps that would meet the
proposed standard, thereby reducing the health impact of a promulgated
standard from levels projected at proposal, cost and economic impacts
of a promulgated standard would likewise be reduced. Plants that have
taken steps voluntarily to reduce emissions to the level of the standard
consequently would bear little control equipment costs as a result of
the standard. Fifth, all EB/S plants currently have in-place emissions
control devices that could be used to reduce a significant portion of
the uncontrolled benzene emissions at a relatively low cost.
Congress writes legislation such as the Clean Air Act and implicitly
sets priorities for Government regulation of risks. In setting these
priorities, Congress has found that it is not feasible to regulate
every risk activity, technology, or event, but that it is desirable to
regulate risks that can be reasonably reduced. Political processes
direct priorities towards risks most repugnant to the public. Ultimately,
Government agencies, through Congressional actions, are given regulatory
authority; but each such agency is likely to interpret its authority
differently, thus addressing risk differently.
Accordingly, EPA is required by Section 112 of the Clean Air Act
to identify and regulate hazardous air pollutants. As described
previously in this response, EPA has determined, based on risk and
2-8
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other factors, that benzene emissions from EB/S process vents represent
a significant source of benzene.
2.1.2 Criteria for Unreasonableness of Residual Risks
Comment: EB/S plants, relative to other stationary sources of
benzene emissions, present an insignificant risk to the population.
The risk EPA found would be "not unreasonable" after implementation of
a national emission standard for benzene emissions from the maleic
anhydride industry is almost eight times greater than the current risk
from EB/S process vents. Also, leukemia risk from benzene emissions
from stationary sources is insignificant because 80 percent of benzene
emissions are derived from mobile sources not subject to Section 112
regulation. Therefore, control of EB/S plants represents an inconsis-
tency in EPA's application of risk assessments to the determination of
acceptable and unacceptable risks in current proposals for the control
of benzene (IV-F-1; IV-F-2; IV-F-3; IV-F-6; IV-D-7; IV-D-10; IV-D-12).
Response: The level of residual risk found to be not unreasonable
in selection of the level of a standard can be explained best when the
standard-setting-procedure followed by EPA is summarized. The Admin-
istrator first identified the best demonstrated technology (BDT),
considering environmental, economic, and energy impacts, to control
benzene emissions from maleic anhydride plants (and also EB/S plants)
from the various regulatory alternatives considered (see Response
2.5.1). The Administrator then examined the residual risks due to
benzene emissions remaining after application of BDT to determine
whether or not they are unreasonable in view of the risk reduction
that would be gained by requiring a control level beyond BDT and the
associated cost increase.
Therefore, the determination of whether or not residual risks are
unreasonable is contingent upon the incremental costs associated with
additional emissions reductions. The risk numbers cannot be viewed by
themselves in absolute terms to determine "unreasonableness," due to
the great uncertainty in the numbers, and, thus, are not an appropriate
measure of "unreasonableness" among source categories. In addition,
different source categories can be controlled differently; a control
2-9
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strategy appropriate for one source category may not be appropriate
for another due to technological differences or control costs. There-
fore, because costs are an integral part in a determination of
unreasonable risk, what is "not unreasonable" for one source category
is not necessarily "not unreasonable" for another source category,
even though the risk numbers alone are the same or less. EPA has
followed this procedure of comparing the costs and risks of BDT with a
more stringent alternative consistently to evaluate the reasonableness
of the risks associated with BDT.
As pointed out by the commenter, mobile sources cannot be regulated
under Section 112, and, consequently, no determination has been made
concerning the unreasonableness of risk due to exposure to benzene
from those sources. However, even if mobile sources could be regulated
under Section 112, catalytic converters already being installed seem
to be an effective control technology. In addition, the commenter
incorrectly assumes that relative emissions determine significance.
2.1.3 Cost Effectiveness
Comment: The proposed standard would have only a minimal impact
on emissions and virtually no effect on mortality and risk according
to three commenters. Assuming the Carcinogen Assessment Group (CAG)
risk factor, the standard's cost effectiveness would be $500 million
per mortality avoided. Assuming the Lamm risk factor, the cost per
mortality avoided would be more than $5 billion (IV-F-1, IV-F-2;
IV-D-10).
Response: Changes within the EB/S industry since the original
analysis of the industry have affected costs associated with regu-
lating EB/S benzene emissions. The original analysis of the EB/S
industry was based on 1978 cost data. CMA supplied cost data to EPA
that reflected changes within the EB/S industry between 1978 and 1981
(IV-D-13). The new cost data results, as prepared by EPA, have been
applied to new regulatory alternatives, discussed in detail in
Response 2.5.1 of this document.
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In short, from these regulatory alternatives, the Administrator
has determined that any existing uncontrolled process emissions source*
with a benzene emissions rate greater than 0.03 g/s be required to
reduce benzene emissions from the source in question to 5 ppmv corrected
to 3 percent oxygen on a dry basis over a time-weighted average of
3 hours.
The promulgated standard will reduce benzene and other VOC
emissions from the five plants in the industry with major uncontrolled
process vents. The promulgated standard will reduce total benzene
emissions from 370 Mg/yr (410 ton/yr) to 140 Mg/yr (150 ton/yr). The
total industry-wide capital and annualized costs required to comply
with the promulgated standard will be $456,000 and $68,000, respectively.
The industry-wide cost per megagram of -benzene reduced for the promul-
gated standard will be $300. For individual plants, the cost per
megagram of benzene reduced ranges from a savings of $20 to a cost of
$1,400. The promulgated standard will reduce total VOC emissions from
980 Mg/yr (1,100 ton/yr) to 450 Mg/yr (500 ton/yr) at an industry-wide
cost per megagram of total VOC emissions reduced of $130. Annualized
costs are divided by annual emissions reduced to determine the cost
per unit of emissions reduction. The promulgated standard will reduce
-4 -3
estimated maximum lifetime risk from a range of 1.7 x 10 to 1.1 x 10
-5 -4
to a range of 3.0 x 10 J to 2.0 x 10 , and the estimated incidence of
-3 -?
leukemia cases per year from a range of 5.8 x 10 to 4.0 x 10 to a
range of 7.5 x 10"4 to 5.2 x lo"3.
In view of the large uncertainties present in any quantitative
estimate of cancer risk, EPA has been reluctant to rely on such esti-
mates as the principal basis for determining appropriate control
levels for benzene sources. A more detailed discussion of this concern
is contained in Response to Public Comments on EPA's Listing of Benzene
under Section 112 and Relevant Procedures for the Regulation of Hazardous
Air Pollutants, EPA-450/5-82-003.
*An uncontrolled process emissions source is one currently not routed
to a boiler or to an existing smokeless flare.
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The cost-effectiveness calculations submitted by the commenter
fall prey to the same uncertainties when the risk estimates are incor-
porated. For this reason, EPA does not consider this form of analysis
a valid indicator of the benefits derived from the standard.
Health impacts associated with the selection of the standard are
used, not in absolute terms but in relative terms, only in conjunction
with costs in comparing BDT with a more stringent alternative to
determine whether or not residual risks after BDT are unreasonable. A
more meaningful and accurate measure of "cost effectiveness" is the
cost per unit emission reduction, which in this case is $300/Mg.
The Administrator considers this average cost (which ranges from a
savings of $20/Mg to a cost of $l,400/Mg) and the cost associated with
controlling the most expensive plant not unreasonable either compared
to other benzene standards or to the per-megagram costs of controlling
VOC's as oxidant precursors.
2.2 HEALTH AND ENVIRONMENTAL IMPACTS
2.2.1 Estimated Current Emissions and Risks
Comment: According to several commenters, CMA used (1) plant-specific
emissions data, (2) local meteorological data, (3) refined population
data, (4) a ring-sector approach, which accounts for directional
variability in population densities, and (5) the Lamm risk factor to
estimate the current risk from benzene emissions from EB/S process
vents to be "the same as the 0.00034 risk EPA calculated would exist if
the proposed standard had been adopted." Also, EPA has overstated
current emissions by a factor of three after correcting for capacity
and existing controls. Therefore, EPA has overestimated both individual
and industry-wide emissions; population extent and distribution; and
as a consequence, risk from EB/S benzene emissions (IV-F-1, IV-F-2;
IV-F-5; IV-F-6; IV-D-10; IV-D-12).
Response: At proposal, environmental impacts were calculated
based on data industry supplied from 1972 to 1978 in response to EPA
"114" letters (information requests provided for by Section 114 of the
Clean Air Act). The responses to the "114" letters provided detailed
information from the entire industry. The data submitted were compiled
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to develop a "typical" EB/S plant that was used to determine impacts.
While this model plant did not conform to any particular plant in the
industry, it was considered representative for purposes of character-
izing the baseline. EPA estimated total nationwide benzene emissions
from all EB/S process vents to be 2,100 Mg/yr based on 1978 control
levels and actual capacity utilization of nameplate production rates.
After publication in the proposal preamble (45 FR 83448), this number
was revised to 2,400 Mg/yr to correct miscalculations in the industry-
wide total (see Table 2-2).
The industrial source complex (ISC) dispersion model was used to
estimate annual average benzene concentrations for distances and
directions out to 20 kilometers from the model plant. Houston
meteorological data, which best represented weather conditions for
most EB/S plants, were used in the dispersion model. Each actual
plant was "modeled" by scaling the model plant's emissions to the
actual plant's emissions based on known or assumed production capacity
and control level. The population residing within 20 kilometers of
each EB/S plant was determined from the 1970 Bureau of the Census
Master Enumeration District (MED) List. Each plant site was located
by latitude and longitude on a grid system having grids of approximately
10 square kilometers. The population was determined from the MED List
for each grid block within 20 kilometers of each plant site. Each
plant's populations were then coupled with the scaled concentrations
derived from the dispersion modeling at the respective distance
intervals and the risk factor developed by CAG for the beyond-BAT
analysis and to describe the standard's health impact. These numbers
did not play a role in selection of BDT.
After proposal, the industry supplied detailed data regarding
current controls and emissions (IV-D-13). EPA subsequently reanalyzed
and revised the baseline environmental impacts on a plant-specific
basis using industry's information. Based on the more recent informa-
tion and revised analysis, current nationwide benzene emissions from
EB/S process vents are estimated to be about 370 Mg/yr (see Table 2-2)
(see Appendix A).
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TABLE 2-2. PLANT-BY-PLANT BASELINE EMISSIONS RATES
FOR BENZENE IN 1978 and 1981
(Mg/yr)
Plant/location
American Hoechst
Baton Rouge, LA
Bayport, TX
Amoco
Texas City, TX
ARCO
Port Arthur, TX
Kobuta, PA
Cos-Mar, Inc.
Carville, LA
Dow Chemical , USA
Midland, MI
Freeport, TX
El Paso Products
Odessa, TX
Gulf Oil
Donaldsville, LA
Monsanto Company
Texas City, TX
Oxirane
Channelview, TX
Sun Oil , Inc.
Corpus Christi , TX
U.S. Steel
Houston, TX
Subtotal
Plus H2 separation
Plus excess emissions
TOTAL
1978
Total
process
emissions
320
0
26
300
70
420
70
180
16
180
320
290
15
1
2,208
110
113
2,431
1981
Total
process .
emissions
117
6
15
0
40
20
57
38
5
19
4
6
12
1
340
-
-
TOTAL 373
Excess
emissions
2
2
1
0
2
1
1
1
1
1
16
0
5
-------
The ISC dispersion model was used again to compute annual average
concentrations at various distances and directions from the plant.
However, each plant was modeled individually according to local meteoro-
logical data. Geographical coordinates supplied by the plant were
then used to match concentrations with corresponding populations on
both a distance and directional basis from the plant. Additionally,
the CAG unit risk factor was revised based on comments. A more
detailed discussion of this methodology can be found in Appendix B of
this document, which describes the methodology used to calculate
health impact.
2.2.2 Superheater Control Efficiency
Comment: One commenter thought EPA used control equipment
efficiency percentages based on a worst-case approach. The worst-case
approach for high-temperature superheaters provides a benzene destruc-
tion efficiency level of 99 percent. The commenter claimed that
actual emissions after application of superheaters were two orders of
magnitude lower than EPA had calculated using the 99-percent benzene
destruction level (IV-F-1; IV-F-2).
Response: When impacts for the various regulatory alternatives
considered were determined, control efficiencies had to be assumed
based on previous test data. For the alternative based on the use of
a boiler or superheater, which eventually was selected as the basis
for the proposed standard, EPA developed impacts based on 99 percent
emissions reduction, considering emissions test data from the El Paso
Products plant in Odessa, Texas (II-A-13); the Amoco plant in Texas
City, Texas (II-A-32); and the U.S. Steel plant in Houston, Texas
(II-A-33).
The Amoco test results indicated benzene destruction efficiency
of 93.4 percent on the average. However, these results are not valid
due to various sampling and analytical problems. The El Paso Products
test results indicate benzene removal efficiency by superheaters to
average 99.9 percent. The U.S. Steel test result indicates a single
burner superheater benzene destruction efficiency of 99.6 percent on
the average. For a detailed discussion of emissions testing, see
Response 2.6.1.
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The data indicate a range of efficiencies above 99 percent, and
no one efficiency appeared more appropriate to assume than another;
thus, the lower end of the efficiency range was selected to assume for
calculating impacts and, in that sense, is "worst case." However,
99 percent efficiency is believed to be a reasonable, conservative
estimate for calculating impacts.
It is important to note that although superheaters have been
shown to attain benzene destruction efficiencies greater than 99 percent,
the standard of 5 ppmv, which roughly equates to 99 percent reduction,
does not require greater than 99 percent. Because the standard is
based on 99 percent benzene destruction efficiency, it is appropriate
to calculate impacts on what is required of superheaters in the EB/S
industry.
2.2.3 Control Device Efficiencies
Comment: A commenter stated that EPA, in its regulatory alternatives
analysis and current emissions calculations, was incorrect to assume
that all control devices of a particular type have the same efficiency.
Assigning all control devices of a particular type a worst-case control
efficiency resulted in an overestimation of current emissions from
EB/S plants (IV-F-1; IV-F-2).
Response: The removal efficiency assigned to a particular type
of control device assumes that type of control device, when properly
operated and maintained, can achieve at least the assigned efficiency.
These efficiencies are determined from test data on the streams con-
sidered for control, from test data on similar streams in other
industries, or from engineering judgment. As discussed in the previous
response, EPA recognizes that efficiencies of like control devices can
fluctuate within a range and, in fact, actual emissions could be less
than assumed; but it is believed that assuming an efficiency at the
lower end of the range provides a reasonable, conservative estimate
for calculating impacts.
2.3 FLARE CONTROL EFFICIENCY
Comment: Three commenters maintained that in the proposed standard,
EPA avoids specifying the type of control equipment to be used to
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limit continuous process emissions. However, the proposed standard
was based on the control level attainable when emissions are combusted
in a boiler or process heater, and if a plant chooses to control
emissions by a method other than combustion in a boiler or process
heater, it is required to monitor emissions continuously using a gas
chromatograph and flame ionization detector. Because proven technology
does not exist for measuring emissions continuously from a flare, the
net effect of these requirements is to preclude the use of flares to
control continuous process emissions, either as the sole control
device or in conjunction with absorbers or condensers. Hydroscience
(now IT Enviroscience) (II-B-23) estimated flare efficiency to range
from 75 to 98 percent. Small flares (2 to 10 inches in diameter) may
have over 99 percent efficiency under optimum conditions. Siege! in
Germany tested 1,300 samples to achieve 99 percent efficiency 100 per-
cent of the time. The Battelle study for EPA demonstrated 95 percent
efficiency. Therefore, EPA's decision to preclude the use of flares
is arbitrary, capricious, and cannot be sustained (IV-F-1; IV-F-3;
IV-D-10.)
Response: At proposal, no conclusive data were available on
flare destruction efficiency. Calculations and limited test data
showed benzene destruction efficiencies ranging from 60 to 99 percent.
These studies included engineering evaluations by Hydroscience, Inc.,
(II-B-23), calculations based on residence time, limited and unverified
test data on a flare burning methane from a flare manufacturer (II-I-29),
and EPA in-house estimates. For the purposes of determining impacts,
a 60-percent flare efficiency was chosen to enable assessment of
"worst-case" emissions from flaring based on limited data and vent
stream conditions within the EB/S industry.
Since proposal, more information on flare design and destruction
efficiency has become available. In response, EPA has examined recent
flare studies to develop a more accurate destruction efficiency estimate
for calculating emissions impacts from EB/S smokeless flares. The
number of flare studies is limited and no data specifically address
conditions present within EB/S vent streams. Table 2-3 summarizes
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TABLE 2-3. FLARE EMISSIONS STUDIES COMPLETE AS OF MAY 1982
ro
i
oo
Investigator
Palmer (1972)
Lee and Whipple
(1981)
Siegel (1980)
Howes et al. (1981)
Source: Payne, R. , D
Flares Used
Sponsor
E. I. du Pont
Union Carbide
Ph.D. dissertation
University of Karl
EPA
. Joseph, J. Lee, C.
Flare tip design
13 mm diameter
Discrete holes in
51-mm diameter capacity
Commercial design
sruhe (0.7-m diameter steam)
Commercial design
(152-mm diameter air
assist)
Commercial design H.P.
(3 tips @ 102 mm
diameter)
Flared gas
Ethyl ene
Propane
s 50% H2
plus light
hydrocarbons
Propane
Natural gas
Throughput
(GJ/hr)
0.4 - 2.2
0.3
52 - 188
46
30 (per tip)
Flare
efficiency
(X)
> 97.8
96 - 100
97 - > 99
91 - 100
> 99
McKinnon, and J. Pohl. Evaluation of the Efficiency of Industrial
to Destroy Waste Gases, Phase I Interim Report — Experimental Design,
Draft. January 1982.
EPA Contract No. 68-02-3661.
-------
four flare studies that provided information on flare gas composition,
flow rate, and destruction efficiency. Each study can be found in
complete form in the docket (IV-D-17; IV-J-2; IV-J-3; IV-J-7). The
following discussion reviews the experimental flare systems and operat-
ing conditions used in these studies.
Siegel (1980) made the only comprehensive study of a commercial
flare system. He studied burning of refinery gas on a commercial
flare head (type FS-6-antipollutant) manufactured by Flaregas Company.
Table 2-3 shows the compositions of the flare gases used, which con-
sisted primarily of hydrogen (45.4 to 69.3 percent by volume) and the
light paraffins (methane to butane). Traces of H2S were also present
in some runs. The flare tested burned from 130 to 2,900 kg/hr of gas.
Hence, the maximum heat release rate was approximately 248 GJ/hr (235 x
106 Btu/hr). However, most of the experiments were conducted between
52 and 188 GJ/hr (49 x lo6 and 178 x 106 Btu/hr).
Palmer (1972) experimented with a 13-millimeter inside diameter
flare head, the tip of which was located 1.2 meter from the ground.
Ethylene was flared at 15 to 76 m/s at the exit, with a heat release
rate of 0.4 to 2.2 GJ/hr (0.4 x 106 to 2.1 x 106 Btu/hr). Helium was
added to the ethylene as a tracer at 1 to 3 volume percent, and the
effect of steam injection was investigated in some experiments.
Lee and Whipple (1981) studied a bench-scale propane flare. The
flare head was 51 millimeters in diameter with one 21-millimeter
center hole surrounded by two rings of sixteen 3.2-millimeter holes
and two rings of sixteen 4.8-millimeter holes. This configuration had
an open area of 57.1 percent. Propane at 3.7 rnVhr was doped with
0.34 rnVhr of helium and fired through the flare head. The velocity
through the head was approximately 0.9 m/s and the heating rate was
0.3 GJ/hr (0.3 x 106 Btu/hr). Effects of steam and crosswind were not
investigated in this study.
Howes et al. studied flares produced on two commercial flare
heads in John Zink's pilot-scale facility. The commercial flare heads
were an LH® air-assisted head and a Linear Relief Gas Oxidizer (LRGO)
head manufactured by John Zink Company. Because both designs are
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proprietary, detailed configurations of the flare heads are unavailable.
®
The LH flare burned 1,040 kg/hr of commercial propane on a 152-millimeter
gas pipe diameter. The exit gas velocity based on the pipe diameter
was 8.2 m/s and the firing rate was 46 GJ/hr (44 x 106 Btu/hr). The
LRGO flare consisted of three burner heads 0.9 meter apart. The three
burners combined fired 1,900 kg/hr of natural gas, which corresponds
to a firing rate of 88.2 GJ/hr (83.7 x 106 Btu/hr). Steam was not
(R)
used for either flare, but the LH flare head was assisted by a forced
draft fan in some trials.
These studies indicate that destruction efficiencies of flares
can range from 91 to 100 percent, given the right combination of flare
gas composition, gas flow rate, flare head design, and weather (which
affects mixing of exit gas and air). However, there are several
reasons why this high destruction efficiency may not be applicable to
flares combusting other gases in plant environments, and three of the
more important are listed below. Although the exact effect on flare
efficiency of these factors is unknown, all of the (considerable)
differences between the test flares and gases and plant flares and
gases would make actual plant efficiency less than test efficiency.
First, all of the test flares were small and the flare gas flow
rates were small. Two of the flares tested were bench scale (Palmer,
and Lee and Whipple) and two were small plant-sized flares (Siegel and
Howes). The largest flare tested (Siegel) burned less than 3,200 kg/hr
of gas. The flares in operation in the EB/S industry are large-diameter
flares designed to handle emergency releases in addition to controlling
low-volume, continuous EB/S gases. As flares become larger, it is
more difficult to move the oxygen (air) required to the combustion
area. Although some part of the air required can be moved into the
combustion zone by steam (or other) injection, most of the air required
for the large flares is induced into the flame through aspiration or
thermal draft effects. As the amount of gas combusted increases, the
air-flame interface does not increase as rapidly as the amount of gas
combusted and aspiration, and thermal draft mixing becomes relatively
less effective.
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Second, the plant-sized flares used in the Siege! and Howes tests
were modern and well maintained. All three of the flares used in
these two tests are of state-of-the-art design and operated in a way
approved by the flare manufacturer. Two of the flares actually were
operated by the manufacturer at the manufacturer's test site (the
Howes test at John Zink).
All three flares were maintained perfectly during the test periods.
In actual EB/S plant use, some flares may be operated long periods
without maintenance, with missing flame retention rings, with burned-off
steam injectors, or with holes in the flare pipe below the flare tip.
A damaged flare tip will mix and combust less efficiently or may
permit some of the gas to bypass the flame completely.
Finally, the two most meaningful tests (Siegel and Howes) actually
determined "local burnout," not overall "global" flare efficiency. It
is possible that some part of the feed gas escaped the flame at the
flare tip or that relatively small flare eddies left the main flame
and were quenched by cold air. If these parts of the feed gas were
not collected proportionally by the flare top sampling traverse, local
efficiency would be higher than would true "global" efficiency.
Based on the available studies, EPA concluded that the destruction
efficiency of the flares currently in place within the EB/S industry
would be greater than the 60-percent conservative estimate at proposal
(which best reflected the knowledge of benzene destruction available
at proposal) but lower than the 91- to 100-percent range projected by
some of the flare studies.
According to the current knowledge of flare design, the best
state-of-the-art flare design will burn without producing smoke during
normal operation. The smokeless flare inducts combustion air into the
flame by steam or air injection. Smoking flares are environmentally
less desirable because they emit particulate, carbon monoxide, and
more unburned VOC than flares that do not smoke. It is difficult,
however, to maintain smokeless operation unless the off-gas flow to
the flare is constant. When the off-gas flow rate increases, there is
a short period of time before the smoke sensor responds and additional
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steam (or air) reaches the flare tip. During this period, the flare
smokes. Smoking may also occur during large "emergency" discharges
because insufficient steam (or air) is available in the plant to make
these infrequent discharges nonsmoking.
There are a number of techniques that help flares operate without
smoke. One involves the use of a staged system, where a small flare
is operated in tandem with a larger one. The small flare takes the
continuous, relatively low volume, flow and the emergency releases are
fed to the larger flare. A second technique is the use of a separate
small line to the flare tip to maintain high gas velocity even with
the continuous low-volume, low-pressure, waste gas flow. A third
technique, sometimes used in conjunction with either of the above,
requires a compressor to recover the continuous low-volume "base load"
of waste gas. Any excess gas, such as during an emergency, is flared.
These techniques help provide smokeless operation of a flare used to
control emissions from closed-vent systems.
The flares in operation within the EB/S industry are smokeless.
All States where EB/S plants are located require smokeless operation
of flares to varying degrees (IV-E-9) to comply with visibility regula-
tions. Texas requires that flares operate smokelessly except for
5 minutes out of a 2-hour period (IV-E-9). Louisiana requires that
flares not smoke at greater than 20 percent opacity for more than
6 hours out of every 10-day period (IV-E-9). Pennsylvania allows no
more than 3 minutes of greater than 20 percent opacity in 1 hour
(IV-E-9). Michigan requires that 20 percent opacity not be exceeded
except for 3 minutes hourly, three times a day (IV-E-9).
The proposed standard would have required smokeless flares to
control excess emissions. The proposed definition of a smokeless
flare was one that produces visible emissions for no more than 5 minutes
within any 2-hour period. No comments were received on this definition.
The prominence of smokeless flares within the EB/S industry
suggests that these flares are capable of achieving a high degree of
benzene destruction efficiency. Consequently, in light of the fact
that flares at EB/S plants are required by the States where they are
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located to be smokeless (suggesting relatively high efficiencies, but
not so high as are efficiencies under controlled or experimental
conditions), EPA assigned a 90-percent destruction efficiency to
smokeless flares within the EB/S industry. The 90-percent value is
considered to be a reasonable estimate of flare efficiency for EB/S
plants based on the very limited data available in the literature to
date. This efficiency estimate does not suggest that all flares used
in the EB/S industry are only 90 percent efficient but represents a
lower level of the range of flare efficiencies at EB/S plants in order
to estimate emissions. EPA will continue to study flares to determine
their destruction efficiency under various conditions and to evaluate
their value as a pollution control device. Consequently, until better
flare efficiency data are available for benzene destruction from EB/S
plants, the 90-percent estimate is used in emissions calculations for
EB/S plants.
Based on costs and revised efficiencies, the promulgated standard
allows flares currently used to control continuous process emissions
to remain as control devices for these streams because the incremental
costs associated with rerouting these emissions sources from an exist-
ing flare to a boiler compared to the additional emissions reduction
gained were determined to be unreasonably high (see Response 2.5.1).
New flares, however, are not allowed for control of continuous process
emissions sources in the future because the costs of routing emissions
to a flare or a boiler are comparable and the emissions reduction
associated with the boiler is better than that of a flare.
2.4 COST AND ECONOMIC IMPACTS
2.4.1 Compliance Costs
Comment: Commenters made the following charges:
1. Because current benzene emissions from the EB/S industry
were overestimated, fuel and feedstock savings (from recovered
benzene or its thermal content) were similarly overestimated
(IV-F-1; IV-F-2).
2. Net annualized costs on the order of $3 million may be
expected, not the $289,000 in savings predicted by EPA
(IV-F-1; IV-F-2).
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3. Although the Cos-Mar plant, the Gulf plant, the American
Hoechst plant, and some others employ Badger technology,
they are not identical. They all have idiosyncrasies unique
to each plant in both layout and process operation. The
differences in design among plants require individual
treatment (piant-by-plant) for retrofitting costs. EPA's
assumption that these plants are identical because of
construction by the same engineering company caused cost
calculations to be inaccurate (IV-F-1; IV-F-6).
Response: At proposal, EPA estimated that total capital costs of
compliance to meet the proposed standard would have been $3.9 million,
while total annualized costs would have resulted in a net savings of
about $289,000 due to fuel savings. CMA, in public comments, stated
that the EPA costs were underestimated and subsequently supplied their
estimated costs (IV-D-13). CMA estimated that total capital costs of
compliance with the proposed standard would have been $11.6 million
and annualized costs would have been $3.2 million. Table 2-4 summarizes
original EPA and CMA cost estimates on a pi ant-by-plant basis.
Original EPA cost estimates and industry estimates differ for
several reasons. First, industry's (represented by CMA) costs were
presented in 1980 and 1981 dollars; EPA costs were based on fourth-
quarter 1978 dollars. Second, CMA costs were based on plant-specific
parameters including assessments of the air pollution control equipment
needed for compliance that the 13 EB/S plants supplied to CMA for the
public hearing and later updated for the CMA data package supplied to
EPA (IV-D-13). EPA costs were based on costs for equipping a model
plant with control equipment. The model plant approach did not account
for differences in plant layout, design, and operating characteristics,
which determine equipment and installation costs. Third, CMA costs
considered the current structure of the EB/S industry, including the
various plants that comprise the industry. The original EPA approach
was based on data obtained up to 1978. Also, EPA assumed 100 percent
use of production capacity for the model plant calculations instead of
actual pi ant-by-plant production. Fourth, CMA costs, with the exception
2-24
-------
TABLE 2-4. EPA AND CMA COST ESTIMATES OF COMPLIANCE WITH THE PROPOSED
STANDARD ON A PLANT-BY-PLANT BASIS
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
ARCO, TX
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
Subtotal
Plus excess emissions
TOTAL
EPA cost data
Capital
costs
421
-
200
130
235
448
555
142
130
215
424
366
130
0
3,396
524
3,920
($l,000's)a
Annual i zed
costs
(72)
-
7
27
(14)
(147)
(75)
25
26
(64.5)
(76.5)
(119)
23
0
(460)
171
(289)
CMA cost data
Capital
costs
1,903
110
985
800
-
660
607
1,438
900
1,427
1,500
1,000
288
50
11,668
Included
11,668
($l,000's)b
Annual ized
costs
540
48
276
97
-
138
205
717
318
242
490
41
63
13
3,188
Included
3,188
1978 dollars. Data from
J1980-1981 dollars. Data
the proposal
from CMA (IV
BID (EPA-450/3-79-035a).
•D-13).
2-25
-------
of two facilities, did not consider fuel recovery savings. EPA assumed
a fuel recovery value for the boiler comparable with that of natural
gas.
Because of the data and information obtained from CMA since
proposal, EPA reanalyzed the costs of compliance with the proposed
standard. This analysis is presented in Appendix C of this document.
Based on this analysis, substantial revisions have been made to the
CMA cost estimates. The revised EPA costs, which are higher than
original EPA costs but lower than CMA costs, reflect some of the
plant-specific parameters not considered by EPA at proposal. EPA's
revised total capital costs of compliance with the proposed standard
would be $7.6 million, while the total annualized costs would be
$1.9 million, including fuel recovery savings.
EPA's revised cost estimates differ from CMA's cost estimates
primarily due to differences in indirect capital costs such as engineer-
ing fees, construction overhead, and contingencies. The magnitude of
indirect costs can vary widely and depends upon the size, type, and
complexity of jobs considered. In addition, the contingencies are
related directly to the firmness of the cost estimate. EPA assumed
that the CMA direct capital costs were accurate in most cases but
reassessed the indirect costs. As a result, the CMA indirect costs
were adjusted to make them consistent on an interplant basis (see
Appendix C).
EPA also revised the cost per unit of benzene reduced that would
have resulted from implementing the proposed standard based on revised
emissions rates (see Response 2.2.1). On a pi ant-by-plant basis, the
cost per megagram of benzene reduced would have ranged from $50 to
$200,000, and industry-wide cost per megagram of benzene reduced would
have been $7,100 (see Table 2-5).
Upon review of the revised EPA cost and emissions data, the
Administrator concluded that the cost of compliance with the proposed
standard would be unreasonably high in view of the emissions reduction
that would be achieved. Consequently, EPA examined other regulatory
2-26
-------
TABLE 2-5. REVISED EPA COSTS OF COMPLIANCE WITH THE PROPOSED STANDARD
ON A PLANT-BY-PLANT BASIS3
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
tv> Dow Chemical, TX
IVJ
^ Dow Chemical, MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
TOTAL
Capital
costs
($l,000's)
168
0
638
289
660
1,440
607
385
525
1,500
1,000
299
50
7,560
Annual ized
costs
($l,000's)
5
0
195
90
185
395
155
110
150
430
110
85
25
1,940
Emissions
reduced
(Mg/yr)
98
0
1
41
5
31
55
5
4
15
6
11
<1
272
$/Mg b
reduced
51
0
200,000
2,200
37,000
13,000
2,800
22,000
38,000
29,000
18,000
7,700
25,000
7,100
Residual
emissions
(Mg/yr)
21
8
15
1
17
6
2
2
17
6
<1
6
<1
101
Costs in 1980 dollars, rounded to 3-digit accuracy. See Appendix C of this document for
explanation of derivation of the costs summarized in this table.
3$/Mg reduced cost estimates rounded to 2-digit accuracy.
-------
alternatives that would achieve substantial emissions reduction for
much less cost. This analysis is presented in Response 2.5.1 of this
document.
2.4.2 Executive Order 12291
Comment: Two commenters stated that the standard is inconsistent
with Executive Order 12291 on Regulatory Management, which requires
that an adequate cost/benefit analysis be made and the most cost-
effective alternative be chosen. The executive order also requires
regulatory priorities to maximize aggregate social benefits "taking
into account ... other regulatory actions contemplated for the future."
EPA has failed to perform an adequate cost/benefit analysis, to choose
the most cost-effective alternative, and to analyze the overlap of
other regulations with the standard and the extent to which the proposed
regulation reduces marginal benefits (IV-D-7; IV-D-10).
Response: Under Executive Order 12291, EPA is required to judge
whether a regulation is a "major rule" and, therefore, subject to
certain requirements of the order. EPA has determined that this
regulation would result in none of the adverse economic effects set
forth in Section 1 of the order as grounds for finding a regulation to
be a "major rule." Fifth-year annualized costs of the standard would
be about $68,000 (see Response 2.5.1). Significant price increases
are not expected to result from implementing this standard. The
maximum price increase of styrene is estimated to be 0.07 percent,
assuming 100 percent capacity utilization. The Agency has concluded,
therefore, that this rule is not a "major rule" under any of the
criteria established in Executive Order 12291.
Executive Order 12291 requires that for promulgating new regula-
tions, all agencies, to the extent permitted by law, shall base
administrative decisions on adequate information concerning the need
for and consequences of the proposed Government action; shall not
undertake regulatory action unless potential benefits to society
outweigh potential costs; shall undertake an alternative analysis
approach where the alternative chosen will involve the least net cost
to society; and shall take into account regulations already imposed
and regulatory actions contemplated for the future.
2-28
-------
At proposal, the impacts analysis projected a benzene emissions
reduction of about 2,000 Mg/yr at a $290,000 net annualized savings,
indicating a very favorable "cost" in light of the benefit of signi-
ficant emissions reduction, even though selection of the standard was
not guided by Executive Order 12291, which was established after
proposal.
However, the revised analysis for complying with the proposed
standard indicated that the costs were unreasonably high in relation
to the emissions reduced (see Responses 2.4.1 and 2.5.1), based on the
industry's current control status. Consequently, other alternatives,
as suggested by commenters, were examined and from these a less costly
alternative was selected as the basis of the standard (see Response
2.5.1). The selected alternative would result in an emissions reduction
of about 230 Mg/yr at a net annualized cost of $68,000, for a cost per
unit emissions reduction of $300/Mg. A more stringent alternative
considered would have reduced emissions by about 240 Mg/yr at a net
annualized cost of $523,000, for a cost per unit emissions reduction
of $2,200/Mg. The marginal emissions reduction and cost between
alternatives show an incremental emissions reduction of 10 Mg/yr, at a
net annualized cost difference of $455,000, for an incremental cost
per megagram reduced of $46,000.
The Administrator has considered the cost per unit emissions
reduction in selecting the basis of the standard and rejected more
stringent regulatory alternatives with unreasonably high cost per unit
emissions reduction. The alternative selected as the basis of the
standard is considered reasonable, especially considering the cost per
unit emissions reduction for total VOC of about $130/Mg. Thus, the
alternative selected has cost per unit emissions reduction for both
benzene and total VOC emissions comparable to or lower than other
standards proposed or promulgated to control VOC's.
2.5 SELECTION OF THE BASIS OF THE PROMULGATED STANDARD
2.5.1 Emissions Floor, Current Control Devices, Excess Emissions
Comment: Concerning emissions and control devices, commenters
said the following:
2-29
-------
1. Emissions Floor. An emissions "floor" should be established
for individual vents, below which the standard would be
inapplicable (15 Ib/day or 25 Mg/yr "floor"). If this is
unworkable, vents should be excluded by name from the defini-
tion of process vent stream (IV-D-10).
2. Excess Emissions. EPA should not require the control of
excess emissions during startup, shutdown, and malfunctions
due to the small amount of excess emissions and the cost of
retrofitting existing facilities (IV-D-10; IV-F-i; IV-F-2).
3. Establish Standards to Permit Continued Use of Current Control
Devices. The proposed standard would have required several
EB/S manufacturers that now substantially control continuous
process emissions to convert to a different control technology
at substantial expense with no measurable risk reduction.
Therefore, EPA should establish standards that permit EB/S
plants whose emissions present no appreciable public health
risk to continue to use their current control devices (IV-F-1;
IV-F-3; IV-D-10).
Response: The proposed standard would have limited the benzene
discharged to the atmosphere from each process vent stream or combina-
tion of process vent streams to 5 ppmv on a dry basis corrected to
3 percent oxygen. A process vent stream is defined as any continuous
benzene containing gas stream released or having the potential to be
released to the atmosphere from the alkylation reactor section,
atmospheric and pressure columns, hydrogen separation system, or
vacuum-producing devices. The proposed standard represented a 99-
percent reduction in benzene emissions from continuous process vent
streams based on the use of a boiler. The proposed standard also
would have required that emissions during startup, shutdown, and
malfunction be combusted with one or more smokeless flares.
As stated in Response 2.4.1, EPA's revised costs of compliance
with the proposed standard would have been $7.6 million in capital
costs and $1.9 million in annualized costs. The proposed standard
would have reduced total benzene emissions (as revised according to
2-30
-------
industry comment) from EB/S plants by about 270 Mg/yr, from 370 Mg/yr
to 100 Mg/yr, at an industry-wide cost per megagram of benzene reduced
of $7,100.
Upon review of the revised EPA cost and emissions data, the
Administrator concluded that the cost of compliance with the proposed
standard would be unreasonably high in view of the emissions reduction
that would be achieved. Consequently, EPA examined other regulatory
alternatives that would achieve substantial emissions reduction for
less cost. First, each emissions source that would have been covered
by the proposed standard and its respective emissions rate, based on
data supplied by CMA (IV-D-13), were reinvestigated. The emissions
sources examined in the analysis were continuous process emissions
sources not routed to a boiler and upset or excess process emissions
sources not routed to a flare. Next, control costs were assigned to
each of these sources based on reducing continuous emissions by
99 percent in a boiler and excess emissions by 90 percent in a flare
(see Response 2.3).
For EB/S plants, the regulatory alternatives studied consisted of
routing several benzene-containing streams to one existing combustion
device: the plant boiler or superheater. In such an integrated
system of emissions control where several vents are routed into one
control device, costs such as burner retrofit costs, surge tank costs,
elaborate manifolding costs, and installation labor costs are common
to all vents. The cost per vent depends on the number of vents con-
trolled. The intent of the analysis was to examine the costs per unit
emission reduction per vent, which cannot be determined if the common
costs are included unless the number of vents to be controlled is
known. Therefore, initial analysis excluding the common costs was
decided upon. Thus, only compressor and piping cost estimates and
fuel recovery savings (the noncommon costs) were used to compare costs
of controlling low-emitting vents in EB/S plants not currently routed
to a boiler. These costs were then used with the estimated emissions
reductions to calculate the cost per unit of benzene reduction for
each emissions point. While all costs are not included, such a relative
2-31
-------
ranking can indicate which sources can be controlled for the greatest
emissions reduction at the least cost. Also, relative ranking can
indicate whether the partial cost of control for certain vents would
be unreasonably high. If partial costs were unreasonably high, the
costs including all additional expenses clearly would be unreasonably
high. Compressor and piping costs were derived based on the model
plant's stream flow rates (see the proposal BID (EPA-450/3-79-035a;
p. 3-23). CMA data (IV-D-13) contained only benzene emissions rates,
which could not be used alone to calculate pipe sizes because EB/S
vent streams contain other compounds that increase total stream flow
rate and thus the pipe size needed to transport the streams. Equipment
costs were calculated according to the procedure described in Perry's
Chemical Engineering Handbook and the 1980-81 Richardson Engineering
Services Process Plant Construction Estimating Standards (IV-E-2)
described in Appendix C.
Table 2-6 contains emissions rates for the uncontrolled continuous
emissions sources, 99 percent reduction of emissions rates, emissions
reduced, annualized costs for compression and piping, and cost per
megagram of benzene reduced for these sources. Grams-per-second
benzenes flow rates were calculated by the industry from annual benzene
emissions flow rates per emission source averaged over 8,760 hr/yr.
Table 2-6 shows that a relatively clear breakpoint between reasonable
and unreasonable cost per megagram of benzene reduced occurs between
benzene flow rates of 0.14 g/s and 0.023 g/s where the costs increase
from $120 to $4,200. The Administrator considered the $4,200/Mg
partial costs of controlling the stream with a benzene flow rate of
0.023 g/s unreasonably high. Certainly, the cost per unit emissions
reduction for this stream would be unreasonably high when total costs
were included. Consequently, the Administrator concluded that costs
of venting these streams less than or equal to 0.023 g/s to a boiler
are unreasonable.
EPA then examined the impacts of controlling uncontrolled contin-
uous process emissions sources with emissions rates greater than
0.023 g/s by routing these sources to a boiler. The impacts of a
2-32
-------
TABLE 2-6. EMISSIONS RATES AND COSTS FOR CONTROLLING UNCONTROLLED
CONTINUOUS BENZENE EMISSIONS SOURCES
Emissions source
Absorber
Condenser
Combined vacuum column
Stripper
Scrubber (2)
BTEB column ejector
Flare
Flare
Flare
Styrene column ejector
Benzene/toluene (B/T) vacuum
B/T vacuum
Condensate stripper
AL wash system
Hotwell
Hotwell
Vacuum column
Dehydro. water mixture
superheater
EB recycle column
Manufacturer
Am. Ho. , LA
Dow, MI
ARCO, PA
Am. Ho. , LA
Dow, TX
Sun Oi 1 , TX
Oxirane, TX
El Paso, TX
Gulf, LA
Sun Oil, TX
Cos-Mar, LA
Cos-Mar, LA
Monsanto, TX
Monsanto, TX
Cos-Mar, LA
Cos-Mar, LA
Gulf, LA
Monsanto, TX
Amoco, TX
Baseline
emissions
(g/s)5
2.09
1.7
1.26
1.036
0.92
0.32
0.19
0.16
0.14
0.023
0.0158
0.0158
0. 0155
0.00472
0.00293
0.00252
0.00201
0.00184
0.00161
99%
control
(g/s)
0.02
0.017
0.013
0.0104
0.0092
0.0032
0.0019
0.0016
0.0014
0.00023
0.00016
0.00016
0.000155
0.00005
0.00003
0.000025
0.00002
0.00002
0.000016
Benzene
emissions
reduced.
(Mg/yr)"
65
53
39
32
29
10
5.9
4.9
4.4
0.71
0.49
0.49
0.48
0.15
0.083
0.078
0.063
0.057
0.050
Annuali zed
costs
(savings)
($l,000's)c
(34)
(19)
(12)
(15)
(13)
(3.0)
0.50
0.60
0.50
3.0
2.0
2.0
2.0
1.4
2.0
2.0
2.0
2.0
2.0
$/Mg
benzene
reduced
(520)
(360)
(310)
(470)
(450)
(300)
85
120
110
4,200
4,100
4,100
4,200
9,300
24,000
26,000
32,000
35,000
40,000
Emissions rates derived from CMA data package (IV-D-13).
bMethod for determining Mg/yr explained in Appendix A of this document.
cCosts in 1980 dollars rounded to 2-digit accuracy. Method for determining costs explained in Appendix C of this
document.
2-33
-------
0.03-g/s cutoff were evaluated. Table 2-7 summarizes pi ant-by-plant
emissions and cost impacts associated with routing all uncontrolled
process emissions sources with benzene emissions rates greater than
0.03 g/s to a boiler. Under this regulatory alternative, industry-wide
continuous process benzene emissions would be reduced by about 240 Mg/yr,
from 340 Mg/yr to 100 Mg/yr. Eight EB/S plants would be affected at a
total capital cost of $1.8 million and a total annualized cost of
$523,000. The industry-wide cost per unit of benzene reduced would be
$2,200/Mg. The reasons for the increased costs between Tables 2-6
and 2-7 are in the parameters used to calculate costs. The costs in
Table 2-6 represent only annualized compression and piping costs and
fuel recovery savings for the purpose of identifying a potential
emissions "floor" below which emissions could not be controlled at a
reasonable cost. The costs in Table 2-7 represent total direct and
indirect capital costs and annualized costs. Appendix C details the
pi ant-by-plant indirect and direct costs EPA used to estimate costs of
compliance with each regulatory alternative. Based on the impacts
summarized in Table 2-7, the Administrator concluded that the costs
associated with this alternative would be unreasonably high considering
the benzene emissions reduction that would be achieved.
As shown in Table 2-7, three plants would incur relatively high
costs per megagram reduced. While higher absolute control costs are
associated with these plants, the high cost per megagram reduced
results primarily from the much lower emissions reduction that would
be achieved at these plants. The emissions reduction is low because
these plants currently control continuous process vents with smokeless
flares. As a result, only minimal emissions reduction would be achieved
if these plants had to bear the additional expense of routing these
vents to a boiler. Consequently, EPA examined the impacts of allowing
these facilities to continue using the smokeless flares they have in
place to control continuous process benzene emissions.
The proposed regulation would have required flares for excess
emissions control to operate smokelessly, and no comments regarding
such a requirement were received during the public comment period. In
2-34
-------
TABLE 2-7. COSTS AND EMISSIONS ASSOCIATED WITH IMPLEMENTING A 0.03-g/s BENZENE
EMISSIONS CUTOFF RATE (EMISSIONS ROUTED TO BOILERS)3
r«o
co
tn
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical, MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
TOTAL
Capital
costs .
($l,000's)D
145
0
0
82.0
0
95.0
82.0
385
350
0
634
52.0
0
1,820
Annuali zed
costs
(savings).
($l,000's)D
(2.00)
0
0
20.0
0
23.0
13.0
115
105
0
235
14.0
0
523
Emissions
reduced
(Mg/yr)
98
0
0
39
0
28
53
5
4
0
6
14
0
243
$/Mg
Reduced
(20)
0
0
510
0
820
240
23,000
26,000
0
39,000
1,400
0
2,200
Residual
emissions
(Mg/yr)
19
6
15
1
20
8
4
<1
16
4
<1
2
1
97
All uncontrolled process emissions sources with emissions rates greater than 0.03 g/s
are routed to a boiler.
3Costs in 1980 dollars rounded to 3-digit accuracy. Method for determining costs explained in
Appendix C of this document.
~$/Mg reduced costs rounded to 2-digit accuracy.
-------
fact, according to State provisions, all EB/S plants are required to
operate their flares smokelessly (see Response 2.3). Therefore, it is
reasonable to require such operation to control continuous emissions
under this alternative because EB/S plants that currently use flares
have the capacity to operate the flares smokelessly without incurring
additional costs or burdens.
Under this regulatory alternative, industry-wide continuous
process benzene emissions would be reduced by about 230 Mg/yr, from
340 Mg/yr to 110 Mg/yr. Five EB/S plants would be affected at a total
capital cost of $456,000 and a total annualized cost of $68,000. The
industry-wide cost per unit of benzene reduced would be $300/Mg.
Table 2-8 summarizes the pi ant-by-plant emissions and cost impacts
associated with routing all uncontrolled process emissions sources
with benzene emissions rates greater than 0.03 g/s to a boiler while
allowing existing smokeless flares to remain control devices. Based
on these impacts, the Administrator concluded that the costs associated
with this alternative would be reasonable in light of the benzene
emissions reduction that would be achieved. Consequently, the
Administrator selected this alternative as the basis for controlling
continuous process emissions sources.
Controlling continuous process vents, however, not only reduces
benzene emissions but also reduces other VOC's in the emissions streams.
VOC emissions rates for each emissions source within the EB/S industry
were calculated from vent source composition data summarized in the
proposal BID (EPA-450/3-79-035a; p. 3-23); these calculations are
summarized in Appendix A of this document. The total VOC emissions
that would be reduced and the associated costs are summarized in
Table 2-9. Industry-wide VOC emissions would be reduced by about
540 Mg/yr, from 920 Mg/yr to 380 Mg/yr. The total capital and annual-
ized costs of compliance would be $456,000 and $68,000, respectively.
The industry-wide cost per unit of VOC emissions reduced would be
$130/Mg. Therefore, while the control costs per megagram of benzene
appear reasonable, the control costs per megagram of all emissions,
which represent the actual situation, would be less than half that of
benzene control alone.
2-36
-------
TABLE 2-8. COSTS AND EMISSIONS ASSOCIATED WITH IMPLEMENTING A 0.03-g/s BENZENE EMISSIONS
CUTOFF RATE (EMISSIONS ROUTED TO BOILERS OR SMOKELESS FLARES)3
ro
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco , TX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical, MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
TOTAL
Capital
costs .
($l,000's)D
145
0
0
82.0
0
95.0
82.0
0
0
0
0
52.0
0
456
Annual i zed
costs
(savings.)
($l,000's)D
(2.00)
0
0
20.0
0
23.0
13.0
0
0
0
0
14.0
0
68.0
Emissions
reduced
(Mg/yr)
98
0
0
39
0
28
53
0
0
0
0
10
0
228
$/Mgc
reduced
(20)
0
0
510
0
820
240
0
0
0
0
1,400
0
300
Residual
emissions
(Mg/yr)
19
6
15
1
20
8
4
5
20
4
7
2
1
112
All uncontrolled process emissions sources with emissions rates greater than 0.03 g/s are
routed to a boiler or existing smokeless flare.
Costs in 1980 dollars rounded to 3-digit accuracy. Method for determining costs explained in
Appendix C of this document.
$/Mg reduced costs rounded to 2-digit accuracy.
-------
TABLE 2-9. CAPITAL AND ANNUALIZED COSTS, TOTAL VOC EMISSIONS REDUCED, COST PER UNIT OF
TOTAL VOC EMISSIONS REDUCED, AND RESIDUAL TOTAL VOC EMISSIONS ASSOCIATED WITH
CONTROLLING CONTINUOUS PROCESS VOC EMISSIONS
a
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
' Dow Chemical , TX
<*> •
00 Dow Chemical, MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
TOTAL
Capital
costs .
($l,000's)D
145
0
0
82.0
0
95.0
82.0
0
0
0
0
52.0
0
456
Annual i zed
costs
(savings).
($l,000's)D
(2.00)
0
0
20.0
0
23.0
13.0
0
0
0
0
14.0
0
68.0
Total
VOC
emissions
reduced
(Mg/yr)
195
0
0
157
0
57
106
0
0
0
0
20
0
535
$/Mg
Reduced0
(10)
0
0
130
0
400
120
0
0
0
0
700
0
130
Total
residual
VOC
emissions
(Mg/yr)
115
15
25
6
70
15
6
9
82
18
15
2
1
379
aAll uncontrolled process emissions sources with emissions rates greater than 0.03 g/s are
routed to a boiler or existing smokeless flare.
Costs in 1980 dollars rounded to 3-digit accuracy. Method for determining cost explained in
Appendix C of this document.
c$/Mg reduced costs rounded to 2-digit accuracy.
-------
EPA also examined the emissions and costs associated with
controlling emissions from excess emissions sources. Excess emissions
occur during plant startup and shutdown and during upsets of EB/S
process and control equipment. Available information on the frequency
and duration of startups, shutdowns, and upsets was examined.
Based on the data received from CMA (IV-D-13) and subsequent
contact with individual industry representatives (IV-E-3, IV-E-4,
IV-E-8), it was estimated that each EB/S plant would average 20 occur-
rences of excess emissions per year. Of these 20 upsets per year,
95 percent are caused by control system problems while 5 percent are
due to controlled startup and shutdown of the plant for maintenance.
EB/S operators usually perform controlled startups and shutdowns every
18 to 24 months (IV-E-3, IV-E-4, IV-E-8). The average duration of an
EB/S plant shutdown is 24 hours, while the actual venting of emissions
averages 10 hours (EPA 450/3-79-035a; p. AA3-2). Likewise, the average
duration of an EB/S startup is 24 hours while actual venting of emis-
sions averages 10 hours (EPA-450/3-79-035a; p. AA3-1).
The duration of process or control equipment upsets can range
from less than an hour to more than a month. Based on the information
provided above, the CMA data package (IV-D-13), and subsequent contact
with individual industry representatives (IV-E-3, IV-E-4, IV-E-8), it
was estimated that the average duration of process or control equipment
upsets is approximately 5 hours. The industry-wide excess emissions
rate associated with startups, shutdowns, and upsets as reported by
CMA in 1981 was about 33 Mg/yr.
EPA reexamined the costs and emissions associated with routing
all excess emissions to smokeless flares for combustion, as proposed.
As with continuous process emissions, environmental and cost impacts
associated with controlling excess emissions under the proposed standard
have been revised based on public comments and recent industry data
(IV-D-13). Five plants currently do not route*excess emissions sources
to a flare during startup, shutdown, and malfunction. If these plants
were required to do so, total industry-wide excess benzene emissions
would be reduced from about 33 Mg/yr to 16 Mg/yr. Capital and annual-
ized costs associated with this reduction of 17 Mg/yr would be $1.9
2-39
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million and $598,000, respectively. The industry-wide cost per unit
of benzene reduced would be $35,000/Mg. Table 2-10 summarizes the
revised pi ant-by-pi ant costs and emissions associated with the routing
of all uncontrolled excess emissions to smokeless flares. Based on
these impacts, the Administrator concluded that the costs of flaring
excess emissions from EB/S plants would be unreasonably high in view
of the amount of benzene emissions that would be reduced when excess
emissions were routed to a flare.
Plant startup occurs on the average of once every 2 years and
involves gradually bringing all empty and nonoperating equipment,
initially at ambient temperature, to full operating temperatures. The
procedure requires an average of approximately 12 to 24 hours to
establish reactions fully and to ensure that product quality meets
specifications. In this interim period, however, benzene emissions
can be released from certain points in the production train.
The benzene emissions potential during one startup period is
approximately 1 Mg/yr for 10 hr/yr from the entire EB/S industry, most
of which is from the hydrogen separation vent. Due to insufficient
flow during startup, this stream is not compressed and sent to the
aromatic recovery section as during normal production. Rather, typical
practice involves either venting the stream directly to the atmosphere,
recycling the stream, or flaring it until the dehydrogenation reaction
is established fully. Only after the reaction is established and the
stream volume is sufficient can the gas be compressed, ducted to the
aromatic recovery section where the benzene and other condensables are
recovered, and the remainder of the stream--!argely hydrogen—be sent
to the steam superheater for use as supplemental fuel.
Shutdown involves terminating plant operation and allowing the
equipment to cool to ambient temperature. Plant shutdown is necessary
an average of once every 2 years so equipment can be inspected, cleaned,
or replaced. The shutdown procedure for a plant normally requires
about 12 to 24 hours, while actual venting of emissions requires an
average of 10 hours. The procedure involves cutting off feedstock to
the reactors while the introduction of steam and catalyst is decreased
2-40
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TABLE 2-10. COSTS AND EMISSIONS ASSOCIATED WITH ROUTING ALL
UNCONTROLLED EXCESS EMISSIONS TO SMOKELESS FLARES
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical, MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
TOTAL
Capital
costs
($l,000's)a
0
0
127
140
0
953
305
0
0
400
0
0
50.0
1,980
Annual i zed
costs
($l,000's)a
0
0
45.0
48.0
0
269
93.0
0
0
119
0
0
24.0
598
Emissions
reduced
(Mg/yr)
0
0
<1
2.0
0
<1
<1
0
0
14
0
0
<1
17
$/Mg b
reduced
0
0
45,000
24,000
0
270,000
93,000
0
0
8,500
0
0
24,000
35,000
Residual
emissions
(Mg/yr)
2
2
<1
<1
1
<1
<1
2
1
2
0
5
<1
16
Costs in 1980 dollars rounded to 3-digit accuracy.
explained in Appendix C of this document.
rounded to 2-digit accuracy.
Method for determining costs
-------
concurrently, so the temperature of all equipment reaches ambient
levels. During this procedure, emissions in excess of the standard
can occur.
Residual benzene in equipment must be purged before maintenance
can begin. During plant shutdown, as in plant startup, the bulk of
benzene emissions occurs at the hydrogen separation vent. Benzene
emissions due to plant shutdown are approximately 1 Mg/yr from the
entire EB/S industry. Therefore, benzene emissions due to plant
startup and shutdown are approximately 2 Mg/yr from the entire EB/S
industry. The benzene emissions potential of 2 Mg/yr is not expected
to change in the future unless startup and shutdown procedures are
changed. Also, the only way to control benzene emissions attributable
to startup and shutdown would be to route emissions to a flare. As
stated earlier, the costs of flaring excess emissions were judged to
be as unreasonably high. Therefore, the promulgated standard does not
require the control of excess emissions during startup and shutdown.
Instead of requiring the flaring of excess emissions during
upsets, EPA examined the option of requiring EB/S plants to shut down
immediately during upsets. Some of the costs incurred to the industry
during startup and shutdown include increased fuel usage to heat the
process equipment during subsequent startup, increased labor to handle
the controls necessary to monitor process equipment during shutdown,
and loss of profit due to downtime (the minimum downtime of a startup
and shutdown is 48 hours). EPA calculated the average profit loss due
to downtime using the following formula:
Styrene profit margin x Upsets/yr x 13 plants .
Based on an average plant capacity of 321,000 Mg/yr, a minimum downtime
of 48 hours, a styrene profit margin of $21/Mg, and 8,760 operating
hr/yr, each EB/S plant could lose approximately $37,000 in profit per
upset (startup and shutdown). By multiplying the profit lost per
upset by the average number of upsets per year, EPA estimated that
2-42
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each plant could lose about $700,000/yr in profit if required to shut
down the plant during every upset. EPA did not estimate the fuel
usage and labor costs associated with startup and shutdown.
In addition, EPA estimated excess emissions resulting from
requiring immediate shut down during upsets. Currently, EB/S plants
average 20 occurrences of excess emissions per year--19 due to upsets
and 1 due to controlled startup and shutdown. Based on 5 hours per
upset and 20 hours per startup/shutdown, the industry-wide duration of
excess emissions is about 1,600 hr/yr (120 hr/yr/plant). These upsets
in process and control equipment resulted in 33 Mg/yr in excess benzene
emissions. If EB/S plants were required to shut down during every
upset, the industry-wide upset duration would increase to about
5,200 hr/yr (400 hr/plant), thereby increasing excess emissions to
approximately 90 Mg/yr. Based on lost profit and increased emissions
resulting from requiring EB/S plants to shut down during upsets, the
Administrator concluded that this alternative would be unreasonable.
Because immediate shutdown could cause more emissions than
continued operation for short periods would, the Administrator consid-
ered allowing excess emissions as a result of malfunctions for limited
durations. Although benzene emissions due to upsets can arise anywhere
on the production train, certain pieces of equipment have been cited
as likely emissions sources.
Although boilers can experience malfunctions, it should be noted
that an economic incentive exists for EB/S owners and operators to
operate and maintain boilers properly. The EB/S process will not run
without a properly operating boiler. This provides an economic incen-
tive to EB/S owners and operators to operate and maintain process or
air pollution control equipment properly to reduce the frequency of
equipment failure and to reduce fuel costs. If a malfunction occurs,
the boiler will either have to be repaired quickly or the plant will
have to shut down.
Experience has shown that the hydrogen separation compressor is
inoperable an average of only 10 hr/yr (EPA-450/3-37-035a; p. AA 3-3).
Because the hydrogen separation compressor is necessary to recover
2-43
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aromatics and to produce the pressure necessary to combust the
superheater's remaining hydrogen-rich stream, upsets are dealt with
rapidly. During outages, the benzene-laden stream is either vented
directly to the atmosphere or flared.
Experience has shown a variable potential for benzene emissions
in the event of a vent gas compressor outage (EPA-450/3-3-79-035a;
p. AA 3-3). Compared to the hydrogen separation compressor, the vent
gas compressor handles relatively small streams. Its function is to
direct gas streams under low or negative pressure to the main header.
Because this equipment is not central to styrene production and because
the vent streams routed by this compressor are small compared to
process vent streams routed by hydrogen separation compressors, much
less incentive exists for immediate repair of this equipment. Vent
gas compressors have been shut down for up to a month or more (EPA-
450/3-79-035a, p. AA 3-3; II-C-46; II-D-39, II-D-41; II-D-49; IV-E-16).
In the case of one EB/S facility, a vent gas compressor was down for
82 days resulting in about 15 megagrams of benzene emissions (IV-D-13;
IV-E-16).
The types of compressors in the EB/S industry used to push small
vent streams under low pressure to the main header include centrifugal
compressors, centrifugal vent gas blowers, and centrifugal gas-powered
air pumps (IV-E-10, 11, 12, 13, 14, 15, 16, 17, 18, 19; IV-D-19, 20,
21, 22, 23). EB/S industry and vendor representatives identified
these types of equipment as similar in design and operation. These
representatives also identified the causes of upsets that are common
for such equipment. They include corrosion of parts, electrical
failure, bearing failure, valve closure, overheating, poor lubrication,
and thrust loading (IV-E-10, 11, 12, 13, 14, 15, 16, 17, 18, 19;
IV-D-19, 20, 21, 22, 23). EB/S industry and vendor representatives
agreed that the time needed to repair the various types of upsets that
could occur in vent gas compressors ranges from 2 hours to 16 hours if
spare parts are readily available. If parts are not in stock, it
could take up to a month or more to repair a vent gas compressor. The
2-44
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reason for this delay is that compressor systems are usually custom
designed for a plant so that if parts are not stocked, the EB/S manufac-
turer must order compressor parts that often must be custom made. The
82-day incident discussed earlier resulted from the EB/S facility
having to order custom parts.
Based on the examination of data on vent gas compressor outages,
the Administrator concluded that the potential emissions reduction
associated with limiting the duration of a vent gas compressor outage
would be significant. For example, if the EB/S facility noted pre-
viously had stocked spare vent gas compressor parts, the 82-day repair
time would have been reduced to a maximum of 16 hours. The 15 megagrams
of benzene emissions associated with the 82-day time period also would
have been reduced to about 0.12 megagram. Therefore, based on the
vendor and EB/S industry data on the time required to repair vent gas
compressors and the potential emissions reduction of repairing vent
gas compressors rapidly, the Administrator concluded that it was
reasonable to allow EB/S owners or operators up to 16 hours of excess
emissions during malfunctions. Thus, 16 hours after onset of a mal-
function of the process or control equipment, the plant owner or
operator must have either corrected the malfunction or shut down the
plant, or the plant owner or operator would be in violation of the
standard. Such a requirement is not expected to cause any hardship,
since no other causes of excess emissions are expected to last as long
(startups, shutdowns, and hydrogen separation compressor malfunctions
would last no longer than 10 hours). However, because the proposed
standard would have allowed excess emissions during malfunctions to be
flared, the Administrator concluded that flaring of excess emissions
during malfunctions is an acceptable alternative to restricting excess
emissions to 16 hours. It should be noted that the plant owner or
operator must demonstrate to the Administrator's satisfaction that any
upset causing excess emissions was a malfunction; i.e., sudden unavoid-
able upset.
Based on examination of the alternatives considered for controlling
excess emissions and the estimated impacts, the Administrator concluded
2-45
-------
that costs associated with the control of excess emissions from EB/S
plants during startup and shutdown would be unreasonably high in light
of the emissions reduction achieved. Excess emissions during process
or control equipment malfunction, however, unless flared the whole
time, would be permitted only up to a maximum of 16 hours after the
onset of the malfunction. It should be noted that if a plant had to
shut down due to a malfunction, the subsequent startup time would not
be included in the 16 hours allowed for malfunction.
In summary, as a result of the above analyses, the Administrator
redefined BDT for EB/S process vents as the combination of (1) control-
ling continuous process vents with benzene flow rates greater than
0.03 g/s by routing emissions to a boiler or, if already being done
so, a smokeless flare; and (2) no required control of excess emissions
during plant startup or shutdown. However, excess emissions due to
malfunctions in process or control equipment would be allowed only up
to 16 hours. The Administrator then examined the residual risks after
application of BDT for process emissions to determine whether or not
they are unreasonable in light of the risk reduction that could be
gained by requiring a more stringent control level and the associated
cost increase.
In selecting a more stringent alternative to BDT, the Administrator
examined the cost and emissions impacts of several regulatory alternatives
that represent different control levels based on various combinations of
continuous and excess process emissions control previously discussed.
These alternatives are outlined as follows:
1. Regulatory Alternative 1: Require that EB/S plants achieve
99 percent benzene emissions reduction from process vents
with benzene flow rates greater than 0.03 g/s (as measured
after all VOC recovery equipment and before the combustion
device for all vent streams controlled by a combustion
device and where the stream exits to the atmosphere for all
streams not controlled by a combustion device). This alterna-
tive is based on the use of a boiler only and would not
2-46
-------
allow the use of smokeless flares to control continuous
process vents. Also, EB/S plants are required to control
excess emissions sources as under BDT.
2. Regulatory Alternative 2: Require that EB/S plants achieve
99 percent benzene emissions reduction from process vents
not burned in a smokeless flare with benzene flow rates
greater than 0.03 g/s (as measured after all VOC recovery
equipment and before the combustion device for all vent
streams controlled by a combustion device and where the
stream exits to the atmosphere for all streams not controlled
by a combustion device). This alternative is based on the
use of a boiler for controlling these process vents while
allowing existing smokeless flares to continue to control
emissions sources they currently control. Also, require
that EB/S plants use one or more smokeless flares to control
excess emissions.
3. Regulatory Alternative 3: Require that EB/S plants achieve
a 99 percent benzene emissions reduction from process vents
with benzene flow rates greater than 0.03 g/s (as measured
after all VOC recovery equipment and before the combustion
device for all vent streams controlled by a combustion
device and where the stream exits to the atmosphere for all
streams not controlled by a combustion device). This alterna-
tive is based on the use of a boiler only and would not
allow the use of smokeless flares to control continuous
process vents. Also, require that EB/S plants use one or
more smokeless flares to control excess emissions.
The cost and emissions impacts of these regulatory alternatives
are summarized in Table 2-11 and compared with BDT. Regulatory Alter-
native 1 is the next more stringent alternative in terms of emissions
reduction and costs. Consequently, the Administrator selected Alterna-
tive I as the control level to examine in determining whether risks
remaining after application of BDT are unreasonable since, of the more
stringent alternatives considered, it has the least cost per megagram
reduced.
2-47
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TABLE 2-11. INDUSTRY-WIDE COSTS AND EMISSIONS FOR EACH REGULATORY ALTERNATIVE3
Regulatory alternative
BDT
Regulatory Alternative 1
Regulatory Alternative 2
Regulatory Alternative 3
Capita]
costs
($l,000's)
456
1,820
2,430
3,800
Annual i zed
costs .
($l,000's)D
68.0
523
666
1,130
Emissions
reduced
(Mg/yr)
228
243
246
261
$/Mg
reduced
300
2,200
2,700
4,300
Residual
emissions
(Mg/yr)
145
130
127
112
aCosts and emissions include continuous and excess process control.
Costs referenced to 1980 dollars rounded to 3-digit accuracy. Method for determining costs
explained in Appendix C of this document.
*» C$/Mg rounded to 2-digit accuracy.
-------
The Administrator compared the health risks and costs associated
with BDT and Regulatory Alternative 1. Due to the assumptions used in
calculating the health risk numbers, there is considerable uncertainty
associated with them beyond that represented by the ranges presented
here. They may represent overestimates or underestimates. The
uncertainties associated with these numbers are explained in Section
2.1.1. The impacts of these alternatives are compared in Table 2-12.
Application of BDT. would result in a range of leukemia incidence of
-4 -3
7.5 x 10 to 5.2 x 10 cases per year and a maximum lifetime risk of
-5 -4
3.0 x 10 to 2.0 x 10 . Alternative 1 would result in a range of
-4 -3
leukemia incidence of 7.1 x 10 to 4.9 x 10 cases per year and a
~5 -4
maximum lifetime risk of 3.0 x 10 to 2.0 x 10 . The capital and
annualized costs associated with BDT are about $456,000 and $68,000,
respectively. The capital and annualized costs associated with
Alternative 1 are about $1.8 million and $523,000, respectively. In
light of the relatively small health benefits that would be gained and
the costs of requiring a more stringent alternative than BDT, the
Administrator concluded the risks remaining after application of BDT
are not unreasonable. Therefore, the Administrator selected BDT as
the basis for the promulgated standard.
It should be noted that the 0.03-g/s cutoff, which was calculated
from annual benzene flow rates averaged over 8,760 hr/yr, is required
to be calculated over a 3-hour average and not from annual averages,
which would be unreasonably costly and lengthy. The 3-hour average
will enable rapid determination of the process vent streams to be
required to reduce benzene emissions. No evidence, such as seasonal
variations, exists to indicate that 3-hour averages differ significantly
from annual averages.
To summarize, in selecting the basis for the promulgated standard,
EPA used suggestions from industry commenters. The promulgated standard
implements a continuous process vent stream emissions "floor" of
0.03 g/s (as measured after all VOC recovery equipment and before the
combustion device for all vent streams controlled by a combustion
device and where the stream exits to the atmosphere for all streams
not controlled by a combustion device), below which no action is
required. Streams currently controlled by boilers or flares are still
2-49
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subject to the standard but incur no control costs. The standard
allows smokeless flares that currently control continuous process
emissions sources to remain control devices. The definition of a
smokeless flare remains at it was proposed; i.e., a flare that produces
visible emissions for no more than 5-minutes within any 2-hour period.
Also, the promulgated standard does not require the flaring of excess
emissions but limits the duration of a malfunction to 16 hours, with
the option of flaring.
The Administrator has determined that implementing the promulgated
standard will reduce benzene emissions significantly from EB/S process
vents at a reasonable cost. Also, residual risks of leukemia after
application of the promulgated standard were determined by the
Administrator to be not unreasonable. On this basis, the promulgated
standard is judged to provide an ample margin of safety to protect
public health.
2.6 SELECTION OF EMISSIONS LIMIT
2.6.1 Attainability of 5-ppmv Standard
Comment: The commenters stated that EPA established the 5-ppmv
standard entirely on the emissions test results conducted by El Paso
Products Company. They considered the data unrepresentative because
of the plant's two-tiered burner system. The commenters also stated
that Dow (in its Midland, Michigan, facility) performed tests with
boiler and superheater equipment that exceeded the 5-ppmv level.
Therefore, they expressed concern over the ability of the EB/S industry
to comply with the standard even using BDT (IV-F-1; IV-F-4; IV-D-10).
Response: Selection of the 5-ppmv numerical emissions limit was
based upon results of emissions tests performed at three EB/S plants.
The tests were performed at the El Paso Products plant in Odessa,
Texas (II-A-13); the Amoco plant in Texas City, Texas (II-A-32); and
the U.S. Steel plant in Houston, Texas (II-A-33).
The test results from the Amoco plant showed that a steam superheater
receiving benzene-containing vent streams reduced benzene emissions to
a range between 6.1 and 53.8 ppmv referenced to 3 percent oxygen. The
average concentration was 16.8 ppmv and the superheater benzene removal
efficiency ranged from 87.8 to 98.9 percent (95.5 mean).
2-50
-------
The data reported for the Amoco plant are not believed to be
representative of the true benzene emissions control from that source.
During the field test, the contractor identified significant residual
contamination in the sampling and analysis apparatus. Several modifi-
cations to the recommended test procedures were made during the test.
The overall result of these modifications was that the final test
methods used at Amoco significantly differed from Reference Method 110
so as to make them not comparable. It was estimated, based on results
of analysis of blank samples, that contamination could have accounted
for at least half, if not all, of the benzene detected in the stack
samples analyzed. These problems are outlined in Appendix C of the
proposal BID (EPA-450/3-79-035a). Because of the problems experienced
during the Amoco test, the results were not used to select the numerical
emissions limit.
Laboratory evaluations were performed to determine the precautions
necessary to eliminate contamination when low-level concentration
streams were measured from EB/S sources. These improvements were
incorporated into the test procedures prior to testing at El Paso and
U.S. Steel. No contamination problems were observed during those
tests.
The test results from the El Paso Products plant showed that
benzene emissions were reduced to between 0 and 0.5 ppmv, with a mean
of 0.39 ppmv corrected to 3 percent oxygen on a dry basis, in a super-
heater and between 0 and 1.4 ppmv, with a mean of 0.5 ppmv corrected
to 3 percent oxygen on a dry basis, in a hot-oil furnace. The hot-oil
furnace and the superheater benzene removal efficiencies were greater
than 99.9 percent. These results can be considered representative for
the superheater and hot-oil furnace designs at the El Paso facility
because the problems that occurred at the Amoco plant were corrected
at the time of the El Paso test and Method 110, the recommended test
method, was followed properly. However, the burner configuration of
the El Paso superheater passed benzene through two combustion zones.
Therefore, benzene might have undergone greater destruction than if it
had passed through a single combustion zone.
2-51
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The test results from the U.S. Steel plant showed that benzene
emissions were reduced to between 0.1 and 0.195 ppmv, with a mean of
0.153 ppmv corrected to 3 percent oxygen on a dry basis, in a superheater
with a single combustion zone. The benzene removal efficiency ranged
from 99.6 to 99.8 percent (99.7 mean). U.S. Steel also tested a
reboiler that reduced benzene emissions to a range between 0.1 and
0.345 ppmv, with a mean of 0.182 ppmv corrected to 3 percent oxygen on
a dry basis. The reboiler benzene removal efficiency ranged from 99.4
to 99.8 percent (99.6 mean). These results can be considered representa-
tive for the superheater and reboiler designs of the U.S. Steel plant.
The test data from the El Paso and U.S. Steel plants show that
less than 2 ppm benzene can be achieved consistently in their respective-
superheaters, hot-oil furnaces, and reboilers. In spite of differences
in burner configuration, benzene destruction efficiency for the test
plant superheaters was greater than 99 percent during all test runs.
Furthermore, the residual benzene emissions from the U.S. Steel plant
were less than those from the El Paso plant (II-A-13, II-A-33).
Because of the consistent benzene destruction efficiency and residual
benzene emissions data from both tests, both tests were considered
representative of the boiler efficiencies of the respective plants in
spite of burner configuration. When proposing that a 5-ppmv numerical
standard could be achieved under all operating conditions by all EB/S
plants, the Administrator evaluated all these considerations (varying
burner capacities, designs, and efficiencies in conjunction with
various benzene off-gas flow rates).
The EPA data are considered the best available on benzene outlet
concentrations from superheaters, boilers, and furnaces in EB/S plants.
Both the El Paso and U.S. Steel tests were conducted according to
Reference Method 110. A number of items in the test report for Dow
Chemical USA deviated from Reference Method 110 so that the results of
the testing reported are not directly comparable to EPA data. The
differences noted between the EPA and Dow Chemical test reports are
summarized below.
2-52
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The EPA procedures include measurement of the benzene concentrations
in the inlet fuel stream and the exhaust gas outlet stream. Test
results show that the burner efficiency for the El Paso and U.S. Steel
superheaters are above 99 percent. The Dow Chemical test did not
perform this evaluation so actual benzene destruction efficiency is
unknown.
The EPA testing showed that benzene outlet concentrations varied
with changes in the process operation. The flue gas benzene concen-
trations fluctuated with process off-gas flow rates, which is consistent
with the basis used in the Administrator's decision on the standard.
The Dow Chemical test report did not account for process operation
changes.
All sampling apparatus for the EPA tests was precleaned to
eliminate equipment contamination. Contamination had been a problem
in one EPA test series, and these precleaning problems were corrected
in subsequent tests. The Dow Chemical test did not mention precleaning
precautions.
The EPA testing procedures for Reference Method 110 consisted of
five 1-hour integrated samples, each taken after a velocity and tempera-
ture traverse at the site. These procedures ensured the extraction of
a representative sample in accordance with EPA Reference Method 110
for gas velocity traverses. Dow Chemical did not comment on inclusion
of velocity traverses in the test plan. Instead, it extracted a
sample 2 feet from the mouth of the stack. This area is subject to
cyclonic gas flow conditions and is specifically not recommended in
EPA Reference Method 110 (this sampling site may be highly prone to
erratic emissions sampling results).
EPA took integrated samples for 1 hour. This method gives a more
representative sampling of the emissions—it is not biased by high or
low fluctuations in the outlet gas benzene. Dow Chemical took 15-minute
grab samples. This procedure is prone to yield erratic results. The
EPA test procedures present more representative data consistent with
the 3-hour average emissions limit described in the regulation. Dow
Chemical could not compute a valid 3-hour average from its data.
2-53
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Finally, the flame ionization detector of the gas chromatograph
used by EPA was calibrated according to audit standard reference
materials (SRM). The SRM audit gases are the most reliable calibration
sources available. The Dow Chemical report does not mention the use
of SRM's.
Because of the deviations from Method 110 in the test procedures
that Dow Chemical performed, EPA considers the Dow Chemical data to be
unrepresentative of the furnace benzene destruction efficiency.
Therefore, based on all valid test data EPA considered, the 5-ppmv
emissions limit is reasonable and, consequently, has not been changed
since proposal.
2.6.2 Flue Gas Oxygen Limit
Comment: Commenters contended that the 1.5-percent excess oxygen
limit for excess emissions reporting is unduly restrictive on new
burner technology. It would be appropriate to establish the minimum
at 0.5 percent (IV-F-1; IV-F-4).
Response: The proposal preamble, in the "Selection of Monitoring
Requirements" section (45 FR 83459), explains how EPA selected the
1.5-percent flue gas oxygen limit for boilers. The flue gas oxygen
level provides information concerning compliance with the standard. A
flue gas oxygen level of 1.5 percent represents a clear breakpoint
between normal fluctuations in boiler operation and serious failure.
Therefore, at proposal, this limit was selected as a parameter that
would indicate proper operation of the boiler.
The monitoring of oxygen levels is important in determining the
proper operation of a boiler and to ensure efficient combustion of
fuel entering the burner. It is unlikely that plant operators would
neglect a boiler, the central device of the EB/S production process,
by failing to monitor oxygen levels based on safety and fuel savings
incentives and to make corrections as necessary. Consequently,
the Administrator concluded that it was unnecessary to require monitoring
oxygen levels since operators already monitor them closely to ensure
proper operation and maintenance. Therefore, the promulgated standard
does not require the monitoring of flue gas oxygen.
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2.7 REPORTING AND RECORDKEEPING
2.7.1 Thirty-Day Startup/Shutdown Notification
Comment: Section 61.103(b) would require all operators to be in
violation for all unscheduled and many scheduled shutdowns. The pro-
posed standard assumes that all startups and shutdowns are anticipated
and that plant operators know 30 days in advance when the plant will
be shut down. A plant may go down for numerous reasons that are not
anticipated. CMA therefore believes that the advance notification
requirements should be dropped entirely from the proposed standard.
Alternatively, EPA should at least modify Section 61.103(b) to eliminate
the mandatory 30-day-advance-notice requirement (IV-F-1; IV-F-4;
IV-F-6; IV-D-10; IV-D-12), according to some commenters.
Response: The Administrator did not intend for operators to be
in violation for not reporting unscheduled startups or shutdowns. It
is recognized that such unanticipated occurrences could not possibly
be reported at least 30 days in advance. The Administrator agrees
with the commenter that such a requirement is unreasonable, especially
because the standard no longer requires control of emissions during
these periods, which eliminates the need for having an observer present.
It is noted that such occurrences must be included in the quarterly
report, as discussed in Responses 2.7.4 and 2.7.5 of this document.
2.7.2 Ambiguous Wording in Enforcement Section
Comments: Commenters charged that Section 61.102(c) constitutes
vague and contrary design, equipment, work, and operational practice
procedures. More guidance and better defined requirements are necessary
for the plant operator to fashion his conduct to avoid problems or
violations (IV-F-1; IV-F-4; IV-D-10).
Response: The standard does not specify how the owner or operator
of a source is to meet the emissions limit; i.e., no specific control
device or system is required. Consequently, an all-inclusive list of
what constitutes proper operation and maintenance is not practical and
perhaps would limit the owner or operator's flexibility with unnecessary
requirements, especially when different control devices may be used.
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The standard's emissions limit is based on test results that are,
in EPA's judgment, achievable when the control device is properly
operated and maintained (see Response 2.6.1). Consequently, because
continuous monitoring results are an indicator of whether or not the
standard is being met, they also serve as an indicator of proper
operation and maintenance. Thus, the owner or operator of a source
can employ whatever operation and maintenance procedures he/she deems
appropriate as long as the monitoring data indicate the standard is
being achieved. It should also be noted that monitoring data that
indicate the standard has been exceeded do not automatically result in
a violation of the emissions limit.
Because EPA anticipates the use of boilers or superheaters as
the control device of choice by the industry, proper operation and
maintenance procedures are necessary to achieve the standard. Babcock
& Wilcox Company (1978), in their 39th edition of Steam/Its Generation
and Use, outline operation and maintenance procedures for boilers and
superheaters. According to Babcock & Wilcox (1978), the following
discussion outlines the generally accepted operation and maintenance
procedures that owners and operators of fossil fuel boilers or super-
heaters follow as part of normal operation and maintenance. Babcock &
Wilcox (1978) also stated that the procedures listed are subject to
expansion and variation depending on the specifics of each plant. It
must also be noted that all of the following operation and maintenance
procedures are necessary to ensure the efficient and safe use of
boiler equipment. Efficient and safe use will further reduce the
frequency of upsets and will help the device achieve maximum reliability
in operation and combustion efficiency.
The most important aspect of boiler operation is well-trained
operators who understand testing methods, designs, purposes of tests
and design, and limitations of the equipment operated.
Startup and shutdown operating procedures are also important for
safety and efficiency. In preparing for startup, operators must
inspect, clean, hydrostatically test, and precalibrate all instruments,
equipment, and controls. Auxiliary equipment and safety valve testing
also must be performed.
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Proper operating procedures during startup and operation protect
pressure parts against corrosion, overheating, and thermal stress.
Steam must be produced at desired temperature, pressure, and purity.
Periodic safety inspections should be performed to prevent dangerous
situations (explosions) and inefficiency (dry gas loss). Plants
should also be taken out of service periodically to inspect internal
and external parts, to clean, and to repair parts every 18 to 24 months.
Preventative maintenance should be practiced by all operators to
ensure operation in accordance with plans and schedule. Maintenance
procedures can be divided into in-service maintenance and outage main-
tenance. In-service preventative maintenance procedures; i.e., avoiding
conditions that could cause explosions and protecting pressure parts
to prevent excessive thermal stress, are applied to ensure safe operation,
Operator training, burner observation to detect flame failure, detection
of unburned combustibles in flue gas, and immediate indication of
fuel-air retention at burners will prevent explosions. Boiler safety
valve installation and monitoring of feedwater, boiler water, steam
purity, temperature, and pressure will protect pressure parts. Proper
in-service maintenance will improve the efficiency of the boiler by
early detection of dry gas losses.
Preventative outage maintenance includes scheduled shutdowns for
internal and external inspections and cleaning every 18 to 24 months.
2.7.3 Ninety-Day Compliance Requirement
Comment: According to one commenter, Section 61.104(a)(l)(2) is
unrealistic in terms of compliance time. A 1-year period for compliance
from the date of promulgation would be more realistic and reduce
paperwork (IV-D-4).
Response: Section 112(c)(l)(B)(i) of the Clean Air Act requires
that the standard apply 90 days after the promulgation date. Also,
under Section 112, the Administrator can grant a waiver only if time
is needed to install controls. Consequently, if a plant already has
controls in place, the Administrator cannot grant that plant a waiver
of compliance. No waiver of compliance with the promulgated standard
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was included in Section 61.104 of the proposed regulation because some
of the vents in all of the 13 EB/S plants can meet the standard
immediately.
Plants requiring more than 90 days to install controls may request
a waiver from the Administrator for a period not exceeding 2 years
from the effective date of the standard. The granting of a waiver by
the Administrator will be in writing and will (1) identify the stationary
source covered; (2) specify the termination date of the waiver; (3) specify
dates by which steps towards compliance are to be taken; and (4) impose
additional conditions as the Administrator determines necessary to
ensure installation of the necessary controls within the waiver period
and to ensure protection of persons' health during the waiver period.
The Administrator may deny waiver requests and will notify owners
and operators of said denial together with: (1) a notice of the
information and findings on which the denial is based, and (2) a
notice of the opportunity to supply additional information to the
Administrator prior to final action on the request for denial. A
final determination to deny any request for a waiver will be in writing
and will set forth the specific grounds on which the denial is based.
The final determination of a waiver denial will be made within 60 days
after presentation of additional information or 60 days after the
final date specified for such presentation if presentation is made.
2.7.4 Monitoring Requirements
Comment: A commenter stated that the annualized monitoring costs
associated with the proposed standard were underestimated by an order
of magnitude (IV-F-1; IV-F-2).
Response: During normal operation, parameters of benzene concen-
tration in the vent stream, firebox temperature, and flue gas oxygen
undergo minor variation. However, during control device malfunctions,
large fluctuations in these parameters occur. By detecting these
fluctuations, a system monitoring these parameters could determine if
the emissions limits were not being achieved.
The proposed standard would have required that owners or operators
of EB/S plants monitor emissions continuously to provide an effective
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and rapid means for enforcement personnel to determine if (1) the
control device is operating, (2) the process vent streams covered by
the standard are being routed to the control device, and (3) the
control device is achieving the emissions limit. Also, if the emissions
limit were exceeded, the cause of the emissions could be determined.
The proposed standard would have required that owners or operators
of sources using boilers as the control device install and operate
continuously (1) a flue gas oxygen monitor with a strip chart recorder,
(2) a continuous firebox temperature monitor with a strip chart recorder,
and (3) a flow meter with recorder that prints a record at least every
30 minutes on each compressor or natural gas ejector. In addition,
owners or operators would have been required to check visually each
process vent stream.once a week to determine if each stream covered by
the standard were being sent to the boiler. This information would
have been kept in a weekly log signed by the plant operator.
For sources that use air pollution equipment other than boilers,
the proposed standard would have required that owners or operators
install and operate continuously a gas chromatograph with a flame
ionization detector to monitor the concentration of benzene exiting
the control device controlling the process vents. To determine if all
the process vent streams were being routed to the control device, the
proposed standard would have required the owners or operators to
install and operate continuously a flow meter and print a record of
the measured flow every 30 minutes on each process vent stream or
combination of process vent streams before entry into the control
device. They also would have been required to make a weekly visual
check of each process vent and to keep a weekly log of each. This
monitoring method was not expected to be used since it was expected
that EB/S plants would use boilers to control benzene emissions.
The owner or operator of each source would have been required to
calibrate the required monitoring equipment and to certify that the
equipment had been installed, operated, and maintained according to
certain specifications as indicated in the regulation.
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The 1978 capital investment required per plant to comply with the
proposed monitoring requirements would have been a maximum of $16,000
for installing two oxygen and temperature monitors and three flow
meters, or $58,000 for installing a gas chromatograph and three flow
meters. This maximum per-plant cost could vary from plant to plant if
some of the EB/S plants had some of the required equipment for use in
standard process operation.
The Administrator determined that the combination of monitoring
requirements outlined at proposal would have provided the best means
of obtaining information concerning compliance with the regulation and
the causes of malfunction. For example, if a flow meter detected a
disturbance, the oxygen and temperature monitors would also corroborate
that the problem existed and could provide data concerning the cause
of the malfunction.
Since proposal, the Administrator reexamined the combination of
monitoring requirements that would have been required by the proposed
standard. It should be noted that the temperature and oxygen levels
are important parameters that determine the proper operation of a
boiler and ensure efficient combustion of fuel entering the burner.
It is unlikely that plant operators would neglect a boiler, which is
essential for the EB/S production process (the process will not run
without a boiler) by failing to monitor carefully temperature and
oxygen levels and to make corrections as necessary based on the safety
and fuel savings incentives. Therefore, the Administrator determined
that it is unnecessary to require monitoring of these parameters since
operators already monitor them to ensure proper operation and maintenance
Because there is less incentive in terms of safety and fuel
savings to operate and maintain properly the flow of vent streams
covered by the standard to the air pollution control device, it is
less likely that a malfunction in the compressor system would be
corrected as rapidly as a malfunction in the control device would be
(see Response 2.5.1). Therefore, stream flow should be monitored to
ensure continued routing of vent streams to the air pollution control
device. At proposal, a flow of zero in a vent stream routed to the
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required control device was used to indicate an occurrence of excess
emissions in that the vent stream was not being routed to the control
device. The zero flow level was selected because wide fluctuations in
vent stream flow prevent selection of a specific flow rate that would
indicate if something were wrong. However, due to the limited accuracy
of the flow meters typically used, the instruments could indicate a
small flow even when there actually is no flow. This selection necessi-
tated identification of a flow rate that would be defined as "zero
flow" for purposes of this regulation.
CMA flow rate data (IV-D-13) were used to estimate flow rates in
standard cubic feet per minute for streams for which flow meters would
be required. Because the flow rates of these streams vary by more
than an order of magnitude, no quantitative flow could be used as
"zero flow" that could be measured accurately and reliably and displayed
by all of the flow meters designed for normal flow of the various
streams. The promulgated regulation specifies that flow meters be
accurate to within plus or minus 5 percent over the normal operating
range. Consequently, when there is no flow in a vent stream, the flow
meter on that stream would be expected to indicate a flow of no more
than 5 percent over the normal operating range. Conversely, "zero
flow" could be expected when the flow meter registers 5 percent or
less. Such a benchmark would be well below the normal stream flow
fluctuations experienced within the industry, of plus or minus 25 per-
cent, according to CMA (IV-D-18). Therefore, for this regulation,
"zero flow" is considered to be less than 5 percent of the normal flow
of the vent stream, as determined at the time of the emissions test by
Reference Method 2A. The monitoring of vent stream flow levels in
combination with weekly visual checks of each vent stream to determine
if it is being routed to the air pollution control device could be
effective in the rapid determination of a change in the routing of
vent streams covered by the standard to the control device.
The final rule allows the continued use of smokeless flares if
they were being used as of the proposal date to control emissions from
existing process vents. However, if a flare is operating smokelessly,
it is difficult to determine if a flame is, in fact, present. Thus,
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the absence of a flame may go undetected for hours if visual inspection
alone is used (this is the typical method of monitoring flares' contin-
uous operation in the EB/S industry [IV-E-21, IV-E-22, IV-E-23]). As
long as the absence of a flame is not discovered, emissions vented to
the flare would pass uncontrolled to the atmosphere. Because the
final rule allows existing flares to be used for controlling continuous
process emissions sources currently routed to the flare, the flame's
continuous operation must be ensured.
Because visual inspection is not suitable for detecting a flame
in the flare, other monitoring techniques were evaluated. The presence
of a flame can be determined through the use of a heat-sensing device
on the flare's pilot flame. Pilot flame monitoring equipment include
various heat sensing thermocouples and ultraviolet (UV) light beam
sensors (IV-E-24; IV-E-25; IV-E-26). A heat-sensing thermocouple
consists of a temperature probe protected by a metal sheath placed in
various positions around a flare's pilot flame. In the absence of a
flame, the temperature probe cools. The sudden temperature drop is an
indication to the plant operator that the flame has gone out. The
thermocouple heat sensor equipment available through vendors costs
about $800 per pilot flame (IV-E-24; IV-E-25; IV-E-26).
Another monitoring device available to plants is the UV sensor.
This equipment involves directing a beam through the flare's pilot to
a sensor to indicate the presence of a flame. The cost of a UV sensor
is approximately $2,000 per pilot (IV-E-24). Vendors mention, however,
that the UV system would not be as accurate as a thermocouple in
indicating the presence of a flame for several reasons (IV-E-25;
IV-E-26). First, the UV beam is influenced by ambient infrared radia-
tion that could affect the accuracy. Second, interference between
different UV beams would make it difficult to monitor flares with
multiple pilots. Finally, UV sensors are designed primarily to monitor
flames within enclosed combustion devices (i.e., incinerators).
Therefore, the heat-sensing thermocouple represents the most reliable
technique in flare flame monitoring (IV-E-25; IV-E-26).
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Therefore, the final rule requires the monitoring of the flare's
pilot flame using a thermocouple heat-sensing device. The Administrator
determined that the monitoring of the flare's pilot flame would be
reasonable based on the costs of the monitoring equipment and the
reliability in ensuring the presence of a flame.
Based on this examination, the Administrator determined that
proper operation and maintenance of boilers would be achieved regard-
less of the monitoring requirements and, in order to reduce unnecessary
reporting and recordkeeping requirements and associated costs, deleted
the requirements for monitoring temperature and oxygen levels of the
boiler from the promulgated standard. Owners or operators of sources
using boilers or smokeless flares as air pollution control devices are
still required to install and operate a flow meter that prints a
record at least every 30 minutes for each compressor. It should be
noted that at proposal, flow meters on natural gas ejectors were
required to ensure that the combustion device was being supplied with
fuel. Because the boiler is central to the EB/S process, it is unlikely
that EB/S plant operators would neglect the proper flow of natural gas
to the control device, making such a requirement unnecessary. There-
fore, the promulgated standard does not require the monitoring of
natural gas flow at the natural gas ejector. In addition, owners or
operators are required to check visually once a week that each process
vent stream covered by the standard is being sent to the boiler or
flare. This information is to be kept in a weekly log signed by the
plant operator. The monitoring requirements for sources using air
pollution control devices other than boilers or flares remain unchanged
because EB/S plants are expected to use boilers and smokeless flares
to control benzene emissions.
The capital investment, in 1980 dollars, per plant to comply with
the promulgated monitoring requirements for sources using boilers as
flares as the air pollution control device will be a maximum of $12,000
for installing three flow meters and a pilot light heat-sensing device.
For sources using air pollution control devices other than boilers or
flares (not expected), the capital investment per plant to comply with
the promulgated monitoring requirements will be a maximum of $70,000.
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This maximum per-plant cost assumes that plants do not have any of the
required monitoring equipment. Actual per plant cost would be less if
some of the EB/S plants currently have some of the required equipment.
2.7.5 Reporting and Recordkeeping Requirements
Comment: Commenters stated that the recordkeeping and reporting
costs associated with the proposed standard were underestimated (IV-F-1;
IV-F-2; IV-D-10).
Response: The proposed standard would have required owners or
operators of sources using boilers as the air pollution control device
to submit within 10 days to the Administrator monitoring and opera-
tional data from flue gas oxygen monitors, firebox temperature monitors,
flow meters, and weekly visual checks if any of these monitoring
equipment indicated the occurrence of excess emissions. Owners or
operators of sources using air pollution control equipment other than
boilers would have been required to submit within 10 days to the
Administrator monitoring and operational data from a continuous gas
chromatograph monitoring system, flow meters, and weekly visual checks
if any of these monitoring equipment indicated the occurrence of
excess emissions. The cost to the EB/S industry to keep records and
to collect, prepare, and report the data specified by the proposed
standard through the first 5 years was estimated to be $122,000.
Industry's contention that the costs associated with the proposed
reporting and recordkeeping requirements may not be correct is not
applicable because these requirements have changed since proposal as
described below.
The reporting and recordkeeping requirements of the proposed
standard have been revised to be consistent with changes in the moni-
toring requirements. The revised reporting and recordkeeping provisions
do not require plant operators of sources that use boilers as air
pollution control devices to monitor firebox temperature, flue gas
oxygen, and natural gas ejector flow. Plant operators of sources that
use boilers or smokeless flares as air pollution control devices are
required to submit to the Administrator any monitoring and operating
data documenting any of the following: (1) a flow of 5 percent of
normal flow or less registered on any flow meter for any 3-hour period,
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(2) each occurrence of the flare's pilot light flame not present as
indicated by a heat-sensing device on the pilot light, and (3) each
weekly visual check that indicates if any vent stream is not being
routed to the pollution control device.
In addition, to ease the reporting burden, the requirement of
reporting excess emissions within 10 days after each occurrence has
been revised to submitting reports on a quarterly basis. It should be
noted that each plant operator subject to the standard is required to
keep records of the following information, as appropriate, depending
on the type of control equipment used: all flow rate measurements,
all flare pilot flame outages, all visual checks, all emissions test
results, all benzene concentration measurements, and all procedures
used for converting the measured benzene concentrations to a dry basis
at the source. The operator must make these records available for
inspection by the Administrator for a minimum of 2 years.
Thirteen existing EB/S plants are subject to the standard. No
new plants are expected to be constructed in the next 5 years. A
summary of the revised industry burden calculations for the 13 EB/S
plants is presented in Table 2-12. In summary, the industry burden to
keep records and collect, prepare, and report the data specified by
the promulgated standard will be about 3,700 person-hours ($46,000) per
year. This represents the average annual burden of the first 2 years
that the standard is in effect. The 3,700 person-hours translates to
approximately 5 person-hours ($60) per week per plant.
2.8 EXEMPTION REQUESTS
2.8.1 Exemption of Hydroperoxidation Process
Comment: Some commenters stated that Oxirane's hydroperoxidation
process should be exempt from the standard due to major process dif-
ferences and overall low emissions rate (IV-F-1; IV-F-3).
Response: The two processes used domestically to produce ethyl-
benzene are benzene alkylation with ethylene and mixed xylene extrac-
tion. The two processes used to produce styrene are ethyl benzene
dehydrogenation and ethylbenzene hydroperoxidation. The standard
applies to each plant producing ethylbenzene by benzene alkylation and
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TABLE 2-12. INDUSTRY REPORTING AND RECORDKEEPING BURDEN CALCULATIONS
Burden item
Person-hours
per
occurrence
Number of
occurrences
per
respondent
per year
Person-hours
per respondent Respondent Person-hours
per year per year per year
1.
(A)
Applications
(B)
NA
(C=AxB)
(D)
(E=CxD)
2. Surveys and Studies NA
3. Reporting Requirements
3A. Read Instructions 1
3B. Required Activities
Initial Emissions Test 280
Demonstration of CMS
Repeat of Emissions Test
Repeat of Oem. of CMS
3C. Create Information
3D. Gather Existing
Information
3E. Write Report
Source Report 4
Waiver Request 6
Notification of Initial
Emissions Test See 3B
Excess Emissions Report 40
No Excess Emissions
Report
4. Recordkeeping Requirements
4A. Read Instructions
4B. Plan Activities
4C. Implement Activities
4D. Develop Record System
4E. Time to Enter Information
Records of Startup, 1.5
Shutdown, Malfunctions,
etc.
Records of all Measure- 1.5
merit and Info. Required
by Standard
4F. Time to Train Personnel
4G. Time for Audits
TOTAL: All Burden Items
1
280
6.5
4.0
6.5
1,120.0
160
6.5
2.5
8.0
26.0
15.0
1,280.0
52
52
78
78
8.0
8.0
624.0
624.0
3,695.5
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to each plant producing styrene by ethyl benzene dehydrogenation and
ethylbenzene hydroperoxidation. The following benzene-containing
streams from the three covered processes are covered by the standard:
(1) alkylation reactor section vents; (2) atmospheric and pressure
column vents; (3) vacuum-producing device vents; and (4) hydrogen
separation system vents.
Although the ethylbenzene hydroperoxidation process differs from
the ethylbenzene dehydrogenation process, its main benzene emission
source, the vacuum column, is the same. The hydroperoxidation vacuum
column vents comprise the largest source of benzene emissions from
vacuum column vents in the EB/S industry. Also, although the hydro-
peroxidation process is different, the major emissions points are
identical to other emissions points within the rest of the industry.
Consequently, the Administrator concluded that it is reasonable to
cover this process under the standard, since there is no significant
difference in the emissions points to be controlled and the associated
control costs between those for other sources. The revised analysis
(see Response 2.5.1) indicates that Oxirane will incur no costs associ-
ated with reducing emissions to comply with the promulgated standard.
2.8.2 Exemption of Pilot and Experimental Facilities
Comment: A clarifying statement should be added to the regulation
to exempt pilot and experimental (R&D) facilities from the standard
regulating benzene emissions from EB/S plants, according to some
commenters. These facilities are used to test new technology. Control-
ling them would not be practical given the small amount of recoverable
benzene, the intermittent operation, and the economic limitations on
R&D expenditures (IV-F-1; IV-F-4; IV-D-10).
Response: [The cutoff of 0.03 g/s is expected to exempt most
experimental facilities. A request for additional information has
been sent to industry so this comment can be assessed further.]*
*Note to Steering Committee.
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2.9 LEGAL ISSUES
2.9.1 The Airborne Carcinogen Policy as Basis for Rulemaking
Comment: The proposed airborne carcinogen policy has been refuted
by the Agency's Science Advisory Board at its September 4-5, 1980,
meeting and apparently will not be promulgated in its original form.
EPA has reported that the policy is undergoing extensive revision, if
not actual withdrawal. Therefore, according to the commenters, it
would not be appropriate for the Agency to promulgate a standard for
EB/S plants that "has been developed consistent with the proposed EPA
policy and procedures" (44 FR 58642—Airborne Carcinogen Policy)
(IV-D-7; IV-D-11).
The commenters further contend that, given the likelihood of
significant revisions to the proposed policy before its finalization,
it is inappropriate for EPA to promulgate an emissions standard identi-
fied as "consistent with the proposed policy."
Response: The Airborne Carcinogen Subcommittee of the Science
Advisory Board met September 4-5, 1980, to review carcinogenicity and
exposure assessments prepared by EPA for six organic chemicals. In
the course of this review, members of the Subcommittee expressed
differences of opinion with the authors of the EPA assessments over
the appropriate interpretation of the animal bioassay results for
several of the chemicals. While such differences may reflect a need
for EPA to modify or better articulate a particular weight of evidence
judgment, they do not represent a rejection of EPA's published guide-
lines on carcinogenicity evaluation, nor do they "refute" the proposed
policy (44 FR 58642) of which the guidelines are a part.
EPA noted in the proposed policy that the procedures outlined
would "generally" be followed for actions taken in the interim between
proposal and promulgation. As a proposal, the policy does not bind
EPA to the procedures described, nor did EPA intend that changes were
responsive to public comment on the proposed policy or relevant rule-
makings. Furthermore, EPA recognizes that defense of a regulatory
decision cannot be based on a proposed policy. While the proposed
EB/S standard was developed "consistent with" the proposed policy.
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standards development was not based on the proposed policy. The final
EB/S rule and the basis for the rule are presented as a separate,
independent rulemaking.
In any event, the basis for the rulemaking is Section 112 of the
Clean Air Act, under which the Administrator is required to publish
proposed regulations establishing emissions standards for hazardous
air pollutants listed under Section 112. Although no approach for
developing such standards is specifically addressed in Section 112,
the Administrator believes the approach used for developing benzene
standards for EB/S plants meets the requirements of Section 112, is
sensible, and results in significant benzene reduction for a relatively
low cost.
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APPENDIX A
EMISSIONS DATA AND ENVIRONMENTAL IMPACTS
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APPENDIX A
EMISSIONS DATA AND ENVIRONMENTAL IMPACTS
A.I INTRODUCTION
The purpose of this appendix is to show how the benzene emissions
data used during development of the proposed and promulgated standards
were developed. An explanation of assumptions used in emissions
estimations accompanies the discussion. This appendix is divided into
four major sections: (1) Subsection A.2 discusses the assumptions
used in determining baseline benzene emissions at proposal and promul-
gation. This subsection also summarizes the benzene emissions data
used to determine the environmental impacts of these emissions;
(2) Subsection A.3 discusses the assumptions used in determining the
emissions levels associated with the regulatory alternatives examined
in selection of the final standard; (3) Subsection A.4 discusses the
methods used in fuel recovery credit estimation and summarizes the
energy impacts of the final standard; and (4) Subsection A.5 discusses
the assumptions used in determining total volatile organic compound
(VOC) emissions (benzene, other aromatics, Cx compounds, and C2/C5
compounds, and excluding methane and ethane) from the ethyl benzene/
styrene (EB/S) industry at current control levels and after application
of best demonstrated technology (BDT).
A.2 ORIGINAL AND REVISED BASELINE BENZENE EMISSIONS
A.2.1 U.S. Environmental Protection Agency (EPA) Baseline Benzene
Emissions Estimates at Proposal
The emissions rates presented at proposal were derived from an
integrated and totally uncontrolled model EB/S plant. Emissions rates
were first estimated assuming a constant nameplate production capacity,
A-2
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100 percent capacity utilization, and no control for four process
emissions sources: (1) alkylation reactor vents; (2) atmospheric/
pressure column vents; (3) vacuum column vents; and (4) H2 separation
vents. Variations in emissions potential among plants were averaged,
assuming a constant capacity and no control, to yield a "typical"
emissions rate for each emissions source in a plant. Emissions rates
for the four sources described above were scaled to actual plant
control levels, actual capacity use, and 8,000 operating hr/yr to
derive pi ant-by-plant emissions estimates. In plants where only
ethylbenzene or styrene was produced, the model plant's corresponding
process vents were used to estimate the contribution of that source.
The pi ant-by-plant emissions controls for continuous process
vents used at proposal are listed in Table A-l. At proposal, these
data (II-B-18) were derived from EPA 114 letters, plant visits, and
phone calls. The estimation of pi ant-by-plant emissions for each vent
involved multiplication of plant nameplate capacity by the sum of the
appropriate emissions factors times the specific control achieved.
The estimation of emissions from all plants for a given vent involved
multiplication of the emissions factor by the sum of each plant name-
plate capacity times the fraction of control for the vent at each
plant. The estimation of emissions from the hydrogen separation vent
involved multiplication of the entire industry nameplate capacity by
the emissions factor times the fraction of control. This was applic-
able because 99 percent control was assumed for the entire industry.
The data used to estimate emissions are listed in Table A-2.
A.2.1.1 Continuous Emissions Estimation—PI ant-By-Pi ant Emissions.
The following example shows how emissions from the American Hoechst "B,"
Baton Rouge, Louisiana, facility were estimated. PI ant-by-plant
emissions were estimated through the following calculations.
The nameplate capacity was multiplied by the sum of the products
of the emissions factor times (Infraction of control]) for each vent
type to determine a plant's emissions. For the American Hoechst "B"
plant, the calculation would be as follows:
A-3
-------
TABLE A-l. EMISSIONS CONTROLS PRESENT ON EB/S PLANTS AT PROPOSAL, LISTED BY VENT TYPE3
Emission controls on various vent types
Plant/location
American Hoechst, LA "A
American Hoechst, TX "B
Amoco, TX
ARCO, PA
ARCO, TX
Cos-Mar, LA
Dow Chemical, TX "A"
Dow Chemical, TX "B"
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
alnformation from EB/S
Control device key:
Alkylation reactor Atmospheric/pressure
area vents column vents
11 LD FLR No C
" RC/RS to SD FLR RC/RS to SD FLR
RC to BLR via Cmp BLR
-
No C No C
LD FLR LD FLR
No C SD FLR
BLR BLR
-
BLR BLR
LD FLR LD FLR
BLR RC to BLR via Cmp
SD FLR SD FLR
BLR BLR
BLR via NGE
Docket Item No. II-B-18.
FLR - Flare (60% efficiency)
BLR - Boiler (99% efficiency)
RC - Refrigerated condenser (85% efficiency)
RS - Refrigerated scrubber (85% efficiency)
Cmp - Compressor
Benzene/toluene Other vacuum
column vents column vents
No C No C
SD FLR via NGE SD FLR via NGE
RC to BLR via Cmp No C
No C No C
-
RC No C
No C No C
RS to SD FLR RS to SD FLR
No C No C
SD FLR SD FLR
RC RC
RC to BLR via Cmp RC to BLR via Cmp
-
No C No C
BLR via NGE BLR via NGE
NGE - Natural gas ejector
SD - Small diameter
LD - Large diameter
No C - No control
- Denotes no vents of this type in
that particular plant.
-------
TABLE A-2. NAMEPLATE CAPACITIES, EMISSIONS FACTORS, AND PERCENT CONTROL USED AS THE BASIS
FOR PLANT-BY-PLANT BENZENE EMISSIONS ESTIMATED AT PROPOSAL3
cn
Percent control by vent type (emissions factor )
Plant/location
American Hoechst, LA "A
American Hoechst, TX "B
Amoco, TX
ARCO, PA
ARCO, TX
Cos-Mar, LA
Dow Chemical , TX "A"
Dow Chemical, TX "B"
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
Capacity0
(10s Mg/yr)
" (0.33)(450)
" (0.67)(450)
375
200
(1.15X227)
600
(0.2) (700)
(0.8) (700)
200
100
275
600
550
40
54
Total emissions per vent
type (Mg/yr)
Plus H2 separation
Plus excess emissions
Total emissions
Alkylation reactor
area vents
(0.3)
0.6
(0.85)(0.6)
0.99
-
0
0.6
0
0.99
-
0.99
0.6
0
0.6
0.99
-
375
Atmospheric/pressure
column vents
(1.2)
0
(0.85X0.6)
0.99
-
0
0.6
0.6
0.99
-
0.99
0.6
0.85
0.6
0.99
-
1,308
alnformation from EB/S Docket Item No. II-B-18.
Emissions factors are in Mg/103 Mg.
GCapacity presented in utilization fraction times nameplate capacity; where nameplate capacity
Assumes 8,000 hr/yr of operation.
eAssumes uncontrolled emissions factor of 2.7 Mg/103 Mg, nameplate capacity and 99% control for
Excess emissions from the proposal background information document (BID) (EPA-450/3-37-035a; p
Benzene/toluene Other vacuum
column vents column vents Total emissions
(0.3) (0.05) (Mg/yr)a
0
0.6
0.99
0
-
0.85
0
(0.85X0.6)
0
0.6
0.85
0.85
-
0
0.99
425
alone is given,
H_ separation
. AA3) based on
0
0.6
0
0
-
0
0
(0.85)(0.6)
0
0.6
0.85
0.85
-
0
0.99
100 2
2
utilization fraction equals 1
continuous vents at all plants
nameplate production capacity
250
70
26
70
300
420
160
20
70
16
180
320
290
15
<1
,208
110
113
,451
.0.
(II-B-18).
and
existing controls.
-------
(0.67) x (450 x 103 Mg/yr) x [0.3 Mg/103 Mg x (1-0.6) x
(1-0.85) +1.2 Mg/103 Mg x (1-0.6) x (1-0.85) +0.3 Mg/103 Mg x
(1-0.6) + 0.05 Mg/103 Mg x (1-0.6)] = 70 Mg/yr ,
where
(0.67) x (450 x 103) = utilized fraction of nameplate production
capacity
(0.3/103) x (1-0.6) x (1-0.85) = uncontrolled emissions factor
from alkylation reactor area
vents
(1.2/103 ) x (1-0.6) x (1-0.85) = uncontrolled emissions factor
from atmospheric/pressure
column vents
(0.3/103) x (1-0.6) = uncontrolled emissions factor from benzene/
toluene column vents
(0.05/103) x (1-0.6) = uncontrolled emissions factor from other
vacuum column vents.
A.2.1.2 Continuous Emissions Estimation—Industry-Wide Emissions
For a Given Vent. The following example shows how industry-wide
emissions from the atmospheric/pressure column vents were estimated.
Each vent's industry-wide emissions were estimated through the following
calculations.
To determine industry-wide emissions for a given vent, multiply
the emissions factor by the summed products of the plant capacity
times (Infraction of control]) for each vent of that type at each
plant. For the atmospheric/pressure column vents, the calculation
would be as follows:
1.2 x [0.33 x (450) + 0.67 x (450) x (1-0.6) x (1-0.85) +
(375) x (1-0.99) x (1.15) x (227) + 600 x (1-0.6) + 0.2 x
(700) x (1-0.6) + 0.8 x (700) x (1-0.99) + 100 x (1-0.99) +
275 x (1-0.6) + 600 x (1-0.85) + 550 x (1-0.6) + 40 x
(1-0.99)] = 1,308 Mg/yr ,
where
1.2 = emissions factor for atmospheric/pressure column vents
(A/P vents) in Mg/103 Mg
A-6
-------
0.33 x (450 x 103 Mg/yr) + 0.67 x (450 x 10s Mg/yr) x (1-0.6)
x (1-0.85) = A/P vent "uncontrolled capacities" from American
Hoechst, LA, "A" and "B" plants, respectively,
103 Mg/yr (units given as an example for all
plants)
375 x (1-0.99) = A/P vent "uncontrolled capacity" from Amoco, TX
227 x (1.15) = A/P vent "uncontrolled capacity" from ARCO, TX
600 x (1-0.6) = A/P vents "uncontrolled capacity" from Cos-Mar, LA
0.2 x (700) x (1-0.6) + 0.8 x (700) x (1-0.99) = A/P vents "uncon-
trolled capacities"
from Dow Chemical,
TX, "A" and "B"
Plants
100 x (1-0.99) = A/P vent "uncontrolled capacity" from El Paso, TX
275 x (1-0.6) = A/P vent "uncontrolled capacity" from Gulf, LA
600 x (1-0.85) = A/P vent "uncontrolled capacity" from Monsanto, TX
550 x (1-0.6) = A/P vent "uncontrolled capacity" from Oxirane, TX
40 x (1-0.99) = A/P vent "uncontrolled capacity" from Sun Oil, TX.
A.2.1.3 Continuous Emissions Estimation—Industry-Wide Emissions
From the Hydrogen Separation Vent. The following calculation shows
how industry-wide emissions from the hydrogen separation column vent
were estimated. Because specific pi ant-by-plant data were unavailable
at proposal, the entire industry nameplate capacity was multiplied by
the emissions factor for the hydrogen separation vent times (Infraction
of control]) to estimate emissions due to hydrogen separation vents.
The calculation would be as follows:
4,000 x 103 Mg/yr [2.7 Mg/103Mg x (1-0.99)] = 110 Mg/yr,
where
4,000 = industry nameplate capacity
2.7 = emissions factor for hydrogen separation vent
(1-0.99) = uncontrolled percent.
A.2.1.4 Excess Emissions Estimation. Excess emissions can occur
during (1) plant startup, (2) plant shutdown, and (3) as a result of
either process or air pollution control equipment malfunction. A
comprehensive discussion of the sources and amounts of excess emissions
A-7
-------
is contained in the proposal BID (EPA-450/3-79-035a; p. AA3). In
summary, the proposal BID explains that at proposal, baseline excess
emissions from EB/S facilities totaled about 133 Mg/yr based on 100
percent nameplate production capacity and existing controls.
A.2.2 Revised U.S. Environmental Protection Agency (EPA) Baseline
Benzene Emissions Estimates
Since proposal, the Chemical Manufacturer's Association (CMA)
commented that EPA's benzene emissions data were overestimated because
the EPA estimates did not consider plant-specific production and
control levels. CMA supplied plant-specific emissions data that
included emissions sources, benzene emissions rates in grams per
second for each emissions source, control device efficiency assumptions,
actual operating capacities, and actual hours per year for continuous
and excess emissions based on actual operating hours per year (IV-D-13).
The grams-per-second benzene emissions flow rate was calculated by CMA
from actual annual benzene flow rates averaged over 8,760 hr/yr.
EPA used the CMA data to revise benzene emissions estimates from
the EB/S industry. EPA converted the benzene emissions rate estimates
presented in the CMA data package (IV-D-13) from grams per second to
megagrams per year assuming 8,760 hr/yr. Revised EPA estimates, in
contrast to original estimates, reflect actual vent-by-vent emissions
rates, capacity utilization, and control levels, and assume 8,760
operating hr/yr. EPA also recalculated emissions estimates from
flares by revising the flare destruction efficiency rating of 60
percent, which CMA used to estimate emissions from flares, to 90
percent (see Response 2.3.1 of this document). First, EPA calculated
uncontrolled emissions from the CMA emissions estimates at 60 percent
control. Second, EPA multiplied the uncontrolled emissions rate by
10 (=100-90) percent to estimate emissions at 90 percent control.
Emissions estimates for each emissions source were summed to estimate
a plant's total emissions, and pi ant-by-plant emissions estimates were
summed to estimate industry-wide emissions. It should be noted that
according to the CMA data package (IV-D-13), the EB/S industry currently
is not operating at peak capacity and exhibits an 80-percent overall
control level (see Table A-3). Some plants achieve more control than
A-8
-------
TABLE A-3. CAPACITY UTILIZATION, PERCENT CONTROL, AND EB/S
PLANTS IN OPERATION AT PROMULGATION3
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
Industry-wide
Capacity
utilization
(%)
60
100
90
45
100
100
100
100
100
100
100
100
100
90
Overall
control
(%)
90
95
50
50
75
90
90
90
90
60
90
90
90
80
Operating
hr/yr
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
8,760
aActual production and control levels from CMA data package (IV-D-13) used
by EPA in estimating current pi ant-by-plant benzene emissions. Operating
hours per year assumed to be 8,760.
A-9
-------
do others; yet 12 of 13 plants have at least one boiler in operation
that could be used to control continuous process benzene emissions (at
an EPA-estimated efficiency of 99 percent). Also, 8 of 13 EB/S plants
have at least one flare in operation that is used to control excess
benzene emissions.
Based on the data supplied by CMA and the assumptions previously
noted, EPA reestimated total benzene emissions from the EB/S industry
to be 370 Mg/yr. Of this total, 340 Mg/yr were estimated to result
from continuous process emissions sources and about 33 Mg/yr were
estimated to result from excess process emissions sources (see Table
A-4).
A.3 BENZENE EMISSIONS ESTIMATES USED IN DEVELOPING THE PROMULGATED
STANDARD
A.3.1 Introduction
Determination of the basis of the standard for the EB/S industry
is explained in Response 2.5.1 of this document. In summary, EPA
selected BDT for EB/S process vents as the combination of (1) control-
ling continuous process vents with benzene flow rates greater than
0.03 g/s by routing emissions to a boiler or, if already being done
so, a smokeless flare; and (2) no required control of excess emissions
during plant startup or shutdown. However, excess emissions due to
malfunctions in process or control equipment are allowed only up to
16 hours. Beyond BDT for EB/S process vents was determined to be the
combination of (1) controlling continuous process vents with benzene
flow rates greater than 0.03 g/sec by routing emissions to a boiler
only and would not allow the use of smokeless flares for control of
continuous process vents, and (2) controlling excess emissions as
under BDT.
A.3.2 Summary of Impacts of BDT and Beyond BDT
The rationale for determining BDT and beyond BDT is discussed
in detail in Response 2.5.1 of this document. In summary, BDT for the
EB/S industry would affect five EB/S plants and would reduce total
nationwide benzene emissions by 230 Mg/yr (250 ton/yr). Beyond BDT
for the EB/S industry would affect eight EB/S plants and would reduce
total nationwide benzene emissions by 240 Mg/yr (260 ton/yr). Table
A-10
-------
TABLE A-4. REVISED EPA BASELINE BENZENE EMISSIONS ESTIMATES'
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
ARCO, TX
Cos-Mar, LA
Dow Chemical , TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
SUBTOTAL
TOTAL
Continuous
emissions
(Mg/yr)
117
6
15
40
Ob
20
38
57
5
19
4
6
12
1
340
373
Excess
emissions
(mg/yr)
2
2
1
2
Ob
1
1
1
1
1
16
0
5
Fl
33
Revised EPA baseline benzene emissions estimates after proposal. Calcu-
lated from CMA data (IV-D-13).
}Plant shutdown since 1978.
A-ll
-------
A-5 lists the vent-by-vent emissions for each regulatory alternative
EPA examined in determining BDT and beyond BDT. Each column in Table
A-5 represents different combinations of continuous and excess emissions
control used in determining BDT and beyond BDT.
A.4 FUEL RECOVERY CREDIT ESTIMATION AND ENERGY IMPACTS
A.4.1 Fuel Recovery Credit Estimation
EPA estimated the fuel recovery credits for vent streams covered
by the proposed standard from the following general equation:
Annual fuel savings = (mass emissions rate of benzene for the particular
stream) x (ratio of total flow to benzene flow
by mass for the stream type) x (heating value of
the total flow of the stream type).
This general equation was applied assuming:
8,760 hr/yr for fuel recovery.
The vent stream characteristics (weight percentage of com-
ponents) given in the proposal BID (EPA-450/3-79-035a;
pp. 3-23).
Lower heating value of recovered volatile organic compound
(VOC) because water is not condensed to recover the heat of
vaporization).
Approximated heating values were used: heating value of
benzene (40.6 MJ/kg; 17,446 Btu/lb) for benzene and other
aromatics, of methane (50.0 MJ/kg; 21,502 Btu/lb) for C^
and of propane (46.4 MJ/kg; 19,929 Btu/lb) for C2/C5.
These general assumptions were used to obtain specific fuel
recovery factors for the alkylation reaction area vents, atmospheric/
pressure and vacuum benzene/toluene (B/T) column vents, other vacuum
column vents, and hydrogen separation vents as follows: (1) for
alkylation reaction area vents, 10.0 mass ratio of total flow to
benzene and 24.7 MJ/kg (10,618 Btu/lb) heating value of total flow;
(2) for atmospheric, pressure, and vacuum B/T column vents, 2.22 mass
ratio of total flow to benzene and 35.6 MJ/kg (15,289 Btu/lb) heating
value of total flow; (3) for other vacuum column vents, 6.67 mass
ratio of total flow to benzene and 25.4 MJ/kg (10,936 Btu/lb) heating
A-12
-------
TABLE A-5. REVISED EPA BENZENE EMISSIONS ESTIMATES ON A SOURCE-BY-SOURCE
BASIS AT BASELINE AND FOR ALL REGULATORY ALTERNATIVES
(GRAMS PER SECOND [MEGAGRAMS PER YEAR])
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
Oxirane, TX
ARCO, PA
Cos-Mar, LA
Emissions source3
(Type)0
Absorber (C)
Stripper (C) h
Superheater (C)n
Superheater (C)
Subtotal (C)
Flare (X)
Subtotal (X)
TOTAL (CX)
Boiler (C)
Boiler (C)
Boiler (C)
Superheater (C)
Subtotal (C)
Flare (X)
Subtotal (X)
TOTAL (CX)
None (C)
None (C) h
Superheaterh(C)
Furnace (C)n
Subtotal (C)
Flare (X)
None (X)
Subtotal (X)
TOTAL (CX)
Flare (c)
TOTAL
None (C)
Superheater (C)
Subtotal (C)
None (X)
Subtotal (X)
TOTAL (CX)
Condenser (C)
Condenser (C)
Flare (C)
Flare (C) h
Superheater (C)£
Superheater (C)
None (C)
None (C)
None (C)
None (C)
Subtotal (C)
Flare (X)
Flare (X)
Subtotal (X)
TOTAL (CX)
Basel inec
(Hg/yr)
2.09
1.04
0.103
0.472
(117) ,
0.0541
(2)
(119)
0.039
0.039
0.039
0.071
(6)
0.058
(2)
(8)
0.0016
0.0006
0.2854
0.1674
(15)
0.014
0.016
(1)
(16)
0.19
(6)
1.26
0.024
(40) ,
0.0781
(2)
(42)
0.016
0.016
0.055
0.064
0.225
0.262
0.00009
0.00293
0.00252
0.00007
(20)
0.0199
0.0232
(1)
(21)
BDTd
(Mg/yr)
0.021
0.0104
0.103
0.472
(19) ,-
0.0571
(2)
(21)
0.039
0.039
0.039
0.071
(6)
0.058
(2)
(8)
0.0016
0.0006
0.2854
0.1674
(15)
0.014
0.016
(1)
(16)
0.19
(6)
0.013
0.024
(1) ,•
0.1051
(3)
(4)
0.016
0.016
0.055
0.064
0.225
0.262
0.00009
0.00293
0.00252
0.00007
(20)
0.0199
0.0232
(1)
(21)
Beyond
BDTe
(Mg/yr)
0.021
0.0104
0.103
0.472
(19) ,
0.0571
(2)
(21)
0.039
0.039
0.039
0.071
(6)
0.058
(2)
(8)
0.0016
0.0006
0.2854
0.1674
(15)
0.014
0.016
(1)
(16)
0.002
(0.1)
0.013
0.024
(1) ,
0.1051
(3)
(4)
0.016
0.016
0.055
0.064
0.225
0.262
0.00009
0.00293
0.00252
0.00007
(20)
0.0199
0.0232
(1)
(21)
BDT plus
control of
excess f
emissions
(Mg/yr)
0.021
0.0104
0.103
0.472
(19) ,
0.057'
(2)
(21)
0.039
0.039
0.039
0.071
(6)
0.058
(2)
(8)
0.0016
0.0006
0.2854
0.1674
(15)
0.014
0.002
(0.5)
(16)
0.19
(6)
0.013
0.024
(1)
0.011
(0.3)
(1.3)
0.016
0.016
0.055
0.064
0.225
0.262
0.00009
0.00293
0.00252
0.00007
(20)
0.0199
0.0232
(1)
(21)
BDT plus
control of
!xc?ss q
emissions"
(Mg/yr)
0.021
0.0104
0.103
0.472
(19) ,
0.0571
(2)
(21)
0.039
0.039
0.039
0.071
(6)
0.058
(2)
(8)
0.0016
0.0006
0.2854
0.1674
(15)
0.014
0.002
(0.5)
(16)
0.002
(0.1)
0.013
0.024
(1)
0.011
(0.3)
(1.3)
0.016
0.016
0.055
0.064
0.225
0.262
0.00009
0.00293
0.00252
0.00007
(20)
0.0199
0.0232
(1)
(21)
(continued)
A-13
-------
TABLE A-5. (continued)
Plant/location
El Paso Products, TX
Dow Chemical , TX
Dow Chemical, MI
Gulf, LA
Emissions source3
(Type)D
Furnace (C)
Superheater (C)
Flare (C)
Subtotal (C)
Flare (X)
Subtotal (X)
TOTAL (CX)
Scrubber (C)
Scrubber (C)
Flare (C)
Flare (C)
Flare (C)
Furnace (C)
Furnace (C)
Furnace (C)
Furnace (C)
Furnace (C)
Furnace (C)
Furnace (C)
Furnace (C)
Furnace (C)
Boiler (C)
Boiler (C)
Boiler (C)
None (C)
Flare (C)
Subtotal (C)
None (X)
None (X)
None (X)
None (X)
None (X)
None (X)
Subtotal (X)
TOTAL (CX)
Condenser (C)
Stripper (C)
Furnace (C)
Furnace (C)
Condenser (C)
Subtotal (C)
None (X)
None (X)
Subtotal (X)
TOTAL (CX)
Condenser (C)
Condenser (C)
Condenser (C)
Condenser (C)
Flare (C) h
Superheater rc)n
Reheater (C)n
Subtotal (C)
Flare (X)
Subtotal (X)
TOTAL (CX)
Baseline0
(Mg/yr)
0.00121
0.00863
0.164
(5) ,
0.0551
(1)
(6)
0.46
0.46
0.02
0.02
0.02
0.098
0.037
0.003
0.003
0.003
0.003
0.0043
0.0043
0.00144
0.0072
0.0072
0.0072
0.0032
0.00006
(38) .
0.00661
0.0215 ,
0.000981
0.0023
0.0014
0.00012
(1)
(39)
1.697
0.0633
0.023
0.023
0.0003
(57) .
0.00321
0.0032
(1)
(58)
0.0003
0.0003
0.002
0.0003
0.138
0.364
0.142
(19) ,
0.03471
(1)
(20)
BDTd
(Mg/yr)
0.00121
0.00863
0.164
(5)
0.055
(1)
(6)
0.0046
0.0046
0.02
0.02
0.02
0.098
0.037
0.003
0.003
0.003
0.003
0.0043
0.0043
0. 00144
0.0072
0.0072
0.0072
0.0032
0.00006
(8) ,
0.00691
0.0215,
0.00111
0.0023
0.0014
0.00012
(1)
(9)
0.017
0.0633
0.023
0.023
0.0003
(4) ,
0.00381
0.0032
(1)
(5)
0.0003
0.0003
0.002
0.0003
0.138
0.364
0.142
(19) ,
0.03471
(1)
(20)
Beyond
BDT6
(Mg/yr)
0.00121
0.00863
0.002
(0.4) .
0.0641
(2)
(2.4)
0.0046
0.0046
0.02
0.02
0.02
0.098
0.037
0.003
0.003
0.003
0.003
0.0043
0.0043
0.00144
0.0072
0.0072
0.0072
0.0032
0.00006
(8) .
0.00691
0.0215,
0.00111
0.0023
0.0014
0.00012
(1)
(9)
0.017
0.0633
0.023
0.023
0.0003
(4) ,
0.00381
0.0032
(1)
(5)
0.0003
0.0003
0.002
0.0003
0.0014
0.364
0.142
(16) ,
0.041
(1)
(17)
BDT plus
control of
excess f
emissions
(Mg/yr)
0.00121
0.00863
0.164
(5)
0.055
(1)
-(6)
0.0046
0.0046
0.02
0.02
0.02
0.098
0.037
0.003
0.003
0.003
0.003
0.0043
0.0043
0.00144
0.0072
0.0072
0.0072
0.0032
0.00006
(8)
0.0007
0.0022
0.00011
0.00023
0.00014
0.000012
(0.1)
(8.1)
0.017
0.0633
0.023
0.023
0.0003
(4)
0.0004
0.0003
(0.02)
(4.02)
0.0003
0.0003
0.002
0.0003
0.138
0.364
0.142
(19) n-
0.03471
(1)
(20)
BDT plus
control of
!X«SS g
emissions'
(Mg/yr)
0.00121
0.00863
0.002
(0.4) .
0.0641
(2)
(2.4)
0.0046
0.0046
0.02
0.02
0.02
0.098
0.037
0.003
0.003
0.003
0.003
0.0043
0.0043
0.00144
0.0072
0.0072
0.0072
0.0032
0.00006
(8)
0.0007
0.0022
0.00011
0.00023
0.00014
0.000012
(0.1)
(8.1)
0.017
0.0633
0.023
0.023
0.0003
(4)
0.0004
0.0003
(0.02)
(4.02)
0.0003
0.0003
0.002
0.0003
0.0014
0.364
0.142
(16) ;
0.041
(1)
(20)
(continued)
A-14
-------
TABLE A-5. (continued)
Plant/location
Sun Oil, TX
Monsanto, TX
U.S. Steel, TX
TOTAL CONTINUOUS
TOTAL EXCESS
TOTAL
Emissions source3
(Type)"
Scrubber (C)
Scrubber (C)
Superheater (C)
Subtotal (C)
Flare (X)
Subtotal (X)
TOTAL (CX)
Scrubber (C)
Condenser (C)
None (C)
None (C)
Boiler (C)
Superheater (C)
Superheater (C)
Subtotal (C)
None (X)
Flare (X)
Subtotal (X)
TOTAL (CX)
Superheater (C)
Reboiler (C)
Reboiler (C)
Subtotal (C)
None (X)
Subtotal (X)
TOTAL (CX)
Baseline0
(Mg/yr)
0.32
0.02
0.03
(12) ,
0.151
(5)
(17)
0.0047
0.0002
0.0018
0.0155
0.0477
0.034
0.034
(4)
0.4899
0.0134
(16)
(20)
0.0016
0.0058
0.0058
(1)
0.0005
(0.02)
(1.02)
10.77
(340)
1.05
(33)
11.82
(373)
BDTd
(Mg/yr)
0.0032
0.02
0.03
(2) •
0.161
(5)
(7)
0.0047
0.0002
0.0018
0.0155
0.0477
0.034
0.034
(4)
0.4899
0.0134
(16)
(20)
0.0016
0.0058
0.0058
(1)
0.0005
(0.02)
(1.02)
3.52
(111)
1.09
(34)
4.61
(145)
Beyond
BDTe
(Mg/yr)
0.0032
0.02
0.03
(2) .
0.161
(5)
(7)
0.0047
0.0002
0.0018
0.0155
0.0477
0.034
0.034
(4)
0.4899
0.0134
(16)
(20)
0.0016
0.0058
0.0058
(1)
0.0005
(0.02)
(1.02)
3.03
(95)
1.09
(35)
4.129
(130)
BDT plus
control of
excess f
emissions
(Mg/yr)
0.0032
0.02
0.03
(2) ,
0.161
(5)
(7)
0.0047
0.0002
0.0018
0.0155
0. 0477
0.034
0.034
(4)
0.049
0.0134
(2)
(6)
0.0016
0.0058
0.0058
(1)
0.0001
(0.003)
(1.003)
3.52
(111)
0.5
(15)
4.02
(126)
BDT plus
control of
?x«ss g
emissions'
(Mg/yr)
0.0032
0.02
0.03
(2) ,
0.161
(5)
(7)
0.0047
0.0002
0.0018
0.0155
0.0477
0.034
0.034
(4)
0.049
0.0134
(2)
(6)
0.0016
0. 0058
0.0058
(1)
0.0001
(0.003)
(1.003)
3.03
(95)
0.5
(16)
3.54
(111)
aEach emissions source is named by the type of devices that currently control these sources.
Defines if the source is continuous (C) or excess (X).
GBaseline emissions rates.
Emissions estimates after establishing 0.03 g/s emissions floor. Emissions in excess of the cutoff rate with the
exception of those already routed to boilers or flares must be routed to a boiler. No control of excess emissions.
Emissions estimates after establishing 0.03 g/s emissions floor. Emissions in excess of the cutoff rate with the
exception of those being routed to boilers must be routed to a boiler. No control of excess emissions required.
Emissions estimates after establishing 0.03 g/s emissions floor. Emissions in excess of the cutoff rate with the
exception of those already being routed to boilers or flares must be routed to a boiler. Must also control excess
emissions by routing them to smokeless flares.
Emissions estimates after establishing 0.03 g/s emissions floor. Emissions in excess of the cutoff rate with the
exception of those already being routed to boilers or flares must be routed to a boiler. Must also control excess
emissions by routing them to smokeless flares.
No further control required although emissions are greater than 0.03 g/s because superheater, boiler, furnace,
and reheater are equivalent as combustion devices.
Excess emissions from control devices increase as more streams are vented into the control device.
A-15
-------
value of total flow; and (4) for hydrogen separation vents, 16.7 mass
ratio of total flow to benzene and 15.5 MJ/kg (6,679 Btu/lb) heating
value of total flow.
EPA estimated annual fuel savings for particular vents by multi-
plying benzene flow rate and the appropriate multipliers (depending on
the vent stream type and the location of the EB/S plant) and conver-
sion factors. If a particular plant had one or more vents covered by
the proposed standard, annual fuel savings were estimated for each
vent and then summed to present total annual fuel savings. The benzene
flow rate in grams per second was obtained from the CMA data package
(IV-D-13). The following example demonstrates how annual fuel savings
were estimated:
Emission source (from CMA data): Absorber
Vent type (from proposal BID): Alkylation reaction area vent
Plant name: American Hoechst
Plant location: Louisiana
Benzene flow rate (from CMA data): 2.09 g/s.
Estimation: annual savings = (2.09 g benzene/s) x (lb/453.6g) x
(3,600 s/hr) x (10.0 mass ratio of total
flow to benzene) x (10,618 Btu/lb total
gas flow) x (MMBtu)/106 Btu) x (8,760 hr/
yr) = 15,000 MMBtu/yr.
A.4.2 Summary of Impacts of BDT and Beyond BDT
The rationale for determining BDT and beyond BDT is discussed in
detail in Response 2.5.1 of this document. In summary, BDT for the
EB/S industry would result in a net energy savings of 47 x 103 MMBtu/yr
(50 x 103 GJ/yr). Beyond BDT for the EB/S industry would result in a
net energy savings of 50 x 103 MMBtu/yr (53 x 103 GJ/yr).
A.5 TOTAL VOLATILE ORGANIC COMPOUND (VOC) EMISSIONS OF THE PROMULGATED
STANDARD
A.5.1 Introduction
Vent streams within EB/S plants contain benzene and other VOC's
in varying weight percentages. Therefore, in addition to controlling
benzene emissions from EB/S process vents, the promulgated standards
A-16
-------
will reduce other VOC's from EB/S process vents. These VOC's include
benzene, other aromatics, and C2/C5 compounds (excluding methane). To
estimate total VOC emissions rates from EB/S process vents, EPA used
baseline benzene emissions data (see Table A-5) and EB/S vent stream
characteristics as described in the proposal BID (EPA-450/3-79-035a;
pp. 3-23). First, total baseline (current) VOC emissions (benzene,
other aromatics, C2/C5) were estimated. Second, total VOC emissions
after application of the standard were estimated.
A.5.2 Baseline Total Volatile Organic Compound Emissions
A.5.2.1 Methodology. EB/S vent streams contain many different
waste gases in different weight percentages. EPA estimated total VOC
emissions by proportionally increasing the baseline benzene emissions
estimates provided in Table A-5 using weight percentages of other
VOC's within EB/S vent streams, which are provided in the proposal
BID. Baseline emissions estimates were increased proportionally by
varying amounts depending on the vent stream classification; i.e.,
whether it is classified as an alkylation reaction area vent,
atmospheric/pressure column vent, vacuum column vent (either B/T
vacuum or other vacuum vent), or a hydrogen separation vent. Each of
these vent types have different vent gas characteristics. Based on
the varying vent gas characteristics, a multiplication factor using
the ratio of mass percentage of total organic emissions to mass percent-
age of benzene emissions for each vent type was estimated for each
EB/S vent type. These factors were multiplied by the baseline emissions
to estimate total VOC emissions for each EB/S vent stream. By summing
total VOC emissions rates for each vent, EPA estimated pi ant-by-plant
total VOC emissions estimates to provide an industry-wide total VOC
emissions estimate.
A.5.2.2 Alkylation Reactor Area Vents. Alkylation reactor area
vent streams are mainly low-flow, high-concentration streams. These
vent streams contain approximately 10 percent by weight benzene and
10 percent by weight C2/C5 compounds. Therefore, alkylation reactor
area streams contain approximately 20 percent by weight total VOC.
Multiplication of the baseline benzene emissions rates provided in
A-17
-------
Table A-5 by a factor of two (20 percent total VOC/10 percent benzene)
provided a total VOC emissions estimate for alkylation reactor area
vents.
A.5.2.3 Atmospheric/Pressure Column Vents. Atmospheric/pressure
column vent streams are mainly low-flow, high-concentration streams.
These vents contain approximately 45 percent by weight benzene, 5 per-
cent by weight other aromatics, and 20 percent by weight C2/C5 compounds,
Therefore, atmospheric/pressure column streams contain approximately
70 percent by weight total VOC. Multiplication of the baseline benzene
emissions rates provided in Table A-5 by a factor of 1.5 (70 percent
total VOC/45 percent benzene) provided a total VOC emissions estimate
for atmospheric pressure column vents.
A.5.2.4 Vacuum Column Vents. Vacuum column vents are mainly
low-flow, high-concentration streams. Two vacuum column vent types
with different flow rate characteristics are delineated here--B/T
vacuum and other vacuum.
1. B/T vacuum column vents. B/T vacuum vents contain approxi-
mately 45 percent by weight benzene, 5 percent by weight
other aromatics, and 20 percent by weight C2/C5 compounds.
Therefore, B/T vacuum streams contain approximately 70
percent by weight total VOC. Multiplication of the baseline
benzene emissions rates provided in Table A-5 by a factor
of 1.5 (70 percent total VOC/45 percent benzene) provided a
total VOC emissions estimate for B/T vacuum vents.
2. Other vacuum column vents. These vacuum column vents contain
approximately 15 percent by weight benzene, 5 percent by
weight other aromatics, and 5 percent by weight C2/C5 com-
pounds. Therefore, other vacuum column vent streams contain
approximately 25 percent by weight total VOC. Multiplication
of the baseline benzene emissions rates provided in Table A-5
by CMA by a factor of 1.7 (25 percent total VOC/15 percent
benzene) provided a total VOC emissions estimate for other
vacuum column vents.
A.5.2.5 Hydrogen Separation Vents. Hydrogen separation streams
are mainly high-flow, low-concentration streams. These vents contain
approximately 6 percent by weight benzene, 30 percent by weight other
aromatics, and 2 percent by weight C2/C5 compounds. Therefore, hydrogen
separation streams contain approximately 38 percent by weight total VOC.
A-18
-------
Multiplication of the baseline benzene emissions rates provided in
Table A-5 by a factor of 6.3 (38 percent total VOC/6 percent benzene)
provided a total VOC emissions estimate for hydrogen separation vents.
A.5.2.6 Baseline Total Organic Emissions Estimates. By using
the above procedure for each vent type, EPA estimated current total
VOC emissions from EB/S plants. The Agency assumed 8,760 operating
hours and a 90-percent flare benzene destruction efficiency. Table A-6
summarizes current total VOC emissions on a pi ant-by-plant basis. EPA
estimated the current total VOC emissions rate from EB/S process vents
to be 980 Mg/yr (1,100 ton/yr). Of this total, 910 Mg/yr (1,010 ton/yr)
are from continuous process sources while 70 Mg/yr (80 ton/yr) are
from excess emissions sources.
A.5.3 Total Organic Emissions Estimates of the Promulgated Standard
The promulgated standard for EB/S process emissions sources will
decrease total VOC emissions by 530 Mg/yr (580 tons/yr), from 980 Mg/yr
(1,080 tons/yr) to about 450 Mg/yr (500 tons/yr). Total continuous
process VOC emissions will be reduced by 530 Mg/yr (580 ton/yr), from
910 Mg/yr (1,000 ton/yr) to 380 Mg/yr (420 ton/yr). Total excess VOC
emissions will increase by about 2 Mg/yr (2 ton/ yr), from about
68 Mg/yr (75 ton/yr) to 70 Mg/yr (77 ton/yr) because more VOC emissions
will be routed to boilers. Table A-6 summarizes total VOC emissions
of the promulgated standard on a pi ant-by-plant basis.
A-19
-------
TABLE A-6. ESTIMATED TOTAL VOLATILE ORGANIC COMPOUND EMISSIONS AT
CURRENT CONTROL LEVELS AND WITH THE PROMULGATED STANDARD
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
SUBTOTAL
TOTAL
Basel
Continuous
(g/s
[Mg/yr])
9.85
(310.27)
0.49
(15.43)
0.78
(24. 57)
5.19
(163.48)
2.21
(69.61)
2.27
(71.50)
3.56
(112.14)
0.29
(9.13)
2.61
(82.21)
0.57
(17.95)
0.49
(15.43)
0.69
(21.73)
0.04
(1.26)
29.04
(914.71)
31
(982
ine
Excess
(g/s
[Mg/yr])
0.14
(4.41)
0.15
(4.72)
0.048
(1.51)
0.25
(7.87)
0.084
(2.65)
0.066
(2.08)
0.013
(0.41)
0.332
(10.46)
0.221
(6.96)
0.84
(26.46)
0.00
(0.00)
0.02
(0.63)
0.0013
(0.04)
2.17
(68.20)
.21
.91)
Promulgated standard
Continuous
(g/s
[Mg/yr])
3.65
(114.97)
0.49
(15.43)
0.78
(24.57)
0.2
(6.30)
2.21
(69.61)
0.47
(14.80)
0.19
(5.98)
0.29
(9.13)
2.61
(82.21)
0.57
(17.95)
0,49
(15.43)
0.05
(1.57)
0.04
(1.26)
12.04
(379.21)
14.
(449.
Excess
(g/s
[Mg/yr])
0.16
(5.04)
0.15
(4.72)
0.048
(1.51)
0.27
(8.50)
0.084
(2.65)
0.069
(2.17)
0.015
(0.47)
0.332
(10.46)
0.221
(6.96)
0.84
(26.46)
0.00
(0.00)
0.03
(0.94)
0.0013
(0.04)
2.22
(69.92)
26
13)
A-20
-------
APPENDIX B
METHODOLOGY FOR ESTIMATING LEUKEMIA INCIDENCE AND MAXIMUM
LIFETIME RISK FROM EXPOSURE TO BENZENE EMISSIONS FROM
ETHYLBENZENE/STYRENE PROCESS VENTS
-------
APPENDIX B
METHODOLOGY FOR ESTIMATING LEUKEMIA INCIDENCE AND MAXIMUM
LIFETIME RISK FROM EXPOSURE TO BENZENE EMISSIONS FROM
ETHYLBENZENE/STYRENE PROCESS VENTS
B.I INTRODUCTION
The purpose of this appendix is to describe the methodology and to provide
the information used to estimate leukemia incidence and maximum lifetime risk
from population exposure to benzene emissions from ethylbenzene/styrene (EB/S)
process vents. The methodology consists of four major components: estimating
annual average concentration patterns of benzene in the region surrounding each
plant, estimating the population associated with each computed concentration,
computing dosage by summing the products of the concentrations and associated
populations, and estimating annual incidence and maximum lifetime risk from
dosage and concentration estimates. Due to the assumptions made in each of these four
steps of the methodology, there is considerable uncertainty associated with the
lifetime individual risk and leukemia incidence numbers calculated in this
appendix. These uncertainties are explained in Section B.6 of this appendix.
A description of the health effects of benzene are not included in this appendix;
however, information on health effects is contained in EPA docket number OAQPS 79-3
and Response to Public Comments on EPA's Listing of Benzene Under Section 112 and
Relevant Procedures for the Regulation of Hazardous Air Pollutants. EPA 450/5-82-003.
0
B.2 ATMOSPHERIC DISPERSION MODELING
The long-term version of the Industrial Source Complex (ISCLT) dispersion
i
model was used to estimate annual average benzene concentrations in the vicinity
of 14 EB/S plants. (For the purpose of this analysis the "A" and "B" units of
the Dow, Texas, plant are assumed to be two plants.)
Seasonal or annual stability array (STAR) summaries are principal meteoro-
logical input to the ISCLT dispersion model. STAR data are standard climatological
frequence of occurrence summaries formulated for use in EPA models and available
for major U.S. sites from the National Climatic Center, Asheville, N.C. A STAR
summary is a joint frequency of occurrence of wind speed stability and wind
direction categories, classified according to the Pasquill stability categories.
For this modeling analysis, annual STAR summaries were used. Urban mixing
heights and rural mixing heights were used for plants in urban and rural areas,
respectively. The ISCLT dispersion model also required user input of ambient
temperatures by stability category and mixing heights by stability and wind
B-l
-------
speed categories, for each season. Seasonal temperature and mixing height input
data were computed by averaging hourly CRSTER meteorological preprocessor data
for each category.
The model receptor grid consists of 10 downwind distances located along
16 radials. The radials are separated by 22.5° intervals beginning with 0.0°
and proceeding clockwise to 337.5°. The 10 downwind distances for each radial
are 0.2, 0.3, 0.5, 0.7, 1.0, 2.0, 5.0, 10.0, 15.0, and 20.0 kilometers. The
center of the receptor grid for each plant was assumed to be the center provided
by the industry (Docket item IV-D-13) except for the Dow (A) plant in
Freeport, Texas. The center specified by the industry for this plant is a
considerable distance (more than 1 km) from the indicated emission points.
Consequently, the plant center was adjusted to approximate the center of the
emission points, to attain better modeling accuracy. These inputs are discussed
in Section B.5.1.
The ISCLT output for all plants modeled, consisting of annual concentration
estimates at all 160 receptors, is contained in the docket (Docket item IV-J-9).
ISCLT dispersion model concentration estimates have been found to be within a
2
factor of two of measured concentrations in most tests.
B.3 POPULATION AROUND ETHYLBENZENE/STYRENE PLANTS
The human exposure model (HEM)3 was used to estimate the population that
resides in the vicinity of each receptor coordinate surrounding each EB/S plant.
A slightly modified version of the "Master Enumeration District List-- Extended"
(MED-X) data base is contained in the HEM and used for population pattern
estimation. This data base is broken down into enumeration district/ block group
(ED/BG) values. MED-X contains the population centroid coordinates (latitude
and longitude) and the 1970 population of each ED/BG in the United States (50
States plus the District of Columbia). For human exposure estimations, MED-X
has been reduced from its complete form (including descriptive and summary data)
to produce a randomly accessible computer file of only the data necessary for
the estimation. A separate file of county-level growth factors, based on the
1970 to 1980 growth factor at the county level, has also been created for use in
estimating 1980 population figures for each ED/BG. The population "at risk" to
benzene exposure was considered to be persons residing within 20 km of EB/S
plants. The population around each plant was identified by specifying the
geographical coordinates of that plant.
B-2
-------
B.4 POPULATION DOSAGE METHODOLOGY
B.4.1 Dosage Methodology
The plant's geographical coordinates and the concentration patterns computed
by the ISCLT were used as input to the HEM. (The HEM also has its own atmospheric
dispersion model. However, the HEM dispersion model, still under development,
is not as detailed as the ISCLT and less well suited for large, point emission
sources.)
For each receptor coordinate, the concentration of benzene estimated by the
ISCLT and the population estimated by the HEM to be exposed to that particular
concentration are identified. The HEM multiplies these two numbers to produce
population dosage estimates and sums these products for each plant. A two-level
scheme has been adopted in order to pair concentrations and populations prior to
the computation of dosage. The two-level approach is used because the concen-
trations are defined on a radius-azimuth (polar) grid pattern with nonuniform
spacing. At small radii, the grid cells are much smaller than ED/BG's; at large
radii, the grid cells are much larger than ED/BG's. The area surrounding the
source is divided into two regions, and each ED/BG is classified by the region
in which its centroid lies. Population dosage is calculated differently for
the ED/BG's located within each region.
For ED/BG centroids located between 0.1 km and 2.8 km from the emission
source, populations are divided between neighboring concentration grid points.
There are 96 (6 x 16) polar grid points within this range. Each grid point has
a polar sector defined by two concentric arcs and two wind direction radials.
Each of these grid points is assigned to the nearest ED/BG centroid identified
from MED-X. The population associated with the ED/BG centroid is then divided
among all concentration grid points assigned to it. The exact land area within
each polar sector is considered in the apportionment.
For population centroids between 2.8 km and 20 km from the source, a
concentration grid cell, the area approximating a rectangular shape bounded by
four receptors, is much larger than the area of a typical ED/BG (usually 1 km in
diameter). Since there is a linear relationship between the logarithm of
concentration and the logarithm of distance for receptors more than 2 km from
the source, the entire population of the ED/BG is assumed to be exposed to the
concentration that is geometrically interpolated radially and azimuthally from
the four receptors bounding the grid cell. Concentration estimates for 80
(5 x 16) grid cell receptors at 2.0, 5.0, 10.0, 15.0, and 20.0 km from the
source along each of 16 wind directions are used as reference points for this
interpolation.
B-3
-------
In summary, two approaches are used to arrive at coincident concentra-
tion/population data points. For the 96 concentration points within 2.8 km of
the source, the pairing occurs at the polar grid points using an apportionment
of ED/BG population by land area. For the remaining portions of the grid,
pairing occurs at the ED/BG centroids themselves, through the use of log-log
linear interpolation. (For a more detailed discussion of the methodology used
to estimate dosage, see Reference 3.)
B.4.2 Total Dosage
^
Total dosage, (persons-ug/m ) is the sum of all multiplied pairs of
concentration-population computed by the previously discussed methodology:
N
Total dosage =1 (P.C.) (1)
i=l n n
where
P.J = population associated with point i,
C.j = annual average benzene concentration at point i, and
N = total number of polar grid points between 0 and 2.8 km and ED/BG
centroids between 2.8 and 20 km.
The computed total dosage is then used with the unit risk factor to estimate
leukemia incidence and maximum lifetime individual risk. This methodology is
described in the following sections.
B.4.3 Unit Risk Factor
_8
The unit risk factor (URF) for benzene is 9.9 x 10 (leukemia cases per year)/
3
(ug/m -person years), as calculated by EPA's Carcinogen Assessment Group (CAG).
The derivation of the URF can be found in the CAG report on population risk to
4
ambient benzene exposure and updated in "Response to Public Comments on EPA's
listing of Benzene Under Section 112 and Relevant Procedures for the Regulation
of Hazardous Air Pollutants," EPA 450/5-82-003.
B.4.4 Calculation of Estimated Annual Leukemia Incidence
The number of leukemia cases per year associated with a given plant under
a given regulatory alternative is the product of the total dosage around that
3 -8
plant in ug/m -persons and the unit risk factor, 9.9 x 10 . Thus,
Leukemia cases per year = (total dosage) x (unit risk factor), (2)
where total dosage is calculated according to Equation 1.
B-4
-------
B.4.5 Calculation of Maximum Lifetime Risk
The populations in areas surrounding EB/S plants have various risk levels
of leukemia incidence from exposure to benzene emissions. Using the maximum
annual average concentration of benzene to which any person is exposed, it is
possible to calculate the maximum lifetime risk of leukemia (lifetime probability
of leukemia to persons exposed to the highest concentration of benzene)
attributable to benzene emissions using the following equation:
Maximum lifetime risk = C. x (URF) x 70, (3)
I 9 (TlaX
where
C. = the maximum annual average concentration at any receptor location
' where exposed persons reside,
_8
URF = the unit risk factor, 9.9 x 10 and
70 years = average individual's life span.
B.5 LEUKEMIA INCIDENCE AND MAXIMUM LIFETIME RISK
B.5.1 Input Data, Assumptions, and Methodology
Population exposures were computed for the current level of control, best
demonstrated technology (BDT), and beyond BDT (see BID Section 2.5) for each
plant in order to estimate the annual incidence and maximum lifetime risk for
each of these alternatives.
The plants and their locations are shown in Table B-l. The emission rates
and other dispersion model inputs are shown in Table B-2. Total dosage and
maximum annual average concentrations for each plant under each alternative are
shown in Table B-3.
After population dosage under each regulatory alternative was computed,
incidence estimates were made. Population dosage was multiplied by the CAG
_8
leukemia risk factor of 9.9 x 10 to estimate theannual leukemia incidence for
each plant.
Maximum lifetime risk for a given plant under each regulatory alternative
is found by multiplying the maximum annual average concentration by the unit
o
risk factor of 9.9 x 10" times 70 years (to obtain a lifetime estimate). The
maximum lifetime risk for the industry under the different alternatives
presented in the BID is that due to the plant with the highest maximum lifetime
risk in the industry for the specified alternative.
B-5
-------
TABLE B-l. EB/S PLANTS AND LOCATIONS
Plant
Location
Latitude
Longitude
American Hoechst
American Hoechst
Amoco
Arco
Cos Mar
Dow
Dow
Dow
El Paso
Gulf
Monsanto
Oxirane
Sun
USS Chemicals
Baton Rouge, LA
Bayport, TX
Texas City, TX
Monaca, PA
Carville, LA
Midland, MI
Freeport, TX
Freeport, TX
Odessa, TX
Donaldsonville, LA
Texas City, TX
Channelview, TX
Corpus Christi, TX
Houston, TX
30°33'08"
29°36'10"
29°21'58"
40°39'21"
30°14'16"
43°35'42"
28°57'23"
28°59'17"
31°49'27"
30°05'44"
29°22'44"
29048'51"
27°49'51"
29°42'18"
91°12'40"
95°OT15"
94°55'45"
80°2T20"
91004'09"
84°12'18"
95°19'55"
95°24'09"
102°19'29"
90°55'19"
94°53'40"
95°06'04"
97°31'38"
95°15'06"
B-6
-------
I
\. rT
BASELINE
TABLE B-2. DISPERSION MODELING INPUT DATA
PUot
Auuv«A
15
ie
OUrW
o.ot,
(I - J-—d»
—<2>
O-OU
M.n
Hoo
*loo
0.05M
o.ovt
_V.
hoo
•«.
ss
»_tl>.
ka (T>
»M ^
30 OOT)
So as
C.X
IOIU
OfWO^fl
0.1
_U_
La
o.t
13
-flh
O.oo(<*
.000 U
0, M
.*?•«._
Hoo
0 _ 0
irco.Pft
21
"
25
26
27
28
30
31
0,0114
O.Oil*
IS . IV) ^A. I _.
M.v*
a a
to 3.1
10
o.-xl
0^
O.I
0. 1 _
.0.1
ov»
0,1
-------
TABLE B-2 (Cont.)
11
12
IS
16
(D3
nt-
V
loj-.ot
loo
TDO
ex
I.
V
O.po>V)-
0-QoooT
s
V,
IV «
DO
C»
O.CA3W
Too
loo
«\\
ix n
m
22
I
lOU
lot
loo
Too
II. r
vvr
•51 .
Rrc
O.I
o.oss
o
28
30
31
O I A
a ' »
ll OH 01
.0«!.
o.t
a.o
O.H
0.1)
O.I
o.il
1.1
O..L
o.l
O.I
o.C,
H.T
C.X
t.X
6 1 II
x ^ a**
1.Q
O.T
Ll
(..•X
o.\
-------
TABLE B-2 (Cont.)
10
12
13
14
19
IS
- IH.ol
lot U
k
v>
H
tl
4.1
TL.O
TL.O
n
loll.
t,),
U
M
»l
Vi
tv,
ll
s
U
rVot"
a / ii
0,0
1.0
O.U
o.»H
CAM
U.
o.t
XH
o.\
fin 3i
-------
TABLE B-2 (Cont.)
10
11 12
13
IS
16
00
I
14
117
)"
I 1B
20
29
3O
31
H
U
0.0001^
\o.\x.
k.-n"
\\.-n
O.ViYV
C> 0
loo
o c
M.cS
one
n
~\oo
7cX>_
To.o.
Ci«^
o.omr
\
0.0V
o.ir
o.ooirt
Itt.
n.v\
o o
106
"Joo
a)
O-oooj-
(LVU
0 / »
w
O.b
~-
o / t
M
Ti'
li
t,
« J I
\0\(\
M
V
a i «
1 I
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2.1
lo 10
I
I.
U
0->\
1'°_
-J..O
o.M
VI
0.1
O.I
Li-
^.o
0.14
-------
BDT
JABLE B-2 (Cont.)
Pla
16
^00
loo
loo
] ~~
e
R<««L
HU
Hi
IV
0 < '<
> 4>> of
• i
l IX Ho
ca
_0,L
h
k
1
ll
CO
I
loo
!•> ^i. 10
loiC,
Vl.l ._
O.OV>
loo
•v-0
100
Ti.r
tA.
C-X
Sc-Ml
lo
13
14
r»
f r
\on
O.ll
o.ooc>(,
.JO
0.1
O.I
17
loo
o.itnn
o.ovl»
_U,^4
•to
fe Xl
16
O.OJ.M
1°°
v uO
IH
0-73.
1.0
T-o
o.tH
3m
-------
TABLE B-2 (Cont.)
12
13
16
O
z
O.GU.
O.olt
O.OSS
(Ua
o.uv
A«kf*«1
100
loo
CO
ro
10
13
14
U
B*«-_
U
O.OOCOT
0. 0 ltV|
loo
O.OW
O.OMoX
o.oooj
loo
•"I |2O
GdIO
0.00316
0-061X1
TOO
10 mj
I 0
lot. n
ri«
27
28
20
30
31
Ffere.
0.055
toi (Uo)
o.r
u.r
tr.s-
ix».%?
0,1
0.1
o.l
X.o
P-lJL
o.J*
O.\l
1.1
U
o..l_
o.\
o,»
o.l
.4.1.
X.o
X.o
C.x
11
o.m
X..O
an
(..X
t.X
0.1
O.I
tl
H
-------
TABLE B-2 (Cont.)
10
12 13 14 15
106
T6&
0 / 1
IOU*
... 9
FW
,>«
'V.I.I'L
7-l.n-
li.rx
Oa
Ovl
n
k
li
MS)
M
V
"7t>o
lot
"\fH>
Cr)
co '
L i
oo !
11
M
n
Ov00*!
o.oww
ixr
<•«)
T-.O
T-.0
__MM_
IT 3H«l
lA
6
^
sr.o
IV.O
loll,
Ton,
o.
o)a4
[f*s 29
S6
27
28
2«
3l
700
I.
^ '
^ T
t>
N
II
V.
o.ooooL
-------
TABLE B-2 (Cont.)
12
13
IS
o.cx»v<\
16.YX
O 1 ll
or «JH
rr M
ru>
0.0
o.t
o.t.
It
K
CD
I
0
z
0 0
10
O.COMTX
(50")
**
"7o6
«n
M--
o-ooir
" \
O.ooYt
0,0*
0 0
'or) a^
RcU.lv
loo
1o6
•700
tJ.3
0,1
t.TL
0,1
0 ' «
46
(XI
0-.0
o,\
w
it
6 / »
n v vt
16IU
vr-o
I'it.'O-
m
C-l-
CM
oil
ir »r ot
X.o
O.H
u
K
-------
BEYOND BDT
TABLE B-2 (Cont.)
CO
I
en
«.>'
0
29
26
27
28
29
30
O.oioS
loo
lOO
lOO
106
Q.OT1
loo
TOO
loo
"Too
O.OCO(o
V
loo
loo
O.ov(.
0>.OU.<.
loo
loo
040^,
Ht
"ix.o
3»
5.60 .0°
Oft
tT-
VM
11. V
11.7
tU-'M
ii n
* ' "
i iv H6
oi ti
J.I lo
lolU
ion
io
(Ml
X-o
lo
o.-xi
Lo
•X.o
O.I
t.L
t.^
CO-
O.I
0,1
(,.1
-------
TABLE B-2 (Cont.)
10
12
13
19
16
<£>
O.OlU
O.oUM
loo
ll
VA
faii
tH OcJ)
IV .
"if W
O.OX$T.
?>
0>J
O.O^o I
O.oliol,
O.CXJOl
Enuif
H
k
MV
t o
ID*, ri
22
E\
o.oot
O.o 6>4
TOO
too
7oo
tl.s
IS.1M
So
27
28
2»
3O
31
o.ll
£\ I
0,\
CU
4.7-
o.l
0.1
H
M
o.C
t.X
1-0
l.o
O.I
r
-------
TABLE B-2 (Cont.)
10
12
13
IS
1!
6-.U-
i -
CO
I
E)1
lil2
"
"
0
27
28
29
6.oom.
0.004L.
loo
a i n
• / H
B.%
4.3L
0.oT_
. a
x-o
u
u
loo
It
0.00X1
Vl
v«
^700
160
700
10°.
~?6O
i_r _ x
n «o
u.v
US
Tja.M •
t-T-
>°._
_>.°_
1.0
L.%
\0\t
o.oou
O.IXHMH
•10
HO
m
SV.O
IT
loo
T..O
0.061 V\
700
C.I
c.^
ca
s
.*?.
s
s
<\.o
o-ooooU
« / «
61m
r i-s o»*
loiL
.CO&
C.\\
o.m
fl.l
s
S
I.
O.
li.O
O.ooj.
0 o
0 ' ul
•ir ow «»M
IOU
1.0
-------
TABLE B-2 (Cont.)
11
13
19
18
K
•»
Gn\]t\
«*> (1>
1 1 ¥
» t a
0,0
lOllo
Un
linn
'S
a
O.oa tyi
106
TOO
loo
O.U
1.0
U
U
C..3L
I TO
IVV.
MO.SM
0 o
"X.O
TUO
"nrf
u
U
CM
»
CO
CO
O
o.ooMU
o. cot 14
o.oonM
H
K
M.oU
•J.T.L1
o I »
1 tt So
CHU) C<
o,u
o.u
M-l
o.o'onir
"loo
loo
30
AW
feoiW"
100.
rua
29
O.O"J
0.IM*
o.ooin
o.ooni
loO
Too
..p.)_
t.x
(..X
m
Ml. I
xi HI
<> i b
•n
0,11
9..0
o.t
o o
xf} liX
» /
•X.I
30
31
01
0.1
C.x,
La
o.m
-------
TABLE B-3. DOSAGE AND MAXIMUM ANNUAL AVERAGE CONCENTRATIONS
Plant
American Hoechst, LA
American Hoechst, TX
Amoco, TX
Arco, PA
Cos Mar, LA
Dow, MI
Dow, TX (A)
Dow, TX (B)
EL Paso, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun, TX
USS Chemicals, TX
Total Dogage Maximum Annual
(ug/m - Average Concentrations
Alternative person) (pg/m )
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
Baseline
BDT
Beyond BDT
102,000
4,480
4,480
743
743
743
2,050
2,050
2,050
14,400
1,510
1,510
879
879
879
14,600
1,200
1,200
81.6
81.6
81.6
6,640
1,260
1,260
249
249
34.6
641
641
573
4,880
4,880
4,880
818
818
19.3
4,790
777
777
292
292
292
6.29x10 2
4.55x10 2
4.55x10
_2
3.0x10 2
3.0xlO~2
3.0x10
1.12
1.12
1.12
2.36 i
3.87x10 i
3.87x10"
4.71xlO"J
4.71xlO"i
4.71x10
i
1.7x10 !
1.12x10!
1.12x10
_2
6.49x10 2
6.49x10*2
6.49x10
1.05 !
1.81x10 j
1.81x10
-2
2.09x10 2
2.09x10 3
2.07x10
1.0
1.0 2
4.43x10
1.37
1.37
1.37
-2
1.54x10 2
1.54x10 .,
7.46x10
3. Ob 3
1.87x10 !
1.87x10
.3
2.44x10 3
2.44x10 3
2.44x10
B-19
-------
B.5.2 Example Calculations
B.5.2.1 Incidence. As an example for calculating incidence the ARCO
plant is used. Under the current level of control, the number of leukemia cases
per year are computed according to Equation 2 as follows:
_s
Annual leukemia incidence per year = 14,400 x 9.9 x 10
_3
Annual leukemia incidence per year = 1.4 x 10 .
In the case of BDT, annual leukemia incidence is:
_8
Annual leukemia incidence = 1,510 x 9.9 x 10
-4
Annual leukemia incidence = 1.5 x 10
B.5.2.2 Maximum Lifetime Risk. Again, ARCO is used to illustrate the
calculation. Under the current level of control, the maximum lifetime risk is
computed according to Equation 3 as follows:
_8
Maximum lifetime risk = 2.36 x 9.9 x 10 x 70
_5
Maximum lifetime risk = 1.6 x 10
Likewise, for BDT:
_8
Maximum lifetime risk = 0.387 x 9.9 x 10 x 70
_6
Maximum lifetime risk = 2.7 x 10
B.5.3 Summary of Impacts
The methodology for calculating leukemia incidence and maximum lifetime risk
(described in Section B.5.1) was extended to each plant for the baseline, BDT,
and beyond BDT. The baseline scenario is the current level of control or the
level of control to be implemented in the near future that would have occurred
regardless of this standard. The estimated annual leukemia incidence is shown in
B-4. The estimated nationwide annual leukemia incidence under the assumed baseline
B-20
-------
TABLE B-4. ESTIMATED ANNUAL LEUKEMIA INCIDENCE (xlO~4)*
Plant Baseline BDT Beyond BDT
American Hoechst, LA
American Hoechst, TX
Amoco, TX
Arco, PA
Cos Mar, LA
Dow, MI
Dow, TX (A)
Dow, TX (B)
El Paso, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun, TX
USS Chemicals, TX
39-260
0.28-1.9
0.77-5.3
5.5-37
0.33-2.3
5.5-38
0.031-0.21
2.5-17
0.094-0.65
0.24-1.7
1.8-13
0.31-2.1
1.8-12
0.11-0.76
1.7-12
0.28-1.9
0.77-5.3
0.57-3.9
0.33-2.3
0.45-3.1
0.031-0.21
0.48-3.3
0.094-0.65
0.24-1.7
1.8-13
0.31-2.1
0.29-2.0
0.11-0.76
1.7-12
0.28-1.9
0.77-5.3
0.57-3.9
0.33-2.3
0.45-3.1
0.031-0.21
0.48-3.3
0.013-0.090
0.22-1.5
1.8-13
0.0073-0.050
0.29-2.0
0.11-0.76
TOTAL 58-400 7.5-52 7.1-49
*These ranges represent the uncertainty of estimates concerning benzene
concentrations to which workers were exposed in the occupational studies
of Infante, Aksoy, and Ott that served as the basis for developing the unit
risk factor, and are based on a 95 percent confidence internal that assumes
the estimated benzene concentrations are within a factor of 2.
B-21
-------
TABLE B-5. ESTIMATED MAXIMUM LIFETIME RISK (XI0~V
Plant Baseline BDT Beyond BDT
American Hoechst, LA
American Hoechst, TX
Amoco, TX
Arco, PA
Cos Mar, LA
Dow, MI
Dow, TX (A)
Dow, TX (B)
El Paso, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun, TX
USS Chemicals, TX
170-1100
0.079-0.54
3.0-20
6.3-43
1.2-8.5
45-310
0.17-1.2
2.8-19
0.055-0.38
2.6-18
3.6-25
0.041-0.28
8.1-55
0.0065-0.044
0.12-0.83
0.079-0.54
3.0-20
1.0-7.0
1.2-8.5
30-200
0.17-1.2
0.48-3.3
0.055-0.38
2.6-18
3.6-25
0.041-0.28
0.50-3.4
0.0065-0.044
0.12-0.83
0.079-0.54
3.0-20
1.0-7.0
1.2-8.5
30-200
0.17-1.2
0.48-3.3
0.0055-0.037
0.12-0.80
3.6-25
0.002-0.014
0.50-3.4
0.0065-0.044
"'These ranges represent the uncertainty of estimates concerning benzene
concentrations to which workers were exposed in the occupational studies
of Infante, Aksoy, and Ott that served as the basis for developing the unit
risk factor, and are based on a 95 percent confidence internal that assumes
the estimated benzene concentrations are within a factor of 2.
B-23
-------
(at least in the calculation of 'incidence) by the assumption that no one
moves into the exposure area whether as a resident or as a transient. The
population "at risk" was assumed to reside within 20 km of each plant, regardless
of the estimated concentration at that point. The selection of 20 km is considered
to be a practical modeling stop-point. The results of dispersion modeling are
felt to be reasonably accurate within that distance. The dispersion coefficients
used in modeling are based on empirical measurements made within 10 kilometers
of sources. These coefficients become less applicable at long distances from
the source, and the modeling results become more uncertain. A numerical estimate
of the accuracy of these assumptions regarding the exposed population is not
available.
B.6.3 Unit Risk Factor
The unit risk factor contains the uncertainty of estimates concerning
benzene concentrations to which workers were exposed in the occupational studies
4
of Infante, Aksoy, and Ott, which serve as the basis for the unit risk factor.
The ranges represent a 95 percent confidence interval that assumes the estimated
benzene concentrations to which the workers were exposed are within a factor of
2 of the actual concentrations. Other uncertainties regarding the occupational
studies and the workers exposed that may affect the unit risk factor were raised
during the public comment period and focus on assumptions and inconclusive data
contained in the studies. However, those uncertainties have not been quantified.
B.6.4 Other Uncertainties
There are several uncertainties associated with estimating health impacts.
Maximum lifetime risk and annual incidence were calculated based on a no-threshold
linear extrapolation of leukemia risk associated with a presumably healthy white
male cohort of workers exposed to benzene concentrations in the parts per million
range compared to the risk associated with the general population, which includes
men, women, children, nonwhites, the aged, and the unhealthy, who are exposed to
concentrations in the parts per billion range. It is uncertain whether these
widely diverse segments of the population have susceptabilities to leukemia that
differ from that of workers in the studies. Furthermore, while death from
leukemia is the only benzene health effect considered in these calculations, it
B-24
-------
is not the only possible health effect. Other health effects, such as aplastic
anemia and chromosomal aberrations, are not as easily quantifiable and are not
reflected in the risk estimates. Although these other health effects have been
observed at occupational levels, it is not clear if they can result from ambient
benzene exposure levels. Additionally, benefits that would affect the general
population as the result of indirect control of other organic emissions in the
process of controlling benzene emissions from ethylbenzene/styrene plants are
not quantified. Possible benzene exposures from other sources also are not
included in the estimate. For example, an individual living near an ethylbenzene/
styrene plant is also exposed to benzene emissions from automobiles. Finally,
these estimates do not include cumulative or synergistic effects of concurrent
exposure to benzene and other substances.
B-25
-------
B.7 REFERENCES
1. U.S. Environmental Protection Agency. Industrial Source Complex
(ISC) Dispersion Model User's Guide, Volume I. Research Triangle
Park, North Carolina. EPA-450/4-79-031. 1979
2. U.S. Environmental Protection Agency. An Evaluation Study for the
Industrial Source Complex (ISC) Dispersion Model. Research Triangle
Park, North Carolina. EPA-450/4-81-002. 1981.
3. Systems Applications, Inc. Human Exposure to Atmospheric Concentrations
of Selected Chemicals. (Prepared for the U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina). Volume I (NTIS
No. PB 81 193252) and Volume II (NTIS No. PB 81 193260). May 1980.
4. Albert , R. E. Carcinogen Assessment Group's Final Report on Popula-
tion Risk to Ambient Benzene Exposures. U.S. Environmental Protection
Agency. Publication No. EPA-450/5-80-004. January 1979.
B-26
-------
APPENDIX C
COST DATA AND ECONOMIC IMPACTS
-------
APPENDIX C
COST DATA AND ECONOMIC IMPACTS
C.I INTRODUCTION
The purpose of this appendix is to show how the cost impacts used
during development of the proposed and promulgated standards were
developed. An explanation of assumptions used in the cost estimations
accompanies the discussion. This appendix is divided into three major
sections: (1) Subsection C.2 discusses the assumptions used in deter-
mining the original and revised cost estimates of the proposed standard,
This subsection also summarizes the original and revised cost data
used to determine the economic impacts of the proposed standard;
(2) Subsection C.3 discusses the assumptions used to determine the
best demonstrated technology (BDT) and beyond BDT for the ethyl benzene/
styrene (EB/S) industry on which the promulgated standard is based;
and (3) Subsection C.4 discusses the economic impacts of BDT and
beyond BDT in terms of rate of return, price, and employment impacts.
C.2 ORIGINAL AND REVISED COMPLIANCE COSTS WITH THE PROPOSED STANDARD
C.2.1 EPA Original Compliance Costs
The capital, operating, and maintenance costs for all of the
control equipment considered at proposal were based on the EB/S vent
stream characteristics summarized in the proposal BID (EPA-450/3-79-
035a; pp. 3-23).
The emissions estimates presented in the proposal BID were based
on the emissions from a model facility with a nameplate capacity of
300,000 Mg/yr (330,000 ton/yr) of styrene and 345,000 Mg/yr (380,000
ton/yr) of ethylbenzene. The cost analysis assumed that vent stream
flows show a linear relationship with plant capacity.
C-2
-------
C.2.1.1 Capital Costs for Control Equipment. Capital cost
curves for flares, flare headers, burners,* scrubbers, and condensers
for the various plant sizes under consideration are shown in the
proposal BID (EPA-450/3-79-035a: pp. 7-34). All capital costs were
presented in fourth-quarter 1978 dollars. All of the cost curves
except those representing the total installed costs of scrubbers and
condensers exhibit a marked plateau below a plant capacity of 150,000
Mg/yr (165,000 ton/yr). It was assumed that there would be little
change in the total installed cost of a piece of equipment below this
size because installation and piping costs are the major contributors
to total installed cost for small pieces of equipment. In addition, a
minimum available size was specified for some equipment. Also, the
analysis assumed that no pipes smaller than 2 inches in diameter would
be used and that the total length of pipe needed would not change
significantly at the small plant sizes.
Capital costs for the flare, burner, and header systems were
derived from data presented in Hydroscience Ethylbenzene/Styrene
Product Report (II-A-1).
C.2.1.2 Annualized Costs. Table C-l presents a list of factors
used to derive the annualized costs for the proposed standard. The
total annual!zed cost of each piece of equipment is made up of operating
and maintenance costs, annualized capital costs, and fuel or recovered
material credits, if any.
Maintenance costs were estimated as a percentage of total installed
capital costs, and supplies (miscellaneous capital expenses) were
estimated similarly. Operating costs were made up of electrical power
requirements (for pumps, compressors, etc.) steam, refrigeration, and
natural gas. Each of these cost factors was assigned a unit value
(see Table C-l). The consumption and cost of the various utilities
for each device were calculated and summed to yield equipment operating
^Burners refer to equipment needed to introduce the vent streams
into the combustion device and include a compressor piping and
aspirating burner if necessary.
C-3
-------
TABLE C-l. ANNUALIZED COST PARAMETERS FOR CONTROL
OF CONTINUOUS EMISSIONS AT PROPOSAL3
1. Operating factors
2. Operating labor
3. Maintenance
4. Miscellaneous materials
5. Utilities:
Electric power
Natural gas
Steam
Refrigeration
6. Operating materials:
Polyethylbenzenes for scrubber
available at zero cost
7. Liquid waste disposal
8. Capital recovery factor
9. Recovery credits:
Fuel value volatile organic
compounds (VOC's) and
benzene using boiler option
Recovered benzene from
scrubber and condensers
(returned to benzene
drying column)
8,760 hr/yr for utility require-
ments assuming 100 percent
capacity utilization credits
8,000 hr/yr for recovery
Negligible for flares, condensers
scrubbers, and boilers
5% of total installed capital cost
4% of total installed capital cost
$8.33/GJ, ($0.03/kWh)
$0.071/MJ ($2.00/1,000 ft3)
$0.55/Kg ($2.50/1,000 Ib)
$1.97/GJ ($2.08/MMBtu)
Negligible quantity generated
16.28% of total installed cost
$1.894/GJ ($2.00/MMBtu)
$0.30/Kg ($0.137/lb)
Annualized cost parameters summarized
pp. 7-37).
in proposal BID (EPA-450/3-79-035a;
C-4
-------
costs. It was assumed that larger control systems would require
additional operating labor. Flare utility requirements for purge,
pilot, and steam were derived from vendor data.
Fuel recovery credits were estimated when a heating value was
assigned to each component of the vent gas streams and the combined
heating value was assumed to have the same monetary value ($2.00/MMBtu,
assuming 1,000 Btu/ft3) as the natural gas it would displace. In
addition, recovery was assumed to occur for 8,000 hr/yr. Capital costs
were annualized based on a capital recovery factor of 16.28 percent,
and operating and maintenance costs less recovery credits from fuel or
material if applicable were summed to obtain total annualized costs
for the proposed standard.
C.2.1.3 Plant-By-Plant Costs.
1. Introduction. Capital and annualized costs for individual
pieces of control equipment were based on the requirements of a model
uncontrolled facility. Because each existing facility practices some
degree of emissions control, only the incremental cost needed to
achieve a given benzene reduction was considered.
An assessment was made of equipment that would be needed to
achieve a given level of emissions reduction at an uncontrolled facility
and was then used as the basis for deciding what equipment would be
needed at existing facilities to achieve the same level of control.
Table C-2 lists the equipment that would be needed by each EB/S plant
to achieve the control specified in the proposed standard. Table C-3
presents the pi ant-by-plant cost estimates.
2. PI ant-by-plant capital costs. The pi ant-by-plant capital
costs for the proposed standard shown in Table C-3 were obtained when
the equipment list shown in Table C-2 was used in conjunction with the
plant size and the individual equipment capital costs presented in the
proposal BID (EPA-450/3-79-035a; pp. 7-34).
Capital costs for each component were then summed, and an allowance
was added to the installed capital costs to account for such indirect
costs as engineering fees, construction overhead, and contingencies.
The magnitude of these indirect costs can vary widely and depends upon
C-5
-------
TABLE C-2. EQUIPMENT NEEDED TO COMPLY WITH THE PROPOSED STANDARD
FOR CONTINUOUS AND EXCESS EMISSIONS3
Plant/location Equipment needed
American Hoechst, LA Flare, header, burner,0 oxygen monitor
Amoco, TX Flare, header, burner, oxygen monitor
ARCO, TX Flare, header,0 burner,0 oxygen monitor
ARCO, PA Flare, header, burner, oxygen monitor
Cos-Mar, LA Flare, header, burner,0 oxygen monitor
Dow Chemical, TX Flare, header, burner, oxygen monitor
Dow Chemical, MI Flare, header, burner, oxygen monitor
El Paso Products, TX Flare, header, burner, oxygen monitor
Gulf, LA Flare, header, burner,0 oxygen monitor
Monsanto, TX Flare, header,0 burner,0 oxygen monitor
Oxirane, TX Flare, header, burner,0 oxygen monitor
Sun Oil, TX Flare, header, burner, oxygen monitor
U.S. Steel, TX Nothing
aFrom the proposal BID (EPA-450/3-79-035a; pp. 7-38).
Complete system required.
°Partial system required, as some equipment already in use.
C-6
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TABLE C-3. ORIGINAL EPA COSTS FOR COMPLIANCE AT PROPOSAL
Plant/location
American Hoechst, LA
American Hoechst, TXa
Amoco, TX
ARCO, PA
ARCO, TX
Cos-Mar, LA
Dow Chemical , TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
SUBTOTAL
Plus H2 separation and
excess emissions
TOTAL
Capital
costs
($l,000's)
421
-
200
130
235
448
555
142
130
215
424
366
130
0
3,396
524
3,920
Annual i zed
costs
($l,000's)
(72)
-
7
27
(14)
(147)
(75)
25
26
(64.5)
(76.5)
(119)
23
0
(460)
171
(289)
Emissions
reduced
(Mg/yr)
302
-
11
68
293
403
174
68
14
163
314
290
9
0
2,109
222
2,331
Costs per
Mg reduced
($/Mg)
(238)
-
636
397
(48)
(365)
(431)
368
1,857
(393)
(242)
(410)
2,556
0
(218)
770
(124)
Residual
emissions
(Mg/yr)
18
-
15
2
8
17
6
2
2
17
6
Fl
6
1
99
21
120
aPlant not open at proposal.
C-7
-------
the size, type, and complexity of jobs under consideration. In
addition, the contingencies are related directly to the firmness of
the cost estimate. Therefore, the absolute magnitude of the indirect
costs used by different estimates can vary widely.
3. PI ant-by-plant annualized costs and savings. The individual
operation and maintenance costs associated with each piece of equipment
shown in Table C-2 and the annualized capital cost for the control
equipment were summed to obtain pi ant-by-plant total annualized costs
for the proposed standard. Any recovery credits that could be assigned
for recovering heating value were then estimated. These credits
were subtracted from the annualized costs to yield net annualized
costs or savings. In several instances, the recovery credits far
exceeded the annualized cost of the control device under consideration.
However, it must be noted that the amount of savings that could be
realized by a given control option would depend upon the actual amount
of recoverable material in the controlled stream. For this analysis,
it was assumed that benzene was the only material of value in the vent
stream, and no recovery credit was given for the other aromatics
contained in the vent gases for the model plant. The recovery credits
were based upon an average vent stream analysis and assumed that
recovery would occur 8,000 hr/yr. The composition of these vent
streams varies from plant to plant, so the absolute magnitude of the
recovery credits would also vary.
Table C-3 indicates that net revenues for some of the EB/S
facilities can result from control of continuous vent streams. The
magnitude of savings depends upon the amount of benzene recovered and
its subsequent value as a feed to the process, as well as the heating
value of the other organics in the vent stream.
The analysis assumed that the VOC's and benzene recovered and
used as a fuel in a boiler can be assigned a value comparable with
that of natural gas ($2.00/MMBtu).
C.2.2 Revised Compliance Costs
C.2.2.1 Introduction. At proposal, EPA estimated that the total
capital cost of compliance to meet the proposed standard would be
$3.9 million, while the total annualized costs would result in a net
C-8
-------
savings of about $289,000 due to the fuel savings. The Chemical
Manufacturers Association (CMA) publicly stated that the EPA costs
were underestimated and subsequently supplied its estimated costs
(IV-D-13). CMA estimated that the total capital costs of compliance
with the proposed standard would be $11.6 million and the annualized
costs would be $3.2 million.
EPA's original cost estimates and industry estimates differ for
several reasons. First, industry (represented by CMA) costs were
presented in 1980 and 1981 dollars, while EPA costs were based on
fourth-quarter 1978 dollars. Second, CMA costs were based on plant-
specific parameters that the 13 EB/S plants supplied to CMA for the
public hearing and later updated for the CMA data package supplied to
EPA (IV-D-13). EPA costs were based on costs for equipping a model
plant with control equipment. The model plant approach (which is
designed to generate cost estimates to industry rather than to specific
plants with an accuracy of +30 percent when more detailed information
is not readily available or a more elaborate analysis is not considered
feasible or affordable) cannot account for differences in plant layout,
design, and operating characteristics, which determine equipment and
installation costs. In the EPA approach, an assessment was made of
the equipment necessary to achieve a given level of emissions reduction
at an uncontrolled facility and was used as the basis for deciding
what equipment would be needed at existing facilities. Third, CMA
costs considered the current structure of the EB/S industry, including
the various plants that comprise the industry. The EPA estimates were
based on data obtained up to 1978. Also, EPA assumed 100 percent
production and 70 percent industry-wide control for the model plant
calculations instead of actual pi ant-by-plant production and control
levels. Fourth, except for two facilities, the CMA costs did not
consider fuel recovery savings. EPA assumed a fuel recovery value for
waste gases burned in boilers.
Because of data and information obtained from CMA since proposal,
EPA reanalyzed the costs of compliance with the proposed standard.
EPA's revised costs, which are lower than the CMA costs, reflect some
of the plant-specific parameters EPA did not consider at proposal.
C-9
-------
EPA's revised cost estimates differ from CMA cost estimates
primarily due to differences in indirect capital costs such as engineering fees,
construction overhead, contingencies, and fuel recovery credits. The
magnitude of indirect costs can vary widely and depends upon the size,
type, and complexity of jobs under consideration. In addition, the
contingencies are related directly to the firmness of the cost estimate.
The CMA data (IV-D-13), with the exception of two facilities, did not
consider fuel recovery credits in their cost analyses. EPA assumed a
fuel recovery value for waste gases burned in boilers.
C.2.2.2 Revised Costs for Controlling Continuous and Excess
Emissions. EPA assumed that direct capital costs cited in the CMA
data package (IV-D-13) were correct but assessed the indirect costs
and as a result adjusted the CMA indirect capital costs according to
cost analysis guidelines used by EPA in developing cost impacts (IV-J-6)
to make them consistent on an interplant basis (Table C-4). EPA
estimated total installed capital costs on a pi ant-by-plant basis by
applying indirect capital cost factors to the CMA direct capital
costs. EPA then used annualized cost factors from Table C-4. Finally,
by dividing the total emissions reduced from the annualized costs, EPA
estimated the cost per unit of benzene reduced on a pi ant-by-plant
basis. The Agency followed this procedure in estimating costs for
controlling continuous and excess emissions from EB/S plants. Total
capital and annualized cost figures were rounded to three significant
digits while cost per megagram reduced values were rounded to two
digits because of limited accuracy in the component weight fractions
used to estimate the fuel recovery credits and the percentage annual-
ized cost factors.
1. Fuel Recovery Credit Estimation. EPA estimated the fuel
recovery credits for each vent stream covered by the proposed standard
by multiplying the benzene flow rate and the appropriate multipliers
(depending on the vent stream type and the location of the EB/S plant)
and conversion factors as outlined in Subsection A.4 of Appendix A of
this document. If a particular plant had one or more vents covered by
the proposed standard, annual savings were estimated for each vent and
C-10
-------
TABLE C-4. REVISED EPA INDIRECT CAPITAL COST AND
. ANNUALIZED COST PARAMETERS
Description
Amount
Indirect capital cost parameters3
1. Engineering 20% of capital cost
2. Construction and field expenses 10% of capital cost
3. Construction fees 10% of capital cost
4. Contingencies 30% of capital cost
5. Startup 1% of capital cost
1. Labor"
2. Miscellaneous materials
3. Capital recovery factor
4. Maintenance
5. Utilities'5
6. Recovery credits
Fuel value of VOC's burned in
the boiler
Annualized cost parameters
$10,000
4% of total installed capital cost
16.28% of total installed capital cost
5% of total installed capital cost
2% of total installed capital cost
$2.14/GJ ($2.26/MMBtu) for Texas and Louisianac .
$1.65/GJ ($1.74/MMBtu) for Michigan and Pennsylvania
aCost factors from the Cost Analysis Manual for Standards Support Document (IV-J-6).
bCost factors from the proposal BID (EPA-450/3-79-035a; pp. 7-37).
clntrastate natural gas price from July 1980 Producer Price Index, assuming a lower heating
value of 36 MJ/sm3 at 0° C (910 Btu/scf at 60r7T.
Interstate natural gas price from July 1980 Producer Price Index, assuming a lower heating
value of 36 MJ/snT at 0° C (910 Btu/scf at 60a F).
C-ll
-------
then summed to present total annual savings. The benzene flow rates
in grams per second were obtained from the CMA data package (IV-D-13).
Fuel recovery was credited at $2.14/GJ ($2.26/MMBtu) for Texas and
Louisiana plants (based on the 1980 intrastate natural gas price) and
$1.65/GJ ($1.74/MMBtu) for Michigan and Pennsylvania plants (based on
the 1980 interstate natural gas price) (from July 1980 Producer Price
Indices) assuming a lower heating value of 36 MJ/m3 at 0° C (910 Btu/
ft3 at 60° F). Fuel recovery energy savings in MMBtu/yr were multiplied
by the appropriate recovery credit in $/MMBtu to estimate annual savings
in dollars per year expected from recovery of gases from EB/S vent
streams.
2. Cost calculation example—controlling continuous emissions
from the ARCO, Pennsylvania, facility. The following example shows
cost calculations for the control of continuous emissions from the
ARCO, Pennsylvania, facility according to provisions of the proposed
standard.
Capital cost calculations
CMA direct capital equipment costs (IV-D-13) $ 87,000
EPA indirect capital cost factors
Engineering fees (20% of capital cost) 17,400
Construction/field expenses (10% of capital cost) 8,700
Construction fees (10% of capital cost) 8,700
Contingencies (30% of capital cost) 26,100
Startup (1% capital cost) 870
TOTAL INSTALLED CAPITAL COST (TICC) $149,000
Annualized cost calculations
EPA annualized cost factors
Personnel ($10,000) $ 10,000
Miscellaneous materials (4% of TICC) 6,000
Capital recovery factor (16.28% of TICC) 24,000
Maintenance (5% of TICC) 7,500
Utilities (2% of TICC) 3,000
Fuel recovery credit (11,000)
TOTAL ANNUALIZED COST $ 40,000
C-12
-------
Cost per megagram benzene reduced ($/Mg)
$40,000/39 Mg reduced = $l,000/Mg
3. Cost calculation example—controlling excess emissions from
the ARCO, Pennsylvania, facility. The following example shows cost
calculations to control excess emissions from the ARCO, Pennsylvania,
facility according to provisions of the proposed standard. Because
the proposed standard required smokeless flares to control excess
process emissions, no fuel savings were assumed.
Capital cost calculations
CMA direct capital equipment costs (IV-D-13) $ 82,000
EPA indirect capital cost factors
Engineering fees (20% of capital cost) 16,400
Construction/field expenses (10% of capital cost) 8,200
Construction fees (10% of capital cost) 8,200
Contingencies (30% of capital cost) 24,600
Startup (1% of capital cost) 820
TICC $140,000
Annualized cost calculations
EPA annualized cost factors
Personnel ($10,000) $ 10,000
Miscellaneous materials (4% of TICC) 5,600
Capital recovery factor (16.28% of TICC) 23,000
Maintenance (5% of TICC) 7,000
Utilities (2% of TICC) 2,800
TOTAL ANNUALIZED COST $ 48,000
Cost per megagram benzene reduced ($/Mg)
$48,000/2 Mg reduced = $24,000/Mg
4. Cost calculation example—controlling continuous and excess
emissions from the ARCO. Pennsylvania, facility. The following example
shows cost calculations to control continuous and excess emissions
from the ARCO, Pennsylvania, facility according to provisions of the
C-13
-------
proposed standard. Costs of controlling continuous and excess emissions
from the previous examples were added to determine the cost estimate.
Capital cost calculations
Total capital cost for continuous emissions $149,000
Total capital cost for excess emissions 140,000
TOTAL CAPITAL COST FOR CONTINUOUS AND EXCESS EMISSIONS $289,000
Annualized cost calculations
Total annualized cost for continuous emissions $ 40,000
Total annualized cost for excess emissions 48,000
TOTAL ANNUALIZED COST FOR CONTINUOUS AND EXCESS EMISSIONS $ 88,000
Cost per megagram benzene erduced ($/Mg)
$88,000/41 Mg reduced = $2,100
5. Industry-wide cost estimates. By following the costing
procedure described above, EPA estimated the costs each EB/S plant
would incur with implementation of the proposed standard. By summing
the respective total plant costs, EPA estimated total industry-wide
costs resulting from implementing the proposed standard. In summary,
industry-wide capital costs to control continuous process emissions
would be $5.6 million, while industry-wide annualized costs would be
$1.3 million (see Table C-5). Also, the industry-wide capital costs
to control excess process emissions would be $2.0 million, while
industry-wide annualized costs would be $598,000 (see Table C-6). To
determine the industry-wide capital and annualized costs for con-
trolling continuous and excess emissions, EPA summed the separate cost
estimates for the control of continous and excess emissions. In
summary, the industry-wide capital costs to control continuous and
excess emissions would be $7.6 million, while the industry-wide annual-
ized costs would be $1.9 million (see Table C-7).
C.3 COST ESTIMATES USED IN DEVELOPING THE PROMULGATED STANDARD
C.3.1 Introduction
Selection of the basis of the promulgated standard is explained
in Response 2.5.1 of this document. EPA reexamined the emissions
C-14
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TABLE C-5. REVISED EPA COST ESTIMATES FOR COMPLIANCE WITH PROPOSED
STANDARD FOR CONTINUOUS EMISSIONS3
Total
Capital in-
equip- stalled
merit capital
costs costs
Plant/location ($l,000's) ($l,000's)
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
Total
98
0
299
87
660C
485C
302C
225
307
1,100C
1,000C
299C
0
4,860
168
0
511
149
660
485
302
385
525
1,100
1,000
299
0
5,580
Total
annu-
alized Emissions
costs reduced
($1,000 's) (Mg/yr)
5.00
0
150
40
185
125
60
110
150
310
110
85
0
1,330
98
0
1
39
5
30
54
5
4
1
6
10
0
253
Cost
per Mg b
reduced
($/Mg)
51
0
150,000
1,000
37,000
4,200
1,100
22,000
38,000
310,000
18,000
8,500
0
5,200
Residual
emissions
(Mg/yr)
19
6
14
2
16
5
1
2
16
4
Fl
1
4
87
aCosts in 1980 dollars rounded to 3-digit accuracy.
Costs per megagram reduced rounded to 2-digit accuracy.
cTotal installed costs; not enough data to separate direct and indirect costs.
C-15
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TABLE C-6. REVISED EPA COST ESTIMATES FOR COMPLIANCE WITH PROPOSED
STANDARD FOR EXCESS EMISSIONS3
Total
Capital in- Total
equip- stalled annu-
ment capital alized Emissions
costs costs costs reduced
Plant/location ($l,000's) ($l,000's)($l,000's) (Mg/yr)
American Hoechst, LA
American Hoechst, TX
Amoco, TX
ARCO, PA
Cos-Mar, LA
Dow Chemical , TX
Dow Chemical , MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
Total
0
0
74.0
82.0
0
953C
305C
0
0
400C
0
0
50. Oc
1,860
0
0
127
140
0
953
305
0
0
400
0
0
50.0
1,980
0
0
45.0
48.0
0
269
93.0
0
0
119
0
0
24.0
598
0
0
Fl
2
0
Fl
Fl
0
0
14
0
0
Fl
17
Cost
per Mg u Residual
reduced emissions
($/Mg) (Mg/yr)
0
0
45,000
24,000
0
270,000
93,000
0
0
8,500
0
0
24,000
35,000
2
2
Fl
Fl
1
Fl
Fl
2
1
2
0
5
Fl
16
Costs in 1980 dollars rounded to 3-digit accuracy.
Costs per megagram reduced rounded to 2-digit accuracy.
cTotal installed costs; not enough data to separate direct and indirect costs.
C-16
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TABLE C-7. REVISED EPA COST ESTIMATES FOR COMPLIANCE WITH PROPOSED
STANDARD FOR CONTINUOUS AND EXCESS EMISSIONS3
Plant/location
American Hoechst, LA
American Hoechst, TX
Amoco, IX
ARCO, PA
Cos-Mar, LA
Dow Chemical, TX
Dow Chemical, MI
El Paso Products, TX
Gulf, LA
Monsanto, TX
Oxirane, TX
Sun Oil, TX
U.S. Steel, TX
Total
Total
Capital in-
equip- stalled
ment capital
costs costs
($l,000's) ($l,000's)
98.0
0
373
169
660C
1,440C
607C
225
307
1,500C
1,-000C
299C
50. Oc
5,730
168
0
638
289
660
1,440
607
385
525
1,500
1,000
299
50.0
7,560
Total
annu-
al i zed
costs
($1,000' s)
5.0
0
195
90.0
185
395
155
110
150
430
110
85.0
25.0
1,940
Emissions
reduced
(Mg/yr)
98
0
1
41
5
31
55
5
4
15
6
11
Fl
272
Cost
per Mg .
reduced
($/Mg)
51
0
200,000
2,200
37,000
13,000
2,800
22,000
38,000
29,000
18,000
7,700
25,000'
7,100
Residual
emissions
(Mg/yr)
21
8
15
2
17
5
2
2
17
6
Fl
6
Fl
101
aCosts in 1980 dollars rounded to 3-digit accuracy.
Costs per megagram reduced rounded to 2-digit accuracy.
cTotal installed costs; not enough data to separate direct and indirect costs.
C-17
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sources that would have been covered by the proposed standard (all
continuous process vents not being routed to a boiler and all excess
emissions not being routed to smokeless flares) and their respective
emissions rates. Preliminary control costs were assigned to each of
these emissions sources based on reducing continuous emissions 99 per-
cent in a boiler and excess emissions 90 percent in a smokeless flare.
C.3.2 Cost Calculations of Regulatory Alternatives for BDT and Beyond
BDT
In an integrated system of emissions control where several vents
are routed into one control device, costs such as burner retrofit costs,
surge tank costs, elaborate manifolding costs, and installation labor
costs are common to all vents. The cost per vent depends on the
number of vents controlled. The intent of the analysis was to examine
the costs per unit emissions reduction per vent, which cannot be
determined if common costs are included unless the number of vents to
be controlled is known. Therefore, it was decided that an initial
analysis would exclude common costs. Thus, only compressor and piping
costs and fuel recovery savings (the noncommon costs) estimates were
used to compare costs of controlling vents that emit low levels of
benzene not currently routed to a boiler in EB/S plants. These costs
were then used with the estimated emissions reductions to calculate
the cost per unit of benzene reduction for each emissions point.
While all costs are not included, such a relative ranking can indicate
which sources can be controlled for the greatest emissions reduction
at the least cost. The compressor and piping costs were derived based
on vent stream flow rates from the model plant described in the proposal
BID (EPA-450/3-79-035a; p. 3-23). The CMA data (IV-D-13) contained
only benzene emissions rates, which alone could not be used to calculate
pipe sizes because EB/S vent streams contain other compounds that
increase the total stream flow rate, thereby increasing the size of
the pipe needed to transport the streams. The compressor and pipeline
costs were calculated according to the following procedure.
A pipeline costing model was developed in order to cost the
pipeline required to move emissions from various emissions sources to
the control device in the wide variety of plant sizes and layouts that
C-18
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exist in the EB/S industry. The costing model considered the capital
and operating costs and installation labor of the piping, fittings,
and compressor machinery necessary to control and move vented emissions
to a boiler for destruction.
The number of input variables for the model was reduced in order
to reduce software development costs and computing costs. The principal
cost variables are the number of emissions sources to be controlled,
the emissions flow rate from each emissions source, the number of
emissions streams that can be combined, emissions source and control
device location, and system reliability. Data on plant layout from
the proposal BID enabled development of a worst-case assumption that
eliminated the need for input concerning the location of emissions
sources and control devices. The worst-case assumption assumed that a
70-foot source leg of pipe would join any emissions source to a com-
pressor, a 20-foot compressor leg would join the source leg and the
pipe leg, and a 2,000-foot pipe leg would join the compressor with the
boiler for destruction. With this assumption, a complete pipeline and
fitting inventory was assembled for each pipe segment (see Table C-8).
Based on these assumptions, the input variables to the model were
reduced to the number of emissions sources to be vented at any plant
site, the flow rate from each of these emissions sources, and the
destruction method (e.g., boiler).
The model is based on the optimum economic pipe-diameter equation
in Perry's Chemical Engineers' Handbook (Equation 5-90, p. 5-32,
5th edition). This equation calculates the optimum economic tradeoff
between compressor and pipeline size.
The equation is complex in that it incorporates approximately
20 separate variables. Table 5-16 in the handbook lists typical
values for the variables, including the variable F, defined as the
ratio of the fittings cost plus the installation cost of pipe and
fittings to the cost of pipe only. Using F values provided in this
table presents a problem because F cannot be selected accurately until
the pipe diameter is known. Therefore, an array of F values, one for
each pipe diameter assumed, must be used. Thus, an iterative process
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TABLE C-8. PIPELINE COMPONENTS ASSUMED FOR EACH EMISSIONS SOURCE
Hardware
Schedule 40 pipe
Check values
Gate valves
Control valves
Strainers
Elbows
Tees
Flanges
Drip valves
Expansion fittings
Bolt and gasket sets
Hangers
Field welds
Source
leg
70'
1
4
1
1
8
6
15
1
2
15
9
18
Compressor
leg
20'
1
2
0
1
6
2
10
1
1
12
4
12
Pipe
leg
2,000'
1
3
1
1
6
3
14
1
1
12
50
14
C-20
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based on a prestored matrix of F values versus pipe diameter is required,
Another problem is that the F values supplied in Table 5-16 of the
handbook are based on June 1968 for one gate valve, one check valve,
one tee, and four elbows per 100-foot costs of straight pipe. The
cost ratio of fittings to straight pipe was different for EB/S work
due to the different fittings and straight pipe inventory for the EB/S
applications and due to the fact that 1980 equipment and labor costs
were used for the EB/S estimates. An article by Chontos in the June 16,
1980, edition of Chemical Engineering (IV-J-5) presents a method for
deriving F as a function of D. This method reduces the problem of
iteration, but Chontos used the equipment specified by Perry, which is
not representative of the pipe, fittings, and valves used to move
emissions in the EB/S analysis. The equipment inventory of EB/S was
used to derive F as a function of pipe diameter.
The other variables in the economic pipe-diameter equation in
Perry's equation developed by du Pont are more straightforward and are
listed below with the equation, the value used for each variable, and
the source of that value:
n(4.84 + n)/(1 + 0 7g4 Le,n) = 0 0001Q9 YKq2.84p0.84m,0.16 [(1 + m)
(1 - d) + Z(a' + b1) EP/(17.9 KY)(a' + b')]/{nXE (1 + F)[Z + (a + b)
(1 - d)]} ,
where
n = 1.31, pipe cost equation exponent (IV-J-5).
X = $15.04, Cost of a 1-foot length of 12-inch diameter pipe,
from 1980-81 Richardson Engineering Services Process Plant
Construction Estimating Standards.
L ' = (Step 4 of model procedure), factor for friction in fittings,
e equivalent length in pipe diameters per unit length of pipe
calculated.
E = 0.50, fractional efficiency of motor and compressor.
P = 340, installed cost of motor and compressor $/hp, calculated.
K = 0.037, Electricity costs $/kWh, calculated.
Y = 365,.days of operation.
C-21
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<|> = 0.45, corporation tax bracket, calculated.
Z = 0.15, IRR on incremental investment, calculated.
a1 = 0.10, fractional annual depreciation of compressor, Perry's
Chemical Engineers' Handbook.
b1 = 0.03, fractional annual maintenance of compressor, Perry's
Chemical Engineers' Handbook.
a = 0.10, fractional annual depreciation of pipeline, Perry's
Chemical Engineers' Handbook.
b = 0.03, fractional annual maintenance of pipeline, Perry's
Engineers' Handbook.
q = (Variable), volumetric flow rate, ft3/s.
p = (Variable), density, Ib/ft3.
u' = 0.091, fluid viscosity, centipoise.
When all these values are substituted into the equation along
with F, the economic pipe size equation in Perry's equation becomes a
quadratic function with diameter (d) as the quadratic variable. The
solution lies in selecting a flow rate and assuming a diameter that,
when substituted into the quadratic, will yield the desired flow rate.
This procedure was accomplished for a range of flow rates for each of
the venting system's three pipe segments. The three pipe segments are
called the source, compressor, and pipeline legs and are separated in
this manner to represent accurately the different flow rates, pressures,
and densities of the vented gas in the system.
The computer model (IV-A-3) picked the closest nominal pipe
diameter (Schedule 40) to the economic pipe diameter determined by
Perry's pipe-diameter equation. Once pipeline diameter was determined
for each of the three pipe segments, the pressure drop was calculated
and a compressor cost was estimated on the basis of emissions flow
rate. Pipeline costs were calculated by hand for each nominal pipe
diameter from 1/4-inch to 24-inch pipe for each pipe segment and
entered into the computer in matrix form. The computer model was used
to add appropriate pipeline costs to compressor costs to estimate
total vent system costs.
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Cost model output results consistently showed pipe diameters that
generate a low pressure drop and, thus, allow the use of a small com-
pressor. The total system pressure drop was typically 1 to 2 psi
maximum and compressor compression capabilities were 5 to 6 psi for
the same flow rate. The cost factors in Table C-4 were used to estimate
indirect capital costs and annualized costs. Fuel recovery credits
were estimated by the procedure described in Subsection C.2.2.2 of
this appendix. Overall, the model provided a simple and accurate
method of conservatively estimating emissions venting system costs.
Results of this analysis are summarized in Table 2-6 of this document
(EPA-450/3-79-035b; pp. 2-33).
This analysis enabled identification of an emissions cutoff rate.
From these data, EPA developed alternatives for BDT and beyond BDT.
This determination is explained in Response 2.5.1 of this document.
The costs associated with the regulatory alternatives that EPA examined
in determining BDT and beyond BDT were developed according to procedures
outlined in Subsection C.2.2.2 of this appendix. The only differences
in costing are the revised piping and compression costs discussed in
Subsection C.3.2 of this appendix. The reason for the cost revision
is that in the CMA data package, piping and compression costs were
estimated for compliance with the proposed standard. The regulatory
alternatives for the promulgated standard call for the control of
fewer emissions sources and thereby reduce piping and compression
costs. Therefore, EPA piping and compression cost estimates, CMA
instrumentation, electrical, and other control equipment direct capital
cost estimates (IV-D-13); EPA fuel recovery estimates; and EPA indirect
capital and annualized cost parameters (see Table C-4) were used to
estimate costs for the regulatory alternatives examined for BDT and
beyond BDT. The rationale for determining BDT and beyond BDT and
costs associated with each regulatory alternative examined are dis-
cussed in Response 2.5.1 of this document.
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C.4 ECONOMIC IMPACTS
C.4.1 Introduction
The following subsections provide estimates of the economic
impacts of BDT and the beyond-BDT control options. Rate of return on
equity impacts are presented in Subsection C.4.2. Subsection C.4.3
presents styrene price impacts, while Subsection C.4.4 provides esti-
mated output and employment impacts.
C.4.2 Rate of Return Impacts
Table C-9 presents estimates of impacts on rates of return on
equity under full cost absorption for BDT and the beyond-BDT control
option. A 15-percent target after tax rate of return is assumed. All
rate-of-return impacts are small.
Under BDT, only three parent companies are expected to experience
any impact on rate of return. Dow Chemical, USA, would experience the
maximum negative impact (-0.000009); however, this impact represents
only 0.01 percent of the target rate of return of 15 percent. Atlantic
Richfield and Sun Oil Company experience negative impacts of less than
0.01 percent of the target rate of return; other parent companies show
no impact from BDT.
Under the beyond-BDT option, five parent companies exhibit impacts
on rate of return. El Paso Products Company would experience the
maximum negative impact: (-0.000137) or 0.09 percent of the target
rate of return. Other parent company impacts represent 0.01 percent
or less of the target rate of return of 15 percent.
C.4.3 Price Impacts
Tables C-10 and C-ll present price changes required to maintain a
15-percent target rate of return under two capacity utilization scenar-
ios for BDT and the beyond-BDT option, respectively. Estimated per-
centage price changes are based on a styrene price of $750/Mg, the
fourth-quarter 1980 price. All indicated price changes are small in
magnitude and percentage terms. These required price changes are
estimated specifically to obtain an indication of maximum impacts.
However, in the absence of collusion among producers, it is unlikely
that maximum required price increases under 76 percent utilization
C-24
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TABLE C-9. RATE OF RETURN ON EQUITY IMPACTS3
BDT
Beyond BDT
Parent company
W RORU
W ROR/RORC
W RORC
W ROR/RORC
American Petrofina 0.000000 0.00 0.000000 0.00
(joint owner, Cos-Mar)
Amoco 0.000000 0.00 0.000000 0.00
Atlantic Richfield -0.000003 F-0.01 -0.000019 -0.01
(ARCO and joint
owner, Oxirane)
Borg-Warner 0.000000 0.00 0.000000 0.00
(joint owner, Cos-Mar)
Dow Chemical, USA -0.000009 -0.01 -0.000009 -0.01
El Paso Products Company 0.000000 0.00 -0.000137 -0.09
Gulf Oil Corporation 0.000000 0.00 -0.000011 -0.01
Monsanto Company 0.000000 0.00 0.000000 0.00
Sun Oil Company -0.000003 F-0.01 -0.000003 F-0.01
U.S. Steel Corporation 0.000000 0.00 0.000000 0.00
almpacts on rates of return on equity are estimated for parent companies whose
financial data are available. A 15-percent target after tax rate of return
is assumed.
Change in rate of return on equity.
""Percentage change in rate of return on equity.
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TABLE C-10. REQUIRED STYRENE PRICE CHANGES: BDT£
76% capacity
utilization
Producing company
American Hoechst Corporation
Amoco
Atlantic Richfield Company
Cos-Mar, Inc.
Dow Chemical, USA
El Paso Products Company
Gulf Oil Corporation
Monsanto Company
Oxirane Corporation
Sun Oil Company
U.S. Steel Corporation
W Pb
($/Mg)
0.06
0.00
0.52
0.00
0.11
0.00
0.00
0.00
0.00
0.66
0.00
W P/PC
(%)
0.01
0.00
0.07
0.00
0.01
0.00
0.00
0.00
0.00
0.09
0.00
100% capacity
utilization
W Pb
($/Mg)
0.04
0.00
0.39
0.00
0.08
0.00
0.00
0.00
0.00
0.50
0.00
W P/PC
(%)
0.01
0.00
0.05
0.00
0.01
0.00
0.00
0.00
0.00
0.07
0.00
aPrice changes required to maintain a 15-percent rate of return
are presented.
bChange in price in fourth quarter, 1980 dollars.
cPercentage change in price assuming a base price of $750/Mg.
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TABLE C-ll. REQUIRED STYRENE PRICE CHANGES: BEYOND BDTa
76% capacity
utilization
Producing company
American Hoechst Corporation
Amoco
Atlantic Richfield Company
Cos-Mar, Inc.
Dow Chemical , USA
El Paso Products Company
Gulf Oil Corporation
Monsanto Company
Oxirane Corporation
Sun Oil Company
U.S. Steel Corporation
W Pb
($/Mg)
0.06
0.00
0.52
0.00
0.11
2.23
0.89
0.00
1.08
0.66
0.00
W P/PC
(%)
0.01
0.00
0.07
0.00
0.01
0.30
0.12
0.00
0.14
0.09
0.00
100% capacity
utilization
W Pb
($/Mg)
0.04
0.00
0.39
0.00
0.08
1.69
0.67
0.00
0.82
0.50
0.00
W P/PC
(%)
0.01
0.00
0.05
0.00
0.01
0.23
0.09
0.00
0.11
0.07
0.00
aPrice changes required to maintain a 15-percent rate of return
are presented.
Change in price in fourth quarter, 1980 dollars.
GPercentage change in price assuming a base price of $750/Mg.
C-27
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would hold. Excess capacity generally inhibits full cost pricing.
Accordingly, the following discussion of price increases will be based
on the assumption of 100 percent utilization.
Under BDT, 4 of 11 producing companies would require price
increases to maintain a 15-percent rate of return. Sun Oil Company
would require the largest price increase, $0.50/Mg or 0.07 percent of
the base price. Atlantic Richfield would require a 0.05-percent price
increase, while American Hoechst and Dow Chemical, USA, would require.
0.01 percent increases. The average of all required company price
changes is $0.09/Mg or 0.01 percent of the base price.
Under the beyond-BDT option, seven producing companies would
require price increases to maintain a 15-percent rate of return. The
largest required price increase is $1.69/Mg for El Paso Products
Company, which represents a 0.23-percent increase in the base price of
styrene. All other required price increases represent less than
0.12 percent of the base price. The average of all required company
price changes is $0.38/Mg or 0.05 percent of the base price.
C.4.4 Output and Employment Impacts
Assuming 100 percent capacity utilization and a 15-percent target
rate of return, BDT results in a maximum required price increase of
about $0.50/Mg or 0.07 percent of product price. Assuming an estimated
long-run price elasticity of 0.49, this maximum price increase corre-
sponds to a maximum potential demand reduction of 0.034 percent, which
corresponds to about 1,370 Mg at the projected 1983 output level.
Based on employment data* this corresponds to a maximum of one worker
displaced.
Under the same assumptions, the beyond-BDT control option generates
a maximum price increase of about $1.70/Mg (0.23 percent of base
price), which corresponds to an output reduction of about 4,500 Mg at
the projected 1983 production level. One or two workers may be dis-
placed.
*Benzene Emissions from Ethylbenzene/Styrene Industry-Background
Information for Proposed Standards. U.S. Environmental Protection
Agency. Draft EIS. August 1980. EPA-450/3-79-035a; pp. 7-63 to 7-72.
C-28
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Note that the output and employment impacts cited above are
maximum values corresponding to maximum price increases. Actual price
increases and output reductions may be smaller. Furthermore, estimated
employment impacts do not include jobs created by the control systems.
Operation and maintenance of controls would require more labor time
than would be displaced by estimated output reductions. Net employment
impacts probably would be positive but small.
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