EFA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-aS.OC'S
December 1987
Air
VOC Emissions
From Petroleum
Refinery
Wastewater
Systems —
Background
Information for
Promulgated
Stai lards
EIS
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EPA-450/3-85-OOlb
VOC Emissions from Petroleum Refinery
Wastewater Systems — Background
Information for Promulgated Standards
Emissions Standards Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Offica of Air and Radiation
Office of Air Quality Planning and Standards
Rasaarch Triangla Park. North Carolina 27711
Daeambr-
U,l frivfrefcmenfa? Protection Agency
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This report has been reviewed by the Emission Standards 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 (MO-35). U.S. Environmental Protection Agency, Research Triangle Park NC 27711 or from
National Technical Information Services, 5285 Port Royal Road, Springfield VA 221 61
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ENVIRONMENTAL PROTECTION AGENCY
Background Information and Final
Environmental Impact Statement
for Petroleum Refinery Wastewater Systems
Prepared by:
Jack'R. Farmer
Director, Emission Standards Division
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
1. The standards of performance would limit emissions of volatile organic
compounds (VOC) from petroleum refinery wastewater systems. Section 111
of the Clean Air Act (42 U.S.C. 7411), as amended, directs the
Administrator to establish standards of performance for any category of
new stationary source of air pollution that ". . . causes or contributes
significantly to air pollution which may reasonably be anticipated to
endanger public health or welfare."
2. Copies of this document have been sent to the following Federal
Departments: Labor, Health and Human Services, Defense, Office of
Management and Budget, Transportation, Agriculture, Commerce, Interior,
and Energy; the National Science Foundation; and the Council on
Environmental Quality. Copies have also been sent to 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:
Mr. Doug Bell
Standards Development Branch (MD-13)
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
Telephone: (919) 541-5568
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
m
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TABLE OF CONTENTS
Section Page
1.0 SUMMARY i_i
1.1 SUMMARY OF CHANGES SINCE PROPOSAL 1-1
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION 1-5
1.2.1 Alternatives to the Promulgated Action 1-5
1.2.2 Environmental Impacts of the Promulgated Action 1-6
1.2.3 Energy and Economic Impacts of the Promulgated Action. . 1-6
1.2.4 Other Considerations 1-6
1.2.4.1 Irreversible and Irretrievable Commitment
of Resources 1-6
1.2.4.2 Environmental and Energy Impacts of
Delayed Standards 1-7
1.2.4.3 Urban and Community Impacts . . 1-7
2.0 SUMMARY OF PUBLIC COMMENTS 2-1
2.1 APPLICABILITY OF THE STANDARDS 2-1
2.2 DEFINITION OF AFFECTED FACILITY AND MODIFICATION/
RECONSTRUCTION 2-13
2.3 SELECTION OF CONTROL TECHNOLOGY 2-21
2.4 COST/COST EFFECTIVENESS 2-37
2.5 ENVIRONMENTAL AND ECONOMIC IMPACTS 2-43
2.6 MONITORING, RECORDKEEPING, AND REPORTING REQUIREMENTS 2-45
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1.0 SUMMARY
On May 4, 1987 the Environmental Protection Agency (EPA) proposed new
source performance standards (NSPS) for petroleum refinery wastewater systems
(52 FR 16334) under the authority of Section 111 of the Clean Air Act. The
standards limit atmospheric emissions of volatile organic compounds (VOC)
from petroleum refinery wastewater systems. Public comments were requested
on the proposal in the Federal Register. There were 12 commenters composed
of industry representatives, one industry trade association, and one equipment
vendor. The public comments, along with responses to these comments, are
summarized in this document. The comments and responses serve as the basis
for the revisions made to the standards between proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
In response to the public comments and as a result of reevaluation,
certain changes have been made in the proposed standards. The use of equip-
ment, work practice, design, and operational standards to reduce VOC emissions
from individual wastewater system components has not changed. Also, the
aggregate facility definition remains in the regulation, although the type of
change that would constitute a modification and bring an existing facility
under the regulation has been changed.
The following are changes made to the standards since proposal:
(1) all refinery wastewater treatment system components downstream of
the oil-water separators (with the exception of slop oil facilities) have
been excluded from coverage under the regulation. This includes two groups
of components: (a) air flotation systems including dissolved air flotation
systems (DAF's) and induced air flotation systems (lAF's); and (b) equaliza-
tion basins and other auxiliary tanks, basins, and equipment located between
the oil-water separator and the downstream air flotation system.
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These two groups of components have been exempted under the final
standards based on a reevaluation of safety concerns, emissions potential,
and cost effectiveness associated with control of these facilities. In the
case of DAF's, safety concerns raised by commenters cannot be overcome in a
cost-effective manner. In the case of both DAF's and lAF's, the overall VOC
emission reductions would be negligible without use of a closed vent system
and a vapor control device because VOC emissions would be suppressed
temporarily only to be emitted downstream of the air flotation system at
facilities which cannot be cost-effectively controlled under Section 111 of
the Clean Air Act.
Equalization basins and other auxiliary tanks, basins and equipment
between the oil-water separator and air flotation system have been exempted
for the same reasons. There are no cost-effective methods of VOC emissions
destruction or removal that have been demonstrated for these facilities.
Further, suppression of VOC emissions at these points in the treatment
process merely suppresses temporarily the VOC's downstream to be emitted at
other uncontrolled locations.
The regulation of slop oil tanks has been revised slightly. Storage
vessels, including slop oil tanks and other auxiliary tanks are now covered
under this Subpart only if they are not an affected facility under Subparts K,
Ka, or Kb of 40 CFR Part 60. Slop oil tanks and other auxiliary tanks
covered under this NSPS are required to have a tightly sealed fixed roof.
The requirement that slop oil be collected, stored, recycled, and transported
in an enclosed system prior to reuse, disposal, or resale remains unchanged,
except for the inclusion under the standards of oily wastewater drawn from
slop oil handling equipment.
(2) The requirement to ensure "no detectable emissions" from seams,
joints, seals, and gaskets on junction boxes, oil-water separators, and other
equipment having atmospheric or pressure control vents has been deleted in
the final standards. For these vented facilities, an initial visual inspec-
tion and semiannual inspections thereafter, coupled with follow-up repairs or
maintenance, is sufficient for monitoring purposes. The requirement that
closed vent systems be monitored to ensure no detectable VOC emissions
(defined as 500 ppm above background levels) has not been changed.
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(3) The aggregate affected facility definition included in the proposed
standards has been retained, but includes two changes. One change is that
air flotation systems and other equipment downstream of the oil-water
separator are no longer included in the aggregate facility because such
facilities are not covered under the final standards. The second change is
that installation of a new individual drain system rather than any physical
or operational change is necessary to constitute a "modification" to the
aggregate facility. In this case, individual drain system means all process
drains connected to the first common downstream junction box. If a new
individual drain system is constructed that results in increased emissions,
the individual drain system together with its ancillary downstream
components, to and including the oil-water separators, would be an affected
facility subject to the requirements of Subpart QQQ.
(4) A new paragraph at Section 60.690(b) has been added to the
regulation concerning modification. This provision alters the application of
the definition of modification in the General Provisions (40 CFR Sec-
tion 60.14) such that the addition of a new individual drain system will be
considered a modification to an aggregate affected facility. This change
eliminates the capital expenditure exemption contained in Section 60.14(e)
for the addition of new individual drain systems for aggregate facilities,
making the addition of any new individual drain system a modification of the
aggregate facility without regard to cost. The change also ensures, however,
that small physical or operational changes made by the refiner that do not
significantly increase emissions will not trigger the applicability of the
standards for aggregate facilities.
(5) The final rule has been revised to require that vented junction
boxes be equipped with vent pipes having a maximum diameter of 10.2 centi-
meters (4 inches) and a minimum length of 90 centimeters (36 inches). This
change has been made to reduce VOC emissions from junction box vent pipes,
which are necessary to eliminate the buildup of potentially explosive vapors,
but whose dimensions can significantly affect VOC emission potential.
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(6) The inspection schedule for water seals in process drains has been
revised. Drains that are kept in active wastewater collection service and
are consequently maintained by use, as well as by precipitation and main-
tenance washing, shall be inspected monthly, rather than weekly as proposed.
However, for drains that are removed from active service, there is no
assurance that use, precipitation, or maintenance washing will maintain the
water seal. Consequently, a weekly visual or physical inspection of the
water seal is still required. However, if a tightly sealed cap or plug is
installed on drains that are not in active service, then semiannual
inspections are required.
(7) The final rule has been clarified as to what is required when an
oil-water separator that was already fully or partially covered at the time
of proposal is modified or reconstructed. A modified or reconstructed
oil-water separator shall be equipped with a roof over the entire separator
tank. If at the time of proposal (May 4, 1987) a separator is already
equipped with a fixed roof over the entire separator tank and the facility is
modified or reconstructed, the roof shall be tightly sealed. If the separator
has a design capacity to treat 38 liters per second [600 gallons per minute
(gpm)] or more of refinery wastewater, the vapor space shall be vented to a
VOC recovery or destruction control device. As an alternative to a fixed
roof vented to a control device, a floating roof may be installed.
If a partial fixed roof was in place at the time of proposal and the
oil-water separator has a design capacity to treat 38 liters per second
(600 gpm) or more, upon modification or reconstruction the remainder of the
oil-water separator shall be covered with a fixed roof and the vapor space
shall be vented to a control device. As an alternative to a fixed roof and
control device, the partial fixed roof may be removed and the entire oil-water
separator covered with a floating roof.
If a partial fixed roof was in place at the time of proposal over a
portion of the separator tank and the oil-water separator has a maximum
design capacity to treat less than 38 liters per second (600 gpm), upon
modification or reconstruction the remainder of the separator tank shall be
covered with either a floating roof or a tightly sealed fixed roof, but shall
not be required to vent vapors to a recovery or destruction device.
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(8) The recordkeeping and reporting requirements applicable to closed
vent systems have been revised to require that certain information about the
operation of the control device be maintained. For facilities using a
thermal incinerator, continuous records must be maintained of the temperature
of the gas stream in the combustion zone of the incinerator. Also, records
of all 3-hour periods during which the average temperature of the gas stream
in the combustion zone of the thermal incinerator is more than 28°C (50°F)
below the design temperature must be maintained and reported semi annually.
Similarly, for facilities using catalytic incinerators, continuous records of
the temperature of the gas stream both upstream and downstream of the
catalyst bed must be maintained. Also, records of all 3-hour periods during
which the average temperature measured before the catalyst bed of a catalytic
incinerator is more than 28°C (50°F) below the design gas stream temperature,
and all 3-hour periods during which the average temperature difference across
the catalyst bed is less than 80 percent of the design temperature difference
across the catalyst bed must be maintained and reported semi annually. For
facilities using a carbon adsorber, continuous records of the VOC
concentration level or reading of organics of the control device outlet
gas stream or inlet and outlet gas stream must be maintained. Records of
all 3-hour periods during which the average VOC concentration level in
the exhaust gases of a carbon adsorber is more than 20 percent greater
than the design concentration level must be reported semiannually to the
Administrator.
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.2.1 Alternatives to the Promulgated Action
The regulatory alternatives are discussed in Chapter 6 of the Volume I
background information document (BID) for the proposed standards
(EPA-450/3-85-001a). These regulatory alternatives reflect the different
levels of emission control that were analyzed in determining best demonstrat-
ed technology, considering costs, nonair quality health, and environmental
and economic impacts for petroleum refinery wastewater systems. These
alternatives remain the same.
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1.2.2 Environmental Impacts of the Promulgated Action
The final standards would reduce atmospheric emissions of VOC from about
100 newly constructed process unit drain systems, 30 newly constructed
oil-water separators, 18 modified or reconstructed process drain systems, and
a small number of modified or reconstructed oil-water separators by about
2,020 megagrams (Mg) per year (2,225 tons per year) in the fifth year of
implementation. This is about 60 Mg (65 tons) less than the proposed
standards as discussed in Chapter 7 of the Volume I BID, and reflects the
exclusion of air flotation systems from the final standards. Implementation
of the standards will not result in any adverse solid waste impact or water
impact. Therefore, with the changes noted in this section, the analysis of
environmental impact in Volume I of the BID now becomes the final
Environmental Impact Statement for the promulgated standards.
1.2.3 Energy and Economic Impacts of the Promulgated Action
Energy impacts resulting from the standards are discussed in Chapter 7
of the Volume I BID and have not changed significantly since proposal. The
economic impacts of the standards have been revised to reflect the exemption
of air flotation systems from the final rule. The fifth year annualized
costs by model unit and regulatory alternative are summarized in Chapter 9 of
the Volume I BID. The economic impact of the final standards is estimated to
be $1.1 million. The economic analysis indicates that no adverse economic
impacts on projected facilities are expected to result from the standards.
1.2.4 Other Considerations
1.2.4.1 Irreversible and Irretrievable Commitment of Resources. The
regulatory alternatives defined in Chapter 6 of the Volume I BID would not
preclude the development of future control options nor would they curtail any
beneficial use of resources. The alternatives do not involve short-term
environmental gains at the expense of long-term environmental losses. The
alternatives yield successively greater short- and long-term environmental
benefits, with the alternative upon which the final standards are based
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providing the greatest benefits. Further, none of the alternatives result in
the irreversible and irretrievable commitment of resources. No changes in
these considerations have resulted since proposal of the standards.
1-2.4.2 Environmental and Energy Impacts of Delayed Standards. As
discussed in Chapter 7 of the Volume I BID, delay in the standards would
cause a similar delay in realizing the beneficial impacts associated with the
standards. No changes in the potential effects of delaying the standards
have occurred since proposal.
1.2.4.3 Urban and Community Impacts. There are no urban and community
impacts attributable to the proposed or promulgated standards.
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2.0 SUMMARY OF PUBLIC COMMENTS
A total of 12 letters commenting on the proposed standards and Volume I
of the BID for the control of emissions of VOC from petroleum refinery
wastewater systems were received. A public hearing on the proposed standards
was not requested. Written comments were provided by industry representatives,
one industry trade association, and one equipment vendor. These comments
have been recorded and placed in the EPA docket for this rulemaking (Docket
Number A-83-07, Category IV). Table 2-1 presents a listing of all persons
submitting written comments, their affiliations and addresses, and the
recorded Docket Item Number assigned to each comment.
For the purpose of orderly presentation, the comments have been
categorized under the following topics:
2.1 Applicability of the Standards
2.2 Definition of Affected Facility and Modification/Reconstruction
2.3 Selection of Control Technology
2.4 Cost/Cost Effectiveness
2.5 Environmental and Economic Impacts
2.6 Monitoring, Recordkeeping, and Reporting Requirements
2.1 APPLICABILITY OF THE STANDARDS
2.1.1 Comment: Three commenters questioned the need for the standards. One
commenter questioned the need to regulate VOC's generally when there is no
demonstration that specific chemicals are being emitted which affect health
and welfare, nor is there any demonstration that significant quantities of
such chemicals are being emitted (IV-D-3, IV-D-5, IV-D-8). One of the
commenters questioned whether the standards should apply outside nonattainment
areas if the concern is over ozone nonattainment (IV-D-3). Another commenter
had the same concern, saying that the definition of volatile organic compound
in Section 60.691 of the proposed regulation arbitrarily requires regulation
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TABLE 2-1. LIST OF COMMENTERS ON THE PROPOSED STANDARDS OF PERFORMANCE FOR
VOC EMISSIONS FROM PETROLEUM REFINERY WASTEWATER SYSTEMS
Commenter/Affillation Docket Item Number3
Neil J. Wasilk IV-D-1
Environmental Representative
Sohio Oil Company
200 Public Square
Cleveland, Ohio 44114-2375
R. M. Bodin IV-D-2
Manager, Environmental Services
Citgo Petroleum Corporation
Lake Charles Operations
Box 1562
Lake Charles, Louisiana 70602
Gary M. Whipple IV-D-3
Assistant Director of Environmental
Affairs
Chemicals and Plastics Group
Union Carbide Corporation
39 Old Ridgebury Road
Danbury, Connecticut 06817-0001
B. F. Ballard, Director IV-D-4
Environment Control
Phillips Petroleum Company
12 A4 Phillips Building
Bart!esvilie, Oklahoma 74004
Allan A. Griggs, P.E. IV-D-5
Project Manager
Diamond Shamrock Refining and
Marketing Company
Post Office Box 69600
San Antonio, Texas 78269-6000
Continued
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TABLE 2-1 (CONTINUED). LIST OF COMMENTERS ON THE PROPOSED STANDARDS OF
PERFORMANCE FOR VOC EMISSIONS FROM PETROLEUM
REFINERY WASTEWATER SYSTEMS
Commenter/Affiliation Docket Item Number3
E. J. Ciechon, Esquire IV-D-6
T. T. Zale
Sun Refining and Marketing Company
Ten Penn Center
1801 Market Street
Philadelphia, Pennsylvania 19103
Steven M. Swanson, Director IV-D-7
Health and Environmental Affairs
Department
American Petroleum Institute
1220 L Street Northwest
Washington, D.C. 20005
U. V. Henderson, Jr. IV-D-8
Associate Director
Environmental Affairs
Research and Environmental Affairs
Department
Texaco, Inc.
Post Office Box 509
Beacon, New York 12508
R. W. Hawes, Manager IV-D-9
J. R. Britt
Air and Water Conservation
Manufacturing Department
Mobil Oil Corporation
3225 Gallows Road
Fairfax, Virginia 22037
J. G. Huddle IV-D-10
Director, Environmental Control
and Planning
Amoco Oil Company
200 East Randolph Drive
Post Office Box 6110A
Chicago, Illinois 60680
Continued
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TABLE 2-1 (CONCLUDED). LIST OF COMMENTERS ON THE PROPOSED STANDARDS OF
PERFORMANCE FOR VOC EMISSIONS FROM PETROLEUM
REFINERY WASTEWATER SYSTEMS
Commenter/Affiliation Docket Item Number3
Michael M. DeLeon IV-D-11
Air Programs Supervisor
Tosco Corporation
Avon Refinery
Martinez, California 94553
W. L. Wagner, P.E. IV-D-12
President
Petrex, Inc.
Post Office Box 907
Warren, Pennsylvania 16365
aThe docket number for this project is A-83-07. Dockets are on file at the
EPA's Central Docket Section.
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of organic compounds that are not volatile and/or do not form photochemical
oxidants, until the Administrator makes a determination to exempt a compound
(IV-D-8). A third commenter stated that several aspects of the proposed rule
constituted excessive regulation of very small sources of emissions (IV-D-5).
Response: Emissions of VOC from petroleum refinery wastewater systems
represent a significant source of VOC emissions to the atmosphere. The EPA
estimates that 55.5 gigagrams (Gg) (61,123 tons) of VOC per year are emitted
from wastewater treatment processes at petroleum refineries. Petroleum
refinery wastewater systems are part of the source category "Petroleum
Refineries: Fugitive Sources." This source category is included in the EPA
Priority List (40 CFR 60.16, 44 FR 49222, August 21, 1979, and as amended by
47 FR 31876, July 23, 1982) and ranks third on the list. The Priority List
consists of categories of air pollution sources that, in the EPA's judgment,
cause or contribute significantly to air pollution that reasonably may be
anticipated to endanger public health or welfare. No information was
presented to demonstrate that the EPA's judgment in listing this source
category is incorrect. The EPA is required by Section 111 of the Clean Air
Act to promulgate standards of performance for each source category on the
Priority List.
As stated in the proposal preamble on page 16337, these standards
regulate VOC emissions that are precursors to the formation of ozone. Ozone
is harmful to human health and welfare. In addition to contributing to the
formation of ozone, VOC emissions from petroleum refinery wastewater systems
include benzene and other potentially toxic constituents such as xylene and
toluene. Benzene has been listed under Section 112 of the Clean Air Act as a
hazardous pollutant because benzene emissions significantly increase the risk
of cancer. Emission controls on VOC's at refinery wastewater systems would
also reduce emissions of benzene, xylene, and toluene.
New source performance standards (NSPS) apply uniformly nationwide.
Specific geographic areas would be excluded only if unreasonable impacts
would result. New source performance standards are not limited only to
attainment areas for any pollutant. In the case of petroleum refineries,
there is no indication that unreasonable impacts will result from regulation
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of wastewater treatment systems for refineries in any specific area. In any
case, most refineries are located in ozone nonattainment areas, which
reinforces the need to reduce VOC's from any new, modified, or reconstructed
wastewater treatment system.
With respect to the second commenter's concern about regulation of
nonvolatile as well as volatile compounds, EPA is convinced that the defini-
tion of VOC in the regulation does not overreach the objective of this NSPS.
Clearly, the majority of compounds found in refinery process wastewater
streams are volatile and photochemically reactive in nature. In addition, as
stated above, most wastewater streams at refineries contain toxic con-
stituents. The emission controls on the wastewater system would provide an
added benefit by also reducing emissions of these toxic constituents.
Finally, with respect to the third commenter's concern about excessive
regulation of very small sources, the final standards exempt air flotation
systems because regulation of DAF's is not cost effective. The cost and
economic impacts of regulating individual drain systems and oil-water
separators have been analyzed thoroughly and are considered reasonable.
2.1.2 Comment: One commenter recommended that a provision be included in
the standards that would exempt facilities with oily wastewater streams
containing only heavier hydrocarbon compounds (IV-D-2). Streams containing
only these compounds would be expected to have lower emissions than streams
containing lighter, more volatile compounds. The commenter specifically
recommended that this exemption be in the form of a minimum vapor pressure
requirement of 1.5 psia. Another commenter suggested that the exemption be
implemented through the use of a minimum relative volatility level (IV-D-3).
Without such an exemption, the commenters stated, the standards would impose
an economic burden on some facilities without accomplishing a significant
reduction in VOC emissions.
Response; A cutoff based on vapor pressure or other measure of
volatility for oily wastewater streams was considered during the development
of the proposed regulation, but was not adopted because the total vapor
pressure of the organics in the wastewater has the potential to vary widely
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and may change with wastewater loading, composition, and temperature. Among
other factors that influence the rate of volatilization are ambient
temperature, wind speed over the basin, and the thickness of the oil layer.
An industry survey showed that the organic loading can vary by orders of
magnitude for the same wastewater system (see Docket A-83-07, Item
No. II-B-45). Although there are no data to reflect the degree of change in
organic composition of the wastewater, these changes can result from the
loading variations, upset conditions, changes in operation, and the addition
of new process units. For these reasons, a vapor pressure cutoff has not
been included in the final standards.
2.1.3 Comment: Seven commenters objected to the requirement for
installation of fixed roofs on DAF's. The concerns range from poor cost
effectiveness (mainly due to low emissions potential); to safety (because of
safety concerns, it may be necessary to purge the fixed roof to a VOC
recovery or destruction device); to operation (roof would interfere with
operation, reduce downstream water quality); and to maintenance (roof would
hinder regular maintenance) (IV-D-1, IV-D-2, IV-D-5, IV-D-6, IV-D-7, IV-D-9,
IV-D-10).
Response: In response to these comments, EPA undertook a thorough
reexamination of the technical, economic, and environmental bases of the
application of the NSPS to air flotation systems, focusing specifically on
the safety problems and the low emission potential of air flotation systems.
As a result of this reexamination, the final standards have been revised to
exempt air flotation systems, including both DAF's and lAF's.
The analysis undertaken by the Agency included a telephone survey of
refiners with fixed roofs installed on their DAF's, as well as a review of
the responses to a telephone survey of vendors conducted prior to the
proposal. Further, DAF float disposal methods were reviewed to evaluate
potential downstream impacts of controlling these systems. As a result of
this analysis, the Agency has determined that a DAF controlled with a tightly
sealed roof may pose safety concerns that were not adequately addressed by
the proposed standards. An unvented fixed roof may present an explosion and
fire hazard in some types of air flotation systems due to the buildup of
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explosive vapors inside the cover. By purging the space beneath the fixed
roof with another gas, such as nitrogen, this safety concern can be
alleviated. For a system with the vapor space purged and vented to a control
device, the incremental cost effectiveness was estimated to be over
$13,000/Mg ($ll,800/ton) of VOC. Consequently, EPA concluded there is no
cost-effective method of VOC destruction or removal demonstrated for DAF's.
Fixed roof controls on air flotation systems serve to suppress VOC emis-
sions temporarily, rather than to destroy VOC. The VOC emissions that are
suppressed temporarily by the fixed roof system are merely transported
downstream through DAF effluent and froth. Consequently, the 60 Mg/year
(65 tons/year) VOC emission reduction shown in Volume I of the BID actually
represents the VOC emissions suppressed temporarily by fixed roof controls on
air flotation systems, but emitted downstream at uncontrolled emission
points.
The Agency did consider DAF froth recycling as an alternative method for
VOC control. However, recycling has not been demonstrated to be a practical
method of froth disposal for all refiners because the froth may contain
additives such as coagulants. The majority of refiners landfarm or landfill
froth rather than recycle it.
Taken together, these considerations led the Agency to decide that the
focus of the standards should be on the control of emissions from individual
drain systems and oil-water separators, including slop oil tanks, rather than
on air flotation systems. Therefore, air flotation systems are not covered
by the final standards.
2.1.4 Comment: One commenter stated that equalization basins located
upstream from the air flotation system should not be included in the
definition of DAF's (IV-D-2). According to this commenter, these are very
large basins and it would be difficult to place covers on them. A cover
could also be dangerous due to the large surface area and amount of potential
air leaks into the cover.
Response; Equalization basins that are part of an air flotation
system have been excluded from the final standards for essentially the same
reasons that air flotation systems themselves have been excluded (see 2.1.3
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above). The recommended method of VOC control is a fixed roof, which, like
DAF's, would suppress VOC emissions temporarily only to be emitted at some
uncontrolled location downstream. There are no cost-effective methods of VOC
recovery or destruction that have been demonstrated for these facilities.
2.1.5 Comment: Two commenters requested clarification of the applicability
of the proposed standards to slop oil from oil-water separators and of the
requirement in the proposed standards that slop oil be collected and reused
or disposed of in an enclosed system (IV-D-8, IV-D-9). The commenters stated
that these requirements could extend the applicability of the standards to
segments of the refinery operation beyond the wastewater system itself, and
could potentially encompass the entire refinery in cases where slop oil is
combined with refinery feedstock. The commenters suggested that the
provision for slop oil be dropped unless a technical basis for justifying
such a requirement can be demonstrated.
Response: The final standards have been revised to clarify the scope
of the regulation of slop oil and slop oil tanks. In the final standards,
storage vessels including slop oil tanks auxiliary to oil-water separators
are regulated. These storage vessels are required to be covered with a
tightly sealed fixed roof. The fixed roof can be vented with a pressure
control valve which has been set at the maximum pressure necessary for proper
system operation, but such that the pressure relief valve is not venting
continuously. Such a requirement is both technically feasible and cost-
effective in view of the VOC emissions potential of these uncovered
facilities.
Emissions from slop oil are regulated under this subpart until the slop
oil reenters a process unit or is disposed of. The slop oil and oily
wastewater drawn from slop oil handling equipment must be collected, stored,
transported, recycled, reused or disposed of in an enclosed system (i.e., it
must not be open to the atmosphere). Once slop oil is returned to the
process, or is disposed of, it is no longer within the scope of this
regulation. Another limitation on the applicability of this subpart to
storage vessels including slop oil tanks is posed by the requirements of
Subparts K, Ka, and Kb that regulate volatile organic liquid storage vessels,
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depending on the size of the facility and the vapor pressure of the liquid
being stored. The NSPS for petroleum refinery wastewater systems does not
apply to storage vessels that are subject to the requirements of Subparts K,
Ka, or Kb, although the transportation, recycling, reuse, or disposal of slop
oil remains subject to the NSPS for petroleum refinery wastewater systems and
must be kept in an enclosed system.
2.1.6 Comment: Four commenters made comments related to the auxiliary
equipment in the wastewater system that is regulated by the NSPS (IV-D-7,
IV-D-8, IV-D-9, IV-D-10). Three of the commenters suggested that the
definition of "oil-water separator" not include operations such as holding
tanks, surge tanks, or catch basins where oil separation is incidental to the
primary function of the equipment (IV-D-7, IV-D-9, IV-D-10). The commenters
suggested that because the rule is based on economic analyses of emissions
from specific types of separators [conventional American Petroleum Institute
(API) and corrugated plate interceptor], the rule should be limited to only
those types of separators.
Response: The definition of oil-water separator in the final rule has
been clarified to include wastewater treatment equipment used to separate oil
from water consisting of a separation tank, which also includes the forebay
and other separator basins, skimmers, weirs, grit chambers, and sludge
hoppers. Slop oil facilities including tanks are included in this term along
with storage vessels and auxiliary equipment located between individual drain
systems and the oil-water separator. This term does not include auxiliary
equipment or storage vessels which do not come in contact with or store oily
wastewater. Auxiliary equipment includes equipment such as holding tanks and
surge tanks.
The rationale for this determination is that oil-water separators are
commonly used by most refineries as the first step in refinery wastewater
treatment. Since oil-water separators remove most of the VOC with the
skimmed oil, the units following this process will have lower VOC emissions.
By the same logic it follows that units that either store skimmed slop oil or
precede the oil-water separator and receive oily wastewater have similar VOC
emission potential as the oil-water separator.
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Auxiliary equipment preceding the oil-water separator is subject to the
same control requirements as the oil-water separator. That is, for equipment
having a design capacity to treat more than 16 liters per second (250 gpm) of
refinery wastewater, a fixed roof vented to a control device, or a floating
roof is required. For equipment with a maximum design capacity of 16 liters
per second (250 gpm) or less, a tightly sealed cover is required or a floating
roof may be used.
For portions of the oil-water separator such as the skimming mechanism
or weirs where it is infeasible to construct a floating roof, a tightly
sealed fixed roof may be installed. A tightly-sealed fixed roof shall also
be installed to completely cover other auxiliary storage vessels such as slop
oil tanks. If the Agency were to allow a mixture of regulated and unregu-
lated components upstream of the oil-water separator, the effectiveness of
the VOC emissions control at the separator would be negated.
The rule does exempt existing individual drain systems with catch basins
in their existing configuration, segregated stormwater removal systems, surge
tanks that receive only stormwater runoff, non-contact cooling water systems,
and any other tanks or basins which are used for storing non-VOC products
such as caustic or coagulant. In addition, storage vessels, including slop
oil tanks, and other auxiliary tanks covered under Subparts K, Ka, or Kb are
exempt from these standards.
Additional cost analyses were also performed to ensure that the cost
effectiveness of control for slop oil tanks is reasonable. The cost
effectiveness of a fixed roof for a 13,250 liter (3,500 gallon) and
75,700 liter (20,000 gallon) slop oil tank was analyzed. The emission
potential for these facilities was calculated based on the VOC content of the
slop oil. The cost effectiveness of control was estimated to be $4/Mg
($3.60/ton) to $490/Mg ($445/ton) for a fixed roof on the slop oil tanks.
The Agency considers these costs to be reasonable.
2.1.7 Comment; One commenter questioned at exactly what point sludge and/or
oil is removed from a separator or air flotation system no longer regulated
by the NSPS (IV-D-8).
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Response: The final rule regulates slop oil until the slop oil
reenters a process unit. Until the slop oil reenters a process unit, it must
be stored, transported, recycled, reused, or disposed of in an enclosed
system (i.e., it must not come in contact with the atmosphere). Once slop
oil is returned to the process, it is no longer within the scope of this
regulation. Sludge-handling facilities and sludge (including air flotation
froth) are not subject to this NSPS, but are expected to be regulated under
the Resource Conservation and Recovery Act.
2.1.8 Comment: Two commenters stated that the proposed standards improperly
include refinery wastewater systems that do not have the potential for
emitting significant amounts of VOC, such as facilities handling low vapor
pressure products (e.g., heavy fuel oils, lubricants, greases, and asphalts)
(IV-D-2, IV-D-8). One commenter (IV-D-2) reported that the highest vapor
pressure for their feedstock was 0.1 psia/
Response: In response to this comment, EPA undertook an evaluation of
the emissions potential of facilities handling low vapor pressure products.
As part of this analysis, EPA identified typical feedstocks, feedstock
characteristics, and other parameters that would influence VOC emissions such
as 10 percent boiling point and wastewater influent temperature. In estima-
ting emissions, EPA used the Litchfield method to estimate the percent volume
loss from an oil-water separator under a set of conditions believed to be
representative of a facility handling low vapor pressure products.
The conditions used for the Litchfield method were an ambient temperature
of 18°C (65°F), a 10 percent boiling point of 232°C (450°F), an influent oil
concentration of 880 milligrams per liter (mg/1), and an influent wastewater
temperature of 60°C (140°F). These conditions differ from those used in
Volume I of the BID to estimate emissions from petroleum refinery oil-water
separators in that the 10 percent boiling point is significantly higher to
account for the low vapor pressure products and the influent temperature is
also higher. The 10 percent boiling point of 232°C (450°F) was chosen based
on a review of data received in response to a refinery survey. The influent
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wastewater temperature of 60°C (140°F) was reported to EPA as a typical
influent wastewater temperature for these facilities. The influent tempera-
ture is higher because of the higher temperatures necessary to process the
heavier hydrocarbons.
Based on these data, EPA calculated a percent volume loss of
12.6 percent, which is equivalent to an emission factor of 420 Kg/million
gallons of wastewater, the same emission factor used by EPA in estimating
emissions from petroleum refinery oil-water separators. Therefore, because
the emission potential of facilities handling low vapor pressure products is
equivalent to other refining facilities, they remain subject to the
applicability requirements of the final rule.
2.2 DEFINITION OF AFFECTED FACILITY AND MODIFICATION/RECONSTRUCTION
2.2.1 Comment: Three commenters felt that the definition of an individual
*
drain system as presented in the proposed rule was inconsistent with the
discussion in the preamble (IV-D-1, IV-D-7, IV-D-8). The commenters stated
that the definition in the proposed rule was much more expansive than the
definition in the preamble and recommended that the definition in the proposed
regulation be revised.
Response: The definition of individual drain systems in the proposed
regulation was intentionally worded to include associated sewer lines and
other junction boxes that carry oily wastewater down to the receiving
treatment unit. The definition in the proposed rule was not intended to
differ from the definition in the preamble. The reason for including
associated sewer lines and other junction boxes down to the treatment unit is
that situations could arise where modified or reconstructed individual drain
systems could be subject to the standards while downstream components would
not be subject to the standards. With such a mixture of regulated and
unregulated components, the effectiveness of the control techniques for
individual drain systems would essentially be zero. The definition for
individual drain systems in the final rule is consistent with the definition
in the proposed regulation.
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2.2.2 Comment: Three commenters recommended that the proposed regulation be
clarified to exclude tanks, drains, and other ancillary equipment that do not
contain oily wastewater and do not generate VOC emissions. One commenter
suggested revising the definitions of air flotation systems and oil-water
separators to make these exemptions clear (IV-D-7). Another commenter
specifically recommended that the requirement for water seals on all
individual drains be amended to clearly provide that only drains that receive
oily wastewater are to be controlled (IV-D-9). A third commenter recommended
that sewers and oil-water separators for once-through cooling water be exempt
from the regulation (IV-D-1).
Response: The Agency did not intend for the NSPS to apply to drains,
tanks, and other ancillary equipment that do not contain or come in contact
with oily wastewater. As stated in the proposed preamble on page 16335, the
source category to be regulated -includes "any component, piece of equipment,
or installation that receives and processes oily water from refinery process
units." The regulation has been further clarified to exempt ancillary
equipment that is physically separate from the wastewater collection system
and does not contain or come in contact with or store oily wastewater, as
suggested by the commenters. For example, the regulation would exempt
storage tanks for non-VOC products such as caustic or coagulant, surge tanks
that receive only stormwater runoff, and non-contact cooling water systems.
2.2.3 Comment: Six commenters recommended that all requirements for sewer
lines be clearly defined as including "above-grade" sewer lines only (IV-D-1,
IV-D-4, IV-D-7, IV-D-8, IV-D-9, IV-D-10). The commenters expressed concern
that the rule, as written, could be misinterpreted to mean that in-ground
sewers would have to be excavated to comply with the regulation.
Response: It was not EPA's intent to require excavation of buried
sewer lines to comply with the proposed standards. As stated on page 16337
of the preamble to the proposed regulation, the purpose of the standards is
to regulate VOC emissions from petroleum refinery wastewater systems at
points where the wastewater is exposed to the atmosphere. Therefore, all
sewer lines that are not buried underground, down to the receiving oil-water
separator, are intended to be subject to the proposed standards. The require-
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ment for sewer lines is that they be covered or enclosed in such a way as to
have no visual gaps or cracks in joints, seals, or other emission interfaces.
These include above-grade sewer lines, and below-grade sewer lines that
consist of open channels or ditches. The definition of sewer line has been
clarified to exclude buried, below-grade sewer lines.
2.2.4 Comment: Seven commenters recommended that the definition of an
aggregate facility as a separate affected facility be deleted from the
proposed regulation (IV-D-1, IV-D-2, IV-D-4, IV-D-5, IV-D-6, IV-D-7, IV-D-9).
The commenters stated that a wastewater treatment system is normally designed
with excess capacity and VOC emissions are more related to surface area than
to oil volume. Further, the commenters stated that there are no data to show
that an increase in the loading of VOC-bearing wastes necessarily results in
an increase in refinery wastewater VOC emissions. Therefore, in the
commenters"view, it is not appropriate to require additional controls as a
result of increased throughput or the addition of one new pump, process
drain, or process unit. The commenters recommended that the standards should
be triggered only when the capacity of the wastewater system is expanded.
Response: The EPA disagrees with the commenters' assertion that an
increase in the loading of VOC-bearing wastes does not result in an increase
in refinery wastewater system VOC emissions. Although the amount of waste-
water surface area exposed to the atmosphere does affect emissions, the
concentration of VOC in the wastewater along with other factors, such as
vapor pressure and temperature, are also factors in determining the emission
potential. As a result, with increases in throughput, the volatile organic
loading also increases when the surface area remains constant. In EPA's
view, VOC emissions can increase with increased loading even if the capacity
of the wastewater system (i.e., surface area) is not expanded.
However, in order to ensure that the application of the standards to
downstream components of the wastewater system is triggered only by
significant changes to the system that result in emission increases, EPA has
amended the definition of affected facility in the final regulation. Under
the proposed rule, any physical or operational change made to an aggregate
facility that resulted in an emissions increase would have constituted a
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modification, thereby making the standards applicable to the changed facility
and all regulated downstream components of the wastewater system. Under the
final rule, the definition of affected facility still includes the "aggregate
facility," but the definition has been amended to clarify what constitutes a
modification that would bring downstream components under the regulation.
In the final regulation, a new paragraph (b) has been added to
Section 60.690 that states that a modification to an aggregate affected
facility occurs when a new individual drain system (consisting of process
drains connected to the first common downstream junction box) is constructed
and tied into an existing wastewater system. Under the final regulation, the
new individual drain system and the components of the system downstream from
the new individual drain system become an aggregate affected facility. This
definition will lead to the control of VOC emissions from new individual
drain systems constructed to serve new process units within the refinery, as
*
well as from those constructed to serve existing process units.
The new paragraph (b) also specifies that the capital expenditure
exemption contained in Section 60.14(e)(2) of the General Provisions does not
apply for the addition of a new individual drain system under this
regulation. Section 60.14(e)(2) states that an increase in the production
rate of an existing facility is not considered a modification if the increase
does not involve a capital expenditure. A capital expenditure is considered
to be any expenditure greater than 7 percent of the total capital cost of the
facility. The intent of the capital expenditure clause is to exclude minor
changes from coverage under the NSPS. The addition of a new individual drain
system is considered to be an significant change to the aggregate facility
because emissions are significantly increased from downstream components of
the wastewater facility. Therefore, under the final regulation, the addition
of a new individual drain system to an existing wastewater facility that
results in increased emissions would constitute a modification of an
aggregate facility, even if no capital expenditure is involved. The
capital expenditure exemption is retained for all other physical or
operational changes to wastewater treatment system components. A small
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physical or operational change within an existing individual drain system
(such as the addition of a pump) that does not constitute a capital
expenditure on the aggregate facility would not be considered a modification
of the aggregate facility. However, such changes may still constitute a
modification to the individual facility (i.e., the individual drain system).
2.2.5 Comment; Four commenters requested that EPA clarify the definitions
of affected facilities for drain systems and the applicability of the modifi-
cation provisions of the standards. As written, two commenters (IV-D-8,
IV-D-10) found it difficult to understand which modified or reconstructed
drain systems are required to comply with the standards. Similarly, a third
commenter (IV-D-11) stated that it is not clear in the regulation what
triggers the broader definition of the aggregate affected facility (i.e.,
drain system, oil-water separator, and air flotation system) versus only the
drain system as the affected facility. This commenter stated that the
addition of one drain or similar minor changes should not result in the
oil-water separator and air flotation system becoming affected facilities.
This commenter suggested clarifying the regulation to explain what situations
would trigger the broader definition of "affected facility" and when the
"offsetting" of small emission increases through decreases elsewhere in the
drain system would be allowed. The fourth commenter (IV-D-6) recommended
that EPA make clear in the final regulation that modifications to refinery
wastewater systems made between proposal and promulgation will not trigger
applicability of the NSPS if those changes do not require increases in the
capacity of the affected wastewater system. This commenter noted that, as
currently written, the proposed regulation carries a risk to refiners that
any operational changes or process unit modifications which increase VOC
emissions in affected facilities, no matter how slightly, may trigger
applicability of the NSPS. This uncertainty will have a serious impact on
the ability of refiners to run their businesses until the uncertainty is
removed. According to this commenter, refineries cannot remain competitive
if routine changes made now carry significant future costs.
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Response: There are two ways in which the definition of affected
facilities includes individual drain systems. The first way is by making
individual drain systems affected facilities. The second way, which overlaps
the first, is by defining an "aggregate" affected facility as an individual
drain system together with all downstream components of the wastewater
system. Under either definition, the equipment standards and work practice
requirements applicable to the individual drain system to control VOC
emissions are the same. The primary distinction between the two is in the
treatment of each under the modification provisions of the standards.
A change in an existing individual drain system which increases
emissions and involves the expenditure of more than 7 percent of the capital
cost of the individual drain system would constitute a modification under the
individual affected facility definition, making the individual drain system
subject to the standards. As discussed in the response to Comment 2.2.4, an
"aggregate facility" would become modified upon the construction of a new
individual drain system consisting of all process drains connected to the
first common downstream junction box, making that system and all downstream
components of the wastewater system subject to the standards, regardless of
the capital cost incurred.
Further, the definition of modification applicable to an "aggregate
facility" has been amended to clarify the type of change to a facility that
would trigger the application of the standards. The addition of a new
individual drain system is a significant change to the aggregate facility
resulting in potentially significant increases in the emissions from the
wastewater system and, therefore, would constitute a modification under the
aggregate definition irrespective of cost. However, if a minor change to the
wastewater system, such as the addition of one drain, was not a capital
expenditure on the aggregate facility, then it would not constitute a
modification under the aggregate facility definition. If a new individual
drain system is installed that results in increased emissions, not only that
individual drain system, but all downstream components included in the
aggregate facility definition would come under the regulation, even if no
capital expenditure is involved. Offsetting of emissions would be allowed
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for all changes to the wastewater system pursuant to Section 60.14 of the
General Provisions. Offsetting of emissions increases through decreases in
emissions within the affected facility would be allowed, provided the owner
or operator of the facility can adequately demonstrate that there will be no
increase in emissions.
The reconstruction provisions remain as stated in Section 60.15 of the
General Provisions. Under these provisions, reconstruction means the replace-
ment of components of an existing facility to such an extent that the fixed
capital cost of the new components exceeds 50 percent of the fixed capital
cost that would be required to construct a comparable entirely new facility.
2.2.6 Comment: Two commenters stated that oil-water separators and air
flotation systems should be subject to the NSPS only if actually modified or
reconstructed (IV-D-1, IV-D-7). Modification of these units is best defined
in reference to design capacity. The commenters recommended that the defini-
tion of aggregate affected facility should be modified to be consistent with
40 CFR Section 60.14(e)(2), which states that "an increase in production rate
of an existing facility, if that increase can be accomplished without a
capital expenditure on that facility" is by itself not considered to be a
modification.
Response: As discussed in the response to Comment 2.1.3, the proposed
standards have been amended to delete air flotation systems from the defini-
tion of affected facility. Oil-water separators continue to be covered by
the standards. Under the final standards, a change in an existing oil-water
separator is considered a modification, making the facility an affected
facility, if the change meets the specifications of 40 CFR Section 60.14.
For existing individual oil-water separators, this includes the provision of
40 CFR Section 60.14(e)(2) requiring an increase in production capacity to be
accomplished through a capital expenditure in order to constitute a modifica-
tion. To this extent, these standards are similar to most other NSPS.
However, as described in the response to Comment 2.2.4, the addition of a new
individual drain system will trigger modification of the "aggregate
facility," which includes the oil-water separator. Consequently, the
addition of a new process unit to a refinery to increase production will
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constitute a modification if the addition of the process unit includes a new
individual drain system. Such an addition would be a major physical change
in the wastewater treatment system resulting in a potentially significant
increase in VOC emissions. This change would constitute a modification of
the aggregate facility regardless of whether or not a capital expenditure is
made.
2.2.7 Comment: One commenter stated that while increased flows resulting
from new process units will change the physical state of the system (i.e.,
flow equalization tanks may have higher levels, and residence times may be
shorter in oil-water separators), it is not clear that the facility (i.e.,
the wastewater treatment system) has been modified (IV-D-7). According to
the commenter, a well-designed wastewater treatment system is capable of
dealing with large short-term variations in loading without any physical
modifications and without any change in operations.
Response: Under the final standards, the addition of a new process
unit to the refinery will not, in itself, constitute a modification. The
addition of a new individual drain system to the wastewater system (regard-
less of whether a capital expenditure is involved) would constitute a
modification of the aggregate facility, as defined in the regulations. (See
response to Comment 2.2.4 for further detail.)
2.2.8 Comment; One commenter maintained that variations in VOC loadings
from changes in the refinery are part of daily routine (IV-D-7). These
variations may be attributed to operational changes such as bringing on line
equipment idled by lack of demand or by maintenance, operating existing
equipment continuously rather than on an intermittent basis, performing
periodic procedures such as tank cleaning. The commenter was concerned that
these normal variations on refinery operations will result in all facilities
being declared modified.
Response; After consideration of the comments received on this issue
in response to the discussion in the preamble to the proposed standards, EPA
has decided that it is not practical to consider routine variations in
wastewater loading as modifications under this NSPS. These variations are
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not changes to individual affected facilities, such as an oil-water separator
or individual drain system, and normally do not involve a capital expenditure.
If, however, physical or operational changes result in increased emissions
and a capital expenditure is made on either the aggregate or individual
facility, that change would constitute a "modification" under the aggregate
or individual affected facility definitions, as applicable. As discussed in
the response to Comment 2.2.4, the addition of a new individual drain system
that results in increased emissions would also constitute a modification of
the aggregate facility, regardless of whether a capital expenditure is
involved.
2.2.9 Comment: One commenter noted that defining the term "modification" as
any. increase in loading rate appears to conflict with the Clean Air Act's
definition of the term, and is thus beyond the Agency's authority (IV-D-7).
The commenter stated that it is clear in the Clean Air Act that a modification
must involve either a physical change in a facility or a change in the method
of operation. According to the commenter, an increased loading rate is not
the same as a change in a method of operation.
Response: After consideration of the issue of increased loading
raised in the proposal preamble, and after review of the comments received on
this issue, EPA has decided that it is not practical to consider an increase
in the loading rate alone as a modification under this NSPS. A modified
facility under these final standards is either an existing individual drain
system or oil-water separator or an aggregate facility that has undergone a
physical or operational change involving a capital expenditure, or an
aggregate facility to which a new individual drain system has been added.
2.3 SELECTION OF CONTROL TECHNOLOGY
2.3.1 Comment; One commenter recommended that process drain seal and cover
system requirements be relaxed in service areas where corrosive materials in
the drain system would cause rapid degradation of the equipment (IV-D-8).
Response: The presence of corrosive material in the drain system is
not sufficient reason to relax the requirements for process drain seals and
covers. In situations where corrosive materials enter the drain systems it
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may be necessary to construct the required process drain controls and covers
out of the same material that was used to construct the drains themselves.
The drains must also be made of material that is resistant to the corrosive
action with which the commenter is concerned. Therefore, it is not unreason-
able that in these situations the drain seal devices and covers also be made
of this same material.
2.3.2 Comment: One commenter disagreed with EPA's statement that it is
common practice to use water seals in drains (IV-D-5). The commenter said
that water seals are commonly used in sewer lines to prevent vapors from
flowing upstream from junction boxes, but are generally not used for
individual drains.
Response: Several types of individual drains are used in petroleum
refineries. These include a straight vent pipe with no liquid seal, a drain
with a p-leg trap that provides a liquid seal in the individual drain, a
drain with an external seal pot which also has a liquid seal, and a completely
closed drain system. The primary reason for installing drains with liquid
seals is for safety. Liquid seals prevent combustible vapors from passing
through the sewer system and escaping near potential ignition sources.
Because of this, drain seals are commonly used as a fire prevention measure.
A liquid seal also can be used as a vapor control device because molecular
diffusion of VOC to the atmosphere is significantly reduced and convection
effects are eliminated. During the development of the proposed standards,
several refineries were identified that employed some type of liquid seal in
the drain pipe. Therefore, EPA believes this type of control for drains to
be adequately demonstrated.
2.3.3 Comment: Three commenters recommended that the tight seal requirement
for junction box covers be deleted given that the junction box cover is
vented (IV-D-2, IV-D-4, IV-D-5). The commenters maintained that the
additional reduction in evaporation rate does not warrant such a requirement.
Response: As described in the Volume I BID, the emission rate of
0.032 kg/hour (0.07 Ib/hr) attributed to vented junction boxes was based on
the assumption that junction boxes, although vented, were also equipped with
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a sealed cover. To address the question the commenters have raised regarding
the reduction in emission rate attributable to sealing the cover, the Agency
evaluated data from a study conducted by the Chicago Bridge and Iron Company.
In this study, emissions were measured from drums filled with hexane. The
data showed a 23 percent reduction in emissions when a cover on the drum was
gasketed and clamped, as opposed to an ungasketed cover. This emission
reduction is believed to be comparable to the emission reduction achieved
when a junction box cover is tightly sealed because the conditions under
which the test was performed are believed to be comparable to the conditions
within a junction box. As a result, the additional emission reduction due to
a gasketed, as opposed to an ungasketed, cover on a vented junction box is
estimated to be 0.06 Mg/year (0.07 tons/yr). With an estimated 1,200
junction boxes expected to become affected by the NSPS after 5 years, this
amounts to a VOC emission reduction of 72 Mg/year (80 tons/yr) nationwide.
The cost of gasketing a junction box cover was also evaluated and was found
to be approximately $80/Mg ($73/ton) per junction box. This cost is
considered reasonable.
2.3.4 Comment: Two commenters suggested that water seals be provided at the
junction box or sump rather than at each individual drain (IV-D-8, IV-D-9).
The commenters maintained that this would provide equivalent emissions
control and better fire protection. According to the commenters, seals
located at the junction box would be less likely to evaporate or freeze
during cold weather.
Response: The basic principle used to control VOC emissions from
drains and junction boxes is to limit the effects of diffusion and convection
on the volatilization of VOC from the wastewater. This can be accomplished
by creating a barrier between the atmosphere and the wastewater. For drains,
the control technique required by the NSPS is to place a water seal in the
drain to form a barrier between the wastewater and the atmosphere. The
control efficiency of water-sealed drains has been estimated at proposal to
be 50 percent or greater. This would reduce the AP-42 emission factor of
0.032 kg/hr (0.07 Ib/hr) for refinery drains to approximately 0.016 kg/hr
(0.035 Ib/hr). For junction boxes, the mechanism for VOC emissions (i.e.,
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effects of diffusion and convection) are the same as for open drains. In
addition, since junction box vent pipes are in the same size range as drains,
the VOC emission rate from junction box vents is estimated to be the same as
open drains, or 0.032 kg/hr (0.07 Ib/hr). Therefore, a water seal on a
junction box will also achieve emission reductions of 50 percent or greater.
The commenters are correct, then, in stating that a water seal in a junction
box provides equivalent emission control as a water seal in a drain.
However, the overall emission reduction is not equivalent because there are
many more drains than junction boxes in the refinery wastewater system. For
example, it is estimated that for every junction box, there are six drains.
Placing a water seal at each of the six drains affords greater overall
emission reduction than placing a water seal at the junction box only.
As for fire protection, water seals are often used in refineries to
prevent combustible vapors from passing through the sewer system and escaping
near potential ignition sources. However, as a result of comments received
at the August 1984 meeting of the National Air Pollution Control Techniques
Advisory Committee (NAPCTAC), EPA further evaluated the potential safety
hazard associated with installing water seals in junction boxes. It was
determined that a water-sealed junction box could pressurize the drain
system, thereby creating a potentially explosive condition. Therefore, EPA
did not require water seals for junction boxes in the proposed regulation.
This decision was endorsed by one commenter (IV-D-10). The EPA has evaluated
an alternative control for junction boxes and, as described further in the
response to Comment 2.3.5, specific vent sizes for vents on junction box
covers are now required in the final rule.
Finally, in response to the comment that a water seal on a junction box
would be less likely to evaporate or freeze, the Agency believes that water
seals on individual drains are no more prone to evaporation or freezing than
water seals at a junction box. The water seal would be essentially the same
no matter where it was placed, and both locations are subject to the same
atmospheric conditions and receive the same wastewater. Therefore, the
requirement for installing water seals on individual drains remains the same
as proposed.
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2.3.5 Comment: One commenter (IV-D-2) stated that the technical basis for
installing sewer seals for emission reduction is flawed. As described by the
commenter, vapors trapped by the sewer drain seals will be emitted via the
junction box to prevent the buildup of potentially explosive vapors. The
commenter recommended that since sewer seals will not materially reduce
emissions, this requirement should be removed from the final standards.
Response: As discussed in the response to the previous comment, the
overall emission reductions from process drain seals are greater than from
controls on junction boxes because of the greater number of process drains
within a process unit. The greater number of drains exposes more surface
area and thereby provides greater opportunity for volatilization.
Based on the assumption that molecular diffusion and convection are the
primary factors affecting VOC emissions from drains and junction boxes, and
in light of the potential safety problems of water seals on junction boxes,
vent pipes are allowed to provide safe and effective emissions control from
junction boxes. Because the rate of molecular diffusion and convection are
influenced by the length of the vent pipe and design of the vent pipe opening,
EPA evaluated the effects of different size vent pipes. Since VOC diffusion
is inversely proportional to the diffusion path length, the greater the vent
pipe length, the lower the rate at which molecular diffusion can transport
VOC into the air. Also, the diameter of the vent pipe opening affects the
emissions due to convection. Therefore, to restrict emissions from junction
box vents due to the effects of molecular diffusion and convection, EPA has
determined that a vent pipe having a maximum diameter of 10.2 cm (4 inches)
and a minimum length of 90 cm (3 feet) will be required. Thus, a vent pipe
is allowed to avoid safety problems, but a maximum diameter and minimum
length are specified in order to restrict emissions due to the effects of
molecular diffusion and convection.
2.3.6 Comment; One commenter stated that the requirement that API separators
have fixed covers and a vapor control vent system as a primary control device
is not technically sound (IV-D-2). The commenter explained that it would be
very difficult to achieve gas-tight seals on all the openings in the cover
and placing a sweep gas under the covers would create a dangerous situation.
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The commenter recommended that fixed roofs be the alternate control technology
and the floating cover control scheme be the preferred method. A second
commenter also endorsed floating cover control as the preferred method
(IV-D-10).
Response: The Agency has determined that fixed roofs with vapor
control vent systems are the best demonstrated technology (BDT) for oil-water
separators. Section 111 of the Clean Air Act requires that standards of
performance be based on the best system of continuous emission reduction that
has been adequately demonstrated, considering costs, nonair quality health
and environmental impacts and energy requirements. Floating roofs were not
chosen as the preferred control because floating covers cannot be used on all
types of separators; for example, corrugated plate interceptors (CPI).
However, EPA has made this requirement flexible by allowing floating roofs as
an alternative technology to a fixed roof with a vapor control device.
Inclusion of this alternative was endorsed by another commenter (IV-D-10).
The EPA disagrees that purging the vapor space to a control device would
be hazardous. Inert gases such as nitrogen, natural gas, or fuel gas have
all been used for this purpose. During development of the standards, a
refinery was visited that was using natural gas for this purpose. In
addition, two other commenters (see Comment 2.4.3) maintained that not using
a sweep gas would be hazardous. As a result, as described in the response to
Comment 2.4.3, EPA has reevaluated the cost of purging the vapor space of a
fixed roof with fuel gas and found this cost to be reasonable.
2.3.7 Comment: Two commenters felt that venting emissions from an oil-water
separator to an existing vapor control device may result in safety concerns
(IV-D-5, IV-D-11). First, a flame would be present to ignite the potential
explosive vapors under the roof. Secondly, emergency flare lines are subject
to rapid pressurizations, which could cause a hazardous condition in the
separator. Furthermore, according to the commenters, this connector would
result in the introduction of air into hydrocarbon transfer lines, a condition
that is scrupulously avoided in most hydrocarbon processing facilities.
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Response: The use of an existing flare to combust vapors from an
oil-water separator would not create safety problems if precautions are taken
in the design and operation of the system. First, the flare should not be
located in such close proximity to the oil-water separator that ignition of
vapors is a serious threat to safety. In the analysis conducted for this
standard, it was assumed that the flare would be located as far as 60 meters
(200 feet) from the oil-water separator. Second, controls such as a fluid
seal or flame arrestor are available that would prevent flashback. These
controls were considered in EPA's previous cost analysis. Finally, the use
of a purge gas, such as nitrogen, plant fuel gas, or natural gas, and/or the
careful control of the total volumetric flow to the flare would prevent
flashback in the flare stack caused by low off-gas flow. As described in the
response to Comment 2.4.3, EPA has revised the costs associated with venting
to a control device to include the cost of a fuel gas purge system. It was
found that even with this additional cost, this requirement is cost
effective.
The rapid pressure buildup cited by the commenters is typically addressed
through the design of the flare system. Contacts with flare vendors indicate
that a flare handling an oxygen-laden vent stream should be initially designed
to handle the anticipated potential pressure buildup.
2.3.8 Comment: One commenter agreed with EPA that a cover is an effective
control device for an API separator (IV-D-11). Beyond the use of a cover,
however, the commenter felt there has been no vapor control system demon-
strated to be safe and effective for API separators because there were none
discussed in the Volume I BID. Consequently, the commenter recommended that
control of VOC vapors from API separators through vapor recovery or combustion
systems should not be required.
Response: During the development of the NSPS, EPA personnel visited
several refineries and found that VOC destruction and recovery systems were
in use for controlling the vented vapor space from oil-water separators.
Because these technologies are demonstrated for control of VOC emissions,
these standards are based on their use. These control systems were described
in Chapter 4 of the Volume I BID and include incinerators, flares, process
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heaters, and carbon absorbers. Another alternative control available for API
separators is the use of a floating roof that eliminates the vapor space
above the liquid, greatly reducing the potential for volatilization of VOC
from the oil layer.
2.3.9 Comment: One commenter said that to use a flare system as a control
device, a separator will have to be operated under positive pressure
(IV-D-7). This is necessary to prevent leakage of outside air into the flare
system and cause a safety hazard. The commenter felt that this increased
pressure could result in an increase in VOC emissions.
Response; A refinery visited during the development of the standards
vented an oil-water separator equipped with a fixed roof to a control device
by purging the vapor space with natural gas at a positive pressure in the
range of 1 to 2 cm (0.4 to 0.8 inches) of water. This pressure was adequate
to maintain a discharge flow of 75 acfm at 15 psig. The EPA disagrees that
this slight positive pressure would cause an increase in VOC emissions. As
described in the response to Comment 2.3.10, the control efficiency of a
tightly sealed fixed roof is 99.7 percent. The effect of the increased
positive pressure would not increase VOC emissions to the atmosphere but may
slightly increase the flowrate to the control device.
2.3.10 Comment: One commenter questioned the requirement of venting to a
control device for fixed roof-equipped oil-water separators (IV-D-7). The
commenter noted there was no basis given in the proposal preamble that
venting to a control device would increase the capture efficiency of a fixed
roof from 85 to 99 percent.
Response; The 85 percent capture efficiency to which the commenter
refers is the capture efficiency that has been estimated for fixed roofs not
vented to a control device. The NSPS requires that fixed roofs vented to a
control device be operated and maintained in a gas-tight condition (i.e., no
detectable emissions as indicated by an instrument reading of less than
500 ppm above background levels). The capture efficiency of a gas-tight
fixed roof has been estimated to be 99 percent. This estimate is based on
AP-42 emission factors for deck fittings on volatile organic storage tank
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access hatches. Gasketing and sealing an access hatch was assumed to be
comparable to the emission reduction achieved by gasketing and sealing a
fixed roof. Deck fitting loss for the access hatch was calculated in terms
of Ib/linear foot/year and applied to a model tank. The emission reduction
achieved with a gasketed fixed roof over the tank was calculated. The
calculations showed that an unbolted, gasketed cover on the model tank
reduced emissions by 99.7 percent over an uncovered tank.
The actual overall control efficiency for a fixed roof vented to a
control device depends on the efficiency of the control device. For flares,
the efficiency is estimated to be 98 percent. Therefore, the overall
efficiency of a fixed roof with vapors vented to a control device is
97 percent (0.99 x 0.98 = 0.97).
2.3.11 Comment: Four commenters stated that placing a fixed roof on
oil-water separators and similar devices creates a serious safety hazard
because the potential exists for a buildup of explosive vapors under the
cover (IV-D-3, IV-D-7, IV-D-8, IV-D-11). Furthermore, the commenters main-
tained that covers may actually have a negative impact on the environment if
an explosion occurs that has the potential to shut down the treatment
facility, resulting in untreated wastewater being discharged.
Response: The Agency believes that a fixed roof is a demonstrated
technology for oil-water separators and similar tanks or basins, given that
an estimated 85 percent of nationwide crude throughput is processed at
refineries that are located in States requiring covered separators. Also,
some oil-water separators, such as the CPI design are supplied with fixed
covers. Therefore, EPA has concluded that there are no safety hazards
associated with fixed roofs beyond those normally experienced by industry.
For DAF's, however, because of the physical design characteristics of
the system, and the use of air or gas used for flotation, a greater potential
for the buildup of explosive vapors under fixed roofs exists for these units.
As discussed in the response to Comment 2.1.3, because of safety and cost
considerations the fixed roof requirement for DAF's has been deleted from the
final rule.
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2.3.12 Comment; One commenter recommended that criteria for covering only
part of an oil-water separator, such as the separator forebay where most slop
oil can be recovered, be included in the proposed regulation (IV-D-8).
Another commenter suggested changing the wording "separator tank" to
"separator zone" in the proposed standard since that is the proper
designation for that portion of the oil-water separator that was evaluated by
the Agency (IV-D-9).
Response: Covering only part of an oil-water separator such as the
forebay is not an acceptable control strategy for this regulation. Although
some oil may be removed in the forebay, not all oil-water separator designs
have a skimming device in the forebay. If the oil is not skimmed, then the
effectiveness of a fixed roof on the forebay is negated. Also, the retention
time required to separate the oil varies with the inlet oil concentration,
which can be extremely variable. Therefore, there is a large emission
potential from the entire separator tank, not just the forebay. In addition,
EPA has determined that covering the entire oil-water separator tank is cost
effective. The incremental cost effectiveness for oil-water separators
subject to the standards is about $810/Mg ($735/ton) of VOC controlled by a
fixed roof vented to a control device. As discussed in the response to
Comment 2.4.3, if the cost of a fuel gas purge system is added, this cost
increases slightly to $850/Mg ($770/ton).
Regarding the request of one commenter (IV-D-9) that the term "separator
tank" be changed to "separator zone," the intent of the regulation is that
the entire separator tank be covered for the reasons stated above.
2.3.13 Comment; One commenter was concerned that EPA used a control
efficiency of 85 percent for floating roofs and this efficiency is unrealis-
tically low (IV-D-12). The commenter believes that with one vapor-mounted
primary seal a floating roof can achieve at least a 90 percent control
efficiency.
Response; The commenter appears to have misunderstood the control
efficiency used by EPA in assessing floating roof control for oil-water
separators. As described on page 16338 of the proposal preamble, EPA has
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determined that a floating roof with a liquid-mounted primary seal and a
secondary seal can reduce VOC emissions by about 95 percent. The precise
emission reduction capability of a well-designed floating roof depends on the
seal system and the effectiveness of the refinery's maintenance and repair
program.
2.3.14 Comment: One commenter recommended that if a battery-limit oil-water
separator is installed at a new, modified, or reconstructed process unit, no
controls on the downstream wastewater treatment system should be required
(IV-D-10). According to the commenter, battery-limit oil-water separators
will eliminate any significant increase in hydrocarbon emissions due to the
new operation.
Response: The commenter is referring to an oil-water separator, also
known as a unit separator, that is dedicated for use at one process unit.
Under the final rule, battery-limit oil-water separators are included in the
definition of oil-water separator and as such are subject to the applicable
control requirements. Installation of a battery-limit oil-water separator
will not cause modification of downstream wastewater treatment components
unless, as explained in the response to Comment 2.2.4, an individual drain
system is also installed or a capital expenditure is made on the aggregate
facility.
2.3.15 Comment: One commenter, noting that some oil-water separators
equipped with external floating roofs are installed below-grade, recommended
that the regulation be revised to allow an opening in the floating roof for
stormwater drainage and removal (IV-D-4). According to the commenter, an
opening in the roof is needed to allow stormwater on the floating roof to
enter the separator.
Response: The EPA agrees with this comment and has revised the final
standards to allow stormwater removal through openings in external floating
roofs of oil-water separators. The final standards require that each emer-
gency roof drain be provided with either a flexible fabric sleeve seal or a
slotted membrane fabric cover that covers at least 90 percent of the area of
the opening.
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2.3.16 Comment: With regard to floating covers on oil-water separators, one
commenter thought it was unrealistic to require a liquid-mounted primary seal
with an allowable gap width of 3.8 cm (1.5 inches) and a secondary seal with
an allowable gap width of 1.3 cm (0.5 inches) (IV-D-12). The commenter felt
it would be more reasonable and cost effective to reduce the liquid-mounted
primary seal gap to 0.63 cm (0.25 inches) and eliminate the requirement for
the secondary seal. Two other commenters recommended that floating covers
with two vapor-mounted seals should be allowed because vapor-mounted seals
are not immersed in oily wastewater, which can weaken the seal structure
(IV-D-7, IV-D-9).
Response: The EPA has not allowed gap widths of 3.8 cm (1.5 inches)
and 1.3 cm (0.5 inches) for liquid-mounted primary and rim-mounted secondary
seals, respectively. Rather, the requirement for liquid-mounted primary
seals is that the total gap area between the primary seal and the separator
wall not exceed 67 cm2/m (3.2 in2/ft) of separator wall perimeter. The gap
width between the primary seal and separator wall shall not exceed 3.8 cm
(1.5 inches) at any point. For secondary seals, the total gap area between
the secondary seal and the separator wall shall not exceed 6.7 cm2/m
(0.32 in /ft) of separator wall perimeter. The gap width between the
secondary seal and the separator wall shall not exceed 1.3 cm (0.5 inches) at
any point. However, as a result of this comment, EPA analyzed three different
control scenarios. These were: (1) a liquid-mounted primary seal alone,
(2) a vapor-mounted primary seal with no gaps in a secondary seal, and (3) a
liquid-mounted primary seal with a secondary seal having the same gap widths
as in the proposed standards. These control scenarios were analyzed using
test data that were gathered during development of the Volatile Organic
Liquid Storage Vessels NSPS (40 CFR Part 60, Subpart Kb).
These data showed that regardless of the type of primary seal, the
addition of a secondary seal system always resulted in lower measured
emissions. In light of this finding and because a liquid-mounted primary
seal with a secondary seal for floating roofs on oil-water separators has
been determined to be cost effective, EPA has retained the requirement for a
secondary seal.
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Next, EPA evaluated test data for both liquid-mounted and vapor-mounted
primary seals with secondary seals. The liquid-mounted seal system had
essentially the same gap widths as were required in the proposed standards.
The vapor-mounted seal system, by contrast, had no gaps between the storage
tank wall and either the vapor-mounted primary seal or the secondary seal.
The emission test results showed that even with the above-specified gap
widths, the liquid-mounted primary seal with a secondary seal had measured
emissions that were lower by a factor of 3 compared to the tight vapor-
mounted primary seal with a secondary seal. As a result of this analysis,
the seal and gap width requirements for floating roofs remain unchanged in
the final rule.
With regard to the comment that vapor-mounted seals are beneficial
because they are not immersed in the oil and water that can weaken their
structure, according to API Publication 2517: Evaporation Loss from FxtPrnal
Floating Roof Tanks, this problem previously associated with liquid-mounted
seals has been reduced. This is due to recent advances in synthetic com-
pounding that have resulted in materials with increased compatibility with
hydrocarbon products.
2.3.17 Comment: One commenter stated that the requirement of using gaskets
and latches to make access doors on lAF's gas-tight is too restrictive
(IV-D-5).
Response; In response to other comments on air flotation systems as
explained in the response to Comment 2.1.3, EPA has concluded that air
flotation systems should not be subject to the final rule. Therefore, the
commenter's concern has been addressed.
2.3.18 Comment; Four commenters pointed out that covers on air flotation
systems raise significant safety concerns (IV-D-1, IV-D-7, IV-D-9, IV-D-10).
An unvented fixed cover may present an explosion and fire hazard in some
types of units due to the buildup of explosive vapors inside the cover.
According to one of the commenters (IV-D-9), either a nitrogen purge system
or a large vapor space is required to minimize the explosive atmosphere under
the cover. This sweeping of air over the unit's flotation zone surface would
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offset the control efficiency claimed by EPA in justifying covers for DAF's.
Another of the commenters (IV-D-10) noted that the only OAF system with a
roof reported on in detail in the BID included a ventilation system to dilute
the vapor space. This commenter said that many refiners would not consider
Regulatory Alternative II to be a realistic alternative because the composi-
tion of the confined vapor space is uncontrolled. The EPA was urged by each
of these commenters to remove the requirement to cover DAF tanks.
Response: The Agency agrees that this is a legitimate concern. See
response to Comment 2.1.3.
2.3.19 Comment: Installation of covers on air flotation systems will reduce
the ability of the operator to visually inspect and monitor the system,
according to four commenters (IV-D-1, IV-D-5, IV-D-6, IV-D-7). This will
reduce the treatment efficiency, and will result in only minimal reduction of
emissions. Operators will be hindered in their ability to notice and
promptly repair minor maintenance problems. These commenters believe that,
if undetected, these problem could lead to major failure and might require a
complete system shutdown to facilitate repairs.
Response: This does not appear to be a significant problem. Access
hatches and peep holes allow the operator to monitor the process and make
repairs. However, for reasons other than those stated by the commenters, EPA
has decided to exempt air flotation systems from the standards as explained
in the response to Comment 2.1.3.
2.3.20 Comment: Three commenters made comments related to the reduction of
VOC emissions using VOC fugitive emission control programs and source control
programs (IV-D-3, IV-D-6, IV-D-8). One commenter said that existing VOC
emission control programs in conjunction with sealed process drains and unit
oil-water separators are more cost effective than retrofitting existing
wastewater treatment systems with the proposed controls (IV-D-6). A second
commenter noted that control of oil-water separators is required regardless
of the extent of wastewater segregation and reuse upstream (IV-D-8). This
commenter maintained that the proposed regulation did not make adequate
allowance for downstream controls when extensive source control is provided.
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A third commenter stated that the regulation forces the use of add-on control
equipment, preventing the possible use of more effective control such as
elimination (IV-D-3). This commenter suggested a better approach would allow
flexibility to control the problem at its source and that EPA should consider
setting a de minimus capacity level below which controls are not needed.
Response; A source control program approach to controlling VOC
emissions was considered during development of the proposed standards. This
approach relies on a system of identifying problematic wastewater streams and
upset conditions, coupled with a series of housekeeping measures tailored to
problems arising in each process unit. This alternative, however, was not
included for several reasons. First, alternative source control programs,
while possibly reducing VOC emissions in some instances, are not based on
control techniques that are demonstrated. The EPA cannot establish standards
based on control techniques that are not demonstrated. Second, the control
techniques used in a source control program may not reduce emissions con-
tinuously, and such a program may be difficult to define or enforce. However,
as was included in the proposed rule, an alternative emission limitation
provision has been included in the final rule. Under this provision, an
individual refiner may apply to the Administrator for approval of a source
control program tailored to the circumstances at an individual refinery. The
alternative control techniques must be shown to be equivalent to the require-
ments of the NSPS in terms of emission reduction. Contrary to the commenter's
statement (IV-D-8), the NSPS does not prevent the use of source control
programs, nor does it discourage the use of such programs. Many refiners
employ such programs to minimize hydrocarbon emissions for safety reasons.
Such programs would still be in use even in the absence of an NSPS.
The EPA did consider the possibility of wastewater segregation and reuse
upstream of the oil-water separator. In the proposed standards, drain
systems that are designed and used as separate systems for the sole purpose
of collecting stormwater runoff were exempted from the standards. The final
rule also contains an exemption for cooling water systems using water that
does not come into contact with oil or oily water.
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Finally, with regard to setting a de minimis emissions level below which
controls are not needed, EPA previously determined that such a format for the
standards is not feasible. For most refinery fugitive emission sources, it
is not feasible to prescribe performance standards because it is impractical
or economically infeasible to measure emissions from these sources. For
individual drain systems, determining compliance with a performance standard
would be prohibitively expensive. In the case of oil-water separators, the
principal limitation with a standard of performance concerns the difficulty
in measuring emission levels. For these reasons, for petroleum refinery
wastewater systems, a combination of equipment, work practice, design, and
operational standards was selected for the format of the standards.
The final standards do include de minimis capacity levels below which
the standards do not apply. Specifically, oil-water separators with a
maximum design capacity to treat less than 16 liters per second (250 gpm) of
refinery wastewater are not required by Section 60.692-3 to be equipped and
operated with a closed vent system and control device. De minimis cutoffs
based on influent oil concentration or vapor pressure were also considered,
but were not included in either the proposed or final standards because of
the variability in influent oil concentration and the poor correlation
between vapor pressure and VOC emissions.
2.3.21 Comment: One commenter said that although the proposed standards
allow alternative means of emission limitation to be used to achieve
equivalent emission reductions, it may be expensive and difficult to verify
equivalent emission reductions (IV-D-8).
Response: Section lll(h)(3) of the Clean Air Act permits the use of
alternative means of emission limitation if it will achieve a reduction in
emissions of any air pollutant at least equivalent to the reduction in
emissions achieved by the applicable standard. The purpose of allowing an
alternative means of emission limitation is to encourage the use of innovative
technologies or systems of continuous emission reduction. The EPA recognizes
that for the petroleum refinery wastewater system source category, verifying
an alternative means of emission limitation may be difficult, but owners and
operators are at least allowed this alternative if they so choose.
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2.4 COST/COST EFFECTIVENESS
2.4.1 Comment; Three commenters stated that neither the extra cost nor the
effort of providing water seals in drains and covers with leak detection
monitoring on junction boxes is unwarranted (IV-D-2, IV-D-4, IV-D-5). The
commenters maintain that covers on junction boxes and visual inspection will
accomplish the goals of the NSPS.
Response: The EPA disagrees that requiring water seals in drains is
unwarranted. As a first step toward determining which control techniques
should be selected as the basis of the proposed standards for individual
drain systems, EPA analyzed the annualized cost and cost effectiveness of
controlling VOC emissions and the resultant VOC reduction for three alterna-
tive control techniques. Also considered were nonair quality health and
environmental, energy, and economic impacts associated with alternative
control techniques. For individual drain systems, it was found that water
seals in drains were a demonstrated technology that could reduce VOC emissions
from drains by an estimated 50 percent. In addition, this control was found
to be cost effective [$300/Mg ($270/ton) for a typical size new facility].
Therefore, water seals were chosen as the best demonstrated technology for
drains and remain the selected control alternative in the final rule.
The Agency does agree, however, that visual inspection, rather than leak
detection monitoring for junction box covers, is appropriate. Therefore, as
discussed in the response to Comment 2.6.7, the requirement for leak
detection monitoring for junction box covers has been deleted from the final
rule.
2.4.2 Comment: One commenter stated that the cost to retrofit the proposed
drain system controls on older process units would be prohibitive (IV-D-8).
This commenter recommended that drain systems in older process units that are
modified or reconstructed should be exempted from the regulation by the same
logic that was used by EPA to exempt facilities with catch basins.
Response; An analysis of the cost of retrofitting existing process
drain systems with p-trap drains was carried out by EPA. The analysis is
documented in Chapter 8 of the Volume I BID. The additional cost required to
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retrofit such a drain compared to installing a new p-trap drain is the cost
for labor and materials for removing the existing drain. Costs used by EPA
assumed a 3-man crew using a backhoe with a pneumatic jackhammer to remove
concrete around the drain. It was estimated that each drain would take about
one-half hour to excavate and remove. Based on these assumptions, EPA
estimated that the additional cost to retrofit existing drains with the
equipment specified in this regulation is $486 per drain. This results in a
cost-effectiveness estimate of about $850/Mg ($770/ton) VOC controlled for
retrofitted drains, compared to a cost effectiveness of about $300/Mg
($270/ton) VOC controlled for new drains. This cost-effectiveness level is
considerably less than for systems with catch basins [estimated to be about
$2,100 Mg ($l,900/ton) VOC controlled] and is considered reasonable in light
of the VOC emissions potential of modified or reconstructed individual drain
systems at refineries.
2.4.3 Comment; Two commenters stated that due to the potential for an
explosive buildup of vapor under fixed roof covers on oil-water separators, a
purging system would be necessary (IV-D-3, IV-D-7). The commenters said the
costs for purging and controlling the purge stream are not included in the
EPA's cost estimates.
Response: As explained in the response to Comment 2.3.6, EPA believes
that a fixed roof is a demonstrated technology for oil-water separators.
Because of the widespread use of fixed roofs, the Agency does not believe
there are safety hazards associated with fixed roofs beyond those normally
experienced by industry. Therefore, the requirement for fixed roof control
on oil-water separators with a maximum design capacity to treat 16 liters per
second (250 gpm) or less remains unchanged in the final rule. For oil-water
separators with a design capacity to treat more than 16 liters per second
(250 gpm), a fixed roof with the vapor space vented to a control device, or
floating roof control is required.
The EPA has reevaluated the cost of purging the vapor space under a
fixed roof to a control device. The cost of a fuel gas purge system was
calculated for a typical size oil-water separator [47.3 liters per second
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(750 gpm)]. The incremental cost effectiveness was found to be $850/Mg
($770/ton), an increase of about $40/Mg ($36/ton) over the cost of venting
the vapor space to a control device without purging. These costs are
considered reasonable.
2.4.4 Comment: Three commenters objected that EPA assumed that an oil-water
separator can be readily vented to an existing vapor control device (IV-D-1,
IV-D-5, IV-D-7). However, wastewater treatment facilities are often remote
from areas where process units or flares are located, and extensive piping
may be required to make a connection. The commenters maintain that the EPA's
cost analysis should be based on the purchase and operation of a dedicated
control device. According to the commenters, the true incremental cost of
this requirement is unreasonably high, and fixed covers provide sufficient
control for all separators.
Response: The use of a dedicated control device for the control of
emissions from the vent of an oil-water separator was evaluated during the
development of this regulation and was found to be too costly under most
applications. However, the use of a dedicated flare for the control of these
emissions is not necessary in order to attain compliance with the final
standards. Two other options are available. The first is to vent the
oil-water separator to an existing flare. This option was examined in the
development of this regulation, with 60 meters (200 feet) of piping for
routing the vent gases to an existing flare being included in the cost
analysis. This proved to be a reasonable alternative. The other option
available to refinery operators is to use another method of control. This
could include either a floating roof over the oil-water separator, or use of
another existing control device such as an incinerator, carbon adsorber,
boiler, or process heater. The cost of these alternative controls is also
considered reasonable.
2.4.5 Comment; One commenter felt that the regulation as proposed will
impose a forced retrofit of control equipment on all existing refineries in a
very short period (IV-D-2). The commenter maintained that the standards will
exact excessive cost for insufficient environmental gain.
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Response: The changes to the proposed regulation dealing with the
modification of an aggregate facility will ensure that only those modifica-
tions to a refinery wastewater system which result in significant increases
in emissions will bring an existing wastewater system under the final
standards. As explained previously in the response to Comment 2.2.4, a
modification occurs when a new individual drain system is constructed or when
additions to either the individual or aggregate facility constitutes a
capital expenditure. Minor changes in a wastewater system would not
constitute modifications. Consequently, it is not anticipated that all
existing refineries will be brought under the standards, and that those which
are will have undergone significant modifications resulting in increases in
emissions. Consequently, the costs of the standards, in terms of requiring
facilities to install equipment and operate control technologies, will be
focused on those cases where the potential for environmental benefit is
greatest.
2.4.6 Comment; One commenter stated that the reduction in evaporation rates
that may result from completely sealing the cover on an oil-water separator
would be insignificant and not commensurate with the cost of installing and
monitoring a seal system (IV-D-4). A second commenter stated that EPA had
overestimated the benefits and underestimated the cost of venting a fixed
roof on an oil-water separator to a control device (IV-D-7). It was suggested
that this requirement be deleted.
Response; The requirement that a fixed roof on an oil-water separator
must be completely sealed and the seal system monitored for no detectable
emissions is applicable to oil-water separators having a design capacity to
treat greater than 16 liters per second (250 gpm) of refinery wastewater.
Separators meeting this requirement and having a fixed roof must also vent
the vapor space to a control device. As an alternative to a fixed roof with
vapors vented to a control device, oil-water separators may be equipped with
a floating roof.
The reason for requiring that a fixed roof vented to a control device be
completely sealed and monitored for no detectable emissions is based on an
analysis of the control efficiency that can be achieved by a fixed roof. The
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EPA has shown that a gas-tight fixed roof on a tank can achieve a capture
efficiency of 99 percent compared to an uncovered tank (see response to
Comment 2.3.10). When vented to a 95 percent efficient control device, the
overall effectiveness of venting a gas-tight fixed roof to a control device
is 94 percent. This represents a substantial incremental emissions reduction
in VOC emissions when compared to the 85 percent efficiency attributed to a
fixed roof that is not gas-tight.
In addition to being technically feasible, this technology is also cost
effective. As presented in the preamble to the proposed standards, the
incremental cost effectiveness of having a gas-tight fixed roof vented to a
control device compared to having a fixed roof alone is $810/Mg ($735/ton)
for a typical size facility. As discussed in the response to Comment 2.4.3,
if the cost of a fuel gas purge system is added, this incremental cost
increases slightly to $850/Mg ($770/ton). These costs are considered
reasonable.
2.4.7 Comment: Several commenters stated that the cost effectiveness of air
flotation system controls is marginal and significantly higher than for other
elements in the proposed NSPS (IV-D-1, IV-D-5, IV-D-7, IV-D-9). Two of the
commenters (IV-D-7, IV-D-9) observed that the cost effectiveness of such
controls will be even worse in the future as the result of other proposed
regulations and industry's increasing efforts to minimize waste production.
In the view of these four commenters, it is questionable whether the low
level of emissions from these facilities warrant control measures. Two of
the commenters (IV-D-1, IV-D-5) noted that EPA's own estimates show that
fixed roofs on air flotation systems will control less than 180 Mg/yr
(200 tons/yr) of VOC nationwide at the end of 5 years.
Response: As stated in Comment Response 2.1.3, the cost effectiveness
of a fixed roof with vapors vented to a control device on DAF systems is
unreasonably high. This is largely attributable to the lower emissions
potential of air flotation systems. In view of the Agency's conclusion that
use of a fixed roof without venting the vapors to a control device would
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result in either a safety hazard or negligible emissions reductions, cost
effectiveness and safety considerations have led the Agency to exclude air
flotation systems from coverage under the final standards.
2.4.8 Comment: One commenter (IV-D-9) claimed that EPA's technical
development and economic bases for imposing controls on DAF's are seriously
flawed. According to this commenter, EPA has grossly overestimated VOC
emissions from DAF's and has underestimated the costs of controls. For
example, the cost for the additional equipment needed to use a nitrogen purge
system was not included in the cost analysis, according to this and another
commenter (IV-D-10). A nitrogen purge system is needed to reduce the hazards
of explosive gases building up under the DAF roof. These commenters
recommended that EPA withdraw the proposed controls on DAF's from this
rulemaking because the technical basis for them has not been demonstrated and
because they are not cost effective.
Response: The emissions estimate used to calculate the cost
effectiveness of controls on DAF's was derived from EPA tests on an operating
DAF. From these tests, an emission factor of 30 Kg VOC per million gallons
of wastewater was developed. This emission factor is still believed to be
representative of the types of DAF's used at refineries and the range of
conditions under which DAF's are operated.
However, as noted in the response to Comment 2.1.3, air flotation
systems have been excluded from the final standards primarily because of
safety concerns and the lack of control a fixed roof alone would afford. The
Agency agrees with these commenters that a nitrogen purge system would be
needed to alleviate safety problems and that those costs were not included in
the original cost estimation work. However, the cost effectiveness of
controls for DAF's is very high, not because the costs have been underestimat-
ed, but because a nitrogen purge system requires that vapors be vented to a
control device if VOC emissions are to be controlled. The cost of a fixed
roof with a control device, coupled with the relatively small resulting
emission reduction, makes the cost effectiveness of controlling these units
unreasonable under Section 111 of the Clean Air Act.
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2.4.9 Comment; Three commenters stated that the DAF selected for EPA's cost
analysis may not be typical (IV-D-2, IV-D-6, IV-D-10). Many of the DAF's
being used in the industry are very large [e.g., 30 million liters per day
(8 million gallons per day) per tank]. The commenters noted that an
equipment supplier has estimated that a DAF roof will add approximately
35 percent to the cost of a new DAF. Retrofit of an existing DAF with a roof
will undoubtedly add more, according to these comments. One of these
commenters (IV-D-10) and another commenter (IV-D-6) stated that installation
of a DAF roof will not only affect initial installation costs, but will also
add to ongoing maintenance costs due to the need to remove large roof
sections in order to replace internal parts.
Response: The EPA believes the size of the DAF tested is
representative of the size range of DAF's in use. The estimate of 35 percent
of the cost of the entire DAF is consistent with information gathered from
vendors by EPA. The size of the DAF unit should not appreciably affect the
percentage of the total cost attributable to the roof because the roof cost
[EPA used $215 per square meter ($20 per square foot)] is directly
proportional to the roof size. With respect to maintenance, vendors report
that DAF roofs can be removed easily, although refiners generally believe the
roofs are heavy and difficult to remove.
In any case, as explained in the response to Comment 2.1.3, DAF's have
been eliminated from coverage under the final standards for a variety of
reasons.
2.5 ENVIRONMENTAL AND ECONOMIC IMPACTS
2.5.1 Comment: One commenter questioned EPA's emission estimates for air
flotation systems (IV-D-8). The commenter maintained that EPA's emission
estimates overpredict actual emissions because in air flotation units the
walls and steady upward displacement of gas caused by the flotation mechanism
minimizes wind effects and evaporative emissions.
Response: During the development of the standards, EPA conducted
emission tests on four lAF's and one DAF. One IAF was treating non-oily
wastewater, so the emission results from this unit were not used to estimate
an emission factor. As described in the Volume I BID, air purging was used
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to test the air flotation systems. Because of the air purging, the emission
results represent the emission potential of the systems rather than the
actual emissions resulting from a system operating under normal conditions.
The VOC emissions measured at these systems were variable. The variation
could be due to design and operational differences between the systems,
differences in the concentration of hydrocarbon in the wastewater, or
differences in the purge rate used during the tests. Therefore, to account
for these variations, an average emission factor was calculated from the
emission test results to represent emission potential for air flotation
systems.
2.5.2 Comment: Two commenters stated that the economic impact of the
standards should be reevaluated because the cost impact is major, not minor,
and additional review is required under Executive Order 12291 (IV-D-2,
IV-D-8). The commenters feel that the economic impact of this regulation is
far greater than that listed in the preface to the regulation. Compliance
with the proposed regulation in its entirety is estimated to cost a refinery
between $2 and 6 million. Applying this estimate to the total industry, an
estimate of $130 million to retrofit all refineries is given, not including
operating and monitoring costs.
Response: The EPA disagrees with the commenters' contention that the
economic impact of the standards is major (i.e., greater than $100 million),
not minor. The fifth year annualized costs by model unit and regulatory
alternative are summarized in Chapter 9 of Volume I of the BID. These cost
estimates show that compliance with the proposed standards will cost the
petroleum refinery industry approximately $1.18 million. Under the final
standards the economic impact will be $1.1 million. The impact of the final
standards is slightly less because of the exemption of air flotation systems
from the final rule.
The commenters did submit estimates of what the commenter determined it
would cost to comply with the NSPS. Compliance with the proposed regulation
was estimated to be $2 to 6 million for one refinery. However, the
commenters erred in assuming for these estimates that every single component
of the existing wastewater system would be subject to the standards. The
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final rule is applicable only to new, modified, or reconstructed components
of the wastewater system. As described in the Volume I BID, EPA estimates
that 100 newly constructed process unit drain systems and 30 new oil-water
separators will become subject to the standards. In addition, 18 process
drain systems and three oil-water separators are expected to become subject
to the standards because of the modification and reconstruction provisions.
Thus, as described above, EPA has determined that the economic impact of the
standards will be approximately $1.1 million, far less than the $100 million
established as the first criterion for a major regulation under Executive
Order 12291.
2.6 MONITORING, RECORDKEEPING, AND REPORTING REQUIREMENTS
2.6.1 Comment: Two commenters stated that the requirement for weekly
inspection of water seals on drains is unnecessarily stringent and would
present a significant burden to the industry given the large number and
location of these drains in a refinery (IV-D-7, IV-D-8). According to the
commenters, drains are often located in areas that are difficult or unsafe to
inspect routinely. The commenters recommended that the inspection frequency
for process drains be reduced to once a month. The commenters further state
that water seals also tend to be maintained by precipitation, maintenance
washing, and use.
Response: The EPA agrees that drains that are kept in wastewater
collection service will be maintained primarily by the refinery wastewater
that is received from a process unit, as well as by precipitation and main-
tenance washing. Inspections are still required, however, to make sure that
the water seals are present or that seal pots are properly capped. Therefore,
the inspection frequency has been reduced to monthly, instead of weekly for
drains in active service. For drains that are removed from service, there is
no assurance that use, precipitation, and maintenance washing will maintain
the water seal. Consequently, a weekly visual or physical inspection is
still required unless a tightly sealed cap or plug is installed. A semiannual
inspection would be required for tightly sealed caps or plugs on drains not
in active service.
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2.6.2 Comment: One commenter recommended that the requirement for a flow
sensor on the flow vent gases to control devices be eliminated (IV-D-1). The
commenter stated that flow measurements of these streams are inaccurate,
unreliable, and subject to extensive maintenance requirements.
Response: As stated in Section 60.692-7(f)(4), the proposed regulation
requires that a flow indicator be installed on a vent stream to a control
device. The regulation does not require that flowrate be measured. Flow
indicators are defined as devices which indicate whether gas flow is present
in a vent stream. This definition has been included in the regulation to
avoid any misunderstanding of the monitoring requirements. The EPA has
determined that flow indicators are necessary to ensure that vent streams are
being continually routed to appropriate vapor recovery or destruction
devices. The Agency has determined that the cost of this monitoring
requirement is reasonable.
2.6.3 Comment; One commenter recommended that continuous monitoring of
flares by television monitors be allowed in addition to thermocouples and
heat sensing devices (IV-D-1). The commenter stated that monitoring by
television monitors is equally effective and more reliable.
Response: The EPA has determined that detection of a flame by visual
means or by remote video camera is not a suitable monitoring method. If a
flare is operating smokelessly it can be difficult to determine if a flame is
present. Therefore, continuous monitoring of flares by television monitors
has not been included in the final standards.
2.6.4 Comment: One commenter questioned the need for weekly monitoring of
lAF's (IV-D-7). The commenter stated that maintaining good workplace habits
rather than conducting frequent inspections will guarantee the effectiveness
of control devices on these units and suggested that semiannual inspections
would be adequate to document whether such good habits are being practiced.
Response: The inspection and monitoring requirements for lAF's have
been deleted because, as explained in response to Comment 2.1.3, all air
flotation systems have been exempted from the final rule.
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2.6.5 Comment: One commenter noted that the definition of "gas-tight
condition" in Section 60.691 applicable to lAF's includes a requirement for
"no detectable emissions" (IV-D-8). The commenter believes this definition
provides a rather uncertain and moving target for compliance because the
detectability of emissions can change with improvements in testing instru-
ments and sophistication of testing methods. The commenter suggested that
the definition be expanded to include "no detectable emissions as indicated
by an instrument reading of less than 500 ppm above background levels."
Response: As discussed in the response to Comment 2.1.3, air
flotation systems are not covered under the final standards. However, the
comment is still relevant to oil-water separators vented to control devices
or other affected facilities with closed vent systems. A requirement of "no
detectable emissions" still applies to these facilities.
The requirement for "no detectable emissions" in both the proposal and
the final standards already includes the provision suggested by the commenter,
As provided in Section 60.691, the term "no detectable emissions" means less
than 500 ppm above background levels, as measured by a detection instrument
in accordance with EPA Method 21 in Appendix A of 40 CFR Part 60.
2.6.6 Comment: One commenter stated that the time period of 15 days to
repair leaking equipment was chosen arbitrarily and could be difficult to
meet in some cases (IV-D-8). The commenter suggested that the rule be
amended to set forth conditions under which repair may be delayed beyond the
15 days in cases where diligent efforts to complete the repairs within
15 days have been unsuccessful.
Response: Provisions were included in the proposed regulation in
Section 60.692-8 for delay of repair if the repair is technically impossible
to make without a complete or partial refinery or process unit shutdown. Two
commenters endorsed the inclusion of this provision. Provisions for delayed
repair are included in Section 60.697(e) (recordkeeping requirements) of the
proposed regulation. This section requires that an emission point or equip-
ment problem be repaired or corrected in 15 calendar days with the exception
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of drains and floating roofs. Drains shall be corrected within 24 hours and
floating roofs shall be repaired within 30 calendar days. If the repair is
technically impossible to make without a complete or partial refinery or
process unit shutdown, the expected date of successful repair of leaking
equipment shall be recorded. The Agency feels that 15 days allows ample time
for the type of minor repairs that may be necessary (for example, replacing
gaskets or seals). Also, the provision for delay of repair for major repairs
that may require plant or process unit shutdown allows the refiner sufficient
flexibility. Therefore, in the final rule, delay of repair provisions are
the same as those proposed.
2.6.7 Comment; Three commenters stated that the applicability of "no
detectable emissions" to specific components of the refinery wastewater
system and the associated requirement for monitoring using a portable hydro-
carbon monitor to detect such emissions was inappropriate and that visual
inspection would be sufficient (IV-D-2, IV-D-4, IV-D-5). Specifically, the
commenters objected to the application of the standards to equipment with
fixed roof controls that are not required to be vented to a vapor recovery or
destruction control device, such as junction boxes and oil-water separators.
Response; The final standards have been revised to delete the "no
detectable emissions" monitoring requirement for junction boxes, oil-water
separators, and other components of the affected refinery wastewater system
that are equipped with atmospheric or pressure control vents not vented to a
control device. The Agency agrees with the comment that visual inspection
coupled with follow-up repairs and maintenance is sufficient to prevent leaks
of VOC through faulty or poorly maintained joints, seals, or gaskets.
Therefore, the final standards are the same as proposed for visual inspection
of all joints, seams, access doors, and other emission sources on junction
boxes, sewer lines, oil-water separators and any other components of the
refinery wastewater system that are subject to the standards.
For oil-water separators with closed vent systems and other closed
systems, such as closed drain systems, the "no detectable emissions"
requirement specified in the proposed rule is maintained in the final rule.
For closed vent systems, monitoring and inspection would be required of
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joints, seams, access doors, and other potential emission sources when the
facility becomes subject to the standards, and semi annually thereafter to
ensure that there are "no detectable emissions as indicated by an instrument
reading of less than 500 ppm above background levels." The EPA Method 21
would be the applicable test method for these facilities.
2.6.8 Comment: One commenter recommended that all inspection requirements
associated with the proposed regulation should coincide with the inspection
requirements in 52 FR 3748: Proposed Standards to Limit Air Emissions of
VOC's at Hazardous Waste Facilities (IV-D-7). The commenter made the point
that by coordinating the inspection schedules, personnel can perform
inspections which will meet the requirements of both regulations.
Response: The commenter is referring to EPA's proposed air emission
standards for volatile organic control from hazardous waste treatment,
storage, and disposal facilities. The proposed standards cited by the
commenter require a monthly leak detection and repair program for equipment
such as pumps, valves, and pressure relief devices. Under the petroleum
refinery wastewater systems NSPS, EPA is requiring that closed vent systems
be monitored for detectable emissions initially and semiannually. This
requirement does not discourage an owner or operator from coordinating this
inspection with any other inspections they may be required to perform under
other regulations. However, separate recordkeeping requirements will still
apply.
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— TECHNICAL REPORT DATA
em read Instructions on the reverse before completing)
EPA-450/3-85-001b
3. RECIPIENT'S ACCESSION NO.
VOC Emissions from Petroleum Refinery Wastewater
Systems - Background Information for Promulgated
Standards
5. REPORT OATE
December 1987
8. PERFORMING ORGANIZATION CODE
B. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Standards Development Branch
Environmental Protection Agency
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
83/14
i i mu. i
11. CONTRACT/GftANT NO."
68-02-3816
ME AND ADDRESS
DAA for Air Quality Planning and Standards
Office of Air and Radiation
U.S. Environmental Protection Agency
Research Triangle Park. North Carolina ?7711
SUPPI CIUEIUTADV- ti/t-ro. w ¥1 I w < r I m Ml I t t
13. TYPE OF REPORT AND PERIOD COVERED
Final
4. SPONSORING AGENCY CODE
EPA/200/04
115. SUPPLEMENTARY NOTES
Owners or operators of petroleum refineries would be required to meet certain
emissions, design, operation, and work practice standards for their wastewater
treatment systems. This report contains a summary of changes to the standards
made since proposal, a summary of impacts of the promulgated standards, and a
summary of public comments and EPA responses on the proposal
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Gr
Air pollution control
Intergovernmental relations
Reporting and recordkeeping requirements
Petroleum refining
Air pollution control
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Tllis Report)
Unclassified
20. SECURITY CLASS (Tliiipage)
Unclassified
21. NO. OF PAGES
64
22. PRICE
EPA Form 2220-1 (R«v. 4-77) PREVIOUS COITION is OBSOLETE
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