[Federal Register Volume 63, Number 25 (Friday, February 6, 1998)]
[Proposed Rules]
[Pages 6288-6336]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 98-2714]
[[Page 6287]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants: Oil and
Natural Gas Production and Natural Gas Transmission and Storage;
Proposed Rule
Federal Register / Vol. 63, No. 25 / February 6, 1998 / Proposed
Rules
[[Page 6288]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[AD-FRL-5955-1]
RIN 2060-AE34
National Emission Standards for Hazardous Air Pollutants: Oil and
Natural Gas Production and Natural Gas Transmission and Storage
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rules and notice of public hearing.
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SUMMARY: These proposed national emission standards for hazardous air
pollutants (NESHAP) would limit emissions of hazardous air pollutants
(HAP) from oil and natural gas production and natural gas transmission
and storage facilities. These proposed rules would implement section
112 of the Clean Air Act (Act) and are based on the Administrator's
determination that oil and natural gas production and natural gas
transmission and storage facilities emit HAP identified on the EPA's
list of 188 HAP.
The EPA estimates that approximately 65,000 megagrams per year (Mg/
yr) of HAP are emitted from major and area sources in these source
categories. The primary HAP emitted by the facilities covered by these
proposed standards include benzene, toluene, ethyl benzene, mixed
xylenes (collectively referred to as BTEX), and n-hexane. Benzene is
carcinogenic and all can cause toxic effects following exposure. The
EPA estimates that these proposed NESHAPs would reduce HAP emissions in
the oil and natural gas production source category by 57 percent and in
the natural gas transmission storage source category by 36 percent.
Also, the EPA is amending the list of source categories established
under section 112(c) of the Act. Natural gas transmission and storage
is being listed as a category of major sources and oil and natural gas
production is being listed as a category of area sources in addition to
its major source listing.
DATES: Comments. Comments must be received on or before April 7, 1998.
For information on submitting electronic comments see the Supplementary
Information section of this document.
Public Hearing. A public hearing will be held, if requested, to
provide interested persons an opportunity for oral presentation of
data, views, or arguments concerning the proposed standards for the oil
and natural gas production and the natural gas transmission and
storage. If anyone contacts the EPA requesting to speak at a public
hearing by March 9, 1998, a public hearing will be held on March 23,
1998, beginning at 9:30 a.m. Persons interested in attending the
hearing should notify Ms. JoLynn Collins, telephone (919) 541-5671,
Waste and Chemical Processes Group (MD-13), to verify that a hearing
will occur.
Request to Speak at a Hearing. Persons wishing to present oral
testimony must contact the EPA by March 9, 1998, by contacting Ms.
JoLynn Collins, Waste and Chemical Processes Group (MD-13), U.S.
Environmental Protection Agency, Research Triangle Park, NC 27711,
telephone (919) 541-5671.
ADDRESSES: Comments. Comments should be submitted (in duplicate, if
possible) to: Air and Radiation Docket and Information Center (MC-
6102), Attention: Docket No. A-94-04, U.S. Environmental Protection
Agency, 401 M Street, SW, Washington, DC 20460. The EPA requests that a
separate copy of comments also be sent to Stephen Shedd, USEPA, Office
of Air Quality Planning and Standards, Research Triangle Park, NC
27711, telephone (919) 541-5397, fax (919) 541-0246 and E-mail:
[email protected] Comments and data may also be submitted
electronically by following the instructions listed in Supplementary
Information. No confidential business information (CBI) should be
submitted through e-mail.
Background Information Document. The background information
document (BID) may be obtained from the U.S. Environmental Protection
Library (MD-35), Research Triangle Park, NC 27711, telephone (919) 541-
2777. Please refer to ``National Emissions Standards for Hazardous Air
Pollutants for Source Categories: Oil and Natural Gas Production and
Natural Gas Transmission and Storage--Background Information for
Proposed Standards'' (EPA-453/R-94-079a, April 1997) for the BID. This
document may also be obtained electronically from the EPA's Technology
Transfer Network (TTN) (see SUPPLEMENTARY INFORMATION for access
information).
Docket. A docket, No. A-94-04, containing information considered by
the EPA in development of the proposed standards for the oil and
natural gas production and natural gas transmission and storage source
categories, is available for public inspection between 8:00 a.m. and
4:00 p.m., Monday through Friday (except for Federal holidays) at the
following address: U.S. Environmental Protection Agency, Air and
Radiation Docket and Information Center (MC-6102), 401 M Street SW.,
Washington DC 20460, telephone: (202) 260-7548. The docket is located
at the above address in Room M-1500, Waterside Mall (ground floor). The
proposed regulations, BID, and other supporting information are
available for inspection and copying. A reasonable fee may be charged
for copying.
FOR FURTHER INFORMATION CONTACT: For information concerning the
proposed standards, contact Ms. Martha Smith, Waste and Chemical
Processes Group, Emission Standards Division (MD-13), U.S.
Environmental Protection Agency, Research Triangle Park, NC 27711,
(919) 541-2421, or electronically at: smith.martha@epamail.epa.gov.
SUPPLEMENTARY INFORMATION: Regulated Entities. Regulated categories and
entities include:
------------------------------------------------------------------------
Category Examples of regulated entities
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Industry.......................... Condensate tank batteries, glycol
dehydration units, natural gas
processing plants, and natural gas
transmission and storage
facilities.
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This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that the EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your facility is regulated by this action, you should carefully
examine the applicability criteria in Secs. 63.760 and 63.1270 of the
rules. If you have questions regarding the applicability of this action
to a particular entity, consult the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section.
Electronic comments can be sent directly to EPA at: A-and-R-
Docket@epamail.epa.gov. Electronic comments must be submitted as an
ASCII file avoiding the use of special characters and any form of
encryption. Comments and data will also be accepted on disks in
WordPerfect in 5.1 or 6.1 file format or ASCII file format. All
comments and data in electronic form must be identified by the docket
number A-94-04. Electronic comments on this proposed rule may be filed
online at many Federal Depository Libraries.
This document, the proposed regulatory texts, and BID are available
in Docket No. A-94-04 or by request from the EPA's Air and Radiation
Docket and Information Center (see ADDRESSES) or
[[Page 6289]]
access through the EPA web site at: http://www.epa.gov/ttn/oarpg.
The following outline is provided to aid in reading the preamble to
the proposed oil and natural gas production and natural gas
transmission and storage NESHAPs.
I. Background
A. Purpose of the Proposed Standards
B. Technical Basis for the Proposed Standards
C. Stakeholder and Public Participation
II. Source Category Descriptions
A. Source Category List
B. Hazardous Air Pollutant Types
C. Facility Types
III. Summary of Proposed Standards
A. Proposed Standards for Oil and Natural Gas Production for
Major and Area Sources
B. Proposed Standards for Natural Gas Transmission and Storage
for Major Sources
IV. Summary of Environmental, Energy, and Economic Impacts
A. HAP Emission Reductions
B. Secondary Environmental Impacts
C. Energy Impacts
D. Cost Impacts
E. Economic Impacts
V. Area Source Finding
VI. Glycol Dehydration Unit Nationwide HAP Emissions Estimates
VII. Definition of Major Source for the Oil and Natural Gas Industry
A. Definition of ``Associated Equipment''
B. Definition of Facility
VIII. Rationale for Proposed Standards
A. Selection of Hazardous Air Pollutants for Control
B. Selection of Emission Points
C. Definition of Affected Source
D. Determination of MACT Floor
E. Oil and Natural Gas Production NESHAP-Regulatory Alternatives
for Existing and New Major Sources
F. Oil and Natural Gas Production NESHAP-Regulatory Alternatives
for Existing and New Area Sources
G. Natural Gas Transmission and Storage NESHAP-Regulatory
Alternatives for Existing and New Major Sources
H. Selection of Format
I. Selection of Test Methods and Procedures
J. Selection of Monitoring and Inspection Requirements
K. Selection of Recordkeeping and Reporting Requirements
IX. Relationship to Other Standards and Programs Under the Act
A. Relationship to the Part 70 and Part 71 Permit Programs
B. Relationship Between the Oil and Natural Gas Production and
the Organic Liquids Distribution (Non-Gasoline) Source Categories
C. Relationship of Proposed Standards to the Pollution
Prevention Act
D. Relationship of Proposed Standards to the Natural Gas STAR
Program
E. Overlapping Regulations
X. Solicitation of Comments
A. Potential-to-Emit
B. Definition of Facility
C. Interpretation of ``Associated Equipment'' in Section
112(n)(4) of the Act
D. Regulation of Area Source Glycol Dehydration Units
E. HAP Emission Points
F. Storage Vessels at Natural Gas Transmission and Storage
Facilities
G. Cost Impact and Production Recovery Credits
XI. Administrative Requirements
A. Docket
B. Paperwork Reduction Act
C. Executive Order 12866
D. Regulatory Flexibility
E. Unfunded Mandates
I. Background
A. Purpose of the Proposed Standards
The Act was developed, in part,
* * * to protect and enhance the quality of the Nation's air
resources so as to promote the public health and welfare and
productive capacity of its population [the Act, section 101(b)(1)].
Oil and natural gas production and natural gas transmission and storage
facilities are major and area sources of HAP emissions. The EPA
estimates that approximately 65,000 Mg/yr of HAP are emitted from major
and area sources in the oil and natural gas production source category
and 320 Mg/yr of HAP are emitted from major and area sources in the
natural gas transmission and storage source category. The primary HAP
associated with oil and natural gas that have been identified include
BTEX and n-hexane. Exposure to these chemicals has been demonstrated to
cause adverse health effects. The adverse health effects associated
with the exposure to these specific HAP are discussed briefly in the
following paragraphs. In general, these findings have only been shown
with concentrations higher than those in the ambient air.
Benzene, one of the HAP associated with this NESHAP, has been
classified as a known human carcinogen on the basis of observed
increases in the incidence of leukemia in exposed workers. In addition,
short-term inhalation of high benzene levels may cause nervous system
effects such as drowsiness, dizziness, headaches, and unconsciousness
in humans. At even higher concentrations of benzene, exposure may cause
death, while lower concentrations may irritate the skin, eyes, and
upper respiratory tract. Long-term inhalation exposure to benzene may
cause various disorders of the blood, and toxicity to the immune
system. Reproductive disorders in women, as well as developmental
effects in animals, have also been reported for benzene exposure.
Short-term inhalation of relatively high concentrations of toluene
by humans may cause nervous system effects such as fatigue, sleepiness,
headaches, and nausea, as well as irregular heartbeat. Repeated
exposure to high concentrations may cause additional nervous system
effects, including incoordination, tremors, decreased brain size,
involuntary eye movements, and may impair speech, hearing, and vision.
Long-term exposure of toluene in humans has also been reported to
irritate the skin, eyes, and respiratory tract, and to cause dizziness,
headaches, and difficulty with sleep. Children whose mothers were
exposed to toluene before birth may suffer nervous system dysfunction,
attention deficits, and minor face and limb defects. Inhalation of
toluene by pregnant women may also increase the risk of spontaneous
abortion. Not enough information exists to determine toluene's
carcinogenic potential.
Short-term inhalation of high levels of ethyl benzene in humans may
cause throat and eye irritation, chest constriction, and dizziness.
Long-term inhalation of ethyl benzene by humans may cause blood
disorders. Animal studies have reported blood, liver, and kidney
effects associated with ethyl benzene inhalation. Birth defects have
been reported in animals exposed via inhalation; whether these effects
may occur in humans is not known. Not enough information exists
concerning ethyl benzene for determination of its carcinogenic
potential.
Short-term inhalation of high levels of mixed xylenes (a mixture of
three closely-related compounds) in humans may cause irritation of the
nose and throat, nausea, vomiting, gastric irritation, mild transient
eye irritation, and neurological effects. Long-term inhalation of high
levels of xylene in humans may result in nervous system effects such as
headaches, dizziness, fatigue, tremors, and incoordination. Other
reported effects noted include labored breathing, heart palpitation,
severe chest pain, abnormal heart functioning, and possible effects on
the blood and kidneys. Developmental effects have been reported from
xylene exposure via inhalation in animals. Not enough information
exists to determine the carcinogenic potential of mixed xylenes.
Short-term inhalation of high levels of n-hexane in humans may
cause mild central nervous system effects (dizziness, giddiness, slight
nausea, and headache) and irritation of the skin and mucous membranes.
Long-term inhalation exposure of high levels of n-hexane in humans has
been reported to
[[Page 6290]]
cause nerve damage expressed as numbness in the extremities, muscular
weakness, blurred vision, headache, and fatigue. Reproductive effects
have been reported in animals after inhalation exposure (testicular
damage in rats). Not enough information exists concerning n-hexane for
determination of its carcinogenic potential.
The EPA estimates that the proposed NESHAP would reduce HAP
emissions from those impacted HAP emission points in the oil and
natural gas production source category by 57 percent and would reduce
HAP emissions from triethylene glycol (TEG) dehydration units in the
natural gas transmission and storage source category by 36 percent.
B. Technical Basis for the Proposed Standards
Section 112 of the Act regulates stationary sources of HAP. Section
112(b) of the Act lists 188 chemicals, compounds or groups of chemicals
as HAP. The EPA is directed by section 112 to regulate the emission of
HAP from stationary sources by establishing national emission
standards.
Section 112(a)(1) of the Act defines a major source as:
* * * any stationary source or group of stationary sources located
within a contiguous area and under common control that emits or has
the potential-to-emit considering controls, in the aggregate 10 tons
per year (tpy) or more of any HAP or 25 tpy or more of any
combination of HAP.
An area source is defined as a stationary source that is not a major
source.
For major sources, the statute requires the EPA to establish
standards to reflect the maximum degree of reduction in HAP emissions
through application of maximum achievable control technology (MACT).
Further, the EPA must establish standards that are no less stringent
than the level of control defined under section 112(d)(3) of the Act,
often referred to as the MACT floor. The proposed standards for major
sources in the oil and natural gas production and natural gas
transmission and storage source categories are based on the MACT floor
for these source categories.
In developing standards for area sources of HAP emissions, the EPA
has discretion to establish standards based on (1) MACT, (2) generally
available control technology (GACT), or (3) management practices that
reduce the emission of HAP. The proposed standards for selected area
source TEG dehydration units are based on GACT. There is no statutory
``floor'' level of control for GACT.
Information on industry processes and operations, HAP emission
points, and HAP emission reduction techniques were collected through
section 114 questionnaires that were distributed to companies in the
oil and natural gas production and natural gas transmission and storage
source categories. The companies provided information on representative
facilities.
This information was used, in part, as the technical basis in
determining the MACT level of control for the emission points covered
under the proposed standards. In addition to information collected in
the questionnaires, the EPA considered information available in the
general literature, as well as information submitted by industry on
technical issues subsequent to the questionnaire responses.
C. Stakeholder and Public Participation
Numerous representatives of the oil and natural gas industry and
other interested parties were consulted in the development of the
proposed standards. Industry assisted in data gathering, arranging site
visits, technical review, and sharing of industry-sponsored data
collection activities. A data base comprised of all industry-supplied
information was developed in the evaluation of HAP emissions and air
emission controls for these proposed standards.
Estimates of HAP emissions from representative facilities in each
industry segment were developed by the EPA. To estimate HAP emissions
from glycol dehydration units in both the oil and natural gas
production and natural gas transmission and storage source categories,
the EPA utilized an emission model, GRI-GLYCalc TM (Version
3.0), developed by the Gas Research Institute (GRI). Inputs used by the
EPA for this model were primarily developed from information supplied
by industry.
The trade associations and organizations that participated in the
development of the proposed rules on a regular basis include (1) the
American Petroleum Institute (API) and (2) GRI. Other interested
parties that participated in the development of the proposed standards
include the Independent Petroleum Association of America (IPAA), the
Audubon Society, the Interstate Oil and Gas Compact Commission (IOGCC),
the American Gas Association (AGA), and the Interstate Natural Gas
Association of America (INGAA).
These interested parties, in addition to individual companies in
the oil and natural gas industry, were offered the opportunity to
provide technical review and comment during the development of the
proposed standards. In addition, interested parties provided technical
review and comment on the preliminary draft BID and preliminary draft
standards.
Representatives from other EPA offices and programs were included
in the regulatory development process. These representatives'
responsibilities included review and internal concurrence with the
proposed standards. Therefore, the EPA believes that the impact of
these proposed regulations to other EPA offices and programs has been
adequately considered during the development of these regulations.
This notice also solicits comment on the proposed standards and
offers a chance for a public hearing on the proposals in order to
provide interested persons the opportunity for oral presentation of
data, views, or arguments concerning the proposed standards.
II. Source Category Descriptions
A. Source Category List
Oil and natural gas production was included on the EPA's initial
list of categories of major sources of HAP emissions established under
section 112(c)(1) of the Act. This list was published on July 16, 1992
(57 FR 31576).
The EPA included natural gas transmission and storage in the
proposed initial listing of source categories that was published in
1991. The EPA's preliminary analysis that led to natural gas
transmission and storage being listed as a source category was based on
the estimated emissions of the HAP ethylidene dichloride (1,1-
dichloroethane). Comments received on the proposed initial list
indicated that these estimates were not accurate.
Based on its review of comments for the final initial list, the EPA
decided that it did not have sufficient available information that
supported that this source category could contain a major source of
HAP. Thus, the natural gas transmission and storage source category was
not included as a distinct source category in the final initial list of
source categories of major sources of HAP.
In the development of the proposed standards for the oil and
natural gas production source category, information was obtained on
glycol dehydration unit BTEX emissions that are representative of both
oil and natural gas production facilities and natural gas transmission
and storage facilities. The information obtained indicates that natural
gas transmission and storage facilities have
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the potential to be major HAP sources. In addition, industry has stated
to the EPA that there are major source TEG dehydration units in the
natural gas transmission and storage source category. Therefore, the
EPA is amending the source category list to add the natural gas
transmission and storage source category as a major source category
and, with this notice, is proposing a regulation that would apply to
major sources in this source category.
The EPA has made a determination that there are area sources in the
oil and natural gas production source category that present a threat of
adverse effects to human health and the environment. Based on this
determination, referred to as an ``area source finding,'' the EPA is
amending the source category list to add oil and natural gas production
to the list of area source categories established under section
112(c)(1) of the Act. The area source finding supporting this listing
is discussed in section V of this preamble.
Glycol dehydration units located at natural gas transmission and
storage facilities have similar HAP emissions and emission potential to
those located at oil and natural gas production facilities. The EPA is
currently evaluating whether TEG dehydration units located at natural
gas transmission and storage facilities that are area sources
constitute an unacceptable risk to public health or the environment and
should be listed and regulated as an area source. The EPA is soliciting
information and comment in this notice regarding the location and HAP
emissions from area source TEG dehydration units in the natural gas
transmission and storage source category (see sections V and X for
further discussion).
The documentation supporting the listing of oil and natural gas
production as a source category (``Documentation for Developing the
Initial Source Category List,'' EPA-450/3-91-030, July 1992) describes
the source category as including
* * * the processing and upgrading of crude oil prior to entering
the petroleum refining process and natural gas prior to entering the
transmission line.
During the development of the proposed rules, industry requested that
HAP emissions associated with distribution of hydrocarbon liquids after
the point of custody transfer be addressed within the scope of the
organic liquids distribution (non-gasoline) source category and not the
oil and natural gas production source category. Custody transfer, as
defined in a previous rule, means transfer, after processing and/or
treatment in the producing operations, from storage vessels or
automatic transfer facilities to pipelines or any other forms of
transportation. Industry representatives commented that there are
differences in the HAP emission potential from facilities involved in
the distribution of petroleum liquids after the point of custody
transfer relative to other processes and operations in the oil and
natural gas production source category.
The EPA, after evaluation of industry comments, is proposing that
HAP emissions associated with the distribution of hydrocarbon liquids
after the point of custody transfer would be more appropriately
addressed as part of the organic liquids distribution (non-gasoline)
source category. Therefore, the proposed rule for the oil and natural
gas production source category would not apply to those facilities that
distribute hydrocarbon liquids after the point of custody transfer (see
proposed regulation for definition of custody transfer).
Facilities involved in the organic liquids distribution (non-
gasoline) sector of the petroleum industry include (but are not limited
to) gathering stations, trunk-line stations, and station storage vessel
farms. The organic liquids distribution (non-gasoline) source category
is scheduled for regulation under section 112 of the Act by November
15, 2000.
The EPA plans to define the organic liquids distribution (non-
gasoline) source category (within that rulemaking) as including those
facilities that distribute hydrocarbon liquids after the point of
custody transfer. This will eliminate the potential for overlapping
regulatory requirements between the oil and natural gas production and
organic liquids distribution (non-gasoline) source categories.
B. Hazardous Air Pollutant Types
The primary HAP associated with the oil and natural gas production
and natural gas transmission and storage source categories include BTEX
and n-hexane. In addition, available information indicates that 2,2,4-
trimethylpentane (iso-octane), formaldehyde, acetaldehyde, naphthalene,
and ethylene glycol may be present in certain process and emission
streams. Carbon disulfide (CS2), carbonyl sulfide (COS), and
BTEX may also be present in the tail gas streams from amine treating
and sulfur recovery units.
C. Facility Types
The oil and natural gas production and natural gas transmission and
storage source categories consist of various facilities used to recover
and treat products (hydrocarbon liquids and gases) from production
wells. These source categories include the processing, storage, and
transport of these products to (1) the point of custody transfer for
the oil and natural gas production source category or (2) the point of
delivery to the local distribution company (LDC) or final end user for
the natural gas transmission and storage source category. The
facilities in the oil and natural gas production source category that
the EPA is proposing requirements for include (1) glycol dehydration
units, (2) condensate tank batteries, and (3) natural gas processing
plants. The EPA is also proposing requirements for glycol dehydration
units located at facilities in the natural gas transmission and storage
source category.
1. Glycol Dehydration Units
The most widely used dehydration process in these source categories
is glycol dehydration. TEG dehydration units account for the majority
of glycol dehydration units, with ethylene glycol (EG) and diethylene
glycol (DEG) dehydration units accounting for the remaining population
of glycol dehydration units. In the dehydration process, natural gas is
contacted with glycol to remove water present in the natural gas. Some
portion of the HAP present in the natural gas are also removed by the
glycol. The ``rich'' glycol is then heated in a reboiler to remove
water vapor and other contaminants prior to recirculation in the
process. The reboiler vent of the glycol dehydration unit is the
primary identified source of HAP emissions for these source categories.
2. Tank Batteries
The term ``tank battery'' refers to the collection of process
equipment used to separate, upgrade, store, and transfer extracted
petroleum products and separated streams. These facilities handle crude
oil and condensate up to the custody transfer of these products to
facilities in the organic liquids distribution (non-gasoline) source
category. Separation and dehydration of natural gas can also occur at a
tank battery. A tank battery may serve an individual production well or
a collection of wells in the field.
Tank batteries can be broadly classified as black oil tank
batteries or condensate tank batteries. Black oil means hydrocarbon
(petroleum) liquid with a gas-to-oil ratio (GOR) less than 50 cubic
meters (m3) (1,750 cubic feet (ft3)) per barrel
and an API gravity less than
[[Page 6292]]
40 degrees ( deg.). Condensate means hydrocarbon liquid that condenses
because of changes in temperature, pressure, or both, and remains
liquid at standard conditions. The majority of tank batteries,
approximately 85 percent, are black oil tank batteries and the
remainder are condensate tank batteries.
The primary identified HAP emission points at tank batteries
include (1) process vents associated with glycol dehydration units and
(2) tanks and vessels storing volatile oils, condensate, and other
similar hydrocarbon liquids that have a flash emission potential.
Condensate tank batteries typically incorporate a glycol dehydration
unit in the process system.
The EPA proposes to exempt from the oil and natural gas production
NESHAP those facilities that handle black oil exclusively. This
exemption is based on the EPA's proposed interpretation of associated
equipment in section 112(n)(4) of the Act. The EPA is proposing that
associated equipment be defined as all equipment associated with a
production well up to the point of custody transfer, except that glycol
dehydration units and storage vessels with flash emissions would not be
associated equipment. The EPA believes that this proposed definition
will provide the relief that Congress intended in section 112(n)(4) for
the numerous, widely dispersed, small emission points in the oil and
natural gas production source category (such as black oil tank
batteries) while preserving the EPA's ability to require appropriate
MACT or GACT controls for the most significant identified HAP emission
points in this source category (see section VII of this preamble for a
detailed discussion of associated equipment).
3. Natural Gas Processing Plants
A natural gas processing plant conditions natural gas by separating
natural gas liquids (NGLs) from field natural gas and, in addition, may
fractionate the NGLs into separate components such as ethane, propane,
butane, and natural gasoline. Natural gas processing may also include
amine treating and sulfur recovery units onsite to treat natural gas
streams.
The primary identified HAP emission points at natural gas
processing plants include (1) the glycol dehydration unit reboiler
vent, (2) storage tanks, particularly those tanks that handle volatile
oils and condensates that may be significant contributors to overall
HAP emissions due to flash emissions, and (3) equipment leaks from
those components handling hydrocarbon streams that contain HAP
constituents. Other potential HAP emission point process vents are the
tail gas stream from amine treating processes and sulfur recovery
units. Limited information has been identified on the potential for HAP
emissions from these operations. Recent research published by GRI
indicates that these emission points have the potential to be
significant sources of HAP emissions. Comment is requested on potential
HAP emissions and emission rates from these operations and potential
applicable air emission controls.
4. Natural Gas Transmission and Storage Facilities
The natural gas transmission and storage source category consists
of transmission pipelines used for the long distance transport of
natural gas and underground natural gas storage facilities. These
facilities typically extend from the natural gas processing plant to
the local distribution company that delivers natural gas to the final
end user. In cases where there is no processing, these facilities may
be located anywhere from the well to the final end user.
Specific equipment used in natural gas transmission includes the
land, mains, valves, meters, boosters, regulators, storage vessels,
dehydrators, compressors, and their driving units and appurtenances,
and equipment used for transporting gas from a production plant,
delivery point of purchased gas, gathering system, storage area, or
other wholesale source of gas to one or more distribution area(s).
Underground natural gas storage facilities are subsurface
facilities that store natural gas that has been transferred from its
original location for the primary purpose of load balancing. Load
balancing is the process of equalizing the receipt and delivery of
natural gas (i.e., utilized for stockpiling natural gas for periods of
high demand, in particular, the winter heating season). Processes and
operations that may be located at an underground storage facility
include, but are not limited to, compression and dehydration.
The primary identified HAP emission point at natural gas
transmission and storage facilities is the glycol dehydration unit
reboiler vent.
5. Facility Populations
There are a large number of glycol dehydration units and tank
batteries in the United States. The estimated population of glycol
dehydration units presented in various industry studies range from
under 20,000 to over 45,000 glycol dehydration units.
For the purpose of estimating nationwide impacts of this proposed
NESHAP, the EPA selected 40,000 as the estimated total domestic
population of all types of dehydration units. Of this total, an
estimated 38,000 are glycol dehydration units and 2,000 are solid
desiccant dehydration units.
Based on typical tank battery configurations and two studies
conducted for the API, the EPA estimates that there are approximately
94,000 tank batteries. Of this total, the EPA estimates that there are
81,000 black oil tank batteries and 13,000 condensate tank batteries.
In 1996, according to the Oil and Gas Journal, there were
approximately 700 natural gas processing plants.
The natural gas transmission and storage source category includes
over 480,000 kilometers (300,000 miles) of high-pressure transmission
pipelines and over 300 underground storage facilities. A recent GRI
report estimates that there are 1,900 compressor stations located along
transmission pipelines.
The EPA estimates that approximately 440 existing facilities would
be affected by the proposed requirements of the production NESHAP for
major sources. In addition, the EPA estimates that out of an estimated
37,000 glycol dehydration units at area sources of HAP, 520 existing
TEG dehydration units would be affected by the proposed standards for
area sources because they meet or exceed the throughput and benzene
emission action levels and are also located in counties designated as
urban (see section III of this preamble for a discussion of area source
action levels).
The EPA estimates that about 5 existing facilities would be
affected by the proposed requirements of the natural gas transmission
and storage NESHAP for major sources.
III. Summary of Proposed Standards
A. Proposed Standards for Oil and Natural Gas Production for Major and
Area Sources
The proposed action would amend title 40, chapter I, part 63 of the
Code of Federal Regulations (CFR) by adding a new subpart HH--National
Emission Standards for Hazardous Air Pollutants from Oil and Natural
Gas Production Facilities. The proposed standards would apply to owners
and operators of facilities that process, upgrade, or store (1)
hydrocarbon liquids (with the exception of those facilities that handle
black oil exclusively) to the point of custody transfer and (2) natural
gas from the well up to and including the natural gas processing plant.
Standards are
[[Page 6293]]
proposed that would limit HAP emissions from the following emission
points at facilities that are major sources of HAP (1) process vents on
glycol dehydration units, (2) storage vessels with flash emissions, and
(3) equipment leaks at natural gas processing plants. In addition,
standards are proposed that would limit HAP emissions from selected
area source TEG dehydration units.
As required by the Clean Air Act, the determination of a facility's
potential-to-emit HAP and, therefore, its status as a major or area
source, is based on the total of all HAP emissions from all activities
at a facility, except that emissions from oil or gas exploration or
production wells (and their associated equipment) and emissions from
pipeline compressor or pump stations may not be combined. A definition
of associated equipment is proposed in the proposed rulemaking. Further
discussion of the definition of associated equipment is presented in
section VII(A) of this preamble.
1. General Standards
The proposed standards for oil and natural gas production
facilities would require that the owner or operator of a major source
of HAP reduce HAP emissions from glycol dehydration units and storage
vessels through the application of air emission control equipment or
pollution prevention measures. In addition, the owner or operator of a
natural gas processing plant that is a major source would be required
to reduce HAP emissions from equipment leaks by establishing a leak
detection and repair (LDAR) program.
The owner or operator of selected area source TEG dehydration units
that meet the criteria in the proposed standards would be required to
reduce HAP emissions from those TEG dehydration units.
Owners and operators of facilities that process and store black oil
exclusively would not be subject to the proposed standards. Black oil
is defined in the proposed oil and natural gas production NESHAP as a
hydrocarbon liquid with (1) a GOR less than 50 m\3\ (1,750 ft\3\) per
barrel and (2) an API gravity less than 40 deg..
2. Glycol Dehydration Unit Provisions
The proposed standards would require that all process vents at
glycol dehydration units that are located at major HAP sources be
controlled unless (1) the actual flowrate of natural gas to the glycol
dehydration unit is less than 85 thousand cubic meters per day (m\3\/
day) (3.0 million standard cubic feet per day (MMSCF/D), on an annual
average basis, or (2) if benzene emissions from the major source glycol
dehydration unit are less than 0.9 Mg/yr (1 tpy).
HAP emissions from process vents at certain area source TEG
dehydration units would be required to be controlled unless (1) the
actual flowrate of natural gas to the glycol dehydration unit is less
than 85 thousand m\3\/day (3.0 MMSCF/D), on an annual average basis, or
(2) if benzene emissions from the area source glycol dehydration unit
are less than 0.9 Mg/yr (1 tpy). The proposed requirements are the same
for existing and new (1) major source glycol dehydration units and (2)
selected area source TEG dehydration units that meet the specified
criteria.
In its analysis of available data, the EPA could not determine any
level of emission control for those glycol dehydration units with low
annual natural gas throughputs (less than 85 thousand m\3\/day (3.0
MMSCF/D), on an annual average basis, or a low benzene emission rate
(less than 0.9 Mg/yr (1 tpy)). Thus, the EPA is proposing the annual
throughput and benzene emission rate cutoffs for major sources. In
addition, the EPA's analysis indicated that control of HAP emissions
below these cutoff levels was not cost-effective for area source glycol
dehydration units.
The EPA is proposing an additional applicability criteria for area
source TEG dehydration units. The additional proposed criteria would
limit air emission controls to those selected area source TEG
dehydration units located in counties classified as urban areas.
Since the Act does not provide a definition of urban area, the EPA
used the U.S. Department of Commerce's Bureau of the Census statistical
data to classify every county in the U.S. into one of three
classifications (1) Urban-1 counties, (2) Urban-2 counties, or (3)
Rural counties. Urban-1 counties consist of counties with metropolitan
statistical areas (MSA) with a population greater than 250,000. Urban-2
counties are defined as all other counties designated urban by the
Bureau of Census (areas which comprise one or more central places and
the adjacent densely settled surrounding fringe that together have a
minimum of 50,000 persons). The urban fringe consists of contiguous
territory having a density of at least 1,000 persons per square mile.
Rural counties are those counties not designated as urban by the Bureau
of the Census (see docket item A-94-04, II-I-9).
Figure 1 shows the methodology for assigning counties to each of
the three classifications. As seen in this diagram, if any part of a
county contains an Urban-1 area then the entire county is classified as
an Urban-1 area. For all remaining counties, if greater than 50 percent
of the population is classified as urban, then that county is
classified as an Urban-2 area. Counties not designated as Urban-1 or
Urban-2 by the above method are classified as Rural areas.
BILLING CODE 6560-50-P
[[Page 6294]]
[GRAPHIC] [TIFF OMITTED] TP06FE98.005
BILLING CODE 6560-50-C
Figure 1. Urban/Rural County Classification Methodology
[[Page 6295]]
Thus, only those area source TEG dehydration units that (1) meet or
exceed the actual natural gas throughput applicability criteria, (2)
meet or exceed the benzene emission rate applicability criteria, and
(3) are located in a county classified as either Urban-1 or Urban-2
would be required to apply air emission controls on all process vents
at those units.
The EPA also evaluated a risk-based distance applicability
threshold criterion as an alternative to the urban area applicability
criteria. This method (subsequently referred to as the ``risk-
distance'' method) would target those area source TEG dehydration units
for regulation that present a potential health risk to exposed
populations. Under the risk-distance method, each area source TEG
dehydration unit that may be subject to control, based on actual
natural gas throughput and benzene emission rate, would have the option
of conducting a site-specific risk assessment. If this site-specific
risk assessment resulted in a maximum incremental lifetime cancer risk
above some threshold level, then the source would be required to
install controls necessary to reduce that risk to an acceptable level.
After its evaluation of applicability alternatives, the EPA
rejected the risk-distance method. The risk based approach would focus
solely on the protection of the most exposed individual rather than the
general population. In addition, the EPA believes that the use of the
urban area as an applicability criteria provides ease of
implementation. This approach (1) limits the group of affected sources
to a well defined urban area group, (2) minimizes the non-productive
burden by exempting the non-urban area group of owners-operators and
regulatory agencies from compliance assessments, and (3) provides a
straightforward approach to compliance. Area sources will not need to
perform analyses to determine if they are affected by the rule if they
screen out based on the urban area criteria. Only those owner-operators
of area source TEG dehydration units in urban areas would need to
evaluate the need for control devices. By contrast, under the risk
distance approach, all owner-operators would need to do an analysis.
The EPA is requesting comment, along with supporting documentation, on
the use of a risk-distance criteria for regulation of area source TEG
dehydration units as an alternative to the urban area criteria (see
section X of this preamble).
Glycol dehydration units that are required to use air emission
controls would be required to connect each process vent on the glycol
dehydration unit to an air emission control system that reduces HAP
emissions by 95 percent or greater (or to an outlet concentration of 20
parts per million by volume (ppmv) for combustion devices). Pollution
prevention measures, such as process modifications that reduce the
amount of HAP emissions generated, would be allowed as an alternative,
provided they achieve a HAP emission reduction, from uncontrolled
levels, of 95 percent or greater.
3. Storage Vessel Provisions
Standards are proposed for existing and new storage vessels
containing hydrocarbon liquids (other than black oil) that are located
at major HAP sources. The types of storage vessels that would be
regulated are those with the potential for flash emissions and that
have an actual throughput of hydrocarbon liquids equal to or greater
than 500 barrels per day (BPD).
Flash emissions from storage occur when a hydrocarbon liquid with a
high vapor pressure flows from a pressurized vessel into a vessel with
a lower pressure. Flash emissions typically occur when a hydrocarbon
liquid, such as condensate, is transferred from a production separator
to a storage vessel. The proposed standards for storage vessels with
the potential for flash emissions would require that a storage vessel
be equipped with an air emission control system if the hydrocarbon
liquid in the storage vessel has a GOR equal to or greater than 50 m
\3\ (1,750 ft \3\) per barrel or an API gravity equal to or greater
than 40 deg. (i.e., the storage vessel has a potential for flash
emission losses). In addition, the storage vessel must have an actual
throughput of hydrocarbon liquids equal to or greater than 500 BPD.
A storage vessel containing a hydrocarbon liquid subject to control
under the proposed standards would have to be equipped with a cover
vented through a closed-vent system to a control device that recovers
or destroys HAP emissions with an efficiency of 95 percent or greater
(or to an outlet concentration of 20 ppmv for combustion devices). The
EPA has included the 20 ppmv cutoff for cases where the HAP emission
concentration is already low, and meeting a 95 percent reduction in
emissions cannot be achieved.
A pressurized storage vessel that is designed to operate as a
closed system would be considered in compliance with the proposed
requirements for storage vessels. External and internal floating roofs
that meet certain design criteria would also be allowed.
4. Standards for Equipment Leaks
The proposed rule requires owners and operators of natural gas
processing plants that are major HAP sources to control HAP emissions
from leaks from each piece of equipment that contains or contacts a
liquid or gas that has a total HAP concentration equal to or greater
than 10 percent by weight. The proposed equipment leak standards would
not apply to equipment that operates less than 300 hours per year.
For equipment subject to these standards at either an existing or
new source, the owner or operator is required to implement a LDAR
program and perform equipment modifications, where necessary. Pumps in
light liquid service, valves in gas/vapor and light liquid service, and
pressure relief devices in gas/vapor service within a process unit that
is located on the Alaskan North Slope would be exempt from some of the
routine LDAR monitoring requirements.
5. Air Emission Control Equipment Requirements
Specific performance and operating requirements are proposed for
each control device installed by the owner or operator. Closed-vent
systems would be required to operate with no detectable emissions. Any
type of control device would be allowed that reduces the mass content
of either total organic compounds (less methane and ethane) or total
HAP in the gases vented to the device by 95 percent by weight or
greater (or to an outlet concentration of 20 ppmv for combustion
devices).
Certain specifications for covers apply based on the type of cover
and where the cover is installed. Requirements are specified for vapor
leak-tight covers, and external and internal floating roofs installed
on storage vessels.
6. Test Methods and Procedures
An owner or operator must be able to demonstrate that exemption
from control criteria are met when controls are not applied. For
example, owners or operators of glycol dehydration units that do not
install air emission controls because the benzene emission rate from
the unit is less than 0.9 Mg/yr (1 tpy) must be able to demonstrate
that the benzene emission rate from the unit is less than 0.9 Mg/yr (1
tpy). In general, the selected exemption criteria minimize the
demonstration burden on owners and operators.
Procedures for demonstrating the HAP emission reduction efficiency
of control devices and HAP concentration would be consistent with
procedures established in previously promulgated
[[Page 6296]]
NESHAP that apply to emission sources similar to those addressed in the
proposed standards. Engineering calculations, modeling (using EPA-
approved models), and previous test results will generally be
acceptable means of demonstrating compliance, except where such means
are not conclusive. Test procedures are specified in the proposed rule
for use when testing is required to demonstrate compliance.
An alternative test procedure is provided to demonstrate control
efficiency for when a condenser is used for controlling emissions from
a glycol dehydration unit reboiler vent. The inclusion of the
alternative test procedure is appropriate in this standard because of
difficulties associated with testing the inlet to a condenser in this
application.
Procedures and test methods are also specified for detection of
equipment leaks.
7. Monitoring and Inspection Requirements
The proposed standards would require that the owner or operator
periodically inspect and monitor air emission control equipment. Visual
inspections and leak detection monitoring is required for certain types
of covers to ensure gaskets and seals are in good condition and for
closed-vent systems to ensure all fittings remain leak-tight.
An owner or operator would also be required to visually inspect and
test covers and closed-vent systems to determine and ensure that they
operate with no detectable emissions.
The proposed standards would also require semi-annual inspection
and leak detection monitoring of covers and annual inspection and leak
detection monitoring of closed-vent systems.
The proposed standards would require continuous monitoring of
control device operation through the use of automated instrumentation.
The automated instrumentation would be used to measure and record
control device operating parameters indicating continuous compliance
with the standards.
8. Recordkeeping and Reporting Requirements
The recordkeeping and reporting requirements associated with the
proposed standards would primarily be those specified in the part 63
General Provisions (40 CFR part 63, subpart A). Major sources would be
subject to all of the requirements of the General Provisions with the
exception that (1) owners or operators would be allowed up to one year
from the effective date of the standards to submit the initial
notification described in Sec. 63.9, paragraph (b) of subpart A and (2)
owners or operators are allowed to submit (a) excess emissions and
continuous monitoring system (CMS) performance reports and (b) startup,
shutdown, and malfunction reports semi-annually instead of quarterly.
The EPA selected these specific exceptions due to the large number of
facilities that would need to submit notifications or reports related
to the proposed NESHAP. The EPA believes that these exceptions will not
adversely affect the implementation of the proposed regulation or
reduce its impact on HAP emissions.
Area sources would be subject to all of the requirements of the
General Provisions with the exception that (1) owners or operators of
existing area sources would be allowed up to one year from the
effective date of the standards to submit the initial notification
required by the General Provisions, (2) an owner or operator of an area
source would not be required to develop and maintain a startup,
shutdown, and malfunction plan and would only need to submit reports of
malfunctions when they are not corrected within a specified time
period, and (3) excess emissions and continuous monitoring reporting
would be done annually, rather than as required by the General
Provisions.
B. Proposed Standards for Natural Gas Transmission and Storage for
Major Sources
The proposed standards would amend title 40, chapter I, part 63 CFR
by adding a new subpart HHH--National Emission Standards for Hazardous
Air Pollutants from Natural Gas Transmission and Storage Facilities.
The standards would apply to owners and operators of facilities that
process, upgrade, transport or store natural gas prior to delivery to a
LDC or a final end user.
1. General Standards
The proposed rule would require that process vents on glycol
dehydration units that are located at major HAP sources be controlled
unless (1) the actual flowrate of natural gas to the glycol dehydration
unit is less than 85 thousand m3/day (3.0 MMSCF/D), on an
annual average basis, or (2) if benzene emissions from the major source
glycol dehydration unit are less than 0.9 Mg/yr (1 tpy). The proposed
requirements are the same for existing and new glycol dehydration
units.
Glycol dehydration units that are required to use air emission
controls would be required to connect each process vent on the glycol
dehydration unit to an air emission control system that reduces HAP
emissions by 95 percent or more or to an outlet concentration of 20
ppmv for combustion devices. As with the proposed standards for the oil
and natural gas production NESHAP, pollution prevention measures, such
as process modifications that reduce the amount of HAP emissions
generated, would be allowed as an alternative provided they achieve a
HAP emission reduction of 95 percent or greater or to an outlet
concentration of 20 ppmv for combustion devices.
The EPA had insufficient information available to determine whether
(1) significant HAP-emitting storage vessels warranting control are
located at natural gas transmission and storage facilities or (2)
whether the same storage vessel regulatory controls being proposed for
the oil and natural gas production source category should be applied to
the natural gas transmission and storage source category. Therefore,
the EPA is soliciting comment in this proposal (see section X) on
whether the storage vessels being proposed for control under the oil
and natural gas production regulation are similar to those that exist
at natural gas transmission and storage facilities. The EPA is
specifically requesting information on (1) the type(s) of storage
vessels at natural gas transmission and storage facilities and (2)
whether the existing control level of storage vessels at natural gas
transmission and storage facilities is similar to the existing control
level of storage vessels at oil and natural gas production facilities.
2. Air Emission Control Equipment Requirements
Specific performance and operating requirements are proposed for
each control device installed by the owner or operator. Closed-vent
systems would be required to operate with no detectable emissions. Any
type of control device would be allowed that reduces the mass content
of either total organic compounds (less methane and ethane) or total
HAP in the gases vented to the device by 95 percent by weight or
greater (or to an outlet concentration of 20 ppmv for combustion
devices).
3. Monitoring and Inspection Requirements
The proposed monitoring and inspection requirements are (1)
periodic control equipment monitoring, (2) periodic leak detection
monitoring for closed-vent systems to ensure all fittings remain leak-
tight, (3) semi-annual
[[Page 6297]]
inspection and leak detection monitoring of covers, (4) annual
inspection and leak detection monitoring of closed-vent systems, and
(5) continuous monitoring of control device operation. Continuous
monitoring would require the use of automated instrumentation that
would measure and record control device compliance operating
parameters.
4. Recordkeeping and Reporting Requirements
The recordkeeping and reporting requirements associated with the
proposed standards would primarily be those specified in the part 63
General Provisions (40 CFR Part 63 subpart A). Major sources would be
subject to all of the requirements of the General Provisions, except
that (1) owners or operators would be allowed up to one year from the
effective date of the standards to submit the initial notification
required under Sec. 63.9, paragraph (b) of subpart A and (2) owners or
operators are allowed to submit excess emissions, CMS performance
reports, and startup, shutdown, and malfunction reports semi-annually
instead of quarterly. These exceptions were selected to maintain
consistency between the major source provisions of these proposed
regulations.
IV. Summary of Environmental, Energy and Economic Impacts
A. HAP Emission Reductions
For major sources, it is estimated by the EPA that the proposed oil
and natural gas production standards for existing sources would result
in a reduction of HAP emissions from 39,000 Mg/yr to 9,000 Mg/yr. In
addition, HAP emissions would be reduced by 3,000 Mg/yr for new sources
over the first 3 years after promulgation of these proposed standards.
For existing area source TEG dehydration units in the oil and
natural gas production source category, the EPA estimates that the
proposed standards would result in a reduction of HAP emissions from
19,000 Mg/yr to 16,000 Mg/yr. In addition, HAP emissions would be
reduced by 330 Mg/yr for new sources over the first 3 years after
promulgation of these proposed standards.
Tables 1 and 2 present the major and area source emission
reductions, in addition to other environmental, energy, and cost
impacts, that the EPA estimates would occur from the implementation of
the proposed standards for oil and natural gas production.
The EPA estimates that the proposed natural gas transmission and
storage standards for existing sources would result in a reduction of
HAP emissions from 320 Mg/yr to 210 Mg/yr. No new major sources are
anticipated in the first three years after promulgation of this
proposed NESHAP. Table 3 presents the major source emission reductions,
in addition to other environmental, energy, and cost impacts, that the
EPA estimates would occur from the implementation of the proposed
standards for existing natural gas transmission and storage facilities.
The air emission reductions achieved by these proposed standards,
when combined with the air emission reductions achieved by other
standards mandated by the Act, will accomplish the primary goal of the
Act to
* * * enhance the quality of the Nation's air resources so as to
promote the public health and welfare and the productive capacity of
its population.
Table 1.--Summary of Estimated Environmental, Energy, and Economic
Impacts for the Proposed Oil and Natural Gas Production Standards for
Existing and New Major Sources
------------------------------------------------------------------------
Impact category Existing New
------------------------------------------------------------------------
Estimated number of impacted facilities....... 440 44
Emission reductions (Mg/yr):
HAP....................................... 30,000 3,000
VOC....................................... 61,000 6,100
Methane................................... 7,000 700
Secondary environmental emission increases (Mg/
yr):
Sulfur oxides............................. <1><1 nitrogen="" oxides...........................="" 5=""><1 carbon="" monoxide...........................=""><1><1 energy="" (kilowatt="" hours="" per="" year)..............="" 38,000="" 3,800="" implementation="" costs="" (million="" of="" july="" 1993="" $):="" total="" installed="" capital...................="" 6.5="" 0.7="" total="" annual..............................="" 4.0="" 0.4="" ------------------------------------------------------------------------="" table="" 2.--summary="" of="" estimated="" environmental,="" energy,="" and="" economic="" impacts="" for="" the="" proposed="" oil="" and="" natural="" gas="" production="" standards="" for="" existing="" and="" new="" area="" sources="" ------------------------------------------------------------------------="" impact="" category="" existing="" new="" ------------------------------------------------------------------------="" estimated="" number="" of="" impacted="" facilities.......="" 520="" 52="" emission="" reductions="" (mg/yr):="" hap.......................................="" 3,300="" 330="" voc.......................................="" 7,200="" 720="" methane...................................="" 1,500="" 150="" secondary="" environmental="" emission="" increases="" (mg/="" yr):="" sulfur="" oxides.............................=""><1><1 nitrogen="" oxides...........................="" 2=""><1 carbon="" monoxide...........................=""><1><1 energy="" (kilowatt="" hours="" per="" year)..............="" none="" none="" implementation="" costs="" (million="" of="" july="" 1993="" $):="" total="" installed="" capital...................="" 6.9="" 0.7="" total="" annual..............................="" 6.2="" 0.6="" ------------------------------------------------------------------------="" [[page="" 6298]]="" table="" 3.--summary="" of="" estimated="" environmental,="" energy,="" and="" economic="" impacts="" for="" the="" proposed="" natural="" gas="" transmission="" and="" storage="" standards="" for="" existing="" major="" sources="">a
------------------------------------------------------------------------
Impact category Existing
------------------------------------------------------------------------
Estimated number of impacted facilities.................... 5
Emission reductions (Mg/yr):
HAP.................................................... 110
VOC.................................................... 1,400
Methane................................................ 54
Secondary environmental emission increases (Mg/yr):
Sulfur oxides.......................................... None
Nitrogen oxides........................................ None
Carbon monoxide........................................ None
Energy (Kilowatt hours per year)........................... None
Implementation costs (Thousand of July 1993 $):
Total installed capital................................ 57
Total annual........................................... 46
------------------------------------------------------------------------
a No new major sources are anticipated for this source category after
the effective date for new sources and in the first three years
following promulgation of the proposed rule.
B. Secondary Environmental Impacts
Other environmental impacts are those associated with operation of
certain air emission control devices. The adverse secondary air impacts
would be minimal in comparison to the primary HAP reduction benefits
from the implementation of the proposed control options for major and
for selected area oil and natural gas sources. The estimated national
annual increase in secondary air pollutant emissions that would result
from the use of a flare to comply with the proposed standards is
estimated to be less than 1.0 Mg (1.1 ton) for both sulfur oxide
(SOX) and carbon monoxide (CO) and less than 7 Mg (8 tons)
for nitrogen oxides (NOX). These estimates are for both
major and area oil and natural gas production sources. There are no
anticipated increases in secondary air pollutant emissions from the
implementation of the proposed control options for major sources at
natural gas transmission and storage facilities.
The adverse water impacts anticipated from the implementation of
control options for the proposed standards are expected to be minimal.
The water impacts associated with the installation of a condenser
system for the glycol dehydration unit reboiler vent would be minimal.
This is because the condensed water collected with the hydrocarbon
condensate can be directed back into the system for reprocessing with
the hydrocarbon condensate or, if separated, combined with produced
water for disposal by reinjection.
Similarly, the water impacts associated with installation of a
vapor control system would be minimal. This is because the water vapor
collected along with hydrocarbon vapors in the vapor collection and
redirect system can be directed back into the system for reprocessing
with the hydrocarbon condensate or, if separated, combined with the
produced water for disposal by reinjection.
There are no adverse solid waste impacts anticipated from the
implementation of the proposed standards.
C. Energy Impacts
Energy impacts are those energy requirements associated with the
operation of emission control devices. The annual energy requirements
for each vapor collection/recovery system installed to comply with the
oil and natural gas production proposed standards is estimated to be
300 kilowatt hours per year (kw-hr/yr). It is estimated that
approximately 125 oil and natural gas production major source
facilities would install one or more of these control options. There
would be no national energy demand increase from the operation of any
of the control options analyzed under the proposed oil and natural gas
production standards for area sources and the national energy demand
increase for major sources would be an estimated 38,000 kw-hr/yr.
There would be no national energy demand increase from the
operation of any of the control options analyzed under the proposed
natural gas transmission and storage standards for major sources.
The proposed standards encourage the use of emission controls that
recover hydrocarbon products, such as methane and condensate, that can
be used on-site as fuel or reprocessed, within the production process,
for sale. Thus, the proposed standards have a positive impact
associated with the recovery of non-renewable energy resources.
D. Cost Impacts
The estimated total capital cost to comply with the proposed rule
for major sources in the oil and natural gas production source category
is approximately $6.5 million. The total capital cost for area sources
is estimated to be approximately $6.9 million.
The total estimated net annual cost to industry to comply with the
proposed requirements for major sources in the oil and natural gas
production source category is approximately $4.0 million. The total net
annual cost for area source TEG dehydration units is approximately $6.2
million. These estimated annual costs include (1) the cost of capital,
(2) operating and maintenance costs, (3) the cost of monitoring,
inspection, recordkeeping, and reporting (MIRR), and (4) any associated
product recovery credits.
The estimated total capital cost to comply with the proposed rule
for major sources in the natural gas transmission and storage source
category is approximately $57,000.
The total estimated net annual cost to industry to comply with the
proposed requirements for major sources in the natural gas transmission
and storage source category is approximately $46,000. As with the oil
and natural gas production total estimated annual cost to industry,
this annual cost estimate includes (1) the cost of capital, (2)
operating and maintenance costs, (3) the cost of MIRR, and (4) any
associated product recovery credits.
The EPA's impact analyses consider a facility's ability to handle
collected vapors. Some remotely located facilities may not be able to
use collected vapor for fuel or recycle it back into the process. In
addition, it may not be technically feasible for some facilities to
[[Page 6299]]
utilize the non-condensable vapor streams from condenser systems as an
alternative fuel source safely. An option for these facilities is to
combust these vapors by flaring.
These concerns are reflected in the analyses conducted by the EPA.
In its analyses, the EPA estimated that (1) 45 percent of all impacted
facilities will be able to use collected vapors from installed control
options as an alternative fuel source for an on-site combustion device
such as a process heater or the glycol dehydration unit firebox, (2) 45
percent will be able to recycle collected vapors from installed control
options into a low pressure header system for combination with other
hydrocarbon streams handled at the facility, and (3) 10 percent will
direct all collected vapor to an on-site flare.
E. Economic Impacts
The EPA prepared an economic impact analysis that evaluates the
impacts of the regulation on affected producers, consumers, and
society. The economic analysis focuses on the regulatory effects on the
U.S. natural gas market that is modeled as a national, perfectly
competitive market for a homogenous commodity. The analysis does not
include a model to assess the regulatory effects on the world crude oil
market because the regulation is anticipated to affect less than 5
percent of the total U.S. crude oil production, and thus, it is
unlikely to have any influence on the U.S. supply of crude oil or world
crude oil prices.
The imposition of regulatory costs on the natural gas market result
in negligible changes in natural gas prices, output, employment,
foreign trade, and business closures. Price and output changes as a
result of the regulation are less than 0.01 of one percent, which is
significantly less than observed market trends. For example, between
1992 and 1993 the average change in wellhead price increased by 14
percent, while domestic production rose by 3 percent.
The total annual social cost of the regulation is $10 million for
major and areas sources combined. This value accounts for the
compliance cost imposed on producers, as well as market adjustments
that influence the revenues to producers and consumption by end users,
plus the associated deadweight loss to society of the reallocation of
resources.
V. Area Source Finding
The EPA performed an analysis to determine the potential threat of
adverse effects on human health and the environment due to HAP
emissions from TEG dehydration units in the oil and natural gas
production source category and the feasibility and impacts of
controlling these emissions. The EPA refers to this determination as an
``area source finding.'' The three primary components of an area source
finding are (1) a risk assessment conducted for area source TEG
dehydration units, (2) an evaluation of the technical feasibility and
associated costs of air emission controls, and (3) an assessment of the
economic impacts associated with installation of controls.
The EPA conducted a risk assessment for area source TEG dehydration
units. The detailed risk assessment is available for review in EPA Air
Docket A-94-04 and the item entry number is II-B-20.
The HAP included in the risk assessment were BTEX and n-hexane.
These are the primary HAP emitted by TEG dehydration units. Toluene,
ethyl benzene, and n-hexane were evaluated for potential non-cancer
impacts. The predicted human exposure levels associated with the
estimated emission of these HAP from area source TEG dehydration units
did not meet or exceed the levels of concern when compared to the
available human health reference levels. Mixed xylenes were not
quantitatively analyzed since the EPA does not have an appropriate
human health benchmark for assessing human xylene exposure by the
inhalation pathway.
The predicted exposures associated with the estimated emission of
benzene from area source triethylene glycol dehydration units result in
a maximum individual risk (MIR) of 3 x 10-4 and an annual
cancer incidence ranging from <1 (assuming="" all="" facilities="" are="" located="" in="" rural="" areas)="" to="" 2="" (assuming="" all="" facilities="" are="" located="" in="" urban="" areas).="" the="" predicted="" maximum="" individual="" risk="" from="" this="" analysis="" is="" above="" the="" epa's="" historical="" action="" level="" range="" of="" 1="" x="">-6 to
1 x 10-4.
The types of controls used on TEG dehydration units are able to
achieve a minimum of 95 percent HAP emission reduction. In the parts of
the U.S. where the vast majority of natural gas is produced and
processed, condensers are typically used to reduce emissions from TEG
dehydration units. Flares are also used to reduce emissions from TEG
dehydration units.
Unlike flares, which destroy emissions through combustion,
condensers capture emissions and allow for the recovery of hydrocarbon
liquids (condensate) entrained in the emission stream, thus conserving
a valuable non-renewable resource. Properly operated condensers used at
TEG dehydration units, that have a flash tank in the overall
dehydration system design, have a HAP/volatile organic compound (VOC)
control efficiency of 95 percent.
The application of condensers and flares to area source TEG
dehydration units have been observed on actual operating units that are
typical of those in this industry. Thus, condensers and flares are a
technically feasible and demonstrated control option for area source
TEG dehydration units.
The economic impact analysis performed to evaluate the impacts of
the major and area source provisions of the proposed regulation
supports the area source finding. The results of this economic analysis
are summarized in section IV of this preamble.
The total annual social cost of the regulation is estimated to be
$10 million for major and area sources combined (approximately $4.0
million for major sources and $6.2 million for area sources). This
value accounts for the compliance cost imposed on producers, as well as
market adjustments that influence the revenues to producers and
consumption by end-users, plus the associated deadweight loss to
society of the reallocation of resources.
Regulation of area source TEG dehydration units in the oil and
natural gas production source category is supported by: (1) The
estimated MIR of 3 x 10-4 for HAP emissions from this area
source category, (2) technically feasible, effective, and demonstrated
control options (condensers and flares) that are readily available for
reducing emissions from area source TEG dehydration units, and (3) the
results the economic impact analysis that supports the minimal economic
impact associated with installation of the identified control options.
The EPA is proposing criteria that would target area source TEG
dehydration units for control: (1) Which have benzene emissions, (2)
that can be cost-effectively controlled, and (3) where potential human
exposures are greatest. These criteria are based on actual natural gas
throughput, benzene emission rate, and location in a county classified
as urban.
The actual natural gas throughput (on an annual average basis)
action levels for area source TEG dehydration units analyzed by the EPA
were: (1) 113 thousand m3/day (4.0 MMSCF/D) or greater, (2)
85 thousand m3/day (3.0 MMSCF/D) or greater, (3) 42 thousand
m3/day (1.5 MMSCF/D) or greater, and (4) 8.5 thousand
m3/day (0.3 MMSCF/D) or greater. Based on its evaluation of
projected impacts and the cost-effectiveness of installed controls, the
EPA selected 85 thousand m3/day (3.0 MMSCF/D) actual natural
gas
[[Page 6300]]
throughput as an action level for area source TEG dehydration units.
The EPA also selected an action level for area sources based on
actual benzene emissions from each area source TEG dehydration unit.
Benzene is a known human carcinogen that is typically emitted from
glycol dehydration units.
In addition, the EPA selected location as a criterion for control
based on the county-level urban versus rural location of area source
TEG dehydration units. Only those area source TEG dehydration units
located in counties classified as urban (see section III of this
preamble) and also meeting or exceeding the actual natural gas
throughput and benzene emission rate action levels would be required to
install air emission controls for HAP under the proposed rule.
VI. Glycol Dehydration Unit Nationwide HAP Emissions Estimates
Glycol dehydration units are estimated to account for up to 90
percent of HAP emissions from the oil and natural gas industry. The EPA
used GRI-GLYCalcTM Version 3.0, an emissions estimation
computer program developed by GRI, to estimate HAP emissions from
glycol dehydration units. This program is regarded within industry and
the EPA as an accurate simulation tool for estimating emissions of
organic compounds from glycol dehydration units.
The EPA developed HAP, VOC, and methane emission estimates for a
series of representative model glycol dehydration units representative
of those that operate within this industry. Nationwide emissions were
then estimated by extrapolating from model glycol dehydration unit
estimates.
Two inputs to the methodology used by the EPA to estimate
nationwide HAP emissions from glycol dehydration units that greatly
influence the result are: (1) The average HAP concentration of field
natural gas prior to the first processing stage, and (2) the average
total number of times that natural gas is dehydrated by all dehydration
methods between the wellhead and the end user. Based on extensive
discussions with industry, and review of available information and
application of engineering judgment, the EPA selected a value of 200
ppmv for the average BTEX concentration of field natural gas and a
value of 1.6 for the average number of times that natural gas is
dehydrated by all dehydration methods between the wellhead and the end
user. Estimated HAP emissions from all glycol dehydration units (at
both major and area sources of HAP) are 55,000 Mg/yr.
The EPA acknowledges that there are uncertainties inherent in any
estimate of nationwide HAP emissions for industries as large and as
diverse as the oil and natural gas production or natural gas
transmission and storage source categories. However, the EPA believes
that the engineering judgments and methodology used in developing the
nationwide HAP emissions estimates for these industries are reasonable
given the available information. The EPA requests comment on the
methodology and engineering judgments made when developing the
nationwide glycol dehydration unit HAP emissions estimates for these
source categories. The EPA specifically requests alternative emission
estimation methodologies, supported by documentation demonstrating how
an alternative methodology would yield improved estimates.
VII. Definition of Major Source for the Oil and Natural Gas Industry
A. Definition of ``Associated Equipment''
Whether a facility is a major source or an area source of HAP
emissions under section 112 of the Act is important for two reasons.
First, different requirements may be established for major and area
sources. Second, a source that is a major source under section 112 of
the Act is also subject to requirements for major sources under the
Federal operating permit program authorized by title V of the Act. Area
sources may also be subject to title V permitting requirements, but the
EPA has discretion to defer or waive these requirements.
For some oil and natural gas operations, it is clearly apparent
what constitutes a facility (e.g., a natural gas processing plant). For
others, however, it may not be clear what constitutes a facility. This
is particularly true for field operations in the oil and natural gas
production source category.
An oil or natural gas production field, for example, may cover many
square miles. Within this area, there can be a large number of
production wells, connected by pipeline, to small (satellite) or larger
(centralized) locations, such as tank batteries, where storage or
intermediate processing occurs prior to transmission to further
processing steps. Leasing and mineral rights agreements can give oil
and natural gas companies control over a large area of contiguous
property.
According to the statutory definition in section 112(a)(1), HAP
emissions from all emissions points within a contiguous area and under
common control must be counted in a major source determination. A
strict interpretation of the statutory definition of major source as
applied to this industry could mean that HAP emissions must be
aggregated from emission points separated by considerable distances.
This distance could be well beyond the distances that separate
equipment at a typical facility.
The Congress addressed the unique aspects of the oil and natural
gas production industry in special provisions included in section
112(n)(4) of the Act that apply to HAP emissions from oil and natural
gas wells and pipeline and compressor facilities. Section 112(n)(4)(A)
states
Notwithstanding the provisions of subsection (a), emissions from any
oil or gas exploration or production well (with its associated
equipment) and emissions from any pipeline compressor or pump
station shall not be aggregated with emissions from other similar
units, whether or not such units are in a contiguous area or under
common control, to determine whether such units or stations are
major sources, and in the case of any oil and gas exploration or
production well (with its associated equipment), such emissions
shall not be aggregated for any purpose under this section.
The language in section 112(n)(4)(A) makes it clear that, for the
purpose of implementing standards for major sources under section
112(d) for this industry, HAP emissions from oil and natural gas
exploration and production wells with their associated equipment cannot
be aggregated in making major source determinations.
However, the statutory language provides no definition of
``associated equipment.'' Neither is a clear intent evident in the
legislative history of the Act's 1990 amendments. The legislative
history does indicate that the Congress, in drafting section 112(n)(4),
believed that wells and their associated equipment generally: (1) Have
low HAP emissions, and (2) are typically located in widely dispersed
geographic areas, rather than concentrated in a single area.
A definition of associated equipment is important to implementing
standards for this industry for two reasons. First, because the statute
prevents the aggregation of HAP emissions from wells and their
associated equipment in making major source determinations, the
definition of associated equipment can influence which sources are
subject to requirements for major sources and which are subject to
requirements for area sources. Second, the definition of associated
equipment affects the regulation of area sources in the oil and natural
gas source category. Section 112(n)(4)(B) states
[[Page 6301]]
The Administrator shall not list oil and gas production wells (with
its associated equipment) as an area source under subsection (c),
except that the Administrator may establish an area source category
for oil and gas production wells located in any metropolitan
statistical area with a population in excess of 1 million, if the
Administrator determines that emissions of hazardous air pollutants
from such wells present more than a negligible risk of adverse
effects to public health.
Thus, production wells (with their associated equipment) may not be
regulated as an area source, but production wells as an individual area
source may be regulated by the Administrator under section 112(n)(4)(B)
upon an adverse risk determination.
In the absence of clear guidance in the statute, the EPA considered
options for defining associated equipment. In extensive discussions
with industry and trade association representatives, the EPA evaluated
a wide range of options.
One option considered was a definition based on a narrow
interpretation of associated equipment that would include only limited
equipment in close proximity to a well as associated with that well.
Another option considered was a definition based on a broad
interpretation of associated equipment that would extend the inclusion
of equipment far beyond the well as associated equipment. The initial
options considered by the EPA for defining associated equipment and the
EPA's assessment of each are discussed below.
The narrowest interpretation option would be that a well and its
associated equipment consists of only the well, defined as all
equipment below the ground surface, and the pressure maintenance and
flow control device attached to the well. For an exploratory well, the
typical pressure maintenance and flow control device is the blow out
preventer (BOP). For a production well, the typical pressure
maintenance and flow control device is referred to as the ``Christmas
tree,'' which may include a BOP. This interpretation would provide a
technical meaning to the term associated equipment, but would provide
limited substantive meaning.
As a practical matter, the term ``well with its associated
equipment'' under this option would not provide any additional relief
to industry from the aggregation of HAP emissions in a major source
determination beyond what would have been provided if Congress had only
used the term ``well'' in section 112(n)(4) of the Act. On this basis,
the EPA did not select this narrow interpretation for proposal.
An option initially suggested by industry is that all production
equipment be considered associated equipment. This is the broadest
possible interpretation of the term associated equipment and would
extend the definition to the boundaries of the source category, which
are (1) to the point of custody transfer for hydrocarbon liquids and
(2) to the natural gas transmission and storage source category for
natural gas. Under this interpretation, industry maintains that no
aggregation of HAP emissions should be allowed, even in situations
commonly acknowledged to be a single facility. Only individual emission
points which, by themselves, emit 10 tpy or more of any one HAP or 25
tpy or more of any combination of HAP would be regulated as major
sources under this interpretation.
The EPA rejects this broad interpretation as an option for defining
associated equipment for several reasons. First, an interpretation of
the language in section 112(n)(4) that would define all equipment as
associated with a well, regardless of (1) the type of equipment, (2)
any processing or commingling of streams that may occur, or (3)
distance from the well, would suggest that the Congress intended that
aggregation of HAP emissions not be allowed within this industry under
any circumstances. When viewed within the framework of section 112, the
EPA does not believe this to be the case.
For example, a natural gas processing plant has numerous HAP
emission points closely grouped together. These points may include one
or more glycol dehydration units, condensate storage vessels, several
gas treatment and separation steps, and various containers. These HAP
emission points may emit, in total, HAP in excess of 25 tpy. Each HAP
emission point within the natural gas processing plant, however, may
emit less than 10 tpy of any one HAP or 25 tpy of any combination of
HAP.
If all equipment within the plant were defined as associated
equipment, then the plant would not be considered a major source
subject to MACT standards. It is, therefore, conceivable that the
natural gas processing plant that meets the criteria of a major source
could go unregulated by MACT standards under this scenario, even though
surrounding populations were exposed to HAP emissions at a level that
would trigger the application of MACT standards in other similar
industries.
In addition, this option would include (as associated equipment)
HAP emission points that the EPA has determined are large individual
sources of HAP. In particular, available information indicates that
glycol dehydration units and storage vessels emit substantial
quantities of HAP.
Glycol dehydration units are the largest identified HAP emission
point in the oil and natural gas production source category, accounting
for about 90 percent of estimated total HAP emissions from this source
category based on available information used in the EPA's analysis.
Individually, glycol dehydration units may emit total HAP in amounts
from less than 0.9 Mg/yr to substantially above major source levels.
Also, a single storage vessel with flash emissions may emit several
megagrams of HAP per year.
The EPA firmly believes that glycol dehydration units and storage
vessels with flash emissions are not the type of small HAP emission
points that Congress intended to be included in the definition of
associated equipment. Further, as previously discussed in section V of
this preamble, the EPA has made an area source finding that benzene
emissions from TEG dehydration units pose a significant risk to public
health.
The EPA does not intend to regulate TEG dehydration units that emit
small amounts of HAP. However, the EPA has an obligation to provide
public health protection where there is risk from exposure to HAP
emissions. If TEG dehydration units were included as associated
equipment, the EPA's ability to provide protection to persons at risk
from exposure would be severely limited through section 112(n)(4)(B).
For all the reasons set out above, defining all equipment as
associated equipment was rejected as an option for proposal by the EPA.
However, the EPA believes that the use of custody transfer within an
interpretation (along with other criteria) is a good method for
delineating between equipment that is associated and not associated
with a well.
A variety of interpretations of associated equipment intermediate
of those two extremes are also possible. Through discussions with
industry and trade association representatives, the EPA considered
several intermediate options based on drawing a line of demarcation
downstream from the well. Equipment before this line of demarcation
would be deemed to be associated with a well and equipment beyond the
line would not be considered associated. The point in the processing of
oil or natural gas at which such a line of demarcation could be drawn
might be tied to where a certain product processing or transfer step
takes place.
[[Page 6302]]
Three intermediate options, using this approach, define associated
equipment as including all equipment up to (1) the point where initial
processing of an extracted hydrocarbon stream takes place, (2) the
point of physical commingling of the extracted hydrocarbon stream with
streams from other wells, and (3) the point of custody transfer, with
exceptions for selected affected sources.
The EPA evaluated each of these options with several objectives in
mind. First, the option chosen should provide substantive meaning to
the term associated equipment and prevent the aggregation of small,
scattered HAP emission points in major source determinations. Second,
the option chosen should be easily implementable. That is, it should be
clear to the regulated community and enforcement personnel what is
associated equipment and what is not associated equipment. Finally, the
option chosen should not preclude the aggregation of the most
significant HAP emission points in the source category. Additionally,
the option chosen should not restrict the EPA's ability to regulate
glycol dehydration units as area sources.
An option tied to the point of initial processing would meet only
the last of these objectives. Initial processing for many extracted
hydrocarbon liquid and natural gas streams occurs immediately after the
stream has left the well. Typical processing steps that may occur at a
well site include gas/oil separation, heating/treating, and
dehydration. The only equipment in addition to the Christmas tree that
would be included as associated equipment under this option would be
storage vessels in which no treating or separation takes place.
Thus, little additional relief from HAP emission aggregation would
be provided by an associated equipment definition based on initial
processing. Also, the term ``point of initial processing'' is not a
term commonly used and understood in the source category, a fact that
would likely lead to confusion between enforcement agencies and the
regulated community.
Selecting an option based on the point of physical commingling of
streams would provide additional substantive meaning to the term
associated equipment and possible relief from HAP emission aggregation
in situations where a stream from a single well undergoes processing
prior to mixing with streams from other wells (the storage vessels and
processing equipment would be associated with that well). However, the
EPA sees great potential for confusion under this option, as the same
equipment that would be considered associated equipment at a single
well facility might not be associated equipment where streams from
multiple wells are combined prior to processing.
Another option is the use of the point of custody transfer in
combination with allowing HAP emission aggregation for selected
affected sources. For the proposed production regulation, the EPA
defines custody transfer (which has been previously defined in other
standards) as transfer, after processing and/or treatment in the
producing operations, from storage vessels or automatic transfer
facilities to pipelines or any other forms of transportation. The EPA
considers the point at which natural gas enters a natural gas
processing plant as a point of custody transfer for the proposed
regulation.
From an implementation perspective, this is an attractive option.
According to industry and trade association representatives, the term
custody transfer is commonly used and understood within the oil and
natural gas production source category. Selecting this option would
simplify the owner or operator's regulatory compliance determination
for a specified piece of equipment. The point of custody transfer often
denotes contractually the point of change in ownership of equipment or
product. Therefore, defining associated equipment as all equipment up
to the point of custody transfer is a good approach for delineating a
line of demarcation between equipment that is associated and equipment
that is not associated. This approach is the same as the broadest
interpretation of associated equipment as initially proposed by
industry, however, selected affected sources are not included as
associated equipment.
Glycol dehydration units and storage vessels with flash emissions
are often located before the point of custody transfer. Many glycol
dehydration units, for example, are located on single wells or at
condensate tank batteries. As discussed previously, the EPA feels
strongly that because glycol dehydration units and storage vessels with
flash emissions are significant sources of HAP emissions, they are not
the HAP emission points intended by Congress to be associated equipment
under section 112(n)(4).
Therefore, the EPA is proposing that associated equipment be
defined as all equipment associated with a production well up to the
point of custody transfer, except that glycol dehydration units and
storage vessels with flash emissions would not be associated equipment.
The EPA believes that this proposed definition will provide the relief
that Congress intended in section 112(n)(4) while preserving the EPA's
ability to require appropriate MACT or GACT controls for the most
significant identified HAP emission points in the oil and natural gas
production source category. The EPA considers the point at which
natural gas enters a natural gas processing plant as a point of custody
transfer for natural gas streams and HAP emission aggregation is
allowed at natural gas processing plants. Natural gas processing plants
are included in the scope of the oil and natural gas production NESHAP.
B. Definition of Facility
As discussed in the previous section, it is not clear for many oil
and gas field operations what constitutes a facility and, consequently,
exactly where facility boundaries exist for the purpose of a major
source determination. With many operations connected by pipeline and
located on common oil and gas leases that extend for miles, the meaning
of the phrase, ``located within a contiguous area under common
control,'' used in section 112(a)(1) of the Act to describe sources
that should be grouped in a major source determination, is not often
clear when applied to oil and natural gas field operations. Relief from
the possible need to aggregate emissions from certain small, widely
dispersed, HAP emission sources is provided in the language of section
112(n)(4), and in the EPA's proposed definition of associated
equipment. However, potential for confusion still exists concerning
when non-associated equipment should be aggregated. Thus, the EPA is
proposing further clarification of what constitutes a facility for the
purposes of major source determinations in the oil and natural gas
production and natural gas transmission and storage source categories.
The EPA's objective in developing a definition of facility for this
proposed rulemaking is to identify criteria that would define a
grouping of emission points that meet the intent of the section
112(a)(1) language, ``located within a contiguous area and under common
control,'' but in terms that are meaningful and easily understood
within the regulated industries. Examples of general facility types in
the oil and natural gas production source category include natural gas
processing plants, offshore production platforms, central tank
batteries, satellite tank batteries, and individual well sites.
Compressor stations and underground storage facilities are examples of
[[Page 6303]]
facilities in the natural gas transmission and storage source category.
Though some facilities in the oil and natural gas production source
category, such as natural gas processing plants, fit the profile of a
typical industrial facility and are easy to define, other facilities
(e.g., production field facilities) do not fit the typical profile.
Substantial differences exist between the majority of typical oil and
natural production field operations and traditional industrial
facilities that are regulated under the Act. Industrial facilities
typically have distinct physical boundaries or fencelines. Emission
points at these facilities are generally in close proximity to or
collocated with one another (contiguous) and located within an area
boundary, the entirety of which (other than roads, railroads, etc.) is
under the physical control of the same owner (common ownership).
Typical oil and natural gas production field facilities do not
adhere to this profile. The owners or operators of production field
facilities typically do not own or control the surface property that
lies between two or more production field facilities. Rather, the
owners or operators of production field facilities control only the
surface area that is necessary to operate the physical structures used
in oil and natural gas production. Production facilities may be
connected by underground flow or gathering lines but are essentially
separate independent facilities. Production equipment sharing the same
close physical location (e.g., a well site, tank battery, or graded
pad) is likely to be under common control and in a contiguous area.
However, production equipment that is physically separated within or
across leases (to serve different wells and connected by flow or
gathering lines) is not contiguous based on surface rights and is not
likely to be under common control.
The EPA intends that a facility definition as it applies to the oil
and natural gas production source category should lead to an
aggregation of emissions in a major source determination that is
reasonable, consistent with the intent of the Act, and easily
implementable. In this source category, functionally related equipment
is generally located at what is referred to as the same surface site.
Surface site means the graded pad, gravel pad, foundation, platform, or
immediate physical location on which equipment is located. Defining
facility based on individual surface site would, in the EPA's view,
identify groupings of equipment on which major source determinations
would be made that are consistent with the EPA's intent. For example, a
definition on this basis would require aggregation of emissions from
significant HAP emission sources that are closely grouped, such as two
or more glycol dehydration units on the same graded pad treating a
natural gas stream. Glycol dehydration units located on different
graded pads, for example at separate tank batteries, would presumably
not be functionally related (i.e., the units treat different streams)
and in most cases would be separated by considerable distance.
Consequently, the EPA does not believe it would be reasonable to
combine emissions from these units. Finally, because the term surface
site is well understood within industry and easily recognizable by
enforcement authorities, a facility definition on this basis should be
easily implementable. For these reasons, the EPA is proposing a
facility definition based on individual surface site. For further
clarification, the EPA is also proposing that equipment located on
different oil and gas properties (oil and gas lease, mineral fee tract,
subsurface unit area, surface fee tract, or surface lease track) shall
not be aggregated.
Another objective of the EPA in developing a definition of facility
was to minimize, where possible and reasonable, the burden on owners
and operators in making a major source determination. The EPA's
evaluation of HAP emission sources in production field operations
indicates that the two primary HAP emission points at field operation
facilities are glycol dehydration units and storage tanks with flash
emissions, and that other potential HAP emission points at these
facilities (e.g., equipment leaks) will be inconsequential to the
determination of a facility's major source status. Therefore, the EPA
is proposing that for the purpose of a major source determination, a
production field facility would be limited to glycol dehydration units
and storage tanks with flash emission potential. The EPA believes that
by eliminating the need to quantify HAP emissions from small sources at
such facilities, the burden on an owner or operator to make a major
source determination would be greatly reduced, while still ensuring an
accurate classification of the facility as a major or area source of
HAP emissions.
The EPA specifically requests comments on the proposed definition
of facility. Specifically the EPA requests comments on whether the
proposed definition appropriately implements the intent of the major
source definition in section 112(a)(1) for the oil and natural gas
production and natural gas transmission and storage source categories,
or if another definition would better implement this intent.
VIII. Rationale for Proposed Standards
A. Selection of Hazardous Air Pollutants for Control
The EPA believes that it is not appropriate to select all organic
HAP listed under section 112(b) of the Act for regulation under the
proposed NESHAP. Of the 188 compounds listed, only a limited number are
emitted from oil and natural gas facilities. Consequently, the EPA
developed a list of the specific HAP to be regulated in the proposed
rules. However, all 188 listed HAP must be considered in any major
source determination under the General Provisions to 40 CFR Part 63.
To select which HAP are to be regulated under the proposed NESHAP,
the EPA evaluated the potential for HAP to be emitted from oil and
natural gas facilities. Based on this evaluation, the EPA is proposing
that the following specific HAP be regulated under the proposed NESHAP:
acetaldehyde, benzene (including benzene in gasoline), carbon
disulfide, carbonyl sulfide, ethyl benzene, ethylene glycol,
formaldehyde, n-hexane, naphthalene, toluene, 2,2,4-trimethylpentane
(iso-octane), and mixed xylenes, including o-xylene, m-xylene, and p-
xylene.
The EPA decided to develop a set of control options for this
industry to control HAP emissions as a class rather than developing a
series of control options to control emissions of each individual HAP
on the list. Consequently, the control options considered are directed
towards the control of total HAP emissions.
B. Selection of Emission Points
The EPA identified the primary types of HAP emission points at oil
and natural gas facilities. The three primary HAP emission point types
are (1) process vents, (2) storage vessels, and (3) equipment leaks.
The primary process vent HAP emission point is the glycol
dehydration unit reboiler vent. A glycol dehydration unit reboiler
regenerates glycol used in the dehydration of natural gas by separating
the water from the glycol. The glycol also attracts aromatic compounds,
including BTEX and n-hexane during the dehydration process. These HAP,
along with the water vapor and other gases, are emitted through the
glycol dehydration unit reboiler vent.
In addition, glycol dehydration units may incorporate the use of a
gas condensate glycol separator (GCG separator or flash tank). The rich
glycol,
[[Page 6304]]
which has absorbed water vapor from the natural gas stream, leaves the
bottom of the absorption column of a glycol dehydration unit and is
directed either to (1) GCG separator (flash tank) and then a reboiler
or (2) directly to a reboiler where the water is boiled off the rich
glycol. If the system includes a GCG separator (flash tank), the gas
separated from the rich glycol is typically (1) recycled to the header
system, (2) used for fuel, or (3) used as a stripping gas. The GCG
separator (flash tank) vent is a potential HAP emission point if vented
to the atmosphere.
Other potential HAP emission point process vents are the tail gas
streams from amine treating processes and sulfur recovery units.
Limited data have been identified that indicate the potential for HAP
emissions from these operations. Thus, HAP emissions from amine
treating processes and sulfur recovery units have not been estimated.
Recent research published by GRI indicates that these emission points
have the potential to be significant sources of HAP emissions. Comment
is requested on potential HAP emissions and emission rates from these
operations and potential applicable air emission controls.
Storage vessels have also been identified as a HAP emission point.
Storage vessels used in the oil and natural gas industry include
storage vessels with flash emissions. Storage vessels in the oil and
natural gas production source category are commonly equipped with fixed
roofs. Emissions from fixed-roof storage vessels with flash emissions
are a result of breathing, working, and (primarily) flash losses.
Pipeline pigging and storage of pipeline pigging wastes is a
potential HAP emission point in the transmission sector of the oil and
natural gas industry. Only limited qualitative data have been
identified that indicate the potential for HAP emissions from this
operation. Thus, HAP emissions have not been estimated. Comment is
requested on potential HAP emissions from storage of pipeline pigging
wastes and potential applicable emission controls.
Valves, pump seals, and other pieces of equipment servicing HAP-
containing streams have the potential to leak. A majority of facilities
in the oil and natural gas industry do not have LDAR programs.
Therefore, equipment leaks from that equipment servicing HAP-containing
streams have been identified as a potential HAP emission point.
In addition to the above HAP emission points, the EPA evaluated the
potential regulation of other HAP emission points. These included (1)
containers, (2) equipment leaks at tank batteries and offshore
production platforms, (3) production surface impoundments, and (4)
waste and wastewater management units.
Insufficient data were submitted in the Air Emissions Survey
Questionnaire responses for the other potential HAP emission points of
containers, equipment leaks at tank batteries and offshore production
platforms, production surface impoundments, and waste and wastewater
management units to allow for determination of existing control levels.
Thus, a review of other data sources was conducted to identify
information on existing control levels for these potential HAP emission
points.
For these other HAP emission points, the review of available
information did not indicate any apparent pattern of existing emission
controls. Thus, it has been determined that the existing level of
control for this collection of other HAP emission points is no control.
C. Definition of Affected Source
The term affected source is used in part 63 regulations to
designate the emission sources or group of sources that are regulated
by a standard. Each standard must define what the affected source is
for purposes of that specific standard.
The EPA has discretion to establish a narrow or broad definition of
affected source, as appropriate for a particular rule. A broad
definition would be in terms of groups of equipment. A narrow
definition would designate specific pieces of equipment or emission
points as separate affected sources.
For the proposed oil and natural gas production and natural gas
transmission and storage NESHAPs, a narrow definition of affected
source is proposed for most HAP emission points. The affected sources
under the oil and natural gas production NESHAP include (1) each glycol
dehydration unit located at a major source of HAP, (2) each TEG
dehydration unit located at an area source of HAP, and (3) each storage
vessel with flash emissions located at a major source of HAP.
For the proposed standards for equipment leaks at natural gas
processing plants, the EPA is proposing a broad definition of affected
source. Specifically, the group of equipment targeted by fugitive
emission standards (pumps, pressure relief devices, valves, flanges,
etc. that operate in organic HAP service) are designated as one
affected source, except that compressors would each be a separate
affected source. The implication of this broader definition is that the
replacement of an individual component, such as a valve, would not be
considered the construction of a new affected source, which triggers
reporting requirements for new sources.
The affected source under the natural gas transmission and storage
NESHAP is each glycol dehydration unit located at a major source of
HAP.
D. Determination of MACT Floor
As described in this preamble, the Act defines a minimum level of
control for standards established under section 112(d), referred to as
the MACT floor. For a source category with 30 or more sources, such as
with the oil and natural gas production and natural gas transmission
and storage source categories, the MACT floor for existing sources
shall not be less stringent than the average emission limitation
achieved in practice by the best performing 12 percent of existing
sources. Standards more stringent than the floor may be established
based on a consideration of cost, environmental, energy, and other
impacts.
The EPA is to establish standards based on available information.
Available information for the MACT floor analysis for these source
categories consists primarily of data gathered from industry responses
to survey questionnaires. The surveys were designed to collect
information representative of processes and operations in these source
categories.
1. MACT Floor for Existing Sources
Oil and Natural Gas Production-Glycol Dehydration Unit Vents;
Natural Gas Transmission and Storage-Glycol Dehydration Unit Vents. The
MACT floor for all process vents at glycol dehydration units (including
area source TEG dehydration units in the oil and natural gas production
source category) is 95 percent HAP emission reduction, which correlates
with the existing control level estimated to be achieved through the
use of condensers.
Oil and Natural Gas Production-Storage Vessels. The MACT floor for
existing storage vessels containing material with a GOR equal to or
greater than 50 m \3\ (1,750 ft \3\) per barrel or an API gravity equal
to or greater than 40 deg. and an actual throughput equal to or greater
than 500 BPD (i.e., storage vessel with flash emissions) is the
installation and operation of a cover that is connected through a
closed-vent system to a 95 percent efficient control device. A
pressurized storage vessel that is designed to operate as a closed
system is considered in compliance with the requirements for storage
vessels.
[[Page 6305]]
Oil and Natural Gas Production-Equipment Leaks. The MACT floor
levels for equipment leaks apply only to those components at natural
gas processing plants handling material with a total HAP content equal
to or greater than 10 percent by weight.
The MACT floor for equipment leaks at natural gas processing plants
is judged to be at the new source performance standard (NSPS) level of
control for natural gas processing plants. The NSPS level of control is
equal to that of 40 CFR part 61, subpart V (equipment leaks NESHAP).
Since the pollutants targeted for control under the proposed standards
are HAP, the proposed standards cross-reference the requirements from
the equipment leaks NESHAP.
The proposed standards require monthly monitoring of equipment with
a leak definition of 10,000 ppmv VOC. Based on the component counts and
other characteristics of the model natural gas processing plants, it is
estimated that the NESHAP LDAR program would attain a 70 percent HAP
emission reduction from uncontrolled cases. The proposed standards
allow existing natural gas processing plants subject to the NSPS to
comply only with those requirements.
2. MACT Floor for New Sources
In the review of available information, the EPA did not identify a
method of control applicable to all types of new sources that would
achieve a greater level of HAP emission reduction than the MACT floor
for existing sources. Therefore, the MACT floor for new sources in the
oil and natural gas production and natural gas transmission and storage
source categories is the same as the MACT floor for existing sources.
E. Oil and Natural Gas Production NESHAP-Regulatory Alternatives for
Existing and New Major Sources
The EPA evaluated two regulatory alternatives for existing and new
major sources in the oil and natural gas production source category.
The first regulatory alternative is the MACT floor levels for the
identified HAP emission points. A second regulatory alternative was
evaluated that included the installation of combustion control systems
for process vents and storage tanks at all impacted major sources.
Combustion systems typically have a control efficiency of 98 percent,
or greater, as compared with the control systems in Regulatory
Alternative 1, which achieve an emission reduction efficiency of 95
percent.
Regulatory Alternative 1 (MACT floor) would achieve a nationwide
decrease in HAP emissions from all HAP emission points at major sources
of approximately 77 percent. In the EPA's judgement, the costs (and the
associated cost-effectiveness) of going beyond the floor would be
greatly disproportional to the additional HAP emission reduction that
would be achieved. The costs and average and incremental cost-
effectiveness of the two regulatory alternatives are presented in Table
4. Based on this and other information, the EPA selected Regulatory
Alternative 1 (MACT floor) as the basis for the proposed standards. In
addition, the EPA did not select Regulatory Alternative 2 since the
control options evaluated (combustion systems) involved the destruction
of a recoverable non-renewable resource and did not encourage the
application of pollution prevention techniques.
Table 4.--Comparison of Regulatory Alternative Cost Impacts for the
Proposed Oil and Natural Gas Production Standards--Major Source
Provisions
------------------------------------------------------------------------
Regulatory alternative
Cost category --------------------------------
1 (MACT floor) 2
------------------------------------------------------------------------
Implementation costs (Million of July
1993 $):
Total installed capital............ 6.5 18
Total annual....................... 4.0 23
Cost-effectiveness ($/Megagram HAP):
Average............................ 130 740
Incremental........................ ............... 19,000
------------------------------------------------------------------------
These standards would impact those glycol dehydration units, at
major sources, with an actual natural gas throughput equal to or
greater than 85 thousand m\3\/day (3.0 MMSCF/D), on an annual average
basis, unless it is demonstrated that benzene emissions from the unit
were less than 0.9 Mg/yr (1 tpy).
F. Oil and Natural Gas Production NESHAP-Regulatory Alternatives for
Existing and New Area Sources
The EPA evaluated four regulatory alternatives for TEG dehydration
units at existing and new area sources at oil and natural gas
production sources. Each regulatory alternative is characterized in
terms of an action level, above which HAP emissions must be controlled.
The action levels considered are expressed as the actual annual average
flow rate of natural gas (in thousand m\3\/day (MMSCF/D)) to the TEG
dehydration unit. The action levels for the regulatory alternatives are
(1) 113 thousand m\3\/day (4.0 MMSCF/D) or greater, (2) 85 thousand
m\3\/day (3.0 MMSCF/D) or greater, (3) 42 thousand m\3\/day (1.5 MMSCF/
D) or greater, and (4) 8.5 thousand m\3\/day (0.3 MMSCF/D) or greater.
Based on an evaluation of the projected action level impacts and
costs-effectiveness, the EPA selected Regulatory Alternative 2 as
representative of GACT for TEG dehydration units at area sources of
HAP. Alternative 2 would impact those TEG dehydration units with an
actual natural gas throughput equal to or greater than 85 thousand
m\3\/day (3.0 MMSCF/D), on an annual average basis, unless it is
demonstrated that benzene emissions from the unit were less than 0.9
Mg/yr (1 tpy).
It is the objective of the EPA to structure the rules for area
sources in a way that protects exposed populations. The EPA also needs
to minimize the cost to industry to control units where there would be
less human exposure and overall cancer incidence from exposure to HAP
emissions from area source TEG dehydration units.
Therefore, the EPA is proposing a criterion that no unit would have
to be controlled if it is demonstrated that emissions of benzene from
the unit are less than 0.9 Mg/yr (1 tpy), either uncontrolled or with
controls in place under federally enforceable limits. As noted
previously, benzene is a known human carcinogen that is typically
emitted from TEG dehydration units.
[[Page 6306]]
The EPA is also proposing the use of a population-based action
level in conjunction with the actual natural gas throughput and benzene
emission rate action levels for area source TEG dehydration units. The
EPA selected an action level based on the county-level urban versus
rural location of area source TEG dehydration units. Only those
selected area source TEG dehydration units located in counties
classified as urban (see section III of this preamble) and also meeting
or exceeding the actual natural gas throughput and benzene emission
rate action levels will be required to install air emission controls on
all process vents.
G. Natural Gas and Transmission NESHAP-Regulatory Alternatives for
Existing and New Major Sources
The EPA evaluated two regulatory alternatives for existing and new
major sources in the natural gas transmission and storage source
category. The first regulatory alternative is the MACT floor level for
all process vents at glycol dehydration units. A second regulatory
alternative was evaluated that included the installation of combustion
control systems for process vents at all impacted major sources.
Combustion systems typically have a control efficiency of 98 percent,
or greater, as compared with the control systems in Regulatory
Alternative 1 which achieve an emission reduction efficiency of 95
percent.
Regulatory Alternative 1 (MACT floor) would achieve a nationwide
decrease in HAP emissions from major sources of approximately 95
percent. The costs and the associated cost-effectiveness of going
beyond the floor would be greatly disproportional to the additional HAP
emission reduction that would be achieved. The costs and average and
incremental cost-effectiveness of the two regulatory alternatives are
presented in Table 5. Based on this and other information, the EPA
selected Regulatory Alternative 1 (MACT floor) as the basis for the
proposed standards. In addition, the EPA did not select Regulatory
Alternative 2 since the control options evaluated (combustion systems)
involved the destruction of a recoverable non-renewable resource and
did not encourage the application of pollution prevention techniques.
Table 5.--Comparison of Regulatory Alternative Cost Impacts for the
Proposed Natural Gas Transmission and Storage Standards
------------------------------------------------------------------------
Regulatory alternative
Cost category -------------------------------
1 (MACT floor) 2
------------------------------------------------------------------------
Implementation costs (Thousand of July
1993 $):
Total installed capital............. 57 230
Total annual 46 250
Cost-effectiveness ($/Megagram HAP):
Average............................. 420 2,100
Incremental......................... .............. 20,000
------------------------------------------------------------------------
H. Selection of Format
Section 112(d) of the Act requires that emission standards for
control of HAP be prescribed unless, in the judgement of the
Administrator, it is not feasible to prescribe or enforce emission
standards. Section 112(h) identifies two conditions under which it is
not considered feasible to prescribe or enforce emission standards.
These conditions include (1) if the HAP cannot be emitted through a
conveyance device or (2) if the application of measurement methodology
to a particular class of sources is not practicable due to
technological or economic limitations. If emission standards are not
feasible to prescribe or enforce, then the Administrator may instead
promulgate equipment, work practice, design or operational standards,
or a combination thereof.
Formats for emission standards include (1) percent reduction, (2)
concentration limits, or (3) a mass emission limit. For the proposed
NESHAPs, standards solely expressed as a percent, concentration, or
mass emission reduction would not alone appropriately reflect the
technologies on which the proposed standards are based and ensure that
the intended emissions reductions are achieved. Therefore, the proposed
standards are a combination of (1) emission standards and (2)
equipment, design, work practice, and operational standards.
The format chosen for glycol dehydration unit (including area
source TEG dehydration units subject to the proposed oil and natural
gas production NESHAP) process vent streams is a HAP weight-percent
reduction requirement that applies to the control device. A weight-
percent reduction format is appropriate for streams with HAP
concentrations above 1,000 ppmv because such a format ensures the 95
percent control level requirement. The format for the proposed storage
vessel provisions is a combination of a weight-percent reduction and
inspection, repair, and work practice requirements. The inspection,
repair, and work practice requirements are necessary to ensure the
proper operation and integrity of control equipment.
For equipment leak sources, such as pumps and valves, the EPA has
previously determined that it is not feasible to prescribe or enforce
emission standards. Except for those items of equipment for which
standards can be set at a specific concentration. The only method of
measuring emissions is total enclosure of individual items of
equipment, collection of emissions for a specified time period, and
measurement of the emissions. This procedure, known as bagging, is a
time-consuming and prohibitively expensive technique considering the
great number of individual items of equipment in a typical process
unit.
The proposed standards for equipment leaks at natural gas
processing plants incorporate several formats, including equipment,
design, base performance levels, work practices, and operational
practices. The proposed formats are the same as for the natural gas
processing plant (on-shore) NSPS and the 40 CFR part 61, subpart V
equipment leaks (fugitive emissions) NESHAP.
I. Selection of Test Methods and Procedures
Test methods and procedures specified in the proposed standards
[[Page 6307]]
would be used to demonstrate compliance. Procedures and methods
included in the proposed standards are, where appropriate, based on
procedures and methods previously developed by the EPA for use in
implementing standards for sources similar to those being proposed for
regulation. Methods and procedures are included to determine the
following (1) no detectable emissions, (2) volatile organic HAP (VOHAP)
concentration, (3) control device performance (i.e., control-
efficiency), and (4) annual average flow rate of field natural gas to a
glycol dehydration unit.
J. Selection of Monitoring and Inspection Requirements
Control devices used to comply with the proposed standards need to
be properly operated and maintained if the standards are to be achieved
on a long-term basis. The EPA considered two monitoring options for
these NESHAPs (1) the use of CMS and (2) the use of monitors that
measure operating parameters that can be directly related to the
emission control performance of a particular control device.
The CMS that use gas chromatography to measure individual gaseous
organic HAP compound chemicals are not practical for applications where
multiple organic HAP chemicals are to be monitored, as is typical with
oil and natural gas production and natural gas transmission and storage
facilities.
An alternative is to use a CMS to measure total VOC or total
hydrocarbons (THC) as a surrogate for total organic HAP. These CMS,
however, provide a measure of the relative concentration level of a
mixture of organic chemicals, rather than a quantified level of the
organic species present.
Based on these reasons, the EPA rejected requiring the use of CMS
for the proposed NESHAPs. Instead, the EPA selected monitoring of
control device operating parameters indicative of air emission control
performance as the appropriate approach to monitoring.
The proposed NESHAPs specify the types of parameters that can be
monitored for common types of control devices. These parameters were
selected because they are good indicators of control device performance
and because continuous parameter monitoring instrumentation is
available at a reasonable cost. An owner or operator could be approved,
on a case-by-case basis, to monitor parameters not specifically listed
in the proposed standards.
The established operating parameters for each control device will
be incorporated in the operating permit issued for a facility (or, in
the absence of an operating permit, the established levels will be
directly enforceable) and will be used to determine a facility's
compliance status. Excursions outside the established operating
parameter values will be considered violations of the applicable
emission standards, except when the excursion is caused by a startup,
shutdown, or malfunction that meets the criteria specified in the part
63 General Provisions (40 CFR part 63 subpart A).
Continuous monitoring is not feasible for those emission points
required to comply with certain equipment standards and work practice
standards (e.g., storage vessels equipped with only covers, pumps and
valves subject to LDAR programs). In such cases, failure to install and
maintain the required equipment or properly implement the LDAR program
constitutes a violation of the applicable equipment or work practice
standards.
The owner or operator of a glycol dehydration unit that does not
install controls would be required to install a flow monitor to
demonstrate that the actual natural gas flow rate to the unit is less
than the action level of 85 thousand m\3\/day (3.0 MMSCF/D), on an
annual average basis. If a flow monitor is installed, it must have an
accuracy of within 2 percent.
K. Selection of Recordkeeping and Reporting Requirements
The EPA may require an owner or operator of a source to establish
and maintain records and prepare and submit notifications and reports.
General recordkeeping and reporting requirements for all NESHAP are
specified in the part 63 General Provisions (40 CFR 63.9 and 40 CFR
63.10).
The proposed standards would require sources to submit (1) initial
notification reports, (2) notification of compliance status reports,
and (3) other periodic reports (e.g., startup, shutdown and malfunction
report, excess emissions report, CMS performance test report).
All recordkeeping and reporting requirements proposed for major
sources are consistent with the General Provision requirements, except
that (1) the initial notification would not be due for a year and (2)
the startup, shutdown and malfunction report, excess emissions report,
and CMS performance test report would be required semi-annually rather
than quarterly unless otherwise specified by the State regulatory
authority.
The EPA is proposing fewer recordkeeping and reporting requirements
for oil and natural gas production area sources. Specifically, the
owners and operators of applicable area sources are not subject to (1)
the requirements in Sec. 63.6, paragraph (e) of the General Provisions
for developing and maintaining a startup, shutdown, and malfunction
plan or (2) the requirements in Sec. 63.10, paragraph (d) for reporting
actions consistent with the plan. The owners and operators of
applicable area sources are required to submit a report identifying
occurrences of startup, shutdown, or malfunction when these events
happen or are anticipated to happen.
Further, the periodic excess emissions reports and summary reports,
as described in Sec. 63.10 paragraph (e)(3) of the General Provisions,
are required on a less frequent basis than for major sources. For area
sources, these reports are required annually (i.e., major sources need
to submit these reports semi-annually). This was done to reduce the
recordkeeping and reporting burden on owners and operators of affected
facilities.
IX. Relationship to Other Standards and Programs under the Act
A. Relationship to the Part 70 and Part 71 Permit Programs
Under title V of the Act, the EPA established a permitting program
(part 70 and part 71 permitting program) that requires all owners and
operators of HAP-emitting sources to obtain an operating permit (57 FR
32251, July 21, 1992). Sources subject to the permitting program (i.e.,
oil and natural gas production and natural gas transmission and storage
sources) are required to submit complete permit applications within a
year after a State program is approved by the EPA or, where a State
program is not approved, within a year after a program is promulgated
by the EPA. If the State where the facility is located does not have an
approved permitting program, the owner or operator of a facility must
submit the application to the EPA Regional Office in accordance with
the requirements of the part 63 General Provisions (40 CFR 63 subpart
A).
In addition, section 502(a) of the Act expressly gives the
Administrator the discretion to exempt one or more area source
categories (in whole or in part) from the requirement to obtain a
permit under 42 U.S.C. 7661a(a).
* * * if the Administrator finds that compliance with such
requirements is impracticable, infeasible, or unnecessarily
burdensome on such categories.
[[Page 6308]]
One critical factor that the EPA considers as part of the
``unnecessarily burdensome'' criteria is the degree to which the
standard is implementable outside of a permit, such that the permit
would provide minimal additional benefit with regard to source-specific
tailoring of the standards.
All area source TEG dehydration units impacted by the provisions of
the proposed standards must (1) comply with the compliance schedule
within the rule, (2) perform monitoring of the required parameters for
ensuring compliance, and (3) follow the limited recordkeeping and
reporting requirements. Therefore, the primary goal of significant
reductions in HAP emissions, particularly BTEX and n-hexane, would be
achieved, regardless of whether a permit is required. Unless otherwise
required by the State, the owner or operator of an area source subject
to the proposed standards is not required to obtain a permit under part
70 of title 40 CFR.
B. Relationship Between the Oil and Natural Gas Production and the
Organic Liquids Distribution (Non-Gasoline) Source Categories
The EPA believes that a clear applicability demarcation is
necessary to distinguish those sources that would be subject to the
proposed oil and natural gas production NESHAP and those that would be
subject to the organic liquids distribution (non-gasoline) NESHAP,
which is scheduled for promulgation by the year 2000.
The proposed standards for the oil and natural gas production
source category identify the source category and applicability as
including facilities up to the point of custody transfer. The EPA
intends to define the organic liquids distribution (non-gasoline)
source category as including those facilities that handle and
distribute organic liquids (non-gasoline) from the point of custody
transfer.
C. Relationship of Proposed Standards to the Pollution Prevention Act
The Congress passed and the President signed into law the Pollution
Prevention Act of 1990 (PPA) making pollution prevention a national
policy. Section 6602(b) identifies an environmental management
hierarchy in which pollution
* * * should be prevented or reduced whenever feasible; pollution
that cannot be prevented should be recycled in an environmentally
safe manner, whenever feasible; pollution that cannot be prevented
or recycled should be treated in an environmentally safe manner,
whenever feasible; and disposal or other releases into the
environment should be employed only as a last resort * * *
In short, preventing pollution before it is created is preferable to
trying to manage, treat or dispose of it after it is created.
According to PPA section 6603, source reduction is defined as
reducing the generation and release of hazardous substances,
pollutants, wastes, contaminants or residuals at the source, usually
within a process. The term includes equipment or technology
modifications, process or procedure modifications, reformulation or
redesign of products, substitution of raw materials, and improvements
in housekeeping, maintenance, training, or inventory control. Source
reduction does not include any practice that alters the physical,
chemical, or biological characteristics or the volume of a hazardous
substance, pollutant, or contaminant through a process or activity that
is not integral to or necessary for producing a product or providing a
service.
Pertaining to these proposals, section 6604(b)(2) of the PPA
directs the EPA to, among other things,
* * * review regulations of the Agency prior and subsequent to their
proposal to determine their effect on source reduction.
The EPA believes that these proposed standards are consistent with the
purpose of the Clean Air Act's requirement to consider source reduction
technologies. The EPA's emphasis on source reduction hierarchy is also
entirely consistent with the Act, particularly the air toxics provision
(section 112) that requires the maximum achievable emission reductions
through measures that
* * * reduce the volume of, or eliminate emissions of, such
pollutants through process changes, substitution of materials or
other modifications; * * *
In the proposed standards, the EPA has incorporated the application of
the environmental source reduction management hierarchy. These proposed
standards encourage source reduction by (1) control of HAP air
emissions through the use of condensers and vapor collection/recovery
systems and (2) allowing for the use of system optimization on glycol
dehydration units through the adjustment of the glycol circulation
rate. This adjustment may significantly reduce related HAP emissions
because, on average, the glycol circulation rate is double the
necessary rate.
D. Relationship of Proposed Standards to the Natural Gas STAR Program
The Natural Gas STAR Program is a voluntary, cooperative program
between the EPA and the natural gas industry to promote cost-effective
methods for reducing methane emissions. The program, part of the U.S.
Climate Change Action Plan, outlines a set of initiatives that will
enable the profitable reduction of greenhouse gas emissions. The first
phase of the program was initiated in 1993 with companies in the
natural gas transmission and distribution industry. The 38 partner
companies are currently capturing 36.8 million m\3\ (1.3 billion ft\3\
(bcf)) of methane annually, worth almost $3 million.
The natural gas production industry program was initiated in 1995.
When fully implemented in the year 2000, Natural Gas STAR companies are
projected to recover more than 710 million m\3\ (25 bcf) of methane
annually, worth an estimated $50 million.
Under this program, partners agree to implement two best management
practices (BMPs) when cost-effective. These include (1) identifying and
replacing high-bleed pneumatic devices and (2) installing GCG
separators (flash tank separators) on glycol dehydration units and
recovering the separated methane stream. Additionally, the EPA has
agreed to assist partner companies in the removal of unjustified
regulatory barriers to implementing these practices.
The standards proposed for the oil and natural gas production and
natural gas transmission and storage source categories do not create
regulatory barriers to implementing the BMPs encouraged under this
program. The control requirements for glycol dehydration units at major
sources and selected area sources would require control of the flash
tank separator vent, if present. This would encourage further product
recovery and reduction of HAP and methane air emissions and enhance the
product recovery and emission reduction goals of the Natural Gas STAR
Program.
E. Overlapping Regulations
The proposed standards clarify the applicability of 40 CFR part 63,
subpart HH (oil and natural gas production NESHAP) equipment leak
provisions by stating that existing oil and natural gas production
sources subject to subpart HH and 40 CFR part 60, subpart KKK (onshore
natural gas processing plants NSPS) are required only to comply with
subpart KKK.
[[Page 6309]]
X. Solicitation of Comments
Comments are specifically requested on several aspects of the
proposed standards. These topics are summarized below.
A. Potential-to-Emit
The EPA is currently in the process of developing a separate
rulemaking to address several potential-to-emit (PTE) issues. Until the
EPA takes final action on the proposal, any determination of PTE made
to determine a facility's applicability status under a relevant part 63
standard should be made according to requirements set forth in the
relevant standard and in the General Provisions.
Industry representatives have commented that both oil and natural
gas production and natural gas transmission and storage facilities
often have a maximum capacity (based on physical and operational
design) to emit higher than inherent physical limitations would allow.
Concern was expressed that potential emissions could be overestimated
and a facility could be subject to the Act requirements affecting major
sources despite inherent limitations (e.g., depletion of oil and
natural gas reservoirs).
The EPA is committed to providing technical assistance on the type
of inherent physical and operational design features that may be
considered acceptable in determining the PTE for certain source
categories. Therefore, the EPA is evaluating and solicits specific
recommendations, along with supporting documentation, on how inherent
limitations should be addressed for oil and natural gas production and
natural gas transmission and storage facilities.
B. Definition of Facility
The EPA specifically requests comments on the proposed definition
of facility. Specifically, the EPA requests comments on whether the
proposed definition appropriately implements the intent of the major
source definition in section 112(a)(1) for the oil and natural gas
production and natural gas transmission and storage source categories,
or if another definition would better implement this intent.
C. Interpretation of ``Associated Equipment'' in Section 112(n)(4) of
the Act
As discussed in section V of this preamble, the EPA has proposed a
definition for the term ``associated equipment'' to implement the
special provisions of section 112(n)(4) of the Act for the oil and
natural gas production source category. Comments are specifically
requested on the EPA's proposed definition.
If there is disagreement with the EPA's proposed definition, the
EPA requests that the commenter provide alternative definition options,
along with supporting documentation, that would provide the relief
intended by Congress for this industry while preserving the EPA's
ability to regulate HAP emissions from glycol dehydration units,
storage vessels with flash emissions, and equipment leaks.
D. Regulation of Area Source Glycol Dehydration Units
The EPA does not intend to regulate TEG dehydration units that have
low HAP emissions or units in areas where there is little or no
potential threat of adverse health effects from exposure to HAP
emissions from TEG dehydration units. The rules, as proposed, include
applicability cutoffs of (1) 85 thousand m\3\/day (3.0 MMSCF/D) of flow
to the unit, on an annual average basis, or (2) 0.9 Mg/yr (1 tpy) of
benzene emissions.
The EPA is proposing an additional action level based on the
county-level urban versus rural location of area source TEG dehydration
units. Thus, only those selected area source TEG dehydration units
located in counties classified as urban (see section III of this
preamble) and also meeting or exceeding the actual natural gas
throughput and benzene emission rate action levels will be required to
install air emission controls on all process vents. Units (1) below
these cutoffs or (2) located in counties classified as rural would not
have to be controlled for HAP emissions under the proposed rules.
The EPA evaluated the use of a risk-distance applicability criteria
as an alternative to the urban area criteria. The EPA is requesting
comment, along with supporting documentation, on the use of a risk-
distance applicability criteria for focussing the area source
provisions of this proposed regulation to only those area source TEG
dehydration units that meet a risk-distance criteria for applicability.
TEG dehydration units located at natural gas transmission and
storage facilities emit similar emissions and have a similar emission
potential to those located at oil and natural gas production
facilities. However, insufficient information was available to conduct
an area source finding analysis for the natural gas transmission and
storage source category.
The EPA is currently evaluating whether TEG dehydration units
located at natural gas transmission and storage area sources result in
an unacceptable risk and should be listed and regulated as an area
source. The EPA is soliciting comment, along with supporting
documentation, in this notice on the emissions, location, and number of
TEG dehydration units located at natural gas transmission and storage
area sources. Information supplied to the EPA should either support or
negate the need for an area source listing.
E. HAP Emission Points
The EPA specifically requests information on potential HAP
emissions that may be associated with (1) process vents at amine
treating units and sulfur plants, (2) transfer and storage of pipeline
pigging wastes, and (3) combustion sources located at oil and natural
gas production and natural gas transmission and storage facilities. The
EPA has not identified sufficient data to adequately address the
potential of HAP emissions from these emission points in these source
categories. Thus, the EPA is requesting comment, along with supporting
documentation, on HAP emissions from these emission points.
F. Storage Vessels at Natural Gas Transmission and Storage Facilities
The EPA had insufficient information to determine whether
significant HAP-emitting storage vessels warranting control are located
at natural gas transmission and storage facilities that are major
sources of HAP. Therefore, the EPA is soliciting information and
comment, along with supporting documentation, regarding the storage
vessels located at these sources.
Specifically, the EPA is requesting information and comment, along
with supporting documentation, on whether the storage vessels currently
being proposed for control under the oil and natural gas production
NESHAP are similar to those located at natural gas transmission and
storage facilities.
G. Cost Impact and Production Recovery Credits
The EPA specifically requests comments on the cost impact and the
production recovery credits as discussed in section IV of the preamble.
In addition to its solicitation for comments, the EPA also requests
documentation to support cost impact or recovery credit comments.
XI. Administrative Requirements
A. Docket
The docket for these rulemakings is A-94-04. The docket is an
organized and complete file of all the information considered by the
EPA in the development of this rulemaking. The principal purposes of
the docket are (1) to allow interested parties a means to
[[Page 6310]]
identify and locate documents so that they can effectively participate
in the rulemaking process and (2) to serve as the record in case of
judicial review (except for interagency review materials) [section
307(d)(7)(A) of the Act]. This docket contains copies of the regulatory
text, BID, BID references, and technical memoranda documenting the
information considered by the EPA in the development of the proposed
rules. The docket is available for public inspection at the EPA's Air
and Radiation Docket and Information Center, the location of which is
given in the ADDRESSES section of this notice.
B. Paperwork Reduction Act
The information collection requirements in these proposed rules
have been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
Information Collection Request (ICR) documents have been prepared by
the EPA (ICR Nos. 1788.01 and 1789.01) and copies may be obtained from
Sandy Farmer, OPPE Regulatory Information Division; U.S. Environmental
Protection Agency (2137); 401 M Street, S.W.; Washington, DC 20460 or
by calling (202) 260-2740.
Information is required to ensure compliance with the provisions of
the proposed rules. If the relevant information were collected less
frequently, the EPA would not be reasonably assured that a source is in
compliance with the proposed rules. In addition, the EPA's authority to
take administrative action would be reduced significantly.
The proposed rules would require that facility owners or operators
retain records for a period of five years, which exceeds the three year
retention period contained in the guidelines in 5 CFR 1320.6. The five
year retention period is consistent with the provisions of the General
Provisions of 40 CFR Part 63, and with the five year records retention
requirement in the operating permit program under Title V of the CAA.
All information submitted to the EPA for which a claim of
confidentiality is made will be safeguarded according to the EPA
policies set forth in Title 40, Chapter 1, Part 2, Subpart B,
Confidentiality of Business Information. See 40 CFR 2; 41 FR 36902,
September 1, 1976; amended by 43 FR 3999, September 8, 1978; 43 FR
42251, September 28, 1978; and 44 FR 17674, March 23, 1979. Even where
the EPA has determined that data received in response to an ICR is
eligible for confidential treatment under 40 CFR Part 2, Subpart B, the
EPA may nonetheless disclose the information if it is ``relevant in any
proceeding'' under the statute [42 U.S.C. 7414(C); 40 CFR 2.301(g)].
The information collection complies with the Privacy Act of 1974 and
Office of Management and Budget (OMB) Circular 108.
Information to be reported consists of emission data and other
information that are not of a sensitive nature. No sensitive personal
or proprietary data are being collected.
The estimated annual average hour burden for the major source
provisions of the proposed oil and natural gas production NESHAP is 169
hours per respondent. The estimated annual average cost of this burden
is $7,300 for each of the estimated 484 existing and new (projected)
respondents.
The estimated annual average hour burden for the area source
provisions of the proposed oil and natural gas production NESHAP is 56
hours per respondent. The estimated annual average cost of this burden
is $2,400 for each of the estimated 572 existing and new (projected)
respondents.
The estimated annual average hour burden for the major source
provisions of the proposed natural gas transmission and storage NESHAP
is 77 hours per respondent. The estimated annual average cost of this
burden is $3,300 for each of the estimated 5 existing respondents.
Reports are required on a semi-annual and annual basis (depending
upon the reports) and as required, as in the case of startup, shutdown,
and malfunction plans. Burden means the total time, effort, or
financial resources expended by persons to generate, maintain, retain,
or disclose or provide information to or for a Federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
An Agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15.
Comments are requested on the EPA's need for this information, the
accuracy of the provided burden estimates, and any suggested methods
for minimizing respondent burden, including through the use of
automated collection techniques. Send comments on the ICRs to the
Director, OPPE Regulatory Information Division; U.S. Environmental
Protection Agency (2137); 401 M Street, S.W., Washington, DC 20460; and
to the Office of Information and Regulatory Affairs, Office of
Management and Budget, 725 17th Street, N.W., Washington, DC 20503,
marked ``Attention: Desk Officer for EPA.'' Include the ICR number(s)
in any correspondence. Since OMB is required to make a decision
concerning the ICR's between 30 and 60 days after February 6, 1998, a
comment to OMB is best assured of having its full effect if OMB
receives it by March 9, 1998. The final rules will respond to any OMB
or public comments on the information collection requirements contained
in this proposal.
C. Executive Order 12866
Under Executive Order 12866 [58 FR 5173 (October 4, 1993)], the EPA
must determine whether the regulatory action is ``significant'' and
therefore subject to OMB review and the requirements of the Executive
Order. The criteria set forth in section 1 of the Order for determining
whether a regulation is a significant rule are as follows: (1) Is
likely to have an annual effect on the economy of $100 million or more,
or adversely and materially affect a sector of the economy,
productivity, competition, jobs, the environment, public health or
safety, or State, local or tribal governments or communities; (2) is
likely to create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency; (3) is likely to materially
alter the budgetary impact of entitlements, grants, user fees or loan
programs, or the rights and obligations of recipients thereof; or (4)
is likely to raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Based on criteria 1, 2, and 3, this action is not a ``significant
regulatory action'' within the meaning of Executive Order 12866.
However, the OMB has deemed it significant under criterion 4 and has
requested review of this proposed rulemaking package. Therefore, the
EPA submitted this action to OMB for review. Changes made in response
to OMB suggestions or recommendations are documented in the public
record.
[[Page 6311]]
D. Regulatory Flexibility
The Regulatory Flexibility Act (RFA) generally requires an agency
to conduct a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements, unless the agency certifies
that the rule will not have a significant economic impact on a
substantial number of small entities. Small entities include small
businesses, small not-for-profit enterprises, and small governmental
jurisdictions. These proposed rules will not have a significant
economic impact on a substantial number of small entities. According to
Wards Business Directory (1993), there are 1,152 firms in the seven
affected Standard Industrial Classification (SIC) codes and 735 of
these firms meet the Small Business Administration (SBA) definition of
a small entity.
The number of affected small entities for these rules is likely to
be minimal due to several considerations in these rules that minimize
the burden on all firms, both small and large. These considerations
include exempting from control requirements those glycol dehydration
units located at major or area sources with (1) an actual flowrate of
natural gas to the glycol dehydration unit less than 85 m\3\/day (3.0
MMSCF/D), on an annual average basis, or (2) benzene emissions less
than 0.9 Mg/yr (1 tpy). In addition, emission controls are limited to
those area source glycol dehydration units located in urban areas.
In a screening of potential impacts on a sample of small entities,
the EPA found that there are minimal impacts on these entities. The
weighted average of control costs as a percent of sales is 0.09 of one
percent for the small firms in the sample, while a maximum value of 1.1
percent results for only two of these firms. The analysis also
indicates that with the regulations, the change in measures of
profitability are minimal (i.e., 0.11 of one percent change in the
cost-to-sales ratio for small firms), and there are no indications of
financial failures or employment losses for both small and large firms.
The screening analysis for these rules is detailed in the Economic
Impact Analysis (see Docket No. A-94-04).
Therefore, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
E. Unfunded Mandates
Title II of the Unfunded Mandate Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, the
EPA generally must prepare a written statement, including a cost-
benefit analysis, for the proposed and final rules with ``Federal
mandates'' that may result in expenditures to State, local, and tribal
governments, in the aggregate, or to the private sector, of $100
million or more in any one year. Before promulgating an EPA rule for
which a written statement is needed, section 205 of the UMRA generally
requires the EPA to identify and consider a reasonable number of
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives
of the rule. The provisions of section 205 do not apply when they are
inconsistent with applicable law. Moreover, section 205 allows the EPA
to adopt an alternative other than the least costly, most cost-
effective, or least burdensome alternative if the Administrator
publishes with the final rule an explanation why that alternative was
not adopted. Before the EPA establishes any regulatory requirements
that may significantly or uniquely affect small governments, including
tribal governments, it must have developed under section 203 of the
UMRA a small government agency plan. The plan must provide for
notifying potentially affected small governments, enabling officials of
affected small governments to have meaningful and timely input in the
development of the EPA regulatory proposals with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
The EPA has determined that these rules do not contain a Federal
mandate that may result in expenditures of $100 million or more for
State, local, and tribal governments, in the aggregate or the private
sector in any one year. The EPA's total estimated annual net costs of
the proposed rules is $10 million, including MIRR costs. Thus, today's
rules are not subject to the requirements of sections 202 and 205 of
the UMRA.
The EPA has determined that these rules contain no regulatory
requirements that might significantly or uniquely affect small
governments. No small government entities have been identified that
have involvement with these source categories and, as such, are not
covered by the regulatory requirements of the proposed regulations.
List of Subjects in 40 CFR Part 63
Environmental protection, Air pollution control, Air emissions
control, Associated equipment, Black oil, Condensate, Custody transfer,
Equipment leaks, Glycol dehydration units, Hazardous air pollutants,
Hazardous substances, Natural gas, Intergovernmental relations, Natural
gas processing plants, Natural gas transmission and storage, Oil and
natural gas production, Pipelines, Organic liquids distribution (non-
gasoline), Reporting and recordkeeping requirements, Storage vessels,
Tank batteries, Tanks, Triethylene glycol.
Dated: November 24, 1997.
Carol M. Browner,
Administrator.
For the reasons set out in the preamble, title 40, chapter I, part
63 of the Code of Federal Regulations is proposed to be amended as
follows:
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
2. Part 63 is amended by adding subpart HH to read as follows:
Subpart HH--National Emission Standards for Hazardous Air
Pollutants From Oil and Natural Gas Production Facilities
Sec.
63.760 Applicability and designation of affected source.
63.761 Definitions.
63.762 [Reserved]
63.763 [Reserved]
63.764 General standards.
63.765 Glycol dehydration unit process vent standards.
63.766 Storage vessel standards.
63.767 [Reserved]
63.768 [Reserved]
63.769 Equipment leak standards.
63.770 [Reserved]
63.771 Control requirements.
63.772 Test methods and compliance procedures.
63.773 Inspection and monitoring requirements.
63.774 Recordkeeping requirements.
63.775 Reporting requirements.
63.776 Delegation of authority. [Reserved]
63.777 Alternative means of emission limitation.
63.778 [Reserved]
63.779 [Reserved]
Table 1 to Subpart HH--List of Air Pollutants for Subpart HH
Table 2 to Subpart HH--Applicability of 40 CFR Part 63 General
Provisions to Subpart HH
[[Page 6312]]
Subpart HH--National Emission Standards for Hazardous Air
Pollutants From Oil and Natural Gas Production Facilities
Sec. 63.760 Applicability and designation of affected source.
(a) This subpart applies to the owners or operators of emission
points, as specified in paragraph (b) of this section, that are located
at oil and natural gas production facilities that meet the specified
criteria in paragraphs (a)(1), (a)(2), and (a)(3) of this section.
(1) Facilities that process, upgrade, or store hydrocarbon liquids
prior to the point of custody transfer;
(2) Facilities that process, upgrade, or store natural gas prior to
the point at which natural gas enters the natural gas transmission and
storage source category or is delivered to a final end user; and
(3) Both major and area sources of HAP.
(b) The affected sources for major sources are listed in paragraph
(b)(1) of this section and for area sources in paragraph (b)(2) of this
section.
(1) For major sources, the affected source shall comprise each
emission point located at a facility that meets the criteria specified
in paragraph (a) of this section and listed in paragraphs (b)(1)(i)
through (b)(1)(iv) of this section.
(i) Each glycol dehydration unit;
(ii) Each storage vessel with flash emissions;
(iii) The group of all ancillary equipment, except compressors; and
(iv) Compressors intended to operate in volatile organic hazardous
air pollutant service (as defined in Sec. 63.761).
(2) For area sources, the affected source includes each triethylene
glycol dehydration unit located at a facility that meets the criteria
specified in paragraph (a) of this section.
(c) [Reserved]
(d) The owner or operator of a facility that does not contain an
affected source as specified in paragraph (b) of this section is not
subject to the requirements of this subpart.
(e) The owner or operator of a facility that exclusively processes,
stores, or transfers black oil (as defined in Sec. 63.761) is not
subject to the requirements of this subpart.
(f) The owner or operator of an affected source shall achieve
compliance with the provisions of this subpart by the dates specified
in paragraphs (f)(1) and (f)(2) of this section.
(1) The owner or operator of an affected source the construction or
reconstruction of which commenced before February 6, 1998, shall
achieve compliance with the provisions of the subpart as expeditiously
as practical after [the date of publication of the final rule], but no
later than three years after [the date of publication of the final
rule] except as provided for in Sec. 63.6(i).
(2) The owner or operator of an affected source the construction or
reconstruction of which commences on or after February 6, 1998, shall
achieve compliance with the provisions of this subpart immediately upon
startup or [the date of publication of the final rule], whichever date
is later.
(g) The following provides owners or operators of an affected
source with information on overlap of this subpart with other
regulations for equipment leaks.
(1) After the compliance dates specified in paragraph (f) of this
section, ancillary equipment that is subject to this subpart and that
is also subject to and controlled under the provisions of 40 CFR part
60, subpart KKK is only required to comply with the requirements of 40
CFR part 60, subpart KKK.
(2) After the compliance dates specified in paragraph (f) of this
section, ancillary equipment that is subject to this subpart and is
also subject to and controlled under the provisions of 40 CFR part 61,
subpart V is only required to comply with the requirements of 40 CFR
part 61, subpart V.
(3) After the compliance dates specified in paragraph (f) of this
section, ancillary equipment that is subject to this subpart and is
also subject to and controlled under the provisions of subpart H of
this part is only required to comply with the requirements of subpart H
of this part.
(h) An owner or operator of an affected source that is a major
source or located at a major source and is subject to the provisions of
this subpart is also subject to 40 CFR part 70 permitting requirements.
Unless otherwise required by the State, the owner or operator of an
area source subject to the provisions this subpart is not required to
obtain a permit under part 70 of title 40 of the Code of Federal
Regulations.
Sec. 63.761 Definitions.
All terms used in this subpart shall have the meaning given them in
the Clean Air Act, subpart A of this part (General Provisions), and in
this section. If the same term is defined in subpart A and in this
section, it shall have the meaning given in this section for purposes
of this subpart.
Alaskan North Slope means the approximately 180,000 square
kilometer area (69,000 square mile area) extending from the Brooks
Range to the Arctic Ocean.
Ancillary equipment means any of the following pieces of equipment:
pumps, compressors, pressure relief devices, sampling connection
systems, open-ended valves or lines, valves, flanges and other
connectors, or product accumulator vessels.
API gravity means the weight per unit volume of hydrocarbon liquids
as measured by a system recommended by the American Petroleum Institute
(API) and is expressed in degrees.
Associated equipment, as used in this subpart and as referred to in
section 112(n)(4) of the Act, means equipment associated with an oil or
natural gas exploration or production well, and includes all equipment
from the wellbore to the point of custody transfer, except glycol
dehydration units and storage vessels with the potential for flash
emissions.
Average concentration, as used in this subpart, means the annual
average flow rate, as determined according to the procedures specified
in Sec. 63.772(b).
Black oil means hydrocarbon (petroleum) liquid with a gas-to-oil
ratio (GOR) less than 50 cubic meters (1,750 cubic feet) per barrel and
an API gravity less than 40 degrees.
Boiler means any enclosed combustion device that extracts useful
energy in the form of steam and that is not an incinerator.
Closed-vent system means a system that is not open to the
atmosphere and that is composed of piping, ductwork, connections, and,
if necessary, flow inducing devices that transport gas or vapor from an
emission point to a control device or back into the process. If gas or
vapor from regulated equipment is routed to a process (e.g., to a fuel
gas system), the process shall not be considered a closed vent system
and is not subject to closed vent system standards.
Combustion device means an individual unit of equipment such as a
flare, incinerator, process heater, or boiler used for the combustion
of volatile organic hazardous air pollutant vapors.
Compressor means a piece of equipment that increases the pressure
of a process gas by positive displacement, employing linear movement of
the drive shaft.
Condensate means hydrocarbon liquid that condenses because of
changes in temperature, pressure, or both, and remains liquid at
standard conditions.
Continuous recorder means a data recording device that either
records an instantaneous data value at least once
[[Page 6313]]
every 15 minutes or records 15-minute or more frequent block average
values.
Continuous seal means a seal that forms a continuous closure that
completely covers the space between the wall of the storage vessel and
the edge of the floating roof. A continuous seal may be a vapor-
mounted, liquid-mounted, or metallic shoe seal.
Control device means any equipment used for recovering or oxidizing
hazardous air pollutant (HAP) and volatile organic compound (VOC)
vapors. Such equipment includes, but is not limited to, absorbers,
carbon adsorbers, condensers, incinerators, flares, boilers, and
process heaters. For the purposes of this subpart, if gas or vapor from
regulated equipment is used, reused, returned back to the process, or
sold, then the recovery system used, including piping, connections, and
flow inducing devices, are not considered to be control devices.
Cover means a device which is placed on top of or over a material
such that the entire surface area of the material is enclosed and
sealed, to reduce emissions to the atmosphere. A cover may have
openings (such as access hatches, sampling ports, and gauge wells) if
those openings are necessary for operation, inspection, maintenance, or
repair of the unit on which the cover is installed, provided that each
opening is closed and sealed when the opening is not in use. In
addition, a cover may have one or more safety devices. Examples of a
cover include a fixed-roof installed on a tank, an external floating
roof installed on a tank, and a lid installed on a drum or other
container.
Custody transfer means the transfer of hydrocarbon liquids or
natural gas, after processing and/or treatment in the producing
operations, from storage vessels or automatic transfer facilities to
pipelines or any other forms of transportation. For the purposes of
this subpart, the EPA considers the point at which natural gas enters a
natural gas processing plant as a point of custody transfer.
Equipment leak means emissions of hazardous air pollutants from a
pump, compressor, pressure relief device, sampling connection system,
open-ended valve or line, valve, or instrumentation system.
Facility means any grouping of equipment: where hydrocarbon liquids
are processed, upgraded, or stored prior to the point of custody
transfer; or where natural gas is processed, upgraded, or stored prior
to entering the natural gas transmission source category. For the
purpose of a major source determination, means oil and natural gas
production and processing equipment that is located within the
boundaries of an individual surface site. Equipment that is part of a
facility will typically be located within close proximity to other
equipment located at the same facility. Pieces of production equipment
or groupings of equipment located on different oil and gas leases,
mineral fee tracts, lease tracts, subsurface unit areas, surface fee
tracts, or surface lease tracts shall not be considered part of the
same facility. Examples of facilities in the oil and natural gas
production source category include, but are not limited to, well sites,
satellite tank batteries, central tank batteries, graded pad sites, and
natural gas processing plants.
Field natural gas means natural gas extracted from a production
well prior to entering the first stage of processing, such as
dehydration.
Fill or filling means the introduction of a material into a storage
vessel.
Fixed-roof means a cover that is mounted on a waste management unit
or storage vessel in a stationary manner and that does not move with
fluctuations in liquid level.
Flame zone means the portion of the combustion chamber in a boiler
occupied by the flame envelope.
Flash tank. See definition for gas-condensate-glycol (GCG)
separator.
Flow indicator means a device that indicates whether gas flow is
present in a line.
Gas-condensate-glycol (GCG) separator means a two-or three-phase
separator through which the ``rich'' glycol stream of a glycol
dehydration unit is passed to remove entrained gas and hydrocarbon
liquid. The GCG separator is commonly referred to as a flash separator
or flash tank.
Gas-to-oil ratio (GOR) means the number of standard cubic meters
(cubic feet) of gas produced per barrel of crude oil or other
hydrocarbon liquid.
Glycol dehydration unit means a device in which a liquid glycol
absorbent directly contacts a natural gas stream (that is circulated
counter current to the glycol flow) and absorbs water vapor in a
contact tower or absorption column (absorber). The glycol contacts and
absorbs water vapor and other gas stream constituents from the natural
gas and becomes ``rich'' glycol. This glycol is then regenerated by
distilling the water and other gas stream constituents in the glycol
dehydration unit reboiler. The distilled or ``lean'' glycol is then
recycled back to the absorber.
Glycol dehydration unit reboiler vent means the vent through which
exhaust from the reboiler of a glycol dehydration unit passes from the
reboiler to the atmosphere.
Glycol dehydration unit process vent means either the glycol
dehydration unit reboiler vent or the vent from the GCG separator
(flash tank).
Hazardous air pollutants or HAP means the chemical compounds listed
in section 112(b) of the Act. All chemical compounds listed in section
112(b) of the Act need to be considered when making a major source
determination. Only the HAP compounds listed in Table 1 of this subpart
need to be considered when determining applicability and compliance.
Hydrocarbon liquid means any naturally occurring, unrefined
petroleum liquid.
In VOHAP service means that a piece of ancillary equipment either
contains or contacts a fluid (liquid or gas) which has a total volatile
organic HAP (VOHAP) concentration equal to or greater than 10 percent
by weight as determined according to the provisions of 40 CFR
61.245(d).
Major source, as used in this subpart, shall have the same meaning
as in Sec. 63.2, except that:
(1) Emissions from any oil or gas exploration or production well
(with its associated equipment (as defined in this section)) and
emissions from any pipeline compressor or pump station shall not be
aggregated with emissions from other similar units, to determine
whether such emission points or stations are major sources, even when
emission points are in a contiguous area or under common control;
(2) Emissions from processes, operations, or equipment that are not
part of the same facility, as defined in this section, shall not be
aggregated; and
(3) For facilities that are production field facilities, only HAP
emissions from glycol dehydration units and storage tanks with flash
emission potential shall be counted in a major source determination.
Natural gas means the gaseous mixture of hydrocarbon gases and
vapors, primarily consisting of methane, ethane, propane, butane,
pentane, and hexane, along with water vapor and other constituents.
Natural gas liquids (NGLs) means the hydrocarbons, such as ethane,
propane, butane, pentane, natural gasoline, and condensate that are
extracted from field gas.
Natural gas processing plant (gas plant) means any processing site
engaged in:
(1) The extraction of natural gas liquids from field gas; or
(2) The fractionation of mixed NGLs to natural gas products.
[[Page 6314]]
No detectable emissions means no escape of HAP from a device or
system to the atmosphere as determined by:
(1) Testing the device or system in accordance with the
requirements of Sec. 63.772(c); and
(2) No visible openings or defects in the device or system such as
rips, tears, or gaps.
Operating parameter value means a minimum or maximum value
established for a control device or process parameter which, if
achieved by itself or in combination with one or more other operating
parameter values, determines that an owner or operator has complied
with an applicable emission limitation or standard.
Operating permit means a permit required by 40 CFR part 70 or part
71.
Organic monitoring device means a unit of equipment used to
indicate the concentration level of organic compounds exiting a
recovery device based on a detection principle such as infra-red,
photoionization, or thermal conductivity.
Point of material entry means at the point where a material first
enters a source subject to this subpart.
Primary fuel means the fuel that provides the principal heat input
(i.e., more than 50-percent) to the device. To be considered primary,
the fuel must be able to sustain operation without the addition of
other fuels.
Process heater means a device that transfers heat liberated by
burning fuel directly to process streams or to heat transfer liquids
other than water.
Produced water means water:
(1) That is extracted from the earth from an oil or natural gas
production well; or
(2) That is separated from crude oil, condensate, or natural gas
after extraction.
Production field facilities means those facilities located prior to
the point of custody transfer.
Production well means any hole drilled in the earth from which
crude oil, condensate, or field natural gas is extracted.
Relief device means a device used only to release an unplanned,
non-routine discharge. A relief device discharge can result from an
operator error, a malfunction such as a power failure or equipment
failure, or other unexpected cause that requires immediate venting of
gas from process equipment in order to avoid safety hazards or
equipment damage.
Safety device means a device that is not used for planned or
routine venting of liquids, gases, or fumes from the unit or equipment
on which the device is installed; and the device remains in a closed,
sealed position at all times except when an unplanned event requires
that the device open for the purpose of preventing physical damage or
permanent deformation of the unit or equipment on which the device is
installed in accordance with good engineering and safety practices for
handling flammable, combustible, explosive, or other hazardous
materials. Examples of unplanned events which may require a safety
device to open include failure of an essential equipment component or a
sudden power outage.
Storage vessel means a tank or other vessel that is designed to
contain an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water and that is constructed
primarily of non-earthen materials (e.g., wood, concrete, steel,
plastic) that provide structural support.
Storage vessel with the potential for flash emissions means any
storage vessel that contains a hydrocarbon with a GOR equal to or
greater than 50 cubic meters (1,750 cubic feet) per barrel or an API
gravity equal to or greater than 40 degrees.
Surface site means the graded pad, gravel pad, foundation,
platform, or immediate physical location upon which equipment is
physically affixed.
Tank battery means a collection of equipment used to separate,
treat, store, and transfer crude oil, condensate, natural gas, and
produced water. A tank battery typically receives crude oil,
condensate, natural gas, or some combination of these extracted
products from several production wells for accumulation and separation
prior to transmission to a natural gas plant or petroleum refinery. A
tank battery may or may not include a glycol dehydration unit.
Temperature monitoring device means a unit of equipment used to
monitor temperature and having an accuracy of 1 percent of
the temperature being monitored expressed in deg.C, or
0.5 deg.C, whichever is greater.
Total organic compounds or TOC, as used in this subpart, means
those compounds measured according to the procedures of Method 18, 40
CFR part 60, appendix A.
Urban area is defined by use of the U.S. Department of Commerce's
Bureau of the Census statistical data to classify every county in the
U.S. into one of the three classifications:
(1) Urban-1 areas which consist of metropolitan statistical areas
(MSA) with a population greater than 250,000;
(2) Urban-2 areas which are defined as all other areas designated
urban by the Bureau of Census (areas which comprise one or more central
places and the adjacent densely settled surrounding fringe that
together have a minimum of 50,000 persons). The urban fringe consists
of contiguous territory having a density of at least 1,000 persons per
square mile; or
(3) Rural areas which are those counties not designated as urban by
the Bureau of the Census.
Volatile organic hazardous air pollutant concentration or VOHAP
concentration means the fraction by weight of all HAP contained in a
material as determined in accordance with procedures specified in
Sec. 63.772(a).
Sec. 63.762 [Reserved]
Sec. 63.763 [Reserved]
Sec. 63.764 General standards.
(a) Table 2 of this subpart specifies the provisions of subpart A
(General Provisions) that apply and those that do not apply to owners
and operators of affected sources subject to this subpart.
(b) All reports required under this subpart shall be sent to the
Administrator at the appropriate address listed in Sec. 63.13. If
acceptable to both the Administrator and the owner or operator of a
source, reports may be submitted on electronic media.
(c) Except as specified in paragraph (e) of this section, the owner
or operator of an affected source located at an existing or new major
source shall comply with the standards in this subpart as specified in
paragraphs (c)(1) through (c)(3) of this section.
(1) For each glycol dehydration unit process vent subject to this
subpart, the owner or operator shall comply with the requirements
specified in paragraphs (c)(1)(i) through (c)(1)(iii) of this section.
(i) The owner or operator shall comply with the control
requirements for glycol dehydration unit process vents specified in
Sec. 63.765;
(ii) The owner or operator shall comply with the monitoring
requirements of Sec. 63.773; and
(iii) The owner or operator shall comply with the recordkeeping and
reporting requirements of Secs. 63.774 and 63.775.
(2) For each storage vessel with the potential for flash emissions
and an actual throughput of hydrocarbon liquids equal to or greater
than 500 barrels per day (BPD), the owner or operator shall comply with
the requirements specified in paragraphs (c)(2)(i) through (c)(2)(iii)
of this section.
(i) The control requirements for storage vessels specified in
Sec. 63.766;
(ii) The monitoring requirements of Sec. 63.773; and
[[Page 6315]]
(iii) The recordkeeping and reporting requirements of Secs. 63.774
and 63.775.
(3) For ancillary equipment (as defined in Sec. 63.761) at a
natural gas processing plant subject to this subpart, the owner or
operator shall comply with the requirements for equipment leaks
specified in Sec. 63.769.
(d) The owner or operator of an affected source located at an area
source of HAP emissions shall comply with the standards in this subpart
as specified in paragraphs (d)(1) through (d)(3) of this section.
(1) The control requirements for glycol dehydration unit process
vents specified in Sec. 63.765;
(2) The monitoring requirements of Sec. 63.773; and
(3) The recordkeeping and reporting requirements of Secs. 63.774
and 63.775.
(e) The owner or operator is exempt from the requirements of
paragraphs (c)(1) and (d) of this section if the actual annual average
flow of gas to the glycol dehydration unit is less than 85 thousand
cubic meters per day (3.0 million standard cubic feet per day) or
emissions of benzene from the unit to the atmosphere are less than 0.9
megagram per year (1 ton per year). The flow of natural gas to the unit
and the emissions of benzene from the unit shall be determined by the
procedures specified in Sec. 63.772(b). This determination must be made
available to the Administrator upon request. In addition, the owner or
operator is exempt from the requirements of paragraph (d) of this
section if the glycol dehydration unit is not located in a county
classified as an Urban area as defined in Sec. 63.761.
(f) Each owner or operator of a major HAP source subject to this
subpart is required to apply for a 40 CFR part 70 or part 71 operating
permit from the appropriate permitting authority. If the Administrator
has approved a State operating permit program under 40 CFR part 70, the
permit shall be obtained from the State authority. If the State
operating permit program has not been approved, the owner or operator
of a source shall apply to the EPA Regional Office pursuant to 40 CFR
part 71.
(g) Unless otherwise required by the State, the owner or operator
of an area source subject to the provisions of this subpart is not
required to obtain a permit under part 70 of title 40 of the Code of
Federal Regulations.
(h) An owner or operator of an affected source that is:
(1) A major source or located at a major source; or
(2) An area source subject to the provisions of this subpart that
is in violation of an operating parameter value is in violation of the
applicable emission limitation or standard.
Sec. 63.765 Glycol dehydration unit process vents standards.
(a) This section applies to each glycol dehydration unit process
vent that must be controlled for HAP emissions as specified in
Sec. 63.764(c)(1)(i) and (d)(1).
(b) Except as provided in paragraph (c) of this section, an owner
or operator of a glycol dehydration unit process vent shall comply with
the requirements specified in paragraphs (b)(1) and (b)(2) of this
section.
(1) For each glycol dehydration unit process vent, the owner or
operator shall control air emissions by connecting the process vent to
a control device through a closed-vent system designed and operated in
accordance with the requirements of Sec. 63.771(c) and (d).
(2) One or more safety devices that vent directly to the atmosphere
may be used on the air emission control equipment complying with
paragraph (b)(1) of this section.
(c) As an alternative to the requirements of paragraph (b) of this
section, the owner or operator may comply with one of the requirements
specified in paragraphs (c)(1) through (c)(3) of this section.
(1) The owner or operator shall control air emissions by connecting
the process vent to a process natural gas line through a closed-vent
system designed and operated in accordance with the requirements of
Sec. 63.771(c).
(2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that the total HAP emissions to the atmosphere from the
glycol dehydration unit reboiler vent and GCG separator (flash tank)
vent (if present) are reduced by 95 percent through process
modifications.
(3) Control of HAP emissions from a GCG separator (flash tank) vent
is not required if the owner or operator demonstrates, to the
Administrator's satisfaction, that total HAP emissions to the
atmosphere from the glycol dehydration unit reboiler vent and GCG
separator (flash tank) vent are reduced by 95 percent.
Sec. 63.766 Storage vessel standards.
(a) This section applies to each storage vessel that must be
controlled for HAP emissions as specified in Sec. 63.764(c)(2).
(b) The owner or operator of a storage vessel shall comply with one
of the control requirements specified in paragraphs (b)(1) through
(b)(3) of this section.
(1) The owner or operator of a storage vessel using a cover that is
connected through a closed-vent system to a control device shall use a
cover that is designed and operated in accordance with the requirements
of Sec. 63.771(b). The closed-vent system and control device shall be
designed and operated in accordance with the requirements of
Sec. 63.771(c) and (d).
(2) The owner or operator of a pressure storage vessel that is
designed to operate as a closed system shall operate the storage vessel
with no detectable emissions at all times that material is in the
storage vessel, except as provided for in paragraph (c) of this
section.
(3) The owner or operator of a storage vessel using a fixed-roof
cover with an internal floating roof shall use a fixed-roof cover with
an internal floating roof designed and operated in accordance with the
requirements of 40 CFR 60.112b(a)(1).
(c) One or more safety devices that vent directly to the atmosphere
may be used on the storage vessel and air emission control equipment
complying with paragraphs (b)(1) through (b)(3) of this section.
Sec. 63.767 [Reserved]
Sec. 63.768 [Reserved]
Sec. 63.769 Equipment leak standards.
(a) This section applies to ancillary equipment and compressors (as
defined in Sec. 63.761) at natural gas processing plants that contain
or contact a fluid (liquid or gas) that has a total VOHAP concentration
equal to or greater than 10 percent by weight (determined according to
the provisions of 40 CFR 61.245(d)) and that operates equal to or
greater than 300 hours per calendar year.
(b) This section does not apply to ancillary equipment and
compressors for which the owner or operator is meeting the requirements
specified in subpart H of this part; or is meeting the requirements
specified in 40 CFR part 60, subpart KKK.
(c) For each piece of ancillary equipment and compressors subject
to this section located at an existing or new source, the owner or
operator shall meet the requirements specified in 40 CFR 61.241 through
61.247, except as specified in paragraphs (c)(1) through (c)(8) of this
section.
(1) Each pressure relief device in gas/vapor service shall be
monitored quarterly and within 5 days after each pressure release to
detect leaks, except under the following conditions.
(i) If an owner or operator has obtained permission from the
Administrator to use an alternative means of emission limitation that
[[Page 6316]]
achieves a reduction in emissions of VOHAP at least equivalent to that
achieved by the control required in this subpart.
(ii) If the pressure relief device is located in a nonfractionating
facility that is monitored only by non-facility personnel, it may be
monitored after a pressure release the next time the monitoring
personnel are on site, instead of within 5 days. Such a pressure relief
device shall not be allowed to operate for more than 30 days after a
pressure release without monitoring.
(2) For pressure relief devices, if an instrument reading of 10,000
parts per million or greater is measured, a leak is detected.
(3) For pressure relief devices, when a leak is detected, it shall
be repaired as soon as practicable, but no later than 15 calendar days
after it is detected, except if a delay in repair of equipment is
granted under 40 CFR 61.242-10.
(4) Sampling connection systems are exempt from the requirements of
40 CFR 61.242-5.
(5) Pumps in VOHAP service, valves in gas/vapor and light liquid
service, and pressure relief devices in gas/vapor service that are
located at a nonfractionating plant that does not have the design
capacity to process 283 standard cubic meters per day (10 million
standard cubic feet per day) or more of field gas are exempt from the
routine monitoring requirements of 40 CFR 61.242-2(a)(1) and paragraphs
61.242-7(a), and paragraphs (c)(1) through (c)(3) of this section.
(6) Pumps in VOHAP service, valves in gas/vapor and light liquid
service, and pressure relief devices in gas/vapor service within a
natural gas processing plant that is located on the Alaskan North Slope
are exempt from the routine monitoring requirements of 40 CFR 61.242-
2(a)(1) and 61.242-7(a), and paragraphs (c)(1) through (c)(3) of this
section.
(7) Reciprocating compressors in wet gas service are exempt from
the compressor control requirements of 40 CFR 61.242-3.
(8) Flares used to comply with this subpart shall comply with the
requirements of Sec. 63.11(b).
Sec. 63.770 [Reserved]
Sec. 63.771 Control requirements.
(a) This section applies to each cover, closed-vent system, and
control device installed and operated by the owner or operator to
control air emissions.
(b) Cover requirements. (1) The cover and all openings on the cover
(e.g., access hatches, sampling ports, and gauge wells) shall be
designed to operate with no detectable emissions when all cover
openings are secured in a closed, sealed position.
(2) The owner or operator shall determine that the cover operates
with no detectable emissions by testing each opening on the cover in
accordance with the procedures specified in Sec. 63.772(c) the first
time material is placed into the unit on which the cover is installed.
If a leak is detected and cannot be repaired at the time that the leak
is detected, the material shall be removed from the unit and the unit
shall not be used until the leak is repaired.
(3) Each cover opening shall be secured in a closed, sealed
position (e.g., covered by a gasketed lid or cap) whenever material is
in the unit on which the cover is installed except during those times
when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this
includes openings necessary to equalize or balance the internal
pressure of the unit following changes in the level of the material in
the unit);
(ii) To inspect or sample the material in the unit;
(iii) To inspect, maintain, repair, or replace equipment located
inside the unit; or
(iv) To vent liquids, gases, or fumes from the unit through a
closed-vent system to a control device designed and operated in
accordance with the requirements of paragraphs (c) and (d) of this
section.
(c) Closed-vent system requirements. (1) The closed-vent system
shall route all gases, vapors, and fumes emitted from the material in
the unit to a control device that meets the requirements specified in
paragraph (d) of this section.
(2) The closed-vent system shall be designed and operated with no
detectable emissions.
(3) If the closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, the owner or operator shall
meet the requirements specified in paragraphs (c)(3)(i) and (c)(3)(ii)
of this section.
(i) For each bypass device, except as provided for in paragraph
(c)(3)(ii) of this section, the owner or operator shall either:
(A) Install, calibrate, maintain, and operate a flow indicator at
the inlet to the bypass device that indicates at least once every 15
minutes whether gas, vapor, or fume flow is present in the bypass
device; or
(B) Secure the valve installed at the inlet to the bypass device in
the closed position using a car-seal or a lock-and-key type
configuration. The owner or operator shall visually inspect the seal or
closure mechanism at least once every month to verify that the valve is
maintained in the closed position.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (c)(3)(i) of this section.
(d) Control device requirements. (1) The control device used to
reduce HAP emissions in accordance with the standards of this subpart
shall be one of the control devices specified in paragraphs (d)(1)(i)
through (d)(1)(iii) of this section.
(i) An enclosed combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) that is
designed and operated in accordance with one of the following
performance requirements:
(A) Reduces the mass content of either TOC or total HAP in the
gases vented to the device by 95 percent by weight or greater as
determined in accordance with the requirements of Sec. 63.772(e);
(B) Reduces the concentration of either TOC or total HAP in the
exhaust gases at the outlet to the device to a level equal to or less
than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec. 63.772(e); or
(C) Operates at a minimum residence time of 0.5 second at a minimum
temperature of 760 deg.C. If a boiler or process heater is used as the
control device, then the vent stream shall be introduced into the flame
zone of the boiler or process heater.
(ii) A vapor recovery device (e.g. carbon adsorption system or
condenser) or other control device that is designed and operated to
reduce the mass content of either TOC or total HAP in the gases vented
to the device by 95 percent by weight or greater as determined in
accordance with the requirements of Sec. 63.772(e).
(iii) A flare that is designed and operated in accordance with the
requirements of Sec. 63.11(b).
(2) Each control device used to comply with this subpart shall be
operated at all times when material is placed in a unit vented to the
control device, except when maintenance or repair of a unit cannot be
completed without a shutdown of the control device. An owner or
operator may vent more than one unit to a control device used to comply
with this subpart.
[[Page 6317]]
(3) The owner or operator shall demonstrate that a control device
achieves the performance requirements of paragraph (d)(1) of this
section as specified in paragraphs (d)(3)(i) through (d)(3)(iv) of this
section.
(i) An owner or operator shall demonstrate using either a
performance test as specified in paragraph (d)(3)(iii) of this section
or a design analysis as specified in paragraph (d)(3)(iv) of this
section the performance of each control device except for the
following:
(A) A flare;
(B) A boiler or process heater with a design heat input capacity of
44 megawatts or greater;
(C) A boiler or process heater into which the vent stream is
introduced with the primary fuel; or
(D) A boiler or process heater burning hazardous waste for which
the owner or operator has either been issued a final permit under 40
CFR part 270 and complies with the requirements of 40 CFR part 266,
subpart H; or has certified compliance with the interim status
requirements of 40 CFR part 266, subpart H.
(ii) An owner or operator shall demonstrate the performance of each
flare in accordance with the requirements specified in Sec. 63.11(b).
(iii) For a performance test conducted to meet the requirements of
paragraph (d)(3)(i) of this section, the owner or operator shall use
the test methods and procedures specified in Sec. 63.772(e).
(iv) For a design analysis conducted to meet the requirements of
paragraph (d)(3)(i) of this section, the design analysis shall meet the
requirements specified in paragraphs (d)(3)(iv)(A) and (d)(3)(iv)(B) of
this section.
(A) The design analysis shall include analysis of the vent stream
characteristics and control device operating parameters for the
applicable control device as specified in paragraphs (d)(3)(iv)(A)(1)
through (d)(3)(iv)(A)(6) of this section.
(1) For a thermal vapor incinerator, the design analysis shall
include the vent stream composition, constituent concentrations, and
flow rate and shall establish the design minimum and average
temperatures in the combustion zone and the combustion zone residence
time.
(2) For a catalytic vapor incinerator, the design analysis shall
include the vent stream composition, constituent concentrations, and
flow rate and shall establish the design minimum and average
temperatures across the catalyst bed inlet and outlet, and the design
service life of the catalyst.
(3) For a boiler or process heater, the design analysis shall
include the vent stream composition, constituent concentrations, and
flow rate; shall establish the design minimum and average flame zone
temperatures and combustion zone residence time; and shall describe the
method and location where the vent stream is introduced into the flame
zone.
(4) For a condenser, the design analysis shall include the vent
stream composition, constituent concentrations, flow rate, relative
humidity, and temperature, and shall establish the design outlet
organic compound concentration level, design average temperature of the
condenser exhaust vent stream, and the design average temperatures of
the coolant fluid at the condenser inlet and outlet.
(5) For a carbon adsorption system that regenerates the carbon bed
directly on-site in a control device such as a fixed-bed adsorber, the
design analysis shall include the vent stream composition, constituent
concentrations, flow rate, relative humidity, and temperature, and
shall establish the design exhaust vent stream organic compound
concentration level, adsorption cycle time, number and capacity of
carbon beds, type and working capacity of activated carbon used for
carbon beds, design total regeneration stream flow over the period of
each complete carbon bed regeneration cycle, design carbon bed
temperature after regeneration, design carbon bed regeneration time,
and design service life of the carbon.
(6) For a carbon adsorption system that does not regenerate the
carbon bed directly on-site in the control device, such as a carbon
canister, the design analysis shall include the vent stream
composition, constituent concentrations, flow rate, relative humidity,
and temperature, and shall establish the design exhaust vent stream
organic compound concentration level, capacity of carbon bed, type and
working capacity of activated carbon used for carbon bed, and design
carbon replacement interval based on the total carbon working capacity
of the control device and source operating schedule. In addition, these
systems will incorporate dual carbon canisters in case of emission
breakthrough occurring in one canister.
(B) If the owner or operator and the Administrator do not agree on
a demonstration of control device performance using a design analysis
then the disagreement shall be resolved using the results of a
performance test performed by the owner or operator in accordance with
the requirements of paragraph (d)(3)(iii) of this section. The
Administrator may choose to have an authorized representative observe
the performance test.
(4) The owner or operator shall operate each control device in
accordance with the requirements specified in paragraphs (d)(4)(i)
through (d)(4)(iii) of this section.
(i) The control device shall be operating at all times when gases,
vapors, and fumes are vented from the unit or units through the closed-
vent system to the control device.
(ii) For each control device monitored in accordance with the
requirements of Sec. 63.773(d), the owner or operator shall operate the
control device such that the actual value of each operating parameter
required to be monitored in accordance with the requirements of
Sec. 63.773(d)(3) is greater than the minimum operating parameter value
or less than the maximum operating parameter value, as appropriate,
established for the control device in accordance with the requirements
of Sec. 63.773(d)(4).
(iii) Failure by the owner or operator to operate the control
device in accordance with the requirements of paragraph (d)(4)(ii) of
this section shall constitute a violation of the applicable emission
standard of this subpart.
(5) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (d)(1) of this section, the owner or
operator shall manage the carbon as specified in paragraphs (c)(5)(i)
and (c)(5)(ii) of this section.
(i) Following the initial startup of the control device, all carbon
in the control device shall be replaced with fresh carbon on a regular,
predetermined time interval that is no longer than the carbon service
life established for the carbon adsorption system.
(ii) All carbon removed from the control device shall be managed in
one of the following manners:
(A) Regenerated or reactivated in a thermal treatment unit for
which the owner or operator has either been issued a final permit under
40 CFR part 270, and designed and operated the unit in accordance with
the requirements of 40 CFR part 264, subpart X; or certified compliance
with the interim status requirements of 40 CFR part 265, subpart P.
(B) Burned in a hazardous waste incinerator for which the owner or
operator has been issued a final permit under 40 CFR part 270, and
designed and operated the unit in accordance with the requirements of
40 CFR part 264, subpart O.
(C) Burned in a boiler or industrial furnace for which the owner or
operator has either been issued a final permit under 40 CFR part 270,
and designed
[[Page 6318]]
and operated the unit in accordance with the requirements of 40 CFR
part 266, subpart H, or certified compliance with the interim status
requirements of 40 CFR part 266, subpart H.
Sec. 63.772 Test methods and compliance procedures.
(a) Determination of material VOHAP or HAP concentration for
applicability to the equipment leak standards under this subpart
(Sec. 63.769).
(1) An owner or operator is not required to determine the VOHAP or
HAP concentration for materials placed in units subject to this subpart
using air emission controls in accordance with the requirements of
Sec. 63.766.
(2) An owner or operator shall perform a VOHAP or HAP concentration
determination at the following times:
(i) When the material enters the facility in a storage vessel, the
owner or operator shall perform a VOHAP or HAP concentration
determination for each storage vessel.
(ii) When the material enters the facility as a continuous,
uninterrupted flow of material through a pipeline or other means, the
owner or operator shall:
(A) Perform an initial VOHAP or HAP concentration determination
before the first time any portion of the material is placed in a unit
subject to this subpart; and
(B) Perform a new VOHAP or HAP concentration determination whenever
changes to the material could potentially cause the VOHAP or HAP
concentration of the material to increase to a level that is equal to
or greater than the applicable VOHAP or HAP concentration limits
specified in Sec. 63.769.
(3) An owner or operator shall determine the VOHAP or HAP
concentration of a material using either direct measurement as
specified in paragraph (a)(4) of this section or knowledge of the
material as specified in paragraph (a)(5) of this section.
(4) Direct measurement to determine VOHAP or HAP concentration.
(i) For the purpose of determining the VOHAP or HAP concentration
at the point of entry, samples of the material shall be collected from
the storage vessel, pipeline, or other device used to deliver the
material to the facility before the material is either:
(A) Combined with other material; or
(B) Conveyed, handled, or otherwise managed in such a manner that
the surface of the material is open to the atmosphere.
(ii) For the purpose of determining the VOHAP or HAP concentration
at the point of treatment, samples shall be collected at or after the
point of treatment but before the point where this material is either:
(A) Combined with other materials;
(B) Conveyed, handled, or otherwise managed in such a manner that
the surface of the material is open to the atmosphere; or
(C) Placed in a unit subject to this subpart.
(iii) The VOHAP or HAP concentration on a mass-weighted average
basis shall be determined using the procedure specified in paragraphs
(a)(4)(iii)(A) through (a)(4)(iii)(D) of this section when the material
flows as a continuous stream for periods less than or equal to 1 hour.
(A) A sufficient number of samples, but no less than four samples,
shall be collected to represent the VOHAP or HAP composition for the
entire quantity of material. All of the samples shall be collected
within a 1-hour period.
(B) Each sample shall be collected in accordance with the
requirements specified in ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' EPA Publication No. SW-846.
(C) Each collected sample shall be prepared and analyzed in
accordance with the requirements of Method 305, 40 CFR part 63,
appendix A or Method 25D, 40 CFR part 60, appendix A.
(D) The VOHAP or HAP concentration shall be calculated by using the
results for all samples analyzed in accordance with paragraph
(a)(4)(iii)(C) of this section and the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.006
where:
C=VOHAP or HAP concentration of the material on a mass-weighted basis,
parts per million by weight.
I=Individual sample ``I'' of the material. n=Total number of samples of
material collected (at least 4) within a 1-hour period.
Ci=Measured VOHAP or HAP concentration of sample ``I'' as
determined in accordance with the requirements of
Sec. 63.772(a)(4)(iii)(C), parts per million by weight.
(iv) The VOHAP or HAP concentration on a mass-weighted average
basis shall be determined using the procedures specified in paragraphs
(a)(4)(iv)(A) through (a)(4)(iv)(E) of this section when the material
flows as a continuous stream of material for periods greater than 1-
hour.
(A) The averaging period to be used for determining the VOHAP
concentration on a mass-weighted average basis shall be designated and
recorded. The averaging period shall represent any time interval that
the material flows until the time that a new VOHAP or HAP concentration
determination must be performed pursuant to the requirements of
paragraph (b) of this section. The averaging period shall not exceed 1
year.
(B) A sufficient number of samples, but no less than four samples,
shall be collected to represent the complete range of VOHAP or HAP
compositions and VOHAP or HAP quantities that occur in the material
stream during the entire averaging period due to normal variations in
the operating conditions for the source, process, or unit generating
the material. Examples of such normal variations are seasonal
variations in material quantity, cyclic process operations, or
fluctuations in ambient temperature.
(C) Each sample shall be collected in accordance with the
requirements specified in ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' EPA Publication No. SW-846. Sufficient
information shall be recorded to document the material quantity and the
operating conditions for the source, process, or unit generating the
material represented by each sample collected.
(D) Each collected sample shall be prepared and analyzed in
accordance with the requirements of Method 305, 40 CFR part 63,
appendix A or Method 25D, 40 CFR part 60, appendix A.
(E) The VOHAP or HAP concentration on a mass-weighted average basis
shall be calculated by using the results for all samples analyzed in
accordance with paragraph (a)(4)(vi)(D) of this section and the
following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.007
where:
C=VOHAP or HAP concentration of the material on a mass weighted basis,
parts per million by weight.
I=Individual sample ``I'' of the material. n=Total number of samples of
the material collected (at least 4) for the averaging period (not to
exceed 1 year).
Qi=Mass quantity of stream represented by Ci, kg/
hr.
QT=Total mass quantity of material during the averaging
period, kilograms per hour.
Ci=Measured VOHAP or HAP concentration of sample ``I'' as
determined in accordance with the requirements of
[[Page 6319]]
Sec. 63.772(a)(4)(iv)(D), parts per million by weight.
(5) Knowledge of the material to determine VOHAP or HAP
concentration.
(i) Sufficient information shall be prepared and recorded that
documents the basis for the owner or operator's knowledge of the
material's VOHAP or HAP concentration. Examples of information that may
be used as the basis for knowledge of the material include: VOHAP or
HAP material balances for the source, process, or unit generating the
material; species-specific VOHAP or HAP chemical test data for the
material from previous testing still applicable to the current
operations; documentation that material is generated by a process for
which no materials containing VOHAP or HAP are used; or previous test
data for other locations managing the same type of material.
(ii) If test data are used as the basis for knowledge of the
material, then the owner or operator shall document the test method,
sampling protocol, and the means by which sampling variability and
analytical variability are accounted for in the determination of the
VOHAP or HAP concentration. For example, an owner or operator may use
HAP concentration test data that are validated in accordance with
Method 301, 40 CFR part 63, appendix A as the basis for knowledge of
the material.
(iii) An owner or operator using species-specific VOHAP or HAP
chemical concentration test data as the basis for knowledge of the
material that is a produced water stream may adjust the test data
results to the corresponding total VOHAP or HAP concentration value
that would be reported had the samples been analyzed using Method 305,
40 CFR part 63, appendix A. To adjust these data, the measured
concentration for each individual VOHAP or HAP chemical species
contained in the material is multiplied by the appropriate species-
specific adjustment factor listed in table 34 in the appendix to 40 CFR
part 63, subpart G.
(b) Determination of glycol dehydration unit flow rate or benzene
emissions. The procedures of this paragraph shall be used by an owner
or operator to determine flow rate or benzene emissions to meet the
criteria for an exemption from control requirements under
Sec. 63.764(e).
(1) The determination of actual flow rate of natural gas to a
glycol dehydration unit shall be made using the procedures of either
paragraph (b)(1)(i) or (b)(1)(ii) of this section.
(i) The owner or operator shall install and operate a monitoring
instrument that directly measures flow to the glycol dehydration unit
with an accuracy of plus or minus 2 percent; or
(ii) The owner or operator shall document that the actual annual
average flow rate of the dehydration unit is less than 85 thousand
cubic meters per day (3.0 million standard cubic feet per day).
(2) The determination of benzene emissions from a glycol
dehydration unit shall be made using the procedures of either paragraph
(b)(2)(i) or (b)(2)(ii) of this section.
(i) The owner or operator shall determine annual benzene emissions
using the model GRI-GLYCalcTM, Version 3.0 or higher. Inputs
to the model shall be representative of actual operating conditions of
the glycol dehydration unit; or
(ii) The owner or operator shall determine an average mass rate of
benzene emissions in kilograms per hour through direct measurement by
performing three runs of Method 18, 40 CFR Part 60, appendix A (or an
equivalent method), and averaging the results of the three runs. Annual
emissions in kilograms per year shall be determined by multiplying the
mass rate by the number of hours the unit is operated per year. This
result shall be multiplied by 1.1023 E-03 to convert to tons
per year.
(c) No detectable emissions test procedure.
(1) The no detectable emissions test procedure shall be conducted
in accordance with Method 21, 40 CFR part 60, appendix A.
(2) The detection instrument shall meet the performance criteria of
Method 21, 40 CFR part 60, appendix A, except that the instrument
response factor criteria in section 3.1.2(a) of Method 21 shall be for
the average composition of the fluid and not for each individual
organic compound in the stream.
(3) The detection instrument shall be calibrated before use on each
day of its use by the procedures specified in Method 21, 40 CFR part
60, appendix A.
(4) Calibration gases shall be as follows:
(i) Zero air (less than 10 parts per million by volume hydrocarbon
in air); and
(ii) A mixture of methane in air at a concentration less than
10,000 parts per million by volume.
(5) The background level shall be determined according to the
procedures in Method 21, 40 CFR part 60, appendix A.
(6) The arithmetic difference between the maximum organic
concentration indicated by the instrument and the background level
shall be compared with the value of 500 parts per million by volume. If
the difference is less than 500 parts per million by volume, then no
HAP emissions are detected.
(d) [Reserved]
(e) Control device performance test procedures. This paragraph
applies to the performance testing of control devices. Owners or
operators may elect to use the alternative procedures in paragraph (f)
of this section for performance testing of a condenser used to control
emissions from a glycol dehydration unit process vent.
(1) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites at the inlet and
outlet of the control device.
(i) To determine compliance with the control device percent
reduction requirement specified in Sec. 63.771(d)(1), sampling sites
shall be located at the inlet of the control device as specified in
paragraphs (e)(1)(i)(A) and (e)(1)(i)(B) of this section, and at the
outlet of the control device.
(A) The control device inlet sampling site shall be located after
the final product recovery device.
(B) If a vent stream is introduced with the combustion air, or as a
secondary fuel, into a boiler or process heater with a design capacity
less than 44 megawatts, selection of the location of the inlet sampling
sites shall ensure the measurement of total HAP or TOC concentration,
as applicable, in all vent streams and primary and secondary fuels.
(ii) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.771(d)(1)(i)(B), the
sampling site shall be located at the outlet of the device.
(2) The gas volumetric flow rate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
(3) To determine compliance with the control device percent
reduction requirement in Sec. 63.771(d)(1)(i), the owner or operator
shall use Method 18, 40 CFR part 60, appendix A; alternatively, any
other method or data that has been validated according to the
applicable procedures in Method 301, 40 CFR part 63, appendix A may be
used. The following procedures shall be used to calculate percent
reduction efficiency:
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall
[[Page 6320]]
be taken at approximately equal intervals in time, such as 15 minute
intervals during the run.
(ii) The mass rate of either TOC (minus methane and ethane) or
total HAP (Ei, Eo) shall be computed.
(A) The following equations shall be used: where:
[GRAPHIC] [TIFF OMITTED] TP06FE98.008
[GRAPHIC] [TIFF OMITTED] TP06FE98.009
Where:
Cij, Coj= Concentration of sample component j of
the gas stream at the inlet and outlet of the control device,
respectively, dry basis, parts per million by volume.
Ei, Eo = Mass rate of TOC (minus methane and
ethane) or total HAP at the inlet and outlet of the control device,
respectively, dry basis, kilogram per hour.
Mij, Moj = Molecular weight of sample component j
of the gas stream at the inlet and outlet of the control device,
respectively, gram/gram-mole.
Qi, Qo = Flow rate of gas stream at the inlet and
outlet of the control device, respectively, dry standard cubic meter
per minute.
K2 =Constant, 2.494 x 10-6 (parts per million)
(gram-mole per standard cubic meter) (kilogram/gram) (minute/hour),
where standard temperature (gram-mole per standard cubic meter) is
20 deg.C.
(B) When the TOC mass rate is calculated, all organic compounds
(minus methane and ethane) measured by Method 18, 40 CFR part 60,
appendix A shall be summed using the equation in paragraph
(e)(3)(ii)(A) of this section.
(C) When the total HAP mass rate is calculated, only HAP chemicals
listed in Table 1 of this subpart shall be summed using the equation in
paragraph (e)(3)(ii)(A) of this section.
(iii) The percent reduction in TOC (minus methane and ethane) or
total HAP shall be calculated as follows
[GRAPHIC] [TIFF OMITTED] TP06FE98.010
Where:
Rcd =Control efficiency of control device, percent.
Ei =Mass rate of TOC (minus methane and ethane) or total HAP
at the inlet to the control device as calculated under paragraph
(e)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per
hour.
Eo =Mass rate of TOC (minus methane and ethane) or total HAP
at the outlet of the control device, as calculated under paragraph
(e)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per
hour.
(iv) If the vent stream entering a boiler or process heater with a
design capacity less than 44 megawatts is introduced with the
combustion air or as a secondary fuel, the weight-percent reduction of
total HAP or TOC (minus methane and ethane) across the device shall be
determined by comparing the TOC (minus methane and ethane) or total HAP
in all combusted vent streams and primary and secondary fuels with the
TOC (minus methane and ethane) or total HAP exiting the device,
respectively.
(4) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.771(d)(1)(i)(B), the
owner or operator shall use Method 18, 40 CFR part 60, appendix A to
measure either TOC (minus methane and ethane) or total HAP.
Alternatively, any other method or data that has been validated
according to Method 301, 40 CFR part 63, appendix A, may be used. The
following procedures shall be used to calculate parts per million by
volume concentration, corrected to 3 percent oxygen:
(i) The minimum sampling time for each run shall be 1 hour, in
which either an integrated sample or a minimum of four grab samples
shall be taken. If grab sampling is used, then the samples shall be
taken at approximately equal intervals in time, such as 15-minute
intervals during the run.
(ii) The TOC concentration or total HAP concentration shall be
calculated according to paragraph (e)(4)(ii)(A) or (e)(4)(ii)(B) of
this section.
(A) The TOC concentration is the sum of the concentrations of the
individual components and shall be computed for each run using the
following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.011
Where:
CTOC = Concentration of total organic compounds minus
methane and ethane, dry basis, parts per million by volume.
Cji = Concentration of sample component j of sample i, dry
basis, parts per million by volume.
n = Number of components in the sample.
x = Number of samples in the sample run.
(B) The total HAP concentration shall be computed according to the
equation in paragraph (e)(4)(ii)(A) of this section, except that only
HAP chemicals listed in Table 1 of this subpart shall be summed.
(iii) The TOC concentration or total HAP concentration shall be
corrected to 3 percent oxygen as follows:
(A) The emission rate correction factor or excess air, integrated
sampling and analysis procedures of Method 3B, 40 CFR part 60, appendix
A shall be used to determine the oxygen concentration. The samples
shall be taken during the same time that the samples are taken for
determining TOC concentration or total HAP concentration.
(B) The TOC or HAP concentration shall be corrected for percent
oxygen by using the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.012
Where:
Cc = TOC concentration or total HAP concentration corrected to 3
percent oxygen, dry basis, parts per million by volume.
Cm = TOC concentration or total HAP concentration, dry
basis, parts per million by volume.
%O2d = Concentration of oxygen, dry basis, percent by
volume.
(f) As an alternative to the procedures in paragraph (e) of this
section, an owner or operator may elect to use the procedures
documented in the Gas Research Institute Report entitled, ``Atmospheric
Rich/Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1).
Sec. 63.773 Inspection and monitoring requirements.
(a) This section applies to an owner or operator using air emission
controls in accordance with the requirements of Secs. 63.765 and
63.766.
(b) Cover inspection and monitoring requirements. (1) Each cover
used in accordance with the requirements of Sec. 63.766 shall be
visually inspected and monitored for no detectable emissions by the
owner or operator using the procedure specified in paragraph (b)(3) of
this section, except as provided for in paragraph (b)(2) of this
section.
(2) An owner or operator is exempt from performing the cover
inspection and monitoring requirements specified in paragraph (b)(3) of
this section for the following units:
(i) A storage vessel internal floating roof that is inspected and
monitored in
[[Page 6321]]
accordance with the requirements of 40 CFR 60.113b(a); or
(ii) A storage vessel external floating roof that is inspected and
monitored in accordance with the requirements of 40 CFR 60.113b(b).
(iii) If a storage vessel is buried partially or entirely
underground, an owner or operator is required to perform the cover
inspection and monitoring requirements specified in paragraph (b)(3) of
this section only for those portions of the storage vessel cover and
those connections to the storage vessel cover or tank body (e.g., fill
ports, access hatches, gauge wells, etc.) that extend to or above the
ground surface and can be opened to the atmosphere.
(3) Inspection and monitoring of a cover shall be performed as
follows:
(i) The cover and all cover openings shall be initially visually
inspected and monitored for no detectable emissions on or before the
date that the unit on which the cover is installed becomes subject to
the provisions of this subpart and at other times as requested by the
Administrator.
(ii) At least once every six months following the initial visual
inspection and monitoring for no detectable emissions required under
paragraph (b)(3)(i) of this section, the owner and operator shall
visually inspect and monitor the cover and each cover opening, except
for following cover openings:
(A) A cover opening that has continuously remained in a closed,
sealed position for the entire period since the last time the cover
opening was visually inspected and monitored for no detectable
emissions;
(B) A cover opening that is designated as unsafe to inspect and
monitor in accordance with paragraph (b)(3)(v) of this section;
(C) A cover opening on a cover installed and placed in operation
before February 6, 1998, that is designated as difficult to inspect and
monitor in accordance with paragraph (b)(3)(vi) of this section.
(iii) To visually inspect a cover, the owner or operator shall view
the entire cover surface and each cover opening in a closed, sealed
position for evidence of any defect that may affect the ability of the
cover or cover opening to continue to operate with no detectable
emissions. A visible hole, gap, tear, or split in the cover surface or
a cover opening is defined as a leak which shall be repaired in
accordance with paragraph (b)(3)(vii) of this section.
(iv) To monitor a cover for no detectable emissions, the owner or
operator shall use the following procedure:
(A) For all cover connections and seals, except for the seals
around a rotating shaft that passes through a cover opening, if the
monitoring instrument indicates an instrument concentration reading
greater than 500 parts per million by volume minus the background
level, then a leak is detected. Each detected leak shall be repaired in
accordance with paragraph (b)(3)(vii) of this section.
(B) For the seals around a rotating shaft that passes through a
cover opening, if the monitoring instrument indicates an instrument
concentration reading greater than 10,000 parts per million by volume
then a leak is detected. Each detected leak shall be repaired in
accordance with paragraph (b)(3)(vii) of this section.
(v) An owner or operator may designate a cover as an unsafe to
inspect and monitor cover if all of the following conditions are met:
(A) The owner or operator determines that inspection or monitoring
of the cover would expose a worker to dangerous, hazardous, or other
unsafe conditions.
(B) The owner or operator develops and implements a written plan
and schedule to inspect the cover using the procedure specified in
paragraph (b)(3)(iii) of this section and monitor the cover using the
procedure specified in paragraph (b)(3)(iv) of this section as
frequently as practicable during those times when a worker can safely
access the cover.
(vi) An owner or operator may designate a cover installed and
placed in operation before February 6, 1998 as a difficult to inspect
and monitor cover if all of the following conditions are met:
(A) The owner or operator determines that inspection or monitoring
the cover requires elevating a worker to a height greater than 2 meters
(approximately 7 feet) above a support surface; and
(B) The owner and operator develops and implements a written plan
and schedule to inspect the cover using the procedure specified in
paragraph (b)(3)(iii) of this section, and monitors the cover using the
procedure specified in paragraph (b)(3)(iv) of this section at least
once per calendar year.
(vii) When a leak is detected by either of the methods specified in
paragraph (b)(3)(iii) or (b)(3)(iv) of this section, the owner or
operator shall make a first attempt at repairing the leak no later than
five calendar days after the leak is detected. Repair of the leak shall
be completed as soon as practicable, but no later than 15 calendar days
after the leak is detected. If repair of the leak cannot be completed
within the 15-day period, then the owner or operator shall not add
material to the unit on which the cover is installed until the repair
of the leak is completed.
(c) Closed-vent system inspection and monitoring requirements. (1)
The owner or operator shall visually inspect and monitor each closed-
vent system for no detectable emissions at the following times:
(i) On or before the date that the unit connected to the closed-
vent system becomes subject to the provisions of this subpart;
(ii) At least once per year after the date that the closed-vent
system is inspected in accordance with the requirements of paragraph
(c)(1)(i) of this section; and
(iii) At other times as requested by the Administrator.
(2) To visually inspect a closed-vent system, the owner or operator
shall view the entire length of ductwork, piping and connections to
covers and control devices for evidence of visible defects (such as
holes in ductwork or piping and loose connections) that may affect the
ability of the system to operate with no detectable emissions. A
visible hole, gap, tear, or split in the closed-vent system is defined
as a leak which shall be repaired in accordance with paragraph (c)(4)
of this section.
(3) To monitor a closed-vent system for no detectable emissions,
the owner or operator shall use Method 21, 40 CFR part 60, appendix A
to test each closed-vent system joint, seam, or other connection. For
the annual leak detection monitoring after the initial leak detection
monitoring, the owner or operator is not required to monitor those
closed-vent system components which continuously operate at a pressure
below atmospheric pressure or those closed-vent system joints, seams,
or other connections that are permanently or semi-permanently sealed
(e.g., a welded joint between two sections of metal pipe or a bolted
and gasketed pipe flange).
(4) When a leak is detected by either of the methods specified in
paragraph (c)(2) or (c)(3) of this section, the owner or operator shall
make a first attempt at repairing the leak no later than five calendar
days after the leak is detected. Repair of the leak shall be completed
as soon as practicable, but no later than 15 calendar days after the
leak is detected.
(d) Control device monitoring requirements. (1) For each control
device, except as provided for in paragraph (d)(2) of this section, the
owner or operator shall install and operate a continuous monitoring
system in accordance with the requirements of paragraphs (d)(3) through
(d)(5) of this
[[Page 6322]]
section. The continuous monitoring system shall be designed and
operated so that a determination can be made on whether the control
device is continuously achieving the applicable performance
requirements of Sec. 63.771.
(2) An owner or operator is exempt from the monitoring requirements
specified in paragraphs (d)(3) through (d)(5) of this section for the
following types of control devices:
(i) A boiler or process heater in which all vent streams are
introduced with primary fuel; or
(ii) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(3) The owner or operator shall install, calibrate, operate, and
maintain a device equipped with a continuous recorder to measure the
values of operating parameters appropriate for the control device as
specified in either paragraph (d)(3)(i), (d)(3)(ii), or (d)(3)(iii) of
this section. The monitoring equipment shall be installed, calibrated,
and maintained in accordance with the equipment manufacturer's
specifications or other written procedures that provide adequate
assurance that the equipment would reasonably be expected to monitor
accurately. The continuous recorder shall be a data recording device
that either records an instantaneous data value at least once every 15
minutes or records 15-minute or more frequent block average values. The
owner or operator shall use any of the following continuous monitoring
systems:
(i) A continuous monitoring system that measures the following
operating parameters as applicable:
(A) For a thermal vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The monitoring device shall
have an accuracy of 1 percent of the temperature being
monitored in deg.C, or 0.5 deg.C, whichever value is
greater. The temperature sensor shall be installed at a location in the
combustion chamber downstream of the combustion zone.
(B) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device shall be capable
of monitoring temperature at two locations and have an accuracy of
1 percent of the temperature being monitored in deg.C, or
0.5 deg.C, whichever value is greater. One temperature
sensor shall be installed in the vent stream at the nearest feasible
point to the catalyst bed inlet and a second temperature sensor shall
be installed in the vent stream at the nearest feasible point to the
catalyst bed outlet.
(C) For a flare, a heat sensing monitoring device equipped with a
continuous recorder that indicates the continuous ignition of the pilot
flame.
(D) For a boiler or process heater with a design heat input
capacity of less than 44 megawatts, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have an accuracy of 1 percent of the temperature
being monitored in deg.C, or 0.5 deg.C, whichever value is
greater. The temperature sensor shall be installed at a location in the
combustion chamber downstream of the combustion zone.
(E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have an
accuracy of 1 percent of the temperature being monitored in
deg.C, or 0.5 deg.C, whichever value is greater. The
temperature sensor shall be installed at a location in the exhaust vent
stream from the condenser.
(F) For a regenerative-type carbon adsorption system, an
integrating regeneration stream flow monitoring device equipped with a
continuous recorder and a carbon bed temperature monitoring device
equipped with a continuous recorder. The integrating regeneration
stream flow monitoring device shall have an accuracy of 10
percent and measure the total regeneration stream mass flow during the
carbon bed regeneration cycle. The temperature monitoring device shall
have an accuracy of 1 percent of the temperature being
monitored in deg.C, or 0.5 deg.C, whichever value is
greater and measure the carbon bed temperature after regeneration and
within 15 minutes of completing the cooling cycle and the duration of
the carbon bed steaming cycle.
(ii) A continuous monitoring system that measures the concentration
level of organic compounds in the exhaust vent stream from the control
device using an organic monitoring device equipped with a continuous
recorder.
(iii) A continuous monitoring system that measures alternative
operating parameters other than those specified in paragraph (d)(3)(i)
or (d)(3)(ii) of this section upon approval of the Administrator as
specified in Sec. 63.8(f)(1) through (f)(5).
(4) For each operating parameter monitored in accordance with the
requirements of paragraph (d)(3) of this section, the owner or operator
shall establish a minimum operating parameter value or a maximum
operating parameter value, as appropriate for the control device, to
define the conditions at which the control device must be operated to
continuously achieve the applicable performance requirements of
Sec. 63.771. Each minimum or maximum operating parameter value shall be
established as follows:
(i) If the owner or operator conducts performance tests in
accordance with the requirements of Sec. 63.771 to demonstrate that the
control device achieves the applicable performance requirements
specified in Sec. 63.771, then the minimum operating parameter value or
the maximum operating parameter value shall be established based on
values measured during the performance test and supplemented, as
necessary, by control device design analysis and manufacturer
recommendations.
(ii) If the owner or operator uses control device design analysis
in accordance with the requirements of Sec. 63.771(d)(3)(iv) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec. 63.771(d)(1), then the minimum operating
parameter value or the maximum operating parameter value shall be
established based on the control device design analysis and the control
device manufacturer's recommendations.
(5) The owner or operator shall regularly inspect the data recorded
by the continuous monitoring system to determine whether the control
device is operating in accordance with the applicable requirements of
Sec. 63.771(d).
Sec. 63.774 Recordkeeping requirements.
(a) The recordkeeping provisions of 40 CFR part 63, subpart A that
apply and those that do not apply to owners and operators of sources
subject to this subpart are listed in Table 2 of this subpart.
(b) Except as specified in paragraphs (c) and (d) of this section,
each owner or operator of a source subject to this subpart shall
maintain the records specified in paragraphs (b)(1) and (b)(2) of this
section in accordance with the requirements of Sec. 63.10(b)(1)
(General Provisions):
(1) Records specified in Sec. 63.10(b)(2);
(2) Records specified in Sec. 63.10(c) for each monitoring system
operated by the owner or operator in accordance with the requirements
of Sec. 63.773(d).
(c) The owner or operator of an area source subject to the control
requirements for triethylene glycol dehydration unit process vents in
Sec. 63.765 is exempt from the requirements of Sec. 63.6(e)(3) and
Sec. 63.10(b)(2)(iv) and (b)(2)(v).
(d) An owner or operator that is exempt from control requirements
[[Page 6323]]
under Sec. 63.764(e) shall maintain a record of the design capacity (in
terms of natural gas flow rate to the unit per day) of each glycol
dehydration unit that is not controlled according to the requirements
of Sec. 63.764(c)(1)(i) and (d)(1).
Sec. 63.775 Reporting requirements.
(a) The reporting provisions of 40 CFR part 63, subpart A that
apply and those that do not apply to owners and operators of sources
subject to these subparts are listed in Table 2 of this subpart.
(b) Each owner or operator of a major source subject to this
subpart shall submit the following reports to the Administrator:
(1) An Initial Notification described in Sec. 63.9(a) through (d),
except that the notification required by Sec. 63.9(b)(2) shall be
submitted not later than one year after the effective date of this
standard.
(2) A Notification of Performance Tests specified in Secs. 63.7 and
63.9(e) and (g).
(3) A Notification of Compliance Status specified in Sec. 63.9(h).
(4) Performance test reports specified in Sec. 63.10(d)(2) and
performance evaluation reports specified in Sec. 63.10(e)(2). Separate
performance evaluation reports as described in Sec. 63.10(e)(2) are not
required if the information is included in the report specified in
paragraph (b)(6) of this section.
(5) Startup, shutdown, and malfunction reports specified in
Sec. 63.10(d)(5) shall be submitted as required. Separate startup,
shutdown, or malfunction reports as described in Sec. 63.10(d)(5) are
not required if the information is included in the report specified in
paragraph (b)(6) of this section.
(6) The excess emission and CMS performance report and summary
report specified in Sec. 63.10(e)(3) shall be submitted on a semi-
annual basis (i.e., once every 6-month period). The summary report
shall be entitled ``Summary Report--Gaseous Excess Emissions and
Continuous Monitoring System Performance.''
(7) The owner or operator shall meet the requirements specified in
paragraph (b) of this section for any emission point or material that
becomes subject to the standards in this subpart due to an increase in
flow, concentration, or other parameters equal to or greater than the
limits specified in this subpart.
(8) For each control device other than a flare used to meet the
requirements of this subpart, the owner or operator shall submit the
following information for each operating parameter required to be
monitored in accordance with the requirements of Sec. 63.773(d):
(i) The minimum operating parameter value or maximum operating
parameter value, as appropriate for the control device, established by
the owner or operator to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.771(d)(1).
(ii) An explanation of the rationale for why the owner or operator
selected each of the operating parameter values established in
paragraph (d)(1) of this section. This explanation shall include any
data and calculations used to develop the value and a description of
why the chosen value indicates that the control device is operating in
accordance with the applicable requirements of Sec. 63.771(d)(1).
(9) Each owner or operator of a major source subject to this
subpart that is not subject to the control requirements for glycol
dehydration unit process vents in Sec. 63.765 is exempt from all
reporting requirements for major sources in this subpart.
(c) Each owner or operator of an area source subject to the control
requirements of this subpart for triethylene glycol dehydration unit
process vents in Sec. 63.765 shall submit the following reports to the
Administrator:
(1) An Initial Notification described in Sec. 63.9 (a) through (d),
except that the notification required by Sec. 63.9(b)(2) shall be
submitted not later than one year after the effective date of this
standard.
(2) A Notification of Performance Tests specified in Secs. 63.7 and
63.9 (e) and (g).
(3) A Notification of Compliance Status specified in Sec. 63.9(h).
(4) Performance test reports specified in Sec. 63.10(d)(2) and
performance evaluation reports specified in Sec. 63.10(e)(2). Separate
performance evaluation reports as described in Sec. 63.10(e)(2) are not
required if the information is included in the report specified in
paragraph (c)(6) of this section.
(5) A report describing any malfunctions that are not corrected
within two calendar days of the malfunction, to be submitted within
seven calendar days of the uncorrected malfunction.
(6) A summary report as specified in Sec. 63.10(e)(3) shall be
submitted on an annual basis (i.e., once every 12-month period). The
summary report shall be entitled ``Summary Report--Gaseous Excess
Emissions and Continuous Monitoring System Performance.''
(7) The owner or operator shall meet the requirements specified in
this paragraph for any emission point or material that becomes subject
to the standards in this subpart due to an increase in flow or
concentration mass parameters equal to or greater than the limits
specified in Sec. 63.764 (b), (c), or (d).
(8) For each control device other than a flare used to meet the
requirements of this subpart, the owner or operator shall submit the
following information for each operating parameter required to be
monitored in accordance with the requirements of Sec. 63.773(d):
(i) The minimum operating parameter value or maximum operating
parameter value, as appropriate for the control device, established by
the owner or operator to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.771(d)(1).
(ii) An explanation of the rationale for why the owner or operator
selected each of the operating parameter values established in
paragraph (d)(1) of this section. This explanation shall include any
data and calculations used to develop the value and a description of
why this value indicates that the control device is operating in
accordance with the applicable requirements of Sec. 63.771(d)(1).
(9) Each owner or operator of an area source subject to this
subpart that is not subject to the control requirements for glycol
dehydration unit process vents in Sec. 63.765 is exempt from all
reporting requirements in this subpart.
Sec. 63.776 Delegation of authority [Reserved]
Sec. 63.777 Alternative means of emission limitation.
(a) If, in the judgment of the Administrator, an alternative means
of emission limitation will achieve a reduction in HAP emissions at
least equivalent to the reduction in HAP emissions from that source
achieved under the applicable requirements in Secs. 63.764 through
63.771, the Administrator will publish in the Federal Register a notice
permitting the use of the alternative means for purposes of compliance
with that requirement. The notice may condition the permission on
requirements related to the operation and maintenance of the
alternative means.
(b) Any notice under paragraph (a) of this section shall be
published only after public notice and an opportunity for a hearing.
[[Page 6324]]
(c) Any person seeking permission to use an alternative means of
compliance under this section shall collect, verify, and submit to the
Administrator information demonstrating that the alternative achieves
equivalent emission reductions.
Sec. 63.778 [Reserved]
Sec. 63.779 [Reserved]
Table 1 to Subpart HH.--List of Hazardous Air Pollutants for Subpart HH
------------------------------------------------------------------------
CAS Number a Chemical name
------------------------------------------------------------------------
75070............................... Acetaldehyde.
71432............................... Benzene (includes benzene in
gasoline).
75150............................... Carbon disulfide.
463581.............................. Carbonyl sulfide.
100414.............................. Ethyl benzene.
107211.............................. Ethylene glycol.
50000............................... Formaldehyde.
110543.............................. n-Hexane.
91203............................... Naphthalene.
108883.............................. Toluene.
540841.............................. 2,2,4-Trimethylpentane.
1330207............................. Xylenes (isomers and mixture).
95476............................... o-Xylene.
108383.............................. m-Xylene.
106423.............................. p-Xylene.
------------------------------------------------------------------------
a CAS numbers refer to the Chemical Abstracts Services registry number
assigned to specific compounds, isomers, or mixtures of compounds.
Table 2 to Subpart HH.--Applicability of 40 CFR Part 63 General Provisions to Subpart HH
----------------------------------------------------------------------------------------------------------------
General provisions reference Applicable to subpart HH Comment
----------------------------------------------------------------------------------------------------------------
Sec. 63.1(a)(1)........................ Yes........................
Sec. 63.1(a)(2)........................ Yes........................
Sec. 63.1(a)(3)........................ Yes........................
Sec. 63.1(a)(4)........................ Yes........................
Sec. 63.1(a)(5)........................ No......................... Section reserved.
Sec. 63.1(a)(6)-(a)(8)................. Yes........................
Sec. 63.1(a)(9)........................ No......................... Section reserved.
Sec. 63.1(a)(10)....................... Yes........................
Sec. 63.1(a)(11)....................... Yes........................
Sec. 63.1(a)(12)-(a)(14)............... Yes........................
Sec. 63.1(b)(1)........................ No......................... Subpart HH specifies applicability.
Sec. 63.1(b)(2)........................ Yes........................
Sec. 63.1(b)(3)........................ No.........................
Sec. 63.1(c)(1)........................ No......................... Subpart HH specifies applicability.
Sec. 63.1(c)(2)........................ Yes........................ Unless required by the State, area
sources subject to subpart HH are
exempted from permitting requirements.
Sec. 63.1(c)(3)........................ No......................... Section reserved.
Sec. 63.1(c)(4)........................ Yes........................
Sec. 63.1(c)(5)........................ Yes........................
Sec. 63.1(d)........................... No......................... Section reserved.
Sec. 63.1(e)........................... Yes........................
Sec. 63.2.............................. Yes........................ Except definition of major source is
unique for this source category and
there are additional definitions in
subpart HH.
Sec. 63.3(a)-(c)....................... Yes........................
Sec. 63.4(a)(1)-(a)(3)................. Yes........................
Sec. 63.4(a)(4)........................ No......................... Section reserved.
Sec. 63.4(a)(5)........................ Yes........................
Sec. 63.4(b)........................... Yes........................
Sec. 63.4(c)........................... Yes........................
Sec. 63.5(a)(1)........................ Yes........................
Sec. 63.5(a)(2)........................ No......................... Preconstruction review required only for
major sources that commence construction
after promulgation of the standard.
Sec. 63.5(b)(1)........................ Yes........................
Sec. 63.5(b)(2)........................ No......................... Section reserved.
Sec. 63.5(b)(3)........................ Yes........................
Sec. 63.5(b)(4)........................ Yes........................
Sec. 63.5(b)(5)........................ Yes........................
Sec. 63.5(b)(6)........................ Yes........................
Sec. 63.5(c)........................... No......................... Section reserved.
Sec. 63.5(d)(1)........................ Yes........................
Sec. 63.5(d)(2)........................ Yes........................
Sec. 63.5(d)(3)........................ Yes........................
Sec. 63.5(d)(4)........................ Yes........................
Sec. 63.5(e)........................... Yes........................
Sec. 63.5(f)(1)........................ Yes........................
Sec. 63.5(f)(2)........................ Yes........................
Sec. 63.6(a)........................... Yes........................
Sec. 63.6(b)(1)........................ Yes........................
Sec. 63.6(b)(2)........................ Yes........................
Sec. 63.6(b)(3)........................ Yes........................
Sec. 63.6(b)(4)........................ Yes........................
[[Page 6325]]
Sec. 63.6(b)(5)........................ Yes........................
Sec. 63.6(b)(6)........................ No......................... Section reserved.
Sec. 63.6(b)(7)........................ Yes........................
Sec. 63.6(c)(1)........................ Yes........................
Sec. 63.6(c)(2)........................ Yes........................
Sec. 63.6(c)(3)-(c)(4)................. No......................... Sections reserved.
Sec. 63.6(c)(5)........................ Yes........................
Sec. 63.6(d)........................... No......................... Section reserved.
Sec. 63.6(e)........................... Yes/No..................... Area sources exempt from paragraph
(e)(3).
Sec. 63.6(f)(1)........................ Yes........................
Sec. 63.6(f)(2)........................ Yes........................
Sec. 63.6(f)(3)........................ Yes........................
Sec. 63.6(g)........................... Yes........................
Sec. 63.6(h)........................... No......................... Subpart HH does not require continuous
emissions monitoring systems.
Sec. 63.6(i)(1)-(i)(14)................ Yes........................
Sec. 63.6(i)(15)....................... No......................... Section reserved.
Sec. 63.6(i)(16)....................... Yes........................
Sec. 63.6(j)........................... Yes........................
Sec. 63.7(a)(1)........................ Yes........................
Sec. 63.7(a)(2)........................ Yes........................
Sec. 63.7(a)(3)........................ Yes........................
Sec. 63.7(b)........................... Yes........................
Sec. 63.7(c)........................... Yes........................
Sec. 63.7(d)........................... Yes........................
Sec. 63.7(e)(1)........................ Yes........................
Sec. 63.7(e)(2)........................ Yes........................
Sec. 63.7(e)(3)........................ Yes........................
Sec. 63.7(e)(4)........................ Yes........................
Sec. 63.7(f)........................... Yes........................
Sec. 63.7(g)........................... Yes........................
Sec. 63.7(h)........................... Yes........................
Sec. 63.8(a)(1)........................ Yes........................
Sec. 63.8(a)(2)........................ Yes........................
Sec. 63.8(a)(3)........................ No......................... Section reserved.
Sec. 63.8(a)(4)........................ Yes........................
Sec. 63.8(b)(1)........................ Yes........................
Sec. 63.8(b)(2)........................ Yes........................
Sec. 63.8(b)(3)........................ Yes........................
Sec. 63.8(c)(1)........................ Yes........................
Sec. 63.8(c)(2)........................ Yes........................
Sec. 63.8(c)(3)........................ Yes........................
Sec. 63.8(c)(4)........................ No.........................
Sec. 63.8(c)(5)-(c)(8)................. Yes........................
Sec. 63.8(d)........................... Yes........................
Sec. 63.8(e)........................... Yes........................
Sec. 63.8(f)(1)-(f)(5)................. Yes........................
Sec. 63.8(f)(6)........................ No......................... Subpart HH does not require continuous
emissions monitoring.
Sec. 63.8(g)........................... No......................... Subpart HH specifies continuous
monitoring system data reduction
requirements.
Sec. 63.9(a)........................... Yes........................
Sec. 63.9(b)(1)........................ Yes........................
Sec. 63.9(b)(2)........................ Yes........................ Sources are given one year (rather than
120 days) to submit this notification.
Sec. 63.9(b)(3)........................ Yes........................
Sec. 63.9(b)(4)........................ Yes........................
Sec. 63.9(b)(5)........................ Yes........................
Sec. 63.9(c)........................... Yes........................
Sec. 63.9(d)........................... Yes........................
Sec. 63.9(e)........................... Yes........................
Sec. 63.9(f)........................... No.........................
Sec. 63.9(g)........................... Yes........................
Sec. 63.9(h)(1)-(h)(3)................. Yes........................
Sec. 63.9(h)(4)........................ No......................... Section reserved.
Sec. 63.9(h)(5)-(h)(6)................. Yes........................
Sec. 63.9(i)........................... Yes........................
Sec. 63.9(j)........................... Yes........................
Sec. 63.10(a).......................... Yes........................
Sec. 63.10(b)(1)....................... Yes........................
Sec. 63.10(b)(2)....................... Yes/No..................... Area sources are exempt from paragraphs
(b)(2)(iv) and (v).
Sec. 63.10(b)(3)....................... No.........................
Sec. 63.10(c)(1)....................... Yes........................
Sec. 63.10(c)(2)-(c)(4)................ No......................... Sections reserved.
Sec. 63.10(c)(5)-(c)(8)................ Yes........................
Sec. 63.10(c)(9)....................... No......................... Section reserved.
[[Page 6326]]
Sec. 63.10(c)(10)-(c)(15).............. Yes........................
Sec. 63.10(d)(1)....................... Yes........................
Sec. 63.10(d)(2)....................... Yes........................
Sec. 63.10(d)(3)....................... Yes........................
Sec. 63.10(d)(4)....................... Yes........................
Sec. 63.10(d)(5)....................... Yes/No..................... Subpart HH requires major sources to
submit a startup, shutdown and
malfunction report semi-annually; area
sources are exempt.
Sec. 63.10(e).......................... Yes/No..................... Subpart HH requires major sources to
submit continuous monitoring system
performance reports semi-annually; area
sources are required to send these
reports annually.
Sec. 63.10(f).......................... Yes........................
Sec. 63.11(a)-(b)...................... Yes........................
Sec. 63.12(a)-(c)...................... Yes........................
Sec. 63.13(a)-(c)...................... Yes........................
Sec. 63.14(a)-(b)...................... Yes........................
Sec. 63.15(a)-(b)...................... Yes........................
----------------------------------------------------------------------------------------------------------------
B. Part 63 is amended by adding subpart HHH to read as follows:
Subpart HHH--National Emission Standards for Hazardous Air Pollutants
from Natural Gas Transmission and Storage Facilities
Sec.
63.1270 Applicability and designation of affected source.
63.1271 Definitions.
63.1272 [Reserved]
63.1273 [Reserved]
63.1274 General standards.
63.1275 Glycol dehydration unit process vent standards.
63.1276 [Reserved]
63.1277 [Reserved]
63.1278 [Reserved]
63.1279 [Reserved]
63.1280 [Reserved]
63.1281 Control equipment requirements.
63.1282 Test methods and compliance procedures.
63.1283 Inspection and monitoring requirements.
63.1284 Recordkeeping requirements.
63.1285 Reporting requirements.
63.1286 Delegation of authority. [Reserved]
63.1287 Alternative means of emission limitation.
63.1288 [Reserved]
63.1289 [Reserved]
Table 1 to Subpart HHH--List of Hazardous Air Pollutants (HAP) for
Subpart HHH
Table 2 to Subpart HHH--Applicability of 40 CFR Part 63 General
Provisions to Subpart HHH
Subpart HHH--National Emission Standards for Hazardous Air
Pollutants From Natural Gas Transmission and Storage Facilities
Sec. 63.1270 Applicability and designation of affected source.
(a) This subpart applies to owners or operators of natural gas
transmission and storage facilities that transport or store natural gas
prior to entering the pipeline to a local distribution company or to a
final end user and that are major sources of hazardous air pollutant
(HAP) emissions.
(b) The affected source is each glycol dehydration unit.
(c) The owner or operator of a facility that does not contain an
affected source, as specified in paragraph (b) of this section, is not
subject to the requirements of this subpart.
(d) The owner or operator of each affected source shall achieve
compliance with the provisions of this subpart by the following dates:
(1) The owner or operator of an affected source the construction or
reconstruction of which commenced before February 6, 1998, shall
achieve compliance with the provisions of the subpart as expeditiously
as practical after [the date of publication of the final rule], but no
later than three years after [the date of publication of the final
rule] except as provided for in Sec. 63.6(i).
(2) The owner or operator of an affected source the construction or
reconstruction of which commences on or after February 6, 1998, shall
achieve compliance with the provisions of this subpart immediately upon
startup or [the date of publication of the final rule], whichever date
is later.
(e) An owner or operator of an affected source that is a major
source or located at a major source and is subject to the provisions of
this subpart is also subject to 40 CFR part 70 permitting requirements.
Sec. 63.1271 Definitions.
All terms used in this subpart shall have the meaning given to them
in the Clean Air Act, subpart A of this part (General Provisions), and
in this section. If the same term is defined in subpart A and in this
section, it shall have the meaning given in this section for purposes
of this subpart.
Associated equipment, as used in this subpart and as referred to in
section 112(n)(4) of the Act, means equipment associated with an oil or
natural gas exploration or production well, and includes all equipment
from the wellbore to the point of custody transfer, except glycol
dehydration units and storage vessels with the potential for flash
emissions.
Average concentration, as used in this subpart, means the flow-
weighted annual average concentration, as determined according to the
procedures specified in Sec. 63.1282(a).
Boiler means any enclosed combustion device that extracts useful
energy in the form of steam and is not an incinerator.
Closed-vent system means a system that is not open to the
atmosphere and is composed of piping, ductwork, connections, and, if
necessary, flow inducing devices that transport gas or vapor from an
emission point to a control device or back into the process. If gas or
vapor from regulated equipment is routed to a process (e.g., to a fuel
gas system), the process shall not be considered a closed vent system
and is not subject to closed vent system standards.
Combustion device means an individual unit of equipment, such as a
flare, incinerator, process heater, or boiler, used for the combustion
of volatile organic compound vapors.
Compressor station means any permanent combination of equipment
that supplies energy to move natural gas at increased pressure from
fields, in transmission pipelines, or into storage.
Continuous recorder means a data recording device that either
records an instantaneous data value at least once every 15 minutes or
records 15-minute or more frequent block average values.
[[Page 6327]]
Control device means any equipment used for recovering or oxidizing
hazardous air pollutant (HAP) and volatile organic compound (VOC)
vapors. Such equipment includes, but is not limited to, absorbers,
carbon adsorbers, condensers, incinerators, flares, boilers, and
process heaters. For the purposes of this subpart, if gas or vapor from
regulated equipment is used, reused, returned back to the process, or
sold, then the recovery system used, including piping, connections, and
flow inducing devices, is not considered to be control devices.
Facility means any grouping of equipment where natural gas is
processed, compressed, or stored prior to entering a pipeline to a
local distribution company or to a final end user. A facility for this
source category typically is: A natural gas compressor station that
receives natural gas via pipeline, from an underground natural gas
storage operation, from a condensate tank battery, or from a natural
gas processing plant; or An underground natural gas storage operation.
The emission points associated with these phases include, but are not
limited to, process vents. Processes that may have vents include, but
are not limited to, dehydration, and compressor station engines.
Facility, for the purpose of a major source determination, means
natural gas transmission and storage equipment that is located inside
the boundaries of an individual surface site connected by ancillary
equipment, such as gas flow lines, roads, or power lines. Equipment
that is part of a facility will typically be located within close
proximity to other equipment located at the same facility. Natural gas
transmission and storage equipment or groupings of equipment located on
different gas leases, mineral fee tracts, lease tracts, subsurface unit
areas, surface fee tracts, or surface lease tracts shall not be
considered part of the same facility.
Flame zone means the portion of the combustion chamber in a boiler
occupied by the flame envelope.
Flow indicator means a device which indicates whether gas flow is
present in a line.
Gas-condensate-glycol (GCG) separator means a two-or three-phase
separator through which the ``rich'' glycol stream of a glycol
dehydration unit is passed to remove entrained gas and hydrocarbon
liquid. The GCG separator is commonly referred to as a flash separator
or flash tank.
Glycol dehydration unit means a device in which a liquid glycol
directly contacts a natural gas stream (that is circulated counter
current to the glycol flow) and absorbs water vapor in a contact tower
or absorption column (absorber). The glycol contacts and absorbs water
vapor and other gas stream constituents from the natural gas and
becomes ``rich'' glycol. This glycol is then regenerated by distilling
the water and other gas stream constituents in the glycol dehydration
unit reboiler. The distilled or ``lean'' glycol is then recycled back
to the absorber.
Glycol dehydration unit reboiler vent means the vent through which
exhaust from the reboiler of a glycol dehydration unit passes from the
reboiler to the atmosphere.
Glycol dehydration unit process vent means either the glycol
dehydration unit reboiler vent or the vent from the GCG separator
(flash tank).
Hazardous air pollutants or HAP means the chemical compounds listed
in section 112(b) of the Act. All chemical compounds listed in section
112(b) of the Act need to be considered when making a major source
determination. Only the HAP compounds listed in Table 1 of this subpart
need to be considered when determining applicability and compliance.
Incinerator means an enclosed combustion device that is used for
destroying organic compounds. Auxiliary fuel may be used to heat waste
gas to combustion temperatures. Any energy recovery section shall not
be physically formed into one manufactured or assembled unit with the
combustion section; rather, the energy recovery section shall be a
separate section following the combustion section and the two are
joined by ducts or connections carrying flue gas. The above energy
recovery section limitation does not apply to an energy recovery
section used solely to permit the incoming vent stream or combustion
air.
Major source, as used in this subpart, shall have the same meaning
as in Sec. 63.2, except that:
(1) Emissions from any oil or gas exploration or production well
(with its associated equipment) and emissions from any pipeline
compressor or pump station shall not be aggregated with emissions from
other similar units, whether or not such units are in a contiguous area
or under common control; and
(2) Emissions from processes, operations, and equipment that are
not part of the same facility, as defined in this section, shall not be
aggregated.
Natural gas means the gaseous mixture of hydrocarbon gases and
vapors, primarily consisting of methane, ethane, propane, butane,
pentane, and hexane, along with water vapor and other constituents.
Natural gas transmission means the pipelines used for the long
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used for transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
No detectable emissions means no escape of hazardous air pollutants
(HAP) from a device or system to the atmosphere as determined by:
(1) Testing the device or system in accordance with the
requirements of Sec. 63.1282(d); and
(2) No visible openings or defects in the device or system such as
rips, tears, or gaps.
Operating parameter value means a minimum or maximum value
established for a control device or process parameter which, if
achieved by itself or in combination with one or more other operating
parameter values, determines that an owner or operator has complied
with an applicable emission limitation or standard.
Operating permit means a permit required by 40 CFR part 70 or part
71.
Organic monitoring device means a unit of equipment used to
indicate the concentration level of organic compounds exiting a
recovery device based on a detection principle such as infra-red,
photoionization, or thermal conductivity.
Point of material entry means at the point where a material first
enters a source subject to this subpart.
Primary fuel means the fuel that provides the principal heat input
(i.e., more than 50-percent) to the device. To be considered primary,
the fuel must be able to sustain operation without the addition of
other fuels.
Process heater means a device that transfers heat liberated by
burning fuel directly to process streams or to heat transfer liquids
other than water.
Safety device means a device that is not used for planned or
routine venting of liquids, gases, or fumes from the unit or equipment
on which the device is installed; and the device remains in a closed,
sealed position at all times except when an unplanned event requires
that the device open for the purpose of preventing physical damage or
permanent deformation of the unit or equipment on which the device is
installed in accordance with good
[[Page 6328]]
engineering and safety practices for handling flammable, combustible,
explosive, or other hazardous materials. Examples of unplanned events
which may require a safety device to open include failure of an
essential equipment component or a sudden power outage.
Storage vessel means a tank or other vessel that is designed to
contain an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water and constructed primarily of
non-earthen materials (e.g., wood, concrete, steel, plastic) that
provide structural support.
Temperature monitoring device means a unit of equipment used to
monitor temperature and having an accuracy of 1 percent of
the temperature being monitored expressed in deg.C, or
0.5 deg.C, whichever is greater.
Total organic compounds or TOC, as used in this subpart, means
those compounds measured according to the procedures of Method 18, 40
CFR part 60, appendix A.
Underground storage means the subsurface facilities utilized for
storing natural gas that has been transferred from its original
location for the primary purpose of load balancing, which is the
process of equalizing the receipt and delivery of natural gas.
Processes and operations that may be located at an underground storage
facility include, but are not limited to, compression and dehydration.
Sec. 63.1272 [Reserved]
Sec. 63.1273 [Reserved]
Sec. 63.1274 General standards.
(a) The owner or operator of an affected source (i.e., glycol
dehydration unit) located at an existing or new major source of HAP
emissions shall comply with the requirements in this subpart as
follows:
(1) The control requirements for glycol dehydration unit process
vents specified in Sec. 63.1275,
(2) The monitoring requirements of Sec. 63.1283, and
(3) The recordkeeping and reporting requirements of Secs. 63.1284
and 63.1285.
(b) The owner or operator is exempt from the requirements of
paragraph (a) of this section if the actual annual average flow of
natural gas to the glycol dehydration unit is less than 85 thousand
cubic meters per day (3.0 million standard cubic feet per day) or
emissions of benzene from the unit to the atmosphere are less than 0.9
megagram per year (1 ton per year). The flow of gas to the unit and
emissions of benzene from the unit shall be determined by the
procedures specified in Sec. 63.1282(a). This determination must be
made available to the Administrator upon request.
(c) Each owner or operator of a major HAP source subject to this
subpart is required to apply for a part 70 or part 71 operating permit
from the appropriate permitting authority. If the Administrator has
approved a State operating permit program under 40 CFR part 70, the
permit shall be obtained from the State authority. If the State
operating permit program has not been approved, the owner or operator
of a source shall apply to the EPA Regional Office pursuant to 40 CFR
part 71.
(d) An owner or operator of an affected source that is a major
source or located at a major source subject to the provisions of this
subpart that is in violation of an operating parameter value is in
violation of the applicable emission limitation or standard.
Sec. 63.1275 Glycol dehydration unit process vents standards.
(a) This section applies to each glycol dehydration unit process
vent required to meet the air emission control requirements specified
in Sec. 63.1274(a).
(b) Except as provided in paragraph (c) of this section, the
following air emission control requirements apply to glycol dehydration
unit process vents at an existing or new source.
(1) For each glycol dehydration unit process vent, the owner or
operator shall control air emissions by connecting the process vent
through a closed-vent system to a control device designed and operated
in accordance with the requirements of Sec. 63.1281(c) and (d).
(2) One or more safety devices that vent directly to the atmosphere
may be used on the air emission control equipment complying with
paragraph (b)(1) of this section.
(c) As an alternative to the requirements of paragraph (b) of this
section, the owner or operator may comply with one of the following:
(1) The owner or operator shall control air emissions by connecting
the process vent to a process natural gas line through a closed-vent
system designed and operated in accordance with the requirements of
Sec. 63.1281(c) and (d).
(2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that total HAP emissions to the atmosphere from the
glycol dehydration unit reboiler vent and GCG separator (flash tank)
vent (if present) are reduced by 95 percent through process
modifications.
(3) Control of HAP emissions from a GCG separator (flash tank) vent
is not required if the owner or operator demonstrates, to the
Administrator's satisfaction, that total HAP emissions to the
atmosphere from the glycol dehydration unit reboiler vent and GCG
separator (flash tank) vent are reduced by 95 percent.
Sec. 63.1276 [Reserved]
Sec. 63.1277 [Reserved]
Sec. 63.1278 [Reserved]
Sec. 63.1279 [Reserved]
Sec. 63.1280 [Reserved]
Sec. 63.1281 Control equipment requirements.
(a) This section applies to each closed-vent system, and control
device installed and operated by the owner or operator to control air
emissions in accordance with the standards of this subpart.
(b) [Reserved]
(c) Closed-vent system requirements. (1) The closed-vent system
shall route all gases, vapors, and fumes emitted from the material in
the unit to a control device that meets the requirements specified in
paragraph (d) of this section.
(2) The closed-vent system shall be designed and operated with no
detectable emissions.
(3) If the closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, the owner or operator shall
meet the following requirements:
(i) For each bypass device except as provided for in paragraph
(c)(3)(ii) of this section, the owner or operator shall either:
(A) Install, calibrate, maintain, and operate a flow indicator at
the inlet to the bypass device that indicates at least once every 15
minutes whether gas, vapor, or fume flow is present in the bypass
device; or
(B) Secure the valve installed at the inlet to the bypass device in
the closed position using a car-seal or a lock-and-key type
configuration. The owner or operator shall visually inspect the seal or
closure mechanism at least once every month to verify that the valve is
maintained in the closed position.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (c)(3)(i) of this section.
(d) Control device requirements. (1) The control device shall be
one of the following devices:
[[Page 6329]]
(i) An enclosed combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) that is
designed and operated in accordance with one of the following
performance requirements:
(A) Reduces the mass content of either TOC or total HAP in the
gases vented to the device by 95 percent by weight or greater, as
determined in accordance with the requirements of Sec. 63.1282(d);
(B) Reduces the concentration of either TOC or a total HAP in the
exhaust gases at the outlet to the device to a level equal to or less
than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec. 63.1282(d)(4); or
(C) Operates at a minimum residence time of 0.5 second at a minimum
temperature of 760 deg.C. If a boiler or process heater is used as the
control device, then the vent stream shall be introduced into the flame
zone of the boiler or process heater.
(ii) A vapor recovery device (e.g., condenser) that is designed and
operated to reduce the mass content of either TOC or total HAP in the
gases vented to the device by 95 percent by weight or greater as
determined in accordance with the requirements of Sec. 63.1282(d).
(iii) A flare that is designed and operated in accordance with the
requirements of Sec. 63.11(b).
(2) Each control device used to comply with this subpart shall be
operated at all times when material is placed in a unit vented to the
control device except when maintenance or repair of a unit cannot be
completed without a shutdown of the control device. An owner or
operator may vent more than one unit to a control device used to comply
with this subpart.
(3) The owner or operator shall demonstrate that a control device
achieves the performance requirements of paragraph (d)(1) of this
section as follows:
(i) An owner or operator shall demonstrate, using either a
performance test as specified in paragraph (d)(3)(iii) of this section
or a design analysis as specified in paragraph (d)(3)(iv) of this
section, the performance of each control device except for the
following:
(A) A flare;
(B) A boiler or process heater with a design heat input capacity of
44 megawatts or greater;
(C) A boiler or process heater into which the vent stream is
introduced with the primary fuel; or
(D) A boiler or process heater burning hazardous waste for which
the owner or operator either has been issued a final permit under 40
CFR part 270 and complies with the requirements of 40 CFR part 266,
subpart H; or has certified compliance with the interim status
requirements of 40 CFR part 266, subpart H.
(ii) An owner or operator shall demonstrate the performance of each
flare in accordance with the requirements specified in Sec. 63.11(b).
(iii) For a performance test conducted to meet the requirements of
paragraph (d)(3)(i) of this section, the owner or operator shall use
the test methods and procedures specified in Sec. 63.1282(d) or (e).
(iv) For a design analysis conducted to meet the requirements of
paragraph (d)(3)(i) of this section, the design analysis shall meet the
following requirements:
(A) The design analysis shall include analysis of the vent stream
characteristics and control device operating parameters for the
applicable control device type as follows:
(1) For a thermal vapor incinerator, the design analysis shall
address the vent stream composition, constituent concentrations, and
flow rate and shall establish the design minimum and average
temperatures in the combustion zone and the combustion zone residence
time.
(2) For a catalytic vapor incinerator, the design analysis shall
address the vent stream composition, constituent concentrations, flow
rate, and shall establish the design minimum and average temperatures
across the catalyst bed inlet and outlet, and the design service life
of the catalyst.
(3) For a boiler or process heater, the design analysis shall
address the vent stream composition, constituent concentrations, and
flow rate; shall establish the design minimum and average flame zone
temperatures and combustion zone residence time; and shall describe the
method and location where the vent stream is introduced into the flame
zone.
(4) For a condenser, the design analysis shall address the vent
stream composition, constituent concentrations, flow rate, relative
humidity, and temperature and shall establish the design outlet organic
compound concentration level, design average temperature of the
condenser exhaust vent stream, and the design average temperatures of
the coolant fluid at the condenser inlet and outlet.
(5) For a carbon adsorption system that regenerates the carbon bed
directly on-site in the control device such as a fixed-bed adsorber,
the design analysis shall address the vent stream composition,
constituent concentrations, flow rate, relative humidity, and
temperature and shall establish the design exhaust vent stream organic
compound concentration level, adsorption cycle time, number and
capacity of carbon beds, type and working capacity of activated carbon
used for carbon beds, design total regeneration stream flow over the
period of each complete carbon bed regeneration cycle, design carbon
bed temperature after regeneration, design carbon bed regeneration
time, and design service life of the carbon.
(6) For a carbon adsorption system that does not regenerate the
carbon bed directly on-site in the control device such as a carbon
canister, the design analysis shall address the vent stream
composition, constituent concentrations, flow rate, relative humidity,
and temperature and shall establish the design exhaust vent stream
organic compound concentration level, capacity of carbon bed, type and
working capacity of activated carbon used for carbon bed, and design
carbon replacement interval based on the total carbon working capacity
of the control device and source operating schedule.
(B) If the owner or operator and the Administrator do not agree on
a demonstration of control device performance using a design analysis
then the disagreement shall be resolved using the results of a
performance test performed by the owner or operator in accordance with
the requirements of paragraph (d)(3)(iii) of this section. The
Administrator may choose to have an authorized representative observe
the performance test.
(4) The owner or operator shall operate each control device in
accordance with the following requirements:
(i) The control device shall be operating at all times when gases,
vapors, and fumes are vented from the unit or units through the closed-
vent system to the control device.
(ii) For each control device monitored in accordance with the
requirements of Sec. 63.1283(d), the owner or operator shall operate
the control device such that the actual value of each operating
parameter required to be monitored in accordance with the requirements
of Sec. 63.1283(d)(3) is greater than the minimum operating parameter
value or less than the maximum operating parameter value, as
appropriate, established for the control device in accordance with the
requirements of Sec. 63.1283(d)(4).
(iii) Failure by the owner or operator to operate the control
device in accordance with the requirements of paragraph (d)(4)(ii) of
this section shall
[[Page 6330]]
constitute a violation of the applicable emission standard of this
subpart.
(5) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (d)(1) of this section, the owner or
operator shall manage the carbon as follows:
(i) Following the initial startup of the control device, all carbon
in the control device shall be replaced with fresh carbon on a regular,
predetermined time interval that is no longer than the carbon service
life established for the carbon adsorption system.
(ii) All carbon removed from the control device shall be managed in
one of the following manners:
(A) Regenerated or reactivated in a thermal treatment unit for
which the owner or operator has either been issued a final permit under
40 CFR part 270, and designs and operates the unit in accordance with
the requirements of 40 CFR part 264, subpart X; or certified compliance
with the interim status requirements of 40 CFR part 265, subpart P.
(B) Burned in a hazardous waste incinerator for which the owner or
operator has been issued a final permit under 40 CFR part 270, and
designs and operates the unit in accordance with the requirements of 40
CFR part 264, subpart O.
(C) Burned in a boiler or industrial furnace for which the owner or
operator has either been issued a final permit under 40 CFR part 270,
and designs and operates the unit in accordance with the requirements
of 40 CFR part 266, subpart H, or has certified compliance with the
interim status requirements of 40 CFR part 266, subpart H.
Sec. 63.1282 Test methods and compliance procedures.
(a) Determination of glycol dehydration unit flow rate or benzene
emissions. The procedures of this paragraph shall be used by an owner
or operator to determine flow rate or benzene emissions to meet the
criteria for an exemption from control requirements under
Sec. 63.1274(b).
(1) The determination of actual flow rate of natural gas to a
glycol dehydration unit shall be made using the procedures of either
paragraph (a)(1)(i) or (a)(1)(ii) of this section.
(i) The owner or operator shall install and operate a monitoring
instrument that directly measures flow to the glycol dehydration unit
with an accuracy of plus or minus 2 percent.
(ii) The owner or operator shall document that the actual annual
average flow rate of the dehydration unit is less than 85 thousand
cubic meters per day (3.0 million standard cubic feet per day).
(2) The determination of benzene emissions from a glycol
dehydration unit shall be made using the procedures of either paragraph
(a)(2)(i) or (a)(2)(ii) of this section.
(i) The owner or operator shall determine annual benzene emissions
using the model GRI-GLYCalcTM, Version 3.0 or higher. Inputs
to the model shall be representative of actual operating conditions of
the glycol dehydration unit.
(ii) The owner or operator shall determine an average mass rate of
benzene emissions in kilograms per hour through direct measurement by
performing three runs of Method 18 in 40 CFR part 60, appendix A (or an
equivalent method), and averaging the results of the three runs. Annual
emissions in kilograms per year shall be determined by multiplying the
mass rate by the number of hours the unit is operated per year. This
result shall be multiplied by 1.1023 E-03 to convert to tons
per year.
(b) No detectable emissions test procedure.
(1) The procedure shall be conducted in accordance with Method 21,
40 CFR part 60, appendix A.
(2) The detection instrument shall meet the performance criteria of
Method 21, 40 CFR part 60, appendix A, except the instrument response
factor criteria in section 3.1.2(a) of Method 21 shall be for the
average composition of the fluid, and not for each individual organic
compound in the stream.
(3) The detection instrument shall be calibrated before use on each
day of its use by the procedures specified in Method 21, 40 CFR part
60, appendix A.
(4) Calibration gases shall be as follows:
(i) Zero air (less than 10 parts per million by volume hydrocarbon
in air); and
(ii) A mixture of methane in air at a methane concentration of less
than 10,000 parts per million by volume.
(5) The background level shall be determined according to the
procedures in Method 21, 40 CFR part 60, appendix A.
(6) The arithmetic difference between the maximum organic
concentration indicated by the instrument and the background level
shall be compared with the value of 500 parts per million by volume. If
the difference is less than 500 parts per million by volume, then no
HAP emissions are detected.
(c) [Reserved]
(d) Control device performance test procedures. This paragraph
applies to the performance testing of control devices. Owners or
operators may elect to use the alternative procedures in paragraph (e)
of this section for performance testing of a condenser used to control
emissions from a glycol dehydration unit process vent.
(1) Method 1 or 1A of 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites at the inlet and
outlet of the control device.
(i) To determine compliance with the control device percentage of
reduction requirement specified in Sec. 63.1281(d)(1)(i)(A) or
Sec. 63.1281(d)(1)(ii)(A), sampling sites shall be located at the inlet
of the control device as specified in paragraphs (d)(1)(i)(A) and
(d)(1)(i)(B) of this section, and at the outlet of the control device.
(A) The control device inlet sampling site shall be located after
the final product recovery device.
(B) If a vent stream is introduced with the combustion air, or as a
secondary fuel, into a boiler or process heater with a design capacity
less than 44 megawatts, selection of the location of the inlet sampling
sites shall ensure the measurement of total HAP or TOC concentration,
as applicable, in all vent streams and primary and secondary fuels.
(ii) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B),
the sampling site shall be located at the outlet of the device.
(2) The gas volumetric flow rate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
(3) To determine compliance with the control device percentage of
reduction requirement specified in Sec. 63.1281(d)(1)(i)(A) or
Sec. 63.1281(d)(1)(ii)(A), the owner or operator shall use Method 18 of
40 CFR part 60, appendix A of this chapter; alternatively, any other
method or data that has been validated according to the applicable
procedures in Method 301 of appendix A of this part may be used. The
following procedures shall be used to calculate the percentage of
reduction:
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall be taken at
approximately equal intervals in time, such as 15 minute intervals
during the run.
(ii) The mass rate of either TOC (minus methane and ethane) or
total HAP (Ei, Eo) shall be computed.
[[Page 6331]]
(A) The following equations shall be used:
[GRAPHIC] [TIFF OMITTED] TP06FE98.013
[GRAPHIC] [TIFF OMITTED] TP06FE98.014
Where:
Cij, Coj=Concentration of sample component j of
the gas stream at the inlet and outlet of the control device,
respectively, dry basis, parts per million by volume.
Ei, Eo=Mass rate of TOC (minus methane and
ethane) or total HAP at the inlet and outlet of the control device,
respectively, dry basis, kilogram per hour.
Mij, Moj=Molecular weight of sample component j
of the gas stream at the inlet and outlet of the control device,
respectively, gram/gram-mole.
Qi, Qo=Flow rate of gas stream at the inlet and
outlet of the control device, respectively, dry standard cubic meter
per minute.
K2=Constant, 2.494 x 10-6 (parts per million)-1 (gram-mole
per standard cubic meter) (kilogram/gram) (minute/hour), where standard
temperature is 20 deg.C.
(B) When the TOC mass rate is calculated, all organic compounds
(minus methane and ethane) measured by Method 18, of 40 CFR part 60,
appendix A shall be summed using the equation in paragraph
(d)(3)(ii)(A) of this section.
(C) When the total HAP mass rate is calculated, only HAP chemicals
listed in Table 1 of this subpart shall be summed using the equation in
paragraph (d)(3)(ii)(A) of this section.
(iii) The percentage of reduction in TOC (minus methane and ethane)
or total HAP shall be calculated as follows
[GRAPHIC] [TIFF OMITTED] TP06FE98.015
Where:
Rcd=Control efficiency of control device, percent.
Ei=Mass rate of TOC (minus methane and ethane) or total HAP
at the inlet to the control device as calculated under paragraph
(d)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per
hour.
Eo=Mass rate of TOC (minus methane and ethane) or total
HAP at the outlet of the control device, as calculated under paragraph
(d)(3)(ii) of this section, kilograms TOC per hour or kilograms HAP per
hour.
(iv) If the vent stream entering a boiler or process heater with a
design capacity less than 44 megawatts is introduced with the
combustion air or as a secondary fuel, the weight-percentage of
reduction of total HAP or TOC (minus methane and ethane) across the
device shall be determined by comparing the TOC (minus methane and
ethane) or total HAP in all combusted vent streams and primary and
secondary fuels with the TOC (minus methane and ethane) or total HAP
exiting the device, respectively.
(4) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B),
the owner or operator shall use Method 18, 40 CFR part 60, appendix A
to measure either TOC (minus methane and ethane) or total HAP.
Alternatively, any other method or data that has been validated
according to Method 301, appendix A of this part, may be used. The
following procedures shall be used to calculate parts per million by
volume concentration, corrected to 3 percent oxygen:
(i) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall be taken at
approximately equal intervals in time, such as 15-minute intervals
during the run.
(ii) The TOC concentration or total HAP concentration shall be
calculated according to paragraph (d)(4)(ii)(A) or (d)(4)(ii)(B) of
this section.
(A) The TOC concentration (CTOC) is the sum of the
concentrations of the individual components and shall be computed for
each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.016
Where:
CTOC=Concentration of total organic compounds minus methane
and ethane, dry basis, parts per million by volume.
Cji=Concentration of sample components j of sample i, dry
basis, parts per million by volume.
n=Number of components in the sample.
x=Number of samples in the sample run.
(B) The total HAP concentration (CHAP) shall be computed
according to the equation in paragraph (d)(4)(ii)(A) of this section,
except that only HAP chemicals listed in Table 1 of this subpart shall
be summed.
(iii) The TOC concentration or total HAP concentration shall be
corrected to 3 percent oxygen as follows:
(A) The emission rate correction factor or excess air, integrated
sampling and analysis procedures of Method 3B, 40 CFR part 60, appendix
A shall be used to determine the oxygen concentration
(%O2d). The samples shall be taken during the same time that
the samples are taken for determining TOC concentration or total HAP
concentration.
(B) The concentration corrected to 3 percent oxygen (Cc)
shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TP06FE98.017
Where:
Cc=TOC concentration of total HAP concentration corrected to
3 percent oxygen, dry basis, parts per million by volume.
Cm=TOC concentration or total HAP concentration, dry basis,
parts per million by volume.
%O2d=Concentration of oxygen, dry basis, percent by volume.
(e) As an alternative to the procedures in paragraph (d) of this
section, an owner or operator may elect to use the procedures
documented in the Gas Research Institute Report entitled, ``Atmospheric
Rich/Lean Method for Determining Glycol Dehydrator Emissions,'' (GRI-
95/0368.1).
Sec. 63.1283 Inspection and monitoring requirements.
(a) This section applies to an owner or operator using air emission
controls in accordance with the requirements of Sec. 63.1275.
(b) [Reserved]
(c) Closed-vent system inspection and monitoring requirements. (1)
The owner or operator shall visually inspect and monitor for no
detectable emissions each closed-vent system at the following times:
(i) On or before the date that the unit connected to the closed-
vent system becomes subject to the provisions of this subpart;
(ii) At least once per year after the date that the closed-vent
system is inspected in accordance with the requirements of paragraph
(c)(1)(i) of this section; and
(iii) At other times as requested by the Administrator.
(2) To visually inspect a closed-vent system, the owner or operator
shall view
[[Page 6332]]
the entire length of ductwork, piping and connections to covers and
control devices for evidence of visible defects (such as holes in
ductwork or piping and loose connections) that may affect the ability
of the system to operate with no detectable emissions. A visible hole,
gap, tear, or split in the closed-vent system is defined as a leak
which shall be repaired in accordance with paragraph (c)(4) of this
section.
(3) To monitor a closed-vent system for no detectable emissions,
the owner or operator shall use Method 21, 40 CFR part 60, appendix A
to test each closed-vent system joint, seam, or other connection. For
the annual leak detection monitoring after the initial leak detection
monitoring, the owner or operator is not required to monitor those
closed-vent system components which continuously operate at a pressure
below atmospheric pressure or those closed-vent system joints, seams,
or other connections that are permanently or semi-permanently sealed
(e.g., a welded joint between two sections of metal pipe or a bolted
and gasketed pipe flange).
(4) When a leak is detected by either of the methods specified in
paragraph (c)(2) or (c)(3) of this section, the owner or operator shall
make a first attempt at repairing the leak no later than 5 calendar
days after the leak is detected. Repair of the leak shall be completed
as soon as practicable, but no later than 15 calendar days after the
leak is detected.
(d) Control device monitoring requirements. (1) For each control
device except as provided for in paragraph (d)(2) of this section, the
owner or operator shall install and operate a continuous monitoring
system in accordance with the requirements of paragraphs (d)(3) through
(d)(5) of this section that will allow a determination be made whether
the control device is continuously achieving the applicable performance
requirements of Sec. 63.1281.
(2) An owner or operator is exempted from the monitoring
requirements specified in paragraphs (d)(3) through (d)(5) of this
section for the following types of control devices:
(i) A boiler or process heater in which all vent streams are
introduced with primary fuel; or
(ii) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(3) The owner or operator shall install, calibrate, operate, and
maintain a device equipped with a continuous recorder to measure the
values of operating parameters appropriate for the control device as
specified in either paragraph (d)(3)(i), (d)(3)(ii), or (d)(3)(iii) of
this section. The monitoring equipment shall be installed, calibrated,
and maintained in accordance with the equipment manufacturer's
specifications or other written procedures that provide adequate
assurance that the equipment would reasonably be expected to monitor
accurately. The continuous recorder shall be a data recording device
that either records an instantaneous data value at least once every 15
minutes or records 15-minute or more frequent block average values. The
owner or operator shall use any of the following continuous monitoring
systems:
(i) A continuous monitoring system that measures the following
operating parameters as applicable:
(A) For a thermal vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The monitoring device shall
have an accuracy of 1 percent of the temperature being
monitored in deg.C, or 0.5 deg.C, whichever value is
greater. The temperature sensor shall be installed at a location in the
combustion chamber downstream of the combustion zone.
(B) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device shall be capable
of monitoring temperature at two locations and have an accuracy of
1 percent of the temperature being monitored in deg.C, or
0.5 deg.C, whichever value is greater. One temperature
sensor shall be installed in the vent stream at the nearest feasible
point to the catalyst bed inlet and a second temperature sensor shall
be installed in the vent stream at the nearest feasible point to the
catalyst bed outlet.
(C) For a flare, a heat sensing monitoring device equipped with a
continuous recorder that indicates the continuous ignition of the pilot
flame.
(D) For a boiler or process heater with a design heat input
capacity of less than 44 megawatts, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have an accuracy of 1 percent of the temperature
being monitored in deg.C, or 0.5 deg.C, whichever value
is greater. The temperature sensor shall be installed at a location in
the combustion chamber downstream of the combustion zone.
(E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have an
accuracy of 1 percent of the temperature being monitored in
deg.C, or 0.5 deg.C, whichever value is greater. The
temperature sensor shall be installed at a location in the exhaust vent
stream from the condenser.
(F) For a regenerative-type carbon adsorption system, an
integrating regeneration stream flow monitoring device equipped with a
continuous recorder, and a carbon bed temperature monitoring device
equipped with a continuous recorder. The integrating regeneration
stream flow monitoring device shall have an accuracy of 10
percent and measure the total regeneration stream mass flow during the
carbon bed regeneration cycle. The temperature monitoring device shall
have an accuracy of 1 percent of the temperature being
monitored in deg.C, or 0.5 deg.C, whichever value is
greater and measure the carbon bed temperature both after regeneration
and within 15 minutes of completing the cooling cycle, and over the
duration of the carbon bed steaming cycle.
(ii) A continuous monitoring system that measures the concentration
level of organic compounds in the exhaust vent stream from the control
device using an organic monitoring device equipped with a continuous
recorder.
(iii) A continuous monitoring system that measures alternative
operating parameters other than those specified in paragraph (d)(3)(i)
or (d)(3)(ii) of this section upon approval of the Administrator as
specified in Sec. 63.8 (f)(1) through (f)(5).
(4) For each operating parameter monitored in accordance with the
requirements of paragraph (d)(3) of this section, the owner or operator
shall establish a minimum operating parameter value or a maximum
operating parameter value, as appropriate for the control device, to
define the conditions at which the control device must be operated to
continuously achieve the applicable performance requirements of
Sec. 63.1281. Each minimum or maximum operating parameter value shall
be established as follows:
(i) If the owner or operator conducts performance tests in
accordance with the requirements of Sec. 63.1281 to demonstrate that
the control device achieves the applicable performance requirements
specified in Sec. 63.1281, then the minimum operating parameter value
or the maximum operating parameter value shall be established based on
values measured during the performance test and supplemented, as
necessary, by control device design analysis and manufacturer
recommendations.
(ii) If the owner or operator uses control device design analysis
in accordance with the requirements of Sec. 63.1281(d)(3)(iv) to
demonstrate that the control device achieves the applicable performance
requirements
[[Page 6333]]
specified in Sec. 63.1281(d)(1), then the minimum operating parameter
value or the maximum operating parameter value shall be established
based on the control device design analysis and the control device
manufacturer's recommendations.
(5) The owner or operator shall regularly inspect the data recorded
by the continuous monitoring system to determine whether the control
device is operating in accordance with the applicable requirements of
Sec. 63.1281(d).
Sec. 63.1284 Recordkeeping requirements.
(a) The recordkeeping provisions of subpart A of this part that
apply and those that do not apply to owners and operators of facilities
subject to this subpart are listed in Table 2 of this subpart.
(b) Except as specified in paragraphs (c) and (d) of this section,
each owner or operator of a facility subject to this subpart shall
maintain the following records in accordance with the requirements of
Sec. 63.10(b)(1):
(1) Records specified in Sec. 63.10(b)(2);
(2) Records specified in Sec. 63.10(c) for each continuous
monitoring system operated by the owner or operator in accordance with
the requirements of Sec. 63.1283(d).
(c) [Reserved]
(d) An owner or operator that is exempt from control requirements
under Sec. 63.1274(b) shall maintain a record of the design capacity
(in terms of natural gas flow rate to the unit per day) of each glycol
dehydration unit that is not controlled according to the requirements
of Sec. 63.1274(a).
Sec. 63.1285 Reporting requirements.
(a) The reporting provisions of subpart A of this part that apply
and those that do not apply to owners and operators of facilities
subject to this subpart are listed in Table 2 of this subpart.
(b) Each owner or operator of a facility subject to this subpart
shall submit the following reports to the Administrator:
(1) An Initial Notification as described in Sec. 63.9 (a) through
(d), except that the notification required by Sec. 63.9(b)(2) shall be
submitted not later than one year after the effective date of this
standard.
(2) A Notification of Performance Tests as specified in
Sec. 63.7(b), Sec. 63.9(e), and Sec. 63.9(g).
(3) A Notification of Compliance Status as specified in
Sec. 63.9(h).
(4) Performance test reports as specified in Sec. 63.10(d)(2) and
performance evaluation reports specified in Sec. 63.10(e)(2). Separate
performance evaluation reports as described in Sec. 63.10(e)(2) are not
required if the information is included in the summary report specified
in paragraph (b)(6) of this section.
(5) Startup, shutdown, and malfunction reports, as specified in
Sec. 63.10(d)(5), shall be submitted as required. Separate startup,
shutdown, or malfunction reports as described in Sec. 63.10(d)(5)(i)
are not required if the information is included in the report specified
in paragraph (b)(6) of this section.
(6) The excess emission and CMS performance report and summary
report as specified in Sec. 63.10(e)(3) shall be submitted on a semi-
annual basis (i.e., once every 6-month period). The summary report
shall be entitled ``Summary Report--Gaseous Excess Emissions and
Continuous Monitoring System Performance.''
(7) The owner or operator shall meet the requirements specified in
paragraph (b) of this section for any emission point or material that
becomes subject to the standards in this subpart due to an increase in
flow, concentration, or other parameters equal to or greater than the
limits specified in this subpart.
(8) For each control device other than a flare used to meet the
requirements of this subpart, the owner or operator shall submit the
following information for each operating parameter required to be
monitored in accordance with the requirements of Sec. 63.1283(d):
(i) The minimum operating parameter value or maximum operating
parameter value, as appropriate for the control device, established by
the owner or operator to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.1281(d)(1).
(ii) An explanation of the rationale for why the owner or operator
selected each of the operating parameter values established in
Sec. 63.1281(d). This explanation shall include any data and
calculations used to develop the value and a description of why this
value indicates that the control device is operating in accordance with
the applicable requirements of Sec. 63.1281(d)(1).
(9) Each owner or operator of a major source subject to this
subpart that is not subject to the control requirements for glycol
dehydration unit process vents in Sec. 63.765 is exempt from all
reporting requirements for major sources in this subpart.
(c) Each owner or operator of a facility subject to this subpart
that is an area source is exempt from all reporting requirements in
this subpart.
Sec. 63.1286 Delegation of authority. [Reserved]
Sec. 63.1287 Alternative means of emission limitation.
(a) If, in the judgment of the Administrator, an alternative means
of emission limitation will achieve a reduction in HAP emissions at
least equivalent to the reduction in HAP emissions from that source
achieved under the applicable requirements in Secs. 63.1274 through
63.1281, the Administrator will publish a notice in the Federal
Register permitting the use of the alternative means for purposes of
compliance with that requirement. The notice may condition the
permission on requirements related to the operation and maintenance of
the alternative means.
(b) Any notice under paragraph (a) of this section shall be
published only after public notice and an opportunity for a hearing.
(c) Any person seeking permission to use an alternative means of
compliance under this section shall collect, verify, and submit to the
Administrator information showing that this means achieves equivalent
emission reductions.
Sec. 63.1288 [Reserved]
Sec. 63.1289 [Reserved]
Table 1 to Subpart HHH--List of Hazardous Air Pollutants (HAP)
------------------------------------------------------------------------
CAS No.a Chemical name
------------------------------------------------------------------------
75070.............................. Acetaldehyde.
71432.............................. Benzene (includes benzene in
gasoline).
75150.............................. Carbon disulfide.
463581............................. Carbonyl sulfide.
100414............................. Ethyl benzene.
107211............................. Ethylene glyco.
50000.............................. Formaldehyde.
110543............................. n-Hexane.
91203.............................. Naphthalene.
108883............................. Toluene.
540841............................. 2,2,4-Trimethylpentane.
1330207............................ Xylenes (isomers and mixture).
95476.............................. o-Xylene.
108383............................. m-Xylene.
106423............................. p-Xylenea.
------------------------------------------------------------------------
a CAS numbers refer to the Chemical Abstracts Services registry number
assigned to specific compounds, isomers, or mixtures of compounds.
[[Page 6334]]
Table 2 of Subpart HHH.--Applicability of 40 CFR Part 63 General Provisions
----------------------------------------------------------------------------------------------------------------
General provisions reference Applicable to subpart HHH Comment
----------------------------------------------------------------------------------------------------------------
Sec. 63.1(a)(1)...................... Yes...........................
Sec. 63.1(a)(2)...................... Yes...........................
Sec. 63.1(a)(3)...................... Yes...........................
Sec. 63.1(a)(4)...................... Yes...........................
Sec. 63.1(a)(5)...................... No............................ Section reserved.
Sec. 63.1(a)(6)-(a)(8)............... Yes...........................
Sec. 63.1(a)(9)...................... No............................ Section reserved.
Sec. 63.1(a)(10)..................... Yes...........................
Sec. 63.1(a)(11)..................... Yes...........................
Sec. 63.1(a)(12)-(a)(14)............. Yes...........................
Sec. 63.1(b)(1)...................... No............................ Subpart HHH specifies applicability.
Sec. 63.1(b)(2)...................... Yes...........................
Sec. 63.1(b)(3)...................... No............................
Sec. 63.1(c)(1)...................... No............................ Subpart HHH specifies applicability.
Sec. 63.1(c)(2)...................... No............................
Sec. 63.1(c)(3)...................... No............................ Section reserved.
Sec. 63.1(c)(4)...................... Yes...........................
Sec. 63.1(c)(5)...................... Yes...........................
Sec. 63.1(d)......................... No............................ Section reserved.
Sec. 63.1(e)......................... Yes...........................
Sec. 63.2............................ Yes........................... Except definition of ``major source'' is
unique for this source category and
there are additional definitions
included in subpart HHH.
Sec. 63.3(a)-(c)..................... Yes...........................
Sec. 63.4(a)(1)-(a)(3)............... Yes...........................
Sec. 63.4(a)(4)...................... No............................ Section reserved.
Sec. 63.4(a)(5)...................... Yes...........................
Sec. 63.4(b)......................... Yes...........................
Sec. 63.49(c)........................ Yes...........................
Sec. 63.5(a)(1)...................... Yes...........................
Sec. 63.5(a)(2)...................... No............................ Preconstruction review required only for
major sources that commence
construction after promulgation of the
standard.
Sec. 63.5(b)(1)...................... Yes...........................
Sec. 63.5(b)(2)...................... No............................ Section reserved.
Sec. 63.5(b)(3)...................... Yes...........................
Sec. 63.5(b)(4)...................... Yes...........................
Sec. 63.5(b)(5)...................... Yes...........................
Sec. 63.5(b)(6)...................... Yes...........................
Sec. 63.5(c)......................... No............................ Section reserved.
Sec. 63.5(d)(1)...................... Yes...........................
Sec. 63.5(d)(2)...................... Yes...........................
Sec. 63.5(d)(3)...................... Yes...........................
Sec. 63.5(d)(4)...................... Yes...........................
Sec. 63.5(e)......................... Yes...........................
Sec. 63.5(f)(1)...................... Yes...........................
Sec. 63.5(f)(2)...................... Yes...........................
Sec. 63.6(a)......................... Yes...........................
Sec. 63.6(b)(1)...................... Yes...........................
Sec. 63.6(b)(2)...................... Yes...........................
Sec. 63.6(b)(3)...................... Yes...........................
Sec. 63.6(b)(4)...................... Yes...........................
Sec. 63.6(b)(5)...................... Yes...........................
Sec. 63.6(b)(6)...................... No............................ Section reserved.
Sec. 63.6(b)(7)...................... Yes...........................
Sec. 63.6(c)(1)...................... Yes...........................
Sec. 63.6(c)(2)...................... Yes...........................
Sec. 63.6(c)(3)-(c)(4)............... No............................ Sections reserved.
Sec. 63.6(c)(5)...................... Yes...........................
Sec. 63.6(d)......................... No............................ Section reserved.
Sec. 63.6(e)......................... Yes...........................
Sec. 63.6(f)(1)...................... Yes...........................
Sec. 63.6(f)(2)...................... Yes...........................
Sec. 63.6(f)(3)...................... Yes...........................
Sec. 63.6(g)......................... Yes...........................
Sec. 63.6(h)......................... No............................ Subpart HHH does not require the use of
a continuous emissions monitoring
system.
Sec. 63.6(i)(1)-(i)(14).............. Yes...........................
Sec. 63.6(i)(15)..................... No............................ Section reserved.
Sec. 63.6(i)(16)..................... Yes...........................
Sec. 63.6(j)......................... Yes...........................
Sec. 63.7(a)(1)...................... Yes...........................
Sec. 63.7(a)(2)...................... Yes...........................
[[Page 6335]]
Sec. 63.7(a)(3)...................... Yes...........................
Sec. 63.7(b)......................... Yes...........................
Sec. 63.7(c)......................... Yes...........................
Sec. 63.7(d)......................... Yes...........................
Sec. 63.7(e)(1)...................... Yes...........................
Sec. 63.7(e)(2)...................... Yes...........................
Sec. 63.7(e)(3)...................... Yes...........................
Sec. 63.7(e)(4)...................... Yes...........................
Sec. 63.7(f)......................... Yes...........................
Sec. 63.7(g)......................... Yes...........................
Sec. 63.7(h)......................... Yes...........................
Sec. 63.8(a)(1)...................... Yes...........................
Sec. 63.8(a)(2)...................... Yes...........................
Sec. 63.8(a)(3)...................... No............................ Section reserved.
Sec. 63.8(a)(4)...................... Yes...........................
Sec. 63.8(b)(1)...................... Yes...........................
Sec. 63.8(b)(2)...................... Yes...........................
Sec. 63.8(b)(3)...................... Yes...........................
Sec. 63.8(c)(1)...................... Yes...........................
Sec. 63.8(c)(2)...................... Yes...........................
Sec. 63.8(c)(3)...................... Yes...........................
Sec. 63.8(c)(4)...................... No............................
Sec. 63.8(c)(5)-(c)(8)............... Yes...........................
Sec. 63.8(d)......................... Yes...........................
Sec. 63.8(e)......................... Yes...........................
Sec. 63.8(f)(1)-(f)(5)............... Yes...........................
Sec. 63.8(f)(6)...................... No............................ Subpart HHH does not require the use of
a continuous emissions monitor.
Sec. 63.8(g)......................... No............................ Subpart HHH specifies continuous
monitoring system data reduction
requirements.
Sec. 63.9(a)......................... Yes...........................
Sec. 63.9(b)(1)...................... Yes...........................
Sec. 63.9(b)(2)...................... Yes........................... Sources are given one year (rather than
120 days) to submit this notification.
Sec. 63.9(b)(3)...................... Yes...........................
Sec. 63.9(b)(4)...................... Yes...........................
Sec. 63.9(b)(5)...................... Yes...........................
Sec. 63.9(c)......................... Yes...........................
Sec. 63.9(d)......................... Yes...........................
Sec. 63.9(e)......................... Yes...........................
Sec. 63.9(f)......................... No............................
Sec. 63.9(g)......................... Yes...........................
Sec. 63.9(h)(1)-(h)(3)............... Yes...........................
Sec. 63.9(h)(4)...................... No............................ Section reserved.
Sec. 63.9(h)(5)-(h)(6)............... Yes...........................
Sec. 63.9(i)......................... Yes...........................
Sec. 63.9(j)......................... Yes...........................
Sec. 63.10(a)........................ Yes...........................
Sec. 63.10(b)(1)..................... Yes...........................
Sec. 63.10(b)(2)..................... Yes...........................
Sec. 63.10(b)(3)..................... No............................
Sec. 63.10(c)(1)..................... Yes...........................
Sec. 63.10(c)(2)-(c)(4).............. No............................ Sections reserved.
Sec. 63.10(c)(5)-(c)(8).............. Yes...........................
Sec. 63.10(c)(9)..................... No............................ Section reserved.
Sec. 63.10(c)(10)-(c)(15)............ Yes...........................
Sec. 63.10(d)(1)..................... Yes...........................
Sec. 63.10(d)(2)..................... Yes...........................
Sec. 63.10(d)(3)..................... Yes...........................
Sec. 63.10(d)(4)..................... Yes...........................
Sec. 63.10(d)(5)..................... Yes........................... Subpart HHH requires major sources to
submit startup, shutdown and
malfunction report semi-annually.
Sec. 63.10(e)........................ Yes........................... Subpart HHH requires major sources to
submit continuous monitoring system
performance reports semi-annually.
[[Page 6336]]
Sec. 63.10(f)........................ Yes...........................
Sec. 63.11(a)-(b).................... Yes...........................
Sec. 63.12(a)-(c).................... Yes...........................
Sec. 63.13(a)-(c).................... Yes...........................
Sec. 63.14(a)-(b).................... Yes...........................
Sec. 63.15(a)-(b).................... Yes...........................
----------------------------------------------------------------------------------------------------------------
[FR Doc. 98-2714 Filed 2-5-98; 8:45 am]
BILLING CODE 6560-50-U
